NERC Petition on BES Definition

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January 25, 2012
VIA ELECTRONIC FILING
Ms. Kimberly D. Bose, Secretary
Federal Energy Regulatory Commission
888 First Street, N.E.
Washington, D.C. 20426
Re:

North American Electric Reliability Corporation
Docket No. RM__-___-__
Petition of the North American Electric Reliability Corporation for Approval of a
Revised Definition of “Bulk Electric System” in the NERC Glossary of Terms
Used in Reliability Standards

Dear Ms. Bose:
The North American Electric Reliability Corporation (NERC) hereby submits a “Petition
for Approval of a Revised Definition of “Bulk Electric System” in the NERC Glossary of Terms
Used in Reliability Standards.”
NERC’s filing consists of: (1) this transmittal letter, (2) the Petition, which follows this
transmittal letter, and (3) Exhibits A, B, C, D, E, F and G, all of which is being transmitted in a
single pdf file. The Table of Contents to the Petition lists and identify the Exhibits.
Please contact the undersigned if you have any questions concerning this filing.
Respectfully submitted,
/s/ Owen E. MacBride
Owen E. MacBride
Attorney for North American Electric
Reliability Corporation

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION

)
)

Docket No. RM__-__-____

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF A REVISED DEFINITION OF “BULK ELECTRIC SYSTEM”
IN THE NERC GLOSSARY OF TERMS USED IN RELIABILITY STANDARDS
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability Corporation
3353 Peachtree Road N.E.
Suite 600, North Tower
Atlanta, GA 30326-1001
(404) 446-2560
David N. Cook
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel for Standards and
Critical Infrastructure Protection
Andrew Dressel, Attorney
North American Electric Reliability Corporation
1325 G Street N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
david.cook@nerc.net
holly.hawkins@nerc.net
andrew.dressel@nerc.net

Owen E. MacBride
Debra A. Palmer
Schiff Hardin LLP
1666 K Street, N.W., Suite 300
Washington, D.C. 20036-4390
(202) 778-6400
(202) 778-6460 – facsimile
omacbride@schiffhardin.com
dpalmer@schiffhardin.com

January 25, 2012

TABLE OF CONTENTS
I. INTRODUCTION....................................................................................................................1
II. NOTICES AND COMMUNICATIONS..................................................................................4
III. PROPOSED REVISED DEFINITION OF “BULK ELECTRIC SYSTEM”...........................4
A. Regulatory Framework........................................................................................................4
B. Directives and Technical and Policy Concerns in Order Nos. 743 and 743-A...................6
C. Discussion of Proposed Revised Definition of “Bulk Electric System”............................13
D. Detailed Information to Support an Exception Request....................................................25
E. Proposed Implementation Plan for Revised Definition of “Bulk Electric System”..........32
IV. SUMMARY OF THE RELIABILITY STANDARD DEVELOPMENT PROCEEDINGS..44
A. Development History.........................................................................................................44
B. Issues Raised During the Development Process Including Minority Issues......................46
C. Initial Ballot.......................................................................................................................49
D. Balloting and Approval......................................................................................................56
V. CONCLUSION........................................................................................................................57
List of Exhibits
Exhibit A:

Proposed Definition of “Bulk Electric System”

Exhibit B:

Current Definition of “Bulk Electric System” (for reference)

Exhibit C:

Detailed Information to Support an Exception Request

Exhibit D:

Consideration of Comments Report created during the development of the revised
definition of “Bulk Electric System”

Exhibit E:

The complete development record of the proposed revised definition of “Bulk
Electric System”

Exhibit F:

The Standard Drafting Team roster and biographical information for NERC
Standards Development Project 2010-17 Definition of Bulk Electric System

Exhibit G:

Technical justification paper for the “Local Network Exclusion” (Exclusion E3 of
the BES Definition)

I. INTRODUCTION
The North American Electric Reliability Corporation (“NERC”) respectfully requests the
Commission to approve, in accordance with §215(d)(1) of the Federal Power Act (“FPA”)1 and
the Commission’s regulations at 18 C.F.R. §39.5, a revised definition of the term “Bulk Electric
System” (“BES Definition”) in the NERC Glossary of Terms Used in Reliability Standards
(“NERC Glossary”). The revised BES Definition is provided in Exhibit A. NERC also requests
Commission approval of the proposed “Detailed Information to Support an Exception Request”
(Exhibit C), which will be used in the submittal, review and approval or disapproval of requests
for Exceptions from the application of the BES Definition. Finally, NERC requests Commission
approval of its plan for implementation of the revised BES Definition.
In Order No. 743 (with clarification provided in Order No. 743-A), the Commission
directed NERC to develop, using its Reliability Standard Development Procedure, and file with
the Commission, within one year following the effective date of the final rule adopted in that
Order, a revised definition of “Bulk Electric System” (“BES”).2 The Commission directed that
the revised BES Definition should address the Commission’s technical and policy concerns
discussed in Order No. 743 and should encompass all facilities necessary for operating an
interconnected electric transmission network. The Commission also directed that NERC work
with the Regional Entities that would be affected by the revised BES Definition to develop
transition plans for implementing the revised BES Definition that will allow a reasonable period
of time for affected entities to achieve compliance with applicable Reliability Standards with

1

16 U.S.C. §824o.

2

Revision to Electric Reliability Organization Definition of Bulk Electric System, 133 FERC ¶
61,150 (2011) (“Order No. 743”), at PP 29-33; Order on Rehearing, 134 FERC ¶ 61,210 (2011)
(“Order No. 743-A”).

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respect to facilities that are subject to Commission-approved Reliability Standards for the first
time based on the revised BES Definition. The transition plans were also required to be filed
within one year of the effective date of the final rule adopted in Order No. 743.3 Further, the
Commission directed NERC to develop, through a stakeholder process, and file with the
Commission within one year following the effective date of the final rule, a process to exempt
facilities from inclusion in the Bulk Electric System through application of the BES Definition.4
Order No. 743 specified the effective date of the final rule to be 60 days following the
date of its publication in the Federal Register. The final rule was published on November 26,
2010;5 the date sixty days following that date was January 25, 2011. This Petition is being filed
within one year following January 25, 2011. Contemporaneously, NERC is filing with the
Commission a separate Petition for approval of proposed revisions to the NERC Rules of
Procedure (“ROP”) including a proposed BES Exception Procedure.6
The NERC Board of Trustees voted to adopt the revised BES Definition, Detailed
Information to Support an Exception Request, and proposed implementation plan (as well as the
proposed Exception Procedure that is being separately filed for approval) on January 18, 2012.
Exhibit A to this Petition is the revised BES Definition. Exhibit B is the current

3

Order No. 743 at P 131.

4

Order No. 743 at P 112-13.

5

75 FR 72910 (2010).

6

Specifically, contemporaneous with this filing, NERC is also filing with the Commission a
Petition for approval of proposed new sections 509 and 1703 of the ROP and proposed new
Appendix 5C to the ROP, Procedure for Requesting and Receiving an Exception from the
Application of the NERC Definition of Bulk Electric System. Section III.D of this Petition,
below, discusses why the “Detailed Information to Support an Exception Request” was
developed through the Reliability Standards development process while the proposed BES
Exception Procedure was developed through the ROP amendment process.

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definition of “Bulk Electric System” in the NERC Glossary; it is provided for reference. Exhibit
C is the Detailed Information to Support an Exception Request, which identifies information that
will be required to be included in Exception Requests submitted pursuant to the proposed
Exception Procedure. Exhibit D is the “Consideration of Comments” report created by the
Standard Drafting Team (“SDT”) during the development of the revised BES Definition.
Exhibit E is the complete development record of the revised BES Definition. Exhibit F is the
SDT roster and biographical information for NERC Standards Project 2010-17 Definition of
Bulk Electric System, which resulted in the revised BES Definition. Exhibit G is a technical
justification paper for the “Local Network Exclusion,” Exclusion E3 of the BES Definition.
NERC is also filing the revised BES Definition with Applicable Governmental
Authorities in Canada for approval or review pursuant to each jurisdiction’s laws or regulations.

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II. NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to:
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability Corporation
3353 Peachtree Road N.E.
Suite 600, North Tower
Atlanta, GA 30326-1001
(404) 446-2560
David N. Cook*
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel for Standards and
Critical Infrastructure Protection
Andrew Dressel, Attorney
North American Electric Reliability Corporation
1325 G Street N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
david.cook@nerc.net
holly.hawkins@nerc.net
andrew.dressel@nerc.net

Owen E. MacBride*
Debra A. Palmer
Schiff Hardin LLP
1666 K Street, N.W., Suite 300
Washington, D.C. 20036-4390
(202) 778-6400
(202) 778-6460 – facsimile
omacbride@schiffhardin.com
dpalmer@schiffhardin.com
*Persons to be included on the official
service list for this proceeding.

III. PROPOSED REVISED DEFINITION OF “BULK ELECTRIC SYSTEM”
A.

Regulatory Framework
By enacting the Energy Policy Act of 2005,7 Congress entrusted the Commission with the

duties of approving and enforcing rules to ensure the reliability of the nation’s Bulk Power
System, and of certifying an Electric Reliability Organization (“ERO”) that would be charged
with developing and enforcing mandatory Reliability Standards, subject to Commission
approval. On July 20, 2006, the Commission certified NERC as the ERO authorized by FPA

7

Energy Policy Act of 2005, Pub. L. No. 109-58, Title XII, Subtitle A, 119 Stat. 594, 941 (2005)
(codified at 16 U.S.C. §824o).

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§215.8 FPA §215 states that all users, owners and operators of the Bulk Power System in the
United States will be subject to Commission-approved Reliability Standards.9
Section 39.5(a) of the Commission’s regulations requires the ERO to file with the
Commission for approval each Reliability Standard that the ERO proposes to become mandatory
and enforceable in the United States, and each proposed modification to a Reliability Standard.
The Commission has the regulatory responsibility to review, approve, and enforce Reliability
Standards that protect the reliability of the Bulk Power System. In discharging its responsibility
to review, approve and enforce mandatory Reliability Standards, the Commission is authorized
to approve those proposed Reliability Standards that meet the criteria detailed by Congress. FPA
§215(d)(2) states, “the Commission may approve, by rule or order, a proposed Reliability
Standard or modification to a Reliability Standard if it determines that the standard is just,
reasonable, not unduly discriminatory or preferential, and in the public interest.”
In Order No. 743 (as clarified in Order No. 743-A), the Commission directed NERC to
develop a revised BES Definition for the NERC Glossary using NERC’s Reliability Standards
development process.10 The directive to use the Reliability Standards development process was
consistent with the approach NERC has previously followed, of using the same processes and
8

Order Certifying North American Electric Reliability Corporation as the Electric Reliability
Organization and Ordering Compliance Filing, 116 FERC ¶ 61,062 (2006) (“ERO Certification
Order”).
9

Terms that are capitalized in this Petition, such as “Bulk Power System” and “Reliability
Standard,” but not separately defined herein, are defined terms from the NERC Glossary of
Terms Used in Reliability Standards and/or the ROP. On November 29, 2011, NERC filed with
the Commission for approval a proposed new Appendix 2, Definitions Used in the Rules of
Procedure, to the ROP, in which all defined terms used in the ROP and its Appendices are
collected. Petition for Approval of Revisions to the Rules of Procedure of the North American
Electric Reliability Corporation, Docket No. RR12-3-000. As of the date of this Petition, the
Commission has not acted on proposed Appendix 2.
10

Order No. 743 at P 29.

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procedures applicable to development of new and revised Reliability Standards in the
development of new and revised definitions of terms included in the NERC Glossary that are
used in the Reliability Standards. NERC has also submitted new and revised definitions to the
Commission for approval in the same way that new and revised Reliability Standards are
submitted to the Commission for approval. As shown in this filing, the revised BES Definition is
just, reasonable, not unduly discriminatory or preferential, and in the public interest.
When evaluating proposed Reliability Standards, the Commission is expected to give
“due weight” to the technical expertise of the ERO. The technical expertise of the ERO is
derived from the SDT. For the BES Definition project, the SDT consisted of 14 industry experts
with over 360 years of collective industry experience. The SDT included several registered
professional engineers, and other members experienced in Bulk Power System operations.
Members of the SDT included individuals employed by electric utilities and transmission
operators, industry associations and organizations, Regional Entities, industry consulting firms,
and a state public utility commission. The SDT roster and detailed biographical information for
each of the SDT members is included in Exhibit F.
B.

Directives and Technical and Policy Concerns in Order Nos. 743 and 743-A
In Order No. 743, the Commission directed NERC to revise its definition of the term

“Bulk Electric System.” The current definition of Bulk Electric System in the NERC Glossary,
which the Commission directed NERC to revise, is:
As defined by the Regional Reliability Organization, the electrical generation
resources, transmission lines, interconnections with neighboring systems, and
associated equipment, generally operated at voltages of 100 kV or higher. Radial
transmission lines serving only load with one transmission source are generally
not included in this definition.
As stated in P 16 of Order No. 743, the Commission directed NERC:

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to revise the definition of “bulk electric system” through the NERC Standards
Development Process to address the Commission’s concerns discussed herein.
The Commission believes the best way to address these concerns is to eliminate
the Regional Entities’ discretion to define “bulk electric system” without ERO or
Commission review, maintain a bright-line threshold that includes all facilities
operated at or above 100 kV except defined radial facilities, and adopt an
exemption process and criteria for excluding facilities that are not necessary to
operate an interconnected electric transmission network. However, NERC may
propose a different solution that is as effective as, or superior to, the
Commission’s proposed approach in addressing the Commission’s technical and
other concerns so as to ensure that all necessary facilities are included within the
scope of the definition.
.
The Commission gave additional direction, and expressed its technical concerns, in the following
paragraphs of Order No. 743.
P 30: “[T]he Commission finds that the current definition of bulk electric system
is insufficient to ensure that all facilities necessary for operating an interconnected
electric energy transmission network are included under the ‘bulk electric system’
rubric. Therefore, pursuant to section 215(d)(5) of the FPA, the Commission
directs the ERO to modify, through the Standards Development Process, the
definition of ‘bulk electric system’ to address the Commission’s technical and
policy concerns described more fully herein. The Commission believes the best
way to address [its] concerns is to eliminate the regional discretion in the ERO’s
current definition, maintain the bright-line threshold that includes all facilities
operated at or above 100 kV except defined radial facilities, and establish an
exemption process and criteria for excluding facilities the ERO determines are not
necessary for operating the interconnected transmission network. It is important
to note that Commission is not proposing to change the threshold value already
contained in the definition, but rather seeks to eliminate the ambiguity created by
the current characterization of that threshold as a general guideline.”11
P 53: “[A]lthough the NOPR used the term ‘rated at,’ the Commission did not
intend to require NERC to utilize that term rather than the term ‘operated at’
which is reflected in the current definition of bulk electric system. While the
Commission does not have firm data on the number of facilities that operate at a
voltage significantly lower than the rated voltage, we find that the term ‘rated at’
could generate confusion.” (Footnote omitted.)
P 55: “[W]e do not seek to modify the second part of the definition through this
Final Rule, which states that ‘[r]adial transmission facilities serving only load
with one transmission source are generally not included in this definition.’ While
11

The Commission observed in footnote 39 that “all regions except NPCC currently utilize 100
kV as a general threshold.”

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commenters would like to expand the scope of the term ‘radial’ to exclude certain
transmission facilities such as tap lines and secondary feeds via a normally open
line, we are not persuaded that such categorical exemption is warranted. For
example, when the normally ‘open’ line is ‘closed,’ it becomes part of the
transmission network and therefore should be subject to mandatory Reliability
Standards. Commenters also argued that the bright line 100 kV threshold would
encourage small utilities to choose not to provide backup service options,
reducing overall customer service. We acknowledge these concerns, and direct
the ERO to consider these comments regarding radial facilities in crafting an
exemption methodology.”
P 72: “The current definition has failed to ensure that all facilities necessary for
operation of the interconnected transmission network are covered by the
Reliability Standards. As discussed above, the current definition allows broad
discretion without ERO or Commission oversight, which has resulted in reliability
issues such as the exclusion of transmission serving bulk electric generators
(including nuclear plants), inconsistency in classification at the seams that
compromises the effectiveness of the Reliability Standards, routine TLR events
on non-bulk electric system facilities, and the exclusion of elements necessary to
operate the interconnected transmission network. Given the inconsistency of the
application among regions and the reliability issues created as a result of the
current definition, we conclude that it is necessary to direct the ERO to revise the
definition of ‘bulk electric system’ to ensure that all facilities necessary to operate
the interconnected transmission network are included and to address the concerns
noted herein. We believe that the Commission’s proposed approach of adopting a
bright-line, 100 kV threshold, along with a NERC-developed, Commissionapproved exemption process, as well as eliminating regional variations unless
approved by the Commission as provided in Order No. 672, is an appropriate
action to ensure bulk electric system reliability.” (Footnote omitted.)
P 73: “[M]any facilities operated at 100 kV and above have a significant effect
on the overall functioning of the grid. The majority of 100 kV and above
facilities in the United States operate in parallel with other high voltage and extra
high voltage facilities, interconnect significant amounts of generation sources and
operate as part of a defined flow gate, which illustrates their parallel nature and
therefore their necessity to the reliable operation of the interconnected
transmission system. Parallel facilities operated at 100-200 kV will experience
similar loading as higher voltage parallel facilities at any given time and the lower
voltage facilities will be relied upon during contingency scenarios. Further . . .
115 kV and 138 kV facilities have either caused or contributed to significant bulk
system disturbances and cascading outages. Additionally, the current definition’s
broad regional discretion has allowed classification inconsistencies to develop
within and along the borders of Regional Entities . . . . The proposed 100 kV
threshold is intended to ensure facilities necessary for reliable operation are
captured by the definition and to avoid entities exempting their facilities by any

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means other than through a Commission-approved exemption process.”
(Footnote omitted.)
P 75: “[W]e believe use of the term ‘operated at’ rather than ‘rated at’ together
with the exemption methodology that NERC will develop . . . addresses the
WPSC’s concern that utilities may elect to build facilities below 100 kV to avoid
oversight.”
P 82: “[U]niform Reliability Standards, and uniform implementation, should be
the goal and the practice, the rule rather than the exception, absent a showing that
a regional variation is superior or necessary due to regional differences.
Consistency is important as it sets a common bar for transmission planning,
operation, and maintenance necessary to achieve reliable operation. . . . [W]e have
found several reliability issues with allowing Regional Entities broad discretion
without ERO or Commission oversight. The Commission’s proposed approach to
addressing these concerns will enable affected entities to pursue exemptions for
facilities they believe should not be included in the bulk electric system, and will
also allow Regional Entities to add facilities below 100 kV they believe should be
included.” (Footnote omitted.)
P 96: “In general, the Final Rule identifies the reliability concerns created by the
current definition and a method to ensure that certain facilities needed for the
reliable operation of the nation’s bulk electric system are subject to mandatory
and enforceable Reliability Standards, and that exemption methodologies would
be developed by NERC and subject to Commission review. From the
Commission’s review, the material impact assessments implemented by NPCC
are subjective in nature, and results from such tests are inconsistent in application,
as shown through the exclusion of facilities that clearly are needed for reliable
operation. Further, we find that the vast majority of 100 kV and above facilities
are part of parallel networks with high voltage and extra high voltage facilities
and are necessary for reliable operation. As a result, and consistent with our
previous statements in Order No. 672, we find it is best for the ERO to establish a
uniform definition that eliminates subjectivity and regional variation in order to
ensure reliable operation of the bulk electric system. We further find that the
existing NPCC impact test is not a consistent, repeatable, and comprehensive
alternative to the bright-line, 100 kV definition we prefer.” (Footnote omitted.)
PP 139-141: “The Commission does not agree with the commenters’ arguments
that 100-199 kV facilities in the Western Interconnection should be treated
differently than facilities in the Eastern Interconnection as a threshold matter.
The bulk electric system definition should include all facilities that are necessary
for operating an interconnected electric transmission network. While commenters
have implied that not all 100-199 kV facilities are needed for reliable operation,
the Commission notes that 100 kV and some lower voltage facilities are included
in some of the WECC Rated Paths. Clearly, these facilities are operationally
significant and needed for reliable operation . . . . While the Western

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Interconnection has a higher percentage of transmission facilities above 200 kV
compared to the Eastern Interconnection, it is how the lines below 200 kV are
interconnected with higher voltages that determines their significance. . . .
[C]ommenters have not provided adequate explanation in this proceeding,
supported by data and analysis, as to why there is a physical difference upon
which to treat the Western Interconnection differently. . . . Order No. 672 details
several factors the Commission will consider in determining whether a proposed
Reliability Standard is just and reasonable. One of the factors indicates that a
‘proposed Reliability Standard should be designed to apply throughout the
interconnected North American Bulk-Power System, to the maximum extent this
is achievable with a single Reliability Standard.’ Moreover, and particularly
compelling with respect to the definition of bulk electric system, Order No. 672
indicates that proposed Reliability Standards ‘should be clear and unambiguous
regarding what is required and who is required to comply.’ Eliminating broad
regional discretion without ERO or Commission oversight and maintaining a
100kV bright-line definition, coupled with an exemption process, removes any
ambiguity regarding who is required to comply and accomplishes the goal of
reducing inconsistencies across regions. Commenters have not provided
compelling evidence that the proposed definition should not apply to the United
States portion of the Western Interconnection as a threshold matter. . . .”
(Footnotes omitted.)
P. 144: “We expect that our decision to direct NERC to develop a uniform
modified definition of ‘bulk electric system’ will eliminate regional discretion and
ambiguity. The change will not significantly increase the scope of the present
definition, which applies to transmission, generation and interconnection
facilities.”
P 150:
“We disagree with commenters that definitions of ‘integrated
transmission elements’ and ‘material impact’ are needed to implement this Final
Rule. These terms are not defined by the present bulk electric system definition,
and defining these terms is not necessary to revise the definition as directed
herein. Whether specific facilities have a material impact is not dispositive with
respect to whether they are needed for reliable operation. These questions are
more appropriately addressed through development of an exemption process at
NERC.”
In Order No. 743-A, the Commission provided several clarifications to its directives and
technical concerns with respect to the definition of “Bulk Electric System.”
P 11: “We clarify that the specific issue the Commission directed the ERO to
rectify is the discretion the Regional Entities have under the current bulk electric
system definition to define the parameters of the bulk electric system in their
regions without any oversight from the Commission or NERC. As we explained
in the Final Rule, NPCC’s use of this discretion has resulted in an impact-based

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approach to defining the bulk electric system that allows significant subjectivity
in application and thus creates anomalous results. . . . [A]ny region could use its
discretion to define the bulk electric system in a way that leads to similar
inconsistent and anomalous results.” (Footnote omitted.)
P 22: “[W]e disagree with the NYPSC’s claim that the Final Rule implicitly
acknowledges that various non-jurisdictional facilities are included within the
Commission’s ‘redefinition’ of bulk electric system. As we clarify herein,
regardless of the 100 kV threshold, facilities that are determined to be local
distribution will be excluded from the bulk electric system.”
P 30: “[U]niformity, absent a showing that the alternative is more stringent or
necessitated by a physical difference, has been a hallmark of the mandatory
Reliability Standards construct since its inception. In establishing the framework
for developing Reliability Standards, we adopted the principle that proposed
Reliability Standards should be ‘designed to apply throughout the interconnected
North American Bulk-Power System, to the maximum extent this is achievable
with a single Reliability Standard.’ The same principle holds true for definitions
contained within the Reliability Standards.” (Footnote omitted.)
P 35-36: “[T]he Commission did not direct or mandate that the bulk electric
system definition include a bright-line 100 kV threshold.
Instead, the
Commission directed NERC to address the inconsistency, lack of oversight and
exclusion of facilities that are required for the reliable operation of the
interconnected transmission network, outlined by the Commission in Order No.
743 using the technical expertise available to NERC. The Commission suggested
that one means to address its concerns would be to, among other things, maintain
the 100 kV threshold and radial exclusion contained in the current definition, but
left it to NERC’s discretion and technical expertise to develop a revised
definition. . . . The Commission’s suggested solution of a 100 kV threshold paired
with an exemption process, in essence, merely clarifies the current NERC
definition, which classifies facilities operating at 100 kV or above as part of the
bulk electric system.”
P 57: “The Commission clarifies that our intent in requiring the ERO to
‘eliminate the regional discretion’ from the current definition was to prevent the
regions from modifying the regional bulk electric system definition without
Commission or ERO oversight.”
P 68: “The Commission clarifies that the statement in Order No. 743,
‘determining where the line between ‘transmission’ and ‘local distribution’ lies . .
. should be part of the exemption process the ERO develops’ was intended to
grant discretion to the ERO, as the entity with technical expertise, to develop
criteria to determine how to differentiate between local distribution and
transmission facilities in an objective, consistent, and transparent manner. This
mechanism will allow the ERO to maintain an inventory of the transmission

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facilities subject to the mandatory Reliability Standards, and to exclude local
distribution facilities from the bulk electric system definition by applying the
criteria.” (Footnote omitted.)
P 102: “The Commission clarifies that Order No. 743 did not intend to alter the
Registry Criteria, shift the evidentiary burden for registration, or otherwise
address matters involving the Registry Criteria. Indeed, the Statement of
Compliance Registry Criteria currently provides that the Regional Entities may
propose registration of entities that do not meet the registry criteria if the Regional
Entity believes and can reasonably demonstrate that the organization is a bulk
power system owner, or operates, or uses bulk power system assets, and is
material to the reliability of the bulk power system. However, we note that while
the Registry Criteria will not change, it is possible that additional facilities may
come under the revised definition and some entities may be required to register
for the first time.” (Footnote omitted.)
The Commission’s directives and technical and policy concerns with respect to the BES
Definition, as reflected in the above-quoted discussion from Order Nos. 743 and 743-A, may be
summarized as follows:
•

The BES Definition should provide for a consistent, uniform, objective nationwide
test to identity those facilities that are part of the BES, and eliminate ambiguity and
the potential for subjectivity in the application of the definition.

•

The BES Definition should provide for a distinct threshold criteria rather than a
“general guideline.”

•

Regional discretion in determining what facilities comprise the BES should be
eliminated, and application of the BES Definition should be overseen by NERC.

•

The BES Definition should identify those facilities that are necessary for reliably
operating the interconnected transmission network.

•

The BES Definition should exclude from the BES facilities used in the local
distribution of electricity.

•

The existing exclusion of radial facilities from the BES should be maintained, but
issues associated with the exclusion of radial facilities, such as the treatment of radial
facilities connected by a normally open switch, should be clarified.

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As shown in the discussion in the next section of this filing, the revised BES Definition
satisfies the Commission’s directives and technical and policy concerns articulated in Order Nos.
743 and 743-A.
C.

Discussion of Proposed Revised Definition of “Bulk Electric System”
NERC is requesting approval of the following revised definition of “Bulk Electric

System”:12
Bulk Electric System (BES): Unless modified by the lists shown below, all
Transmission Elements operated at 100 kV or higher and Real Power and
Reactive Power resources connected at 100 kV or higher. This does not include
facilities used in the local distribution of electric energy.
Inclusions:
•

I1 - Transformers with the primary terminal and at least one secondary
terminal operated at 100 kV or higher unless excluded under Exclusion E1 or
E3.

•

I2 - Generating resource(s) with gross individual nameplate rating greater than
20 MVA or gross plant/facility aggregate nameplate rating greater than 75
MVA including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above.

•

I3 - Blackstart Resources identified in the Transmission Operator’s restoration
plan.

•

I4 - Dispersed power producing resources with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacity, connected at a common point at a voltage
of 100 kV or above.

•

I5 –Static or dynamic devices (excluding generators) dedicated to supplying
or absorbing Reactive Power that are connected at 100 kV or higher, or
through a dedicated transformer with a high-side voltage of 100 kV or higher,
or through a transformer that is designated in Inclusion I1.

12

Capitalized terms used in the BES Definition are terms that are already defined in the NERC
Glossary. Those terms are: Balancing Authority, Blackstart Resources, Element, Flowgate,
Generator Operator, Generator Owner, Interconnection, Interconnection Reliability Operating
Limit (IROL), Load, Real Power, Reactive Power, Transmission, and Transmission Operator.

-13-

Exclusions:
•

E1 - Radial systems: A group of contiguous transmission Elements that
emanates from a single point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusion I3,
with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,
c) Where the radial system serves Load and includes generation
resources, not identified in Inclusion I3, with an aggregate capacity
of non-retail generation less than or equal to 75 MVA (gross
nameplate rating).
Note – A normally open switching device between radial systems, as depicted
on prints or one-line diagrams for example, does not affect this exclusion.

•

E2 - A generating unit or multiple generating units on the customer’s side of
the retail meter that serve all or part of the retail Load with electric energy if:
(i) the net capacity provided to the BES does not exceed 75 MVA, and (ii)
standby, back-up, and maintenance power services are provided to the
generating unit or multiple generating units or to the retail Load by a
Balancing Authority, or provided pursuant to a binding obligation with a
Generator Owner or Generator Operator, or under terms approved by the
applicable regulatory authority.

•

E3 - Local networks (LN): A group of contiguous transmission Elements
operated at or above 100 kV but less than 300 kV that distribute power to
Load rather than transfer bulk power across the interconnected system. LN’s
emanate from multiple points of connection at 100 kV or higher to improve
the level of service to retail customer Load and not to accommodate bulk
power transfer across the interconnected system. The LN is characterized by
all of the following:
a) Limits on connected generation: The LN and its underlying
Elements do not include generation resources identified in
Inclusion I3 and do not have an aggregate capacity of non-retail
generation greater than 75 MVA (gross nameplate rating);
b) Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain a

monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western
-14-

Interconnection, or a comparable monitored Facility in the ERCOT
or Quebec Interconnections, and is not a monitored Facility
included in an Interconnection Reliability Operating Limit (IROL).
•

E4 – Reactive Power devices owned and operated by the retail customer
solely for its own use.

Note - Elements may be included or excluded on a case-by-case basis through the
Rules of Procedure exception process.
As a starting point, the revised BES Definition deletes the phrase “As defined by the
Regional Reliability Organization” that is included in the current BES Definition. This deletion
eliminates the express basis for Regional discretion that is embedded in the current BES
Definition. Further, the revised BES Definition establishes a clear, bright-line definition of the
BES, based on the 100 kV threshold, with clearly-stated Inclusions and Exclusions that will
eliminate discretion in application of the revised BES Definition.
In the revised BES Definition, the “core” definition (the initial paragraph preceding the
Inclusions and Exclusions) establishes the fundamental threshold for inclusion of facilities in the
BES: that the facilities are operated at 100 kV or higher, if they are Transmission Elements,13 or
are connected at 100 kV or higher, if they are Real Power or Reactive Power resources.14 The

13

The current BES Definition includes "associated equipment," and the revised BES Definition
does not use that term; however, "associated equipment" remains encompassed by the revised
BES Definition through the defined term "Transmission Elements." The NERC Glossary defines
“Transmission” as, “An interconnected group of lines and associated equipment for the
movement or transfer of electric energy between points of supply and points at which it is
transformed for delivery to customers or is delivered to other electric systems;” and defines
“Elements” as, “Any electrical device with terminals that may be connected to other electrical
devices such as a generator, transformer, circuit breaker, bus section, or transmission line. An
element may be comprised of one or more components.”

14

The NERC Glossary defines Real Power as “The portion of electricity that supplies energy to
the load,” and defines Reactive Power as follows: “The portion of electricity that establishes and
sustains the electric and magnetic fields of alternating-current equipment. Reactive power must
be supplied to most types of magnetic equipment, such as motors and transformers. It also must
supply the reactive losses on transmission facilities. Reactive power is provided by generators,
-15-

core definition also states the 100 kV criterion as a bright-line threshold, rather than as a general
guideline as in the current definition (i.e., the phrase “generally operated at” in the current
definition is eliminated in the revised BES Definition). Further, the core definition retains the
phrase “operated at” [voltages of 100 kV or higher] found in the current BES Definition.15
Finally, the core definition, in its last sentence, expressly excludes “facilities used in the local
distribution of electric energy” from the BES, consistent with §215(a)(1)(B) of the FPA and the
Commission’s regulations at 18 C.F.R. §39.116 and as recognized in Order No. 743-A.17. Thus,
the core definition places within the BES all Transmission Elements operated at 100 kV or
above, and all Real Power and Reactive Power resources connected at 100 kV or above, while
establishing an express exclusion for facilities used in the local distribution of electrical energy.
The five Inclusions address five specific facilities configurations to provide clarity that
the facilities described in these configurations are included in the BES (unless the facilities are
excluded based on one of the specific Exclusions in the BES Definition), and thereby further
reduce the potential for the exercise of discretion and subjectivity to exclude such configurations
from the BES. The facilities described in Inclusions I1, I2, I4 and I5 are each operated (if
transformers – Inclusion I1) or connected (if generating resources, dispersed power producing

synchronous condensers, or electrostatic equipment such as capacitors and directly influences
electric system voltage. It is usually expressed in kilovars (kvar) or megavars (Mvar).”
15

See Order No. 743 at PP 53 and 75.

16

While both §215(a)(1) of the FPA and 18 C.F.R. §39.1 define “bulk-power system” rather than
“bulk electric system,” both provisions expressly exclude “facilities used in the local distribution
of electric energy.” Although the congruity between the “bulk-power system” and the “Bulk
Electric System” has not been resolved, there would be no basis, in light of these provisions, not
to exclude “facilities used in the local distribution of electric energy” from the BES Definition.
17

See Order No. 743A at P 22 (“regardless of the 100 kV threshold, facilities that are determined
to be local distribution will be excluded from the bulk electric system”) and P 68.

-16-

resources or Reactive Power resources – Inclusions I2, I4 and I5) at or above the 100 kV
threshold.

Inclusion I3 encompasses Blackstart Resources identified in a Transmission

Operator’s restoration plan, which are necessary for the Reliable Operation of the
interconnection transmission system and should be included in the BES regardless of their size
(MVA) or the voltage at which they are connected.18 The addition of the Inclusions to the BES
Definition will provide for consistency, and eliminate ambiguity, across all Regional Entities, as
all facilities meeting the criteria in the five Inclusions will be part of the BES.
Focusing on each of the individual Inclusions in detail, the five Inclusions were added to
the BES Definition based on the following considerations:
•

Inclusion I1 – Transformers operating at 100 kV or higher are part of the existing
definition, but since transformers have windings operating at different voltages, and
multiple windings in some circumstances, clarification was required to explicitly
identify which transformers are included in the BES. Inclusion I1 includes in the
BES those transformers operating at 100 kV or higher on the primary winding and at
least one secondary winding, so as to be in concert with the core definition.

•

Inclusion I2 – This inclusion mirrors the text of the NERC Statement of Compliance
Registry Criteria (Appendix 5B of the ROP) for generating units.19 A basic tenet that
was followed in developing the revised BES Definition was to avoid changes to
Registrations due to the revised BES Definition if such changes are not technically
required for the BES Definition to be complete.20 The SDT found no technical
rationale for changing at this time from the thresholds for generating resources
presently specified in the Statement of Compliance Registry Criteria. In order to
provide clarity on these conditions, the revised BES Definition specifies that the BES
includes the generator terminals through the high-side of the step-up transformer
connected at a voltage of 100 kV or above.

18

Blackstart Resources are defined in the NERC Glossary as: “A generating unit(s) and its
associated set of equipment which has the ability to be started without support from the System
or is designed to remain energized without connection to the remainder of the System, with the
ability to energize a bus, meeting the Transmission Operator’s restoration plan needs for real and
reactive power capability, frequency and voltage control, and that has been included in the
Transmission Operator’s restoration plan.” Under this Inclusion, both the generating unit and its
“associated set of equipment” are included in the BES.

19

See §III.c.1 and III.c.2 of Appendix 5B of the ROP.

20

This is consistent with the Commission’s clarification in P 102 of Order No. 743-A.
-17-

•

Inclusion I3 – Blackstart Resources are vital to the Reliable Operation of the BES.
Consequently, Blackstart Resources are included in the BES regardless of their size
(MVA) or the voltage at which they are connected. This inclusion is also consistent
with the Statement of Compliance Registry Criteria.21

•

Inclusion I4 – This inclusion was added to the BES Definition in order to
accommodate the effects of variable generation on the BES. The purpose of this
inclusion is to include variable generation (e.g., wind and solar resources). Although
this inclusion arguably could be considered subsumed in Inclusion I2 (because the
gross aggregate nameplate rating of the power producing resources must be greater
than 75 MVA), it was considered appropriate for clarity to add this separately-stated
inclusion in order to expressly cover dispersed power producing resources utilizing a
system designed primarily for aggregating capacity.

•

Inclusion I5 – This inclusion is the technical equivalent of Inclusion I2, for Reactive
Power devices. The existing BES Definition is unclear as to how these devices were
to be treated. Inclusion I5 addresses this lack of clarity by providing specific criteria
for Reactive Power devices, thereby further limiting subjectivity and the potential for
discretion in the application of the BES Definition.

Correspondingly, the four Exclusions identify facilities configurations that should not be
included in the BES. Exclusion E1 is the exclusion for radial systems. Order Nos. 743 and 743A made it abundantly clear that the BES Definition should exclude radial facilities from the
BES.22 This Exclusion provides detailed criteria for determining that facilities are properly
excluded from the BES as radial facilities, thereby enhancing the clarity of the radial facilities
exclusion.23 The radial exclusion is part of the existing BES Definition and was supported in the
work done on the topic prior to Order Nos. 743 and 743-A, as well as being specifically
supported by those Orders. Conditions (b) and (c) in Exclusion E1, pertaining to the maximum
21

See §III.c.3 of Appendix 5B of the ROP (“Any generator, regardless of size, that is a blackstart
unit material to and designated as part of a transmission operator entity’s restoration plan”).

22

See, Order No. 743 at PP 16, 30 and 55 and Order No. 743-A at P 35.

23

Exclusion E1 applies to “[a] group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher.” If the facilities emanate from a point of
connection less than 100 kV, they would not be part of the BES under the core BES Definition,
without the need to consider application of Exclusion E1.

-18-

amount of generation allowed on the radial facility while still qualifying for the radial facilities
exclusion (aggregate capacity less than or equal to 75 MVA), address the circumstances of small
utilities (including municipal utilities and cooperatives). The maximum amount of generation
allowed on the radial facility is sufficient to allow small utilities to continue to provide service
options that support reliability of the interconnected electric transmission system, while not
operating to exclude larger generators from the BES.24 The maximum amount of generation
allowed on the radial facility per Conditions (b) and (c) is consistent with the aggregate capacity
threshold presently provided in the Statement of Compliance Registry Criteria for registration as
a Generator Owner or Generator Operator (75 MVA gross nameplate rating).25
Exclusion E1 includes the note, “A normally open switching device between radial
systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.”
This note addresses a common network configuration that required clarification, in which two
separate sets of facilities that, each standing alone, would be recognized as radial systems and
not included in the BES, are connected by a “normally open switch” – i.e., a switch that is set to
the open position – for reliability purposes.
The concept and usage of the “normally open switch” in such configuration is well
understood in the electric utility industry. These switches are installed by entities to provide
greater reliability to their end-use customers. For example, scheduled maintenance activities on
a radial line, or an unscheduled outage impacting the single point of supply to the radial line,
could cause the disruption of power supply to the end-use customers served by the line, unless
the entity has the ability to switch over to another feed on a temporary basis. The entity’s
24

The interests of small utilities addressed in Conditions (b) and (c) of Exclusion E1 were
recognized in P 55 of Order No. 743.
25

See §III.c.2 of Appendix 5B.

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operating procedures dictate how and when to operate such a normally open switch. Operation
of the normally open switch placed in this configuration is not an arbitrary process, but rather is
driven by the objective of maintaining reliability of service to end-use customers served from the
radial line. Facilities that otherwise meet the criteria for the radial system exclusion should not
be included in the BES solely because the entity maintains a switch of this type, which is
normally open, between sets of radial facilities. Further, for a set of radial facilities that are
connected by a switch to qualify for the radial exclusion under Exclusion E1, the switch must be
identified as “normally open” on source documents such as, for example, prints or one-line
diagrams;26 and must in fact be normally set in the open position. An entity that claimed
exclusion of connected radial lines on the grounds that they were connected by a “normally open
switch,” but did not in fact maintain the switch in the open position except for the maintenance
or outage circumstances described above, would be untruthful and could be subject to serious
consequences when discovered.
In Order No. 743, the Commission stated that
While commenters would like to expand the scope of the term ‘radial’ to exclude
certain transmission facilities such as tap lines and secondary feeds via a normally
open line, we are not persuaded that such categorical exemption is warranted. For
example, when the normally “open” line is “closed,” it becomes part of the
transmission network and therefore should be subject to mandatory Reliability
Standards. . . . [We] direct the ERO to consider these comments regarding radial
facilities in crafting an exemption methodology.27
The concept that two sets of radial facilities that are normally unconnected to each other should
be subject to, and need to comply with, the Requirements of applicable Reliability Standards
during the limited time periods when they are connected by the closing of the normally open
26

Other example source documents could include diagrams displayed within an energy
management system or a SCADA system.
27

Order No. 743 at P 55.

-20-

switch in the maintenance-related or outage-related circumstances described above would be
fundamentally impractical and unworkable (from both the entity’s perspective and the ERO’s
perspective), and would misapprehend this very common, reliability-driven facilities
configuration. As noted, the connecting switch must be normally set in the open position to
qualify for Exclusion E1. Further, this configuration is so common that to write the BES
Definition to include radial systems connected by a normally open switch in the BES, with the
proviso that the owner(s) of the facilities can request an Exception, would undoubtedly result in a
veritable flood of Exception Requests.
Moreover, the SDT extensively considered the reliability issues associated with tap lines
and tapped facilities feeding separate radial systems and concluded that the real reliability issue
associated with these facilities is the coordination of the respective transmission Protection
Systems for the transmission facilities feeding the radial systems. However, this reliability issue
is adequately addressed by the Requirements of the Protection and Control Reliability Standards,
including in particular PRC-001, without providing for the inclusion of these facilities in the
BES in the revised BES Definition.
Therefore, based on the above-described considerations, the SDT concluded, and NERC
agrees, that this configuration would be more appropriately addressed in the BES Definition,
through a specific exclusion (Exclusion E1), rather than through the Exception process.
Exclusion E2 excludes from the BES a generating unit or units on the customer’s side of
the retail meter that serves all or part of the retail Load, so long as the following two conditions
are met: (i) the net capacity provided by the generating unit(s) to the BES does not exceed 75
MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating
unit(s) or the retail Load by a Balancing Authority, or pursuant to a binding obligation with a

-21-

Generator Owner or Generator Operator, or under terms approved by the applicable regulatory
authority. Under these circumstances, the generating unit(s) are not necessary for the Reliable
Operation of the interconnected transmission system, and therefore do not need to be included in
the BES, because they serve a single retail Load, provide a limited amount of capacity to the
BES, and are fully backed up by other resources. The wording of Exclusion E2 is extracted from
the Statement of Compliance Registry Criteria.28
Exclusion E3, the “local network” exclusion, encompasses local networks of transmission
Elements operated at between 100 kV and 300 kV that distribute power to Load rather than
transfer bulk power across the interconnected system. Local networks provide local electrical
distribution service and are not planned, designed or operated to benefit or support the balance of
the interconnected transmission network. The purpose of local networks is to provide local
distribution service, not to provide transfer capacity for the interconnected transmission network.
The design and operation of local networks is such that at the point of connection with the
interconnected transmission network, the effect of the local network on the interconnected
transmission network is similar to that of a radial facility, in particular that flow always moves in
a direction from the interconnected transmission network into the local network. A network that
simply supports distribution and does not accommodate bulk power transfers across the
interconnected system should not be included in the BES. Exclusion E3 provides detailed
criteria for determining that facilities, although operated at or above 100 kV, comprise a local
network and therefore are not part of the BES. These criteria are that:
•

28

the local network and its underlying Elements include limited non-retail generation;

See the second exclusion following §III.c.4 in Appendix 5B of the ROP.

-22-

•

power flows only into the local network and it does not transfer energy originating
outside the local network for delivery through the local network; and

•

the facilities are not part of a Flowgate or transfer path.29

The detailed conditions established in Exclusion E3 are sufficient to ensure that such qualifying
local networks are being used exclusively for local distribution purposes.
Exhibit G is a technical justification paper for the local network exclusion. As discussed
in greater detail in the technical justification paper, the local network exclusion is justified by the
following factors:
1. Facilities used in the local distribution of electric energy are to be excluded from the
BES.
2. The exclusion for local networks ensures that a candidate for this exclusion must
satisfy all of the criteria for this exclusion, thereby demonstrating that the candidate
facilities are not performing a transmission function.
3. The limit on connected generation within the local network is consistent with the
existing threshold above which a generating plant in aggregate becomes subject to
Registration under the NERC Statement of Compliance Registry Criteria.
4. The voltage cap applied to the criteria for the local network exclusion, 300 kV, is
consistent with the distinction between Extra High Voltage (“EHV”) and High
Voltage in Reliability Standard TPL-001-2 on transmission planning as approved by
the NERC Board of Trustees on August 4, 2011.30 Use of the 300 kV voltage cap
ensures that the local network exclusion cannot be used to exclude EHV facilities,
which under TPL-001-2 are held to a higher standard of performance, from the BES.

29

Flowgate is defined in the NERC Glossary as: “(1) A portion of the Transmission system
through which the Interchange Distribution Calculator calculates the power flow from
Interchange Transactions, and (2) a mathematical construct, comprised of one or more monitored
transmission Facilities and optionally one or more contingency Facilities, used to analyze the
impact of power flows upon the Bulk Electric System.”
30

TPL-001-2 was filed with the Commission for approval on October 19, 2011. Petition of the
North American Electric Reliability Corporation for Approval of a Revised Transmission
Planning System Performance Requirements Reliability Standard and Five New Glossary Terms
and for Retirement of Four Existing Reliability Standards, Docket No. RM12-1-000 (October 19,
2011).

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5. The power flow shifts that would occur on the Elements of a local network are a
negligible fraction of that which distributes upon the BES Elements for a given power
transfer, and is fully eclipsed by the Load in the local network.
6. The interaction of a local network with the BES is similar in character to that of a
radial facility.
Finally, Exclusion E4 encompasses Reactive Power devices owned and operated by a
retail customer solely for its own use. Exclusion E4 is the technical equivalent of Exclusion E2
for Reactive Power devices. The existing BES Definition is unclear as to how these devices are
to be treated; the revised BES Definition provides specific criteria for Reactive Power devices, in
Exclusion E4.
The revised BES Definition satisfies the Commission’s directives and addresses its
technical and policy concerns as expressed in Order Nos. 743 and 743-A. The explicit basis of
authority for Regional Entity discretion in the current definition is eliminated.

The core

definition establishes the specific threshold criteria (rather than a general guideline) of facilities
operated (Transmission Elements) or connected (Real Power or Reactive Power resources) at or
above 100 kV, and this threshold value is recognized in the specific facilities configurations
described in Inclusions I1, I2, I4 and I5. The core definition in combination with the specific
Inclusions and Exclusions provides a detailed set of criteria that can be applied on a uniform,
consistent basis across all Regional Entities, eliminates ambiguity, and eliminates the potential
for discretion and subjectivity in determining what facilities are part of or not part of the BES.
Blackstart Resources, which are necessary for the Reliable Operation of the interconnected
transmission system even if they are operated or connected below 100 kV, are expressly included
in the BES. Facilities for the local distribution of electric energy are expressly excluded from the
BES by the core definition as well as by Exclusion E3 (local networks). The exclusion for radial
facilities is maintained, but with more specific, detailed criteria provided for determining what

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facilities are radial facilities. Specifically-defined behind-the-meter generating resources and
Reactive Power devices are also excluded from the BES.
Additionally, in terms of the Commission’s directives and concerns for consistency and
the elimination of Regional Entity discretion and subjectivity in determining what facilities
comprise the BES, NERC calls the Commission’s attention to the proposed BES Exception
Procedure, Appendix 5C to the ROP, which is being submitted for the Commission’s approval in
a separate, contemporaneous filing. Under the proposed BES Exception Procedure, the Regional
Entities will conduct initial screenings of Exception Requests emanating from their Regions, and
will make Recommendations to NERC as to whether an Exception Request should be approved
or disapproved. However, the Regional Entities will not actually make the decisions to approve
or disapprove Exception Requests. All decisions to approve or disapprove Exception Requests
will be made by NERC in accordance with the processes and procedures specified in proposed
Appendix 5C.
In summary, the revised BES Definition provides a detailed, objective set of criteria that
can be applied consistently and uniformly on a nationwide basis to identify those facilities that
are necessary for the Reliable Operation of the interconnected transmission system, as well as
those facilities that are not.

The revised BES Definition is just, reasonable, not unduly

discriminatory or preferential, and in the public interest, and fully addresses the Commission’s
directives and technical and policy concerns as detailed in Order Nos. 743 and 743-A. The
revised BES Definition should be approved by the Commission.
D.

Detailed Information to Support an Exception Request
In addition to developing a revised BES Definition, the SDT for Project 2010-17 was

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assigned the task of developing a set of technical criteria to support a BES Exception Request.31
Based on discussions among the NERC Standards Committee, NERC Reliability Standards
program management, the SDT for the BES Definition, and the team that was formed to develop
the BES Exception Procedure for the ROP (“BES ROP Team”), this task was assigned to the
SDT (as opposed to being assigned to the BES ROP Team) so that the Reliability Standards
development process would be followed in the development and establishment of the technical
criteria.
Thereafter (as discussed in greater detail in §IV.A and IV.B below), the SDT determined
that it was more feasible to develop a common set of data and information that could be used by
the Regional Entities and NERC to evaluate and decide Exception Requests. A Submitting
Entity would be required to submit the common data and information with the Exception
Request, for use by the applicable Regional Entity and NERC in evaluating the Exception
Request. The set of common data and information, captioned “Detailed Information to Support
an Exception Request,” was separated into data and information applicable to transmission
entities and data and information applicable to generation entities. The Detailed Information to
Support an Exception Request was balloted in the recirculation ballot for the BES Definition
and, as described in greater detail in §IV.D below, achieved the necessary quorum of the ballot
pool and two-thirds weighted Segment approval. The full text of the Detailed Information to
Submit an Exception Request is provided in Exhibit C to this Petition.
Under the proposed BES Exception Procedure, Appendix 5C to the ROP, which is being
submitted to the Commission for approval in a separate, contemporaneous filing, the Detailed
31

In P 115 of Order No. 743, the Commission stated that “NERC should develop an exemption
process that includes clear, objective, transparent, and uniformly applicable criteria for
exemption of facilities that are not necessary for operating the grid.”

-26-

Information to Submit an Exception Request is to be provided by the Submitting Entity as the
Section III Required Information required by the Exception Request Form. Section 4.5.3 of
proposed Appendix 5C states that “Section III of an Exception Request shall contain the
Detailed Information to Support an Exception Request as specified on the Exception Request
Form” (emphasis in original). Further, section 2.12 of proposed Appendix 5C states that “the
Exception Request Form must include Section III.B as adopted by NERC.”32
The Detailed Information to Support an Exception Request, Section III.B of the
Exception Request Form, specifies that the following information must be included in all
Exception Requests:
A one-line breaker diagram identifying the Element(s) for which the exception is
requested must be supplied with every request. The diagram(s) supplied should
also show the Protection Systems at the interface points associated with the
Elements for which the exception is being requested.
Additionally, the Detailed Information to Support an Exception Request specifies that “Entities
are required to supply the data and studies needed to support their submittal,” and provides the
following specifications for studies:
•

Studies should be based on an Interconnection-wide base case that is suitably
complete and detailed to reflect the electrical characteristics and system topology.

•

Studies should clearly document all assumptions used.

•

Studies should address key performance measures of BES reliability through steadystate power flow, and transient stability analysis as necessary to support the entity’s

32

The information that the Submitting Entity may submit, or may be asked by the Regional
Entity and NERC to submit, in support of an Exception Request will not be limited to the
Detailed Information to Support an Exception Request. The Submitting Entity will be expected
to submit all relevant data, studies and other information that supports its Exception Request, and
the Regional Entity and NERC may ask the Submitting Entity to provide other data, studies and
information in addition to the Detailed Information to Support an Exception Request and the
other information included by the Submitting Entity in the Exception Request.

-27-

request, consistent with the methodologies described in the Transmission Planning
(TPL) standard and commensurate with the scope of the request.
The Detailed Information to Support an Exception Request then provides separate sets of
questions applicable to Transmission Elements and to generation resources. The questions for
Exception Requests pertaining to Transmission Elements are:
1. Is there generation connected to the Element(s)?
If yes, what are the individual gross nameplate values of each unit?
2. How do/does the Element(s) impact permanent Flowgates in the Eastern
Interconnection, major transfer paths within the Western Interconnection, or a
comparable monitored facility in the ERCOT Interconnection or the Quebec
Interconnection?
Please list the Flowgates or paths considered in your analysis along with any
studies or assessments that illustrate the degree of impact.
3. Is/Are the Element(s) included in an Interconnection Reliability Operating
Limit (IROL) in the Eastern Interconnection, ERCOT Interconnection, or
Quebec Interconnection or a major transfer path rating in the Western
Interconnection?
Please provide the appropriate list for the operating area where the Element(s)
is located.
4. How does an outage of the Element(s) impact the over-all reliability of the
BES?
Please provide study results that demonstrate the most severe system impact
of the outage of the Element(s) and the rationale for your response.
5. Is/Are the Element(s) used for off-site power supply to a nuclear power plant
as designated in a mutually agreed upon Nuclear Plant Interface Requirement
(NPIR)?
6. Is/Are the Element(s) part of a Cranking Path identified in a Transmission
Operator’s restoration plan?
7. Does power flow through the Element(s) into the BES?
If yes, then using metered or SCADA data for the most recent consecutive two
calendar year period, what is the minimum and maximum magnitude of the
power flow out of the Element(s)?
Describe the conditions and the time duration when this occurs?
The questions for Exception Requests pertaining to generation resources are:

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1. What is the MW value of the host Balancing Authority’s most severe single
Contingency and what is the generation resources percent of this value?
Please provide the values and a reference to supporting documents.
2. Is the generation resource used to provide reliability-related Ancillary
Services?
If so, what reliability-related Ancillary Services are the generation resource
supplying?
3. Is the generation resource designated as a must run unit for reliability?
Please provide the appropriate reference for your operating area?
4. How does an outage of the generation resource impact the over-all reliability
of the BES?
Please provide study results that demonstrate the most severe system impact
of the outage of the generator and the rationale for your response.
5. Does the generation resource use the BES to deliver its actual or scheduled
output, or a portion of its actual or scheduled output, to Load?
Two of the overriding directives in Order No. 743 were that (1) the revised BES
Definition should identify all facilities necessary for operating an interconnected electric energy
transmission network, and (2) the exemption process should identify and exclude facilities that
are not necessary for operating the interconnected transmission network.33 The SDT initially
attempted to develop a set of technical criteria for determining whether or not the Elements that
are the subject of an Exception Request are necessary for operating the interconnected
transmission network. However, the SDT concluded that it was infeasible to develop a single set
of criteria that would be applicable to the wide variety of configurations and circumstances likely
to be presented by a broad range of Exception Requests. The SDT therefore determined that the
more appropriate approach was to develop a detailed set of data and information that can be used
by the Regional Entity and NERC in evaluating whether or not the Elements that are the subject

33

See, e.g., Order No. 743 at PP 16 and 30.

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of an Exception Request are necessary for reliably operating the interconnected transmission
network.
The Detailed Information to Support an Information Request in fact requires the
Submitting Entity to provide specific data and information that can be used by the Regional
Entity and NERC in evaluating whether or not the Elements that are the subject of an Exception
Request are necessary for reliably operating the interconnected transmission network. Requiring
the submission of the Detailed Information to Support an Exception Request is intended to
ensure that a consistent baseline of technical information is provided with all Exception
Requests, in addition to the specific information and arguments provided by the Submitting
Entity in support of its Exception Request. The Submitting Entity remains responsible to present
sufficient information and argument to justify the Exception Request.34 Further, several of the
questions and information requirements in the Detailed Information to Support an Exception
Request parallel components of one or more Inclusions or Exclusions in the BES Definition and
will enable the Regional Entity and NERC to verify that no applicable Inclusions or Exclusions
have been overlooked.
The specific questions posed were created by the SDT with the intention of having the
responses to the body of questions in a specific section (transmission or generation) complement
the general information required for Exception Requests, thereby creating a “big picture”
concept while also providing the specific technical analysis which addresses the potential
reliability benefit of the Element in question. The availability of this information will allow the
34

Section 3.2, Burden, in the proposed BES Exception Procedure (which is being filed with the
Commission for approval in a separate petition contemporaneously with this Petition) states in
part: “The burden to provide a sufficient basis for Approval of an Exception Request in
accordance with the provisions of this Exception Procedure is on the Submitting Entity . . . . All
evidence provided as part of an Exception Request or response will be considered in determining
whether an Exception Request shall be approved or disapproved.”

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Regional Entity and NERC review panels to utilize their technical expertise by exercising sound
engineering judgment to provide informed recommendations on whether or not the Element in
question is necessary for reliably operating the interconnected transmission network and
therefore should be included in or excluded from the BES. The breadth of industry coverage and
technical experience and backgrounds among the SDT members came into play in developing
the Detailed Information to Support an Exception Request. The questions to be included in the
Detailed Information were debated at length to arrive at the set of information that would be
needed by the review panels and, ultimately, to reach a decision on the Exception Request, but
with consideration given to the burden that would be placed on the Submitting Entity in
compiling, and the Regional Entity and NERC in reviewing, an extensive amount of technical
information. The SDT attempted to create a balance in order to produce a set of data and
information that would provide sufficient information for the Regional Entity to make a
technically appropriate Recommendation and for NERC to make a technically appropriate
determination, without overwhelming the review panels and decision makers with unnecessary
data.
In order to test whether these objectives were achieved, a number of SDT members
conducted “dry runs” compiling the Detailed Information to Support an Exception Request using
Elements on their own organizations’ systems. The SDT members reported their experiences
and observations with the test runs to the full SDT, and this experience was used in refining the
list of questions for the Detailed Information to support an Exception Request.
Thereafter, the draft Detailed Information to Support an Exception Request was posted
for industry review and comment. The SDT considered the comments that were received from

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industry, and made a number of changes, before submitting the Detailed Information to Support
an Exception Request for industry approval through balloting by the ballot pool.35
The development of the Detailed Information to Support an Exception Request, which
must be provided with every Exception Request, represents an equal and effective alternative
approach to developing a substantive set of technical criteria for granting and rejecting Exception
Requests. The Detailed Information to Support an Exception Request encompasses a wide range
of potential configurations and will provide useful information for the Regional Entity and
NERC in evaluating and deciding Exception Requests. The Commission should approve the
Detailed Information to Support an Exception Request in Exhibit C as satisfying the
Commission’s technical concerns expressed in Order No. 743 with respect to the need for criteria
to approve or disapprove Exception Requests.
E.

Proposed Implementation Plan for Revised Definition of “Bulk Electric System”
In Order No. 743, the Commission addressed the need to allow a Regional Entity to

submit a transition plan that “allows a reasonable period of time for affected entities within that
region to achieve compliance with respect to facilities that are subject to Commission-approved
Reliability Standards for the first time.”36 The Commission stated:
131. . . . We direct NERC to work with the Regional Entities affected by this
Final Rule to submit for Commission approval transition plans that allow a
reasonable period of time for the affected entities within each region to achieve
compliance with respect to facilities that are subject to Commission-approved
Reliability Standards for the first time based on a revised bulk electric system
definition. The Commission expects that NPCC is the only region that will be
significantly affected. Based on ReliabilityFirst’s experience in adopting a
35

Because the Detailed Information to Support an Exception Request was developed and
adopted using the Reliability Standards development process, in the future, revisions will be
made using the Reliability Standards development process, including industry balloting, rather
than using NERC’s process for amending the ROP.
36

Order No. 743 at P 122 (footnote omitted).

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“bright-line” definition for bulk electric system facilities, we expect transition
periods not to exceed 18 months from the time the Commission approves a
revised definition and exemption process, unless the Commission approves a
longer transition period based on specific justification. The Commission directs
NERC to file the proposed transition plans within one year of the effective date of
the Final Rule.
132. While the Commission is sensitive to commenters’ concerns regarding
non-compliance during the transition period, the Commission will not provide a
trial period, as we declined to do in Order No. 693, with respect to those facilities
that are subject to Commission approved Reliability Standards for the first time.
We expect that the transition periods will be long enough for exemption requests
to be processed and to allow entities to bring newly-included facilities into
compliance prior to the mandatory enforcement date. Additionally, the ERO and
Regional Entities may exercise their enforcement discretion during the transition
periods. (Footnote omitted.)37
Further, in Order No. 743-A, the Commission again addressed the need for and length of a
transition period:
93.
. . . [A]s indicated in Order No. 743, “we expect that the transition periods
will be long enough for exemption requests to be processed and to allow entities
to bring newly-included facilities into compliance prior to the mandatory
enforcement date.” We reiterate that we do not expect a large number of
exemption requests arising outside NPCC. Thus, our expectation remains that
NERC should be able to process any exemption requests in a timely manner,
allowing any entity denied an exemption to come into compliance with the
relevant reliability Standards within the transition period. (Footnotes omitted.)
94.
With respect to the length of the transition period, as discussed in the Final
Rule, we based our determination to establish an 18-month transition period on
ReliabilityFirst’s prior experience in adopting a revised bulk electric system
definition in that region, and continue to believe it is a reasonable transition
period. Additionally, we noted that the ERO may request a longer transition
period based on a specific justification. This provides sufficient flexibility should
the ERO determine that the 18-month transition period is insufficient. (Footnote
omitted.)38
The SDT for the BES Definition concluded that the revised BES Definition should be
effective on the first day of the second calendar quarter after receiving applicable regulatory
37

Order No. 743 at PP 131-132 (footnote omitted).

38

Order No. 743-A at PP 93-94.

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approval, or, in those jurisdictions where no regulatory approval is required, the revised BES
Definition should go into effect on the first day of the second calendar quarter after its adoption
by the NERC Board. The existing definition of the BES would be retired at midnight of the day
immediately prior to the effective date of the revised BES Definition in the jurisdiction in which
the revised BES Definition is becoming effective. The proposed effective date is appropriate in
order to provide a reasonable time between the date of regulatory approval, which is not under
the control of NERC or the industry, and the effective date of the revised BES Definition.39
The SDT further concluded that compliance obligations for all Elements newly-identified
to be included in the BES based on the revised BES Definition should begin 24 months after the
applicable effective date of the revised BES Definition. That is, the mandatory enforcement date
for the Reliability Standard Requirements that have become applicable to Facilities and Elements
that are newly-included in the BES due to the revised BES Definition, and to the owners and
operators of those Facilities and Elements, will be 24 months after the effective date of the
revised BES Definition.
The proposed implementation plan was balloted with the recirculation ballot for the
revised BES Definition and, as described in greater detail in §IV.D below, the ballot achieved the
required quorum and the necessary weighted Segment approval. The NERC Board approved
both the proposed effective date and the proposed date by which owners of newly-included
Facilities and Elements must be in compliance with applicable Requirements of Reliability
Standards.
39

For example, if the revised BES Definition were approved by the Commission at its June 2012
meeting, and the effective date were the first day of the first calendar quarter following approval
(July 1, 2012), the industry would have only a few weeks before the new BES Definition became
effective. With the proposed effective date, the new BES Definition would be effective on
October 1, 2012 in this example.

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Although the Commission stated in Order Nos. 743 and 743-A that the transition period
should not exceed 18 months from the date of Commission approval of the revised Definition,
unless the Commission approved a longer transition period based on specific justification, the
SDT determined, and the industry ballot pool and the NERC Board agreed, that a somewhat
longer transition period is necessary in light of the actions that will need to be completed in
connection with the revised BES Definition. In the U.S., the proposed transition period will be
between a minimum of approximately 27 months and a maximum of 30 months from the date of
Commission approval, depending on the date of Commission approval.40 The reasons supporting
the need for this longer transition period, as articulated by the SDT, include the following:
•

Sufficient time is needed to implement transition plans in order to accommodate any
changes resulting from the revised BES Definition. As discussed below, and as
suggested in Order Nos. 743 and 743-A, only NPCC has identified the need for, and
developed, a specific transition plan. The other Regional Entities will implement the
revised BES Definition and the proposed BES Exception Procedure, and will adhere
to the proposed transition period, but they do not expect an extensive amount of
additional facilities to be included in the BES as the result of the revised BES
Definition.41 Nevertheless, the effective date of the revised BES Definition, and the
subsequent mandatory enforcement date on which owners of newly-included

40

In the example given in the preceding footnote, if Commission approval occurred in June
2012, the transition period would be slightly more than 27 months (i.e., the effective date would
be October 1, 2012 and newly-included Facilities and Elements would need to be compliant with
applicable Reliability Standards by October 1, 2014). To vary the example, if Commission
approval occurred in July 2012, the transition period would be slightly less than 30 months (i.e.,
the effective date would be January 1, 2013 and newly-included Facilities and Elements would
need to be compliant with applicable Reliability Standards by January 1, 2015).

41

This expectation is consistent with the Commission’s expectation as stated in Order No. 743,
at P 131.

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Facilities and Elements are required to be compliant with applicable Reliability
Standards, need to be consistent across all Regions.
•

Sufficient time is needed to identify and implement any Registration changes
resulting from the revised BES Definition, in particular new Registrations of entities
owning Facilities and Elements, and revised Registrations of existing Registered
Entities owning additional Facilities and Elements, that are identified as included in
the BES based on the revised BES Definition.

•

Sufficient time is needed for entities to file for Exceptions, and for the Regional
Entities and NERC to process those Exceptions to a final determination, pursuant to
the proposed BES Exception Procedure. These Exception Requests will include both
requests that Facilities and Elements that are included in the BES by the revised BES
Definition should be excluded from the BES, and requests that Facilities and
Elements that are not included in the BES by the revised BES Definition should be
included in the BES. At this time, NERC and the Regional Entities do not have a
basis for estimating the numbers of Exception Requests that will be submitted or their
complexity, and therefore cannot estimate the time and resources that will be required
to process them to completion. Therefore, it is prudent to provide for a somewhat
longer transition period so as to increase the likelihood that all Exception Requests
can be processed to completion so as (i) to allow owners of newly-included Facilities
and Elements time to be compliant with applicable Reliability Standards, and (ii)
avoid the need for owners whose Exclusion Exceptions are approved to expend
resources on compliance that may prove to be unnecessary.

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•

Finally, sufficient time must be provided for owners of Facilities and Elements that
are newly-included in the BES based on the revised BES Definition to train their
personnel on compliance with the Reliability Standards applicable to the newlyincluded Facilities and Elements, so that these entities can in fact achieve compliance
with applicable Reliability Standards by the end of the transition period.

It was not the intent nor the expectation of either the SDT or NERC to either expand or
reduce the scope of the BES, or (with the likely exception of the NPCC Region) to increase or
decrease the numbers of Elements included in the BES, through the revised BES Definition as
compared to the current BES Definition.42 Nonetheless, there is not a specific basis to determine
to what extent Elements currently included in the BES will become not included, nor to what
extent Elements currently not included in the BES will no longer be included, until the revised
BES Definition becomes effective and entities begin to apply it to their facilities. Nor is there
currently a basis to determine the numbers of Exception Requests that will be submitted, and
need to be processed, as entities begin to determine whether facilities are included in or excluded
from the BES by application of the revised BES Definition. NERC has reviewed the anticipated
requirements and activities for implementation of the revised BES Definition with the eight
Regional Entities. Although, as noted, there currently is not a basis for estimating the numbers
of Exception Requests that will be submitted, none of the Regional Entities believes that it will
42

As part of its work, the SDT did conduct a detailed and systematic review of the Applicability
sections of all Reliability Standards that are currently in effect, pending for approval at FERC, or
under development in standard development projects, to ascertain whether revisions to any
Applicability sections would be needed based on the revised BES Definition. The SDT
determined that no revisions to any Applicability sections would be needed. The SDT also
reviewed all existing terms and definitions in the NERC Glossary that refer to the Bulk Electric
System, to ascertain if changes to these definitions would be needed based on the revised BES
Definition. The SDT determined that no changes to any of these existing definitions in the
NERC Glossary would be needed.

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require a longer transition period than the transition period proposed by the SDT, balloted by the
industry and approved by the NERC Board. As indicated above, only NPCC has seen the need
to develop a specific transition plan. The other Regional Entities do not expect an extensive
amount of newly-included facilities, and therefore do not expect extensive implementation
activities; as a result, they may not need to follow the steps outlined by NPCC. For these
reasons, there is not a need for the other Regional Entities to develop and submit separate
individual transition plans. However, if circumstances prove to be different than anticipated, a
Regional Entity can revisit its initial decision and formulate a detailed plan in response to actual
conditions.
NERC believes that the transition plan steps as outlined below are generally appropriate.
The objectives of the transition plan are (1) to identify BES Facilities and Elements in the Region
based on the revised BES Definition, and register the owners of those Facilities and Elements if
they are not already registered, or revise their registrations if necessary to reflect the newlyincluded and excluded Facilities and Elements; (2) to identify those newly-included BES
Facilities and Elements that are not currently compliant, or whose owners are not currently
compliant, with applicable Reliability Standards; and (3) to identify specific actions that are
necessary to bring newly-included BES Facilities and Elements, and their owners, that are not in
compliance with applicable Reliability Standards into compliance by the end of the transition
period. The transition plan will include the following specific steps:
Step 1: Identify a Comprehensive List of BES Facilities and Elements
Each U.S. asset owner will be expected to apply the revised BES Definition to all
facilities to determine if those facilities are included in the BES pursuant to the revised
BES Definition. This analysis should identify facilities that (i) should be included in the

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BES or (ii) can be excluded from the BES, based on the revised BES Definition. The
analysis should also identify any Exception Requests that the owner intends to submit.
This analysis will allow the owner to identify those facilities that need to be added to its
Facilities and Elements already included in the BES. A gap analysis (Step 2 below) will
then be performed on the newly-included Facilities and Elements.
Step 2: Perform a Gap Analysis
Each U.S. asset owner and each Functional Entity owning or operating Facilities and
Elements that have been newly-identified for inclusion in the BES will be expected to
perform a gap analysis for both (i) Registration (and Certification, if applicable) and (ii)
compliance with applicable Reliability Standards. The gap analysis should identify (i)
any additional Registrations and/or Certifications that are required due to the newlyincluded Facilities and Elements (e.g., reliability functions for which the entity is not
currently registered on the Compliance Registry but should be registered based on the
newly-included Facilities and Elements), and (ii) additional compliance obligations for
the entity, i.e., the applicable Requirements of Reliability Standards with which the entity
must now become compliant due to the inclusion of the new Facilities and Elements in
the BES.
Step 3: Develop Implementation Plans
An entity with newly-included Facilities or Elements may need to develop a Registration
implementation plan (which may include the need for Certification or a revision to an
existing Certification), a compliance implementation plan, or both. In either case, the
entity should submit its implementation plan(s) to the applicable Regional Entity for
review and concurrence. The implementation plans should be structured so that they can

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be nominally completed by, or prior to, the end of the transition period (i.e., by the date
by which newly-included Facilities and Elements, and their owners, must be compliant
with applicable Reliability Standards). The Regional Entity may approve exceptions to
this deadline for specific Facilities and Elements, and their owners, for which the
implementation plan identifies, and the Regional Entity concurs in, a need for a longer
amount of time to achieve compliance.
Step 3a: Develop Registration Implementation Plan
A Registration plan for impacted entities will be developed, in coordination with
other impacted entities (e.g., Transmission Owners and/or Transmission
Operators with Balancing Authorities) and in consultation with the Regional
Entity, to determine the new, additional or modified Registrations required due to
implementation of the revised BES Definition. The Registration implementation
plan should identify any new Registrations associated with the newly-included
Facilities and Elements. For Facilities and Elements that are newly-included in
the BES as a result of the revised BES Definition, the Registration
implementation plan must identify what Registered Entity or Registered Entities
will be responsible for performing each of the reliability functions required by the
Reliability Standards that are applicable to the newly-included Facilities and
Elements. The Registration implementation plan should identify whether any
new or modified Joint Registration Organization agreements, Coordinated
Functional Registrations, or other contractual arrangements will be entered into
with respect to the newly-included Facilities and Elements.

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The Registration implementation plan should also take into account any
Certification requirements (i.e., Certification of the entity to perform a new
reliability function that requires Certification, or Certification of the entity to
perform an existing reliability function in an expanded Footprint) and any
preparation and Certification Team reviews needed for entities that will require
new or amended Certifications. The Registration implementation plan should
identify any instances in which it is anticipated that achieving Certification will
require an amount of time longer than the time remaining to the end of the
transition period.
NERC and the Regional Entities will work to register entities who become
required to register based on application of the revised BES Definition, and to
modify existing Registrations that are necessary based on the revised BES
Definition, promptly after the need for the new or modified Registration is
identified, and will encourage entities that identify the need to register or to
modify existing Registrations to do so promptly. NERC and the Regional Entities
recognize that Registration may result in the entity, at the time of Registration,
being not in compliance with newly-applicable Reliability Standards.

The

entity’s compliance implementation plan, discussed below in Step 3b, should
detail the actions the entity will take, and the time period required, to come into
compliance with the Requirements of Reliability Standards that become
applicable to the entity and to newly-included Facilities and Elements due to the
revised BES Definition.
Step 3b: Develop a Compliance Implementation Plan

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A compliance implementation plan should be developed for each newly-included
Facility or Element, and its owner and operator, identified in the gap analysis as
not currently in compliance with applicable Reliability Standards, detailing the
actions to be taken to bring the Facility or Element, and its owner and operator,
into compliance.

The compliance implementation plan should reflect all

applicable existing or newly-required Registrations (e.g., new registered
functions). The compliance implementation plan should identify both (1) all
newly-included Facilities and Elements, based on the revised BES Definition, for
which the owner is not initially compliant with applicable Reliability Standard
Requirements and therefore requires time to achieve compliance with those
Requirements, and (2) all situations in which the entity is required to register for
the first time, or to register for new reliability functions, based on the revised BES
Definition, and the Reliability Standard Requirements with which the entity must
come into compliance due to the new or modified Registration. The compliance
implementation plans should identify activities the entity needs to perform to
achieve compliance, including training its personnel in the Requirements of
newly-applicable Reliability Standards and the time required, or milestone dates,
for these activities.

The compliance implementation plan should specifically

identify those newly-included Facilities and Elements, and those new or modified
Registrations, for which the entity projects that a time period longer than the time
to the end of the transition period will be needed to achieve compliance with
applicable Reliability Standards.

As noted earlier, the extension of the

completion of compliance activities beyond the end of the transition period (i.e.,

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beyond 24 months after the effective date of the revised BES Definition) will
require concurrence of the Regional Entity.
Step 4: Complete Implementation Plans and Certify Completion
The actions required by the implementation plans will nominally have to be completed by
the end of the transition period, except for specific Facilities and Elements for which the
implementation plan identifies, with Regional Entity approval, the need for a longer time
period. Each entity that adopted a Registration implementation plan or a compliance
implementation plan should, upon completion of the activities described in the plan,
provide a statement of completion to the applicable Regional Entity.43
NERC and Regional Entity Resource Requirements
In their 2012 Business Plans and Budgets, the Regional Entities and NERC did not
provide for specific, incremental resources to perform incremental work that could result from
the revised BES Definition (including processing Exception Requests). Specific incremental
resources were not budgeted because (1) the business plan and budget preparation cycle requires
the Regional Entities and NERC to have their proposed business plans and budgets essentially
completed by late June or early July of the preceding year; (2) as of mid-year 2011, the revised
BES Definition and the proposed BES Exception Procedure were still under development; (3)
the proposed BES Definition and BES Exception Procedure were required to be filed with the
Commission for approval in late January, 2012, and, although NERC and the Regional Entities
have no control over the timing of the Commission’s review and approval of these proposals, it
43

Beginning with the 2013 NERC and Regional Entity Annual Compliance Monitoring and
Enforcement Implementation Plans, the Annual Implementation Plans will identify specific
compliance monitoring activities that will be employed to verify the entities’ completion of their
compliance implementation plans and achievement of compliance with the newly-applicable
Reliability Standard Requirements.

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was reasonable to assume that Commission review and approval could take six months or longer
following the submission date, with the effective date of the revised BES Definition and the new
BES Exception Procedure occurring some time after the date of the Commission’s order; and (4)
if NERC or a Regional Entity began to experience a need for significant additional resources in
the latter part of 2012, it would have the options of drawing on its working capital reserves or
filing a supplemental budget and funding request with the Commission. In their 2013 business
plans and budgets, which will be prepared during the first half of 2012 and filed with the
Commission for approval in late August 2012, NERC and the Regional Entities will provide for
specific incremental resources (if any) projected to be needed for additional activities resulting
from adoption of the revised BES Definition and the BES Exception Procedure.
IV. SUMMARY OF THE RELIABILITY STANDARD
DEVELOPMENT PROCEEDINGS
A.

Development History
On December 17, 2010, NERC received, and the Standards Committee accepted, a

standards authorization request (“SAR”) proposing to revise the definition of “Bulk Electric
System” in North America for the NERC Glossary. The SAR was posted for one industry
comment period and approved by the Standards Committee for standard development on March
11, 2011 as Project 2010-17: Definition of Bulk Electric System.
A SDT was selected using the approved nomination and acceptance criteria.

The

assigned SDT posted the draft BES Definition for a 30-day industry comment period from April
28, 2011 to May 27, 2011. There were 154 sets of comments submitted, including comments
from more than 279 different people from approximately 213 entities representing all 10 of the
industry Segments. The comments primarily addressed the need for:

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•

Explicit wording on the inclusion of Reactive Power resources in the bright-line core
BES Definition.

•

Clarification on the exclusion of local distribution facilities.

•

Clarification of transformer windings considered to be a part of the BES.

•

Technical justification of the generator thresholds.

•

Clarification on the need to include Cranking Paths in the BES Definition.

•

Clarification of radial systems.

•

Clarification of local networks.

Based on its consideration of the comments, the SDT revised the draft BES Definition
and re-posted it for a second round of industry comment (concurrent with an initial ballot) for a
45-day period running from August 26, 2011 to October 10, 2011. This time there were 113 sets
of comments, including comments from approximately 255 different people from approximately
156 entities representing all 10 industry Segments. The comments primarily focused on:
•

How to interpret multiple terminal transformers within the BES Definition.

•

Difficulties with circular references to the Statement of Compliance Registry Criteria.

•

The need to exclude small generators from the Reactive Power inclusion.

•

The need to clarify the language for generation on the customer’s side of the retail
meter.

•

The need to clarify the language dealing with power flows into a local network.

The SDT was also assigned the task of concurrently developing the technical criteria to
support a BES Exception Request. As noted earlier, the SDT was assigned this task so that the
Reliability Standards development process would be followed in establishing the technical
criteria. The first draft of the technical criteria was posted for a 30-day period from May 11,
2011 to June 10, 2011. In response, there were 91 sets of comments, including comments from

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more than 75 different people from approximately 45 entities representing 8 of the 10 industry
Segments. Comments stated that the attempt to develop continent-wide criteria for use in the
Exception process was not an acceptable or workable approach.
The SDT then developed a new approach that utilized the collection of a common set of
data and information (“Detailed Information to Support an Exception Request”) that would be
weighed by the ERO in assessing the Exception Requests. The Detailed Information to Support
an Exception Request was posted for a 45-day period from August 26, 2011 to October 10, 2011.
There were 72 sets of comments received, including comments from approximately 137 different
people from approximately 83 entities representing all 10 industry Segments.
B.

Issues Raised During the Development Process including Minority Issues
During the development process, the SDT considered the following comments, issues,

and concerns. The following discussion summarizes those issues and describes how the SDT
resolved those issues.
Threshold values – Commenters wanted the revised BES Definition to address threshold
values, as the values contained in the NERC Statement of Compliance Registry Criteria were
never technically justified. The deadline that the SDT was working under (specifically, to
complete the development process and produce a revised BES Definition within a time frame
that would allow it to be adopted by the NERC Board and filed with the Commission for
approval by January 25, 2012) did not allow for such analysis; therefore, the SDT split the
project into two phases – the first to directly address the Commission directives in Order No.
743, and the second to address the additional concerns raised by industry in a non-deadline
environment. The majority of commenters agreed with this approach.

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Cranking Paths – The first posting of the revised BES Definition had Cranking Paths for
Blackstart Resources included in the BES Definition. A number of commenters complained that
this was improperly bringing distribution level Elements into the BES, as many Cranking Paths
are at the distribution level. Commenters also pointed out that this was an illusory proposition as
intended Cranking Paths are not always the ones used in actual restoration. The SDT was
concerned about the possibility of having Blackstart Resources without a “guaranteed” path to
the BES – what would be the value of a Blackstart Resource if it could not connect to the BES?
The solution was to delete Cranking Paths from the BES Definition in this phase of the project
and to take up the issue in Phase 2 of the project. This approach would maintain status quo on
this topic, consistent with Order Nos. 743 and 743-A, while providing for a full discussion and
consideration of the issue in a less time constrained environment.
Distribution vs. Transmission – Some commenters were concerned about the
delineation of distribution facilities in the BES Definition. The SDT originally had commented
that the BES Definition identifies transmission and therefore if a facility is not included in the
BES Definition the facility was considered to be distribution. However, commenters wanted an
explicit statement on this topic. The SDT added a sentence to the BES Definition to address this
matter: “This does not include facilities used in the local distribution of electric energy.”
Evaluation criteria – Commenters expressed a desire for hard and fast guidance on how
an Exception Request was going to be evaluated. The SDT attempted to develop such hard and
fast values that could be used in evaluating Exception Requests. However, the SDT struggled
with the development of these criteria and asked the industry for assistance. There was a lack of
response from the industry, which the SDT construed as indicating that the industry was
struggling with this concept as well. Therefore, the SDT took a different path and developed a

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series of data and information points that a Submitting Entity should provide to support
Exception Requests. This list was designed to allow for a consistent set of data to be presented
for use in the evaluation of Exception Requests thus leading to consistency in decision making.
In addition, the SDT documented that the Detailed Information to Support an Exception Request
would be reviewed during Phase 2 of the project to see if improvements needed to be made.
Contiguous BES – A number of commenters stated that the BES should be contiguous.
The SDT understood the sensitivity of the industry to such a condition but once again recognized
that this is an issue requiring a great deal of technical analysis which was not possible in the
project timeframe based on the Commission-established deadline for NERC to submit a revised
BES Definition. For purposes of Phase 1 of the project, the SDT noted that the current BES
Definition does not directly address the issue of contiguity. Given the indication in Order Nos.
743 and 743-A toward maintaining the status quo, at least in most of the Regions, the SDT did
not attempt to resolve this complex issue in Phase 1. Rather, the issue of contiguity will be
addressed in Phase 2. This approach was accepted by the majority of commenters, after the
NERC Legal department provided input that Reliability Standards and Requirements could be
written and enforced against Elements that are considered material to the reliability of the
interconnected transmission system, such as e.g., Protection Systems and control systems, even if
those Elements are not included in the BES based on the BES Definition.44
Minority Issues
The minority issues are issues raised by commenters during the development process that
the SDT chose not to address in the manner that a minority of commenters preferred.
44

The Legal Department advice was not intended as a determination that Elements such as
Protection Systems and control systems are not included in the BES under the revised BES
Definition, but rather specified that applicable Reliability Standard Requirements could be
enforced against such Elements even if they were determined to not be included in the BES.

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Threshold values – Some commenters thought that the threshold value issue should be
resolved in Phase 1 of the project and that the BES Definition should not move forward until this
issue was resolved. This was an untenable position as the SDT was under a constraint to produce
a revised BES Definition within a time frame consistent with the deadline established by Order
No. 743, and this time frame did not allow for the in-depth analysis required to resolve such an
issue. Splitting the project into two phases, with the threshold values to be addressed in Phase 2,
was not acceptable to these minority commenters.

The SDT attempted to assuage the

commenter’s fears by getting the proper approvals in place to proceed with Phase 2 prior to the
completion of Phase I. The SDT received approval from the Standards Committee that Phase 2
of the project would continue to be considered as a high-priority project and that the same SDT
that worked on Phase 1 would continue on in Phase 2. The phased project plan was endorsed by
the NERC Members Representative Committee and the Board of Trustees. Assurances were also
received from all appropriate bodies that they would support the SDT in obtaining any assistance
required for in-depth technical analysis from relevant NERC standing committees.
Distribution vs. Transmission – A few commenters continue to suggest that the sevenfactor test should be employed to determine distribution facilities.

The SDT rejected this

approach as the sole determination of distribution facilities, based on the reception such a test
received in previous Commission proceedings where it was suggested that this test be the sole
determining factor for distribution facilities. The SDT pointed out that such a test could be
utilized by a Submitting Entity making an Exception Request but that other information should
be supplied to support the request.
C.

Initial Ballot
NERC conducted an initial ballot on both the BES Definition and the Detailed

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Information to Support an Exception Request from September 30, 2011 through October 10,
2011. With a 92.97% quorum participating in the ballot, the proposed BES Definition achieved
a weighted segment vote of 71.68%. The Detailed Information to Support an Exception Request
achieved an 89.53% quorum and a weighted segment vote of 64.03%.
There were 75 negative ballots submitted for the initial ballot of the BES Definition and
all of those ballots included a comment, which necessitated a recirculation ballot.
There were 88 negative ballots submitted for the initial ballot of the Detailed Information
to Support a BES Exception Request and all of those ballots included a comment, which
necessitated a recirculation ballot.
As discussed below, many of the comments related to the Exception Request process
rather than to the proposed BES Definition. There were four main themes to the comments
provided in the initial balloting:
1.

Lack of guidance for the Exception Request evaluation process – The SDT

understood the concerns raised by the commenters in not receiving hard and fast guidance on this
issue. The SDT would have preferred to be able to provide a simple continent-wide resolution to
this matter. However, after many hours of discussion and an initial attempt at doing so, it
became obvious to the SDT that a simple approach was not achievable. If the SDT could have
come up with a simple approach, it would have been supplied within the bright-line criteria. The
SDT directly solicited assistance on this topic in the first posting of the technical criteria and
received very little in the form of substantive comments from stakeholders.
The SDT recognized that there are so many individual variables that will apply to specific
cases that there is no way to cover all of them in a set of bright-line criteria. There are always
going to be extenuating circumstances that may influence individual cases. One could take this

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statement to say that Regional discretion has not been removed from the BES Definition as
directed by Order No. 743. However, the SDT would disagree with this interpretation. The
Exception Request Form has to be taken in concert with the changes to the Rules of Procedure
and looked at as a single package. When one looks at the proposed Exception Procedure, it
becomes clear that the role of the Regional Entity has been drastically reduced. The role of the
Regional Entity is now one of reviewing the Exception Request for completeness and making a
Recommendation to NERC on whether the Exception Request should be approved or
disapproved. The Regional Entity plays no role in actually approving or disapproving the
Exception Request, other than providing a Recommendation. NERC, not the Regional Entity,
will make the final determination. Moreover, the Exception Procedure in proposed Appendix 5C
of the NERC Rules of Procedure, sections 5.2.4 and 5.3, provides an added check by requiring
review and provision of an opinion by an independent Technical Review Panel of a Regional
Entity’s proposed Disapproval of an Exception Request. The Technical Review Panel’s
evaluation becomes part of the Exception Request record submitted to NERC. Finally, section
7.0 of proposed Appendix 5C provides NERC the option to remand a rejected Exception Request
to the Regional Entity with the directive to conduct a substantive review of the Exception
Request, if NERC determines the Regional Entity should not have rejected the Exception
Request.
Commenters also pointed out that the specific types of studies to be provided with an
Exception Request, and how the Regional Entity should interpret the information, are not
provided in the proposed Exception Procedure, and therefore the Regional Entity has no basis for
determining what is an acceptable submittal. The SDT, however, again noted that the variations
that will occur among Exception Requests negate the ability to establish specific, hard and fast

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criteria. However, there will be a great deal of professional and technical experience involved on
behalf of Submitting Entities, Regional Entities and NERC in the Exception Request process.
The SDT believed that Submitting Entities, Regional Entities and NERC will be able to
determine what types of information is important to support Exclusion Requests and Inclusion
Requests under the Exception Procedure.
Commenters pointed to a lack of specific guidelines in the Exception Procedure for
NERC to follow in making its decision. The SDT reiterated the problem with providing a single
set of hard and fast rules, in light of there being so many variables to take into account. The SDT
believed that providing a single set of criteria that would have to be inflexibly applied to every
Exception Request would inappropriately constrain NERC’s ability to address the particular facts
and circumstances of individual Exception Requests.

Moreover, section 3.1 of proposed

Appendix 5C states the fundamental principle that the evaluation of an Exception Request must
be based on whether the Elements are necessary for the Reliable Operation of the interconnected
transmission system. “Reliable Operation” is defined in the Rules of Procedure as “operating the
Elements of the Bulk Power System within equipment and electric system thermal, voltage, and
stability limits so that instability, uncontrolled separation, or Cascading failures of such system
will not occur as a result of a sudden disturbance, including a Cyber Security Incident, or
unanticipated failure of system Elements.”45 The SDT concluded that the technical expertise of
the NERC review team, the visibility of the Exception Request process, and the overriding
requirement of “Reliable Operation” will result in appropriate decision making on Exception

45

This is the definition of “Reliable Operation” in proposed Appendix 2 to the Rules of
Procedure as filed with the Commission on November 29, 2011, and is taken from the definition
of the term in FPA §215(a)(4) and 18 C.F.R. §39.1.

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Requests while providing NERC with the flexibility to consider the particular facts and
circumstances of each Exception Request.
Finally, the SDT noted that the draft SAR for Phase 2 of this project calls for a review of
the Detailed Information to Support an Exception Request after 12 months of experience with
Exception Requests. The SDT believes that this time period will allow both industry and the
ERO to see if the data and information required by the Detailed Information to Support an
Exception Request are appropriate and complete and to suggest changes to questions and
information required by the Detailed Information to Support an Information Request based on
actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this issue and the filing deadline that the SDT was
working under for Phase I of this project, the SDT believed it reached a fair and equitable
resolution of this difficult issue for Phase 1.
2.

Will a single “negative” response to the checklist questions mean a request

will be denied - Some commenters asked whether a “yes” or “no” response to a single item on
the Exception Request Form will mandate a Disapproval of the Exception Request. The SDT
referred to text in section 3.2 of the then-current draft of the Exception Procedure stating that no
single piece of evidence provided as part of an Exception Request or response to a question will
be solely dispositive in the determination of whether an Exception Request shall be approved. In
its final version of the proposed Exception Procedure, the BES ROP Team revised this text to the
following text, which the Team viewed as a functionally equivalent but more encompassing
statement: “All evidence provided as part of an Exception Request or response will be
considered in determining whether an Exception Request shall be approved or disapproved.”

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3.

Lack of certainty that Phase 2 would start - The SDT has obtained the proper

approvals for Phase 2 even prior to the completion of Phase I. The SDT received approval from
the NERC Standards Committee that Phase 2 of the project would continue to be considered as a
high-priority project and that the same SDT that worked on Phase 1 would continue in Phase 2.
The phased project plan was endorsed by the NERC Members Representative Committee and the
Board of Trustees. Assurances were also received from all appropriate bodies that they would
assist the SDT in receiving any assistance required for in-depth technical analysis from relevant
NERC standing committees. In fact, Phase 2 activities have started.
4.

How to weigh the Exclusions against the Inclusions in the BES Definition -

The application of the proposed BES Definition is a three-step process that when properly
applied will identify the vast majority of BES Elements in a consistent manner that can be
applied on a continent-wide basis. In step 1, the core BES definition is used to establish the
bright line of 100 kV, the overall demarcation point between BES and non-BES Elements:
Unless modified by the lists shown below, all Transmission Elements operated at
100 kV or higher and Real Power and Reactive Power resources connected at 100
kV or higher. This does not include facilities used in the local distribution of
electric energy.
To fully appreciate the scope of the core definition, an understanding of the term Element is
needed. Element as defined in the NERC Glossary of Terms as:
Any electrical device with terminals that may be connected to other electrical
devices such as a generator, transformer, circuit breaker, bus section, or
transmission line. An Element may be comprised of one or more components.”46
Thus, an Element is basically any electrical device that is associated with the transmission or the
generation (generating resources) of electric energy. Moreover, the NERC Glossary definition of
“Transmission” encompasses “an interconnected group of lines and associated equipment for the
46

This is also the definition of Element in proposed Appendix 2 of the Rules of Procedure.

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movement or transfer of electric energy between points of supply and points at which it is
transformed for delivery to customers or is delivered to other electric systems.”
Step 2 of the BES Definition provides additional clarification for the purposes of
identifying specific Elements that are included in the BES through the application of the core
definition. The Inclusions address transmission Elements and Real Power and Reactive Power
resources with specific criteria to provide for a consistent determination of whether an Element is
classified as BES or non-BES.
Step 3 of the BES Definition is to evaluate specific situations for potential exclusion from
the BES (i.e., classification as non-BES Elements). The exclusion language is written to
specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion from the BES of transmission Elements from
radial systems that meet the specific criteria identified in the exclusion language. This does not
include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 –
I5. Exclusion E1 only speaks to the transmission component of the radial system. Similarly,
Exclusion E3 (local networks) should be applied in the same manner. Therefore, the only
inclusion that Exclusions E1 and E3 can supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of Real Power resources that reside behind the
retail meter (on the customer’s side), if the enumerated conditions (i) and (ii) are met, and
supersedes Inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive
Power devices, and supersedes Inclusion I5.
In the event that the BES Definition designates an Element as BES that is not necessary
for the Reliable Operation of the interconnected transmission network, or designates an Element

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as non-BES that is necessary for the Reliable Operation of the interconnected transmission
network, the BES Exception Procedure in proposed Appendix 5C may be utilized on a case-bycase basis to either exclude or include, respectively, the Element from or in the BES.
5.

Assurance that threshold values would be addressed in Phase 2 – As

described earlier, the SDT has separated the project into two phases which will enable the SDT
to address the concerns of both industry stakeholders and regulatory authorities. In Phase 2, the
SDT will consider all recommendations for modifications to the technical aspects of the BES
Definition.

This will allow the SDT, in conjunction with the NERC technical standing

committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values.
D.

Balloting and Approval
The SDT addressed all of the ballot comments47 and made several clarifying changes to

the proposed BES Definition and the Detailed Information to Support an Exception Request, and
posted both documents for a recirculation ballot from November 10, 2011 through November 21,
2011. The SDT posted its Consideration of Comments reports to the second posting and initial
ballot comments as part of the recirculation posting.
A 95.92% quorum participated in the recirculation ballot and the proposed BES
definition achieved a weighted Segment approval vote of 81.32%. Therefore, the proposed BES
Definition achieved at least a 75% quorum of the ballot pool and a two-thirds weighted Segment
vote, as required by the NERC Standard Processes Manual.
A 93.02% quorum participated in the recirculation ballot for the proposed Detailed

See Exhibit D for Consideration of Comments and Exhibit E for the complete development
history.

47

-56-

Information to Support an Exception Request, and it achieved a weighted Segment approval vote
of 81.48%. Therefore, the proposed Detailed Information to Support an Exception Request
achieved the required 75% quorum of the ballot pool and a two-thirds weighted Segment vote.
The NERC Board of Trustees adopted the proposed BES Definition, the Detailed
Information to Support an Exception Request, and the SDT’s proposed implementation plan, on
January 18, 2012.

V. CONCLUSION
For the reasons set forth in this Petition, the North American Electric Reliability
Corporation requests the Commission to (1) approve the revised definition of “Bulk Electric
System” in Exhibit A, and the retirement of the current BES Definition on midnight of the day
immediately preceding the effective date of the revised BES Definition; (2) approve the
“Detailed Information to Support an Exception Request in Exhibit C; (3) approve the
implementation plan described in §III.E of this Petition; and (4) accept this filing as compliance
with Order Nos. 743 and 743-A.

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Respectfully submitted,
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability Corporation
3353 Peachtree Road N.E.
Suite 600, North Tower
Atlanta, GA 30326-1001
(404) 446-2560
David N. Cook
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel for Standards and
Critical Infrastructure Protection
Andrew Dressel, Attorney
North American Electric Reliability Corporation
1325 G Street N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
david.cook@nerc.net
holly.hawkins@nerc.net
andrew.dressel@nerc.net

-58-

/s/Owen E. MacBride
Owen E. MacBride
Debra A. Palmer
Schiff Hardin LLP
1666 K Street, N.W., Suite 300
Washington, D.C. 20036-4390
(202) 778-6400
(202) 778-6460 – facsimile
omacbride@schiffhardin.com
dpalmer@schiffhardin.com

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF A REVISED DEFINITION OF “BULK ELECTRIC SYSTEM”
IN THE NERC GLOSSARY OF TERMS USED IN RELIABILITY STANDARDS

EXHIBIT A

PROPOSED DEFINITION OF “BULK ELECTRIC SYSTEM”

Proposed Definition of “Bulk Electric System”
Bulk Electric System: Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV
or higher. This does not include facilities used in the local distribution of electric energy.
Inclusions:
•

I1 - Transformers with the primary terminal and at least one secondary terminal operated
at 100 kV or higher unless excluded under Exclusion E1 or E3.

•

I2 - Generating resource(s) with gross individual nameplate rating greater than 20 MVA
or gross plant/facility aggregate nameplate rating greater than 75 MVA including the
generator terminals through the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above.

•

I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.

•

I4 - Dispersed power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily for aggregating
capacity, connected at a common point at a voltage of 100 kV or above.

•

I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is
designated in Inclusion I1.

Exclusions:
•

E1 - Radial systems: A group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusion I3, with an
aggregate capacity less than or equal to 75 MVA (gross nameplate rating).
Or,
c) Where the radial system serves Load and includes generation resources,
not identified in Inclusion I3, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted
on prints or one-line diagrams for example, does not affect this exclusion.

•

E2 - A generating unit or multiple generating units on the customer’s side of the retail
meter that serve all or part of the retail Load with electric energy if: (i) the net capacity
provided to the BES does not exceed 75 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating
units or to the retail Load by a Balancing Authority, or provided pursuant to a binding
obligation with a Generator Owner or Generator Operator, or under terms approved by
the applicable regulatory authority.

•

E3 - Local networks (LN): A group of contiguous transmission Elements operated at or
above 100 kV but less than 300 kV that distribute power to Load rather than transfer bulk
power across the interconnected system. LN’s emanate from multiple points of
connection at 100 kV or higher to improve the level of service to retail customer Load
and not to accommodate bulk power transfer across the interconnected system. The LN is
characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do
not include generation resources identified in Inclusion I3 and do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating);
b) Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain a

monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection,
or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
•

E4 – Reactive Power devices owned and operated by the retail customer solely for its
own use.

Note - Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.

-2-

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF A REVISED DEFINITION OF “BULK ELECTRIC SYSTEM”
IN THE NERC GLOSSARY OF TERMS USED IN RELIABILITY STANDARDS

EXHIBIT B

CURRENT DEFINITION OF “BULK ELECTRIC SYSTEM” (FOR REFERENCE)

Current Definition of “Bulk Electric System”

As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment,
generally operated at voltages of 100 kV or higher. Radial transmission facilities serving only
load with one transmission source are generally not included in this definition.

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF A REVISED DEFINITION OF “BULK ELECTRIC SYSTEM”
IN THE NERC GLOSSARY OF TERMS USED IN RELIABILITY STANDARDS

EXHIBIT C

DETAILED INFORMATION TO SUPPORT AN EXCEPTION REQUEST

Detailed Information to Support an Exception Request

Entities that have Element(s) designated as excluded, under the BES definition and designations, do not
have to seek exception for those Elements under the Exception Procedure.
General Instructions:
A one-line breaker diagram identifying the Element(s) for which the exception is requested must be
supplied with every request. The diagram(s) supplied should also show the Protection Systems at the
interface points associated with the Elements for which the exception is being requested.
Entities are required to supply the data and studies needed to support their submittal. Studies should:
•
•
•

Be based on an Interconnection-wide base case that is suitably complete and detailed to reflect
the electrical characteristics and system topology
Clearly document all assumptions used
Address key performance measures of BES reliability through steady-state power flow, and
transient stability analysis as necessary to support the entity’s request, consistent with the
methodologies described in the Transmission Planning (TPL) standard and commensurate with
the scope of the request

Supporting statements for your position from other entities are encouraged.
List any attached supporting documents and any additional information that is included to support the
request:

1

Detailed Information to Support an Exception Request
For Transmission Elements:
1. Is there generation connected to the Element(s)?
Yes

No

If yes, what are the individual gross nameplate values of each unit?

Description/Comments:

2. How do/does the Element(s) impact permanent Flowgates in the Eastern Interconnection, major
transfer paths within the Western Interconnection, or a comparable monitored facility in the ERCOT
Interconnection or the Quebec Interconnection?
Please list the Flowgates or paths considered in your analysis along with any studies or assessments
that illustrate the degree of impact:

3. Is/Are the Element(s) included in an Interconnection Reliability Operating Limit (IROL) in the Eastern
Interconnection, ERCOT Interconnection, or Quebec Interconnection or a major transfer path rating in
the Western Interconnection?
Yes

No

Please provide the appropriate list for the operating area where the Element(s) is located:

4. How does an outage of the Element(s) impact the over-all reliability of the BES? Please provide study
results that demonstrate the most severe system impact of the outage of the Element(s) and the
rationale for your response:

2

Detailed Information to Support an Exception Request

5. Is/Are the Element(s) used for off-site power supply to a nuclear power plant as designated in a
mutually agreed upon Nuclear Plant Interface Requirement (NPIR)?
Yes

No

Description/Comments:

6. Is/Are the Element(s) part of a Cranking Path identified in a Transmission Operator’s restoration plan?
Yes

No

Description/Comments:

7. Does power flow through the Element(s) into the BES?
Yes

No

If yes, then using metered or SCADA data for the most recent consecutive two calendar year period,
what is the minimum and maximum magnitude of the power flow out of the Element(s)? Describe the
conditions and the time duration when this occurs?

3

Detailed Information to Support an Exception Request

For Generation Resources:
1. What is the MW value of the host Balancing Authority’s most severe single Contingency and what is
the generation resources percent of this value?
Please provide the values and a reference to supporting documents:

2. Is the generation resource used to provide reliability-related Ancillary Services?
Yes

No

If so, what reliability-related Ancillary Services are the generation resource supplying:

3. Is the generation resource designated as a must run unit for reliability?
Yes

No

Please provide the appropriate reference for your operating area:

4. How does an outage of the generation resource impact the over-all reliability of the BES? Please
provide study results that demonstrate the most severe system impact of the outage of the generator
and the rationale for your response:

5. Does the generation resource use the BES to deliver its actual or scheduled output, or a portion of its
actual or scheduled output, to Load?
Yes

No

Description/Comments:

4

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF A REVISED DEFINITION OF “BULK ELECTRIC SYSTEM”
IN THE NERC GLOSSARY OF TERMS USED IN RELIABILITY STANDARDS

EXHIBIT D

CONSIDERATION OF COMMENTS REPORT
CREATED DURING THE DEVELOPMENT OF THE
REVISED DEFINITION OF “BULK ELECTRIC SYSTEM”

Consideration of Comments on Definition of Bulk Electric System— Project
2010-17

Following the development of this report, the leadership of the BES Definition SDT and Rules
of Procedure teams met with the leadership of the Standards Program and the Standards
Committee and determined that the BES Definition SDT will assume responsibility for
working with stakeholders to identify what evidence is needed to support a request for an
exception to the BES definition.
The BES Definition team will solicit stakeholder input to identify the evidence an entity will
need to provide when submitting a request for an exception to the definition of BES. While
the determination of what evidence will be needed to support a request for a BES Definition
Exception will be developed using NERC’s standard development process, a decision on
where the final product will reside - in the definition of BES, or as an attachment (e.g., a
procedure identifying what evidence to produce when applying for a BES exception) to the
Rules of Procedure will be made jointly by the leadership of the Standards Program and the
Standards Committee at a later stage. Given the time constraints of this project, having all
the technical clarity associated with this project developed by a single team seemed the
most efficient decision.

The Definition of Bulk Electric System Drafting Team thanks all commenters who submitted
comments on the SAR and proposed modification to the definition of Bulk Electric System.
These standards were posted for a 30-day public comment period from December 17, 2010
through January 21, 2011. The stakeholders were asked to provide feedback on the
standards through a special Electronic Comment Form. There were 82 sets of comments,
including comments from more than 175 different people from approximately 129
companies representing 10 of the 10 Industry Segments as shown in the table on the
following pages.

http://www.nerc.com/filez/standards/Project2010-17_BES.html
Prior to the issuance of Order 743a, the SDT carefully weighed the many suggestions
received in these comments as well as reviewing numerous documents from Regional
Entities and other sources in coming up with a revised definition shown here:
Bulk Electric System (BES): All Transmission Elements operated at 100 kV or higher,
Real Power resources as described below, and Reactive Power resources connected at 100
kV or higher unless such designation is modified by the list shown below.
Inclusions:
•

I1 - Transformers, other than generator step-up (GSU) transformers, including phase
angle regulators, with two windings of 100 kV or higher unless excluded under
Exclusions E1 and E3.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Consideration of Comments on Definition of Bulk Electric System— Project 2010-17
•

•

•
•

I2 - Individual generating units greater than 20 MVA (gross nameplate rating)
including the generator terminals through the GSU which has a high side voltage of
100 kV or above.
I3 - Multiple generating units located at a single site with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) including the generator terminals
through the GSUs, connected through a common bus operated at a voltage of 100
kV or above.
I4 - Blackstart Resources and the designated blackstart Cranking Paths identified in
the Transmission Operator’s restoration plan regardless of voltage.
I5 - Dispersed power producing resources with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing a collector system through a
common point of interconnection to a system Element at a voltage of 100 kV or
above.

Exclusions:
•

•

•

E1 - Any radial system which is described as connected from a single Transmission
source originating with an automatic interruption device and:
a) Only serving Load. A normally open switching device between radial systems
may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5.
Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and
includes generation resources not identified in Inclusions I2, I3, I4 and I5.
E2 - A generating unit or multiple generating units that serve all or part of retail Load
with electric energy on the customer’s side of the retail meter if: (i) the net capacity
provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and
(ii) standby, back-up, and maintenance power services are provided to the
generating unit or multiple generating units or to the retail Load pursuant to a
binding obligation with a Balancing Authority or another Generator Owner/Generator
Operator, or under terms approved by the applicable regulatory authority.
E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV
that distribute power to Load rather than transfer bulk power across the
interconnected System. LDN’s are connected to the Bulk Electric System (BES) at
more than one location solely to improve the level of service to retail customer Load.
The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the
BES, the LDN must be connected through automatic fault-interrupting devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in
aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed
the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy
originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored
Facility of a permanent Flowgate in the Eastern Interconnection, a major transfer
path within the Western Interconnection as defined by the Regional Entity, or a

March 30, 2011

2

Consideration of Comments on Definition of Bulk Electric System— Project 2010-17
comparable monitored Facility in the Quebec Interconnection, and is not a
monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).
Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.
The SDT has made corresponding changes to the appropriate wording of the SAR and is now
asking the Standards Committee for approval to move this project to the definition
development phase.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at herb.schrayshuen@nerc.net. In addition, there is
a NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.

March 30, 2011

3

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Index to Questions:
1. Should the following be classified as part of the BES? ........................................................ 16
•
2.

Should the following be classified as part of the BES? ........................................................ 30
•

3.

Generation plants with aggregate capacity greater than 75 MVA (gross nameplate
rating) directly connected via a step-up transformer(s) to Facilities operated at voltages
below 100kV where the exemption process deems the generation plants to be included
in the BES ..................................................................................................................... 94

Should the following be excluded from the Elements and Facilities classified as part of the
BES? ................................................................................................................................... 106
•

9.

Individual generation resources greater than 20 MVA (gross nameplate rating) directly
connected via a step-up transformer(s) to Facilities operated at voltages below 100kV
where the exemption process deems the generation resources to be included in the BES
....................................................................................................................................... 81

Should the following be classified as part of the BES? ........................................................ 94
•

8.

Transmission Elements or Facilities operated at voltages below 100kV where the
exemption process deems the Element or Facility to be included in the BES .............. 71

Should the following be classified as part of the BES? ........................................................ 81
•

7.

Blackstart Resources and the designated blackstart Cranking Paths identified in the
Transmission Operator’s (TOP’s) restoration plan ....................................................... 59

Should the following be classified as part of the BES? ........................................................ 71
•

6.

Generation plants (including GSU transformers and the associated generator
interconnecting line lead(s))with aggregate capacity greater than 75 MVA (gross
nameplate rating) directly connected via a step-up transformer(s) to Transmission
Facilities operated at voltages of 100 kV or above ....................................................... 46

Should the following be classified as part of the BES? ........................................................ 59
•

5.

Individual generation resources (including GSU transformers and the associated
generator interconnecting line lead(s)) greater than 20 MVA (gross nameplate rating)
directly connected via a step-up transformer(s) to Transmission Facilities operated at
voltages of 100 kV or above ......................................................................................... 30

Should the following be classified as part of the BES? ........................................................ 46
•

4.

Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle
Regulators, with both primary and secondary windings of 100 kV or higher .............. 16

Any radial Transmission Element or System, connected from one Transmission source
to a Load-serving Element and/or generation resources not included in items 2, 3, 4, 6,
and 7 above are excluded from the BES ..................................................................... 106

Should the following be excluded from the Elements and Facilities classified as part of the
BES? ................................................................................................................................... 119
•

Elements and Facilities identified through application of the exemption process,
consistent with the criteria, where the exemption process deems that the Element or
Facility should be excluded from the BES (with concurrence from the ERO) .......... 119

March 30, 3011

4

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

10. Should the following be excluded from the Elements and Facilities classified as part of the
BES? ................................................................................................................................... 129
•

Generating plant control and operation functions which include relays and systems that
control and protect the unit for boiler, turbine, environmental, and/or other plant
restrictions ................................................................................................................... 129

11. Do you believe that the proposed definition of BES, accompanied by a separate BES
Definition Exception Process meets the reliability-related intent of the directives in Order
743? ..................................................................................................................................... 138
12. If you have a proposal for an equally efficient and effective method of achieving the
reliability- related intent of the directives in Order 743, please provide your proposal here.
157
13. Please provide any other information that you feel would be helpful to the drafting team
working on the definition of BES. ...................................................................................... 171

March 30, 3011

5

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Group

1.

Guy Zito

Northeast Power Coordinating Council

Additional Member Additional Organization

Region

3

4

5

6

7

8

9

10

X

Segment
Selection

1.

Alan Adamson

New York State Reliability Council, LLC

NPCC

10

2.

Gregory Campoli

New York Independent System Operator

NPCC

2

3.

Kurtis Chong

Independent Electricity System Operator

NPCC

2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC

1

5.

Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC

3

6.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC

10

7.

Dean Ellis

Dynegy Generation

NPCC

5

8.

Brian Evans-Mongeon

Utility Services

NPCC

8

9.

Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC

5

10.

Brian L. Gooder

Ontario Power Generation Incorporated

NPCC

5

11.

Kathleen Goodman

ISO - New England

NPCC

2

12.

Chantel Haswell

FPL Group, Inc.

NPCC

5

13.

David Kiguel

Hydro One Networks Inc.

NPCC

1

14.

Michael R. Lombardi

Northeast Utilities

NPCC

1

March 30, 3011

2

6

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

15.

Randy MacDonald

New Brunswick System Operator

NPCC

2

16.

Bruce Metruck

New York Power Authority

NPCC

6

17.

Lee Pedowicz

Northeast Power Coordinating Council

NPCC

10

18.

Robert Pellegrini

The United Illuminating Company

NPCC

1

19.

Si Truc Phan

Hydro-Quebec TransEnergie

NPCC

1

20.

Saurabh Saksena

National Grid

NPCC

1

21.

Michael Schiavone

National Grid

NPCC

1

22.

Bohdan Dackow

US Power Generating Company (USPG)

NPCC

NA

2.

Group

Charles W. Long

SERC EC Planning Standards Subcommittee

Additional Member Additional Organization

Region

Pat Huntley

SERC Reliability Corporation

SERC

10

2.

Bob Jones

Southern Company Services

SERC

1

3.

Darrin Church

Tennessee Valley Authority

SERC

1

4.

Jim Kelley

PowerSouth Energy Cooperative SERC

1

5.

John Sullivan

Ameren Services Co.

SERC

1

6.

Phil Kleckley

South Carolina Electric & Gas Co. SERC

1

Group

Patricia Hervochon

Additional Member

Public Service Enterprise Group Company

Additional Organization
PSE&G

RFC

1, 3

2. Scott Slickers

PSEG Fossil

RFC

5

3. Jim Hebson

PSEG ER&T

RFC

6

4. Dominic Grasso

PSEG Power CT

NPCC

5

5. Peter Dolan

PSEG ER&T

NPCC

6

6. Dominic DiBari

PSEG Fossil Odessa Ector Power Partners ERCOT 5

7. Eric Schmidt

PSEG ER&T

Group

March 30, 3011

Carol Gerou

4

5

6

X

7

8

9

10

X

X

X

X

X

Region Segment Selection

1. Jim Hubertus

4.

3

Segment
Selection

1.

3.

2

ERCOT 6

MRO's NERC Standards Review
Subcommittee

X

7

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Additional Member

Additional Organization
Omaha Public Utility District

MRO

1, 3, 5, 6

2. Chuck Lawrence

American Transmission Company

MRO

1

3. Tom Webb

Wisconsin Public Service Corporation MRO

3, 4, 5, 6

4. Jason Marshall

Midwest ISO Inc.

MRO

2

5. Jodi Jenson

Western Area Power Administration

MRO

1, 6

6. Ken Goldsmith

Alliant Energy

MRO

4

7. Alice Ireland

Xcel Energy

MRO

1, 3, 5, 6

8. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

9. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

10. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

11. Scott Nickels

Rochester Public Utilties

MRO

4

12. Terry Harbour

MidAmerican Energy Company

MRO

6, 1, 3, 5

13. Richard Burt

Minnkota Power Cooperative, Inc.

MRO

1, 3, 5, 6

Group

Al DiCaprio

IRC Standards Review Committee

Additional Member Additional Organization Region
Bill Phillips

MISO

2.

James Castle

NYISO NPCC

2

3.

Matt Goldberg

ISO-NE NPCC

2

4.

Greg Van Pelt

CAISO WECC

2

5.

Charles Yeung

SPP

SPP

2

6.

Dan Rochester

IESO

NPCC

2

7.

Mark Thompson

AESO

WECC

2

8.

Steve Myers

ERCT

ERCOT

2

Group

Frank Gaffney

4

5

6

7

8

9

10

X

Segment
Selection

1.

6.

3

Region Segment Selection

1. Mahmood Safi

5.

2

MRO

2

Florida Municipal Power Agency

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Tim Beyrle

City of New Smyrna Beach FRCC

4

2. Greg Woessner

KUA

3

March 30, 3011

FRCC

8

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

3. Jim Howard

Lakeland Electric

FRCC

3

4. Lynne Mila

City of Clewiston

FRCC

3

5. Joe Stonecipher

Beaches Energy Services FRCC

1

6. Cairo Vanegas

FPUA

FRCC

4

7. Randy Hahn

Ocala Electric Utility

FRCC

3

Group

7.

Denise Koehn

Bonneville Power Administration

Additional Member Additional Organization

Region

X

Sara Sundborg

BPA, Transmission, Technical Operations WECC

1

2.

John Anasis

BPA, Transmission, Technical Operations WECC

1

3.

Jim Gronquist

BPA, Transmission, Technical Operations WECC

1

4.

James O'Brien

BPA, Transmission, Technical Operations WECC

1

5.

Siraji Hirsi

BPA, Transmission, Technical Operations WECC

1

6.

Daniel Goodrich

BPA, Transmission, Technical Operations WECC

1

7.

Lorissa Jones

BPA, Transmission Reliability Program

1

Group

Doug Hohlbaugh

3

4

X

5

6

X

X

X

X

X

X

7

8

9

10

Segment
Selection

1.

8.

2

WECC

FirstEnergy Corp

X

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Rob Martinko

FirstEnergy Corp

Group

9.

Mike Garton

Additional Member Additional Organization

RFC

1, 3, 4, 5, 6

Electric Market Policy
Region

Segment
Selection

1.

Michael Gildea

Dominion Resources Services, Inc. NPCC

5

2.

Louis Slade

Dominion Resources Services, Inc. SERC

3

3.

Connie Lowe

Dominion Resources Services, Inc. RFC

5

4.

John Loftis

Dominion Virginia Power

1

10.

Group

March 30, 3011

Jim Case

SERC

SERC OC Standards Review Group

9

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Additional Member Additional Organization

Region

Gerald Beckerle

Ameren

SERC

1, 3

2.

Andy Burch

EEI

SERC

1, 5

3.

Randy Castello

Mississippi Power SERC

1, 3, 5

4.

Dan Roethemeyer

Dynegy

SERC

5

5.

Melinda Montgomery

Entergy

SERC

1, 3

6.

Sam Holeman

Duke Energy

SERC

1, 3, 5

7.

Joel Wise

TVA

SERC

1, 3, 5, 9

8.

Alvis Lanton

SIPC

SERC

1, 3, 5

9.

Hamid Zakery

Dynegy

SERC

5

10.

John Neagle

AECI

SERC

1, 3

11.

Mike Hirst

Cogentrix

RFC

5, 6

12.

Tim Hattaway

PowerSouth

SERC

1, 3, 5, 9

13.

Robert Thomasson

BREC

SERC

1, 3, 5, 9

14.

Shardra Scott

Gulf Power

SERC

1, 3, 5

15.

Patrick Woods

EKPC

SERC

1, 3, 5, 9

16.

Alisha Ankar

Prairie Power

SERC

1, 3, 5

17.

Bill Hutchison

SIPC

SERC

1, 3, 5

18.

J. T. Wood

Southern

SERC

1, 3, 5

19.

John Troha

SERC

SERC

10

Individual

Sandra Shaffer

PacifiCorp

X

Individual

Sylvain Clermont /
Alain Pageau

Hydro-Québec

X

13.

Individual

William J. Gallagher

Transmission Access Policy Study Group

X

14.

Individual

John Cummings

PPL Energy Plus

12.

March 30, 3011

3

4

5

6

7

8

9

10

Segment
Selection

1.

11.

2

X

X

X

X

X

X

X

X

X

10

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

X

5

X

6

15.

Individual

Jack Cashin

Competitive Suppliers

16.

Individual

Marty Kaufman

ExxonMobil Research and Engineering

17.

Individual

John Seelke

NERC Staff

18.

Individual

Janet Smith

Arizona Public Service Company

X

X

X

X

19.

Individual

Brian J. Murphy

NextEra Energy Inc.

X

X

X

X

20.

Group

David Dworzak

Edison Electric Institute

X

X

X

X

X

X

X

7

8

9

10

X

X

X

http://www.eei.org/whoweare/ourmembers/USElectricCompanies/Pages/USMemberCoLinks.aspx
21.

Individual

Brent Ingebrigtson

LG&E and KU Energy LLC

22.

Individual

Steve Alexanderson

Central Lincoln

23.

Individual

David Thorne

Pepco Holdings Inc.

X

24.

Individual

Martyn Turner

LCRA Transmission Services Corporation

X

25.

Individual

David W Proebstel

PUD No.1 of Clallam County

26.

Individual

Joe Petaski

Manitoba Hydro

27.

Individual

Kevin Koloini

American Municipal Power

28.

Individual

Robert Beadle

North Carolina EMC

29.

Individual

Jim Uhrin

ReliabilityFirst

March 30, 3011

X

X

X

X

X
X

X
X
X

X

X
X

11

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

6

7

8

30.

Individual

Elroy Switlishoff

on behalf of Teck Metals Ltd.

31.

Individual

Rex A Roehl

Indeck Energy Services

32.

Individual

Samuel Stonerock

Southern California Edison

X

X

X

33.

Individual

Patrick Farrell

Southern California Edison Company

X

X

X

34.

Individual

E Switlishoff

on behalf of Catalyst Paper Corporation

X

X

35.

Individual

Jeff Mead

City of Grand Island

X

36.

Individual

Michelle D'Antuono

Occidental Energy Ventures Corp

X

37.

Individual

Manny Robledo

City of Anaheim

38.

Individual

Josh Dellinger

Glacier Electric Cooperative

39.

Individual

Kathleen Goodman

ISO New England Inc.

40.

Individual

Ed Davis

Entergy Services

X

X

41.

Individual

John D. Martinsen

Snohomish County PUD

X

X

42.

Individual

Rick Paschall

PNGC Power

X

43.

Individual

Bud Tracy

Blachly-Lane Electric Co-op

X

X

44.

Individual

Dave Hagen

Clearwater Power Co.

X

X

45.

Individual

Dave Sabala

Douglas Electric Cooperative

X

March 30, 3011

X

5

9

10

X
X

X
X

X

X

X
X
X
X

X
X

12

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

Individual

Dave Markham

Central Electric Cooperative, Inc. (Redmond
Oregon)

X

47.

Individual

Heber Carpenter

Raft River Rural Electric Cooperative

X

48.

Individual

Jon Shelby

Northern Lights Inc.

X

49.

Individual

Ken Dizes

Salmon River Electric Cooperative

50.

Individual

Ray Ellis

Okanogan Country Electric Cooperative

X

51.

Individual

Richard Reynolds

Lost River Electric

X

52.

Individual

Rick Crinklaw

Lane Electric Cooperative

X

53.

Individual

Roger Meader

Coos-Curry Electric Cooperative

X

54.

Individual

Roman Gillen

Consumer's Power Inc.

X

X

55.

Individual

Steve Eldrige

Umatilla Electric Co-op

X

X

56.

Individual

Marc Farmer

West Oregon Electric Cooperative

X

57.

Individual

Michael Henry

Lincoln Electric Cooperative

X

58.

Individual

Bryan Case

Fall River Electric Cooperative

X

59.

Individual

Jonathan Appelbaum

United Illuminating Company

X

60.

Individual

David Burke

Orang and Rockland Utilities, Inc.

X

46.

March 30, 3011

X

4

5

6

7

8

9

10

X

X

13

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

61.

Individual

Andrew Z. Pusztai

american Transmission company

62.

Individual

John A. Gray

The Dow Chemical Company

63.

Individual

Brian Evans-Mongeon

Utility Services

Individual

Barry Lawson

National Rural Electric Cooperative
Association (NRECA)

65.

Individual

Andrew Gallo

City of Austin dba Austin Energy

66.

Individual

Laura Lee

67.

Individual

68.
69.

64.

3

4

X

X

X

X

X

X

Duke Energy

X

Hertzel Shamash

The Dayton Power and Light Company

X

Individual

Michael Moltane

ITC Holdings Corp

X

Individual

Bill Keagle

BGE

X

Amir Hammad

Constellation Power Source Generation, Inc.
(“CPSG”) filing on behalf of Constellation
Energy Group, Inc. (“CEG”), Constellation
Energy Commodities Group, Inc. (“CCG”),
Constellation Energy Control and Dispatch,
LLC (“CDD”), Constellation NewEnergy, Inc.,
(“CNE”) and Constellation Energy Nuclear
Group, LLC, (“CENG”)

Shaun Anders

City Water Light and Power (CWLP) Springfield, IL

Individual
Individual

March 30, 3011

5

6

7

8

9

10

X

X

70.

71.

2

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

14

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

72.

Individual

Steven Grega

Lewis County PUD

73.

Individual

Thad Ness

American Electric Power (AEP)

X

X

X

X

74.

Individual

Marc M. Butts

Southern Company

X

X

X

X

75.

Individual

David Angell

Idaho Power

X

X

X

Individual

John P. Hughes

Electricity Consumers Resource Council
(ELCON)

77.

Individual

Dan Rochester

Independent Electricity System Operator

78.

Individual

Jeff Nelson

Springfield Utility Board

79.

Individual

Jack Stamper

Clark Public Utilities

80.

Individual

Allen Mosher

APPA

81.

Individual

Alice Ireland

Xcel Energy

82.

Individual

Paul Cummings

City of Redding

X

X

83.

Individual

Manny Robledo

City of Anaheim

X

X

76.

March 30, 3011

7

8

9

10

X

X
X
X
X
X
X

X

X

X

X

X

X

15

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

1. Should the following be classified as part of the BES?
•

Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with both primary and
secondary windings of 100 kV or higher

Summary Consideration: Stakeholders who responded to this question were evenly divided with about half the respondents indicating support
for the proposal, and the other half disagreeing with at least some part of the proposal.
The SDT has clarified the definition based on industry comments regarding the classification of transformers.
Included in the BES: I1 - Transformers, other than generator step-up (GSU) transformers, including phase angle regulators, with two
windings of 100 kV or higher unless excluded under Exclusions E1 and E3.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an
automatic interruption device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’
fashion to allow for reliable system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not
identified in Inclusions I2, I3, I4 and I5.
Excluded from the BES: E3 - Local distribution networks (LDN): Groups of Elements operated above 100 kV that distribute power to Load
rather than transfer bulk power across the interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than
one location solely to improve the level of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through
automatic fault-interrupting devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA
generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through
the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent flowgate in the
Eastern Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a
comparable monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).

March 30, 3011

16

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
Northeast Power Coordinating
Council

Yes or No
No

Question 1 Comment
1. Exclusions should be applied to radial non-transmission facilities serving a distribution function.
Step-down transformers with the low-side terminals serving non-BES facilities, which are serving a
distribution function, should not be part of the definition of BES.
2. Transformers, other than GSUs, with both primary and secondary winding above 100kV, and performing a
transmission function, should be classified as BES.
3. Transformers other than GSUs, with both primary and secondary windings above 100kV, and only
providing a distribution function should be classified as non-BES.
4. Transformers other than GSUs, with their secondary windings or both primary and secondary windings
operated below 100kV should not be included in the definition of BES.

Response:
1. The SDT has excluded local distribution networks as shown:
• Excluded from the BES: E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV that distribute power to Load rather than
transfer bulk power across the interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to improve
the level of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting
devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the Quebec Interconnection,
and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
The SDT agrees with your suggestion and has incorporated it in its latest proposal.
2. The SDT agrees with your suggestion and has incorporated it in its latest proposal:
Included in the BES: I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two windings of 100 kV
or higher unless excluded under items E1 and E3.
Excluded from the BES: Any radial system which is described as connected from a single Transmission source originating with an automatic interruption

March 30, 3011

17

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment

device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.
3. The SDT feels that your comment does not illustrate a readily identifiable bright-line designation as there is no definition for distribution. However, the SDT
has determined that such transformers on a radial system will be non-BES.
4. The SDT agrees with your suggestion and has incorporated it in its latest proposal.
Electric Market Policy

No

Dominion could respond yes if the sentence read “All transformers, including Generator Step-up (GSU)
transformers and Phase Angle Regulators, with both primary and secondary windings of 100 kV or higher.

ExxonMobil Research and
Engineering

No

Transformers like all elements should be included based on their function; however, the use of an element's
rating or operating voltage may provide a good guideline for selecting elements to review for inclusion in the
BES.

Response: The SDT does not share your view on the inclusion of all transformers and feels that transformers used in Transmission and generation should be
included. The SDT agrees that operating voltage is a good guideline for applying the definition of BES.
PacifiCorp

March 30, 3011

No

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology. Significant
efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF) over the
course of the past year to identify some initial criteria and methodologies. These efforts are ongoing and
should be supported by the NERC drafting team. For example: Transformers should not be included or
excluded solely based on their voltage classifications (high side and low side). Transformers which are
necessary to operate the interconnected network should be included as part of the regulated BES.
Transformers which are not “necessary for the operation of the interconnected network” should be excluded.
A methodology needs to be developed to determine which transformers may be excluded as part of the

18

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
regulated BES.

Response: The SDT is aware of the WECC Bulk Electric System Definition Task Force’s efforts and has considered that work. The SDT has revised the
definition and included specific inclusion and exclusion designations. Bright-line designations will be developed as part of this project and the process will handle
any exceptions and those will be addressed through the revision of the Rules of Procedure which is a separate parallel effort to the development of the BES
definition by another team. Your comments will be forwarded to the Rules of Procedure Team.
Hydro-Québec

No

For questions 1 to 10, refer to questions 11 to 13.

Response: Please see responses to questions 11 to 13.
National Rural Electric
Cooperative Association
(NRECA)

No

This should not be dependent only on the voltage, but also on where the transformer, etc., is located on the
system. For example, if such a transformer is on a radial line of any transmission voltage that is serving only
load, then it should not be considered part of the BES.

Orange and Rockland Utilities,
Inc.

No

Exclusions should be applied to radial non-transmission facilities serving a distribution function. Step-down
transformers with the low-side terminals serving non-BES facilities, which are serving a distribution function,
should not be part of the definition of BES. Transformers, other than GSUs, with both primary and secondary
winding above 100kV should be classified as BES. However, it is our belief that transformers with either a
primary or secondary winding below 100kV should not be included directly or through the separate BES
Definition Exception Process.

City of Anaheim

No

Transformers with secondary windings of 100kV or less should not be part of the BES if they feed radial load
or radial distribution systems; provided, however, to eliminate any reliability gaps, such transformers should
be classified as "Distribution" equipment subject to DP standards, and the PRC and vegetation management
standards should be made applicable to Distribution Providers and including this equipment. This is
consistent with the NERC Reliability Functional Model and is more efficient than requiring TO/TOP
registration for radial transmission facilities that function as Distribution and are not required for the reliable
operation of the BES.

Southern California Edison
Company

No

The presence of an Automatic Fault Interrupting Device (or in the instance of a ring bus or breaker-and-a-half
configuration) allows the transformer to be considered as a separate unit serving the function of providing
connection and transformation of the high-side to the low-side. Where the electric facilities on the low-side are
below 100kV, the transformer is simply an extension of non-BES facilities, providing delivery and connectivity
from the BES sources.

March 30, 3011

19

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment

PPL Energy Plus

No

Certain transformers with primary and secondary windings greater than 100 kV may serve transmission lines
with only radial load and should therefore be excluded from the BES definition (without requiring application
for an exemption on a case-by-case basis). The BES definition should be modified to incorporate this
exclusion.

LG&E and KU Energy LLC

No

Certain transformers connected with both primary and secondary windings of 100 kV or higher serving only
radial load should be excluded from the BES definition (without requiring application for an exemption on a
case-by-case basis). The BES definition should be modified to incorporate this exclusion.

Central Lincoln

No

PUD No.1 of Clallam County

No

Lewis County PUD

No

While we believe the SAR is on the right track here, we note that many transformers with both windings above
100 kV may be installed on radial systems. We also note that the FERC order excepted “defined radial
facilities,” and expect NERC to provide a definition for “radial” so that facilities that meet this criteria may be
excluded by inspection rather than by going through an exemption process. It should also be clarified that
transformer protection systems are part of the BES only if installed to protect BES transformers.

Response: The SDT agrees with your suggestion and has incorporated it in its latest proposal.
•

Included in the BES: I1 - Transformers, other than generator step-up (GSU) transformers, including phase angle regulators, with two windings of 100 kV or
higher unless excluded under Exclusions E1 and E3.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5.

American Municipal Power

No

Occidental Energy Ventures Corp

No

This would require further study in order to answer in the affirmative.

Response: Thank you for your comment.

March 30, 3011

20

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
Indeck Energy Services

Yes or No

Question 1 Comment

No

The threshold issue is whether the equipment affects the reliability of the Bulk Power System, as defined in
the FPA. By requesting a BES definition that greatly expands the jurisdiction of the NERC Standards beyond
the scope of the BPS, FERC and NERC are outside of their legal jurisdiction. NERC is responsible to the
FPA through the FERC, but not to the FERC instead of the FPA. NPCC had the correct approach until FERC
required it to register every entity down to 20 MW. Reliability is the issue, and in a 30,000+ MW system like
NYISO, a 20, 50 or 150 MW piece of equipment cannot cause a Reportable Disturbance (under NERC's
definition), so how can it have a significant impact on reliability? Deferring the development of the exemption
process to a separate, and possibly much delayed, process of modifying the Rules of Procedure is
disingenuous.

Response: The SDT has been tasked with coming up with a revised definition of the Bulk Electric System. The SDT is following through on this charge. Brightline designations will be developed as part of this project and the ROP process will handle any exemptions or inclusions and those will be addressed through the
revision of the Rules of Procedure which is a separate parallel effort to the development of the BES definition utilizing a different team.
Glacier Electric Cooperative

No

I think it depends on the transformer. If the loss of the transformer would significantly affect the reliability of
the grid, then, yes, it should be included. However, if the loss of the transformer would not significantly affect
the reliability of the grid, then, no, it should not be included no matter what voltage it is connected at.

ReliabilityFirst

Yes

In some cases, facilities that need included do not have both windings operated at 100 kV or higher. This
needs further detail and definition to be helpful in determining if the facility is included or excluded. An
example of this is a distribution transformer (e.g. 138/34 kV) tapped from a BES line with a high side
protective device (such as a circuit switcher or ground switch), in which case the BES line to which it is
connected will trip (and may or not lockout) for a fault in the transformer. Should the distribution transformer
lockout the BES line to which it is connected, and then it should be included in the BES. If the distribution
transformer only trips the BES line to which it is connected (and successfully recloses), it could be argued
whether it should be included in the BES or not. But this issue needs to be addressed in the revised BES
definition.

Response: The SDT feels that your comment does not illustrate a readily identifiable bright-line designation. Bright-line designations will be developed as part of
this project and the ROP process will handle any exemptions or inclusions and those will be addressed through the revision of the Rules of Procedure; which is a
separate parallel effort to the development of the BES definition. Your comments will be forwarded to the Rules of Procedure Team.
Snohomish County PUD

No

PNGC Power

No

March 30, 3011

We note that many transformers with both windings above 100 kV may be installed on radial systems or local
networks used to provide local distribution service. Transformers installed on such systems should not be
part of the BES regardless of operating voltage. We also note that in Order No. 743, FERC made clear that it

21

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric
Cooperative

No

Lincoln Electric Cooperative

No

March 30, 3011

Question 1 Comment
does not intend the Standards Drafting Team to change the exception for radial facilities, and expects the
standards development process to provide a definition for “radial” so that facilities that meet this criteria may
be excluded by inspection rather than by going through an exemption process.
The Standards Drafting Team should also clarify that transformer protection systems are part of the BES only
if installed to protect “BES transformers” (transformer with both windings above 200kV).

22

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
Fall River Electric Cooperative

Yes or No

Question 1 Comment

No

Response: The SDT agrees with your suggestion and has incorporated it in its latest proposal.
•

Included in the BES: I1 - Transformers, other than generator step-up (GSU) transformers, including phase angle regulators, with two windings of 100 kV or
higher unless excluded under Exclusions E1 and E3.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.

The SDT has discussed this issue and will be seeking guidance from FERC staff in regards to the directives in FERC Order No. 743 and how they potentially
apply to Protection Systems. Protection Systems are not currently within the scope of the SAR for this project and any significant expansion could potentially
jeopardize the ability of the SDT to complete this project and file in accordance with the Commission directed time requirements in FERC Order No. 743.
Utility Services

No

Initially, yes; however, such a classification could be exempted upon a NERC review of the technical
justification for exemption.
We suggest that the BES definition be changed to: All Transmission and Generation Elements operated at
voltages of 100 kV or higher; unless modified by the BES Exemption Process.
We note that the term Facility, as defined in the NERC Glossary, implies that it is part of the BES. We
suggest that the BES definition just use the term Element since Facility is already defined as being a part of
the BES.
We envision the BES Exemption Process containing 3 sub-processes; one for Exclusion, one for Exemption,
and one for Inclusion. Each sub-process will establish provisions and guidelines for the three different tasks.
In order to ensure consistency across the continent, it is our view that NERC will be the facilitator of these
processes. We believe that NERC may choose to provide that some of these tasks may be performed at the
regional levels through the existing delegation agreements.
For “Exclusion”, we envision NERC establishing a first set of Exclusions, with FERC’s acceptance, that
Registered Entities can utilize as a means to justify not registering within the ERO or as a means to not have

March 30, 3011

23

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
to meet the compliance obligations of specific reliability standards and or requirements. NERC would also be
in a position to add or remove Exclusions provided such was performed through notification to the industry
and industry’s acceptance. If a Registered Entity uses a listed accepted Exclusion, it would be our
expectation that the RE would be treated in a manner similar to an unregistered organization, in that penalties
or sanctions could not be assessed during the exclusionary period. NERC would have the ability to revoke an
RE’s use of an Exclusion prospectively only. However, If NERC or the Regional Entity determined that a
Registered Entity intentionally claimed an accepted Exclusion; and it turned out to be knowingly false, the
Registered Entity would be subject to penalties and or sanctions appropriate to the period of the falsehood. In
order for Elements to be “Included” or “Exempted”, we envision that NERC will establish a set of criteria
including outlining the types of permissible technical studies or documentation necessary to seek inclusion or
an exemption.
We feel that any inclusion or exemption should be handled on an Element by Element basis, not by broad
application of a set of Elements. Each should be judged based upon its technical merits of the Element(s)
involved.
While an inclusion or exemption is pending, the Registered Entity shall not be subject to the performance
obligations under the any reliability standard(s) associated with the Element(s) being considered.
For Inclusion, any Registered Entity may submit Element(s) with the appropriate materials meeting the criteria
for Inclusion.
For there to be consistency within the ERO, NERC must be the evaluator of the requests. We believe there
must be a measurable, not subjective, improvement in the reliability of the transmission system for the
Element(s) to be included.
All Registered Entities, including applicable RCs, BAs, TOPs, and Regional Entities, who would be impacted
by the proposed Inclusion must be provided sufficient notice and time to participate in the consideration
process. NERC shall render a decision following the timely submission from the potentially impacted
Registered Entities.
For an Exemption to be granted, any Registered Entity may submit Element(s) with the appropriate materials
meeting the criteria for Exemption.
For there to be consistency within the ERO, NERC must be the evaluator of the requests. We believe there
must be no measurable, not subjective, decrease in the reliability of the transmission system for the
Element(s) to be included.
All Registered Entities, including applicable RCs, BAs, TOPs, and Regional Entities, who would be impacted
by the proposed exemption must be provided sufficient notice and time to participate in the consideration
process. NERC shall render a decision following the timely submission from the potentially impacted

March 30, 3011

24

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
Registered Entities.
We note that BES Exemption Process must be an active and ongoing aspect of the ERO program. With the
addition of new or deletion of existing Transmission and Generation Elements, Facilities, or systems; it needs
to be recognized that Exclusions, Inclusions, and Exemptions could possibly need alteration over time. By
establishing appropriate guidelines and processes, the ERO will be able to monitor and maintain information
of what is the bulk electric system or BES.

Response: The SDT thanks you for your comments on the inclusion of transformers.
The SDT agrees with your view that a briefer, more concise definition is beneficial and has incorporated it in the latest proposal.
The SDT agrees with the use of the term, “Elements” rather than “Facilities” and has corrected its use throughout the proposal.
The SDT does not share your view of the BES exception process. Bright-line designations will be developed as part of this project and the ROP process will
handle any exceptions and those will be addressed through the revision of the Rules of Procedure which is a separate parallel effort to the development of the
BES definition utilizing a different team. Your comments will be forwarded to the Rules of Procedure Team.
The Dow Chemical Company

The Dow Chemical Company (“Dow”) recommends that NERC finalize a basic framework for identifying BES
facilities before evaluating individual facilities or types of facilities. Such a framework is recommended by
Dow in response to questions #11 and #12 below.

Response: See response to Q11 & 12.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Yes

Constellation firmly believes that the classifications found in the Compliance Registry Criteria - Section III
(Rules of Procedure Appendix 5B), such as that cited in this question, provide a useful basis to create a
comprehensive, revised BES definition.
Further, we propose that the BES drafting team incorporate the criteria directly into the revised BES definition,
replacing the term “bulk power system” in each criterion with “greater than 100 kV.” This would then include
assets that are currently registered as BES elements as well as those that may have been previously
excluded due to Regional exemption variances. Structuring the revised BES definition to clarify both the
inclusions and exclusions, can, ideally, eliminate the need for an onerous exemption process as well as
eliminate the need for Section III of the Registry Criteria.
Please see our response to question 12 for more detail on a proposed alternative approach to structuring the
BES definition revision.

Response: The SDT agrees and has incorporated as one of its goals that it will not drive a change in the registry criteria if at all possible. .

March 30, 3011

25

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment

The SDT agrees with your suggestion and has incorporated it in its latest proposal.
Please see response to Question 12.
Florida Municipal Power Agency

Yes

In general, yes, unless it is part of a radial Element that is excluded from the BES.

Transmission Access Policy
Study Group

Yes

See FMPA response to Question 12 below. Throughout these comments, FMPA refers to “Elements” and not
to “facilities.”
This is because “Facility” is defined in the NERC Glossary as “[a] set of electrical equipment that operates as
a single Bulk Electric System Element....” Because these comments (and the BES definition) address
whether Elements are or are not part of the BES, it is incorrect to refer to the Elements in question as
“Facilities,” because a Facility is defined as a BES Element.

Response: The SDT agrees with your suggestion and has incorporated it in its latest proposal.
•

Included in the BES: I1 - Transformers, other than generator step-up (GSU) transformers, including phase angle regulators, with two windings of 100 kV or
higher unless excluded under Exclusions E1 and E3.
Excluded from the BES: Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.

See response to Q12.
The SDT agrees with the use of the term, “Elements” rather than “Facilities” and has corrected its use throughout the proposal.
NERC Staff

Yes

Please see additional comments in Attachment 3 at the end of this report.

Response: Please see response to Q13.
Public Service Enterprise Group
Company

March 30, 3011

Yes

The PSEG Companies consider transformers with primary and secondary windings of greater than 100 kV,
and which are not GSU transformers to be part of the BES.

26

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment

Competitive Suppliers

Yes

SERC EC Planning Standards
Subcommittee

Yes

MRO's NERC Standards Review
Subcommittee

Yes

IRC Standards Review
Committee

Yes

Bonneville Power Administration

Yes

FirstEnergy Corp

Yes

SERC OC Standards Review
Group

Yes

Arizona Public Service Company

Yes

AZPS agrees that Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle
Regulators, with both primary and secondary windings of 100 kV or higher should be classified as part of the
BES.

Pepco Holdings Inc.

Yes

Transformers with primary greater than 100kv (connected to a BES facility) but a secondary less than 100kv
are not specially addressed. They should be specially “excluded” and not part of an exemption process.

LCRA Transmission Services
Corporation

Yes

ERCOT, this would include the 138:345-kV autotransformers.

Manitoba Hydro

Yes

North Carolina EMC

Yes

March 30, 3011

EPSA believes that it is appropriate that transformers other than generator step-up transformers, including
Phase Angle Regulators, with primary and secondary windings of 100 kV or higher should be classified as
part of the BES under the proposed definition for Project 2010-17.

Yes, since FERC has directed the bright-line criteria is 100kV or above.

27

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

on behalf of Teck Metals Ltd.

Yes

Southern California Edison

Yes

on behalf of Catalyst Paper
Corporation

Yes

City of Grand Island

Yes

ISO New England Inc.

Yes

Entergy Services

Yes

United Illuminating Company

Yes

American Transmission
company

Yes

City of Austin dba Austin Energy

Yes

Duke Energy

Yes

The Dayton Power and Light
Company

Yes

ITC Holdings Corp

Yes

BGE

Yes

City Water Light and Power
(CWLP) - Springfield, IL

Yes

American Electric Power (AEP)

Yes

March 30, 3011

Question 1 Comment

SCE currently reports on many of its transformers with both primary and secondary windings of 100kV or
higher.

Only those transformers that are not a radial Transmission Element should be included.

No comment.

28

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment

Southern Company

Yes

Only non-radial networked transformers with both primary and secondary voltages >_100kV should be
included in the BES definition.

Idaho Power

Yes

Independent Electricity System
Operator

Yes

Conditional on having an exemption criteria/process which must still be developed.

Springfield Utility Board

Yes

If BOTH primary AND secondary windings are 100kV or higher

Clark Public Utilities

Yes

Xcel Energy

Yes

City of Redding

Yes

Only if the elements or facilities are shown through engineering studies to be necessary to reliably operate an
interconnected transmission system.

Response: Thank you for your response. Please see the summary consideration immediately under the question. Several stakeholders made suggestions that
were adopted by the drafting team.

March 30, 3011

29

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

2. Should the following be classified as part of the BES?
•

Individual generation resources (including GSU transformers and the associated generator interconnecting line lead(s))
greater than 20 MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Transmission Facilities
operated at voltages of 100 kV or above

Summary Consideration: Most Stakeholders who responded to this question disagreed with at least some part of the
proposal.
The SDT has discussed the history and determination of the 20 MVA threshold for inclusion of generating units in the Statement
of Compliance Registry Criteria and subsequently into a draft definition of the BES. Two Regional Entities (FRCC and RFC)
specifically use this criterion in each of their current BES definitions. The 20 MVA unit is a low enough level to capture most
generating units that have an effect on the reliability of the BES and that may be dispatched by Balancing Authorities, but
allows for the exclusion of smaller units, such as 10 MVA units, connected to the BES that may not be dispatched by Balancing
Authorities. The SDT believes that the 20 MVA threshold for inclusion of generating units connected at 100 kV and above is
proper for inclusion in the BES since there is no technical basis to change the values contained in the Statement of Compliance
Registry Criteria. The SDT also has carefully discussed the inclusion of generator step-up (GSU) transformers and associated
interconnection line leads and believes the BES must be contiguous at this level in order to be reliable. The SDT believes it
does not make sense to include generation in the BES without including the Facilities to transfer power from a generating unit
to the BES. The GSUs and line leads must be a part of the BES the same as other Facilities are part of the BES.
Commenters have suggested other thresholds (anywhere from 0 to 100 MVA) for generation plants to be included into the BES
definition. However, as of this date commenters have not submitted technical justification upon which to base a significant
departure from the generation MVA thresholds included in the NERC Statement of Compliance Registry Criteria.
Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the
generator terminals through the GSU which has a high side voltage of 100 kV or above.
Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) including the generator terminals through the GSUs, connected through a common
bus operated at a voltage of 100 kV or above.
Included in the BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a collector system through a common point of interconnection to a system Element
at a voltage of 100 kV or above.
Excluded from the BES: E2 - A generating unit or multiple generating units that serve all or part of retail Load with
electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does not exceed the
criteria identified in Inclusions I2 or I3, and (ii) standby, back-up, and maintenance power services are provided to the
generating unit or multiple generating units or to the retail Load pursuant to a binding obligation with a Balancing

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable regulatory
authority.

Organization

Yes or No

Question 2 Comment

Northeast Power Coordinating
Council

No

Some generators act as a local load modifier, regardless of connected voltage. The power generated is
consumed locally and does not flow up onto the BES, nor does its operation materially impact any BES
transmission facilities. If a generator functions as a local load modifier and does not materially impact the
BES, meaning that it is not necessary to maintain BES reliability, then it should be excluded from the
definition of BES under the BES Exemption Process.

Orange and Rockland Utilities,
Inc.

No

Some generators act as a local load modifier, regardless of connected voltage. The power generated is
consumed locally and does not flow up onto the BES, nor does its operation materially impact any BES
transmission facilities. If a generator functions as a local load modifier and does not materially impact the
BES, meaning that it is not necessary to maintain BES reliability, then it should be excluded from the
definition of BES under the BES Exemption process.

Response: The SDT has discussed the behind-the-meter customer generation issues and has addressed it in the revised BES definition.
Excluded from the BES: E2 - A generating unit or multiple generating units that serve all or part of retail Load with electric energy on the customer’s side of
the retail meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in items I2 or I3, and (ii) standby, back-up, and maintenance
power services are provided to the generating unit or multiple generating units or to the retail Load pursuant to a binding obligation with a Balancing
Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable regulatory authority.
Public Service Enterprise Group
Company

No

The concept of a stand-alone generator connected through a single GSU transformer to the grid at greater
than 100kV should be included as part of the BES. However, the term “generation resources” is too vague
leading to possible misinterpretation as to what associated generator resource elements are to be included
within the BES. All those “resources” and any connected element would be part of the BES? The definition
should clearly describe (with examples) of the intent of what should be included within the BES scope.. (e.g.
Would a station service transformer connected at 26kV which is part of the generation “resource” be included
as a BES element)?

Response: The SDT has discussed what constitutes a “generation resource” including balance of generation plant controls and auxiliary equipment and believes
that balance of plant equipment is not within the scope of this project. The term “generation resource” is no longer used in the revised definition. Certain
equipment, such as protection systems and under-frequency Load shed controls, may not be part of the BES, but may be subject to specific NERC standards
requirements. Generation plant controls should be treated in a similar fashion.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
Electric Market Policy

Yes or No

Question 2 Comment

No

Dominion does not agree that a generation resource should be classified as part of the BES.Dominion
supports the criteria for registering owners, operators, and users of the bulk power system, as indicated in the
current Statement of Compliance Registry Criteria .

Response: The SDT has carefully considered this matter, and believes that generating units and plants are an integral part of the BES, without which it could not
function, and therefore, should be included in the BES.
SERC OC Standards Review
Group

No

We do not agree with the inclusion of GSU transformers and associated interconnecting line leads. Lines and
transformers should be included based upon the voltage and not the function they serve.
We support the inclusion of all non-radial lines operated at a voltage of 100 kV or higher as well as all
transformers with both primary and secondary windings operated at 100 kV or higher.
We do not support generic inclusions of any radial lines or transformers with primary or secondary windings
operated below 100kV. Our response in question 13 amplifies this statement.

Response: The SDT has carefully discussed the inclusion of GSU transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable. The SDT believes it does not make sense to include generation in the BES without including the Facilities to
transfer power from a generating unit to the BES. The GSUs and line leads must be a part of the BES the same as other Facilities are part of the BES.
Please also see the response to Q13.
PacifiCorp

March 30, 3011

No

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology. Significant
efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF) over the
course of the past year to identify some initial criteria and methodologies. These efforts are ongoing and
should be supported by the NERC drafting team. For example: Generation units should not be included or
excluded solely based on a their gross nameplate rating and the operating voltage at which they are
connected to transmission facilities. Generation resources which are necessary to operate the interconnected
network should be included as part of the regulated BES. Generating units which are not “necessary for the
operation of the interconnected network” should be excluded. A methodology needs to be developed to

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment
determine which generating units may be excluded as part of the regulated BES.

Central Lincoln

No

The generation resources so described should be presumed to be part of the BES unless or until they have
been through the exemption process and as a result have been classified as non-BES.

PUD No.1 of Clallam County

No

The generation resources so described should be presumed to be part of the BES unless or until they have
been through the exemption process and as a result have been classified as non-BES. The 20 MVA threshold
is too low for many parts of the system. The interconnecting source impedance and adjacent facilities may
have a more significant impact on the BES than the MVA of a machine. A 100 MVA plant connected to a high
fault duty/low source impedance system may create little to thermal or transient stability concerns even under
delayed clearing. However a 25 MVA plant connected to a low fault duty/high source impedance system may
create concerns on a weak system. or above.

Snohomish County PUD

No

The generation resources described should not be presumed to be part of the BES. The criteria above are
intended to identify GO/GOP registration as a user/owner/operator rather than to identify BES elements. On
this score, we note there has been considerable confusion between the NERC Statement of Registry Criteria,
which is merely intended to establish a list of entities that may presumptively be required to comply with
Reliability Standards, and the BES definition, which defines which facilities are ultimately protected by
Reliability Standards. In defining the BES, those concepts should be kept separate.

Response: The SDT believes the revised definition contains enough criteria (both for exceptions and inclusions) to determine most, if not all, of the Elements that
will be part of the BES. The SDT also believes that the criteria for including generating units 20 MVA and greater that are connected to the BES at 100 kV and
above provides the “bright-line” criteria that will eliminate the ambiguity the Commission cited in Order 743.
The separate exception process will be drafted by the Rules of Procedure Drafting Team with the DBES SDT developing the bright-line criteria. There will be
coordination between the two groups in this effort.
Hydro-Québec

For questions 1 to 10, refer to questions 11 to 13.

Response: Please see response to Q11 to Q13.
City of Redding

No

The NERC Registration Criteria thresholds were a good start at the time of implementation of the compliance
program, however there is no engineering evidence that all of the facilities are necessary to reliably operate
an interconnected transmission system.

Independent Electricity System

No

To be totally consistent with the 100 kV bright line approach, any Elements and Facilities that are not
operated at voltages of 100 kV or higher should be excluded unless otherwise determined to be included

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Operator

Question 2 Comment
through the exemption/inclusion process being developed.

Lewis County PUD

No

20MVA generation resources should not be part of the BES. This size generating resource is too small to
affect the BES. Suggest the minimum size BES resource be changed to 100MVA for a single generator. If a
smaller threshold is used then the RE or BA should demonstrate to the GO than this resource is critical to the
BES

ITC Holdings Corp

No

20 MVA is too small a unit to be included in the BES definition. The definition should include units or plants
with 75 MVA or more

Glacier Electric Cooperative

No

Once again, I believe it depends on the facility and whether or not it has a significant impact on the grid.

American Municipal Power

No

Suggest 50 MVA

Arizona Public Service Company

No

The minimum size should be 50 MVA connected to 200 kV or higher. Small generators or plants do not
materially impact the reliability of the BES and do not need to be included.

PPL Energy Plus

No

LG&E and KU Energy LLC

No

The 20 MVA threshold appears to be arbitrary and will include many small generation facilities that have
minimal impact on BES reliability, A 200 MVA aggregate threshold for generating units at the same site
would be more appropriate. Generators that are smaller than 200 MVA are not likely to have a significant
impact on the BES and should be excluded from the definition (without requiring application for an exemption
on a case-by-case basis). The BES definition should be modified to incorporate this exclusion.(See also
response to Question 8.)

Response: The SDT has carefully considered this threshold, and believes that the 20 MVA unit is a low enough level to capture most generating units that have
an effect on the reliability of the BES and may be dispatched by Balancing Authorities, but allows the exclusion of smaller units, such as 10 MVA units, connected
to the BES that may not be dispatched by Balancing Authorities. The SDT believes the 20 MVA threshold for inclusion of generating units connected to the BES is
proper.
ExxonMobil Research and
Engineering

March 30, 3011

No

I have reservations about the removal of the ability to use the net rating of a generation asset as the
generator rating (i.e. the use of gross rating of a machine instead of net rating of the energy provided to the
BES). Many industrial companies have back up power agreements with utilities to cover the loss of internal
generation assets. The requirement to ensure that this back up power can be provided should be part of the
NERC requirements for Transmission Operators and Balancing Authorities (e.g. the VAR-001 requirement for
TOPs to obtain the necessary reactive resources to cover normal and contingency operations). The reliability
goals and strategy of some large electricity consumers that this change is targeting differ from the bulk

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment
electric system. For instance, a petrochemical facility that utilizes generation to offset the load seen by the
BES may desire to disconnect from the bulk electric system during an event in order to preserve the stability
of the private use network that supplies electricity to the equipment that control its chemical processes. As
history has demonstrated, the most dangerous activities that petrochemical facilities undertake are the
shutdown and startup of their processes.
As a side note, the term 'directly connected' should be added to the NERC glossary. The concept of 'directly
connected' is the key to understanding which generators are included in the BES and which generators are
exempted.

Response: The SDT has carefully considered “behind-the-meter” generation, and considers it to be an exclusion to the BES. The SDT agrees with the language
currently contained in the Statement of Compliance Registry Criteria regarding the exemption of net capacity associated with a retail meter.
Excluded from the BES: A generating unit or multiple generating units that serve all or part of retail Load with electric energy on the customer’s side of the
retail meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load pursuant to a binding obligation with a
Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable regulatory authority.
With the revised definition and designations, the SDT does not believe that the term ‘directly connected’ needs to be utilized or defined.
on behalf of Teck Metals Ltd.

No

Indeck Energy Services

No

on behalf of Catalyst Paper
Corporation

No

Clark Public Utilities

No

Same response as Question 1

Response: Please see response to Question 1.
City of Grand Island

No

This is a registration criteria issue. Can this project directly cause changes in the registration criteria?
20 MVA is too low. That size of generator can not affect the Adequate Level of Reliability of the BES. 100
MVA is appropriate for this region.

Response: The goal of the SDT is not to change registration criteria if at all possible. In this case, the SDT has adopted the registration criteria and no changes
are necessary.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment

The SDT has carefully considered this threshold, and believes that the 20 MVA unit is a low enough level to capture most generating units that have an effect on
the reliability of the BES and may be dispatched by Balancing Authorities, but allows the exclusion of smaller units, such as 10 MVA units, directly connected to
the BES that may not be dispatched by Balancing Authorities. The SDT believes the 20 MVA threshold for inclusion of generating units directly connected to the
BES is proper.
City of Anaheim

No

Unless the generator is required to maintain BES reliability, i.e. black start, etc., the GSU and gen tie should
be excluded from the BES; provided, however, to eliminate any reliability gaps, such generation-tie equipment
should be classified as "Generator" equipment subject to GO/GOP standards, and the PRC and vegetation
management standards should be made applicable to GO/GOPs and this equipment. This is consistent with
the NERC Reliability Functional Model and is more efficient than requiring TO/TOP registration for non-critical
generation-tie transmission elements that are not required for the reliable operation of the BES.

Response: The SDT has carefully discussed the inclusion of GSU transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable. The SDT believes it does not make sense to include generation in the BES without including the Facilities to
transfer power from a generating unit to the BES. The GSUs and line leads must be a part of the BES the same as other Facilities are part of the BES. The SDT
has carefully considered additional Facilities that may be included in the BES due to this project and the ramifications on registration of GO/GOPs and TO/TOPs.
However, the SDT must satisfy the Commission Order and do what is best for reliability of the BES. The development of the BES definition is not meant to result
in registration of GO/GOPs as TO/TOPs. That issue will be addressed as needed in Project 2010-07: Generator Requirements at the Transmission Interface.
PNGC Power

No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.
Douglas Electric Cooperative
Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

March 30, 3011

The generation resources described should not be presumed to be part of the BES. The criteria above are
intended to identify GO/GOP registration as a user/owner/operator rather than to identify BES elements. On
this score, we note there has been considerable confusion between the NERC Statement of Registry Criteria,
which is merely intended to establish a list of entities that may presumptively be required to comply with
Reliability Standards, and the BES definition, that defines which facilities are ultimately protected by Reliability
Standards. In defining the BES, those concepts should be kept separate. In general, we do not believe that
every generator rated at, or greater than, 20MVA should automatically be ‘assumed’ to be part of the BES.
We do believe that some of the Mandatory Reliability Standards should apply however. This leads to an
issue which might be somewhat philosophical, but, in this case, has real-world implications. We do not
believe that the BES is contiguous. That is, say every generator which is greater than 20MVA is assumed to
be part of the BES, does that mean that all the lines and equipment associated with this generator are also
part of the BES? We do not think so, hence the possibility that the BES is non-contiguous. We also believe
that some of the Mandatory Reliability Standards can apply to non-BES facilities, and equipment. A good
example is the UFLS standards. As you might realize some UFLS relays are on lines rated well below 100kV.
So in this case, a generator rated at 20MVA might not be part of the BES, but still the standards that apply to

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric
Cooperative

No

Lincoln Electric Cooperative

No

Fall River Electric Cooperative

No

Question 2 Comment
a generator could still apply.

Response: The SDT has carefully considered this threshold, and believes that the 20 MVA unit is a low enough level to capture most generating units that have
an effect on the reliability and adequacy of the BES and may be dispatched by Balancing Authorities, but allows the exclusion of smaller units, such as 10 MVA
units, directly connected to the BES that are not dispatched by Balancing Authorities. The SDT believes the 20 MVA threshold for inclusion of generating units
directly connected to the BES is proper. The SDT also believes that the criteria of including generating units 20 MVA and greater that are connected to the BES at
100 kV and above provides the “bright-line” criteria that will eliminate the ambiguity the Commission cited in Order 743. The SDT has carefully discussed the
inclusion of GSU transformers and associated interconnection line leads and believes the BES must be contiguous at this level in order to be reliable. The SDT
believes it does not make sense to include generation in the BES without including the Facilities to transfer power from a generating unit to the BES. The GSUs
and line leads must be a part of the BES the same as other Facilities are part of the BES.
United Illuminating Company

No

Any Generator connected at 100 kV or above should be part of BES. There should not be a MVA threshold

Response: The SDT has carefully considered this threshold, and believes that the 20 MVA unit is a low enough level to capture most generating units that have

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment

an effect on the reliability of the BES and may be dispatched by Balancing Authorities, but allows the exclusion of smaller units, such as 10 MVA units, directly
connected to the BES that may not be dispatched by Balancing Authorities. The SDT believes the 20 MVA threshold for inclusion of generating units directly
connected to the BES is proper. The SDT also believes that the criteria of including generating units 20 MVA and greater that are connected to the BES at 100 kV
and above provides the “bright-line” criteria that will eliminate the ambiguity the Commission cited in Order 743.
Southern Company

No

Lines and transformers should be included based upon the voltage and not the function they serve. We
support the inclusion of all non-radial lines operated at a voltage of 100 kV or higher as well as all
transformers with both primary and secondary windings operated at 100 kV or higher. We do not support
generic inclusions of any radial lines or transformers with primary or secondary windings operated below
100kV. Our response in question 13 amplifies this statement.
Individual, non-blackstart, generator
resources of 20MVA are too small to impact the reliability of the BES. We recommend single resource (unit)
inclusion threshold be increased to 75MVA to match the threshold indicated in Q3 below for the aggregated
case. Units smaller than 75MVA could be included using the “exemption process" or the NERC Compliance
Registry Criteria could be changed.

Response: Lines and transformers are discussed as part of Questions 1 and 5.
The SDT has carefully considered this threshold, and believes that the 20 MVA unit is a low enough level to capture most generating units that have an effect on
the reliability of the BES and may be dispatched by Balancing Authorities, but allows the exclusion of smaller units, such as 10 MVA units, directly connected to
the BES that may not be dispatched by Balancing Authorities. The SDT believes the 20 MVA threshold for inclusion of generating units connected to the BES is
proper.
The Dow Chemical Company

As discussed in response to question #12 below, issues relating to the registry criteria applicable to
generation resources should not be revisited at this time.

Response: See response to Q12.
Bonneville Power Administration

Yes

Generation resources should also define how wind generation is included in this clarification (by turbine, by
string, etc)

Response: Wind generating units would be included or excluded based upon the criteria for dispersed generation, generating units, and multiple generating units.
Included in the BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a
collector system through a common point of interconnection to a system Element at a voltage of 100 kV or above.
Florida Municipal Power Agency

March 30, 3011

Yes

1. For the sake of clarity and consistency, the BES should track the Statement of Compliance Registry Criteria

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
Transmission Access Policy
Study Group

March 30, 3011

Yes or No
Yes

Question 2 Comment
wherever possible. In this case, for example, generation resources with respect to which an entity is
registered as a Generator Owner or Generator Operator should be included in the BES, while nonregistered generation resources should not be included in the BES.
2. FMPA’ proposal, as further explained in response to the questions below, is introduced here in the interests
of clarity. FMPA proposes that the BES definition should establish the universe of Elements that are,
absent other factors, considered part of the BES. FMPA supports continuing to use a general 100 kV
threshold, and basing the inclusion of generators in the BES on whether the generation is registered
pursuant to the Statement of Compliance Registry Criteria. There is one “exclusion” in the definition
proposed by FMPA, i.e., the existing exclusion for radial transmission serving only load with one
transmission source (with a proposed clarification). Unlike the definition proposed in the draft SAR,
therefore, but like the current definition, FMPA’ proposal treats radial transmission Elements serving only
load with one transmission source like sub-100 kV Elements, in that they are presumed to be non-BES
unless a showing has been made, on a case-by-case basis, that a particular radial Element is necessary
for operating the interconnected electric transmission network. The current definition of the BES excludes
“radial transmission facilities serving only load with one transmission source,” and FERC stated in Order
743 that it did not intend to require a change to that exclusion. It is very important that radial transmission
serving only load with one transmission source remain excluded from the BES; if such radials instead had
to go through an exemption process, as the SDT’s proposed definition suggests, the burden on small
entities and on NERC and the Regional Entities would be staggering since it would be presumed that the
radial would be part of the BES until exempted (opt-out), where it should be that the radial should be
excluded from the BES unless there is a determination that it should be part of the BES (opt-in).
3. As explained in more detail in response to Question 8 below, FMPA supports adding the clarification that
radials serving generation that is not registered pursuant to the Statement of Compliance Registry Criteria
are covered by the exclusion of radials serving only load with one transmission source. Of course, the
application of the definition of the BES is dynamic. For example, in considering whether new generation
connected by what had previously been a radial to load should be registered, NERC may also reevaluate
the exclusion of the radial.
4. FMPA’ proposed definition of the BES is: In general, the Bulk Electric System includes all Transmission
Elements operated at voltages of 100 kV or higher, and all generation resources registered pursuant to the
Statement of Compliance Registry Criteria. Radial Transmission Elements serving only load with one
Transmission source are generally not included in this definition. A radial Transmission Element may be
considered as “serving only load” for purposes of the foregoing general exclusion even if it connects
generation, so long as that generation is not registered pursuant to the Statement of Compliance Registry
Criteria. An Element that nominally meets the general BES criteria, but which an entity demonstrates, on a
case-by-case basis, is not necessary for operating the interconnected electric transmission network, shall
be exempted from the BES pursuant to the NERC exemption process. An Element that does not nominally
meet the general BES criteria, but which NERC demonstrates, on a case-by-case basis, is necessary for

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment
operating the interconnected electric transmission network, shall be included in the BES pursuant to the
NERC inclusion process.
5. As FMPA’ proposed definition suggests, FMPA proposes that entities be able to seek “exemptions” for
Elements nominally included in the BES; obtaining an exemption would require a demonstration that the
Element to be exempted is not necessary for operating the interconnected electric transmission network.
Elements for which NERC has approved exemptions would not be part of the BES.
Conversely, FMPA proposes that NERC have the authority, upon a case-by-case demonstration that a
particular Element that is not nominally included in the BES is necessary for operating the interconnected
electric transmission network, to add such an Element to the BES.
6. Please see also FMPA’ Official Comment Form for BES Definition Exception Process, submitted today.

Response:
1. The SDT agrees that the definition should track the registry criteria. One of the basic tenets of the SDT scope is to not expand the registry criteria if at all
possible.
2. The SDT has revised the definition and included specific inclusion and exclusion criteria that address these issues. The SDT also believes that the revised
definition provides the “bright-line” criteria that will eliminate the ambiguity the Commission cited in Order 743. The separate exception process will be drafted
by the Rules of Procedure Team with the DBESSDT developing the criteria. There will be coordination between the two groups in this effort.
3. See response to Q8.
4. See response to #2 above.
5. The separate exception process will be drafted by the Rules of Procedure Team with the DBESSDT developing the criteria. There will be coordination
between the two groups in this effort.
6. See response to definition exception process.
ReliabilityFirst

Yes

It is recommended that the term “directly connected” be defined and examples of this term are included in the
ERO definition.
Also, most wind farms have multiple transformations when connected to the BES and the intent should be to
capture these wind farms in the BES, so more specific language is most likely needed in the definition to
capture them.

Response: The SDT has revised the definition and “directly connected” is no longer utilized in the revised draft definition.
The SDT has addressed the issue of wind generation in the revised draft definition.
Included in the BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a
collector system through a common point of interconnection to a system Element at a voltage of 100 kV or above.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
NERC Staff

Yes or No
Yes

Question 2 Comment
Please see additional comments at the end of this report.

Response: Please see response to Q13.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Yes

Constellation firmly believes that the classifications found in the Compliance Registry Criteria - Section III
(Rules of Procedure Appendix 5B), such as that cited in this question, provide a useful basis to create a
comprehensive, revised BES definition.
Further, we propose that the BES drafting team incorporate the criteria directly into the revised BES definition,
replacing the term “bulk power system” in each criterion with “greater than 100 kV.” This would then include
assets that are currently registered as BES elements as well as those that may have been previously
excluded due to Regional exemption variances. Structuring the revised BES definition to clarify both the
inclusions and exclusions, can, ideally, eliminate the need for an onerous exemption process as well as
eliminate the need for Section III of the Registry Criteria.
Please see our response to question 11 for more detail on a proposed alternative approach to structuring the
BES definition revision.

Response: The SDT agrees that the definition should track the registry criteria. One of the basic tenets of the SDT scope is to not expand the registry criteria if at
all possible
The SDT agrees and has made the suggested change.
See response to Q11.
Occidental Energy Ventures Corp

March 30, 3011

Yes

Many generator interconnection lines are operated at voltages greater than 100KV, but have traditionally not
been considered part of the the transmission system. Rather these lines have been considered part of the
generation system and, for quite some time, have been constructed and operated according to
interconnection agreements which specify design and protection criteria. The BES definition should not be
constructed in either a direct or implied manner that would alter the interconnection line status as being part of
the Generation Facilities. Otherwise, it could result in registration of GO/GOPs as TO/TOPs. The issue of
what additional standards, if any, should apply to these generation interconnection lines is the subject of
Project 2010-07 and should be resolved by that standards development effort, not by a definition change.
The proposed definition appears not to violate the inclusion of the interconnection line as part of the
Generation Facility while still providing for these lines to be part of the BES, however, some clarification might
be advisable (e.g., a statement that interconnection lines are part of the Generation Facility or are Generation
Elements).

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment

Response: The SDT has carefully considered additional Facilities that may be included in the BES due to this project and the ramifications on registration of
GO/GOPs and TO/TOPs. However, the SDT must satisfy the Commission Order and do what is best for reliability of the BES. The development of the BES
definition is not meant to result in registration of GO/GOPs as TO/TOPs. That issue will be addressed as needed in Project 2010-07: Generator Requirements at
the Transmission Interface.
American Transmission company

Yes

For clarity, ATC suggests that the (gross nameplate rating) be changed to read “(gross generator nameplate
rating)” and further classified as part of the BES given that a fault or outage of the individual generator
resource greater than 20 MVA would not maintain an Adequate Level of Reliability of the BES.

Response: The SDT discussed this and does not agree with the suggested wording change.
LCRA Transmission Services
Corporation

Yes

The 20 MVA threshold is too low.
Should consider the region’s or area’s reserve margin to determine the appropriate level of individual
generator loss. Leave this to the region to determine.

Response: The SDT has carefully considered this threshold, and believes that the 20 MVA unit is a low enough level to capture most generating units that have
an effect on the reliability of the BES and may be dispatched by Balancing Authorities, but allows the exclusion of smaller units, such as 10 MVA units, connected
to the BES that may not be dispatched by Balancing Authorities. The SDT believes the 20 MVA threshold for inclusion of generating units connected to the BES is
proper.
The SDT’s goal is to “eliminate the regional discretion in the ERO’s current definition”, which is specifically stated in the Commission’s Order.
Utility Services

Yes

Initially, yes; however, such a classification could be exempted upon a NERC review of the technical
justification for exemption.

Response: The SDT believes the revised definition will contain enough criteria to determine most, if not all, of the Facilities that will be part of the BES. The
exception process will be handled through the revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
Your comments will be forwarded to the Rules of Procedure Team.
Xcel Energy

March 30, 3011

Yes

Xcel Energy believes that clarity should be added as to what constitutes an individual generation resource
and a generating plant, especially as it pertains to multiple owner facilities and aggregating facilities such as
wind or solar farms (which may also have multiple owners for discreet facilities that tie into a common bus).
Discussion and controversy in other NERC and regional forums and standard development teams indicates
that this is not well defined. It may be that the Statement of Compliance Registry needs to be enhanced if it
forms the foundation for which these items are to be understood.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment

Response: The new wording for generating units in the revised definition has addressed this issue. The Statement of Compliance Registry Criteria should agree
with the BES definition, as they are intended not to be in conflict with each other.
Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the generator terminals through the GSU which
has a high side voltage of 100 kV or above.
Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
Included in the BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a
collector system through a common point of interconnection to a system Element at a voltage of 100 kV or above.
MRO's NERC Standards Review
Subcommittee

Yes

The SAR DT should use caution if the above statement is to be used within a guideline or rational box. The
use of the word “interconnecting line leads may be somewhat ambiguous and lead to other confusion.
GSU should be spelled out as a “generator step up transformer” and properly used within the statement:
Individual generation resources (including Generator Step Up transformers and the associated generator
interconnecting line lead(s)) greater than 20 MVA (gross nameplate rating) directly connected via a
Generator Step-Up transformer(s) to Transmission Facilities operated at voltages of 100 kV or above.
For clarity, the NSRS suggests that the (gross nameplate rating) be changed to read “(gross generator
nameplate rating)” and further classified as part of the BES given that a fault or outage of the individual
generator resource greater than 20 MVA would not maintain an Adequate Level of Reliability of the BES.

Response: The term “interconnecting lines leads” has been deleted in the revised definition.
Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the generator terminals through the GSU which
has a high side voltage of 100 kV or above.
Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
All acronyms used in the definition and supporting materials will be spelled out.
The SDT discussed the wording change to the term “gross generator nameplate rating” and does not agree with the suggested wording change.
SERC EC Planning Standards
Subcommittee

Yes

IRC Standards Review

Yes

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment

Committee
FirstEnergy Corp

Yes

Competitive Suppliers

Yes

Pepco Holdings Inc.

Yes

Manitoba Hydro

Yes

North Carolina EMC

Yes

Southern California Edison

Yes

SCE currently reports on individual generation resources (including GSU transformers and the associated
generator interconnecting line lead(s)) greater than 20 MVA (gross nameplate rating) directly connected via a
step-up transformer(s) to Transmission Facilities operated at voltages of 100 kV or above. SCE does not feel
a blanket inclusion of all the listed equipment is needed.

Southern California Edison
Company

Yes

A GSU transformer is clearly an extension of the functionality provided by the Generator Interconnection
Elements, namely, to move bulk power from the BES generator to the BES network, and hence, the
classification of the GSU transformer should match that of the Generator Interconnection Elements.

Entergy Services

Yes

City of Austin dba Austin Energy

Yes

Duke Energy

Yes

The Dayton Power and Light
Company

Yes

BGE

Yes

City Water Light and Power
(CWLP) - Springfield, IL

Yes

March 30, 3011

Increasing numbers of small generators could create reliability issues if excluded.

No comment.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

American Electric Power (AEP)

Yes

Idaho Power

Yes

Springfield Utility Board

Yes

Question 2 Comment

"directly connected" is important.

Response: Thank you for your response. Please see the summary consideration immediately under the question. Several stakeholders made suggestions that
were adopted by the drafting team.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

3. Should the following be classified as part of the BES?
•

Generation plants (including GSU transformers and the associated generator interconnecting line lead(s))with aggregate
capacity greater than 75 MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Transmission
Facilities operated at voltages of 100 kV or above

Summary Consideration: While many commenters did agree with the proposal, most commenters who responded to this question disagreed
with some aspect of the proposal.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. This
threshold is based on the generation threshold values found in the NERC Statement of Compliance Registry Criteria. Also, two Regional Entities
(FRCC and RFC) specifically use this criterion in each of their current BES definitions. The 75 MVA plant is a low enough level to capture most
generating plants that would have an effect on the reliability of the interconnected Transmission network.
Commenters have suggested other thresholds (anywhere from 0 to 300 MVA) for generation plants to be included into the BES definition.
However, as of this date commenters have not submitted technical justification upon which to base a significant departure from the generation
MVA thresholds included in the NERC Statement of Compliance Registry Criteria.
Included in BES: I3 – Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating) including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
Included in BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
utilizing a collector system through a common point of interconnection to a system Element at a voltage of 100 kV or above.
Excluded from BES: E2 - A generating unit or multiple generating units that serve all or part of retail Load with electric energy on the customer’s
side of the retail meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and (ii) standby,
back-up, and maintenance power services are provided to the generating unit or multiple generating units or to the retail Load pursuant to a
binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.

Organization

Yes or No

Question 3 Comment

Northeast Power Coordinating
Council

No

Refer to the response Question 2 above. The answer depends on whether the generator output is consumed
locally or is necessary to maintain the reliability of the BES.

PUD No.1 of Clallam County

No

See comments to question2.

Orange and Rockland Utilities,
Inc.

No

Refer to the response Question 2 above. The answer depends on whether the generator output is consumed
locally or is necessary to maintain the reliability of the BES.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment

No

As in question 2, there is no engineering evidence that all of the facilities are necessary to reliably operate an
interconnected transmission system.

No

Dominion does not agree that generation plants should be classified as part of the BES.Dominion supports
the criteria for registering owners, operators, and users of the bulk power system, as indicated in the current
Statement of Compliance Registry Criteria .

City of Redding

Response: Please see response to Q2.
Electric Market Policy

Response: Dominion makes the suggestion that all generators be excluded from the BES, however, Dominion does not provide a technical justification for this
significant departure.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
SERC OC Standards Review
Group

No

We do not agree with the inclusion of GSU transformers and associated interconnecting line leads. Lines and
transformers should be included based upon the voltage and not the function they serve.
We support the inclusion of all non-radial lines operated at a voltage of 100 kV or higher as well as all
transformers with both primary and secondary windings operated at 100 kV or higher. We do not support
generic inclusions of any radial lines or transformers with primary or secondary windings operated below
100kV. Our response in question 13 amplifies this statement.

Response: SERC has not provided justification for excluding all GSU transformers and associated interconnecting lines leads from the BES.
The SDT believes that generation plants larger than 75 MVA connected above 100kV including GSU transformers and interconnecting line leads need to be
included within the BES.
The SDT has revised the definition and included specific inclusion and exclusion criteria that address these issues.
Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
PacifiCorp

March 30, 3011

No

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology. Significant
efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF) over the
course of the past year to identify some initial criteria and methodologies. These efforts are ongoing and
should be supported by the NERC drafting team. For example: Generation plants should not be included or
excluded solely based on a their gross nameplate rating and the operating voltage at which they are
connected to transmission facilities. Generation plants which are necessary to operate the interconnected
network should be included as part of the regulated BES. Generating plants which are not “necessary for the
operation of the interconnected network” should be excluded. A methodology needs to be developed to
determine which generating plants may be excluded as part of the regulated BES.

Response: The SDT acknowledges that commenters will need to reserve judgment on the exception process, which is being developed as a modification to the
NERC Rules of Procedure (ROP). This exception process will be a parallel effort to this BES definition development. The SDT further acknowledges the work of
WECC and other regional entities (e.g., RFC, FRCC, and NPCC) in proposing the BES definition, bright lines, and exclusion/inclusion criteria and processes. The
work of these regional entities has greatly helped the SDT.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
PPL Energy Plus

No

See response to Questions 2 and 8.

LG&E and KU Energy LLC

No

See response to Questions 2 and 8.

No

I have reservations about the removal of the ability to use the net rating of a generation asset as the
generator rating (i.e. the use of gross rating of a machine instead of net rating of the energy provided to the
BES). Many industrial companies have back up power agreements with utilities to cover the loss of internal
generation assets. The requirement to ensure that this back up power can be provided should be part of the
NERC requirements for Transmission Operators and Balancing Authorities (e.g. the VAR-001 requirement for

Response: See response to Q2 & Q8.
ExxonMobil Research and
Engineering

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment
TOPs to obtain the necessary reactive resources to cover normal and contingency operations). The reliability
goals and strategy of some large electricity consumers that this change is targeting differ from the bulk
electric system. For instance, a petrochemical facility that utilizes generation to offset the load seen by the
BES may desire to disconnect from the bulk electric system during an event in order to preserve the stability
of the private use network that supplies electricity to the equipment that control its chemical processes. As
history has demonstrated, the most dangerous activities that petrochemical facilities undertake are the
shutdown and startup of their processes. As a side note, the term 'directly connected' should be added to the
NERC glossary. The concept of 'directly connected' is the key to understanding which generators are
included in the BES and which generators are exempted.

Response: The SDT’s proposed BES definition has exclusion criteria that address these issues.
Excluded from BES: E2 - A generating unit or multiple generating units that serve all or part of retail Load with electric energy on the customer’s side of the
retail meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load pursuant to a binding obligation with a
Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable regulatory authority.
Arizona Public Service Company

No

The minimum plant size should be 300 MVA. Smaller plants do not materially impact the reliability of thle
BES.

Response: The SDT appreciates the suggestion of a 300 MVA generation threshold for materiality of impact, however, as of this date sufficient technical
justification has not been submitted upon which to base a significant departure from the generation MVA thresholds included in the NERC Statement of
Compliance Registry Criteria.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
Central Lincoln

No

The generation resources so described should be presumed to be part of the BES unless or until they have
been through the exemption process and as a result have been classified as non-BES.

Response: Thank you for your response. The SDT agrees.
American Municipal Power

March 30, 3011

No

Suggest 125 MVA

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment

Response: The SDT appreciates the suggestion of a 125 MVA generation threshold, however, as of this date sufficient technical justification has not submitted
upon which to base a significant departure from the generation MVA thresholds included in the NERC Statement of Compliance Registry Criteria.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure, in a parallel effort to the development of this BES definition.
Indeck Energy Services

No

Same Response as Question 1

No

75 MVA aggregate is too low. 200 MVA aggregate is appropriate for this region.

Response: See response to Q1.
City of Grand Island

Response: The SDT appreciates the suggestion of a 200 MVA generation threshold however, as of this date sufficient technical justification has not been
submitted upon which to base a significant departure from the generation MVA thresholds included in the NERC Statement of Compliance Registry Criteria.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
City of Anaheim

No

Unless the generator is required to maintain BES reliability, i.e. black start, etc., the GSU and gen tie should
be excluded from the BES; provided, however, to eliminate any reliability gaps, such generation-tie equipment
should be classified as "Generator" equipment subject to GO/GOP standards, and the PRC and vegetation
management standards should be made applicable to GO/GOPs and this equipment. This is consistent with
the NERC Reliability Functional Model and is more efficient than requiring TO/TOP registration for non-critical
generation-tie transmission elements that are not required for the reliable operation of the BES.

Response: The SDT appreciates the City’s suggestions, however; the City’s recommendations go beyond the SAR scope of work given to the SDT. The SDT has
not been charged with determining the applicability of various standards.
Also, as of this date sufficient justification has not been submitted demonstrating that GSU transformers and interconnecting generation ties should be excluded
from the BES.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment

should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
Snohomish County PUD

No

The generation resources described should not be presumed to be part of the BES. The criteria above are
intended to identify those entities that are required to register as user, owner or operator of the bulk system,
and not to define a BES device. As noted in our response to question 2, Snohomish is concerned that the
enforcement process to date has frequently conflated registry criteria and definitions of the BES.

Response: Snohomish has not provided justification for varying from a 75 MVA bright line for determining BES generation plants. Further, as of this date, the
SDT has not received sufficient technical justification upon which to base a significant departure from the generation MVA thresholds included in the NERC
Statement of Compliance Registry Criteria.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
PNGC Power

No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Please see our response to Question 2

.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric
Cooperative

No

Lincoln Electric Cooperative

No

Fall River Electric Cooperative

No

Question 3 Comment

Response: See response to Q2.
Glacier Electric Cooperative

No

Once again, I believe it depends on the facility and its importance to the grid. Some 75 MVA plants will have
a greater impact than others. The ones that are truly important to the grid should be include, but the ones that
are not should not be. I believe more of an analytical approach would be much more accurate in determing
which facilities truly should be part of the BES than the bright-line approach that is being attempted.

United Illuminating Company

No

Any goupr of Generators connected at 100 kV or above should be part of BES. There should not be a MVA
threshold

Response: The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception
process – for exclusions/inclusions – should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such

March 30, 3011

52

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment

plants are not necessary for operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES
definition should include exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of
the revision to the NERC Rules of Procedure, in a parallel effort to the development of this BES definition.
Lewis County PUD

No

75MVA generation resources should not be part of the BES. This size generating resource is too small to
affect the BES. Suggest the minimum size BES resource be changed to 150MVA. If a smaller threshold is
used then the RE or BA should demonstrate to the GO than this resource is critical to the BES.

Response: The SDT appreciates the suggestion of a 150 MVA threshold for materiality of impact, however, sufficient technical justification has not been submitted
upon which to base a significant departure from the generation MVA thresholds included in the NERC Statement of Compliance Registry Criteria.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
Independent Electricity System
Operator

No

Same comment as in Q3, above.

Response: It is assumed that the commenter is referring to Q2. See SDT response to Q2.
The Dow Chemical Company

As discussed in response to question #12 below, issues relating to the registry criteria applicable to
generation resources should not be revisited at this time.

Response: See response to Q12.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation

March 30, 3011

Yes

Constellation firmly believes that the classifications found in the Compliance Registry Criteria - Section III
(Rules of Procedure Appendix 5B), such as that cited in this question, provide a useful basis to create a
comprehensive, revised BES definition.
Further, we propose that the BES drafting team incorporate the criteria directly into the revised BES definition,
replacing the term “bulk power system” in each criterion with “greater than 100 kV.” This would then include
assets that are currently registered as BES elements as well as those that may have been previously
excluded due to Regional exemption variances. Structuring the revised BES definition to clarify both the
inclusions and exclusions, can, ideally, eliminate the need for an onerous exemption process as well as

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Question 3 Comment
eliminate the need for Section III of the Registry Criteria.
Please see our response to question 11 for more detail on a proposed alternative approach to structuring the
BES definition revision.

Response: the SDT agrees that the Registry Criteria is a valuable resource for deliberations on a BES definition and has utilized it whenever possible.
The SDT agrees and has made the suggested change.
See response to Question 11.
Occidental Energy Ventures Corp

Yes

Many generator interconnection lines are operated at voltages greater than 100KV, but have traditionally not
been considered part of the the transmission system. Rather these lines have been considered part of the
generation system and, for quite some time, have been constructed and operated according to
interconnection agreements which specify design and protection criteria. The BES definition should not be
constructed in either a direct or implied manner that would alter the interconnection line status as being part of
the Generation Facilities. Otherwise, it could result in registration of GO/GOPs as TO/TOPs. The issue of
what additional standards, if any, should apply to these generation interconnection lines is the subject of
Project 2010-07 and should be resolved by that standards development effort, not by a definition change.
The proposed definition appears not to violate the inclusion of the interconnection line as part of the
Generation Facility while still providing for these lines to be part of the BES, however, some clarification might
be advisable (e.g., a statement that interconnection lines are part of the Generation Facility or are Generation
Elements).

Response: The SDT appreciates the Occidental’s suggestions, however; the recommendations go beyond the SAR scope of work given to the SDT. The SDT
has not been charged with determining the applicability of various standards.
American Transmission company

Yes

For clarity, ATC suggests that the “. . . aggregate capacity greater than 75 MVA . . . “ wording be changed to
read, “. . . aggregate generator capacity greater than 75 MVA. . . and further classified as part of the BES
given that a fault or outage of the aggregate generator capacity greater than 75 MVA would not maintain an
Adequate Level of Reliability of the BES.

Response: The SDT appreciates the ATC’s concern; however, ATC has not provided rationale for the change.
Xcel Energy

March 30, 3011

Yes

Xcel Energy believes that clarity should be added as to what constitutes an individual generation resource
and a generating plant, especially as it pertains to multiple owner facilities and aggregating facilities such as
wind or solar farms (which may also have multiple owners for discreet facilities that tie into a common bus).
Discussion and controversy in other NERC and regional forums and standard development teams indicates

54

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment
that this is not well defined. It may be that the Statement of Compliance Registry needs to be enhanced if it
forms the foundation for which these items are to be understood.

Response: The SDT has revised the BES definition and has included specific inclusion and exclusion criteria that addresses dispersed generation plants
(including wind and solar farms, which may contain multiple owners).
Included in BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a
collector system through a common point of interconnection to a system Element at a voltage of 100 kV or above.
The SDT has not been charged with making changes to NERC’s Statement of Compliance Registry Criteria and has adopted a goal of not changing that criteria if
at all possible.
Bonneville Power Administration

Yes

There needs to be additional clarity on the definition of generation plant. Wind generation needs to be
incorporated.

Response: The SDT has revised the BES definition and has included specific inclusion and exclusion criteria that addresses dispersed generation plants
(including wind and solar farms).
Included in BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a
collector system through a common point of interconnection to a system Element at a voltage of 100 kV or above.
NERC Staff

Yes

Please see additional comments at the end of this document.

Response: These comments were submitted in response to the concepts paper and were considered
MRO's NERC Standards Review
Subcommittee

Yes

See question 2 for similar comments and it is apparent that the SDT is trying to model the BES definition on
the Statement of Compliance Registry Criteria (v5). Recommend that this question be struck. Question 2
above addresses connection requirements of Generators. For clarity, NSRS suggests that the “. . . aggregate
capacity greater than 75 MVA . . . “ wording be changed to read, “. . . aggregate generator capacity greater
than 75 MVA. . . and further classified as part of the BES given that a fault or outage of the aggregate
generator capacity greater than 75 MVA would not maintain an Adequate Level of Reliability of the BES.

Response: The SDT appreciates the comments; however, the SDT has not received sufficient technical justification upon which to base a significant departure
from the generation MVA thresholds included in the NERC’s Statement of Compliance Registry Criteria. MRO has not provided a rationale for making the
language change.
ReliabilityFirst

March 30, 3011

Yes

It is recommended that the term “directly connected” be defined and examples of this term are included in the

55

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment
ERO definition.

Response: The SDT has revised the definition and the term “directly connected” is no longer utilized.
SERC EC Planning Standards
Subcommittee

Yes

Public Service Enterprise Group
Company

Yes

IRC Standards Review
Committee

Yes

Florida Municipal Power Agency

Yes

FirstEnergy Corp

Yes

Transmission Access Policy
Study Group

Yes

Competitive Suppliers

Yes

Pepco Holdings Inc.

Yes

LCRA Transmission Services
Corporation

Yes

Manitoba Hydro

Yes

North Carolina EMC

Yes

on behalf of Teck Metals Ltd.

Yes

Southern California Edison

Yes

March 30, 3011

Yes, but see comments in section 2 above.

See FMPA response to Question 2 above.

See TAPS response to Question 2 above.

See comment to item 2 above.

SCE currently reports on generation plants (including GSU transformers and the associated generator
interconnecting line lead(s))with aggregate capacity greater than 75 MVA (gross nameplate rating) directly

56

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment
connected via a step-up transformer(s) to Transmission Facilities operated at voltages of 100 kV or above.
SCE does not feel a blanket inclusion of all the listed equipment is needed.

Southern California Edison
Company

Yes

on behalf of Catalyst Paper
Corporation

Yes

Entergy Services

Yes

Utility Services

Yes

City of Austin dba Austin Energy

Yes

Duke Energy

Yes

The Dayton Power and Light
Company

Yes

ITC Holdings Corp

Yes

BGE

Yes

City Water Light and Power
(CWLP) - Springfield, IL

Yes

American Electric Power (AEP)

Yes

Southern Company

Yes

March 30, 3011

A GSU transformer is clearly an extension of the functionality provided by the Generator Interconnection
Elements, namely, to move bulk power from the BES generator to the BES network, and hence, the
classification of the GSU transformer should match that of the Generator Interconnection Elements.

Initially, yes; however, such a classification could be exempted upon a NERC review of the technical
justification for exemption.

No comment.

However, considering today’s transmission network and typical plant size, the plant size that can impact the
reliability should be reevaluated. Particularly Wind Farms with dozens of small generators could have an
impact on the BES if enough exist. Therefore, the 75 MVA threshold should work in this instance.

57

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Idaho Power

Yes

Springfield Utility Board

Yes

Clark Public Utilities

Yes

Question 3 Comment

"directly connected" is important.

Response: Thank you for your response. Please see the summary consideration immediately under the question. Several stakeholders made suggestions that
were adopted by the drafting team.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

4. Should the following be classified as part of the BES?
•

Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s (TOP’s)
restoration plan

Summary Consideration: There was no consensus amongst commenters who responded to this question. The Commission directed NERC to
revise its BES definition to ensure that the definition encompasses all Facilities necessary for operating an interconnected electric Transmission
network. The SDT interprets this to include operation under both normal and Emergency conditions, which includes situations related to black
starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be energized without
connection to the remainder of the System, to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from
a Blackstart Resource is essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system
restoration plan. For these reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths
indentified in the Transmission Operator’s restoration plan as BES Elements.

Organization

Yes or No

SERC EC Planning Standards
Subcommittee

No

Southern Company

No

Question 4 Comment
A blackstart designation should not necessarily make it part of the BES.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
Public Service Enterprise Group
Company

March 30, 3011

No

Including these in the definition of BES would impose compliance obligations for these assets even if below
100kV at the same level as assets at or above the 100kV level. Blackstart Resources and Cranking Paths
below 100kV do not impact the reliability of the BES and thus should not be required to comply with all
standards as if they did. For example, 26kV cranking path protection systems typically only trip the 26kV, not
100kV or higher BES transmission facilities, thus do not impact the BES, and should not be required to meet

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment
BES compliance standards for system protection. That assets can have different impacts and thus different
levels of required compliance is expressly recognized in the recently stakeholder approved CIP-002-4 draft
standard where blackstart cranking paths must be included as critical assets subject to CIP protections only to
the point where two or more path options exist. Rather than include all Blackstart Resources and the
designated Blackstart Cranking Paths indentified in the Transmission Operator’s (TOP’s) restoration plan in
the blanket definition of BES, the drafting team should be directed to develop a definition that states that
these assets are not part of the BES except where specifically identified in a requirement of a standard as
needing to be compliant. For example, a standard requiring testing of Blackstart units would result in a
Blackstart unit being deemed BES for purposes of that standard only.

FirstEnergy Corp

No

Blackstart generation and cranking paths do not need to be defined as being part of the BES. Rather, they
are more appropriately reflected as supporting and restoring operation of the BES. Not all aspects of the BES
reliability standards pertain to BES facilities. For example, UFLS and UVLS installed on a distribution system
are important to arrest BES reliability concerns but they are not needed in what defines the BES. Similarly,
blackstart generation and Cranking Paths do not need to be inclusive of what defines the BES but are
important aspects of a restoration plan to re-establish a functioning BES.

American Transmission company

No

Blackstart Resources and designated blackstart Cranking Paths should not be classified as part of the BES,
except those Elements and/or Facilities that are rated 100 kV or more and with a gross generator nameplate
rating of 20 MVA or more.

City of Austin dba Austin Energy

No

Just because a unit can be used for black start should not - by definition - mean it is part of the BES. For
example, there may be a very small unit which can be used for black start and the operating utility should not
have to comply with all the NERC Standards all the time when that asset becomes “important” only during a
black start event. Additionally, protective systems associated with small black start units would have to fulfill
the same reliability requirements as any other BES generator even though those protective systems would
have little purpose during a black start event.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

Again, Facilities identified as necessary for blackstart capability (both Blackstart Resources and the blackstart Cranking Path) in a Transmission Operator’s
restoration plan should be designated as part of the BES, and be subject to the corresponding NERC Standards referencing the BES.
A review of the NERC Reliability Standards will be undertaken once the BES Definition is finalized to clearly delineate responsibilities for owners and operators of
BES designated Facilities.
MRO's NERC Standards Review
Subcommittee

No

This question is irrelevant to the scope of this project. A Blackstart Resource may be a 10 MVA unit
connected at the distribution level of voltage and within the TOP’s Restoration Plan. Just because the unit is
within the TOP’s Restoration Plan does not make it a BES connected asset. CIP-002-4 is already industry
approved and may “push” both large and small entities to remove these units from the TOP’s Restoration
Plan due to the Critical Asset label. If the Blackstart Resource is connected via GSU at 100 kV then it would
be part of the BES. If the SDT is worried that a Blackstart Resource will not be maintained or tested, those
requirements are within EOP-005-1 (and yet to be approved EOP-005-2). Blackstart Resources and
designated blackstart Cranking Paths should not be classified as part of the BES, except those Elements
and/or Facilities that are rated 100 kV or more and with a gross nameplate rating of 20 MVA or more.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
For example, BES generation may require external Interconnections and Facilities in order to provide power to auxiliary equipment within the plant during times of
system restoration.
IRC Standards Review
Committee

No

NERC Standards EOP-00-2 stipulates the requirements for testing Blackstart Resource and Cranking Paths.
This testing requirement ensures that the facilities critical to system restoration are functional when needed.
Inclusion of any resources or transmission paths as BES Elements/Facilities intended for use for system
restoration should be determined using the criteria 1-3, above.

Response: The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for operating an
interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which includes situations
related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be energized without

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power capability,
frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart Resources are
essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT
has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s restoration plan as BES
Elements.
A review of the NERC Reliability Standards will be conducted once the BES Definition is finalized in order to clearly delineate responsibilities for owners and
operators of BES designated Facilities.
PacifiCorp

No

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology. Significant
efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF) over the
course of the past year to identify some initial criteria and methodologies. These efforts are ongoing and
should be supported by the NERC drafting team. For example: Blackstart Resources and designated
blackstart Cranking Paths should be included only if they are deemed necessary to restore the interconnected
electric transmission network.

ISO New England Inc.

No

1. Revise the statement, “Blackstart Resources and the designated blackstart Cranking identified in the
Transmission Operator’s (TOP’s) restoration plan.” to “Blackstart Resources “material to” and designated as
part of a Transmission Operator’s (TOPs) restoration plan.” Reason - Some regions have many blackstart
units that are not material to a TOPs restoration plan. These units need not register and be subjected to the
NERC Standards. Only those deemed material (i.e., “key facilities”) should be classified as part of the BES.
See NERC Registry Criteria for reference to “material” in describing, and qualifying, what constitutes
Blackstart Resources.”
2. NERC Standard EOP-00-2 stipulates the requirements for testing Blackstart Resources and Cranking
Paths. This testing requirement suffices to ensure that the facilities critical to system restoration are functional
when needed. Designating these facilities as BES Elements or Facilities beyond the 100 kV bright line
criterion will impose unnecessary requirements for these facilities which may not contribute to the BES
reliability for everyday operations. If indeed any of these facilities are deemed necessary to support BES
reliability for everyday operation, they will be identified through either the 100 kV bright line criterion or the

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment
exemption/inclusion process.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
The SDT assumes that the Blackstart Resources and designated blackstart Cranking Paths included in the Transmission Operator’s restoration plans are those
deemed necessary or required to reliably restore the system, or they wouldn’t be included in the plan, subjecting them to the NERC Standard testing requirements.
Arizona Public Service Company

No

With all of the new NERC Standards in place, a blackout should be an extremely rare event; therefore,
classifying Blackstart units or Cranking Paths is not needed.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
Again, the Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for operating an interconnected
electric Transmission network. This determination is based on the reliable restoration of the system, independent of likelihood of the assumed occurrence of the
need for restoration.
Independent Electricity System
Operator

March 30, 3011

No

NERC Standards EOP-00-2 stipulates the requirements for testing Blackstart Resource and Cranking Paths.
This testing requirement suffices to ensure that the facilities critical to system restoration are functional when
needed. Designating these facilities as BES Elements or Facilities beyond the 100 kV bright line criterion will
impose unnecessary requirements for these facilities which may not contribute to the BES reliability at times
other than during system restoration. If indeed any of these facilities are deemed necessary to support bulk
power system reliability at times other than during system restoration, they will be identified through either the
100 bright line criterion or the exemption/inclusion process.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

American Electric Power (AEP)

No

Should be re-written to state that only those Blackstart Resources in the Transmission Operator’s (TOP’s)
restoration plan be classified as part of the BES.

City Water Light and Power
(CWLP) - Springfield, IL

No

CWLP feels that blackstart resources and cranking paths not otherwise qualified as a part of the BES based
on other criteria should not be included in the definition of BES solely based on their status as blackstartcapable units. Requirements for blackstart resources and cranking paths are already addressed by existing
and proposed EOP standards and we feel that arbitrarily classifying these elements as part of the BES may
create undue burden on Transmission Owners when the same reliability result can be achieved through more
directed effort in the EOP standards. Further, while such blackstart resources and cranking paths may
support operation of the BES, they need not be strictly included in the definition of BES to achieve the desired
reliability result.

City of Grand Island

No

Not across the board. Generator criteria from questions 2 and 3 can apply to blackstart generators as well.
Otherwise the exception process can be used.

Southern California Edison

No

SCE does not feel a blanket inclusion of all the listed equipment is needed.

Pepco Holdings Inc.

No

To remain consistent with the proposed definition of facilities 100kv and above, this should not be included.
Inclusion would not result in a more reliable system or reduce risk.

Electric Market Policy

No

Dominion does not agree that Blackstart Resources should be classified as part of the BES.Dominion
supports the criteria for registering owners, operators, and users of the bulk power system, as indicated in the
current Statement of Compliance Registry Criteria .

Central Lincoln

No

The generation resources so described should be presumed to be part of the BES unless or until they have
been through the exemption process and as a result have been classified as non-BES.

Lewis County PUD

No

Entergy Services

No

The Dayton Power and Light
Company

No

Snohomish County PUD

No

March 30, 3011

The generation resources so described should be presumed to be part of the BES unless they have been

64

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

PNGC Power

No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric
Cooperative

No

March 30, 3011

Question 4 Comment
demonstrated through performance-based studies to present no substantial threat of separation events,
cascading outages, or voltage instability on the bulk system.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Lincoln Electric Cooperative

No

Fall River Electric Cooperative

No

Question 4 Comment

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
Again, Facilities critically identified as necessary for blackstart capability (both Blackstart Resources and the blackstart Cranking Path) in a Transmission Operator’s
restoration plan should be designated as part of the BES, and be subject to the corresponding NERC Standards referencing the BES.
BGE

No

This proposal as written could lead to a reduction in the number of blackstart units which rely on cranking
paths of less than 100 kV and not currently classified as BES, thereby reducing BES reliability.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
The Transmission Operator will remain responsible for maintaining a viable restoration plan, regardless of the BES definition.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC

March 30, 3011

No

This proposal as written could lead to a reduction in the number of blackstart units which rely on cranking
paths of less than 100 kV and not currently classified as BES, thereby reducing BES reliability. To account for
this potential gap, Constellation firmly believes that the classifications found in the Compliance Registry
Criteria - Section III (Rules of Procedure Appendix 5B), such as that cited in this question, provide a useful
basis to create a comprehensive, revised BES definition.
Further, we propose that the BES drafting team incorporate the criteria directly into the revised BES definition,
replacing the term “bulk power system” in each criterion with “greater than 100 kV.” This would then include

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Question 4 Comment
assets that are currently registered as BES elements as well as those that may have been previously
excluded due to Regional exemption variances. As an example, the Compliance Registry Criteria includes
any generator, regardless of size, that is a blackstart unit material to and designated as part of a transmission
operator entity’s restoration plan. The Compliance Registry also includes transmission as elements above
100kV or that is critical as defined by the Regional Entity (excluding radial facilities as described in the current
BES definition). Structuring the revised BES definition to clarify both the inclusions and exclusions, can,
ideally, eliminate the need for an onerous exemption process.
Please see our response to question 12 for more detail on a proposed alternative approach to structuring the
BES definition revision.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary
for operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
The SDT agrees and has made the suggested change and replaced the term “bulk power system” in each criterion with “greater than 100 kV.”
Please see response to Q12.
The Dow Chemical Company

As discussed in response to question #12 below, issues relating to the registry criteria applicable to
generation resources should not be revisited at this time.

Response: Please see response to Q12.
ReliabilityFirst

Yes

It is recommended that the term “cranking path” be defined and examples of this term be provided.
Also, does the term "cranking paths” include all paths or just the primary path if there are multiple paths
available?

Response: The NERC Glossary of Terms defines ‘Cranking Path’ as “A portion of the electric system that can be isolated and then energized to deliver electric
power from a generation source to enable the startup of one or more other generating units”.
NERC Staff

March 30, 3011

Yes

Please see additional comments at the end of this document.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

Response: See response to Q13.
Springfield Utility Board

Yes

Clark Public Utilities

Yes

Xcel Energy

Yes

City of Redding

Yes

City of Anaheim

Yes

Northeast Power Coordinating
Council

Yes

Florida Municipal Power Agency

Yes

See FMPA response to Question 2 above.

Bonneville Power Administration

Yes

Blackstart resources should never be allowed to be excluded through any technical studies.

SERC OC Standards Review
Group

Yes

Transmission Access Policy
Study Group

Yes

See TAPS response to Question 2 above.

PPL Energy Plus

Yes

LG&E and KU Energy LLC

Yes

Blackstart Resources and the designated blackstart Cranking Paths identified in the TOP’s restoration plan
are a special case and warrant inclusion in the BES definition regardless of voltage because of their
importance to BES reliability. However, this would not be the case for other facilities operated below 100 kV.

Competitive Suppliers

Yes

ExxonMobil Research and
Engineering

Yes

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

LCRA Transmission Services
Corporation

Yes

This is critical for system restoration.

PUD No.1 of Clallam County

Yes

Based on the current Reliability Standards practices it may be advantageous to reduce the number of
blackstart generation and cranking paths to limit exposure to BES applicable standards. At this time if a
registered entity has multiple blackstart units, it may be advantageous to reduce or decommission the number
to avoid compliance risks. The current requirements may ultimately reduce the number of blackstart units and
reduce BES electric reliability. It may make more sense to identify subset of critical blackstart projects and
associated cranking paths as BES elements. The generation resources so described should be presumed to
be part of the BES unless or until they have been through the exemption process and as a result have been
classified as non-BES.

Manitoba Hydro

Yes

American Municipal Power

Yes

North Carolina EMC

Yes

on behalf of Teck Metals Ltd.

Yes

Indeck Energy Services

Yes

Southern California Edison
Company

Yes

on behalf of Catalyst Paper
Corporation

Yes

Occidental Energy Ventures Corp

Yes

City of Anaheim

Yes

Glacier Electric Cooperative

Yes

March 30, 3011

These resources are significant to the BES and should be included.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

United Illuminating Company

Yes

Orange and Rockland Utilities,
Inc.

Yes

Utility Services

Yes

Duke Energy

Yes

ITC Holdings Corp

Yes

Idaho Power

Yes

Question 4 Comment

Yes, but the Blackstart Resources identified as the PRIMARY resources in the System Restoration Plan
should be the focus.

Response: Thank you for your response.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

5. Should the following be classified as part of the BES?
•

Transmission Elements or Facilities operated at voltages below 100kV where the exemption process deems the Element or
Facility to be included in the BES

Summary Consideration: Most commenters who responded to this question indicated disagreement with the proposal however there was no
consensus amongst the alternate proposals offered, and the proposals suggesting other thresholds were not supported with any technical
justification. The SDT has reviewed the industry comments on this issue, debated the topic, and has come to an agreement that the bright-line
designation for Transmission Elements is 100kV and above. Any deviations from the bright-line designation (beyond those identified in the revised
definition of BES), including Transmission Elements operated below 100kV, will be handled through the Rules of Procedure process that is being
developed by a separate team.

Organization

Yes or No

Question 5 Comment

SERC EC Planning Standards
Subcommittee

No

We prefer a bright-line rule of 100 kV. The exception process should not be used to include facilities operated
at voltages below 100 kV.

Arizona Public Service Company

No

There are no practical cases where the facilities below 100 kV impact the major load centers or BES.

North Carolina EMC

No

Transmission elements or facilities operated at voltages below 100kV should only be included in the BES if
identified by the RRO as critical to the BES.

Southern California Edison
Company

No

The Exemption Process should apply to transmission elements or facilities greater than 100kV only. Facilities
operated below 100kV are generally used for distribution purposes.

BGE

No

This proposal as written could lead to the inclusion of elements or facilities which have no material reliability
impact on the interconnected transmission system.

Southern Company

No

We prefer a bright-line rule of 100 kV. The exception process should not be used to include facilities operated
at voltages below 100 kV.

ExxonMobil Research and
Engineering

Yes

It is conceivable that, in some areas, the Bulk Electric System may include transmission assets that are rated
and operated at 69kV or below.

Response: The SDT appreciates the preference of several entities to utilize strict bright-line criteria of Facilities at 100kV and above that would be considered for
inclusion in the BES. The SDT has carefully considered this matter, and believes that the exception process must allow for the possibility that certain Facilities

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment

operated at voltages below 100kV could have appreciable influence over the reliable operation of the interconnected network Transmission grid, thereby
warranting examination through an exception process for inclusion in the BES. The SDT expects that these exceptions for Facilities operated at voltages below
100kV will be relatively rare. The criteria for such inclusion will be developed as part of this project and the ROP process will be handled by a separate team
through the revision to the Rules of Procedure, in an effort parallel to the development of the BES definition.
ITC Holdings Corp

No

PRC023 has developed a process for specification of critical lines below 100 kV. This same process should
be used to include below 100 kV lines in the BES

Florida Municipal Power Agency

No

Transmission Access Policy
Study Group

No

This Question refers to including an Element in the BES through the exemption process, suggesting that the
SDT is contemplating a single process for including nominally non-BES Elements in the BES and for
exempting nominally BES Elements from the BES. While it would make sense for the two processes to be
similar, they cannot be identical: The burden should be on the entity requesting an exemption to show that an
Element that is nominally part of the BES is nevertheless not necessary for operating the interconnected
electric transmission network and thus should be exempted from the BES. In contrast, with respect to
transmission operated at voltages below 100 kV, it is NERC that must show, on a case-by-case basis, that
transmission that is not nominally part of the BES is nevertheless necessary for operating the interconnected
electric transmission network and thus should be included in the BES.Transmission operated at voltages
below 100 kV should only be classified as part of the BES if the inclusion process, assessing each Element on
a case-by-case basis, based on a uniform set of criteria, results in a finding that the particular Element should
be included in the BES.

Response: The process for inclusions and exclusions will be developed by a separate team as part of the revision to the Rules of Procedure, in an effort parallel to
the development of the BES definition. Your comments will be forwarded to the Rules of Procedure Team.
FirstEnergy Corp

No

We do not agree with an "exemption process" being associated with "including facilities". We suggest keeping
the exemption process separate from the identification of critical sub 100kV facilities that will be included in the
BES. We do agree that a consistent continent-wide approach for identifying these facilities is a worthwhile
goal but should be a secondary priority to establishing the BES definition and BES exemption process.

Response: The SDT envisions an “exception process”, and regrets the use of “exemption” in the original SAR. The processes for inclusions and exclusions will be
developed by a separate team as part of the revision to the Rules of Procedure, in an effort parallel to the development of the BES definition. Your comments will
be forwarded to the Rules of Procedure Team.
American Electric Power (AEP)

March 30, 3011

No

Exemption processes are distinctly different than inclusion processes, and clarification is needed to address
their differences. There should be two distinct processes. Until details of such processes and their related
criteria are better defined, it is difficult to provide substantive comments.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment

MRO's NERC Standards Review
Subcommittee

No

FERC has directed (in section 30 of FERC Order 743) that NERC have an established “exemption” process to
remove this judgment from the Regions in defining what the BES is. However, the applicable process should
be called an “exception” process, not an “exemption” process that infers the concept of “exclusion” and further
classified as part of the BES given that a fault or an outage on the Transmission Element or Facility at
voltages below 100kV would not maintain an Adequate Level of Reliability of the BES.

PacifiCorp

No

In paragraph 121 of Order No. 743, the Commission states that it agrees that the ERO should develop a
parallel process for including as part of the bulk electric system “critical” facilities, operated at less than 100
kV, that the Regional Entities determine are necessary for operating the interconnected transmission network.
(emphasis added) Further, the Commission stated that “[w]e believe that it would be worthwhile for NERC to
consider formalizing the criteria for inclusion of critical facilities operated below 100 kV in developing the
exemption process.” (emphasis added) PacifiCorp believes that it is appropriate to use the same criteria to
determine what elements or facilities should be included in the definition of Bulk Electric System as those used
to determine what elements or facilities should be excluded from the definition. However, the formal process
used for exclusion (i.e. the exemption process) of facilities above 100 kV should not be the same process as
the process for inclusion of sub-100 kV facilities. As PacifiCorp understands it, per the Commission, the
exemption process will require a facility-by-facility approval by NERC for exemption whereas inclusion of sub100 kV facilities will involve a Regional Entity determination that such facilities must be included. These
should therefore be separate processes.

Central Lincoln

No

PUD No.1 of Clallam County

No

Including elements through an exemption process is bound to create confusion and misunderstandings
between the registrants and REs. Please include such elements through an inclusion process. It should also
be clarified that registrants are not required to put all sub-100 kV elements through this process; the burden
should be on the RE to include elements of particular concern.

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743. The process for such inclusions will be developed by a separate team through the revision to
the Rules of Procedure, in an effort parallel to the development of the BES definition.
Pepco Holdings Inc.

No

Some details on the exemption process must be known before accepting this. Who can submit an exemption
(DP, GO, GOP, TO, TOP, RC, etc)? How do interested parties get informed? Can others intervene?

Occidental Energy Ventures Corp

No

Until the expemtion process is finalized, it is not prudent to answer in the affirmative.

Entergy Services

No

Our response to this question depends on the details of the “exemption process”, including what entity has the

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment
final decision and how it is implemented. Please see our response to Q13 below.

City Water Light and Power
(CWLP) - Springfield, IL

No

While CWLP agrees with the general concept of inclusion by exception (as opposed to exemption), we have
concerns regarding the lack of detailed definition of this process, especially the administrative process for
disputes regarding inclusion of elements in the BES. Without firm administrative rules for resolving disputes
based on technical justification, we cannot support this measure currently.

Manitoba Hydro

It is confusing to use the term “exemption process” to determine what is included. Abstain until exemption
process has been defined.

Duke Energy

There is not enough information available at this time to adequately evaluate this question. It would be
necessary to have a list of exemption criteria or more detail on the exemption process to address this
question. This is one of the reasons that the exemption criteria should be developed through the standards
development process along with the definition.

Xcel Energy

Xcel Energy does not disagree that there may be situations where elements below 100KV may need to be
included, but we have concerns about the exemption process. This undeveloped process presents itself as a
wild card to entities, and will most likely present inconsistencies between regions based upon each Region’s
preference. Additionally, does the Regional Methodology require any approval (e.g. ERO) other than the
Region’s own process? The “exclusions” process indicates that the ERO has the final approval authority to
exclude an item from the BES. Why would the same not apply for including something into the BES based on
the Region’s Methodology?

IRC Standards Review
Committee

Yes

We generally support the concept but we need to assess the criteria for the exception, which have not been
developed. Further, the wording seems to present a circular argument. We suggest the following revised
wording to more clearly convey this criterion:Transmission Elements or Facilities operated at voltages below
100kV that are deemed to be included in the BES as determined by the exception/inclusion process.

Response: The SDT acknowledges that commenters will need to reserve judgment on the exception process, which is being developed by a separate team as a
modification to the Rules of Procedure in an effort parallel with the development of the BES definition.
American Municipal Power

No

on behalf of Teck Metals Ltd.

No

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

on behalf of Teck Metals Ltd.

No

on behalf of Catalyst Paper
Corporation

No

Idaho Power

No

Question 5 Comment

Response: Thank you for your response.
Indeck Energy Services

No

Same Response as Question 1

Utility Services

Yes

See the answer to Question 1.

Response: See Response to Question 1.
Snohomish County PUD

No

Snohomish agrees that certain Elements or Facilities operated at voltages below 100 kV may need to be
classified as part of the BES if engineering studies demonstrate those Elements or Facilities to be necessary
to the reliable operation of the bulk transmission system. We disagree, however, that inclusion of such
facilities should be part of the exemption process. The exemption process should be focused on facilities
operating at voltages above 100 kV that nonetheless are exempt because they are local distribution facilities
or are demonstrated by engineering analysis to be unnecessary for the reliable operation of the
interconnected bulk transmission grid. The inclusion of facilities below 100 kV should be a separate process
in which the RRO is required to demonstrate that the facility has a material impact on the interconnected bulk
transmission system despite its low operating voltage

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of proposed “inclusions” and “exclusions”, and subsequent drafts will
refer to the “exception” process suggested by the Commission in its Order 743. The process for such inclusions and exclusions will be developed as part of the
revision to the Rules of Procedure by a separate team, in an effort parallel to the development of the BES definition. The SDT appreciates the preference of
several entities to utilize strict bright-line criteria of facilities greater than 100kV that would be considered for inclusion in the BES. The SDT has carefully
considered this matter, and believes that the exception process must allow for the possibility that certain Facilities operated at voltages below 100kV could have
appreciable influence over the reliable operation of the interconnected network Transmission grid, thereby warranting examination through an exception process
for inclusion in the BES. The SDT expects that these exceptions for Facilities operated at voltages below 100kV will be relatively rare.
Lewis County PUD

March 30, 3011

No

Including elements through an exemption process is bound to create confusion and misunderstandings
between the registrants and REs. Please include such elements through an inclusion process. It should also
be clarified that registrants are not required to put all sub-100 kV elements through this process; the burden of

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment
proof should be on the RE to include elements less than 100kV.

PNGC Power

No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric

No

March 30, 3011

Including elements through an exemption process is bound to create confusion and misunderstandings
between the registrants and REs. Please include such elements through an inclusion process. It should also
be clarified that registrants are not required to put all sub-100kV elements through this process; the burden
should be on the RE to include elements of particular concern.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment

Cooperative
Lincoln Electric Cooperative

No

Fall River Electric Cooperative

No

Central Lincoln

No

PUD No.1 of Clallam County

No

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743. The process for such inclusions will be developed by a separate team through the revision to
the Rules of Procedure, in an effort parallel to the development of the BES definition.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

No

Although Constellation believes that it may be appropriate to include some of the elements above in the BES,
this proposal will lead to the inclusion of elements or facilities which have no material impact on the
interconnected transmission system. Furthermore, the use of an exemption process to include assets is
confusing. Constellation proposes that the BES drafting team structure the revised BES definition to clarify
both the inclusions and exclusions as completely as possible. If a separate “opt-in” process is deemed
necessary (in anticipation of a few exceptions to the definition) then the drafting team should develop criteria
for such a process.Using this approach the sentence above would then read “Transmission Elements or
Facilities operated at voltages below 100kV where a Regional Entity deems the Element or Facility to be
included in the BES.”

Response: The SDT appreciates the preference of several entities to utilize strict bright-line criteria of Facilities at 100kV or above that would be considered for
inclusion in the BES. The SDT has carefully considered this matter, and believes that the exception process must allow for the possibility that certain Facilities
operated at voltages below 100kV could have appreciable influence over the reliable operation of the interconnected network Transmission grid, thereby
warranting examination through an exception process for inclusion in the BES. The SDT expects that these exceptions for Facilities operated at voltages below
100kV will be relatively rare. The criteria for such inclusion will be developed as part of this project and the ROP process will be handled by a separate team
through the revision to the Rules of Procedure, in an effort parallel to the development of the BES definition.
The SDT acknowledges that the term “exemption” is inappropriate in the context of proposed “inclusions” and “exclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment

No

Why would an entity want to include an element in the definition of the BES? If an entity has a 69kV line that
the ERO believes should be part of the BES but the entity does not want it part of the BES who initiates and
pays for the exemption process? Does the ERO have the ability to initiate the process? If the owner of the
Transmission Element or Facility is the only one that can initiate and exemption process and they do not want
to what is the remedy if the line is necessary for bulk electric system reliability?

Springfield Utility Board

Response: The bright-line designation will be developed as part of this project and the ROP process will be handled through the revision to the Rules of
Procedure by a separate team in an effort parallel to the development of the BES definition. Your comments will be forwarded to the Rules of Procedure Team.
National Rural Electric
Cooperative Association
(NRECA)

Without exemption criteria to review, it is too early to explicitly answer this question. However, the concept
appears to be logical as long as it is also paired with the ability of an entity that owns facilities above 100kV to
appeal the inclusion of its facilities as part of the BES. Such an appeal would need to be supported by a
technical justification demonstrating why certain facilities should not be classified as part of the BES.In
addition, it is critical for exemption criteria to be based on operating voltage, not design voltage. Using design
voltage in the criteria would provide a disincentive to build for future expansion. This could have significant
negative impacts on BES reliability.

Response: The process for such inclusions and exclusions will be developed by a separate team as part of the revision to the Rules of Procedure, in an effort
parallel to the development of the BES definition. Your comments will be forwarded to the Rules of Procedure Team.
The Dow Chemical Company

Dow recommends that NERC finalize a basic framework for identifying BES facilities before evaluating
individual facilities or types of facilities. Such a framework is recommended by Dow in response to questions
#11 and #12 below.

Response: See responses to Q11 & 12.
Orange and Rockland Utilities,
Inc.

Refer to the response to Question 13.

Northeast Power Coordinating
Council

Refer to the response to Question 13.

NERC Staff

Yes

Please see additional comments at the end of this document.

Response: See response to Q13.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment

SERC OC Standards Review
Group

Yes

We think the process should be an “exception” rather than an “exemption”.

City of Grand Island

Yes

Exemption process should be termed “exception” process. Exception means not conforming to general rule,
whereas exemption primarily means exclusion. This process will be difficult to develop and administer and is
counter productive to “bright line” philosophy. Thus the bright lines should be at a high level resulting in fewer
challenges. The exception process must consider the impact of a fault or outage of that facilities on the
Adequate Level of Reliability (NERC defined term) of the BES.

American Transmission company

Yes

However, the applicable process should be called an “exception” process, not an “exemption” process that
infers the concept of “exclusion” and further classified as part of the BES given that a fault or an outage on the
Transmission Element or Facility at voltages below 100kV would not maintain an Adequate Level of Reliability
of the BES.

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743. The process for such inclusions will be developed by a separate team through the revision to
the Rules of Procedure, in an effort parallel to the development of the BES definition.
City of Redding

Yes

City of Anaheim

Yes

Public Service Enterprise Group
Company

Yes

Bonneville Power Administration

Yes

Electric Market Policy

Yes

LCRA Transmission Services
Corporation

Yes

March 30, 3011

If the exemption process is based on reliable engineering studies.

No Comment

Dominion conceptually supports an exemption process whereby NERC or the RRO could apply to have an
element included or excluded from the BES definition. Such process recognizes that it may be necessary to
include elements that do not meet the bright line criteria but are necessary for operating an interconnected
transmission network. Such process should be developed through the existing NERC standards development
process and include a robust appeals process for the owner/operator of any element so included or excluded.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment

PPL Energy Plus

Yes

LG&E and KU Energy LLC

Yes

Yes, PPL Energy Plus supports an exemption process provided the Exemption process follows FERCs Order
743 paragraph 115: “NERC should develop an exemption process that includes clear, objective, transparent,
and uniformly applicable criteria for exemption of facilities that are not necessary for operating the grid.”

ReliabilityFirst

Yes

It is recommended that the exemption process be defined and criteria setup so that a common approach
across the ERO can be used to include these facilities.

Southern California Edison

Yes

SCE currently reports on transmission elements or facilities operated at voltages below 100kV that are
interconnected with other utilities.

Glacier Electric Cooperative

Yes

Yes - this is assuming that the exemption process is an accurate way to truly determine whether or not a
facility is significant to the grid.

ISO New England Inc.

Yes

United Illuminating Company

Yes

City of Austin dba Austin Energy

Yes

The Dayton Power and Light
Company

Yes

Independent Electricity System
Operator

Yes

Clark Public Utilities

Yes

This answer assumes that an appropriate engineering study is performed to determine that the asset is
necessary for the reliability of the BES.

We generally support the concept but we need to assess the criteria for the exception, which have not been
developed. Further, the wording seems to present a circular argument. We suggest the following revised
wording to more clearly convey this criterion:Transmission Elements or Facilities operated at voltages below
100kV that are deemed to be included in the BES as determined by the exception/inclusion process

Response: The SDT thanks you for your comments.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

6. Should the following be classified as part of the BES?
•

Individual generation resources greater than 20 MVA (gross nameplate rating) directly connected via a step-up
transformer(s) to Facilities operated at voltages below 100kV where the exemption process deems the generation
resources to be included in the BES

Summary Consideration: Most commenters who responded to this question indicated disagreement with the proposal, however there was no
consensus amongst the alternate proposals offered, and the proposals suggesting other thresholds were not supported with any technical
justification. The SDT has reviewed the industry comments on this issue, debated the topic, and come to an agreement that the bright-line
designation for individual generating units is 20 MVA and 100 kV. Any deviations from the bright-line designation would be handled through the
pending Rules of Procedure process. Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including
the generator terminals through the GSU which has a high side voltage of 100 kV or above.

Organization

Yes or No

Question 6 Comment

SERC EC Planning Standards
Subcommittee

No

We prefer a bright-line rule of 100 kV. The exception process should not be used to include facilities operated
at voltages below 100 kV.

Public Service Enterprise Group
Company

No

The intent of the BES definition is to address the reliability of the bulk electric system and associated
elements. The generation connected at less than 100kV should not be classified as BES - it should be
considered to be within the same category as radial connected facilities serving load (which is not included as
part of the BES).

Response: In Order No. 743, the Commission directed NERC to adopt an inclusion process for including in the BES definition Facilities operated at voltages
below 100 kV. The Commission believes that NERC should “consider formalizing the criteria for inclusion of critical facilities operated below 100 kV in developing
the exemption process.” The DBES SDT and NERC Rules of Procedure team are responding to FERC’s directive.
Florida Municipal Power Agency

No

Transmission Access Policy
Study Group

No

See FMPA response to Question 5 above. Generation resources of any size directly connected via a step-up
transformer(s) to transmission operated at voltages below 100 kV should only be classified as part of the BES
if the generation resource is registered pursuant to the Statement of Compliance Registry Criteria or if the
inclusion process, assessing each generation resource on a case-by-case basis based on a uniform set of
criteria, results in a finding that the particular generation resource should be included in the BES. The
standards for registering a generator should be the same as those for including it in the BES.

Response: The SDT agrees with the comment that designation of these generators as BES would occur only if the pending Rules of Procedure process deems
them to be BES, and such a designation would necessarily warrant registration per the terms of the NERC Statement of Compliance Registry Criteria (SCRC).

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 6 Comment

The scope of the SDT does not extend to revisions of the SCRC; however, recommendations for revision of the SCRC may result from the definition development.
PacifiCorp

No

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology. Significant
efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF) over the
course of the past year to identify some initial criteria and methodologies. These efforts are ongoing and
should be supported by the NERC drafting team. For example: Generation units should not be included or
excluded solely based on a their gross nameplate rating and the operating voltage at which they are
connected to transmission facilities. Generation units which are necessary to operate the interconnected
network should be included as part of the regulated BES. Generating units which are not “necessary for the
operation of the interconnected network” should be excluded. A methodology needs to be developed to
determine which generating units may be excluded as part of the regulated BES.

Response: The SDT believes that the criteria enumerated in the current Statement of Compliance Registry Criteria should be the template (or “methodology” as
used in the comment) for defining the bright-line exception criteria in Project 2010-17. The SDT plans to review past efforts of Regional Entities to develop their
own BES definition.
ExxonMobil Research and
Engineering

No

See comments on questions 2 and 3.

No

Individual generation resources less than 50 MVA (gross nameplate rating) directly connected via a step-up
transformer(s) to Facilities operated at voltages below 100 kV do not materially impact the reliability of the
BES and therefore, should not be classified as part of the BES.

Response: See response to Q2 & Q3.
Arizona Public Service Company

Response: The SDT believes that the criteria enumerated in the current Statement of Compliance Registry Criteria should be the template for defining the brightline exception criteria in Project 2010-17. The comment provides no technical justification for departing from existing practices defined by the Statement of
Compliance Registry Criteria.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 6 Comment

No

Some details on the exemption process must be known before accepting this. Who can submit an exemption
(DP, GO, GOP, TO, TOP, RC, etc)? How do interested parties get informed? Can others intervene? Would
the other facilities completing the connection to a BES facility be automatically included?

Pepco Holdings Inc.

Response: The SDT acknowledges that commenters will need to reserve judgment on the pending Rules of Procedure process, which is to be developed in an effort
parallel with this BES definition development. The SDT believes that the criteria enumerated in the current Statement of Compliance Registry Criteria should be the
template for defining the bright-line criteria in Project 2010-17. The SDT will coordinate its efforts with the NERC ROP team developing the Rules of Procedure
process to develop a single coordinated implementation plan that will define the responsibilities of various parties.
American Municipal Power

No

on behalf of Teck Metals Ltd.

No

on behalf of Catalyst Paper
Corporation

No

Idaho Power

No

Clark Public Utilities

No

Response: Thank you for your response.
Indeck Energy Services

No

Same Response as Question 1

No

SCE currently reports on generation resources greater than 20 MVA (gross nameplate rating) directly
connected via a step-up transformer(s) to Facilities operated at voltages above 100kV. SCE does not feel it is
necessary to report on generation below 100kV.

Response: See response to Q1.
Southern California Edison

Response: In Order No. 743, the Commission directed NERC to adopt an inclusion process for including in the BES definition Facilities operated at voltages
below 100 kV. The Commission believes that NERC should “consider formalizing the criteria for inclusion of critical facilities operated below 100 kV in developing
the exemption process.”
Southern California Edison
Company

March 30, 3011

No

In SCE's system, generation resources are used to offset load being served by distribution facilities. This
means that generation does not flow through step-up transformers into the 100kV and above system.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 6 Comment
Therefore, those generation resources which are used to provide power to local load within a distribution
system should not be included as part of the BES. The Exemption Process should not be applied to such
resources.

Response: The SDT believes that such generation resources will be excluded as part of the BES unless the Facilities are otherwise deemed material to the
reliability of the BES by a ROP to the pending Rules of Procedure exception process. In a section in the revised BES definition on Local Distribution Networks, the
SDT is considering the issue of generation resources used to offset Load being served by distribution Facilities.
ISO New England Inc.

No

1. Yes - There are situations as envisioned in the Registry Criteria clause, i.e., “Any generator, regardless of
size, that is material to the reliability of the bulk power system” where reliability would be threatened without
such inclusion. Similarly, cases can be made for materiality to the reliability of the bulk power system for units
< 20 MVA directly connected at 100 kV or greater and for units < 20 MVA connected at any voltage level. The
exemption process developed should account for any and all situations where a generator, or group of
generators, may be deemed material to support a BES function such as riding through an UFLS event. Just
as UFLS Relays have been stated to be material to the reliability of the bulk power system, despite their
location on the lower voltage distribution systems, any size generator at any voltage level may be found,
through an analysis, to have a supporting role in protecting the BES during a postulated system disturbance.
2. No - In general small generators connected at voltages of 100 kV and greater and those larger generators
connected at voltages less than 100 kV do not impact the reliability of the BES and to classify them as BES
and require them to register with NERC and abide by all NERC Reliability Standards would place an undue
burden on the Generator Owners/Operators with little or no perceived reliability benefit. A more reasonable
process would allow a systematic analysis to define the material need of such otherwise exempted generators
and allow these generators to be registered on a “requirement basis”, a process which FERC has
encouraged, and is an approach recognized in NERC’s “Statement of Registry Criteria” (See “Notes to Above
Criteria” #4, page 10).

Electric Market Policy

No

Dominion does not agree that a generation resource should be classified as part of the BES. Dominion
supports the criteria for registering owners, operators, and users of the bulk power system, as indicated in the
current Statement of Compliance Registry Criteria.

Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.

No

Although Constellation believes that it may be appropriate to include some of the elements above in the BES,
this proposal will lead to the inclusion of elements or facilities which have no material impact on the
interconnected transmission system. Furthermore, the use of an exemption process to include assets is
confusing. Constellation proposes that the BES drafting team structure the revised BES definition to clarify
both the inclusions and exclusions as completely as possible. If a separate “opt-in” process is deemed
necessary (in anticipation of a few exceptions to the definition) then the drafting team should develop criteria

March 30, 3011

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Organization

Yes or No

(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Question 6 Comment
for such a process. Using this approach the sentence above would then read “Individual generation resources
greater than 20 MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Facilities
operated at voltages below 100kV where a Regional Entity deems the generation resources to be included in
the BES.”

Response: The SDT agrees that criteria enumerated in the current Statement of Compliance Registry Criteria should be the template for defining the bright-line
exception criteria in Project 2010-17. FERC Order No. 743 states that changes to the BES definition “will not significantly increase the scope of the present
definition, which applies to transmission, generation and interconnection facilities.”
Snohomish County PUD

No

The NERC GOTO Task Force considered the issue of whether dedicated interconnection facilities connecting
BES generation to the BES transmission system should also be classified as BES. The Task Force
concluded that it is unnecessary to classify such facilities as part of the BES and that reliability would not be
compromised as long as those interconnection facilities are required to comply with few reliability standards,
primarily those related to vegetation management. The standards drafting group should follow the
recommendation of the GOTO Task Force when considering the status of interconnection facilities and should
consider those recommendations when considering related questions such as the status of radial lines that
both interconnect a generator and serve distribution functions.

Response: The SDT acknowledges the work of Project 2010-07 Generator Requirements at the Transmission Interface regarding the classification rationale for
generation interconnection Facilities and has considered it in the development process of the BES definition. The subject of this question was focused upon the
generating elements themselves, rather than the associated interconnection Facilities. The SDT has carefully considered this matter, and believes that the
pending Rules of Procedure exception process must allow for the possibility that certain generating units larger than 20 MVA yet connected below 100kV could
have appreciable influence over the reliable operation of the interconnected network Transmission grid, thereby warranting a submittal through the ROP process
for inclusion in the BES. The SDT expects that these exceptions for generating units larger than 20 MVA, yet connected to the grid at below 100kV, will be
relatively rare. Additionally, the Commission in its Order No. 743 suggests that the revised BES definition should include exception processes for inclusion of
these sorts of Elements. The process for such inclusions will be developed as part of the revision to the Rules of Procedure, in an effort parallel to the
development of this BES definition.
Central Lincoln

No

PUD No.1 of Clallam County

No

PNGC Power

No

March 30, 3011

Including elements through an exemption process is bound to create confusion and misunderstandings
between the registrants and REs. Please include such elements through an inclusion process. It should also
be clarified that registrants are not required to put all sub-100 kV elements through this process; the burden
should be on the RE to include elements of particular concern.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric
Cooperative

No

Lincoln Electric Cooperative

No

March 30, 3011

Question 6 Comment

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
Fall River Electric Cooperative

Yes or No

Question 6 Comment

No

Response: The SDT agrees. In Order No. 743, the Commission directed NERC to adopt an inclusion process for including in the BES definition Facilities
operated at voltages below 100 kV. The Commission believes that NERC should “consider formalizing the criteria for inclusion of critical facilities operated below
100 kV in developing the exemption process.”
ITC Holdings Corp

No

The lower limit for BES generators should be 75 MVA. As long as this Plant is connected to the 100 kV or
greater, it should be included. Below 100 kV, only if it meets the critical test.

Response: The SDT believes that criteria enumerated in the current Statement of Compliance Registry Criteria should be the template for defining the bright-line
exception criteria in Project 2010-17. FERC Order No. 743 states that changes to the BES definition “will not significantly increase the scope of the present
definition, which applies to transmission, generation and interconnection facilities.” As envisioned, Regional Entities will be able to request the inclusion of
Elements below 100 kV in the pending Rules of Procedure exception process and will bear the burden of proof that such Elements are critical Facilities.
BGE

No

This proposal as written could lead to the inclusion of elements or facilities which have no material reliability
impact on the interconnected transmission system.

Response: The SDT believes that criteria enumerated in the current Statement of Compliance Registry Criteria should be the template for defining the bright-line
exception criteria in Project 2010-17. In addition, potential registrants may use the pending Rules of Procedure exception process to demonstrate the lack of
materiality.
City Water Light and Power
(CWLP) - Springfield, IL

No

While CWLP agrees with the general concept of inclusion by exception (as opposed to exemption), we have
concerns regarding the lack of detailed definition of this process, especially the administrative process for
disputes regarding inclusion of elements in the BES. Without firm administrative rules for resolving disputes
based on technical justification, we cannot support this measure currently.

Response: NERC is obligated under Order No. 743 to develop an exception process (including revisions to the NERC ROP) and implementation plan to
administer a revised BES definition and associated exception criteria, and a dispute resolution process. The SDT acknowledges that commenters will need to
reserve judgment on the pending Rules of Procedure exception process, which is to be developed in an effort parallel with this BES definition development.
Lewis County PUD

No

I find it hard to believe that elements connected at less than 100kV are part of the BES. The burden of proof
to include elements in the BES should be on the RE not the owner of such facilities.

Response: In Order No. 743, the Commission directed NERC to adopt an inclusion process for including in the BES definition Facilities operated at voltages
below 100 kV. The Commission believes that NERC should “consider formalizing the criteria for inclusion of critical facilities operated below 100 kV in developing
the exemption process.” Thus, as envisioned, Regional Entities will be able to request the inclusion of Elements below 100 kV in the pending Rules of Procedure

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 6 Comment

exception process and will bear the burden of proof that such Elements are critical Facilities.
American Electric Power (AEP)

No

Please see response provided to question 5.

No

We prefer a bright-line rule of 100 kV. The exception process should not be used to include facilities operated
at voltages below 100 kV.

Response: See response to Q5.
Southern Company

Response: The SDT believes that the criteria enumerated in the current Statement of Compliance Registry Criteria should be the template for defining the “brightline” exception criteria in Project 2010-17. In Order No. 743, the Commission also directed NERC to adopt an inclusion process for including in the BES definition
Facilities operated at voltages below 100 kV. The Commission believes that NERC should “consider formalizing the criteria for inclusion of critical facilities
operated below 100 kV in developing the exemption process.” As envisioned, Regional Entities will be able to request the inclusion of Elements below 100 kV in
the pending Rules of Procedure exception process and will bear the burden of proof that such Elements are critical Facilities.
Independent Electricity System
Operator

No

Again, we need to assess the criteria for the exception, which have not been developed.
Also, the proposed wording seems to present a circular argument. We suggest to change the wording as
follows: Individual generation resources greater than 20 MVA (gross nameplate rating) directly connected via
a step-up transformer(s) to Facilities operated at voltages below 100kV that are deemed to be included in the
BES as determined by the exception/inclusion process.

Response: The SDT acknowledges that commenters will need to reserve judgment on the exception process, which is to be developed as a modification to the
Rules of Procedure in an effort parallel with this BES definition development.
The SDT notes the suggested language in this comment, and has considered it in the development of the revised definition of BES.
Springfield Utility Board

No

"directly connected" is important.

Response: The SDT has revised the definition and that term is no longer utilized.
Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the generator terminals through the GSU which
has a high side voltage of 100 kV or above.
Manitoba Hydro
Occidental Energy Ventures Corp

March 30, 3011

Abstain until exemption process has been defined.
No

Until the exemption process is finalized, it is not prudent to answer in the affirmative.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
Duke Energy

Yes or No

Question 6 Comment
There is not enough information available at this time to adequately evaluate this question. It would be
necessary to have a list of exemption criteria or more detail on the exemption process to address this
question. This is one of the reasons that the exemption criteria should be developed through the standards
development process along with the definition.

Response: The SDT acknowledges that commenters will need to reserve judgment on the pending Rules of Procedure exception process, which is to be
developed in a parallel effort with this BES definition development. Nonetheless, the SDT believes that criteria enumerated in the current Statement of
Compliance Registry Criteria should be the template for defining the bright-line exception criteria in Project 2010-17. The exception criteria (now included in the
revised definition of BES) provides for both inclusions and exclusions. FERC Order No. 743 states that changes to the BES definition “will not significantly
increase the scope of the present definition, which applies to transmission, generation and interconnection facilities.”
Northeast Power Coordinating
Council

Refer to the response to Question 13.

Response: See response to Q13.
Entergy Services

Our response to this question depends on the details of the “exemption process”, including what entity has
the final decision and how it is implemented. Please see our response to Q13 below.

Orange and Rockland Utilities,
Inc.

The purpose of this question is hard to ascertain. The BES exemption process has not yet been finalized or
approved. So, it is somewhat difficult to know a priori whether any individual generation resources greater
than 20 MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Facilities operated at
voltages below 100kV should or should not be classified as part of the BES definition.
This document uses both “exemption process” and “exception process”. Recommend that the phraseology
be standardized on “exception process” as the exception (not the exemption) can be to include or exclude
elements and facilities.
Refer to the response to Question 13.

Response: The SDT acknowledges that commenters will need to reserve judgment on the pending Rules of Procedure exception process, which is to be
developed in an effort parallel with this BES definition development. Nonetheless, the SDT believes that criteria enumerated in the current Statement of
Compliance Registry Criteria should be the template for defining the bright-line exception criteria in Project 2010-17. The exception criteria will provide for both
inclusions and exclusions. FERC Order No. 743 states that changes to the BES definition “will not significantly increase the scope of the present definition, which
applies to transmission, generation and interconnection facilities.”
See response to Q13.

March 30, 3011

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Organization

Yes or No

Xcel Energy

Question 6 Comment
Xcel Energy does not disagree that there may be situations where generators greater than 20 MVA
individually or 75 MVA in aggregate are connected via step up Transformers below 100 KV that may need to
be included, but we have concerns about the exemption process. This undeveloped process presents itself
as a wild card to entities, and will most likely present inconsistencies between regions based upon each
Region’s preference. Additionally, does the Regional Methodology require any approval (e.g. ERO) other
than the Region’s own process? The “exclusions” process indicates that the ERO has the final approval
authority to exclude an item from the BES. Why would the same not apply for including something into the
BES based on the Region’s Methodology?

Response: The SDT acknowledges that commenters will need to reserve judgment on the pending Rules of Procedure exception process, which is to be
developed in an effort parallel with this BES definition development. Nonetheless, the SDT believes that criteria enumerated in the current Statement of
Compliance Registry Criteria should be the template for defining the bright-line exception criteria in Project 2010-17. The exception criteria will provide for both
inclusions and exclusions. The SDT notes that a stated purpose of Order No. 743 was to eliminate the regional discretion allowed in the existing definition of BES
and remove any ambiguity regarding who is required to comply and accomplish the goal of reducing inconsistencies across regions. As per FERC Order No. 672,
any regional variations must be approved by FERC, and generally must be more “stringent” than NERC criteria. As envisioned, Regional Entities will be able to
question the outcome of bright-line criteria in the BES definition in the pending Rules of Procedure exception process and will bear the burden of proof that such
Elements are critical Facilities or not. FERC Order No. 743 states that changes to the BES definition “will not significantly increase the scope of the present
definition, which applies to transmission, generation and interconnection facilities.”
The Dow Chemical Company

As discussed in response to question #12 below, issues relating to the registry criteria applicable to
generation resources should not be revisited at this time.

Response: See response to Q12.
City of Grand Island

Yes

See comments for items 2 and 5.

Yes

Please see additional comments at the end of this document.

PPL Energy Plus

Yes

LG&E and KU Energy LLC

Yes

Yes, PPL Energy Plus supports an exemption process provided the Exemption process follows FERCs Order
743 paragraph 115: “NERC should develop an exemption process that includes clear, objective, transparent,
and uniformly applicable criteria for exemption of facilities that are not necessary for operating the grid.” As
written, however, the 20 MVA threshold does not appear to have been developed per FERC’s requirements

Response: See response to Q2 & Q5.
NERC Staff
Response: See response to Q13.

March 30, 3011

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Organization

Yes or No

Question 6 Comment
for the reasons discussed in the response to Questions 2 and 8.

Response: The SDT is committed to drafting a BES definition and exception criteria that will enable the pending Rules of Procedure exception process “that
includes clear, objective, transparent, and uniformly applicable criteria for exemption of facilities that are not necessary for operating the grid.” The SDT believes
that the criteria enumerated in the current Statement of Compliance Registry Criteria should be the template for defining the bright-line exception criteria in Project
2010-17.
Utility Services

Yes

See the answer to Question 1.

Yes

However, the applicable process should be called an “exception” process, not an “exemption” process that
infers the concept of “exclusion” and further classified as part of the BES given that a fault or an outage on
individual generation resources greater than 20MVA would not maintain an Adequate Level of Reliability of
the BES.

Response: See response to Q1.
American Transmission company

Response: The SDT has adopted the use of the terms “exception criteria” and “exception process.”
SERC OC Standards Review
Group

Yes

We think the process should be an “exception” rather than an “exemption”. This question seems illogical
since the last part of the question assumes the generator is already part of the BES through the determination
of the exemption process. If the question was actually generators less than 20 MVA, we don’t agree.

Response: The SDT has adopted the use of the terms “exception criteria” and “exception process.” The SDT believes that the criteria enumerated in the current
Statement of Compliance Registry Criteria should be the template for defining the bright-line exception criteria in Project 2010-17.
IRC Standards Review
Committee

Yes

Again, we need to assess the criteria for the exception, which have not been developed.
Also, the proposed wording seems to present a circular argument. We suggest to change the wording as
follows: Individual generation resources greater than 20 MVA (gross nameplate rating) directly connected via
a step-up transformer(s) to Facilities operated at voltages below 100kV that are deemed to be included in the
BES as determined by the exception/inclusion process.

Response: The SDT acknowledges that commenters will need to reserve judgment on the pending Rules of Procedure exception process, which is to be
developed in an effort parallel with this BES definition development.
The SDT notes the suggested language in this comment, and has considered it in the development of the revised definition of BES., Included in the BES: I2
- Individual generating units greater than 20 MVA (gross nameplate rating) including the generator terminals through the GSU which has a high side voltage

March 30, 3011

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Organization

Yes or No

Question 6 Comment

Yes

FERC has directed (in section 30 of FERC Order 743) that NERC have an established “exemption” process to
remove this judgment from the Regions in defining what the BES is. However, the applicable process should
be called an “exception” process, not an “exemption” process that infers the concept of “exclusion” and further
classified as part of the BES given that a fault or an outage on individual generation resources greater than
20MVA would not maintain an Adequate Level of Reliability of the BES.

of 100 kV or above.
MRO's NERC Standards Review
Subcommittee

Response: The SDT has adopted the use of the terms “exception criteria” and “exception process” in its work. Note, however, that neither term is used in the
proposed definition of BES.
City of Redding

Yes

City of Anaheim

Yes

Bonneville Power Administration

Yes

LCRA Transmission Services
Corporation

Yes

North Carolina EMC

Yes

ReliabilityFirst

Yes

It is recommended that the exemption process be defined and criteria setup so that a common approach
across the ERO can be used to include these facilities.

Glacier Electric Cooperative

Yes

Yes - Once again, this is assuming that the exemption process is an accurate way to truly determine whether
or not a facility is significant to the grid.

United Illuminating Company

Yes

Any Generator directly connected via a step-up transformer(s) to Facilities operated at voltages below 100kV
where the exemption process deems the generation resources to be included in the BES should be part of
BES . There should not be a MVA threshold

City of Austin dba Austin Energy

Yes

This answer assumes that an appropriate engineering study is performed to determine that the asset is
necessary for the reliability of the BES.

March 30, 3011

If the exemption process is based on engineering studies targeted to identify those facilities necessary to
reliably operate the interconnected transmission system.

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Organization
The Dayton Power and Light
Company

Yes or No

Question 6 Comment

Yes

Response: Thank you for your response. This criterion was not changed, but is now embedded in the revised definition of BES.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

7. Should the following be classified as part of the BES?
•

Generation plants with aggregate capacity greater than 75 MVA (gross nameplate rating) directly connected via a step-up
transformer(s) to Facilities operated at voltages below 100kV where the exemption process deems the generation plants
to be included in the BES

Summary Consideration: Most commenters who responded to this question indicated disagreement with the proposal however there was no
consensus amongst the alternate proposals offered, and the proposals suggesting other thresholds were not supported with any technical
justification. The SDT has reviewed the industry comments on this issue, debated the topic, and come to an agreement that the bright-line
designation for multiple generating units is 75 MVA and 100 kV as shown below. Any deviations from the bright-line designation would be handled
through the Rules of Procedure process.
Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating) including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
Several comments indicated that local distribution networks should be excluded, and the drafting team adopted this suggestion and added the
following to the list of “Exclusions” from the 100 kV threshold that are included in the revised definition of BES.
Excluded from the BES: E3 - Local distribution networks (LDN): Groups of Elements operated above 100 kV that distribute power to Load rather
than transfer bulk power across the Interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one location
solely to improve the level of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;
b) Limits on connected generation: The LDN, nor its underlying Elements, includes no more than a total of 75 MVA generation;
c) Power flows only into the Local Distribution Network: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or Transfer Path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored
Facility in the Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

Organization
SERC EC Planning Standards
Subcommittee

March 30, 3011

Yes or No

Question 7 Comment

No

We prefer a bright-line rule of 100 kV. The exception process should not be used to include facilities operated
at voltages below 100 kV.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

BGE

No

Question 7 Comment
This proposal as written could lead to the inclusion of elements or facilities which have no material reliability
impact on the interconnected transmission system.

Response: The SDT has reviewed the industry comments on this issue, debated the topic, and come to an agreement that the bright-line designation for multiple
generating units is 75 MVA and 100 kV. Any deviations from the bright-line designation will be handled through the Rules of Procedure process. The process
for such inclusions will be developed as part of the revision to the Rules of Procedure by another team, in an effort parallel to the development of this BES
definition.
IRC Standards Review
Committee

No

Same comment as in Q6, above.

Public Service Enterprise Group
Company

No

See the response to item 6 above.

Snohomish County PUD

No

See response to question 6

Independent Electricity System
Operator

No

Same comment as in Q6, above.

Florida Municipal Power Agency

No

See FMPA responses to Questions 5 and 6 above.

Transmission Access Policy
Study Group

No

Response: See response to Q6.

Response: See responses to Q5 & Q6.
Electric Market Policy

No

Dominion does not agree that generation plants should be classified as part of the BES.

Response: The SDT finds no basis for the exclusion of generation plants from the BES, and continues to believe that generation is an integral part of the BES
which any core BES definition must necessarily include.
PacifiCorp

March 30, 3011

No

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 7 Comment
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology.
Significant efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF)
over the course of the past year to identify some initial criteria and methodologies. These efforts are ongoing
and should be supported by the NERC drafting team. For example: Generation plants should not be included
or excluded solely based on a their gross nameplate rating and the operating voltage at which they are
connected to transmission facilities. Generation plants which are necessary to operate the interconnected
network should be included as part of the regulated BES. Generating plants which are not “necessary for the
operation of the interconnected network” should be excluded. A methodology needs to be developed to
determine which generating plants may be excluded as part of the regulated BES.

Response: The SDT acknowledges that commenters will need to reserve judgment on the process, which is to be developed as a modification to the Rules of
Procedure by another team in an effort parallel with this BES definition development.
The SDT acknowledges the work of the WECC BESDTF, and in keeping with the concepts of that work, envisions that the process will identify for inclusion in the
BES only those generators that are necessary to operate the interconnected network.
ExxonMobil Research and
Engineering

No

See comments on questions 2 and 3.

No

Generation plants with aggregate capacity of less than 300 MVA (gross nameplate rating) directly connected
via a step-up transformer(s) to Facilities operated at voltages below 100 kV do not materially impact the
reliability of the BES and therfore, should not be classified as part of the BES.

Response: See responses to Q2 & Q3.
Arizona Public Service Company

Response: The SDT appreciates the suggestion of a 300 MVA threshold for materiality of impact; however, it sees no technical justification upon which to base a
significant departure from the generation MVA thresholds included in the NERC Statement of Compliance Registry Criteria. The SDT has reviewed the industry
comments on this issue, debated the topic, and come to an agreement that the bright-line designation for multiple generating units is 75 MVA and 100 kV. Any
deviations from the bright-line designation will be handled through the Rules of Procedure process. The process for such inclusions will be developed as part of
the revision to the Rules of Procedure by another team, in an effort parallel to the development of this BES definition.

March 30, 3011

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Organization

Yes or No

Question 7 Comment

Pepco Holdings Inc.

No

Some details on the exemption process must be known before accepting this. Who can submit an exemption
(DP, GO, GOP, TO, TOP, RC, etc)? How do interested parties get informed? Can others intervene? Would
the other facilities completing the connection to a BES facility be automatically included?

American Municipal Power

No

on behalf of Teck Metals Ltd.

No

on behalf of Catalyst Paper
Corporation

No

Occidental Energy Ventures
Corp

No

Idaho Power

No

Springfield Utility Board

No

Clark Public Utilities

No

Until the exemption process is finalized, it is not prudent to answer in the affirmative.

Response: The SDT acknowledges that commenters may need to reserve judgment on the exception process, which is to be developed as a modification to the
Rules of Procedure in an effort parallel with this BES definition development.
North Carolina EMC

No

Generation facilities operated at voltages below 100kV should only be included in the BES if identified by the
RRO as critical to the BES.

Response: The SDT envisions that the exception process that would be used to possibly include such Facilities will identify for inclusion in the BES only those
generating plants that are essential to the reliable operation of the interconnected system. This process is being developed as a revision to the NERC Rules of
Procedure by another team in an effort parallel to the development of this BES definition.
Indeck Energy Services

No

Same Response as Question 1

Utility Services

Yes

See the answer to Question 1.

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Organization

Yes or No

Question 7 Comment

Response: See response to Q1.
Southern California Edison

No

SCE currently reports on generation plants with aggregate capacity greater than 75 MVA (gross nameplate
rating) directly connected via a step-up transformer(s) to Facilities operated at voltages above 100kV. SCE
does not feel it is necessary to report on generation below 100kV.

Response: While the definition of the BES is a different matter than data reporting for generation plants, the SDT has incorporated a BES designation it believes
will address your concerns.

Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
Southern California Edison
Company

No

In SCE's system, generation resources are used to offset load being served by distribution facilities. This
means that generation does not flow through step-up transformers into the 100kV and above system.
Therefore, those generation resources which are used to provide power to local load within a distribution
system should not be included as part of the BES. The Exemption Process should not be applied to such
resources.

Response: In its latest revision of the BES definition, the SDT has incorporated a designation for local distribution networks (LDN) for exclusion from the BES.
•

Excluded from the BES: E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV that distribute power to Load rather than
transfer bulk power across the interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to improve
the level of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting
devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the Quebec Interconnection, and
is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

ISO New England Inc.

March 30, 3011

No

See the comments provided in response to question 7.

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Organization

Yes or No

Question 7 Comment

Response: This is Q7. The SDT assumes that this is a typo and should have referred to a different question.
PUD No.1 of Clallam County

No

Central Lincoln

No

PNGC Power

No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

March 30, 3011

Including elements through an exemption process is bound to create confusion and misunderstandings
between the registrants and REs. Please include such elements through an inclusion process. It should also
be clarified that registrants are not required to put all sub-100 kV elements through this process; the burden
should be on the RE to include elements of particular concern.

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Organization

Yes or No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric
Cooperative

No

Lincoln Electric Cooperative

No

Fall River Electric Cooperative

No

Question 7 Comment

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743. The process for such inclusions will be developed as part of the revision to the Rules of
Procedure by another team in an effort parallel to the development of this BES definition.
ITC Holdings Corp

No

Only included if the plant is deemed Critical by the PRC023 test.

Response: The SDT is aware of the test proposed under PRC-023, however, in this definition, the SDT is striving to develop “bright-line” characteristic criteria
that will be used to make definitional inclusions and exclusions, and this will be paired with an “exception process” which will be developed as part of the revision
to the Rules of Procedure by another team in an effort parallel to the development of this BES definition. The SDT will forward the suggestion of a “PRC-023 test”
to the team tasked with development of the revision to the Rules of Procedure.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

No

Although Constellation believes that it may be appropriate to include some of the elements above in the BES,
this proposal will lead to the inclusion of elements or facilities which have no material impact on the
interconnected transmission system.
Furthermore, the use of an exemption process to include assets is confusing. Constellation proposes that the
BES drafting team structure the revised BES definition to clarify both the inclusions and exclusions as
completely as possible. If a separate “opt-in” process is deemed necessary (in anticipation of a few
exceptions to the definition) then the drafting team should develop criteria for such a process. Using this
approach the sentence above would then read “Generation plants with aggregate capacity greater than 75
MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Facilities operated at
voltages below 100kV where a Regional Entity deems the generation plants to be included in the BES.”

Response: The SDT has reviewed the industry comments on this issue, debated the topic, and come to an agreement that the bright line designation for multiple

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Organization

Yes or No

Question 7 Comment

generating units is 75 MVA and 100 kV. Any deviations from the bright line designation will be handled through the Rules of Procedure process. The SDT is
striving to develop “bright-line” characteristic criteria that will be used to make definitional inclusions and exclusions, and this will be paired with the “exception
process” which will be developed as part of the revision to the Rules of Procedure by another team in an effort parallel to the development of this BES definition.
The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the “exception”
process suggested by the Commission in its Order 743. The process for such inclusions will be developed as part of the revision to the Rules of Procedure by
another team in an effort parallel to the development of this BES definition.
City Water Light and Power
(CWLP) - Springfield, IL

No

While CWLP agrees with the general concept of inclusion by exception (as opposed to exemption), we have
concerns regarding the lack of detailed definition of this process, especially the administrative process for
disputes regarding inclusion of elements in the BES.
Without firm administrative rules for resolving disputes based on technical justification, we cannot support this
measure currently.

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743. The SDT is striving to develop “bright-line” characteristic criteria that will be used to make
definitional inclusions and exclusions as part of the revised definition of BES. The SDT acknowledges that commenters may need to reserve judgment on the
process until more clarity is provided via the development of the revision to the Rules of Procedure.
Lewis County PUD

No

I find it hard to believe that elements connected at less than 100kV are part of the BES.
The burden of proof to include elements in the BES should be on the RE not the owner of such facilities.

Southern Company

No

We prefer a bright-line rule of 100 kV.
The exception process should not be used to include facilities operated at voltages below 100 kV.

Response: The SDT agrees that the bright-line designation for multiple generating units is 75 MVA and 100 kV. Any deviations from the bright-line designations
identified in the final BES definition will be handled through the Rules of Procedure process. (The SDT is striving to develop “bright-line” characteristic criteria that
will be used to make definitional inclusions and exclusions as part of the revised definition of BES. ) The process for approving such inclusions will be developed
as part of the revision to the Rules of Procedure by another team in an effort parallel to the development of this BES definition.
American Electric Power (AEP)

No

Please see response provided to question 5.

Response: See response to Q5.
Orange and Rockland Utilities,

March 30, 3011

The purpose of this question is hard to ascertain. The BES exemption process has not yet been finalized or
approved. So, it is somewhat difficult to know a priori whether any generation plants with aggregate capacity

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Organization
Inc.

Yes or No

Question 7 Comment
greater than 75MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Facilities
operated at voltages below 100kV should or should not be classified as part of the BES definition. This
document uses both “exemption process” and “exception process”. Recommend that the phraseology be
standardized on “exception process” as the exception (not the exemption) can be to include or exclude
elements and facilities. Refer to the response to Question 13.

Response: The SDT acknowledges that commenters may need to reserve judgment on the exception process until more clarity is provided via the development of
the revision to the Rules of Procedure.
The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the “exception”
process suggested by the Commission in its Order 743. Any deviations from the bright-line designations identified in the final BES definition will be handled
through the Rules of Procedure process. (The SDT is striving to develop “bright-line” characteristic criteria that will be used to make definitional inclusions and
exclusions as part of the revised definition of BES.)
Also, see response to Q13.
The Dow Chemical Company

As discussed in response to question #12 below, issues relating to the registry criteria applicable to
generation resources should not be revisited at this time.

Response: See response to Q12.
Manitoba Hydro

Abstain until exemption process has been defined.

Duke Energy

There is not enough information available at this time to adequately evaluate this question. It would be
necessary to have a list of exemption criteria or more detail on the exemption process to address this
question. This is one of the reasons that the exemption criteria should be developed through the standards
development process along with the definition.

Response: Thank you for your response. The revised definition of BES includes both a “bright-line” characteristic and a list of criteria that will be used to make
definitional inclusions and exclusions to that bright line,
Entergy Services

Our response to this question depends on the details of the “exemption process”, including what entity has
the final decision and how it is implemented. Please see our response to Q13 below.

Northeast Power Coordinating
Council

Refer to the response to Question 13.

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Organization

Yes or No

NERC Staff

Yes

Question 7 Comment
Please see additional comments at the end of this document.

Response: See response to Q13.
Xcel Energy

Xcel Energy does not disagree that there may be situations where generators greater than 20 MVA
individually or 75 MVA in aggregate are connected via step up Transformers below 100 KV that may need to
be included, but we have concerns about the exemption process. This undeveloped process presents itself
as a wild card to entities, and will most likely present inconsistencies between regions based upon each
Region’s preference. Additionally, does the Regional Methodology require any approval (e.g. ERO) other
than the Region’s own process? The “exclusions” process indicates that the ERO has the final approval
authority to exclude an item from the BES. Why would the same not apply for including something into the
BES based on the Region’s Methodology?

Response: A separate Rules of Procedure (ROP) team is undertaking to develop a process for Facilities that do not fit within the bright-line definition. The details
of the process are still under discussion and development. However, the SDT expects that ERO will have an oversight role on the Regional Process.
ReliabilityFirst

Yes

It is recommended that the exemption process and the term “directly connected” be defined and criteria setup
so that a common approach for including plants of this size be used across the ERO for reviewing these
facilities and making this determination.

Response: The SDT believes that the phrase “directly connected” has been addressed in the latest revision. The SDT replaced this term with more descriptive
language.

Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
City of Grand Island

Yes

See comments for items 3 and 5.

PPL Energy Plus

Yes

LG&E and KU Energy LLC

Yes

Yes, PPL Energy Plus supports an exemption process provided the Exemption process follows FERCs Order
743 paragraph 115: “NERC should develop an exemption process that includes clear, objective, transparent,
and uniformly applicable criteria for exemption of facilities that are not necessary for operating the grid.” As
written, however, the 75 MVA does not appear to have been developed per FERC’s requirements for the
reasons discussed in the response to Questions 2 and 8.

Response: See responses to Q3 & Q5.

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Organization

Yes or No

Question 7 Comment

Response: The exception process will be developed as part of the revision to the Rules of Procedure by another team in an effort parallel to the development of
this BES definition.
Also, see response to Questions 2 and 8.
SERC OC Standards Review
Group

Yes

We think the process should be an “exception” rather than an “exemption”. This question seems illogical
since the last part of the question assumes the generation plant is already part of the BES through the
determination of the exemption process If the question was actually generation plants less than75 MVA, we
don’t agree.

American Transmission
company

Yes

The applicable process should be called an “exception” process, not an “exemption” process that infers the
concept of “exclusion” and further classified as part of the BES given that a fault or an outage on the
generation resource with aggregate capacity greater than 75 MVA would not maintain an Adequate Level of
Reliability of the BES.

MRO's NERC Standards Review
Subcommittee

Yes

However, the applicable process should be called an “exception” process, not an “exemption” process that
infers the concept of “exclusion” and further classified as part of the BES given that a fault or an outage on the
generation resource with aggregate capacity greater than 75 MVA would not maintain an Adequate Level of
Reliability of the BES.

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743. The process for such inclusions will be developed as part of the revision to the Rules of
Procedure by another team in an effort parallel to the development of this BES definition.
City of Redding

Yes

See question 6 comments

Response: See response to Q6.
City of Anaheim

Yes

Bonneville Power Administration

Yes

LCRA Transmission Services
Corporation

Yes

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Organization

Yes or No

Question 7 Comment

Glacier Electric Cooperative

Yes

Yes - Once again, this is assuming that the exemption process is an accurate way to truly determine whether
or not a facility is significant to the grid.

United Illuminating Company

Yes

Generation Plants directly connected via a step-up transformer(s) to Facilities operated at voltages below
100kV where the exemption process deems the generation resources to be included in the BES should be
part of BES . There should not be a MVA threshold

City of Austin dba Austin Energy

Yes

This answer assumes that an appropriate engineering study is performed to determine that the asset is
necessary for the reliability of the BES.

The Dayton Power and Light
Company

Yes

Response: Thank you for your response.

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8. Should the following be excluded from the Elements and Facilities classified as part of the BES?
•

Any radial Transmission Element or System, connected from one Transmission source to a Load-serving Element and/or
generation resources not included in items 2, 3, 4, 6, and 7 above are excluded from the BES

Summary Consideration: Most commenters who responded to this question indicated agreement with the proposal. The SDT agrees with the
majority of industry comments and has developed “bright-line” exclusions for designated radial systems (only serving Load and designated
generation resources) as part of the revised BES definition in the NERC Glossary without going through the exception process being developed
separately as part of the revision to the Rules of Procedure by another team in an effort parallel to the development of this BES definition.
The revised definition includes a list of “Inclusions” and “Exclusions” from the 100 kV threshold and no longer references any ‘exemption process’.
Based on stakeholder comments, the following “Exclusions,” relative to radial systems, has been added to the revised definition of BES:
•

Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an
automatic interruption device and:
d) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow
for reliable system reconfiguration to maintain continuity of electrical service. Or,
e) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
f) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in
Inclusions I2, I3, I4 and I5.

Based on stakeholder comments, the following “Exclusions,” relative to local distribution networks, has been added to the revised definition of
BES:
•

Excluded from the BES: E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV that distribute power to Load
rather than transfer bulk power across the interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than
one location solely to improve the level of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic
fault-interrupting devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable
monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating
Limit (IROL).

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Organization

Yes or No

Question 8 Comment

Electric Market Policy

No

Dominion supports bright line exclusions of radial lines regardless of their kV rating. Radial lines to/from
solely generation facilities and radial lines to/from load are comparable in terms of their impact on an
interconnected transmission network. There are situations where these radials make a meaningful and
required contribution to the operation of an interconnected transmission network and there are other
locations/situations where these radials do not. Therefore, radial lines should only be specifically included in
the definition of BES after the RRO has demonstrated that inclusion of the radial is necessary to operate an
interconnected transmission network and the owner/operator of the radial line has had the opportunity to
exercise its aforementioned appeal rights.

Independent Electricity System
Operator

Yes

Classification of all radial facilities operated at voltages of 100 kV and above as part of the BES by default
would be unnecessary and administratively inefficient, and could potentially lead to delays in the review and
approval of other exemption requests. As such, the proposed definitions should be revised to clearly define
what radial Transmission Elements will not be included as part of the BES. This would be consistent with
FERC’s intention expressed in Paragraph 55 of Order 743 to not alter the part of the approved definition that
deals with “radial transmission facilities serving only load”. Additionally, to ensure a common understanding
of the meaning of “radial” and to promote consistency in its application, we believe “radial” should be defined
after seeking stakeholder input and added to the NERC Glossary.

MRO's NERC Standards Review
Subcommittee

Yes

However, the NSRS agrees that a radial transmission element or system directly connected from one
Transmission source to a Load-serving Element and/or generation resources are excluded as part of the BES
given that a fault or an outage of the radial transmission element or system would not impact the Adequate
Level of Reliability of the BES.

SERC EC Planning Standards
Subcommittee

Yes

The definition should clearly state that these elements are excluded. It currently implies that the exception
process would have to be applied to exclude radial elements.

Florida Municipal Power Agency

Yes

Transmission Access Policy
Study Group

Yes

Radial Transmission Elements connected from one Transmission source to a Load-serving Element and/or
generation resources not included in items 2, 3, 4, 6, and 7 above should be excluded from the BES. It is
very important that the exclusion of radial transmission serving only load with one transmission source be
recognized as a categorical exclusion from the BES definition, not merely as grounds for requesting an
exemption. In that way, such radials do not have to go through an exemption process, but are treated the
same as sub-100 kV Transmission, as they are today. In other words, such Elements could be included in
the BES only if a case-by-case assessment pursuant to the inclusion process demonstrates that a particular
radial Element is necessary for operating the interconnected electric transmission network. If every such
Element instead had to go through a case-by-case exemption process in order to be exempted from the BES,
there would be a staggering burden on small entities and on NERC to process exemption requests for all of

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Organization

Yes or No

Question 8 Comment
the radials serving only load with one transmission source that are excluded from the BES under the current
definition. Order 743 does not require NERC to impose any new burdens on entities who own radials serving
only load that are currently excluded from the BES.FMPA supports adding to the current exclusion a
specification that “A radial Transmission Element may be considered as ‘serving only load’ for purposes of the
foregoing general exclusion even if it connects generation, so long as that generation is not registered
pursuant to the Statement of Compliance Registry Criteria.” We believe that this formulation captures the
generation intended in this Question’s reference to “generation resources not included in items 2, 3, 4, 6, and
7 above.” The FERC-approved Compliance Registry Criteria recognize that a small generator, so long as it is
not a “blackstart unit material to and designated as part of a transmission operator entity’s restoration plan,” is
not material to the reliability of the BES. It follows, therefore, that if a radial line would not be included in the
BES but for the presence of this inconsequential generation, the presence of such non-registered generation
does not cause the line to become necessary for operating an interconnected electric transmission system.
For example, rooftop photovoltaic cells are now common enough that allowing their presence to prevent a
radial from being excluded would render the exclusion of radials to load meaningless. Of course, the
application of the definition of the BES is dynamic. For example, in considering whether new generation
connected by what had previously been a radial to load should be registered, NERC may also reevaluate the
exclusion of the radial.There is no basis for differentiating between radials serving only load, and radials
serving load with insignificant generation. Neither is necessary for operating an interconnected electric
transmission network, and so both should be excluded from the BES absent a specific demonstration as to
the materiality of a particular radial.Finally, it may be appropriate for Registered Entities to have the option of
submitting to NERC an informational filing listing their excluded radials. Whether or not a Registered Entity
submits such an informational filing to NERC, a Registered Entity’s claimed exclusion of a radial serving only
load and/or unregistered generation should apply unless and until the radial is added to the BES through the
inclusion process (see FMPA comments on BES exemption process submitted today).

SERC OC Standards Review
Group

Yes

Southern Company

Yes

We assume the question was meant to read: Any radial Transmission Element or System, connected from
one Transmission source to a Load-serving Element and/or generation resources not included in items 2, 3,
4, 6 and 7 above. Any ac transmission Facility composed of Transmission Line(s), substation Facilities, and
transformers that is connected to BES ac Transmission Facilities at only one point by automatic interruption
devices (e.g., circuit breaker or fuse), and is not capable of being switched so as to be simultaneously
connected to BES ac transmission Facilities at a second point, should be considered an “excluded radial
transmission Facility.”

Response: The SDT agrees and has developed “bright-line” exclusions for designated radial systems (only serving Load and designated generation resources) as
part of the revised BES definition in the NERC Glossary without going through the exemption process being developed separately as part of the revision to the
Rules of Procedure by another team in an effort parallel to the development of this BES definition.

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Organization

Yes or No

Question 8 Comment

Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic
interruption device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.
Any deviations from the bright-line designation would be handled through the Rules of Procedure process.
PPL Energy Plus

No

LG&E and KU Energy LLC

No

a) By not allowing exclusion of the generators listed under Items 2,3,4,6,&7, this exclusion is really a blanket
inclusion of all generators over 20MVA. This blanket inclusion is discriminatory because it does not take into
consideration FERC’s orders in Order 743 paragraph 38 that states it is the parallel nature of the lines (and
generator lead lines are not parallel to the Interconnected Network) that justify their inclusion in the BES, NOT
the radial nature of their service. The blanket inclusion of items 2,3,4,6&7 also does not appear to account for
FERC Order 743 in paragraph 120 that encourages exclusion of radial facilities.
b)Further, for the reasons provided in brackets beside the quoted text below, the stated exemption (which is
really a blanket inclusion of items 2,3,4,6&7) appears to ignore FERC Order 743 paragraph 73 which
recognizes that Network Transmission Facilities with specific characteristics should be included in the BES
and most generator lead lines fail to meet the criteria laid out by FERC:
i.most 100 kV lines are parallel to other HV/EHV lines and are significantly loaded by failure of the HV/EHV
lines. [this is not the case with 20 MVA generators]
ii.connect “significant” generation. [less than 200 MVA is generally not significant to the BES]
iii.may be part of a defined transfer path or flowgate. [rarely if ever for a generator]
iv.are capable of causing or contributing to major disturbances. [rarely if ever will this apply to a generator
since an N-1 will take out most generators and the reliability of the Interconnected Network is rarely affected
by an N-1.]

PacifiCorp

March 30, 3011

No

In Order No. 743, the Commission stated that it believes that the best way to address their concerns is to
eliminate the Regional Entities’ discretion to define “bulk electric system” without ERO or Commission review,
maintain a bright-line threshold that includes all facilities operated at or above 100 kV except defined radial
facilities, and adopt an exemption process and criteria for excluding facilities that are not necessary to operate
an interconnected electric transmission network. PacifiCorp believes that the correct interpretation of this

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Organization

Yes or No

Question 8 Comment
sentence is that certain defined radial facilities may be excluded from the definition of BES without going
through the exemption process. The Commission, in paragraph 119 of Order No. 743, does state that the
ERO “could track exemptions for radial facilities,” however, PacifiCorp believes that this step is unnecessary
and would be unduly burdensome for both NERC and registered entities. Therefore a clear definition of
excluded radial transmission elements must be developed and should be defined in the NERC Glossary or in
the BES definition itself.

Springfield Utility Board

No

This question is unclear. There is no NERC definition of "radial" or "Radial". Does this mean transmission
systems normally operated radially but that could be operated in such a way that the system was not radial
that are owned by an LSE/DP and not a TOP/TO (for example) or transmission system?
If radial includes systems "normally operated radial" then "Yes".

Lewis County PUD

No

We note that “radial” and “one Transmission source” are not presently defined. Any radial Transmission
Element or System, connected from one Transmission source to a Load-serving Element and/or generation
resources less than 150MVA should be excluded from the BES.We object to requiring such elements to go
through an exemption process to become excluded.

Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Yes

Constellation believes that the BES definition should incorporate exclusions where possible to eliminate the
need for going through an exclusion process for common facilities that should not be classified as BES.

FirstEnergy Corp

Yes

Needs to be directly identified in the BES definition and not subject to the exemption process.

Response: The SDT agrees and has developed “bright-line” exclusions for designated radial systems (only serving Load and designated generation resources) as
part of the revised BES definition in the NERC Glossary without going through the exception process being developed separately as part of the revision to the
Rules of Procedure by another team in an effort parallel to the development of this BES definition.

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Organization

Yes or No

Question 8 Comment

Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5.
United Illuminating Company

No

Generator Resources should not be excluded.
Load connected by a single radial line can be excluded.

Response: The current Compliance Registry Criteria already excludes certain generator resources from registration. The SDT agrees with this concept and is
continuing that line of thought in the revised definition.
The SDT agrees.
ITC Holdings Corp
National Rural Electric
Cooperative Association
(NRECA)

No
Without explicit exemption criteria to review, it is too early to answer this question. Final exemption criteria
must provide for consistency across all Regional Entities when determining the inclusion or exclusion of radial
facilities as part of the BES. All exemption criteria must be explicit and unambiguous in order to provide as
much certainty as possible. Work done by the Regional Entities on exemption criteria should be reviewed to
determine is usefulness to the SDT.The SDT should consider that load-serving radial transmission lines of
any voltage should be excluded from the BES, especially since these lines are localized and do not affect the
integrity of the BES, i.e., load flow, power flow and short circuit studies.The SDT must also pay particular
attention to the PRC standards and it applicability to radial facilities.

Response: Thank you for your response.
The Dow Chemical Company

Dow recommends that NERC finalize a basic framework for identifying BES facilities before evaluating
individual facilities or types of facilities. Such a framework is recommended by Dow in response to questions
#11 and #12 below.

Response: See responses to Q11 & 12.

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Organization

Yes or No

Question 8 Comment

Central Lincoln

Yes

PUD No.1 of Clallam County

Yes

PNGC Power

Yes

We note, however, that “radial” and “one Transmission source” are not presently defined and are not treated
the same way by the various REs. Please define “radial” in terms of a normal operating mode and clarify that
“one Transmission source” may branch out to have multiple paths to generation upstream of the radial tap.As
noted elsewhere, we object to requiring such elements to go through an exemption process to become
excluded.

Blachly-Lane Electric Co-op

Yes

Clearwater Power Co.

Yes

Douglas Electric Cooperative

Yes

Central Electric Cooperative, Inc.
(Redmond Oregon)

Yes

Raft River Rural Electric
Cooperative

Yes

Northern Lights Inc.

Yes

Salmon River Electric
Cooperative

Yes

Okanogan Country Electric
Cooperative

Yes

Lost River Electric

Yes

Lane Electric Cooperative

Yes

Coos-Curry Electric Cooperative

Yes

Consumer's Power Inc.

Yes

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Organization

Yes or No

Umatilla Electric Co-op

Yes

West Oregon Electric
Cooperative

Yes

Lincoln Electric Cooperative

Yes

Fall River Electric Cooperative

Yes

Question 8 Comment

Response: The SDT agrees and has developed “bright-line” exclusions for designated radial systems (only serving Load and designated generation resources)
as part of the revised BES definition in the NERC Glossary without going through the exception process being developed separately as part of the revision to the
Rules of Procedure by another team in an effort parallel to the development of this BES definition.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5.
Radial systems will be clearly described in the exclusion designations.
Xcel Energy

Xcel Energy has provided a diagram to Ed Dobrowolski on 1/21/11 that lays out a scenario that should be
considered and worked through as part of the development of the definition and exemptions. As stated in
questions 2 & 3 it is unclear as to how treatment of facilities would occur, especially if there are
multiple/separate owners of each wind farm, even thought they aggregate to a common bus that connects to
the transmission system. Treatment of the bus and breakers between each wind farm and the transformer
also needs to be contemplated and addressed in the definition or exclusion process.

Response: See responses to Q2 & Q3.
Indeck Energy Services

March 30, 3011

Yes

Same Response as Question 1

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Organization

Yes or No

Question 8 Comment

Response: See response to Q1.
NERC Staff

Please see additional comments at the end of this document.

Response: See response to Q13.
ExxonMobil Research and
Engineering

Yes

NERC should follow the model of RFC and provide an appendix that provides examples of what type of radial
feeds are exempted. NERC should also utilize IEEE C37.95: Guide for the Protective Relaying of UtilityConsumer Interconnections Section 4, which details typical interconnection facilities, as a reference when
developing their concept of the BES. Addressing typical interconnection facility configurations will assist the
NERC SDT in developing a clear and concise definition that provides a precise line of demarcation between
elements of the BES and end use customer facilities.

Response: The SDT believes that a bright-line definition such as provided in the latest revision is more useful than examples in appendices.
Pepco Holdings Inc.

Yes

Radial transmission element or system and load-serving elements need to be defined.

Manitoba Hydro

Yes

Radial tranmission elements and systems should be excluded, but a clear NERC definition of radial is
required.

Duke Energy

Yes

Radial Transmission Element or System needs to be more clearly defined.

Response: The SDT believes that with the revisions made to the proposed definition that no other definitions will be required.
Idaho Power

Yes

This should be expanded to transmission elements or systems that source load servering stations.Two
examples are: 1.) The non-radial transmission system serving a metro area load at 138 kV where 230 kV and
higher voltage systems surround the area and provide the bulk electric system transfer, and 2.) The nonradial transmission loops that serve rural area load at 138 kV that are essentially tangential to the bulk electric
transfer path.

Response: The SDT has discussed this at length and has drafted exclusions for local distribution networks that should address these concerns and that will be
available for review and comments.
Excluded from the BES: E1 - Local Distribution Networks (LDN): Groups of Elements operated above 100 kV that distribute power to Load rather than transfer
bulk power across the Interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to improve the level

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Organization

Yes or No

Question 8 Comment

of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored
Facility in the Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

Public Service Enterprise Group
Company

Yes

See the response to item 6 above.

Response: See response to Q6.
Northeast Power Coordinating
Council

Yes

City of Redding

Yes

City of Anaheim

Yes

IRC Standards Review
Committee

Yes

Bonneville Power Administration

Yes

March 30, 3011

However, the NERC GO/TO work should incorporated.
Transmission elements serving radial load, radial distribution systems, or non-GO/GOP generation connected to
such radial lines and excluded from BES; provided, however, to eliminate any reliability gaps, such radial
transmission elements should be classified as "Distribution" equipment subject to DP standards, and the PRC
and vegetation management standards should be made applicable to Distribution Providers and this equipment.
This is consistent with the NERC Reliability Functional Model and is more efficient than requiring TO/TOP
registration for radial transmission facilities that function as Distribution and are not required for the reliable
operation of the BES.

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Organization

Yes or No

Question 8 Comment

Competitive Suppliers

Yes

The consideration and criteria about whether radials should be included as elements of the BES or not, needs
to ensure consistency across the Regional Entities, based upon the future revised BES definition and the
exemption criteria. Much of the consideration from the prior questions is based on generators and their size
as measured by their capacity and connection voltage. While EPSA believes that there are some facilities
that should be included (but not all) the “Yes” response to this question is really dependent on the exemption
criteria developed by the Standard Drafting Team for radial lines. The “bright-line” criteria from earlier
questions are not sufficient to make an assertion about what is necessary for reliability with respect to radial
lines. Criteria about generators and their connections is one piece for ensuring reliability. Further bright-line
criteria need to be determined for load-serving elements on par with the generator criteria relevant for
reliability. The BES definition additionally needs to recognize that load and generation can have similar
affects on the BES because both can affect BES voltage and frequency. As written, the BES definition
appears to apply to generation but not load when in fact the BES sees the difference between load and
generation mainly as the direction of power flow.

Arizona Public Service Company

Yes

LCRA Transmission Services
Corporation

Yes

American Municipal Power

Yes

North Carolina EMC

Yes

Radial facilities meeting the above criteria should be automatically exempted from classification as a part of
the BES and should not be required to go through a separate exemption process.

ReliabilityFirst

Yes

As long the facility is purely radial and could under no circumstance or system topology (i.e. via switching or
re-configuration) trip/lockout a BES facility.

on behalf of Teck Metals Ltd.

Yes

Parallel transmission lines from a single source (substation) to a singe load should be excluded from the BES,
with the consent/request of the owner of the connected load (and/or all customers that constitute the
connected load).

Southern California Edison

Yes

SCE currently does not report on any radial Transmission Element or System, connected from one
Transmission source to a Load-serving Element and/or generation resources not included in items 2, 3, 4, 6,
and 7 and believes the above should be excluded.

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Organization

Yes or No

Question 8 Comment

Southern California Edison
Company

Yes

on behalf of Catalyst Paper
Corporation

Yes

City of Grand Island

Yes

Occidental Energy Ventures Corp

Yes

The existing exclusion for radial lines serving load should be maintained. If clarification of the existing
language concerning radials is required, the exclusion and definition of “radial systems,” including the
explanation of “normal operations,” contained in the BES Concept Document seems to accurately reflect
radials serving load or small generators that should be excluded from the BES. FERC orders directing
change in the BES definition support maintaining this exclusion.

City of Anaheim

Yes

Transmission elements serving radial load, radial distribution systems, or non-GO/GOP generation connected
to such radial lines and excluded from BES; provided, however, to eliminate any reliability gaps, such radial
transmission elements should be classified as "Distribution" equipment subject to DP standards, and the PRC
and vegetation management standards should be made applicable to Distribution Providers and this
equipment. This is consistent with the NERC Reliability Functional Model and is more efficient than requiring
TO/TOP registration for radial transmission facilities that function as Distribution and are not required for the
reliable operation of the BES.

Glacier Electric Cooperative

Yes

I don't think a radial transmission system would ever have a significant impact on the BES, so they should be
excluded.

ISO New England Inc.

Yes

Per FERC Order 743, paragraph 55, the Commission declared, "As we stated in the NOPR, we do not seek to
modify the second part of the definition through this Final Rule, which states that "radial transmission facilities"
serving only load with one transmission source are generally not included in this definition.” ISO-NE maintains
that this definition of radial should be the default position and only in cases where other radial configurations
are to be considered should they be examined as part of any exemption or exclusion methodology that is
developed by NERC in accordance with Order 743.

Entergy Services

Yes

March 30, 3011

Parallel transmission lines from a single source (substation) to a singe load should be excluded from the BES,
with the consent/request of the owner of the connected load (and/or all customers that constitute the
connected load).

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Organization

Yes or No

Snohomish County PUD

Yes

Orange and Rockland Utilities,
Inc.

Yes

American Transmission company

Yes

Utility Services

Yes

City of Austin dba Austin Energy

Yes

The Dayton Power and Light
Company

Yes

BGE

Yes

City Water Light and Power
(CWLP) - Springfield, IL

Yes

American Electric Power (AEP)

Yes

Clark Public Utilities

Yes

Question 8 Comment
FERC Order No. 743 is clear that FERC did not intend to disturb the existing exemption for radial facilities.
Accordingly, radial systems should be excluded from the BES. This should not change if the radial system is
used to interconnect a BES generator for reasons set forth in the GOTO Task Force report.

ATC agrees that a radial transmission element or system directly connected from one Transmission source to
a Load-serving Element and/or generation resources are excluded as part of the BES given that a fault or an
outage of the radial transmission element or system would not maintain an Adequate Level of Reliability of the
BES.

BGE believes that the BES definition should incorporate exclusions where possible to eliminate the need for
going through an exclusion process for common facilities which should not be classified as BES.

Yes, and we believe that this exclusion should be applied to both Transmission and Generation.

Response: Thank you for your comments. The revised definition includes a list of “Inclusions” and “Exclusions” from the 100 kV threshold and no longer
references any ‘exemption process’. Based on stakeholder comments, the drafting team added “Exclusions,” to the BES definition relative to radial systems and
local distribution networks.

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9.

Should the following be excluded from the Elements and Facilities classified as part of the BES?
•

Elements and Facilities identified through application of the exemption process, consistent with the criteria, where the
exemption process deems that the Element or Facility should be excluded from the BES (with concurrence from the ERO)

Summary Consideration: The majority of the industry responded positively to this question. However, the SDT understands that the process is
still in development and that may affect actual responses. The SDT is striving to develop a revised “bright-line” definition that contains certain
inclusions/exclusions and that should remove any confusion. A separate Rules of Procedure (ROP) team is undertaking to develop a separate
process for Facilities that entities may choose to follow for their unique/special circumstances that do not fit within the definition and its
designation.

Organization

Yes or No

Question 9 Comment

IRC Standards Review
Committee

No

We find this exclusion criteria to be redundant. We believe that the proposed definition together with the basic
inclusion criteria suffice to provide a bright line framework for determining Elements/Facilities that should be
included as BES. Having this exclusion criteria confuses the bright line approach and does not add any value
to the basic definition and inclusion criteria.

Independent Electricity System
Operator

No

We find this exclusion criteria to be redundant. We believe that the proposed definition together with the basic
inclusion criteria suffice to provide a bright line framework for determining Elements/Facilities that should be
included as BES. Having this exclusion criteria confuses the bright line approach and does not add any value
to the basic definition and inclusion criteria.

Electric Market Policy

Yes

Dominion conceptually supports an exemption process whereby NERC or the RRO could apply to have an
element included or excluded from the BES definition. Such process recognizes that it may be necessary to
include elements that do not meet the bright line criteria but are necessary for operating an interconnected
transmission network. Such process should be developed through the existing NERC standards development
process and include a robust appeals process for the owner/operator of any element so included or excluded.

Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC

Yes

Constellation recognizes the value in clarifying the Definition of Bulk Electric System into a bright line
threshold consistently applied across the regions. However, we are concerned that the current approach of a
simple, all inclusive definition coupled with an exception criteria and process will not draw on the
fundamentals underpinning the existing definition and create a cumbersome and unnecessary exception
process. As an alternative, we propose that the standard drafting team utilize the -Section III (Rules of
Procedure Appendix 5B) along with definition threshold language to develop a more comprehensive
definition. Regardless of approach, any elements and facilities found to meet the criteria for exemption
should be exempted. The development of such criteria should be part of the BES drafting team’s

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Organization

Yes or No

(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Question 9 Comment
responsibility.

Response: Your comments are noted. The SDT is striving to develop a “bright-line” definition that will contain certain inclusions/exclusions and that should
remove any confusion. A separate Rules of Procedure (ROP) team is undertaking to develop a separate process for Facilities that entities may choose to follow for
their unique/special circumstances that do not fit within the definition and its designation.
Occidental Energy Ventures Corp

No

Manitoba Hydro

Until the exemption process is finalized, it is not prudent to answer in the affirmative.
Abstain until exemption process has been defined.

Response: The SDT understands that the process is still in development and how that may affect your response.
National Rural Electric
Cooperative Association
(NRECA)

Without specific exemption criteria to review, it is too early to explicitly answer this question. However, the
concept appears to be logical. All exemption criteria must be explicit and unambiguous in order to provide as
much certainty as possible.
Work done by the Regional Entities on exemption criteria should be reviewed to determine is usefulness to
the SDT.

PacifiCorp

Yes

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology.
Significant efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF)
over the course of the past year to identify some initial criteria and methodologies. These efforts are ongoing
and should be supported by the NERC drafting team.

Response: The SDT is striving to develop a “bright-line” definition that will contain certain inclusions/exclusions and that should remove any confusion. A separate
Rules of Procedure (ROP) team is undertaking to develop a separate process for Facilities that entities may choose to follow for their unique/special

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Organization

Yes or No

Question 9 Comment

circumstances that do not fit within the definition and its designation.
Work done by Regional Entities is one of many inputs to the SDT deliberations.
Xcel Energy

MRO's NERC Standards Review
Subcommittee

This undeveloped process presents itself as a wild card to entities, and will most likely present inconsistencies
between regions based upon each Region’s preference. Additionally, does the Regional Methodology require
any approval (e.g. ERO) other than the Region’s own process? The “exclusions” process indicates that the
ERO has the final approval authority to exclude an item from the BES. Why would the same not apply for
including something into the BES based on the Region’s Methodology?
Yes

This will give the industry a clear set of criteria to follow which is FERC approved. If a Regional Entity has a
need to alter this process there are processes in place for them to pursue a variance. However, the
applicable process should be called an “exception” process to avoid the connotation that “exemption” process
has for the “inclusion” aspect of the process. NSRS believes the exemption process, review and approval,
would be best handled by the Regional Entity (RE) since they have more knowledge on the transmission
system in their region. The “who” and “what” will have to be spelled out clearly in the criteria for the exception
process.

Response: A separate Rules of Procedure (ROP) team is undertaking to develop a process for Facilities that do not fit within the bright-line definition. The details
of the process are still under discussion and development. However, the SDT expects that ERO will have an oversight role on the Regional Process.
The Dow Chemical Company

Dow recommends that NERC finalize a basic framework for identifying BES facilities before evaluating
individual facilities or types of facilities. Such a framework is recommended by Dow in response to questions
#11 and #12 below.

Response: See responses to Q11 & 12.
Entergy Services

Our response to this question depends on the details of the “exemption process”, including what entity has
the final decision and how it is implemented. Please see our response to Q13 below.

Northeast Power Coordinating
Council

Yes

Refer to the response to Question 13.

FirstEnergy Corp

Yes

Yes, but the process should be simple, rarely used with a high threshold for removing any 100kV and above
facility from the normally defined BES. Please see our Question 13 response for further views.

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Organization

Yes or No

Question 9 Comment

NERC Staff

Yes

Please see additional comments at the end of this document.

Orange and Rockland Utilities,
Inc.

Yes

Refer to the response to Question 13.

Florida Municipal Power Agency

Yes

Transmission Access Policy
Study Group

Yes

It is important to maintain the distinction between “exclusions” and “exemptions.” The SDT seems at times to
use the words interchangeably. An exclusion is a categorical carve-out from the BES definition, such that
excluded Elements are treated the same as sub-100 kV Transmission. FMPA proposes the following
exclusion, which would retain the existing exclusion of radials serving only load with one Transmission
source, clarified to add radials serving inconsequential generation to the exclusion:Radial Transmission
Elements serving only load with one Transmission source are generally not included in this definition. A radial
Transmission Element may be considered as “serving only load” for purposes of the foregoing general
exclusion even if it connects generation, so long as that generation is not registered pursuant to the
Statement of Compliance Registry Criteria. To obtain an exemption, on the other hand, an entity must go
through the NERC exemption process. If the owner or operator of an Element that is nominally part of the
BES can demonstrate to NERC that the particular Element meets the criteria for demonstrating that it is not
necessary for operating the interconnected electric transmission network, that Element should be granted an
exemption and thus considered non-BES. (See also FMPA comments on BES exemption process submitted
today.)Requests for exemptions should be decided by NERC, not the Regional Entities, in order to foster
continent-wide uniformity.

Response: See response to Q13.

Response: Your comments are noted. The SDT is striving to develop a “bright-line” definition that will contain certain inclusions/exclusions and that should
remove any confusion. A separate Rules of Procedure (ROP) team is undertaking to develop a separate process for Facilities that entities may choose to follow for
their unique/special circumstances that do not fit within the definition and its designation.
Pepco Holdings Inc.

Yes

1. The proposed BES definition should be expanded to contain more specific criteria for what is excluded
(and included) to minimize the need for exemptions. The exemption process should only be needed for a few
special situations that are not covered in the criteria.
2. The exemption process should rest with the regional entity.

Response: 1. Your comments are noted. The SDT is striving to develop a “bright-line” definition that will contain certain inclusions/exclusions and that should
remove any confusion.
2. A separate Rules of Procedure (ROP) team is undertaking to develop a process. Regional entities are expected to have an important role in the exception

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Organization

Yes or No

Question 9 Comment

process. However, as directed by FERC, it is expected that the ERO would have an oversight and/or approval role. The details of the process are still under
discussion and development.
Indeck Energy Services

Yes

Same Response as Question 1

Utility Services

Yes

See the answer to Question 1.

PUD No.1 of Clallam County

Yes

Central Lincoln

Yes

We agree with this except for the parenthetical. If the exemption process itself is approved by the ERO, there
should be no reason to get ERO concurrence on every exempted element. Such a process will bog down the
system so that the process will take years. Concurrence with the RE should be sufficient. The ERO should
only become involved in the event of disagreement between the registrant and the RE.

PNGC Power

Yes

Blachly-Lane Electric Co-op

Yes

Clearwater Power Co.

Yes

Douglas Electric Cooperative

Yes

Central Electric Cooperative, Inc.
(Redmond Oregon)

Yes

Raft River Rural Electric
Cooperative

Yes

Northern Lights Inc.

Yes

Salmon River Electric
Cooperative

Yes

Okanogan Country Electric
Cooperative

Yes

Response: see response to Q1.

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Organization

Yes or No

Lost River Electric

Yes

Lane Electric Cooperative

Yes

Coos-Curry Electric Cooperative

Yes

Consumer's Power Inc.

Yes

Umatilla Electric Co-op

Yes

West Oregon Electric
Cooperative

Yes

Lincoln Electric Cooperative

Yes

Fall River Electric Cooperative

Yes

Lewis County PUD

Yes

Question 9 Comment

Response: A separate Rules of Procedure (ROP) team is undertaking to develop an exception process. Regional entities are expected to have an important role
in the exception process. However, as directed by FERC, it is expected that the ERO would have an oversight and/or approval role. The details of the process are
still under discussion and development.
United Illuminating Company

Yes

NERC should specify the technical criteria to determine the exemption of a facility. NERC could either directly
or delegate to the The Regional Entity to oversee the exemption process and verify consistency and maintain
lists.

Response: A separate Rules of Procedure (ROP) team is undertaking to develop an exception process. Regional entities are expected to have an important role
in the exception process. However, as directed by FERC, it is expected that the ERO would have an oversight and/or approval role. The details of the process are
still under discussion and development.
American Transmission company

March 30, 3011

Yes

However, the applicable process should be called an “exception” process to avoid the connotation that
“exemption” process has for the “inclusion” aspect of the process. ATC believes the exemption process,
review and approval, would be best handled by the Regional Entity (RE) since they have more knowledge on
the transmission system in their region. The “who” and “what” will have to be spelled out clearly in the criteria

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Organization

Yes or No

Question 9 Comment
for the exception process. For consistency, it is appropriate for the ERO to monitor and concur with the
exceptions.

Response: A separate Rules of Procedure (ROP) team is undertaking to develop an exception (inclusion/exclusion) process. Regional entities are expected to
have an important role in the exception process. However, as directed by FERC, it is expected that the ERO would have an oversight and/or approval role. The
details of the process are still under discussion and development.
City Water Light and Power
(CWLP) - Springfield, IL

Yes

CWLP generally agrees with this point, but would like to see a firm, detailed administrative process for
resolving disputes for exemptions with technical justification as the guiding principle.

Response: A separate Rules of Procedure (ROP) team is undertaking to develop an exception process for Facilities that do not fit within the bright-line definition.
The details of the process are still under discussion and development.
American Electric Power (AEP)

Yes

As noted in our response to question 5, we believe that an exemption process is needed, though substantive
comments cannot be made until details of such a process and its related criteria are provided.

Yes

Who can apply? Who pays for the process? Is there a time frame for approval? Is the registered entity
required to meet reliability requirements for the Element or Facility while it is in the exemption process? Part
of the concern is that there are Elements and Facilities that are not necessary for the reliability for the BES
but if they were included as part of the BES definition would significantly harm the entity financially to meet
compliance with no measurable impact to reliability.

Response: See response to Q5.
Springfield Utility Board

Response: A separate Rules of Procedure (ROP) team is undertaking to develop an exception process for Facilities that do not fit within the bright-line definition.
The details of the process are still under discussion and development. The SDT will forward your comments to the ROP team for consideration as part of their
process.
City of Redding

Yes

City of Anaheim

Yes

SERC EC Planning Standards
Subcommittee

Yes

March 30, 3011

The key element is a good exemption process based on sound engineering principles.

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Organization

Yes or No

Question 9 Comment

Public Service Enterprise Group
Company

Yes

Bonneville Power Administration

Yes

PPL Energy Plus

Yes

LG&E and KU Energy LLC

Yes

ExxonMobil Research and
Engineering

Yes

Arizona Public Service Company

Yes

LCRA Transmission Services
Corporation

Yes

American Municipal Power

Yes

North Carolina EMC

Yes

If elements or facilities meet one of the BES definition classifications identified in Questions 1-7 above, the
owner of the facility or element should be able to apply for an exemption through the exemption process. In
other words, the criteria outlined in Questions 1-7 should be considered a "bright-line" criteria for inclusion in
the BES. If a facility meets one or more of these criteria, it can only be excluded from the BES by applying for
an exemption through the exemption process.

ReliabilityFirst

Yes

However, the exemption process and criteria needs to be clearly defined so that a common approach across
the ERO is used when this determination is made.

on behalf of Teck Metals Ltd.

Yes

Southern California Edison

Yes

March 30, 3011

No Comment

Yes, PPL Energy Plus support an exemption process for facilities (such as radial generation service and 100
kV looped load service) provided the Exemption process follows FERCs Order 743 paragraph 115: “NERC
should develop an exemption process that includes clear, objective, transparent, and uniformly applicable
criteria for exemption of facilities that are not necessary for operating the grid.”
There should be an exemption process. There should also be a documented process for appealing the
determination of whether or not a facility is part of the BES.

SCE agrees Elements and Facilities identified through application of the exemption process, consistent with
the criteria, where the exemption process deems that the Element or Facility should be excluded from the
BES (with concurrence from the ERO).

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Organization

Yes or No

Question 9 Comment

Southern California Edison
Company

Yes

on behalf of Catalyst Paper
Corporation

Yes

City of Grand Island

Yes

Glacier Electric Cooperative

Yes

Yes - This is assuming that the exemption process is an accurate way to truly determine whether or not a
facility is significant to the grid. I think such an analytical method will be much more effective and accurate
than a bright-line approach.

ISO New England Inc.

Yes

We generally support this approach, subject to the assessment of the detailed exemption/inclusion criteria
and process.

Snohomish County PUD

Yes

If the Element or Facility is demonstrated through engineering studies performed as part of the exemption
process to be unnecessary for the reliable operation of the interconnected bulk transmission system, the
Element or Facility should not be classified as part of the BES regardless of its operating voltage.

City of Austin dba Austin Energy

Yes

Duke Energy

Yes

The Dayton Power and Light
Company

Yes

ITC Holdings Corp

Yes

BGE

Yes

No comment.

Southern Company

Yes

Yes, provided the evaluation method is clear, understandable, and technically based.

Idaho Power

Yes

March 30, 3011

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Organization
Clark Public Utilities

Yes or No

Question 9 Comment

Yes

Response: Thank you for your response.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

10. Should the following be excluded from the Elements and Facilities classified as part of the BES?
•

Generating plant control and operation functions which include relays and systems that control and protect the unit for
boiler, turbine, environmental, and/or other plant restrictions

Summary Consideration: Most commenters who responded to this question indicated agreement with the proposal. The SDT has discussed
generator plant controls and operation functions and feels that they should not be included in the BES definition. It was determined that balance of
plant equipment, including control and operation functions, fall within the scope of existing reliability standards. However, the SDT believes the
inclusion of generator leads and the GSU for some configurations have been established by the SDT through discussions of the elements and
resources material integral to the reliable operation of the BES. The bright-line designation will be developed as part of this project and the ROP
process will be handled through the revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES
definition.
The revised BES definition includes the following “Inclusions” as elements of the BES:
Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the generator terminals through the
GSU which has a high side voltage of 100 kV or above.
Included in the BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or
above.

Organization

Yes or No

Question 10 Comment

Bonneville Power Administration

No

However, if the generator is not part of BES, then the plant control and operation functions should not be
included in the BES as well.

Glacier Electric Cooperative

No

Once again, it depends on the facility's significant impact to the grid.

Manitoba Hydro

If there is an impact to frequency or voltage response or facility ratings it should be included.

City of Austin dba Austin Energy

Yes

This response assumes the question refers to devices within the plant itself. In other words, the relays, etc.
within the plant and used to protect the generation assets should not be included in the definition of BES.
Additionally, many generation units have a design basis allowing some equipment to trip without impact to the
generation output.

City of Redding

Yes

Only the relays and protection schemes that protect BES equipment (example is a BES substation bus), not
power plant equipment. Exception could be a RMR unit.

March 30, 3011

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Organization

Yes or No

Question 10 Comment

Response: The SDT has discussed generator plant controls and operation functions and feels that they should not be included in the BES definition. It was
determined that balance of plant equipment, including control and operation functions, fall within the scope of existing reliability standards.
Duke Energy

No

ReliabilityFirst

Boiler, turbine, environmental or other control systems that are designed to automatically trip a BES facility in
the normal system configuration, when operating correctly for their intended function, should be included in
the BES definition.
Several of these examples listed could in fact force a unit or units out of service, thereby causing a negative
impact (such as lowering frequency, etc.) to the BES. However, there should be some additional thought for
exclusion of balance of plant facilities, such as the boiler, turbine, and environmental and auxiliary equipment
(i.e. scrubber, baghouse, precipitator, fuel/ash coal handling, cooling water, etc.), if they cannot trip the unit
off-line.

Response: The SDT has discussed generator plant controls and operation functions including those associated with balance of plant equipment such as boiler,
turbine, environmental and other control systems and feels that they should not be included in the BES definition. It was determined that balance of plant
equipment, including control and operation functions, fall within the scope of existing reliability standards.
LCRA Transmission Services
Corporation

No

American Municipal Power

No

Response: Thank you for your response.
NERC Staff

No

Please see additional comments at the end of this document.

Response: See response to Q13.
The Dow Chemical Company

As discussed in response to question #12 below, issues relating to the registry criteria applicable to
generation resources should not be revisited at this time.

Response: See response to Q12.
Competitive Suppliers

March 30, 3011

Plant controls and other systems on the generation side from the point of interconnection should not be
included in the BES definition because they do not significantly affect the reliability of the interconnected

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Organization

Yes or No

Question 10 Comment
electric network. EPSA recommends that the standards drafting team develop a BES exemption criteria that
considers the impact of all equipment (including lead lines and GSUs) on the generator side from the point of
interconnection on the reliability of the BES.

Response: The SDT has discussed generator plant controls and operation functions and feels that they should not be included in the BES definition. It was
determined that balance of plant equipment, including control and operation functions, fall within the scope of existing reliability standards. The bright-line
designation will be developed as part of this project and the process will be handled through the revision to the Rules of Procedure by a separate team in an effort
parallel to the development of this BES definition. Your comments will be forwarded to the Rules of Procedure Team.
Arizona Public Service Company

Yes

The above description for defining the exclusion is vague and too difficult to determine where the exclusion
applies for a Generator. AZPS recommends identifying exclusions for all systems which are not
electrically/magnetically connected to generation elements including the GSU, line leads and the generator or
its protection systems.

City of Anaheim

Yes

Unless the generator is required to maintain BES reliability, i.e. black start, etc., the GSU and gen tie should
be excluded from the BES; provided, however, to eliminate any reliability gaps, such generation-tie equipment
should be classified as "Generator" equipment subject to GO/GOP standards, and the PRC and vegetation
management standards should be made applicable to GO/GOPs and this equipment. This is consistent with
the NERC Reliability Functional Model and is more efficient than requiring TO/TOP registration for non-critical
generation-tie transmission elements that are not required for the reliable operation of the BES.

Response: The inclusion of generator leads and the GSU for some configurations have been established by the SDT through discussions of the elements and
resources material integral to the reliable operation of the BES.

Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the generator terminals through the GSU
which has a high side voltage of 100 kV or above.
Included in the BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
Indeck Energy Services

Yes

Same Response as Question 1

Yes

Individual loads equal to or below 25 MW (one customer on a line) served by Transmission Facilities greater
than 100kV and the Transmission Facilities themselves should be excluded for the same reason. Entity
registration is based on aggregate loads. But a 10 MW load may served by an LSE that has a 200 MW peak

Response: See response to Q1.
Springfield Utility Board

March 30, 3011

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Organization

Yes or No

Question 10 Comment
is part of the BES while the same 10 MW load served by a 20 MW LSE would not be part of the BES. From a
reliability perspective this is inconsistent. Either a facility is or isn't necessary for the reliability of the BES. If a
facility isn't necessary because an entity does not meet registration thresholds then the same facility should
be excluded from the BES for an entity that is registered.

Response: The SDT has decided to stay with the limits in the NERC Statement of Compliance Registry Criteria with regard to the size of generators that will be
included in the BES.
Unless the generator is required to maintain BES reliability, i.e. black start, etc., the GSU and gen tie should be
excluded from the BES; provided, however, to eliminate any reliability gaps, such generation-tie equipment
should be classified as "Generator" equipment subject to GO/GOP standards, and the PRC and vegetation
management standards should be made applicable to GO/GOPs and this equipment. This is consistent with the
NERC Reliability Functional Model and is more efficient than requiring TO/TOP registration for non-critical
generation-tie transmission elements that are not required for the reliable operation of the BES.

City of Anaheim

Yes

Northeast Power Coordinating
Council

Yes

SERC EC Planning Standards
Subcommittee

Yes

Public Service Enterprise Group
Company

Yes

The relays and systems described above should not be classified as part of the BES. The intent of the BES
definition and applicable standards should not include these items as this would further confuse the BES
boundary scope rather than clarify what should be included. The described functions and controls by
themselves do not add to BES reliability.

MRO's NERC Standards Review
Subcommittee

Yes

This will give our industry a clear defining line of what is a BES Facility and what it is comprised of.

IRC Standards Review
Committee

Yes

Florida Municipal Power Agency

Yes

Transmission Access Policy
Study Group

Yes

March 30, 3011

These systems are internal protection systems and will not impact the reliability of the BES.

Excluding such generating plant control and operation functions, which have to do with mechanical energy,
rather than electric energy, would be consistent with Section 215 of the Federal Power Act, which states that
the Bulk Power System includes “electric energy from generation facilities needed to maintain transmission
system reliability.” There are standards, such as PRC-024, FAC-008, and FAC-009, regulating total unit
performance and ratings, which necessarily covers component performance as well. Therefore, no purpose

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Organization

Yes or No

Question 10 Comment
would be served by including these types of items in a granular way in the BES definition.

FirstEnergy Corp

Yes

Electric Market Policy

Yes

SERc OC Standards Review
Group

Yes

PacifiCorp

Yes

PPL Energy Plus

Yes

LG&E and KU Energy LLC

Yes

Central Lincoln

Yes

Pepco Holdings Inc.

Yes

PUD No.1 of Clallam County

Yes

North Carolina EMC

Yes

on behalf of Teck Metals Ltd.

Yes

Southern California Edison

Yes

Southern California Edison
Company

Yes

March 30, 3011

Yes these should be excluded from the BES definition. If there is a reliability need related to these devices a
standard could be written even though they are not included within the BES definition. Our position is similar
to our prior stated view on the blackstart and cranking path.

Excluding these generator components is correct.

Only relay elements and systems for generating units that meet or exceed the 20 MVA nameplate BES
criteria should be included in this classification.

SCE believes generating plant control and operation functions which include relays and systems that control
and protect the unit for boiler, turbine, environmental, and/or other plant restrictions should not be included in
the BES definition.

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Organization

Yes or No

on behalf of Catalyst Paper
Corporation

Yes

City of Grand Island

Yes

Occidental Energy Ventures Corp

Yes

ISO New England Inc.

Yes

Entergy Services

Yes

Snohomish County PUD

Yes

PNGC Power

Yes

Blachly-Lane Electric Co-op

Yes

Clearwater Power Co.

Yes

Douglas Electric Cooperative

Yes

Central Electric Cooperative, Inc.
(Redmond Oregon)

Yes

Raft River Rural Electric
Cooperative

Yes

Northern Lights Inc.

Yes

March 30, 3011

Question 10 Comment

The BES by statutory definition can include only those Facilities and Elements that are necessary for the
reliable operation of the interconnected bulk transmission system. While the facilities identified in question 10
may be necessary for the protection of plant equipment or to meet regulatory obligations related to
environmental protection, they cannot be classified as BES facilities in the absence of a clear demonstration
that the facilities are material to the reliable operation of the bulk system because the failure of those facilities
could threaten cascading failures, separation events, or instability on the interconnected bulk transmission
system.

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Organization

Yes or No

Question 10 Comment

Salmon River Electric
Cooperative

Yes

Okanogan Country Electric
Cooperative

Yes

Lost River Electric

Yes

Lane Electric Cooperative

Yes

Coos-Curry Electric Cooperative

Yes

Consumer's Power Inc.

Yes

Umatilla Electric Co-op

Yes

West Oregon Electric
Cooperative

Yes

Lincoln Electric Cooperative

Yes

Fall River Electric Cooperative

Yes

United Illuminating Company

Yes

The Generator Protection systems for the Electrical Interconnection should not be excluded from the BES.

Orange and Rockland Utilities,
Inc.

Yes

These systems are internal protection systems and will not impact the reliability of the BES.

American Transmission company

Yes

Utility Services

Yes

The Dayton Power and Light

Yes

March 30, 3011

Utility Services believes that these systems are internal protection systems and will not impact the reliability
the BES. .

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 10 Comment

Company
ITC Holdings Corp

Yes

BGE

Yes

Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Yes

City Water Light and Power
(CWLP) - Springfield, IL

Yes

Lewis County PUD

Yes

These elements have little to do with the BES and should be excluded.

American Electric Power (AEP)

Yes

Given the vast diversity of plant auxiliary systems, together with their built-in redundancies, component
failures in these systems would have negligible impact on BES reliability. In support of this, RFC’s definition of
BES does well by seeking to maintain electric system reliability without over-reaching, by allowing the
exemption of the devices mentioned in question 10.

Southern Company

Yes

Generator protection systems and operational control systems for generating plants are not critical to the BES
operation. Generator protection systems should be included. However, we do not believe that other plant
control systems such as boiler controls and operational control systems, etc should be included for generating
plants as they are not critical to the BES operation.

Idaho Power

Yes

March 30, 3011

No comment.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Independent Electricity System
Operator

Yes

Clark Public Utilities

Yes

Xcel Energy

Yes

Question 10 Comment

Response: Thank you for your response.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

11. Do you believe that the proposed definition of BES, accompanied by a separate BES Definition Exception Process
meets the reliability-related intent of the directives in Order 743?

Summary Consideration: Most commenters who responded to this question indicated disagreement with the proposal, indicating a
preference to have more details in the definition. The SDT will develop the BES definition and associated criteria. The SDT intends to develop
criteria that will be explicit enough so that the owners/operators of the vast majority of Facilities will not have to seek a case-by-case exception on
whether their Facilities are part of the BES. This includes addressing radial Transmission serving only Load.
A separate ROP team will develop the procedures for seeking an exception that is not clearly addressed by the definition and criteria. The SDT
understands the importance of the exception process being developed in parallel with the BES definition and associated criteria and will closely
coordinate with the ROP team that is responsible for developing that process. As the SDT develops the modified BES definition and associated
criteria, it will carefully consider Canadian-specific issues and the current NERC Statement of Compliance Registry Criteria.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an
automatic interruption device and:
a)
b)
c)

Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow
for reliable system reconfiguration to maintain continuity of electrical service. Or,
Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in
Inclusions I2, I3, I4 and I5.

Excluded from the BES: E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV that distribute power to Load
rather than transfer bulk power across the interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one
location solely to improve the level of service to retail customer Load. The LDN is characterized by all of the following:
a)
b)
c)
d)
e)

Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic
fault-interrupting devices;
Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;
Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable
monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating
Limit (IROL).

March 30, 3011

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Organization
Public Service Enterprise Group
Company

Yes or No
No

Question 11 Comment
There is still room for misinterpretation. The definition of the BES should be as explicit as possible since it
affects the majority of the standards.

Response: The SDT is developing a bright-line BES definition and associated criteria that will address as many Facilities as possible.
Florida Municipal Power Agency

No

Transmission Access Policy
Study Group

No

The proposed definition abandons the current exclusion of radials serving only load with one transmission
source that Order 743 specifically left in place, and instead conflates “excluded” Elements with Elements for
which an “exemption” can be sought. The proposed definition would thus require entities to seek an
exemption, presumably on a case-by-case basis, for every > 100 kV radial serving only load with one
transmission source. FERC did not intend to direct such a result in Order 743, but rather intended to allow
the current exclusion of such radials to load to continue.Furthermore, to comply with Order 743, the new BES
definition and exemption/inclusion processes must ensure uniformity throughout the United States. Thus
there must be a uniform process; clear criteria for exemption and inclusion; and a right to appeal decisions to
a higher body within NERC and/or to FERC.

Response: The SDT has proposed the following radial exclusion from the BES as part of its revised definition. The SDT believes that this will address your
concern.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.
Electric Market Policy

No

See comments at bottom of questionnaire (Q13).

PPL Energy Plus

No

For the reasons discussed above, the proposed BES definition does not take into account FERC’s desire to
only include Facilities in the BES that have an impact on the reliability of the Interconnected Electric Network.

LG&E and KU Energy LLC

No

Response: See response to Q13.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 11 Comment

Response: The SDT assumes that you are referring to responses that you provided to earlier questions. See above responses.
Competitive Suppliers

No

The intent of the directives in Order 743 is to, “direct NERC to develop a uniform modified definition of Bulkelectric system [that] will eliminate regional discretion and ambiguity”. In Order 743 the Commission also
finds that the exemption process needs to work with the definition. Paragraph 115 from the BES final rule
states “NERC should develop an exemption process that includes clear, objective, transparent, and uniformly
applicable criteria for exemption of facilities that are not necessary for operating the grid. The ERO also
should determine any related changes to its Rules of Procedures (ROP) that may be required to implement
the exemption process, and file the proposed exemption process and rule changes with the Commission.”
This section does not direct NERC to use the ROP modification process to develop “separate” exemption
criteria. It only recommends that NERC modify its ROP for any related changes to implement the exemption
process, not for developing the exemption criteria. BES exemption criteria need to be developed through the
NERC standards development procedure by the Standard Drafting Team (SDT) that is modifying the BES
definition. The exemption criteria need to be done by the same group that forms the definition so that the
exemptions are crafted to fit with the new BES definition. The definition and the exemption criteria need to be
meshed and work together.

Response: The SDT will develop the BES definition and associated criteria. A separate Rules of Procedure (ROP) team will develop the procedures for seeking
an exception that is not clearly addressed by the definition and criteria. The SDT will closely coordinate with the ROP team.
PacifiCorp

No

The proposed definition does not meet the reliability-related intent of the directives in Order 743 in two
respects. First, the second clause of the first sentence of the proposed definition re-introduces the ambiguity
that the Commission believes a bright-line threshold will eliminate. The first sentence states that the BES is
“all Transmission and Generation Elements and Facilities operated voltages of 100 kV or higher necessary to
support bulk power system reliability.” (emphasis added). PacifiCorp understands that the intent of this
language is to indicate that only some subset of 100 kV facilities (those necessary for reliability) are included
in the definition of the BES. However, this language is ambiguous in that it does not make it clear that the
only way to exempt 100 kV and above facilities (other than certain defined radial facilities) from the definition
is to utilize the exemption process. Second, the proposed definition does not make it clear that certain
defined radial facilities may be excluded from the definition without utilizing the exemption process.
PacifiCorp proposes the following:Bulk Electric System: All Transmission and Generation Elements and
Facilities operated at voltages of 100 kV or higher except [defined radial facilities]. Transmission and
Generation Elements and Facilities operated at voltages of 100 kV or higher may be excluded if they are not
necessary to operate an interconnected electric transmission network. Transmission and Generation
Elements and Facilities operated at voltages of 100 kV or lower must be included if they are necessary to
operate an interconnected electric transmission network. The criteria for determining whether Elements and

March 30, 3011

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Organization

Yes or No

Question 11 Comment
Facilities are necessary to operate an interconnected electric transmission network are defined in the BES
definition exemption process.

Response: The SDT is developing criteria that will be explicit enough so that the owners/operators of the vast majority of Facilities will not have to seek a case-bycase decision on whether their Facilities are part of the BES. This includes addressing radial Transmission serving only Load.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.

ExxonMobil Research and
Engineering

No

The proposed definition is over reaching and can potentially expand the scope of the BES beyond the point to
which NERC was intended to have the authority to govern. The proposed definition does not directly address
the line of demarcation between customer owned facilities and elements of BES.

Response: The SDT is developing a BES definition and associated criteria that it believes will address your concerns and those of others in this regard.
NERC Staff

No

Please see additional comments at the end of this document.

Entergy Services

No

Please see our response to Q13 below.

No

Radial transmission systems operated below 100 kV should not be included as part of the BES and should
not have to go through the exception process.

Response: See response to Q13.
Arizona Public Service Company

Response: The SDT is developing a BES definition and associated criteria that it believes will address your concerns and minimize the need for owners/operators
to have to have to go through an exception process.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:

March 30, 3011

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Organization

Yes or No

Question 11 Comment

a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.

Xcel Energy

No

Manitoba Hydro

No

No. The proposed definition includes the wording ‘...necessary to support bulk power system reliability’ which
increases ambiguity and reduces the 100kV and above bright line distinction. This wording should be
removed. Manitoba Hydro suggests the following: Bulk Electric System: All Transmission and Generation
Elements and Facilities operated at voltages of 100 kV or higher except defined radial facilities. Elements and
Facilities operated at voltages of 100kV or higher, including Radial Transmission systems, may be excluded
and Elements and Facilities operated at voltages less than 100kV may be included if approved through the
BES definition exemption process.

Response: The SDT has revised the definition and the wording is no longer utilized.
Indeck Energy Services

No

Same Response as Question 1

No

SCE believes that the 100kV brightline threshold is sufficient.

Response: See response to Q1.
Southern California Edison

Response: Thank you for your comment. Please see the revised definition – it includes a detailed list if inclusions/exclusions to minimize the need to use the BES
Exception Process.
City of Grand Island

No

This question is premature given that the BES Exception Process has not been developed.

Occidental Energy Ventures Corp

No

Until the expemtion process is finalized, it is not prudent to answer in the affirmative.

Response: The SDT understands the importance of this process being developed in parallel with the BES definition and associated criteria.
Central Lincoln

March 30, 3011

No

The order was to provide a definition that excepted radial facilities and to create an exemption process for

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Yes or No

PUD No.1 of Clallam County

No

PNGC Power

No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

March 30, 3011

Question 11 Comment
other facilities not necessary for operating the interconnected network. The SAR proposes to treat the two the
same. This will cause unneeded expense, delay, and uncertainty for those radial facilities that could simply be
eliminated by inspection. This would work against reliability by misdirecting resources toward the elements
tied up in the process, and possibly away from the elements that should be included.The SAR also fails to
meet the order by failing to apply it to all entity types. We fail to see how a bright line is achieved if DPs,
PSEs, and IAs work from a definition different from all the other types of registered entities. Please edit the
SAR to include all entity types.

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Organization

Yes or No

West Oregon Electric
Cooperative

No

Lincoln Electric Cooperative

No

Fall River Electric Cooperative

No

Lewis County PUD

No

Question 11 Comment

Response: The SDT is developing criteria that will be explicit enough so that the owners/operators of the vast majority of Facilities will not have to seek a case-bycase decision on whether their Facilities are part of the BES. This includes addressing radial Transmission serving only Load.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in inclusions I2, I3, I4
and I5.

The Dow Chemical Company

March 30, 3011

No

Order No. 743 correctly recognizes that local distribution facilities are expressly excluded from the definition of
“Bulk-Power System” set forth in Section 215 of the Federal Power Act. See Order No. 743 at P 37. As such,
local distribution facilities must also be excluded from the definition of BES adopted by NERC. That is not the
case with respect to the proposed definition, which makes no mention whatsoever of local distribution
facilities. Instead, the proposed definition simply provides that certain facilities, including “Radial
Transmission systems, may be excluded . . . if approved through the BES definition exemption process.”
While this language presumably is an acknowledgement that Radial Transmission lines perform a local
distribution function and should be excluded, numerous other types of facilities also perform a local
distribution function and should also be excluded regardless of their voltage.For example, Dow and certain of
its subsidiaries, including Union Carbide Corporation, own and operate electrical facilities at a number of
industrial sites within the U.S. In all cases, a tie line or lines connect the industrial site to the electric
transmission grid. Power is delivered from the electric transmission grid to the industrial site through the tie
line(s). Lines within the industrial site then deliver power to individual manufacturing plants within the site.
Additionally, cogeneration facilities are located at a number of industrial sites owned by Dow and Union

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Question 11 Comment
Carbide Corporation, principally in Texas and Louisiana. These cogeneration facilities generate power that is
primarily distributed within the industrial site and used for manufacturing plant operations. In some instances,
excess power not required for plant operations is delivered into the electric transmission grid through the tie
line(s) connecting the industrial site to the grid.While the tie lines and internal lines at these industrial sites
can be fairly significant in terms of voltage, they do not perform anything that resembles a transmission
function. Rather than transmit power long distances from generation to load centers, the tie lines and internal
lines perform a local distribution function consisting of the distribution of power brought in from the grid or
generated internally to different manufacturing plants within each industrial site. In some cases, the facilities
also perform an interconnection function to the extent they enable excess power from cogeneration facilities
to be delivered into the grid. The voltage of the tie lines and internal lines at these industrial sites is dictated
by the load and basic configuration of each site. Higher voltage lines (>100 kV) are used to reduce line
losses while meeting applicable load requirements. That does not mean that such lines perform a
transmission function. Indeed, just as a line that delivers power into a home, or from a home to an
accompanying garage, is considered a distribution facility and not a transmission facility, the same is true of
lines that deliver power into industrial sites owned by Dow or its subsidiaries (even though such lines also
may be used to deliver excess power to the transmission grid) or within those sites. The definition of BES
adopted by NERC should explicitly provide for these types of local distribution facilities to be categorically
excluded.

City of Redding

No

The current definition goes to far; local goverments, cities, and citizens have been given the right to decide
the level of reliability of their distribution system. FERC & NERC were not given jurisdiction over local
distribution facilities. Note: many local distribution facilities are operated above 100 kV.

Response: The SDT is developing a BES definition and associated criteria that it believes will address your concerns.
•

Excluded from the BES: E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV that distribute power to Load rather than
transfer bulk power across the interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to improve
the level of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting
devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the Quebec Interconnection, and

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Question 11 Comment

is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
National Rural Electric
Cooperative Association
(NRECA)

No

It is too early to determine the effectiveness of the proposed BES definition and BES criteria included in the
draft SAR. However, the concept of a BES definition and BES criteria, along with BES exemption criteria,
appears, at least from a preliminary standpoint, to be a satisfactory direction to begin the process. The
concepts presented in the draft SAR should not preclude any other potential direction for the SDT to explore
at this point in the process.The proposed BES definition in the SAR should be considered only as an
alternative for the SDT to consider in its work, not a final definition or a definition that precludes other
proposed definitions.

Response: The SDT considers the proposed BES definition in the SAR as a starting point for SDT consideration.
Duke Energy

No

The high level direction does, but the details need to be defined before this question can be answered
affirmatively.

Response: The SDT is developing a BES definition and associated criteria that it believes will address your concerns.
American Electric Power (AEP)

No

It’s not clear how the criteria in the concept paper will be related back to the overall definition of BES. We
recommend that the finalized criteria be included verbatim in the definition, or that the definition refer to an
official companion document. The definition cannot automatically include all equipment (both primary-voltage
and the associated auxiliary equipment) by default.

Response: The SDT considers the concept paper one of the starting points for SDT consideration. The finalized criteria will be included in the definition.
Springfield Utility Board

March 30, 3011

No

SUB appreciates the work to provide a clearer definition of the BES, but the proposed language is
ambiguous.The existing definition is:"As defined by the Regional Reliability Organization, the electrical
generation resources, transmission lines, interconnections with neighboring systems, and associated
equipment, generally operated at voltages of 100 kV or higher. Radial transmission facilities serving only load
with one transmission source are generally not included in this definition."The proposed definition is: "Bulk
Electric System: All Transmission and Generation Elements and Facilities operated at voltages of 100 kV or
higher necessary to support bulk power system reliability. Elements and Facilities operated at voltages of
100kV or higher, including Radial Transmission systems, may be excluded and Elements and Facilities
operated at voltages less than 100kV may be included if approved through the BES definition exemption
process."Looking at the first sentence, 100kV or higher facilities are part of the BES ONLY if they are
necessary to support bulk power system reliability. As written, if an registered entity determines that a 100kV
or higher facility is not necessary for BPS system reliability then the facility may be excluded. If the intent is to

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Question 11 Comment
assume that all 100kV and above facilities are necessary for BPS reliability, SUB strongly disagrees.To avoid
confusion, SUB suggests that the first sentence state: "Bulk Electric System: All Transmission and Generation
Elements and Facilities operated at voltages of 100 kV or higher." The language "necessary to support bulk
power system reliability." should be deleted.
Turning to the second sentence:"Elements and Facilities operated at voltages of 100kV or higher, including
Radial Transmission systems, may be excluded and Elements and Facilities operated at voltages less than
100kV may be included if approved through the BES definition exemption process."The approved April 2010
NERC Glossary of Terms includes definitions for "Elements", "Facilities", and "Transmission", but does not
have a definition for "Radial" or "Radial Transmission", "Radial Transmission systems", Transmission
systems", or "systems". SUB does not know what this language is intended to mean.If the language "Radial
Transmission systems" means an Transmission Element or Facility normally operated open then SUB agrees
with this language. If all Elements or Facilities are outright excluded from being excluded from the BES
because they could "potentially" be operated closed, this language has little value as most facilities have the
"potential" to operated closed.SUB has concerns that EROs are making interpretation of language, such as
"radial", without going through a required interpretation public process and are just "announcing" what
language means. Is is not uncommon for an ERO to announce a definition for an undefined term and then tell
registered entities that they need to request a formal interpretation from NERC in order to modify an informal
ERO interpretation. SUB would like to eliminate this confusion - starting with the BES definition which is
confusing and may perpetuate an informal interpretation process. SUB proposes that the second sentence
read:"Elements and Facilities operated at voltages of 100kV or higher, including Radial Transmission
systems, may be excluded and Elements and Facilities operated at voltages less than 100kV may be included
if approved through the BES definition exemption process. Radial Transmission systems include Elements or
Facilities normally operated open."
Lastly, why would an entity want to include an Element or Facility that would otherwise be excluded? If an
ERO determines that an Element or Facility below 100kV is necessary for reliability would the ERO be ability
to initiate an exemption process to include the Element or Facility without the owners knowledge or consent?
What if the owner is not a Registered Entity? This inclusion language for elements below 100kV is unclear in
terms of the application, implementation, or intent.

Response: The proposed BES definition included in the SAR is only a starting point for the SDT. The SDT intends to address the issues you have identified in its
efforts to develop a BES definition and associated criteria. The initial thinking is that for Facilities captured as BES by the definition/criteria, if an owner/operator
believed those Facilities should not be considered BES, that owner/operator would need to technically demonstrate why such Facilities should be excluded. In
addition, for Facilities that are not captured as BES by the definition/criteria, if the ERO or a Regional Entity believed those Facilities should be considered as BES,
then the ERO or the Regional Entity would need to technically demonstrate why such Facilities should be included. It is the intent of the SDT that the BES
definition and associated criteria it develops will address the vast majority of Facilities and minimize the need for technical demonstration by owners/operators or

March 30, 3011

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Question 11 Comment

the ERO and regional Entities.
Electricity Consumers Resource
Council (ELCON)

No

The Electricity Consumers Resource Council (ELCON) appreciates the opportunity to submit the following
comments on the draft concept document prepared by the Regional Bulk Electric System Definition
Coordination Group (RBESCG), a team of representatives of the Regional Entities (REs).ELCON is the
national group representing the interests of large industrial consumers of electricity. Many ELCON member
facilities are Registered Entities. One or more ELCON members are registered as: BA, IA, GO, GOP, TO,
TOP, TSP, PA, RP, LSE, and PSE. However, the most common registered functions of large industrial end
users are GO, GOP and PSE by virtue of the need to supply a complex industrial process with low-cost
thermal energy and/or low-cost electric energy.The stated purpose of the concept document is to provide a
“common approach” for:
o Defining the BES and therefore improve the clarity, reduce ambiguity and establish a universal method (i.e.,
bright line) for distinguishing between BES and non-BES Elements and Facilities.
o Identifying BES Elements and Facilities so as to establish a “repeatable” method for applying NERC
Reliability Standard requirements and facilitate consistent application of compliance efforts across regional
boundaries.CommentsELCON members have always supported fair and effective reliability efforts at NERC.
However, the expansion of the standards compliance responsibility implied by the NERC Concept Document
goes too far. As written, this proposal could have the effect of devaluing a large number of industrial owned
electrical power assets by forcing industrials to meet new and unnecessary compliance obligations. Many will
be forced to choose to either accept a significant new cost or fire sale their assets to local providers
increasing the purchaser’s market power in the process. ELCON feels the addition of new compliance
obligations should not be done in such a wholesale manner but instead done on an exception and as needed
basis that factors in both a realistic appraisal of the underlying risk and the economic burden imposed on the
registered entity relative to the expected benefits.
Specific recommendations and concerns are:
1. An Overarching “Principle” for the Identification of BES Elements and Facilities Must be the Guidance
Provided by FERC That Significant Expansion of the Compliance Registry is Not Contemplated.In FERC’s
March 18, 2010 Notice of Proposed Rulemaking (NOPR) on the Revision to Electric Reliability Organization
Definition of Bulk Electric System, the Commission stated regarding the revision to the BES definition:"This
proposal would eliminate the discretion provided in the current definition for a Regional Entity to define “bulk
electric system” within a region. Importantly, however, we emphasize that we are not proposing to eliminate
all regional variations and we do not anticipate that the proposed change would affect most entities." ¶
16."... the Commission does not believe that the proposal would have an immediate effect on entities in any
Regional Entity other than NPCC." ¶ 27.Similarly, in Order No. 743, the Commission stated:"We expect that
our decision to direct NERC to develop a uniform modified definition of 'bulk-electric system' will eliminate

March 30, 3011

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Question 11 Comment
regional discretion and ambiguity. The change will not significantly increase the scope of the present
definition, which applies to transmission, generation and interconnection facilities. The proposed exemption
process will provide sufficient means for entities that do not believe particular facilities are necessary for
operating the interconnected transmission system to apply for an exemption." ¶ 144.One area where the
proposed BES definition and exception process will significantly expand the Compliance Registry is the
criteria applicable to behind-the-meter generation (primarily cogeneration facilities). We urge that the BES
definition should not change the currently applicable 20 MVA / 75 MVA generation size threshold applicable to
generation facilities or the manner in which that threshold is currently applied, with behind‐the‐meter
cogeneration facilities evaluated based on the net capacity actually provided to the grid.
2. A Second Overarching “Principle” for the Identification of BES Elements and Facillities Is the Need to
Clarify Which Facilities Perform a True Transmission Function and Excluding Facilities That Perform a Local
Distribution Function, As Required by Law.Congress stated in Federal Power Act section 215:SEC. 215.
ELECTRIC RELIABILITY.’’(a) DEFINITIONS.-For purposes of this section:’’(1) The term ‘bulk-power system’
means-‘‘(A) facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof); and’’(B) electric energy from generation facilities needed to
maintain transmission system reliability.The term does not include facilities used in the local distribution of
electric energy.There has been little attempt by NERC to clarify what in fact are “facilities used in the local
distribution of electric energy” even though any plain English application of the term makes such a
determination self-evident. The proposed BES definition should expressly exclude facilities used in the local
distribution of electric energy, and the identification of such facilities is independent of the identification of BES
transmission. Facilities used for local distribution are NOT the residual of any determination of what are BES
transmission facilities.
3. A Third Overarching “Principle” for the Identification of BES Elements and Facilities Must be Recognition of
the Risk Imposed by the Element or Facility, and the Economic Burden of the Owner/Operator of the Element
of Facility.The efforts of the BES Standards Drafting Team follow the release of two important policy
documents. First, on January 18, 2011, the White House issued an Executive Order (“Improving Regulation
and Regulatory Review”) by President Obama regarding improvements to federal regulations and the review
of existing regulations to ensure, among other things, that a regulation be proposed or adopted “only upon
reasoned determination that its benefits justify its costs,” and that regulations be tailored “to impose the least
burden on society.” Second, the NERC Planning Committee issued on January 10, 2011, “Risk-Based
Reliability Compliance - White Paper Concept Discussion,” which attempts to advance “processes and
procedures to prioritize [NERC’s] efforts and ‘tiering’ elements of its programs to maximize their value and
optimize the benefit/cost of effort from stakeholders.” This white paper complements the President’s
Executive Order.ELCON believes that BES exclusion criteria and process should recognize and exclude
elements and facilities in which the risk to bulk electric system reliability is at most theoretical or speculative,
and where the compliance burden clearly outweighs the benefits. Such a determination should recognize the

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Question 11 Comment
historical record of the element or facility in terms of the owner or operator’s coordination with the BA or
control area, and transmission operators. This principle should be applied to the development of
exclusion/inclusion criteria for private lines that connect loads and behind-the-meter generation to true BES
Elements and Facilities.
4. An Additional Principle for the Identification of BES Elements and Facilities Should Be the Explicit
Recognition on How the Element or Facility is Actually Operated or Used, Not Its Physical or Nominal Rating
That May be Irrelevant to Reliability Considerations.In Order No. 743, FERC clarified that it did not intend to
require NERC to utilize the term “rated at” rather than the term “operated at” for the voltage threshold in the
revised BES definition. A principle for the identification of BES Elements and Facilities should be such
recognition and not exclusively on the rated value of an Element or Facility. This principle should be used to
retain the exclusion in the Statement of Compliance Registry Criteria (Revision 5.0) for “net capacity provided
to the bulk power system” in the context of the 20 MVA generating unit and 75 MVA generating plant
thresholds. The “net capacity” applies to capacity “put” of a behind-the-meter generator whose predominant
function is to serve load at the same site.
5. An Additional Principle for the Identification of BES Elements and Facilities Should be the Exclusion of
PSEs That Do Not Own or Operate Physical Assets and Whose Power Transactions Are Exclusively
Financial in Nature.Many PSEs that operate in FERC jurisdictional organized wholesale markets (i.e., ISOs
and RTOs) do not own, operate or lease physical assets and are currently bombarded with data requests that
assume that they own or control such assets. An example of a superfluous data request is to prove that
adequate reactive power has been procured to support the load. This is a question that should not have been
asked and displays a profound ignorance of the operation of ISO/RTO markets. One potential solution to this
problem is to create two subsets of PSEs: one that owns and operates physical assets that are used to serve
their loads, and a second that does not.Some Regional Entities have also begun to ask questions that require
PSEs to reveal the details of specific commercial transactions. This raises a broader question on what NERC
and regional compliance staffs and auditors “need to know” and whether such questions are an abuse of their
enforcement authority.
6. Any Attempt to Make Demand Side Management (DSM) Measures an Element or Facility of BES Will Be
Shortsighted and Counterproductive.Proposals that unilaterally and arbitrarily remove exclusions for
generation and transmission, including the application of new compliance obligations to DSM programs, go
far beyond what FERC intended in its guidance for revisions. Any new requirement concerning voluntary
DSM adds cost to a process that so far has only acted to support reliability with performance equal to and
sometimes superior to traditional providers. How is it that a potential resource that can contribute to
maintaining reliability is now so quickly identified as a risk? We warn against the overzealous pursuit of
control over every asset and resource on the electric system. This mindset will only breed cynicism and end
the willingness of potentially dispatchable loads to cooperate with the real operators and owners of the BES.A
recently issued FERC study highlights the potential value to reliability of DSM (in the form of dispatchable

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Question 11 Comment
demand response) (See Joseph H. Eto et al., Use of Frequency Response Metrics to Assess the Planning
and Operating Requirements for Reliable Integration of Variable Renewable Generation, LBNL-4142E,
December 2010). To reliably integrate greater amounts of wind energy resources to the bulk electric system,
the study recommended the:"Expanded use of demand response that is technically capable of providing
frequency control (potentially including smart grid applications), starting with broader industry appreciation of
the role of demand response in augmenting primary and secondary frequency control reserves."
7. Revising the Definition of BES Does Not Justify Shifting the Plenary Burden for BPS Reliability from Utilities
to Utility Customers. A BES Principle Should Recognize That the Obligation to Serve Applies in One
Direction.The only reason the bulk power system exists is to deliver electric power to residential households,
commercial businesses, government facilities and industrial facilities of all sizes. The value of a reliable BPS
is dependent on the needs of end use customers. Nothing in the legislative history of section 215 of the
Federal Power Act suggests that Congress wittingly intended to change that relationship. The burden of
complying with NERC Reliability Standards is a cost of doing business for utility providers of generation,
transmission and distribution services. Generation and interconnection facilities of industrial customers are
almost never intended for or used to “operate the interconnected transmission network.” Those facilities are
integral to a manufacturing process, including purchasing power from the grid. They were built in expectation
that the BPS was prudently planned and operated by utilities. The rare exceptions are administered under
applicable tariffs or contracts, and are already Registered Entities. Part of NERC’s effort should include
defining the line between a BES asset that is used to deliver power and an End User asset that's sole
purpose is to serve the End User's load. The NERC Functional Model includes a vague definition of End-use
Customer. The problem is determining the scope of an end-use device. If an industrial company owns a 138
kV to 13.8 kV transformer that feeds its plant, is that an end-use device or a transmission asset that is used to
transmit power to the low voltage distribution network within the manufacturing facility? Any work to revise
the definition of the BES should also include a clarification of its boundaries. We believe that NERC should
not expand the scope of the BES to include assets within end-use customer's private use networks. (See our
recommendation #2 above)
8. An Additional BES Principle Should be that BES Elements and Facilities be Limited to Only Functions
Currently Specified in the NERC Functional Model (Version 5).NERC’s development of the revised BES
definition and exclusion/inclusion criteria and processes should be limited to functions specified in the NERC
Functional Model (Version 5).
9. NERC is Encouraged to Propose a “Different Solution” That is as Effective as, or Superior to, the
Commission’s Proposed Approach. The Proposed Principles for the Exclusion of Elements and Facilities
from the BES Should Include a Process for Categorical Exclusion Based on Common Physical
Characteristics.The Commission stated in Order No. 743 regarding its proposed revision of the BES definition
(and presumably the exclusion/inclusion criteria and processes):"... NERC may propose a different solution
that is as effective as, or superior to, the Commission’s proposed approach in addressing the Commission’s

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Question 11 Comment
technical and other concerns so as to ensure that all necessary facilities are included within the scope of the
definition." ¶ 16.In addition, specific to the exclusion of Elements and Facilities from the BES, the Final Rule
did not adopt the exclusion process proposed in the NOPR (i.e., facility-by-facility review). In the Final Order,
FERC directed NERC to develop an exclusion process “with practical application that is less burdensome
than the NOPR proposal.” FERC has also allowed NERC to consider concerns (mainly industrials’) regarding
“exclusion categories” in developing the exclusion process and criteria. ¶ 120.ELCON interprets the
Commission’s statements to mean that the agency is open to developing a more efficient compliance
process, including processes that minimize unnecessary regulatory burdens on potential Registered Entities
and the administrative costs of NERC and RE compliance operations. In the spirit of “streamlining” NERC
and the REs’ review of smaller entities, ELCON recommends the addition of a principle on the exclusion of
Elements and Facilities from the BES that encourages a process for categorical exclusion of entities based on
common physical characteristics.

Response: The SDT considers the proposed BES definition in the SAR as a starting point for SDT consideration. As it develops a modified BES definition and
associated criteria, it is carefully reviewing and considering the NERC Statement of Compliance Registry Criteria. The SDT has considered your comments in
developing a modified BES definition and associated criteria. The SDT appreciates these observations and believes that our new definition with the exclusion and
inclusion designations will provide a bright-line definition, clarity, and consistency across the regions while addressing most, if not all, of the provided suggestions.
This definition will eliminate regional discretion and any questions on this bright-line definition will be handled through a revision to the Rules of Procedure by a
separate team in an effort parallel to the development of this BES definition. NERC will follow the due process established for changes to the Glossary of terms.
This new definition addresses radial Loads, generation, and local distribution networks.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

March 30, 3011

Yes

Paragraph 115 from the BES final rule states “NERC should develop an exemption process that includes
clear, objective, transparent, and uniformly applicable criteria for exemption of facilities that are not necessary
for operating the grid. The ERO also should determine any related changes to its Rules of Procedures (ROP)
that may be required to implement the exemption process, and file the proposed exemption process and rule
changes with the Commission.” This section does not direct NERC to use the ROP modification process to
develop “separate” exemption criteria. It only recommends that NERC modify its ROP for any related changes
to implement the exemption process, not the exemption criteria itself. The compliance implications and
technical nature of such criteria make it imperative that industry input be considered in a transparent
stakeholder process. It is appropriate for NERC to develop aspects such as the administrative management,
the role and interaction of the regions, an appeal process, etc. However, due to the technical aspects of BES
operation, the drafting team members are best suited to devise criteria for non-BES facilities to warrant
inclusion in the BES.As currently proposed, the definition language and the exception criteria are not being
developed in the properly coordinated fashion. This should change. Further, Constellation is not convinced
that creation of a definition and an exception process is the best course to respond to the FERC directives. In
question 12, an alternative approach is proposed.

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City Water Light and Power
(CWLP) - Springfield, IL

Yes

CWLP feels, again, that the lack of a firm, detailed administrative process for exemptions hampers the
proposed BES definition in meeting the intent of Order 743

American Transmission company

Yes

However, ATC does not want to appear to endorse any separate BES Definition Exception and Inclusion
Processes until one has been clearly proposed and meets the reliability-related intent of the Order 743
directives. Furthermore, ATC believes the separate Exception and Inclusion Processes should be subject to
the same Standards Development review and approval process as the associated BES definition.

MRO's NERC Standards Review
Subcommittee

Yes

However, NSRS does not want to appear to endorse any separate BES Definition Exception Process until
one has been clearly proposed and meets the reliability-related intent of the Order 743 directives.
Furthermore, NSRS believes the separate Exception Process should be subject to the Standards
(“Definition”) Development Process as the associated BES definition.

Response: The SDT is developing the BES definition and associated criteria. A separate Rules of Procedure (ROP) team will develop the procedures for seeking
an exception that is not clearly addressed by the definition and criteria. The SDT will closely coordinate with the ROP team.
APPA

Yes

I agree that the proposed definition meets the intent of Order 743. However, the separate development of
exception criteria ouside of the standards development process does raise concerns. See response to
Question 12.

Response: See response to Q12.
Pepco Holdings Inc.

See comments above and below.

Response: See responses above and below.
Hydro-Québec

For the Canadian entities, it is important to consider that the definition of the Bulk Electric System must also
be approved by the Canadian regulators.

Response: The SDT is aware of the issues related to Canadian utilities and regulators and will consider those as it develops a modified BES definition and
associated criteria.
Utility Services

March 30, 3011

Yes

However, Utility Services would like to suggest alternative definitions for Bulk Electric System and BES
Exemption Process. We have presented our proposed definitions in the answer to Question 1. While the
proposed definition may meet the Order, Utility Services believes that the definition can be made cleaner and

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Yes or No

Question 11 Comment
easier to read

Response: See response to Q1.
United Illuminating Company

Yes

Order 743 focused on the definition of BES and the exemption process. Although not part of the SAR or
ORDER 743, UI suggests NERC provide an explanation in the implementation plan of the impact on the
registry criteria. Will the Registry Criteria serve as another filter for identifying which entities willbe part of
Compliance Monitoring

Response: As the SDT develops a modified BES definition and associated criteria, it will be carefully reviewing and considering the NERC Statement of
Compliance Registry Criteria.
Northeast Power Coordinating
Council

Yes

Orange and Rockland Utilities,
Inc.

Yes

A qualified “Yes”. The BES exemption process has not yet been written. So, it is somewhat difficult to know
in advance that this approach meets the reliability-related intent of the directives in Order 743. While in
general agreement with this conclusion, there is concern that the BES definition and BES exception process
do not yet adequately address a “point-of-demarcation” between the BES Facilities and Elements and nonBES facilities and elements (lower case). Propose to add two new terms for the NERC Glossary of Terms in
our reply to Question 13, in order to identify a point-of-demarcation and more fully respond to this question.

Response: The SDT will consider your concerns in its deliberations as it moves forward in revising the definition. .
City of Anaheim

Yes

IRC Standards Review
Committee

Yes

Bonneville Power Administration

Yes

FirstEnergy Corp

Yes

SERc OC Standards Review
Group

Yes

LCRA Transmission Services
Corporation

Yes

March 30, 3011

The definition is critically dependent on the detailed exemption/inclusion criteria and process, which has not
been developed.

However, BES definition changes are needed to establish a bright-line for the BES.

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Yes or No

American Municipal Power

Yes

North Carolina EMC

Yes

ReliabilityFirst

Yes

on behalf of Teck Metals Ltd.

Yes

Southern California Edison
Company

Yes

on behalf of Catalyst Paper
Corporation

Yes

City of Anaheim

Yes

Glacier Electric Cooperative

Yes

ISO New England Inc.

Yes

Snohomish County PUD

Yes

City of Austin dba Austin Energy

Yes

The Dayton Power and Light

Yes

March 30, 3011

Question 11 Comment

A single and uniform definition that includes exemption criteria and an exemption process must be the result
of this effort. Then this material must be consistently used by all of the Regional Entities across the ERO in
order to achieve the directives set forth in Order 743.

I have not seen the BES Definition Exception Process, but I trust it will be an accurate method.

While Snohomish believes FERC substantially overstepped its statutory authority in Order No. 743 for the
reasons set forth in its comments and petition for rehearing filed with FERC in that docket, we nonetheless
support FERC's underlying goal to assure reliable operation of the interconnected bulk transmission system.
Within the constraints imposed by FERC, we believe the approach of defining the BES and then establishing
an exemption process to exclude Facilities and Elements that are not necessary for the reliable operation of
the interconnected bulk transmission system should meet FERC's reliability goals while mitigating the
excessive compliance costs that will arise from blunt application of a 100-kV brightline threshold. Nothing
stated in these comments, however, should be interpreted as withdrawing or waiving any objection
Snohomish has made to Order No. 743.

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Yes or No

Question 11 Comment

Company
ITC Holdings Corp

Yes

As long as the PRC023 Critical criteria is used for below 100 kV is used for inclusion.

BGE

Yes

No comment.

Southern Company

Yes

The framework appears to be in place to respond to the directive; however, the details of the “exemption
process” remain to be fully developed.

Idaho Power

Yes

Independent Electricity System
Operator

Yes

Clark Public Utilities

Yes

The definition is critically dependent on the detailed exemption/inclusion criteria and process, which has not
been developed. We advocate that the revised BES definition and the exemption/inclusion process and
criteria be developed at the same time and preferably by the same drafting team to ensure consistency in
approach, since these issues are very closely interrelated.

Response: Thank you for your response. Please see the revised definition –it includes a detailed list if inclusions/exclusions to minimize the need to use the BES
Exception Process.

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12. If you have a proposal for an equally efficient and effective method of achieving the reliability- related intent of the directives
in Order 743, please provide your proposal here.
Summary Consideration: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion
designations (included within the body of the definition), will provide a bright-line definition, clarity, and consistency across the regions while
addressing most, if not all, of the provided suggestions. This definition will eliminate regional discretion and any questions on this bright-line
definition will be handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES
definition. NERC will follow the due process established for changes to the Glossary of terms. This new definition addresses radial Loads,
generation, and local distribution networks. Furthermore, the SDT has utilized many resources to provide this clarity including the Compliance
Registry Criteria and the WECC BESDTF recommendations.

Organization

Question 12 Comment

Public Service Enterprise Group
Company

The BES definition impacts many standards and has been the source of misunderstanding with subsequent requests for
interpretations. In this one case, a stand alone interpretive descriptive document with clear lines of demarcation using
example one lines and associated notes in lieu of a three sentence description that attempts to describe all elements of the
BES could be considered.

Manitoba Hydro

Manitoba Hydro supports a true bright-line threshold that includes all facilities operated at or above 100kV except defined
radial facilities. There should be no regional differences in the definition or exemption process and the regional discretion
should be removed from the BES definition.

ReliabilityFirst

The ERO and the Regional Entities should develop and propose the common BES definition and exemption process, submit
it to FERC, and allow for the FERC process, whereby the industry provides its comments, etc., to be used to finalize this
definition, exemption process and criteria.

United Illuminating Company

The BES definition should be very clear and simple.

ITC Holdings Corp

Exclusion criteria should be determined at the NERC level and implemented continent wide by the Regions, rather than
allowing each Region to come up with their own policy and criteria on exclusions.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
MRO's NERC Standards Review

March 30, 3011

Proposed Bulk Electric System definition: Facilities operated at voltages of 100 kV or higher necessary to support the

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Subcommittee

Question 12 Comment
interconnected transmission network reliability (Note see the NERC approved exemption process for Facilities that are and
are not considered part of the BES).
Rational:1. NERC defines Facilities as “a set of electrical equipment that operates as a single BES Element. Since Element
is part of the Facilities NERC definition it is not needed to be repeated.
2. Section 30 of FERC Order 743 “all facilities operated at or above 100kV” should be included in the bright-line criteria.
3. This new language eliminates the ambiguity as directed in FERC Order 743 whereby the Region cannot establish other
bright-line criteria for what the BES is.
4. This reinforces foot note 41 by stating exactly what “reliability” of the BES needs to be reinforced. The “interconnected
transmission reliability should also be used in any “exemption criteria” that the SDT formulates in the future.
5. The removal of bulk power system reliability is still a somewhat ambiguous term and FERC has stated that the BPS
definition is not within the scope of this FERC Order.
6. Note that the NERC defined term of Facility contains the word BES. So, as written, a Facility is energized at 100kV or
above. The capitalized word of Facility cannot be used in the inclusion process since those facilities would be below the
100kV level.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
Section 30 of FERC Order 743 directs the ERO to include exclusions as deemed appropriate, such as radials.
The SDT agrees that the term BPS is not in scope and also stipulates that this work is focused on defining the BES.
The SDT recognized the problem with Facility and has corrected that in the revised work.
City of Anaheim

Transmission elements serving radial load, radial distribution systems, or non-GO/GOP generation connected to such radial
lines and excluded from BES; provided, however, to eliminate any reliability gaps, such radial transmission elements should
be classified as "Distribution" equipment subject to DP standards, and the PRC and vegetation management standards
should be made applicable to Distribution Providers and this equipment. This is consistent with the NERC Reliability
Functional Model and is more efficient than requiring TO/TOP registration for radial transmission facilities that function as
Distribution and are not required for the reliable operation of the BES.
Transformers with secondary windings of 100kV or less should not be part of the BES if they feed radial load or radial
distribution systems; provided, however, to eliminate any reliability gaps, such transformers should be classified as
"Distribution" equipment subject to DP standards, and the PRC and vegetation management standards should be made
applicable to Distribution Providers and including this equipment. This is consistent with the NERC Reliability Functional

March 30, 3011

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Question 12 Comment
Model and is more efficient than requiring TO/TOP registration for radial transmission facilities that function as Distribution
and are not required for the reliable operation of the BES.
Unless the generator is required to maintain BES reliability, i.e. black start, etc., the GSU and gen tie should be excluded
from the BES; provided, however, to eliminate any reliability gaps, such generation-tie equipment should be classified as
"Generator" equipment subject to GO/GOP standards, and the PRC and vegetation management standards should be made
applicable to GO/GOPs and this equipment. This is consistent with the NERC Reliability Functional Model and is more
efficient than requiring TO/TOP registration for non-critical generation-tie transmission elements that are not required for the
reliable operation of the BES.

Florida Municipal Power Agency
Transmission Access Policy
Study Group

FMPA proposes that the BES be defined as:In general, the Bulk Electric System includes all Transmission Elements
operated at voltages of 100 kV or higher, and all generation resources registered pursuant to the Statement of Compliance
Registry Criteria. Radial Transmission Elements serving only load with one Transmission source are generally not included
in this definition. A radial Transmission Element may be considered as “serving only load” for purposes of the foregoing
general exclusion even if it connects generation, so long as that generation is not registered pursuant to the Statement of
Compliance Registry Criteria. An Element that nominally meets the general BES criteria, but which an entity demonstrates,
on a case-by-case basis, is not necessary for operating the interconnected electric transmission network, shall be exempted
from the BES pursuant to the NERC exemption process. An Element that does not nominally meet the general BES criteria,
but which NERC demonstrates, on a case-by-case basis, is necessary for operating the interconnected electric transmission
network, shall be included in the BES pursuant to the NERC inclusion process.
There should be an exemption process with clear criteria pursuant to which an entity can attempt to demonstrate that
although a particular Element is nominally part of the BES, it is not necessary for operating the interconnected electric
transmission network. Elements for which an exemption is granted would be considered non-BES. FMPA’s proposed
criteria and exemption process are discussed in FMPA’ comments on BES exemption process submitted today.
There should be an inclusion process with clear criteria pursuant to which NERC may show, on a case-by-case basis, that
although a particular non-BES Element is nominally not part of the BES, it is necessary for operating the interconnected
electric transmission network and should therefore be considered part of the BES. FMPA’ proposed criteria and inclusion
process are discussed in FMPA’ comments on BES exemption process submitted today.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
This new definition addresses radial Loads.
PacifiCorp

March 30, 3011

See respons #11.

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Question 12 Comment

Response: See response to Q11.
PPL Energy Plus
LG&E and KU Energy LLC

The determination of whether or not a facility is part of the BES should consider FERC’s Order 743 paragraph 73 which
clearly states the network nature of the BES. FERC states that the ability to overload parallel facilities (Order 743 paragraph
73) is a key feature of an element in the BES.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition. Elements such as
Transmission lines are included and excluded in the BES based on this bright-line definition. Furthermore, entities will need to continue to meet all the
performance of Facilities per the applicable NERC standards.
Competitive Suppliers

Initial EPSA suggestions for meeting the directives for Order 743 are included in the answer to question 11. Additionally,
EPSA recommends that the drafting team can benefit from utilizing the Compliance Registry Criteria in the BES definition.
By using the classifications found in the Compliance Registry Criteria - Section III (Rules of Procedure Appendix 5B), of
which much is alluded to in the questions included on this comment form, can provide a useful basis to create a
comprehensive, revised BES definition. Further, competitive suppliers recommend that the BES drafting team incorporate the
criteria directly into the revised BES definition, replacing the term "bulk power system" in each criteria with "100 kV."
Structuring the revised BES definition to clarifying that aligns with the Compliance Registration criteria will ensure against
complex exemption process as well as eliminate the need for Section III of the Registry Criteria.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition. Furthermore, the SDT has
utilized many resources during the development of this definition including the Compliance Registry Criteria.
NERC Staff

Please see additional comments at the end of this document. .

Entergy Services

Please see our response to Q13 below.

Response: See response to Q13.
NextEra Energy Inc.

March 30, 3011

Based on the information posted by the North American Electric Reliability Corporation (NERC) on its plans to address
Order No. 743 of the Federal Energy Regulatory Commission (FERC), NextEra Energy, Inc. (NextEra) believes that NERC
(and associated drafting teams) should slightly modify its direction to more closely align with FERC’s proposed framework.
In Order No. 743, at paragraph 30, FERC stated that:The Commission believes the best way to address these concerns is to

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Question 12 Comment
eliminate the regional discretion in the ERO’s current definition, maintain the bright-line threshold that includes all facilities
operated at or above 100 kV except defined radial facilities, and establish an exemption process and criteria for excluding
facilities the ERO determines are not necessary for operating the interconnected transmission network. It is important to
note that Commission is not proposing to change the threshold value already contained in the definition, but rather seeks to
eliminate the ambiguity created by the current characterization of that threshold as a general guideline.FERC also provided
NERC with the opportunity to propose an alternative approach. NextEra believes, however, that FERC’s proposed
framework is appropriately designed to enhance the definition of the Bulk Electric System (BES) in the NERC glossary, and
to separately develop a process to apply for and receive, as appropriate, an exemption from the BES definition. Although it
appears that NERC and the drafting teams may also be inclined to proceed as suggested by FERC, there are indications in
the questionnaire and BES concept paper that there may be some thought to deviating from FERC’s proposal. A review of
the information posted by NERC seems to indicate NERC’s intention to have a drafting team develop a revised BES
definition via the standards development process (i.e., Appendix 3A of the NERC Rules of Procedure).
It also seems that NERC is interested in assigning a “working group” to separately develop an exemption process that would
be implemented as a new process in the NERC Rules of Procedure. NextEra agrees with this approach. NextEra’s
concerns stem from some of the words in the proposed BES definition, the BES concept paper and the questions asked,
which seem to suggest an unnecessarily overlapping definition and exemption process, and a movement toward an
exemption process based on categories rather than criteria.
Thus, to address these concerns NextEra proposes the following enhancements to more clearly separate the BES definition
and exemption process, and align each more closely with Order No. 743. As for the BES definition, NextEra encourages the
drafting team to solely focus its efforts on the definition. The currently posed revised BES definition reads as follows:Bulk
Electric System: All Transmission and Generation Elements and Facilities operated at voltages of 100 kV or higher
necessary to support bulk power system reliability. Elements and Facilities operated at voltages of 100kV or higher, including
Radial Transmission systems, may be excluded and Elements and Facilities operated at voltages less than 100kV may be
included if approved through the BES definition exemption process.NextEra maintains that this is not the correct starting
point, nor consistent with Order No. 743 or the other material posted by NERC, that suggests a more definitive separation of
the BES definition from the exemption process. Thus, NextEra proposes that the definition be revised to read as follows:Bulk
Electric System: All Transmission and Generation Elements and Facilities operated at voltages of 100 kV or higher, unless a
Transmission or Generation Element or Facility has been exempted pursuant to the exemption process set forth in the NERC
Rules of Procedure. This proposed BES definition more clearly and cleanly separates the BES definition from the
exemption process. It also does not add unnecessary qualifiers or verbiage that may result in confusion.
NextEra is also concerned that the working group assigned to the exemption process may initially be more focused on
developing categories, instead of an exemption process and associated criteria. Given the unique circumstances of the
interconnected BES, including system topology, NextEra does not believe that it would be a productive exercise for the
exemption working group to focus on types, groups or categories of equipment; instead, its efforts should focus on
developing specific objective criteria to judge the reasonableness of a request or application for an exemption. This
approach also seems more in line with FERC’s statement in Order No. 743 at paragraph 115: NERC should develop an

March 30, 3011

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Question 12 Comment
exemption process that includes clear, objective, transparent, and uniformly applicable criteria for exemption of facilities that
are not necessary for operating the grid. The ERO also should determine any related changes to its Rules of Procedures
that may be required to implement the exemption process, and file the proposed exemption process and rule changes with
the Commission. The challenges of developing an exemption process also include ensuring than any applicant is afforded
due process and balanced decision-making, as required by section 215 of the Federal Power Act. Thus, the exemption
process must address legal, regulatory and technical issues. Accordingly, NextEra requests that NERC assemble a working
group (perhaps via the Standards Committee) to develop the exemption process that is comprised of stakeholders with legal,
regulatory and technical experience. Without this balance of disciplines, NextEra is concerned that a technical-heavy
working group will attempt to develop a “fix,” instead of a process whereby applicants may request an exemption, and have
that exemption judged by specific criteria and pursuant to a process that affords due process and balanced decision-making.
It is not clear whether an exemption working group has already been assembled. If it has, NextEra requests that NERC
consider restructuring of the group consistent with NextEra’s proposal.In summary, NextEra requests that the BES definition
drafting team adopt NextEra’s proposed definition of BES. NextEra also requests that NERC assemble a cross-functional
working group to develop an exemption process based on specific criteria (rather than categories), and a process that affords
applicants due process and balanced decision-making.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
The new definition removes the term “general” and provides more specific wording.
NERC will follow the due process established for changes to the Glossary of Terms.
Pepco Holdings Inc.

The RFC BES Definition and Clarifications could be used as a model for definition. It specifically incorporates additional
detail of what is included and what is excluded.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. The SDT has utilized many resources during the development of this definition including the work done by
RFC.
Indeck Energy Services

March 30, 3011

The BES definition should be the same as the FPA Bulk Power System definition! It will not be a bright line, like >100 kV. It
will focus NERC's efforts on the real reliability issues rather than chasing many small entities through paper exercises that
make someone feel that they are punishing unreliable behavior. Such exercises over the last 3 years have not measurably
improved reliability, in fact, NERC doesn't seem to know how to measure reliability in its purest form. It can monitor
operating and planning parameters of the BPS, but none of them truly measure reliability. The July, 2010 FERC Technical
Conference showed how far off NERC is when a FERC Commissioner had to state that preventing "loss of load" does not
define reliability. As referred to in the FPA, preventing cascading outages defines reliability. How does having a Sabotage

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and Bomb Threat procedure at a 100 MW wind farm prevent cascading outages?

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions.
Snohomish County PUD

Snohomish has worked extensively with the WECC Bulk Electric System Task Force ("BESDTF") over the last two years
and, while we disagree with certain details of the BESDTF approach (in particular, we believe a 200-kV threshold rather than
a 100-kV threshold more appropriately reflects conditions in the Western Interconnection), we believe the approach
developed by the BESDTF will achieve the reliability goals laid down by FERC in Order No. 743 while at the same time
excluding facilities from the BES that have no meaningful impact on the reliable operation of the bulk transmission system,
which thereby minimizes unnecessary compliance costs. Accordingly, we commend the work of the BESDTF to the
standards drafting team. Given the relatively short deadline imposed by FERC for completion of work on the revised
definition, we believe it will be necessary for the standards drafting team to rely on existing work of groups like the BESDTF
rather than re-inventing the wheel.

Central Lincoln

The WECC Bulk Electric System Definition Task Force has made significant progress in defining the BES. We encourage
the SAR to look at the work they’ve done.

PUD No.1 of Clallam County
PNGC Power
Blachly-Lane Electric Co-op
Clearwater Power Co.
Douglas Electric Cooperative
Central Electric Cooperative, Inc.
(Redmond Oregon)
Raft River Rural Electric
Cooperative
Northern Lights Inc.
Salmon River Electric

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Question 12 Comment

Cooperative
Okanogan Country Electric
Cooperative
Lost River Electric
Lane Electric Cooperative
Coos-Curry Electric Cooperative
Consumer's Power Inc.
Umatilla Electric Co-op
West Oregon Electric
Cooperative
Lincoln Electric Cooperative
Fall River Electric Cooperative
Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. The SDT has utilized many resources during the development of this definition including the work done by
the WECC BESDTF.
The Dow Chemical Company

March 30, 3011

As discussed above, the proposed definition of BES is flawed because it fails to expressly exclude local distribution facilities.
It is also confusing, particularly with respect to its use and application of the 100 kV standard. As the definition is written, the
100 kV standard would apply to both transmission and generation facilities - i.e., “All Transmission and Generation Elements
and Facilities” - even though voltage is primarily a measure of transmission capability with little applicability to generation.
Such a standard would, depending on how it is applied, be inconsistent with the generation criteria already set forth in the
NERC Statement of Compliance Registry Criteria. In the case of Dow and Union Carbide Corporation, these criteria
establish a generally-applicable 20 MVA threshold applicable to exports of electricity to the transmission grid from individual
generating units and a 75 MVA threshold applicable to exports of electricity to the transmission grid from generating
plants/facilities.

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The BES definition should not change the currently applicable 20 MVA / 75 MVA generation size threshold applicable to
generation facilities or the manner in which that threshold is currently applied, with behind-the-meter cogeneration facilities
evaluated based on the net capacity actually provided to the grid. The best approach might be to define BES as simply
consisting of three types of facilities: (1) BES Generation; (2) BES Transmission; and (3) BES Protection and Controls.
Those terms would then be defined by reference to criteria set forth in NERC’s Statement of Compliance Registry Criteria.
For example, the term BES Generation would be defined as individual generating units or generating plants or facilities that
meet the criteria set forth in the Statement of Compliance Registry Criteria.
This approach would provide greater clarity. It would also generally preserve the status quo, which is particularly important in
the context of generation. NERC and the Regional Entities have already made significant progress in deciding what
generators should be subject to compliance with mandatory reliability standards and what generators should be exempted.
Nothing in Order No. 743 requires that those determinations be revisited.
The issues raised in Order No. 743 will, however, likely require revisions to the transmission-related criteria set forth in
NERC’s Statement of Compliance Registry Criteria. Dow is not in principle opposed to the retention of the 100 kV standard
that is already set forth in the registry criteria, but it must be clarified to apply to facilities that perform a transmission function
while excluding facilities that perform a local distribution function. The criteria should also preserve the “material to reliability”
standard that is set forth in the proposed definition, i.e., that facilities must be “necessary to support bulk power system
reliability” in order to be considered part of the BES. This standard is particularly important in the context of interconnection
facilities that connect generation resources to the transmission grid. FERC has recognized that such facilities do not neatly
qualify as either transmission facilities or distribution facilities, but that such facilities should nevertheless be considered part
of the BES and subject to mandatory reliability standards only if they are determined to be “material to the reliability of the
bulk power system.” See New Harquahala Generating Company, LLC, 123 FERC ¶ 61,173 at P 44 (2008), clarified, 123
FERC ¶ 61,311 (2008).Based on these considerations, the criteria set forth in the NERC Statement of Compliance Registry
Criteria should be structured so as to define “BES Transmission” as including: (1) facilities that perform a transmission
function, that are operated at voltages of 100 kV or higher, and that are materially necessary to support bulk power system
reliability; and (2) any other facility that performs a transmission function that is found to be materially necessary to support
bulk power system reliability. To the extent an interconnection line from a BES Generation facility is materially necessary to
support bulk power reliability, that interconnection line should be treated as part of the BES Generation facility, rather than a
BES Transmission facility. Such a structure would preserve the bright-line 100 kV standard preferred by FERC, while
defining and applying the standard in a manner that appropriately preserves the distinctions that are recognized for local
distribution and interconnection facilities, and that ensures that all facilities that materially affect reliability are covered by the
standards.
Of course, once a definition for BES Transmission is adopted, the next step is to develop a process for applying that
definition so as to identify specific facilities that qualify as BES Transmission facilities, and that are subject to mandatory
reliability standards. Owners and operators should be afforded an opportunity in the process to demonstrate that their
facilities should be excluded because they either: (1) perform a distribution function; (2) are not materially necessary to
support bulk power system reliability; or (3) are included as part of BES Generation facilities. Such an opportunity must be

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Question 12 Comment
provided before facilities become subject to mandatory BES Transmission reliability standards.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
This new definition addresses radial Loads and generation.
Furthermore, the SDT has utilized many resources to provide this clarity including the Compliance Registry Criteria.
Utility Services

We believe our answers to the questions above provide for sufficient means to meet the intent of Order 743.

Response: Please see responses to questions above.
BGE

It is preferable that non-BES facilities be excluded by the definition language rather than to define BES broadly and require
non-BES facilities go through an exception process. For those special case facilities that may exist, an “opt-in” evaluation
could be conducted. We find that this approach to revising the BES definition would satisfy the FERC directives in Order
743 by encompassing all facilities necessary for operating an interconnected electric transmission network into a national
level, bright-line definition. This approach will improve the clarity and consistency of the BES definition for application by
Industry and NERC as well as avoiding creation of a potentially cumbersome exception process. The rules of procedure
process may be used to develop the “opt-in” process that would replace the proposed exception concept; however, the
drafting team, perhaps in collaboration with regional entities, should develop any opt-in criteria needed for the process. It is
appropriate for NERC to develop aspects such as the administrative management, the role and interaction of the regions, an
appeal process, etc. However, due to the technical aspects of BES operation, the drafting team members are best suited to
devise criteria for non-BES facilities to warrant inclusion in the BES.

Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear

Constellation recognizes the value in clarifying the Definition of Bulk Electric System into a bright line threshold consistently
applied across the regions. However, we are concerned that the current approach of a simple, all inclusive definition coupled
with an exception criteria and process will not draw on the fundamentals underpinning the existing definition and create a
cumbersome and unnecessary exception process. As an alternative, we propose that the standard drafting team utilize the
Compliance Registry Criteria-Section III (Rules of Procedure Appendix 5B) along with definition threshold language (such as
100 kV) to develop a more comprehensive definition. Further, we propose that the BES drafting team incorporate the criteria
directly into the revised BES definition, replacing the term “bulk power system” in each criterion with “greater than 100 kV.”
This will make for a longer definition, but by aligning the facilities requiring registration as those defined as BES, the definition
will more clearly determine the line between BES and non-BES. It is preferable that non-BES facilities be excluded by the
definition language rather than to define BES broadly and require non-BES facilities go through an exception process.
Ideally, this approach can eliminate the need for an onerous exemption process as well as eliminate the need for Section III
of the Registry Criteria in the Rules of Procedure. For special case facilities deemed non-BES by the revised definition that

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Organization
Group, LLC, (“CENG”)

Question 12 Comment
may warrant consideration for inclusion, an “opt-in” evaluation could be conducted. The rules of procedure process may be
used to develop the “opt-in” process that would replace the proposed exception concept; however, the drafting team,
perhaps in collaboration with regional entities, should develop any opt-in criteria needed for the process. Again, it is
appropriate for NERC to develop aspects such as the administrative management, the role and interaction of the regions, an
appeal process, etc. However, due to the technical aspects of BES operation, the drafting team members are best suited to
devise criteria for non-BES facilities to warrant inclusion in the BES.We find that this approach to revising the BES definition
would satisfy the FERC directives in Order 743 by encompassing all facilities necessary for operating an interconnected
electric transmission network into a national level, bright-line definition. This approach will improve the clarity and
consistency of the BES definition for application by Industry and NERC as well as avoiding creation of a potentially
cumbersome exception process.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition. Furthermore, the SDT has
utilized many resources to provide this clarity including the Compliance Registry Criteria.
Springfield Utility Board

See suggested language in the comment to Question 11. (This e-survey process is confusing as one does not know what
will be asked to know the right context to provide a response. Can you please post all questions in advance of an entity
walking through the survey. Also - seeing the responses at the conclusion of the survey is great, but it would be convenient
to be able to edit responses at the conclusion as well)

Response: See response to Q11.
The SDT has no control over the logistics of the system for providing comments. However, a Word version was posted on the project web page for review.
APPA

The Concept Paper states at page 1 that in Order 743, FERC directed NERC to do the following:
A. Utilize the NERC Standard Development Process to revise the definition of Bulk Electric System (BES) contained in the
NERC Glossary of Terms.
B. Develop a single Implementation Plan to address the application of the revised definition of the BES and the
implementation of the exemption process.
C. Utilize the NERC Rules of Procedure to develop and implement an ‘exemption process’ used to identify Elements and
Facilities which will be included in or excluded from the BES.
The Concept Paper continues to state that: This project will address items ‘A’ and ‘B’ and will coordinate efforts between the
Standard Drafting Team (SDT) and the group working to develop the exemption process for inclusion in the NERC Rules of
Procedure to ensure that the revised BES definition and exemption process result in an accurate, repeatable, and

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Question 12 Comment
transparent method for the identification of BES and non-BES Elements and Facilities.
APPA agrees that the standards process must be used to develop the revised BES definition and that NERC has been
directed to use its Rules of Procedure process to develop an ROP-based procedure to implement an
exemption/exclusion/inclusion process. However, the FERC directives do not speak to how and by whom the technical
methodology, study criteria and data requirements for requesting and receiving approval for an exemption should be
developed.
To the maximum extent possible, subject to time constraints imposed by FERC, this inherently technical methodology needs
to be developed through the NERC standards development process, in conjunction with development of the revised definition
of BES. Separate development will significantly hamper development of industry consensus in support of the revised BES
definition and the yet to be developed ROP modifications for the exemption process.
The most critical question is how do we arrive at a commonly agreed upon, widely accessible, transparent, and replicable
continent-wide methodology to determine whether each specific facility is or is not “necessary to operate an interconnected
electric transmission network” to quote from paragraph 16 of Order 743. While each region may have a separate model
reflecting its topology and system performance characteristics, a continent-wide approach is required to address FERC
concerns about inconsistency across regions that are not the result of physical differences.
The statutory definition of the term bulk-power system defines the outer extent of facilities that can be included (at least
within the United States) within the NERC definition of BES. FPA section 215(a)(1) states that the bulk-power system
includes “(A) facilities and control systems necessary for operating an interconnected electric energy transmission network
(or any portion thereof); and (B) electric energy from generation facilities needed to maintain transmission system reliability.”
Further, the term BPS “does not include facilities used in the local distribution of electric energy.” [emphasis added].Similarly,
“reliable operation” is defined at 215(a)(4) to mean “operating the elements of the bulk-power system within equipment and
electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such
system will not occur as a result of a sudden disturbance, including a cybersecurity incident, or unanticipated failure of
system elements.” These definitions appear to point to two basic questions for the classification of each facility or element as
BES or non-BES:
1. Is the facility or element necessary for reliable operation because it contributes significant capability to the interconnected
transmission network?
2. Will the misoperation or unanticipated failure of the facility or element adversely affect the reliable operation of the
interconnected transmission network? APPA suggests that the BES SDT or separate study teams should be directed to
establish the outline for this study methodology.
APPA further suggests that BES sub-teams be established to address the Proposed BES Criteria in the Concept Paper.
Separate sub-teams should be established to address detailed system configuration and study methodology issues affecting:

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Question 12 Comment
1. Radials serving load (with and without distribution voltage generation not subject to registration)
2. Other transmission elements that entities seek to include in or exclude from the BES.
3. Generating plant equipment that entities seek to include in or exclude from the BES.
4. Technical issues raised by the FERC Seven Factor Test for Local Distribution Facilities.
Separate sub-teams are appropriate because the study issues are likely to be quite distinct. For example, radials serving
only load do not provide alternative pathways for reliable BES operations, as might some sub-100 kV facilities. Mixing the
two teams together might slow progress on identification of various commonly used radial to load center configurations that
with proper protection schemes do not have the potential to adversely affect the BES. A focused effort on permissible
exclusions of radials serving load is essential to prevent distribution providers from adopting less reliable system
configurations to serve their loads because they are concerned that the preferred configuration will make them subject to
registration as TOs and/or TOPs.
Note that the proposed sub-teams do not necessarily have to be populated by members of the SDT. The new standards
process allows SDTs to gather informal input from a variety of sources. However, development and posting for industry
comment of the minimum acceptable characteristics of the study methodology to be used in the Exceptions Process should
be the responsibility of the BES SDT.
The Comment Form on the Exclusion Process poses reasonable questions and it is my hope that registered entities and
regional entities identify numerous candidate facilities and elements for inclusion or exclusion from the BES, accompanied by
one-line diagrams that lay out each of the permutations for such facilities that are candidates for exclusion/inclusion. These
facilities range from simple radial transmission lines and distribution step-down transformers to 100 kV class distribution
networks that operate radially from the BES. I also hope that entities submit extensive technical documentation to explain
why such facilities should be excluded from or included in the BES.
Good luck!

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
NERC will follow the due process established for changes to the Glossary of Terms.
This new definition addresses radial Loads, generation, and local distribution networks.
Xcel Energy

March 30, 3011

Xcel Energy agrees that the FERC Order 743 directs NERC to modify the Rules of Procedure to include the process for how
an entity or region may initiate an exclusion or inclusion. However, we do not agree that FERC also directed that the actual
criteria and technical specifics for inclusion or exclusion be developed as part of the Rules of Procedure. Furthermore, since

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Question 12 Comment
the inclusion/exclusion criteria is a key component to the definition of BES, we feel the criteria should be treated as part of
the definition development and developed in the same manner as the definition itself. (Preferably by the same drafting
team.)

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
NERC will follow the due process established for changes to the Glossary of Terms.
City of Redding

Please consider the WECC Bulk Electric Defination Task Force work to date.
See Attachment 1 at the end of this document.
See Attachment 2 at the end of this document.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions that will address many, if not all, of the issues in the provided examples. This definition will eliminate regional
discretion and any questions on this bright-line definition will be handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the
development of this BES definition.
Furthermore, the SDT has utilized many resources to provide this clarity including the Compliance Registry Criteria and the work in the WECC BESDTF
recommendations.

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13. Please provide any other information that you feel would be helpful to the drafting team working on the definition of BES.
Summary Consideration: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which
consists of a core definition that establishes the overall starting point for assessing BES and non-BES Elements. The exception criteria use
the same bright-line criteria to provide further guidance as to whether an Element is considered BES or non-BES. The SDT believes that this
is the best method to address the Commission’s concerns of establishing a bright-line definition of the BES that is clear, unambiguous, and
provides for consistent application across the continent.
The SDT acknowledges the comments and concerns related to the Exception Process and recognizes that the forum for providing these
comments to the NERC Rules of Procedure Team was not established prior to this posting. The revision process for the NERC ROP to
develop the Exception Process will be coordinated by NERC staff and governed by current practice for administering such revisions. All
comments pertaining to the Exception Process, the NERC ROP Team, and the ROP revision process will be forwarded to the appropriate
parties for consideration.
The SDT acknowledges the industry’s concerns surrounding the separation of work to different teams in response to the directives in FERC
Order No. 743. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the
directives in Order No. 743 the decision was made to establish two teams working in close coordination to address the issues related to the
project. The SDT is committed to that close coordination between the development of the core definition of the BES and the exception
criteria by the SDT and the development of the Exception Process by the NERC ROP Team. The goal is to have parallel postings from each
aspect of the project, which will enable the industry to review the entire project ‘package’ at one time and effectively provide comments
simultaneously on the core definition exception criteria with its associated lists of “inclusions” and “exclusions” and the Exception Process.

Organization
Northeast Power Coordinating
Council

Yes or No

Question 13 Comment

a.) Proposed definitions to be added to the NERC Glossary of Terms: BES Exemption Process: The review processes for
(a) excluding or exempting facilities and Elements from the BES that are determined not to be necessary to support bulk
power system reliability (e.g., radial elements), and (b) including Elements operated at voltages below 100 kV that are
determined to be necessary to support bulk power system reliability. By identifying all such BES and non-BES facilities
and elements, the BES Exemption Process will establish the Points-of-Demarcation between Facilities and BES Elements
and non-BES facilities and Elements. Point-of-Demarcation: A physical point and/or electrical connection between
facilities and BES Elements and non-BES facilities and elements, e.g., the upstream terminals of a disconnect switch (or
a buss connection) representing the boundary between a BES supply bus and a non-BES radial feeder. The BES
exemption process has not yet been written. So, it is somewhat difficult to know a priori whether any element, elements or
a group of elements or facilities should or should not be classified as part of the BES definition.
b.) This document uses both “exemption process” and “exception process”. Recommend that the phraseology be
standardized on “exception process” as the exception (not the exemption) can be to include or exclude elements and

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Yes or No

Question 13 Comment

facilities.
c.) It is envisioned that the BES Exception Process will contain 3 sub-processes; one for Exclusion, one for Exemption, and
one for Inclusion. Each sub-process will establish provisions and guidelines for the three different tasks. In order to
ensure consistency across the continent, it is our view that NERC should be the facilitator of these processes. NERC
may choose to have some of these tasks performed at the regional levels through the existing delegation agreements.
d.) The BES Exception Process must be an active and ongoing aspect of the ERO program. With the addition of new or
deletion of existing Transmission and Generation Elements, Facilities, or systems. It needs to be recognized that
Exclusions, Inclusions, and Exemptions might need alteration over time. By establishing appropriate guidelines and
processes, the ERO will be able to monitor and maintain information on what is the Bulk Electric System, or BES.
e.) The exception (exemption) process should clearly address the process and requirements for FERC non-jurisdictional
entities (such as the Canadian entities) with the exception of the interconnections between them and those entities under
FERC jurisdiction, and/or those entities having a direct impact on those interconnections.
f.) Classification of all radial facilities operated at voltages of 100 kV and above as part of the BES by default would be
unnecessary and administratively inefficient, because the operation of all radial facilities do not have a significant
operational impact on the BES. Those radial facilities not having a significant impact should be excluded from the BES. If
they aren’t, it could lead to delays in the review and approval of other exemption requests. As such, the proposed BES
definition should be revised to clearly define what radial Transmission Elements will not be included as part of the BES.
This would be consistent with FERC’s intention expressed in Paragraph 55 of Order 743 to not alter the part of the
approved definition that deals with “radial transmission facilities serving only load”.
g.) Additionally, to ensure a common understanding of the meaning of “radial” and to promote consistency in its application,
“radial” should be defined and added to the NERC Glossary.
Response:
a.) With the proposed revisions to the definition of BES, at this time, the SDT does not contemplate adding any additional definitions beyond BES. In regards
to the term “BES Exception Process’; it has been determined that the process will reside in the NERC Rules of Procedure (ROP) and therefore it seems
logical that the purpose of the process would be defined within the boundaries of the NERC ROP.
b.) The inconsistency of the use of ‘exemption’ vs. ‘exception’ in several documents has been identified by the SDT and the team has determined that
‘exception’ is the proper term to be used in reference to the Bulk Electric System definition and supporting processes.
c.) The ‘Exception Process’ will be developed by the NERC Rules of Procedure Drafting Team while coordinating with the DBES SDT. The ‘Exception
Process’ and the responsibilities associated with the implementation and oversight will be defined by the NERC Rules of Procedure Team. Based on the

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Yes or No

Question 13 Comment

language contained in FERC Order No. 743, there are Commission expectations associated with the process oversight by the ERO and allowances for the
delegation of responsibilities to Regional Entities as appropriate, while ensuring the process is clear and capable of being applied consistently, objectively,
and uniformly across all regions.
d.) The SDT agrees that the Bulk Electric System is dynamic and that the implementation and continued application of the BES Definition and supporting
processes will require active oversight and management to ensure that changing conditions (i.e., operational & new construction) surrounding the Bulk
Electric System will be addressed and result in proper evaluation and identification of BES & non-BES Elements. The current scope of the Standard
Authorization Request (SAR) for Project 2010-17 Definition of Bulk Electric System does not include the development of the ‘Exception Process’. The
‘Exception Process’, including the implementation and continued application of the process will be developed by the NERC ROP Team.
e.) The SDT has established non-jurisdictional representation to address the concerns of the applicable entities (i.e., Canadian entities) in regards to the
application of a continent-wide ‘bright-line’ definition of the Bulk Electric System and the exception criteria listed in the definition. NERC Staff has
determined the needs of the NERC Rules of Procedure Team in regards to the diversity of the membership and the technical expertise required to
appropriately modify the ROP in response to the directives identified in FERC Order No. 743.
f.) The SDT has further developed the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall
starting point for assessing BES and non-BES Elements. The ‘exception criteria’ utilizes the same ‘bright-line’ approach to provide further guidance as to
whether an Element is considered BES or non-BES (i.e., bright-line for identifying Generation Facilities, Radials, etc.). The exception criteria has been
listed in the revised definition of BES.
g.) With the proposed revisions to the definition of BES, at this time, the SDT does not contemplate adding any additional definitions beyond BES.
MRO's NERC Standards Review
Subcommittee

A. What time frame is the SDT considering for the implementation of this definition and process once approved, allowing
enough time for the entities to provide justification, and then make the necessary changes to their internal programs?
B. Recommend the BES SDT be consistent with the generation registration criteria and the Protection System definition and
other documents. For example, what is a “common bus” as stated in the generation registration criteria.
C. Please review and update the concept paper. The concept paper does not specifically call out Transmission Lines above
100 kV as in the BES definition (the proposed definition does, however) and there is a circular exemption criteria in the
concept paper. In criterion #2, it refers to the exemption process "consistent with the criteria". The criteria exempt generating
plant controls and Transmission Elements or Systems that are radial to a load or generator not included in the BES List.
However, the BES list is defined prior to the criteria in the concept paper. Exemption criterion #1 points to BES list elements
#6 and #7, which in turn, refer to the exemption process. But, the exemption criteria never define how to exempt the
elements referred to in #6 and #7.
D. How often would a Registered Entity revisit this Exception Process? NSRS can envision a scenario where they are doing
that every year or two because of the changes in load, generation, and transmission. The process should also allow for

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Yes or No

Question 13 Comment

multi-year distinctions for exceptions. In other words, if a Registered Entity gets a facility excluded, then that exclusion
should be allowed for 3 or more years. Annual certifications and approval are too restrictive.
E. NSRS believes the exception criteria needs to be developed by the SDT. NERC Staff should focus on the process
(identification, notification, appeal and rights) but the SDT is in the better position to develop the technical piece of the
exception criterion.
Response:
A. The SDT has established basic goals and assumptions that will be used to guide the development of the BES definition and supporting documents. The
assumptions include: ‘The revised definition will not significantly expand or contract what are currently considered BES Elements, nor will the revised
definition drive entity registration or de-registration”. Based on these goals and assumptions the overall impact of the revised definition is expected to be
minimized for the majority of the Regions and Registered Entities. However, once the definition and supporting documents are nearing completion, the
impact of the revised definition will be assessed and the Implementation Plan and Transition Plans will be developed to provide an appropriate time-period
for entities to establish compliance with the applicable Reliability Standards.
B. The SDT has established basic goals and assumptions that will be used to guide the development of the BES definition and supporting documents. The
assumptions include: ‘The revised definition will not significantly expand or contract what is currently considered to be BES Elements, nor will the revised
definition drive entity registration or de-registration”. Based on these goals and assumptions and in the absence of technical justification, the current
generator registration criteria appears to be the logical starting point for assessing BES Elements. The goal of the SDT is to establish a component-based
‘bright-line’ definition which enables the proper assessment of BES and non-BES Elements. The ‘bright-line’ associated with the identification of Protection
Systems which are applicable to the PRC series of Reliability Standards is not necessarily at the same point. The SDT has discussed this issue and will
be seeking guidance from FERC staff in regards to the directives in FERC Order No. 743 and how they potentially apply to Protection Systems. Protection
Systems are not currently within the scope of the SAR for this project and any significant expansion could potentially jeopardize the ability of the SDT to
complete this project and file in accordance with the Commission directed time requirements in FERC Order No. 743.
C.

The SDT is not considering updating the concept paper as future work will be in crafting the actual definition and designations.

D. The SDT agrees that the Bulk Electric System is dynamic and that the implementation and continued application of the BES Definition and supporting
processes will require active oversight and management to ensure that changing conditions (i.e., operational & new construction) surrounding the Bulk
Electric System will be addressed and result in proper periodic evaluation and identification of BES & non-BES Elements. The current scope of the
Standard Authorization Request (SAR) for Project 2010-17 Definition of Bulk Electric System does not include the development of the ‘Exception Process’.
The specific review/re-assessment ‘time periods’ associated with the identified exceptions (inclusions & exclusions) will be drafted by the NERC ROP
Team and vetted through the ROP Revision Process.
E. The current scope of Project 2010-17 includes the development of the exception criteria. Additionally, the SDT will have representation on the NERC ROP
Team to ensure that consistency is maintained throughout the development of the revised definition and the Exception Process.

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Organization
IRC Standards Review
Committee

Yes or No

Question 13 Comment
a. On the SAR, it indicates an SC approval date of December 8. It is misleading since the SC did not approve
the SAR; it only approved posting of the SAR for industry comment.
b. We have a concern with the concept paper on the exemption/inclusion criteria/process. Please see other
comments on that paper submitted separately.
c. We suggest use of consistent term between “exception” and “exemption”.
d. We suggest the exception/inclusion criteria to be included in the definition and developed/approved by the
balloting body. Determining these criteria via any other processes will not provide the industry the opportunity
to fully vet the criteria.
e. The SAR indicates that “...the definition drafting team will work closely with the team developing the BES
definition exemption process to develop a single coordinated implementation plan. It is also envisioned, that
the team working to develop the BES definition exemption process will solicit input from drafting teams,
stakeholders....” We find this confusing and have a concern that having two teams working on this
definition/criteria package leads to misalignment and confusion. Further, while the definition drafting team is
formed by a nomination process and appointed by the NERC Standards Committee, there is no transparency
and/or public announcement to solicit nominations for the team working to develop the exemption process.
We urge the NERC Standards Committee to direct the definition drafting team to also be responsible for
developing the exemption process, and include the exemption criteria as part of the definition hence
subjecting them to industry comment and balloting.

Response:
a. The default language in the form is misleading and implies that the NERC Standards Committee’s approval is required. Per the NERC Standard Process
Manual the Standards Committee authorizes posting of the SAR for industry comment. The DBES SDT will provide a recommendation to NERC
Standards Staff to revise the SAR form to read, "Date SC Authorized Posting the SAR”.
b. Please see comment responses to other questions.
c.

The inconsistency of the use of ‘exemption’ vs. ‘exception’ in several documents has been identified by the SDT and the SDT has determined that
‘exception’ is the proper term to be used in reference to the Bulk Electric System definition and supporting processes.

d. The current scope of Project 2010-17 includes the development of the exception criteria and the revised definition of BES includes a proposed list of
criteria for “Inclusions” and a proposed list for “Exclusions”. Additionally, the SDT will have representation on the NERC ROP Team to ensure that
consistency is maintained throughout the development of the revised definition and the Exception Process.
e. The passage from the SAR that is referenced in the comment is addressing the need for a single Implementation Plan that takes into consideration all

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Yes or No

Question 13 Comment

aspects of this project. The Implementation Plan will need to address the impact of the revised BES definition and exception criteria, the Exception
Process (ROP) and the Regional Transition Plans. The current scope of Project 2010-17 includes the development of the exception criteria. Additionally,
the SDT will have representation on the NERC ROP Team to ensure that consistency is maintained throughout the development of the revised definition
and the Exception Process. The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC
staff and governed by current practice for administering such revisions. The NERC ROP Team will be established by NERC staff and include
representation from the DBES SDT along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be
determined and administered by NERC staff.
Bonneville Power Administration

1. Define the definition of generation resources and plants, specifically wind.
2. Ensure that the exemption process incorporates all lines in service, outage conditions, etc.
3. Ensure that BA’s have the ability to recommend inclusion in the BES, if the BA determines the facility has
an impact on the BES.

Response:
1. The term is no longer used in the definition.
2. The SDT has developed the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall starting
point for assessing BES and non-BES Elements. The ‘exception criteria’ utilizes the same type of ‘bright-line’ criteria approach to provide further guidance
as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation Facilities, radials, etc.). The idea of injecting the
‘current operational conditions’ (lines in service, outage conditions, etc.) of Elements poses difficulties with the universal application of the definition to
achieve consistent results across the continent. Additionally, the idea of ‘current operational conditions’ (lines in service, outage conditions, etc.) suggests
that these conditions are subject to change and therefore could result in different assessments when identifying BES and non-BES Elements.
3. The responsibilities associated with the Exception Process will be determined and established by the NERC ROP Team as part of the Exception Process.
FirstEnergy Corp

March 30, 3011

a.) FirstEnergy supports a new BES definition that will provide a clear bright-line of electric facilities
deemed inclusive to the BES. The exclusion process should be a simple, continent wide, rarely used
with high-thresholds for removing any 100kV and above facility from the BES. The exclusion process
and BES definition change should also include a practical means for transition for any affected
companies.
b.) The BES definition should explicitly contain language to exclude radial to load transmission operated
at 100kV and above voltage levels. Presently, it seems that radial transmission to load “may” be
excluded, subject to the exemption process. The excluded radial facilities described by the BES
definition should be simply defined and avoid overly complicated scenarios for qualify a facility as
radial transmission.

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c.) BES definition clarity can be accomplished by incorporating aspects of the concept paper’s proposed
“BES Criteria” as being part and parcel of the overall BES definition. Doing so will establish the
desired BES bright-line by further describing facilities as “in” or “out” by definition and avoid an overly
complicated exclusion process.
d.) The exclusion process should be rarely used, having a narrow expectation for removing facilities from
the BES and thus avoid an overly burdensome administrative process. From an exclusion view, the
BES definition should directly exclude radial 100kV and higher transmission, facilities operated below
100kV unless deemed critical to the BES by the Regional Entity and any 100kV and higher facility
qualified by the BES exemption process.
e.) Further, we support EEI’s views that the BES Definition and the technical aspects of the exemption
criteria (outside of the definition) should be treated as a single standards development project and
performed by this drafting team.
f.) We also support a parallel effort by NERC staff, subject to industry review/comment, of revising the
Rules of Procedure to account for the process oriented information that would point to the technical
exemption criteria/guidance developed by the standard drafting team.
g.) Finally, the concept paper awkwardly describes an “exclusion process” that would identify any sub
100kV facilities that would be “included” in the BES. The criterion developed for potentially including
sub 100kV facilities should be separately developed or at least not referenced within an “exclusion
process”. Additionally care should be taken to not cast the net too wide in this regard. While we
propose a high threshold for excluding 100kV facilities from the BES, we similarly propose a high
threshold for inclusion of sub 100kV facilities. The primary focus of this drafting team should be the
drafting of the new BES definition and the technical BES exemption criteria. The development of
continent-wide criteria for including other sub 100kV facilities in the BES should be treated as a
secondary priority for meeting the milestone expectations of the FERC compliance filing.

Response:
a.) The SDT agrees with the comments. The Implementation Plan will need to address the impact of the revised BES definition and exception criteria, the
Exception Process (ROP) and the Regional Transition Plans on affected entities and provide sufficient time to ensure a smooth transition into the realm of
mandatory and enforceable Reliability Standards.
b.) The SDT has further developed the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall
starting point for assessing BES and non-BES Elements with a list of exceptions. The ‘exception criteria’ utilizes the same ‘bright-line’ criteria approach to
provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation Facilities, radials, etc.).
c.) The SDT agrees with the comments and has established the tight linkage between the core definition of the BES with the component-based ‘bright-line’
exception criteria.

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d.) The Exception Process will be employed when the bright-line core definition and its associated exception criteria cannot be applied to a specific Element.
It is anticipated by the SDT that the ‘bright-line’ will be the definitive approach to identifying BES and non-BES Elements for the vast majority of the system
configurations across the continent and utilization of the Exception Process will be limited to the remaining Elements.
e.) The current scope of Project 2010-17 includes the development of the exception criteria and these have been included in the revised definition of BES.
Additionally, the SDT will have representation on the NERC ROP Team to ensure that consistency is maintained throughout the development of the
revised definition and the Exception Process.
f.) The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC
staff.
g.) It is the vision of the SDT that the process to include Elements within the BES and the ability to exclude Elements from the BES should parallel each other
and require the same level of technical justification to achieve consistent results.
Electric Market Policy

Dominion supports, in large part, EEI’s response to the draft concept paper. Dominion provides the following
comments on the proposed exemption process. NERC should use the FERC-approved standards
development process to develop the Bulk Electric System (BES) definition and the exemption process in a
single, integrated and stakeholder approved process. To this end, Dominion conceptually supports an
exemption process whereby NERC or the RRO could apply to have an element included or excluded from the
BES definition. Such process recognizes that it may be necessary to include elements that do not meet the
bright line criteria but are necessary for operating an interconnected transmission network. Such process
should be developed through the existing NERC standards development process and include a robust
appeals process for the owner/operator of any element so included or excluded.
Dominion supports bright line exclusions of all elements rated at less than 100 kV, any transformer that has a
primary or secondary winding of less than 100 kV, and all radial lines regardless of their kV rating. Radial
lines to/from solely generation facilities and radial lines to/from load are comparable in terms of their impact
on an interconnected transmission network. There are situations where these radials make a meaningful and
required contribution to the operation of an interconnected transmission network and there are other
locations/situations where these radials do not. Therefore, radial lines should only be specifically included in
the definition of BES after the RRO has demonstrated that inclusion of the radial is necessary to operate an
interconnected transmission network and the owner/operator of the radial line has had the opportunity to
exercise its aforementioned appeal rights. Adopting this paradigm would prevent a gap in the application of
reliability standards. Specifically, all radial lines would either be included in the definition of BES or would be
captured via the NERC registry under distribution or generation.

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Dominion supports the criteria for registering owners, operators, and users of the bulk power system, as
indicated in the current Statement of Compliance Registry Criteria . Adoption of the foregoing process would
insure confidence in entities that the compliance registration process is equitable and fair.

Response: The NERC Standard Processes Manual is the governing document for the development of the revised BES definition and exception criteria. The SDT
is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall starting
point for assessing BES and non-BES Elements. The ‘exception criteria’ use the same ‘bright-line’ criteria to provide further guidance as to whether an Element is
considered BES or non-BES (i.e. bright-line criteria for identifying Generation Facilities, Radials, etc.).
The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current practice
for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT along with industry
experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC staff.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception Process
by the NERC ROP Team. The goal (identified key to the project’s success) is to have parallel postings from each aspect of the project, which will enable the
industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception criteria, and the
Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the directives in Order
No. 743, the decision was made to establish two teams working in close coordination to address the issues related to the project.
See responses to EEI comments.
SERC OC Standards Review
Group

We agree that Transmission and Generation Elements and Facilities operated at voltages of 100 kV or higher
that are necessary to support bulk power system reliability should be included. Elements and Facilities
operated at voltages of 100kV or higher, including radial elements, may be excluded and Elements and
Facilities operated at voltages less than 100kV may be included if approved through the BES definition
exemption process.”The comments expressed herein represent a consensus of the views of the above
named members of the SERC OC Standards Review group only and should not be construed as the position
of SERC Reliability Corporation, its board or its officers.”

Competitive Suppliers

EPSA recognizes the value in revising the BES definition so that a bright-line proxy can be consistently
applied by the NERC Regional Entities. It is important that this definition be completed so that the drafting
team work sequentially by determining the new BES definition and then move on to developing a exemption
process that can work efficiently with that new definition

Response: The DBESSDT acknowledges your comments and thanks you for the support of the presented concepts.
Hydro-Quebec

March 30, 3011

For Canadian entities, inclusion or exclusion of equipment and facilities in the BES must be also approved by
Canadian regulators. Common interconnection between two jurisdictions must be included in BES when at

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least one Facilities is necessary for the reliability of BES.
The transmission lines dedicated to serve the native load in Quebec Interconnection should be excluded,
considering that the Quebec Interconnection is one of the four recognized interconnection.
Finally, we believe that it is very difficult to propose first a definition for the BES and only after an Exemption
process. Both aspects influence each other and both should be conducted together.

Response: The SDT has established non-jurisdictional representation to address the concerns of the applicable entities (e.g., Canadian entities) in regards to the
application of a continent-wide ‘bright-line’ definition of the Bulk Electric System and exception criteria. NERC Staff has determined the needs of the NERC Rules
of Procedure Team in regards to the diversity of the membership and the technical expertise required to appropriately modify the ROP in response to the
directives identified in FERC Order No. 743.
Transmission Lines dedicated to serving native Load are an identified concern in several Regions and Interconnections. The issues surrounding this concern and
the development of potential bright-line criteria are currently being considered by the SDT.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception Process
by the NERC ROP Team.
PPL Energy Plus
LG&E and KU Energy LLC

Please consider that it is the magnitude of MVA flow on a facility and the subsequent impact on the remaining
facilities that defines when a facility is in the BES rather than just the direction of the real power flowing on the
facility.

Response: The SDT has developed the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall
starting point for assessing BES and non-BES Elements. The ‘exception criteria’ (now proposed as part of the definition of BES) utilizes the same ‘bright-line’
criteria approach to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation Facilities,
radials, etc.). The idea of injecting the ‘current operational conditions’ (i.e., MVA flow) of Elements poses difficulties with the universal application of the definition
to achieve consistent results across the continent. Additionally, the idea of ‘current operational conditions’ (i.e., MVA flow) suggests that these conditions are
subject to change and therefore could result in different assessments when identifying BES and non-BES Elements.
ExxonMobil Research and
Engineering

Industrial facilities must retain the ability to control their electric facilities in order to ensure that the system is
designed to provide for the safest and most reliable source of electric power for the control of their processes.
The definition of the bulk electric system and the exemption process should address this fact and exclude or
provide a process to exclude industrial facilities from all or a select number of NERC requirements when there
is a conflict between the requirements designed to ensure the reliability of BES and the safe operation of
chemical processes.

Response: The SDT has established basic goals and assumptions that will be used to guide the development of the BES definition and supporting documents.

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The assumptions include: ‘The revised definition will not significantly expand or contract what are currently considered BES Elements, nor will the revised
definition drive entity registration or de-registration”. Based on these goals and assumptions the overall impact of the revised definition is expected to be minimized
for the majority of the Regions and Registered Entities. The SDT is currently working toward an equitable solution concerning industrial customers based on
language currently contained in the Registry Criteria which establishes guidance for addressing ‘behind the meter generation’.
NERC Staff

See Attached.

Response: The SDT will consider your comments in the further development of the core definition and the exception criteria.
Edison Electric Institute

Order 743 / NERC BES Project Edison Electric Institute Responses to Draft Concept Paper General Issues:
On behalf of its member companies, Edison Electric Institute (EEI) appreciates the opportunity to offer the
following brief comments on NERC Project 2010-17 for developing response to FERC Order No. 743,
definition of Bulk Electric System and an exemptions process for certain facilities. EEI is the association of
the nation’s shareholder-owned electric companies, international affiliates, and industry associates worldwide.
EEI’s U.S. members serve approximately 95 percent of the ultimate consumers served by the shareholderowned segment of the electric utility industry and approximately 70 percent of all electric utility ultimate
consumers in the nation. Virtually all EEI members are required to comply with the mandatory electric
reliability standards established by the ERO and approved by the Commission, pursuant to section 215 of the
Federal Power Act. As a process matter, EEI develops comments such as these through a disciplined and
well-practiced process that includes broad distribution of draft documents to member companies, conference
calls, and email exchanges, all conducted to ensure that EEI speaks with broad member company support
and with as much specificity as possible. For additional information about the roster of membership, NERC
staff should contact EEI directly.
The concept paper envisions two parts of the project - (1) development of the technical criteria for the BES
definition through the NERC Standards Development Process and (2) development of the Rules of Procedure
for the exemption process.
a.) NERC should use the FERC-approved standards development process for developing the technical
criteria for both the BES definition and exemptions. EEI views this as a single exercise, that is, the BES
definition and technical aspects relating to exemptions as a single project.
b.) EEI members believe that this is a critical project and understands various concerns about timeliness
and process efficiency, and therefore recommends that stakeholders make strong commitments now to
a project plan that will ensure a timely compliance filing at FERC. The drafting team should also
expedite development of a project plan that shows tasks, deliverables, and milestone dates for the entire
one-year timeline.

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c.) EEI reads Order No. 743 as suggesting that NERC should develop appropriate changes to the Rules of
Procedure (ROP) to accommodate the process and due process features of the BES exemptions
process, including matters such as administrative procedure, decision authority, appeals and other due
process matters, and requests for changes. EEI strongly believes that the technical matters are best
resolved in the FERC-approved standards development process, which for this project includes the BES
definition and the various technical criteria to be used to define exemptions. NERC should manage the
development of ROP changes through an open process that considers stakeholder comments and
recommendations.
d.) Alternatively, if NERC decides to develop various technical criteria for the granting of exemptions
through the Rules of Procedure, EEI strongly encourages NERC to plainly describe the process plan,
which will help communicate to companies how the process will be open, inclusive, transparent, and
ensure due process.
e.) Issues recommended for drafting team consideration: Order No. 743 provides that the best way to
address its concerns about the definition of BES is to eliminate the regional discretion in the current
definition, maintain the bright-line threshold that includes all facilities operated at or above 100 kV except
defined radial facilities and establish an exemption process and criteria for excluding facilities that the
ERO determines are not necessary for operating the interconnected transmission network. (P 30)
Because transmission lines below 100 kV and radial lines are not included in the definition of BES, the
standards drafting project should ensure that the definition expressly incorporates these exclusions.
Entities should not have to seek an exemption for facilities below 100 kV or for radial lines. They should
be clearly excluded in the BES definition itself.
f.) Removing regional discretion does not imply that regions have no role. EEI also encourages NERC in
the ROP to delegate the authority to grant exemptions in the first instance to the Regional Entities.
NERC should maintain oversight authority, including review of decisions for consistent application of the
criteria.
g.) Applicants for exemptions should be able to appeal adverse Regional Entity decisions to NERC. The
NERC Compliance Registry process should serve as a general model.
h.) The BES definition must also address the statutory exclusion for facilities used in “local distribution.”
Section 215 plainly excludes facilities used in local distribution from jurisdiction and EEI notes that the
definition is applied under other provisions of the Federal Power Act. The exemptions process should
provide that previous or future regulatory decisions regarding local distribution facilities can serve as an

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exemption criterion. While Order 743 does not provide explicit guidance on this issue, EEI urges the
drafting team to expand the concept paper to include how this issue will be addressed. If the concept
paper is not expanded to include this issue, NERC needs to plainly say where the issue will be
addressed.
i.) Order 743 made references to facilities below 100 kv that might be defined as necessary for operating
an interconnected transmission network, and asked that whatever processes are used to make
jurisdictional decisions are rolled into the NERC process. In addition, the order referred to several
“technical concerns” that might inform jurisdictional decisions on specific facilities greater than 100 kv,
which are scattered references throughout the order. For example: operate in parallel with other high
voltage and extra-high voltage facilities (P. 73), interconnect significant amounts of generation and
(possibly) operate as a defined flowgate (P. 73), will experience similar loadings as high voltage or extrahigh voltage facilities at any given time (P. 73), can cause or contribute to significant bulk power system
disturbances and cascading outages (P. 73), will be relied upon during contingency operations (P. 73),
are not primarily radial in character (P. 39), multiple interconnections of facilities (to other higher voltage
facilities) do not constrain an otherwise limited geographical area (P. 39), overall, (implementation of) the
proposed definition may not result in a reduction in reliability (P. 74), facilities that, when they fail, cause
or influence significant loss of load (PP. 87, 89). Order No. 743 does not explicitly connect these criteria
to the process to be developed; however, the drafting team in its plan should explain how it will address
them, as required by the order (P 74). EEI encourages the drafting team to seek informal agreement
with FERC staff on these various “technical concerns” prior to significantly advancing the project.
j.) As a design matter, EEI encourages the drafting team to endorse a principle to seek to maximize the
“brightness” of bright line criteria. While this may produce a longer or more detailed definition, EEI
believes that greater demarcation at the outset will help reduce companies’ uncertainty, and help avoid
the need to maintain a costly and bureaucratic exemptions process. EEI has previously offered
comments on many occasions to both FERC and NERC in support of a ‘simple and clean’ TFE process.
k.) EEI urges the drafting team to resist the temptation to create a complicated ‘Rube Goldberg’ device for
BES exemptions. Order No. 743 (PP 77-78, 84-85) criticizes the NPCC impact-based study as failing to
identify many facilities that are necessary for operating an interconnected transmission network.
However, the order does not reject such studies generically, and plainly states that the Commission is
not dictating the substance or content of the exemptions process. (P 114) The concept paper needs to
clarify whether requests for exemptions may use impact-based studies to support their requests.
l.) The concept paper reflects an awkwardly-worded reference (Item #6, proposed BES criteria) to the
effect that certain facilities will be deemed included in the BES “...where the exemptions process

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deems...” In the paragraph at the top of p. 2, the concept paper refers to the exemption process as
seeking to determine “...whether a facility should be included or excluded....” EEI requests clarification
that an exemptions process will be used to determine facilities for exclusions and not inclusions, and
based on a 100 kv bright-line criterion for inclusion. Alternatively, the concept paper should clarify the
general intention of this particular criterion.
m.) As previously stated, the proposed ROP to be developed should codify the process - and due process aspects of the exemptions process. The exemptions process should strike the right balance in
establishing the criteria for exemptions to ensure that the process does not become mired in attenuated
processes such as those developed for the TFE process.

Response:
a.) The NERC Standard Processes Manual is the governing document for the development of the revised BES definition and exception criteria. The SDT is
continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall
starting point for assessing BES and non-BES Elements. The ‘exception criteria’ (now proposed as part of the definition of BES) utilizes the same ‘brightline’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation
Facilities, radials, etc.).
b.) The SDT agrees with the critical nature of the project and the need to provide deliverables within the Commission directed time frame. The SDT has
developed and posted a project schedule which identifies the tasks, deliverables, and milestone dates for the entire project. The schedule is publically
posted and available on the project page (Project 2010-17 Definition of the Bulk Electric System) of the NERC website.
c.) The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC
staff.
d.) The SDT has determined that one of the keys to success for this team and the NERC ROP Team is effective communication that provides the industry
with an understanding of the project plan and concepts, which will emphasize the development process attributes of openness, inclusiveness,
transparency, and due process.
e.) The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ utilizes the same ‘bright-line’ criteria to provide
further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying Generation Facilities, Radials, etc.). The
tight linkage between the core definition and the exception criteria provides the framework for identifying BES and non-BES for the vast majority of the
Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or non-BES utilizing the core definition and
exception criteria would be candidates for application of the Exception Process where the technical justification would be required to identify Elements as

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BES (inclusions) or non-BES (exclusions).
f.) The ‘Exception Process’ and the responsibilities associated with the implementation and oversight will be defined by the NERC Rules of Procedure Team.
Based on the language contained in FERC Order No. 743, there are Commission expectations associated with the process oversight by the ERO and
allowances for the delegation of responsibilities to Regional Entities as appropriate, while ensuring the process is clear and capable of being applied
consistently, objectively and uniformly across all regions.
g.) The SDT agrees that within the NERC ROP Exception Process, entities should have the opportunity to appeal decisions made by the Regional Entities
and the ERO concerning the inclusion or exclusion of Elements in relation to the BES.
h.) The SDT agrees that the issues surrounding ‘local distribution networks’ deserve consideration when developing the BES Designations. See the revised
definition as it proposes exclusions for local distribution networks that meet certain criteria.
i.)

The SDT will consider your comments in the further development of the core definition and the exception criteria and will seek clarity on the issues
identified in future discussions with FERC staff.

j.) The SDT has developed the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall starting
point for assessing BES and non-BES Elements. The ‘exception criteria’ utilizes the same ‘bright-line’ criteria approach to provide further guidance as to
whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation Facilities, radials, etc.).
k.) The specific methodology associated with establishing the technical justification of inclusions to or exclusions from the BES will be determined and vetted
by the NERC ROP Team utilizing the revision process for the NERC ROP and will be coordinated by NERC staff and governed by current practice for
administering such revisions.
l.) The SDT disagrees with the commenter in that any Exception Process should establish a process for exceptions from and inclusions to the BES. As
stated in FERC Order No. 743, P83 “The Commission’s proposed approach to addressing these concerns will enable affected entities to pursue
exemptions for facilities they believe should not be included in the bulk electric system, and also will allow Regional Entities to add facilities below 100 kV
they believe should be included”. The Regional Entities currently have the authority to include Elements operated at voltages below 100 kV that are
deemed necessary for the reliable operation of the BES. The Order does not eliminate this authority, but rather emphasizes the need to maintain the
Regional Entity’s ability of establishing inclusions to the BES through the Exception Process.
m.) The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. With that in mind, the SDT agrees with the commenter in that the Exception Process should carry the same
characteristics as the core definition and exception criteria: clear, unambiguous, repeatable, and establish consistency on a continent-wide basis.
Pepco Holdings Inc.

March 30, 3011

1. The definition should be expanded to contain what is excluded to minimize the need for exemptions. For
example radial facilities should by definition be excluded and not have to go through a formal exemption

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process. Other “generic” criteria identified should also be excluded.
2. The exemption process needs to be well designed to minimize the effort. The exemption process
development should incorporate lessons learned and experience from the TFE process, so that this new
process is more manageable.
3. Instead of two separate groups, one working on the definition and one on the exemption process, one
group should handle both activities to assure continuity and consistency.
4. Any data required for the exemption process needs to be kept secure and not posted on an open source.
5. PHI is supportive the EEI comments offered on the BES Project.

Response:
1. The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed as part of the definition of BES)
utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying Generation Facilities, Radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for
identifying BES and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as
BES or non-BES utilizing the core definition and exception criteria would be candidates for application of the Exception Process where the technical
justification would be required to identify Elements as BES (inclusions) or non-BES (exclusions).
2. The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP team will be determined and administered by NERC
staff. With that in mind, the SDT agrees with the commenter in that the Exception Process should be a manageable process that is clear, unambiguous,
repeatable, and establishes consistency on a continent-wide basis.
3. The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception
Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which will enable
the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception criteria
and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the
directives in Order No. 743, the decision was made to establish two teams working in close coordination to address the issues related to the project.
4. The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The current process includes public postings of proposed changes which will allow the industry provide
comments. We will forward your comment to the team working on the ROP modifications.

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5. See responses to EEI comments.
PUD No.1 of Clallam County

Due to the lack of clarity around the current definition of the Bulk Electric System ("BES") the NERC
Statement of Compliance Registry Criteria is often used/misused to define elements of the BES. The
registration criterion uses many undefined terms as well as “bright line” thresholds that that in many cases
have little to no technical basis. One example is using “gross nameplate rating” when the machine size may
be significantly limited by boiler capacity on a cogeneration steam plant or water on a hydro plant. In addition
there is no technical or reliability bases used to identify the low MVA/MW thresholds used in the load and
generation thresholds for the DP, GO, GOp registrations.
The Standards Authorization Requests (SARs) should also address how, or if the registration criteria is used
in identifying BES elements. We believe the Registration Criteria should not be used to identify BES
elements; it should be used as indented, to address functional registration.

Response: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes
the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed as part of the definition of BES)
utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying
Generation Facilities, Radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying BES and nonBES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or non-BES utilizing the core
definition and exception criteria would be candidates for application of the Exception Process where the technical justification would be required to identify
Elements as BES (inclusions) or non-BES (exclusions).
Any impact of the revised core definition, the exception criteria, or Exception Process on the current Registry Criteria will be addressed in the Implementation Plan.
Manitoba Hydro

a.) A NERC definition of ‘radial’ is required to prevent misapplication of the BES definition and exemption
process.
b.) There should be no regional differences in the BES definition or in the BES definition exemption process.
c.) There should be equal representation from the regions to draft this standard and exemption process

Response:
a.) With the proposed revisions to the definition of BES, at this time, the SDT does not contemplate adding any additional definitions beyond BES.
b.) FERC Order No. 743 provides specific direction on the elimination of the regional discretion which is allowed under the current definition of the Bulk
Electric System. The SDT fully intends to be responsive to the Commission directives.
c.) In forming the SDT, NERC staff has utilized the criteria established in the NERC Standard Drafting Team Scope Document, which states: ‘Representation

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from as many NERC Regions as possible’.
North Carolina EMC

The BES definition for radial facilities serving only load with one source should be clarified to include radial
facilities with the potential ability to be served from more than one source, but always operated with an
"opening point" that makes it radial. If the entity can demonstrate that it always operates in this fashion, either
by producing switching orders indicating such operation or other evidence such as documentation of open
and tagged switches, etc., then it should be considered to be in full compliance with the radial BES definition
exemption.

Response: The DBES SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that
establishes the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed as part of the definition
of BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The SDT has revised the definition but is retaining the single source designation.
ReliabilityFirst

March 30, 3011

•

ReliabilityFirst would like to see this as a simple easy-to-follow definition. The exclusion process needs to
be clear without room for discussion or interpretation.

•

There must be a common framework developed to apply the entire process that begins with a single
NERC-wide BES definition.

•

The definition should serve as a common approach for the identification of BES Elements and Facilities
that are subject to compliance that is married to the Registration Criteria.

•

The definition and approach for the determination must be repeatable

•

The method must clearly identify the BES elements for use by the industry.

•

In order to obtain consistency, the definition, application and criteria must be used across Regional Entity
boundaries.

•

The revised BES definition should be consistent with the Statement of Compliance Registry Criteria so as
not to create a conflict between the two, and could possibly simply reference the Criteria for issues such
as size of generating units (e.g., 20 MVA units and 75 MVA plants) included in the BES.

•

As stated in the FERC Order No. 743, the criteria for exemption should be included within the BES
definition, and the exemption process should contain only the procedure for submitting and determination

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of such. The exemption process should not contain a third set of criteria (in addition to the BES definition
and the Statement of Compliance Registry Criteria) in which to make a determination of facilities to be
monitored for compliance to standards.
•

With the revised BES definition containing specific requirements for inclusion in the BES, will the
separate Statement of Compliance Registry Criteria be needed?

Response: The SDT agrees and has considered your comments in the further development of the core definition and the exception criteria.
The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed as part of the definition of BES)
utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying
generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying BES and nonBES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or non-BES utilizing the
core definition and exception criteria would be candidates for application of the Exception Process where the technical justification would be required to
identify Elements as BES (inclusions) or non-BES (exclusions).
A revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBES SDT along
with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC staff. With
that in mind, the SDT agrees with the commenter in that the Exception Process should be a manageable process that is clear, unambiguous, repeatable, and
establishes consistency on a continent-wide basis.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception
Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which will enable the
industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception criteria, and
the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the directives in
Order No. 743 the decision was made to establish two teams working in close coordination to address the issues related to the project.
Any impact of the revised core definition, the exception criteria, or Exception Process on the current Registry Criteria will be addressed in the Implementation
Plan.
on behalf of Teck Metals Ltd.
on behalf of Catalyst Paper
Corporation

Parallel transmission lines from a single source (substation) to a single load should be excluded from the
BES, with the consent/request of the owner of the connected load (and/or all customers that constitute the
connected load).

Response: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes

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the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation facilities, radials, etc.). In the development of the exception criteria, the SDT has considered your comments.
City of Grand Island

a.) The NERC defined Adequate Level of Reliability is the governing factor on whether or not a facility really
has an impact on the BES. Currently the standards are applied far too broadly and numerous small
entities are needlessly involved. This project should pull the standards/compliance environment back to
entities that have a real impact.
b.) Exemption process should be termed “exception” process. Exception means not conforming to general
rule, whereas exemption primarily means exclusion. This process will be difficult to develop and
administer and is counterproductive to “bright line” philosophy. Thus the bright lines should be at a high
level resulting in fewer exceptions. The exception process must consider the impact of a fault or outage of
that facility on the Adequate Level of Reliability of the BES.
c.) The exception process development should be simultaneous to the BES definition project. It’s all one, not
two pieces. In addition if this is a direct impact on registration criteria, then that should be part of the
project as well.

Response:
a.) The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The SDT believes that this method of identification will provide the desired clarity requested by the industry
and directed by the Commission while ensuring that consistent results will be produced universally across the continent. In the development of the core
definition and the exception criteria, the SDT has considered your comments.
b.) The inconsistency of the use of ‘exemption’ vs. ‘exception’ in several documents has been identified by the SDT and the team has determined that
‘exception’ is the proper term to be used in reference to the Bulk Electric System definition and supporting processes.
The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ utilizes the same ‘bright-line’ criteria to provide
further guidance as to whether an Element is considered BES or non-BES (i.e. bright-line criteria for identifying generation Facilities, radials, etc.). The
tight linkage between the core definition and the exception criteria provides the framework for identifying BES and non-BES for the vast majority of the
Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or non-BES utilizing the core definition and
exception criteria would be candidates for application of the Exception Process where the technical justification would be required to identify Elements as

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BES (inclusions) or non-BES (exclusions).
c.) The development of the core definition of the BES and the exception criteria by the DBES SDT will be closely coordinated with the development of the
Exception Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which
will enable the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the
exception criteria and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be
responsive to the directives in Order No. 743, the decision was made to establish two teams working in close coordination to address the issues related to
the project.
Any impact of the revised core definition, the exception criteria or Exception Process on the current Registry Criteria will be addressed in the
Implementation Plan.
Occidental Energy Ventures Corp

Demand Side Management. One commenter has apparently suggested that “Demand Side Management”
relied on to provide Contingency Reserves be included in the BES definition. On the surface, this seems
reasonable. However, this would possibly subject aggregators of DSM resources to registration as a yet
unknown resource type. The DSM resources could be located on lower voltage distribution systems that
should not be part of the BES. Once again, the issue of DSM registration is being pursued under a separate
NERC initiative and should be resolved by that process rather than a broadening of the definition of BES
which forces registration of entities not currently registered. This also could provide a disincentive for potential
DSM development, which the Federal Energy Regulatory Commission (FERC) is on record as trying to foster
as a peak shaving resource. When the issues surrounding DSM as a resource are resolved by due process,
any recommendations could include a change to the definition of BES, if actually required. Finally, this issue
is not part of the FERC directives for changing the BES definition.
Self-Generation and Cogeneration. One commenter has apparently suggested that self-generation as
currently defined and excluded in the Statement of Compliance Registry should not be excluded from the
definition of BES based on the “immediate-term impact on reliability.” This same commenter notes that, in
order to be excluded under the current BES definition, the self-generation is required to purchase back-up
(stand-by) power for the generation in case of an outage. Paying for this standby power (which is essentially
“extra” reserve power) is one reason for allowing the self-generation to be excluded from the BES. Once
again, subjecting self-generation/cogeneration to NERC regulatory requirements is not one of the directives
from the FERC concerning the BES definition and could provide a disincentive for cogeneration, which has
been historically supported by FERC and the federal government. Hence, suggestions such as this are out of
the scope of this process.

Response: The SDT has established basic goals and assumptions that will be used to guide the development of the BES definition and supporting documents.
The assumptions include: ‘The revised definition will not significantly expand or contract what are currently considered BES Elements, nor will the revised

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definition drive entity registration or de-registration. Based on these goals and assumptions the overall impact of the revised definition is expected to be minimized
for the majority of the Regions and Registered Entities. The SDT will consider your comments in the further development of the core definition, the exception
criteria and the Exception Process.
Glacier Electric Cooperative

I highly encourage the development of a method that utilizes engineering analyses to more accurately define
which elements are truly significant to the BES and which are not. Thanks for taking on the challenge to
improve the BES definition.

Response: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes
the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The SDT believes that this method of identification will provide the desired clarity requested by the industry and
directed by the Commission while ensuring that consistent results will be produced universally across the continent. exception criteria
Entergy Services

a.) The following are Entergy’s comments concerning the scope and implementation of the requested work,
the draft SAR, draft standard, draft criteria, draft exemption criteria, exemption process, and
implementation process. We suggest the SAR ad the standard development be revised to reflect the
comments below. In particular, we believe there are several parts to the scope of this project.
First, the development of the revised definition of the BES including all inclusion / exemption criteria and
the development of the implementation plan for that revised definition should be developed through the
Standards Development Process. All future inclusion / exemption criteria would also be developed
through the Standards Development Process. The process for changing the Rules of Procedure should
be used for the development, approval and application of the process for obtaining an exemption of
specific facilities. It would be helpful, but not required, that the development of the standard and the
changes to the ROP proceed together.
b.) We suggest there be one continent-wide definition of BES with no exemption criteria specific to a
particular region...
DEFINITION OF BES, INCLUSION CRITERIA and EXEMPTION CRITERIA We suggest the definition of
BES be the following: Bulk Electric System: All Transmission and Generation Elements and Facilities
conforming to the Inclusion Criteria and Exemption Criteria identified below. Elements and Facilities
operated at voltages of 100kV or higher may be excluded and Elements and Facilities operated at
voltages less than 100kV may be included if approved through the BES definition exemption process
included in the NERC Rules of Procedure.
INCLUSION CRITERIA1. All transmission and generation elements and facilities operated at voltages of

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100 kV or higher,
2... Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators,
with both primary and secondary windings of 100 kV or higher;
3. Individual generation resources (including GSU transformers and the associated generator
interconnecting line lead(s)) greater than 20 MVA (gross nameplate rating) directly connected via a stepup transformer(s) to Transmission Facilities operated at voltages of 100 kV or above;
4. Generation plants (including GSU transformers and the associated generator interconnecting line
lead(s)) with aggregate capacity greater than 75 MVA (gross nameplate rating) directly connected via a
step-up transformer(s) to Transmission Facilities operated at voltages of 100 kV or above;
5. Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission
Operator’s (TOP’s) restoration plan;
6. Transmission Elements or Facilities operated at voltages below 100kV where the exemption process
deems the Element or Facility to be included in the BES;
7. Individual generation resources greater than 20 MVA (gross nameplate rating) directly connected via a
step-up transformer(s) to Facilities operated at voltages below 100kV where the exemption process
deems the generation resources to be included in the BES; and
8. Generation plants with aggregate capacity greater than 75 MVA (gross nameplate rating) directly
connected via a step-up transformer(s) to Facilities operated at voltages below 100kV where the
exemption process deems the generation plants to be included in the BES.
EXEMPTION CRITERIA1. Any radial Transmission Element or System, connected from one
Transmission source to a Load-serving Element and/or generation resources not included in items 2, 3, 4,
6, and 7 above are excluded from the BES;
2. Elements and Facilities identified through application of the exemption process, consistent with the
criteria, where the exemption process deems that the Element or Facility should be excluded from the
BES (with concurrence from the ERO); and
3. Generating plant control and operation functions which include relays and systems that control and
protect the unit for boiler, turbine, environmental, and/or other plant restrictions.
IMPLEMENTATION PLAN FOR REVISED DEFINITION OF BES The Standard Drafting Team will
develop for industry comment an Implementation Plan for the revised definition of BES.

Response:

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a.) The NERC Standard Processes Manual is the governing document for the development of the revised BES definition and exception criteria. The SDT is
continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall
starting point for assessing BES and non-BES Elements. The ‘exception criteria’ (now proposed for inclusion in the definition of BES) utilizes the same
‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e. bright-line criteria for identifying generation
Facilities, radials, etc.).
The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBES SDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC
staff.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the
Exception Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which
will enable the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the
exception criteria and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be
responsive to the directives in Order No. 743, the decision was made to establish two teams working in close coordination to address the issues related
to the project.
b) FERC Order No. 743 provides specific direction on the elimination of the regional discretion which is allowed under the current definition of the Bulk
Electric System. The SDT fully intends to be responsive to the Commission directives.
The SDT has considered your comments in the further development of the core definition and the exception criteria. See the proposed revised definition of
BES with its lists of “Inclusions” and “Exclusions.”
Snohomish County PUD

March 30, 3011

While we recognize that the Standards Drafting Team is a technical body and is not charged with interpreting
legal doctrine, we nonetheless urge the Drafting Team to bear in mind the statutory limitations on the
definition of the BES. If the BES definition is drafted with these limits in mind, the process will more easily
meet with industry acceptance. If the BES definition adopted by the drafting team fails to meet these limits,
by contrast, its efforts are likely to result in extended litigation that will be counterproductive to the goal of
improving the reliability of the bulk delivery system. The definition of “bulk-power system” adopted by
Congress in Section 215 of the Federal Power Act is the ultimate source of the Standards Drafting Team’s
authority and the Team should therefore pay particular attention to that statutory definition:The term ‘bulkpower system’ means-(A) Facilities and control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof); and(B) Electric energy from generation facilities needed
to maintain transmission system reliability. The term does not include facilities used in the local distribution of
electric energy. This definition, and in particular the language italicized above, imposes clear restrictions on
the definition to be developed by the Drafting Team.

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These restrictions are:
a. Only facilities “necessary for” the operation of the interconnected bulk transmission network can be
included in the BES. Snohomish believes the most logical way to determine whether facilities are “necessary
for” operation of the bulk system is through engineering-based studies demonstrating that particular Facilities
or Elements play a material role in the operation of the bulk grid.
b. Generation facilities can be included in the BES only if they are “needed to maintain” the reliability of the
bulk system. Accordingly, as noted above, the thresholds used in the NERC Statement of Registry
Compliance are not determinative of whether a generator is necessary to maintain bulk system reliability.
That determination is an engineering-based assessment and the fact that a generator may exceed the 20 MW
capacity threshold in the Registry Statement does not mean that the generator is “needed to maintain” bulk
system reliability. It may well not be.
c. “Reliability” was also given a specific meaning by Congress when it drafted Section 215. Specifically, the
statute defines “reliable operation” to mean “operating the elements of the bulk-power system within
equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation,
or cascading failures of such system will not occur as a result of sudden disturbances, including . . .
unanticipated failure of system elements.” Accordingly, the BES definition should focus on facilities that are
necessary to ensure that the bulk transmission system does not suffer instability, uncontrolled separation, or
cascading failures. Facilities that do not threaten these kinds of severe consequences should not be included
in the BES.
d. The definition explicitly excludes “facilities used in the local distribution of electric energy.” The definition
adopted by the Standards Drafting Team must therefore unequivocally exclude all local distribution facilities.
In light of these statutory constraints, Snohomish supports as part of the Standards Drafting Team’s process
the creation of a categorical exclusion from the BES for systems that meet NERC’s historical definition of
Local Network. As explained in more detail below, Local Networks are operated to provide service to specific,
geographically-limited service areas and do not affect the reliable operation of the bulk transmission system.
Accordingly, there is no good reason to include Local Networks in the BES and to do so would be contrary to
the language in the statute discussed above. Historically, NERC employed a definition of “Local Networks”
and NERC’s “Bulk Electric System” definition distinguished between the “Bulk Transmission System” and
“Sub-transmission.” More recently, those distinctions have been lost, diverting attention away from critical
elements of the transmission system that, if they fail, threaten cascading outages or other large-scale events,
and increasing attention to facilities that, if they fail, threaten only to disrupt service in a localized areas. The
Standards Drafting Team can remedy this over breadth problem by categorically excluding facilities meeting
the definition of “Local Networks” from the BES definition. Until a few years ago, NERC used the following
definition of “Local Network”: Local Network- a non-radial portion of a bulk electric system whose customers
may be interrupted for the loss of a single transmission element (100 kV or more). This loss of load is only

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allowed in those rare circumstances when it is impractical (e.g., long transmission distances, extremely high
costs with low benefits) to avoid interruption of service to a portion or all of the customers in the network due
to the network being directly connected to or supplied by the faulted transmission system element (e.g.,
generator, transmission circuit, transformer). The resulting customer interruption should be of relatively low
probability of occurrence and limited in magnitude (less than 100 MW). The interruption of such local network
customers shall not impact the overall security of the interconnected transmission systems. The term Local
Network is currently used in the NERC TPL Reliability Standard. However the definition is no longer defined
in the NERC Standard Glossary of Terms. The important distinctions between Local Networks and the Bulk
Electric System have been further obscured by changes in NERC’s BES definition. The “Bulk Electric
System” definition that appeared in the Glossary of Terms reference document approved by both the NERC
EC and OC at a joint meeting of those committees on July 16, 1996, distinguished between “Transmission”
and “Sub-transmission”: Bulk Electric System - A term commonly applied to the portion of an electric utility
system that encompasses the electrical generation resources and bulk transmission system. Where
Transmission - An interconnected group of lines and associated equipment for the movement or transfer of
electric energy between points of supply and points at which it is transformed for delivery to customers or is
delivered to other electric systems. Bulk Transmission - A functional or voltage classification relating to the
higher voltage portion of the transmission system. Sub-transmission - A functional or voltage classification
relating to the lower voltage portion of the transmission system. The current version of the BES definition
does not, by contrast, make such a distinction: Bulk Electric System - As defined by the Regional Reliability
Organization, the electrical generation resources, transmission lines, interconnections with neighboring
systems, and associated equipment, generally operated at voltages of 100 kV or higher. Radial transmission
facilities serving only load with one transmission source are generally not included in this definition. The
definitional changes have diverted attention away from the systems that pose the greatest risks of cascading
outages and toward systems that do not threaten such widespread reliability impacts. Protecting the electric
system from wide-spread cascading outages and focusing on protecting equipment and isolating cascading
outages has historically been the primary goal of NERC reliability efforts and, as FPA Section 215 requires,
should remain so now and in the future. It is clear, however, that there are real distinctions between “Bulk
Transmission,” “Sub-transmission,” and “Local Networks” in terms of their impacts on bulk system reliability.
We propose that, in order to restore these important distinctions, WECC categorically exclude systems
meeting the definition of Local Network from its BES definition. Doing so will refocus the NERC-WECC
reliability mission on those systems that most effect bulk system reliability, while excluding from the BES
ambit those systems whose impacts are purely local.
As noted above, Snohomish has participated in and supports the work of the WECC BESDTF. The
BESDTF’s current proposal contains a categorical exclusion for Local Networks along the lines of the one we
advocate here and the BESDTF has developed an extensive factual and technical record supporting its
approach. We urge the Standards Drafting Team to follow that approach.

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Response: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes
the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The SDT believes that this method of identification will provide the desired clarity requested by the industry and
directed by the Commission while ensuring that consistent results will be produced universally across the continent. In the development of the core definition and
the exception criteria, the SDT has considered your comments.
United Illuminating Company

Any technical definition should provide the means to differentiate facilities used in local distribution since
these facilities are excluded from the statutory definition of bulk-power system. The definition of BES should
be very broad or bright.

Response: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes
the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The SDT believes that this method of identification will provide the desired clarity requested by the industry and
directed by the Commission while ensuring that consistent results will be produced universally across the continent. In the development of the core definition and
the exception criteria, the SDT has considered your comments.
Orange and Rockland Utilities,
Inc.

a.) Proposed definitions to be added to the NERC Glossary of Terms: BES Exemption Process: The review
processes for (a) excluding facilities and elements from the BES that are determined not to be necessary
to support bulk power system reliability (e.g., radial elements), and (b) including Elements operated at
voltages below 100 kV that are determined to be necessary to support bulk power system reliability. By
identifying all such BES and non-BES facilities and elements, the BES Exemption Process will establish
the Points-of-Demarcation between Facilities and BES Elements and non-BES facilities and elements.
Point-of-Demarcation: A physical point and/or electrical connection between facilities and BES Elements
and non-BES facilities and elements, e.g., the upstream terminals of a disconnect switch (or a buss
connection) representing the boundary between a BES supply bus and a non-BES radial feeder.
b.) The BES exemption process has not yet been finalized or approved. So, it is somewhat difficult to know a
priori whether any element, elements or a group of elements or facilities should or should not be
classified as part of the BES definition.
c.) This document uses both “exemption process” and “exception process”. Recommend that the
phraseology be standardized on “exception process” as the exception (not the exemption) can be to
include or exclude elements and facilities.

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d.) It is envisioned that the BES Exemption Process will contain 3 sub-processes; one for Exclusion, one for
Exemption, and one for Inclusion. Each sub-process will establish provisions and guidelines for the
three different tasks. In order to ensure consistency across the continent, it is our view that NERC should
be the facilitator of these processes. NERC may choose to have some of these tasks performed at the
regional levels through the existing delegation agreements.
e.) The BES Exemption Process must be an active and ongoing aspect of the ERO program. With the
addition of new or deletion of existing Transmission and Generation Elements, facilities, or systems. It
needs to be recognized that Exclusions, Inclusions, and Exemptions might need alteration over time. By
establishing appropriate guidelines and processes, the ERO will be able to monitor and maintain
information of what is the Bulk Electric System, or BES.

Response:
a.) The SDT is not currently contemplating any additional definitions beyond BES. In regards to the term “BES Exemption Process’; it has been determined
that the process will reside in the NERC Rules of Procedure (ROP) and therefore it seems logical that the purpose of the process would be defined within
the boundaries of the NERC ROP.
b.) Exception criteria Agree. The Exemption Process is being developed by a separate team and will be posted for stakeholder comment.
c.) The inconsistency of the use of ‘exemption’ vs. ‘exception’ in several documents has been identified by the SDT and the team has determined that
‘exception’ is the proper term to be used in reference to the Bulk Electric System definition and supporting processes.
d.) The ‘Exception Process’ will be developed by the NERC Rules of Procedure Team while coordinating with the DBESSDT. The ‘Exception Process’ and
the responsibilities associated with the implementation and oversight will be defined by the NERC Rules of Procedure Team. Based on the language
contained in FERC Order No. 743, there are Commission expectations associated with the process oversight by the ERO and allowances for the
delegation of responsibilities to Regional Entities as appropriate, while ensuring the process is clear and capable of being applied consistently, objectively,
and uniformly across all regions. Note, however, that the drafting team has revised the definition of BES so that it now includes the exceptions (both
inclusions and exclusions) stakeholders have already proposed be applied to the 100 kV bright line threshold.
e.) The SDT agrees that the Bulk Electric System is dynamic and that the implementation and continued application of the BES Definition and supporting
processes will require active oversight and management to ensure that changing conditions (i.e., operational & new construction) surrounding the Bulk
Electric System will be addressed and result in proper evaluation and identification of BES & non-BES Elements.
American Transmission company

March 30, 3011

1. ATC suggests that once the term “exemption” is replaced with the term “exception”, then consider
modifying the BES definition wording to, “All Transmission and Generation Elements and Facilities operated
at voltages of 100 kV or higher, necessary to support bulk power system reliability. Elements and Facilities

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operated at voltages of 100kV or higher, including Radial Transmission systems, may be excluded through
the BES definition exception process and Elements and Facilities operated at voltages less than 100kV may
be included through the BES definition exception process”.
2. The “Concept Paper” does not specifically call out Transmission Lines above 100 kV as in the BES
definition (the proposed definition does, however) and there is a circular exemption criteria in the concept
paper. In criterion #2, it refers to the exemption process "consistent with the criteria". The criteria exempt
generating plant controls and Transmission Elements or Systems that are radial to a load or generator not
included in the BES List. However, the BES list is defined prior to the criteria in the concept paper. Exception
criterion #1 points to BES list elements #6 and #7, which in turn, refer to the exception process. But, the
exemption criteria never define how to exempt the elements referred to in #6 and #7.
3. The revised definition of the BES and exception process does not address a timeframe for the
implementation of this standard once approved, allowing enough time for the entities to provide justification,
and then make the necessary changes to their internal programs?
4. How often would a Registered Entity revisit this Exception Process? ATC can envision a scenario where
they are doing that every year or two because the loads, generation and transmission changes. The process
should also allow for multi-year distinctions for exceptions. In other words, if a Registered Entity gets a facility
excluded, then that exclusion should be allowed for 3 or more years. Annual certifications and approval are
two restrictive.
5. ATC believes the exception criteria needs to be developed by the SDT. NERC Staff should focus on the
process (identification, notification, appeal and rights) but the SDT is in the better position to develop the
technical piece of the exception criterion.
6. ATC also supports the comments as submitted by EEI REAC on the Draft Concept Paper on the Definition
of BES Project 2010-17.

Response:
1. The SDT has considered your comments in the further development of the core definition and the exception criteria. The drafting team has revised the
definition of BES so that it now includes the exceptions stakeholders have already proposed be applied to the 100 kV bright line threshold. The word,
“exemption” is not used in the proposed definition of BES.
2. The SDT has considered your comments in the further development of the core definition and the exception criteria. Please see the revised definition of
BES.
3. The Implementation Plan will need to address the impact of the revised BES definition and exception criteria, the Exception Process (ROP), and the

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regional Transition Plans on affected entities and provide sufficient time to ensure a smooth transition into the realm of mandatory and enforceable
Reliability Standards.
4. The ‘Exception Process’ will be developed by the NERC Rules of Procedure Team while coordinating with the DBESSDT. The DBESSDT recognizes that
the Bulk Electric System is dynamic and that the implementation and continued application of the BES Definition and supporting processes will require
active oversight and management to ensure that changing conditions (i.e., operational & new construction) surrounding the Bulk Electric System will be
addressed and result in proper evaluation and identification of BES & non-BES Elements. The time frames associated with the ‘review’ processes will be
determined by the NERC ROP Team. The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by
NERC staff and governed by current practice for administering such revisions.
5. The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying
BES and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or nonBES utilizing the core definition and exception criteria would be candidates for application of the Exception Process where the technical justification would
be required to identify Elements as BES (inclusions) or non-BES (exclusions).
The ‘Exception Process’ will be developed by the NERC Rules of Procedure Team while coordinating with the DBES SDT.
6. See responses to EEI comments.
The Dow Chemical Company

Dow has reviewed and generally supports the comments prepared by The Electricity Consumers Resource
Council (ELCON).

Response: See response to ELCON comments.
National Rural Electric
Cooperative Association
(NRECA)

March 30, 3011

a.) BES definition exemption criteria must be developed by the same SDT that is modifying the BES
definition and through the standards development procedure. The BES exemption criteria must not be
developed by a separate group outside of the standard development procedure, e.g., through a NERC
Rules of Procedure (ROP) modification process as is currently proposed in the SAR. The BES exemption
process, not criteria, can be included in the ROP by utilizing the process for making such modifications to
the ROP. The BES definition exemption process should refer to the procedure for applying for such an
exemption, not the criteria that such an exemption application would be based upon. It is critical for the
final SAR to provide clarity as it relates to what is considered exemption criteria and exemption process.

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b.) We appreciate the work of the Regional BES Definition Coordination Group, however, this group must
conclude its work now that a SAR has been proposed and is posted for comment. This group can provide
comment on this SAR and future products from the SDT in same way as any other stakeholder can
provide comment. Having a parallel effort led by Regional Entity staff, outside the formal Project 2010-17
SDT process, will create confusion and potentially cause inefficient use of industry resources. All efforts
should be focused on the formal standard development activities including related future comment and
ballot periods. Compliance registry criteria should only be reviewed and potentially modified if specifically
needed to implement a modified BES definition and associated exemption criteria.
c.) The SDT is tasked with addressing definition modifications to ensure consistent and uniform application
of the BES definition across the Regional Entities. The focus of the SDT's work should first be on the
BES definition and exemption criteria. Any Compliance Registry Criteria modifications would have to be
approached very carefully as it was developed through a lengthy stakeholder consensus process.

Response:
a.) The NERC Standard Processes Manual is the governing document for the development of the revised BES definition and exception criteria. The SDT is
continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall
starting point for assessing BES and non-BES Elements. The ‘exception criteria’ (now proposed for inclusion in the definition of BES) utilizes the same
‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation
Facilities, radials, etc.).
The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC
staff.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the
Exception Process by the NERC ROP team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which
will enable the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the
exception criteria, and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be
responsive to the directives in Order No. 743 the decision was made to establish two teams working in close coordination to address the issues related to
the project.
b.) When the NERC Standards Committee accepted the SAR and established the SDT, the RBESDCG acknowledged that the primary development of
definition and supporting documents had shifted from the RBESDCG to the SDT. The RBESDCG agrees that parallel efforts will result in inconsistencies
and disruption of the SDTs efforts. Therefore, the RBESDCG forwarded all applicable work products to the SDT and to the NERC ROP Team for
consideration. Going forward, the RBESDCG will support the development of the definition, supporting documents, and the revisions to the ROP by
collectively participating in the respective development processes (i.e., providing consensus comments to posting and participating in the associated

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balloting process).
c.) Any impact of the revised core definition, the exception criteria, or Exception Process on the current Registry Criteria will be addressed in the
Implementation Plan.
City of Austin dba Austin Energy

The word “exemption” in the last line is confusing. Lines above 100kV would be “exempted” from inclusion as
part of the BES. Lines below 100kV would be “added” to the BES (under certain circumstances) which,
technically, is not an “exemption.” (In fact, the Word document on the NERC web page refers to the process
as an “Exception Process”) AE recommends the following language: Bulk Electric System: All Transmission
and Generation Elements and Facilities operated at voltages of 100 kV or higher necessary to support bulk
power system reliability. Elements and Facilities operated at voltages of 100kV or higher, including Radial
Transmission systems, and Elements and Facilities operated at voltages less than 100kV may be included if
approved through the process described in the BES Definition Exception Process.

Response: The inconsistency of the use of ‘exemption’ vs. ‘exception’ in several documents has been identified by the SDT and the team has determined that
‘exception’ is the proper term to be used in reference to the Bulk Electric System definition and supporting processes. In the development of the core definition and
the exception criteria, the SDT has considered your comments. Please see the revised definition of BES – it now includes a list of both “Inclusions” and
“Exclusions” as part of the definition and no longer references an exemption (or exception) process).
Duke Energy

There should be a provision for the Planning Coordinator or Transmission Planner to include individual
generators and generation plants that are not included in these criteria through a technical evaluation, either
in the definition or in the inclusion of facilities below 100 kV portion of the exemption process. For example,
generating facilities connected to generator step up transformers below 100 kV that have a demonstrated
ability to have a significantly adverse affect on the reliability on the bulk power grid or a major urban load
center should be included.

Response: The SDT agrees with the commenter, in that any Exception Process should establish a process for exceptions from and inclusions to the BES. As
stated in FERC Order No. 743, P83 “The Commission’s proposed approach to addressing these concerns will enable affected entities to pursue exemptions for
facilities they believe should not be included in the bulk electric system, and also will allow Regional Entities to add facilities below 100 kV they believe should be
included”. The Regional Entities currently have the authority to include Elements operated at voltages below 100 kV that are deemed necessary for the reliable
operation of the BES. The Order does not eliminate this authority, but rather emphasizes the need to maintain the Regional Entity’s ability of establishing
inclusions to the BES through the Exception Process. Under these circumstances, the SDT feels that a Planning Coordinator or Transmission Planner could
pursue inclusion of selected Elements into the BES by lobbying with their Regional Entity. exception criteria
BGE

a.) NERC should use the FERC-approved standards development process for developing the technical
criteria for both the BES definition and exemptions process. We view this as a single exercise. BGE

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feels joint development of the BES Definition & Exception Process under a single SDT would be
preferable. The standards drafting project should ensure that the definition expressly incorporates these
exclusions for facilities below 100 kV. Entities should not have to seek an exemption for facilities below
100 kV or for radial lines. They should be clearly excluded in the BES definition itself.
b.) We encourage the drafting team to embrace a design concept that seeks to maximize the “brightness” of
bright line criteria. The BES exemptions process should contemplate very few exemptions. The TFE
process is an example of a process not to be repeated here.

Response:
a.) The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception
Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which will enable
the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception criteria
and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the
directives in Order No. 743 the decision was made to establish two teams working in close coordination to address the issues related to the project.
b.) The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying
BES and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or
non-BES utilizing the core definition and exception criteria would be candidates for application of the Exception Process where the technical justification
would be required to identify Elements as BES (inclusions) or non-BES (exclusions).
City Water Light and Power
(CWLP) - Springfield, IL

Relative to the BES Definition Exclusion Process, CWLP has chosen to comment on the inclusion/exclusion
process as a whole. The current lack of detailed, firm administrative guidelines as well as an unambiguous
process for resolving disputes between parties involved in the process of adjudicating inclusions/exclusions is
problematic. It is CWLP’s belief that developing the proposed administrative framework for the process is
needed first. Focusing on the data to be submitted as shown in (1) and (2) above does not address the
scope, nature, and criteria applicable to the review of requests for inclusions/exclusions. Regardless, CWLP
feels strongly that the sole basis for approval or rejection of a request should be technical justification.
Speaking to the process in general, any inclusion or exclusion should be a specific request for a specific
facility; continent-wide, interconnect-wide, and region-wide applicability for inclusions/exclusions departs from
the intent of FERC Order 743 to establish a definition without regional variances.

Response: The SDT has considered your comments in the further development of the core definition and the exception criteria .

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The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying
BES and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or nonBES utilizing the core definition and exception criteria would be candidates for application of the Exception Process where the technical justification would be
required to identify Elements as BES (inclusions) or non-BES (exclusions).
A revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT along
with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC staff. With
that in mind, the SDT agrees with the commenter in that the Exception Process should be a manageable process that is clear, unambiguous, and repeatable
and establishes consistency on a continent-wide basis.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception
Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which will enable the
industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception criteria, and
the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the directives in
Order No. 743 the decision was made to establish two teams working in close coordination to address the issues related to the project.
Lewis County PUD

The ever increasing regulatory environment does little to improve electric reliability. Suggest that the BES
definition only include the most critical elements of the electric system and leave the smaller elements out of
the definition, e.g. less than 100kV and less than 150MVA.

Response: The SDT has established basic goals and assumptions that will be used to guide the development of the BES definition and supporting documents.
The assumptions include: ‘The revised definition will not significantly expand or contract what are currently considered BES Elements, nor will the revised
definition drive entity registration or de-registration. Based on these goals and assumptions the overall impact of the revised definition is expected to be minimized
for the majority of the Regions and Registered Entities. exception criteria
American Electric Power (AEP)

There needs to be more comprehensive BES nomenclature established that distinguishes among the
applicable primary-voltage equipment, the associated auxiliary equipment having an impact to the BES, and
the associated ancillary equipment having no electrical impact to the BES.
The draft versions of PRC-005-2, Protection System Maintenance, look to bring into scope “systemconnected station service transformers for generators that that are part of the BES”. These transformers are
not clearly included within the proposed BES criteria, and consistency must be obtained between the two

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documents.

Response: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes
the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying BES
and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or non-BES utilizing
the core definition and exception criteria would be candidates for application of the Exception Process where the technical justification would be required to identify
Elements as BES (inclusions) or non-BES (exclusions).
The SDT will be reviewing all NERC and Regional Reliability Standards to ensure that no conflicts have been established between the core definition, the
supporting documents and procedures, and the applicability or requirements in the standards.
Southern Company

a. The proposed definition includes the phrase "... necessary to support bulk power system reliability". The
exemption process should resolve the question related to precisely which transmission and generation
elements and facilities are necessary to support reliability of the bulk power system.
b. A clear definition of what is included in “Generation Elements and Facilities” is needed. Does it include
components other than the GSU transformer? As written, does the BES extend beyond the low voltage
side of a GSU transformer?

Response: The SDT has considered your comments in the further development of the core definition and the exception criteria.
a. The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying
BES and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or
non-BES utilizing the core definition and exception criteria would be candidates for application of the Exception Process where the technical justification
would be required to identify Elements as BES (inclusions) or non-BES (exclusions).
A revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC
staff. With that in mind, the SDT agrees with the commenter in that the Exception Process should be a manageable process that is clear, unambiguous,
repeatable, and establishes consistency on a continent-wide basis. We will forward your comment to the NERC ROP Team.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception

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Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which will enable
the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception
criteria, and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to
the directives in Order No. 743 the decision was made to establish two teams working in close coordination to address the issues related to the project.
b. The SDT is not contemplating any further definitions beyond BES based on the latest revision to the definition. Please see the revised definition of BES as
this incorporates more details about including specific generation elements.
Independent Electricity System
Operator

a. On the SAR, it indicates an SC approval date of December 8. It is misleading since the SC did not approve
the SAR; it only approved posting of the SAR for industry comment.
b. We have a concern with the concept paper on the exemption/inclusion criteria/process. Please see other
comments on that paper submitted separately.
c. We suggest use of consistent term between “exception” and “exemption”.
d. We suggest the exception/inclusion criteria to be included in the definition and developed/approved by the
balloting body. Determining these criteria via any other processes will not provide the industry the opportunity
to fully vet the criteria.
e. The SAR indicates that “...the definition drafting team will work closely with the team developing the BES
definition exemption process to develop a single coordinated implementation plan. It is also envisioned, that
the team working to develop the BES definition exemption process will solicit input from drafting teams,
stakeholders....” We find this confusing and have a concern that having two teams working on this
definition/criteria package leads to misalignment and confusion. Further, while the definition drafting team is
formed by a nomination process and appointed by the NERC Standards Committee, there is no transparency
and/or public announcement to solicit nominations for the team working to develop the exemption process.
We urge the NERC Standards Committee to direct the definition drafting team to also be responsible for
developing the exemption process, and include the exemption criteria as part of the definition hence
subjecting them to industry comment and balloting.

Response:
a. The default language in the form is misleading and implies that the NERC Standards Committee’s approval is required. Per the NERC Standard Process
Manual the Standards Committee authorizes posting of the SAR for industry comment. The DBES SDT will provide a recommendation to NERC
Standards Staff to revise the SAR form to read, "Date SC Authorized Posting the SAR”.
b. The SDT has considered your comments in the further development of the core definition and the exception criteria. Note that the revised definition of BES
now includes lists of criteria for both “inclusion” and “exclusion”.

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c. The inconsistency of the use of ‘exemption’ vs. ‘exception’ in several documents has been identified by the SDT and the team has determined that
‘exception’ is the proper term to be used in reference to the Bulk Electric System definition and supporting processes.
d. The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying
BES and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or
non-BES utilizing the core definition and exception criteria would be candidates for application of the Exception Process where the technical justification
would be required to identify Elements as BES (inclusions) or non-BES (exclusions).
e. The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ utilizes the same ‘bright-line’ criteria to provide
further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation Facilities, radials, etc.). The
tight linkage between the core definition and the exception criteria provides the framework for identifying BES and non-BES for the vast majority of the
Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or non-BES utilizing the core definition and
exception criteria would be candidates for application of the Exception Process where the technical justification would be required to identify Elements as
BES (inclusions) or non-BES (exclusions).
The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC
staff.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception
Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which will enable
the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception criteria
and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the
directives in Order No. 743, the decision was made to establish two teams working in close coordination to address the issues related to the project.
APPA

See text submitted under Question 12.

Response: See response to Q12.
Xcel Energy

March 30, 3011

It is not clear as to why the Reliability Assurer is included as an applicable entity in the SAR.

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Response: The NERC Functional Model Version 5 defines the role of the Reliability Assurer as: “The functional entity that monitors and evaluates the activities
related to planning and operations, and coordinates activities of functional entities to secure the reliability of the Bulk Electric System within a Reliability Assurer
area and adjacent areas”. Any revision to the definition of the Bulk Electric System could potentially expand or contract the ‘Reliability Assurer area’ which would
have a direct effect on the responsibilities indentified in the Functional Model.

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Consideration of Comments on the Revisions Made to the Definition of Bulk
Electric System — Project 2010-17
The Definition of Bulk Electric System Drafting Team thanks all commenters who submitted
comments on the revisions made to the definition of BES. The definition and supporting
documents were posted for a 30-day public comment period from April 28, 2010 through
May 27, 2010. The stakeholders were asked to provide feedback on the standards through
a special Electronic Comment Form. There were 154 sets of comments, including comments
from more than 279 different people from approximately 213 companies representing 10 of
the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Project2010-17_BES.html
The SDT has made numerous clarifying changes to the definition due to comments received:
•

The bright-line core definition has been revised to clarify that all Transmission
Elements at 100 kV or higher and Real Power and Reactive Power resources
connected at 100 kV or higher are to be included in the BES unless there is a
modification for a particular Element in the Inclusion or Exclusion lists.

•

An additional inclusion (I5) was developed for Reactive Resources and an additional
exclusion (E4) was developed to clarify that Reactive Resources that are owned by
retail customers for their own use are not to be included.

•

In Inclusion I1, deleted the Generator Step-Up and Phase Angle Regulating
transformer language, changed the wording from “windings” to “terminals”, and
added the terms “primary” and “secondary”.

•

Inclusion I2 has been eliminated and Inclusion I3 (now numbered as Inclusion I2)
has been revised to include generating resourceswith gross aggregate nameplate
rating per the ERO Statement of Compliance Registry Criteria for consistency
between the two documents.

•

The SDT agreed that Cranking Paths identified in a Transmission Operator’s
restoration plans are often composed of distribution system elements and has
removed the inclusion for Cranking Paths.

•

Inclusion I4 has been revised to eliminate the term ‘collector system.’

•

Within Exclusion E1, the SDT clarified the point of connection, removed the
automatic interrupting device, moved the concept of the normally open switch to a
note, and clarified the generation allowed within the system.

•

Within Exclusion E2, the SDT clarified the generation allowed within the system

•

Within Exclusion E3, the SDT eliminated the term “Distribution” in the label,
eliminated the provision which referred to automatic fault interrupting devices,
clarified the connection point of the local network, inserted a provision in the local
network exclusion to limit the operating voltage of the local network to 300 kV, and
effectively removed the comparison test between generation and minimum demand
of the local network.

•

Included in the core definition a statement that excludes facilities used in local
distribution of electric energy.

116-390 Village Blvd.
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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System —
Project 2010-17

Several commenters objected to simply carrying through the generation thresholds
from the ERO Statement of Compliance Registry Criteria as part of the revised
definition. However, no respondents provided technical justifications for changing
these values. Furthermore, the scope of this project deals mainly with responding to
FERC Orders 743 and 743a which clearly stated that the intent of the order was to
maintain the status quo and to only address those urgent issues identified in the
Orders. After consulting with the NERC Board of Trustees and the NERC Standards
Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic
justice with the mandated schedule. Therefore, the primary focus of the SDT efforts
will be to address the directives in Orders 743 and 743a. However, this does not
mean that the other issues will be dropped. Both the NERC Board of Trustees and
the NERC Standards Committee have endorsed the idea that the Project 2010-17
SDT take a phased approach to this project with a new Standards Authorization
Request (SAR) to address generation thresholds as well as several other issues that
have arisen from SDT deliberations. Issues such as what is necessary for the reliable
operation of the BES, whether the BES needs to be contiguous, possible
interconnection differences, who are users of the BES, and correlation of the
definition of BES and the ERO Statement of Compliance Registry Criteria will be
addressed with this new SAR. The proposed SAR has been posted for information
purposes only concurrent with the second posting of this project. A formal comment
period will follow.
The following minority opinions did not result in changes to the definition:
•

The SDT retained the inclusion for Blackstart Resources although some commenters
thought it should be deleted. The Commission directed NERC to revise its BES
definition to ensure that the definition encompasses all facilities necessary for
operating an interconnected electric transmission network. The SDT interprets this
to include operation under both normal and Emergency conditions, which include
situations related to blackstarts and system restoration. Blackstart Resources have
the ability to be started without support from the System or can be energized
without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability,
frequency, and voltage control. The associated resources of the electric system that
can be isolated and then energized to deliver electric power during a restoration
event are essential to enable the startup of one or more other generating units as
defined in the Transmission Operator’s system restoration plan. For these reasons,
the SDT continues to include Blackstart Resources indentified in the Transmission
Operator’s restoration plan as BES Elements.

•

The SDT considered commenters’ suggestions regarding allowance of some power
flow out of the local network, and concluded that strict limits precluding out-flow are
appropriate, particularly given that the local network comprises facilities that are
electrically parallel to the BES.

In addition, in response to comments received, the SDT has clarified the effective date in
the Implementation Plan.
The SDT proposes to move this project to the 45-day parallel comment and initial ballot
stage.

August 19, 2011

2

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System —
Project 2010-17

If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at herb.schrayshuen@nerc.net. In addition, there
is a NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
August 19, 2011

3

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System —
Project 2010-17

Index to Questions, Comments, and Responses
1.

The SDT has made clarifying changes to the core definition in response to industry
comments. Do you agree with these changes? If you do not support these changes or
you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. ......................................... 22

2.

The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................... 69

3.

The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I2? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................... 90

4.

The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I3? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................. 135

5.

The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I4? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................. 160

6.

The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I5? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................. 183

7.

The SDT has added specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E1? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................. 206

8.

The SDT has added specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E2? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................. 242

August 19, 2011

4

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System —
Project 2010-17

9.

The SDT has added specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E3? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................. 268

10.

The SDT is discussing an exclusion from the Bulk Electric System (BES) for small
utilities based on statements in Order No. 743 that FERC does not believe its
suggested approach to the BES definition and exemption process will have a
significant economic impact on a substantial number of small entities and that small
entities will not adversely impact the reliability of the Bulk Electric System. The SDT
has been made aware that organizations that are not presently required to be
registered by the NERC Statement of Compliance Registry Criteria would meet the
requirements to be registered as Transmission Owners given the current proposed
BES definition. These small utilities could use the Rules of Procedure (ROP) exception
process but this may be an issue that could be handled more appropriately through
the BES definition. This would alleviate the paperwork burden for these small utilities
and also avoid a possibly unnecessary and significant impact on the administration of
the ROP exception process during the transition period to the revised BES definition.
The proposed exclusion language is: Exclusion E4: Transmission Elements, from a
single Transmission source connected at a voltage of 100 kV or greater, owned by a
small utility whose connection to the BES is solely through this single Transmission
source, and without interconnected generation as recognized in the BES Designation
Inclusion Items I2, I3, I4, or I5. A small utility is recognized as an entity that
performs a Distribution Provider or Load Serving Entity function but is not required to
register as a Distribution Provider or Load Serving Entity by the ERO. Do you agree
with this approach and the proposed language? If not, please be specific in your
response with a technical reason for your disagreement and, if appropriate, suggested
language for such an exclusion if you agree in general but feel that alternative
language would be more appropriate. ............................................................... 340

11.

In Order No. 743, the Commission addressed the need to differentiate between
Transmission and distribution in the revised definition of the Bulk Electric System
(BES). Specifically, the Commission stated that local distribution facilities are to be
excluded from the BES. The SDT believes that it has excluded local distribution
facilities through the revised bright-line core definition and specific inclusions and
exclusions. Do you agree with this position? If not, please provide specific comments
and suggestions on what else needs to be addressed or added. ........................... 357

12.

Are you aware of any conflicts between the proposed definition and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement, or
jurisdictional issue? If so, please identify them here and provide suggested language
changes that may clarify the issue. .................................................................. 390

13.

Are there any other concerns with this definition that haven’t been covered in previous
questions and comments? ............................................................................... 410

August 19, 2011

5

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Mikhail Falkovich

Public Service Enterprise Group LLC

X

2

3

X

4

5

6

X

X

7

8

9

10

Additional Member Additional Organization Region Segment Selection
1. Clint Bogan

NPCC 5, 6

2. Ken Brown

RFC

1

3. Jeffrey Mueller

RFC

3

4. Peter Dolan

RFC

6

2.

Group
Additional Member

Guy Zito

Northeast Power Coordinating Council

Additional Organization

X

Region Segment Selection

1. Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC 3

2. Gregory Campoli

New York Independent System Operator

NPCC 2

3. Kurtis Chong

Independent Electricity System Operator

NPCC 2

4. Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5. Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6. Gerry Dunbar

Northeast Power Coordinating Council

NPCC 10

7. Mike Garton

Dominion Resources Services, Inc.

NPCC 5

August 19, 2011

6

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

8. Brian L. Gooder

Ontario Power Generation Incorporated

NPCC 2

10. Chantel Haswell

FPL Group, Inc.

NPCC 5

11. David Kiguel

Hydro One Networks Inc.

NPCC 1

12. Michael Lombardi

Northeast Utilities

NPCC 1

13. Randy MacDonald

New Brunswick Power Transmission

NPCC 1

14. Bruce Metruck

New York Power Authority

NPCC 6

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

16. Robert Pellegrini

The United Illuminating Company

NPCC 1

17. Si Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

18. Saurabh Saksena

National Grid

NPCC 1

19. Michael Schiavone

National Grid

NPCC 1

20. Wayne Sipperly

New York Power Authority

NPCC 5

21. Donald Weaver

New Brunswick System Operator

NPCC 1

Orange and Rockland Utilities

NPCC 1

22. Ben Wu

Group

Bill Middaugh

Additional Member

Tri-State Generation and Transmission
Association, Inc.
Additional Organization

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

2. Rick Ashton

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

3. Mark Graham

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

4. Chris Pink

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

5. Marlene Marquez

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

6. Mark Conner

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

7. Keith Carman

Group

4

5

6

X

X

7

8

9

10

X

X

Region Segment Selection

1. Michael Houglum

4.

3

NPCC 5

9. Kathleen Goodman ISO - New England

3.

2

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

Kevin Koloini

American Municipal Power and Members

X

X

X

Additional Member Additional Organization Region Segment Selection

August 19, 2011

7

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1. Steve Harmath

City of Orrville

5.

Scott Berry

Group
Additional Member

RFC

4

5

X

X

6

7

8

9

10

X

Region Segment Selection

1. Kevin Koloini

American Municipal Power, Inc.

RFC

4

2. Mark Ringhausen

Old Dominion Electric Cooperative RFC

4

3. Gary Wright

Allegheny Electric Cooperative

RFC

4

4. Mike Tracy

Hoosier Energy REC, Inc

RFC

1

5. Bob Thomas

Illinois Municipal Power Agency

RFC

4

6. Tom Connell

Indiana Municipal Power Agency

RFC

4

6.

Sammy Alcaraz

Group

3

4

Small Entity Working Group (SEWG)

Additional Organization

2

Imperial Irrigation District

X

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Jose Landeros

IID BES Working Gp

WECC

2. Epifano Martinez

IID BES Working Gp

WECC

3. David Barajas

IID BES Working Gp

WECC

4. Chris Reyes

IID BES Working Gp

WECC

5. Fernando Gutierrez

IID BES Working Gp

WECC

6. Chris Riven

IID BES Working Gp

WECC

7. Joel Fugett

IID BES Working Gp

WECC

8. Al Minor

IID BES Working Gp

WECC

9. Juan Carlos Sandoval IID BES Working Gp

WECC

7.

Group

Frank Gaffney

Florida Municipal Power Agency

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle

City of New Smyrna Beach FRCC

4

2. Greg Woessner

Kissimmee Utility Authority FRCC

3

3. Jim Howard

Lakeland Electric

FRCC

3

4. Lynne Mila

City of Clewiston

FRCC

3

5. Joe Stonecipher

Beaches Energy Services FRCC

1

August 19, 2011

8

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

6. Cairo Vanegas

Fort Pierce Utility Authority FRCC

4

7. Randy Hahn

Ocala Electric Utility

3

8.

Terry L. Blackwell

Group

FRCC

Santee Cooper

2

X

3

X

4

5

6

X

X

7

8

9

10

X

X

Additional Member Additional Organization Region Segment Selection
1. S. T. Abrams

Santee Cooper

SERC

1

2. Rene Free

Santee Cooper

SERC

1

3. Vicky Budreau

Santee Cooper

SERC

1

SERC

1

4. Jim Peterson

Santee Cooper

9.

Group

David Taylor

NERC Staff Technical Review

10.

Group

Mark Byrd

NERC Transmission Issues Subcommittee
(TIS)

X

X

Additional Member Additional Organization Region Segment Selection
1. See TIS Roster

11.

Group

Louis Slade

Dominion

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Michael Gildea

Electric Market Policy

SERC

1, 3, 5, 6

2. Connie Lowe

Electric Market Policy

RFC

5, 6

3. Mike Garton

Electric Market Policy

MRO

5, 6

4. Matt Woodzell

F&H

SERC

5

5. Chip Humphrey

F&H

RFC

5

6. Jeff Bailey

Nuclear

NPCC 5

7. Mike Crowley

Electric Transmission

SERC

12.

Group

Robert Rhodes

1, 3

SPP Standards Review Group

X

Additional Member Additional Organization Region Segment Selection

August 19, 2011

9

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1. John Allen

City Utilities of Springfiled SPP

1, 4

2. Matt Bordelon

CLECO

SPP

1, 3, 5, 6

3. Michelle Corley

CLECO

SPP

1, 3, 5, 6

4. Louis Guidry

CLECO

SPP

1, 3, 5, 6

5. Jonathan Hayes

SPP

SPP

2

6. Tom Hestermann

Sunflower Electric

SPP

1, 5

7. Valerie Pinamonti

AEP

SPP

1, 3, 5

8. Mike Richardson

AEP

SPP

1, 3, 5

13.

Group
Additional Member

Carol Gerou

3

4

5

6

7

8

9

10

MRO's NERC Standards Review Forum

Additional Organization

X

Region Segment Selection

1. Mahmood Safi

Omaha Public Utility District

MRO

1, 3, 5, 6

2. Chuck Lawrence

American Transmission Company

MRO

1

3. Tom Webb

Wisconsin Public Service Corporation MRO

3, 4, 5, 6

4. Jodi Jenson

Western Area Power Administration

MRO

1, 6

5. Ken Goldsmith

Alliant Energy

MRO

4

6. Alice Ireland

Xcel Energy

MRO

1, 3, 5, 6

7. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

8. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

9. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

10. Scott Nickels

Rochester Public Utilties

MRO

4

11. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

12. Marie Knox

Midwest ISO Inc.

MRO

2

13. Lee Kittelson

Otter Tail Power Company

MRO

1, 3, 4, 5

14. Scott Bos

Muscatine Power and Water

MRO

1, 3, 5, 6

15. Tony Eddleman

Nebraska Public Power District

MRO

1, 3, 5

16. Mike Brytowski

Great River Energy

MRO

1, 3, 5, 6

17. Richard Burt

Minnkota Power Cooperative, Inc.

MRO

1, 3, 5, 6

August 19, 2011

2

10

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

14.

Group

Additional Member

Charles W. Long

SERC Planning Standards Subcommittee

Additional Organization

3

4

5

6

7

8

9

10

X

X

Region Segment Selection

1. Pat Huntley

SERC Reliability Corporation

SERC

10

2. John Sullivan

Ameren Services Co.

SERC

1

3. Charles Long

Entergy Services, Inc.

SERC

1

4. Philip Kleckley

South Carolina Electric & Gas Co SERC

1

5. Bob Jones

Southern Company Services

SERC

1

6. Darrin Church

Tennessee Valley Authority

SERC

1

15.

Don Mazuchowski

Group

2

Michigan Public Service Commission(MPSC)

X

Additional Member Additional Organization Region Segment Selection
1. Angie Butcher

MPSC

16.

Jason Marshall

Group

Additional Member

RFC

9

ACES Power Participating Members

Additional Organization

X

X

X

X

X

X

Region Segment Selection

1. Chris Lang

Golden Spread Electric Cooperative ERCOT 3, 4, 6

2. Chris Bradley

Big Rivers Electric Cooperative

3. James Jones

Southwest Transmission Company WECC 1

4. Liz Hayden

Arizona Electric Power Cooperative WECC 3, 5, 6

17.

Jim Case

Group

X

SERC

1, 3, 5, 6

SERC OC Standards Review Group

Additional Member Additional Organization Region Segment Selection
1. Gerald Beckerle

Ameren

1, 3

2. Scott Brame

Ameren

1, 3

3. Mike Hirst

Cogentrix

5, 6

4. Dan Roethemeyer

Dynegy

5, 6

5. Tim Hattaway

PowerSouth

1, 3, 5, 9

6. Randy Castello

Alabama Power

1, 3, 5

7. Danny Dees

MEAG

1, 3, 5, 9

August 19, 2011

11

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

8. Robert Thomasson

BREC

1, 3, 5, 9

9. Bob Dalrymple

TVA

1, 3, 5, 9

10. Andy Burch

EEI

1, 5

11. David Trego

Fayetteville PWC

1, 3, 4, 9

12. Reggie Wallace

Fayetteville PWC

1, 3, 4, 9

13. Patrick Woods

EKPC

1, 3, 5, 9

14. Darrin Adams

EKPC

1, 3, 5, 9

15. George Carruba

EKPC

1, 3, 5, 9

16. Alvis Lanton

SIPC

1, 3, 5

17. Brad Young

LGE/KU

1, 3, 5

18. Melinda Montgomery Entergy

1, 3

19. Steve McElhaney

SMEPA

1, 3, 5, 9

20. Marc Butts

Southern

1, 3, 5

21. John Troha

SERC

10

18.

Group

David Curtis

Hydro One Networks Inc

X

2

3

4

5

X

6

7

8

9

10

X

Additional Member Additional Organization Region Segment Selection
1. Bing Young

Transmission Development NPCC 1

2. David Kiguel

Hydro One Distribution

NPCC 3

3. Oded hubert

Regulatory Affairs

NPCC 9

19.

Barry Lawson

Group

National Rural Electric Cooperative
Association (NRECA)

X

Barbara Hindin

Edison Electric Institute

X

Richard Malloy

Idaho Falls Power

X

X

X

1. Patti Metro

20.
1.

Group

See EEI member
list at www.eei.org

21.

Individual

August 19, 2011

12

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Jim Lauth

City of Santa Clara, California, dba Silicon
Valley Power

2

3

4

5

6

22.

Individual

23.

Individual

Randall Ozaki

Overton Power District No. 5

X

X

24.

Individual

Richard Dearman

Tennessee Valley Authority

X

X

X

X

25.

Individual

Janet Smith

Arizona Public Service Company

X

X

X

X

26.

Individual

Brent Ingebrigtson

LG&E and KU Energy LLC

X

X

X

X

27.

Individual

John Free

Alabama Public Service Commission

28.

Individual

Michelle MIzumori

Western Electricity Coordinating Council

29.

Individual

William Drummond

Western Montana Electric Generating and
Transmission Cooperative

30.

Individual

Jim Uhrin

ReliabilityFirst

31.

Individual

Don Brookhyser

Cogeneration Association of California and
Energy Producers & Users Coalition

32.

Individual

Eddy Reece

Rayburn Country Electric Cooperative, Inc.

33.

Individual

Roger Clayton

New York State Reliability Council

34.

Individual

Cynthia S. Bogorad

Transmission Access Policy Study Group

X

X

35.

Individual

Randy D. Crissman

New York Power Authority

X

X

August 19, 2011

7

X

8

9

10

X

X
X
X

X

X
X
X

X

X

X
X
X

X
X

X

13

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

36.

Individual

Antonio Grayson

Southern Company

37.

Individual

Dennis Hogan

Luminant Energy

38.

Individual

Darren D. GIll

Pennsylvania Public Utility Commission

39.

Individual

Katie Coleman

Texas Industrial Energy Consumers (TIEC)

40.

Individual

John P. Hughes

Electricity Consumers Resource Council
(ELCON)

41.

Individual

Brian Conroy

Central Maine Power Company

X

42.

Individual

John Allen

New York State Electric & Gas and
Rochester Gas & Electric

X

43.

Individual

Brandy A. Dunn

Western Area Power Administration

X

44.

Individual

Robin Lunt

National Association of Regulatory Utility
Commissioners

45.

Individual

Scott Tomashefsky

Northern California Power Agency

46.

Individual

Sandra Shaffer

PacifiCorp

47.

Individual

Kevin Conway

Intellibind

48.

Individual

Si Truc PHAN

Hydro-Quebec TransEnergie

49.

Individual

Martin Bauer

US Bureau of Reclamation

August 19, 2011

X

2

3

4

5

6

7

8

X

9

10

X
X
X
X

X

X

X

X

X
X
X

X

X
X

X
X

X
X

14

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

50.

Individual

Jerome Murray

Oregon Public Utility Commission Staff

51.

Individual

Eric Lee Christensen

52.

Individual

Nicholas Winsemius

Public Utility District No. 1 of Snohomish
County, Washington
Grand Haven Board of Light and Power

53.

Individual

Josh Dellinger

Glacier Electric Cooperative

54.

Individual

Russ Schneider

FHEC

55.

Individual

Kim Moulton

Vermont Transco

X

56.

Individual

Richard McLeon

South Texas Electric Cooperative, Inc.

X

57.

Individual

Angela Gaines

Portland General Electric Company

X

58.

Individual

Richard McLeon

South Texas Electric Cooperative, Inc.

X

59.

Individual

Michael Albosta

Sweeny Cogeneration LP

60.

Individual

Michael Jones

National Grid

61.

Individual

Bud Tracy

Blachly Lane Electric Cooperative

62.

Individual

Paul Titus

Northern Wasco County PUD

X

X

63.

Individual

Bill Dearing

PUD No. 2 of Grant County, Washington

X

X

64.

Individual

Dave Markham

Central Electric Cooperative

X

65.

Individual

Dave Hagen

Clearwater Power Company

X

August 19, 2011

4

5

6

7

8

9

10

X
X

X

X

X

X

X

X

X

X

X
X

X
X

X

X

15

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

3

66.

Individual

Roman Gillen

Consumers Power Inc.

67.

Individual

Roger Meader

Coos-Curry Electric Cooperative

X

68.

Individual

Dave Sabala

Douglas Electric Cooperative

X

69.

Individual

Bryan Case

Fall River Electric Cooperative

X

70.

Individual

Rick Crinklaw

Lane Electric Cooperative

X

71.

Individual

Ray Ellis

Lincoln Electric Cooperative

X

72.

Individual

Richard Reynolds

Lost River Electric Cooperative

X

73.

Individual

Annie Terracciano

Northern Lights Inc.

X

74.

Individual

Doug Adams

Okanogan Electric Cooperative

X

75.

Individual

Rick Paschall

PNGC Power

X

76.

Individual

Heber Carpenter

Raft River Rural Electric Cooperative

X

77.

Individual

Ken Dizes

Salmon River Electric Cooperative

X

X

78.

Individual

Steve Eldrige

Umatilla Electric Cooperative

X

X

79.

Individual

Marc Farmer

West Oregon Electric Cooperative

X

80.

Individual

Kerry Robinson

Wells Rural Electric Company

X

81.

Individual

Hertzel Shamash

Dayton Power and Light Company

August 19, 2011

X

2

X

4

5

6

7

8

9

10

X

X

X

X

X

16

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

82.

Individual

David Proebstel

Clallam County PUD No.1

83.

Individual

Matt Morais

Electric Reliability Council of Texas, Inc.

84.

Individual

Martin Kaufman

ExxonMobil Research and Engineering

X

85.

Individual

Laura Lee

Duke Energy

X

86.

Individual

Curtis Klashinsky

FortisBC

87.

Individual

Mark Thompson

Alberta Electric System Operator

88.

Individual

RoLynda Shumpert

South Carolina Electric and Gas

89.

Individual

Reggie Wallace

90.

Individual

91.

2

3

4

5

6

8

9

10

X
X
X
X

X

X

X

X

X

X

Fayetteville Public Works Commission

X

X

Gary Kruempel

MidAmerican Energy Company

X

X

X

X

Individual

Dennis Minton

Florida Keys Electric Cooperative

X

92.

Individual

Thad Ness

American Electric Power

X

X

X

X

93.

Individual

Rick Drury

East Kentucky Power Cooperative, Inc.

X

X

X

94.

Individual

Andrew Z. Pusztai

American Transmission Company, LLC

X

95.

Individual

Linda Jacobson

Farmington Electric Utility System

96.

Individual

Rich Salgo

Sierra Pacific Power Co d/b/a NV Energy

X

X

X

X

97.

Individual

Jennifer Eckels

Colorado Springs Utilities

X

X

X

X

August 19, 2011

7

X

X

17

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

X

X

X

98.

Individual

Jianmei Chai

Consumers Energy Company

99.

Individual

Chad Bowman

Chelan PUD - CHPD

100. Individual

Michelle R D'Antuono

Occidental Energy Ventures Corp. (answers
include all various Oxy affiliates)

101. Individual

Kenneth A. Goldsmith

Alliant Energy

102. Individual

Deborah J Chance

Chevron Global Power, a division of
Chevron U.S.A. Inc.

103. Individual

Scott Bos

Muscatine Power and Water

X

104. Individual

Bill Keagle

X

105. Individual

John Bee

BGE and on behalf of Constellation
NewEnergy, Constellation Commodities
Group and Constellation Control and
Dispatch
Exelon

106. Individual

David C. Kahly

Kootenai Electric Cooperative

X

107. Individual

Tracy Richardson

Springfield Utility Board

X

108. Individual

Joe Tarantino

Sacramento Municipal Utility District
(SMUD)

109. Individual

Rick Hansen

City of St. George

110. Individual

John Brockhan

CenterPoint Energy

August 19, 2011

X

6

7

8

X

X

X

X

X

X

X

X

X

9

10

X

X

X

X

X

X

X

X

X
X

X

X

X

X
X

X
X

X

18

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

111. Individual

Sunitha Kothapalli

Puget Sound Energy

112. Individual

Linda Esparza

113. Individual

Patrick Farrell

Public Utility District No. 1 of Franklin
County
Southern California Edison Company

114. Individual

Thomas Weller

Midstate Electric Cooperative

115. Individual

Jason Snodgrass

GTC

116. Individual

Diane Barney

New York State Dept of Public Service

117. Individual

Bob Thomas

Illinois Municipal Electric Agency

118. Individual

Kim Wissman

Public Utilities Commission of Ohio

119. Individual

Jeff Nelson

Springfield Utility Board

120. Individual

David Angell

Idaho Power

X

121. Individual

Robert Ganley

Long Island Power Authority

X

122. Individual

Mike Hirst

Cogentrix Energy, LLC

123. Individual

Jack Stamper

Clark Public Utilities

124. Individual

John A. Gray

The Dow Chemical Company

125. Individual

David Thorne

Pepco Holdings Inc

126. Individual

Gary Ferris

Vigilante Electric Cooperative

August 19, 2011

X

2

3

4

X

5

6

7

8

9

10

X

X
X

X

X

X

X
X
X
X
X
X
X

X
X
X
X

X

X
X

19

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

127. Individual

Steve Alexanderson

Central Lincoln

X

X

128. Individual

Neil Phinney

Georgia System Operations

X

X

129. Individual

Bill Harm

PJM

130. Individual

Heather Hunt

New England States Committee on
Electricity

131. Individual

Darryl Curtis

Oncor Electric Delivery Company LLC

132. Individual

Charles Yeung

Southwest Power Pool

133. Individual

Geoff Carr

Northwest Requirements Utilities

134. Individual

Jonathan Appelbaum

United Illuminating

135. Individual

John Cummings

PPL Energy Plus and PPL Generation

136. Individual

Joe Petaski

Manitoba Hydro

137. Individual

Kathleen Goodman

ISO New England, Inc.

138. Individual

Manny Robledo

City of Anaheim

139. Individual

Chris de Graffenried

Consolidated Edison Co. of NY, Inc.

X

140. Individual

Scott Miller

MEAG Power

141. Individual

Alice Ireland

Xcel Energy

August 19, 2011

5

6

7

8

9

10

X

X
X
X
X

X
X

X

X

X

X

X

X

X

X

X

X

X

X

X

X
X
X

X

20

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

142. Individual

Michael Falvo

Independent Electricity System Operator

143. Individual

Randy MacDonald

NB Power Transmission

X

144. Individual

Glen Sutton

ATCO Electric

X

145. Individual

David Burke

Orange and Rockland Utilities, Inc.

X

146. Individual

Shane McMinn

Golden Spread Electric Cooperative, Inc.

147. Individual

Rick Spyker

AltaLink

148. Individual

Benjamin A Friederichs

Big Bend Electric Cooperative, Inc.

149. Individual

J. McFeely, PE

Modern Electric Water Company

150. Individual

Gary Carlson

Michgan Public Power Agency

151. Individual

Peter Mackin

Utility System Efficiencies, Inc.

152. Individual

Keith Morisette

Tacoma Power

153. Individual

Russell A. Noble

Cowlitz County PUD

154. Individual

Mihai Cosman

California Public Utilities Commission

August 19, 2011

2

3

4

5

X

X

6

7

8

9

10

X

X
X

X
X

X

X

X

X

X

X

X

X

X

X

21

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

1. The SDT has made clarifying changes to the core definition in response to industry comments. Do you agree
with these changes? If you do not support these changes or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: Based on stakeholder comments, the SDT has made additional clarifying revisions to the draft BES definition.
The BES Draft Definition includes all three sections – core definition, list of inclusions, and list of exclusions. The SDT has revised the bright-line
core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists. In response to
comments, the SDT added an additional inclusion to clarify the inclusion of Reactive Resources and an additional exclusion to clarify that Reactive
Resources that are owned by retail customers for their own use are not to be included. Finally, the SDT elected to retain the 100 kV bright-line
criteria. This is the bright-line voltage level that is included in the existing approved definition of the Bulk Electric System in the NERC Glossary of
Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification was provided that would lead the SDT to
make a change. One goal of this project is to add clarity to the definition without significantly changing the population of BES Elements.
Changes made to the definition as a result of comments on this question are:
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real
Power and Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is
modified by the list shown below. This does not include facilities used in the local distribution of electric energy.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary
windingsterminals of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that
distribute power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection
at 100 kV or higher are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail
customer Load and not to accommodate bulk power transfer across the interconnected system.
E4 – Reactive Power devices owned and operated by the retail customer solely for its own use.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.

Organization
Public Service Enterprise Group
LLC

August 19, 2011

Yes or No

Question 1 Comment

No

There is still room for misinterpretation of the BES boundaries. The BES definition has ramifications affecting
many standards. NERC should provide examples of what specifically is in and what is out of BES boundaries.

22

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
Example one line diagrams showing “Generation Resources” included or excluded and types of radial feeds
exempted should be shown. Identify what element is in BES / what is out. Suggest showing typical
interconnection facilities. Addressing typical interconnection facility configurations will assist in developing a
clear and concise definition that provides a precise line of demarcation between elements of the BES.

Response: Based on the stakeholder comments, the SDT has made additional revisions to the three parts of the BES Definition (Core Definition, Inclusion List,
and Exclusion List) in order to improve clarity.
Northeast Power Coordinating
Council

No

The core definition should be revised to read: Bulk Electric System (BES): All Transmission Elements
operated at 100 KV or higher, unless such designation is modified by the list shown below. The resulting
modified BES shall comprise all Elements deemed necessary for operating an interconnected electric energy
transmission network, but shall exclude any Elements used in the local distribution of electric energy.
The inclusion and exclusion requirements are restrictive. For example, radial characteristics should not be
limited by the amount of installed generation or single transmission source and/or require an interrupting
device. Instead, one or more transmission sources could feed the radial load to provide redundancy as long
as there is adequate protection and isolation for improved customer-supply continuity and reliability. This
would be considered radial as long as the loss of any transmission source would not affect, and is not
necessary for the operation of the interconnected transmission network. This retains the incentive to build
transmission.
The revised definition will have a direct impact on entities across North America and may conflict with
regulatory requirements, Codes, and Licenses. FERC in its Order 743 and 743A has directed NERC to
address these concerns.
Include provisions in both the NERC exception criteria and exception process for federal, state and provincial
jurisdictions. These provisions should provide clear guidance so that, if and when there are deviations from
the exception criteria, they are properly identified with technical and regulatory justifications ensuring there is
no adverse impact on the interconnected transmission network. This burden of proof should be left to the
entity seeking exception because it may be difficult to define the exception criteria. Further, if such an explicit
criteria could be defined, it could become another bright-line BES.

Hydro-Quebec TransEnergie

No

The bright line revised definition could expand significantly what is considered to be BES in the case of HQT,
with no discernible impact on the reliable operation of the interconnected system, because of the nature of the
Quebec interconnection.
Furthermore, it should be stated that there appears to be a conflict between the proposed definition and the
regulatory framework applicable in Quebec or at least there are some important differences between both.
The non-FERC juridiction was acknowledged by FERC Order 743 in paragraph 95. As an example, the

August 19, 2011

23

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
Quebec regulatory framework considers that there are several levels of application for standards, not only
one. A single BES definition cannot apply to all standards.The definition must include more latitude for nonFERC jurisdictions, as long as the reliability objective is achieved.

Hydro One Networks Inc

Yes

We agree with the concept of a bright-line definition and commend the SDT for developing a concept of
explicit inclusions and exclusions as part of the definition. This will reduce the number of exception
applications for some of the BES elements. However, the inclusion and exclusion requirements are extremely
restrictive. For example, radial characteristics should not be limited by the amount of installed generation or
single transmission source and/or require an interrupting device. Instead we believe that one or more
transmission sources could feed the radial load to provide redundancy as long as there is adequate protection
and isolation for improved customer-supply continuity and reliability. This should be considered radial as long
as the loss of any transmission source does not affect, and is not necessary for, the operation of the
interconnected transmission network.
Further, it is imperative to understand that the NERC’s revised definition will have a direct impact on entities
across North America and will conflict with regulatory requirements, Codes, and Licenses. FERC in its Order
743 and 743A has directed NERC to address these concerns.We suggest the SDT and RoP teams should:
o Carefully craft the exception criteria and procedure to be flexible and technically sound, to allow entities to
adequately present their case to the ERO for inclusions or exclusions outside of the definition. This burden of
proof should be left to the entity seeking exception because it may be difficult if not impossible to define the
exception criteria. If such a criteria could be defined, it will in fact become another bright-line BES.
o Include provisions in both the NERC exception criteria and exception procedure for federal, state and
provincial jurisdictions. These provisions should provide clear guidance so that, if and when there are
deviations from the exception criteria, they are properly identified with technical and regulatory justifications
ensuring there is no adverse impact on the interconnected transmission network.

Response: Based on the stakeholder comments, the SDT has made additional revisions to the three parts of the BES Definition (Core Definition, Inclusion List,
and Exclusion List) in order to improve clarity.
See the responses to comments as well as a discussion of the latest revisions regarding the Radial Exclusion in Question 7 and the responses to comments
regarding the Regulatory Requirements in Question 12 below.
Tri-State Generation and
Transmission Association, Inc.

August 19, 2011

No

The Northeast Power Coordinating Council stated that “Step-down transformers with the low-side terminals
serving non-BES facilities, which are serving a distribution function, should not be part of the definition of
BES.” The drafting team stated that it agrees with the comment, but the implementation uses the term local
distribution network, which is different than a step-down transformer. Transformers are addressed in the

24

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
answer to the NPCC comment 2, but uses the ambiguous “single Transmission source” phrase as a
requirement to determine BES status.Other specific comments are below.

Response: The SDT has made revisions to the draft definition to clarify that only transformers with primary and secondary terminals operated at 100 kV or
higher unless excluded under Exclusions E1 or E3 would be included in the BES under Inclusion I1.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary
windingsterminals of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
NERC Staff Technical Review

No

The core definition lacks a clear bright-line designation for generating resources. For such resources, the core
definition only references “Real Power resources as described below” which in and of itself is not a bright-line
designation. A bright-line designation for generating resources needs to be included in the core definition. A
bright-line can be established in the core definition by including generating units based on the MVA ratings as
found in current Inclusions I2, I3, and I5. Additional generating unit specifications could be included in the
core definition or as Inclusions such as the existing Inclusion I4 for black start generating units. >>>>>>>>>>
The core definition also lacks clarity with respect to the facilities included under “Reactive Power resources”
and may unintentionally omit Reactive Power resources necessary for reliable operation of the BES. The
definition as proposed excludes devices such as shunt reactors connected to the tertiary terminals of a BES
transformer and synchronous condensers connected through a transformer, and is unclear whether a static
var compensator (SVC) with thyristor switched capacitors and thyristor switched or controlled reactors
operated below 100 kV, but connected to the BES through a transformer (similar to a generator connected to
the BES through a generator step-up transformer) is included in the BES definition. The qualifications on
Reactive Power resources recommended below will include the necessary transmission resources noted
above, without unintentionally including distribution capacitors connected on the low voltage side of a
distribution transformer. >>>>>>>>>>
These concerns can be addressed by revising the core definition as follows:>>>>>>>>>> “Bulk Electric
System (BES): All Transmission Elements operated at 100 kV or higher;Real Power resources including,
* Individual Generating Units greater than 20 MVA (gross nameplate rating),
* Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross
nameplate rating) connected through a common point of interconnection,
* Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) utilizing a collector system through a common point of interconnection, and
* Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission
Operator’s restoration plan regardless of voltage; andReactive Power devices (capacitive or inductive, static

August 19, 2011

25

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
or actively controlled) greater than 20 Mvar that are directly connected at 100 kV or higher, or connected
through a transformer at 100 kV or higher at the site of transformation;unless such designations are modified
by the list of Inclusions and Exclusions shown below.” >>>>>>>>>>
(Note that the rationale for excluding the 100 kV interconnection threshold on the first three bullets is provided
in our responses to Questions 3, 4, and 6.) >>>>>>>>>>
In conjunction with the alternative language for the core definition proposed above, NERC staff proposes the
following definition of Generating Unit be added to the NERC Glossary of Terms used in Reliability Standards:
>>>>>>>>>> Generating Unit - A device, whether spinning or static and whether connected synchronously,
asynchronously, or electronically coupled, that produces electrical energy from another source of energy,
either directly from the other energy source (such as a combustion turbine from natural gas or light distillate
oil, a wind turbine from wind, or a solar array from the sun) or through a storage medium (such as pumped
storage hydro, a flywheel, compressed air, or battery).

NERC Transmission Issues
Subcommittee (TIS)

No

Although the wording can work as it is, the TIS believes clearer wording would be: “All Transmission
Elements operated at 100 kV or higher, Real Power and Reactive Power resources as described below,
connected at 100 kV or higher unless such designation is modified by the list shown below.”

Response: The BES draft definition includes all three sections – core definition, list of inclusions, and list of exclusions. The SDT has revised the bright-line core
definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or higher are to be
included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.
In response to comments, the SDT added an additional item to clarify the inclusion of Reactive Resources and an additional exclusion to clarify that Reactive
Resources that are owned by retail customers for their own use are not to be included.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.
E4 – Reactive Power devices owned and operated by the retail customer solely for its own use.
Dominion

No

Dominion believes the core BES definition should include any non-radial Element or Facility operated at 100
Kv or higher and should exclude any radial Element or Facility (regardless of operating voltage) as well as
non-radial Element or Facility operated below 100 kV.
The core definition should also include defined criteria that are applied to an Element or Facility to determine

August 19, 2011

26

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
whether or not it meets the intent of the Section 215 of Federal Power which defines the bulk power system
as (1) facilities and control systems necessary for operating an interconnected electric energy transmission
network; and (2) electric energy from generation facilities needed to maintain transmission system reliability.
(3) However, Section 215 excludes facilities used in the local distribution of electric energy From the definition
of the bulk power system . An Element or Facility should be included where the Element or Facility is
necessary for operating an interconnected electric energy transmission network or is needed to maintain
transmission system reliability. Likewise an Element or Facility should be excluded where the Element or
Facility is not necessary for operating an interconnected electric energy transmission network or is needed to
maintain transmission system reliability.
Dominion agrees that the BES definition should exclude local distribution facilities under state jurisdiction.
In specific instances (including UFLS programs and transmission protection systems that are implemented on
distribution elements or radial transmission) local distribution facilities can be included in approved NERC
reliability standards following under explicit standards dedicated to their explicit mission without their
automatic inclusion in a definition of BES that could infringe on state jurisdiction.
Dominion is also concerned at how complicated these lists of inclusions and exclusions has become!
Dominion had implemented the 100 kV threshold, as displayed in prior drafts of this bright line test (without all
these distractions provided in this BES definition version). With the complexity of inclusion and exclusion
criteria now provided in this draft, Dominion is not sure it can replicate the list of facilities that are now
qualified for inclusion in the BES as seen through the eyes of different auditors and this will expose Dominion
to undesirable disputes down the road on what should have been included or excluded.

National Grid

No

The core definition should be revised to read: Bulk Electric System (BES): All Transmission Elements
operated at 100 KV or higher, unless such designation is modified by the list shown below. The resulting
modified BES shall comprise all Elements deemed necessary for operating an interconnected electric energy
transmission network, but shall exclude any Elements used in the local distribution of electric energy.

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists.
See the responses to comments regarding Local Distribution Facilities in Question 11 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list

August 19, 2011

27

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment

shown below. This does not include facilities used in the local distribution of electric energy.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.
E4 – Reactive Power devices owned and operated by the retail customer solely for its own use.
SPP Standards Review Group

No

A reference needs to be made to the ROP changes which also provide a mechanism whereby Elements may
be excluded/included in the BES. Without that reference the proposed definition does not completely include
all means for exceptions/inclusions. We would suggest the definition be expanded to say ‘...modified by the
list shown below or as provided by Appendix 5C of the NERC Rules of Procedure.’

ISO New England, Inc.

Yes

This definition does not indicate that there may be other "inclusions" and "exclusions" for which an entity has
to seek ERO/RRO approval. Therefore our recommendation is that this definition be modified to resolve this
concern.This questionnaire contains information as part of the definition description that is different from the
draft Implementation Plan and definition of Bulk Electric System document, specifically the entirety of E4 is
included in the questionnaire but in neither of the other two documents; this may lead to confusion by
commenters.

Response: In the first posting, a reference to the Rules of Procedure exception process was inadvertently omitted from the posting. It has been added back in
to this posting.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.
Michigan Public Service
Commission(MPSC)

August 19, 2011

No

MPSC Staff Comments: The BES definition proposed by the SDT should not use the term “transmission”, if
that term is defined as facilities that are at 100 kV or above. Not all facilities at 100 kV or above are properly
considered transmission facilities. Use of “transmission” is causing unnecessary uncertainty and much
debate among NERC stakeholders in the standards development and outreach processes over potential
effects on jurisdiction, ownership, and possible new NERC registration requirements. This is especially true
in states such as Michigan where Michigan Public Service Commission-regulated utilities sold their
transmission facilities to independent transmission companies. Using FERC’s Order 888 seven-factor
technical-functional test as the basis for technical studies presented and evaluated in individual state dockets,
the Michigan Public Service Commission approved, and subsequently FERC deferred to, those transmission
and distribution classifications. Using “transmission” in the BES definition could cause unintended
consequences. Entities already registered with NERC as Distribution Providers, Load Serving Entities, or
Generation Owners, etc. which own facilities previously classified as distribution by state regulatory agencies,
may also now be required to register with NERC as Transmission Planners, Owners, or Operators. A system
element defined as BES should not determine jurisdiction, ownership, or require duplicative or additional

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Organization

Yes or No

Question 1 Comment
NERC registration. Much compliance with reliability standards is already being done by RTOs and entities
already registered with NERC. Unnecessary and costly duplication of standards work should be avoided. We
support that “All Transmission Elements ...” be replaced with “All network System Elements ...” in the BES
definition.

Consumers Energy Company

No

The generic inclusion within the definition of BES, of the NERC-defined term, “Transmission”, has the
potential to cause confusion and controversy. Small entities that own facilities that have been approved by
FERC as being classified as “distribution” according to the FERC Order 888 seven-factor test, could be
viewed as owning “Transmission.” Therefore, Regional Entities might require these small entities to register
as Transmission Owners, Transmission Operators, and/or Transmission Planners. However, these facilities
may not form a contiguous system, as expressed in the defined term, “Transmission” and being “An
interconnected group of lines and associated equipment”. Alternatively, such facilities, because they do not
form such a contiguous system (and thus are not, and should not be, classified as Transmission) may
inappropriately be excluded from the BES. Therefore, even though “Transmission Facilities” represent a
subset of the BES, we urge that NERC avoid the use of the term, “Transmission” within the definition of BES.
NERC should more explicitly describe, in a functional manner independent of the term, “Transmission”, what
is intended to be included within the core definition. For NERC to fail to do so is to invite challenges to the
final definition as well as establish inappropriate reliability gaps. We agree with GO/TO Interface Project
2010-07 method of resolving reliability gaps by expanding requirements to the Distribution Provider function
as necessary.We propose that “All Transmission Elements ...” be replaced with “All network System Elements
...”

Response: The SDT elected to retain the use of the word “Transmission” as it is an approved term in the NERC Glossary of Terms. As defined, Transmission is
“An interconnected group of lines and associated equipment for the movement or transfer of electric energy between points of supply and points at which it is
transformed for delivery to customers or is delivered to other electric systems.” The SDT considers this an appropriate use of the term. No change made.
Idaho Falls Power

No

We believe that inclusions or exclusions tied to brightline registration criteria (such as the 20MVA single
generation source or 75 MVA facility) does not fulfill the effort the NERC BES definition project was tasked to
undertake. The current draft's language will draw in many small municipal and other like entities with small
generation assets, which have no material impact upon the BES.
Further, should these generation assets not be excluded, this draft implies that all assets downstream to the
point of interconnection are BES as well regardless of point of connection. We believe it was the original
intent of this definition project to remove such immaterial assets and the undue burden placed upon such
entities and subsequently their rate payers, who have no impact to the BES.

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Organization

Yes or No

Question 1 Comment

Southern Company

No

Inclusion of individual units less than 75MVA was established when these smaller units were significant to the
reliability of the BES and is outdated.

Intellibind

No

I agree in principle with the changes; however the definition and direct effect on certain small entities has not
been improved. Primarily there are many entities that will be included that are marginal at best. Such entities
will include intermittent generation such as wind, which may, or may not fit into the designation of aggregation
of up to 75 MVA. It is becoming a practice to size a farm, or phase of a farm, to under 75MVA to get around
the rules. A site is not defined and could be defined very narrowly.
I do not agree with the 20MVA threshold for single generators when the generators net output cannot reach
the 20MVA output. Trash burning facilities have heavy station service loads and by nameplate are included
when in reality they operate below the arbitrary cut off.
FERC has asked for technically justified standards, and the proposed BES definition still applies an arbitrary
threshold not supported by technical argument. This issue is further aggravated by location of these
resources. Many of these resources are remotely located specifically so that they have no, or minimize
impact on the BES. Many times they are on long lines that are over 100KV simply because of efficiency in
electrical transmission.

Fayetteville Public Works
Commission

No

The changes made by the SDT with respect to Real Power resources in Inclusion I2 do not ensure a
consistent determination by independent entities of whether a generator should be included within the BES.
The ambiguity in Inclusion I2 has implications on other Inclusions and Exclusions. See the comments on
Question 3 for additional detail.

Response: See the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below.
Overton Power District No. 5

No

The term does not include facilities used in the local distribution of electric energy.

Response: The SDT has made additional clarifying revisions to the draft BES definition to address your concern.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Western Montana Electric
Generating and Transmission
Cooperative

August 19, 2011

No

As a general matter, Western Montana Electric Generating and Transmission Cooperative (WMG&T)
supports the approach the Standards Development Team (“SDT”) has taken to defining the Bulk Electric
System (“BES”). The changes made in the revised core definition are helpful and represent significant

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Organization

Yes or No

Northern Wasco County PUD

Question 1 Comment
progress toward an acceptable definition. With an effective and efficient exclusion process, the draft will
better define the BES as a whole.We urge the SDT to bear in mind the restrictions contained in Section 215 of
the Federal Power Act (“FPA”) The “bulk-power system” (As per FERC, we treat the statutory term “bulkpower system” as equivalent to the term ordinarily used in the industry, “Bulk Electric System”) definition
imposes a clear limit on the reach of the mandatory reliability regime. The BES is made up of only those
“facilities and control systems necessary for operating an interconnected electric energy transmission network
(or any portion thereof)” and “electric energy from generation facilities needed to maintain transmission
system reliability.” Congress reinforced that limit in Section 215(i), where it emphasized that the FPA
authorizes the imposition of reliability standards “for only the bulk-power system.” WMG&T is concerned that
the SDT’s proposed definition is overly-broad, and that it will sweep in many Elements that have little or no
material impact on the reliable operation of the interconnected bulk transmission grid. For example, the
definition uses the arbitrary 20 MVA threshold from the NERC Statement of Registry Criteria for inclusion of
generators. Accordingly, for the BES definition to conform to the requirements of the statute, the SDT must
adopt an effective mechanism to exempt facilities like these that are improperly swept in by the SDT’s
brightline approach to inclusions and exclusions. For this reason, the Exception process to accompany the
SDT’s definition is of critical concern. If the SDT incorporates this statutory language as its core definition, it
will have addressed FERC’s primary concern with a minimum of disruption to the current NERC system of
definitions. The definition could then be further elaborated to show specific points of demarcation for each
inclusion and exclusion similar to that Proposal 6 from the WECC Bulk Electric System Definition Task Force
(“BESDTF”) team to further delineate BES and non-BES facilities.

Chelan PUD – CHPD
Kootenai Electric Cooperative
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Big Bend Electric Cooperative,
Inc
Northwest Requirements Utilities
Cowlitz County PUD

Response: See the responses to comments regarding the Regulatory Requirements in Question 12 below.
See the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below.
The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list of inclusions,
and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and
Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or
Exclusion lists.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
ReliabilityFirst

No

We feel the intent of the FERC Order was to simplify and not complicate the definition and the
inclusion/exclusion process. This definition is now even more complex.
we also feel that as a result of several defined terms such as the LDN teh proposed definition will in most

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Organization

Yes or No

Question 1 Comment
cases exclude portions of networks in locations such as Washington DC, New York and other Metro Areas,
many Munis and citiies that are currently registered. If the intent is to remove entities from the registry this will
in most likely do it.

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists.
See the responses to comments as well as a discussion of the latest revisions regarding local networks in Question 9 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
New York State Reliability
Council

No

HVDC and VFT technologies are not addressed specifically.
Consideration should be given to expanding the core BES definition to clarify that it includes all AC and DC
system Element(s).

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists. The SDT discussed your comment and feels that HVDC and VFT technologies are already included in the draft core definition since
they are Transmission Elements.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Grand Haven Board of Light and
Power

August 19, 2011

No

The Grand Haven Board of Light and Power (GHBLP) does not agree that the core definition for the BES use
a “bright line” definition of 100kV and above. Currently, we have a 138kV/69kV transformer that connects to
the BES and serves a radial, load serving system. This transformer is presently protected by a “ground
switch” relay scheme. We have a project in process that is replacing this “ground switch” relay scheme with a
circuit switcher. The circuit switcher, unlike the ground switch, would not affect the BES if it were to operate.
By this “bright line” definition this single asset would be defined as a part of the BES. The cost that our
organization would incur from being forced to register as a Transmission Owner and Transmission Operator
(TO/TOP) would be extreme, and would significantly impact our budget and our customer’s rates. We should

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Organization

Yes or No

Question 1 Comment
not have to depend on an “exclusion” process to remove this asset from being defines as a part of the BES,
and this should be addressed in the core definition.

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists. The SDT has made revisions to the draft definition to further clarify that radial systems at 100 kV or higher serving only Load would be
excluded under Exclusion E1.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Glacier Electric Cooperative

No

I still feel that a bright-line of 200 kV would be more appropriate, with language stating that certian significant
elements operated below 200 kV would be included.
However, I believe the exlusion process is definitely a step in the right direction.

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists. The SDT elected to retain the 100 kV bright line criteria. This is the bright-line voltage level that is included in the existing approved
definition of the Bulk Electric System in the NERC Glossary of Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification
was provided that would lead the SDT to make a change. One goal of this project is to add clarity to the definition without significantly changing the population
of BES elements.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Blachly Lane Electric
Cooperative
Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc.

August 19, 2011

No

First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of the Bulk
Electric System (BES). We appreciate the work that the Standards Development Team (SDT) has put into a
new definition so far and believe the draft is a step in the right direction. We also understand the relatively
short timeframe that NERC is working under in order to create a new BES definition to submit to FERC for
approval before the imposed deadline. That said, we believe that the draft definition needs significant revision
before NERC files it with FERC for approval. In response to question #1, we recommend that NERC revise
the draft BES definition so that the first paragraph reads as follows:”Bulk Electric System (BES): Includes

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Organization
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Salmon River Electric
Cooperative Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative

August 19, 2011

Yes or No

Question 1 Comment
anything that meets each of the following three (3) criteria:(1) (a) Is a facility or control system necessary for
operating an interconnected electric energy transmission network (or any portion thereof), or(b) Is electric
energy from generation facilities needed to maintain transmission system reliability; AND(2) Is not a facility
used in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC Order
888; AND(3) (a) Unless included or excluded in subpart (b), isi. A Transmission Element operated at 100kV or
higher; orii. A Real Power Resource identified in subpart (b); oriii. A Reactive Power resource connected at
100kV or higher;(b) [the list of inclusions of exclusions in the draft, as modified by our comments below]”
Criteria (1) and (2) of these revisions would capture the limitations on what may be included in the BES due to
the jurisdictional limits that Congress placed on FERC, NERC, and the Regional Entities in developing and
enforcing mandatory reliability standards. Specifically, Section 215(i) of the Federal Power Act provides that
the Electric Reliability Organization (ERO) “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1)
(emphasis added). Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A)
facilities and control systems necessary for operating an interconnected electric energy transmission network
(or any portion thereof); and (B) electric energy from generation facilities needed to maintain transmission
system reliability. The term does not include facilities used in the local distribution of electric energy.” Id.
With this language, Congress expressly limited FERC, NERC, and the Regional Entities’ jurisdiction with
regard to local distribution facilities as well as those facilities not necessary for operating a transmission
network. Given that these facilities are statutorily excluded from the definition of the BPS, reliability standards
may not be developed or enforced for facilities used in local distribution, and therefore the definition of the
BES may not include such facilities. In Order No. 672, FERC adopted the statutory definition of the BPS.
See Order No. 672, FERC Stats. & Regs. ¶ 31,204 (2006). In Order No. 743-A, issued earlier this year, the
Commission acknowledged that “Congress has specifically exempted ‘facilities used in the local distribution of
electric energy’” from the BPS definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also
held that to the extent any facility is a facility used in the local distribution of electric energy, it is exempted
from the requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution that will
be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process is for NERC to
propose criteria for approval by FERC to determine which facilities are not BPS facilities and therefore not
BES facilities. Accordingly, it is critical that NERC create a definition of the BES that first excludes facilities
used in local distribution. In Order No. 743-A, the Commission confirmed this, stating: “once a facility is
classified as local distribution, the facility will be excluded from the [BES] unless changes to the system
warrant a review of the determination.” Order No. 743-A, at P 71 (emphasis added).We believe that the
Seven Factor is the appropriate means to determine whether a facility is used in the local distribution of
electricity and therefore should be referenced in the definition of the BES. This is the test that applies
elsewhere to determine whether facilities qualify as local distribution, and therefore there is strong and clear
precedent for using it in the BES definition. See 334 F.3d 48. In fact, the statutory language in Section 201 of

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Organization

Yes or No

Question 1 Comment
the FPA that led to the Seven Factor Test for other purposes is identical to the statutory language in Section
215 of the FPA at issue here. Well established rules of statutory construction call for interpreting identical
language to produce similar meanings, therefore applying the Seven Factor Test under both sections of the
statute is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain facilities are
part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor Test could be
relevant and possibly is a logical starting point for determining which facilities are local distribution for
reliability purposes, while also allowing NERC flexibility in applying the test or developing an alternative
approach as it deems necessary.” Id. at P 69. The Seven Factor Test includes the following factors: 1) Local
distribution facilities are normally in close proximity to retail customers; 2) local distribution facilities are
primarily radial in character; 3) power flows into local distribution systems, it rarely, if ever, flows out; 4) when
power enters a local distribution system, it is not re-consigned or transported on to some other market; 5)
power entering a local distribution system is consumed in a comparatively restricted geographical area; 6)
meters are based at the transmission/local distribution interface to measure flows into the local distribution
system; and 7) local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC
precedent indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and Denying in
Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010).
NERC must also limit the BES to facilities or control systems necessary for operating an interconnected
electric energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local distribution
exclusion, facilities not falling into either of these categories are not part of the BPS and therefore must be
expressly excluded from the BES.In order to establish a process that is consistent with the FPA and NERC’s
delegated authority from FERC, the proper sequence of steps must be applied in the correct order to
determine which facilities are subject to NERC and FERC jurisdiction in the first instance, and only then, from
among the jurisdictional facilities, to determine which facilities and control systems must comply with the
electric reliability standards. Our revisions to the BES definition would create such a process within the
definition of the BES. It would ensure that entities would begin any analysis of whether a particular item
qualifies as BES by asking, first, whether that facility is “necessary for operating an interconnected electric
energy transmission network (or any portion thereof)” or is “electric energy from generation facilities needed
to maintain transmission system reliability,” and second, whether that facility is “used in the local distribution
of electric energy.” Only after addressing these questions might further analysis be appropriate. We
understand, but disagree with, the argument that, because the FPA clearly excludes local distribution facilities
and facilities necessary for operating an interconnected electric transmission network from FERC, NERC, and
Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the definition of
the BES. This approach might be legally accurate, but could lead to significant confusion for entities
attempting to implement the new BES definition. There are numerous examples of Regional Entities,

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Organization

Yes or No

Question 1 Comment
particularly WECC, attempting to include such facilities in the BES under the current BES definition, and
regulated entities are not certain as to which facilities they should consider part of the BES. Clarifying FERC,
NERC, and Regional Entity in the BES definition, even if such clarification is already provided in the FPA,
would avoid such problems under the new definition.
Criterion (3) of these revisions is necessary to resolve the ambiguity in the proposed definition as to whether
the clause “unless such designation is modified by the list shown below” modifies only the preceding clause
(“Reactive Power resources connected at 100 kV or higher”) or the entire definition.Rearranging the definition
in this way should make clear that the list of inclusions and exclusionsthat would be inserted as Subpart (b)
modifies each provision ofSubpart (a). Thus, for example, even if a Transmission Element is
otherwiseincluded by virtue of operating at 100 kV or higher, it is nonetheless excluded ifspecifically
addressed in the list of exclusions that would be incorporated assubpart (b) of the definition (if, for example,
the Element qualifies as a LocalDistribution Network). The rearrangement of the language eliminates
anyargument that the phrase “unless such designation is modified by the list shownbelow” does not modify
“all Transmission Elements operated at 100 kV or higher”because of its placement at the end of the
independent clause “Reactive Powerresources connected at 100 kV or higher.”Further, we support the use of
the phrase “Transmission Elements” as the startingpoint for the base definition because both “Transmission”
and “Elements” arealready defined in the NERC Glossary of Terms Used, and the use of the
term”Transmission” makes clear that the Bulk Electric System includes only Elementsused in Transmission
and therefore excludes Elements used in local distribution ofelectric power.
As discussed above, the definition must exclude facilities used inlocal distribution in order to comply with the
limits placed on NERC authority byCongress in Section 215 of the FPA.
For similar reasons, we believe the SDT has improved the proposed definition from its initial proposal by
eliminating the use of terms such as “Generation” that are not specifically defined in the NERC Glossary of
Terms and by eliminating terms such as “Facility” that include “Bulk Electric System” as part of their definition.
Eliminating the use of such terms helps sharpen the core definition. If a key term is undefined, incorporating it
into the definition only begs the question of how the incorporated term is defined. If a currently-defined term
uses the phrase “Bulk Electric System” as part of its definition, incorporating that term into the BES definition
creates a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,”
“Real Power,” and “Reactive Power.”

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists.
See the responses to comments regarding Local Distribution Facilities in Question 11 and the responses to comments regarding the Regulatory Requirements in

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Organization

Yes or No

Question 1 Comment

Question 12 below.
The SDT has made revisions to the draft definition to clarify that the BES does not include Facilities used in the local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Electric Reliability Council of
Texas, Inc.

No

ERCOT ISO suggests a different approach. In order 743, to remedy its concerns, FERC suggested
eliminating RE discretion in defining the BES, and instead basing it upon a bright-line 100kV threshold,
provided that elements above and below 100kV could be excluded and included, respectively, based on
specific procedures. Consistent with that approach, ERCOT ISO suggests that the BES definition itself
establish a bright line standard, with inclusions and exclusions managed through the exception process (the
exception process allows for both exclusions and inclusions of relevant facilities/equipment).With respect to
exclusions (and inclusions), FERC contemplated a process involving stages that established “exclusion”
criteria in the first instance. If equipment met such criteria, the process ended there and it was excluded or
included, as appropriate. If the equipment did not meet the bright-line criteria, then it moved to the
“exception” analysis, which contemplated additional critical analysis to determine if exemption was
warranted.ERCOT ISO believes that structuring the revised definition in accordance with this approach is
more consistent with FERC’s intent of having an inclusive definition in the first instance, with modifications
occurring subsequently pursuant to critical analysis in a well defined exception process.Revising the BES
definition consistent with the above principles would counsel in favor of revisions to the current definition that
removed RE discretion and provided for inclusion or exclusion on a case by case basis.
ERCOT ISO also believes that the BES definition should provide for a general exclusion of distribution
facilities. In Orders 743 and 743-A, FERC made clear that, consistent with the terms of EPAct 2005,
distribution systems were excluded from the BES. However, FERC also made clear that it reserved the right
to judge whether something was distribution or transmission, and, therefore, subject to its jurisdiction.
Consistent with FERC’s findings in this regard, ERCOT ISO believes that the definition should provide the
general exclusion, with specific exclusions being performed as part of the exception process. This will meet
the goal of respecting Congress’ exclusion of distribution facilities, while ensuring the distribution/transmission
distinction is subject to clear, objective standards the application of which can be critically reviewed by FERC
to provide the appropriate procedural and substantive checks FERC envisions to ensure its jurisdiction is
applied in all relevant cases to facilitate enhanced system reliability.
In addition, ERCOT ISO supports memorializing the generation registration criteria in the BES definition.
However, consistent with the approach described above, the BES definition should not be characterized in
terms of inclusions or exclusions, but rather as general thresholds, with modifications occurring solely

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Organization

Yes or No

Question 1 Comment
pursuant to the exemption process.
Finally, with respect to generation, ERCOT ISO questions the 75 MVA threshold applied to collector system
type generation. As indicated by the SDT, this was intended to capture renewable resources (e.g. wind), and
ERCOT ISO agrees with this clarification, but questions whether the 20 MVA threshold should apply. These
systems can include multiple wind turbines on the collector system, but when they are interconnected at a
single point, they are viewed as a single resource and, as such, should be subject to the same 20 MVA
threshold as other single units.Applying the approach described above, the BES definition would reflect
general thresholds. Specific circumstances warranting exception would occur via a separate process ERCOT ISO is not disagreeing with any of the SDT’s inclusions or exclusions, it is merely suggesting that
they be addressed in that separate process.
Consistent with this approach, ERCOT ISO offers the following language:The Bulk Electric System shall
include: A) all Transmission Elements operated at voltages100 kV or higher; B) all generation resources that:
1) are individual units greater than 20 MVA; 2) multiple units at a single facility that are equal to or greater
than 75 MVA in the aggregate, provided that all units have a common point of interconnection; and 3) multiple
units connected to a collector system that are equal to or greater than 20 MVA in the aggregate; 4) all
Blackstart Resources; and C) Reactive Power resources connected at 100 kV or higher. The BES shall not
include distribution facilities, and radial transmission facilities serving only load with one transmission source
are generally not included in this definition. The foregoing notwithstanding, any relevant element (e.g.
transmission, generation, etc.) may be included or excluded in the BES pursuant to the relevant exception
processes criteria and analyses as provided for in the NERC Rules of Procedure.

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists.
In the first posting, a reference to the Rules of Procedure exception process was inadvertently omitted from the posting. It has been added back in to this
posting.
The SDT has also made revisions to the draft definition to clarify that the BES does not include Facilities used in the local distribution of electric energy.
The SDT feels this threshold is consistent with the existing limits in the ERO Statement of Compliance Registry Criteria. No stakeholder provided sufficient
technical analysis to support a change.
Also, see the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list

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Question 1 Comment

shown below. This does not include facilities used in the local distribution of electric energy.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.
ExxonMobil Research and
Engineering

No

The SDT’s attempt to create a structure that clarifies what types of facilities should be included / excluded
from the bulk electric system is a positive step; however, the utilization of an automatic fault interrupting
device as the end point criteria for bulk electric and start point for local distribution is inappropriate. The
Federal Power Act specifically excludes all “facilities used in the local distribution of electric energy” from the
bulk power system without mention of how these facilities are isolated from the transmission system.

Response: See the responses to comments as well as a discussion of the latest revisions regarding the Radial Exclusion in Question 7 and the responses to
comments regarding Local Distribution Facilities in Question 11 below. No change made.
American Electric Power

No

Rather than a 75 MVA threshold as designated in I3, we suggest a threshold of 100 MVA which we believe to
be more appropriate.
It is difficult to provide comments regarding the BES definition, given the parallel nature of the other related
deliverables currently out for review. For example, there needs to be a defined relationship between an
approved definition of BES, the technical principles for demonstrating BES exception, and the exception
process itself. When closely related projects such as these are done simultaneously, no individual deliverable
can rely on the completed work of another. As a result, we risk having conflicting decision making across
these projects.

Response: The SDT discussed and has retained the 75 MVA threshold for generating resource(s) located at a single site. The SDT feels this threshold is
consistent with the existing limits in the Registry Criteria. No stakeholder provided sufficient technical analysis to support a change. Also, see the responses to
comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below. No change made.
The teams working on the various documents needed to address the revision to the definition of BES are coordinating their work and did provide some overlap in
the posting periods to provide stakeholders with an opportunity to see the various draft products at one time. Unfortunately, the schedule for delivery doesn’t allow
the products to be developed serially.
Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

No

Please see discussion in response to Questions 2, 7, 9, 10, 11, 12 and 13.

Response: Please see response to Questions 2, 7, 9, 10, 11, 12, and 13.

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Question 1 Comment

Springfield Utility Board

No

SUB appreciates the effort put forward in this process and is indicating “no” primarily because Springfield
Utility Board (SUB) has observed that the statutory term “Bulk Power System” is being applied in some cases
as being equivalent and interchangeable with “Bulk Electric System”. SUB is concerned that the SDT’s
proposed BES definition is broad and that it will sweep in many elements that have little or no material impact
on the reliable operation of the interconnected bulk transmission grid. Springfield Utility Board requests that
NERC create a distinction between the terms BPS and BES. Are the two to be used interchangeably, or will
BPS no longer be used? SUB suggests NERC consider adopting the statutory definition of the Bulk Power
System as the core definition of the Bulk Electric System.

Springfield Utility Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with the
concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: See the responses to comments as well as a discussion of the latest revisions regarding Generation Exclusions for units serving retail customer load
in Question 8 below.
See the responses to comments regarding the Regulatory Requirements in Question 12 below.
Note that in Reliability Standards, the term “Bulk Electric System” (a formally defined term) is used; however in other NERC corporate documents the term, “bulk
power system” (not capitalized) is used.
Southern California Edison
Company

August 19, 2011

No

The current approach seems to be based on the assumption that the presence of particular equipment is
more important than the manner in which the equipment is used. Before SCE can support the BES Definition,
the definition should be revised to include “All Transmission and Generation Elements and Facilities operated
at voltages 100 kV or higher, Real Power resources as described below, and Reactive Power resources

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Question 1 Comment
connected at 100 kV or higher that operate in parallel with the integrated networked transmission system and
are necessary for operating the interconnected transmission network, unless such designation is modified by
the list shown below.” This modification will provide the clarification needed to better ascertain what facilities
should be identified as part of the BES and lessen the need to trigger the Rules Of Procedure exceptions
process.
If “Inclusions” and “Exclusions” continue to be a part of the BES definition, they will need additional
clarification to ensure the exclusion of radial and distribution facilities which (1) do not have interconnected
operations risk and (2) are not used for inter-utility transfers on the BES and, therefore, are not necessary for
operating the interconnected transmission network.
They also need to be modified to work in tandem with the “Technical Principles for Demonstrating BES
Exceptions”, so that these types of facilities don’t continually have to be validated by the ROP exceptions
process. Example: The exclusion of facilities which are radial or distribution in nature and that have
connecting generation of 20MVA or higher for the purpose of serving local load and that are not used to
transfer power between “systems” to the BES should be automatic under the BES Definition.

Response: Based on the stakeholder comments as shown below, the SDT has made additional clarifying revisions to the draft BES definition. The BES draft
definition includes all three sections – core definition, list of inclusions, and list of exclusions. The SDT has revised the bright line core definition to clarify that all
Transmission Elements at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless
there is a modification for a particular Element in the Inclusion or Exclusion lists.
The Rules of Procedure exception process will only be used for those facilities that entities feel should also be excluded or that regions feel should also be
included.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
New York State Dept of Public
Service

August 19, 2011

No

1) We do not agree with the core definition. The core definition starts with the premise that the definition
must be drafted based on a 100 kV brightline designation. FERC’s Order 743 and 743-A clearly state that is
just one approach and would entertain other approaches that demonstrate the same level of reliable operation
and is responsive to FERC’s reliable operation concerns. As the EPAct 2005 recognizes, the industry
technical expertise is preserved in the NERC and does not reside at FERC. Therefore, FERC’s jurisdiction is
expressly limited by Section 215 of the Federal Power Act. Moreover, FERC cannot, under the guise of
“policy” concerns, exceed the limits of its statutory authority. FERC’s orders recognize this, and repeatedly
acknowledge that FERC must exclude facilities used in local distribution from the definition of BES. FERC’s
orders, at most, assert that “some” 115/138 kV facilities are needed to reliably operate the bulk system.

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FERC has made no showing that all facilities of 100kV or greater are necessary for reliable operation of the
grid. Without a record based finding that all such facilities are necessary for reliable operation of the grid,
FERC cannot include all such facilities within its definition of BES. FERC has even explicitly acknowledged
within a New York transmission tariff rate case that a 115 kV loop around a significant size city should not be
included in the transmission account as it existed solely to serve load in that city. Given the technical
expertise to devise a definition more refined lies with the industry, FERC wisely deferred to NERC processes
the ability to employ a different approach other than a brightline. Therefore, NERC should apply its expertise
to fashion a definition of “bulk electric system” that comports with the statutory jurisdictional limitations
Congress imposed upon FERC in FPA Section 215. NERC’s efforts should be checked at every step that they
are not exceeding the originating authority contained in FPA Section 215. Overall, the definition must be
guided by, and limited to, the FPA definition of reliable operation which is explicitly defined as limited to
protection of the bulk system by “operating the elements of the bulk-power system ... so that instability limits,
uncontrolled separation, or cascading failures of such systems will not occur....”, and expressly excludes
facilities used in local distribution.
2) NERC fails to make any technical demonstration that using the existing definition as a starting point is
valid. Moreover, NERC has resisted pursuing alternative avenues. The NPCC study submitted to FERC in
the combined NERC-NPCC compliance filing in September 2009, clearly demonstrated the movement from
the NPCC regional criteria to a 100 kV brightline provided little, if any, increased levels of reliable operation.
Through extrapolation, a study of other areas is likely to indicate that reliable operation levels throughout the
rest of the country could be assured by a more refined selection of which facilities under 200 kV should be
included as part of the bulk system. Note that FERC did not reject use of material impact assessmensts; they
only objected to the fact that the NPCC test did not include some regional interconnection facilities, some
nuclear interconnections and a particular load area.NERC’s failure to evaluate other approaches than a
brightline 100 kV standard is a failure to ensure adequate levels of reliable operation at a sustainable level
consistent with provisions of the FPA.All remaining comments on the definition, as presented by NERC, are
based on our belief that the proposed definition is overreaching in its basic premise of starting with a brightline
100 kV as its core definition of the bulk system.
3) It is not clear why the core definition has dropped “generation” interconnected at the specified voltage level.
The following inclusions/exclusions included generation facilities and it appears inconsistent to not include
generation in the core definition.

Public Utilities Commission of
Ohio

August 19, 2011

No

FERC jurisdiction is limited by the Federal Power Act, Section 215. To make a bright line designation as the
starting point, without a demonstration that ALL facilities at 100 kV and greater affect the reliability of the bulk
power system is a step beyond FERC jurisdictional boundaries. The Federal Power Act explicitly excludes
facilities used in local distribution from the bulk power system. NERC should give serious consideration to

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Question 1 Comment
other (non bright-line) approaches to ensure bulk system reliability.

City of Redding

Yes

In general Redding supports the work of the SDT team in revising the core definition of the Bulk Power System
as ordered by FERC. The core definition, as written, is a good step at removing the ambiguities of the current
definition and is acceptable as long as it is coupled with a fair and objective Exception Process that, as FERC
directed in Order 743, “excludes facilities the ERO determines are not necessary for operating the
interconnected transmission network”. (P 30). It is Redding’s opinion that using a voltage threshold is a
convenient method to make an initial dividing line however it does not provide adequate proof that elements,
over or under this voltage threshold, are “necessary” for the operation of the Bulk Electric System (BES). It is
also noted that while the 100 kV threshold is intended to capture the majority of the power system elements
that are potentially BES, on a continent wide basis, a 200 kV threshold would serve the Western Interconnect
better as a starting brightline. In the Western Interconnect the majority of 100 kV elements are used as
Distribution facilities. Therefore, this will burden NERC and the Regional Entity in the West with a larger
number of Exception Process applications.
Redding supports the use of exclusion and inclusion lists in the Definition; however Redding believes the SDT
needs to take a more literal approach to FERC’s Orders and define the term “necessary for operating the
interconnected transmission network” and clearly “establish whether a particular facility is local distribution or
transmission”. Without a clear distinction of these two foundational principles it is difficult to have a significant
discussion about the validity of the proposed inclusions and exclusions and the thresholds involved.
As an alternative to the proposed definition, Redding would support using a simple approach to meet FERC’s
orders (as long as is coupled with an “exception process that includes clear, objective, transparent, and
uniformly applicable criteria of facilities that are not necessary for operating the grid”). (Order 743A P73). If the
above criteria is developed to accomplish the above then the existing definition could be modified to read:
“Electrical generation resources, transmission lines, interconnections with neighboring systems, and associated
equipment, operated at voltages of 100 kV or higher.”

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists.
The SDT elected to retain the 100 kV bright line criteria. This is the bright-line voltage level that is included in the existing approved definition of the Bulk Electric
System in the NERC Glossary of Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification was provided that would

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Question 1 Comment

lead the SDT to make a change. One goal of this project is to add clarity to the definition without significantly changing the population of BES elements.
Finally, the SDT has made revisions to the draft definition to clarify that the BES does not include Facilities used in the local distribution of electric energy as
established by applicable regulatory authorities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Cogentrix Energy, LLC

No

I would like to see a definition for clarity of an "Individual Generating Unit"Example:Solar farm with 300
photovoltaic units. Each is a stand-alone unit with its own inverter, but all come together at a common tie
breaker to connect to the BES.
Questions:1. Would each one be considered directly tied to the BES through one common tie breaker?
2. Would each photovoltaic unit be considered an individual generating unit?
3. Would the combined total of 300 units be considered an individual generating unit or would they be
considered a facility?

Response: The SDT is not in position to provide an answer without first making sure that all relevant data is in hand.
The Dow Chemical Company

No

See Dow's specific comments on some of the following questions.

Response: See specific responses in following questions.
Clark Public Utilities

No

Clark is concerned that the core definition is overly-broad and sweeps facilities into the BES that are required
by the statute to be excluded, even considering the list of inclusions and exclusions. Clark urges the SDT to
bear in mind the specific restrictions on the definition of “bulk-power system” contained in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress defined “bulk-power system” to mean “facilities
and control systems necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” and “electric energy from generation facilities needed to maintain transmission system
reliability.” 16 U.S.C. § 824
o(a)(1). Congress unequivocally excluded from this definition “facilities used in the local distribution of electric
energy.” The “bulk-power system” definition thus imposes a clear limit on the reach of the mandatory reliability
regime. Congress reinforced that limit in Section 215(i), where it emphasized that the FPA authorizes the
imposition of reliability standards “for only the bulk-power system.” 16 U.S.C. § 824
o(i)(1). Clark believes it is clear that Congress intended the “bulk-power system” to be defined narrowly so

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Question 1 Comment
that it would incorporate only high-voltage, interstate facilities used to transmit power over long distances,
whose failure threatens drastic reliability events such as system instability, uncontrolled separation, or
cascading outages.In addition, the Federal Energy Regulatory Commission clearly stated that Order No. 743
did not mandate or direct NERC to adopt a 100 kV bright-line threshold (Order No. 743-A, 134 FERC ¶
61,210 at P 20. The Commission goes on to state that the 100 kV bright-line threshold is only one way to
address the Commission’s concerns. The Commission only requires that NERC use the Commission’s
recommendation or propose a different solution that is as effective as, or superior to, the Commission’s
proposed approach. The Commission also acknowledges that Congress has specifically exempted facilities
used in the local distribution of electric energy.The definition developed by the SDT should therefore focus on
that portion of the interconnected bulk transmission grid for which thermal, voltage, and stability limits must be
observed in order to prevent instability, uncontrolled separation, or cascading outages.
Further, in order to honor the specific limits placed on the definition by Congress, the SDT’s definition must
exclude facilities used in the local distribution of electric power and it must exclude facilities whose operation
or mis-operation affects only the level of service and does not threaten cascading outages or other
widespread events on the bulk interconnected system. Clark asserts that the adoption of a bright-line
threshold of 100 kV is arbitrary and not based on any investigation of the potential for facilities at this voltage
level to cause instability, uncontrolled separation, or cascading outages or for the general need of these
facilities for the operation of an interconnected electric energy transmission network. The threshold excludes
transmission facilities below 100 kV without any determination on a general basis of whether these facilities
affect interconnected system operation. It goes without saying that these low voltage transmission facilities
should be subject to an inclusion process in the event that regional reliability entities believe they do have an
impact on reliability but on a case-by-case basis. Clark agrees with this concept and does not believe bringing
low voltage transmission facilities into the BES through an inclusion process causes any BES reliability
issues.
Similarly, Clark believes that the majority of facilities between 100 kV and 200 kV can be shown to have no
impacts on interconnected system operation and do not threaten instability, uncontrolled separation, or
cascading outages. Clark also points out that the vegetation outage standard (FAC-003) uses this approach.
The standard applies to facilities operated at 200 kV or above and “lower voltage lines designated by the
RRO as critical to the reliability of the electric system in the region.”
Clark believes the use of 100 kV as the bright-line threshold will result in a large number of facilities being
brought into the definition of the BES that are either 1) part of a Local Distribution Network, 2) are radial
serving only load from one transmission source, or 3) that can be shown to have no affect on interconnected
system operation or cannot cause instability, uncontrolled separation, or cascading outages. This
unnecessary inclusion will cause a large amount of effort on the part of the owners of these facilities and on
the part of the Regional Reliability Organizations that will have to review the many exclusion filings that will
result. Utilizing a 200 kV threshold with a low voltage inclusion process will eliminate much of the

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Question 1 Comment
unnecessary paperwork since very few owners of 200 kV or above facilities will seek exclusions. This will free
up regional reliability entities to focus on low voltage transmission facilities that truly have an impact on
interconnected system operations.Clark believes that the SDT and the NERC should consider adopting a
bright-line threshold higher than 100 kV with low voltage inclusion and develop the arguments necessary to
demonstrate to the Commission that this solution is as effective as, or superior to, the Commission’s
proposed approach.
These arguments should include the following: o Eventually, a 200 kV bright-line threshold with a low voltage
inclusion process will incorporate into the BES the same facilities that a 100 kV bright-line threshold with an
exclusion process. This means that these two concepts both have the same effect on the reliability and the
operability of the BES. o Utilizing a 200 kV bright-line will reduce the amount of initial effort by transmission
owners and Regional Reliability Organizations and allow these entities to concentrate on low voltage facilities
that truly have an impact on the BES.
Clark is similarly concerned that the SDT’s proposed definition is overly-broad in including all generating units
greater than 20 MVA capacity connected to transmission at 100 kV or above. Clark believes that there are
many small to medium sized generators that individually have no affect on interconnected system operations
and do not threaten the BES with instability, uncontrolled separation, or cascading outages. Many of these
generators are connected to Local Distribution Networks with minimum loads that exceed maximum
generation. While the generators do support system reliability collectively, it is questionable whether many of
these generators individually represent a facility necessary for interconnected system operations. The
adoption by the SDT of a 200 kV bright-line threshold would eliminate many of these smaller generating units.
Again, the RROs must have an inclusion process for smaller generating units it believes support
interconnected system operations. Clark believes that eventually both thresholds (with appropriate inclusion
and exclusion processes) will result in the same 100 kV to 200 kV connected generators being included in the
BES so there will be no difference in the reliability of the BES. Adopting the higher of the two thresholds and
adopting a generating capacity threshold higher than 20 MVA will allow generator owners and Regional
Reliability Organizations to devote resources to small generating units that truly have an impact on
interconnected system operations.

Response: The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power
resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.
The SDT elected to retain the 100 kV bright-line criteria. This is the bright-line voltage level that is included in the existing approved definition of the Bulk Electric
System in the NERC Glossary of Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification was provided that would
lead the SDT to make a change. One goal of this project is to add clarity to the definition without significantly changing the population of BES elements.
See the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below.

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Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Central Lincoln

No

We support the PNGC comments suggesting beginning with the statutory definition of BPS that excludes local
distribution.
The definition should also be further elaborated to show specific points of demarcation for each inclusion and
exclusion by the use of diagrams similar to those included with Proposal 6 from the WECC Bulk Electric
System Definition Task Force.
We also note that per the flowchart at
http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf, any >100 kV element that does not
meet an inclusion or an exclusion ends up being included. We don’t think that was the SDT’s intent. For
example a 5 kW solar project connected at 115 kV does not meet any inclusions so proceed to the exclusion
box. It is not radial load, behind a retail meter, or part of an LDN so it is BES by application of the definition.
We realize this flowchart was drafted by another team. It therefore becomes imperative that the definition
team clearly specifies exactly what becomes of an element that does not meet an inclusion.

Response: See the responses to comments regarding Local Distribution Facilities in Question 11 below.
The SDT has revised the wording of the generation inclusions to reference the ERO Statement of Compliance Registry Criteria for consistency. Therefore, there
should be no change in registration due to the revised definition.
Southwest Power Pool

August 19, 2011

No

SPP generally agrees with the substance of the SDT’s changes, but suggests a different approach. In order
743, to remedy its concerns, FERC suggested eliminating RE discretion in defining the BES, and instead
basing it upon a bright-line 100kV threshold, provided that elements above and below 100kV could be
excluded and included, respectively, based on specific procedures. Consistent with that approach, SPP
suggests that the BES definition itself establish a bright line standard, with inclusions and exclusions
managed through the exemption process.With respect to exclusions (and inclusions), FERC contemplated a
process involving stages that established “exclusion” criteria in the first instance. If equipment met such
criteria, the process ended there and it was exempt. If the equipment did not meet the bright-line criteria, then
it moved to the “exemption” analysis, which contemplated additional critical analysis to determine if exemption
was warranted.SPP believes that structuring the revised definition in accordance with this approach is more
consistent with FERC’s intent of having an inclusive definition in the first instance, with modifications occurring
subsequently pursuant to critical analysis in a well defined exemption process.Revising the BES definition
consistent with the above principles would counsel in favor of revisions to the current definition that removed

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Question 1 Comment
RE discretion and provided for inclusion or exclusion on a case by case basis.
SPP also believes that the BES definition should provide for a general exclusion of distribution facilities. In
Orders 743 and 743-A, FERC made clear that, consistent with the terms of EPAct 2005, distribution systems
were excluded from the BES. However, FERC also made clear that it reserved the right to judge whether
something was distribution or transmission, and, therefore, subject to its jurisdiction. Consistent with FERC’s
findings in this regard, the SRC believes that the definition should provide the general exclusion, with specific
exclusions being performed as part of the exception process. This will meet the goal of respecting Congress’
exclusion of distribution facilities, while ensuring the distribution/transmission distinction is subject to clear,
objective standards the application of which can be critically reviewed by FERC to provide the appropriate
procedural and substantive checks FERC envisions to ensure its jurisdiction is applied in all relevant cases to
facilitate enhanced system reliability.
However, consistent with the approach described above, the BES definition should not be characterized in
terms of inclusions or exclusions, but rather as general thresholds, with modifications occurring solely
pursuant to the exemption process. Applying the approach described above, the BES definition would reflect
general thresholds. Specific circumstances warranting exclusion/exception/inclusion would occur via a
separate process -SPP is not disagreeing with any of the SDT’s inclusions or exclusions, it is merely
suggesting that they be addressed in that separate process.
Consistent with this approach, SPP offers the following language:The Bulk Electric System shall include: A)
all Transmission Elements operated at voltages 100 kV or higher; B) all generation resources that: 1) are
individual units greater than 20 MVA; 2) multiple units at a single facility that are equal to or greater than 75
MVA in the aggregate, provided that all units have a common point of interconnection; and 3) multiple units
connected to a collector system that are equal to or greater than 75 MVA in the aggregate; 4) all Blackstart
Resources regardless of size; and C) Reactive Power resources connected at 100 kV or higher. The BES
shall not include distribution facilities, and Radial transmission facilities serving only load with one
transmission source are generally not included in this definition. The foregoing notwithstanding, any relevant
element (e.g. transmission, generation, etc.) may be identified as an exception and excluded or included in
the BES pursuant to the process delineated in the NERC Rules of Procedure and subject to the exclusion or
inclusion criteria.All equipment specific issues that affect exclusions/exceptions/inclusions would then be
addressed via the Rules of Procedure processes and the exclusion and inclusion criteria.

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists.
In the first posting, a reference to the Rules of Procedure exception process was inadvertently omitted from the posting. It has been added back in to this

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posting.
The SDT has also made revisions to the draft definition to clarify that the BES does not include facilities used in the local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.
PPL Energy Plus and PPL
Generation

No

See the response to Question 13

Response: See response to Question 13.
Independent Electricity System
Operator

No

We agree with the BES definition principles in general, the concept of Inclusions and Exclusions, as well as
the proposal for an Exception Process. However, since the Exception Process and the Technical Principles
and Criteria (TPC) for justifying BES Exceptions are being developed and will be approved independently,
albeit concurrently with the BES definition, there is a risk that the revised definition may be approved while the
TPC and Exception Process may not come to fruition in the form anticipated during development of the BES
definition. In short, our support for any revised BES definition would be conditional to the establishment of the
associated TPC. As such we advocate developing the revised BES definition and TPC as a “single
package”.Thus, we do not agree with the blanket inclusion of generation units and Facilities meeting the
thresholds of 20 MVA and 75 MVA respectively. We also do not agree with using these same thresholds in
determining when Exclusions are applicable. Instead, we believe the impact on BES reliability of all
generation units and Facilities meeting these capacity thresholds, should be assessed against the TPC and if
found to be impactive, these units and Facilities should be included as part of the BES after going through the
Exception Process.We believe this change in the approach to defining the BES will take into account the
evolving reality of distributed generation, particularly in the context of radial systems and local distribution
networks (LDNs), where generation units are installed in lieu of transmission reinforcements. We offer our
further comments on the Definition and its Inclusions and Exclusions against the backdrop of this general
philosophy.
The BES definition refers to Reactive Power resources “connected at” 100 kV or higher as opposed to
“operated at” 100 kV or higher. Is the intent of this wording to include in the BES a reactive resource
(capacitor, reactor, etc.) operating at a voltage below 100 kV and connected to the BES via a step-up
transformer?

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Organization

Yes or No

Question 1 Comment
If yes, would the transformer be excluded from the BES to be consistent with Inclusion I1?

Response: The SDT is tasked with creating a bright-line continent-wide definition for the BES. One of the goals of this effort is to ensure that similarly situated
elements in different regions are included or excluded on a consistent basis. The Rules of Procedure Exception process will only be used for those facilities that
entities feel should also be excluded or that regions feel should also be included.
The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power resources
connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.
In response to comments, the SDT added an additional item to clarify the inclusion of Reactive Resources and an additional exclusion to clarify that Reactive
Resources that are owned by retail customers for their own use are not to be included.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Dayton Power and Light
Company

No

Response: Without any specific comments, the SDT is unable to respond.
BPA

No

Tacoma Power

BES Definition First Paragraph - Change first sentence to “Unless otherwise excluded below, all Transmission
Elements operated at 100 kV or higher and those facilities included in the list below, Real Power resources
included below, and Reactive Power resources connected at 100 kV or higher.”
Tacoma Power generally supports clarifying changes to the BES definition by the SDT and the goal of
including only those facilities that materially impact the reliable operation of the interconnected bulk
transmission system. We propose one change to help guide the industry as the definition is applied.
Currently, the definition includes the clause ‘unless such designation is modified by the list shown below,’
positioned after the reactive resources clause. Due to the position of the clause, it can be misinterpreted to
apply only to reactive resources. To eliminate this ambiguity, we suggest that the proposed definition be
reordered to read as follows:”Bulk Electric System (BES) definition: (A) Unless included or excluded in
Section B below, the BES consists of: (1) All Transmission Elements operated at 100 kV or higher; (2)
Real Power resources identified in Section B below; and (3) Reactive Power resources connected at 100
kV or higher.(B) [BES designation criteria, list of inclusions and exclusions].”
Additionally, the BES definition should not require the inclusion of contiguous elements as the definition is
further developed.Lastly, the proposed BES definition for comments is not clear on the state of the system

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Organization

Yes or No

Question 1 Comment
conditions (normal or emergency) that should be assumed when applying the definition. The definition should
apply to only normal operating conditions.

Orange and Rockland Utilities,
Inc.
American Transmission
Company, LLC

In the core definition, “the list shown below” is still not clearly defined and causes some confusion.

Yes

However, to clarify the core definition, ATC proposes to change the text for Real and Reactive Power
resources from “connected” to “operated or connected”.

Response: The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power
resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Consolidated Edison Co. of NY,
Inc.

PUD No. 2 of Grant County,
Washington

Guidance Document - The SDT should develop a BES Definition Guidance Document which includes a fairly
comprehensive list of Elements considered to be potentially necessary for operating an interconnected
electric energy transmission network. This list would include references to Real Power and Reactive Power
resources.
Yes

Grant supports the approach the Standards Development Team (“SDT”) has taken to defining the Bulk
Electric System (“BES”). The changes made in the revised core definition are helpful and represent
significant progress toward an acceptable definition. With an effective and efficient exclusion process, the
draft will better define the BES as a whole. The definition could then be further elaborated to show specific
points of demarcation for each inclusion and exclusion similar to that Proposal 6 from the WECC Bulk Electric
System Definition Task Force (“BESDTF”) team to further delineate BES and non-BES facilities.

Response: The SDT will consider drafting a Guidance Document as a part of this project in order to provide the specific guidance you suggest.
United Illuminating

The definition should incorporate the language in Energy Policy Act of 2005 that defines bulk power system.
UI agrees in general that facilities operated at 100 kV and above are part of bulk power system. Without the
clarification in the definition the possibility of facilities that are not necessary for the operation of the
interconnected transmission will be pulled into scope.

Response: This suggestion would be outside of the scope of the approved BES Definition project. The SDT is tasked with creating a bright-line continent-wide

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Organization

Yes or No

Question 1 Comment

definition for the BES. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and
Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or
Exclusion lists.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Portland General Electric
Company

The bright-line definition of 100kV should specify that this is a three-phaseline-to-line voltage.

Response: The currently approved definition of the BES in the Glossary of Terms does not include this clarification. The SDT discussed your comment and
decided that this clarification was not necessary. Furthermore, all ac and dc facilities with a line-ground or line-line voltage greater than 100 kV would be included
in the BES except as modified by the lists of exclusions or inclusions. No change made.
Sweeny Cogeneration LP

The specific identification of global inclusions and exclusions is a very good way to approach this complex
issue.
We believe there are further items to be added to the list related to generator interconnections, a task that
was passed to this project from Project 2010-07.
Just as is the case with complex distribution systems, there are a variety of generator-transmission
interconnection architectures which are driving the Regions to inappropriately register Generator
Owner/Operators as Transmission Owners.

Response: See the responses to comments as well as a discussion of the latest revisions regarding generation inclusions in Questions 3, 4, and 6 below.
For clarification, no tasks were passed from Project 2010-07 to the Project 2010-17.
The BES Definition and the associated Exception Process are separate and distinct from the ERO Statement of Compliance Registry Criteria.
American Municipal Power and
Members
Florida Municipal Power Agency
Transmission Access Policy
Study Group

August 19, 2011

Yes

AMP and its members appreciate the opportunity to comment on the draft BES definition. We generally
support the direction taken by the SDT, with some minor changes.We agree with some other entities'
comments and suggest a few clarifying edits to the core definition. First, the definition should refer to “nongenerator Reactive Power resources,” to make clear that although all generators provide some reactive
power, those that do not meet the criteria of I2-I5 are not included in the BES.
There is ambiguity concerning whether a transformer stepping down from >100 kV to <100 kV is included or
not, though we believe that the SDT intends to exclude such transformers. It is clear that transformers with

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Organization

Yes or No

Question 1 Comment
two windings >100 kV are included and GSUs for registered generators are included, but it is somewhat
unclear in the current draft whether a 138 kV to 69 kV transformer is included or excluded. We suggests
making it clear that the intent of the SDT is to include (a) GSUs associated with BES generators and (b)
transformers with 2 or more windingwindings >100 kV, and that other transformers are excluded.
We also believe the drafting team intended to exclude all elements that are not included either under the BES
definition and designations or through the exception process. For the sake of clarity, we suggest that a
sentence to that effect be added to the core definition.
Finally, we note that the definition does not currently refer to the existence of the exception process. We
suggest that such a reference be added either to the core definition or to the lists of Inclusions and
Exclusions.
The following is the core definition incorporating the changes:All Transmission Elements (except
transformers) operated at 100 kV or higher, transformers as described below, Real Power resources as
described below, and non-generator Reactive Power resources connected at 100 kV or higher unless such
designation is modified by the list shown below. The NERC Rules of Procedure provide an Exception
Process through which Elements not included in the BES under this definition and designations may be
included in the BES, and Elements included in the BES under this definition and designations may be
excluded from the BES. Elements not included in the BES either by application of this definition and
designations, or through the BES exception process, are not BES Elements.

Northern California Power
Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.

Response: The SDT added an additional item to clarify the inclusion of Reactive Resources and an additional exclusion to clarify that Reactive Resources that
are owned by retail customers for their own use are not to be included.
See the responses to comments as well as a discussion of the latest revisions regarding the Transformer Inclusion in Question 2.
In the first posting, a reference to the Rules of Procedure exception process was inadvertently omitted from the posting. It has been added back in to this
posting.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.

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Organization
Small Entity Working Group
(SEWG)

Yes or No

Question 1 Comment

Yes

The Small Entity Working Group (SEWG) appreciates the opportunity to comment on the draft BES definition.
The group generally supports the direction taken by the SDT, with some minor changes.The BES definition
should refer to “non-generator Reactive Power resources,” to clarify that although all generators provide some
reactive power, the generators that do not meet the criteria of I2 through I5 are not included in the BES.
The BES definition should include a reference to the existence of the exception process.

MRO's NERC Standards Review
Forum

Yes

Please quantify that Reactive Resources within the BES definition are meant to be generator resources and
not static resources.

Muscatine Power and Water

Yes

Would like to ask the SDT to please affirm that Reactive Resources within the BES definition are intended to
be generator resources and not static resources.

Illinois Municipal Electric Agency

Yes

With the following clarifying edits. The BES definition should refer to “non-generator Reactive Power
resources,” to clarify that although all generators provide some reactive power, the generators that do not
meet the criteria of I2 through I5 are not included in the BES.

Pepco Holdings Inc

Yes

Do reactive power resources include reactors?

Response: In response to comments, the SDT added an additional item to clarify the inclusion of Reactive Resources and an additional exclusion to clarify that
Reactive Resources that are owned by retail customers for their own use are not to be included.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.
E4 – Reactive Power devices owned and operated by the retail customer solely for its own use.
Santee Cooper

Yes

We agree with the changes of adding the inclusions and exclusions. We recommend that I3 be 100 MVA or
higher. Was there a rationale for using 75 MVA?

Response: See the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below.
SERC OC Standards Review
Group

Yes

The SERC Standards Review Group (SRG) still believes that 200KV is the correct bright line for the BES
definition

Response: The SDT elected to retain the 100 kV bright-line criteria. This is the bright-line voltage level that is included in the existing approved definition of the
Bulk Electric System in the NERC Glossary of Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification was provided

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Organization

Yes or No

Question 1 Comment

that would lead the SDT to make a change. One goal of this project is to add clarity to the definition without significantly changing the population of BES
elements.
National Rural Electric
Cooperative Association
(NRECA)

Yes

NRECA believes the definition should explicitly state that facilities used in local distribution are excluded from
the BES.

Response: See the responses to comments regarding Local Distribution Facilities in Question 11 below.
New York Power Authority
MEAG Power

Yes

The New York Power Authority (NYPA) supports the Standards Drafting Team’s development of a revised
Bulk Electric System (BES) definition in response to FERC Order 743 that is directly linked to an exception
process for inclusions and exclusions. The definition must be closely coupled to the exception process and
the two must be integrated in the standard that is ultimately adopted. This will ensure that the regulatory
requirements apply to only those facilities that materially affect the reliability of the BES.In general, NYPA
agrees with the proposed definition and the objectives the Standards Drafting Team has established. NYPA
recommends that the team make additional clarifications to provide industry with a better understanding of the
inclusions and exclusions, as well as the impact of the inclusions/exclusions on the BES.
The definition should exclude generator leads for generating units that do not materially affect the reliability of
the BES regardless of the BES designation of the generating unit.
In addition, the definition should not require the inclusion of contiguous elements. Generating units that are
designated BES are currently required to comply with a subset of NERC Reliability Standards, but may not be
material to the reliable operation of the interconnected BES. This portion of the definition should not require
that both BES and non-BES generating units have their generator leads defined as BES transmission
elements.
A length-based criterion for generator leads ought to be considered. For example, the definition should
exclude generator leads that are one mile or less between BES elements.
The Standards Drafting Team should engage and coordinate with the Standards Drafting Team for Project
2010-07 (the GO/TO task force). This coordination is needed to determine the impacts of the new BES
definition on Transmission Owner (TO) and Transmission Operator (TOP) registration.
In addition, NYPA recommends that the Standards Drafting Team and the GO/TO Task Force consider, if
they have not already done so, the impacts of ownership and operating agreements on registration. For
example, clarification of registration impacts for BES elements that are jointly owned by two utilities (e. g.
where one utility owns 5 of 20 towers and the other utility owns the remaining towers and the conductor of a
transmission line) is required.

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Organization

Yes or No

Question 1 Comment
The definition does not provide clarity on the state of the system conditions (normal or emergency) that
should be applied. The definition should apply to only normal operating conditions.

Response: See the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3, 4, and 6 below.
One goal of this project is to add clarity to the definition without significantly changing the population of BES elements. The Registry Criteria is not being revised
by this project.
The leadership of the two SDTs, Project 2010-17 Definition of BES and Project 2010-07 GO/TO TF, have met and coordinated as necessary.
Electricity Consumers Resource
Council (ELCON)

Yes

We support the expanded structure of the core definition that provides for inclusions and exclusions. This
clarification establishes a rebuttable presumption that excluded elements are not BES and appropriately shifts
the burden of proof for any subsequent inclusion to Regional Entities or the ERO, thereby minimizing the
regulatory burden on the industry, an outcome consistent with the Commission’s stated assumption that
revising the BES definition should have relatively minor impacts on registrations in non-NPCC regions.

Response: Thank you for your comments.
Western Area Power
Administration

Yes

As a Transmission Operator (TO) it helps us define and write O & M, and operating agreements for our Load
Serving Entities (LSE/customers) that prefer to contract the responsibilities to the TO. The definition 'Bright
Line Threshold' is a general statement, that needs more definition for the special circumstances in the
southwestern U.S. where pump loads provide necessary irrigation. Based upon NERC's compliance registry
criteria, small entities prefer to contract responsibilities to the TO in order to forego NERC registration, or the
exception process for special circumstances.

Response: The ERO Statement of Compliance Registry Criteria is not being revised by this project.
PacifiCorp

Yes

In general PacifiCorp agrees with the direction of the proposed BES definition. Specific exceptions are
discussed in questions 2 - 13

Response: Thank you for your support. See specific responses to Questions 2 – 13.
Public Utility District No. 1 of
Snohomish County, Washington
Clallam County PUD No.1

August 19, 2011

Yes

As a general matter, Snohomish County PUD supports the approach the Standards Development Team
(“SDT”) has taken to defining the Bulk Electric System (“BES”). In the comments we submit today, we identify
several refinements we believe would improve the definition. We also discuss the legal framework the SDT
must operate under as we understand it. But we support the SDT’s conceptual approach and, if refined as we
suggest, we will support the SDT’s proposal so long as an acceptable process for defining exceptions

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Organization

Yes or No

Question 1 Comment
accompanies the definition.
As to the core definition addressed in Question 1, Snohomish believes the changes made in the revised
definition are helpful and represent significant progress toward an acceptable definition. Nonetheless, we are
concerned that the core definition is overly-broad and sweeps facilities into the BES that are required by the
statute to be excluded, even considering the list of inclusions and exclusions. We therefore suggest two
different approaches below that may achieve the SDT’s aims more effectively than the proposed core
definition. At a minimum, as we explain below, additional clarifications to the core definition are necessary
and an acceptable exemption process is required to ensure that facilities that by statute must be excluded are
excluded from the BES as defined by the SDT.At the outset, we urge the SDT to bear in mind the specific
restrictions on the definition of “bulk-power system” contained in Section 215 of the Federal Power Act
(“FPA”) (Following FERC’s guidance on the question, we treat the statutory term “bulk-power system” as
equivalent to the term ordinarily used in the industry, “Bulk Electric System”). In Section 215(a)(1), Congress
defined “bulk-power system” to mean “facilities and control systems necessary for operating an
interconnected electric energy transmission network (or any portion thereof)” and “electric energy from
generation facilities needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1). Congress
unequivocally excluded from this definition “facilities used in the local distribution of electric energy.” Id. The
“bulk-power system” definition thus imposes a clear limit on the reach of the mandatory reliability regime.
Congress reinforced that limit in Section 215(i), where it emphasized that the FPA authorizes the imposition of
reliability standards “for only the bulk-power system.” 16 U.S.C. § 824o(i)(1) (emph. added).Further, the SDT
must bear in mind “the cardinal rule that a statute is to be read as a whole since the meaning of statutory
language, plain or not, depends on context.” City of Mesa v. FERC, 993 F.2d 888, 893 (D.C. Cir. 1993)
(citation omitted). In considering how Congress used the term “bulk-power system” in the statute, as well as
the limits on the reliability regime imposed in the surrounding statutory language, it is clear that Congress
intended the “bulk-power system” to be defined narrowly so that it would incorporate only high-voltage,
interstate facilities used to transmit power over long distances, whose failure threatens drastic reliability
events such as cascading outages. These limitations are plain from, for example, the statutory definition of
“reliability standard,” which provides that reliability standards are to encompass only requirements to “provide
for reliable operation of the bulk-power system.” 16 U.S.C. § 824o(a)(3) (emph. added). Congress further
refined the scope of reliability authority by specifically defining “reliable operation” to mean “operating the
elements of the bulk-power system within equipment and electric system thermal, voltage, and stability limits
so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a
sudden disturbance. . . or unanticipated failure of system elements.” 16 U.S.C. § 824o(a)(4). Congress’s
intent to focus the national reliability regime on broad-scale threats to the interconnected, interstate highvoltage system like cascading outages is made clear, as well, by Congress’s specific direction that the
mandatory reliability system is prohibited from enforcing standards for adequacy of service, which were left to
state and local authorities. 16 U.S.C. § 824o(i)(2).When read in the context of the statute as a whole, the
definition developed by the SDT should therefore focus on that portion of the interconnected bulk

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Organization

Yes or No

Question 1 Comment
transmission grid for which thermal, voltage, and stability limits must be observed in order to prevent
instability, separation events, and cascading outages. Further, in order to honor the specific limits placed on
the definition by Congress, the SDT’s definition must exclude facilities used in the local distribution of electric
power and it must exclude facilities whose operation or mis-operation affects only the level of service and
does not threaten cascading outages or other widespread events on the bulk interconnected system.
Snohomish is concerned that the SDT’s proposed definition is overly-broad, and that it will sweep in many
Elements that have little or no material impact on the reliable operation of the interconnected bulk
transmission grid. For example, the definition would sweep in all generators with 20 MVA capacity even
though generators this small rarely create impacts on the interconnected bulk transmission system that would
threaten to violate the thermal, voltage or stability limits of the bulk transmission system and therefore do not
threaten instability, separation, or cascading outages on the interconnected transmission system.
Accordingly, for the BES definition to conform to the requirements of the statute, the SDT must adopt an
effective mechanism to exempt facilities like these that are improperly swept in by the SDT’s brightline
approach to inclusions and exclusions. For this reason, the Exception process to accompany the SDT’s
definition is of critical concern. It constitutes the last line of defense against a SDT definition that sweeps in
facilities excluded by the statutory definition.Snohomish believes the SDT can achieve the goals of FERC’s
Orders No. 743 and 743-A while honoring these statutory limits by taking one of two alternative approaches to
the core definition. First, perhaps the simplest way the SDT could achieve the goals of FERC Order No. 743
while avoiding overbreadth that violates statutory limits is to simply adopt the statutory definition of “bulkpower system” as the core definition. This approach is commonly used by regulatory agencies in defining
key jurisdictional terms to ensure that the agency does not cross statutory boundaries when carrying out the
duties assigned to it by Congress. Under this approach, the core definition would simply echo the statutory
definition, substituting “Bulk Electric System” for its statutory equivalent, “bulk-power system”:The term ‘Bulk
Electric System’ means: (A) Facilities and control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof); and,(B) Electric energy from generation facilities
needed to maintain transmission system reliability.The term does not include facilities used in the local
distribution of electric energy.See 16 U.S.C. § 824o(a)(1). The inclusions and exclusions developed by the
SDT, with the refinements we discuss below, would then be added to provide guidance in the application of
this definition to specific classes of electric system facilities and Elements.
A second alternative approach is to make the smallest possible adjustment to the current BES definition that
suffices to address the central concern expressed by FERC in Orders No. 743 and 743-A. Those orders
emphasized that FERC’s concerns are with the initial phrase in the current NERC BES definition, which
provides that the “Bulk Electric System” is: As defined by the Regional Reliability Organization, the electrical
generation resources, transmission lines, interconnections with neighboring systems, and associated
equipment, generally operated at voltages of 100 kV or higher.In Order No. 743, FERC made clear that it
views the initial phrase ("As defined by the Regional Reliability Organization") as creating unreviewable
discretion for Regional Entities to define the BES in their region, and that this unreviewable discretion, rather

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Yes or No

Question 1 Comment
than lack of uniformity per se, is the problem Order No. 743 is designed to remedy. See, e.g., Order No. 743,
133 FERC ¶ 61,150 at P 16 (2010) (FERC believes the “best way to address these concerns is to eliminate
the Regional Entities’ discretion to define ‘bulk electric system’ without ERO or Commission review”; id. at 30
(same). In Order No. 743-A, FERC clarified that the primary aim of its rulemaking was to eliminate this
unreviewed regional discretion, and it was not, as FERC had originally proposed, to create a uniform national
definition that does not allow for any regional variation. Order No. 743-A, 134 FERC ¶ 61,210 at P 11 (“We
clarify that the specific issue the Commission directed the ERO to rectify is the discretion the Regional Entities
have under the current bulk electric system definition to define the parameters of the bulk electric system in
their regions without any oversight from the Commission or NERC.”); id. at P 39 (“The Commission’s
suggested solution simply would eliminate regional discretion that is not subject to review by [NERC] or the
Commission”).Accordingly, the SDT could achieve the primary aim of Order No. 743 by simply rewriting the
current definition to read:Unless a different definition has been developed by the Regional Reliability
Organization and approved by NERC and FERC, the Bulk Electric System is defined as the electrical
generation resources, transmission lines, interconnections with neighboring systems, and associated
equipment, generally operated at voltages of 100 kV or higher.If the SDT uses this suggested language as its
core definition, it will have addressed FERC’s primary concern with a minimum of disruption to the current
NERC system of definitions. The definition could then be further elaborated with the list of specific inclusions
and exclusions of Elements and systems (modified as discussed below), to provide more specific guidance to
the industry.
In this connection, we note that a 200 kV threshold would be more appropriate for WECC than a 100-kV
threshold. This is because generation in the West is generally located far from load, and power is generally
transmitted from these generation sources to distant load centers on extremely high-voltage lines, usually
operating in the range of 230-kV to 500-kV. Further, because loads are often dispersed across relatively
broad geographic areas, especially in the rural West, 115-kV lines are frequently used in local distribution
systems. See WECC Bulk Electric System Definition Task Force, Initial Proposal and Discussion, at pp. 1116 (posted May 15, 2009) (available at: http://www.wecc.biz/Standards/Development/BES/default.aspx)
(technical discussion showing that most transmission in the Western Interconnection operates at voltages
greater than 200 kV). Accordingly, a 200-kV threshold with an “inclusion” mechanism to sweep in the
relatively limited number of 115-kV lines in the West that perform a transmission function would be better
suited to the typical topology of systems in the West than a 100-kV threshold with exceptions for facilities that
operate as local distribution. That being said, we recognize that 200-kV may not be an appropriate threshold
for other parts of the country and we are willing to support the SDT’s approach as long as discretion is
preserved for the WECC to develop a definition better suited to the conditions in the Western Interconnection.
If the STD elects not to adopt one of the above suggestions, the core definition proposed on April 28 requires
clarification. Specifically, as drafted, the proposed definition is ambiguous in that it is not clear whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding clause

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Organization

Yes or No

Question 1 Comment
(“Reactive Power resources connected at 100 kV or higher”) or the entire definition. To eliminate this
ambiguity, we suggest that the proposed definition be reordered to read as follows:Bulk Electric System
(BES): (A) Unless included or excluded in subpart B, the Bulk Electric System consists of: (1) all Transmission
Elements operated at 100 kV or higher; (2) Real Power resources identified in subpart B; and, (3) Reactive
Power resources connected at 100 kV or higher.(B) [the list of inclusions and exclusions, modified as
discussed in our responses to questions 2 through 9]. Rearranging the definition in this way should make
clear that the list of inclusions and exclusions that would be inserted as Subpart B modifies each provision of
Subpart A. Thus, for example, even if a Transmission Element is otherwise included by virtue of operating at
100 kV or higher, it is nonetheless excluded if specifically addressed in the list of exclusions that would be
incorporated as subpart B of the definition (if, for example, the Element qualifies as a Local Distribution
Network). The rearrangement of the language eliminates any argument that the phrase “unless such
designation is modified by the list shown below” does not modify “all Transmission Elements operated at 100
kV or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.”
Snohomish supports the use of the phrase “Transmission Elements” as the starting point for the base
definition because both “Transmission” and “Elements” are already defined in the NERC Glossary of Terms
Used, and the use of the term “Transmission” makes clear that the Bulk Electric System includes only
Elements used in Transmission and therefore excludes Elements used in local distribution of electric power.
As discussed above, the definition must exclude facilities used in local distribution in order to comply with the
limits placed on NERC authority by Congress in Section 215 of the Federal Power Act (“FPA”), 16 U.S.C. §
824o.
For similar reasons, we believe the SDT has improved the proposed definition from its initial proposal by
eliminating the use of terms such as “Generation” that are not specifically defined in the NERC Glossary of
Terms and by eliminating terms such as “Facility” that include “Bulk Electric System” as part of their definition.
Eliminating the use of such terms helps sharpen the core definition. If a key term is undefined, incorporating it
into the definition only begs the question of how the incorporated term is defined. If a currently-defined term
uses the phrase “Bulk Electric System” as part of its definition, incorporating that term into the BES definition
creates a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,”
“Real Power,” and “Reactive Power.”

Response: The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power
resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.
The SDT elected to retain the 100 kV bright-line criteria. This is the bright line voltage level that is included in the existing approved definition of the Bulk Electric
System in the NERC Glossary of Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification was provided that would
lead the SDT to make a change. One goal of this project is to add clarity to the definition without significantly changing the population of BES elements.

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Organization

Yes or No

Question 1 Comment

See the responses to comments regarding the Regulatory Requirements in Question 12 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
FHEC

Yes

Generally agree, but think E1 should be changed slightly to:From: E1 - Any radial system which is described
as connected from a single Transmission source originating with an automatic interruption device and: To:E1
- Any radial system which is described as connected from a Transmission source originating with a single
automatic interruption device and:

Response: See the responses to comments as well as a discussion of the latest revisions regarding the Radial Exclusion in Question 7 below.
Vermont Transco

Yes

It appears that the SDT has made progress in addressing comments made to date. Concerned that facilities
below 100 kV will fall into the current definition of BES. If changes in the wording better identified key areas
the new definition would be easier to interpret, apply, and it would better align with the concerns of the
members

Response: The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power
resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.
The SDT elected to retain the 100 kV bright-line criteria. One goal of this project is to add clarity to the definition without significantly changing the population of
BES elements.
See the responses to comments regarding Local Distribution Facilities in Question 11 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
South Texas Electric
Cooperative, Inc.

Yes

There is general confusion as to whether or not the “BES” is synonymous with the “BPS”. If this is so, then it
should be expressly stated as such. If not, clarification should be provided to industry.

Response: The BES and BPS are not synonymous. The BES is a subset of the BPS. This has been stated in numerous documents, including Orders No. 693
(P76) and 743 (P36). No change made.
FortisBC

August 19, 2011

Yes

We agree with the concept of a bright-line definition and commend the SDT for developing a concept of
explicit inclusions and exclusions as part of the definition. This will reduce the number of exception

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Organization

Yes or No

Question 1 Comment
applications for some of the BES elements. However, the inclusion and exclusion requirements are extremely
restrictive. For example, radial characteristics should not be limited by the amount of installed generation or
single transmission source and/or require an interrupting device. Instead we believe that one or more
transmission sources could feed the radial load to provide redundancy as long as there is adequate protection
and isolation for improved customer-supply continuity and reliability. This should be considered radial as long
as the loss of any transmission source does not affect, and is not necessary for, the operation of the
interconnected transmission network.
Further, it is imperative to understand that the NERC’s revised definition will have a direct impact on entities
across North America and will conflict with regulatory requirements, Codes, and Licenses. FERC in its Order
743 and 743A has directed NERC to address these concerns.We suggest the SDT and RoP teams should:
o Carefully craft the exception criteria and procedure to be flexible and technically sound, to allow entities to
adequately present their case to the ERO for inclusions or exclusions outside of the definition.
o Include provisions in both the NERC exception criteria and exception process for federal, state and
provincial jurisdictions. These provisions should provide clear guidance so that, if and when there are
deviations from the exception criteria, they are properly identified with technical and regulatory justifications
ensuring there is no adverse impact on the interconnected transmission network. This burden of proof should
be left to the entity seeking exception because it may be difficult if not impossible to define the exception
criteria. Further, if such an explicit criteria could be defined, it will in fact become another bright-line BES.

Response: See the responses to comments as well as a discussion of the latest revisions regarding the Radial Exclusion in Question 7 and the responses to
comments regarding Regulatory Requirements in Question 12 below.
Puget Sound Energy

Yes

E3. Local distribution networks (LDNs): In this exclsion criteria, it was unclear about the size of the LDN that
could be excluded from BES. There was a limit on connected generation but not connected load. If there is
any mention of total aggregate load served by this LDN then that would clarify the definition better. We would
like to suggest using a limit say lesser than or equal to 300 MW of total aggregate load served by LDN could
be excluded from BES definition in addition to all the 5 (a-e) characteristics mentioned.

Response: After extensive communication, the SDT has made changes to the draft Local Network definition to provide additional clarity. The draft definition now
includes an upper voltage limit of 300 kV. The draft definition does not contain a limit on connected Load as no technical basis has yet been provided regarding
this issue that would lead the SDT to make this change.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to

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Organization

Yes or No

Question 1 Comment

accommodate bulk power transfer across the interconnected system.
Manitoba Hydro

Yes

We recommend that the definition be prefaced with the statement ‘except where provided otherwise by
applicable law...’

Response: The SDT has made revisions to the draft definition to clarify that the BES does not include facilities used in the local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
City of Anaheim

Yes

I1: Change the "and" to an "or" at the end of the sentence, i.e. Exclusions E1 or E3.
E3 (b): Use the same language in E1 (b), i.e. Only including generation resources not identified in Inclusions
I2, I3, I4, and I5.

Response: The SDT has accepted your proposed change for Inclusion I1.
The SDT has adopted the suggestion. Note that former Inclusions I2 and I3 have been combined into a new Inclusion I2.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
AltaLink

Yes

We agree with the concept of a bright-line definition and commend the SDT for developing a concept of
explicit inclusions and exclusions as part of the definition. This will reduce the number of exception
applications for some of the BES elements. However, the inclusion and exclusion requirements are extremely
restrictive. For example, radial characteristics should not be limited by the amount of installed generation or
single transmission source and/or require an interrupting device. Instead we believe that one or more
transmission sources could feed the radial load to provide redundancy as long as there is adequate protection
and isolation for improved customer-supply continuity and reliability. This should be considered radial as long
as the loss of any transmission source does not affect, and is not necessary for, the operation of the
interconnected transmission network.
We suggest the SDT and RoP teams should:
o Carefully craft the exception criteria and procedure to be flexible and technically sound, to allow entities to
adequately present their case to the ERO for inclusions or exclusions outside of the definition.
o Include provisions in both the NERC exception criteria and exception process for federal, state and

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Organization

Yes or No

Question 1 Comment
provincial jurisdictions. These provisions should provide clear guidance so that, if and when there are
deviations from the exception criteria, they are properly identified with technical and regulatory justifications
ensuring there is no adverse impact on the interconnected transmission network. This burden of proof should
be left to the entity seeking exception because it may be difficult if not impossible to define the exception
criteria. Further, if such an explicit criteria could be defined, it will in fact become another bright-line BES.

Response: See the responses to comments as well as a discussion of the latest revisions regarding the Radial Exclusion in Question 7.
The SDT appreciates your comments and suggestions for the Rules of Procedure exception process and will consider them in its deliberations.
Modern Electric Water Company

Yes

Taken by itself, the proposed core definition directly accomplishes the following: i) it re-affirms the 100kV
bright-line and ii) it removes Regional discretion to define the BES. However, the language continues to inject
ambiguity in that it introduces the use of the separately-defined capitalized term “Transmission”. In NERC’s
Glossary of Terms (May 24, 2011), “Transmission” is defined in terms of function rather than voltage. Strictly
interpreted, the core definition implies that only Elements used for the transfer of energy to points where it
transformed for delivery to customers as well as certain resources are considered to be included in the BES.
Under this viewpoint, there exists a two-stage qualifier for non-resource Elements - namely that it must first be
used for Transmission and not for “Distribution”, and secondly, that it be operated above 100kV. Rather, the
BES cannot contain Elements used for “Distribution” (a term not explicitly defined, but extrapolated from other
NERC glossary terms to mean the “wires” between the transmission system and the end-use customer, and
NOT defined by voltage). If this is the case, the SDT has established that an Element’s function is equally
important to its voltage, and has simultaneously excluded all Transmission Elements under 100kV - even if
used for bulk transfers. While the Exclusions detail characteristics of specific distribution-like Elements, we
suggest that the core BES definition contain language explicitly excluding Distribution (there are Elements
that are neither qualifying radials as defined in E1 nor local distribution networks as defined in E3).

Michgan Public Power Agency

Yes

My concern centers on the intent of FERC Order 743 language “we certify that this Final Rule will not have a
significant economic impact on a substantial number of small entities” still falls short from being met by this
definition change. This is a good start but additional work remains to be done. As pointed out in FERC Order
743A the 100 KV bright-line was not required but NERC can provide an alternative which can be supported
technically. Also I have concerns for the FERC Order 743A language “facilities used in the local distribution
of energy should be excluded from the revised bulk electric system definition” also needs additional work
remains to be done.

Response: The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power
resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.

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Organization

Yes or No

Question 1 Comment

The SDT elected to retain the 100 kV bright-line criteria. One goal of this project is to add clarity to the definition without significantly changing the population of
BES elements.
See the responses to comments regarding Local Distribution Facilities in Question 11 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
California Public Utilities
Commission

Yes

The CPUC supports the changes, especially the exclusions and the flexibility given to facilities to prove that
they are not part of the BES. However, the CPUC is concerned about the automatic imposition of
deterministic standards that are arbitrary rather than technically-based:
(1) the 100kV “bright line” test for transmission facilities, and the
(2) 20 MVA threshold for generating units.In general, the current BES definition is largely deterministic rather
than based on economics or probabilities.
An arbitrary number such as a “bright line” test should not be the singular gauge for inclusion in the BES. A
robust BES definition should consider the actual impact on the system and the cost. The courts have spoken
on the issue, Illinois Commerce Commission v. Federal Energy Regulatory Commission, 576 F.3d 476, and
instructed FERC to approve projects, “pricing scheme”, only if the benefits outweigh the cost.
Further, the 20 MVA threshold for generating facilities is coincident with the NERC threshold for registered
entities. While a logical threshold to require generators to register with NERC, the required reliability
assessments, and subsequent reliability upgrades may be prohibitively expensive for small generating units.

Response: The SDT elected to retain the 100 kV bright-line criteria. One goal of this project is to add clarity to the definition without significantly changing the
population of BES elements. This is the bright-line voltage level that is included in the existing approved definition of the Bulk Electric System in the NERC
Glossary of Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification was provided that would lead the SDT to make a
change.
See the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Sierra Pacific Power Co d/b/a

August 19, 2011

Yes

The revised core definition serves to address the directives of the Commission Order in 743 and 743A,

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Organization

Yes or No

NV Energy

particularly the elimination of regional discretion, and it also eliminates the ambiguity of the word “generally”.

City of St. George

Yes

Imperial Irrigation District

Yes

SERC Planning Standards
Subcommittee

Yes

ACES Power Participating
Members

Yes

Utility System Efficiencies, Inc.

Yes

Tennessee Valley Authority

Yes

Arizona Public Service Company

Yes

Western Electricity Coordinating
Council

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

Luminant Energy

Yes

Central Maine Power Company

Yes

New York State Electric & Gas
and Rochester Gas & Electric

Yes

US Bureau of Reclamation

Yes

Duke Energy

Yes

August 19, 2011

Question 1 Comment

The definition is okay as long as proper inclusions and exclusions are included in the definition.

No comments

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Organization

Yes or No

Alberta Electric System Operator

Yes

South Carolina Electric and Gas

Yes

MidAmerican Energy Company

Yes

Florida Keys Electric
Cooperative

Yes

East Kentucky Power
Cooperative, Inc.

Yes

Farmington Electric Utility
System

Yes

Colorado Springs Utilities

Yes

Sacramento Municipal Utility
District (SMUD)

Yes

GTC

Yes

Idaho Power

Yes

Long Island Power Authority

Yes

PJM

Yes

Oncor Electric Delivery
Company LLC

Yes

Xcel Energy

Yes

Golden Spread Electric

Yes

August 19, 2011

Question 1 Comment

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Organization

Yes or No

Question 1 Comment

Cooperative, Inc.
Exelon

Yes

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities
Group and Constellation Control
and Dispatch

Yes

No comment.

Response: Thank you for your support. Many stakeholders suggested revisions to the definition – and the drafting team made modifications that were
responsive to theses suggestions. Please see the revised definition.

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

2. Q2. The SDT has added specific inclusions to the core definition in response to industry comments. Do you
agree with Inclusion I1? If you do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: The SDT has made changes to Inclusion I1 of the BES definition based upon comments received from the
industry. These changes in the revised definition include removing the Generator Step-Up and Phase Angle Regulating transformer language,
changing the wording from “windings” to “terminals”, and adding the terms “primary” and “secondary”.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary
windingsterminals of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.

Organization
Tri-State Generation and
Transmission Association, Inc.

Yes or No

Question 2 Comment

No

We recommend changing I1 to the following: “Only transformers, including phase angle regulators, with two or
more windings of 100 kV or higher that are connected through automatic fault-interrupting devices, unless
excluded under Exclusions E1 and E3.” “Only” is required to prevent a regional interpretation that includes
distribution transformers since they are never specifically excluded.
The phrase regarding GSUs is removed since they are covered in I2 and I3.

Response: The SDT has addressed the issue of transformers serving local networks in the revised Exclusion E3 for the Local Network portion of the revised
version of the definition. A transformer serving a local network could be considered an “Element” that is part of the local network and would be excluded if so
justified by the characteristics of the exclusion. No change made.
The SDT agrees with your comment regarding GSUs and has made the appropriate revision in the revised version of the definition.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
NERC Staff Technical Review

No

Inclusion I1 is acceptable in general; however, there are two items that should be modified.>>>>>>>>>>
The reference to “two windings” is technically incorrect because it would exclude autotransformers with two
terminals at 100 kV or higher since the primary and secondary terminals are connected to the same winding.
It would be better to replace the phrase “with two windings of 100 kV or higher” with the phrase “with two or
more terminals connected at 100 kV or higher.”>>>>>>>>>>
The phrase “other than Generator Step-up (GSU) transformer” is unnecessary. The qualifier “with two or
more terminals connected at 100 kV or higher” already will exclude GSU transformers. In unusual cases in
which a generator is connected to the system through a transformer that does have two terminals connected
at 100 kV or higher the transformer should be included by Inclusion I1.

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Organization

Yes or No

Question 2 Comment

Response: The SDT has made appropriate changes in the revised version of the definition regarding both comments.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
NERC Transmission Issues
Subcommittee (TIS)

No

It is not necessary to exclude generator step-up transformers because a GSU should be considered to be part
of the generating Unit. >>>>>>>>>>
The reference to two windings is technically incorrect because it would exclude autotransformers which
technically only have one winding. It would be better to say that both the high-side and the low side of the
transformer connected at 100 kV or higher. >>>>>>>>>>
“I1 - Transformers, other than generator step-up (GSU) transformers, including phase angle regulators, with
two windings both the high-side and the low side of the transformer connected at 100 kV or higher unless
excluded under Exclusions E1 and E3.”

Response: The SDT has deleted the GSU language in the revised Inclusion I1.
The SDT has changed the wording from “windings” to “terminals” in the revised version of the definition.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Dominion

No

While Dominion appreciates the SDT’s attempt to respond to initial comments, unfortunately the response
does not squarely address Dominion’s concerns. Rather, the SDT proposes that all transformers, whether for
transmission or generation should be included. The SDT’s response to SERC also seems to indicate that the
facility associated with generators should be included in the BES. In order to provide clarity Dominion
restates its comment. Dominion’s position is that all transformers with two windings at 100 kV or higher
should be included in the BES. Dominion does not agree that a transformer with two windings at 100 kV or
higher should be excluded merely because it is a generator step up (GSU). And, while Dominion does not
agree that a generation resource, Element or Facility should automatically be classified as part of the BES, if
the SDT decides to do so, then it is Dominion’s position that the GSU should also be included in the BES. It
doesn’t seem to make sense to include the generator itself, but exclude an associated element that is
operated at 100 kV or above. If the SDT’s intent was to ‘carve out’ GSUs in Inclusion -I1, but to include GSUs
in Inclusion I2 and 3, then Dominion suggests revising the phrase “....including the generator terminals
through the GSU....” to read “....including the generator terminals and the GSU.”

Response: The SDT agrees with the inclusion of all generation and transmission transformers and has attempted to provide clarity in the revised version of the

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Organization

Yes or No

Question 2 Comment

definition.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary
windingsterminals of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Overton Power District No. 5

No

clarification is needed to identify which transformers to include in the BES

Tennessee Valley Authority

No

We suggest I1 to read, “Transformers, other than generator step-up (GSU) transformers, including phase
angle regulators, having two windings of 100 kV or higher, unless excluded under Exclusions E1 or E3.
Transformers having only one winding of 100 kV or higher are excluded.”

Central Maine Power Company

No

By definition above, a transformer with a 100 kV winding is already an “element operated at 100 kV or above.”
This inclusion is actually intended to exclude transformers with only one winding operated at 100 kV or higher
voltage. Therefore, Inclusion I1 should be deleted and a new Exclusion should be made: “Transformers with
only one winding of 100 kV or higher, including phase angle regulators, unless included under Inclusions I2,
I3, or I5.”

Hydro-Quebec TransEnergie

No

Since transformers are already part of "all transmission Elements operated at 100 kV and above" in the
definition, and since inclusions I2 to I5 are commonly related to only generation, I1 should be removed and
replace instead by the following Exclusion: Ex "Transformers not used as Generator Step-Up (GSU)
transformers that have primary or secondary winding at less than 100 kV."

Consumers Energy Company

No

The facilities currently listed in Inclusion I1 are already arguably included in the core definition. Inclusion I1
should be reclassified as an Exclusion to cover transformers that do not meet the criteria in Inclusion I1 such
as those transformers with a single winding of 100kV or higher. Following is our proposed language for the
exclusion we are proposing. Transformers, other than Generator Step-up (GSU) transformers, including
Phase Angle Regulators, that have less than two windings of 100 kV or higher.

Southern California Edison
Company

No

Identifying specific equipment within the “Inclusions” or “Exclusions” component is too prescriptive, and
itemizing them in this fashion misses the intent of this endeavor which should be to ultimately ensure the risks
to region wide reliability are captured.Therefore, it is SCE’s position that the proposed BES Definition should
not single out specific pieces of equipment, and that they should be included or excluded based on the criteria
of the definition. To do otherwise could: (i) generate confusion due the many types and variations of
equipment, and what should/should not be included In the BES; and(ii) include radial or distribution systems
into scope that might not otherwise have been considered, and which pose no regional reliability risk. If the
BES Definition continues to reference transformer types, it should clarify what specific attributes qualify for
inclusion. This might best reside in companion documentation that would accompany the definition to ensure

New York State Electric & Gas
and Rochester Gas & Electric

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Organization

Yes or No

Question 2 Comment
consistency in application.

Clark Public Utilities

No

Transformers should only be part of the Bulk Electric System if they are transforming voltage from one BES
element to another BES element. The current inclusion language would apply to all transformers with two
windings operated at greater the 100 kV subject to the E1 and E3 exclusions. There is no indicated exclusion
referring to the exception process. If a facility is excluded from the BES by the exception process, connected
transformers should also be excluded. Clark believes if the inclusion language was changed slightly, the
exclusion references to E1 and E3 would not be necessary. Without this change, it appears that a transformer
with two winding connected to greater than 100 kV would be a BES asset even if both of the facilities these
windings were connected to had been excluded (E1 or E3) or excepted (BES Exception Process). I1 should
be rewritten to state: Transformers, other than generator step-up (GSU) transformers, including phase angle
regulators, with two windings of 100 kV or higher connected to Transmission Elements determined to be part
of the Bulk Electric System.

Independent Electricity System
Operator

No

We agree with the concept of Inclusion I1. We suggest that since transformers with at least two windings
greater than 100 kV are already part of "all transmission Elements operated at 100 kV and above" in the
definition, and since inclusions I2 to I5 are commonly related to only generation, Inclusion 1 should be
removed and replace by the following Exclusion: E(x)”Transformers that have a primary or secondary winding
at less than 100 kV except for those included by I2 and I3”

BPA

No

Transformers, other than generator step-up (GSU) transformers, including phase angle regulators, with two
windings of 100 kV or higher unless excluded under Exclusions E1 and E3.

American Municipal Power and
Members

Yes

We support I2, but propose clarifying edits. To minimize possible confusion as to the category of
transformers being addressed in I1, and the sufficiency of a single applicable Exclusion, we suggest the
following rewording: “Transformers, including phase angle regulators, and not including generator step-up
(GSU) transformers, with two windings of 100 kV or higher unless excluded under Exclusion E1 or E3.”

Transmission Access Policy
Study Group

Yes

To minimize possible confusion as to the category of transformers being addressed in I1, and the sufficiency
of a single applicable Exclusion, TAPS suggests the following rewording: “Transformers, including phase
angle regulators, and not including generator step-up (GSU) transformers, with two windings of 100 kV or
higher unless excluded under Exclusion E1 or E3.”

Northern California Power
Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.

Florida Municipal Power Agency

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Organization

Yes or No

Question 2 Comment

Illinois Municipal Electric Agency

Yes

With the following clarifying edits. “Transformers, including phase angle regulators, and not including
generator step-up (GSU) transformers, with two windings of 100 kV or higher unless excluded under
Exclusion E1 or E3.”

Idaho Power

Yes

I generally agree but the definition accidently excludes autotransformers. It should be restated as
transformers with two terminal at or above 100 kV. Also, there should be clarification about any tertiary
windings that a transformer might have. I would assume that the tertiary winding and any real or reactive load
or generation connected to it to be excluded as the tertiary winding are typically of distribution class voltage.
Finally, there is no need to exclude GSUs in this definition because they will be excluded unless the two
terminals are at 100 kV or above. Additionally, the GSUs will be covered by other inclusion statements related
to generators.

Xcel Energy

Yes

The drafting team should consider how components such as autotransformers would be considered under
this aspect, and if additional language needs to be added to clearly include certain autotransformers.

Response: The SDT has revised Inclusion I1 to provide more clarity on specifically which transformers are included in the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Western Montana Electric
Generating and Transmission
Cooperative

No

In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped down
from transmission voltages to distribution voltages. We believe, however, that the SDT should undertake the
effort to more clearly define the point where the BES ends and non-BES systems begin. In this regard, we
note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted considerable effort
to this question and has developed one-line diagrams noting the BES demarcation point for a number of
different kinds of Elements that are common in the Western Interconnection. Using this work as a starting
point, the SDT should be able to provide much useful guidance to the industry with relatively little additional
effort.
Also, the reference to “two windings of 100 kV or higher” may create some confusion because many threephase transformer banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We
suggest clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”
We again urge the SDT to consider further delineation of points of demarcation similar to WECC BESDTF

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Organization

Yes or No

Question 2 Comment
Proposal 6.

Sierra Pacific Power Co d/b/a NV
Energy

No

We agree with the concept; however there are two issues that must be resolved. First, the “two windings”
language should be changed to “two terminals”, as in the case of an auto-transformer, there is technically only
one winding, and it would fail to be included in this inclusion designation as written.
Second, a literal read could have an unintended interpretation that transformers with fewer than 2 windings at
100kV might still be included through the core definition. The SDT should consider whether this I1 inclusion
item would be better applied in the converse as an exclusion designation.

Chelan PUD – CHPD

No

Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc.
Cowlitz County PUD

In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped down
from transmission voltages to distribution voltages. We believe, however, that the SDT should undertake the
effort to more clearly define the point where the BES ends and non-BES systems begin. In this regard, we
note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted considerable effort
to this question and has developed one-line diagrams noting the BES demarcation point for a number of
different kinds of Elements that are common in the Western Interconnection. Using this work as a starting
point, the SDT should be able to provide much useful guidance to the industry with relatively little additional
effort.
Also, the reference to “two windings of 100 kV or higher” may create some confusion because many threephase transformer banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We
suggest clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”We again
urge the SDT to consider further delineation of points of demarcation similar to WECC BESDTF Proposal 6.

Public Utility District No. 1 of
Snohomish County, Washington
Clallam County PUD No.1

August 19, 2011

Yes

In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped down
from transmission voltages to distribution voltages. We believe, however, that the SDT should undertake the
effort to more clearly define the point where the BES ends and non-BES systems begin. In this regard, we
note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted considerable effort
to this question and has developed one-line diagrams denoting the BES demarcation point for a number of
different kinds of Elements that are common in the Western Interconnection. See WECC BES Definition Task
Force Proposal 6, Appendix C (available at: http://www.wecc.biz/Standards/Development/BES/default.aspx).
Similarly, the FRCC’s BES Definition Clarification Project has devoted considerable effort to developing oneline diagrams of transmission and distribution Elements, and identifying the point of demarcation between
BES and non-BES Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B
(available at: https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT

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Organization

Yes or No

Question 2 Comment
should be able to provide much useful guidance to the industry with relatively little additional effort.
Also, the reference to “two windings of 100 kV or higher” may create some confusion because many threephase transformer banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We
suggest clarifying this provision by changing the clause referencing two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”

Response: The SDT has changed the wording from “windings” to “terminals” in the revised version of the definition. The SDT has revised Inclusion I1 to
provide more clarity on specifically which transformers are included in the BES. The SDT will consider the suggestions to incorporate the WECC work into its
effort.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
PacifiCorp

No

Transformers with two or more windings greater than 100 kV exclusively serving local distribution networks
should be excluded from the BES.

Response: The SDT has addressed the issue of transformers serving local networks in the revised Exclusion E3 for the local network portion of the revised
version of the definition. A transformer serving a Local Network could be considered an “Element” that is part of the local network and would be excluded if so
justified by the characteristics of the exclusion. No change made.
Electric Reliability Council of
Texas, Inc.

No

ERCOT ISO agrees that such equipment should be considered for inclusion, but suggests that these issues
be addressed relative to the criteria for evaluation in the exception process. In other words, this inclusion
doesn’t need to be explicitly identified. It would simply be included under the general 100 kV threshold, and to
the extent an owner believed the characteristics of its equipment don’t warrant inclusion, it would seek an
exception.

Response: The SDT believes the BES definition should be “bright-line” criteria and be able to include a very high percentage of the facilities by inspection. The
exception criteria and process is meant to handle very few facilities. The BES definition and exemption process have been developed under this guiding concept.
No change made.
Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

No

Inclusion I1 would be unlawful to the extent that it would include the transformers of retail customers that have
self-provided “hard-tapped” facilities behind the retail delivery point. (For the purposes of these Comments,
“hard-tapped” means connected without an automatic fault-interrupting device).

Response: The SDT believes that retail customer transformers could be excluded based upon Exclusions E1 or E3. No change made.

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Organization
Kootenai Electric Cooperative

Yes or No

Question 2 Comment

No

In concept, Kootenai supports the SDT’s attempt to provide a clear demarcation between the BES and nonBES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin. In this
regard, we note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams noting the BES demarcation point
for a number of different kinds of Elements that are common in the Western Interconnection. Using this work
as a starting point, the SDT should be able to provide much useful guidance to the industry with relatively little
additional effort. We again urge the SDT to consider further delineation of points of demarcation similar to
WECC BESDTF Proposal 6.

Yes

We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES elements.
Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped down from
transmission voltages to distribution voltages. We believe, however, that the SDT should undertake the effort
to more clearly define the point where the BES ends and non-BES systems begin. We note that the WECC
Bulk Electric System Definition Task Force (“BESDTF”) has devoted considerable effort to this question and
has developed one-line diagrams denoting the BES demarcation point for a number of different kinds of
Elements that are common in the Western Interconnection. See WECC BES Definition Task Force Proposal
6, Appendix C (available at: http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the
FRCC’s BES Definition Clarification Project has devoted considerable effort to developing one-line diagrams
of transmission and distribution Elements, and identifying the point of demarcation between BES and nonBES Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should be able to
provide much useful guidance to the industry with relatively little additional effort.

Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative

Blachly Lane Electric Cooperative
PUD No. 2 of Grant County,
Washington
Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc.
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric

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Organization

Yes or No

Question 2 Comment

No

In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped down
from transmission voltages to distribution voltages. We believe, however, that the SDT should undertake the
effort to more clearly define the point where the BES ends and non-BES systems begin. In this regard, we
note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted considerable effort
to this question and has developed one-line diagrams noting the BES demarcation point for a number of
different kinds of Elements that are common in the Western Interconnection. Using this work as a starting
point, the SDT should be able to provide much useful guidance to the industry with relatively little additional
effort. Also, the reference to “two windings of 100 kV or higher” may create some confusion because many
three-phase transformer banks have 6 or 9 windings, depending on whether the transformer has a tertiary.
We suggest clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”We again
urge the SDT to consider further delineation of points of demarcation similar to WECC BESDTF Proposal 6.

Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative

Northern Wasco County PUD

Response: The SDT will consider the suggestions to incorporate the WECC work and FRCC work into its effort.
Public Utilities Commission of
Ohio

No

FERC jurisdiction is limited by the Federal Power Act, Section 215. To make a bright line designation as the
starting point, without a demonstration that ALL facilities at 100 kV and greater affect the reliability of the bulk
power system is a step beyond FERC jurisdictional boundaries. The Federal Power Act explicitly excludes
facilities used in local distribution from the bulk power system. NERC should give serious consideration to
other (non bright-line) approaches to ensure bulk system reliability.

Response: The task of the SDT is to put forward a 100 kV bright-line for the BES definition. The SDT has modified the definition and distribution facilities are
now specifically excluded from the BES. However, the SDT acknowledges that there may still be regulatory conflicts as many of the commenters have voiced. The
definition is neither intended to nor can it supersede any regulatory orders and/or rulings by relevant Federal, State, or Provincial Authorities. Although the SDT
can not resolve all regulatory conflicts, it believes that a) proposed revisions to the definition should address many of these concerns; and b) remaining issues
may be effectively addressed by the Rules of Procedure exception procedure currently under development.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and

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Organization

Yes or No

Question 2 Comment

Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
The Dow Chemical Company

No

An additional exclusion for industrial distribution facilities needs to be added for the reasons expressed in
Dow's comments on Exclusion E3. Dow's manufacturing sites have transformers, other than generator step
up transformers, that have two windings of 100 kV or higher and that are between on-site generation and
individual manufacturing plants at such sites. Such transformers should be excluded, because they are part of
electricity distribution facilities. However, such transformers do not fall within proposed Exclusion E1 or E3.

Response: If a manufacturing site’s facilities cannot meet the exclusion criteria, then those facilities must be part of the BES. There may be instances where
customer facilities are part of the BES. See response to Question 9. No change made.
Central Lincoln

No

We support the SDT’s intent, but it is unclear from the language how single winding transformers
(autotransformers) are handled. We suggest replacing “two windings...” with “two sets of terminals....”
Please also indicate how transformers with only one set of terminals above 100 kV are treated, since we don’t
believe the flowchart at http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly
expresses the SDT’s intent to classify these transformers as non-BES.

United Illuminating

No

Inclusion I1 is an attempt to limit the scope of the core definition to only those transformers with a high and
low side connection at or above 100 kV. However it is not clear that a transformer connected solely on the
high side at 100 kV, that is a distribution transformer, is not included in the BES by the definition. This is
because the core definition includes all transmission elements connected at 100 kV, this would include the
distribution transformer. Then Inclusion I1 does not eliminate the distribution transformer explicitly. It is only
implied that the core definition applies only to those transformers with a high and low side connection at or
above 100 kV. UI would prefer a more explicit description. Such as: I1- Only those Transformers, including
phase angle regulators, with two windings of 100 kV or higher unless excluded under Exclusions E1 and E3
are included in the definition of BES. Generator Step Up Transformers are included based on the generator. A
similar comment can be made for the other inclusions. An alternative solution is to change word Inclusions to
a sentence that explicitly states: for the category of element below only include the type of equipment
specified.
Also The use of the descriptor two windings implies auto transformers with one winding is excluded. UI
understands that is not the intent of the team.

Response: The SDT has changed the wording from “windings” to “terminals” in the revised version of the definition. The SDT has revised Inclusion I1 to
provide more clarity on specifically which transformers are included in the BES.

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Organization

Yes or No

Question 2 Comment

Transformers with only one set of terminals operated above 100 kV would not be included in the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Oncor Electric Delivery Company
LLC

No

The reference to two windings is technically incorrect because it would exclude autotransformers which
technically only have one winding. Recommend rephrasing this to say that both the high-side and the low
side of the transformer connected at 100 kV or higher.I1 Suggested Language:”I1 - Transformers, including
phase angle regulators, with both the high-side and the low side of the transformer connected at 100 kV or
higher unless excluded under Exclusions E1 and E3.”

Manitoba Hydro

No

Inclusion I1 requires clarification. The intention of I1 is to include transformers that have both their primary
and secondary windings operated at 100kV and the wording in I1 should reflect this. Requiring that only ‘two
windings’ must be connected at 100kV or greater for inclusion is not sufficient in the case of 3 separate single
phase banks connected to form a delta-wye connection for example. As currently written, even if only the
primary windings of this bank were connected at greater than 100kV, this transformer would be included in
the BES regardless of the secondary voltage.
-Suggested wording: “Transformers, other than Generator Step-up (GSU) transformers, including Phase
Angle Regulators, that are connected at 100kV or above on their primary and secondary windings unless
excluded under Exclusions E1 and E3.OR”Transformers, other than generator step-up (GSU) transformers,
including phase angle regulators, with two windings of 100 kV or higher in the same phase unless excluded
under Exclusions E1 and E3.”

Tacoma Power

Western Electricity Coordinating
Council

Tacoma Power agrees with Inclusion I1. However, we believe the reference to ‘two windings’ is ambiguous
and propose changing it to read,”Transformers, other than Generator Step-up (GSU) transformers, including
Phase Angle Regulators, with two or more connections to Elements at 100 kV or higher, unless excluded
under Exclusions E1 and E3.”
Yes

WECC agrees in concept and understands that the intent of the phrase “other than GSU transformers” was
used to prevent duplication or conflict with I2. However, it has the unintended consequence of creating the
appearance that GSU transformers are not included in the definition, which is more of a conflict. By removing
this phrase, such transformers would be clearly included because, if both terminals are connected at greater
than 100 kV, it will also be true that the high side is connected at greater than 100 kV, per I2. WECC suggests
removing this phrase.
Also, the final statement more appropriately should be “...unless excluded under Exclusions E1 or E3.”

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Organization

Yes or No

Question 2 Comment
Finally, the term “two windings” may be technically incorrect because some transformers may only have one
winding. This wording would exclude single-winding transformers at or above 100 kV. One option may be to
change the language to “two terminals” instead of “two windings.” It may also be useful to clarify that
transformers with one terminal above and one terminal below 100 kV should be excluded.

Portland General Electric
Company

Yes

The reference to “two windings” will cause confusion. Presumably theStandard Drafting Team means two
three-phase windings, which would mean that boththe high sides and the low sides of a typical transformer
bank would have to beoperating at 100kV and above in order to be part of the BES. In other words,
a230kV/57kV transformer would not be included, despite the fact that all three windingsthat make up the high
side are individually rated at over 100kV. The inclusion needs tomake clear that it’s talking about two or more
sets of windings, each set consisting ofthree phases.

Sacramento Municipal Utility
District (SMUD)

Yes

Sacramento Municipal Utility District (SMUD) agrees with the concept of Inclusion 1. However, to ensure a
clarity of the “Bright-Line” criteria, two items for the Drafting Team (DT) to consider are: 1) removal of the
phrase other than GSU as it may lead to confusion. The GSUs typically have one winding below 100 kV that
disqualify their inclusion.
2) Reference to the transformer terminals each above 100 kV would reduce confusion for single winding
transformers and multiple winding transformers.

Long Island Power Authority

Yes

For clarification it is recommended that “windings” be replaced with “connection points”.

Modern Electric Water Company

Yes

The use of “terminals” rather than “windings” might be more clear.

Response: The SDT has changed the wording from “windings” to “terminals” in the revised version of the definition. The SDT has revised Inclusion I1 to
provide more clarity on specifically which transformers are included in the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Consolidated Edison Co. of NY,
Inc.

No

Recommended changes to the wording used in Inclusion I#1, et al:Formatting - When referring to an Inclusion
(or Exclusion), the SDT should use a number/pound sign (“#”) between the “I” and number to avoid confusing
“I” with the numerical value “1.”

Response: The comment isn’t related to the question and will be considered by the technical writers when the final draft is written. No change made.

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Organization

Yes or No

ATCO Electric

Question 2 Comment
While we agree generally with the inclusion, we have some questions based on specific examples:
1. A load substation has two 144/25kV transformers that connects to two separate 144kV transmission lines
(i.e. two separate 144kV buses). However, the two transformers joins on one 25kV bus. Should these two
144/25kV transformers be part of BES?
2. A protection relay is on 72kV side of a 144/72 tie transformer and its purpose is to remove 72kV weak
source (i.e. trip 72kV breakers) during 144kV bus fault. Should this protective relay be included in BES?
3. According to Inclusion I1, a 144/25kV transformer is not a BES element. The transformer's 144kV side has
a Motor Operated Disconnecting Switch (MOD), and this MOD connects to one or two 144kV line breakers.
The transformer's protections trip the 144kV line breakers. Should the transformer protection systems be part
of BES?

Response: 1. The two transformers cited in the comment would not be part of the BES based upon Inclusion I1 of the definition.
2. This relay cited in the comment would not be part of the BES because it trips a less than 100 kV interrupting device.
3. The substation configuration would need to be reviewed before a determination could be made on whether the protection system cited in the comment is part
of the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
MRO's NERC Standards Review
Forum

Yes

Please clarify that an exclusion would be a tertiary winding for example an auto transformer.

Response: The SDT has revised Inclusion I1 to provide more clarity on specifically which transformers are included in the BES. As an example, a 345/138 kV
transformer with a 23 kV tertiary winding would be included in the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
ACES Power Participating
Members

August 19, 2011

Yes

We agree with limiting transformers to bulk power transformers and not including step-down or distribution
transformers. Some regions have been enforcing standards on protection equipment that is on the low-side
of these step-down or distribution transformers. Additional language further clarifying that this low-side
protection equipment is not part of the BES should be added to for consistency across regions.Additionally,
the drafting team might consider using the terms primary and secondary rather than windings. Otherwise,

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Organization

Yes or No

Question 2 Comment
autotransformers which have a sing

Response: The SDT has changed the wording from “windings” to “terminals” in the revised version of the definition. The SDT has revised I1 to provide more
clarity on specifically which transformers are included in the BES. Associated protection system equipment will be handled separately via the PRC standards.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Hydro One Networks Inc

Yes

We agree with the concept of Inclusion I1. However, we suggest that since transformers are already covered
by the definition, "all transmission Elements operated at 100 kV and above", and since Inclusions I2 to I5 are
commonly related to generation only, Inclusion I1 should be removed and replaced by the following Exclusion:
E(x) "Transformers not used as Generator Step-Up (GSU) transformers that have primary or secondary
winding at less than 100 kV."
We also suggest the SDT to put forward a high-level exception criteria with key menu items of assessment
that can be followed continent-wide by entities to put forward their exception for element(s) mentioned in
Inclusion I1, or any other inclusion(s). These inclusion(s) that are intended for exemption would be based on
the entity’s technical assessment, evidence and justification for its unique characteristics, configuration, and
utilization.

Response: The SDT has revised Inclusion I1 to provide more clarity on specifically which transformers are included in the BES.
The SDT believes the BES definition should be “bright line” criteria and be able to include a very high percentage of the facilities by inspection. The exemption
criteria and process is meant to handle very few facilities. The BES definition and exemption process have been developed under this guiding concept.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
FHEC

Yes

Believe that the NERC Statement of Compliance Registry Criteria should be revised to reflect only thsese
inclusions and exclusions. An entity with no assets that meet this definition should be allowed to de-register.

Response: Revision of registry criteria is not part of this project. No change made.
Vermont Transco

August 19, 2011

Yes

This inclusion’s wording allows an entity to easily identify which of its transformers will be included as BES
and also adheres directly to the FERC identified 100kV or higher equipment. Question: if a transformer does
not have two windings of 100 kV or higher but does have protection devices that could open the BES system,
e.g. due to a low-voltage failed breaker scenario, would the protective devices be part of the BES even

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Organization

Yes or No

Question 2 Comment
though the transformer itself is not?

Response: Associated protection system equipment will be handled separately via the PRC standards. No change made.
National Grid

Yes

We would like some clarification regarding three-winding transformers, for example a 345/115/23 kV
transformer. Was the intention to include the 23kV in the new definition of BES? If so, it seems likely that
other 23 kV components on the buswork could be pulled into the definition of BES if it is in the zone of
protection of the transformer.

Response: The cited 345/115/23 kV transformer in the comment would be included in the BES since it has both primary and secondary terminals operated
above 100 kV. The SDT has changed the wording from “windings” to “terminals” in the revised version of the definition. The SDT has revised Inclusion I1 to
provide more clarity on specifically which transformers are included in the BES. The 23 kV facilities would not be included in the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
City of Redding

Yes

Redding supports the concept of additional inclusions to the brightline if the objective is to further hone the
generalness of the proposed definition. As we stated in question #1, we support the definition as long as an
entity has the ability to seek an exception via a fair and objective Exception Process. If the SDT keeps
inclusion 1, we believe it is overly broad and should have additional clarification added to address the various
types of transformers such as auto transformers, three phase “Y” transformers, transformers with tertiary
windings, etc. Additionally, the exclusion “other than generator step-up (GSU) transformers” could easily be
interpreted to mean “all” GSU transformers regardless of voltage. Redding suggests that I1 be changed to read:
“Transformers, including phase angle regulators, with both high side and low side windings connected at 100
kV or higher unless excluded under E1 or E3 and generator step-up (GSU) transformers, serving generators
in I2 and I3, with the high-side winding connected at 100 kV or higher.”

FortisBC

Yes

We agree with the concept of Inclusion I1. However, we suggest that since transformers are already covered
by the definition, "all transmission Elements operated at 100 kV and above", and since Inclusions I2 to I5 are
commonly related to generation only, Inclusion I1 should be removed and replaced by the following Exclusion:
E(x) "Transformers not used as Generator Step-Up (GSU) transformers that have primary or secondary
winding at less than 100 kV."
We also suggest the SDT to put forward a high-level exception criteria with key menu items of assessment
that can be followed continent-wide by entities to put forward their exception for element(s) mentioned in
Inclusion I1, or any other inclusion(s). These inclusion(s) that are intended for exemption would be based on
the entity’s technical assessment, evidence and justification for its unique characteristics, configuration, and

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Organization

Yes or No

Question 2 Comment
utilization.

AltaLink

Yes

We agree with the concept of Inclusion I1. However, we suggest that since transformers are already covered
by the definition, "all transmission Elements operated at 100 kV and above", and since Inclusions I2 to I5 are
commonly related to generation only, Inclusion I1 should be removed and replaced by the following Exclusion:
E(x) "Transformers not used as Generator Step-Up (GSU) transformers that have primary or secondary
winding at less than 100 kV."We also suggest the SDT to put forward a high-level exception criteria with key
menu items of assessment that can be followed continent-wide by entities to put forward their exception for
element(s) mentioned in Inclusion I1, or any other inclusion(s). These inclusion(s) that are intended for
exemption would be based on the entity’s technical assessment, evidence and justification for its unique
characteristics, configuration, and utilization.

Response: The SDT believes the BES definition should be “bright-line” criteria and be able to include a very high percentage of the facilities by inspection. The
exemption criteria and process is meant to handle very few facilities. The BES definition and exception process have been developed under this guiding concept.
The SDT has revised Inclusion I1 to provide more clarity on specifically which transformers are included in the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Springfield Utility Board

Yes

In concept, SUB supports an attempt to provide a clear demarcation between BES and non-BES elements.
The WECC Bulk Electric System Definition Task Force (BESDTF) has devoted considerable effort to this
question and has developed one-line diagrams which note the BES demarcation point for a number of
different kinds of elements that are common in the Western Interconnection.

Springfield Utility Board

Yes

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of

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Organization

Yes or No

Question 2 Comment
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: The SDT will consider the suggestions to incorporate the WECC work into its effort.
See the answers to Questions 7, 8, and 9 related to generation.
New England States Committee
on Electricity

Yes

Inclusion I1 now appears to exclude transformers that connect the BES to the sub transmission networks (the
sub transmission elements connected to one of the windings is less than 100 kV). This suggests that the
intent of this language is to exclude such transformers and all sub transmission elements (unless included by
the other Inclusion criteria) from the BES. With that understanding, NESCOE supports Inclusion I1.

Southwest Power Pool

Yes

SPP agrees that such equipment should be included, but suggests that these issues be addressed in the
exception process. In other words, this inclusion doesn’t need to be explicitly identified. It would simply be
included under the general 100 kV threshold, and to the extent an owner believed the characteristics of its
equipment don’t warrant inclusion, it would seek an exception, which can be for either an exclusion or an
inclusion.

City of Anaheim

Yes

Change the "and" to an "or" at the end of the sentence, i.e. Exclusions E1 or E3.This appears to be the intent.

Response: The SDT has revised Inclusion I1 to provide more clarity on specifically which transformers are included in the BES. Your understanding is correct.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Michgan Public Power Agency

Yes

Sweeny Cogeneration LP

Yes

Transmission system transformers are not part of our existing or anticipated base of facilities.

Western Area Power
Administration

Yes

Appreciate the bullet comments that help explain the reasoning for the inclusion.

Public Service Enterprise Group
LLC

Yes

Northeast Power Coordinating

Yes

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Organization

Yes or No

Question 2 Comment

Council
Imperial Irrigation District

Yes

Santee Cooper

Yes

SPP Standards Review Group

Yes

SERC Planning Standards
Subcommittee

Yes

SERC OC Standards Review
Group

Yes

National Rural Electric
Cooperative Association
(NRECA)

Yes

Arizona Public Service Company

Yes

ReliabilityFirst

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

New York State Reliability
Council

Yes

New York Power Authority

Yes

Southern Company

Yes

Luminant Energy

Yes

Intellibind

Yes

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Organization

Yes or No

US Bureau of Reclamation

Yes

Grand Haven Board of Light and
Power

Yes

Glacier Electric Cooperative

Yes

South Texas Electric
Cooperative, Inc.

Yes

South Texas Electric
Cooperative, Inc.

Yes

Dayton Power and Light
Company

Yes

ExxonMobil Research and
Engineering

Yes

Duke Energy

Yes

Alberta Electric System Operator

Yes

South Carolina Electric and Gas

Yes

Fayetteville Public Works
Commission

Yes

MidAmerican Energy Company

Yes

Florida Keys Electric Cooperative

Yes

American Electric Power

Yes

August 19, 2011

Question 2 Comment

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Organization

Yes or No

East Kentucky Power
Cooperative, Inc.

Yes

American Transmission
Company, LLC

Yes

Farmington Electric Utility System

Yes

Colorado Springs Utilities

Yes

Muscatine Power and Water

Yes

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

Yes

Exelon

Yes

City of St. George

Yes

Puget Sound Energy

Yes

GTC

Yes

Cogentrix Energy, LLC

Yes

Pepco Holdings Inc

Yes

PJM

Yes

ISO New England, Inc.

Yes

August 19, 2011

Question 2 Comment

No comment.

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Organization

Yes or No

MEAG Power

Yes

Orange and Rockland Utilities,
Inc.

Yes

Golden Spread Electric
Cooperative, Inc.

Yes

Idaho Falls Power

Yes

Question 2 Comment

It seems reasonable to conclude that such transformers would belong in a classification that comprises the
BES.

Response: Thank you for your support. The SDT has made changes to Inclusion I1 of the BES definition based upon other stakeholder comments. These
changes in the revised definition include removing the Generator Step-Up and Phase Angle Regulating transformer language, changing the wording from
“windings” to “terminals”, and adding the terms “primary” and “secondary”. Please see the revised definition.

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3. The SDT has added specific inclusions to the core definition in response to industry comments. Do you agree
with Inclusion I2? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration:
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any
attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice
with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743
and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC
Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from
SDT deliberations.
Changes have been made to Inclusion I2 for clarity.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or
gross aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV
or above.

Organization

Yes or No

Public Service
Enterprise Group
LLC

Question 3 Comment

No

See comment 1 above.

No

I2 should pertain to individual generating units, but the entire path should not be labeled as BES.
Oftentimes there are cases when neither the path nor a 20 MVA unit itself will have any impact on
the reliability of the interconnected transmission network, nor is it necessary for its operation. The
path to generating facilities does not need to be BES contiguous. Generating units can be required
to be planned, designed, and operated in accordance with a subset of NERC Standards, but
should not require a contiguous path unless the unit is identified essential for the operation of
transmission network.

Response: See response to Q1 above.
Northeast Power
Coordinating
Council

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Organization

Yes or No

Question 3 Comment

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the generator step up transformer which is connected on the high
side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to the
BES.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
NERC Staff
Technical Review

No

The interconnection voltage threshold should be removed. The contribution of a generator to
system reliability is a function of its MVA rating rather than its interconnection voltage. All
generating units greater than 20 MVA should be included in the BES definition because all such
units provide similar contributions to system reliability. >>>>>>>>>>
Also, the specific inclusion of the GSU transformer implies that all other components of a
generating unit, such as its unit auxiliary transformer, start-up transformer, governor, exciter,
power system stabilizer, etc., are excluded. The SDT should define “generating unit” or otherwise
clarify which components of a generating unit are included in the BES definition.

Response: The SDT has changed the terminology in the definition to include “generating resources” for clarity. Balance of Plant equipment is not included in the
contiguous path of the generator and therefore does not fall under the definition. The SDT carefully debated the generating threshold for inclusion in the
definition. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
NERC Transmission

August 19, 2011

No

It is commonly understood that a generating unit includes the generator itself, and all of the

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Organization

Yes or No

Issues
Subcommittee (TIS)

Question 3 Comment
components that connect it to the grid, including the GSU. The specific inclusion of the GSU
implies that other components of a generating unit, such as its auxiliary transformers and loads,
the governors, exciters, etc., are not included. >>>>>>>>>>
The TIS suggests the following wording: >>>>>>>>>>“I2 - Individual generating units greater than
20 MVA (gross nameplate rating) generator terminals through the GSU which has a high side
connected at a voltage of 100 kV or above.”

Response: The SDT has changed the terminology in the definition to include “generating resources” for clarity. Balance of Plant equipment is not included in
the contiguous path of the generator and therefore does not fall under the definition.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Dominion

No

As stated in its response to Question 2 above, Dominion disagrees that a generation resource,
Element or Facility should automatically be included in the BES. Dominion agrees that the
Generator Owner and Generator Operator, as users of the bulk power system, should have to
abide by applicable reliability standards, but do not agree that this should automatically require the
inclusion of a generation resource, Element or Facility in the BES.
Further, Dominion prefers that the SDT use the term “generation resources” as stated in the
current BES definition contained in the Glossary of Terms instead of the proposed term
“generating unit”.

Response: The SDT has changed the terminology in the definition to include “generating resources” for clarity. The SDT carefully debated the generating
threshold for inclusion in the definition. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any
attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will
be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach
to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.

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Organization
SPP Standards
Review Group

Yes or No

Question 3 Comment

No

With the inclusion of a voltage criteria in the definition an inconsistency is created between
Elements that are not a part of the BES but are still required to be part of the NERC Compliance
Registry. Does this create an issue? Did the SDT intend to create this inconsistency? A large
generating unit or group of units that are connected to the interconnection via 69kV does not
qualify as a part of the BES. Although the generation level could be substantial, it is still not a part
of the BES. If said generation is 20 MVA or 75 MVA, respectively, it would have to be registered in
the Compliance Registry. While an entity may be able to petition to include such a facility in the
BES, what is the incentive to do so? This seems to detract from the ‘bright line’ definition.

Response: The SDT is drafting a definition for the Bulk Electric System and does not have involvement with the registration criteria. If reliability is a concern
regarding specific generation that has been excluded from the definition, the Reliability Coordinator can always go through the NERC Rules of Procedure exception
process to petition to bring generation into the BES. No change made.
Michigan Public
Service
Commission(MPSC)

No

MPSC Staff Comments: This inclusion should be eliminated entirely for the reasons provided in
E1 above. If the BES is required to be contiguous, this I2 threshold will result in many radial
subtransmission lines losing their non-BES status and having to comply with NERC security and
reliability requirements.
Two different generation thresholds, one for I2 and one for I3, should not be used. The I3
inclusion (75MVA) threshold should be sufficient.

Tennessee Valley
Authority

No

Other than the NERC Registry Criteria definition, what is the technical justification for the 20 MVA
thresholds? The threshold level for inclusion should be technically based on the BES capacity and
configuration at the location of the generating source’s connection to the BES.

New York State
Reliability Council

No

The use of a 20 MVA threshold based on NERC's Registry Criteria may be administratively
convenient but is arbitrary when based upon BES reliability considerations. Suggest use of a 300
MW or other regionally and technically acceptable threshold such as NPCC's A-10 criterion.

Michgan Public
Power Agency

Yes

Generally I would agree with I2 but question the technical justification for 20 MVA without also
considering its capacity factor.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new

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Organization

Yes or No

Question 3 Comment

Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
SERC OC
Standards Review
Group

No

SERC proposes the following as an alternative to the Inclusion I2 wording in the draft BES
definition: “Individual generating units greater than 20 MVA (gross nameplate rating) including the
generator terminals through its GSU which has a high side voltage of 100 kV or above.” The only
difference in proposed text is that the word “the” preceding “GSU” has been changed to “its”. The
text in the draft clearly defines that the inclusion begins with the generator, continues through the
terminals, and ends at a GSU. The wording in the draft text does not, however, explicitly limit the
scope of equipment that should be evaluated for inclusion to the GSU which is directly connected
to the generator terminals. Since GSU is not a defined term there is a strong potential for
inconsistent interpretation of this boundary to include multiple transformers in series until ultimately
a transformer which does operate at a voltage of greater than 100 kV is included in the flow path.
To eliminate this potential for compliance re-interpretation, we also strongly suggest the term GSU
be defined in the NERC Glossary of Terms. A suggested definition is: “Generator Step-up
Transformer (GSU) should be defined as a transformer directly connected to a generator on the
low side and to a bus on the high side.”

Response: The SDT generally agrees with your clarification statement.
Inclusion I2 has been eliminated and Inclusion I3 has been clarified to use the term step-up transformer rather than GSU.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Hydro One
Networks Inc

August 19, 2011

No

We agree with the concept of Inclusion I2 with respect to individual generating units, but do not
support having the entire path labeled as BES. In most cases, neither the path nor a 20 MVA unit
itself will have any impact on the reliability of the interconnected transmission network nor is it
necessary for the operation. Hence, we do not support the fact that there should be a blanket
application of the BES definition to all individual generating units greater than 20 MVA and its
connection to the system. It is also important to mention that moving into the future, with the Green
Energy and Smart Grid plans advocated by both Canadian and US policy makers, the gross
nameplate rating of 20 MVA acquired from NERC registration restricts the penetration of dispersed

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Organization

Yes or No

Question 3 Comment
generation in many parts of North America.
We suggest the following: o Generation restriction (20 MVA or 75 MVA) should either be revised
or the exception procedure should allow entities, with the support of technical evidence, to exclude
element(s) from being labeled as part of the BES.
o Entities should be able to use the exception process, with the help of technical evidence, to
exclude generating units that do not impact the interconnected grid and the bulk transfer of power.
o The path to generating facilities does not need to be BES contiguous. Generating units can be
required to be planned, designed, and operated in accordance with a subset of NERC Standards,
but should not require a contiguous path unless the unit is identified essential for the operation of
transmission network.

Ida ho Falls Power

No

We feel the bright line criteria 20 MVA for generation is equally as arbitrary as the 100KV threshold
for transmission, which was the impetus for the NERC BES definition effort. There should be more
defining criteria to establish what generation resources should be included in the BES. Possible
criteria to consider would be generation serving load other than local load connected to an LDN or
generation that is dispatchable. Surely, just as not all 100 kV is is material to the BES, niether is all
20MVA or greater generation. If this draft's language is allowed to stand at the brightline of
20MVA, without additional defining criteria, will have the likely result of an inordinate number of
entities having to resolve the issue of material impact through the Rules of Procedure exemption
process. We urge NERC to take this opportunity now to more clearly define material generation
assets beyond a simple brightline criteria.
In addition to our concern of this draft following bright line registry criteria for generation assets, it
is our concern that there is no distinction made as to where the generation is connected. Our
belief is that generation on an LDN wherein the net flow of power is into the LDN should be exempt
as the liklihood of that generation being material to the larger BES is exceedingly small.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Entities seeking exception from the core definition can utilize the NERC RoP exception process to present relevant evidence.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross

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Organization

Yes or No

Question 3 Comment

aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Western Montana
Electric Generating
and Transmission
Cooperative

No

WMG&T is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the
20 MVA threshold discussed in our response to question 3, the 75 MVA threshold appears to have
been drawn from the NERC Statement of Compliance Registry without appreciation for the
function of the threshold in that document and without adequate technical justification
demonstrating the generators with an aggregate capacity of 75 MVA produce electric energy
“needed to maintain transmission system reliability” and are therefore properly included in the BES
definition.
In the same comments, the SDT also states that it has considered “the inclusion of generator stepup (GSU) transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable.” Unfortunately, the SDT appears to have concluded
that any interconnection facility operating above 100-kV should be classified as BES. The result
will be to require Generation Owners to register as Transmission Owners/Operators, as well,
producing substantial additional compliance costs for those Generation Owners but resulting in
little or no improvement in the reliability of the BES. We recommend that the SDT, like the Project
2010-07 SDT (commonly referred to as the GO/TO Team), give careful consideration to the
practical results of its recommendations rather than relying on abstract conclusions about whether
a “contiguous” or “non-contiguous” BES is more desirable. We are concerned that the SDT’s
pursuit of a “contiguous” BES will result in a substantially over-inclusive BES definition. The
“contiguous” BES concept implies that every Element arguably necessary for the reliable operation
of the interconnected bulk system must be included in the BES definition, even if it is
interconnected with Elements that have no bearing on the operation of the BES. NERC’s
Standards Drafting Team for Project 2010-07, has already considered this question and, based on
an in-depth review of potentially applicable reliability standards, has concluded that generation
interconnection facilities, even if operated above 100-kV, need to comply only with a limited set of
reliability standards in order to achieve the reliability goals. Much of the work of the Project 201007 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” Similarly, a
“contiguous” BES suggests that, because certain system protection facilities, such as UFLS relays,
are ordinarily embedded in local distribution systems, the local distribution system, along with the
UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only

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Yes or No

Question 3 Comment
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would,
by improperly classifying local distribution lines as BES “Transmission” facilities, result in huge
regulatory compliance burdens with little or no improvement in bulk system reliability.

Response: There has been no significant technical justification by which to base a departure from the 75 MVA threshold where connected at 100 kV and
above. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the generator step up transformer which is connected on the high
side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to the
BES.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Southern Company

No

The inclusion criterion I3 and I5 establish the level of generation that has been deemed to be the
important threshold for the amount of generation at a facility. The individual generating unit size
criteria should match that same aggregate size given in I3 and I5. It doesn't make sense to specify
a 20 MVA level for a single unit compared to multiple smaller unit plants whose aggregate totals 75
MVA. To provide equivalent weight to each configuration of plant structure, the individual
generating unit size should be 75 MVA rather than 20 MVA. The NERC Registry Criteria should
also be changed from 20 MVA to 75 MVA for a single generator size. Further, a significant
number of respondents to the first BES definition posting stated that the 20 MVA generator
threshold is too low. Many Generator Owners and Operators do not understand the technical
basis for including individual generators rated 75 MVA or less. The NERC Registry Criteria alone
does not clearly define the technical basis for the 20 MVA threshold, and appears to use this as a
conservative generator rating to cover some areas where units this size may have a material
impact on the local area reliability. We do not believe this translates to material impact on BES
reliability in terms of wide area blackouts and cascading outages. We believe that the technical
basis for including any single generator of 75 MVA or less needs to be more clearly concisely
established and documented to support Inclusion Criterion I2.

Electricity

No

Although the BES Standards Drafting Team has stated that it will not propose changing the 20-

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Consumers
Resource Council
(ELCON)

Question 3 Comment
MVA/75-MVA thresholds, we think the thresholds should be set based on the BA/RC needs in
each area and that a suggested range (perhaps by taking a survey of the operational entities)
should be in the new BES Definition. Having an arbitrary and capricious number in the new BES
Definition just because it is in the current Statement of Compliance Registry Criteria, and requiring
significant technical justification for change, does not seem appropriate when so many expert
industry commenters have indicated the existing thresholds are too low to be operationally
significant.

Response: There has been no significant technical justification by which to base a departure from the 75 MVA threshold where connected at 100 kV and
above. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations. The goal of this project is
to clarify the BES definition and not to address issues related to registration criteria.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
National
Association of
Regulatory Utility
Commissioners

No

The inclusion of individual generating units between 20 MVA and 75 MVA nameplate capacity is
inconsistent with I3 that sets the aggregate threshold at 75 MVA. There is no technical justification
for including a facility as low as 20 MVA and no rational basis for thinking that these generators
could be the cause of instability, uncontrolled separation, or cascading events. We recommend
removing this inclusion or raising the threshold to 75 MVA.

American Electric
Power

No

The use of the word “including” within I2 seems to imply the inclusion of 20MVA (or greater)
generating units beyond those which have a high side voltage of 100 kV or above. Was this
intentional? If not, the following wording is preferable: "Individual generating units greater than 20
MVA (gross nameplate rating) having a GSU with a high side voltage of 100 kV or above. This
includes equipment installed from the generator terminals through the high side of the GSU."

Springfield Utility
Board

No

SUB raises the questions “Are multiple individual units considered one unit if they have a shared
bus?” SUB is concerned that in the instance where individual units have a shared bus that some
interpretations would be that these are individual and therefore not part of the BES while other
interpretations would result in the units being considered part of the BES because of a shared bus.
Given I3, SUB suggests that units connected to a shared bus be considered as if they were not

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Question 3 Comment
connected to a shared bus if they are individually separable by automatic fault-interrupting devices
(e.g. two 15aMW units that have a shared bus would not be included as part of I2 if they each
have automatic fault-interrupting devices). Continuing the example of the two 15aMW units, if a
shared bus somehow combined the two individual units into one unit for purposes of I2, where
does this distinction end? What if they share the same transmission line? Is this transmission line
considered being a “bus” for purposes of combining the two units into one individual unit?
Because this discussion could go on with multiple examples, SUB suggests that the distinction be
the automatic fault-interrupting device. If the devices can be separated from each other and the
local network then they should be considered individual. While Springfield Utility Board does not
own any generating units, we do recognize the importance of the stability and restoration of the
Grid, and the generation necessary for the Grid.

Springfield Utility
Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on
May 26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental
comment deals with the concept of "serving only load" and the classification of what types of
generation are incorporated into the definition of generation for purposes of BES inclusion or
exclusion.SUB's comment is that generation normally operated as backup generation for retail
load is not counted as generation for purposes of determining generation thresholds for inclusion
or exclusion from the BES. For purposes of BES inclusion or exclusion, a system with load and
generation normally operated as backup generation for retail load is considered "serving only load"
when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is
normally used during a localized outage and for testing for reliability during a localized outage
event. Including backup generation for retail load in generation thresholds (e.g. 75MVA) would not
reflect generation used for restoration or reliability of the BES. Including backup generation for
retail load in generation threshold calculations would cause a inappropriate inclusion of elements
and devices, accelerate the triggering of inclusion (and may make exclusion provisions
meaningless), and push more activity of excluding smaller systems from the BES into the
exception process.

New York State
Dept of Public
Service

No

The inclusion of 20 MVA generation seems inconsistent with I3 that sets the aggregate threshold
at 75 MVA. It is not rational that a 20 MVA facility could be the cause of instability, uncontrolled
separation of the system or cascading events. This inclusion should be dropped.

Idaho Power

No

Generators at 20 MVA are not material to the BES. I would recommend combining I2, I3, and I5
with the limit at 75 MVA for plant nameplate capability regardless of the number of generators and

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Question 3 Comment
type of generators.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
PacifiCorp

No

Although certain areas of the country may have a need for generating units of this magnitude to be
included in the BES for reliability, the 20 MVA minimum rating essentially discriminates against the
owners of these generators. In I3 and I5 a 75 MVA limit has been established for different
combinations of generation. This limit should also be used for a single generating unit. Those
areas that require generator units less than 75 MVA for reliability should add them back to the BES
via the inclusion/exclusion process to be proposed in NERC’s Rules of Procedure (“ROP”).
o The 20 MVA threshold was intended to mirror the existing NERC Compliance Registry Criteria.
This registry value was adopted without the benefit of having been scrutinized through a NERC
Reliability Standards Development Process, so the technical record justifying the 20 MVA
threshold is non-existent. The BES Drafting Team will need to have technical justification for
adopting the 20 MVA threshold beyond the fact that it was previously adopted by NERC in a
different framework (i.e., for entity registration). Absent any technical justification, Inclusion I2
should be eliminated. This would leave the 75 MVA threshold in Inclusion I3 and Inclusion I5 as
the minimum BES thresholds for generation.
Also, please refer to additional comments in question 13 regarding a contiguous BES.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Comments regarding contiguous BES submitted under Q13 will be answered under Q13.

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Question 3 Comment

I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Intellibind

No

In the discussion the Drafting team stated they found no technical rational to change the 20 MVA
rule, however there is no technical rational to support 20 MVA either. There are arguably cases
where it will be appropriate to include these generators; however there are may instances where
these generators should not be included. This should be driven by the interconnected
transmission operators, not by an arbitrary threshold. In the WECC there are multiple examples of
small/medium hydro, waste-to-energy, and other non-dispatchable generation that not only are
located where they cannot add to the reliability of the BES, are not manned, and are bound by
contractual relationships by a BA. These facilities have a tendency to have multiple forced
outages, are affected by weather events, and are not considered reliable by the interconnected
transmission operator for BES reliability purposes. Many of these facilities generate power as a
secondary business, not primary. Wood burning, trash burning is waste disposal, irrigation
projects are primarily focused on water delivery. Failure of power generation is not addressed as a
primary importance during a failure, and none of these facilities were constructed to benefit the
BES. In many cases the contract to construct these facilities was predicated on proving they do
not impact the interconnected transmission operator or the BES.

Portland General
Electric Company

No

The 20 MVA gross nameplate rating threshold for an individual unit is toolow and will result in the
inclusion in the BES of generating units that have no potentialto impact the reliability of the BES.
The 20 MVA threshold was taken from theregistration criteria, and no technical justification has
been provided for its use. PGErecommends that this inclusion be removed entirely.

City of St. George

No

It is understood that this mirrors the Registry Criteria and this is a simple way to address the issue.
The justification states there is no technical rationale to change the 20 MVA threshold, however
the technical rationale for the 20 MVA criteria has not been provided to the industry either. Having
a 20 MVA unit treated the same and subject to all of the same standard requirements as a unit
with several hundred MVA of capacity doesn’t make sense either. The requirements for an entity
or facility should match the impact of that facility to the system.

City of Redding

Yes

August 19, 2011

In concept Redding is in agreement that the Brightline should specify generators at a certain level,
however we believe the SDT has no technical basis to choose the 20 MVA threshold. If the SDT
elects to retain I2 in its current form then Redding suggests changing the generation level from 20
MVA to 100 MVA. If the goal of the Brightline Definition is to create a starting point to identify power
system elements that are “necessary” then the SDT should choose a larger generation threshold as

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Question 3 Comment
a starting point. The 100 MVA would serve a better purpose by casting the burden of proof (via the
Exception Process) from the smaller units under 100 MVA to the Regional Entity. This would help
the SDT to achieve an objective of reducing the burden on the “small entity” and “distribution”
facilities due to the fact that most smaller generators of this size are installed to serve local loads.
Additionally, The SDT has not provided justification that the “generator terminals through GSU” on
smaller units are “needed to maintain transmission system reliability.” The inclusion of the low
voltage equipment from the GSU to the Generator on small generators is going beyond what is
necessary to operate an interconnected transmission network. This portion of the inclusion should
be removed or modified because the SDT has not demonstrated why the connection facilities are
“necessary”.
The biggest argument for smaller units to be included as BES elements is that their
operation/maintenance schedules and output visiablity are “necessary to operate an interconnected
transmission network”. If that is the case the Compliance Registry captures units above 20 MVA as
users of the BES system; Standards can be written to address the support aspects of these types of
units. As recommended, selecting a higher generator MVA threshold in the brightline definition does
not exempt the lower MVA generation units from being classified as Users of the BES in the
Compliance Registry. In fact Redding, suggests that the Registry be revised to have a more tiered
approach allowing the Standards to be equably applied to Entities. Redding suggests that SDT
recommend that the Generator Owner and Operator definitions be modified to have Large and
Small generator owners and operators.
In summary, Redding supports the concept that the brightline is an initial dividing line of elements
that are necessary to operate the BES. Therefore, Redding suggests that the SDT change the
language in I2:
From: “Individual generating units greater than 20 MVA (gross nameplate rating) including the
generator terminals through the GSU which has a high side voltage of 100 kV or above”.
To: “Individual generating units greater than 100 MVA (gross nameplate rating) including the
generator terminals through the GSU which has a high side voltage of 100 kV or above”.
OR
To: “Individual generating units which have a contractual obligation to provide operational support
necessary to operate the interconnected transmission system.”

California Public
Utilities Commission

August 19, 2011

Yes

The CPUC would like a technical justification/rational for the 20 MVA threshold. We understand
and agree with the ability to show no impact through a technical impact assessment, but such an

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Question 3 Comment
assessment may be costly for a small 20-50 MW peaker plant that may operate for few hours
during any given month. The cost imposed to small generating plants that operate a few hours a
month may be too excessive given the probability of the generator causing an event and the cost
associated with the event. The BES definition should be more than a deterministic standard and
should properly assess every asset it proposes to include, especially given what the courts have
ruled. We believe it would be preferable to include individual elements at power plants that can
impact the BES (governors, system stabilizers, breakers,...) rather than to extend the definition of
the BES to include all small power plants.

Response: There has been no significant technical justification by which to base a departure from the 75 MVA threshold where connected at 100 kV and above.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Hydro-Quebec
TransEnergie

No

We believe that it is not necessary to include small generator of 20 MVA into the BES, neither the
transmission path that connect them. However, a provision should be made so that some reliability
standards related to generator shall apply (voltage regulation, etc.).

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Oregon Public Utility
Commission Staff

August 19, 2011

No

The inclusion of individual generation units with a nameplate capacity between 20 MVA and 75
MVA is over-inclusive and unnecessary. Generation in this range generally has no impact to the
reliability of the bulk transmission system. The 20 MVA threshold was pulled from the existing

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Question 3 Comment
NERC Statement of Compliance Registry. This Registry value was adopted without the benefit of
having been scrutinized through a NERC Standards Development Process, so the technical record
justifying the 20 MVA threshold is unavailable. The BES Drafting Team will need to have technical
justification for adopting the 20 MVA threshold beyond the fact that it was previously adopted by
NERC in a different framework. Absent any technical justification, Inclusion I2 should be
eliminated. This would leave the 75 MVA threshold in Inclusion I3 and Inclusion I5 as the
minimum BES thresholds for generation.The proposed BES Definition does not address the BES
“demarcation points” and whether the BES must be “contiguous.” NERC Staff has submitted
written comments to this project stating that the BES “must be contiguous.” Instituting a
contiguous BES with Inclusion I2 would result in a over-inclusive BES definition. The adoption of a
“contiguous” BES is therefore likely to result in imposition of reliability standards on a substantial
number of distribution elements that have nothing to do with improving or protecting the reliability
of bulk transmission system.There is no compelling reason to adopt a “contiguous” BES down into
local distribution systems. Section 215 of the FPA of 2005 gives FERC jurisdictional authority over
“users” as well as “owners” and “operators” of the bulk power system. Consequently, FERC has
the jurisdictional authority to require generation entities in the Compliance Registry to comply with
applicable NERC requirements. Hence, even where an entity does not own or operate BES
assets, it could still be required, for example, to provide necessary information to the applicable
Reliability Coordinator or Planning Coordinator and to participate in programs to prevent instability,
uncontrolled separation or cascading outages to the bulk transmission system. This approach
would fully achieve the goals of bulk transmission system reliability without imposing the full BES
regulatory compliance burden on local distribution elements.

Response: There has been no significant technical justification by which to base a departure from the 75 MVA threshold where connected at 100 kV and
above. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The SDT proposal does not address BES contiguity beyond the connection to 100 kV or greater (the high side of the GSU).
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Public Utility District

August 19, 2011

No

Snohomish is concerned that the inclusion of individual generation units with a nameplate capacity

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Organization
No. 1 of Snohomish
County, Washington

August 19, 2011

Yes or No

Question 3 Comment
as small as 20 MVA is over-inclusive. Under FPA Section 215, generation resources are excluded
from the “bulk-power system” unless they produce “electric energy” that is “needed to maintain
transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators with a capacity of
20 MVA almost never produce electricity that is “needed to maintain transmission system
reliability.” Hence, the inclusion as drafted improperly expands the BES definition to include
generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be
material to the operation of the BES, and not to definitively determine whether a given generator is,
in fact, material to the operation of the BES, the STD has acted arbitrarily and without adequate
technical justification in adopting the 20 MVA threshold. In responding to comments on its initial
proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical basis
to change the values contained in the Statement of Compliance Registry Criteria.” Consideration of
Comments on Definition of Bulk Electric System - Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context.
Without a technical justification demonstrating that facilities operating at capacities as low as 20
MVA are “needed to maintain transmission system reliability,” the proposed definition is overly
broad and fails to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16
U.S.C. § 8240(a)(1). Further, the Statement of Compliance Registry was adopted without the
benefit of having been vetted through the NERC Standards Development Process, so the technical
record underlying the choice of that threshold is unavailable for review by the industry.In the same
comments, the SDT also states that it has considered “the inclusion of generator step-up (GSU)
transformers and associated interconnection line leads and believes the BES must be contiguous
at this level in order to be reliable.” Id. The SDT’s reasons for reaching this conclusion are not
well-explained, but apparently the concern is that a “non-contiguous” BES could create “reliability
gaps.” But this conclusion cannot be supported as an abstract proposition, but can only be
demonstrated by a careful examination how application of reliability standards will change
depending on how the BES is defined. In fact, we believe that if the SDT insists on a “contiguous”
BES, an over-inclusive definition will result.We base these conclusions on the findings of NERC’s
Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO Task Force.” The
Project 2010-07 Team was formed to address how the dedicated interconnection facilities linking a
BES generator to high-voltage transmission facilities should be treated under the NERC standards.
After reviewing these questions in considerable depth, the Team concluded that dedicated highvoltage interconnection facilities need not be treated as “Transmission” and classified as part of
the BES in order to make reliability standards effective. On the contrary, the team concluded that
by complying with a handful of reliability standards, primarily related to vegetation management,

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Question 3 Comment
reliable operation of the bulk interconnected system could be protected without unduly burdening
the owners of such interconnection systems. See Final Report from the NERC Ad Hoc Group for
Generator Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the
predecessor of the Project 2010-07 SDT). Much of the work of the Project 2010-07 SDT is
applicable to the work of the BES Standards Developoment Team. For example, the Project 201007 Team observed that interconnection facilities “are most often not part of the integrated bulk
power system, and as such should not be subject to the same level of standards applicable to
Transmission Owners and Transmission Operators who own and operate transmission Facilities
and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the
same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of
the equipment that actually produces electricity - the generation equipment itself.” Id. We believe
the many of the questions considered by the Project 2010-07 Team are analogous to the
questions under consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES,
the resulting definition will be substantially over-inclusive. The “contiguous” BES concept implies
that every Element arguably necessary for the reliable operation of the interconnected bulk system
must be included in the BES definition, even if it is interconnected with Elements that have no
bearing on the operation of the BES. The adoption of a “contiguous” BES is therefore likely to
result in imposition of reliability standards on a substantial number of facilities that have little or
nothing to do with bulk system reliability, resulting in wasted regulatory expense and additional
stress on the limited resources of reliability regulators. For example, a “contiguous” BES would
require dedicated interconnection facilities that connect a BES generator to BES transmission
facilities to be classified as BES. But, as the discussion above demonstrates, the classification of
dedicated interconnection facilities as “BES” facilities would, based on the findings of the Project
2010-07 SDT, result in substantial overregulation and unnecessary expense with little gain for bulk
system reliability. Similarly, a “contiguous” BES suggests that, because certain system protection
facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the local
distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” Such a result is not only plainly contrary to the local distribution exclusion embedded
in Section 215 of the FPA, but would, by improperly classifying local distribution lines as BES
“Transmission” facilities, result in huge regulatory compliance burdens with little or no improvement
in bulk system reliability. There is no good reason for the SDT to adopt a “contiguous” BES. On
the contrary, because Section 215 allows reliability standards to be applied to “users” of the bulk
system as well as “owners” and “operators,” local distribution systems operating UFLS relays and
other bulk system protection devices could be required to comply with standards governing those

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Question 3 Comment
devices as a precondition for their use of transmission on the bulk system. The other alternative is
to draft standards that apply to a specific type of equipment - again UFLS relays is a good example
- rather than to BES facilities categorically. Either approach will fully achieve the goals of bulk
system reliability without imposing an undue regulatory compliance burden on local distribution
systems.For these reasons, we urge the SDT to follow the example of the Project 2010-07 Team
and the GO-TO Task Force by giving careful consideration to the specific and practical results of
how its definition will affect the application of particular reliability standards and whether the results
are beneficial to reliability or simply result in unnecessary regulatory burdens that do not benefit
bulk system reliability. We believe there is considerable danger of error if the SDT bases its
conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES is
more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.

Blachly Lane
Electric Cooperative
Central Electric
Cooperative
Clearwater Power
Company
Consumers Power
Inc
Clallam County
PUD No.1

No

The inclusion of individual generation units with a nameplate capacity as small as 20 MVA is overinclusive. Under FPA Section 215, generation resources are excluded from the “bulk-power
system” unless they produce “electric energy” that is “needed to maintain transmission system
reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators with a capacity of 20 MVA almost never
produce electricity that is “needed to maintain transmission system reliability.” Hence, the inclusion
as drafted would improperly expand the BES definition to include generators that the statute
requires to be excluded.
Further, the 20 MVA threshold appears to have been drawn without explanation from the existing
NERC Statement of Compliance Registry. Given that the purpose of the Compliance Registry is to
sweep in all generators that might be material to the operation of the BES, and not to definitively
determine whether a given generator is, in fact, material to the operation of the BES, the STD has
acted arbitrarily and without adequate technical justification in adopting the 20 MVA threshold.
The 100 MVA threshold seems more in alignment with technical standards such as Power System
Stabilizer requirements. In responding to comments on its initial proposal, the SDT states that it
adopted the 20 MVA threshold because “there is no technical basis to change the values
contained in the Statement of Compliance Registry Criteria.” Consideration of Comments on
Definition of Bulk Electric System - Project 2010-17, March 30, 2011, at 30. But this gets the
equation backwards. The SDT must have some technical justification for adopting the 20 MVA
threshold beyond the fact that it was previously adopted by NERC in a different context. Without a
technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and
fails to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §

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Organization

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Question 3 Comment
8240(a)(1).
Further, the Statement of Compliance Registry was adopted without the benefit of having been
vetted through the NERC Standards Development Process, so the technical record underlying the
choice of that threshold is unavailable for review by the industry.
In the same comments, the SDT also states that it has considered “the inclusion of generator stepup (GSU) transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable.” Id. The SDT’s reasons for reaching this conclusion
are not well-explained, but apparently the concern is that a “non-contiguous” BES could create
“reliability gaps.” This conclusion cannot be supported as an abstract proposition, but can only be
demonstrated by a careful examination how application of reliability standards will change
depending on how the BES is defined. We believe that if the SDT insists on a “contiguous” BES,
an over-inclusive definition will result.We base these conclusions on the findings of NERC’s
Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO Task Force.” The
Project 2010-07 Team was formed to address how the dedicated interconnection facilities linking a
BES generator to high-voltage transmission facilities should be treated under the NERC standards.
After reviewing these questions in considerable depth, the Team concluded that dedicated highvoltage interconnection facilities need not be treated as “Transmission” and classified as part of
the BES in order to make reliability standards effective. On the contrary, the team concluded that
by complying with a handful of reliability standards, primarily related to vegetation management,
reliable operation of the bulk interconnected system could be protected without unduly burdening
the owners of such interconnection systems. See Final Report from the NERC Ad Hoc Group for
Generator Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the
predecessor of the Project 2010-07 SDT). Much of the work of the Project 2010-07 SDT is
applicable to the work of the BES Standards Development Team. For example, the Project 201007 Team observed that interconnection facilities “are most often not part of the integrated bulk
power system, and as such should not be subject to the same level of standards applicable to
Transmission Owners and Transmission Operators who own and operate transmission Facilities
and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the
same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of
the equipment that actually produces electricity - the generation equipment itself.” Id.
We
believe the many of the questions considered by the Project 2010-07 Team are analogous to the
questions under consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES,
the resulting definition will be substantially over-inclusive. The “contiguous” BES concept implies

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Yes or No

Question 3 Comment
that every Element arguably necessary for the reliable operation of the interconnected bulk system
must be included in the BES definition, even if it is interconnected with Elements that have no
bearing on the operation of the BES. The adoption of a “contiguous” BES is therefore likely to
result in imposition of reliability standards on a substantial number of facilities that have little or
nothing to do with bulk system reliability, resulting in wasted regulatory expense and additional
stress on the limited resources of reliability regulators. For example, a “contiguous” BES would
require dedicated interconnection facilities that connect a BES generator to BES transmission
facilities to be classified as BES. But, as the discussion above demonstrates, the classification of
dedicated interconnection facilities as “BES” facilities would, based on the findings of the Project
2010-07 SDT, result in substantial overregulation and unnecessary expense with little gain for bulk
system reliability. Similarly, a “contiguous” BES suggests that, because certain system protection
facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the local
distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” Such a result is not only plainly contrary to the local distribution exclusion embedded
in Section 215 of the FPA, but would, by improperly classifying local distribution lines as BES
“Transmission” facilities, result in huge regulatory compliance burdens with little or no improvement
in bulk system reliability. There is no good reason for the SDT to adopt a “contiguous” BES. On
the contrary, because Section 215 allows reliability standards to be applied to “users” of the bulk
system as well as “owners” and “operators,” local distribution systems operating UFLS relays and
other bulk system protection devices could be required to comply with standards governing those
devices as a precondition for their use of transmission on the bulk system. For these reasons, we
urge the SDT to follow the example of the Project 2010-07 Team and the GO-TO Task Force by
giving careful consideration to the specific and practical results of how its definition will affect the
application fo particular reliability standards and whether the results are beneficial to reliability or
simply result in unnecessary regulatory burdens that do not benefit bulk system reliability. We
believe there is considerable danger of error if the SDT bases its conclusions on metaphysical
debates about whether a “contiguous” or “non-contiguous” BES is more desirable rather than
engaging in a careful analysis of whether the proposed definition achieves reliability goals in the
most efficient manner possible.

Coos-Curry Electric
Cooperative
Douglas Electric
Cooperative
Fall River Electric

August 19, 2011

No

Specific language change: Change 20 MVA to 100 MVAThe inclusion of individual generation
units with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215,
generation resources are excluded from the “bulk-power system” unless they produce “electric
energy” that is “needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B).
Smaller generators with a capacity of 20 MVA almost never produce electricity that is “needed to
maintain transmission system reliability.” Hence, the inclusion as drafted would improperly expand
the BES definition to include generators that the statute requires to be excluded. Further, the 20

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Organization
Cooperative
Lane Electric
Cooperative
Lincoln Electric
Cooperative
Lost River Electric
Cooperative
Northern Lights Inc
Okanogan Electric
Cooperative
PNGC Power
Raft River Rural
Electric Cooperative
Salmon River
Electric Cooperative
Umatilla Electric
Cooperative
West Oregon
Electric Cooperative

August 19, 2011

Yes or No

Question 3 Comment
MVA threshold appears to have been drawn without explanation from the existing NERC
Statement of Compliance Registry. Given that the purpose of the Compliance Registry is to sweep
in all generators that might be material to the operation of the BES, and not to definitively
determine whether a given generator is, in fact, material to the operation of the BES, the STD has
acted arbitrarily and without adequate technical justification in adopting the 20 MVA threshold.
The 100 MVA threshold seems more in alignment with technical standards such as Power System
Stabilizer requirements. In responding to comments on its initial proposal, the SDT states that it
adopted the 20 MVA threshold because “there is no technical basis to change the values
contained in the Statement of Compliance Registry Criteria.” Consideration of Comments on
Definition of Bulk Electric System - Project 2010-17, March 30, 2011, at 30. But this gets the
equation backwards. The SDT must have some technical justification for adopting the 20 MVA
threshold beyond the fact that it was previously adopted by NERC in a different context. Without a
technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and
fails to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of
having been vetted through the NERC Standards Development Process, so the technical record
underlying the choice of that threshold is unavailable for review by the industry.In the same
comments, the SDT also states that it has considered “the inclusion of generator step-up (GSU)
transformers and associated interconnection line leads and believes the BES must be contiguous
at this level in order to be reliable.” Id. The SDT’s reasons for reaching this conclusion are not
well-explained, but apparently the concern is that a “non-contiguous” BES could create “reliability
gaps.” This conclusion cannot be supported as an abstract proposition, but can only be
demonstrated by a careful examination how application of reliability standards will change
depending on how the BES is defined. We believe that if the SDT insists on a “contiguous” BES,
an over-inclusive definition will result.We base these conclusions on the findings of NERC’s
Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO Task Force.” The
Project 2010-07 Team was formed to address how the dedicated interconnection facilities linking a
BES generator to high-voltage transmission facilities should be treated under the NERC standards.
After reviewing these questions in considerable depth, the Team concluded that dedicated highvoltage interconnection facilities need not be treated as “Transmission” and classified as part of
the BES in order to make reliability standards effective. On the contrary, the team concluded that
by complying with a handful of reliability standards, primarily related to vegetation management,
reliable operation of the bulk interconnected system could be protected without unduly burdening
the owners of such interconnection systems. See Final Report from the NERC Ad Hoc Group for
Generator Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the
predecessor of the Project 2010-07 SDT). Much of the work of the Project 2010-07 SDT is

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Organization

Yes or No

Question 3 Comment
applicable to the work of the BES Standards Development Team. For example, the Project 201007 Team observed that interconnection facilities “are most often not part of the integrated bulk
power system, and as such should not be subject to the same level of standards applicable to
Transmission Owners and Transmission Operators who own and operate transmission Facilities
and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the
same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of
the equipment that actually produces electricity - the generation equipment itself.” Id.
We
believe the many of the questions considered by the Project 2010-07 Team are analogous to the
questions under consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES,
the resulting definition will be substantially over-inclusive. The “contiguous” BES concept implies
that every Element arguably necessary for the reliable operation of the interconnected bulk system
must be included in the BES definition, even if it is interconnected with Elements that have no
bearing on the operation of the BES. The adoption of a “contiguous” BES is therefore likely to
result in imposition of reliability standards on a substantial number of facilities that have little or
nothing to do with bulk system reliability, resulting in wasted regulatory expense and additional
stress on the limited resources of reliability regulators. For example, a “contiguous” BES would
require dedicated interconnection facilities that connect a BES generator to BES transmission
facilities to be classified as BES. But, as the discussion above demonstrates, the classification of
dedicated interconnection facilities as “BES” facilities would, based on the findings of the Project
2010-07 SDT, result in substantial overregulation and unnecessary expense with little gain for bulk
system reliability. Similarly, a “contiguous” BES suggests that, because certain system protection
facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the local
distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” Such a result is not only plainly contrary to the local distribution exclusion embedded
in Section 215 of the FPA, but would, by improperly classifying local distribution lines as BES
“Transmission” facilities, result in huge regulatory compliance burdens with little or no improvement
in bulk system reliability. There is no good reason for the SDT to adopt a “contiguous” BES. On
the contrary, because Section 215 allows reliability standards to be applied to “users” of the bulk
system as well as “owners” and “operators,” local distribution systems operating UFLS relays and
other bulk system protection devices could be required to comply with standards governing those
devices as a precondition for their use of transmission on the bulk system. For these reasons, we
urge the SDT to follow the example of the Project 2010-07 Team and the GO-TO Task Force by
giving careful consideration to the specific and practical results of how its definition will affect the
application for particular reliability standards and whether the results are beneficial to reliability or

August 19, 2011

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Organization

Yes or No

Question 3 Comment
simply result in unnecessary regulatory burdens that do not benefit bulk system reliability. We
believe there is considerable danger of error if the SDT bases its conclusions on metaphysical
debates about whether a “contiguous” or “non-contiguous” BES is more desirable rather than
engaging in a careful analysis of whether the proposed definition achieves reliability goals in the
most efficient manner possible.

Northern Wasco
County PUD
Chelan PUD –
CHPD
Kootenai Electric
Cooperative
Public Utility District
No. 1 of Franklin
County
Midstate Electric
Cooperative
Northwest
Requirements
Utilities
Big Bend Electric
Cooperative, Inc.
Cowlitz County PUD

August 19, 2011

No

Northern Wasco County PUD is concerned that I2 inclusion criteria that includes the arbitrary 20
MVA threshold from the NERC Statement of Registry Criteria for inclusion of generators is overinclusive. Under FPA Section 215, generation resources are excluded from the “bulk-power
system” unless they produce “electric energy” that is “needed to maintain transmission system
reliability.” Hence, the inclusion as drafted improperly expands the BES definition to include
generators that the statute requires to be excluded. In the same comments, the SDT also states
that it has considered “the inclusion of generator step-up (GSU) transformers and associated
interconnection line leads and believes the BES must be contiguous at this level in order to be
reliable.” Unfortunately, the SDT appears to have concluded that any interconnection facility
operating above 100-kV should be classified as BES. The result will be to require Generation
Owners to register as Transmission Owners/Operators, as well, producing substantial additional
compliance costs for those Generation Owners but resulting in little or no improvement in the
reliability of the BES. We recommend that the SDT, like the Project 2010-07 SDT (commonly
referred to as the GO/TO Team), give careful consideration to the practical results of its
recommendations rather than relying on abstract conclusions about whether a “contiguous” or
“non-contiguous” BES is more desirable. We are concerned that the SDT’s pursuit of a
“contiguous” BES will result in a substantially over-inclusive BES definition. The “contiguous” BES
concept implies that every Element arguably necessary for the reliable operation of the
interconnected bulk system must be included in the BES definition, even if it is interconnected with
Elements that have no bearing on the operation of the BES. NERC’s Standards Drafting Team for
Project 2010-07, has already considered this question and, based on an in-depth review of
potentially applicable reliability standards, has concluded that generation interconnection facilities,
even if operated above 100-kV, need to comply only with a limited set of reliability standards in
order to achieve the reliability goals. Much of the work of the Project 2010-07 SDT is applicable to
the work of the BES Standards Development Team. For example, the Project 2010-07 Team
observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to
Transmission Owners and Transmission Operators who own and operate transmission Facilities
and Elements that are part of the integrated bulk power system.” Similarly, a “contiguous” BES
suggests that, because certain system protection facilities, such as UFLS relays, are ordinarily
embedded in local distribution systems, the local distribution system, along with the UFLS relays,

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Yes or No

Question 3 Comment
must be classified as BES to make the BES “contiguous.” Such a result is not only plainly contrary
to the local distribution exclusion embedded in Section 215 of the FPA, but would, by improperly
classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability.

Response: The SDT has carefully debated your comments. The SDT does not base its conclusions on “metaphysical debates” as you imply, but rather the
practical nature of inclusions and exclusions in the definition and the reliability impacts associated with them based on technical debate and justification. There
has been no significant technical justification by which to base a departure from the 75 MVA threshold where connected at 100 kV and above. After consulting
with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time.
There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to
address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the
NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization
Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the generator step up transformer which is connected on the
high side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to
the BES.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Sweeny
Cogeneration LP

No

The threshold for individual generation units is consistent with the NERC functional registry
criterion. We believe that it is important to maintain this uniformity. However, we believe there are
further items to be added to the list related to generator interconnections, a task that was passed
to this project from Project 2010-07. Just as is the case with complex distribution systems, there
are a variety of generator-transmission interconnection architectures which are driving the Regions
to inappropriately register Generator Owner/Operators as Transmission Owners.

Response: The SDT cannot respond to this general comment as it lacks specific action.
PUD No. 2 of Grant
County, Washington

August 19, 2011

No

In the same comments, the SDT also states that it has considered “the inclusion of generator stepup (GSU) transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable.” Unfortunately, the SDT appears to have concluded
that any interconnection facility operating above 100-kV should be classified as BES. The result
will be to require Generation Owners to register as Transmission Owners/Operators, as well,
producing substantial additional compliance costs for those Generation Owners but resulting in

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Yes or No

Question 3 Comment
little or no improvement in the reliability of the BES. We recommend that the SDT, like the Project
2010-07 SDT (commonly referred to as the GO/TO Team), give careful consideration to the
practical results of its recommendations rather than relying on abstract conclusions about whether
a “contiguous” or “non-contiguous” BES is more desirable. We are concerned that the SDT’s
pursuit of a “contiguous” BES will result in a substantially over-inclusive BES definition. The
“contiguous” BES concept implies that every Element arguably necessary for the reliable operation
of the interconnected bulk system must be included in the BES definition, even if it is
interconnected with Elements that have no bearing on the operation of the BES. A “contiguous”
BES suggests that, because certain system protection facilities, such as UFLS relays, are
ordinarily embedded in local distribution systems, the local distribution system, along with the
UFLS relays, must be classified as BES to make the BES “contiguous.” The improper
classification of local distribution lines as BES “Transmission” facilities results in huge regulatory
compliance burdens with little or no improvement in bulk system reliability.

FortisBC

No

We agree with the concept of Inclusion I2 with respect to individual generating units, but do not
support having the entire path labeled as BES. In most cases, neither the path or a 20 MVA unit
itself will have any impact on the reliability of the interconnected transmission network nor is it
necessary for the operation.
We also do not support the fact that there should be a blanket application of the BES definition to
all individual generating units greater than 20 MVA. It is also important to mention that moving into
the future, with the Green Energy and Smart Grid plans advocated by both Canadian and US
policy makers, the gross nameplate rating of 20 MVA acquired from NERC registration restricts the
penetration of dispersed generation in many parts of North America.
We suggest the following:
o Generation restriction (20 MVA or 75 MVA) should either be revised or the exception procedure
should allow entities, with the support of technical evidence, to exclude element(s) from being
labeled as part of the BES.
o Entities should be able to use the exception process, with the help of technical evidence, to
exclude generating units that do not impact the interconnected grid and the bulk transfer of power.
o The path to generating facilities does not need to be BES contiguous. Generating units can be
required to be planned, designed, and operated in accordance with a subset of NERC Standards,
but should not require a contiguous path unless the unit is identified essential for the operation of
transmission network.
o Definition and/or exception process should provide clear acknowledgement and flexibility to

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Question 3 Comment
avoid any regulatory conflicts.
- For example: NERC and SDT should consider introducing a
concept of a new category of registration or BES Support (BESS) elements. These elements are
NOT BES but support the reliable operation of the interconnected transmission network. A sub-set
of relevant NERC Standards should still apply to BESS elements such as planning, design, and
maintenance. However, they may not be subject to mandatory compliance.

Public Utilities
Commission of Ohio

No

The inclusion of individual generating units between 20 MVA and 75 MVA nameplate capacity is
inappropriate and over-reaching. Inclusion I3 sets the aggregate threshold at 75 MVA for multiple
generating units. Technical justification for assuming a 20 MVA generating facility could cause
instability, uncontrolled separation, or cascading events on the bulk system appears to be lacking.
This appears to simply be based on that fact the NERC used it in a separate framework, which has
no basis. Inclusion I2 should be removed.Regarding the contiguous standard - simply because an
element is connected to the BES does not make it a part of the BES. By the very nature, a radial
or distribution element should pose limited or no impact on the BES. They are easily isolated from
the rest of the system. This contiguous measurement could impose standards unnecessarily on
systems with no ultimate impact on the bulk system, thereby enabling far-reaching authority into
the distribution system.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations. The SDT
proposal does not address BES contiguity beyond the connection to 100 kV or greater (the high side of the GSU). The SDT believes that the definition must be
contiguous at this level in order to ensure reliability of the BES. Aside from registration burdens, stakeholders have not provided technical justification or
recommendations by which to base a departure from the contiguous nature of the definition. The goal of the SDT is to provide clarity to the definition of the BES
and not to address registration criteria.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Electric Reliability
Council of Texas,
Inc.

August 19, 2011

No

See response to question 1. ERCOT ISO supports redefining generation covered under the BES
to reflect the registration threshold, but, consistent with the comments to question 1, believes it
should be included within the bright line criteria unless otherwise indicated by application of the
inclusion and exclusion criteria of the exception process or analyses.

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Question 3 Comment

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Fayetteville Public
Works Commission

August 19, 2011

No

Inclusion I2 contains wording that is ambiguous and does not support a consistent determination
by independent parties of whether or not a specific generator should be included in the BES. This
definition will be a critical part of the guidance used by registered entities to validate their current
registration status and by new entities to properly determine their initial registration status. It will
also be used by regional reliability entities during compliance activities to verify proper registration.
The ambiguous wording of Inclusion I2 could easily lead to re-interpretation issues between the
owner/operator of the generator and regional entities in a compliance audit or other compliance
setting. To be specific, the phrase "including the generator terminals through the GSU which has
a high side voltage of 100 kV or above" is particularly troublesome. The phrase as written is
intended to establish the boundary of the Real Power resource that will be included in the BES if
the conditions of Inclusion I2 are met. The intent appears to be to include within the BES the
generator, the cables connecting the generator terminals to the GSU, and the GSU, if the GSU has
a high side voltage of 100 kV or above. If the GSU, however, does not have a high side voltage of
100 kV or above, then neither the generator, nor the connecting cables, nor the GSU would
included within the BES.The crux of the problem lies in the interpretation of the term "GSU" and
the phrase "through the GSU which". The term "GSU" or "generator step-up transformer" is
commonly applied to a transformer with a generator directly connected to the low side and a bus
directly connected to the high side. This is not, however, a defined term within the NERC Glossary
and no standard for that interpretation is provided. The very structure of the phrase "through the
GSU which" implies that there may be more than one GSU to be considered, some of which do not
but at least one of which does have a high side voltage of 100 kV or above. This could be
interpreted to include multiple transformers (GSUs) stepping up the generator voltage in series, the
first stepping up the generator voltage to a bus, the second stepping up that bus voltge to another
bus, and the third, and so on, and so on, until finally 'THE" transformer (GSU?) is encountered
"WHICH" does have a high side voltage of 100 kV or higher.Thus, if the registering entity were to
apply the commonly accepted definition of "GSU" to a generator, and the GSU directly connected
to that generator has a high side of less than 100 kV, that entity would properly conclude that

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Organization

Yes or No

Question 3 Comment
neither the generator nor the leads nor the GSU should be included in the BES. If a regional
compliance entity applies the interpretation that transformers in series must be considered until a
generator is encountered which does have a high side of 100 kV or higher, then that compliance
entity would properly conclude that the generator, all the transformers in series, and the buses
connecting those transformers should be included in the BES. Clearly this potential for
contradictory conclusions would be better cleared up during this comment period than repeatedly
coming up during compliance processes.I offer two suggestions for eliminating this ambiguity. The
first and preferred method would be to change the wording of Inclusion I2 to read s follows:
"Individual generating units greater than 20 MVA (gross nameplate rating) directly connected to
the low side of a GSU which has a high side voltage of 100 kV or higher. The generator, the leads
directly connecting the generator terminals to the GSU, and the GSU are all included in the BES."
The second method would be to define within the NERC Glossary the term GSU as follows: "A
generator step-up transformer (GSU) is a transformer directly connected to the terminals of a
generator on the low side and to a bus at a higher voltage on the high side."

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The SDT does not feel that the wording is confusing but is understood to mean that any generating resources, their generator terminals, connecting cabling up to
and including their generator step up transformers that are connected at 100 kV or greater will be included in the definition of the BES. The SDT believes that the
definition must be contiguous at this level in order to ensure reliability of the BES. Aside from registration burdens, stakeholders have not provided technical
justification or recommendations by which to base a departure from the contiguous nature of the definition. Elements connected at below 100 kV that meet
registration criteria will still be required to meet NERC Reliability Standards that apply to their registration.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Southern California
Edison Company

August 19, 2011

No

Inclusions I2, I3, and I5 should either be modified or removed, because as currently written, these
three Inclusion criteria force the definition to be arbitrarily demarcated by the size of generators
connecting to the system, or the aggregate thereof, rather than focusing on the risk characteristics
that should define the BES, as SCE identified in its response to Question No. 1. In the WECC, it
can safely be said that the vast majority of 20MVA generators are located in local distribution
systems and are used to off-set local load, rather than transfer power to the BES. In SCE’s case,

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Organization

Yes or No

Question 3 Comment
our distribution system has a number of components which are marginally above the 100kV BES
threshold, are radial in nature, and were previously exempted from the BES by the WECC. These
radial systems have interconnecting generation units larger than 20 MVA and/ or aggregate
generation exceeding 75 MVA. In many cases, the generation levels on those radial systems
exceed the limits proposed in I2, I3, and I5, but the loading on those same systems is such that
generation will rarely exceed the local load. Therefore, there is little to no power flow back to the
BES from these radial systems.If the BES definition continues to heavily focus its inclusion criteria
on generator/ generation size, SCE feels that the SDT also consider incorporating the concept of
“potential exports to the BES” from these generating sources. An example being:”I2 - Individual
generating units greater than 20 MVA (gross nameplate rating) including the generator terminals
through the GSU which has a high side voltage of 100 kV or above and have no more than 5% net
flows into the BES based on the past XXX calendar years.”This “Net Flow” concept would negate
the need for Section 1C of the “Technical Principles for Demonstrating BES Exceptions”, or
conversely, provide the framework for a more quantifiable criteria in Section 1C.

Response: The SDT has debated your comments and similar comments from stakeholders. After consulting with the NERC Board of Trustees and the NERC
Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to
do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a.
However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the
idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as
well as several other issues that have arisen from SDT deliberations. Individual situations can be evaluated on a case by case basis and utilities can use the NERC
RoP exception process.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Cogentrix Energy,
LLC

No

We also strongly suggest the term GSU be defined in the NERC Glossary of Terms to prevent
potential compliance re-interpretation of this requirement. A suggested definition is: “Generator
Stepup Transformer (GSU) should be defined as a transformer directly connected to a generator
on the low side and to a bus on the high side.”

Response: The SDT has made clarifying changes to the inclusion to address your concern.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.

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Organization
Clark Public Utilities

Yes or No

Question 3 Comment

No

Generators should only be part of the Bulk Electric System if they are connected through a GSU to
a Transmission Element determined to be part of the BES. The current inclusion language would
apply to all generators connected to facilities greater the 100 kV with no exclusion or exception
process. Without a change, it appears that a generator connected to a facility greater than 100 kV
would be a BES asset even if the transmission assets could be excluded or excepted. I2 should be
rewritten to state: Individual generating units greater than 20 MVA (gross nameplate rating)
including the generator terminals through the GSU which has a high side winding connected to a
Transmission Element determined to be part of the Bulk Electric System.
Additionally, as indicated by Clark in its comments on the core definition of the BES, Clark believes
the 20 MVA threshold lacks an adequate technical justification and is a purely arbitrary quantity.
The use of a capacity threshold in the definition of the BES should have technical reasons.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The SDT feels that the revised definition provides adequate clarifying measures. Individual situations can be addressed through the NERC RoP exception process.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
The Dow Chemical
Company

No

It should be clarified that if something falls within an Inclusion and an Exclusion, then it is
excluded. See ELCON comments.

Response: The SDT has made clarifying changes to the definition to address your concern.
New England
States Committee
on Electricity

No

Inclusion Criteria I2 through I4 relate to generation connected with GSU High side voltages greater
than 100 kV and refer to generators with MVA limits exceeding either 20 or 75 MVA aggregate
depending on their configuration.
It should be made clear that all generation connected to sub transmission are not BES as these
units are adequately covered under other applicable NERC and/or regional reliability organization
criteria. These units have no direct impact on the reliability of the BES. This includes black start
units because they do not directly impact normal or contingency operation of the BES. These units

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Organization

Yes or No

Question 3 Comment
and their associated cranking paths are used only for restoration and not operation. Further, they
are appropriately covered under regional restoration procedures and NERC standards (see for
example, Emergency Operating Procedure EOP-005-2).
Use of varying generator MVA thresholds as inclusion criteria under I2 and I3 could lead to
inconsistent treatment of generation facilities. For example, a generation facility with a single 30
MVA generator would qualify as BES under I2. However, if an additional 30 MVA generator was
added at the same site, the facility’s status would change to non-BES under I3 even though the
facility’s capacity had doubled.
NESCOE is also concerned that if the BES is required to be contiguous, the I2 threshold will result
in many radial sub transmission lines becoming BES, resulting in substantial costs without
significant justifying benefits. NESCOE suggests deleting Inclusion I2 or adopting a threshold that
is consistent with I3, and which in no event should be lower than 75 MVA.
Regarding facilities connected at 100 kV and above, some generation units in paper mills or other
entities operating on the retail side of the meter may exceed the Inclusion Criteria. The Exception
Process, which will be the subject of future comments, should provide some flexibility in this area.
NESCOE further notes that in the case of radially connected generation, the contiguous
connection paths should not be BES even if the operating voltage is greater than 100 kV. This is
due to the fact that loss of a path has no greater impact than loss of the connected generator. This
is simply a first contingency loss that has no significant impact on the BES. Inclusion I2 should be
clarified to include only connections that impact the BES.

Response: The definition states that Real and Reactive Power resources connected at 100 kV or higher are considered BES. Sub-transmission referenced in
your comments would generally be considered below 100 kV. Inclusions within the definition address resources connected at below 100 kV that are considered
BES elements.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the generator step up transformer which is connected on the
high side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to
the BES.
Aside from registration burdens, stakeholders have not provided technical justification or recommendations by which to base a departure from the contiguous

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Organization

Yes or No

Question 3 Comment

nature of the definition.
Individual situations can be addressed through the NERC RoP exception process.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
PPL Energy Plus
and PPL
Generation

No

See comments in Question 13.

Illinois Municipal
Electric Agency

Yes

Please see comments under Question 13.

No

The inclusion of generation to the BES should be subject to an impact test.‬

Response: See response to Q13.
Consolidated
Edison Co. of NY,
Inc.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Independent
Electricity System
Operator

August 19, 2011

No

We agree with the goal of inclusion of I2 but as stated earlier in our response to Q1, we do not
support the blanket application of the BES definition to all individual generating units and Facilities
meeting the respective capacity thresholds. Entities should be able to assess the impact of these
units and Facilities against the TPC and use the Exception Process, with the help of technical
evidence, to include generating units and Facilities that impact the interconnected grid and the bulk
transfer of power.

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Organization
Orange and
Rockland Utilities,
Inc.

Yes or No
No

Question 3 Comment
: XI2 should pertain to individual generating unit impact to the Bulk system, rather than the size
unit only. Oftentimes there are cases when neither the path nor a 20 MVA unit itself will have any
impact on the reliability of the interconnected transmission network, nor is it necessary for its
operation.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Individual situations can be addressed through the NERC RoP exception process.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
AltaLink

No

We agree with the concept of Inclusion I2 with respect to individual generating units, but do not
support having the entire path labeled as BES. In most cases, neither the path or a 20 MVA unit
itself will have any impact on the reliability of the interconnected transmission network nor is it
necessary for the operation. Generation restriction (20 MVA or 75 MVA) should either be revised
or the exception procedure should allow entities, with the support of technical evidence, to exclude
element(s) from being labeled as part of the BES. The path to generating facilities does not need
to be BES contiguous. Generating units can be required to be planned, designed, and operated in
accordance with a subset of NERC Standards, but should not require a contiguous path unless the
unit is identified essential for the operation of transmission network.Definition and/or exception
process should provide clear acknowledgement and flexibility to avoid any regulatory conflicts.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the generator step up transformer which is connected on the
high side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to
the BES. Aside from registration burdens, stakeholders have not provided technical justification or recommendations by which to base a departure from the

August 19, 2011

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Organization

Yes or No

Question 3 Comment

contiguous nature of the definition.
Individual situations can be addressed through the NERC RoP exception process.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Utility System
Efficiencies, Inc.

No

The 20 MVA threshold appears to have been drawn without explanation from the existing NERC
Statement of Compliance Registry. Given that the purpose of the Compliance Registry is to sweep
in all generators that might be material to the operation of the BES, and not to definitively
determine whether a given generator is, in fact, material to the operation of the BES, the STD has
acted arbitrarily and without adequate technical justification in adopting the 20 MVA threshold. In
responding to comments on its initial proposal, the SDT states that it adopted the 20 MVA
threshold because “there is no technical basis to change the values contained in the Statement of
Compliance Registry Criteria.” Consideration of Comments on Definition of Bulk Electric System Project 2010-17, March 30, 2011, at 30. But this response gets the equation backwards. The
SDT must have some technical justification for adopting the 20 MVA threshold beyond the fact that
it was previously adopted by NERC in a different context. Without a technical justification
demonstrating that facilities operating at capacities as low as 20 MVA are “needed to maintain
transmission system reliability,” the proposed definition is overly broad and fails to comply with the
restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. § 8240(a)(1).
Further, the Statement of Compliance Registry was adopted without the benefit of having been
vetted through the NERC Standards Development Process, so the technical record underlying the
choice of that threshold is unavailable for review by the industry.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The goal of the SDT is to provide clarity to the definition of the BES and not to address registration criteria.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.

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Organization
BPA

Yes or No

Question 3 Comment

No

Change to “Individual generating units greater than 20 MVA (gross nameplate rating), including the
generator terminals through the GSU, where the GSU has a high side voltage of 100 kV or
above.” The 100 kV high side voltage is important for determining whether the generation is
included, not whether the terminals are included.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Clarifying language has been included in the definition which addresses your concern.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
ATCO Electric

If a generator connects to 2 back to back transformers (25kV/72kV and 72kV/144kV), which
transformer is GSU? 25/72kV transformer only or both transformers.

Response: There is not enough information included in your comment to determine inclusions or exclusions.
Tacoma Power

Tacoma Power generally supports Inclusion I2. However, the term ‘gross nameplate rating’ is not
defined and should be replaced with a specific definition. Additionally, no justification for the 20
MVA level has been provided and therefore it appears arbitrary. Since this measurement will
define Elements for absolute inclusion in the BES, the threshold for generation units should be
based on a need to maintain transmission reliability. Generation units located within a Local
Distribution Network (LDN), which do not exit the LDN, should not be included. We propose
changing Inclusion I2 to read,”Individual generating units greater than 20 MVA (ratings based on
the Code of Federal Regulation, CFR 18, Part 11.1 definition “Authorized Installed Capacity”)
including the generator terminals through the GSU which has a high side voltage of 100 kV or
above, except generating units that are within a Local Distribution Network (LDN) and do not have
a net export out of the LDN.”

Response: The SDT feels that the term “gross nameplate rating” is a widely used term within industry and does not require additional definition. No change
made.

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Organization

Yes or No

Question 3 Comment

After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Please refer to stakeholder comments and responses to Question 9 for the local distribution network.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Pepco Holdings Inc

Clarification needed: If a generator greater than 20mva connected to a bus less than 100kv, but
the bus is connected through a transformer (high side greater then 100kv) to the BES, are the
generator, GSU or transformer considered BES?

Response: The generator and its contiguous path including the bus or interconnecting cable through the GSU high side bushing would all fall under the BES
definition.
Georgia System
Operations

It is unclear to us what the phrase “including the generator terminals through the GSU...” means.
Is the GSU itself included (it apparently would not be under I-1)? We understand terminals to be in
essence points, and therefore don’t see how they go “through” a GSU. Is the intention perhaps to
mean “including the generator terminals at the GSU” or even “including the generator terminals at
the GSU and the GSU itself”?

Response: The SDT has included clarifying language to address your concern.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Central Lincoln

Yes

But please indicate how generators below 20 MVA are treated, since we don’t believe the
flowchart at http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly
expresses the SDT’s intent to classify these small units as non-BES.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus

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Organization

Yes or No

Question 3 Comment

of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The RoP flowchart that was originally posted was incorrect and a corrected version is now available.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
American Municipal
Power and
Members

Yes

We support I2 but propose clarifying edits. We understand that the intent is to define the BES
component of qualifying generators as that equipment from the generator terminals through the
GSU. To convey clearly this point, as well as that only generators that are both over 20 MVA and
connected through a GSU with a high side voltage of at least 100 kV are included in the BES, I2
should be reworded as follows: “Individual generating units greater than 20 MVA (gross nameplate
rating) including the generator terminals, connected through a GSU that has a high-side voltage of
100 kV or above. A BES generator includes the equipment from the generator terminals through
the GSU.”

Small Entity
Working Group
(SEWG)

Yes

Yes, with a minor clarification. Individual generating units greater than 20 MVA (gross nameplate
rating) including the generator terminals through the GSU which has a high side connection
voltage of 100 kV or above. This should help state that only generators that are both over 20 MVA
and connected through a GSU with a high side voltage of at least 100kV are included in the BES.

Florida Municipal
Power Agency

Yes

FMPA understands that the intent is to define the BES component of qualifying generators as that
equipment from the generator terminals through the GSU. To convey clearly this point, as well as
that only generators that are both over 20 MVA and connected through a GSU with a high side
voltage of at least 100 kV are included in the BES, I2 should be reworded as follows: “Individual
generating units greater than 20 MVA (gross nameplate rating), connected through a GSU with a
high-side voltage of 100 kV or above. A BES generator includes the equipment from the generator
terminals through the GSU.”

Western Electricity
Coordinating
Council

Yes

WECC agrees in concept, but the language could be clarified on the GSU transformer. Suggested
language “Individual generating units greater than 20 MVA (gross nameplate rating) including the
generator terminals up to and including the GSU transformer, which has a high-side voltage of 100
kV or above.”

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Organization

Yes or No

Question 3 Comment

Transmission
Access Policy Study
Group

Yes

TAPS understands that the intent is to define the BES component of qualifying generators as that
equipment from the generator terminals through the GSU. To convey clearly this point, as well as
that only generators that are both over 20 MVA and connected through a GSU with a high side
voltage of at least 100 kV are included in the BES, I2 should be reworded as follows: “Individual
generating units greater than 20 MVA (gross nameplate rating), connected through a GSU with a
high-side voltage of 100 kV or above. A BES generator includes the equipment from the generator
terminals through the GSU.”

Northern California
Power Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this
regard.

Sacramento
Municipal Utility
District (SMUD)

Yes

SMUD agrees with the concept of Inclusion 2. To ensure the clarity of the “Bright-Line” criteria the
GSU when connected to a voltage 100 kV and above as indicated in the proposal should clearly
state that the GSU is included as BES.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Clarifying edits have been made to the definition to address your comments.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Santee Cooper

Yes

The inclusion for generating units needs to be consistent with regional entities exclusion criteria for
MODO24.

Response: The SDT has been asked to provide a definition that provides clarity and less ambiguity on a continent-wide basis. The SDT does not agree that
there should be regional interpretation and criteria associated with this definition.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards

August 19, 2011

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Organization

Yes or No

Question 3 Comment

Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
New York Power
Authority

Yes

The definition should exclude generator leads for generating units that do not materially affect the
reliability of the BES regardless of the BES designation of the generating unit.
In addition, the definition should not require the inclusion of contiguous elements. Generating units
that are designated BES are currently required to comply with a subset of NERC Reliability
Standards, but may not be material to the reliable operation of the interconnected BES. This
portion of the definition should not require that both BES and non-BES generating units have their
generator leads defined as BES transmission elements. A length-based criterion for generator
leads ought to be considered. For example, the definition should exclude generator leads that are
one mile or less between BES elements.This comment has been raised in Question number 1 as
well.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the generator step up transformer which is connected on the high
side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to the
BES. Aside from registration burdens, stakeholders have not provided technical justification or recommendations by which to base a departure from the
contiguous nature of the definition.
Radial exclusions are discussed under Question 7.
Please see responses to comments under question 1 for further discussion.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Central Maine

August 19, 2011

Yes

Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is

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Organization

Yes or No

Power Company
New York State
Electric & Gas and
Rochester Gas &
Electric

Question 3 Comment
MVA instead of MW.

Yes

Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is
MVA instead of MW.

Response: ERO registration criteria utilize MVA as a measurement unit. No change made.
Vermont Transco

Yes

How will generating owners currently registered as a GO/GOP and have units tied to the BES
system through a radial transmission line, that they own, and connects them to the grid be affected
by the new definition? Will they need to become TO and TOP registered also?
Should a GO/GOP have to adhere to all TO/TOP standards and requirements or only a sub-set of
requirements?

Response: The SDT cannot address individual registration questions. Discussion of radial connections can be found under Question 7.
ExxonMobil
Research and
Engineering

Yes

Support is contingent on the continued exclusion of generation based on its net capacity provided
to the BES.

Response: See response to question 4 in this regard.
Alberta Electric
System Operator

Yes

Consider adding the word “transformer” after “GSU”.

Response: Clarifying edits have been made to the definition to address your comments.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
MEAG Power

August 19, 2011

Yes

The definition should exclude generator leads for generating units that do not materially affect the
reliability of the BES regardless of the BES designation of the generating unit. In addition, the
definition should not require the inclusion of contiguous elements. Generating units that are
designated BES are currently required to comply with a subset of NERC Reliability Standards, but

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Organization

Yes or No

Question 3 Comment
may not be material to the reliable operation of the interconnected BES.This portion of the
definition should not require that both BES and non-BES generating units have their generator
leads defined as BES transmission elements. A length-based criterion for generator leads ought to
be considered. For example, the definition should exclude generator leads that are one mile or
less between BES elements.This comment has been raised in Question number 1 as well.

Response: The SDT proposal does not address BES contiguity beyond the connection to 100 kV or greater (the high side of the GSU).
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Xcel Energy

Yes

Xcel Energy thanks the SDT for their work and appreciates the clarification that BES extends from
the generator out and does not include the prime mover and balance of plant equipment.

Southwest Power
Pool

Yes

Please refer to SPP's response to question 1. but, consistent with the comments to question 1,
believes it should be reflected as part of the general definition, as opposed to
inclusions/exclusions, which should all be addressed pursuant to the separate processes.

Consumers Energy
Company

Yes

We are supportive of Inclusion I2. Generators 20MVA and greater with terminals through a GSU
connected at 100kV and above are treated as Bulk Electric System at this time along with their
radial connections to the Transmission system. We agree with the SDT that no technical rationale
for changing this condition exists.

Sierra Pacific Power
Co d/b/a NV Energy

Yes

While 20MVA has no technical basis for the threshold above which a generator should be
considered to be necessary for the reliable operation of an interconnected transmission network,
the industry has not provided any technical data to support a value other than this which has been
established in the NERC Statement of Compliance Registry Criteria.

Western Area
Power
Administration

Yes

the bullet comments that define a specific point for demarcation.

Tri-State Generation
and Transmission
Association, Inc.

Yes

August 19, 2011

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Organization

Yes or No

Imperial Irrigation
District

Yes

MRO's NERC
Standards Review
Forum

Yes

SERC Planning
Standards
Subcommittee

Yes

ACES Power
Participating
Members

Yes

National Rural
Electric Cooperative
Association
(NRECA)

Yes

Overton Power
District No. 5

Yes

Arizona Public
Service Company

Yes

ReliabilityFirst

Yes

Rayburn Country
Electric
Cooperative, Inc.

Yes

Luminant Energy

Yes

US Bureau of

Yes

August 19, 2011

Question 3 Comment

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment

Reclamation
Grand Haven Board
of Light and Power

Yes

Glacier Electric
Cooperative

Yes

FHEC

Yes

South Texas
Electric
Cooperative, Inc.

Yes

National Grid

Yes

Dayton Power and
Light Company

Yes

Duke Energy

Yes

South Carolina
Electric and Gas

Yes

MidAmerican
Energy Company

Yes

Florida Keys
Electric Cooperative

Yes

East Kentucky
Power Cooperative,
Inc.

Yes

American

Yes

August 19, 2011

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Organization

Yes or No

Question 3 Comment

Transmission
Company, LLC
Farmington Electric
Utility System

Yes

Colorado Springs
Utilities

Yes

Muscatine Power
and Water

Yes

Exelon

Yes

BGE and on behalf
of Constellation
NewEnergy,
Constellation
Commodities Group
and Constellation
Control and
Dispatch

Yes

Puget Sound
Energy

Yes

GTC

Yes

Long Island Power
Authority

Yes

PJM

Yes

Oncor Electric
Delivery Company

Yes

August 19, 2011

No comment.

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment

LLC
Manitoba Hydro

Yes

ISO New England,
Inc.

Yes

City of Anaheim

Yes

Golden Spread
Electric
Cooperative, Inc.

Yes

Response: Thank you for your support. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo
any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will
be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach
to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations. Please see the revised definition.

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4.

The SDT has added specific inclusions to the core definition in response to industry comments. Do you agree
with Inclusion I3? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: While many commenters did agree with the proposal, about half of the commenters who responded to this
question disagreed with some aspect of the proposal.
The SDT believes that generation plants larger than 75 MVA connected at 100 kV or higher need to be included within the Bulk Electric System
(BES) definition. This threshold is based on the generation plant threshold values found in the NERC Statement of Compliance Registry Criteria.
Also, two Regional Entities (FRCC and RFC) specifically use this criterion in each of their current BES definitions. The 75 MVA plant is a low
enough level to capture most generating plants that would have an effect on the reliability of the interconnected Transmission network.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that
the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the
Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation
thresholds as well as several other issues that have arisen from SDT deliberations.
Commenters have suggested other thresholds (anywhere from 0 to 300 MVA) for generation plants to be included in the BES definition.
However, as of this date, commenters have not submitted technical justification upon which to base a departure from the generation MVA
thresholds included in the ERO Statement of Compliance Registry Criteria. The SDT recommends that entities use the NERC Rules of
Procedure (RoP) exception process for obtaining exceptions to the BES Definition.
Some other issues raised include the following:
•

Some commenters expressed that “single site” should be defined. “Single site” basically means “generating plant/facility” as used in the
ERO Statement of Compliance Registry Criteria (SCRC). Because this SCRC criteria understanding has not been problematic to date, the
SDT does not believe that “single site” needs to be further clarified.

•

Concerns were raised about the interpretation of the term “through a common bus”. The SDT eliminated this term, which should improve
the clarity of the definition.

•

Some commenters brought up concerns related to the “contiguous” nature of the BES. For purposes of this inclusion, the SDT is proposing
BES contiguity from the generator leads through the step up transformer(s). The SDT proposal for this inclusion does not address BES
contiguity beyond the connection to 100 kV or greater (the high side of the step-up transformer).

•

Two commenters expressed concerns that Exclusion E2 (using net capacity) and the new Inclusion I2 (using gross aggregate nameplate
capacity) are inconsistent. The SDT agrees that Exclusion E2 should over-ride this Inclusion. Exclusion E2 is dedicated to the situations
faced by behind-the-meter (retail customer owned) generation that are PURPA qualifying facilities in the US and similarly situated

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

generators in Canada. While the criteria in Inclusions I2 and I3 were based on gross nameplate ratings in MVA, the first condition (i) in
Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed relevant to the
exclusion, not the nameplate rating. The “net capacity provided to the BES” is the behind-the-meter generation that exceeds the Load
directly served by the generator. The revised language in Exclusion E2 should address these concerns.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was
reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual
or gross aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV
or above.

Organization
Northeast Power Coordinating
Council

Yes or No

Question 4 Comment

No

I3 should pertain to multiple generating units located at a single site, but the entire contiguous path should not
be labeled as BES. Oftentimes there are cases when neither the path of a 75 MVA plant or aggregated
generation will have any impact on the reliability of the interconnected transmission network nor be necessary
for its operation.
As stated earlier, under various green energy, smart grid and dispersed renewable energy plans advocated
by both Canadian and US policy makers, the gross nameplate rating of 75 MVA may undermine and deter the
future potential of integrating Distributed Generations (DG’s) that will be implemented to ensure the reliable
operation of the interconnected transmission network BES, and, at the same time, providing the most
effective and economical solutions for rate payers. Local generation can cost-effectively enhance the
reliability of load pocket by avoiding transmission, but such restrictions would deter the adoption of good
planning decisions.Path to generating facilities need not be BES contiguous. Generating units can be required
to be planned, designed, and operated in accordance with a subset of NERC Standards, but should not
require contiguous BES paths.

Response: The SDT carefully debated the generating threshold for this inclusion in the definition. After consulting with the NERC Board of Trustees and the
NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or
resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and
743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed
the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds
as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the step up transformer(s) connected on the high side at a
voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to the BES.

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Santee Cooper

No

We recommend that it say "Single generating units located at a single site with a capacity of greater than or
equal to 100 MVA". The use of aggregate capacity greater than 75 MVA pulls in some very small units.

Idaho Falls Power

No

Again, following our statement in question 3, we feel an arbitrary brightline threshold requires additional
defining criteria for inclusion.Adopting the registry's brightline criteria is to us skirting the purpose of the BES
definition effort, and lends no more clarity to what is in fact the BES.

Tennessee Valley Authority

No

Other than the NERC Registry Criteria definition, what is the technical justification for the 75 MVA threshold?
The threshold level for inclusion should be technically based on the BES capacity and configuration at the
location of the generating sources’ connection to the BES.

Western Montana Electric
Generating and Transmission
Cooperative

No

WMG&T is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn from
the NERC Statement of Compliance Registry without appreciation for the function of the threshold in that
document and without adequate technical justification demonstrating the generators with an aggregate
capacity of 75 MVA produce electric energy “needed to maintain transmission system reliability” and are
therefore properly included in the BES definition.

New York State Reliability
Council

No

The use of a 75 MVA threshold based on NERC's Registry Criteria may be administratively convenient but is
arbitrary when based upon BES reliability considerations. Suggest use of a 300 MW or other regionally and
technically acceptable threshold such as NPCC's A-10 criterion.

Intellibind

No

Though as previously stated I do not think that the 20 MVA threshold has technical merit, I do not believe that
the 75MVA limit has technical merit either. Further the impact should be measured at the buss bar not at the
nameplate. The aggregate rating should be the same as the individual unit rating on a single plant, unless the
plant can prove that there is not a common failure mode to lose more than 20MVA.

Public Utility District No. 1 of

No

Snohomish is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn from

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Snohomish County, Washington

Blachly Lane Electric Cooperative
Northern Wasco County PUD
Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc.

Question 4 Comment
the NERC Statement of Compliance Registry without appreciation for the function of the threshold in that
document and without adequate technical justification demonstrating the generators with an aggregate
capacity of 75 MVA produce electric energy “needed to maintain transmission system reliability” and are
therefore properly included in the BES definition.

No

We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn from
the NERC Statement of Compliance Registry without appreciation for the function of the threshold in that
document and without adequate technical justification demonstrating the generators with an aggregate
capacity of 75 MVA produce electric energy “needed to maintain transmission system reliability” and are
therefore properly included in the BES definition. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements.

Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Northern Lights Inc
Okanogan Electric Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Clallam County PUD No.1
Chelan PUD – CHPD
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Northwest Requirements Utilities

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

Big Bend Electric Cooperative,
Inc.
Cowlitz County PUD
Utility System Efficiencies, Inc
Coos-Curry Electric Cooperative

No

Specific language change: Change 75 MVA to 100 MVAWe are concerned that the 75 MVA threshold has
been chosen arbitrarily by the SDT. Like the 20 MVA threshold discussed in our response to question 3, the
75 MVA threshold appears to have been drawn from the NERC Statement of Compliance Registry without
appreciation for the function of the threshold in that document and without adequate technical justification
demonstrating the generators with an aggregate capacity of 75 MVA produce electric energy “needed to
maintain transmission system reliability” and are therefore properly included in the BES definition. The 100
MVA threshold seems more in alignment with technical standards such as Power System Stabilizer
requirements.

City of St. George

No

It is understood that this mirrors the Registry Criteria and this is a simple way to address the issue. The
justification states there is no technical rationale to change the 75 MVA threshold, however the technical
rationale for the 75 MVA criteria has not been provided either. Having a 75 MVA plant treated the same as a
plant with a rating of several hundred or several thousand MVA doesn’t make sense either. The requirements
for an entity or facility should match the impact of that facility to the system.

Clark Public Utilities

No

Generators should only be part of the Bulk Electric System if they are connected through a GSU to a
Transmission Element determined to be part of the BES. The current inclusion language would apply to all
generators connected to facilities greater the 100 kV with no exclusion or exception process. Without a
change, it appears that a generator connected to a facility greater than 100 kV would be a BES asset even if
the transmission assets could be excluded or excepted. I3 should be rewritten to state: Multiple generating
units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus to a Transmission
Element determined to be part of the Bulk Electric System.

Lost River Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative

Additionally, as indicated by Clark in its comments on the core definition of the BES, Clark believes the 75
MVA threshold lacks an adequate technical justification and is a purely arbitrary quantity. The use of a
capacity threshold in the definition of the BES should have technical reasons.
New England States Committee
on Electricity

August 19, 2011

No

Please refer to comments under 3 above. Additionally, regardless of the connection voltage, the 75 MVA limit
may unintentionally impose unnecessary added costs to renewable generation, thus inhibiting the
development of these resources. This is of particular concern to New England, which has aggressive

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment
renewable energy objectives and is working to develop resources in and around the region to meet them in
the most cost-effective way. Looking forward, the exception process should provide criteria allowing flexibility
as to the aggregate MVA rating as related to the specific connection and impact on a region. This will be
discussed further in comments on the Exception Process as appropriate.

Consolidated Edison Co. of NY,
Inc.

No

The inclusion of generation to the BES should be subject to an impact test.‬

Orange and Rockland Utilities,
Inc.

No

XI3 should pertain to multiple generating units impact to the Bulk system, rather than the size unit only.
Oftentimes there are cases when neither the path nor a 75 MVA unit itself will have any impact on the
reliability of the interconnected transmission network, nor is it necessary for its operation.

City of Redding

Yes

As stated in question #3 above, in concept Redding is in agreement that the Brightline should specify
generation facilities at a certain level, however we believe the SDT has no technical basis to choose the 75
MVA threshold. If the SDT elects to retain I3 in its current form then Redding suggests changing the generation
level from 75 MVA to 200 MVA. If the goal of the Brightline Definition is to create a starting point to identify
power system elements that are “necessary” then the SDT should choose a larger generation threshold as a
starting point. The 200 MVA would serve a better purpose by casting the burden of proof (via the Exception
Process) from the smaller facilities under 200 MVA to the Regional Entity. This would help the SDT to achieve
an objective of reducing the burden on the “small entity” and “distribution” facilities due that fact that most
generator facilities of this size are installed to serve local loads.
In summary, Redding supports the concept that the brightline as an initial dividing line of elements to be
labeled as BES. Therefore, Redding suggests that the SDT change the language in I3:
From: “Multiple generating units located at a single site with aggregated capacity greater than 75 MVA (gross
nameplate rating) including the generator terminals through the GSUs, connected through a common buss
operated at a voltage of 100 kV or above”.
To: Multiple generating units located at a single site with aggregated capacity greater than 200 MVA (gross
nameplate rating) including the generator terminals through the GSUs, connected through a common bus
operated at a voltage of 100 kV or above”.

Response: The SDT has not received sufficient technical justification upon which to base a departure from the generation threshold included in the ERO’s
Statement of Compliance Registry Criteria.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the

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Organization

Yes or No

Question 4 Comment

high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
The SDT recommends that entities use the NERC Rules of Procedure process for obtaining exceptions to the BES Definition as needed. No change made.
NERC Staff Technical Review

No

>>>The interconnection voltage threshold should be removed. The contribution of a multiple generating units
at a single site to system reliability is a function of the aggregate MVA rating rather than the interconnection
voltage. All locations with multiple generating units with aggregate capacity greater than 75 MVA should be
included in the BES definition because all such units provide similar contributions to system reliability.
>>>>>>>>>>
As noted in the comment on Question 3 of this comment request, the specific inclusion of the GSU
transformer implies that all other components of a generating unit, such as its unit auxiliary transformer, startup transformer, governor, exciter, power system stabilizer, etc., are excluded. The SDT should define
“generating unit” or otherwise clarify which components of a generating unit are included in the BES definition.
>>>>>>>>>>
The use of the term “common bus” introduces ambiguity into the definition. It would be better to replace the
phrase “connected through a common bus” with the phrase “connected through a common point of
interconnection” which also provides consistency with the description of Inclusion I5.

Response: NERC Staff has not provided technical justification for requiring the inclusion of all generating resources greater than 75MVA no matter the
interconnecting voltage.
The SDT believes that “generating unit” (now expressed as “generating resources”) does not need further clarification. The SDT believes that specific
requirements for generation support equipment and functions should be addressed by specific NERC standards. The goal of the SDT is to provide clarity to the
BES Definition and not to address reliability standards applicability.
The SDT agrees that using the “common bus” term is problematic. The revised definition should resolve this concern.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
NERC Transmission Issues
Subcommittee (TIS)

No

The use of the term “common bus” technically has a very specific meaning and would openly exclude most
modes of connection. There is no “common bus” in a ring-bus or a breaker-and-one-half configuration. Also,
it is not necessary to include the GSU (s), as commented in 3 above. >>>>>>>>>>
The TIS suggests using wording similar to that contained in I5: >>>>>>>>>>“I3 - Multiple generating units

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Yes or No

Question 4 Comment
located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
connected through a common bus operated at a common point of interconnection to a system Element at a
voltage of 100 kV or above.”

Response: The SDT has eliminated term “common bus”. The SDT believes that the revised proposed definition is an improvement.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Dominion

No

As stated in its response to Question 2 above, Dominion disagrees that a generation resource, Element or
Facility should automatically be included in the BES. Dominion agrees that the Generator Owner and
Generator Operator, as users of the bulk power system, should have to abide by applicable reliability
standards, but do not agree that this should automatically require the inclusion of a generation resource,
Element or Facility in the BES.
Further, Dominion prefers that the SDT use the term “generation resources” as stated in the current BES
definition contained in the Glossary of Terms, instead of the proposed term “generation unit”

Response: The SDT agrees and has proposed the term “generating resources” for clarity.
The SDT scope was determined by the language contained in Order Nos. 743 & 743a in which the Commission provided guidance to the ERO to clarify the
definition for continent-wide application. The Commission did not propose significant changes to the current application of the existing definition over the majority
of the continent. Therefore the SDT has developed a draft core definition, together with BES designations (Inclusions and Exclusions) that provide the specificity
necessary to identify the vast majority of BES Elements by utilizing the existing definition and criteria previously approved for this purpose. After consulting with
the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time.
There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to
address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the
NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization
Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.

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Organization
MRO's NERC Standards Review
Forum

Yes or No

Question 4 Comment

No

The wording “connected through a common bus” is drawn from the NERC Compliance Registry Criteria.
NSRF agrees with the language if the intent is to let entities classify the applicable multiple generating units
as part of the BES only when it is connected to one (common) bus. However, if the intent is for entities to also
classify multiple generation as part of the BES when it is connected through two or more GSUs to different
bus sections of a set of (common) buses that are interconnected through bus-tie breakers [which may be
done to provide improved reliability and maintenance flexibility], then wording like “connected through a
common bus or set of interconnected buses” would be more appropriate.
It is the NSRF’s understanding that entities do not have to classify applicable multiple generating units as part
of the BES when the aggregate MVA is connected to different buses at different voltage levels and no more
than 75 MVA is connected to any one bus (or set of interconnected buses) at a single voltage level of 100 kV
or more. Is this a correct interpretation?

American Transmission
Company, LLC

No

ATC offers the following alternative language: o The wording “connected through a common bus” is drawn
from the NERC Compliance Registry Criteria. ATC agrees with the language if the intent is to let entities
classify the applicable multiple generating units as part of the BES only when it is connected to one (common)
bus. However, if the intent is for entities to also classify multiple generation as part of the BES when it is
connected through two or more GSUs to different bus sections of a set of (common) buses that are
interconnected through bus-tie breakers [which may be done to provide improved reliability and maintenance
flexibility], then wording like “connected through a common bus or set of interconnected buses” would be
more appropriate.
o It is also ATC’s understanding that entities do not have to classify applicable multiple generating units as
part of the BES when the aggregate MVA is connected to different buses at different voltage levels and no
more than 75 MVA is connected to any one bus (or set of interconnected buses) at a single voltage level of
100 kV or more. Is this a correct interpretation?

Response: The SDT has eliminated the term “through a common bus”. The SDT believes that the revised proposal should be an improvement. The SDT also
believes that this inclusion is in conformance with the generation plant 75 MVA threshold in the NERC Statement of Compliance Registry Criteria, which has not
needed clarification to date.
The SDT cannot address each and every unique situation related to the connection of generation resources. More information would be needed before this
question could be answered. For individual situations, entities may seek exception by using the NERC Rules of Procedure (RoP) exception process to present
relevant evidence.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross

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Yes or No

Question 4 Comment

aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
SERC OC Standards Review
Group

No

“Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) including the generator terminals through the GSUs, connected through a
common bus operated at a voltage of 100 kV or above.”
GSUs need to be defined - see response to question 3 above.

Response: This inclusion has been clarified using the term step up transformer(s) rather than GSU.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Hydro One Networks Inc
FortisBC

No

We agree with the concept of Inclusion I3 with respect to multiple generating units located at a single site, but
do not support that the entire contiguous path has to be BES. The path of a 75 MVA plant or aggregated
generation will rarely have any impact on the reliability of the interconnected transmission network nor is it
necessary for its operation. We also do not support the fact that there should be a blanket application of this
inclusion.As stated earlier, under various green energy, smart grid and dispersed renewable energy plans
advocated by both Canadian and US policy makers, the gross nameplate rating of 75 MVA may undermine
and deter the future potential of integrating Distributed Generations (DG’s) that will be implemented to ensure
the reliable operation of the interconnected transmission network BES, and, at the same time, providing the
most effective and economical solutions for the rate payers in North America. Local generation can costeffectively enhance the reliability of load pocket by avoiding transmission, but such restrictions would deter
the adoption of good planning decisions.Upcoming load displacement projects would result in the installation
of new self-generation facilities at customer sites, with the electricity generated being used on-site by the
customer, with a resultant decrease in the consumption of electricity purchased via large scale generation.
These projects can be large, and displace a substantial portion of the customer’s (or local distribution
company’s) existing load, even to the extent of total self-sufficiency and the availability of surplus generation.
The aggregated surplus generation capacity may very well exceed 75 MVA and would consequently force the
facility owners to register as both Generation Owners (GO) and Transmission Owners (TO), which may be in
conflict with regulatory rules in many jurisdictions.
We suggest the following:
o Generation restriction (75 MVA) should either be revised or the exception procedure should allow entities,

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Yes or No

Question 4 Comment
with the support of technical evidence, to exclude element(s) being labeled as part of BES.
o Path to generating facilities need not be BES contiguous unless the unit is identified essential for the
operation of transmission network. Generating units can be required to be planned, designed, and operated in
accordance with a subset of NERC Standards, but should not require contiguous paths.
o Entities should be able to use the exception process, with the help of technical evidence, to exclude
generating units that do not impact the interconnected grid and the bulk transfer of power.
o From a regulatory perspective such an inclusion could also be in conflict with the current regulatory
requirements. Definition and/or exception process should provide acknowledgement and flexibility to avoid
any regulatory conflicts. For example, as stated earlier (Q3 response) NERC and SDT should consider
introducing a concept of a new category of registration or BES Support elements. These elements are NOT
necessarily BES but support the reliable operation of the interconnected transmission network.

Response: The definition for this inclusion only addresses BES contiguity from the generator leads through the step up transformer(s).
The SDT has not received sufficient technical justification upon which to base a departure from the generation plant 75 MVA threshold included in the ERO’s
Statement of Compliance Registry Criteria. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo
any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will
be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach
to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations.
The SDT recommends that entities use the NERC Rules of Procedure exception process for obtaining exceptions to the BES Definition.
With respect to the regulatory issue raised, the revised definition should resolve this concern.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Electricity Consumers Resource
Council (ELCON)

No

Same response as item 3 above.

Response: See response to Q3.

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Yes or No

Question 4 Comment

Electric Reliability Council of
Texas, Inc.

No

See response to question 3 - ERCOT ISO agrees with substance, but not the approach.

Fayetteville Public Works
Commission

No

The same comment made in Question 3 and applicable to Inclusion I2 is also applicable to Inclusion I3.

American Electric Power

No

Please see response to question 3.

Southern California Edison
Company

No

Please refer to SCE’s answer for Question No. 3 above.

SPP Standards Review Group

No

The comment provided for Question 3 above applies here also.

Pepco Holdings Inc

Clarification needed: Same situation as described in #3 above.

Southwest Power Pool

Yes

Please see SPP's response to question 3 - SPP agrees with substance, but not the approach.

Michgan Public Power Agency

Yes

See comments to question 3

No

We believe that automatic inclusion of 75 MVA generation and the path to connect them to the BES should
not be automatically included in the BES.

Response: See response to Q3.
Hydro-Quebec TransEnergie

However, a provision should be made so that some reliability standards related to generator shall apply
(voltage regulation, etc.).
Response: The definition for this inclusion only addresses BES contiguity from the generator leads through the step up transformer(s) which is connected on
the high side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service
(generation) to the BES.
The SDT believes that NERC Reliability Standards may be applied to specific generator support elements (e.g., voltage regulation) that are necessary to operate
the interconnected transmission network. The goal of the SDT is to provide clarity to the BES Definition and not to address Reliability Standards applicability.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross

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Yes or No

Question 4 Comment

aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Vermont Transco

No

What is the definition of “common bus”?
Would this only apply to generating facilities with a direct GSU tie to the 100 kV, and up, system?
Or would it apply to those units tied to the low side of a transformer at a voltage below 100 kV that has a step
up high side voltage greater than 100 KV? Example: units are tied through to a single 46 kV substation (GSU
high side connected to this substation) with a tie from this substation to the BES through a step up
transformer.

Response: The SDT has eliminated the term “common bus”.
The SDT cannot address each and every unique situation related to the connection of generation resources. More information would be needed before this
question could be answered. For individual situations, entities may seek exception by using the NERC Rules of Procedure (RoP) exception process to present
relevant evidence.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Sweeny Cogeneration LP

No

The threshold for multiple generation units aggregated at a single location is consistent with the NERC
functional registry criterion. We believes that it is important to maintain this uniformity. However, we believe
there are further items to be added to the list related to generator interconnections, a task that was passed to
this project from Project 2010-07. Just as is the case with complex distribution systems, there are a variety of
generator-transmission interconnection architectures which are driving the Regions to inappropriately register
Generator Owner/Operators as Transmission Owners.

Response: More information would be needed before the concern can be answered. No change made.
Muscatine Power and Water

August 19, 2011

No

The phrase “connected through a common bus” is taken from the NERC Compliance Registry Criteria.
MP&W would agree with this language if the intent is to let entities categorize the applicable multiple
generating units as part of the BES only when it is connected to one (common) bus. However, if the intent is
for entities to also classify multiple generation as part of the BES when it is connected through two or more
GSUs to different bus sections of a set of (common) buses that are interconnected through bus-tie breakers

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Question 4 Comment
(which may be done to provide improved reliability and maintenance flexibility), then using language like
“connected through a common bus or set of interconnected buses” would be more appropriate.

Response: The SDT believes the term “through a common bus” is problematic and the revised proposal should resolve this concern.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Springfield Utility Board

No

While Springfield Utility Board does not own any generating units, we do recognize the importance of the
restoration of the Grid, and the generation necessary for the Grid. SUB would recommend that NERC clearly
define “location” and “single site”. Does single site mean interstate service area location (adding up
generation over multiple geographically separate areas), same City?, same common bus?, etc... SUB
suggests that for purposes of I3 (and other inclusions and exclusions that reference “same site”, “same
location”, or similar language) that the term “collectively share a common bus” be used.

Springfield Utility Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: The SDT believes that “single site” is in agreement with the ERO Statement of Compliance Registry Criteria (SCRC) threshold for including greater
than 75 MVA generating plants/plants. Because this SCRC criterion has not been problematic to date, the SDT does not believe that “single site” needs to be
further clarified.

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Organization

Yes or No

Question 4 Comment

The SDT has not received sufficient technical justification to exclude load modifying or backup generation plants as described from the BES Definition. No
changes made.
Public Utilities Commission of
Ohio

No

New York State Dept of Public
Service

This should be expanded to also refer to individual generation capacity, as well as aggregate, at 75 MVA and
above.
I3 should be revised to read all generation - individually or aggregate - 75 MVA and above.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Cogentrix Energy, LLC

No

GSUs need to be defined - see response to question 3 above

Response: This inclusion has been clarified to use the term step up transformer(s) rather than GSU.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
The Dow Chemical Company

No

It should be clarified that Exclusion E2 over-rides this Inclusion. See ELCON comments.

ExxonMobil Research and
Engineering

Yes

Support is contingent on the continued exclusion of generation based on its net capacity provided to the BES.

Response: The SDT agrees that Exclusion E2 should over-ride this inclusion. The revised language in Exclusion E2 should address these concerns.

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PJM

Yes or No
No

Question 4 Comment
As written I3 implies a contiguous system from the unit to a “common bus operated at a voltage above 100
kV” there is no technical justification for a contiguous system. The requirement should read “Multiple
generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) including the generator terminals through the GSU”

Response: The SDT’s revised proposal should address this concern. The definition for this inclusion only addresses BES contiguity from the generator leads
through the step up transformer(s).
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Oncor Electric Delivery Company
LLC

No

The ERCOT Region already considers load in any combination equal to and over 20 MVA through a single
Point of Interconnect as part of the BES

Response: The definition does not preclude more restrictive local requirements.
PPL Energy Plus and PPL
Generation

No

See comments in Question 13

Illinois Municipal Electric Agency

Yes

Please see comments under Question 13.

No

It is not clear if this inclusion only applies if the generators at a single site have an aggregate capacity greater
than 75 MVA AND are connected through a common bus operated at 100kV or if the inclusion applies if the
generators at a single site have an aggregate capacity of over 75MVA regardless of whether or not they are
connected through a common bus operated at 100kV or above. For example, would this inclusion apply if a
utility has over 75MVA at single generating site but only a small portion of the generating capacity is
connected through the GSU to a common bus at 100kV or above and the rest is connected through a
common bus operating at less than 100kV? Suggested wording: “Multiple generating units located at a single
site connected to a common bus operated at a voltage of 100kV or above with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) including the generator terminals through the GSUs.

Response: See response to Q13.
Manitoba Hydro

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Yes or No

Question 4 Comment

Response: The SDT’s revised proposal should be understood to mean that all applicable generating resources at a single site, their generator terminals,
connecting cabling up to and including their step up transformer(s) that are connected at 100kV or greater will be included in the definition of the BES.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Independent Electricity System
Operator

No

See our responses to Q1 and Q3.

No

We agree with the concept of Inclusion I3 with respect to multiple generating units located at a single site, but
do not support that the entire contiguous path has to be BES. The path of a 75 MVA plant or aggregated
generation will rarely have any impact on the reliability of the interconnected transmission network nor is it
necessary for its operation.

Response: See responses to Q1 & Q3.
AltaLink

Generation restriction (75 MVA) should either be revised or the exception procedure should allow entities,
with the support of technical evidence, to exclude element(s) being labeled as part of BES. Path to generating
facilities need not be BES contiguous. Generating units can be required to be planned, designed, and
operated in accordance with a subset of NERC Standards, but should not require contiguous paths.
Response: The definition for this inclusion only addresses BES contiguity from the generator leads through the step up transformer(s) connected on the high
side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to the
BES.
The SDT has not received sufficient technical justification upon which to base a departure from the generation plant threshold included in the ERO’s Statement of
Compliance Registry Criteria. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at
changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the
primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped.
Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this
project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations.
The SDT recommends that entities use the NERC Rules of Procedure exception process for obtaining exceptions to the BES Definition.

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Organization

Yes or No

Question 4 Comment

Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
BPA

No

BPA suggest defining “single site.” BPA is assuming that a “single site is a single substation with aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating) including the generator terminals through
the GSUs, connected through a common bus operated at a voltage of 100 kV or above. BPA would also like
this to be consistent with Inclusion #2 and state: a high side voltage of 100 kV or above.

Response: The SDT believes that “single site” is in agreement with the ERO Statement of Compliance Registry Criteria (SCRC) threshold. Because this SCRC
criterion has not been problematic to date, the SDT does not believe that “single site” needs to be defined. No change made.
Portland General Electric
Company

The 75 MVA aggregate capacity rating threshold could result in the inclusionin the BES of generating units
that have no potential to impact the reliability of the BES.The 75 MVA threshold was taken from the
registration criteria, and no technicaljustification has been provided for its use.
In addition, the meaning of the phrase”located at a single site” is unclear and subject to multiple
interpretations. The phrase”connected through a common bus” accomplishes the same goal, and therefore
thephrase “located at a single site” hould be removed.

Response: The SDT has not received sufficient technical justification upon which to base a departure from the generation plant threshold included in the ERO’s
Statement of Compliance Registry Criteria. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo
any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will
be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach
to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations.
The SDT believes that the term “single site” is agreement with the ERO Statement of Compliance Registry Criteria (SCRC) threshold. Because this SCRC criterion
has not been problematic to date, the SDT does not believe that “single site” needs further clarification. No changes made.
Tacoma Power

Tacoma Power generally supports Inclusion I3. However, the term ‘gross aggregate nameplate rating’ is not
defined and should be replaced with a specific definition.
Additionally, no justification for the 75 MVA level has been provided and therefore it appears arbitrary. Since
this measurement will define Elements for absolute inclusion in the BES, the threshold for multiple generation

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Organization

Yes or No

Question 4 Comment
units located at a single site should be based on a need to maintain transmission reliability. Such single sites
located within a Local Distribution Network (LDN), which do not exit the LDN, should not be included. We
propose changing Inclusion I3 to read, “Multiple generating units located at a single site with an aggregate
capacity greater than 75 MVA (aggregate capacity based on the Code of Federal Regulation, CFR 18, Part
287.1, “Determination of powerplant design capacity”) including the generator terminals through the GSUs,
connected through a common bus operated at a voltage of 100 kV or above, except multiple generating units
located at a single site that are within a Local Distribution Network (LDN) and do not have a net export out of
the LDN.”

Response: The SDT feels that the term “gross nameplate rating” is a widely used term within the industry and does not require additional defining.
The SDT has not received sufficient technical justification upon which to base a departure from the generation plant threshold included in the ERO’s Statement of
Compliance Registry Criteria. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt
at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the
primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped.
Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this
project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations.
American Municipal Power and
Members

Yes

I3 contains language similar to I2, and should be similarly reworded, as follows: “Multiple generating units
located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating),
connected through a common bus operated at a voltage of 100 kV or above. A BES generating plant
includes the equipment from the generator terminals through the respective GSUs.”

Transmission Access Policy
Study Group

Yes

I3 contains language similar to I2, and should be similarly reworded, as follows: “Multiple generating units
located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating),
connected through a common bus operated at a voltage of 100 kV or above. A BES generating plant
includes the equipment from the generator terminals through the respective GSUs.”

Northern California Power
Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.

Florida Municipal Power Agency

Response: The SDT agrees that BES contiguity for this inclusion is limited to the generator leads through the step up transformer(s). However, the SDT believes
the last sentence in the comment is not needed for clarification.

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Organization

Yes or No

Question 4 Comment

Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Western Electricity Coordinating
Council

Yes

WECC agrees in concept, but suggests that the phrase “connected through a common bus” may be unclear.
For example, if there is also load connected through that common bus, does that net, does it negate the
inclusion, or does it not matter? Perhaps a phrase such as “regardless of the amount of load also connected
through that common bus” would help. The GSU comment from I2 also applies. Suggested language
“...including the generator terminals up to and including the GSU transformer, which has a high-side voltage
of 100 kV or above.”

Response: The SDT eliminated the term “common bus”.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Central Maine Power Company

Yes

New York State Electric & Gas
and Rochester Gas & Electric

Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is MVA instead of
MW.

Response: The ERO Statement of Compliance Registry Criteria uses MVA units (not MW units) for both generator unit and generation plant capacities. No
change made.
PacifiCorp

Response:

Yes

PacifiCorp understands the SDT is looking for technical reasons for something other than 75 MVA. PacifiCorp
believes it is not feasible to determine a value that is consistent across the continent. Although PacifiCorp
believes 75 MVA is too low, it is an acceptable number for any configuration of generation (see comment on
question 3). Those above 75 MVA believed to be exempt from the BES definition can be processed through
the proposed ROP inclusion/exclusion process.PacifiCorp submits the following suggested wording for I3:
“Multiple generating units with an aggregate capacity greater than 75 MVA or a single generating unit with a
generating capacity greater than 75 MVA.....”

Stakeholder comments have not provided technical justification by which to base a departure from the 75 MVA threshold where connected at 100

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Organization

Yes or No

Question 4 Comment

kV and above. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Alberta Electric System Operator

Yes

Consider adding the word “transformer” after “GSU”.

Response: The SDT agrees and has replaced GSU with the term “step-up transformer(s)”.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Idaho Power

Yes

Generally agreed but please revise to inlcude I2, I3 and I5 at 75 MVA, see Question 3 and 6 comments.

Long Island Power Authority

Yes

We recommend clarifying that I3 only covers units under 20 MVA and that the aggregation similarly just
applies to those units that are under 20MVA. Example: a 100 MVA generating unit and a 15 MVA generating
unit at a single site only the 100 MVA generating unit would be BES per Inclusion I2 but Inclusion I3 would not
apply.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross

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Organization

Yes or No

Question 4 Comment

aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Central Lincoln

Yes

Please indicate how aggregate generation below 75 MVA is to be treated, since we don’t believe the flowchart
at http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly expresses the SDT’s
intent to classify these small plants as non-BES.

Response: The BES Rule of Procedure team has been made aware of this.
Sacramento Municipal Utility
District (SMUD)

Yes

SMUD also agrees with the Inclusion 3 concept.

Sierra Pacific Power Co d/b/a NV
Energy

Yes

While 75MVA has no technical basis for the threshold above which an aggregate generation plant should be
considered to be necessary for the reliable operation of an interconnected transmission network, the industry
has not provided any technical data to support a value other than this which has been established in the
NERC Statement of Compliance Registry Criteria.

PUD No. 2 of Grant County,
Washington

Yes

Grant supports this proposed inclusion.

Public Service Enterprise Group
LLC

Yes

Tri-State Generation and
Transmission Association, Inc.

Yes

Imperial Irrigation District

Yes

SERC Planning Standards
Subcommittee

Yes

ACES Power Participating
Members

Yes

National Rural Electric
Cooperative Association

Yes

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Organization

Yes or No

Question 4 Comment

(NRECA)
Overton Power District No. 5

Yes

Arizona Public Service Company

Yes

ReliabilityFirst

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

New York Power Authority

Yes

Southern Company

Yes

Luminant Energy

Yes

Western Area Power
Administration

Yes

US Bureau of Reclamation

Yes

Grand Haven Board of Light and
Power

Yes

Glacier Electric Cooperative

Yes

FHEC

Yes

South Texas Electric
Cooperative, Inc.

Yes

National Grid

Yes

Dayton Power and Light

Yes

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Organization

Yes or No

Question 4 Comment

Company
Duke Energy

Yes

South Carolina Electric and Gas

Yes

MidAmerican Energy Company

Yes

Florida Keys Electric Cooperative

Yes

East Kentucky Power
Cooperative, Inc.

Yes

Farmington Electric Utility System

Yes

Colorado Springs Utilities

Yes

Consumers Energy Company

Yes

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

Yes

Exelon

Yes

Puget Sound Energy

Yes

GTC

Yes

ISO New England, Inc.

Yes

City of Anaheim

Yes

August 19, 2011

No comment.

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Organization

Yes or No

MEAG Power

Yes

Xcel Energy

Yes

Golden Spread Electric
Cooperative, Inc.

Yes

Question 4 Comment

Response: Thank you for your support. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo
any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will
be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach
to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations. Please see the revised definition.

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5. The SDT has added specific inclusions to the core definition in response to industry comments. Do you agree
with Inclusion I4? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often
composed of distribution system elements. In addition, the Transmission Operator’s actual restoration may make use of paths that were not
identified as Cranking Paths in the restoration plan due to the particular system configuration on the day in question. Therefore, the SDT has
removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise
its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission
network. The SDT interprets this to include operation under both normal and Emergency conditions, which include situations related to
blackstarts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be energized
without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for Real and
Reactive Power capability, frequency, and voltage control. The associated resources of the electric system that can be isolated and then
energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating units as
defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources
indentified in the Transmission Operator’s restoration plan as BES Elements.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules
of Procedure exception process to request including it in the BES.
Inclusion I4 has been re-numbered as Inclusion I3 and revised as follows:
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of
voltage.

Organization

Yes or No

Question 5 Comment

Public Service Enterprise Group
LLC

No

Black start resources and the cranking path should not be included in the BES definition unless connected at
100kV and above. There are many other existing standards that impact black start units. Routine testing and
redundancy is part of them. Adding in black start units < 100kV and the associated cranking path to the BES
definition may discourage entities from providing black start capability due to cost associated with cumulative
testing and record keeping criteria. This may result in withdrawing the offer to provide that service and/or
potentially drive up the cost of that service significantly without any related increase in BES reliability.

ACES Power Participating

No

Blackstart resources are rarely used. For many reasons, restoration almost always starts with synchronizing

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Organization

Yes or No

Members

Western Montana Electric
Generating and Transmission
Cooperative
Public Utility District No. 1 of
Snohomish County, Washington

Question 5 Comment
to other systems (the Interconnection) that are already intact. Because Blackstart Resources can actually be
on the distribution system, the distribution system can then become subject to the enforceable standards.
This results in significant increased costs in tracking compliance for these distribution systems without a
commensurate increase in reliability. Because a Blackstart Resource must be included in the Transmission
Operator’s restoration plan, this creates a perverse incentive to un-designate the Blackstart Resource that is
on a distribution system to avoid the distribution system becoming part of the Bulk Electric.

Yes

Including “all” blackstart and blackstart cranking paths in the BES may ultimately provide an incentive to the
electric industry to reduce the number of resources with blackstart capability. We therefore suggest that
essential blackstart resources identified by the Regional Entity should be included in the Bulk Electric System,
but non-essential blackstart resources need not be.

Northern Wasco County PUD
Clallam County PUD No.1
Chelan PUD – CHPD
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc.
Cowlitz County PUD
Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system elements. In
addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking Paths in the restoration plan due to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES definition to
ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this to include
operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources have the
ability to be started without support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the electric system

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Organization

Yes or No

Question 5 Comment

that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating
units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the
Transmission Operator’s restoration plan as BES Elements.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
Transmission Operators are responsible for maintaining a viable, reliable restoration plan, regardless of the BES definition; the SDT does not agree that adding
Blackstart Resources to the BES definition alone would “discourage entities from providing Blackstart capability.”
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Northeast Power Coordinating
Council

August 19, 2011

No

Blackstart resources and transmission facilities on the cranking path should not be classified as BES
regardless of size and voltage level. From a regulatory perspective, such an inclusion would be in conflict with
the current regulatory requirements in many jurisdictions. More importantly, designating these facilities as
BES Elements or Facilities beyond the 100 kV bright line, the 20 MVA/unit or 75 MVA/plant criteria, without a
regard to their impact on the BES (under conditions other than system restoration) will impose unnecessary
requirements for these facilities, which do not contribute to reliability under interconnected operation
conditions. For a restoration condition, this inclusion is extraneous. There is already a designation specific for
system restoration covered by an existing standard to recognize their reliability impacts and to ensure their
expected performance. NERC Standards EOP-005-2 stipulates the requirements for testing blackstart
resource and cranking paths. This testing requirement suffices to ensure that the facilities critical to system
restoration are functional when needed, which meets the intent of identifying their criticality to reliability.The
BES definition should cover those facilities that are needed for operation under both normal and emergency
conditions, which includes situations related to blackstart and system restoration. The directives should not
specifically ask for inclusion of blackstart resources and facilities on the cranking path in the BES definition.
The requirements in EOP-005-2 suffice to address the SDT’s interpretation and concern regarding recognition
of the reliability impacts and requirements for blackstart resources and facilities used for system
restoration.Generating units of any size and transmission facilities of any voltage level may be used for black
start and restoration. Conceivably, a generator of 10 MW and transmission or distribution facilities of 44 kV or
69 kV may be a part of the cranking path. A BES inclusion will then subject these generators and facilities,
which are essentially “local” facilities but called upon to begin restoring its bulk interconnected counterparts, to
comply with the reliability standards intended for maintaining BES reliability. Included in the BES definition will
thus discourage smaller generators from providing black start capability, and the transmission facilities from
being a part of the cranking path. This may also discourage Transmission Owners and Operators from
identifying multiple black start resources and cranking paths to provide restoration flexibility. Such an inclusion
will ultimately undermine reliability.If indeed any of these facilities are deemed necessary to support bulk
power system reliability at times other than system restoration, they would/should have been identified

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Organization

Yes or No

Question 5 Comment
through the basic BES definition and inclusion list or can be addressed through the exception procedure.
I4 should be removed based upon: o The availability and performance expectations of blackstart resources
and facilities on the cranking path are already specifically addressed in an existing standard; and o Unless
they meet the BES definition and the other inclusion criteria, they do not have any perceived reliability impact
on everyday operation of the BES.
o I4 may include very small generators and distribution facilities as it is written. Is it necessary from a
reliability point of view to include “cranking paths” below 100kV?

American Municipal Power and
Members

No

We recommend that the SDT exclude Blackstart Units under 20MW and Blackstart Units that are connected
via their GSU to Non-BES Facilities (under 100kV). We believe this would be a minimal impact on the
existing Restoration Plans while increasing the reliability and viability of these Restoration Plans since the
industry would be forced to use only BES facilities as defined by NERC BES definition. This would force all
Blackstart Units to be compliance with all Reliability Standards if this change is implemented.

Hydro One Networks Inc

No

We do not agree with Inclusion I4. Blackstart resources and transmission facilities on the cranking path
should not be classified as BES regardless of size and voltage level. From a regulatory perspective, such an
inclusion would be in conflict with the current regulatory requirements in many of the jurisdictions. More
importantly, designating these facilities as BES Elements or Facilities beyond the 100 kV bright line, the 20
MVA/unit or 75 MVA/plant criteria, without a regard to their impact on the BES (under conditions other than
system restoration) will impose unnecessary requirements for these facilities, which do not contribute to
reliability under interconnected operation conditions. For restoration condition, this inclusion is extraneous
given there is already a designation specific for system restoration covered by an existing standard to
recognize their reliability impacts and to ensure their expected performance. NERC Standards EOP-005-2
stipulates the requirements for testing blackstart resource and cranking paths. This testing requirement
suffices to ensure that the facilities critical to system restoration are functional when needed, which meets the
intent of identifying their criticality to reliability.While we do not disagree with the SDT’s interpretation of the
FERC directives, the BES definition should cover those facilities that are needed for operation under both
normal and emergency conditions, which includes situations related to black-start and system restoration. We
do not agree that the directives specifically ask for inclusion of blackstart resources and facilities on the crank
path in the BES definition. We believe the requirements in EOP-005-2 suffice to address the SDT’s
interpretation and concern regarding recognition of the reliability impacts and requirements for blackstart
resources and facilities used for system restoration.Generating units of any size and transmission facilities of
any voltage level may be used for blackstart and restoration. Conceivably, a generator of 10 MW and
transmission facilities of 44 kV or 69 kV may be a part of the cranking path. A BES inclusion will then subject
these generators and facilities, which are essentially “local” facilities but called upon to begin restoring its bulk
interconnected counterpart, to comply with the reliability standards intended for maintaining BES reliability.

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Organization

Yes or No

Question 5 Comment
Included in the BES definition will thus discourage smaller generators from providing blackstart capability, and
the transmission facilities from being a part of the cranking path. This may also discourage Transmission
Owners and Operators from identifying multiple blackstart resources and cranking paths to provide restoration
flexibility. Such an inclusion will ultimately undermine reliability.If indeed any of these facilities are deemed
necessary to support bulk power system reliability at times other than system restoration, they would/should
have been identified through the basic BES definition and inclusion list or can be addressed through the
exception procedure. We suggest and urge the SDT to remove I4 on the basis that: o The availability and
performance expectations of blackstart resources and facilities on the cranking path are already specifically
addressed in an existing standard; and o Unless they meet the BES definition and the other inclusion criteria,
they do not have any perceived reliability impact on everyday operation of the BES.

Southern Company

No

Inclusion I4 should be removed from this definition. There is an existing standard, EOP-005-2 (System
Restoration from Blackstart Resources), which specifically addresses Blackstart Resources and the
designated Blackstart Cranking Paths "regardless of voltage". Also, use of "regardless of voltage" in Inclusion
I4 as part of the BES definition will expand the applicability of some NERC Reliability Standards, which
pertains to the BES, to connected facilities at voltage levels below 100Kv.

Hydro-Quebec TransEnergie

No

When we have to use Blackstart Resources, there is no more system. Therefore, reliability is not a system
planning issue, the need is no more for reliability since we lost the System or part of it. It becomes a need for
restoration of the system as fast as possible. The restoration plan is necessary, but the Blackstart Resources
and do not contribute to the reliability of the System, which just failed, but to limit the time of loss of service.
There is no obligation to apply the same Reliability Standards on the paths and it should not be automatically
included in the BES.

National Grid

No

We do not feel that blackstart resources and cranking paths should be classified as BES. In several
instances, cranking paths direct the operator to pick up distribution load before moving on to the next step for
stability purposes. These are non-jurisdictional distribution facilities and should not be considered BES, since
they are not necessary to support the reliability of the bulk power system during normal conditions. The BES
definition should cover those facilities that are within FERC’s jurisdiction and that are needed for operation
under both normal and emergency conditions, which may include some facilities related to black-start and
system restoration, but not all. The directives should not broadly include blackstart resources and facilities on
the cranking path in the BES definition. This is over inclusive. The requirements in NERC standard EOP-0052 address the SDT’s interpretation and concern regarding recognition of the reliability impacts and
requirements for blackstart resources and facilities used for system restoration.For example, there could also
be small generators (less than 20 MVA/unit or 75 MVA/plant) or transmission and distribution facilities of 69
kV or less, which are considered “local”, that are used for system restoration in the cranking path. A BES
inclusion will then subject these generators and facilities, which are “local”, non-jurisdictional facilities that

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Organization

Yes or No

Question 5 Comment
may be called upon to begin restoring its bulk interconnected counterparts, to comply with the reliability
standards intended for maintaining BES reliability. Including these facilities in the BES definition will thus
discourage smaller generators from providing blackstart capability, and the transmission facilities from being a
part of the cranking path. This may also discourage Transmission Owners and Operators from identifying
multiple blackstart resources and cranking paths to provide restoration flexibility. This will ultimately
undermine reliability.
Also, including these types of facilities in the BES definitions could lead to jurisdictional challenges that could
cause uncertainty and delay the implementation of the new BES definition and divert important industry and
regulatory resources.
Because of these reasons, I4 should be removed from the inclusions list.

Dayton Power and Light
Company

No

Black start resources should not be included in this new proposal, which is being developed in response to
FERC Orders 743 and 743A. These orders do not mention the inclusion of black start resources or cranking
paths. These resources are undeniably important and we believe the existing CIP and other NERC standards
applicable to them provide sufficient and appropriate safeguards. Their inclusion as BES elements would
significantly increase the requirements for both distribution and 69kV cranking paths - which would be
classed as BES elements and fall under all those requirements. Entities currently include multiple cranking
paths for their restoration plans to improve the flexibility of their resources. However, if cranking paths are
considered BES and must meet those requirements, they will default to a single cranking path which would
potentially decrease their flexibility. The purpose of the bulk electric system is to accommodate the bulk
movement of electricity through the interconnected system. In a black start situation, entities would NOT be
interconnected and not moving bulk power. In light of the above, there is no sound basis for inclusion of
these elements as part of the BES.

Cogentrix Energy, LLC

No

The SERC SRG is concerned that this provision may have the effect of incenting transmission operators to
limit the available generator options to the minimum necessary for a reliable option as opposed to every
possible option that might be utilized in a pinch. We recommend the following adjusted language: “Essential
Blackstart Resources and the designated essential blackstart Cranking Paths identified in the Transmission
Operator’s restoration plan regardless of voltage”

New England States Committee
on Electricity

No

Please refer to comments under 3 above. Black start units should be excluded from BES. These units and
their associated cranking paths are used only for restoration and not operation. Such units are appropriately
covered under regional restoration procedures and applicable NERC standards (see for example, Emergency
Operating Procedure EOP-005-2). NESCOE is still exploring the impact and necessity of this proposed
inclusion.

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Organization

Yes or No

Question 5 Comment

Manitoba Hydro

No

Inclusion I4 should be modified so that only the Blackstart Resources and designated Cranking Paths
required for compliance with the NERC Emergency Preparedness and Operations Standards are included in
the BES Definition.

ISO New England, Inc.

No

The SDT states that “One of the basic tenets that the SDT is following is to avoid changes to registration due
to the revised definition if such changes are not technically required for the definition to be complete.”
However, adding every black start generator and the designated cranking path to the definition of the BES is
at odds with the Statement of Compliance Registry Criteria which states: III.c.3 Any generator, regardless of
size, that is a blackstart unit material to and designated as part of a transmission operator entity’s restoration
plan, or; The SDT should use the registry language in order to not expand the BES to every cranking path on
the distribution system from a small generator entered into the black start program.
Furthermore, the SDT cannot simply disregard voltage level, because: (a) FERC Order 743 expresses
preference for a bright line definition, and (b) Section 215 of the Federal Power Act defines the “bulk-power
system” as, in part, “electric energy from generation facilities needed to maintain transmission reliability”. As
the NERC Compliance Registry has long recognized, not every generator that is a blackstart unit is “material”
- i.e., may not be necessary - to the restoration plan or, therefore, to bulk-power system reliability.

Independent Electricity System
Operator

No

This inclusion is extraneous given there is already a designation specific for system restoration covered by an
existing standard to recognize their reliability impacts and to ensure their expected performance. NERC
Standards EOP-005-2 stipulates the requirements for testing blackstart resource and cranking paths. This
testing requirement suffices to ensure that the facilities critical to system restoration are functional when
needed, which meets the intent of identifying their criticality to reliability. We therefore suggest removing
Inclusion I4.

AltaLink

No

We do not agree with Inclusion I4. Blackstart resources and transmission facilities on the cranking path
should not be classified as BES regardless of size and voltage level. From a regulatory perspective, such an
inclusion would be in conflict with the current regulatory requirements in many of the jurisdictions. More
importantly, designating these facilities as BES Elements or Facilities beyond the 100 kV bright line, the 20
MVA/unit or 75 MVA/plant criteria, without a regard to their impact on the BES (under conditions other than
system restoration) will impose unnecessary requirements for these facilities, which do not contribute to
reliability under interconnected operation conditions. For restoration condition, this inclusion is extraneous
given there is already a designation specific for system restoration covered by an existing standard to
recognize their reliability impacts and to ensure their expected performance. NERC Standards EOP-005-2
stipulates the requirements for testing blackstart resource and cranking paths. This testing requirement
suffices to ensure that the facilities critical to system restoration are functional when needed, which meets the
intent of identifying their criticality to reliability.While we do not disagree with the SDT’s interpretation of the

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Organization

Yes or No

Question 5 Comment
FERC directives, the BES definition should cover those facilities that are needed for operation under both
normal and emergency conditions, which includes situations related to black-start and system restoration. We
do not agree that the directives specifically ask for inclusion of blackstart resources and facilities on the crank
path in the BES definition. We believe the requirements in EOP-005-2 suffice to address the SDT’s
interpretation and concern regarding recognition of the reliability impacts and requirements for blackstart
resources and facilities used for system restoration.Generating units of any size and transmission facilities of
any voltage level may be used for blackstart and restoration. Conceivably, a generator of 10 MW and
transmission facilities of 44 kV or 69 kV may be a part of the cranking path. A BES inclusion will then subject
these generators and facilities, which are essentially “local” facilities but called upon to begin restoring its bulk
interconnected counterpart, to comply with the reliability standards intended for maintaining BES reliability.
Included in the BES definition will thus discourage smaller generators from providing blackstart capability, and
the transmission facilities from being a part of the cranking path. This may also discourage Transmission
Owners and Operators from identifying multiple blackstart resources and cranking paths to provide restoration
flexibility. Such an inclusion will ultimately undermine reliability.If indeed any of these facilities are deemed
necessary to support bulk power system reliability at times other than system restoration, they would/should
have been identified through the basic BES definition and inclusion list or can be addressed through the
exception procedure.
We suggest and urge the SDT to drop I4 on the basis that: o The availability and performance expectations
of blackstart resources and facilities on the cranking path are already specifically addressed in an existing
standard; and
o Unless they meet the BES definition and the other inclusion criteria, they do not have any perceived
reliability impact on everyday operation of the BES.

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system elements. In
addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking Paths in the restoration plan due to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES definition to
ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this to include
operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources have the
ability to be started without support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the electric system
that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating
units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the
Transmission Operator’s restoration plan as BES Elements.

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Organization

Yes or No

Question 5 Comment

If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Small Entity Working Group
(SEWG)

No

The SEWG proposes a minor change to Inclusion I4. The SEWG recommends that the SDT exclude
Blackstart Units under 20MW and Blackstart Units that are connected via their GSU to Non-BES Facilities
(under 100kV). We believe this would be a minimal impact on the existing Restoration Plans while increasing
the reliability and viability of these Restoration Plans since the industry would be forced to use only BES
facilities as defined by NERC BES definition. In addition, a clarification is needed under the first bullet under
I4 in the posted word comment form for this BES draft (posted in the first column under Implementation Plan
for Definition). It should be changed to read "Blackstart units that have been included in the Transmission
Operator’s restoration plan and their respective cranking paths..." We do not believe it was the intent of the
SDT to include all blackstart units in the BES definition regardless if they are not part of a Transmission
Operator's restoration plan.

Dominion

No

Dominion continues to disagree that a generation resource, Element or Facility should automatically be
included in the BES. Dominion agrees that the Generator Owner and Generator Operator, as users of the
bulk power system, should have to abide by applicable reliability standards, but do not agree that this should
automatically require the inclusion of a generation resource, Element or Facility in the BES.

SPP Standards Review Group

No

While we understand the necessity of including the Cranking Path in the BES, we are equally concerned
about the broad usage of the term BES throughout the NERC Reliability Standards and the ramifications of
extending the requirements associated with those standards to parts of the distribution system that do not
have a logical association with the BES. For example, some of the TPL standards require studies of the BES.
Does this then mean those studies would apply to those Cranking Paths on the distribution system? We think
Cranking Paths that include portions of the distribution system should be excluded from the BES definition.
Could the SDT please provide us with an explanation of why these Elements would be included in the BES
and what would be gained if they were included? We’d also like to ask the SDT to identify the standards and
requirements that would be applied to the distribution system Cranking Paths. Is there any way that the
significance of the distribution Cranking Paths could be maintained without going as far as including them in
the BES?
Also, if a Distribution Provider has a portion of his distribution system designated an Element of the BES, as
in the Cranking Path scenario, does that then require the DP to register as a TO or TOP?

Michgan Public Power Agency

August 19, 2011

No

I would agree to this for Blackstart Resources only designated Blackstart Cranking Paths in the Transmission

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Organization

Yes or No

Question 5 Comment
Operator’s restoration plan regardless of voltage.

Tacoma Power

Tacoma Power generally supports Inclusion I4. We believe additional consideration should be given to
identifying only the Blackstart Resource`s that support a regional recovery. Based on that criteria, we
propose changing Inclusion I4 to read,”Blackstart Resources and the designated blackstart Cranking Paths
identified in the Transmission Operator’s restoration plan, regardless of voltage, and included in a regional
restoration plan.”

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system elements. In
addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking Paths in the restoration plan due to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES definition to
ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this to include
operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources have the
ability to be started without support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the electric system
that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating
units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the
Transmission Operator’s restoration plan as BES Elements.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
SERC OC Standards Review
Group

No

“Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s
restoration plan regardless of voltage.” The SERC SRG is concerned that this provision may have the effect
of incenting transmission operators to limit the available generator options to the minimum necessary for a
reliable option as opposed to every possible option that might be utilized in a pinch. We recommend the
following adjusted language: “Essential Blackstart Resources and the designated essential blackstart
Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage”

Vermont Transco

No

: The phrase “regardless of voltage” is a concern. The goal of the FERC order is to provide a more reliable
“bulk power system”. Many blackstart resources are at voltages well below the 100 kV voltage and are not
material to the restoration of the bulk electric system during a blackout. The wording of this inclusion would
require many units that are used only for local area support to now be listed as a BES facility. The wording of

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Organization

Yes or No

Question 5 Comment
this inclusion should be something to the order of “Blackstart Resources and the designated blackstart
cranking paths identified in the transmission operators restoration plan that are necessary to restore the BES
system”, this should not include cranking paths on distribution feeds that are used primarily for local area
support. The purpose of this inclusion should be to make certain all units necessary to energize the BES grid
after a blackout are maintained and operated appropriately

Consumers Energy Company

No

We recommend that the word, primary, be added, and that the phrase, “regardless of voltage” be removed:
“Blackstart Resources and the designated primary blackstart Cranking Paths identified in the Transmission
Operator’s restoration plan.” NERC’s May 19, 2011 webinar described this as applying only to the path
directly from the blackstart unit to the Transmission System. Is this correct? If so, please clarify within the
definition.

Exelon

No

Exelon believes that the entire designated cranking path should not be included in the BES definition if there
are facilities less than 100kV on the path. Doing so may inappropriately include a number of facilities that are
local distribution facilities under jurisdiction of the states, i.e, the inclusion of the entire cranking path occurs
without an inquiry as to whether or not the facilities are “facilities used in local distribution of electric energy”
even though such facilities are by explicit language in the Federal Power Act not included in the definition of
Bulk Power System. In Orders 743 and 743-A, FERC reiterated several times that “facilities that are
determined to be local distribution will be excluded from the bulk electric system.” (Order No. 743-A, P.22).
Furthermore, by including these facilities the Drafting Team has gone beyond the boundaries of Section 215
of the Federal Power Act and Orders 743 and 743-A. It should be noted that there is no reference to black
start Cranking Paths in either Order. Practically, it is unclear that including lower voltage facilities on a
Cranking Path will have any positive impact on reliability without potential entity registration changes or NERC
Reliability Standards changes. For example, NERC Reliability Standards FAC-008 and FAC-009 do not
currently apply to Distribution Providers.

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system Elements.
In addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking paths in the restoration plan die to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths. Accordingly, as suggested, the phrase
“regardless of voltage” has been also removed.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
National Rural Electric

August 19, 2011

No

This is the only part of the BES definition and inclusions/exclusions that specifically states “regardless of

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Organization

Yes or No

Cooperative Association
(NRECA)

Question 5 Comment
voltage.” NRECA does not believe it is appropriate for the BES definition to include such a statement. This
issue needs to be addressed in standard applicability language, not in the definition of BES.

Response: As suggested, the phrase “regardless of voltage” has been also removed.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Edison Electric Institute

No

EEI believes that the entire designated cranking path should not be included in the BES definition if it would
include facilities that are less than 100 kV on the path. Including such facilities may inappropriately include
some facilities that are local distribution facilities, which are under state jurisdiction. These facilities might be
swept into the definition of BES without an inquiry as to whether or not the facilities are “facilities used in local
distribution of electric energy,” which is an explicit exclusion under the Federal Power Act definition of “BulkPower System.”
This issue is more fully discussed in EEI’s response to Question 13.

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system elements. In
addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking Paths in the restoration plan due to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES definition to
ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this to include
operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources have the
ability to be started without support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the electric system
that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating
units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the
Transmission Operator’s restoration plan as BES Elements.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
See response to Q13.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
New York Power Authority

August 19, 2011

No

The Standards Drafting Team needs to clarify whether this inclusion is intended to apply to local transmission
operator restoration plans or only to the Balancing Authority’s restoration plans. This inclusion should be
stated as follows: Blackstart Resources and the designated cranking paths identified in the Balancing

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Organization

Yes or No

Question 5 Comment
Authority’s Restoration Plan regardless of voltage.”Local restoration plans may not be material to the
restoration and operation of the BES, but black start resources for the Balancing Authority’s restoration plan
are material to the reliable restoration of the BES.

Response: The SDT reaffirms that the reference is to the Blackstart Resources identified in the Transmission Operator’s restoration plan.
Central Maine Power Company
New York State Electric & Gas
and Rochester Gas & Electric

No

Inclusion I4 should be stricken for several reasons:
1. The SDT states that “One of the basic tenets that the SDT is following is to avoid changes to registration
due to the revised definition if such changes are not technically required for the definition to be complete.”
Adding every black start generator and the designated cranking path is not technically required. All significant
black start generation is already included in I2 and I3 and I5.
2. The NERC Compliance Registry notes that not every generator that is a blackstart unit is “material” - it may
not be necessary to the restoration plan or to bulk power system reliability.
3. There is already an existing standard to ensure reliability of blackstart performance. NERC Reliability
Standard EOP-005-2 ensures that the facilities critical to system restoration are functional when needed.
4. In CMP’s case, there are two generator locations which are part of the Black Start capability, and they are
small hydroelectric stations connected to our 34.5 kV transmission system. Under this inclusion, these small
hydroelectric stations and 34.5 kV paths would inappropriately be classified as BES. Other, critical blackstart
facilities are already included in the BES definition without I4.

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system elements. In
addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking Paths in the restoration plan due to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES definition to
ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this to include
operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources have the
ability to be started without support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the electric system
that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating
units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the
Transmission Operator’s restoration plan as BES Elements.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure

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Organization

Yes or No

Question 5 Comment

exception process to request including it in the BES.
Accordingly, as suggested, the phrase “regardless of voltage” has been also removed.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
PacifiCorp

No

PacifiCorp supports the concept of unique or singular blackstart paths being included in the BES. However,
once the uniqueness of the path disappears PacifiCorp believes the multiple non-unique blackstart paths
should be excluded by definition from the BES. This approach could be equated to pending version 4 of the
CIP Reliability Standards, in which the Critical Asset Criteria of CIP-002-4 set forth the facilities comprising
the Cranking Paths that are considered Critical Assets, up to the point on the path where two or more path
options exist.

Farmington Electric Utility System

No

The drafting team should consider adopting language similar to CIP-002-4 for Cranking Paths. Cranking
Paths up to the the point on the Cranking Path where two or more path options exist.

New York State Dept of Public
Service

No

This inclusion is problematic at a couple levels. First, blackstart resources can be facilities smaller than the
previous thresholds located deep within the local distribution system. Second, given you do not know ahead
of time how the system might come apart, often there are multiple cranking paths specified. To avoid
incurring the costs of upgrading facilities all along multiple paths, there will be an inclination to designate only
one path involving the fewest impacted facilities. The result could be reduced reliable operation - not more.

Pepco Holdings Inc

No

1)In many cases the cranking path or portions of it may consist of facilities less than 100kv. Many of these
facilities are local distribution facilities and should not be included in the BES.
2) If there is an identified cranking path that is transmission designated, but the path is not contiguous with the
BES, must the elements in-between be included as BES?

PJM

No

Black start units are used to start other units to when the BES is compromised. There is no technical
justification to include all elements in the “cranking path” as BES facilities.

ReliabilityFirst

Yes

but needs to state if this is ALL paths or just a single path, there may be many.

American Electric Power

Yes

While AEP supports the concept of including designated Blackstart Cranking paths as part of the BES, there
is concern that doing so without respect to voltage would unnecessarily include elements which should not be
included as part of the BES. More clarity is needed to explicitly describe the scope of the inclusion. Is it
limited to Transmission facilities or more broad to include Distribution facilities or even sub-Distribution
auxiliary systems? If so, this would unnecessarily bring those sub-systems under the purview of PRC-005, for

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Organization

Yes or No

Question 5 Comment
example.

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system Elements.
In addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking paths in the restoration plan die to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Electric Reliability Council of
Texas, Inc.

No

See response to question 3 - ERCOT ISO agrees with the substance, but not the approach.

Southwest Power Pool

No

Please see SPP's response to question 3 - SPP agrees with the substance, but not the approach.

No

We do not agree with Inclusion I4. Blackstart resources and transmission facilities on the cranking path
should not be classified as BES regardless of size and voltage level. From a regulatory perspective, such an
inclusion would be in conflict with the current regulatory requirements in many of the jurisdictions. More
importantly, designating these facilities as BES Elements or Facilities beyond the 100 kV bright line, the 20
MVA/unit or 75 MVA/plant criteria, without a regard to their impact on the BES (under conditions other than
system restoration) will impose unnecessary requirements for these facilities, which do not contribute to
reliability under interconnected operation conditions. For restoration condition, this inclusion is extraneous
given there is already a designation specific for system restoration covered by an existing standard to
recognize their reliability impacts and to ensure their expected performance. NERC Standards EOP-005-2
stipulates the requirements for testing blackstart resource and cranking paths. This testing requirement
suffices to ensure that the facilities critical to system restoration are functional when needed, which meets the
intent of identifying their criticality to reliability.While we do not disagree with the SDT’s interpretation of the
FERC directives, the BES definition should cover those facilities that are needed for operation under both
normal and emergency conditions, which includes situations related to black-start and system restoration. We
do not agree that the directives specifically ask for inclusion of blackstart resources and facilities on the crank
path in the BES definition. We believe the requirements in EOP-005-2 suffice to address the SDT’s
interpretation and concern regarding recognition of the reliability impacts and requirements for blackstart
resources and facilities used for system restoration.Generating units of any size and transmission facilities of
any voltage level may be used for blackstart and restoration. Conceivably, a generator of 10 MW and

Response: See response to Q3.
FortisBC

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Organization

Yes or No

Question 5 Comment
transmission facilities of 44 kV or 69 kV may be a part of the cranking path. A BES inclusion will then subject
these generators and facilities, which are essentially “local” facilities but called upon to begin restoring its bulk
interconnected counterpart, to comply with the reliability standards intended for maintaining BES reliability.
Included in the BES definition will thus discourage smaller generators from providing blackstart capability, and
the transmission facilities from being a part of the cranking path. This may also discourage Transmission
Owners and Operators from identifying multiple blackstart resources and cranking paths to provide restoration
flexibility. Such an inclusion will ultimately undermine reliability.If indeed any of these facilities are deemed
necessary to support bulk power system reliability at times other than system restoration, they would/should
have been identified through the basic BES definition and inclusion list or can be addressed through the
exception procedure.
We suggest and urge the SDT to drop I4 on the basis that:
o The availability and performance expectations of blackstart resources and facilities on the cranking path are
already specifically addressed in an existing standard; and
o Unless they meet the BES definition and the other inclusion criteria, they do not have any perceived
reliability impact on everyday operation of the BES.

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system elements. In
addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking Paths in the restoration plan due to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES definition to
ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this to include
operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources have the
ability to be started without support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the electric system
that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating
units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the
Transmission Operator’s restoration plan as BES Elements.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
The SDT does not agree that adding Blackstart Resources to the BES definition alone would “discourage” entities from providing blackstart capability.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.

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Organization
Public Utilities Commission of
Ohio

Yes or No
No

Question 5 Comment
this should be determined by an impact analysis, not inclusive of all Blackstart Resources, regardless of
location on the system.

Response: The SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES
definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this
to include operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources
have the ability to be started without support from the system or can be energized without connection to the remainder of the System, in order to meet a
Transmission Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the
electric system that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other
generating units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources
indentified in the Transmission Operator’s restoration plan as BES Elements. No change made.
Intellibind

Yes

There continues to be confusion in the industry of blackstart by Generator Owners and Operators (especially
small to medium generation), and the drafting team should clearly define what is meant by blackstart. Many
small generators have the capability to blackstart their resource, but are not part of the Transmission
Operator's blackstart plan on restoring the BES. In most cases they are asked to blackstart if possible and
wait until lines are energized and close in as directed by Transmission Operator. This is significantly different
than owning a blackstart resource designated to provide power during a blackout.

American Transmission
Company, LLC

Yes

For clarification, ATC understands that only blackstart resources that are part of a Transmission Operator’s
Blackstart Restoration plan are included in I4 (Ref. EOP-005) and should be consistent with the upcoming
CIP-002 version 4 standard.
ATC also recommends that the SDT consider adding Blackstart Resources as a defined term in the NERC
Glossary.

Response: Only Blackstart Resources indentified in the Transmission Operator’s restoration plan are included in the BES. The term “Blackstart Resource” is a
defined term in the NERC Glossary. No change made.
PUD No. 2 of Grant County,
Washington

Yes

Grant supports this proposed inclusion with the caveat that the BES should be allowed to be non-contiguous,
especially in this case, if the unit is low voltage.

Response: The SDT proposed BES definition allows for non-contiguous elements.
Illinois Municipal Electric Agency

August 19, 2011

Yes

Please see comments under Question 13.

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Organization

Yes or No

Question 5 Comment

Springfield Utility Board

Yes

While Springfield Utility Board does not own any Blackstart Resources, we do recognize the importance of the
restoration of the Grid, and the generation necessary for the Grid should have identified paths that are critical,
regardless of voltage level.

Springfield Utility Board

Yes

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Central Lincoln

Yes

But please indicate how blackstart resources (regardless of voltage) not in the TO’s restoration plan are
treated, since we don’t believe the flowchart at
http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly expresses the SDT’s intent
to classify these resources (when also below the 20 or 75 MVA thresholds) as non-BES.

City of Redding

Yes

Redding suggests that only the primary black start resource in the TO or BA’s black start plan fall under this
inclusion otherwise the secondary and or backup black start units may not be identified in the main plans to
avoid excessive regulation of the equipment.

Response: See response to Q13.

Response: Only Blackstart Resources indentified in the Transmission Operator’s restoration plan are included as BES Elements. The Commission directed
NERC to revise its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network.
The SDT interprets this to include operation under both normal and Emergency conditions, which includes situations related to blackstarts and system restoration.
Blackstart Resources have the ability to be started without support from the System or can be energized without connection to the remainder of the System, in
order to meet a Transmission Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated

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Organization

Yes or No

Question 5 Comment

resources of the electric system that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of
one or more other generating units as defined in the Transmission Operator’s system restoration plan. No change made.
Long Island Power Authority

Yes

Need to define Cranking Paths.

Response: “Cranking Path” is a defined NERC Glossary term but is no longer used in the revised inclusion.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
MEAG Power

Yes

The Standards Drafting Team needs to clarify whether this inclusion is intended to apply to local transmission
operator restoration plans or only to the Balancing Authority’s restoration plans. This inclusion should be
stated as follows: Blackstart Resources and the designated cranking paths identified in the Balancing
Authority’s Restoration Plan regardless of voltage.”Local restoration plans may not be material to the
restoration and operation of the BES, but black start resources for the Balancing Authority’s restoration plan
are material to the reliable restoration of the BES.

Response: Only Blackstart Resources indentified in the Transmission Operator’s restoration plan are included as BES Elements. The Commission directed
NERC to revise its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network.
The SDT interprets this to include operation under both normal and Emergency conditions, which includes situations related to blackstarts and system restoration.
Blackstart Resources have the ability to be started without support from the System or can be energized without connection to the remainder of the System, in
order to meet a Transmission Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated
resources of the electric system that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of
one or more other generating units as defined in the Transmission Operator’s system restoration plan.
The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system Elements. In addition,
the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking paths in the restoration plan die to the particular
system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Muscatine Power and Water

Yes

This Inclusion I4 provides a defense in depth with CIP-002-4.

New York State Reliability
Council

Yes

BS facilities and their cranking paths are critical to the maintenance of system reliability under system
restoration conditions. However, they are a special case and should not be construed as a precedent for
inclusion of all BES contiguous elements.

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Organization

Yes or No

Question 5 Comment

Idaho Falls Power

Yes

It is reasonable to conclude that Blackstart generation resources are material to the BES.

MRO's NERC Standards Review
Forum

Yes

It does provide a defense in depth with CIP-002-4.

BPA

Yes

Duke Energy

Yes

ExxonMobil Research and
Engineering

Yes

Alberta Electric System Operator

Yes

South Carolina Electric and Gas

Yes

Fayetteville Public Works
Commission

Yes

MidAmerican Energy Company

Yes

Florida Keys Electric Cooperative

Yes

Sierra Pacific Power Co d/b/a NV
Energy

Yes

Colorado Springs Utilities

Yes

East Kentucky Power
Cooperative, Inc.

Yes

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and

Yes

August 19, 2011

No comment.

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Organization

Yes or No

Question 5 Comment

Dispatch
Sacramento Municipal Utility
District (SMUD)

Yes

City of St. George

Yes

Puget Sound Energy

Yes

Southern California Edison
Company

Yes

GTC

Yes

Idaho Power

Yes

Clark Public Utilities

Yes

The Dow Chemical Company

Yes

Oncor Electric Delivery Company
LLC

Yes

City of Anaheim

Yes

Xcel Energy

Yes

Golden Spread Electric
Cooperative, Inc.

Yes

Utility System Efficiencies, Inc.

Yes

Tri-State Generation and
Transmission Association, Inc.

Yes

August 19, 2011

SMUD agrees with the inclusion of blackstart resources and their cranking paths.

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Organization

Yes or No

Imperial Irrigation District

Yes

Florida Municipal Power Agency

Yes

Santee Cooper

Yes

NERC Staff Technical Review

Yes

SERC Planning Standards
Subcommittee

Yes

Overton Power District No. 5

No

Tennessee Valley Authority

Yes

Arizona Public Service Company

Yes

Western Electricity Coordinating
Council

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

Luminant Energy

Yes

Electricity Consumers Resource
Council (ELCON)

Yes

Western Area Power
Administration

Yes

US Bureau of Reclamation

Yes

Grand Haven Board of Light and

Yes

August 19, 2011

Question 5 Comment

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Organization

Yes or No

Question 5 Comment

Power
Glacier Electric Cooperative

Yes

FHEC

Yes

South Texas Electric
Cooperative, Inc.

Yes

Portland General Electric
Company

Yes

South Texas Electric
Cooperative, Inc.

Yes

Response: Thank you for your response. Several stakeholders identified that Cranking Paths usually involve distribution elements, and the SDT has removed the
inclusion for Cranking Paths. Please see the revised definition.

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6. The SDT has added specific inclusions to the core definition in response to industry comments. Do you agree
with Inclusion I5? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: Industry comments included the following issues:
•
•
•
•

Concern over the assumed contiguous nature of the BES definition. The SDT did not mandate a contiguous BES and has clarified the
language of the inclusions to make this clear.
Confusion over the term ‘collector system.’ The SDT has deleted this terminology.
Concern that the definition could ensnare distributed generation or small generators in a distribution system. The SDT has clarified the
wording of the inclusion to emphasize that the inclusion is ‘designed primarily for aggregating capacity.’
While several commenters asked about the technical justification of the generation thresholds, the SDT was not presented with any technical
rationale for moving away from this existing limit. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the
SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that
topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and
743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards
Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization
Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.

Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system
designed primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a
voltage of 100 kV or above.

Organization

Yes or No

Question 6 Comment

Northeast Power Coordinating
Council

No

The entire contiguous path does not have to be BES. The path or aggregate generation will rarely have any
impact on the reliability on the interconnected transmission network, nor is it necessary for its operation.
These are generally referred to as connection facilities.

MRO's NERC Standards Review
Forum

No

We propose the following questions for your consideration:Which components of the dispersed power
resources would be classified as BES? Are the individual small wind generator units and terminals through
the GSUs to a higher voltage (e.g. 34.5 kV) collector bus classified as BES Elements? Are the higher voltage
bus, the associated elements (e.g. protection system, cap bank, SVC, etc.), and step up transformer to a
system Element of 100 kV or above to be classified as BES Elements?With these questions, the NSRF is

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Organization

Yes or No

Question 6 Comment
confused on what the SDT is trying to formulate as an Inclusion. If a dispersed power systems meets the
threshold of 75MVA and connected at 100kV or higher, does this make the entire dispersed system
considered to be part of the BES? We recommended that one solution is that I5 to be revised as follows
“Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) utilizing a collector system from the point where the aggregated rating exceeds 75 MVA
through a common point of interconnection to a system Element at a voltage of 100 kV or above. “

Hydro One Networks Inc

No

We agree with the concept of Inclusion I5 but do not support that the entire contiguous path has to be BES.
The path or aggregate generation will rarely have any impact on the reliability on the interconnected
transmission network nor is it necessary for its operation. These are generally referred to as connection
facilities. In addition, renewable generation units are intermittent and the planning and operational standards
and practices make sure that their unavailability or unexpected (sudden) loss of generation won’t jeopardize
reliability of the network; therefore, they should not be BES. As stated earlier, with the Green Energy and
Smart Grid plans and dispersed renewable energy advocated by both Canadian and US policy makers, the
gross nameplate rating of 75 MVA may undermine and deter the future potential of integrating DG’s that will
be implemented to ensure the reliable operation of the interconnected transmission network BES, and, at the
same time, provides the most effective and economical solutions for the rate payers in North America. Local
generation can cost-effectively enhance the reliability of load pocket, by avoiding transmission, but such
restrictions would deter the adoption of good planning decisions.(Refer to Q4 comments).

Hydro-Quebec TransEnergie

No

We believe that automatic inclusion of dispersed generation greater than 75 MVA and the path to connect
them to the BES should not be automatically included in the BES. However, a provision should be made so
that some reliability standards related to generator shall apply (voltage regulation, etc.).

New York State Reliability
Council

No

Distributed resources are comprised of multiple small units that cycle on and off depending upon local
ambient conditions. They have multiple feeders collecting at the point of interconnection. It is not credible
that simultaneous loss of multiple units and/or collector system feeders could occur and they should be
excluded from the BES based upon reliability considerations. It is noted that system Element(s) beyond the
point of interconnection are subject to BES inclusion per the core definition.

FortisBC

No

We agree with the concept of Inclusion I5 but do not support that the entire contiguous path has to be BES.
The path or aggregate generation will rarely have any impact on the reliability on the interconnected
transmission network nor is it necessary for its operation. These are generally referred to as connection
facilities.As stated earlier, with the Green Energy and Smart Grid plans and dispersed renewable energy
advocated by both Canadian and US policy makers, the gross nameplate rating of 75 MVA may undermine
and deter the future potential of integrating DG’s that will be implemented to ensure the reliable operation of
the interconnected transmission network BES, and, at the same time, provides the most effective and

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Organization

Yes or No

Question 6 Comment
economical solutions for the rate payers in North America. Local generation can cost-effectively enhance the
reliability of load pocket, by avoiding transmission, but such restrictions would deter the adoption of good
planning decisions.(Refer to Q4 comments).

PJM

No

As written I5 implies a contiguous system from the unit to a “point a system element at a voltage above 100
kV” there is no technical justification for a contiguous system. The requirement should read “- Dispersed
power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
utilizing a collector system through a common point of interconnection."

Xcel Energy

No

For dispersed power producing resources, such as wind farms, we do not see the value in making each
individual 1-2 MW wind turbine a BES element. The BES applicability should be focused on the point when
the collective becomes large enough to impact the grid. So, we recommend that I5 apply from the point of
aggregation of 75 MW or more to a system element operated at 100 kV or more. Specifically, we feel it should
be limited to the feeder bus and aggregating transformer.

Independent Electricity System
Operator

No

We agree with the goal of Inclusion I5 but have the same concerns expressed in our responses to Q1 and
Q3. For the dispersed power resources referred to in Inclusion I5, we do not see the benefit of including the
collector system, switchgear, associated medium voltage equipment and step-up transformer(s) in the BES.
As before, these Facilities should be subject to assessment and included if found to impact BES reliability
after going through the Exception Process. To reinforcing what was stated during the NERC BES webinar, we
do not believe that the entire contiguous path has to be BES.

AltaLink

No

We agree with the concept of Inclusion I5 but do not support that the entire contiguous path has to be BES.
The path or aggregate generation will rarely have any impact on the reliability on the interconnected
transmission network nor is it necessary for its operation. These are generally referred to as connection
facilities.

American Transmission
Company, LLC

Yes

ATC poses the following questions to the SDT for consideration:Which components of the dispersed power
resources would be classified as BES? Are the small wind generator units and terminals through the GSUs to
a higher voltage (e.g. 34.5 kV) collector bus classified as BES Elements? Are the higher voltage bus, the
associated elements (e.g. protection system, cap bank, SVC, etc.), and step up transformer to a system
Element of 100 kV or above to be classified as BES Elements?

Exelon

Yes

Exelon agrees with this inclusion as long as it’s clear that distribution voltage collector systems are not to be
included in the BES. Exelon suggests that a clarifying statement be added to the inclusion item, such as
“Collector system facilities that are <100kV are excluded from the BES.”

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Organization

Yes or No

Central Lincoln

Yes

Question 6 Comment
But please indicate how dispersed aggregate generation below 75 MVA is to be treated, since we don’t
believe the flowchart at http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly
expresses the SDT’s intent to classify these resources as non-BES.

Response: There is no contiguous path requirement and the SDT has revised the wording for clarity.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
American Municipal Power and
Members

No

There is concern over inadvertently including small distribution that has behind-the-meter generation on a 69
kV loop. We somewhat agree with the concept of Inclusion I5 but suggest a language change to clarify what
we understand to be the drafting team’s intent, that the inclusion is intended to apply to dispersed wind and
solar generating plants, and not, for example, to a radially-connected city with an aggregate of 75 MW of
small generators behind-the-meter. This distinction is appropriate because such a city cannot have the same
impact on the grid as a 75 MW wind farm; loss of the radial connecting the city to the grid would result in loss
of its load as well as its generation, so that the supply-demand mismatch would be far less significant. We
suggest that I5 be revised.

Response: The SDT clarified the language to address this point.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Imperial Irrigation District

No

In reference to I5 If the collector system is in the distribution system and after a series of elements and (sub
transmission system) is connected to a common point of interconnection to a system element at a voltage of
100 kV and above, is there a criteria of after how many elements before it connects to a system element at a
voltage of 100 kV and above is I5 still applicable?IID prefers the following language: Dispersed power
producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) after
the collector system to the first system Element at a voltage of 100 kV or above.

Response: The SDT clarified the language to address this point.

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Organization

Yes or No

Question 6 Comment

Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
NERC Staff Technical Review

No

We agree that Inclusion I5 is an effective method for including dispersed resources; however, the
interconnection voltage threshold should be removed. The contribution of dispersed power producing
resources to system reliability is a function of the aggregate MVA rating rather than the interconnection
voltage. All dispersed resources with aggregate capacity greater than 75 MVA should be included in the BES
definition because all such units provide similar contributions to system reliability.

Response: The SDT appreciates the concern regarding the 100 kV threshold and the 75 MVA limit on connected generation; however, the SDT has been
presented with no technical basis upon which to suggest a change from these values. No change made.
Dominion

No

Dominion disagrees that an Element or Facility operated below 100 kV should be included automatically in
the BES. Dominion agrees that users of the bulk power system should be required to abide by applicable
reliability standards. Dominion questions why the SDT chose to use the phrase ‘Dispersed power producing
resources’ As opposed to the phrase ‘Dispersed generating resources’. Dominion asks that the SDT provide
an explanation for its choice of phrases.

Response: The SDT used this term intentionally. Generation resources suggest a “generator”. Using the term power producing resources includes devices now
and in the future that could produce energy (like wind and solar). No change made.
SPP Standards Review Group

No

Limiting this to 75 MVA does allow the opportunity for a significant amount of generation to ‘slip under the
fence’ regarding inclusion in the BES. Was this the intent of the SDT? For example, in order to circumvent the
BES issue a developer may decide to build 2-74 MVA sites rather than a single 148 MVA site. Regarding the
similarity of the I3 and I5, what is the difference between a ‘single site’ and a ‘common point of
interconnection’? Shouldn’t they be the same in the two inclusions?

Response: If a developer wants to build 2- 74 MVA sites solely to not be deemed part of the BES, they can do so, but the Regional Entity could still require them
to register. No change made.
Idaho Falls Power

August 19, 2011

No

This inclusion seems redundant to the registry criteria for GO/GOP of a facility generation of 75MVA or
greater. We do not see how this definition adds or removes any assets already defined by the registry
criteria.

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Organization
City of Redding

Yes or No
No

Question 6 Comment
Redding believes that this could be handled in the Statement of Compliance Registration Registry by
specifically addressing distributed generation. This could be part of a tiered approach where these type of
facilities would be included as a User of the BES instead of an owner and operator of BES elements.

Response: The goal of the SDT is to provide clarity to the definition of the BES and not to address registration criteria. No change made.
Tennessee Valley Authority

No

Other than the NERC Registry Criteria definition, what is the technical justification for the 75 MVA threshold?
The threshold level for inclusion should be technically based on the BES capacity and configuration at the
location of the generating sources’ connection to the BES.

Western Montana Electric
Generating and Transmission
Cooperative

No

WMG&T agrees that it is important to address wind generation facilities and similar generation facilities in
which a large number of generating units, each with a relatively small capacity, are clustered and fed into the
grid at a single interconnection point. That being said, WMG&T is concerned that the 75 MVA threshold has
been chosen arbitrarily for the reasons stated in our comments on Question 4.

Public Utility District No. 1 of
Snohomish County, Washington

No

Snohomish agrees that it is important to address wind generation facilities and similar generation facilities in
which a large number of generating units, each with a relatively small capacity, are clustered and fed into the
grid at a single interconnection point. That being said, Snohomish is concerned that the 75 MVA threshold
has been chosen arbitrarily for the reasons stated in our comments on Question 4.

Blachly Lane Electric Cooperative

No

We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.

Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative

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Organization

Yes or No

Question 6 Comment

No

Northern Wasco County PUD agrees that it is important to address wind generation facilities and similar
generation facilities in which a large number of generating units, each with a relatively small capacity, are
clustered and fed into the grid at a single interconnection point. That being said, Northern Wasco County PUD
is concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our comments
on Question 4.

No

Generators should only be part of the Bulk Electric System if they are connected through a GSU to a
Transmission Element determined to be part of the BES. The current inclusion language would apply to all
generators connected to facilities greater the 100 kV with no exclusion or exception process. Without a
change, it appears that a generator connected to a facility greater than 100 kV would be a BES asset even if
the transmission assets could be excluded or excepted. I5 should be rewritten to state: Dispersed power
producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
utilizing a collector system through a common point of interconnection to a Transmission Element determined
to be part of the Bulk Electric System.Additionally, as indicated by Clark in its comments on the core definition

Northern Lights Inc
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Northern Wasco County PUD
Clallam County PUD No.1
Chelan PUD – CHPD
Public Utility District No. 1 of
Franklin County
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc.
Utility System Efficiencies, Inc
Cowlitz County PUD
Clark Public Utilities

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Organization

Yes or No

Question 6 Comment
of the BES, Clark believes the 75 MVA threshold lacks an adequate technical justification and is a purely
arbitrary quantity. The use of a capacity threshold in the definition of the BES should have technical reasons.

Santee Cooper

Yes

What is the rationale for 75 MVA.

Response: The SDT appreciates the concern regarding the lack of technical justification for a 75 MVA threshold; however, the SDT has not been presented with
a technical basis upon which to suggest a change from this value. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the
SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with
the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean
that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17
SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues
that have arisen from SDT deliberations.
Intellibind

No

Though the intent is understood through the discussion, the language presented is not clear enough. The
drafting team should be cautioned on how Standards are read through many different entities and audiences.
The team should also understand if the issue is not clearly defined, there will continue to be ambiguity through
the registration and compliance processes.As previously stated on an earlier question, I do not think that the
20 MVA threshold has technical merit, I do not believe that the 75MVA limit has technical merit either. Further
the impact should be measured at the buss bar not at the nameplate. The aggregate rating should be the
same as the individual unit rating on a single plant, unless the plant can prove that there is not a common
failure mode to lose more than 20MVA.

Response: The SDT appreciates the concern regarding the lack of technical justification for a 20/75 MVA threshold; however, the SDT has not been presented
with a technical basis upon which to suggest a change from this value. After consulting with the NERC Board of Trustees and the NERC Standards Committee,
the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice
with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not
mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 201017 SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues
that have arisen from SDT deliberations.
Electric Reliability Council of
Texas, Inc.

No

See response to question 3 - ERCOT ISO agrees with the substance but not the approach.

Southwest Power Pool

No

Please see SPP's response to question 3 - SPP agrees with the substance but not the approach.

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Organization

Yes or No

Question 6 Comment

No

I5 is not defined clearly enough. It appears that distributed generators connected to a 44 kV load pocket that
is fed radially from a 100 kV source would be included, but it’s not clear that this was the intent. Adding
generator before collector system would provide greater precision.

Response: See response to Q3.
Duke Energy

Response: The SDT believes the re-wording of Inclusion I5 (now Inclusion I4) should address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Fayetteville Public Works
Commission

No

Because no differentiation has been defined between "power producing resources" in Inclusion I5 and
"generating units" from Inclusions I2 and I3, this Inclusion has the potential to conflict with other Inclusions. It
should be modified to read "Dispersed power producing resources with individual capacity of 20 MVA or less
(gross nameplate rating) but with aggregate capacity greater than 75 MVA. . ."

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
MidAmerican Energy Company

No

It is suggested that the inclusion be modified to include a more definitive description of the portion of the
facility that would be considered to be in the BES. It is suggested that the phrase "from the point where the
aggregated rating exceeds 75 MVA" be added after collector system in I5. The revised inclusion would then
read as follows: Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a collector system from the point where the aggregated rating exceeds
75 MVA through a common point of interconnection to a system Element at a voltage of 100 kV or above.

Muscatine Power and Water

No

MP&W recommends to have Inclusion 5 be revised as follows “Dispersed power producing resources with
aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a collector system from
the point where the aggregated rating exceeds 75 MVA through a common point of interconnection to a
system Element at a voltage of 100 kV or above.”

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Organization

Yes or No

Question 6 Comment

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Springfield Utility Board

No

What is a collector system? Does this include a Local Distribution Network? A Local Distribution Network
(E3) may have multiple generating units within its service area that serve all or part of retail load (E2). Would
the aggregate nameplate rating of these units be included even though they would otherwise be excluded by
application of E2? For example, there may be multiple end users with 500 kW photovoltaic systems whose
total nameplate capacity is 100 MVA. All or most of the power used is consumed by the retail
consumers.SUB suggests that the language be restated to say “Dispersed power producing resources with
aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) that are not excluded under E2
utilizing a collector system through a common point of interconnection to a system Element at a voltage of
100 kV or above” Or”Dispersed power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a cCollector sSystem through a common point of interconnection
to a system Element at a voltage of 100 kV or above. For purposes of this inclusion, a Collector System is
any infrastructure not connected to load - where parasitic load associated with a generation unit or units is not
considered load.” While Springfield Utility Board does not own any power producing resources, we do
recognize the importance of the restoration of the Grid, and the generation necessary for the Grid, regardless
of voltage level.

Springfield Utility Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of

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Organization

Yes or No

Question 6 Comment
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: The SDT believes that the re-wording of the inclusion should address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
City of St. George

No

See comments to questions 3 & 4 above. The requirements for an entity or facility should match the impact of
that facility to the system.

Response: The SDT carefully debated the generating threshold for the inclusion. After consulting with the NERC Board of Trustees and the NERC Standards
Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that
topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this
does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the
Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as
several other issues that have arisen from SDT deliberations.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Southern California Edison
Company

No

Please refer to SCE’s answer for Question No. 3 above.If the SDT goes forward and includes I5 into either
the proposed BES definition or the Technical Principles for Demonstrating BES Exceptions, the following
additional clarification should be made:(i) Clarify the terms “Dispersed power producing resources” and
“collector system”;
(ii) When referencing “collector system,” does it include the lines connecting the generation?;
(iii) Why the 75 MVA threshold? This seems to be a somewhat arbitrary number which does not correlate with
specific operational risks, operational limits, or network capability. This is highlighted when taking SCE’s
system into consideration, as we carry operational spinning reserves that are 10 to 20 times greater than the
75 MVA threshold identified in the proposed BES Definition. If SCE were to lose 75 MVA in an event, there
would be no reliability risk or perceptible frequency deviation that would attend the event. The proportionality

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Organization

Yes or No

Question 6 Comment
of risk and benefit does not seem to fit within the application and philosophy behind the mandatory limit.
Setting the BES Definition in this manner in order to bring in the smallest utilities is not appropriate for
application to the larger utilities.; and
(iv) As written, I5 could unintentionally bring into scope sub-trans/distribution systems with enough generation
as these radial systems could be categorized as “collector systems”. Specifically, there are radiallyconnected distribution systems in the Desert Southwest designed to enable the interconnection of multiple
renewable resources which could be viewed as grouping this collective generation at the point of
interconnection with the transmission system. In many cases, the sum total of this generation could be
greater than 75 MVA.

Response: 1. The SDT re-worded the definition to address these concerns.
2. There is no contiguous path requirement and the SDT has revised the wording for clarity.
3. The SDT appreciates the concern regarding the lack of technical justification for a 75 MVA threshold; however, the SDT has been presented with no technical
basis upon which to suggest a change from this value. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has
decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the
mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that
the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT
take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that
have arisen from SDT deliberations.
4. The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
The Dow Chemical Company

No

The language is not clear enough to understand what is covered.

Response: Please consider the revised language.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or

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Organization

Yes or No

Question 6 Comment

No

As noted in comment under 4 above, the 75 MVA threshold may unintentionally impose unnecessary added
costs that may ultimately be paid by New England ratepayers. The exception process should provide flexibility
as to total MVA rating. In addition, NESCOE believes this language should be clarified to exclude collector
systems and include only elements that actually impact the BES.

above.
New England States Committee
on Electricity

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system
designed primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of
100 kV or above.
Oncor Electric Delivery Company
LLC

No

The ERCOT Region already considers load in any combination equal to and over 20 MVA through a single
Point of Interconnect as part of the BES

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Consolidated Edison Co. of NY,
Inc.

No

Please define the terms “collector system” and “common point.”

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed

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Organization

Yes or No

Question 6 Comment

primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Orange and Rockland Utilities,
Inc.

No

See comments from question 4.

Response: See response to Q4.
BPA

No

Does the interconnection point have to be the only interconnection point for all of the resources?
Additionally BPA would like to see a definition of :dispersed power.”

Response: The SDT has revised Inclusion I5 to clarify the interconnection point as a ‘common point’ where the aggregated capacity of the dispersed power
producing resource is connected to the BES.
The SDT is responsible for the revision of the BES definition. In fulfilling this responsibility the SDT is developing a definition that properly classifies facilities as
BES or non-BES Elements. Defining ‘dispersed power’ is not within the scope of Project 2010-17, however the term is used in the definition to capture resources
such as wind farms, solar arrays, etc. that utilize installations over a larger area than would typically be seen at a conventional generation facility.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Tacoma Power

August 19, 2011

Tacoma Power generally supports Inclusion I5. However, the term ‘gross aggregate nameplate rating’ is not
defined and should be replaced with a specific definition. Additionally, no justification for the 75 MVA level has
been provided and therefore it appears arbitrary. Since this measurement will define Elements for absolute
inclusion in the BES, the threshold for dispersed power producing resources should be based on a need to
maintain transmission reliability. Further, there is no traceable definition for ‘collector system.’ Rather than
defining it, it can be replaced with a ‘common interconnection point.’ Lastly, such dispersed resources located
within a Local Distribution Network (LDN), which do not exit the LDN, should not be included. We propose
changing Inclusion I5 to read,”The common interconnection point for dispersed power producing resources
with aggregate capacity greater than 75 MVA (aggregate capacity based on the Code of Federal Regulation,
CFR 18, Part 287.1, “Determination of powerplant design capacity”) connected to an Element that is part of
the BES, except for common interconnection points that are within a Local Distribution Network (LDN) and do
not have a net export out of the LDN.”

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Organization

Yes or No

Question 6 Comment

Response: The goal of the SDT is to provide clarity to the definition of the BES and not to address registration criteria.
The SDT feels that the term “gross aggregate nameplate rating” is a widely understood term within the industry and does not require additional definition. No
changes made.
I5 (now I4) was revised and no longer uses the term, ‘collector system.’
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Portland General Electric
Company

It is not clear what the SDT is attempting to capture with this inclusion thatis not already captured in I3. In
addition, the term “collector system” needs to bedefined.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Midstate Electric Cooperative

MSEC agrees that it is important to address wind generation facilities and similar generation facilities in which
a large number of generating units, each with a relatively small capacity, are clustered and fed into the grid at
a single interconnection point.
That being said, MSEC is concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons
stated in our comments on Question 4. This would lump together many IPP's that are spread out over a large
distribution network that happen to be tied into a single point of interconnection.

Response: The SDT re-worded the definition to better clarify these concerns.
The SDT appreciates the concern regarding the lack of technical justification for a 75 MVA threshold; however, the SDT has been presented with no technical
basis upon which to suggest a change from this value. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has
decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the
mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that
the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT
take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that

August 19, 2011

197

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Organization

Yes or No

Question 6 Comment

have arisen from SDT deliberations.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Florida Municipal Power Agency

Yes

FMPA agrees with the concept of Inclusion I5 but suggests a language change to clarify what we understand
to be the drafting team’s intent, that the inclusion is intended to apply to dispersed wind and solar generating
plants, and not, for example, to a radially-connected city with an aggregate of 75 MW of small generators
behind-the-meter. This distinction is appropriate because such a city cannot have the same impact on the
grid as a 75 MW wind farm; loss of the radial connecting the city to the grid would result in loss of its load as
well as its generation, so that the supply-demand mismatch would be far less significant. FMPA thus
suggests that I5 be revised to read:I5 Wind farm or solar power installation with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) utilizing a collector system through a common point of
interconnection to a system Element at a voltage of 100 kV or above.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Western Electricity Coordinating
Council

Yes

WECC agrees in concept, but it is unclear why there is the new term “power producing resources.” Is this
meant to include both Real Power Resources and Reactive Power Resources (terms used in the base
definition)? This should be clarified. In addition, it appears from comments of the drafting team that the intent
of this inclusion was primarily for wind and solar farms, but the language would also pull in traditional
generation that happens to be connected at a single point. The language should be clarified so that it only
captures the intended generation.

Response: The SDT used this term intentionally. Generation resources suggest a “generator”. Using the term power producing resources is to include devices
now and in the future that could produce energy (like wind and solar). No change made.
Edison Electric Institute

August 19, 2011

Yes

EEI suggests that the following language more clearly expresses the intent of the SDT:Dispersed power
producing resources with aggregate capacity greater than 75 MVA gross aggregate nameplate rating) utilizing

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Organization

Yes or No

Question 6 Comment
a collector system from the point where the aggregate rating exceeds 75 MVA through a common point of
interconnection to a system Element at a voltage o 100 kV or above.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
ReliabilityFirst

Yes

but the term "Dispersed Power Producing Resuorces" needs to be defined.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Transmission Access Policy
Study Group

Yes

TAPS agrees with the concept of Inclusion I5 but suggests a language change to clarify what we understand
to be the drafting team’s intent, that the inclusion is intended to apply to dispersed wind and solar generating
plants, and not, for example, to a radially-connected city with an aggregate of 75 MW of small generators
behind-the-meter. This distinction is appropriate because such a city cannot have the same impact on the
grid as a 75 MW wind farm; loss of the radial connecting the city to the grid would result in loss of its load as
well as its generation, so that the supply-demand mismatch would be far less significant. TAPS thus
suggests that I5 be revised to read:I5 Wind farm or solar power installation with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) utilizing a collector system through a common point of
interconnection to a system Element at a voltage of 100 kV or above.

Northern California Power
Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed

August 19, 2011

199

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 6 Comment

primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
New York Power Authority

Yes

This inclusion should be specific to the type of generation that the team envisioned it to capture (e.g. wind and
solar). Since the term “dispersed power producing resources” can be interpreted to include generation
resources from a few KW up to 50 MW, this inclusion can be misinterpreted to include “peaker GT’s”, fuel
cells and microturbines, etc.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Central Maine Power Company

Yes

New York State Electric & Gas
and Rochester Gas & Electric

Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is MVA instead of
MW.

Response: The SDT believes that MVA is the correct way to measure this. No change made.
PacifiCorp

Yes

PacifiCorp understands the SDT is looking for technical reasons for something other than 75 MVA. PacifiCorp
believes it is not feasible to determine a value that is consistent across the continent. Although PacifiCorp
believes 75 MVA is too low, it is an acceptable number for any configuration of generation. Those above 75
MVA believed to be exempt from the BES definition can be processed through the proposed ROP
inclusion/exclusion process.

Response: The SDT agrees that the exception process will be the proper venue to sort out differences.
Sacramento Municipal Utility
District (SMUD)

August 19, 2011

Yes

SMUD agrees with the Inclusion 5 concept. However, there are a few terms that require clarification to
support the “Bright-Line” application. It is unclear what is meant to be captured by the term “Dispersed power
producing resources”. As reflected in the intent statement it would be preferred to indicate the applicability of
the wind and solar resources or the term intermittent in the Inclusion 5 language. The term “collector system
through a common point” is rather vague that lends to varied interpretations that perhaps a defined level of
MW through a single element bottleneck would help quantify BES impacts.

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Organization

Yes or No

Question 6 Comment
In addition, the BES delineation should be the single “bottleneck” element for aggregate connection of 75
MVA as it is that element's interruption is what would impact the BES.
Additional concerns of I-5 suggests that the wind and solar resources would be BES components where their
singular contribution has no appreciable impact to the BES. Including the bottleneck option seems to identify
an aggregate BES impact for a loss of a 75 MW block that could have an impact on the BES.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Illinois Municipal Electric Agency

Yes

Please see comments under Question 13.

Yes

Generally agreed but please revise to one Inclusion for I2, I3 and I5 at 75 MVA, see Question 3 and 4
comments.

Response: See response to Q13.
Idaho Power

Response: The SDT believes that Inclusion I4 (formerly Inclusion I5) is sufficiently distinct from Inclusion I2 that it needs to be retained. No change made.
MEAG Power

Yes

This inclusion should be specific to the type of generation that the team envisioned it to capture (e.g. wind and
solar). Since the term “dispersed power producing resources” can be interpreted to include generation
resources from a few KW up to 50 MW, this inclusion can be misinterpreted to include “peaker GT’s”, fuel
cells and microturbines, etc.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Michgan Public Power Agency

August 19, 2011

Yes

I would suggest I5 be revised to say Wind farm or solar power installation with aggregate capacity greater

201

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 6 Comment
than 75 MVA (gross aggregate nameplate rating) utilizing a collector system

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Sierra Pacific Power Co d/b/a NV
Energy

Yes

Similar to the response to Q4, the 75MVA has no technical basis as being a threshold for determining
necessity in the reliable operation of the interconnected transmission system; however, no technical data
supports an alternate value.

Sweeny Cogeneration LP

Yes

The threshold for widely distributed and aggregated generation units (wind farms) is consistent with the NERC
functional registry criterion.

Public Service Enterprise Group
LLC

Yes

Tri-State Generation and
Transmission Association, Inc.

Yes

SERC Planning Standards
Subcommittee

Yes

ACES Power Participating
Members

Yes

SERC OC Standards Review
Group

Yes

National Rural Electric
Cooperative Association
(NRECA)

Yes

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Organization

Yes or No

Overton Power District No. 5

No

Arizona Public Service Company

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

Southern Company

Yes

Luminant Energy

Yes

Western Area Power
Administration

Yes

US Bureau of Reclamation

Yes

Grand Haven Board of Light and
Power

Yes

Glacier Electric Cooperative

Yes

FHEC

Yes

South Texas Electric
Cooperative, Inc.

Yes

National Grid

Yes

Dayton Power and Light
Company

Yes

ExxonMobil Research and
Engineering

Yes

August 19, 2011

Question 6 Comment

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Organization

Yes or No

Alberta Electric System Operator

Yes

South Carolina Electric and Gas

Yes

Florida Keys Electric Cooperative

Yes

American Electric Power

Yes

East Kentucky Power
Cooperative, Inc.

Yes

Farmington Electric Utility System

Yes

Colorado Springs Utilities

Yes

Consumers Energy Company

Yes

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

Yes

Puget Sound Energy

Yes

GTC

Yes

Long Island Power Authority

Yes

Cogentrix Energy, LLC

Yes

Manitoba Hydro

Yes

ISO New England, Inc.

Yes

August 19, 2011

Question 6 Comment

No comment.

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Organization

Yes or No

City of Anaheim

Yes

Golden Spread Electric
Cooperative, Inc.

Yes

Question 6 Comment

Response: Thank you for your support. Based on stakeholder comments, the SDT made some modifications to the inclusion. After consulting with the NERC
Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply
isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the
directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC
Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization Request
(SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations. Please see the revised definition.

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7. The SDT has added specific exclusions to the core definition in response to industry comments. Do you agree
with Exclusion E1? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: The SDT believes that the changes made to the wording of the definition based on comments received will
provide clarity and address the concerns provided by the commenters. In particular the SDT clarified the point of connection, removed the
automatic interrupting device, moved the concept of the normally open switch to a note, and clarified the generation allowed within the system.
In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local
networks.
The SDT realizes that a bright-line definition may require entities to seek exceptions through the Rules of Procedure exception process.
This BES definition does not address protection or control systems. Standards and requirements can be written against components that are not
BES Elements.
The SDT does not specify the type of normally open switch that will be used to separate the systems described in Exclusion E1 but understands
that any such switch needs to be operated in such a fashion that insures safety, utilizes the best operating practices, and maintains reliability.
Changes due to industry comments are as follows:
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real
Power and Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is
modified by the list shown below. This does not include facilities used in the local distribution of electric energy.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of
connection of 100 kV or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to
allow for reliable system reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to
c)

75 MVA (gross nameplate rating). Or,
Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in
Inclusions I2, I3, I4 and I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

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Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this
exclusion.

Organization
Public Service Enterprise Group
LLC

Yes or No
No

Question 7 Comment
Again, in similar comments to item 1 above, where is the BES line of demarcation between BES elements
(the interrupting device itself) connecting the non-BES radial system?
The term “Generation resource” is not defined and open for interpretation.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.
The SDT believes that generation resource is a widely used and understood term and therefore, a definition is not required.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Northeast Power Coordinating
Council

August 19, 2011

No

The concept is consistent with the statements in the FERC Order. However, it is imperative to understand
that the limitations of E1 will have a direct impact on many entities (big and small) along with distribution
companies across North America. The exclusion requirements are restrictive and these restrictions mayhave
an adverse affect on future transmission investment, for example the addition of a second line removing the
radial status exclusion. Consideration should be given to allowing entities to build additional transmission and
not automatically compromise the exclusion status of any given facilities. For example, a redundant double
circuit designed to supply the load with adequate protection and isolation beyond the radial tap could be

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Organization

Yes or No

Question 7 Comment
significantly better for load supply-continuity and reliability. If more than one transmission source feed radial
load to ensure customer supply continuity and reliability, then this should be either part of the bright-line
definition E1 exclusion as long as there is adequate protection and, the loss of any single transmission source
does not affect the interconnected transmission network.
The SDT should:
o Carefully craft the exception criteria and procedure that is flexible and technically sound to adequately allow
entities to present their case to the ERO for exclusion
o Exception criteria should be at a high-level with items of assessment that can be followed continent-wide
by entities to put forward their exception for element(s) mentioned in exclusions or inclusions based on
technical assessment, evidence and justification for its unique characteristics, configuration, and utilization
o Acknowledge and provide provisions in both NERC exception criteria and exception process for federal,
state and provincial jurisdictions.

Tri-State Generation and
Transmission Association, Inc.

No

A “single Transmission source” is unclear and may be interpreted differently by different Regional Entities. A
circuit switcher-protected transformer serving only distribution load may be tapped to a single transmission
line but the transmission line has two or more sources. Is the system then connected to a single
Transmission source, thus making it radial and being excluded? Or will the Regional Entity declare that, since
the transmission line has two sources that the radial system also has two sources?
We suggest changing the opening sentence of Exclusion E1 to “Any radial system that is connected to a
Transmission source through an automatic interrupting device or devices and:”

American Municipal Power and
Members

No

The words “described as” should be deleted from the exclusion to avoid confusion. What matters is how the
system is actually connected, not how someone describes it.
In addition, “a single Transmission source” could be defined, and should be generic enough to encompass the
various bus configurations. It is not the case, for example, that each individual breaker position in a ring bus
is a separate Transmission source; in that case, a bus at one voltage level at one substation should be
considered “a single transmission source.” Some examples of configurations that should be considered a
single transmission source for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples 1-6.
The phrase “automatic interrupting device” should be replaced with the phrase “switching device”.” Many
radials are connected to ring buses or breaker-and-a-half schemes where the breakers (automatic interrupting
devices) are within the bus arrangement where the appropriate division between BES and non-BES is at the
disconnect switch as the radial “takes off” from the bus arrangement.

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Organization
Central Maine Power Company

Yes or No
No

New York State Electric & Gas
and Rochester Gas & Electric

Question 7 Comment
The definition of radial needs to be clear and comply with Order 743. We do not know what a radial “system”
is.
Also, “automatic interruption device” is not defined.
This exclusion includes “radial” “systems” with more than one supply from a single “source” - including
normally-open switches, even those which are intended to be normally closed before further switching takes
place (“make-before-break”). This seems to be a problem, per Order page 32. We suggest a compliant and
straightforward “radial” exclusion, and recommend that E1 be replaced with, “Those Transmission Elements
interconnected to only one other substation through only one transmission line; except those elements
included in I2, I3, and I5.” It is clear and it can be applied in a “bright-line”, consistent fashion.

Intellibind

No

Small radial systems that have two interconnection points at the same location or very close to the same
location, but are not used for Transmission flow through should also be excluded. There are numerous
examples of two interconnection points that are paralleled by much higher voltage systems and do not flow
power through the system, but are redundant to increase distribution reliability. This should be left to the
Transmission Operator/Transmission Owner to determine if there is flow through and impact to the BES
before designating these as BES assets based on interconnection points. Radial should be defined as power
flowing one direction only, not based on how it is interconnected to 100KV or higher lines.

Hydro-Quebec TransEnergie

No

It is too much restrictive to refuse exclusion of radial system when they have generator greater than 20 MVA,
or multiple generating units of aggregate capacity greater than 75 MVA, especially when a system is able to
function reliably with the loss of generation much higher than this amount. The fact that no Reliability
Standards apply to generators excluded from BES is problematic. Generators should be allowed to be
excluded but reliability standards should apply to them in specific.
Also, the connection through only a single Transmission source is again too restrictive. Other Transmission
source could be used for load continuity of service and the restriction should be limited to radial transmission
paths where the power flow is greater than the first contingency lost.

National Grid

No

We feel that there might be some confusion between I1 and E1 because while I1 only includes transformers
with 2 windings greater than 100kV, E1 specifically says a tap must have an automatic interruption device to
be excluded.So, we are concerned that radial tapped lines with a transformer whose low-side voltage is less
than 100kV, but do not have an automatic interruption device are not excluded. We would like to see some
additional clarity in this exclusion to address this situation
Does automatic interruption device only include breakers/circuit switchers? Would a device such as a
motorized loadbreak be considered an automatic interruption device? If motorized loadbreaks are also

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Organization

Yes or No

Question 7 Comment
considered as an automatic interruption device, then there would be less confusion between E1 and I1. We
also request that this issue be addressed by adding clarity to the exclusion.
Another concern is that this exclusion requirement is restrictive and may have an adverse affect on future
transmission investment for redundant radial supply to improve local load service, for example the addition of
a second line removing the radial status exclusion. Consideration should be given to allowing entities to build
additional transmission without automatically compromising the exclusion status of any given facilities.

CenterPoint Energy

No

CenterPoint Energy believes that some radial systems described in Exclusion E1 are similar to the local
distribution networks (LDNs) described in Exclusion E3. A radial system may be connected to more than one
automatic interrupting device in certain substation designs, such as a ring bus configuration. CenterPoint
Energy believes similar wording should be used for Exclusion E1 and Exclusion E3. Utilizing wording from
Exclusion E3, CenterPoint Energy recommends changing the beginning of Exclusion E1 to “Any radial system
which is described as separable by automatic fault interrupting devices: Wherever connected to the BES, the
radial system must be connected through automatic fault-interrupting devices; and:”.

ISO New England, Inc.

No

The definition of radial needs clarification; we suggest “fed from a single transmission source, i.e. fed from a
single substation at a single voltage”. It is clear and it can be applied in a “bright-line”, consistent fashion.
As currently drafted, if the interruption device is not automatic, E1 would not exclude tapped “radial - i.e.
single fed” equipment. Does the SDT mean to imply that even transformers which do not have an automatic
interruption device on the high side, but have low voltage side at lower than 100 kV, will be considered part of
the BES? If so, is the BES considered to extend to where the circuit has an automatic interruption device?
Would the bus conductor and leads to the high side of the transformer be BES? This would not be
acceptable if the answer is yes. It is important to keep in mind that the in the instance of a radial line served
via a tap, the system needs to be designed for loss of the line in any event and requiring an automatic
switching device is not necessary.In short, the term radial should be better defined and the requirement for an
automatic interruption device should be eliminated.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the
normally open switch to a note, and clarified the generation allowed within the system.
In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local networks. The SDT
realizes that a bright-line definition may require entities to seek exceptions through the Rules of Procedure exception process.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:

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Organization

Yes or No

Question 7 Comment

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems does not affect this exclusion.
NERC Staff Technical Review

No

Exclusion E1 would be acceptable if (i) switching the radial system to connect it to the BES at a second point
of interconnection is modified to require that when a make-before-break connection is used, it occurs at a
voltage below 100 kV and (ii) the automatic interrupting device is not excluded as part of the radial system.
>>>>>>>>>>
The allowance for make-before-break connections of radial facilities at voltages 100 kV or higher will result in
operating conditions with the potential to degrade system reliability if the subject Elements are not planned,
designed, maintained, and operated in accordance with NERC Reliability Standards. The risk is most
pronounced when the make-before-break connection is automated, increasing the likelihood of adverse
reliability impacts occurring as a result of placing the system into an unplanned operating condition. If the
make-before-break connection is made at a voltage below 100 kV the impedance in the parallel connection
will mitigate the reliability impact. When the radial system is connected to the BES at a second point of
interconnection 100 kV or higher, the radial system should not be excluded unless a break-before-make
connection is used because system protection during the momentary parallel network operation is critical to
overall BES reliability. >>>>>>>>>>
The reason for requiring an automatic interrupting device between the BES and the excluded radial system is
to prevent faults and other abnormal conditions on the radial system from negatively impacting reliability of
the BES. Given the reliance on the interrupting device to support BES reliability, it is appropriate to include
the interrupting device in the BES so that it is planned, designed, maintained, and operated in accordance
with NERC Reliability Standards the same as other BES Elements. Thus, when excluding a radial system
operated at 100 kV or higher, the BES line of demarcation should be on the load side of the automatic
interrupting device. >>>>>>>>>>
The main clause and part (a) of the exclusion should be changed to read; >>>>>>>>>> Exclusion E1 - Any
radial system which is described as connected from a single Transmission source originating on the load side
of an automatic interruption device and:a) Only serving Load. A normally open switching device between

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Organization

Yes or No

Question 7 Comment
radial systems may operate in a ‘break-before-make’ fashion at 100 kV or higher or a ‘make-before-break’
fashion below 100 kV to allow for reliable system reconfiguration to maintain continuity of electrical service.
Or, etc. ...

Small Entity Working Group
(SEWG)

Yes

Yes, with some minor changes. Delete the words “described as” in the sentence: Any radial system which is
described as connected from a single Transmission source originating with an automatic interruption device
and. How the radial system is actually connected is important not the description.
The SEWG believes that “a single Transmission source” should be defined in such a way to ensure all the
various bus configurations are captured.
The SEWG recommends modifying the language in E1 to allow for the use of a “switching device” rather than
an “automatic reclosing device” for two specifics situations as follows: 1) When a radial transmission line is
feed from a ring bus, but only serve load and/or non-registered generation: 2) When a radial transmission line
is feed from a breaker and half bus and it only serves load and/or non-registered generation. In both cases,
faults on the radial transmission line will not interrupt network transmission flows and therefore has minimal
impact on the BES.
For direct connection of radial transmission lines to a networked transmission line, the SEWG agrees that an
automatic interrupting device is required to protect the BES.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by most of the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the
normally open switch to a note, and clarified the generation allowed within the system.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.

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Organization

Yes or No

Question 7 Comment

Dominion

No

Dominion can agree with Exclusion E1 only if the exclusion is applied to any radial Facility, regardless of
whether it is used to connect load or generation to the bulk power system.

SPP Standards Review Group

No

We could concur with this exception providing the ‘automatic interruption device’ is not considered a part of
the BES.
Additionally, what are the implications for a radial element connected in a ring bus via two breakers or a radial
element connected via a breaker and a half scheme?

Edison Electric Institute

No

EEI suggests the following change to E1:Any radial system which is described as connected from a single
Transmission source [Delete "originating with an automatic interruption device"] and:

Idaho Falls Power

No

This exclusion speaks to radial systems with generation resouces not identified in I2, I3, I4, or, I5, thus
seemingly only to apply to generation resouces smaller than 20MVA. We wonder why this exclusion then
exists as these resources are already excluded by not being large enough to fall under the registry criteria,
and thus need not comply with the reliability standards.

Tennessee Valley Authority

No

We suggest the first statement in E1 to read, “Any radial system connected to a single BES transmission
source, operating with an automatic interruption device, including the facilities between the connection to the
transmission source and the automatic interruption device which are within the transmission source’s zone of
protection, and:”

New York State Reliability
Council

No

E1 too prescriptive. Suggest developing a general, flexible definition of radial system in NERC Glossary such
as "A system connected from a single Transmission source originating with an automatic interruption device".

New York Power Authority

No

The definition of Exclusion E1 does not cover radial systems that are connected to a single transmission
source by more than one automatic interruption device, such as occurs with a “breaker-and-a-half”
arrangement. The definition should be modified as follows:”Any radial system which is described as
connected from a single Transmission source originating with one or more automatic interruption devices and:
....”This exclusion uses many terms that are not defined under NERC’s standard definitions: “radial load”,
“automatic interruption device” and “make-before-break”. If these terms are used to define an exclusion and
can be understood or interpreted differently by different people, then the terms should be formally defined.

Electricity Consumers Resource
Council (ELCON)

No

The existing language in the NERC Statement of Compliance Registry for radial exclusions should be
maintained since the change proposed by the SDT could result in a significant increase in entities and/or
facilities that would have to be registered or included (because of the addition of the automatic interruption

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Organization

Yes or No

Question 7 Comment
device). The burden for proving the need for such significant changes should be placed on the ERO and the
Regional Entities through the BES Exception Process, not on the users of the BES. In particular, it could
force retail load (customers) to register as transmission owners, or engage in other maneuvers to avoid
registration, when this is clearly a transmission owner/customer issue (as to whether to install automatic
interruption devices). These lines are non-jurisdictional and are obvious under the purview of the state
commissions.

The Dow Chemical Company

No

The existing language in the NERC Statement of Compliance Registry for radial exclusions should be
maintained since the change proposed by the SDT could result in a significant increase in entities and/or
facilities that would have to be registered or included (because of the addition of the automatic interruption
device). See ELCON comments for additional details.

Grand Haven Board of Light and
Power

No

Exclusion E1 addresses a radial, load serving system, but it does not address whether the automatic
interrupting device should be defined as a part of the BES or not. In our case, the ONE automatic interrupting
device that we own would force us to register as a TO/TOP, and as a result incur significant costs. This does
not comply with FERC Order No. 743 (and No. 743a) and should be addressed in this exclusion if not in the
core definition.

FHEC

No

Suggest the word single be moved later in the sentence, see below-From: E1 - Any radial system which is
described as connected from a single Transmission source originating with an automatic interruption device
and: To:E1 - Any radial system which is described as connected from a Transmission source originating with
a single automatic interruption device and:

ExxonMobil Research and
Engineering

No

The inclusion or exclusion of radial lines serving load should not be contingent on whether the radial line is
isolated by a single automatic fault interrupting device. Many of the radial lines impacted by the requirement
for the presence of an automatic fault interrupting device are industrial companies that are fed via 138 kV and
230 kV systems that are hard-tapped or fed from breaker and a half or ring buss transmission substations.
The requirement for the installation of an automatic fault interrupting device on the radial line is predicated on
the assumption that an event on a hard-tapped line serving load will produce a negative impact on the
interconnected transmission network. Accepting this assumption as a true fact, the SDT is following the logic
that they should expand the scope of the interconnected transmission network to include the hard-tapped line
(used to locally distribute power) due to the fact that the transmission owner has neglected to properly protect
their facilities from the impact of an event on the hard-tapped line. In effect, the SDT is allowing the
transmission planner to take credit for protective devices installed on the distribution network when they
conduct their contingency studies as part of NERC Reliability Standards TPL-002 and TPL-003; thus shifting
the responsibility of protecting the interconnected transmission network from the owners of the transmission
network to the customers and their local distribution facilities. The SDT should revisit their assertion that

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Organization

Yes or No

Question 7 Comment
facilities should be included based on the presence of an automatic fault interrupting device based on the fact
that if a contingency study indicates that an automatic fault interrupting device should be present in order to
preserve system stability or prevent a cascading outage during an N-1 or N-2 contingency, the transmission
planner should be recommending such a device is installed on the interconnected transmission system and
not a customer owned facility or any facility used to locally distribute electric power. It is inappropriate to let
transmission owners take credit for customer owned and local distribution facilities in their reliability studies
and require customer’s and local distribution facilities to protect the interconnected transmission network
when those facilities are explicitly excluded from the bulk power system in Section 215 of the Federal Power
Act and the interconnected transmission system is owned and operated by entities that the customers and
local distribution facility owners pay to provide them with reliable transmission service.

MidAmerican Energy Company

No

The statement “originating with an automatic interruption device” seems to go beyond differentiating what is
radial. If that were removed, the rest of the draft exclusion seems to capture what is radial.

Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

No

(Note: Inserted language provided in brackets; deleted language denoted by empty brackets: [ ].) Exclusion
E1 contradicts the plain language of Section 215 of the Federal Power Act (“FPA”), which denies FERC
jurisdiction over facilities used in the local distribution of electric energy (16 U.S.C. § 824o(a)(1) (stating the
Bulk Power System “does not include facilities used in the local distribution of electric energy”)). For example,
Exclusion E1 would impermissibly include within the definition of the Bulk Electric System (“BES”) a retail
customer’s self-provided “hard-tapped” radial line that is located behind the retail delivery point. The
Standard Drafting Team (“SDT”) stated in commentary to Exclusion E1 that it has clarified the existing
exclusion for radial systems by specifying that protection for the BES is a required element, and that it
believes that faults on radial lines without protection devices could negatively impact the BES. Even if faults
on radial lines could negatively impact the BES, however, radial lines that are used in local distribution of
electric energy are outside of FERC’s jurisdiction. Congress did not place any qualifications on the exclusion
of facilities used in the distribution of electric energy, and certainly did not make the exclusion contingent on
whether the facility is “originating with an automatic interruption device.” Exclusion E1 would rewrite Section
215 of the FPA to exclude from the definition of the BES only “facilities [with an automatic interruption device]
used in the local distribution of electric energy.” Such an interpretation, as discussed further below in
response to Questions 11 and 12, is unlawful as it is in direct contravention of Congress’ intent. To make
Exclusion E1 consistent with the jurisdictional requirements of Section 215 of the FPA, Exclusion E1 could be
rewritten as follows:Any radial system which is described as connected from a single Transmission source [ ]
and: a) Only serving Load. [ ] Or, b) Only including generation resources not identified in Inclusions I2, I3, I4
and I5. Or, c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes
generation resources not identified in Inclusions I2, I3, I4 and I5. Please see further discussion in response to
Questions 11, 12 and 13.

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Organization

Yes or No

Question 7 Comment

Alliant Energy

No

We believe the first sentence should be revised to read “Any radial system which is described as connected
from a single Transmission source at 100 kV or above originating with . . .” In this way it is clear that E1
covers radial transmission, not radial distribution systems.

Exelon

No

Exelon points out that this is another case where facilities used in local distribution of electric energy that are
presently under state jurisdiction might be included in the BES. Depending on the location of the automatic
interrupting device, the radial facilities in between the tap point at the transmission sources and the
interrupting device would be included in the BES.

City of St. George

No

Radial systems should be excluded as outlined in E1a; however the generation level requirements of 20 MVA
and 75 MVA (I2, I3, & I5) should be revisited. As long as the normal power flow is into the radial system, the
amount of generation on a radial segment should not automatically trigger an inclusion to the BES.

Golden Spread Electric
Cooperative, Inc.

No

We recommend modifying "Any radial system which is described as connected from a single Transmission
source originating with an automatic interruption device and..." to read EITHER1. "Any radial system which is
described as connected from a single Transmission source and... [remove originating with an automatic
interruption device ] OR2. "Any radial system which is described as connected from a single Transmission
source originating with an automatic interruption device or manual isolating switch..."

Michigan Public Service
Commission(MPSC)

MPSC Staff Comments: The MPSC supports this exclusion with the exception that Inclusion I2 should be
removed from the E1(c) provision. Keeping the I2 here will result in too many subtransmission load-serving
elements losing their non-BES status.

Georgia System Operations

A. The phrase “which is described as” is unclear. If the intention is to mean “which is defined as,” the term
“Radial System” should be capitalized and added to the glossary. Otherwise, consider deleting the phrase.
B. It is not clear whether the automatic interruption device on the excluded system is itself in or out of the
BES. Can the drafting team clarify this intent with respect to breakers protecting radial lines (perhaps
compared to circuit switchers protecting load serving transformers)? Drawings could be very beneficial here.
C. The second part of sub-bullet “a” (the sentence beginning “A normally open switching device...”) applies
not only to “a” but to all the sub-bullets, and therefore should be moved to either the initial sentence or to be a
closing item after the last sub-bullet. For example, if the sub-bullets are indented, and then this sentence
returns to the original margin, that would show that it applies to any “radial system” and not just to a system
falling under a single sub-bullet.

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Organization

Yes or No

United Illuminating

Florida Municipal Power Agency
Florida Keys Electric Cooperative

Question 7 Comment
UI suggests the following change to E1 eliinating the automatic device:Any radial system which is described
as connected from a single Transmission source.These taps are not necessary for the opeation of the
interconnected system.

Yes

FMPA agrees with the intent / concept, but has suggested wording changes to add clarity.The words
“described as” should be deleted from the exclusion to avoid confusion. What matters is how the system is
actually connected, not how someone describes it.
In addition, “a single Transmission source” should be defined, and should be generic enough to encompass
the various bus configurations. It is not the case, for example, that each individual breaker position in a ring
bus is a separate Transmission source; in that case, a bus at one voltage level at one substation should be
considered “a single transmission source.” Some examples of configurations that should be considered a
single transmission source for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples 1-6.
The phrase “automatic interrupting device” should be replaced with the phrase “switching device.” Many
radials are connected to ring buses or breaker-and-a-half schemes where the breakers (automatic interrupting
devices) are within the bus arrangement where the appropriate division between BES and non-BES is at the
disconnect switch as the radial “takes off” from the bus arrangement.As written, E1 would eliminate most
radials from automatic exclusion and force most of them into the Exception Procedure. For instance, see
examples 2 of the FRCC draft BES definition Appendix A at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf).Switch "A" in example 2 is
usually not automatic. Breaker D and E are automatic. Switch A is radial, Breakers D&E may not be. FMPA
recommends replacing "automatic interrupting" with "switching" and allow manual switching devices to
establish the boundary between BES and non-BES, otherwise we get into splitting up ring-buses or breakerand-a-half schemes, or flooding the Exception Procedures with a lot of needless requests.Also, "device" is
singular whereas the exclusion is for a "radial system". I presume that the SDT intends that if there are two
lines originating at the same substation supply a load in a redundant nature, that the "radial system" would be
excluded (see examples 1, 3 and 4 of the FRC draft BES Definition Attachment A), which would mean there
would be more than one device.Also, the phrase "A normally open switching device between radial systems
may operate in a ‘make-before-break’ fashion to allow for reliable system reconfiguration to maintain
continuity of electrical service." is misplaced in bullet a) and belongs in the non-bulleted section.FMPA
recommends re-wording E1 to be:"Any radial system which is connected from a single Transmission source
(such as a contiguous bus configuration like a ring bus or breaker-and-a-half scheme) originating with
switching device(s) and meeting the criteria in bullets a, b or c below. A normally open switching device
between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service.a) Only serving Loadb) Only including generation

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Organization

Yes or No

Question 7 Comment
resources not identified in Inclusions I2, I3, I4 and I5c) A combination of (a) and (b)"

MRO's NERC Standards Review
Forum

Yes

We recommend the phrase “originating with an automatic interruption device” be clarified as to the location of
the interruption device. An entity may not have interruption devices at both ends of a radial fed line. If the
interruption device is at the load end of the radial line, then the “up-stream” portion of the radial line is
unprotected. Please clarify.Please add the Brightline Criteria that all facilities less than a 100kV are excluded
unless those facilities meet the criteria of an Inclusion.

Hydro One Networks Inc

Yes

We agree with this concept as part of establishing a bright-line definition, as well as clarifying this exclusion as
part of the revised BES definition. Although the concept is consistent with the statements in the FERC Order,
it is imperative to understand that the limitations of E1 will have a direct impact on many entities (big and
small) along with distribution companies across North America. The exclusion requirements are extremely
restrictive with little or no technical basis and are limited to the fact that these parametric restrictions may not
have any reliability impact in terms of location, configuration of element, and system characteristics. The
radial characteristics and/or the reliability of the interconnected transmission network should not be
determined by the amount of installed generation or a single transmission source or an interrupting device.
For example, a redundant double circuit designed to supply the load with adequate protection and isolation
beyond the radial tap could be significantly better for load supply-continuity and reliability. We suggest if more
than one transmission source feed radial load to ensure customer supply continuity and reliability then this
should be either part of the bright-line definition as long as there is adequate protection and, the loss of any
single transmission source does not affect the interconnected transmission network.
We suggest SDT to consider revising E1 as follows:Any radial system which is described as connected from a
single Transmission source originating with an automatic interruption device or can be isolated with adequate
protection without affecting the BES and: a) Serves load, or, b) Includes generation resources not identified
in Inclusions I2, I3, I4 and I5, unless excluded by E2, or, c) Has any combination of items (a) and (b). The
radial system can have a normally open switching device for connecting it to a second Transmission source in
a ‘make-before-break’ fashion to allow for reliable system reconfiguration to maintain continuity of electrical
service.

National Rural Electric
Cooperative Association
(NRECA)

Yes

NRECA requests that the drafting team state explicitly whether the automatic interruption device is included or
excluded from the BES.
Examples of automatic interruption devices should be included in a reference or FAQ document, and
drawings/diagrams on typical configurations would be beneficial.
Consistent language is needed in the Inclusions/Exclusions. E1 states “automatic interruption device” and
E3(a) states “automatic fault interrupting devices.” NRECA recommends adding the word “fault” as in E3(a)

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Organization

Yes or No

Question 7 Comment
and also stating “device(s)” in E1 and E3(a) and wherever else the phrase may be used in the BES definition
and inclusions/exclusions.Additional clarification is needed in explaining E1(c) to ensure industry understands
the scenario.

ReliabilityFirst

Yes

teh term "Single Transmission Source" needs defined, and as well what elemnents are defined by "automatic
interrupting devices" there is debate out in the industry.

Transmission Access Policy
Study Group

Yes

TAPS suggests some clarifying changes:The words “described as” should be deleted from the exclusion to
avoid confusion. What matters is how the system is actually connected, not how someone describes it.

Michgan Public Power Agency

In addition, “a single Transmission source” should be defined, and should be generic enough to encompass
the various bus configurations. It is not the case, for example, that each individual breaker position in a ring
bus is a separate Transmission source; in that case, a bus at one voltage level at one substation should be
considered “a single transmission source.” Some examples of configurations that should be considered a
single transmission source for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples 1-6.
The phrase “automatic interrupting device” should be replaced with the phrase “switching device.” Many
radials are connected to ring buses or breaker-and-a-half schemes where the breakers (automatic interrupting
devices) are within the bus arrangement where the appropriate division between BES and non-BES is at the
disconnect switch as the radial “takes off” from the bus arrangement.

Northern California Power
Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.

Texas Industrial Energy
Consumers (TIEC)

Yes

TIEC supports excluding radial loads serving only load or generation resources that do not trigger NERC
registration requirements. This is consistent with the FERC’s intent and the existing BES definition.
However, TIEC believes that this exclusion should not be contingent upon a radial system “originating with an
automatic interruption device” as proposed by the SDT. Radial feeds serving a system that contains only load
and generation that does not trigger registration requirements should be categorically excluded from the BES
definition regardless of whether the radial lines originate with an automatic interruption device. It should be
the responsibility of the transmission provider to ensure that its facilities and interconnection properly protect
the grid from facilities that fall under this exclusion, just as the transmission providers do for other load and
unregistered generation. The absence of automatic interruption device should not trigger inclusion as a part
of the BES, but should trigger a requirement upon the transmission provider to install such a device on its side
of the facilities or take other measures to insulate the grid from the activities of a radial network. Accordingly,
TIEC would proposed to strike the phrase “originating with an automatic interruption device” from the

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Organization

Yes or No

Question 7 Comment
proposed exclusion language.

National Association of
Regulatory Utility Commissioners

Yes

We agree with Exclusion E1. Radial systems are clearly local distribution and excluded from FERC and
NERC jurisdiction. This is consistent with FERC Order 743 and 743a (see e.g. Order 743A P 1, 76 Fed. Reg.
16264 (March 23, 2011)). We suggest that I2 be removed from this exclusion (and from the standard as a
whole) as discussed in response to question 3.

Oregon Public Utility Commission
Staff

Yes

Exclusion I as currently proposed adequately defines radial systems; however, Inclusion I2 language should
be removed per the rationale stated in the response to Question 3 above. To retain the Inclusion I2 language
herein would sweep in an abundance of distribution elements that have no impact on the reliable operation of
the interconnected bulk transmission system.

PUD No. 2 of Grant County,
Washington

Yes

E1 specifically states “Any radial system which is described as connected from a single transmission source
originating with an automatic disconnection device and...”. The example of concern is a radial tap to a single
distribution power transformer that is connected to a ring bus or breaker and a half bus. In this case the
transformer would have 2 automatic disconnection devices from what is essentially a single source. Typically
ring bus and breaker and a half bus are used to improve reliability, limiting the exclusion to a single
disconnecting device appears to bring a hypothetical radial tap fed from a ring bus or breaker and a half bus
into the BES definition. Although the LDN exclusion might apply there is the potential for many situations
where it might not.A possible remedy is to revise the exclusion as follows:”Any radial system which is
described as connected from a single transmission source that originates with automatic disconnection
device(s) and...”
In addition, a definition for “a single transmission source” should be provided to clarify the intent.
Suggestion:”A single transmission source would be any transmission source located within a single facility,
yard or fenced area and electrically continuous at a single voltage level”.

FortisBC
AltaLink

August 19, 2011

Yes

We agree with this concept as part of establishing a bright-line definition, as well as clarifying this exclusion as
part of the revised BES definition. Although the concept is consistent with the statements in the FERC Order,
it is imperative to understand that the limitations of E1 will have a direct impact on many entities (big and
small) along with distribution companies across North America. The exclusion requirements are extremely
restrictive with little or no technical basis and are limited to the fact that these parametric restrictions may not
have any reliability impact in terms of location, configuration of element, and system characteristics. The
radial characteristics and/or the reliability of the interconnected transmission network is determined by the
amount of installed generation or a single transmission source or an interrupting device. For example, a
redundant double circuit designed to supply the load with adequate protection and isolation beyond the radial
tap could be significantly better for load supply-continuity and reliability. We suggest if more than one

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Organization

Yes or No

Question 7 Comment
transmission source feed radial load to ensure customer supply continuity and reliability then this should be
either part of the bright-line definition as long as there is adequate protection and, the loss of any single
transmission source does not affect the interconnected transmission network.
Accordingly, it will be an understatement to suggest that the SDT:
o Carefully craft the exception criteria and procedure that is flexible and technically sound to adequately allow
entities to present their case to the ERO for exclusion
o Exception criteria should be at a high-level with key menu items of assessment that can be followed
continent-wide by entities to put forward their exception for element(s) mentioned in exclusions or inclusions
based on technical assessment, evidence and justification for its unique characteristics, configuration, and
utilization
o Acknowledge and provide provisions in both NERC exception criteria and exception process for federal,
state and provincial jurisdictions.

American Electric Power

Yes

AEP supports the concept of the exclusion of radial systems, however further clarification is needed regarding
whether or not the source equipment is included as part of the radial system (for example, ring bus or breaker
and a half bus configurations). In addition, “automatic interruption device” should be defined to alleviate any
ambiguity.

East Kentucky Power
Cooperative, Inc.

Yes

EKPC has a concern with the wording of the definition for Exclusions:E1 - Any radial system which is
described as connected from a single Transmission source originating with an automatic interruption device
and:a) Only serving Load. A normally open switching device between radial systems may operate in a ‘makebefore-break’ fashion to allow for reliable system reconfiguration to maintain continuity of electrical
service.”This wording leads EKPC to believe that a radial 138 kv line that steps down into a 69 kv looped
system that have no facilities included in the BES would not be excluded as radial. This line cannot have any
more impact on the BES than the 69 kv system it connects to that is excluded from the BES. Therefore I
would add to exclusion E1a, “or only connecting to a transformer stepping down to a voltage below 100kv”.

American Transmission
Company, LLC

Yes

ATC offers the following alternative language:ATC suggests replacing the wording of “connected from a single
Transmission source” with “connected to the Bulk Electric System”.
Furthermore, ATC believes that Exclusion E1 is appropriate and should be part of the definition of the BES.
However, ATC believes that a registered entity should be given the option to not be required to follow the
exclusions in the E1 criteria. Some registered entities for operational and business purposes may wish to
continue to classify their radial system assets, which are operated above 100 kV, as BES components.

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Organization

Yes or No

Question 7 Comment

Muscatine Power and Water

Yes

MP&W recommends to clarify the phrase “originating with an automatic interruption device” regarding the
location of the interruption device. An entity may not have interruption devices at both ends of a radial fed
line. If the interruption device is at the load end of the radial line, then the “up-stream” portion of the radial line
is unprotected. Furthermore, please make it unambiguous that all facilities operated at less than a 100kV are
excluded unless those facilities meet the criteria of an Inclusion.

Sacramento Municipal Utility
District (SMUD)

Yes

SMUD support with the Exclusion 1 concept. However to maintain the clarity for a “Bright-line” the term
“single Transmission source” needs to be expanded as it could be read to be a single line, common bus or a
single entity, that will change the meaning of this exclusion.

GTC

Yes

Agree, but further clarification requested. E1 reads as if the originating automatic interrupting device is to be
excluded with the radial system. Can the drafting team clarify this intent with respect to breakers protecting
radial lines versus for example a breaker or circuit switcher protecting an excluded transformer which is not
part of the BES? Drawings would be very beneficial here.

Illinois Municipal Electric Agency

Yes

With the following clarifying edits. Delete the words “described as” in the first sentence.
Also, “a single Transmission source” should be defined to encompass various bus configurations. For
example, an individual breaker position in a ring bus is not a single Transmission source, but a bus at one
voltage level at one substation should be considered a single Transmission source.
Also, the phrase “automatic interrupting device” should be replaced with the phrase “switching device”. The
current wording does not take into account that a radial system is often connected to a ring bus or a breakerand-a-half scheme where the breaker/automatic interrupting device is within the bus arrangement. The
appropriate division between BES and non-BES is at the disconnect switch where the radial line attaches to
the bus arrangement.

Public Utilities Commission of
Ohio

Yes

Exclusion E1 is appropriate. However, any inclusion that are inconsistent with this exclusion should be
eliminated. Any facility that has an impact on the bulk system could be considered for inclusion under a case
by case basis.

Long Island Power Authority

Yes

For clarification purposes, we understand “Transmission source” to be a substation and not a line. A
substation connected to only one other substation “source” by two lines would still be considered radial and
thus excluded.

Idaho Power

Yes

Generally agreed assuming that the make-before-break may be performed manually.

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Organization
New England States Committee
on Electricity

Yes or No

Question 7 Comment

Yes

NESCOE generally supports these exclusions. However, NESCOE also notes that subsections (b) and (c)
could (depending on the final definition of Inclusions I2 through I5) sweep many sub-transmission load serving
elements into the BES, at a cost that is not justified in terms of reliability benefits.
Regarding sub transmission, Exclusion Criteria E1 and E2 are concerned with radial configurations while E3
relates to Local Distribution Networks (LDN’s). None of these apply to sub transmission networks that may
contain both looped and radial configurations. Also, sub transmission networks may have power flowing
parallel to the BES and may have power flowing into the BES with no potential for adverse impact on the
reliability of the BES. Sub transmission networks operated at voltages less than 100 kV, connected to the
BES via non-GSU transformers, should be excluded from the BES regardless of their configuration. It should
be clear that all generation facilities connected to sub transmission are not BES as these units are adequately
covered under other applicable NERC and/or regional reliability criteria. These units have no direct impact on
the reliability of the BES.Regarding facilities at operated at 100 kV and above, the switching configuration as
defined is not clear and possibly overly restrictive. The definition should incorporate language related to
avoiding “parallel paths” with diverse electrical nodes in the BES.

Big Bend Electric Cooperative,
Inc.

Yes

Our only concern about this exclusion is the timeframe we'd have to get an appropriate automatic interruption
device installed. Currently, we have a short radial that hasn't yet caused us to be registered as a TO or TOP.
Having time to get a solution in place would be crucial for us, as a small utility, to avoid additional regulatory
fees and requirements.

Modern Electric Water Company

Yes

Clear exclusionary language for radial systems is absolutely necessary for a usable BES definition,
particularly since radial systems serving load are already excluded from the existing NERC definition, radial
systems serving load can only be used for the local distribution of energy (and are thus excluded by Congress
in Sec. 215 of the FPA), and radial systems serving load have been confirmed excluded from the BES by
previous FERC Orders. However, the proposed language could be improved to be more explicit and further
remove the opportunity for improper/unintended interpretation. The currently-drafted E1 language has several
issues that need to be addressed. For instance: The use of “automatic interruption device” in E1 is not
consistent with “automatic fault interruption device” in E3-a, and could lead to different interpretations.
Another issue is the use of the un-clarified phrase “single Transmission source”, and deserves additional
attention. Presumably, this language exists to describe the commonly-used radial tap from a networked (twostation) line, as detailed in NERC Project 2009-17-Response to Request for an Interpretation of PRC-004-1
and PRC-005-1 for Y-W Electric and Tri-State G&T. In Project 2009-17, diagrams show a radial tap placed on
a line between Station A and Station B, and could be interpreted to indicate that the tap connects to two
sources. Unless “single Transmission source” is clarified, then a radial line originating from a Double-BusDouble-Breaker or a Breaker-and-a-Half station would also connect to two sources.

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Organization

Yes or No

Question 7 Comment
The drafted language does not go far enough to consider how networked lines are operated - sometimes
radially, sometimes with multiple protection and isolation schemes and equipment. As drafted, this exclusion
cannot be utilized by many insignificant taps (some of such insignificant length that no automatic fault
interrupting device was deemed necessary). This situation leaves those insignificant elements to apply the
LDN exclusion whose characteristics are dissimilar to a simple, load-serving radial tap. We support the intent
of the language of E1-a, “A normally open switching device between radial systems may operate in a ‘makebefore-break’ fashion to allow for reliable system reconfiguration to maintain continuity of electrical service....”,
but suggest that it be re-written as follows: “The existence and use of ‘make-before-break’ switching devices,
which temporarily connect otherwise radial load-serving systems to alternate sources for purposes of service
continuity, do not affect the BES status of the system before, during, or after their use.” This clarification is
needed to address a position held in the WECC region (WECC Compliance Bulletin #4, April 15, 2011) that
make-before-break switches render systems part of the BES, and discourage distribution providers from
“reliably” serving their customers.We do not intend to air grievances, but ambiguous radial exclusion language
has led to an extreme misuse of resources in the WECC region. It is imperative that industry and the SDT get
this exclusionary language correct and put into use as soon as possible.In an explanatory bullet below
Exclusion E1-c (herein) the SDT states “The SDT believes that faults on radial lines without protection
devices could negatively impact the BES.” Where this reasoning errs is that it assumes that everything
upstream of a radial element is already determined to be BES. Many radial taps connect to LDN lines without
AFIDs. The language proposed does not allow for a radial exclusion directly, but forces the insignificant tap to
apply the LDN exclusion E3 - E1’s success at being complete depends on another exclusion. Additionally, this
reasoning implies that the mere existence of a AFID is the cure-all to reliability or that technical analysis
hasn’t already established the proper balance of equipment to adequately serve and protect these elements.
We suggest including additional isolation devices as the demarcation point of small radial systems wishing to
apply this exclusion.

Utility System Efficiencies, Inc.

Yes

USE agrees in concept with this Exclusion. However, it is unclear what is required to demonstrate the “makebefore-break” connection. Is this statement intended to mean that the normally-open switch is mechanically or
electrically interlocked to ensure the “make-before-break” requirement is met? It would be a normal switching
practice to close the normally-open switch to make the parallel before opening the normally-closed switch, but
is the normal switching practice sufficient to make this claim? Also, it is unclear whether the automatic
interruption device itself is a part of the BES.

Duke Energy

No

This needs further clarification as to what constitutes a “single Transmission source”. Does having a
double/multiple circuit line(s) from a single transmission station constitute a radial system?.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally

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Organization

Yes or No

Question 7 Comment

open switch to a note, and clarified the generation allowed within the system through changes.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems does not affect this exclusion.
SERC OC Standards Review
Group

No

This exclusion is acceptable if the suggestions in Questions 3 and 4 are incorporated.
We also suggest modifying Exclusion E1a as follows: a) Only serving Load or only connecting to a
transformer stepping down to a voltage below 100kv. A normally open switching device between radial
systems may operate in a ‘make-before-break’ fashion to allow for reliable system reconfiguration to maintain
continuity of electrical service. Or,

Response: See responses to Q3 & 4
The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns provided by
the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally open switch
to a note, and clarified the generation allowed within the system.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and

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Organization

Yes or No

Question 7 Comment

I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Luminant Energy

No

E1 a) Omit or clarify-Sentence beginning “A normally open switch...” Does not say what to do with it. Is it
included or excluded. Suggested wording would be “An example would be a line with a normally open
switching device between radial systems that may operate in a ‘make -before-break’ fashion to allow for
reliable system reconfiguration to maintain continuity of electrical service.” E1
b)-Clarify- Sentence beginning “Only including...”Are those resources that are included in the exclusions that
are not included in the inclusions? Or are they resources that are included in the inclusions that are not
included in the inclusions? This meaning of this sentence is not clear. It should not be necessary to say that
resources are excluded that are not included. Suggested wording would be “Generation resources that are
not specifically described in the Inclusions I2, I3, I4 and I5.”

Response: a) The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the
concerns provided by the respondents. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of
the normally open switch to a note, and clarified the generation allowed within the system.
b) The SDT believes these changes provide clarification to how the Exclusions and Inclusions are related. If a generation resource is included in the Inclusions
then it can not be excluded by the Exclusions. In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple
connections serving local networks. The SDT realizes that a bright-line definition may require entities to seek exceptions through the Rules of Procedure exception
process.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

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Organization

Yes or No

Question 7 Comment

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Vermont Transco

No

Does “a single transmission source” mean a single “substation” at 100 kV or above?
The wording of this exclusion appears to allow distribution (<100 kV) level generating units to be excluded
from the definition of BES. If so then this generation exclusion is appropriate to the FERC order. However,
the definition of “automatic interruption device” should be defined fully. Specifically what types of equipment
are considered an AID? If a transformer has a high side voltage of 115 kV and a low side voltage of 34.5 kV
it would not be part of the BES definition, however depending on how one interprets the exclusion for a radial
feed, if the transformers automatic interruption device were on the low side of this transformer, it appears that
this transformer would then need to be “included” as BES.
In addition, would the protection schemes associated with the breaker failure on the low side of a transformer
(voltage <100 kV) designed to send a signal to the high side (which is greater than 100KV) for a breaker
failure scenario fall into the “included” facilities even though the transformer would not be “included”?

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the respondents. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.
In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local networks. The SDT
realizes that a bright-line definition may require entities to seek exceptions through the Rules of Procedure exception process. This BES definition does not
address protection or control systems. Standards and requirements can be written against components that are not BES Elements.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.

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Organization
Electric Reliability Council of
Texas, Inc.

Yes or No

Question 7 Comment

No

See response to question 1 - while ERCOT ISO does not necessarily disagree with the substance of the
proposed exclusions, it believes all exceptions should occur pursuant to the separate processes and criteria
being developed that will be established in the NERC ROP. The BES definition should be more general in
nature, focusing on objective thresholds. All exclusions should be addressed in the separate proceeding
being conducted in parallel with this proceeding to develop the exception process, and ERCOT ISO reserves
its right to comment on the substance of such proposals in that proceeding.

Southwest Power Pool

Response:
Please see response to Q1.
The SDT has developed a draft core definition, together with BES designations (Inclusions and Exclusions) that provide the specificity necessary to identify the
vast majority of BES Elements by utilizing the existing definition and criteria previously approved for this purpose. The remaining facilities will be candidates for
the Exception Process (RoP) where the Technical Principles will be utilized to determine if the facility is necessary for the reliable operation of the interconnected
transmission network.
Fayetteville Public Works
Commission

No

Exclusion E1 references Inclusions I2 and I3. Therefore the comments provided in Question 3 with respect to
Inclusion I2 are pertinent here as well. The radial system cannot be excluded if it includes any generation
resources that are included in Inclusion I2. The ambiguity that exists in Inclusion I2 could, therefore, also
have consequences in determining if a radial system can be excluded. If the recommended changes are
made in Inclusion I2 then Exclusion E1 is acceptable as is.

Response: The SDT believes these changes provide clarification to how the Exclusions and Inclusions are related. If a generation resource is included in the
Inclusions then it can not be excluded by the Exclusions. In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used
for multiple connections serving local networks. The SDT realizes that a bright-line definition may require entities to seek exceptions through the Rules of
Procedure exception process.
BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

No

BGE generally agrees with the “radial” exclusion, but votes “NO” due to a lack of clarity. The definition does
not make it clear if radial facilities operating above 100 kV with automatic interrupting devices (which would
otherwise be classified as non-BES under exclusion E1, part a) and serving networks operating below 100 kV
are classified as non-BES. We believe E1 should make it clear that such radial facilities are non-BES. BGE
would like to note that under the current RFC BES definition, such facilities are not designated as BES.To
illustrate and clarify the BGE questions, please see the BGE Diagram attached. The BES designations
included on the diagram are BGE’s interpretation of BES facilities under the proposed definition.
Questions regarding the BGE Diagram:1. If the 13.8 kV device TB is operated “normally closed” as shown, is
it the SDT’s understanding that the two 115 kV lines classified as Non-BES in the diagram are no longer

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Organization

Yes or No

Question 7 Comment
considered “radial”?
2. If the SDT does not consider the two 115 kV lines described above as “radial” with device TB closed, would
this configuration be excluded as BES under exclusion E3? Or would the Exception Process be required to
classify such a configuration as non-BES?
See diagram at end of report.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.

The SDT is not in a position to provide advice on specific cases.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Springfield Utility Board

August 19, 2011

No

SUB agrees with the exclusion for radial systems, but would like clarification regarding the definition of
“radial”. SUB appreciates NERC developing a more clear and consistent definition of “radial”. For clarity,
SUB suggests the following language:” o Exclusion E1 - Any radial system which is described as connected
from a single Transmission source originating with an automatic interruption device and that is characterized
by any of the following:a)Only serving Load. A normally open switching device between radial systems with
the same or different transmission sources may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Systems with a normally open switching
device(s) that would otherwise result in a system with more than one transmission source if the switching
device(s) is closed are considered radial systems. Or,b)Only including generation resources not identified in

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Organization

Yes or No

Question 7 Comment
Inclusions I2, I3, I4 and I5. Or,c)Is a combination of items (a.) and (b.) where the radial system serves Load
and includes generation resources not identified in Inclusions I2, I3, I4 and I5?”
As a side note, some in the industry appear to place a demarcation based on whether there is a fuse
separating two systems. SUB is concerned with interpretations that indicate that if there is a fuse, they are
separate. This could result in “closed” systems being considered “open” because there are fuses installed
within the network. For example, consider a 115 kV interconnection point stepped down to distribution level
service with a fuse continues along the distribution network to another fuse that is interconnected to a 115kV
system with another transmission source. Is this fused system closed or open? Is this an intended outcome?
SUB is hopeful that E1 will provide clarity to this issue.

Springfield Utility Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.
In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local networks. The SDT
realizes that a bright-line definition may require entities to seek exceptions through the Rules of Procedure exception process. This BES definition does not
address protection or control systems. Standards and requirements can be written against components that are not BES Elements. The SDT does not specify the
type of normally open switch that will be used to separate the systems described in Exclusion E1 but understands that any such switch needs to be operated in
such a fashion that insures safety, utilizes the best operating practices, and maintains reliability. Fuses are not considered normally open switches.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV

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Organization

Yes or No

Question 7 Comment

or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Southern California Edison
Company

No

SCE cannot support this exclusion as it will only apply if generation on the radial system does not exceed the
criteria identified in I2, I3 and I5. SCE has identified its concerns regarding these aforementioned items in its
previous responses.If the SDT goes forward with E1 criteria, the criteria should be modified as follows:
(i) Delete “originating with an automatic interrupting device.” This statement does not change or describe the
flow to or from a radial system;
(ii) E1 should be modified to identify that generation interconnected to a radial system should not exceed a
measureable threshold of electrical demand on the radial system - an example being “5% occurrence in the
past XXX years”. This would negate some of the concerns identified regarding I2, I3 and I5; and
(iii) SCE also feels that if the core BES definition is to reference protection devices, it should not identify the
particular type of protection device as it did in E1, by specifically calling out “make before break” switching, as
there are other types of protection with similar functionality.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular, the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the
normally open switch to a note, and clarified the generation allowed within the system.
In particular, the SDT has changed the inclusions to further specify what generation resources are included in a radial (refer to Exclusion E1 and Inclusion I3).
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

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Organization

Yes or No

Question 7 Comment

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Cogentrix Energy, LLC

No

This exclusion is acceptable if the suggestions in Questions 3 and 4 are incorporated.

Response: Please see responses to Q3 & 4.
PPL Energy Plus and PPL
Generation

No

See comments in Question 13

No

We agree with the concept of a allowing a radial exclusion from the BES. However, we ask that the term
“device” be modified to include the optional plural; “device(s).” Some radial systems may require isolation by
more than one automatic interrupting device.

Response: See response to Q13.
Consolidated Edison Co. of NY,
Inc.

Response: The SDT has eliminated the automatic interrupting device qualification.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

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Organization

Yes or No

Question 7 Comment

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
MEAG Power

No

The definition of Exclusion E1 does not cover radial systems that are connected to a single transmission
source by more than one automatic interruption device, such as occurs with a “breaker-and-a-half”
arrangement. The definition should be modified as follows:”Any radial system which is described as
connected from a single Transmission source originating with one or more automatic interruption devices and:
....
”This exclusion uses many terms that are not defined under NERC’s standard definitions: “radial load”,
“automatic interruption device” and “make-before-break”. If these terms are used to define an exclusion and
can be understood or interpreted differently by different people, then the terms should be formally defined.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.
In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local networks.
The terms in question are no longer used.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Independent Electricity System
Operator

August 19, 2011

No

Again, we agree with the goal of E1 but we repeat the same concerns expressed in our responses to Q1 and
Q3 with respect to the generation capacity thresholds. A majority of the transmission elements excluded by
E1 would already be excluded by E3 and, therefore, E1 may be redundant. The SDT may wish to consider
combining Exclusion E1 with Exclusion E3, modified as proposed in our response to Q9.

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Organization

Yes or No

Question 7 Comment
In Exclusion E1, we suggest changing “automatic interruption device” to “automatic fault-interrupting device”
for consistency with E3(a).

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular, the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the
normally open switch to a note, and clarified the generation allowed within the system.

In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local networks and there
are sufficient differences between radial systems to warrant Exclusions E1 and E3.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
BPA

No

August 19, 2011

Exclusions E1 and E3 use the similar yet different terms “automatic fault interruption device” and “automatic
fault interrupting device” respectively to refer to the specific type of device that must be used to separate the
excluded area from the BES. Neither “automatic interruption device” nor “automatic fault interrupting device”
are specifically defined in the NERC Glossary; leaving them up to auditor interpretation. From a compliance
perspective, the fact that different terms are used seems to lead to a conclusion that different types of devices
are being referred to in each case. However, given the technical characteristics of these exclusions, we are
not able to discern how these devices might differ when used to isolate a “radial system” or a “Local
Distribution Network”, from the BES, as defined in E1 and E3 respectively. BPA would like to see the definition
of “automatic fault interruption device” and “automatic fault interrupting device” If the intention is to refer to the
same set of devices as being acceptable for E1 exclusion of Radial Systems and E3 exclusion of Local
Distribution Networks, then please modify the language to be identical in each case. If the intention is to refer
to a difference in the types of devices acceptable for providing separation from the BES in each case, then

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Organization

Yes or No

Question 7 Comment
please modify the language as necessary to further clarify the specific intention in a manner that enables
consistent interpretation and application by auditors from the full spectrum of backgrounds and perspectives. If
necessary, we further recommend that the drafting team consider creating a specific defined term (or 2) to add
to the NERC Glossary that provides specific clarification to a clear and consistent manner in which these
exclusions are to be applied.
BPA would also like to point out a possible way to make E1 more clear – “Any radial system which is
connected to a single Transmission source which connection originates with an automatic interruption device
and . . .”
BPA seeks clarification on whether, if a normally open breaker is switched in-service, it can still be
considered radial. BPA understands this to mean that if a normally open switch is closed to maintain load
service until the original source is disconnected, the system may still be considered radial.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.
Your assumption is correct. The SDT does not specify the type of normally open switch that will be used to separate the systems described in Exclusion E1 but
understands that any such switch needs to be operated in such a fashion that insures safety, utilizes the best operating practices, and maintains reliability.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Tacoma Power

August 19, 2011

Tacoma Power supports Exclusion E1.

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Organization

Yes or No

Question 7 Comment

Response: Thank you for your support.
Chevron Global Power, a division
of Chevron U.S.A. Inc.
PacifiCorp

See response to question 13

Yes

: Please refer to additional comments in question 13 regarding a contiguous BES.

Response: See response to Q13.
ATCO Electric

Is a load substation categorized as a "radial substation" if its 144kV bus connects to another 144kV bus at an
adjacent substation via two 144kV parallel transmission lines?

Response: The SDT is not in position to respond to this question as more information may be required to make a proper determination.
City of Redding

Yes

Redding supports this high level exclusion of Radial systems as a clarification to the Brightline definition as
long as it is part of the SDT’s overall plan to make a clear distinction between distribution and transmission
facilities. Redding’s support rests on the assumption that the SDT will adequately address the distribution and
transmission facilities issue via the Exception Process. There needs to be a fair and equable method where
radial elements that do not meet this criterion can be identified as distribution acilities. This will hinge on the
ability of the SDT to adequately address the two major issues: clarify the term “necessary for operating the
interconnected transmission network” and to “establish whether a particular facility is local distribution or
transmission”.

Response: The SDT has clarified the core definition in this regard.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Western Electricity Coordinating
Council

Yes

WECC generally agrees in concept. However, it is unclear what is required to demonstrate the “make-beforebreak” connection. Is this intended to mean that the normally-open switch is mechanically or electrically
interlocked to ensure the “make-before-break” requirement is met?
It would be a normal switching practice to close the normally-open switch to make the parallel before opening
the normally-closed switch, but is the normal switching practice sufficient to make this claim?

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Organization

Yes or No

Question 7 Comment
Also, it is unclear whether the automatic interruption device itself is a part of the BES.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.
The SDT does not specify the type of normally open switch that will be used to separate the systems described in Exclusion E1 but understands that any such
switch needs to be operated in such a fashion that insures safety, utilizes the best operating practices, and maintains reliability.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, or I4
and I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Cowlitz County PUD

Yes

FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained. Cowlitz believes the exclusion as drafted adequately defines radials. Further, we would point out
that two transmission systems that are operated radial with a normal open between them can’t be operated
reliably with the normal open indefinitely closed. Such extended closures are not possible were transmission
protection systems are not designed for networked systems.

New York State Dept of Public
Service

Yes

We agree with exclusion E1. As described, the facilities are clearly local distribution. Requiring a “makebefore-break” switching device, between the BES and the excluded radial system, as a condition-precedent
for such exclusion is proper. Such switches are necessary to promote reliable operation by enabling removal
of radial systems principally serving load for maintenance and other reliable system operations. If the “makebefore-break” switching capability is not included as part of the exclusion, the specification would undermine
reliable system operation.

Sierra Pacific Power Co d/b/a NV

Yes

Agree with this exception and emphasize that the make-before-break language is essential to be retained in

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Organization

Yes or No

Energy

Question 7 Comment
this exclusion.

Sweeny Cogeneration LP

Yes

We agree that all radial connections serving a single load, small generator, or combination should be
excluded

Western Montana Electric
Generating and Transmission
Cooperative

Yes

FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained. We believe the exclusion as drafted adequately defines radials.

Public Utility District No. 1 of
Snohomish County, Washington
Blachly Lane Electric Cooperative
Northern Wasco County PUD
Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc.
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc.
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric

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Organization

Yes or No

Question 7 Comment

Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Clallam County PUD No.1
Chelan PUD – CHPD
Kootenai Electric Cooperative
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Central Lincoln
Northwest Requirements Utilities
Imperial Irrigation District

Yes

Santee Cooper

Yes

SERC Planning Standards
Subcommittee

Yes

ACES Power Participating
Members

Yes

Overton Power District No. 5

Yes

Arizona Public Service Company

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

Southern Company

Yes

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Organization

Yes or No

Western Area Power
Administration

Yes

US Bureau of Reclamation

Yes

Glacier Electric Cooperative

Yes

South Texas Electric
Cooperative, Inc.

Yes

Portland General Electric
Company

Yes

South Texas Electric
Cooperative, Inc.

Yes

Dayton Power and Light
Company

Yes

Alberta Electric System Operator

Yes

South Carolina Electric and Gas

Yes

Farmington Electric Utility System

Yes

Colorado Springs Utilities

Yes

Consumers Energy Company

Yes

Puget Sound Energy

Yes

Clark Public Utilities

Yes

Pepco Holdings Inc

Yes

August 19, 2011

Question 7 Comment

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Organization

Yes or No

PJM

Yes

Oncor Electric Delivery Company
LLC

Yes

Manitoba Hydro

Yes

City of Anaheim

Yes

Xcel Energy

Yes

Orange and Rockland Utilities,
Inc.

Yes

Question 7 Comment

Response: Thank you for your support. The SDT believes that the changes made to the wording of the definition based on comments received will provide
clarity and address the concerns provided by the respondents. In particular the SDT clarified the point of connection, removed the automatic interrupting device,
moved the concept of the normally open switch to a note, and clarified the generation allowed within the system.

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8. The SDT has added specific exclusions to the core definition in response to industry comments. Do you agree
with Exclusion E2? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: The SDT believes that Exclusion E2 should be dedicated to the situation faced by behind-the-meter (i.e., retail
customer owned) generation that are PURPA qualifying facilities (in the US) (e.g., see 18 CFR Part 292 for the regulations that are applicable in
the US).and similarly situated generators in Canada. Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to
qualifying facilities. The SDT believes that condition (ii), which requires that the generation serving the retail customer load self provide reserves,
is essential for the integrity of the exclusion. The references to Inclusions I2 and I3 in Exclusion E2 have been deleted. Exclusion E2 now
designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA. The SDT has
also modified Exclusion E3 to make non-retail generation in a local network (LN) subject to a comparable exclusion designation as that for
customer-owned generation in Exclusion E2.
Due to industry comments, some slight changes were made for clarity:
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of
connection of 100 kV or higher from a single Transmission source originating with an automatic interruption device and:
a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow
for reliable system reconfiguration to maintain continuity of electrical service. Or,
b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to
75 MVA (gross nameplate rating). Or,
c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in
Inclusions I2, I3, I4 and I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example does not affect
this exclusion.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the
retail meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, backup, and maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or provided pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under
terms approved by the applicable regulatory authority.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that
distribute power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection
at 100 kV or higher are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail
customer Load and not to accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:

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Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in
Inclusion I3 and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate),
includes more than 75 MVA generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the
LDN The LN does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored
Facility in the ERCOT or Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).

Organization
Tri-State Generation and
Transmission Association, Inc.

Yes or No
No

Question 8 Comment
This Exclusion should also include “wholesale” meters for the instance where an electric distribution
cooperative has some small generation connected to its distribution system that meets the same criteria.

Response: The SDT believes that Exclusion E2 should be dedicated to the situations faced by behind-the-meter (i.e., retail customer owned) generation that are
PURPA qualifying facilities (in the US) and similarly situated generators in Canada. For example, see 18 CFR Part 292 for the regulations that are applicable in the
US. Exclusion E2 has also been clarified by replacing the reference to “retail Load” with “retail customer Load.”
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
NERC Staff Technical Review

No

The second condition (ii) in E2 is confusing. While the condition is appropriate and has specific meaning, the
meaning will not be readily understood by most users of the definition. This condition should be clarified.

SPP Standards Review Group

No

We think we may concur with E2, but we are uncertain as to what is included in (ii). Could you please clarify?

Response: Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying cogeneration and small power production

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Organization

Yes or No

Question 8 Comment

facilities. For example, see 18 CFR §292.101 and §292.305(b) for the requirements specific to the US. The SDT believes that the meaning of the definition will be
understood in Balancing Authority Areas where it is applicable. No change made.
SERC Planning Standards
Subcommittee

No

While we agree with the first part of E2, but we do not see the rationale for section (ii) and suggest it be
deleted.

Response: The SDT believes that condition (ii) in Exclusion E2, which requires that the generation serving the retail customer load self provide reserves, is
essential for the integrity of the exclusion. No change made.
SERC OC Standards Review
Group

No

This exclusion is acceptable if the suggestions in Questions 3 and 4 are incorporated.

Cogentrix Energy, LLC

No

This exclusion is acceptable if the suggestions in Questions 3 and 4 are incorporated.

No

We do not agree with E2(i). If the generation assets listed in the inclusions of I2 and I3 are not permitted to
be excluded in E2, then what is the point of E2? The generation assets would already be in or out based
upon the registry's MVA nameplate capacity. We would support E2 if provision (i) were struck.

Response: See response to Q3 & 4.
Idaho Falls Power

If generation assets are behind the meter on a local distribution network (fitting the criteria E3 for exemption)
then too the generation should be exempted regardless of MVA rating.
Moreover, we do not agree that there is a brightline MVA threshold of materiality to the BES. We would hope
that the drafting team could demonstrate how the 20MVA brightline is a valid threshold for generation while
the 100kV for transmission is not.We are concerned that relatively small generation on a local distribution
network wherein generation is always serving local retail load behind the meter will be labelled a BES asset.
As such, then is the LDN to the point of interconnection a BES asset as well, and therefore subject to the
suite of TO/TOP standards? We feel such an outcome is unreasonable. It seems to us, as is stated under
section 215 of the FPA, that the term BES "does not include facilities used in the local distribution of electric
energy." To a logical conclusion, the generation attached to local distribution was considered and is intended
to be one of the "facilities" and should therefore be exempted form inclusion in the BES. However, should the
drafting team deem that all generation above 20MVA are a BES assets, we would hope that the exclusion for
Local Distribution Networks could still stand and that the generation on the LDN would be divorced and
defined separately. Our opinion is the BES is not one large contiguous system, but is rather comprised of
assets across the region, which due to their size or location are vital to a sound BES but are not necessarily
connected to each other. This principle would allow the generation to be regulated yet remove the burden of

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Organization

Yes or No

Question 8 Comment
transmission standards from small entities.

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
The SDT has also modified Exclusion E3 to make non-retail generation in an LN subject to a comparable exclusion designation as that for customer-owned
generation in Exclusion E2.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3 and do
not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
The SDT has changed Inclusion I2 to simply reference the ERO Statement of Compliance Registry Criteria.
Tennessee Valley Authority

No

We suggest adding a reference to “I5” in the (i) section as follows: “the net capacity provided to the BES does
not exceed the criteria identified in the inclusions I2, I3, or I5.”

Response: The SDT believes that situations where the resources captured in Inclusion I5 directly serve its own Load are extremely rare and therefore may be
demonstrated in the Exception Process. No change made.

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Organization

Yes or No

Question 8 Comment

Western Montana Electric
Generating and Transmission
Cooperative

No

As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through reference
to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the generation unit is
reliability-must-run or essential blackstart, the function of the unit is irrelevant to the reliable operation of the
interconnected bulk transmission grid, and we therefore believe the reference to the function of the generation
unit (“standby, back-up, and maintenance power...”) should be eliminated.

Northern Wasco County PUD

No

As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through reference
to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the generation unit is
reliability-must-run or essential blackstart, the function of the unit is irrelevant to the reliable operation of the
interconnected bulk transmission grid, and we therefore believe the reference to the function of the generation
unit (“standby, back-up, and maintenance power...”) should be eliminated.

Chelan PUD – CHPD
Public Utility District No. 1 of
Franklin County
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc
Midstate Electric Cooperative
Cowlitz County PUD

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
The SDT believes that condition (ii) in Exclusion E2, which requires that the generation serving the retail customer Load self provide reserves, is essential for the
integrity of the exclusion.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Southern Company

No

Section (i) is confusing because it mixes MW with MVA. The net capacity in section (i) would be in MW while
the values referenced in I2 and I3 would be in MVA. This will create confusion.
Also, we do not see any need for section (ii). Section (i) is sufficient without section (ii).
We recommend Exclusion E2 to be re-written as follows:Exclusion E2 - A generating unit or multiple
generating units that serve all or part of retail Load with electric energy on the customer’s side of the retail
meter if the net capacity provided to the BES does not exceed 20 MW for a single generating unit or 75 MW

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Organization

Yes or No

Question 8 Comment
for multiple generating units located at a single site.

Response: The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed
relevant to the exclusion, not the nameplate rating. No change made.
The SDT believes that condition (ii) in Exclusion E2, which requires that the generation serving the retail customer Load self provide reserves, is essential for the
integrity of the exclusion. No change made.
Exclusion E2 has been revised due to industry comments:
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Central Maine Power Company

No

New York State Electric & Gas
and Rochester Gas & Electric

E2 refers to “net capacity provided to the BES” (which seems to be a flow on an interconnection, not
generator capacity), yet I2 and I3 refer to generator MVA. These are not the same unit which leads to
inconsistency.This Exclusion appears to add confusion or additional criteria to that of the Compliance
Registry.We recommend that E2 be stricken.

Response: The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed
relevant to the exclusion, not the nameplate rating. No change made.
Intellibind

No

This is very confusing. Understanding the Drafting Team's goal, it would better to adjust the I2 and I3 criteria
to address NET generation and behind the meter generation.
E2 appears to try and address the net generation versus nameplate issue, but not fully. Station service power
is behind the meter and it is a commitment of the resource. Many small generators have multiple processes
outside of power generation they must provide for, and these should be considered in the exceptions.

Response: The SDT believes that Exclusion E2 should be dedicated to the situations faced by behind-the-meter (retail customer owned) generation that are
PURPA qualifying facilities (in the US) and similarly situated generators in Canada. Exclusion E3 has been modified to accommodate non-retail generation in the
LN. Exclusion E2 has also been clarified by replacing the reference to “retail Load” with “retail customer Load.”
The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed relevant to
the exclusion, not the nameplate rating.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail

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Organization

Yes or No

Question 8 Comment

meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting
devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3 and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
US Bureau of Reclamation

No

The term "retail load" is ambiguous and unnecessary. The term should be changed to "load". The change is
justified by the conditions (i) and (ii) placed on the generators.

Springfield Utility Board

No

The proposed language for Exclusion E2 refers to the “customer’s side of the retail meter”. There may be
multiple customers with different resources within the geographic area served by a Registered Entity.
Because E2 also refers to “net capacity provided to the BES”, SUB assumes that E2 is intended to address
resources within the Registered Entity that are served to a single customer or multiple customers. A
Registered Entity may have Elements that are separate and independent but that are connected to the BES.
Individually, these elements may not have resources that serve customer load that meet I2 or I3, but
collectively the sum or resources and elements served do meet I2 or I3. SUB believes that the issue of
reliability comes down to both resources, load served, and what paths are shared (or not) between resources
and loads. SUB suggests that isolated loads and resources that are functionally independent from a

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Organization

Yes or No

Question 8 Comment
Registered Entities overall system do not need to be added together.
SUB suggests the following language: “A generating unit or multiple generating units that serve all or part of
retail Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity along shared
Elements provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and (ii) standby,
back-up, and maintenance power services are provided to the generating unit or multiple generating units or
to the retail Load pursuant to a binding obligation with a Balancing Authority or another Generator
Owner/Generator Operator, or under terms approved by the applicable regulatory authority. For purposes of
this exclusion, if a Registered Entity is responsible for elements that serve loads and resources that are
separate from other elements that the Registered Entity is responsible for, then each set of loads and
resources that are connected to Elements the Registered Entity is responsible for shall be evaluated
separately and resources will not be added together.While Springfield Utility Board does not own any
generating units, we do recognize the importance of the restoration of the Grid, and the generation necessary
for the Grid.

Springfield Utility Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: The SDT believes that Exclusion E2 should be dedicated to the situations faced by behind-the-meter (retail customer owned) generation that are
PURPA qualifying facilities (in the US) and similarly situated generators in Canada. Exclusion E3 has been modified to accommodate non-retail generation in the
LN. Exclusion E2 has also been clarified by replacing the reference to “retail Load” with “retail customer Load.”
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided

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Organization

Yes or No

Question 8 Comment

pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3 and do
not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Sweeny Cogeneration LP

No

Generators which serve local retail load (cogeneration) should be excluded if the net capacity available to the
BES does not exceed 20 MW Single Unit/75 MW Multiple Units thresholds. We believe there are further items
to be added to the list related to generator interconnections, a task that was passed to this project from
Project 2010-07. Just as is the case with complex distribution systems, there are a variety of generatortransmission interconnection architectures which are driving the Regions to inappropriately register Generator
Owner/Operators as Transmission Owners.

Response: The SDT is aware of Project 2010-07 (“Generator Requirements at the Transmission Interface”) and believes that this SDT should not attempt to
duplicate that effort. A primary objective of Project 2010-17 is to clarify the BES definition, make it more transparent, and eliminate regional discretion with
respect to the definition. No change made.
Electric Reliability Council of
Texas, Inc.

No

See response to question 7.

Southwest Power Pool

No

See response to question 7.

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Organization

Yes or No

Question 8 Comment

Response: See response to Q7.
South Carolina Electric and Gas

No

We agree with the first part of E2, but we do not see the rationale for section (ii) and suggest it be deleted.

Central Lincoln

No

We support excluding behind the meter generation below the limits, but the string of “ands” and “ors” in this
exclusion are far too confusing with numerous ways to parse them. Suggest eliminating bullet (ii) since the
existence of obligations has no bearing on impact.

NERC Transmission Issues
Subcommittee (TIS)

PUD No. 2 of Grant County,
Washington

The last sub-bullet in E2 is terribly confusing. The TIS does not offer alternate wording because we are
unsure of the meaning of the phrase: >>>>>>>>>> “...pursuant to a binding obligation with a Balancing
Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.”
Yes

Unless the generation unit is reliability-must-run or essential blackstart, the function of the unit is irrelevant to
the reliable operation of the interconnected bulk transmission grid, and we therefore believe the reference to
the function of the generation unit (“standby, back-up, and maintenance power...”) should be eliminated.

Response: Condition (ii) in Exclusion E2 is derived from FERC and provincial regulations applicable to qualifying cogeneration and small power production
facilities. For example, see 18 CFR Part 292 for the regulations that are applicable in the US. The SDT believes that condition (ii), which requires that the
generation serving the retail customer Load self provide reserves, is essential for the integrity of the exclusion. No change made.
Southern California Edison
Company

No

City of Redding

Yes

August 19, 2011

SCE does not believe that the size of generator should dictate what system facilities, regardless of voltage,
will or will not be included in the BES definition. More important, is the issue of whether or not the generation
has net flow(s) out to the greater integrated networked transmission system. It is the “generation” and not the
“generator” which has impacts on the BES.In addition, it would seem that if these are truly “behind-the-meter”,
non-export interconnected generation, then there is no scenario that would result in flow back onto the BES,
no matter what the interconnection level. The focus should not be restricted to only “behind-the-meter”
generation, but rather on the flow generation from the radial system.
Redding agrees that generators located in close proximity to the end user should be classified as distribution
load modifier generators. Additionally, Redding believes small utilities that have distinct metered boundaries
with installed generation intended to serve their customers (load displacement generators) should receive the
same exclusion as generators behind retail meters. These generators installed on distribution facilities are
almost identical to the generating units in Exclusion E2: “a generating unit or multiple generating units that
serve all or part of retail Load with electric energy on the customer’s side of the retail meter if: (i) the net
capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and (ii) standby,

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Question 8 Comment
back-up, and maintenance power services are provided to the generating unit or multiple generating units or
to the retail Load pursuant to a binding obligation with a Balancing Authority or another Generator
Owner/Generator Operator, or under terms approved by the applicable regulatory authority.” A local
distribution network that is owned by a utility is directly serving load to the end user (retail customer), it has
meters at the network boundaries where bulk power is transferred from the BES network to the distribution
facilities, it has binding obligations with the BA or Reserve Sharing Group, to provide reserves (back up
power), and meets the net capacity requirement. The distribution facilities are technically retail load to the
BES network if owned by the retail user (example would be a Municipal, Public Utility District, Irrigation
District, etc.).
Redding has three suggestions to address our concerns:
1. The language in Exclusion E2 could be changed:
From: “electric energy on the customer’s side of the retail meter”
To: “electric energy on the customer’s side of the retail, or distribution system, meter(s)”. This change will
provide an equable exclusion for the small utility and for generation directly dedicated to local distribution
load.
OR
2. The LDN characteristic #b in Exclusion E3 could have the limits of generation removed and modified to
read “the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I3”
(identical to the language in E2).
3. The SDT address this issue via the Exception Process by specifically creating an exception that
addresses generation in a LDN used as a load modifier.

Response: The SDT believes that Exclusion E2 should be dedicated to the situations faced by behind-the-meter (i.e., retail customer owned) generation that are
PURPA qualifying facilities in the US and similarly situated generators in Canada. Exclusion E3 has been modified to accommodate non-retail generation in the LN.
The SDT has merged Inclusion I2 and Inclusion I3 and therefore Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides
net capacity to the BES that does not exceed the criteria identified, which is greater than 75 MVA. The SDT has merged Inclusion I2 and Inclusion I3 and
therefore Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed the criteria
identified, which is greater than 75 MVA.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable

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Yes or No

Question 8 Comment

regulatory authority.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3 and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Clark Public Utilities

No

As indicated by Clark in its comments on the core definition of the BES, Clark believes the 20 MVA and the 75
MVA thresholds lack adequate technical justification and are a purely arbitrary quantities. The use of a
capacity thresholds in the definition of the BES should have technical reasons.

Response: The MVA thresholds were adopted from the Statement of Compliance Registry Criteria. Exclusion E2 now designates for exclusion relevant behindthe-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
The Dow Chemical Company

August 19, 2011

No

Clause (ii) should be revised as follows: "(ii) standby, back-up, and maintenance power services are provided
to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or pursuant to
a binding obligation with another Generator Owner/Generator Operator, or under terms approved by the
applicable regulatory authority."

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Question 8 Comment

Manitoba Hydro

No

It is not clear what is meant by “retail Load”. This is not a NERC defined term. Additional detail is required.

Florida Municipal Power Agency

Yes

We understand that E2 is intended to apply only to retail customers’ generation. The exclusion should
therefore be revised to make that limitation clear. Specifically, the first sentence should read: “A generating
unit or multiple generating units that serve all or part of retail customer Load with electric energy on the retail
customer’s side of the retail meter.

Transmission Access Policy
Study Group

Yes

We understand that E2 is intended to apply only to retail customers’ generation. The exclusion should
therefore be revised to make that limitation clear. Specifically, the first sentence should read: “A generating
unit or multiple generating units that serve all or part of retail customer Load with electric energy on the retail
customer’s side of the retail meter.”

Northern California Power
Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.

Michgan Public Power Agency

Yes

I understand that E2 is intended to apply only to retail customers’ generation. If that is the case then I would
suggest the following changes be made to make that limitation clear. Specifically, the first sentence should
read: “A generating unit or multiple generating units that serve all or part of retail customer Load with electric
energy on the retail customer’s side of the retail meter.”

Response: Exclusion E2 was modified to reflect your recommendation.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
ISO New England, Inc.

No

E2 refers to net capacity and yet I2 and I3 refer to MVA. These are not the same unit which leads to
inconsistency.
This Exclusion appears to add additional criteria than that of the Compliance Registry; we suggest simply
using the language from the Compliance Registry.

Response: The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed
relevant to the exclusion, not the nameplate rating. Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to

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Yes or No

Question 8 Comment

the BES that does not exceed 75 MVA.
Clarification of the original language adopted from the Statement of Compliance Registry Criteria (SCRC) was in response to industry comments.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Independent Electricity System
Operator

No

Again, we echo the same comments stated in our responses to Q1 and Q3. We do not agree with the
Exclusion E2 for the very same reasons specified in responses to questions 3, 4, and 6. Additionally, we are
not clear of the intent for the restriction stated in Exclusion E2 (ii).

Response: See responses to Q1, Q3, Q4 and Q6. Condition (ii) in Exclusion E2 is derived from FERC and provincial regulations applicable to qualifying
cogeneration and small power production facilities. For example, see 18 CFR Part 292 for the regulations applicable in the US. The SDT believes that condition
(ii), which requires that the generation serving the retail customer Load self provide reserves, is essential for the integrity of the exclusion. No change made.
Utility System Efficiencies, Inc.

No

As noted in USE's response to Question 3, we believe the inclusion of the 20 MVA threshold (through
reference to Inclusion I2) lacks an adequate technical justification in this context.
In addition, whether or not there is provision of standby, back-up, and maintenance power services to the
unit(s) or the load is irrelevant to the reliable operation of the interconnected bulk transmission grid, and we
therefore believe the item (ii) in this Exclusion should be eliminated.

Blachly Lane Electric Cooperative
Central Electric Cooperative
Clearwater Power Company

As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an adequate
technical justification. Further, unless the generation unit is reliability-must-run or essential blackstart, the
function of the unit is irrelevant to the reliable operation of the interconnected bulk transmission grid, and we
therefore believe the reference to the function of the generation unit should be eliminated.

Consumers Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative

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Yes or No

Question 8 Comment

Yes

As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through reference
to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the generation unit is
reliability-must-run or essential blackstart, the function of the unit is irrelevant to the reliable operation of the
interconnected bulk transmission grid, and we therefore believe the reference to the function of the generation
unit (“standby, back-up, and maintenance power...”) should be eliminated.

Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Clallam County PUD No.1
Public Utility District No. 1 of
Snohomish County, Washington

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
Condition (ii) in Exclusion E2 is derived from FERC and provincial regulations applicable to qualifying cogeneration and small power production facilities. For
example, see 18 CFR Part 292 for the regulations applicable to the US. The SDT believes that condition (ii), which requires that the generation serving the retail
customer Load self provide reserves, is essential for the integrity of the exclusion.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.

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BPA

Yes or No
No

Question 8 Comment
BPA seeks clarification on exactly what “net capacity provided to the BES” means.
BPA would like to suggest a minor clarification in brackets below:
A generating unit or multiple generating units located on, and that serve all or part of retail Load with electric
energy on, the customer’s side of the retail meter if: (i) the net capacity provided to the BES does not exceed
the criteria identified in Inclusions I2 or I3 or I5 and (ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load pursuant to a binding
obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms
approved by the applicable regulatory authority.

Response: Exclusion E2 is dedicated to the situations faced by behind-the-meter (retail customer owned) generation that are PURPA qualifying facilities in the
US and similarly situated generators in Canada. While the criteria in Inclusions I2 and I3 were based on gross nameplate ratings in MVA, the first condition (i) in
Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed relevant to the exclusion, not the
nameplate rating. The “net capacity provided to the BES” is the behind-the-meter generation that exceeds the Load directly served by the generator. The SDT
believes that situations where the resources captured in Inclusion I5 directly serve its own load are extremely rare and should therefore be demonstrate in the
Exception Process. No change made.
Georgia System Operations

How is “net capacity provided to the BES” measured (e.g., by nameplate capacity minus peak load, by actual
generated energy - rather than capacity - minus actual load at each moment or over some period of time,
etc.)? It is possible that a larger than currently necessary generator may be installed in anticipation of future
load growth, but that it is never used to generate significantly more than what is needed for load. Depending
on how “net capacity” is calculated, such a generator might unnecessarily be pulled into the BES.

Response: The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed
relevant to the exclusion, not the nameplate rating. Regardless of the nameplate rating of the generator(s), the “net capacity” is the behind-the-meter generation
that exceeds the Load. No change made.
Tacoma Power

Tacoma Power generally supports Exclusion E2. However, no justification for the 20 MVA and 75 MVA levels
in Inclusion I2 and Inclusion I3 have been provided and therefore they appear arbitrary. Since this
measurement will define Elements for absolute inclusion in the BES, the thresholds should be based on a
need to maintain transmission reliability. We strongly urge the SDT to accept our proposed changes to
Inclusion I2 and Inclusion I3, listed above in items 3 and 4.

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
See responses to Q3 and Q4.

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Yes or No

Question 8 Comment

E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Dominion

Yes

Dominion agrees with Exclusion E2 because we agree that specific criteria can be applied and will indicate
the Element or Facility is not necessary for operating an interconnected electric energy transmission network
or is needed to maintain transmission system reliability. . However Dominion suggests that the SDT add a
defined interval of time for measurement of net capacity so that planners can be assured that the exclusion
should really be applied at the location. Dominion suggests use of an hour as the time increment.

Response: The SDT believes that the context of “net capacity” is understood and no change is necessary.
American Municipal Power and
Members

Yes

We understand that E2 is intended to apply only to retail customers’ generation. The exclusion should
therefore be revised to make that limitation clear. Specifically, the first sentence should read: “A generating
unit or multiple generating units that serve all or part of retail customer Load with electric energy on the retail
customer’s side of the retail meter.”
In addition, the first condition of exclusion, (i), "the net capacity provided to the BES does not exceed the
criteria identified in Inclusions I2 or I3," as written is vague and could be subjectively applied. I2 limits
capacity supplied to the BES to 20MVA while I3 limits that capacity to 75MVA. A better way to state the
exclusion would be as follows: (i), "the net capacity provided to the BES does not exceed the retail
customer's total nameplate generation, or 75MVA, whichever is greater,".

Response: The term “retail Load” had been replaced with “retail customer Load.”
Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Hydro One Networks Inc

August 19, 2011

Yes

We agree with most of the changes in Exclusion E2. However, we feel there is a need for evidence or
technical study in regards to the limits described in I2 & I3. The real net aggregated power seen by the bulk

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Yes or No

Question 8 Comment
power system at the interconnection, with the outlook of distributed generation systems, may be different than
past experience. Hence it requires to be reassessed based on technical studies with respect to the future
integration of DG’s. (Please refer to comments in questions: 3 & 4).
To establish a bright-line definition, Exclusion E2 may be acceptable if the SDT provides adequate provisions
within the exception procedure. (See response to Q7)

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
The I2 Inclusion was adopted from the ERO Statement of Compliance Registry Criteria.
See response to question 7.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Western Electricity Coordinating
Council

Yes

WECC agrees in concept, but it is unclear what happens if/when the “binding obligation” ends, as well as
what constitutes a “binding obligation.” E2(ii) should be clarified as to what constitutes “standby, back-up, and
maintenance power services provided...pursuant to a binding obligation.” This may cause administrative
burden to monitor such binding commitments.

Cogeneration Association of
California and Energy Producers
& Users Coalition

Yes

To respond to WECC's concern, please consider that facilities procure standby service because it is needed
for the facility's operation, not to escape registration or compliance. This is a long-term commitment, and the
sufficiency of the service will be monitored by the state regulatory authority. "Standby service" is a term wellunderstood in the industry and generally not further defined in any utility tariff.

Response: Binding obligations are retail tariffs approved by state PUCs or applicable Canadian provincial authorities, or the FERC-approved market rules of
RTOs/ISOs in cases where FERC has granted a waiver to local utilities from those service obligations because the RTO/ISO market provides comparable services.
In the US, the services are defined in 18 CFR §292.101 and §292.305(b). No change made.
ReliabilityFirst

Yes

as long as the resources when removed from service have a load component that accompanies it, otherwise
there could be an impact to the BES.

Response: That is the purpose of condition (ii) in Exclusion E2. Back-up power, as defined in the US in 18 CFR §292.101, means electric energy or capacity
supplied by an electric utility to replace energy ordinarily generated by a facility’s own generation equipment during an unscheduled outage of the facility.

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Organization

Yes or No

Question 8 Comment

Maintenance power, also as defined in 18 CFR §292.101, means electric energy or capacity supplied by an electric utility during scheduled outages of the
qualifying facility. Provincial regulations do the same in Canada. No change made.
Texas Industrial Energy
Consumers (TIEC)

Yes

TIEC supports this exclusion with two clarifications. The language currently excludes generation on the
customer’s side of the meter as long at “the net capacity provided to the BES does not exceed the criteria
identified in Inclusions I2 or I3.” There are special circumstances in which an regional Reliability Coordinator
may ask that customer-owned generation export to its maximum capability (i.e., with its load curtailed to the
lowest level) in order to support grid reliability. Circumstances such as this should not be considered in
determining whether the “net” capacity exported to the BES exceeds the threshold for registration.
Additionally, there are often instances when customer-owned generation and associated load are in start-up
or shut-down processes that may cause the net export to the BES to vary such that it temporarily exceeds the
registration thresholds. Outlying situations such as these should not trigger registration. Rather, the “net”
capacity should be interpreted as the typical amount exported during steady-state operation of the site. This
interpretation of “net capacity” should also apply to exclusions E1 and E3.

Response: The SDT has discussed your concern and agrees that emergency or other extraordinary situations should not impair the general applicability of the
E2 Exclusion.
The SDT has changed E1 and E3 to clarify the criteria applicable to non-retail generation.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
d) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
e) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA
(gross nameplate rating). Or,
f)

Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this
exclusion.

E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to

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Yes or No

Question 8 Comment

accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3 and do
not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
FortisBC

Yes

We agree with most of the changes in Exclusion E2. However, we feel there is a need for evidence or
technical study in regards to the limits described in I2 & I3. The real net aggregated power seen by the bulk
power system at the interconnection, with the outlook of distributed generation systems, may be different than
past experience. Hence it requires to be reassessed based on technical studies with respect to the future
integration of DG’s. (Please refer to comments in questions: 3 & 4).
To establish a bright-line definition, E2 exclusion may be acceptable if the SDT provides adequate provisions
within the exception procedure.
See response to Q8
Accordingly, we suggest the SDT carefully craft the exception criteria that will allow entities to present their
case to the ERO for exclusion from E2 requirements.

AltaLink

Yes

We agree with most of the changes in Exclusion E2. However, we feel there is a need for evidence or
technical study in regards to the limits described in I2 & I3. The real net aggregated power seen by the bulk
power system at the interconnection, with the outlook of distributed generation systems, may be different than
past experience. Hence it requires to be reassessed based on technical studies with respect to the future
integration of DG’s.
To establish a bright-line definition, E2 exclusion may be acceptable if the SDT provides adequate provisions
within the exception procedure. Accordingly, we suggest the SDT carefully craft the exception criteria that will
allow entities to present their case to the ERO for exclusion from E2 requirements.

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Organization

Yes or No

Question 8 Comment

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
See response to Q8.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
City of St. George

Yes

The limits on generation levels need to be revisited, with similar concerns as noted to questions 7 & 9 for
exclusions E1 & E3.

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
The SDT adopted the criteria from the ERO Statement of Compliance Registry Criteria.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Illinois Municipal Electric Agency

Yes

Please see comments under Question 13.

Yes

Please refer to comments in number 7 above. Additionally, there appears to be an inconsistency in how
generating units are expressed in E2 (net capacity) and in I2 and I3 (MVA).

Response: See response to Q13.
New England States Committee
on Electricity
Response: See response to Q7.
The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed relevant to
the exclusion, not the nameplate rating. Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES
that does not exceed 75 MVA.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and

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Organization

Yes or No

Question 8 Comment

maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
New York State Dept of Public
Service

Yes

This exclusion is appropriately specified. Behind the meter generation is mainly on the local distribution
system and most likely modeled in power flow cases used to study the bulk system as netted against load.
For the few sizable behind the meter generation that are: 1) connected at the 100 kV level and above; and, 2)
exceed the 75 MVA threshold, if it is believed that these facilities will impact the bulk system they can be
petitioned for inclusion under the rules of procedure.

Exelon

Yes

Exelon agrees with this Exclusion since this language is quoted from the Statement of Compliance Registry
Criteria.

Public Utilities Commission of
Ohio

Yes

Exclusion E2 is appropriate. Same as 7.

GTC

Yes

Northeast Power Coordinating
Council

Yes

Imperial Irrigation District

Yes

Santee Cooper

Yes

MRO's NERC Standards Review
Forum

Yes

Michigan Public Service
Commission(MPSC)

Yes

ACES Power Participating
Members

Yes

National Rural Electric
Cooperative Association

Yes

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Organization

Yes or No

Question 8 Comment

(NRECA)
Overton Power District No. 5

Yes

Arizona Public Service Company

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

New York State Reliability
Council

Yes

New York Power Authority

Yes

Luminant Energy

Yes

Electricity Consumers Resource
Council (ELCON)

Yes

Western Area Power
Administration

Yes

National Association of
Regulatory Utility Commissioners

Yes

PacifiCorp

Yes

Grand Haven Board of Light and
Power

Yes

Glacier Electric Cooperative

Yes

FHEC

Yes

South Texas Electric

Yes

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Organization

Yes or No

Question 8 Comment

Cooperative, Inc.
Portland General Electric
Company

Yes

South Texas Electric
Cooperative, Inc.

Yes

National Grid

Yes

Dayton Power and Light
Company

Yes

ExxonMobil Research and
Engineering

Yes

Duke Energy

Yes

Alberta Electric System Operator

Yes

Fayetteville Public Works
Commission

Yes

Florida Keys Electric Cooperative

Yes

American Electric Power

Yes

East Kentucky Power
Cooperative, Inc.

Yes

American Transmission
Company, LLC

Yes

Farmington Electric Utility System

Yes

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Organization

Yes or No

Sierra Pacific Power Co d/b/a NV
Energy

Yes

Colorado Springs Utilities

Yes

Consumers Energy Company

Yes

Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

Yes

Muscatine Power and Water

Yes

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

Yes

Sacramento Municipal Utility
District (SMUD)

Yes

Puget Sound Energy

Yes

GTC

Yes

Idaho Power

Yes

Long Island Power Authority

Yes

PJM

Yes

Oncor Electric Delivery Company
LLC

Yes

August 19, 2011

Question 8 Comment

No comment.

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Organization

Yes or No

City of Anaheim

Yes

MEAG Power

Yes

Xcel Energy

Yes

Golden Spread Electric
Cooperative, Inc.

Yes

Question 8 Comment

Response: Thank you for your support. The SDT modified Exclusion E3 to make non-retail generation in a local network subject to a comparable exclusion
designation as that for customer-owned generation in Exclusion E2. Please see the modified definition.

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9. The SDT has added specific exclusions to the core definition in response to industry comments. Do you agree
with Exclusion E3? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: The SDT has modified the local network definition in the following manner:
•

Elimination of the term “Distribution” in the label of this exclusion, making it a “local network”.

•

Changes were made to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network, including a
statement that the local network does not accommodate bulk power transfer across the interconnected system.
Eliminated the provision in Exclusion E3.a which referred to automatic fault interrupting devices, and changed wording to clarify the
connection point of the local network.

•

While the SDT disagrees with removal of restrictions on the amount of connected generation, it takes note of the concern about growing amounts
of connected generation within the distribution system. As such, the SDT has made changes to those limits from the original posting in a new
item E3.a limiting connected generation within a local network to 75 MVA aggregate non-retail generation similar to the provision in Exclusion
E1.c. Commenters expressed concern about the lack of technical justification for a 75 MVA limit on connected generation; however, the SDT has
been presented with no technical basis upon which to suggest a change from this value. After consulting with the NERC Board of Trustees and
the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t
enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address
the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and
the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Items E3.c and E3.d were combined into a new item E3.b, incorporating the concepts of power flow into the Local Network and precluding energy
transfers across the Local Network. This provision also effectively removed the comparison test between generation and minimum demand of the
Local Network.
The SDT considered commenters’ suggestions regarding allowance of some power flow out of the LN, and concluded that strict limits precluding
out-flow are appropriate, particularly given that the local network comprises facilities that are electrically parallel to the BES.
Finally, the SDT, in consideration of regulatory concerns, inserted a provision in the local network exclusion to limit the operating voltage of the
local network to 300 kV.
The revised Exclusion E3 reads as follows:
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that
distribute power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection
at 100 kV or higher are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail
customer Load and not to accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:

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Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in
Inclusion I3, and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in
aggregate), includes more than 75 MVA generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the
LDN The LN does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored
Facility in the ERCOT or Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).

Organization
Northeast Power Coordinating
Council

Yes or No

Question 9 Comment

No

Regarding E3.a.--If the supply to a LDN is tapped off a Bulk Electric System facility, and the step down
transformer is protected on its high side by a fault magnitude supervised automatic interrupting device (such
as a circuit switcher), how does that affect the exclusion? The circuit switcher will only interrupt faults up to a
certain magnitude. Above that threshold, depending on the system configuration, fault clearing might have to
be done at the Bulk Electric System facility.
Regarding E3.d.--The LDN cannot be used to transfer real or reactive power under all operating conditions.
Suggest combining E3.c and E3.d to read as follows:Power is intended to flow only into the LDN. The
generation within the LDN shall not exceed the electric real or reactive power demand within the LDN. The
LDN only delivers real or reactive power to load, and is not to be used to transfer real or reactive power
between different locations in the BES. Under no system condition is BES reliability to be dependent on LDN
flow.

Response: The SDT has modified the local network definition, eliminating provision E3.a, which referred to the automatic fault interrupting devices. The point
of demarcation of the local network may be clarified in subsequent guidance documents; however, it begins at the point where the three remaining
characteristics (E3.a, b, and c) can be demonstrated. Additionally, the SDT has combined prior items E3.c and E3.d into a new item E3.b in the revised definition
incorporating the concepts of power flow into the local network and precluding energy transfers across the Local Network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to

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Organization

Yes or No

Question 9 Comment

accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Tri-State Generation and
Transmission Association, Inc.

No

We believe that element c. needs to be changed to : “Power flows only into the Local Distribution Network,
even under all contingency conditions that are considered under any TPL standard requirement dealing with
transmission system performance: The generation within the LDN shall not exceed the electric Demand
within the LDN;"

Response: The SDT has combined prior items E3.c and E3.d into a new item E3.b in the revised definition incorporating the concepts of power flow into the
Local Network and precluding energy transfers across the Local Network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Interconnected System. LDN’s emanate from multiple points of connection at 100 kV or higher are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to accommodate
bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and

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Organization

Yes or No

Question 9 Comment

c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
NERC Staff Technical Review

No

Exclusion E3 is acceptable in general; however, (i) including the word “distribution” in the exclusion could be
interpreted to imply that certain distribution facilities are included in the BES unless specifically excluded,
(ii) item d) is unclear as to whether it applies to any parallel flow or only to parallel flow for which the group of
Element(s) are part of the contract path, and
(iii) interrupting devices should be included in the BES for the same reasons as stated above for Exclusion
E1. >>>>>>>>>>
The concern with the word distribution in the term “Local Distribution Network” can be avoided by eliminating
use of this phrase. The proposed definition already defines the Elements covered by Exclusion E2 and does
not require defining a term for use in this standard. An alternate solution would be to establish a different
term to describe the groups of Elements that does not include the word distribution. >>>>>>>>>>
The phrase “is used to” in item d) lacks clarity. Clarity should be provided by stating that the group of
Elements does not transfer energy originating outside the group of Elements; this is consistent with item c)
that requires that power flows only into the group of Elements. >>>>>>>>>>
The reason for requiring automatic interrupting devices between the BES and the excluded LDN is to prevent
faults and other abnormal conditions in the LDN from negatively impacting reliability of the BES. Given the
reliance on the interrupting devices to support BES reliability, it is appropriate to include the interrupting
devices in the BES so that they are planned, designed, maintained, and operated in accordance with NERC
Reliability Standards the same as other BES Elements. Thus, when excluding groups of Elements at 100 kV
or higher, the BES line of demarcation should be on the load side of the automatic interrupting devices.
>>>>>>>>>>
To address our concerns, Exclusion E3 should be changed to read: >>>>>>>>>> E3 - Groups of Elements
operated above 100 kV that distribute power to Load rather than transfer bulk power across the
interconnected System. Such groups of Elements are connected to the Bulk Electric System (BES) at more
than one location solely to improve the level of service to retail customer Load. These groups of Elements are
characterized by all of the following:a) Separable by automatic fault interrupting devices: Wherever
connected to the BES, the group of Elements must be connected through automatic fault-interrupting devices
(the automatic interrupting device is part of the BES);b) Limits on connected generation: Neither the group of
Elements, nor any underlying Elements operated at 100 kV or below, includes more than 75 MVA generation
(in aggregate);c) Power flows only into the group of Elements: The generation within the group of Elements
shall not exceed the electric Demand within the group of Elements;d) Not used to transfer bulk power: The

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Organization

Yes or No

Question 9 Comment
group of Elements does not transfer energy originating outside the group of Elements for delivery through the
group of Elements; ande) Not part of a Flowgate or transfer path: The group of Elements does not contain a
monitored Facility of a permanent flowgate in the Eastern Interconnection, a major transfer path within the
Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the Quebec
Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).

Response: The term “Distribution” has been removed; these facilities are now referred to as “local networks”.
The SDT has combined prior items E3.c and E3.d into a new item E3.b in the revised definition incorporating the concepts of power flow into the local network
and precluding energy transfers across the local network.
Item E3.a has been removed from the definition, and as such, there is no longer any mention of the interrupting devices within this exclusion.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Interconnected System. LDN’s emanate from multiple points of connection at 100 kV or higher are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to accommodate
bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Dominion

No

An Element or Facility should only be excluded where the Element or Facility is not necessary for operating
an interconnected electric energy transmission network or is needed to maintain transmission system
reliability.

Response: The SDT believes that the revised Exclusion E3 properly identifies facilities that are not necessary for operating an interconnected electric energy

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Organization

Yes or No

Question 9 Comment

transmission network and not needed to maintain transmission system reliability.
SPP Standards Review Group

No

While the principle contained in (c) is valid, the explanation following it is too restrictive. This does not allow
the LDN to maintain any excess generation for contingencies and normal load fluctuations.
In (b) the implication is that the LDN is being treated like a single site in I3 whereby the total generation
capability is restricted to 75 MVA. Is this a valid assumption for municipals?
In (e) permanent flowgates may change from month to month, therefore an LDN could bounce into and back
out of the BES depending upon what happens regarding a specific facility which may be included as part of a
flowgate. This creates a very fluid situation which can lead to confusion.

Response: The SDT has revised the language concerning limits on connected generation in new item E3.a.
A 75 MVA aggregate non-retail generation limit is proposed, and the SDT believes that this is consistent with the similar provision in the radial exclusion, E1.c.
The SDT appropriately uses the word “permanent” in connection with the flowgates in E3.c, as its intent is to prevent facilities that might temporarily be
considered to be a flowgate from qualifying for exclusion as a local network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Interconnected System. LDN’s emanate from multiple points of connection at 100 kV or higher are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to accommodate
bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
MRO's NERC Standards Review

August 19, 2011

No

The SDT is defining what a Local Distribution Network is but the term transfer bulk power is ambiguous.

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Organization

Yes or No

Forum

Question 9 Comment
Please clarify what the intent of this exclusion is.

Response: The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term
“bulk power” was retained in paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
SERC OC Standards Review
Group

No

“b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes
more than 75 MVA generation;” The SERC SDT believes you intended to grant exception E2 in this case;
however, it is not explicitly identified”
c)Power flows only into the Local Distribution Network: The generation within the LDN shall not exceed the
electric Demand within the LDN;” Is this intended for each hour of the year or is it possible for some hours
that generation may exceed load? This needs to be clarified.

Response: The revised definition includes a revised item E3.a, which clarifies the limits on connected generation within the local network.
It is the intent of the SDT that the power flowing into the local network be demonstrated through integrated hourly measurements over a period of time
consistent with the ROP Exception Process, which is currently contemplated to be a period of two years.
Idaho Falls Power

August 19, 2011

No

We support this exclusion, however generation assets on a Local Distribution Network should be excluded

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Organization

Yes or No

Question 9 Comment
regardless of MVA rating if all other defining critera in E3 are met.
Additionally, it is unclear as written whether a single generation asset greater than 20MVA would be excluded
as E3(b) states 75 MVA, but is inconsist with E2(i). Some clarification of intent is needed to resolve the
ambiguities between these two exclusions.

Response: The SDT disagrees with removing restrictions on the amount of connected generation, but has made changes to those limits to address industry
concerns.
Please refer to the new item E3.a.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Tennessee Valley Authority

No

The following comments are specific to subsections of E3:Section (c): We suggest the section to read,
“Power flows out of the LDN shall not exceed the limitations imposed in Inclusions I3 and I5.
”Section (d): We suggest the section be read, “Not used to transfer bulk power: The LDN is not used to
transfer energy originating outside the LDN for delivery through the LDN, except for the power flowing in a
normally open switching device between radial systems operating in a make-before-break fashion as defined
in exclusion E1.”

Response: The SDT considered this suggestion regarding allowance of some power flow out of the local network, and concluded that strict limits precluding out-

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Organization

Yes or No

Question 9 Comment

flow are appropriate, particularly given that the local network comprises facilities that are electrically parallel to the BES.
The revised definition has included a change to the prior E3.d language, which is now reflected in the revised item E3.b.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
ReliabilityFirst

No

the LDN term must be a NERC defined term and if this is allowed as mentioned in the first comment, we feel
the intent of the FERC Order was to simplify and not complicate the definition and the inclusion/exclusion
process. This definition is now even more complex.
we also feel that as a result of several defined terms such as the LDN teh proposed definition will in most
cases exclude portions of networks in locations such as Washington DC, New York and other Metro Areas,
many Munis and citiies that are currently registered. If the intent is to remove entities from the registry this
will in most likely do it.

Response: The SDT intends to fully explain the characteristics of a “local network” within the BES definition, and as such, the term is not necessary in the
Glossary.
It is not the SDT’s intent to specifically exclude any facilities in major metropolitan areas; it expects that the specific examples mentioned (NYC, Washington DC)
would not qualify for exclusion under the revised Exclusion E3. No change made.
Electricity Consumers Resource

August 19, 2011

No

There are two different types of LDN: utility owned and customer owned. They should not be treated the

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Organization

Yes or No

Council (ELCON)

Question 9 Comment
same. Criteria (a) through (e) in Exclusion E3 may be appropriate for distinguishing between utility-owned
LDN and utility-owned BES transmission often owned and operated by the same integrated utility. A
separate, stand-alone exclusion criteria should be established for customer-owned elements that serve to
distribute electric energy to on-site loads, including all or part of the electric energy from behind-the-meter
generation. Thus, E3 criteria (a) through (e) would apply exclusively to utility-owned elements. For
customer-owned elements, the new criterion (f) might read:"Or the LDN is also characterized by:"f) The
Elements are customer owned and used to distribute electric energy to on-site loads, including all or part of
the electric energy from behind-the-meter generation."See response to #11 below for further justification for
this recommendation.

Response: The SDT has revised item E3.a to clarify that retail generation would not contribute toward the limits of connected generation within the local
network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or
Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Central Maine Power Company
New York State Electric & Gas
and Rochester Gas & Electric

August 19, 2011

No

This exclusion is vague, but needs to be clear and comply with Order 743. Also, “distribution” is already
excluded from transmission and therefore “BES.”
Also, E1 refers to “automatic interruption device” and E3 refers to “automatic fault interrupting device”, neither
of which are defined.We think that large portions of the network may be inappropriately excluded under this
exclusion and exclusion E3 should be deleted.

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Organization

Yes or No

Question 9 Comment

Response: The term “Distribution” has been removed, and now this exclusion refers to “local networks”.
Also, the prior item E3.a, referring to automatic fault interrupting devices, has been removed in this revision of the definition.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Hydro-Quebec TransEnergie

No

Part b) is again very restrictive. It is not necessary to refuse exclusion when generation is above 75 MVA.
However, a provision should be made so that reliability standards related to generator shall apply.

Response: The SDT disagrees with removing restrictions on the amount of connected generation, but has made changes to those limits to address industry
concerns. Please refer to new item E3.a.
The application of the reliability standards to generators will continue to be determined by the Statement of Compliance Registry Criteria.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and

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Organization

Yes or No

Question 9 Comment

do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
National Grid

No

E3.c and E3.d - These two points can be combined into one:Power is intended to flow only into the LDN. The
generation within the LDN shall not exceed the electric real or reactive power demand within the LDN. The
LDN only delivers real or reactive power to load, and is not to be used to transfer real or reactive power
between different locations in the BES. Under no system condition is BES reliability to be dependent on LDN
flow.
E3.e - We would like more clarification on flowgates and what they are. We are interpreting flowgate as the
lines that make up defined operational interface, as defined by the Operations group not the Planning group.
Is this the correct interpretation of flowgate?

Response:
Flowgate is a defined term in the Glossary of Terms used in Reliability Standards as follows:
1.) A portion of the Transmission system through which the Interchange Distribution Calculator calculates the power flow from Interchange Transactions.
2.) A mathematical construct, comprised of one or more monitored transmission Facilities and optionally one or more contingency Facilities, used to analyze
the impact of power flows upon the Bulk Electric System.
Items E3.c and E3.d were indeed combined as suggested, and now have become new item E3.b.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusions I3, and

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Organization

Yes or No

Question 9 Comment

do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or
Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Electric Reliability Council of
Texas, Inc.

No

See response to Question 7.

Southwest Power Pool

No

See response to question 7.

No

Similar to the comments provided on Exclusion E1, the inclusion of a requirement for automatic fault
interrupting device to separate the local distribution network from the interconnected transmission network
will in many cases shift the onus of securing a reliable interconnected transmission network from the owners
and operators of that interconnected transmission network to the customers and owners of local distribution
networks that pay the owners and operators of the interconnected transmission network a fee for providing
reliable transmission services. Furthermore, the Federal Power Act excludes all facilities used in the local
distribution of electric energy and does not distinguish whether such local distribution facilities must be
isolated by automatic fault interrupting devices.

Response: See response to Q7.
ExxonMobil Research and
Engineering

Response: Item E3.a has been removed from the definition, and as such, there is no longer any mention of the interrupting devices within this exclusion.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA

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Organization

Yes or No

Question 9 Comment

generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Colorado Springs Utilities

No

Colorado Springs Utilities generally supports Exclusion E3 that provides for the exclusion of Local Distribution
Networks (LDNs) from the BES, with the following modifications:
1) It is not necessary to articulate the nature of the LDN’s connection to the BES. If the characterizations are
met, the number of connections and the reasons for the connections are immaterial.
2) If the LDN is a normal net import, there is no need to limit the amount of connected generation since the
generation will have no material effect on the BES.
3) ‘Bulk power transfers’ are acceptable across an LDN if the transfer is to a nested LDN. Contractual
energy, originating outside the LDN and delivered to a nested LDN, for example, is still load delivery and has
the same physical characteristics of a holistic LDN and the transfer of bulk power is immaterial.We propose
changing Exclusion E3 to read,”Local Distribution Networks (LDN): Groups of Elements operated above 100
kV that distribute power to Load rather than transfer bulk power across the Interconnected System. The LDN
is characterized by all of the following:a) Separable by automatic fault interrupting devices: Wherever
connected to the BES, the LDN must be connected through automatic fault-interrupting devices;b) Power
flows only into the Local Distribution Network: The generation within the LDN shall not exceed the electric
Demand within the LDN;c) Not used to transfer bulk power, except transfers to nested LDNs: The LDN is not
used to transfer energy originating outside the LDN for delivery through the LDN, except transfers to nested
LDNs; andd) Not part of a Flowgate or Transfer Path: The LDN does not contain a monitored Facility of a
permanent flowgate in the Eastern Interconnection, a major transfer path within the Western Interconnection
as defined by the Regional Entity, or a comparable monitored Facility in the Quebec Interconnection, and is
not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).”

Response: The SDT has revised Exclusion E3 Local network in a way that removes the mention of automatic fault interrupting devices.
This is a continent-wide definition that applies to all cases of a local network. One can not assume that a local network will always be a net importer in all
situations, hence the limit on generation.

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Organization

Yes or No

Question 9 Comment

While the SDT does not fully understand the concept of “nested LDN”, we believe that the revised Exclusion E3 in sum captures the concept of networks that are
providing a distribution function.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

August 19, 2011

No

(Note: Inserted language provided in brackets; deleted language denoted by empty brackets: [ ].) Exclusion
E3 is also contrary to the plain language of Section 215 of the FPA. The SDT stated in commentary to E3
that it “believes that any network that simply supports distribution and is providing adequate protection should
be excluded from the BES.” This statement highlights the fundamental disconnect between the proposal and
Section 215 of the FPA, which excludes facilities used in the local distribution of electric energy from the
definition of the BES regardless of whether the facilities are “providing adequate protection.” That is, Section
215 of the FPA states that the definition of the BES excludes “facilities used in the local distribution of electric
energy,” not “facilities used in the local distribution of electric energy [providing adequate protection].”With
respect to the enumerated criteria in Exclusion E3, the requirement that Local Distribution Networks (“LDNs”)
“must be connected through automatic fault-interrupting devices” violates the FPA because, as discussed in
response to Question 7, it places a condition on the unqualified exemption granted by Congress to facilities
used in the local distribution of electric energy. Moreover, the other enumerated criteria also fail under
Section 215 of the FPA and case law because they ignore, as discussed further in response to Question 11,
a long line of precedent that requires a fact-specific analysis to be conducted to determine whether a facility
is used in local distribution (see, e.g., Order No. 888 at 31,980). To make Exclusion E3 consistent with the
requirements of Section 215 of the FPA and case law, Exclusion E3 could be rewritten as follows:E3 - [All

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Organization

Yes or No

Question 9 Comment
facilities used in the distribution of electric energy] ([“]Local [D]istribution [N]etworks,[“ or “]LDNs[“]): Groups of
Elements operated above 100 kV that distribute power to Load rather than transfer bulk power across the
interconnected System. LDN[]s are [normally] connected to the Bulk Electric System (BES) at more than one
location solely to improve the level of service to retail customer Load. The LDN is characterized by all of the
following:a) [ ]b) Limits on connected generation: [Generally], neither the LDN, nor its underlying Elements (in
aggregate), includes more than 75 MVA generation;c) Power flows only into the LDN: The generation within
the LDN [normally does] [ ] not exceed the electric Demand within the LDN;d) Not used to transfer bulk
power: The LDN is [generally] not used to transfer energy originating outside the LDN for delivery through the
LDN; ande) Not part of a Flowgate or transfer path: The LDN normally does not contain a monitored Facility
of a permanent flowgate in the Eastern Interconnection, a major transfer path within the Western
Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the Quebec
Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).Please see further discussion in response to Questions 11 and 12.

Response: The SDT has revised the Exclusion E3 Local network in a way that removes the mention of automatic fault interrupting devices, which it believes
addresses the concern about the apparent disconnect between Section 215 and the prior proposal.
The SDT disagrees with the use of terms such as “normally” and “generally” as these tend to lack precision and objectivity. Please see the revised exclusion.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

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Organization
Muscatine Power and Water

Yes or No
No

Question 9 Comment
The SDT is defining what a Local Distribution Network is but the expression “transfer bulk power” is
ambiguous. Please clarify the purpose of this exclusion.

Response: The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term
“bulk power” was retained in paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or
Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Exelon

No

Exelon has issues with the ambiguity of this Exclusion item. It seems that Local Distribution Networks will all
need to be approved via the Rules of Procedure Exception Process because the characteristics of each LDN
as described are not bright line. For example, does (b) refer to any generation, including behind-the-meter
generation?
Does (c) mean always, i.e., generation can never exceed the load under any condition? In theory or in
actuality?
How does (d) deal with parallel flows under abnormal conditions when some energy may go in and out?
Exelon understands the concept that an LDN primarily serves load, but how will the owners prove that there
is no impact to the BES under contingency configurations?

Response: The SDT has modified exclusion E3 in a manner that addresses the ambiguity of the proposal, clarifies the amount of connected generation rather

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Organization

Yes or No

Question 9 Comment

than the prior comparison of demand and generation, and clarifies that the power flow must always be into the Local Network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Springfield Utility Board

No

SUB agrees with items, a), b), and e) of the characteristics of an LDN.
SUB believes that the language regarding c) and d) needs clarification.c) states: “Power flows only into the
Local Distribution Network: The generation within the LDN shall not exceed the electric Demand within the
LDN.” There may be times where a closed system creates a situation where power flows through the system
on an unscheduled basis (electron’s will follow the path of least resistance). Left as is, there may be a
situation where on a planning basis there is no power flowing out of the LDN, but on a real time basis power
does flow in and out. “Power flows only into the Local Distribution Network: The sum of all power being
delivered into the LDN at the points of measurement is greater than the sum of all the power measured as
being delivered out of the LDN at the points of measurement”
The generation within the LDN shall not exceed the electric Demand within the LDN.”SUB suggests that the
generation language should be deleted, but if the language “The generation within the LDN shall not exceed
the electric Demand within the LDN.” is retained, what does “Demand” mean? The lowest demand? The
highest demand? Instantaneous demand?SUB suggests that if some generation language is added that the
exclusion read:”Power flows only into the Local Distribution Network: The sum of all power being delivered
into the LDN at the points of measurement is greater than the sum of all the power measured as being
delivered out of the LDN at the points of measurement The generation within the LDN shall not exceed the

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Question 9 Comment
maximum electric Demand within the LDN, where the maximum electric Demand is the maximum electric
Demand within the LDN as measured for over the prior sixty (60) months.”
d) states: “Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the
LDN for delivery through the LDN”. Again, this language needs clarification. How would an LSE/DP/TO (or
other similar entity) know that their system is not being used to transfer bulk power when other parties are
scheduling transmission paths via a Balancing Authority or other overarching entity?SUB suggests that the
language be clarified to read “Not used to transfer bulk power: The LDN is not used to transfer energy
originating outside the LDN for delivery through the LDN. This would be evaluated using scheduled
transmission paths and not measured amounts at the point of measurement. It is the responsibility of the
Balancing Authority to notify the Registered Entity with an LDN twelve (12) months in advance of when an
LDN would be used to schedule the transfer of energy outside the LDN for delivery through the
LDN.”Collectively, E3 would read:The LDN is characterized by all of the following:a)Separable by automatic
fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic
fault-interrupting devices; andb)Limits on connected generation: Neither the LDN, nor its underlying
Elements (in aggregate), includes more than 75 MVA generation; and c)Power flows only into the Local
Distribution Network: The sum of all power being delivered into the LDN at the points of measurement is
greater than the sum of all the power measured as being delivered out of the LDN at the points of
measurement; andd)Not used to transfer bulk power: The LDN is not used to transfer energy originating
outside the LDN for delivery through the LDN. This would be evaluated using scheduled transmission paths
and not measured amounts at the point of measurement. It is the responsibility of the Balancing Authority to
notify the Registered Entity with an LDN twelve (12) months in advance of when an LDN would be used to
schedule the transfer of energy outside the LDN for delivery through the LDN.;ande)Not part of a Flowgate or
Transfer Path: The LDN does not contain a monitored Facility of a permanent flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity,
or a comparable monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in
an Interconnection Reliability Operating Limit (IROL).
o Local distribution networks were added to the exclusion list after considerable discussions among the SDT
and various registered entities that have configurations meeting these conditions. The SDT believes that any
network that simply supports distribution and is providing adequate protection should be excluded from the
BES.

Springfield Utility Board

August 19, 2011

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation
normally operated as backup generation for retail load is not counted as generation for purposes of

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Question 9 Comment
determining generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or
exclusion, a system with load and generation normally operated as backup generation for retail load is
considered "serving only load" when using generation normally operated as backup generation for retail load
(See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is
normally used during a localized outage and for testing for reliability during a localized outage event.
Including backup generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation
used for restoration or reliability of the BES. Including backup generation for retail load in generation
threshold calculations would cause a inappropriate inclusion of elements and devices, accelerate the
triggering of inclusion (and may make exclusion provisions meaningless), and push more activity of excluding
smaller systems from the BES into the exception process.

Response: Items E3.c and E3.d were indeed combined as suggested, and now have become the new item E3.b.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
City of St. George

August 19, 2011

No

Local distribution networks should have an exclusion provision. However, the local generation limit of 75
MVA is too restrictive. As long as power flows into a LDN the amount of generation should not trigger a LDN
to be included in the BES. E3b should be removed from these exclusion criteria or maybe a reasonable ratio
of load level to allowed generation on the LDN.

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Question 9 Comment

Response: The limits on connected generation, now described in item E3.a, have been revised, resulting in a less restrictive exclusion characteristic.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Southern California Edison
Company

No

SCE is in support of the general LDN premise, but believes that this definition should more closely track the
FERC seven-factor test from Order 888.
As written, the five factors identified could lead to the reclassification of radial sub-transmission system
facilities above 100kV from “distribution facilities” to “network facilities”. For example, interconnection
amounts within an LDN may exceed an aggregate level of 75MVA, but will not exceed the load in the LDN.
SCE suggests striking characteristics “B” and “D” from Exclusion E3, and allowing characteristic “C” to stand
alone as the generation characteristic which would define an LDN.The SDT may want to incorporate the
following revision:”LDN’s are connected to the Bulk Electric System (BES) at one or more location solely to
improve the level of service to retail customer load.”

Response: The genesis of the characteristics in the local network exclusion is the FERC seven-factor test; however, the SDT seeks to establish bright-line
characteristics that add specificity and objectivity to these principles through this exclusion. The definition differentiates between radial systems and LNs by
clarifying the connection points to the BES from these systems. Radial systems have a single connection point and LNs have multiple connection points. This
alone establishes a bright-line between radial systems and LNs which does not allow for the re-classification of such systems as alluded to in the comment.
Items E3.c and E3.d have now been combined, and have become the new item E3.b. After much discussion, the SDT believes that there must be a limit on

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Question 9 Comment

connected generation (new item E3.a) as well as a provision ensuring that power flow only into the local network (new item E3.b).
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Long Island Power Authority

No

Revise last two sentences in the introductory paragraph to read as follows: “LDN’s are connected to the bulk
electric system (BES) at several points and are characterized by all of the following:”; This removes ambiguity
that exists in the deleted portion of the text.See also response to question 11 regarding Exclusion E3-b.

Response: The SDT has made changes to the introductory paragraph in E3, which it believes clarifies the intent of the local network; however, the SDT believes
that the descriptive language adds necessary context to the entire exclusion principle and therefore should be retained.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;

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Question 9 Comment

b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
The Dow Chemical Company

August 19, 2011

No

The Dow Chemical Company (“Dow) is an international chemical and plastics manufacturing firm and a
leader in science and technology, providing chemical, plastic, and agricultural products and services to many
essential consumer markets throughout the world. Dow and certain of its worldwide affiliates and
subsidiaries, including Union Carbide Corporation, own and operate electrical facilities at a number of
industrial sites within the U.S., principally, in Texas and Louisiana. The electrical facilities at these various
industrial sites are configured similarly and perform similar functions. In most cases, a tie line or lines
connect the industrial site to the electric transmission grid. Power is delivered from the electric transmission
grid to the industrial site through the tie line(s). Lines within the industrial site then deliver power to individual
manufacturing plants within the site. Additionally, cogeneration facilities are located at a number of industrial
sites owned by Dow and its subsidiaries. These cogeneration facilities generate power that is distributed
within the industrial site and used for manufacturing plant operations. In some instances, excess power not
required for plant operations is delivered back into the electric transmission grid through the tie line(s)
connecting the industrial site to the grid. Under all circumstances, electricity is not flowing into and out of such
industrial sites at the same time. While the tie lines and some of the internal lines at these industrial sites
operate at 100kV or higher, they do not perform anything that resembles a transmission function. Rather than
transmit power long distances from generation to load centers, the tie lines and internal lines perform
primarily a local distribution function consisting of the distribution of power brought in from the grid or
generated internally to different plants within each industrial site. In some cases, the facilities also perform
an interconnection function to the extent they enable power from cogeneration facilities to be delivered into
the grid. The voltage of the tie lines and internal lines at these industrial sites is dictated by the load and basic
configuration of each site. Higher voltage lines are used when necessary to meet applicable load
requirements or to reduce line losses. That does not mean that such lines perform a transmission function.
At some sites, Dow is registered as a Generation Owner and Generation Operator. At other sites, the
applicable Regional Entity has found that such registration is not required because of the relatively small
amount of power supplied to the grid from the applicable cogeneration resources, even though those
cogeneration resources have an aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating). Tie lines (to the grid) and internal lines at an industrial site that operate at 100kV or higher should be
excluded from the BES definition if, due to the relatively small amount of power supplied to the grid from the
generation resources at the site, the owner of those generation resources is not required to be registered as

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Question 9 Comment
a Generation Owner and the operator of those generation resources is not required to be registered as a
Generation Operator.At sites where the owner of the generation resources is registered as a Generation
Owner and the operator of those generation resources is registered as a Generation Operator, the internal
lines (between the generation resources and the manufacturing plants) that operate at 100kV or higher
should be excluded from the BES definition, because they are distribution and not transmission facilities. The
lines interconnecting the generation resources at such sites to the transmission grid should be included in the
BES definition, but the owner and operator of such interconnection lines should not be registered as a
Transmission Owner or Transmission Operator. In no instance has a Regional Entity determined that Dow or
any subsidiary should be registered as a Transmission Owner or Transmission Operator. Instead, such
interconnection lines should be considered as part of the generation resource and Generation Owners and
Generation Operators should be subject to reliability standards specifically developed for such
interconnection lines. Dow is strongly opposed to any BES definition that would result in either the tie lines or
the internal lines at industrial sites being subject to the mandatory reliability standards applicable to
Transmission Owners and Transmission Operators. Complying with reliability standards would cause Dow
and its subsidiaries to incur substantial compliance costs and create potential exposure to penalties in the
future for noncompliance. Perhaps such costs and exposure could be justified if subjecting these facilities to
compliance with reliability standards resulted in a material increase in reliability of the BES, but there is no
reason to believe that will be the case. In fact, the opposite might be true. The tie lines and internal lines at
industrial sites owned by Dow and its subsidiaries have been operated for decades as distribution and
interconnection facilities, and practices and procedures have developed over the years that have enabled
such operations to achieve a high degree of reliability for such sites. Requiring these facilities to now operate
in a different manner as transmission facilities may well result in a degradation of the reliability of the
manufacturing plants located at such sites. For example, outages would have to be coordinated with the
RTO, which may not be interested in coordinating such outages with scheduled manufacturing plant
outages.Dow recommends that a separate exclusion be added to the BES definition to address industrial
distribution facilities. Proposed exclusion E-3 for local distribution networks is not sufficient to ensure that all
industrial distribution facilities are excluded. For example, criteria b), entitled “Limits on connected
generation” states that “Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75
MVA generation”. This criteria makes no sense for an industrial site with on-site electricity generation and a
number of manufacturing plants that has internal power lines and lines interconnecting with the transmission
grid that operate at 100 kV or higher where the owner and operator of the on-site electricity generation
facilities are not registered as a Generation Owner and a Generation Operator because only a small amount
of electricity is ever exported from the on-site electricity generation facilities to the transmission grid. This
criteria also makes no sense with respect to internal electric lines (operated at 100 kV or higher) at such
industrial sites even where the owner and operator of the on-site electricity generation facilities are registered
as a Generation Owner and a Generation Operator.Criteria c) also causes proposed exclusion E-3 not to be
sufficient to ensure that all industrial distribution facilities are excluded where the owner and operator of the

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Question 9 Comment
on-site electricity generation facilities are not registered as a Generation Owner and a Generation Operator
because only a small amount of electricity is ever exported from the on-site electricity generation facilities to
the transmission grid. Criteria c), entitled “Power flows only into the LDN”, states: “The generation within the
LDN shall not exceed the electric Demand within the LDN.” Criteria c) also makes no sense with respect to
internal lines at such industrial sites even where the owner and operator of the on-site electricity generation
facilities are registered as a Generation Owner and a Generation Operator.

Response: Criteria E3.c has been revised to separate the concepts of power flow into the network from the comparison of generation to demand. Additionally,
the new E3.a addresses the limits on connected generation and in so doing, excludes from consideration all retail generation.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Central Lincoln

No

Central Lincoln strongly supports the exclusion of LDNs. These networks are used for improving local
service, not for BES reliability; and their use should not be discouraged. However, we see problems with the
language of part d. Part d uses the term the undefined term “bulk power” as part of the overall definition of
“bulk power system,” leading to a circular definition. Did the SDT mean to indicate that no power may be
transferred though an LDN? If so, suggest striking the word “bulk.”
We also believe the SDT meant to define the LDN in terms of normal operating conditions, since all LDNs
would transfer power under the right contingency (such as a complete loss of load within the LDN). Please
make it clear that part d test applies during normal operating conditions.

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Question 9 Comment

Response: The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term
“bulk power” was retained in the paragraph E3, as we believe it provides conceptual value to the exclusion principle.
The SDT disagrees with the use of the concept “normal operating conditions” as it tends to lack precision and objectivity for use in an effective definition.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
PPL Energy Plus and PPL
Generation

No

See comments in Question 13.

No

Exclusion E3 needs to be strengthened to ensure that the LDN will have no impact on the BES. The
protective elements preventing the LDN from impacting the BES should be included in the BES.

Response: See response to Q13.
Manitoba Hydro

As well, the term Local Distribution Network (LDN) should be defined as a separate NERC Glossary term,
instead of being defined in the BES definition.
Response: The SDT has revised the E3 local network exclusion in a way that removes the mention of automatic fault interrupting devices.
The SDT intends to fully explain the characteristics of a “local network” within the BES definition, and as such, the term is not necessary in the Glossary.

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Yes or No

Question 9 Comment

E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
ISO New England, Inc.

No

We think that large portions of the network may be inappropriately excluded under this exclusion and the
exclusion should be deleted.If E-3 is retained, then it is recommended that the SDT change the sentence
“LDN’s are connected to the Bulk Electric System (BES)” to “LDN’s include transmission connected to the
Bulk Electric System (BES)...”
An Automatic Interruption device needs to be defined. For example, Iis a fuse an Automatic Interruption
device?
The definition needs clarification in the phrase: Power flows only into the Local Distribution Network: The
generation within the LDN shall not exceed the electric Demand within the LDN;Should this be “Net power
...”? One transmission path could be exporting power but the net sum of all paths would always be importing
power.

Response: The SDT has debated Exclusion E3 and has determined that it should be retained.
similar to what your comment suggested.

However, the language has been changed to provide clarification

The SDT has revised the Exclusion E3 local network in a way that removes the mention of automatic fault interrupting devices.
The revised Exclusion E3 now combines the prior items E3.c and E3.d into a revised item E3.b.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute

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Yes or No

Question 9 Comment

power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Consolidated Edison Co. of NY,
Inc.

No

Multiple Connections - The current wording in the second sentence “at more than one location” could be
misinterpreted. Replace this sentence with the following wording:LDN’s use multiple connections to the Bulk
Electric System (BES) solely to improve the level of service to retail customer load.

Response: The SDT considered this suggestion and believes that reference to “more than one location” has sufficient clarity; therefore this language was
retained. The paragraph has been revised to eliminate the term “solely” and to explain that the local network does not accommodate bulk transfer across the
interconnected system.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN

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does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Independent Electricity System
Operator

No

Consistent with our earlier comments in response to Q1, we do not agree that an LDN should be
characterized by a 75 MVA limit on the connected generation as described in part (b). It is expected that
under various “green energy” programs that the development and implementation of distributed generation
will grow considerably in the future. The 75 MVA generation limit may discourage this development of
distributed generation (in general, it may discourage the installation of generation in lieu of transmission to
supply load) because installing generation in an LDN would cause the entire LDN to be classified as BES
and, as a result, subject the LDN to NERC planning standards that are inconsistent with well established
jurisdictional planning criteria. To avoid subjecting the LDN to NERC requirements, the planning authority
may elect to build generation outside of the LDN, which is undesirable because of increased transmission
losses and reduced reliability. We suggest that (b) be deleted or revised in keeping with our earlier
suggestions.
We also suggest modifying Exception E3 (c) and (d) for consistency with language used in Technical
Principles for Demonstrating BES Exceptions, since Bullet 1 recognizes that the system for which the
exemption is being applied, may not be necessary for BES reliability and may experience power flows out to
the BES under specified conditions. The suggested modified wording for E3 (c) and (d) is shown below: (c)
Power is intended to flow only into the LDN: the total net Generation output within the LDN shall not exceed
the total electric Demand of the LDN. (d) Not intended for use in transferring bulk power: While the LDN is
intended to deliver power to load and not transfer bulk power between different locations in the BES, it is
acceptable that under specified system conditions, bulk power transfers may take place between different
points of the BES via the LDN, when it can be demonstrated that these power flows through the LDN are not
necessary for maintaining BES reliability.

Response: The SDT takes note of the concern about growing amounts of connected generation within the distributed generation arena, and has proposed a
revision to the limits on connected generation, now found in item E3.a.
Regarding the suggestion for language changes in sub-items c and d, the SDT has made a modification in the revised definition item E3.b to address both the
power flow into the local network and the prohibition of use of a candidate local network for power flow transactions through the network (commonly referred to
as “wheel-through” transactions). Since the local network is electrically parallel to facilities presumed to be BES, and hence, may have some interactive effect
upon the BES, the SDT believes that in order to qualify for exclusion, the local network must exhibit characteristics that mimic a classic radial system; i.e., flow

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only into the network and no utilization for “through” transactions.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
BPA

No

[As requested above BPA would like “automatic interruption device” and “automatic fault interrupting device” to
be defined terms] Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;
BPA seeks clarification on:
E3 – couldn’t E2 and E3 both apply to the same system? If so, wouldn’t the generation limit in E3(b) (75 MVA
maximum) eliminate the exemption in E2 (can be above 75 MVA if maximum net capacity provided to BES
does not exceed 75 MVA)?
BPA seeks to have “transfer bulk power” defined.
If an LDN had two connections, 200 MW flowed in on one, and 150 MW flowed out on another, how would
that be counted?)
How do you determine if the LDN is being used for bulk power transfer or not?
One interpretation could be: any path that is scheduled across for purposes other than serving load

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contained therein would be determined to be used to “transfer bulk power”. In other words, transactions can
only flow INTO an LDN. If transactions flow out of an area at any point, then from a compliance perspective
that area would not meet this component of the LDN definition. The LDN is not used to transfer energy
originating outside the LDN for delivery through the LDN; and (end of comment)

Response: The SDT has revised the Exclusion E3 local network in a way that removes the mention of automatic fault interrupting devices.
The revised Exclusion E3 now specifically excludes from consideration the “behind the meter” generation in the limits on connected generation.
The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term “bulk power”
was retained in the paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.
In the example of 200 MW in-flow and 150 MW out-flow, this network would not meet the revised item E3.b, as power is flowing out at one or more of the
interfaces; therefore the exclusion would not be satisfied.
The determination of use of the local network for transfer of bulk power would be characterized by the demonstration that power is flowing only in to the
network and that the network is not accommodating power transfers for instance, it is not a contract path for power transactions.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Portland General Electric
Company

August 19, 2011

While PGE appreciates the SDT’s efforts to exclude distribution systems, asrequired by the statute, PGE
believes that this Exclusion needs further clarification to beworkable. PGE has specific concerns with the
following aspects of the Exclusion:(b) The phrase “nor its underlying Elements (in aggregate)” is ambiguous.

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It does notmake it clear how a utility could differentiate between the multiple Local DistributionNetworks
within its service territory.
(c) The phrase “Power flows only into the Local Distribution Network” does not makeclear that under certain
abnormal circumstances power may flow out of a LocalDistribution Network. Wording such as “the
predominant direction of flow is into theLocal Distribution Network during normal (non-outage) conditions”
could account forsuch abnormal circumstances.
(d) The phrase “Not used to transfer bulk power” should similarly be modified toindicate that it is meant to
describe normal rather than abnormal conditions. Inaddition, this aspect of the Exclusion should account for
the fact that two utilities mayhave multiple interchange points at the distribution level, but the fact that energy
istransferred at these points does not inherently make them transmission paths. A phrasesuch as “none of
the LDN facilities are identified as belonging to or having direct ratingimpact on a regionally-recognized
constrained transmission path used to deliver energyto points outside of the LDN” could address this
concern.

Response: The SDT appreciates your concern about the possible ambiguity in “underlying Elements”; however, the SDT believes that this language is
appropriate in order to clarify that the lower than 100 kV facilities contribute to the limits on connected generation.
The SDT has determined that it will refrain from the use of “predominant direction”, “normal circumstances” etc., as the use of this language tends to lack
precision and objectivity and is therefore unsuitable in a definition. No changes made for these comments.
Georgia System Operations

In item c, What is meant by “generation” and by “electric Demand,” and how is whether “generation within the
LDN...exceed[s] the electric Demand within the LDN” to be calculated? Is this installed nameplate capacity
(rather than energy) minus peak Demand, or minus forecast Demand, or minus actual Demand - in each
case either for some period of time or at every moment (the NERC Glossary defines Demand as either)? Is it
the actual generated energy minus actual or forecast Demand for some period of time or at every moment?
If the definition is based on capacity, this exclusion should allow for the possibility that a larger than currently
necessary generator may be installed in anticipation of future load growth, so long as it is never used to
generate significantly more than what is needed for load. If actual generated energy is intended, the
exclusion should provide for inadvertent and/or de minimis power flows.

Response: The SDT has removed the concept of comparison of generation to electric demand, and instead has moved to a simpler limit on connected
generation.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to

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accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Tacoma Power

Tacoma Power generally supports Exclusion E3 that provides for the exclusion of Local Distribution Networks
(LDNs) from the BES, with the following modifications:
1) It is not necessary to articulate the nature of the LDN’s connection to the BES. If the characterizations are
met, the number of connections and the reasons for the connections are immaterial.
2) If the LDN is a normal net import, there is no need to limit the amount of connected generation since the
generation will have no material effect on the BES.
3) ‘Bulk power transfers’ are acceptable across an LDN if the transfer is to a nested LDN. Contractual
energy, originating outside the LDN and delivered to a nested LDN, for example, is still load delivery and has
the same physical characteristics of a holistic LDN and the transfer of bulk power is immaterial.
We propose changing Exclusion E3 to read,”Local Distribution Networks (LDN): Groups of Elements
operated above 100 kV that distribute power to Load rather than transfer bulk power across the
Interconnected System. The LDN is characterized by all of the following:a) Separable by automatic fault
interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;b) c) Power flows only into the Local Distribution Network: The generation within the
LDN shall not exceed the electric Demand within the LDN;d) Not used to transfer bulk power, except
transfers to nested LDNs: The LDN is not used to transfer energy originating outside the LDN for delivery
through the LDN, except transfers to nested LDNs; ande) Not part of a Flowgate or Transfer Path: The LDN
does not contain a monitored Facility of a permanent flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable
monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an

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Interconnection Reliability Operating Limit (IROL).”

Response: The SDT considered this suggestion and believes that reference to “more than one location” has sufficient clarity; therefore this language was
retained. The paragraph has been revised to eliminate the term “solely” and to explain that the Local Network does not accommodate bulk transfer across the
interconnected system.
The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty as possible
in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current application of
the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support consistent
application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation that the
revision to the definition would not significantly expand or contract what is currently considered to be the BES. The SDT disagrees with removal of all limits on
connected generation, as this could significantly change the scope of the definition and potentially limit the amount of generation that would be classified as BES
Elements.
While the SDT does not fully understand the concept of “nested LDN”, it believes that the revised Exclusion E3 in sum captures the concept of networks that are
providing a distribution function.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
City of Redding

August 19, 2011

Yes

Redding will support this high level exclusion of Local Distribution in the light that it is a “sharpening” of the
Brightline and is part of the SDT’s overall plan to make the distinction between distribution and transmission
facilities. As Redding mentioned with the radial exclusion (E1), Redding’s support rests on the fact that the

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Exception Process will adequately address the distribution and transmission facilities issue and there will be a
fair and equable method where LDN’s that do not meet this criteria will be adequately identified as distribution
facilities.
However, Redding does believe (as noted in question #4) that the 75 MVA threshold has very little
justification as “necessary” for the transmission system. Generators connected to LDNs are a classic
example where the generation installed acts only as a load modifier. Redding suggests using the 200 MVA
level for generation connected to a LDN.

Response: The SDT has determined that a generation limit is essential to qualify these local networks as distribution; however, in the revised Exclusion E3, the
limits on connected generation have been made somewhat less restrictive as indicated in item E3.a.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
American Municipal Power and
Members
Florida Municipal Power Agency
Florida Keys Electric Cooperative

Yes

The exclusion refers to groups of Elements that “distribute power to Load rather than transfer bulk power
across the interconnected system.” The use of the term “bulk power” is vague and could be read incorrectly
as a reference to the “bulk-power system,” which is defined in the Federal Power Act but is not a NERC
defined term. If the LDN is connected to the BES at more than one location, there will by definition be some
loop flow. We recommend below that Exclusion 3(d) be revised to quantify the amount of loop flow that is
permissible in an excluded LDN.
In the context of the first sentence of Exclusion E3, less specificity is needed, and the sentence should only

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Question 9 Comment
be revised for the sake of accuracy to state: “Groups of Elements operated above 100 kV that are primarily
intended to distribute power to load rather than to transfer power across the interconnected System.
”The exclusion’s reference to connection “at more than one location” is vague. The sentence should be
revised to read “connected to the Bulk Electric System (BES) from more than one Transmission source solely
to improve the level of service to retail customer Load,” and “Transmission source” should have the same
meaning that it does in E1.
E3(a) should require that there be switching devices between the LDN and the BES, not specifically
automatic fault-interrupting devices. The term “separable by” in “Separable by automatic fault interrupting
devices” is unclear and should be reworded.
E3(b) To avoid pulling an LDN into the BES based on very small customer-owned generation (such as
rooftop photovoltaics and hospital backup diesel generators) that the utility does not consider or rely on, or
necessarily even know about, the item should be reworded: “Limits on connected generation: Neither the
LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA of generation used to meet the
resource adequacy requirements of electric utilities.”
E3(d) states “Not used to transfer bulk power.” As noted above, “bulk power” is a vague term. There will
necessarily be some loop flow on a system that is connected to the BES at more than one location. The
amount of permissible loop flow for this purpose needs to be determined and stated in this item.

Response: The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term
“bulk power” was retained in paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.
The SDT has made changes to the introductory paragraph in Exclusion E3, which it believes clarifies the intent of the local network; however, the SDT believes
that the descriptive language adds necessary context to the entire exclusion principle and therefore should be retained.
The SDT considered this suggestion and believes that reference to “more than one location” has sufficient clarity; therefore this language was retained. The
paragraph has been revised to eliminate the term “solely” and to explain that the Local Network does not accommodate bulk transfer across the interconnected
system.
The SDT has revised the Exclusion E3 local network in a way that removes the mention of automatic fault interrupting devices.
The revised Exclusion E3 now specifically excludes from consideration the “behind the meter” generation in the limits on connected generation.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:

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Question 9 Comment

Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Small Entity Working Group
(SEWG)

Yes

Yes, with some clarifying edits. The first sentence of Exclusion 3 should be revised for accuracy as follows:
““Local Distribution Networks (LDN): Groups of Elements operated above 100 kV that are primarily intended
to distribute power to Load rather than to transfer bulk power across the Interconnected System.
”The second sentence should be revised for clarity as follows: “LDN’s are connected to the Bulk Electric
System (BES) from more than one Transmission source solely to improve the level of service to retail
customer Load.”Exclusion E3 a) should be revised as we note in our comments in Question#7 to allow for the
use of switching devices in specific situations

Response: The SDT has made changes to the introductory paragraph in Exclusion E3, which it believes clarifies the intent of the local network; however, the
SDT believes that the descriptive language adds necessary context to the entire exclusion principle and therefore should be retained.
The SDT considered this suggestion and believes that reference to “more than one location” has sufficient clarity; therefore this language was retained. The
paragraph has been revised to eliminate the term “solely” and to explain that the Local Network does not accommodate bulk transfer across the interconnected
system.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA

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generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Hydro One Networks Inc

Yes

We agree with this concept of LDN as part of establishing a bright-line definition along with Exclusion E3.
However, restrictions for LDN such as connected Generation must neither be more restrictive than radial nor
should generation limits be applicable unless they impact the reliability of interconnected transmission
network.Requirements in Exclusion E3 are very restrictive and we do not agree to the limits on connected
generation for Local Distribution Networks (LDN), described in part (b). We suggest that bullet b) be revised
and limits on connected generation must not include generation resources identified in Inclusions I2, I3, I4
and I5. The development and implementation of distributed generation will grow considerably in the future
and will operate together with conventional sources of energy. The real net aggregated power of distributed
generation seen by the bulk power system at the interconnection may be larger than past experience; hence
it requires to be reassessed based on technical studies with respect to the future integration of DG’s. (Please
refer to comments in questions: 3 & 4)
Also, we suggest combining exception E3 (c) and (d) as follows:”(c) Power is intended to flow only into the
LDN: The generation within the LDN shall not exceed the electric Demand within the LDN; The LDN is
intended to deliver power to load and not be used to transfer bulk power between different locations in the
BES. It is recognized that under specified system conditions, bulk power transfers may take place between
different points of the BES via the LDN. However, for these conditions BES reliability is not dependent on the
existence of these power flows through the LDN.”

Response: The SDT has made changes to Exclusion E3 which promotes improved consistency between the restrictions of Exclusions E1 and E3. As well, the
revised item E3.a now provides specific reference to items of the inclusion list.
The SDT has made revisions to combine items E3.c and E3.d into a new item E3.a.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:

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Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
City of Santa Clara, California,
dba Silicon Valley Power

Yes

Yes, Silicon Valley Power agrees with proposed Exclusion E3 that "Local Distribution Networks (LDNs):
Groups of Elements above 100 kV that distribute power to Load rather than transfer bulk power across the
interconnected System," that are (among the other characterizations) "connected to the Bulk Electric System
(BES) at more than one location solely to improve the level of service to retail customer load" should be
specifically excluded from the Bulk Electric System definition. SVP also agrees with the majority of the
characteristics of an LDN set forth in proposed Exclusion E3. However, SVP believes that alternative
language may be more appropriate with respect to characteristic "b" of proposed Exclusion E3. Part "b" to
proposed Exception E3 states "Limits on connected generation: Neither the LDN, nor its underlying
Elements (in aggregate), includes more than 75 MVA generation." SVP submits that the use of a fixed level
of generation to determine whether an entity qualifies as an LDN is too arbitrary and does not reflect
engineering reality. If a fixed level of generation is used, it will often be too high, if the registered entity has a
small system, or too low, when the registered entity has a large system. SVP submits that NERC should
consider modifying part "b" to proposed Exception E3 to give the Regional Entities discretion to determine
whether 75 MVA of generation is the appropriate benchmark for an individual utility. Therefore, SVP submits
that with respect to draft exception E3 b), "Limited connected generation to the LDN or its underlying
Elements (in aggregate), as determined by the LDN's Regional Entity, using 75 MVA as a benchmark" may
be appropriate.
Alternatively, SVP submits that instead of a fixed level of generation, NERC could consider modifying the
language of proposed Exception E3 b) to limit an LDN's connected generation to a high percentage of local
minimum demand, or to a high percentage of generation not already committed to run to meet local reliability
needs. Either option would meet the purpose of the LDN: a registered entity with connected generation that
is, for the most part, only used to serve native or local load.SVP thanks NERC for the opportunity to comment

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on its 1st Draft definition of BES, and its proposed inclusions and exceptions.

Response: The SDT appreciates the concern regarding the lack of technical justification for a 75 MVA limit on connected generation; however, the SDT has been
presented with no technical basis upon which to suggest a change from this value. After consulting with the NERC Board of Trustees and the NERC Standards
Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that
topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However,
this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the
Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as
several other issues that have arisen from SDT deliberations. The revised Exclusion E3 has resulted in a somewhat less restrictive limit on connected generation
as provided in revised item E3.a.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Public Utility District No. 1 of
Snohomish County, Washington

August 19, 2011

Yes

Snohomish strongly supports the categorical exclusion of Local Distribution Networks from the BES. In fact,
for reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to ensure
that the BES definition complies with the statutory requirement to exclude all facilities used in the local
distribution of electric power. LDNs are, of course, probably the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the level of
service to retail customers. But providing an exclusion for radials without providing an equivalent exclusion
for LDNs will have the opposite effect, to the ultimate detriment of electric consumers.Snohomish also

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supports, with the reservations discussed below, the LDN exclusion as drafted by the SDT. At least
conceptually, we believe the SDT has identified the key characteristics that separate LDNs from facilities that
are part of the bulk transmission system and therefore should be classified as BES. Hence, LDNs can be
excluded from the BES based on the characteristics identified by the SDT without compromising the reliability
of the interconnected bulk transmission system.Although Snohomish supports the LDN exclusion, we believe
the exclusion should be refined in the following respects: o The SDT’s draft states that:”LDN’s are connected
to the Bulk Electric System (BES) at more than one location SOLELY to improve the level of service to retail
customer Load.” (emphasis added) We are concerned that the use of the term “solely” implies the need for
an examination of the motives of a local distribution utility in connecting to the BES at more than one location.
This result is problematic because it defeats the purpose of the exclusion, which is to allow LDNs to be
excluded from the BES without an in-depth and expensive inquiry into the exact nature of the LDN. In
addition, the local utility may have a number of motives for connecting to the BES at more than one location,
but the local utility’s motives have nothing to do with how the LDN interacts with the interconnected bulk
system, which should be the key determinant in including or excluding any Element from the BES. With
these concerns in mind, we therefore recommend that the SDT revise the sentence quoted above as follows:
“LDNs are connected to the Bulk Electric System (BES) at more than one location to improve the level of
service to retail customer load and not to accommodate bulk transfers of power across the interconnected
bulk system.” By instituting this suggestion, the SDT would emphasize the key difference between an LDN,
which is designed to reliably serve local, end-use retail customers, and the BES, which is designed to
accommodate bulk transfer of power at wholesale over long distances.
o We believe the characteristics specified by the LDN in subsections (b) and (c) of the exclusion are
redundant. Subsection b specifies that the LDN would not interconnect more than 75 MVA of generation in
aggregate. Subpart c specifies that power flows only into the LDN. We believe the SDT can eliminate
subpart b of the definition and simply rely on subpart c because if power only flows into the LDN even if it
interconnects more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system, only with the LDN. Further, with the
advent of distributed generation, it is easy to foresee a situation in which a large number of very small
distributed generators are interconnected into a LDN, so that the aggregate capacity of these generators
exceeds 75 MVA. However, because the generators are small and dispersed and, under the subpart c
criteria, would be wholly absorbed within the LDN rather than transmitting power onto the interconnected grid,
those generators would not have a material impact on the grid. In addition, the 75 MVA criterion would make
an LDN interconnecting more than 75 MVA part of the BES. For the reasons set forth by the Project 2010-07
SDT, we are concerned the result will be the local utility being improperly classified as a Transmission Owner
and Transmission Operator, which would subject the local utility to a number of reliability standards that
would significantly increase its compliance burden without substantially improving bulk system reliability. In
fact, in the LDN situation, there is even less reason to impose these burdens on the local utility than in the
situation addressed by the Project 2010-07 team, where generators are interconnected to the BES by

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dedicated interconnection facilities. Because the LDN is interconnected at multiple points, the generators
interconnected to the LDN could continue to operate even if one or two interconnection points are out of
service. On the other hand, in the situation addressed by the Project 2010-07 team, if the dedicated
interconnection facility is out of service, the generation is unavailable because there is no alternative route to
deliver it to load.
Finally, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale adoption
of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry lacks adequate
technical justification. The SDT repeats that error here by incorporating those thresholds into the LDN
exception.

Overton Power District No. 5

No

we support Snohomish's clarifications

Response: The introductory paragraph in Exclusion E3 has been revised to eliminate the term “solely” and to explain that the local network does not
accommodate bulk transfer across the interconnected system.
The Commission provided guidance within Order Nos. 743 & 743a which identified the current application of the existing BES definition was essentially correct for
the majority of the continent and directed clarification of the existing language to support consistent application across all regions. Additional guidance from the
Commission spoke to significant changes in the scope of the definition with an expectation that the revision to the definition would not significantly expand or
contract what is currently considered to be the BES. Based on these expectations, the SDT believes that there must be a limit on connected generation as well as
a provision to ensure that power flows only into the local network. Elimination of the generation limit would potentially limit what generation is currently
considered to be BES Elements. The SDT has proposed revised characteristics E3.a and E3.b to capture these concepts.
The SDT has made revisions to combine the items E3.c and E3.d into a new item E3.a.
The revised definition, Exclusion E3, and item E3.a makes the limit on connected generation somewhat less restrictive than in the prior definition document.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN

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does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Western Electricity Coordinating
Council

Yes

WECC agrees in concept. However, in sub-bullet b), it should be clarified that the 75 MVA is gross-aggregate
nameplate, as described in the inclusions.
In sub-bullet c), it should be clarified whether this requirement is at any time or is for hourly integrated values.
Also, the use of the term “major transfer paths” should be modified to be “major transfer paths in the Table
titled Major WECC Transfer Paths in the Bulk Electric System.”
Finally, the reference to “above 100 kV” should be “at or above 100 kV” for consistency.

Response: The suggestion regarding “gross aggregate nameplate” has been incorporated into this revision of the definition.
The SDT has removed the concept of comparison of connected generation to electric demand.
The SDT has incorporated the suggestion to add the words in the introductory paragraph of Exclusion E3.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec

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Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Western Montana Electric
Generating and Transmission
Cooperative

Yes

WMG&T strongly supports the categorical exclusion of Local Distribution Networks from the BES. In fact, for
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to ensure
that the BES definition complies with the statutory requirement to exclude all facilities used in the local
distribution of electric power. LDNs are, of course, probably the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the level of
service to retail customers.
WMG&T supports the LDN exclusion, but we believe the exclusion should be refined in the following
respects: o The SDT’s draft states that:”LDN’s are connected to the Bulk Electric System (BES) at more than
one location solely to improve the level of service to retail customer Load.” We recommend that the SDT
revise the sentence quoted above as follows: “LDN’s are connected to the Bulk Electric System (BES) at
more than one location to improve the level of service to retail customer Load and not to accommodate bulk
transfers of power across the interconnected bulk system.” By instituting this suggestion, the SDT would
emphasize the key difference between an LDN, which is designed to reliably serve local, end-use retail
customers, and the BES, which is designed to accommodate bulk transfer of power at wholesale over long
distances.

Response: The introductory paragraph in Exclusion E3 has been revised to eliminate the term “solely” and to explain that the local network does not
accommodate bulk transfer across the interconnected system.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a

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Question 9 Comment

major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Transmission Access Policy
Study Group

Yes

The exclusion refers to groups of Elements that “distribute power to Load rather than transfer bulk power
across the interconnected system.” The use of the term “bulk power” is vague and could be read incorrectly
as a reference to the “bulk-power system,” which is defined in the Federal Power Act but is not a NERC
defined term. If the LDN is connected to the BES at more than one location, there will by definition be some
loop flow.
We recommend below that Exclusion 3(d) be revised to quantify the amount of loop flow that is permissible in
an excluded LDN. In the context of the first sentence of Exclusion E3, less specificity is needed, and the
sentence should only be revised for the sake of accuracy to state: “Groups of Elements operated above 100
kV that are primarily intended to distribute power to load rather than to transfer power across the
interconnected System.
”The exclusion’s reference to connection “at more than one location” is vague. The sentence should be
revised to read “connected to the Bulk Electric System (BES) from more than one Transmission source solely
to improve the level of service to retail customer Load,” and “Transmission source” should have the same
meaning that it does in E1.
E3(a) should require that there be switching devices between the LDN and the BES, not specifically
automatic fault-interrupting devices. The term “separable by” in “Separable by automatic fault interrupting
devices” is unclear and should be reworded.
E3(b) To avoid pulling an LDN into the BES based on very small customer-owned generation (such as
rooftop photovoltaics and hospital backup diesel generators) that the utility does not consider or rely on, or
necessarily even know about, the item should be reworded: “Limits on connected generation: Neither the
LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA of generation used to meet the
resource-adequacy requirements of electric utilities.
”E3(d) states “Not used to transfer bulk power.” As noted above, “bulk power” is a vague term. There will
necessarily be some loop flow on a system that is connected to the BES at more than one location. The
amount of permissible loop flow for this purpose needs to be determined and stated in this item.

Response: The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term
“bulk power” was retained in the paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.
The SDT has found no technical basis upon which to establish any limits on the amount of allowable loop flow in a local network; however, the technical
exception process may be an avenue for considering such a metric. The SDT has made changes to the introductory paragraph in Exclusion E3, which the SDT

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believes clarifies the intent of the local network; however, the SDT believes that the descriptive language adds necessary context to the entire exclusion principle
and therefore should be retained.
The SDT considered this suggestion and believes that reference to “more than one location” has sufficient clarity; therefore this language was retained. The
paragraph has been revised to eliminate the term “solely” and to explain that the Local Network does not accommodate bulk transfer across the interconnected
system.
The SDT has revised Exclusion E3 local network in a way that removes the mention of automatic fault interrupting devices.
The revised Exclusion E3 now specifically excludes from consideration the “behind the meter” generation in the limits on connected generation, and the SDT has
made revisions that allow up to 75 MVA of connected generation to exist while still qualifying for this exclusion.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Northern California Power
Agency

August 19, 2011

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.In
addition to this support, NCPA asks for consideration of an alternative approach for determining an exception
in this regard, as opposed to having it based on a somewhat arbitrary fixed level of generation (75 MVA).
NCPA suggests consideration be given for an approach based on a determined percentage of actual demand
for a given LDN. As such, NCPA submits the following with respect to draft exception E3 (b), Limits on
Connected Generation: Neither the LDN, nor its underlying Elements (in aggregate), include more than a
certain percentage of minimum area load, as determined by the regional entity." Such an approach would
require the regional entity to look at the amount of connected generation on a case-by-case basis.

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Question 9 Comment

Response: The SDT has made modifications to the exclusion criteria under Exclusion E3; however, the SDT continues to believe that a flat, fixed value of
generation is the most suitable approach in order to promote consistency and repeatability in the determination.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Texas Industrial Energy
Consumers (TIEC)

Yes

Proposed exclusion E3 should be revised to categorically exclude all facilities that are part of a local
distribution network (LDN), regardless of the specifics of the LDN’s interconnection with the Bulk Electric
System. As currently drafted, Exclusion 3 places a number of inappropriate limits on a whether a local
distribution system is excluded from the Bulk Electric System definition. As recognized by the Commission in
Order No. 743-A, Section 215 of the Federal Power Act categorically excludes local distribution systems from
the Bulk Power System definition without qualification. As a result, LDNs are outside the FERC’s jurisdiction
and are outside the scope of this rulemaking. The SDT should revise the approach to Exclusion 3 to exclude
all facilities that are part of a LDN, regardless of how the LDN is interconnected to the grid. Specifically,
making exclusion of an LDN contingent upon the LDN being connected through automatic fault-interrupting
devices is inappropriate. Similar to the concerns TIEC expressed in response to Question 7, above, if there
are concerns about LDNs impacting the Bulk Electric System, then it is the responsibility of the transmission
provider serving the LDN to ensure that systems and facilities are in place to protect the grid. The specifics
of an LDN’s interconnection to the grid should not dictate whether it is subject to regulation. TIEC would
therefore recommend removing proposed qualification (a) to the LDN exclusion.
Further, the requirement that generation in the LDN can never exceed demand is inappropriate. As the SDT

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Question 9 Comment
properly recognized in Exclusion 2, as long as the generation within an LDN does not trigger registration
requirements, the LDN should be able to export power to the grid without subjecting itself to regulation. Many
LDNs export small amount of power intermittently to balance the flow within the LDN. Subjecting these
networks to regulation as a result of this balancing activity is inconsistent with the existing generation
registration requirements and would exceed the scope of this rulemaking. The existing generation
registration requirements exempt customer-owned generation that serves retail load from generation
registration requirements as long as the net capacity provided to the bulk power system does not exceed the
nameplate requirements for stand-alone generators. Consistent with this approach, an LDN should not have
to be registered as long as its net exports to the grid do not exceed the generation registration requirements.
TIEC accordingly requests that proposed LDN characteristics (c) and (d) be removed as qualifications to the
LDN exclusion, and that the exclusion be revised to allow generation output to the grid as long the net export
to the grid does not exceed the threshold levels for registration as a generator owner/operator.

Response: One of the objectives of the revised definition of the BES is to provide a deterministic method of identifying and excluding facilities that are used for
distribution, and Exclusion E3 is one of the mechanisms by which the SDT proposes to accomplish this. The SDT has revised the Exclusion E3 local network in a
way that removes the mention of automatic fault interrupting devices which the SDT believes addresses the concern about the apparent disconnect between
Section 215 and the prior proposal.
The SDT believes that generation connected within a network that would otherwise be a distribution system, can change the functionality of that network to one
that serves transmission functions; hence, the SDT believes that some limit on connected generation must continue to exist in this exclusion principle.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec

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Organization

Yes or No

Question 9 Comment

Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
PacifiCorp

Yes

PacifiCorp believes this meets FERC’s intent in Order Nos. 743 and 743A, however additional clarification
may be added particularly around items b and c. Regardless of the generation level (item b), if the power only
flows into the Local Distribution Network (“LDN”) (item c) then the the level of generation is not material and
should have no impact on the reliable operation of the BES.

Response: The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty
as possible in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current
application of the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support
consistent application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation
that the revision to the definition would not significantly expand or contract what is currently considered to be the BES. Therefore the SDT disagrees with removal
of all limits on connected generation, but it has made this provision somewhat less restrictive as shown in the revised item E3.a.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Intellibind

Yes

This does address some of my concerns on small radial transmission systems. I think that there will be
confusion when small entities try and apply both E3 and E1 to their particular situations. The ambiguity will
cause more questions than it is trying to answer.

Response: The revisions to Exclusion E3 are intended to bring more clarity and consistency to the application of this exclusion principle. The SDT believes this

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Organization

Yes or No

Question 9 Comment

revision removes the ambiguity mentioned in your comment.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Blachly Lane Electric Cooperative
Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative

Yes

We strongly support the categorical exclusion of Local Distribution Networks from the BES. For reasons
discussed at length in our answer to Question 1, we believe the exclusion is necessary to ensure that the
BES definition complies with the statutory requirement to exclude all facilities used in the local distribution of
electric power. LDNs are likely the most common kind of local distribution facility. Further, the conversion of
radial systems to local distribution networks should be encouraged because networked systems generally
reduce losses, increase system efficiency, and increase the level of service to retail customers. We also
support, with the reservations discussed below, the LDN exclusion as drafted by the SDT. We believe the
SDT has identified the key characteristics that separate LDNs from facilities that are part of the bulk
transmission system and therefore should be classified as BES. Hence, LDNs can be excluded from the
BES based on the characteristics identified by the SDT without compromising the reliability of the
interconnected bulk transmission system.However, for the reasons stated in our answers to Questions 3 and
4, we believe the SDT’s wholesale adoption of the 20 MVA and 75 MVA thresholds from the NERC
Statement of Compliance Registry lacks adequate technical justification. The SDT repeats that error here by
incorporating those thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements.

Northern Lights Inc

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Yes or No

Question 9 Comment

Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Response: The SDT has revised the Exclusion E3 Local Network in a way that removes the mention of automatic fault interrupting devices, which the SDT
believes addresses the concern about the apparent disconnect between Section 215 and the prior proposal.
The limits on connected generation, now described in item E3.a, have been revised, resulting in a less restrictive exclusion characteristic. The SDT notes,
however, that the responses to the comments in the first posting of the BES Definition did not yield any technically-based alternatives to the generation
thresholds of the ERO Statement of Compliance Registry Criteria (SCRC), and as such, the SDT has no technical rationale to deviate from the SCRC. After
consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at
this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will
be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and
the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization
Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and

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Yes or No

Question 9 Comment

Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Northern Wasco County PUD
Chelan PUD – CHPD
Kootenai Electric Cooperative
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc

Yes

Northern Wasco County PUD strongly supports the categorical exclusion of Local Distribution Networks from
the BES. In fact, for reasons discussed at length in our answer to Question 1, we believe the exclusion is
necessary to ensure that the BES definition complies with the statutory requirement to exclude all facilities
used in the local distribution of electric power. LDNs are, of course, probably the most common kind of local
distribution facility. Further, the conversion of radial systems to local distribution networks should be
encouraged because networked systems generally reduce losses, increase system efficiency, and increase
the level of service to retail customers. Northern Wasco County PUD supports the LDN exclusion, but we
believe the exclusion should be refined in the following respects: o The SDT’s draft states that:”LDN’s are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service
to retail customer Load.” (emphasis added) We recommend that the SDT revise the sentence quoted above
as follows: “LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to
improve the level of service to retail customer Load and not to accommodate bulk transfers of power across
the interconnected bulk system.” By instituting this suggestion, the SDT would emphasize the key difference
between an LDN, which is designed to reliably serve local, end-use retail customers, and the BES, which is
designed to accommodate bulk transfer of power at wholesale over long distances.

Response: The SDT agrees with your suggestion, and has incorporated this concept into the revised introductory paragraph for Exclusion E3.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and

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Yes or No

Question 9 Comment

c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
PUD No. 2 of Grant County,
Washington

Yes

Grant supports the categorical exclusion of Local Distribution Networks from the BES. We believe the
exclusion is necessary to ensure that the BES definition complies with the statutory requirement to exclude
all facilities used in the local distribution of electric power. LDNs are, of course, probably the most common
kind of local distribution facility. Further, the conversion of radial systems to local distribution networks
should be encouraged because networked systems generally reduce losses, increase system efficiency, and
increase the level of service to retail customers. Grant supports the LDN exclusion, but we believe the
exclusion should be refined in the following respects: o The SDT’s draft states that:”LDN’s are connected to
the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail
customer Load.” (emphasis added) We recommend that the SDT revise the sentence quoted above as
follows: “LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to improve
the level of service to retail customer Load and not to accommodate bulk transfers of power across the
interconnected bulk system.” By instituting this suggestion, the SDT would emphasize the key difference
between an LDN, which is designed to reliably serve local, end-use retail customers, and the BES, which is
designed to accommodate bulk transfer of power at wholesale over long distances.Two more suggestions:
Bullet d, starts with “bulk power” and ends with generic “energy” transferred through and out of the LDN. This
is inconsistent and will likely lead to confusion.
In addition, “paper only” contract path transfers that result in no physical flow across the LDN should be
specifically excluded.

Response: The SDT agrees with your suggestion, and has incorporated this concept into the revised introductory paragraph for Exclusion E3.
The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term “bulk power”
was retained in the paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.
The SDT disagrees with the suggestion that “paper only” contract path transfers that result in no physical flow be specifically excluded, as the use of a local
network for transaction scheduling purposes causes it to be serving a transmission function. Where transactions are scheduled through the facilities of a local
network, some physical flow change will occur in accordance with the transfer distribution factor of the network in relation to the transaction source and sink.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:

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Organization

Yes or No

Question 9 Comment

Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Clallam County PUD No.1

August 19, 2011

Yes

Clallam strongly supports the categorical exclusion of Local Distribution Networks from the BES. In fact, for
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to ensure
that the BES definition complies with the statutory requirement to exclude all facilities used in the local
distribution of electric power. LDNs are, of course, probably the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the level of
service to retail customers. Clallam also supports, with the reservations discussed below, the LDN exclusion
as drafted by the SDT. At least conceptually, we believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be classified
as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified by the SDT
without compromising the reliability of the interconnected bulk transmission system.Although Clallam
supports the LDN exclusion, we believe the exclusion should be refined in the following respects: o The
SDT’s draft states that:”LDN’s are connected to the Bulk Electric System (BES) at more than one location
solelyto improve the level of service to retail customer Load.” (emphasis added)We are concerned that the
use of the term “solely” implies the need for an examination of the motives of a local distribution utility in
connecting to the BES at more than one location. This result is problematic because it defeats the purpose
of the exclusion, which is to allow LDNs to be excluded from the BES without an in-depth and expensive
inquiry into the exact nature of the LDN. In addition, the local utility may have a number of motives for
connecting to the BES at more than one location, but the local utility’s motives have nothing to do with how
the LDN interacts with the interconnected bulk system, which should be the key determinant in including or
excluding any Element from the BES. With these concerns in mind, we therefore recommend that the SDT
revise the sentence quoted above as follows: “LDN’s are connected to the Bulk Electric System (BES) at
more than one location solely to improve the level of service to retail customer Load and not to accommodate

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Yes or No

Question 9 Comment
bulk transfers of power across the interconnected bulk system.” By instituting this suggestion, the SDT would
emphasize the key difference between an LDN, which is designed to reliably serve local, end-use retail
customers, and the BES, which is designed to accommodate bulk transfer of power at wholesale over long
distances.
o We believe the characteristics specified by the LDN in subsections (b) and (c) of the exclusion are
redundant. Subsection b specifies that the LDN would not interconnect more than 75 MVA of generation in
aggregate. Subpart c specifies that power flows only into the LDN. We believe the SDT can eliminate
subpart b of the definition and simply rely on subpart c because if power only flows into the LDN even if it
interconnects more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system, only with the LDN. Further, with the
advent of distributed generation, it is easy to foresee a situation in which a large number of very small
distributed generators are interconnected into a LDN, so that the aggregate capacity of these generators
exceeds 75 MVA. However, because the generators are small and dispersed and, under the subpart c
criteria, would be wholly absorbed within the LDN rather than transmitting power onto the interconnected grid,
those generators would not have a material impact on the grid. In addition, the 75 MVA criterion would make
an LDN interconnecting more than 75 MVA part of the BES. For the reasons set forth by the Project 2010-07
SDT, we are concerned the result will be the local utility being improperly classified as a Transmission Owner
and Transmission Operator, which would subject the local utility to a number of reliability standards that
would significantly increase its compliance burden without substantially improving bulk system reliability. In
fact, in the LDN situation, there is even less reason to impose these burdens on the local utility than in the
situation addressed by the Project 2010-07 team, where generators are interconnected to the BES by
dedicated interconnection facilities. Because the LDN is interconnected at multiple points, the generators
interconnected to the LDN could continue to operate even if one or two interconnection points are out of
service. On the other hand, in the situation addressed by the Project 2010-07 team, if the dedicated
interconnection facility is out of service, the generation is unavailable because there is no alternative route to
deliver it to load.
Finally, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale adoption
of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry lacks adequate
technical justification. The SDT repeats that error here by incorporating those thresholds into the LDN
exception.

Response: The SDT has made changes to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network; however,
the SDT believes that the descriptive language adds necessary context to the entire exclusion principle and therefore should be retained.
The SDT has determined that a generation limit is appropriate from a bright-line perspective to qualify these local networks as distribution; however, in the
revised Exclusion E3, the limits on connected generation have been made somewhat less restrictive as indicated in E3.a. Also, the revised Exclusion E3 now

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Yes or No

Question 9 Comment

specifically excludes from consideration the “behind the meter” generation in the limits on connected generation. Entities that own/operate facilities that are not
necessarily captured for exclusion by Exclusion E3 can still pursue exclusion through the RoP Exception Process.
The SDT notes that the responses to the comments in the first posting of the BES Definition did not yield any technically-based alternatives to the generation
thresholds of the ERO Statement of Compliance Registry Criteria (SCRC), and as such, the SDT has no technical rationale to deviate from the SCRC. After
consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at
this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will
be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and
the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization
Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
FortisBC

August 19, 2011

Yes

We agree with this concept as part of establishing a bright-line definition along with this clarifying exclusion in
the revised BES definition. However, requirements in Exclusion E3 are restrictive and we do not agree to the
limits on connected generation for Local Distribution Networks (LDN), described in part (b). The development
and implementation of distributed generation will grow considerably in the future and will operate together
with conventional sources of energy. The real net aggregated power of distributed generation seen by the
bulk power system at the interconnection may be larger than past experience; hence it requires to be
reassessed based on technical studies with respect to the future integration of DG’s. (Please refer to
comments in questions: 3 & 4)

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Question 9 Comment
Also, we suggest combining exception E3 (c) and (d) as follows:”(c) Power is intended to flows only into the
LDN: The generation within the LDN shall not exceed the electric Demand within the LDN; The LDN is
intended to deliver power to load and not be used to transfer bulk power between different locations in the
BES. It is recognized that under specified system conditions, bulk power transfers may take place between
different points of the BES via the LDN. However, for these conditions BES reliability is not dependent on the
existence of these power flows through the LDN.”Finally, we suggest and urge the SDT to carefully craft the
exception criteria & procedure that is flexible and technically sound to adequately allow entities to present
their case, and/or unique characteristics of the elements under exception to the ERO for exclusion

Response: The SDT has determined that a generation limit is essential to qualify these local networks as distribution; however, in the revised Exclusion E3, the
limits on connected generation have been made somewhat less restrictive as indicated in E3.a. Also, the revised Exclusion E3 now specifically excludes from
consideration the “behind the meter” generation in the limits on connected generation.
The revised Exclusion E3 now combines the prior items E3.c and E3.d into a revised item E3.b.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Sierra Pacific Power Co d/b/a NV
Energy

August 19, 2011

Yes

NV Energy strongly supports the definitional exclusion of LDN’s from the BES, and such exclusion is
necessary to ensure that the BES definition meets the statutory requirement to exclude all facilities used in
the local distribution of electric power.In the characteristics of the LDN, item (d) should be clarified to
eliminate the ambiguity that arises from the term “used”. We suggest the following revision:Not intentionally

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Organization

Yes or No

Question 9 Comment
used to transfer bulk power: The LDN is not used to provide a transaction scheduling path for, nor
intentionally used to accommodate the transfer of, energy originating outside the LDN for delivery through the
LDN;

Response: The SDT has incorporated this suggestion into the revised language of Exclusion E3.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Consumers Energy Company

Yes

LDN needs to be specifically defined. The draft appears to come close with the term “Groups of Elements
operated above 100kV that distribute power to Load rather than transfer bulk power across the
interconnected System.” These Groups of Elements should be contiguous to avoid confusion.
We are also concerned with the limits on connected generation.

Response: The SDT agrees with the suggestion regarding the contiguous nature of these local networks and has incorporated that suggestion into the revision
of Exclusion E3.
The SDT received many comments on the limits of connected generation, and it has made this provision somewhat less restrictive as shown in the revised item
E3.a.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher

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Yes or No

Question 9 Comment

are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Sacramento Municipal Utility
District (SMUD)

Yes

SMUD agrees with the concept for Exclusion 3. However, sub-bullet “C” should address potential for integral
values for variations of the load to the connected resource.

Response: The SDT has removed the concept of comparison of generation to electric demand, and instead has moved to a simpler limit on connected
generation.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a

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Yes or No

Question 9 Comment

major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Puget Sound Energy

Yes

As suggested in Q1. If a limit on total aggregate load served by LDN is included, that would improve the
clarity of this exclustion.

Response: To address similar concerns about the size of a local network, the SDT has now introduced a voltage cap for the LN exclusion of 300 kV.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Illinois Municipal Electric Agency

Yes

With the following clarfying edits. “Local Distribution Networks (LDN): Groups of Elements operated above
100 kV that are primarily intended to distribute power to Load rather than to transfer bulk power across the
Interconnected System.” The second sentence should be revised as follows: “LDN’s are connected to the
Bulk Electric System (BES) from more than one Transmission source solely to improve the level of service to
retail customer Load.”

Response: The SDT has made changes to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to

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Yes or No

Question 9 Comment

accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Clark Public Utilities

Yes

Clark strongly supports the categorical exclusion of Local Distribution Networks from the BES. Clark also
believes that adopting a 200 kV bright-line threshold will result in most, if not all, LDN being exempted from
the BES without any need to analyze or self-certify an LDN. This is another case where a higher threshold
(with an appropriate inclusion process) will have no affect on BES reliability but will focus resources on
investigation low voltage facilities that truly have an impact on interconnected system operations. Clark does
recommend a revision to the LDN exclusion language. E3 - Local distribution networks (LDNs): Groups of
Elements operated above 100 kV that distribute power to Load rather than transfer bulk power across the
interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one location
solely to improve the level of service to retail customer Load and not to accommodate bulk transfers of power
across the interconnected bulk system. The LDN is characterized by all of the following:

Response: The SDT has not uncovered nor been presented with any technical rationale for deviating from the voltage threshold of 100 kV in the definition of
BES; however, the SDT believes that the revised definition speaks to, and sufficiently identifies, the exclusion of the facilities used for distribution functions.
The SDT has made changes to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;

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Yes or No

Question 9 Comment

a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
City of Anaheim

Yes

In E3 (b) use the same language as in E1 (b), i.e. Only including generation resources not identified in
Inclusions I2, I3, I4, and I5. This avoids re-defining all of the generator provisions here. At a minimum
"operated at a voltage of 100 kV or above" should be added at the end of E3 (b).

Response: The SDT has made modifications to the new item E3a, which addresses this concern.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

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Organization
AltaLink

Yes or No

Question 9 Comment

Yes

We agree with this concept as part of establishing a bright-line definition along with this clarifying exclusion in
the revised BES definition. However, requirements in Exclusion E3 are restrictive and we do not agree to the
limits on connected generation for Local Distribution Networks (LDN), described in part (b). The development
and implementation of distributed generation will grow considerably in the future and will operate together
with conventional sources of energy. The real net aggregated power of distributed generation seen by the
bulk power system at the interconnection may be larger than past experience; hence it requires to be
reassessed based on technical studies with respect to the future integration of DG’s. We suggest and urge
the SDT to carefully craft the exception criteria & procedure that is flexible and technically sound to
adequately allow entities to present their case, and/or unique characteristics of the elements under exception
to the ERO for exclusion.

Response: The SDT has determined that a generation limit is appropriate from a bright-line perspective to qualify these local networks as distribution; however,
in the revised Exclusion E3, the limits on connected generation have been made somewhat less restrictive as indicated in E3.a. Also, the revised Exclusion E3
now specifically excludes from consideration the “behind the meter” generation in the limits on connected generation. Entities that own/operate facilities that are
not necessarily captured for exclusion by Exclusion E3 can still pursue exclusion through the RoP Exception Process.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Modern Electric Water Company

August 19, 2011

Yes

Similar to our Question #7 comments regarding radial exclusions in E1, a usable BES definition excluding
local distribution networks (LDNs) is needed to allow this industry to focus on and conduct business in a

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Question 9 Comment
fashion that promotes reliable and efficient system operation. In line with a 1/18/2011 Executive Order
directing federal regulatory agencies to base their practices on science and to consider costs, excluding
LDNs from the BES definition would achieve that aim on a national scale. While differing only in connectivity,
LDNs operate and function exactly as radial systems. We suggest modifying the second and third sentences
of E3 as “LDNs are normally operated such that they are connected to the BES through more than one AFID
simultaneously, and exist to promote the level of service to Loads as commonly defined by states’ utility
commissions. For a System to be characterized as an LDN, it must meet all of the following:”Sub-bullet E3-c
should be clarified to indicate conditions, timeframes and metrics used to demonstrate power flow
direction.We support the intent of the remaining sub-bullets.

Response: The SDT has made changes to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network.
The SDT has revised the Exclusion E3 local network in a way that removes the mention of automatic fault interrupting devices.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Michgan Public Power Agency

Yes

I question the technical justification for the 75 MVA and the 100 KV as pointed out in my comments above.
But given those points addressed above I would suggest the following clarification be considered.
The exclusion refers to groups of Elements that “distribute power to Load rather than transfer bulk power
across the interconnected system.” The use of the term “bulk power” is vague and could be read incorrectly
as a reference to the “bulk-power system,” which is defined in the Federal Power Act but is not a NERC

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Yes or No

Question 9 Comment
defined term.
If the LDN is connected to the BES at more than one location, there will by definition be some loop flow. We
recommend below that Exclusion 3(d) be revised to quantify the amount of loop flow that is permissible in an
excluded LDN.
In the context of the first sentence of Exclusion E3, less specificity is needed, and the sentence should only
be revised for the sake of accuracy to state: “Groups of Elements operated above 100 kV that are primarily
intended to distribute power to load rather than to transfer power across the interconnected System.”
The exclusion’s reference to connection “at more than one location” is vague. The sentence should be
revised to read “connected to the Bulk Electric System (BES) from more than one Transmission source solely
to improve the level of service to retail customer Load,” and “Transmission source” should have the same
meaning that it does in E1.
E3(a) should require that there be switching devices between the LDN and the BES, not specifically
automatic fault-interrupting devices. The term “separable by” in “Separable by automatic fault interrupting
devices” is unclear and should be reworded.
E3(b) To avoid pulling an LDN into the BES based on very small customer-owned generation (such as
rooftop photovoltaics and hospital backup diesel generators) that the utility does not consider or rely on, or
necessarily even know about, the item should be reworded: “Limits on connected generation: Neither the
LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA of generation used to meet the
resource -adequacy requirements of electric utilities.”
E3(d) states “Not used to transfer bulk power.” As noted above, “bulk power” is a vague term. There will
necessarily be some loop flow on a system that is connected to the BES at more than one location. The
amount of permissible loop flow for this purpose needs to be determined and stated in this item.

Response: The SDT has not uncovered nor been presented with any technical rationale for deviating from the voltage threshold of 100 kV or 75 MVA in the
definition of BES; however, the SDT believes that the revised definition speaks to, and sufficiently identifies, the exclusion of the facilities used for distribution
functions. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary
focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the
NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a
new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term “bulk power”
was retained in the paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.

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Yes or No

Question 9 Comment

The SDT has revised the Exclusion E3 Local Network in a way that removes the mention of automatic fault interrupting devices.
The SDT has made changes to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network.
After consideration of the establishment of limits on flow-through, the SDT has elected to make modifications to the local network characteristics to preclude the
scheduled use of the network for flow-through rather than establishing a MW limit or transfer distribution factor. The SDT has determined that this is appropriate
from a bright-line perspective to qualify these local networks as distribution; Entities that own/operate facilities that are not necessarily captured for exclusion by
Exclusion E3 can still pursue exclusion through the RoP Exception Process.
The revised Exclusion E3 now specifically excludes from consideration the “behind the meter” generation in the limits on connected generation.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Utility System Efficiencies, Inc.

Yes

USE agrees in concept with this Exclusion. However, in sub-bullet b), as noted in our response to Question 4,
there is no technical justification for the 75 MVA threshold on connected generation.
In sub-bullet c), it should be clarified whether this requirement is at any time or is for hourly integrated values.
Also in sub-bullet e), the use of the term “major transfer paths” should be modified to be “major transfer paths
in the Table titled Major WECC Transfer Paths in the Bulk Electric System.” Finally, the reference to “above
100 kV” should be “at or above 100 kV” for consistency with the rest of the definition.

Response: See response to Q4.

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Question 9 Comment

The SDT has determined that a generation limit is appropriate from a bright-line perspective to qualify these local networks as distribution; however, in the
revised Exclusion E3, the limits on connected generation have been made somewhat less restrictive as indicated in E3.a. Also, the revised Exclusion E3 now
specifically excludes from consideration the “behind the meter” generation in the limits on connected generation. Entities that own/operate facilities that are not
necessarily captured for exclusion by Exclusion E3 can still pursue exclusion through the RoP Exception Process.
The revised version of the Exclusion E3 language removes the comparison of connected generation to network demand.
The new item E3.c clarifies the language regarding WECC major paths.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Cowlitz County PUD

August 19, 2011

Yes

Cowlitz strongly supports the categorical exclusion of Local Distribution Networks from the BES. In fact, for
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to ensure
that the BES definition complies with the statutory requirement to exclude all facilities used in the local
distribution of electric power. LDNs are, of course, probably the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the level of
service to retail customers. Cowlitz supports the LDN exclusion, but we believe the exclusion should be
refined in the following respects: o The SDT’s draft states that:”LDN’s are connected to the Bulk Electric
System (BES) at more than one location solely to improve the level of service to retail customer Load.”
(emphasis added) We recommend that the SDT revise the sentence quoted above as follows: “LDN’s are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service

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Question 9 Comment
to retail customer Load and not to accommodate bulk transfers of power across the interconnected bulk
system.” By instituting this suggestion, the SDT would emphasize the key difference between an LDN, which
is designed to reliably serve local, end-use retail customers, and the BES, which is designed to
accommodate bulk transfer of power at wholesale over long distances. We propose that a reliable BES will
help insure a reliable LDN. If the LDN is not reliable, it should then be an issue to be resolved by the local
authorities. If the BES is not reliable, the local authorities lack the tools to remedy the situation.

Response: The introductory paragraph in Exclusion E3 has been revised to eliminate the term “solely” and to explain that the local network does not
accommodate bulk transfer across the interconnected system.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
New England States Committee
on Electricity

Yes

NESCOE believes that this language appropriately excludes facilities that serve local distribution loads from
the BES.

Public Utilities Commission of
Ohio

Yes

Exclusion 3 is appropriate. This reflects the reality that local distribution can be at any level. As a reminder
the Commission proposed seven indicators of local distribution to be evaluated on a case-by-case basis:(1)
Local distribution facilities are normally in close proximity to retail customers.(2) Local distribution facilities are
primarily radial in character.(3) Power flows into local distribution systems; it rarely, if ever, flows out.(4)
When power enters a local distribution system, it is not reconsigned or transported on to some other
market.(5) Power entering a local distribution system is consumed in a comparatively restricted geographical

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Question 9 Comment
area.(6) Meters are based at the transmission/local distribution interface to measure flows into the local
distribution system.(7) Local distribution systems will be of reduced voltage.This test clearly indicates that not
all radial circuit lines are the same. This exclusion would not only appropriately apply the seven factor test,
but also comply with the Federal Power Act regarding appropriate authority.

New York State Dept of Public
Service

Yes

This exclusion properly recognizes that local distribution facilities can be at any voltage level. It also properly
recognizes that reliable service to load often requires parallel circuits. As written, the exclusion respects
FERC’s concern that major generation facilities should not be part of the LDN, by limiting the exclusion to
generation of75 MVA or less, and to only facilities that move energy down to the LDN.

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

Yes

No comment.

Oregon Public Utility Commission
Staff

Yes

Exclusion E3 is absolutely necessary for excluding local distribution elements from the interconnected bulk
transmission system as required by Section 215 of the FPA of 2005. This exclusion mirrors the Seven Factor
Test (established in FERC Order 888), which sets sound overarching principles for differentiating local
distribution elements from bulk transmission elements. Also, the conversion of radial systems to local
distribution networks is generally implemented by a distribution provider to improve the level of service to
local retail customers, not to accommodate bulk transfer of wholesale power.Retaining Exclusion E3 is
absolutely crucial for maintaining the 100 kV brightline in the core BES definition. Without the distribution
network E3 exclusion, the voltage threshold in the core BES definition would need to be changed to the 200
kV level. Otherwise, NERC and Regional Entities will have to deal with endless exception applications and
evaluations associated with the removal of local distribution elements that have no impact on the reliable
operation of the interconnected bulk transmission system.

National Association of
Regulatory Utility Commissioners

Yes

Exclusion 3 is essential for the standard to conform to Federal Power Act Section 215 that clearly excludes
local distribution from FERC and NERC jurisdiction. The exclusion properly recognizes that local distribution
can operate at above 100 kV. This exclusion seems to reflect the essence of the Seven Factor test from
FERC’s Order 888. Although FERC Order 743A did not bind NERC to the Seven Factor test, it makes sense
to pursue consistency between these tests.

Michigan Public Service
Commission(MPSC)

Yes

MPSC Staff Comments: The MPSC strongly supports this exclusion because it should exclude a large
number of subtransmission facilities that are used for the distribution of local load. Also, this exclusion

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Question 9 Comment
together with E1 parallels the seven-factor technical-functional test for classifying transmission and
distribution. The problem with the seven-factor test is that it does not provide an on-going clear bright line for
BES determination. For example, an engineer cannot apply the seven-factor test using a one-line diagram of
an electric power network and determine - without supplemental evidence - that an element is classified as
distribution or not.

FHEC

Yes

Public Service Enterprise Group
LLC

Yes

Imperial Irrigation District

Yes

Santee Cooper

Yes

ACES Power Participating
Members

Yes

National Rural Electric
Cooperative Association
(NRECA)

Yes

Arizona Public Service Company

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

New York Power Authority

Yes

Southern Company

Yes

Luminant Energy

Yes

Western Area Power
Administration

Yes

August 19, 2011

We support the current wording of E3.

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US Bureau of Reclamation

Yes

Grand Haven Board of Light and
Power

Yes

Glacier Electric Cooperative

Yes

South Texas Electric
Cooperative, Inc.

Yes

South Texas Electric
Cooperative, Inc.

Yes

Sweeny Cogeneration LP

Yes

Dayton Power and Light
Company

Yes

Duke Energy

Yes

Alberta Electric System Operator

Yes

Fayetteville Public Works
Commission

Yes

MidAmerican Energy Company

Yes

American Electric Power

Yes

East Kentucky Power
Cooperative, Inc.

Yes

American Transmission
Company, LLC

Yes

August 19, 2011

Question 9 Comment

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Farmington Electric Utility System

Yes

GTC

Yes

Idaho Power

Yes

Pepco Holdings Inc

Yes

PJM

Yes

Oncor Electric Delivery Company
LLC

Yes

MEAG Power

Yes

Xcel Energy

Yes

Orange and Rockland Utilities,
Inc.

Yes

Golden Spread Electric
Cooperative, Inc.

Yes

Question 9 Comment

Response: Thank you for your support. Based on stakeholder comments, the SDT modified the local network exclusion in the following manner:
Elimination of the term “Distribution” in the label of this exclusion, making it a “local network”.
Changes were made to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network, including a statement that the
local network does not accommodate bulk transfer across the interconnected system.
Eliminated the provision in Exclusion E3.a which referred to automatic fault interrupting devices, and changed wording to clarify the connection point of the local
network.
Please see the revised definition.

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10.The SDT is discussing an exclusion from the Bulk Electric System (BES) for small utilities based on
statements in Order No. 743 that FERC does not believe its suggested approach to the BES definition and
exemption process will have a significant economic impact on a substantial number of small entities and
that small entities will not adversely impact the reliability of the Bulk Electric System. The SDT has been
made aware that organizations that are not presently required to be registered by the NERC Statement of
Compliance Registry Criteria would meet the requirements to be registered as Transmission Owners given
the current proposed BES definition. These small utilities could use the Rules of Procedure (ROP) exception
process but this may be an issue that could be handled more appropriately through the BES definition. This
would alleviate the paperwork burden for these small utilities and also avoid a possibly unnecessary and
significant impact on the administration of the ROP exception process during the transition period to the
revised BES definition. The proposed exclusion language is:
Exclusion E4: Transmission Elements, from a single Transmission source connected at a voltage of 100 kV or
greater, owned by a small utility whose connection to the BES is solely through this single Transmission
source, and without interconnected generation as recognized in the BES Designation Inclusion Items I2, I3,
I4, or I5. A small utility is recognized as an entity that performs a Distribution Provider or Load Serving
Entity function but is not required to register as a Distribution Provider or Load Serving Entity by the ERO.
Do you agree with this approach and the proposed language? If not, please be specific in your response
with a technical reason for your disagreement and, if appropriate, suggested language for such an exclusion
if you agree in general but feel that alternative language would be more appropriate.

Summary Consideration: The basis for the additional exclusion was predicated by the circumstances of radial systems and
the demarcation of the automatic interrupting device. With the change of the demarcation point back to the point where the
tap line intersects with the transmission line; this proposed exclusion is unnecessary. The SDT will drop consideration for this
proposed exclusion given the change to radial systems. This shall serve as a single response to all comments submitted in
response to this question.

Organization
Northeast Power Coordinating
Council
Hydro One Networks Inc

August 19, 2011

Yes or No

Question 10 Comment

No

Small utility or distribution provider is a relative term. A distribution provider may have an impact on the
transmission network based on its design, configuration, connection point, and protection. Such an exception
should apply regardless of the size of an entity. The concept discussed here is to define a radial system and
not a small utility, as mentioned in the FERC Order. We do not believe that the SDT had sufficient discussions
while crafting the proposed exclusion in regards to small utilities. The language used in the proposed clause

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Question 10 Comment
is only appropriate to establish a bright-line definition for a radial system.Many small utilities (and individual
load customers or generation connections) have more than a single transmission source with a solid tap and,
at the same time, be adequately protected and effectively isolated without any adverse impact on the
transmission network. Such a practice and design is widely used across North America. Hence, we do not
agree that this exclusion is an attempt to address the issue of small utilities. The definition and inclusions will
force many small entities, load customers and generation unit owners to act and register as Transmission
Owners. This may be in conflict with state or provincial regulatory act, Codes and Licenses. Consistent with
the FERC Order, the ERO and the SDT should be aware of these conflicts and should not ignore them. The
ERO and the SDT address this by providing explicit but simple provisions in the exception procedure by
considering sound technical exception criteria that is flexible based on demonstration of evidence to justify the
element’s necessity for operation. Regulatory Acts and Rules will always overrule NERC requirements and
the only evidence that should be required of small utilities/entities is: o Regulatory evidence o Evidence
demonstrating that NO adverse reliability impact is afflicted on the interconnected BES because of their
connection.

Tri-State Generation and
Transmission Association, Inc.

No

We disagree with adding E4. This issue should be resolved by enhancing the NERC Statement of
Compliance Registry Criteria, not by integrating registration exemptions in NERC definitions.

NERC Staff Technical Review

No

The basis for exclusion must be based on system reliability. The need for an interrupting device between the
BES and excluded radial Elements is necessary for system reliability independent of ownership of the
excluded radial Elements.

Dominion

No

It is Dominion’s position that, all things being equal a generator or a load have similar, but typically inverse
impacts of the bulk power system. The burden for small entities is similar, whether that entity is a LSE, DP,
GO or GOP.

SPP Standards Review Group

No

What’s the difference between the proposed E4 and E1(a)? Wouldn’t they be the same?
Would it be more appropriate to use single point of Transmission interconnection rather than single
Transmission source in E1 and E4?

SERC Planning Standards
Subcommittee

No

This seems to be covered by E1.

South Carolina Electric and Gas

No

This seems to be covered by E1.

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Question 10 Comment

Michigan Public Service
Commission(MPSC)

No

MPSC Staff Comments: The BES definition proposed by the SDT should not use the term “transmission”.
BES should not equal transmission. A system element defined as BES should not determine jurisdiction,
ownership, or require duplicative NERC registration.

SERC OC Standards Review
Group

No

We suggest that our comments to Question 3 and Question 4 be incorporated.

Idaho Falls Power

No

Just as 100kv is an arbitrary number, so is 20MVA. We appreciate the NERC efforts made to define
transmission material to the BES, and likewise feel the same efforts should be applied to small generation
resources. There exists a large number of utilities with small generation serving local load on an LDN that will
be possibly drawn into TO/TOP standard's compliance by the language in this draft.We hope the drafting
team will define BES generation beyond a brightline criteria, as 20MVA lends no more clarity as to what is a
BES asset than does 100kV.We believe it should be demonstrated as to why 20MVA is deemed a generation
threshold of materiality to the BES. The opportunity now exists to address thresholds, not just the 100kV.

Western Electricity Coordinating
Council

No

As written, it is unclear how this exclusion differs from the Radial exclusion.

We also question whether this is going to have an unintended consequence of requiring Distribution Providers
to register that otherwise wouldn’t have to register because some technical aspect has not been included in
this exception.

The term “single Transmission source” needs to be clarified - it could be read to be a single line or a single
entity, which would change the meaning of this exclusion.
It is also improper to include registration criteria in a definition.
Furthermore, “small utility” needs to be defined more clearly. The last sentence appears circular because
ownership of a transmission element would draw the owner into registration.

ReliabilityFirst

No

it needs to be clear that "all" items must be met to be excluded in E4,
E4b seems to conflict with I2 that states it needs included,
E4a should state a single source unless LDNs are allowed mutilple sources and then could be considered
networked, E4c needs to define who make a the determination on flow and under all system configurations

Southern Company

No

This seems to be covered by Exclusions E1 and E3.

Electricity Consumers Resource

No

We support the concept and intent of the exclusion but it should apply equally to similarly situated loads such
as manufacturing facilities that have loads comparable to small municipalities or rural cooperative utilities.

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Council (ELCON)

Central Maine Power Company

Question 10 Comment
Thus the language should be amended as noted below:"Exclusion E4: Transmission Elements, from a single
Transmission source connected at a voltage of 100 kV or greater, owned by a small utility or similarly situated
load whose connection to the BES is solely through this single Transmission source, and without
interconnected generation as recognized in the BES Designation Inclusion Items I2, I3, I4, or I5. A small
utility or similarly situated load is recognized as an entity that performs a Distribution Provider or Load Serving
Entity function but is not required to register as a Distribution Provider or Load Serving Entity by the ERO."

No

This exclusion E4 seems to already be covered under the E1 “radial” exclusion.

Intellibind

No

This does not address the full concerns of these small entities. In on case I am familiar with the entity has a
switchyard over 100KV and it was convenient for the interconnected utility to utilize the location of the
switchyard to add a line for the Transmission Operators purpose, however now that there are two lines into
the switchyard it has affected the small utility and they will not have exemption as described in Question 10.
The financial burden is very high for these entities when not exempted. In this particular case noted above,
the entity is planning to eventually decommission its system, but is caught in having to bear the cost of
operating a transmission system even though it is only one substation that is immediatly stepped down to
13.8Kv and feeding a small distributed load. The proposed exemption will still not allow this entity to be
exempt.The ROP process does not serve these small utilities well as an alternative and the Drafting Team
should resolve these issues in the definition of the BES if possible.

Hydro-Quebec TransEnergie

No

The case of small Utility is covered through other exclusions. However, the Facilities owned by small utility
should have protection requirement applied.

US Bureau of Reclamation

No

The small entities can seek exclusion using the BES Exception Process developed under this project.

Grand Haven Board of Light and
Power

No

We agree with addition of Exclusion E4, except that it should apply to small load serving distribution utilities
even if they are required to register as a Distribution Provider and Load Serving Entity. In our last fiscal year,
July 2009 through June 2010, the Grand Haven Board of Light and Power served 262,847 MWh and peaked
at 54 MW. Even though we are required to register as DP/LSE, we are still a small utility. Please revise the
definition of a small entity for the purpose of this exception to use more reasonable criteria.

South Texas Electric
Cooperative, Inc.

No

I agree with everything up to “...but is not required to register...by the ERO”. There are many small utilities
that fit into the scope and spirit of the exclusion BUT were required to register as DP and/or LSE by their
ERO. This has generally been on the interpretation of “better safe”. Please remove the language which gives

New York State Electric & Gas
and Rochester Gas & Electric

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Question 10 Comment
this discretion to the ERO and insert language allowing already registered small utilities with have their
registrations revoked or surrendered.

National Grid

No

This exclusion is not necessary. Many small utilities (and individual load customers or generation
connections) have more than a single transmission source with a solid tap and, at the same time, be
adequately protected and effectively isolated without any adverse impact on the transmission network. Such a
practice and design is widely used across North America. Hence, we do not agree that this exclusion is an
attempt to address the issue of small utilities. The definition and inclusions will force many small entities, load
customers and generation unit owners to act and register as Transmission Owners. This may be in conflict
with state or provincial regulatory act, Codes and Licenses, and may lead to jurisdictional challenges that
could cause uncertainty and delay in implementing the new BES definition. Consistent with the FERC Order,
the ERO and the SDT should be aware of these conflicts and should not ignore themThe ERO and the SDT
address this by providing explicit but simple provisions in the exception procedure by considering sound
technical exception criteria that is flexible based on demonstration of evidence to justify the element’s
necessity for operation. The only evidence that should be required of small utilities/entities is: o Regulatory
evidence. o Evidence demonstrating that NO adverse reliability impact is afflicted on the interconnected BES
because of their connection.

Electric Reliability Council of
Texas, Inc.

No

These entities should be subject to the exception process. They may warrant “first instance” exclusion in that
process, but any such action should occur there, as opposed to the definition of BES. ERCOT ISO believes
this is more consistent with FERC’s position that BES should reflect an objective threshold, with exceptions
being subject to review by the ERO and FERC, as applicable. Accordingly, ERCOT ISO suggests that this
issue be raised in the concurrent BES exception proceeding and ERCOT ISO reserves its right to comment
on the substance in that proceeding.

ExxonMobil Research and
Engineering

No

While the exclusion for a small utility makes sense, the exclusion should not be limited to a utility company.
The SDT should extended the exclusion to similarly situated facilities or organizations with other primary
business functions, such as industrial companies.

FortisBC

No

Small utility or distribution provider is a relative term. A smaller distribution provider may have an impact on
the transmission network while a large one may not; this is based on their design, configuration and
protection. Hence, such an exception should apply regardless of the size of an entity. Having said that, the
concept discussed here is to define a radial system and not a small utility, as mentioned in the FERC Order.
We do not believe that the SDT had sufficient discussions while crafting the proposed exclusion in regards to
small utilities. The language used in the proposed clause is only appropriate to establish a bright-line
definition for a radial system.It is worth noting that many small utilities (and individual load customers or
generation connections) would have more than a single transmission source with a solid tap and, at the same

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Question 10 Comment
time, be adequately protected and effectively isolated without any adverse impact on the transmission
network. Such a practice and design is widely used across North America. Hence, we do not agree that this
exclusion is an attempt to address the issue of small utilities. The definition and inclusions will force many
small entities, load customers and generation unit owners to act and register as Transmission Owners. In
some parts of the continent this would be in conflict with state or provincial regulatory act, Codes and
Licenses. Consistent with the FERC Order, the ERO and the SDT should be aware of these conflicts and
should not ignore them for later. Hence, we suggest the ERO and the SDT address this by providing explicit
but simple provisions in the exception procedure by considering sound technical exception criteria that is
flexible based on demonstration of evidence to justify the element’s necessity for operation. Regulatory Acts
and Rules will always trump NERC requirements and hence we suggest that the only evidence that should be
required of small utilities/entities is:
o Regulatory evidence
o Evidence demonstrating that NO adverse
reliability impact is afflicted on the interconnected BES because of their connection.

American Transmission
Company, LLC

No

ATC believes that small utilities have interfacing responsibilities, and should not be exempt if they own
elements (e.g. CTs, batteries, etc.) that are part of a protection scheme that protects the BES Elements.

Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

No

There is no legal basis to distinguish between “small utilities” and other similarly situated entities. Thus, to
avoid unlawful discrimination, Exclusion E4 should be revised as follows:(Deleted language denoted by empty
brackets: [ ].) Exclusion E4: Transmission Elements, from a single Transmission source connected at a
voltage of 100 kV or greater [ ] whose connection to the BES is solely through this single Transmission
source, and without interconnected generation as recognized in the BES Designation Inclusion Items I2, I3,
I4, or I5. [ ]

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

No

An automatic interruption device should be required as in exclusion E1.

City of St. George

No

Is the transmission source a single line, a single substation? This needs to be defined.
What is a small utility? This needs to be defined.
Generation limits should also be revisited, see previous comments.

Southern California Edison
Company

August 19, 2011

No

Small utilities should not be automatically excluded from the BES if the BES Definition continues to focus on
the size of interconnecting generators to determine what facilities are included in the BES. Instead, small

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Question 10 Comment
utilities should be required to justify their exclusion using the exemption procedure and the Technical
Principles for Demonstrating BES Exceptions. This would provide the necessary oversight to ensure these
smaller systems continued to stay under the thresholds stipulated in the BES definition. In many areas, it is
both faster and less expensive for renewable generators to interconnect with these systems, thus potentially
allowing for the addition of large amounts of generation totaling more than the draft BES allowances within a
relatively short period of time.

Idaho Power

No

As written, it is unclear how this exclusion differs from the Radial exclusion. The term “single Transmission
source” needs to be clarified - it could be read to be a single line or a single entity, which would change the
meaning of this exclusion. It is also improper to include registration criteria in a definition. Furthermore, “small
utility” needs to be defined more clearly. The last sentence appears circular because ownership of a
transmission element would draw the owner into registration.

Cogentrix Energy, LLC

No

We suggest that our comments to Question 3 and Question 4 be incorporated.
We also question whether this is going to have an unintended consequence of requiring Distribution Providers
to register that otherwise wouldn’t have to register because some technical aspect has not been included in
this exception.

Clark Public Utilities

No

This proposed exclusion has no affect or benefit. If an entity is not required to register as a DP or LSE why do
they then need to be exempted from a standard that does not apply to the entity. The Commission was
obviously focusing on a small utility with facilities greater that 100 kV making that entity a Transmission
Owner. A 100 kV facility owned by a utility with a small amount of load is either material or immaterial to the
reliability of the BES irrespective of the amount of load that entity serves. Therefore the term ‘small utility”
must refer to some other measure of size. This may be size of load, but also may include circuit miles of
transmission greater than 100 kV, capacity of largest line greater than 100 kV line, and possible other
measures of “smallness.”

The Dow Chemical Company

No

If this is adopted, it should apply to industrial sites as well as small utilities.

PJM

No

There is no technical justification to include/exclude elements based on the asset size of the owning
company. The exclusion should be based on the technical merits.

New England States Committee
on Electricity

No

This appears overly restrictive in that it only includes networks connected at a single source. Please see
comments under 7 above.

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Question 10 Comment

Southwest Power Pool

No

These entities should be subject to the exception process within the exclusion criteria. They warrant a “first
instance” exclusion in that process, but any such action should occur there, as opposed to the definition of
BES. SPP believes this is more consistent with FERC’s position that BES should reflect an objective
threshold, with exceptions being subject to review by the ERO and FERC, as applicable. It may prove
through that process that these entities receive the presumption of exclusion, but that should take part in that
process as opposed to being granted a de jure exemption from the definition. Accordingly, SPP suggests that
this issue be raised in the concurrent BES exception proceeding as an exclusion criterion, and SPP reserves
its right to comment on the substance in that proceeding.

Manitoba Hydro

No

Small utilities should be excluded under the definition of the BES without requiring an additional and specific
exclusion.

ISO New England, Inc.

No

This exclusion would not be required if the automatic disconnect requirement was removed from E1. If E1 is
not modified as proposed herein then a MW threshold might have to be considered for this E4 definition.
E4 should have also been included in the draft definition as well as this comment form.

Xcel Energy

No

There seems to be an implication that if a facility is determined to be BES, registration is required. Yet, the
registration criteria already includes exclusion of users, owners and operators of the BES from registration, if
they do not meet all the criteria. So, we fail to see why a special exclusion is necessary.

Independent Electricity System
Operator

No

Small utilities may be impactive to the bulk power system and as such should not be subject to a carteblanche exemption but should be subject to assessment and if necessary exclusions after going through the
exception process. The outcome of the exception process may well be that such small utilities can be
excluded but this cannot be determined a priori.
In addition, Exclusion E4 is worded very similarly to Exclusion E1. It is not clear what additional facilities will
be excluded by E4 that are not already excluded by E1.

Golden Spread Electric
Cooperative, Inc.

No

Suggested revision: Transmission Elements, from a single Transmission source connected at a voltage of
100 kV or greater, owned by a small utility whose connection(s) to the BES is(are) solely through this(these)
single Transmission source(s), and without interconnected generation as recognized in the BES Designation
Inclusion Items I2, I3, I4, or I5. The intent of the revision is to exlude a small utility with multiple radial
connections to BES elements owned by others.

AltaLink

No

Small utility or distribution provider is a relative term. A smaller distribution provider may have an impact on
the transmission network while a large one may not; this is based on their design, configuration and

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Question 10 Comment
protection. Hence, such an exception should apply regardless of the size of an entity. Having said that, the
concept discussed here is to define a radial system and not a small utility, as mentioned in the FERC Order.
We do not believe that the SDT had sufficient discussions while crafting the proposed exclusion in regards to
small utilities. The language used in the proposed clause is only appropriate to establish a bright-line
definition for a radial system.It is worth noting that many small utilities (and individual load customers or
generation connections) would have more than a single transmission source with a solid tap and, at the same
time, be adequately protected and effectively isolated without any adverse impact on the transmission
network. Such a practice and design is widely used across North America. Hence, we do not agree that this
exclusion is an attempt to address the issue of small utilities. The definition and inclusions will force many
small entities, load customers and generation unit owners to act and register as Transmission Owners. In
some parts of the continent this would be in conflict with state or provincial regulatory act, Codes and
Licenses. Consistent with the FERC Order, the ERO and the SDT should be aware of these conflicts and
should not ignore them for later. Hence, we suggest the ERO and the SDT address this by providing explicit
but simple provisions in the exception procedure by considering sound technical exception criteria that is
flexible based on demonstration of evidence to justify the element’s necessity for operation. Regulatory Acts
and Rules will always trump NERC requirements and hence we suggest that the only evidence that should be
required of small utilities/entities is: o Regulatory evidence o Evidence demonstrating that NO adverse
reliability impact is afflicted on the interconnected BES because of their connection.

Modern Electric Water Company

No

The BES definition has already had a significant economic (and operational) impact on a substantial number
of small entities and those small entities have not adversely impacted the reliability of the BES. The
Commission (and the SDT) should also consider the other side of the coin - an improved BES definition could
have a positive impact on a significantly greater number of small entities than it will negatively impact small
entities otherwise not currently registered. Crafting exclusions properly with industry suggestions should limit
the small number affected by this proposed definition.
Additionally, we point out that in one instance the SDT states that the BES definition does not address
registration or the applicability of standards, yet in another instance is concerned what impact the definition
will have on an entity’s possible registration status. We don’t believe you can have it both ways or continue to
keep one’s proverbial head in the sand any longer.
We understand the SDTs scope is to provide a USABLE definition of the BES, but also understand that its
intent is two-fold: 1) to correct what the Commission believes is a gap in reliability due to regional discretion,
and 2) to remove ambiguity in what constitutes the BES so that industry can focus on and conduct business in
a fashion that promotes reliable and efficient system operation and so that the RROs can implement their
CMEPs. This second point is absolutely related to registration and the applicability of standards, and shouldn’t
be ignored.

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Organization

Yes or No

Question 10 Comment
As drafted, Exclusion E4 still would not allow for the exclusion of ALL small utilities that may inadvertently be
included in the BES based on the currently-drafted definition, even though they are, indeed, small utilities that
should be excluded from the BES. It appears that the SDT is struggling with the idea that the BES definition
should properly evaluate every single element in North America by itself. We believe this is why the term
“generally” was used in NERC’s Statement of Compliance Registry Criteria (SCRC), and why the issue of the
BES definition presently in front of the SDT cannot be entirely separated from registration and applicability of
standards.
If the SCRC will not be examined and modified similarly as the NERCs Rules of Procedure, then the BES
definition must include some “grey area deference” for small utilities such as is the intent of E4. If it is the
intent of the definition to exclude most small utilities from the BES, then exclusions should be granted based
entirely on the definition. Otherwise, as the SDT correctly states, the RoP-based exclusion process will be
flooded and ineffectual. As stated in the SCRC, the definition will initially identify those necessary, but still
allows for refinements later. The SCRC utilizes NERC’s approved definition of the BES, and will be
“improved” by this BES definition. Therefore, craft E4 with language that does not limit its intent to exclude
small utilities from the BES. Do not use metrics already used in other exclusions. Do not reference registration
requirements in exclusions that comprise the definition of the BES - the BES should not be defined in terms of
registration criteria. In Order 743, FERC defines a small utility in terms of an entity’s annual MWhs sold.
Consider aligning NERC’s and FERC’s definitions similarly.

City of Redding

No

Redding in theory supports this concept however the language proposed does little to improve the current
LDN and Radial exemptions. Redding would like the SDT to continue exploring the issue however we have no
suggestions for the definition level at this time. Redding does suggest that a viable alternative is to target this
issue via the exception process by allowing a exception method to use system or entity “characteristics” as
proof for an exception. This would allow a shorter and less burdensome exception process for small entities.

Tacoma Power

Tacoma Power supports the SDT’s thoughtful approach to minimizing impacts to small entities. They have no
measureable impact to the BES and should not be burdened with the exemption process.

Vermont Transco

The exclusion wording is difficult to understand and apply. Are their voltage levels where this would not apply
(ex. 230 kV) or load levels that would be seen as too high? Cannot agree or disagree due to the wording

Exelon

Exelon is abstaining from voting on this item. How would this exclusion be different from E1? Furthermore,
Exelon suggests that a definition of “Small Utility” would need to be developed.

BPA

Yes

August 19, 2011

Generally agree BPA would like to provide an exclusion for a small utility with multiple connections to a single
Transmission source connected at a voltage of 100 kV or greater. An example would be a single long 115 kV

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Organization

Yes or No

Question 10 Comment
transmission line passing through a rural area where a small utility utilizes multiple taps to the 115 kV line to
serve several radial systems

Cowlitz County PUD Cowlitz
County PUD

Yes

Cowlitz supports the SDT in its efforts to avoid unintended consequences from changes to the BES definition,
especially for small entities that can ill afford the substantial costs that accompany imposition of mandatory
compliance with reliability standards. Further, we agree that the small utilities covered by the exemption will
have no measurable impact on the operation of the interconnected BES. In the Pacific Northwest, many
small entities were required to register by virtue of owning a very small portion of the region’s 115-kV system.
These utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance therefore
will have no measurable effect in improving the reliability of the interconnected grid. Further, the such
resources used to comply with the reliability efforts unjustly take away from necessary resources needed for
local quality of service efforts.

Small Entity Working Group
(SEWG)

Yes

Yes, with some clarifying edits. The final sentence should be revised as follows: “For purposes of this
exclusion, a ‘small utility’ is an entity that performs a distribution provider or load serving entity function but is
not required to register as a Distribution Provider or Load Serving Entity by the ERO.”

Florida Municipal Power Agency

Yes

FMPA supports this exclusion. For the sake of clarity, the final sentence should be revised to read as follows:
“For purposes of this exclusion, a “small utility” is an entity that performs a Distribution Provider or Load
Serving Entity function but is not required to register as a Distribution Provider or Load Serving Entity by the
ERO.”

American Municipal Power and
Members

Yes

For the sake of clarity, the final sentence should be revised to read as follows: “For purposes of this exclusion,
a “small utility” is an entity that benefits from the utility of the BES, but does not meet the registry criteria to
perform functions in the BES."

National Rural Electric
Cooperative Association
(NRECA)

Yes

NRECA agrees with this approach, but also believes this could be addressed in the Statement of Compliance
Registry Criteria document.

Overton Power District No. 5

Yes

We support exclusion E4, for small utilities, but we are unclear how small utilities are defined in the exclusion
language presented here.

Transmission Access Policy
Study Group
Northern California Power
Agency

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Organization

Yes or No

Question 10 Comment

PacifiCorp

Yes

PacifiCorp believes this concept is appropriate with the following concern: Essentially the only difference
between this proposed exclusion and E1a is this proposed exclusion does not include “an automatic
interruption device”. So if the proposed E4 is left as a stand-alone exclusion it should also require “an
automatic interrupting device” qualifier. Technical justification for requiring an interrupting device is the same
justification used by the SDT in E1.

FHEC

Yes

this begs the question of the Statement of Compliance Registry Criteria being updated also.

South Texas Electric
Cooperative, Inc.

Yes

There are many small utilities that fit into the scope and spirit of the exclusion BUT are currently registered as
a DP and/or LSE. Will this exclusion remove them from registration OR should language be inserted that
automatically revokes the NERC registrations of “already registered” small utilities. I recommend that any
such revocation be handled by NERC and NOT by the various EROs for the sake of consistency.

Sacramento Municipal Utility
District (SMUD)

Yes

As written, it is unclear how this exclusion differs from the Radial exclusion.
Furthermore, “small utility” needs to be defined more clearly.
The last sentence appears circular because ownership of a transmission element would draw the owner into
registration. Small entities have no measurable impact to the BES and should not be burdened with the
exemption process.

Illinois Municipal Electric Agency

Yes

With the following clarifying edits. The final sentence should be revised as follows: “For purposes of this
exclusion, a ‘small utility’ is an entity that performs a distribution provider or load serving entity function but is
not required to register as a Distribution Provider or Load Serving Entity by the ERO.”

Michgan Public Power Agency

Yes

But I question if the "Small Entity definition" as indicated in Order 743 language "we certify that this Final Rule
will not have a significant economic impact on a substantial number of small entities." has been appropriately
addressed.

Public Utilities Commission of
Ohio

Yes

It appears this could be applied consistently with other exclusions.

New York State Dept of Public
Service

Yes

This exclusion is consistent with E1 and E2. There should not be discrimination against similarly situated
loads.

Springfield Utility Board

Yes

Springfield Utility Board supports the SDT in its efforts to avoid unintended consequences from changes to

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Organization

Yes or No

Question 10 Comment
the BES definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory compliance with Reliability Standards. Further, we agree that the small utilities
covered by the exemption will have no measureable impact on the operation of the interconnected BES. In
the Pacific Northwest, many small entities were required to register by virtue of owning a very small portion of
the region’s 115 kV system. These utilities have faced substantial compliance burdens even though their
operations are simply not material to the interconnected bulk grid in our region, and the investment of
resources in compliance, therefore, will have no measurable effect in improving the reliability of the
interconnected Grid.

Springfield Utility Board

Yes

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

American Electric Power

Yes

AEP agrees with the proposed exclusion to the extent that such excluded small utilities would continue to
provide any needed information the registered entities have requested from the excluded small utilities to
ensure the reliability compliance of those registered entities.

MidAmerican Energy Company

Yes

Arbitrarily excluding small entities could affect reliability depinding on the specific transmission facilities the
entity owns and/or operates.

Western Area Power
Administration

Yes

As discussed in the Applicability of Federal Power Act Section 215 to Qualifying Small Power Production and
Cogeneration Facilities document, the concerns regarding the Regulatory Flexibility Act Analysis of 1980
stated in section VII does not define the phrase a 'significant economic impact' from the perspective of a small
entity. A small entity may have staffed maintenance personnel, to accomplish its' own maintenance but now
prefers to transfer by written agreement with another entity based upon NERC's compliance registry criteria,

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Organization

Yes or No

Question 10 Comment
in order to bypass the NERC registration. The significant economic impact is the cost associated with the
reduced work load for the small entity, maintenance personnel, and the work contracted to another entity.

Western Montana Electric
Generating and Transmission
Cooperative
Public Utility District No. 1 of
Snohomish County, Washington
Blachly Lane Electric Cooperative
Northern Wasco County PUD

Yes

WMG&T supports the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that can ill afford the substantial costs that accompany imposition of
mandatory compliance with reliability standards. Further, we agree that the small utilities covered by the
exemption will have no measurable impact on the operation of the interconnected BES. In the Pacific
Northwest, many small entities were required to register by virtue of owning a very small portion of the
region’s 115-kV system. These utilities have faced substantial compliance burdens even though their
operations are simply not material to the interconnected bulk grid in our region, and the investment of
resources in compliance therefore will have no measurable effect in improving the reliability of the
interconnected grid.

PUD No. 2 of Grant County,
Washington
Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric

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Organization

Yes or No

Question 10 Comment

Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Clallam County PUD No.1
Chelan PUD – CHPD
Kootenai Electric Cooperative
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Central Lincoln
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc
Imperial Irrigation District

Yes

Santee Cooper

Yes

MRO's NERC Standards Review
Forum

Yes

ACES Power Participating
Members

Yes

Tennessee Valley Authority

Yes

Arizona Public Service Company

Yes

Rayburn Country Electric

Yes

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Organization

Yes or No

Question 10 Comment

Cooperative, Inc.
New York Power Authority

Yes

Luminant Energy

Yes

Dayton Power and Light
Company

Yes

Fayetteville Public Works
Commission

Yes

Florida Keys Electric Cooperative

Yes

East Kentucky Power
Cooperative, Inc.

Yes

Farmington Electric Utility System

Yes

Sierra Pacific Power Co d/b/a NV
Energy

Yes

Colorado Springs Utilities

Yes

Chevron Global Power, a division
of Chevron U.S.A. Inc.

Yes

Muscatine Power and Water

Yes

Puget Sound Energy

Yes

GTC

Yes

Long Island Power Authority

Yes

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Organization

Yes or No

Pepco Holdings Inc

Yes

Oncor Electric Delivery Company
LLC

Yes

City of Anaheim

Yes

MEAG Power

Yes

Utility System Efficiencies, Inc.

Yes

Question 10 Comment

Response: The basis for the additional exclusion was predicated by the circumstances of radial systems and the demarcation of the automatic interrupting
device. With the change of the demarcation point back to the point where the tap line intersects with the transmission line; this proposed exclusion is
unnecessary. The SDT will drop consideration for this proposed exclusion given the change to radial systems.

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

11. In Order No. 743, the Commission addressed the need to differentiate between Transmission and
distribution in the revised definition of the Bulk Electric System (BES). Specifically, the Commission stated
that local distribution facilities are to be excluded from the BES. The SDT believes that it has excluded local
distribution facilities through the revised bright-line core definition and specific inclusions and exclusions.
Do you agree with this position? If not, please provide specific comments and suggestions on what else
needs to be addressed or added.

Summary Consideration: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater
distinction between transmission and distribution facilities. The SDT has also included in the definition a statement that excludes facilities used in
local distribution of electric energy. The SDT believes that the revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide
appropriate opportunities to exclude distribution facilities above 100 kV. In addition, the “cranking path” and “automatic interrupting devices”
language have been removed from the draft BES definition.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real
Power and Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is
modified by the list shown below. This does not include facilities used in the local distribution of electric energy.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or
gross aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV
or above.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of
voltage.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of
connection of 100 kV or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion
b)
c)

to allow for reliable system reconfiguration to maintain continuity of electrical service. Or,
Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or
equal to 75 MVA (gross nameplate rating). Or,
Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in
Inclusions I2, I3, I4 and I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate
rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect
this exclusion.

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E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that
distribute power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection
at 100 kV or higher are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail
customer Load and not to accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;
E3a. Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in
Inclusion I3, and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in
aggregate), includes more than 75 MVA generation;
E3b. Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within
the LDN The LN does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
E3c. Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored
Facility in the Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

Organization
Northeast Power Coordinating
Council

Yes or No

Question 11 Comment

No

The current definition drafted by the SDT has not differentiated between Transmission and Distribution, nor
excluded distribution facilities from the BES, nor addressed the issue of local distribution facilities above
100kV. It is important for the ERO and the SDT to understand and be consistent with the FERC Order for
these important but complex issues. Many parts of the continent could be in conflict with state or provincial
regulatory act, Codes, and Licenses. The ERO and SDT and RoP teams be aware of these conflicts and not
disregard them, as they will pose many implementation complexities and confusion within the industry.
Regulatory Acts and Rules will always supersede NERC requirements and hence it is important that ERO
should neither be caught in regulatory conflict nor put entities in these situations.As responded to in Question
10, the ERO and SDT can address this by providing explicit but simple provisions in the exception criteria (to
be used by exception procedure) by putting forward required technical assessments , which are based on a
demonstration of evidence to justify the element’s necessity for operation.
For example, suggest that for local distribution, the evidence that should be required is:
o Regulatory evidence
o Evidence demonstrating that NO adverse reliability impact is afflicted on the interconnected BES because of

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Organization

Yes or No

Question 11 Comment
their connection
Some of the other key attributes of such an exception criteria should be: o Elements are not to be part of
interconnection between two balancing authority or contribute to IROLs
o Entire system cannot be classified as contiguous o Entity to justify whether or not the elements are
necessary for the operation of the interconnected transmission network
o Distinguish if the element in question supplies load centers, major cities, serves the national interest and/or
possibly impact national commerce or national security, or is identified by the relevant regulatory authority
Accordingly, the exception criteria should ONLY list a menu of items and a prescribed report template that
should be assessed and presented by an entity as their evidence and justification for exception to a RE, the
ERO and any relevant regulatory authority. This evidence and justification would be used by the ERO as part
of its decision making process.

Hydro One Networks Inc

No

We commend the SDT for their concept in putting forward a 100kV BES bright-line definition. However, we do
not believe that the current definition drafted by the SDT has differentiated between Transmission and
Distribution or excluded distribution facilities from the BES, or addressed the issue of local distribution
facilities above 100kV. It is worth noting that different jurisdictions may use different terminology for
“distribution” or non transmission facilities or elements. For example, some jurisdictions label certain facilities
as distribution which connect and are owned and operated by the distribution utility, customer or a generator
customer while other label them as connection facility or elements.(See Q10 response)

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT has also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Pepco Holdings Inc

No

see answer to #5

Response: See response to Q5.
American Municipal Power and
Members

August 19, 2011

No

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Organization

Yes or No

Question 11 Comment

Response: Thank you for your response. In the future please provide more information to let us know more specifically what you disagree with.
Tri-State Generation and
Transmission Association, Inc.

No

See the comments to Question 7.

No

Dominion believes the core BES definition should include any non-radial Element or Facility operated at 100
Kv or higher and should exclude any radial Element or Facility (regardless of operating voltage) as well as
non-radial Element or Facility operated below 100 kV. The core definition should also include defined criteria
that are applied to an Element or Facility to determine whether or not it meets the intent of the Section 215 of
Federal Power Act Section 215 defines the bulk power system as (1) facilities and control systems necessary
for operating an interconnected electric energy transmission network; and (2) electric energy from generation
facilities needed to maintain transmission system reliability. (3) However, Section 215 excludes facilities used
in the local distribution of electric energy From the definition of the bulk power system. An Element or Facility
should be included where the Element or Facility is necessary for operating an interconnected electric energy
transmission network or is needed to maintain transmission system reliability. Likewise an Element or Facility
should be excluded where the Element or Facility is not necessary for operating an interconnected electric
energy transmission network or is needed to maintain transmission system reliability.Dominion agrees that
the BES definition should exclude local distribution facilities under state jurisdiction. In specific instances
(including UFLS programs and transmission protection systems that are implemented on distribution elements
or radial transmission) local distribution facilities can be included in approved NERC reliability standards
following under explicit standards dedicated to their explicit mission without their automatic inclusion in a
definition of BES that could infringe on state jurisdiction.

Response: See the response to Q7.
Dominion

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT has also included in the definition a statement that excludes facilities used in local distribution of electric energy. NERC Reliability
Standards can apply to non-BES Facilities and compliance can be enforced for those entities in the NERC Compliance Registry.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
SPP Standards Review Group

August 19, 2011

No

The inclusion of Cranking Paths into the BES without regard to voltage level has the potential to pull
distribution facilities into the BES. (See Question 5)

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Organization

Yes or No

Question 11 Comment

Response: The SDT removed Cranking Paths from the BES definition.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Michigan Public Service
Commission(MPSC)

No

MPSC Staff Comments: The intent of the updated BES definition should be to classify facilities required to
meet mandatory NERC reliability standards. Unnecessary and costly duplication of standards work should be
avoided.

Response: The SDT is revising the BES definition to meet the FERC directives in Order Nos. 743 and 743-A. The SDT does not believe it is contributing to any
unnecessary and costly duplication of standards work. No change made.
National Rural Electric
Cooperative Association
(NRECA)

No

NRECA believes the definition should explicitly state that facilities used in local distribution are excluded from
the BES.

United Illuminating

No

The core definition should state that local distribution facilities are not included.

Response: The SDT included in the definition a statement that excludes facilities used in local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy as established by applicable regulatory authorities.
Idaho Falls Power

No

In the exclusions, we feel there has not been given enough clarification of generation assets on a LDN,
specifically, is a single generation resource >20MVA but <75 MVA excluded? This does not seem clear
because of the seeming inconsistencies of E2(i) and E3(b).Further, we believe generation on an LDN serving
local load wherein the net flow is into the LDN should be excluded.

Response: The SDT made changes to the LDN, now LN, to address your comment and the comments of others. Specifically, LNs are permitted to have
generating resources that in the aggregate do not exceed 75 MVA, and such generating resources are not already included under I3 of the BES definition. The
SDT believes these changes clarify the amount of generation permitted in the LN.
E3a. Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3 and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;

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Organization

Yes or No

Question 11 Comment

Overton Power District No. 5

No

Facilities used in local distribution should not be swept up into the BES

Western Montana Electric
Generating and Transmission
Cooperative

No

While WMG&T agrees that the approach adopted by the SDT -- a core definition coupled with specific
inclusions and exclusions - will be effective in removing most local distribution facilities from the BES, it will
not remove all such facilities. For the reasons discussed at greater length in our answer to Question 1,
WMG&T believes that the proposed definition is over-inclusive and is likely to sweep up certain facilities used
in local distribution that should not be classified as BES. As discussed in our answer to Question 3, WMG&T
notes that exclusion of facilities from the BES does not mean that owners of those facilities are entirely
exempt from reliability standards. On the contrary, the statute provides that “users” of the BES can be subject
to reliability regulation. Hence, even where an entity does not own BES assets, it could be required to, for
example, provide necessary information to the applicable Reliability Coordinator and to participate in the
regional Under-Frequency Load Shedding program by setting the UFLS relays in its Local Distribution
Network at the appropriate settings. We note that participants in the WECC BESDTF Task Force generally
agreed that appropriate information should be provided by non-BES entities, although there was considerable
concern related to ensuring that the provision of information was not unduly burdensome.

Texas Industrial Energy
Consumers (TIEC)

No

TIEC appreciates the SDT’s effort to identify situations where facilities rated above 100 kV should still be
categorically excluded from the BES definition This recognition is consistent with the concerns raised by
TIEC and many of its individual members in comments to the FERC in Docket RM09-18-000. However, TIEC
submits that the SDT’s approach to these exclusions should be revised to meet FERC’s express recognition
in Order No. 743-A that “facilities used for local distribution are excluded from the Bulk-Power System
definition under section 215, and thus are excluded from the bulk electric system.” Order No. 743-A at ¶58.
It is crucial that the BES definition is drafted in a way that recognizes that it is the transmission provider’s
responsibility to ensure that equipment is in place to protect the BES from the operations of excluded
facilities, not the responsibility of a person owning facilities involved in the local distribution of electricity.
These issues are addressed in further detail in response to the specific exclusions.

Electricity Consumers Resource
Council (ELCON)

No

Section 215 of the Federal Power Act denies FERC jurisdiction over facilities used in the local distribution of
electric energy. FERC has recognized that since facilities used in the local distribution of electric energy “are
exempted from the Bulk-Power System, they also are excluded from the bulk electric system.” Section 215 of
the Federal Power Act does not qualify the exclusion from FERC jurisdiction of “facilities used in the local
distribution of electric energy.” For example, Section 215 does not state that:--The term “bulk power system”
“does not include facilities used in the local distribution of electric energy [unless needed for reliability
purposes];” or --The term “bulk power system” “does not include facilities [with automatic interruption devices]
used in the local distribution of electric energy.”Any definition of the bulk electric system that does not exclude
all “facilities used in the local distribution of electric energy” is unlawful.

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Yes or No

Question 11 Comment
Further, the definition of the bulk electric system must recognize that Section 215 of the Federal Power Act
does not allow the potential reliability impact of a facility to determine whether the facility is local distribution or
transmission. By excluding all facilities used in the local distribution of electric energy from the definition of
the Bulk-Power System in Section 215, Congress recognized that while facilities used in the local distribution
of electric energy may be part of the Bulk-Power System, they are, nonetheless, not FERC jurisdictional.
Thus, “facilities and control systems necessary for operating an interconnected electric energy transmission
network (or any portion thereof)” that are used in the local distribution of electric energy are not FERC
jurisdictional regardless of the potential reliability impact of the facilities.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Tennessee Valley Authority

No

We cannot be certain of the effect of the BES definition on distribution facilities until our comments to the
inclusions and exclusions above are considered.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
these changes address your concerns.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Alabama Public Service
Commission

August 19, 2011

No

In drafting the inclusions and exclusions that accompany the core BES definition, the SDT needs to be very
careful in considering jurisdictional issues. FERC has recognized in its recent orders regarding the BES
definition that local distribution facilities are not subject to its jurisdiction under Section 215 of the Federal
Power Act. As the SDT considers the scope of the inclusions and exclusions from the BES Definition, it
needs to consider whether the proposed provisions only include: 1) facilities or control systems that are
“necessary” for operating an interconnected electric transmission network and 2) whether they involve
generation facilities that are “needed” to maintain transmission system reliability. If the proposed inclusions
and exclusions result in the BES definition applying to facilities beyond this “necessary” and “needed” scope
(such as local distribution facilities), then the definition would be inconsistent with Section 215 and could
improperly make those facilities subject to “reliability standards” contrary to the Federal Power Act.

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Question 11 Comment
The APSC generally supports the BES Core Definition and all three Exclusions proposed by the SDT.
The APSC strongly supports Exclusion E3 for local distribution networks and Exclusion E1 for radial systems
(subject to the concerns below). Exclusion E3 will ensure State jurisdiction over facilities that are used in the
local distribution of electric energy.
The APSC does not support Inclusion I2 for individual generating units greater than 20 MVA. Inclusion I2
should be eliminated entirely because it will result in too many radial sub-transmission load serving facilities
losing their non-BES status, when those facilities are not “necessary” for bulk power system reliability.
The APSC supports Inclusion I3 (75MVA) as a sufficient generating unit threshold for purposes of this
definition.If Inclusion I2 is eliminated, then the reference to Inclusion I2 within Exclusion E1 should also be
eliminated.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
ReliabilityFirst

No

we feel that BES elements have been included in teh exclusions

PJM

No

The bright line exclusion includes facilities that would normally be BES facilities but are excluded based on
the asset size of the owner.

Response: The SDT does not believe it has excluded BES Elements in the draft BES definition. The SDT made a number of clarifying changes to the draft BES

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Question 11 Comment

definition that it believes provides a greater distinction between transmission and distribution facilities. The SDT also included in the definition a statement that
excludes facilities used in local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Central Maine Power Company

No

Transmission and distribution facilities are already mutually exclusive and are already classified and reported
in FERC Form 1. The SDT definition may have rolled in considerable portions of the distribution system for
consideration as BES. A small generator that is entered into the black start program would make the
complete cranking path BES. As documented previously this inclusion of immaterial generators and
subsequently their distribution cranking paths is at odds with the Compliance Registry.

No

As highlighted in the answers to Questions 5 and 7, Exelon does not believe that facilities used in local
distribution of electric energy have been fully excluded in the draft BES definition. For example, there are
many examples of black start cranking path facilities that are <100kV and that are currently defined as
facilities used in the “local distribution of electric energy”.

New York State Electric & Gas
and Rochester Gas & Electric

Exelon

Response: The SDT removed Cranking Paths from the BES definition. The SDT made a number of clarifying changes to the draft BES definition that it believes
provides a greater distinction between transmission and distribution facilities. The SDT also included in the definition a statement that excludes facilities used in
local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Western Area Power
Administration

No

Numerous distribution lines in the western US are 115kV, and some are being upgraded from 115kV to
230kV.

Intellibind

No

Due to the voltage bright line of 100kV there is still a question of what makes up sub-transmission. Many
rural companies with large geographic areas use the 115kV system internally as sub transmission, but
because of the bright line it is considered part of the transmission system. This is not its purpose, or how it is
operated. There are no commercial paths, and no transmission flow through. On the other hand there are
significant generation resources (significantly over 20MVA) that are interconnected directly through the sub
transmission system to the BES, and by definition, since they are not interconnected at 100kV, they are

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Yes or No

Question 11 Comment
exempted from BES status. Some of these facilities do have direct impact on the BES.

Public Utility District No. 1 of
Snohomish County, Washington

August 19, 2011

No

While Snohomish County PUD agrees that the approach adopted by the SDT -- a core definition coupled with
specific inclusions and exclusions - will be effective in removing most local distribution facilities from the BES,
it will not remove all such facilities. For the reasons discussed at greater length in our answer to Question 1,
Snohomish believes that the proposed definition is over-inclusive and is likely to sweep up certain facilities
used in local distribution that should not be classified as BES. To give a further example, assume that a local
distribution utility operates a distribution network that currently would be excluded from the SDT’s definition,
but that a cogeneration facility with a capacity of 30 MVA and average production of 15 MW is constructed in
one of the industrial areas served by local distribution facility and the output is purchased by one of the
industrial customers. Because of inclusion I2, the local utility would now be classified as owning BES
facilities, even though the output of the generator rarely exceeds 20 MW in practice and the output is, as a
matter of physics, absorbed by the surrounding industrials loads rather than being transmitting onto the
interconnected grid. Further, the fundamental nature of the local distribution facilities has not changed. They
are still used to deliver electric power to the utility’s end-use customers, not to deliver power on the wholesale
market across the interconnected bulk grid. Hence, the result of the SDT’s definition is to include “facilities
used on the local distribution of electric energy” in contravention of FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). The practical result of the improper classification would be that the local utility would be required
to register as a Transmission Owner and Transmission Operator, and would incur substantial costs to comply
with requirements that are designed to ensure the reliable operation of transmission lines that are part of the
interconnected grid, not local distribution facilities. For the reasons explained in the papers published by the
Project 2010-07 Task Force, the result is substantially increased compliance costs that produce little or no
improvement in the reliability of the interconnected bulk system. Accordingly, if viewed in isolation, the SDT’s
core definitions and list of inclusions/exclusions do not comply with the statute or produce optimum benefits
for bulk system reliability. Whether the SDT’s approach complies with the statute can only be determined by
examining the Exception process now under development, in conjunction with the SDT’s definition. If the
Exception process results in the exclusion of facilities that are improperly swept into the BES by the bright-line
thresholds included in the SDT’s definition, and the Exception can be attained at a reasonable cost to the
involved entities, then the SDT will have achieved a result that complies with the statute. But this conclusion
can be reached only upon review of the entire package, not just the core definition and list of
inclusions/exclusions. In this regard, as discussed in our answer to Question 3, Snohomish notes that
exclusion of facilities from the BES does not mean that owners of those facilities are entirely exempt from
reliability standards. On the contrary, the statute provides that “users” of the BES can be subject to reliability
regulation. 16 U.S.C. § 824o(b). Hence, even where an entity does not own BES assets, it could be
required to, for example, provide necessary information to the applicable Reliability Coordinator and to
participate in the regional Under-Frequency Load Shedding program by setting the UFLS relays in its Local
Distribution Network at the appropriate settings. We note that participants in the WECC BES Task Force

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Question 11 Comment
generally agreed that appropriate information should be provided by non-BES entities, although there was
considerable concern related to ensuring that the provision of information was not unduly burdensome.

Blachly Lane Electric Cooperative

No

We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions and
exclusions - will be effective in removing some local distribution facilities from the BES, it will not remove all
such facilities. For the reasons discussed in our answer to Question 1, the proposed definition is overinclusive and is likely to sweep up certain facilities used in local distribution that should not be classified as
BES.

No

While Northern Wasco County PUD agrees that the approach adopted by the SDT -- a core definition coupled
with specific inclusions and exclusions - will be effective in removing most local distribution facilities from the
BES, it will not remove all such facilities. For the reasons discussed at greater length in our answer to
Question 1, Northern Wasco County PUD believes that the proposed definition is over-inclusive and is likely
to sweep up certain facilities used in local distribution that should not be classified as BES. As discussed in

Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc.
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Northern Wasco County PUD
Chelan PUD – CHPD
Kootenai Electric Cooperative

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Yes or No

Public Utility District No. 1 of
Franklin County

our answer to Question 3, Northern Wasco County PUD notes that exclusion of facilities from the BES does
not mean that owners of those facilities are entirely exempt from reliability standards. On the contrary, the
statute provides that “users” of the BES can be subject to reliability regulation. Hence, even where an entity
does not own BES assets, it could be required to, for example, provide necessary information to the
applicable Reliability Coordinator and to participate in the regional Under-Frequency Load Shedding program
by setting the UFLS relays in its Local Distribution Network at the appropriate settings. We note that
participants in the WECC BESDTF Task Force generally agreed that appropriate information should be
provided by non-BES entities, although there was considerable concern related to ensuring that the provision
of information was not unduly burdensome.

Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc.
Cowlitz County PUD

Clallam County PUD No.1

August 19, 2011

Question 11 Comment

No

While Clallam County PUD agrees that the approach adopted by the SDT -- a core definition coupled with
specific inclusions and exclusions - will be effective in removing most local distribution facilities from the BES,
it will not remove all such facilities. For the reasons discussed at greater length in our answer to Question 1,
Clallam believes that the proposed definition is over-inclusive and is likely to sweep up certain facilities used
in local distribution that should not be classified as BES. To give a further example, assume that a local
distribution utility operates a distribution network that currently would be excluded from the SDT’s definition,
but that a cogeneration facility with a capacity of 30 MVA and average production of 15 MVA is constructed in
one of the industrial areas served by local distribution facility and the output is purchased by one of the
industrial customers. Because of inclusion I2, the local utility would now be classified as owning BES
facilities, even though the output of the generator rarely exceeds 20 MVA in practice and the output is, as a
matter of physics, absorbed by the surrounding industrials loads rather than being transmitting onto the
interconnected grid. Further, the fundamental nature of the local distribution facilities has not changed. They
are still used to deliver electric power to the utility’s end-use customers, not to deliver power on the wholesale
market across the interconnected bulk grid. Hence, the result of the SDT’s definition is to include “facilities
used on the local distribution of electric energy” in contravention of FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). The practical result of the improper classification would be that the local utility would be required
to register as a Transmission Owner and Transmission Operator, and would incur substantial costs to comply
with requirements that are designed to ensure the reliable operation of transmission lines that are part of the
interconnected grid, not local distribution facilities. For the reasons explained in the papers published by the
Project 2010-07 Task Force, the result is substantially increased compliance costs that produce little or no
improvement in the reliability of the interconnected bulk system. Accordingly, if viewed in isolation, the SDT’s
core definitions and list of inclusions/exclusions do not comply with the statute or produce optimum benefits
for bulk system reliability. Whether the SDT’s approach complies with the statute can only be determined by
examining the Exception process now under development, in conjunction with the SDT’s definition. If the
Exception process results in the exclusion of facilities that are improperly swept into the BES by the bright-line
thresholds included in the SDT’s definition, and the exclusion can be accomplished at a reasonable cost to
the involved entities, then the SDT will have achieved a result that complies with the statute. But this

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Yes or No

Question 11 Comment
conclusion can be reached only upon review of the entire package, not just the core definition and list of
inclusions/exclusions. In this regard, as discussed in our answer to Question 3, Clallam notes that exclusion
of facilities from the BES does not mean that owners of those facilities are entirely exempt from reliability
standards. On the contrary, the statute provides that “users” of the BES can be subject to reliability
regulation. 16 U.S.C. § 824o(b). Hence, even where an entity does not own BES assets, it could be
required to, for example, provide necessary information to the applicable Reliability Coordinator and to
participate in the regional Under-Frequency Load Shedding program by setting the UFLS relays in its Local
Distribution Network at the appropriate settings. We note that participants in the WECC BES Task Force
generally agreed that appropriate information should be provided by non-BES entities, although there was
considerable concern related to ensuring that the provision of information was not unduly burdensome.

Electric Reliability Council of
Texas, Inc.

No

See response to question 1 - ERCOT ISO agrees that distribution facilities should be excluded, and such
facilities are generally excluded in ERCOT ISO’s proposed alternative definition. However, FERC stated in
743 and 743-A that it has the right to determine if facilities are distribution or transmission. Accordingly, to
respect the FPA explicit exclusion of distribution facilities and FERC’s authority to determine if a facility is
transmission or distribution, ERCOT ISO position is that the general exemption should be in the BES
definition, but any such exemptions must be subject to the exemption process to facilitate FERC’s authority to
make the relevant determination. With respect to that process, it may provide for a presumptive exclusion
with additional at FERC’s discretion. ERCOT ISO reserves its rights to comment on the criteria for
exclusion/exemption/inclusion in that proceeding. In addition, the exception process should provide for the
ability to include certain distribution facilities if the inclusion criteria of the exception process indicate such
action is appropriate.

MidAmerican Energy Company

No

We disagree that the SDT has appropriately excluded local distribution facilities through the revised bright-line
core definition and specific inclusions and exclusions. A similar bright line criterion excluding facilities below
100 kV would be better. The intent is to clearly define facilities below 100kV (exclusive of resources added
under criterion I4) as local distribution (excluded from FERC jurisdiction in accordance with the Federal Power
Act). Critical facilities below 100 kV would be brought back in under the provisions of inclusion exception
criteria of the Technical Principles for Demonstrating BES Exceptions procedure.

Springfield Utility Board

No

While SUB agrees that the approach adopted by the SDT, a core definition, couple with specific inclusions
and exclusions, will be effective in removing most local distribution facilities from the BES, it will not remove
all such facilities. SUB believes that the proposed definition is over-inclusive and is likely to sweep up certain
facilities used in local distribution that should not be classified as BES. SUB notes that exclusion of facilities
from the BES does not mean that owners of those facilities are entirely exempt.

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Organization

Yes or No

Question 11 Comment

Springfield Utility Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Midstate Electric Cooperative

No

While MSEC agrees that the approach adopted by the SDT -- a core definition coupled with specific
inclusions and exclusions - will be effective in removing most local distribution facilities from the BES, it will
not remove all such facilities. For the reasons discussed at greater length in our answer to Question 1,MSEC
believes that the proposed definition is over-inclusive and is likely to sweep up certain facilities used in local
distribution that should not be classified as BES.
As discussed in our answer to Question 3, MSEC notes that exclusion of facilities from the BES does not
mean that owners of those facilities are entirely exempt from reliability standards. On the contrary, the statute
provides that “users” of the BES can be subject to reliability regulation. Hence, even where an entity does not
own BES assets, it could be required to, for example, provide necessary information to the applicable
Reliability Coordinator and to participate in the regional Under-Frequency Load Shedding program by setting
the UFLS relays in its Local Distribution Network at the appropriate settings. We note that participants in the
WECC BESDTF Task Force generally agreed that appropriate information should be provided by non-BES
entities, although there was considerable concern related to ensuring that the provision of information was not
unduly burdensome.

Public Utilities Commission of
Ohio

August 19, 2011

No

While it appears there was an attempt to draft the standard to comply with the Federal Power Act, the issues
outlined throughout the questions above raise concerns that local distribution could easily get captured in
NERC and FERC reliability standards needlessly and inappropriately.

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Yes or No

Question 11 Comment

New England States Committee
on Electricity

No

As stated in 1 above, NESCOE is concerned that the proposed definition may unintentionally incorporate
facilities into the BES that do not have a direct impact on the reliability of the system, potentially imposing
significant costs without meaningful reliability benefits.

AltaLink

No

We commend the SDT for their concept in putting forward a 100kV BES bright-line definition. However, we do
not believe that the current definition drafted by the SDT has differentiated between Transmission and
Distribution or excluded distribution facilities from the BES, or addressed the issue of local distribution
facilities above 100kV. We believe that the ERO and SDT can address this by providing explicit but simple
provisions in the exception criteria (to be used by exception procedure) by putting forward a menu of key
technical assessments , which are based on demonstration of evidence to justify the element’s necessity for
operation. For example, we suggest that for local distribution, the evidence that should be required is: o
Regulatory evidence o Evidence demonstrating that NO adverse reliability impact is afflicted on the
interconnected BES because of their connectionWe suggest that the exception criteria should ONLY list a
menu of items and a prescribed report template that should be assessed and presented by an entity as their
evidence and justification for exception to a RE, the ERO and any relevant regulatory authority. This evidence
and justification would be used by the ERO as part of its decision making process.

Modern Electric Water Company

No

The proposed definition continues to inject ambiguity in that it introduces the use of the separately-defined
capitalized term “Transmission”. In NERC’s Glossary of Terms (May 24, 2011), “Transmission” is defined in
terms of function rather than voltage. As it should, the core definition implies that only Elements used for the
transfer of energy to points where it is transformed for delivery to customers as well as certain resources are
considered to be included in the BES. However, it also uses voltage, and we do not believe that the proposed
definition goes far enough to distinguish between T and D. Under the language of the core definition, there
exists a two-stage qualifier for non-resource Elements - namely that it must first be used for Transmission and
not for “Distribution”, and secondly, that it be operated above 100kV. Rather, the BES cannot contain
Elements used for “Distribution” (a term not explicitly defined, but extrapolated from other NERC glossary
terms to mean the “wires” between the transmission system and the end-use customer, and NOT defined by
voltage). While the Exclusions detail characteristics of specific distribution-like Elements, we suggest that the
core BES definition contain language explicitly excluding Distribution (there are Elements that are neither
qualifying radials as defined in E1 nor local distribution networks as defined in E3). Section 215(a)(1) contains
specific language that could be used in the core definition in this instance.

Michgan Public Power Agency

No

As I have indicated in my comments above the "small entity definition" is not being used when the 100 KV, 20
MVA, and 75 MVA aggregate are being used only. A unit with a long start up time and a low capacity factor
and/or availability factor and connected to a local distribution system is interconnected to the BES has little
opportunity to be counted on to support the BES during a critical event. With the environmental issues out

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Question 11 Comment
there it could be expected that owners of these types of units may well decide on economics of the issue and
retire such units. How would the reliability of the BES be served then?

City of Redding

No

Redding agrees that addressing Radial’s and LDN’s in the core definition is a great first step in identifying
distribution facilities, however there will still be a sizeable amount of elements operated over 100 kV that will
not be identified as distribution facilities through the efforts of the brightline. Additionally, as noted in question
#1, in the Western Interconnect the majority of 100 kV elements are used as Distribution facilities. Therefore,
the exclusions E1 & E2 will help ease the burden of NERC and the Regional Entity in the West by reducing the
number of Exception Process applications.
Also, Redding believes the SDT needs to take a more literal approach to FERC’s Orders and define the term
“necessary for operating the interconnected transmission network” and clearly “establish whether a particular
facility is local distribution or transmission”. Without a clear distinction of these two foundational principles it
will be difficult to remove the confusion between the Regulators and Entities as to the term “necessary”.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Hydro-Quebec TransEnergie

No

See comments on E3 (Q.9)

No

Without BES "demarcation" and "contiguous" principles being addressed in the proposed BES definition, this
question is difficult to answer. NERC Staff has submitted written comments to this project stating that the
BES “must be contiguous.” Instituting a contiguous BES with Inclusion I2, for example, would result in a
substantially over-inclusive BES definition. The adoption of a “contiguous” BES is therefore likely to result in
imposition of reliability standards on a substantial number of distribution elements that nothing to do with
improving or protecting the reliability of bulk transmission system.There is no compelling reason to adopt a
“contiguous” BES down into local distribution systems. Section 215 of the FPA of 2005 gives FERC
jurisdictional authority over “users” as well as “owners” and “operators” of the bulk power system.
Consequently, FERC has the jurisdictional authority to require generation and other entities in the Compliance
Registry to comply with applicable NERC requirements. Hence, even where an entity does not own or

Response: See response to Q9.
Oregon Public Utility Commission
Staff

August 19, 2011

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operate BES assets, it could still be required, for example, to provide necessary information to the applicable
Reliability Coordinator or Planning Coordinator and to participate in programs to prevent instability,
uncontrolled separation, or cascading outages to the bulk transmission system. This approach would fully
achieve the goals of bulk transmission system reliability without imposing the full BES regulatory compliance
burden on local distribution elements.

National Association of
Regulatory Utility Commissioners

The standard as currently written seems to exempt most local distribution from NERC and FERC reliability
standards. Section 215 of the Federal Power Act requires such exemptions. There remain some outstanding
concerns, however. For example, earlier comments from NERC staff have suggested that the BES needs to
be contiguous. If the definition were to require continuity, it would likely sweep in many local distribution
facilities that should not (and cannot under the statute) be included in the BES definition.

Response: The SDT did not adopt a “contiguous” BES down into the local distribution systems. The SDT made a number of clarifying changes to the draft BES
definition that it believes provides a greater distinction between transmission and distribution facilities. The SDT also included in the definition a statement that
excludes facilities used in local distribution of electric energy. The SDT believes that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion)
provide appropriate opportunity to exclude distribution facilities above 100 kV.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Grand Haven Board of Light and
Power

No

The exclusions do not properly address the exclusion of single automatic interrupting device that serves a
radial, load serving system and, through its operation, does not affect the BES.

Response: The SDT removed the requirement for an automatic interrupting device for radial exclusions.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
FHEC

No

Not until the Statement of Compliance Registry Criteria is conformed to this proposed definition.

South Texas Electric
Cooperative, Inc.

Yes

I agree, but believe that those distribution companies that were forced to register as LSEs under FERC
interpretation should be excluded as well.

South Texas Electric
Cooperative, Inc.

Yes

I agree, but believe that those local distribution companies operating below the bright-line that were forced to
register as LSEs under FERC Order on Compliance Filing (October 16, 2008) should be excluded as well.
For example, BAL-005-0.1b, CIP-001-1a, EOP-002-3 and others do not apply to DPs but affect small local

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utilities as LSEs. If, according to FERC Order 743 a small local distribution utility would be rightly excluded
from DP standards, then, by the same logic and as a distribution-level LSE, they should be excluded from
LSE standards as well.If an operating system voltage below 100kV is too low to affect the BES/BPS, then it
stands to reason that their connected load is too small as well. If not - then another bright-line should be
established in the spirit of FERC Order 743 to differentiate between power flow across the BES/BPS and
power flow to end-use consumers.

Response: The SDT was assigned the job of revising the BES definition as required by FERC Order Nos. 743 and 743-A. Any changes to the ERO Statement of
Compliance Registry Criteria are outside the scope of the SDT’s assigned work. No change made.
Vermont Transco

No

The inclusion of all black start units “regardless of voltage”, the unclear definition of “automatic interruption
device” and “common bus” could lead to local distribution company facilities being included in the definition of
BES.

ISO New England, Inc.

No

The SDT definition will unnecessarily roll in portions of the distribution system for consideration as BES. A
small generator that is entered into the black start program would make the complete cranking path BES. As
documented previously this inclusion of immaterial generators and subsequently their distribution cranking
paths is at odds with the Compliance Registry.

Response: The SDT removed the requirement for (1) an automatic interrupting device for radial exclusions and (2) all Cranking Paths regardless of voltage from
the draft BES definition. In addition, the “common bus” language has been deleted from the draft BES definition.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
National Grid

August 19, 2011

No

We don’t believe the bright-line core definition and specific inclusions and exclusions prevent distribution from
being considered as BES. Actually, it seems like a lot of distribution will be considered BES according to the
inclusions and exclusions. (E1 may be interpreted to include step downs if they don't have automatic
interruption devices and possibly the tied through distribution system to the other step-down transformer that
doesn't have an automatic interruption device from the same Transmission source) If the definition is not
revised to exclude more distribution, we are concerned about how the distribution elements that will be
considered BES under the new definition will be classified. The BES definition should not be used to
differentiate between transmission and distribution. It is important for the ERO and the SDT to understand and
be consistent with the FERC Order for these important but complex issues. There could be conflicts with state
or provincial jurisdictions. The ERO and SDT and RoP teams should be aware of these conflicts and not

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disregard them, as they will pose many implementation complexities and confusion within the industry, and
may lead to jurisdictional challenges that could cause uncertainty and delay in implementation of the new
BES definition. It is important for the ERO to not put entities in situations where there is some confusion or
conflict.Removing I4, the inclusion regarding blackstart resources and cranking paths, will prevent distribution
from being considered as BES.
Also, clarification that step downs which have one winding which is less than 100 kV but are tapped off of the
BES system without an automatic interruption device are not BES could also prevent distribution from being
considered as BES.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV. In
addition, the Cranking Path and automatic interruption device language has been removed from the draft BES definition.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
ExxonMobil Research and
Engineering

August 19, 2011

No

The SDT has defined a specific type of local distribution facility in their bright-line definition of the bulk electric
system. The SDT’s definition focuses on a specific type of local distribution system that has a minimum
impact on an interconnected transmission system when that interconnected transmission system does not
include the facilities necessary to properly protect itself from faults originating on its boundary. Section 215 of
the Federal Power Act does not qualify the type of local distribution facility that should be excluded. It
exempts ALL facilities used in the local distribution of electric energy, regardless of whether the owners and
operators of the interconnected transmission system have installed facilities that are necessary to secure the
reliability of the interconnected transmission system from incidents originating at its boundaries.Additionally,
the SDT should consider making its definition of a local distribution network consistent with exclusion E2. If a
generation facility with a net aggregate rating less than 75 MVA or single unit with a net export capacity below
20 MVA is not a part of the bulk electric system, what is the technical justification of including a local
distribution network that exports less than 75 MVA in the bulk electric system when it is not used to transmit
electric energy between geographic regions? Many QFs and large industrial facilities may fall under the
description of local distribution network due to the breadth of their private use network, connection to mulitple

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138 kV / 230 kV substations (done to improve reliability in order to provide safer operation of the industrial
process), and possible cyclical generation exports (sometimes exporting / sometimes importing).

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy as established by applicable regulatory authorities.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
FortisBC

August 19, 2011

No

We commend the SDT for their concept in putting forward a 100kV BES bright-line definition. However, we do
not believe that the current definition drafted by the SDT has differentiated between Transmission and
Distribution or excluded distribution facilities from the BES, or addressed the issue of local distribution
facilities above 100kV. It is important for the ERO and the SDT to understand and be consistent with the
FERC Order for these important but complex issues. Otherwise, many parts of the continent could be in
conflict with state or provincial regulatory act, Codes, and Licenses. We urge the ERO and SDT and RoP
teams be aware of these conflicts and not disregard them, as they will pose many implementation
complexities and confusion within the industry. Regulatory Acts and Rules will always trump NERC
requirements and hence it is important that ERO should neither be caught in regulatory conflict nor put
entities in these situations. It is worth noting that different jurisdictions may use different terminology for
“distribution” or non transmission facilities or elements. For example, some jurisdictions label certain facilities
as distribution which connect and are owned and operated by the distribution utility, customer or a generator
customer while other label them as connection facility or elements.As stated earlier (Q10), we believe that the
ERO and SDT can address this by providing explicit but simple provisions in the exception criteria (to be used
by exception procedure) by putting forward a menu of key technical assessments , which are based on
demonstration of evidence to justify the element’s necessity for operation. For example, we suggest that for
local distribution, the evidence that should be required is:
o Regulatory evidence.
o Evidence
demonstrating that NO adverse reliability impact is afflicted on the interconnected BES because of their
connection.Some of the other key attributes of such an exception criteria should be:
o Elements are not to
be part of interconnection between two balancing authority or contribute to IROLs
o Entire system cannot

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be classified as contiguous
o BESS Elements within exclusion can still be subject to relevant NERC
Standards
o Entity to justify whether or not the elements are necessary for the operation of the
interconnected transmission network
o Distinguish if the element in question supplies load centers, major
cities, serves the national interest and/or possibly impact national commerce or national security, or is
identified by the relevant regulatory authority.Accordingly, we suggest that the exception criteria should ONLY
list a menu of items and a prescribed report template that should be assessed and presented by an entity as
their evidence and justification for exception to a RE, the ERO and any relevant regulatory authority. This
evidence and justification would be used by the ERO as part of its decision making process.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV.
Your comments regarding the exception process criteria will be addressed separately in the response to the exception process comments.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Consumers Energy Company

No

The proposed definition appears to treat “BES” and “Transmission” synonymously, and this is highly likely to
have a significant effect on registration, even if this is not intended. To support consistency between reliability
and tariffs, we recommend that more direct consideration be given to the FERC 7-factor test that has been
consistently used to delineate transmission facilities for tariff purposes, and to discriminate between
registration requirements for TO and DP based on this delineation. Further, reliability gaps will not be created
(or can be addressed by minor changes to the applicable standards) if this recommendation is adopted
because all aspects of the applicable standards/requirements are (or will be) captured by the current
registration process.

Response: The SDT reviewed and considered the FERC 7-factor test and has included some concepts of that test in the LN portion of the draft BES definition.
No change made.
Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

August 19, 2011

No

Local distribution facilities have not been excluded from the proposed definition of the BES. As FERC
recognized in Order No. 743-A in directing NERC to exclude local distribution facilities from the revised
definition of the BES, any definition that does not exclude all “facilities used in the local distribution of electric
energy” is unlawful. FERC, as well as federal courts, have repeatedly stated that whether a facility is used in
local distribution must be determined on a “case-specific” basis (see, e.g., Order No. 888 at 31,980-81). As a
threshold matter, before devoting any additional time and resources to developing a definition of the BES,
there must be a clear understanding of the factors to consider when determining whether a facility is either a

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local distribution facility or a transmission facility. Currently, such a determination is made by considering a
“seven-factor test” that FERC has adopted, and the U.S. Supreme Court has upheld. The “seven-factor test,”
of which no one factor is determinative, evaluates the following indicators: (1) Local distribution facilities are
normally in close proximity to retail customers.(2) Local distribution facilities are primarily radial in
character.(3) Power flows into local distribution systems; it rarely, if ever, flows out.(4) When power enters a
local distribution system, it is not reconsigned or transported on to some other market. (5) Power entering a
local distribution system is consumed in a comparatively restricted geographical area. (6) Meters are based at
the transmission/local distribution interface to measure flows into the local distribution system.(7) Local
distribution systems will be of reduced voltage (Order No. 888 at 31,981). The seven-factor test, which
recognizes that a bright-line between transmission and distribution is a not a workable approach, is designed
to ensure FERC does not impermissibly usurp state and local regulation of local distribution facilities. There
is no evidence that the seven-factor test was considered in drafting the proposed definition of the BES.
Please see further discussion in response to Question 12.

Central Lincoln

No

We believe the SDT has excluded most distribution facilities, but not all. The remaining distribution facilities
will find it necessary to go through a lengthy exception process. As stated in Q1, we support the PNGC
comments stating that local distribution as determined by the seven factor test should be excluded by
definition. We note that the SDT has also developed a technical principal document that uses language
similar to the seven factor test. To use it, though, an entity must apply for exception first. We believe the
seven factors or technical principles should be part of the definition in order to avoid numerous exception
applications and resulting delays.

City of Anaheim

No

A functional test, similar to the seven factor test used for FERC Order 888, should be used to identify
transmission network facilities independent of voltage. All other electrical facilities not identified as
transmission network facilities should be deemed local distribution facilities, and should excluded from the
Bulk Electric System pursuant to the statutory Bulk Power System definition provided under federal law (18
CFR 39.1, Title 18, Chapter I, Subchapter B, Part 39)i.e. “facilities and control systems necessary for
operating an interconnected electric energy transmission network (or any portion thereof), and electric energy
from generating facilities needed to maintain transmission system reliability. The term does not include
facilities used in the local distribution of electric energy.” Please note that the statute does not reference any
voltage level, therefore both transmission network and local distribution facilities each can operate at voltages
higher or lower than 100 kV. The radial (E1) and local distribution network (E3)exclusions are a good starting
point under the definition, but the exception procedure should have a functional exception for local distribution
facilities independent of voltage level.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and

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distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV. In
addition, the SDT reviewed and considered the FERC 7-factor test and has included some concepts of that test in the LN portion of the draft BES definition.
However, the 7-factor test, in and of itself, has been cited by FERC as insufficient to prove a facility is distribution. The SDT has attempted to provide additional
tests that will hopefully pass FERC scrutiny.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

No

BGE votes “NO” due to the lack of clarity in exclusion E1.

Response: The SDT made significant revisions to Exclusion E1 and hopes that addresses the lack of clarity referred to in your comment.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA
(gross nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this
exclusion.
City of St. George

August 19, 2011

No

The way the definition is currently written it will include many entities with lines, generation and other facilities
whose only purpose is for the local generation and distribution of energy to local customers. The generation
restrictions and other language in the proposed definition will add additional registrations (i.e. TO/TOP) to
many smaller entities which will have a significant economic impact to those utilities with little or no benefit to

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the main bulk system. The problems may stem more from the “one size fits all” approach to the standards
requirements, with the TO/TOP requirements being the most onerous and difficult to comply with especially
for smaller entities. Allowed generation levels and the actual use of the transmission and generation facilities
should be considered in what is and is not included in the BES. As the proposed definition stands now along
with the current reliability standards a small utility with a few segments of 115 kV or 138 kV lines and with
some generation to serve local load must comply with the same requirements as a very large utility with
hundreds of miles of 345 kV or 500 kV lines and 1,000’s of MVA of generation. The use of applying small,
medium and large criteria to many of the standard requirements, similar to what is being considered for the
CIP standards with low, medium and high requirements should be considered.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV. The
SDT is focused solely on revisions to the BES definition, and changes to specific standards are outside the scope of this project.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Puget Sound Energy

No

The language on total aggregate load served by LDN should be added for the exclusion list.

Response: The SDT did not see a need to provide an aggregate Load limitation on any of the draft BES definition exclusions. No change made.
Southern California Edison
Company

No

SCE believes that the BES Definition, as currently proposed, relies too heavily on the characterization of
interconnected generation in its “Inclusion” criteria.

Response: The SDT made significant revisions to the draft BES definition, including changes to the inclusion and exclusion portions to address your concerns and
those of others.
GTC

No

Since distribution facilities are to be excluded can the drafting team clarify if the automatic interrupting
protective device (breaker or circuit switcher) operating at 100kV or above and protecting an excluded
transformer (non-BES) should be excluded with the excluded transformer? Perhaps an additional separate
exclusion could eliminate any uncertainty.

Response: The SDT removed the automatic interrupting device language from the draft BES definition.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of

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100 kV or higher from a single Transmission source originating with an automatic interruption device and:
New York State Dept of Public
Service

No

See comments under question 1.

Long Island Power Authority

No

We don’t believe the bright-line definition and specific inclusions and exclusions prevents distribution from
being considered as BES. It seems like the intent to exclude non bulk distribution systems would still be
included because of E3b. We don’t believe that the SDT has fully excluded local distribution facilities as
required by the FERC Order. Specifically E3b should be eliminated. The other remaining items a,c,d,e
adequately define the LDN.

Independent Electricity System
Operator

No

The existing definition and the associated inclusions and exclusions do not exclude local distribution facilities
because the 75 MVA limit on generation within LDNs in E3 (b) will result in portions of the power system that
are serving a distribution function being classified as BES. As stated before, we suggest subjecting the LDNs
to assessment to determine their impact on the BES and including them if impactive by using the Exception
Process.

Response: See response to Q1.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV. In
addition, item E3b) was revised to provide further clarity.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
E3b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA
(gross nameplate rating).
The Dow Chemical Company

August 19, 2011

No

The Dow Chemical Company (“Dow) is an international chemical and plastics manufacturing firm and a leader
in science and technology, providing chemical, plastic, and agricultural products and services to many
essential consumer markets throughout the world. Dow and certain of its worldwide affiliates and
subsidiaries, including Union Carbide Corporation, own and operate electrical facilities at a number of
industrial sites within the U.S., principally, in Texas and Louisiana. The electrical facilities at these various
industrial sites are configured similarly and perform similar functions. In most cases, a tie line or lines connect

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the industrial site to the electric transmission grid. Power is delivered from the electric transmission grid to the
industrial site through the tie line(s). Lines within the industrial site then deliver power to individual
manufacturing plants within the site. Additionally, cogeneration facilities are located at a number of industrial
sites owned by Dow and its subsidiaries. These cogeneration facilities generate power that is distributed
within the industrial site and used for manufacturing plant operations. In some instances, excess power not
required for plant operations is delivered back into the electric transmission grid through the tie line(s)
connecting the industrial site to the grid. Under all circumstances, electricity is not flowing into and out of such
industrial sites at the same time. While the tie lines and some of the internal lines at these industrial sites
operate at 100kV or higher, they do not perform anything that resembles a transmission function. Rather than
transmit power long distances from generation to load centers, the tie lines and internal lines perform primarily
a local distribution function consisting of the distribution of power brought in from the grid or generated
internally to different plants within each industrial site. In some cases, the facilities also perform an
interconnection function to the extent they enable power from cogeneration facilities to be delivered into the
grid. The voltage of the tie lines and internal lines at these industrial sites is dictated by the load and basic
configuration of each site. Higher voltage lines are used when necessary to meet applicable load
requirements or to reduce line losses. That does not mean that such lines perform a transmission function.
At some sites, Dow is registered as a Generation Owner and Generation Operator. At other sites, the
applicable Regional Entity has found that such registration is not required because of the relatively small
amount of power supplied to the grid from the applicable cogeneration resources, even though those
cogeneration resources have an aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating). Tie lines (to the grid) and internal lines at an industrial site that operate at 100kV or higher should be
excluded from the BES definition if, due to the relatively small amount of power supplied to the grid from the
generation resources at the site, the owner of those generation resources is not required to be registered as a
Generation Owner and the operator of those generation resources is not required to be registered as a
Generation Operator.At sites where the owner of the generation resources is registered as a Generation
Owner and the operator of those generation resources is registered as a Generation Operator, the internal
lines (between the generation resources and the manufacturing plants) that operate at 100kV or higher should
be excluded from the BES definition, because they are distribution and not transmission facilities. The lines
interconnecting the generation resources at such sites to the transmission grid should be included in the BES
definition, but the owner and operator of such interconnection lines should not be registered as a
Transmission Owner or Transmission Operator. In no instance has a Regional Entity determined that Dow or
any subsidiary should be registered as a Transmission Owner or Transmission Operator. Instead, such
interconnection lines should be considered as part of the generation resource and Generation Owners and
Generation Operators should be subject to reliability standards specifically developed for such interconnection
lines. Dow is strongly opposed to any BES definition that would result in either the tie lines or the internal lines
at industrial sites being subject to the mandatory reliability standards applicable to Transmission Owners and
Transmission Operators. Complying with reliability standards would cause Dow and its subsidiaries to incur

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substantial compliance costs and create potential exposure to penalties in the future for noncompliance.
Perhaps such costs and exposure could be justified if subjecting these facilities to compliance with reliability
standards resulted in a material increase in reliability of the BES, but there is no reason to believe that will be
the case. In fact, the opposite might be true. The tie lines and internal lines at industrial sites owned by Dow
and its subsidiaries have been operated for decades as distribution and interconnection facilities, and
practices and procedures have developed over the years that have enabled such operations to achieve a high
degree of reliability for such sites. Requiring these facilities to now operate in a different manner as
transmission facilities may well result in a degradation of the reliability of the manufacturing plants located at
such sites. For example, outages would have to be coordinated with the RTO, which may not be interested in
coordinating such outages with scheduled manufacturing plant outages.Dow recommends that a separate
exclusion be added to the BES definition to address industrial distribution facilities. Proposed exclusion E-3
for local distribution networks is not sufficient to ensure that all industrial distribution facilities are excluded.
For example, criteria b), entitled “Limits on connected generation” states that “Neither the LDN, nor its
underlying Elements (in aggregate), includes more than 75 MVA generation”. This criteria makes no sense for
an industrial site with on-site electricity generation and a number of manufacturing plants that has internal
power lines and lines interconnecting with the transmission grid that operate at 100 kV or higher where the
owner and operator of the on-site electricity generation facilities are not registered as a Generation Owner
and a Generation Operator because only a small amount of electricity is ever exported from the on-site
electricity generation facilities to the transmission grid. This criteria also makes no sense with respect to
internal electric lines (operated at 100 kV or higher) at such industrial sites even where the owner and
operator of the on-site electricity generation facilities are registered as a Generation Owner and a Generation
Operator.Criteria c) also causes proposed exclusion E-3 not to be sufficient to ensure that all industrial
distribution facilities are excluded where the owner and operator of the on-site electricity generation facilities
are not registered as a Generation Owner and a Generation Operator because only a small amount of
electricity is ever exported from the on-site electricity generation facilities to the transmission grid. Criteria c),
entitled “Power flows only into the LDN”, states: “The generation within the LDN shall not exceed the electric
Demand within the LDN.”
Criteria c) also makes no sense with respect to internal lines at such industrial sites even where the owner
and operator of the on-site electricity generation facilities are registered as a Generation Owner and a
Generation Operator.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV.
In addition, the SDT made extensive changes to Exclusion E3 to address your concerns and those of others.

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Organization

Yes or No

Question 11 Comment

Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting
devices;
E3a. Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3,
and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75
MVA generation;
E3b. Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The
LN does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
E3c. Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the
Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Southwest Power Pool

No

See response to question 1 - SPP does not necessarily disagree with the characterization of excluded
distribution facilities, but believes that issue should be addressed in the concurrent BES exemption
proceeding for the reasons described in question 1. SPP reserves its rights to comment on the criteria for
exclusion/inclusion in that proceeding.

Response: The SDT believes it is appropriate to exclude Facilities used in the local distribution of electric energy in the BES definition.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Golden Spread Electric
Cooperative, Inc.

August 19, 2011

No

All load serving radials need to be excluded from the BES.

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Organization

Yes or No

Question 11 Comment

Response: The SDT believes that the draft BES definition excludes Load-serving radial systems as your comment recommends. No change made.
Tacoma Power

Tacoma Power supports the work of the SDT towards a revised BES definition directly linked to the
exemption process of inclusions and exclusions. The definition must be closely coupled to the exemption
process and the two must move forward together. This will ensure that only the facilities that materially
impact the reliability of the BES will be burdened with the regulatory requirements.

Response: The SDT is working closely with the Rules of Procedure team to ensure that the respective work products are appropriately linked and proceed
forward in a parallel manner.
Edison Electric Institute

See comments to Question 13.

Response: See response to Q13.
Portland General Electric
Company

As stated above, PGE believes that the Exclusion for Local DistributionNetwork needs to be more explicit.

Response: The SDT made significant clarifying changes to the LDN, now LN, exclusion of the draft BES definition to address your concerns and those of others.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting
devices;
E3a. Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3,
and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75
MVA generation;
E3b. Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The
LN does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
E3c. Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the

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Organization

Yes or No

Question 11 Comment

Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
SERC OC Standards Review
Group

Yes

Exception E4 potentially does have issues - see our response to Question 10.

Yes

Please refer to comments on question 9 - Exclusion 3

Yes

In general we believe that the bright line has been created. There should however be one additional
exclusion - Distribution Protection Systems designed specifically to protect Distribution System assets should
not be considered part of the BES, even if they open an element of the BES (ie; Distribution Breaker Failure
Relaying), as long as the action is to protect the Distribution System and not the BES.

Response: See response to Q10.
Colorado Springs Utilities
Response: See response to Q9.
Alliant Energy

Response: The SDT does not see a need to add the exclusion you requested since distribution protection systems that protect distribution systems are not
determined to be BES under the draft BES definition. No change made.
Illinois Municipal Electric Agency

Yes

Please see comments under Question 13.

Sacramento Municipal Utility
District (SMUD)

Yes

SMUD does agree that the differentiation is established between the transmission & distribution systems.
Although there is concern that the general “Bright-line” is not definitive and could afford additional value
through incorporating clarifying language.

Sierra Pacific Power Co d/b/a NV
Energy

Yes

Through the radial exclusion and the LDN exclusion (E1 and E3), the definition has made a delineation
between distribution and bulk transmission. In this exclusion language, the definition as proposed addresses
the quantifiable parameters from the FERC 7-factor transmission test.

American Transmission
Company, LLC

Yes

ATC agrees that the revised bright-line core definition and associated inclusion and exclusion criteria
excludes distribution, however, recognizes that there are protection elements that may be owned by
distribution which may trip a BES Element. (Covered by NERC Standard PRC-005)

Response: See response to Q13.

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Organization

Yes or No

Question 11 Comment

PUD No. 2 of Grant County,
Washington

Yes

Grant supports the concepts as presented in the draft. Exclusion of facilities from the BES does not mean
that owners of those facilities are entirely exempt from reliability standards. The statutes provide that “users”
of the BES can be subject to reliability regulation. Hence, even where an entity does not own BES assets, it
could be required to, for example, provide necessary information to the applicable Reliability Coordinator and
to participate in the regional Under-Frequency Load Shedding program by setting the UFLS relays in its Local
Distribution Network at the appropriate settings. We note that participants in the WECC BESDTF Task Force
generally agreed that appropriate information should be provided by non-BES entities, although there was
considerable concern related to ensuring that the provision of information was not unduly burdensome.

Glacier Electric Cooperative

Yes

I do believe that the language in its plain sense does exclude local distribution systems, but I do see the
possibility of differeing interpretations of the language across the regions again. Perhaps adding some
example system diagrams showing what would and would not be included in the BES would help alleviate
any possible ambiguity and increase consistency across the regions.

PacifiCorp

Yes

PacifiCorp understands that no single bright line can accommodate all the various scenarios of local
distribution. The proposed definition appears to capture a high percentage of LDNs. Additional LDNs can be
addressed through the exemption process. Also, please refer to additional comments in question 13 regarding
a contiguous BES.

Santee Cooper

Yes

The commission should remain open to future modifications of the bright-line core definition and specific
inclusion and exclusions.

BPA

Yes

Utility System Efficiencies, Inc.

Yes

Imperial Irrigation District

Yes

Florida Municipal Power Agency

Yes

NERC Staff Technical Review

Yes

MRO's NERC Standards Review
Forum

Yes

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Organization

Yes or No

SERC Planning Standards
Subcommittee

Yes

ACES Power Participating
Members

Yes

Arizona Public Service Company

Yes

Western Electricity Coordinating
Council

Yes

Transmission Access Policy
Study Group

Yes

Northern California Power
Agency

Yes

New York Power Authority

Yes

Southern Company

Yes

Luminant Energy

Yes

US Bureau of Reclamation

Yes

Sweeny Cogeneration LP

Yes

Dayton Power and Light
Company

Yes

Duke Energy

Yes

Alberta Electric System Operator

Yes

August 19, 2011

Question 11 Comment

NCPA supports the comments of the Transmission Access Policy Study Group in this regard.

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Organization

Yes or No

South Carolina Electric and Gas

Yes

Fayetteville Public Works
Commission

Yes

Florida Keys Electric Cooperative

Yes

American Electric Power

Yes

East Kentucky Power
Cooperative, Inc.

Yes

Farmington Electric Utility System

Yes

Muscatine Power and Water

Yes

Idaho Power

Yes

Cogentrix Energy, LLC

Yes

Clark Public Utilities

Yes

Oncor Electric Delivery Company
LLC

Yes

Manitoba Hydro

Yes

MEAG Power

Yes

Xcel Energy

Yes

Question 11 Comment

Response: Thank you for your support. Several stakeholders made suggestions for clarifying changes to the draft BES definition that were adopted to provide a
greater distinction between transmission and distribution facilities. Please see the revised definition.

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12. Are you aware of any conflicts between the proposed definition and any regulatory function, rule order,
tariff, rate schedule, legislative requirement or agreement, or jurisdictional issue? If so, please identify
them here and provide suggested language changes that may clarify the issue.

Summary Consideration: The task of the SDT is to put forward a 100 kV bright-line for the BES definition. The SDT has
modified the definition and distribution facilities are now specifically excluded from the BES. However, the SDT acknowledges
that there may still be regulatory conflicts as many of the commenters have voiced. The definition is neither intended to nor
can it supersede any regulatory orders and/or rulings by relevant Federal, State, or Provincial Authorities. Although the SDT can
not resolve all regulatory conflicts, it believes that a) proposed revisions to the definition should address many of these
concerns; and b) remaining issues may be effectively addressed by the Rules of Procedure exception procedure currently under
development.
Changes to the definition due to industry comments are as follows:
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real
Power and Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is
modified by the list shown below. This does not include facilities used in the local distribution of electric energy.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or
gross aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV
or above.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of
voltage.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of
connection of 100 kV or higher from a single Transmission source originating with an automatic interruption device and:
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.

Organization

Yes or No

AltaLink

Yes

East Kentucky Power
Cooperative, Inc.

Yes

August 19, 2011

Question 12 Comment

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Organization

Yes or No

Question 12 Comment

Response: Without any details the SDT is unable to respond.
BPA

Yes

The Low Voltage Ride Through standard is a U.S. industry standard via FERC Order 611A and applies to wind
generation without regard to size. The I2 definition appears to be in conflict with the LVRT set by Order 611A.
Request NERC clarification including when it will be issuing a LVRT reliability standard.
DGF supports Rebecca Berdahl Comment 2, as discussed below.

Response: Inclusion I2 has been modified by the SDT in the revised BES definition to address your concerns and those of others.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Northeast Power Coordinating
Council

Yes

The proposed definition will have a direct impact on entities not under FERC jurisdiction, and may be in
conflict with regulatory requirements with which those entities must comply.

Dominion

Yes

The inclusion of an element or facility that is not integral to the reliable operation of the integrated bulk power
system is in conflict with the intent of Section 215 of the FPA . This is especially true for radial facilities,
whether used to connect generators or load to the bulk power system.

Michigan Public Service
Commission(MPSC)

Yes

MPSC Staff Comments: The proposed BES definition creates friction with Order 888’s seven-factor technicalfunctional test as implemented by state regulatory agencies. The resulting inconsistent treatment is likely to
result in challenges by entities with FERC-defined distribution assets being now considered as transmission
assets as inconsistent with the FPA. FERC’s Order 888 discusses the two components of an unbundled
transaction in interstate commerce has “for jurisdictional purposes -- a transmission component and a local
distribution component.” p 439 The Order also states that the Commission “will defer to recommendations by
state regulatory authorities concerning where to draw the jurisdictional line under FERC’s technical test for
local distribution facilities” p 437, also known as the seven-factor technical-functional test. This test was
applied by Michigan utilities, filed with the Michigan Public Service Commission in contested case-specific
dockets, and after deliberation approved. These state-approved jurisdictional bright-line determinations were
subsequently filed with and approved by FERC.

Hydro-Quebec TransEnergie

Yes

There appears to be a conflict between the proposed definition and the regulatory framework applicable in
Quebec or at least there are some important differences between both.NERC's proposed definition of Bulk
Electric System (“BES”) is made in response to FERC's Order 743. FERC is looking to remove regional
discretion, and in some cases to make sure BES includes the most important national load centers.As for

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Organization

Yes or No

Question 12 Comment
HQT's System, the BES definition shall meet the expectations of Quebec's regulator, the Régie de
l'Énergie du Québec, (Quebec Energy Board) which has the responsibility to ensure that electric power
transmission in Québec is carried out according to the reliability standards it adopts. In a recent order (D2011-068), the Régie de l'Énergie du Québec has recognized several level of application for the
Reliability Standards in Québec. It stated specifically that most reliability standards in Québec shall be
applied to the Main Transmission System (MTS). One other level of application recognised by this decision is
the NPCC Bulk Power System (BPS) to which the standards related to the protection system (PRC-004-1 and
PRC-005-1) and those related to the design of the transmission system (TPL 001-0 to TPL-004-0) will be
applicable. The Main Transmission System definition is somewhat different than the Bulk Electric System
definition. The Main Transmission System includes elements that impact the reliability of the grid, supplydemand balance and interchanges. It can be described as follows :The transmission system comprised of
equipments and lines generally carrying large quantities of energy and of generating facilities of 50 MVA or
more controlling reliability parameters: o Generation/load balancing o Frequency control o Level of
operating reserves o Voltage control of the system and tie lines o Power flows within operating limits o
Coordination and monitoring of interchange transactions o Monitoring of special protection systems o
System restorationTherefore, it will be necessary to accommodate NERC's proposed definition of BES or the
exception process with the Québec situation where Entities are under a different jurisdiction. These
differences include more than one level of application for the reliability standards, the Main Transmission
System definition being the main one to which most reliability standards apply.

Hydro One Networks Inc

Public Utility District No. 1 of

August 19, 2011

See earlier comments and suggestions. NERC’s revised definition will have a direct impact on many entities
across North America and could also be in conflict with regulatory requirements, Codes, and Licenses, which
non FERC jurisdictional must comply. It would be hard if not impossible to identify the conflicts. For example:
in one of the the provincial energy acts, NERC Standards maycan only apply to generation over 50 MVA
which will cause one or more of the requirements to be in conflict and /or what constitutes distribution and
what is not considered transmission (such as connection facility to a load or generation and owned by the
proponent). However, we agree to establish a 100kV BES bright-line definition and we believe that the best
venue to address avoiding compliance conflicts is through the exception criteria and the exception procedure.
The benefits of such an approach are: o Establishment of a continent wide bright line definition o
Avoidance of regulatory conflicts and legal complexities o Assurance of the reliability of the interconnected
transmission network

Yes

As noted in our responses to Question 1 and Question 11, we believe the SDT proposal is potentially in
conflict with the limitations of the Federal Power Act, and in particular the statutory exclusion for facilities used

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Organization

Yes or No

Question 12 Comment

Snohomish County, Washington

in the local distribution of electric energy. Unless the SDT adopts some approach other than a core definition
with inclusions and exclusions based on brightline thresholds, the SDT’s approach can meet the statutory
requirements only if the Exception process currently under development results in facilities that are not
properly classified as BES being exempted from regulation as BES facilities.

Blachly Lane Electric Cooperative

As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.

Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Northern Wasco County PUD
Clallam County PUD No.1

August 19, 2011

Yes

The Exceptions process is a necessary part of making this proposal complaint with the Federal Power Act. As
noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is potentially in
conflict with the limitations of the Federal Power Act, and in particular the statutory exclusion for facilities used
in the local distribution of electric energy. The SDT’s approach can meet the statutory requirements only if

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Organization

Yes or No

Chelan PUD – CHPD

Question 12 Comment
the Exception process currently under development results in facilities that are not properly classified as BES
being exempted from regulation as BES facilities.

Kootenai Electric Cooperative
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc
PUD No. 2 of Grant County,
Washington

Yes

The Exceptions process is a necessary part of making this proposal complaint with the Federal Power Act.
The SDT’s approach can meet the statutory requirements only if the Exception process currently under
development results in facilities that are not properly classified as BES being exempted from regulation as
BES facilities.

ExxonMobil Research and
Engineering

Yes

Section 215 of the Federal Power Act excludes facilities used in the local distribution of electric energy without
any qualifications of the type of local distribution facility.

FortisBC

Yes

See earlier comments and suggestions. NERC’s revised definition will have a direct impact on many entities
across North America and could also be in conflict with regulatory requirements, Codes, and Licenses, which
non FERC jurisdictional must comply. It would be impossible to identify each of these conflicts. For example:
in one of the energy acts, NERC Standards can only apply to generation over 50 MVA which will cause one or
more of the requirements to be in conflict and /or what constitutes distribution and what is not considered
transmission (such as connection facility to a load or generation and owned by the proponent).However, we
agree to establish a 100kV BES bright-line definition and we believe that the best venue to address avoiding
compliance conflicts is through the exception criteria and the exception process. The benefits of such an
approach are:
o Establishment of a continent wide bright line definition
o Avoidance of regulatory
conflicts and legal complexities
o Assurance of the reliability of the interconnected transmission network

Consumers Energy Company

Yes

The proposed definition creates a tension between FERC Order 888 and the resulting 7-factor test as applied
for tariff purposes, and the registry criteria for registration of Transmission Owners and Transmission
Operators. Entities with assets defined by FERC as Distribution might challenge any rules that treat
Distribution assets as Transmission as not being consistent with the Federal Power Act of 2005.

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Organization

Yes or No

Question 12 Comment

Exelon

Yes

To the extent facilities used in local distribution of electric energy may be included in the definition of BES, the
proposed definition is in conflict with the Federal Power Act.

Springfield Utility Board

Yes

The exceptions process is a necessary part of making this proposal compliant with the Federal Power Act. As
noted in responses to Questions 1 and 11, SUB believes the basic SDT proposal is potentially in conflict with
the limitations of the Federal Power Act, and in particular the statutory exclusion for facilities used in the local
distribution of electric energy. The SDT’s approach can meet the statutory requirements only if the Exception
process currently under development results in facilities that are not properly classified as BES being
exempted from regulation as BES facilities.

New York State Dept of Public
Service

Yes

As expressed in comments under question 1, we believe that use of a 100 kV brightline definition is an
overreach of authority and that any definition must respect the limitations itemized in FPA 215. The FPA
recognizes that only a subset of the electric system facilities have the capacity to impact multi-state portions
of the electric system and rise to the level of federal attention. As a practical matter, however, the electric
system is a continuous machine and efforts to maintain reliability on both the transmission and local
distribution portions of the electric system must be compatible. That is the key role that the regional entities
play and that role should be maintained and respected by NERC efforts. The time and effort it takes to draft
standards to address issues on the bulk system is directly attributable to the many different options to design
and operate transmission facilities, and options to ensure reliability are different for each design and mode of
operation. Multiply that a hundred fold to the different approaches there are to design, operate and to ensure
reliability on the local distribution system. Attempts at the federal level to design uniform standards to apply at
lower and lower levels of the system are doomed to failure given the nuances of each local system. These
attempts will only lead to needless complications and the actual undermining of the reliability on the local
distribution system. NERC staff comments seeking to sweep into NERC standards behind the meter
generation, meters and relays located deep within the distribution system, etc. and then insist that the bulk
system be contiguous is a phenomenal overreach and an intrusion on the design and functioning of the
distribution system which will a) complicate efforts to maintain a reliable distribution system; and 2) will
needlessly incur costs on ratepayers. NERC needs to stay focused on the authorities extended to it in the
FPA. Leave it to the regions to interface locally with utilities, state authorities and other stakeholders to shape
seamless reliability protocols that will benefit us all.The question asks if there are orders that relate to this
effort. In 1997, the New York Public Service Commission held a proceeding Case No. 97-E-0251 that
supplemented the FERC Seven Factor Test with three additional factors to be used in New York to distinguish
between transmission and local distribution. This order can be found at the following
link:http://documents.dps.state.ny.us/public/Common/ViewDoc.aspx?DocRefId={3C7602E0-62E0-4831-82B68C34A72934F4}

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Organization

Yes or No

Question 12 Comment

Midstate Electric
CooperativePublic Utilities
Commission of Ohio

Yes

See concerns above with exceeding authority under the Federal Power Act Section 215. State Utility
Commissions are charged with assuring safe, reliable service to their customers. We are in a much better
situated position than FERC or NERC to provide any necessary regulation and oversight of the local
distribution system.

The Dow Chemical Company

Yes

Comments: Section 215 of the Federal Power Act denies FERC jurisdiction over facilities used in the local
distribution of electric energy. FERC has recognized that since facilities used in the local distribution of
electric energy “are exempted from the Bulk-Power System, they also are excluded from the bulk electric
system.” Section 215 of the Federal Power Act does not qualify the exclusion from FERC jurisdiction of
“facilities used in the local distribution of electric energy.” For example, Section 215 does not state that:
The term “bulk power system” “does not include facilities used in the local distribution of electric energy
[unless needed for reliability purposes];” or  The term “bulk power system” “does not include facilities [with
automatic interruption devices] used in the local distribution of electric energy.”Any definition of the bulk
electric system that does not exclude all “facilities used in the local distribution of electric energy” is
unlawful.Further, the definition of the bulk electric system must recognize that Section 215 of the Federal
Power Act does not allow the potential reliability impact of a facility to determine whether the facility is local
distribution or transmission. By excluding all facilities used in the local distribution of electric energy from the
definition of the Bulk-Power System in Section 215, Congress recognized that while facilities used in the local
distribution of electric energy may be part of the Bulk-Power System, they are, nonetheless, not FERC
jurisdictional. Thus, “facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof)” that are used in the local distribution of electric energy are not
FERC jurisdictional regardless of the potential reliability impact of the facilities.

Central Lincoln

Yes

Improper classification of local distribution facilities, even if only for the duration of the exceptions process;
puts these facilities under the regulatory jurisdiction of NERC contrary to the Federal Power Act when they
should be under the exclusive jurisdiction of state utility commissions or local utility boards.

Cowlitz County PUD

Yes

The Exceptions process is a necessary part of making this proposal complaint with the Federal Power Act. As
noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is potentially in
conflict with the limitations of the Federal Power Act, and in particular the statutory exclusion for facilities used
in the local distribution of electric energy. The SDT’s approach can meet the statutory requirements only if
the Exception process currently under development results in facilities that are not properly classified as BES
being exempted from regulation as BES facilities. Cowlitz understands the difficulty in demonstrating what is
and is not distribution to FERC due to the vague statute language. Cowlitz will work to help provide technical
arguments which will buttress the BES definition in the future.

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Organization

Yes or No

Question 12 Comment

Response: The definition is neither intended to nor can it supersede any regulatory orders and/or rulings by relevant Federal, State, or Provincial Authorities.
Although the SDT can not resolve all regulatory conflicts, it believes that a) proposed revisions to the definition should address many of these concerns; and b)
remaining issues may be effectively addressed by the Rules of Procedure exception procedure currently under development. Specifically, the SDT added a
sentence to the core definition to address concerns about local distribution.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
SPP Standards Review Group

Yes

See our responses to Questions 5 and 11 regarding the issue of distribution facilities and Cranking Paths.

Response: See responses to Q5 and Q11.
Idaho Falls Power

Yes

It is unclear how the reliability standards will be applied to registered entities should some assets be deemed
not to be a part of the BES. As an example; will a an LSE with >25MW of load connected at 161kv be
responsible for relay maintenance under PRC-005-1 if the 161 kv is exempted as a local distribution network?
Clarification of this issue may be beyond the scope of the BES definition effort, however guidance in this area
should accompany this effort.

Response: The application of Reliability Standards is not based solely on registration or an Element being classified as BES or not. There are several standards
that are currently mandatory for Elements that are non-BES and they will continue to apply if those Elements are considered necessary for the operation of BES,
such as UFLS. No change made.
Alabama Public Service
Commission

Yes

See comments in response to Question 11 above.

Yes

The Exceptions process is a necessary part of making this proposal complaint with the Federal Power Act. As
noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is potentially in
conflict with the limitations of the Federal Power Act, and in particular the statutory exclusion for facilities used
in the local distribution of electric energy. The SDT’s approach can meet the statutory requirements only if
the Exception process currently under development results in facilities that are not properly classified as BES
being exempted from regulation as BES facilities.

Response: See response to Q11.
Western Montana Electric
Generating and Transmission
Cooperative

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Organization

Yes or No

Question 12 Comment

Electricity Consumers Resource
Council (ELCON)

Yes

See response to question 11 above. The definition of “local distribution” should be as defined and practiced
in each state (US only) under state laws and regulations, and similarly by the Canadian provincial
governments.

MRO's NERC Standards Review
Forum

Yes

Within the Commission’s definition of BPS, it is clearly stated that BPS does not include facilities used in the
local distribution of electrical energy.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
PacifiCorp

Yes

The SDT proposal combined with the ROP may be in conflict with Section 215 of the Federal Power Act
(“FPA”) which excludes “facilities used in the local distribution of electric energy” from the definition of “bulkpower system.”
As identified in other responses, without a technical reason for setting the generation limit to 20 MVA and
even 75 MVA and/or requiring a contiguous BES to include such generators may be over-inclusive and by
default require several elements which are not required for the reliable operation of the BES to be included in
the BES definition.

Response: The definition is neither intended to nor can it supersede any regulatory orders and/or rulings by relevant Federal, State, or Provincial Authorities.
Although the SDT can not resolve all regulatory conflicts, it believes that a) proposed revisions to the definition should address many of these concerns; and b)
remaining issues may be effectively addressed by the Rules of Procedure exception procedure currently under development.
The SDT did not adopt a “contiguous” BES. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo
any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will
be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach
to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.

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Organization
Grand Haven Board of Light and
Power

Yes or No

Question 12 Comment

Yes

This current definition does not comply with FERC Order No. 743 (and 743a) by not addressing the exclusion
of a single automatic interrupting device that serves a radial, load serving system.

Response: The SDT revised Exclusion E1 to address your concern and those of others.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
National Grid

Yes

There could be some conflicts with the ISO-NE Pool Transmission Facility (PTF) definition. If something is
considered non-PTF, but is considered BES with this new definition, it could lead to confusion about which
criteria should be applied to these entities and potentially which tariff (non-PTF or PTF) is truly the correct
tariff. We believe adding more clarity as previously mentioned in the other questions to the definition and
excluding I4 and clarifying E1 will minimize these issues.

Response: The task of SDT is to put forward a 100 kV bright-line definition for BES. The SDT acknowledges that there may be regulatory conflicts but believes
that many of these concerns may be addressed by the revised BES definition and exception procedure currently under development. SDT has made some changes
to Inclusion I4 (now Inclusion I3) and Exclusion E1 that may address your concerns.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
Electric Reliability Council of
Texas, Inc.

Yes

See response to question 1 - ERCOT ISO believes defining BES in terms of the relevant exclusions may be
contrary to FERC’s suggested approach in 743 and 743-A. While FERC did not mandate a particular
approach, and gave the ERO the opportunity to propose an alternative to its suggested approach, it stated
that any alternative must be equal to or greater than its suggested approach in terms of remedying the
identified flaws associated with the current definition. Part of the remedy envisioned by FERC included the
removal of subjectivity in defining BES and the ability of the ERO and FERC to review any proposed
exemptions from the bright line definition. Although the exclusions strive to apply objective criteria, it is
arguable that any such circumstances may not be that clear and may require some level of subjective
judgment as to whether elements deemed to be distribution according to the exclusion criteria actually are
distribution, as opposed to transmission. In addition, FERC expressly stated that it reserved the right to make
that determination in the first instance. This approach takes that away from FERC.

Southwest Power Pool

Yes

See SPP's response to question 1 - SPP believes defining BES in terms of the relevant exclusions may be
contrary to FERC’s suggested approach in 743 and 743-A. While FERC did not mandate a particular

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Organization

Yes or No

Question 12 Comment
approach, and gave the ERO the opportunity to propose an alternative to its suggested approach, it stated
that any alternative must be equal to or greater than its suggested approach in terms of remedying the
identified flaws associated with the current definition. Part of the remedy envisioned by FERC included the
removal of subjectivity in defining BES and the ability of the ERO and FERC to review any proposed
exemptions from the bright line definition. Although the exclusions strive to apply objective criteria, it is
arguable that any such circumstances may not be that clear and may require some level of subjective
judgment as to whether elements deemed to be distribution according to the exclusion criteria actually are
distribution, as opposed to transmission. In addition, FERC expressly stated that it reserved the right to make
that determination in the first instance. This approach takes that away from FERC.

Alberta Electric System Operator

Yes

Comments: Alberta’s legislation enables reliability standards, but prevents the AESO from developing rules
related to reliability standards. The AESO therefore would like to see retention of the following clause from the
NERC “Statement of Compliance Registry Criteria (revision 5) included in the list of inclusions as well as
identifying the authority that determines what generators are material to reliability:III.c.4 Any generator,
regardless of size, that is material to the reliability of the bulk power system. The wording should reflect that,
for example, in the case of Alberta, that the AESO has the authority to make this determination.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV. The
definition is neither intended to nor can it supersede any regulatory orders and/or rulings by relevant Federal, State, or Provincial Authorities. Although the SDT
can not resolve all regulatory conflicts, it believes that a) proposed revisions to the definition should address many of these concerns; and b) remaining issues
may be effectively addressed by the Rules of Procedure exception procedure currently under development.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

August 19, 2011

Yes

The proposed definition conflicts with Section 215 of the FPA and case law because it ignores years of
precedent regarding what constitutes “facilities used in local distribution” and defines the BES in such a way
as to possibly cover local distribution facilities as well as transmission facilities. Specifically, FERC has
jurisdiction over “all users, owners and operators of the bulk-power system” under Section 215 of the FPA (16
U.S.C. § 824o(b)(1)). The bulk-power system is defined as:”(A) facilities and control systems necessary for
operating an interconnected electric energy transmission network (or any portion thereof); and (B) electric
energy from generation facilities needed to maintain transmission system reliability. The term does not
include facilities used in the local distribution of electric energy” (Id. at § 824o(a)(1)).By the plain language of
Section 215 of the FPA, FERC’s jurisdiction over the Bulk Power System cannot include any “facilities used in

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Organization

Yes or No

Question 12 Comment
the local distribution of electric energy.” FERC has recognized that “[s]ince such facilities are exempted from
the Bulk-Power System, they also are excluded from the bulk electric system” (Order No. 743-A at P 25).
Congress specifically recognized that while facilities used in the local distribution of electric energy may be
part of the Bulk-Power System, they are not FERC jurisdictional. Thus, “facilities and control systems
necessary for operating an interconnected electric energy transmission network (or any portion thereof)” that
are used in the local distribution of electric energy are not jurisdictional regardless of the potential reliability
impact of the facilities. The proposed definition of the BES would rewrite Section 215 of the FPA to exclude
only “facilities used in local distribution of electric energy [unless needed for reliability purposes].” As the DC
Court of Appeals stated in Detroit Edison Co. v. FERC: “[s]uch an interpretation would eviscerate state
jurisdiction over numerous local facilities, in direct contravention of Congress’ intent” (Detroit Edison Co. v.
FERC, 334 F.3d 48, 54 (U.S. App. D.C. 2003) (citation omitted)). In Detroit Edison Co. v. FERC, the DC
Court of Appeals rejected FERC’s proposed definition of a “FERC-jurisdictional distribution facility” as any
distribution facility that is not “used exclusively to provide service to unbundled retail customers” (Id.). The
Court stated: “FERC’s position contradicts the plain language of the FPA,” and further that “FERC would
rewrite the statute to exclude only ‘facilities used exclusively in local distribution’” (Id.). The exclusion of
facilities used in the local distribution of electric energy from the definition of the BES does not mean that
NERC lacks the ability to maintain the reliability of the BES. For example, if NERC determined that a retail
customer’s self-provided “hard-tapped” radial line that is located behind the retail delivery point created a
reliability issue, NERC could require that the transmission facilities be equipped with automatic faultinterruption devices. NERC could not, however, define the BES to include such local distribution facilities,
which is the result of the proposed bright-line core definition and specific inclusions and exclusions.While
FERC “granted NERC discretion” in developing the revised definition of the BES because FERC wanted to
give NERC “the greatest amount of flexibility to utilize its technical expertise” (Order No. 743-A at PP 0-71),
NERC’s discretion is not unbounded. Moreover, while FERC stated that it “will evaluate whether the [BES
definition] proposal results in any conflicts with the statutory language” (Id. at P 72), it is imperative that NERC
work within the statutory limitations of Section 215 of the FPA as to prevent submitting a proposal to FERC
that is fundamentally unlawful. It would be a colossal waste of government and industry resources to develop
and advance a definition that cannot withstand basic legal review. As provided above, the following are
suggested language changes that may clarify the issue:Exclusion E1 - Any radial system which is described
as connected from a single Transmission source [ ] and: a) Only serving Load. [ ] Or, b) Only including
generation resources not identified in Inclusions I2, I3, I4 and I5. Or, c) Is a combination of items (a.) and (b.)
where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5. Exclusion E3 - [All facilities used in the distribution of electric energy] ([“]Local [D]istribution
[N]etworks,[“ or “]LDNs[“]): Groups of Elements operated above 100 kV that distribute power to Load rather
than transfer bulk power across the interconnected System. LDN[]s are [normally] connected to the Bulk
Electric System (BES) at more than one location solely to improve the level of service to retail customer Load.
The LDN is characterized by all of the following:a) [ ]b) Limits on connected generation: [Generally], neither

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Organization

Yes or No

Question 12 Comment
the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;c) Power flows
only into the LDN: The generation within the LDN [normally does] [ ] not exceed the electric Demand within
the LDN;d) Not used to transfer bulk power: The LDN is [generally] not used to transfer energy originating
outside the LDN for delivery through the LDN; ande) Not part of a Flowgate or transfer path: The LDN
normally does not contain a monitored Facility of a permanent flowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable
monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).Exclusion E4 - Transmission Elements, from a single
Transmission source connected at a voltage of 100 kV or greater [ ] whose connection to the BES is solely
through this single Transmission source, and without interconnected generation as recognized in the BES
Designation Inclusion Items I2, I3, I4, or I5. [ ]

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV.
Muscatine Power and Water

Yes

Within FERC’s definition of Bulk Power System, it is plainly stated that BPS does not include facilities used in
the local distribution of electrical energy. Does this support or contradict the SDT's concept of Local
Distribution Network?

Response: The LDN (now referred to as LN) is a unique case due to the multiple connections to the BES and as such the SDT believes it deserves a specific
exclusion but it supports the SDT’s concept.
Southern California Edison
Company

Yes

For participants in an ISO/RTO, such as the CAISO, the final BES Definition may change the party who will
control system facilities, even if they are distribution or radial in nature, based on the amount or size of
interconnected generation. Generally, within the CAISO, facilities that are included in the BES Definition are
under CAISO’s direct control, while radial and distribution facilities are not.

Response: Control of system facilities is not within the scope of the SDT and must be worked out locally.
Clark Public Utilities

August 19, 2011

Yes

The BES Definition does not have any reference to the exception process being developed. Both the
exclusion and inclusion sections of the BES Definition should have a reference to the process where “BES
Definition included” Transmission Elements may be excluded and “BES Definition excluded” Transmission
Elements may be included.

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Organization

Yes or No

Question 12 Comment

Response: The reference to the exception process was inadvertently left off the posting.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.
New England States Committee
on Electricity

Yes

A possible conflict exists with respect to state renewable resource objectives. Please refer to number 4
above regarding renewable energy objectives, which includes state legislation regarding renewable portfolio
standards.

Response: The task of SDT is to put forward a 100 kV bright-line definition for BES. The definition is neither intended to nor can it supersede any regulatory
orders and/or rulings by relevant Federal, State, or Provincial Authorities. Although the SDT can not resolve all regulatory conflicts, it believes that a) proposed
revisions to the definition should address many of these concerns; and b) remaining issues may be effectively addressed by the Rules of Procedure exception
procedure currently under development.
PPL Energy Plus and PPL
Generation

Yes

Edison Electric Institute

See comments in Question 13.

See comments to Question 13.

Response: See response to Q13.
Manitoba Hydro

Yes

Canadian Entities are not under FERC jurisdiction, so the revised BES Definition may not apply. A number of
Canadian Entities have the BES defined within their provincial legislation. This may introduce differences and
even contradictions between elements that are included in the BES according to provincial legislation and the
NERC definition.

Response: The definition is neither intended to nor can it supersede any regulatory orders and/or rulings by relevant Federal, State, or Provincial Authorities.
Although the SDT can not resolve all regulatory conflicts, it believes that a) proposed revisions to the definition should address many of these concerns; and b)
remaining issues may be effectively addressed by the Rules of Procedure exception procedure currently under development. Regional difference (vs. regional
discretion), under the purview of the ERO, is acceptable methodology that will be consistently applied as a result of the definition and exception process.
ISO New England, Inc.

August 19, 2011

Yes

The proposal to include all Blackstart units’ cranking paths has the potential to roll into the BES facilities
distribution level circuits. Inclusion of those circuits would appear to conflict with statutory exclusion of set out
in Section 215(a)(1) of the Federal Power Act, which states that the term “bulk power system”: “does not
include facilities used in the local distribution of electric energy.” Section 215 sets the limits on what may be
included within the bulk electric system, and thus subject to regulation by the ERO and FERC under the

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Organization

Yes or No

Question 12 Comment
reliability standards regime.

Response: The SDT has eliminated Cranking Path from the definition.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Consolidated Edison Co. of NY,
Inc.

Yes

As FERC stated in Order 743-A “... the Commission uses the term “exclusion” herein when discussing
facilities expressly excluded by the statute (i.e., local distribution) and the term “exemption” when referring to
the exemption process NERC will develop for use with facilities other than local distribution that may be
exempted from compliance with the mandatory Reliability Standards for other reasons.” (Footnote
82)Thereby, the Commission clearly established its preferred terminology; “exclusion” for local distribution
and “exemption” for exceptions allowed under the NERC designations and Exception Process. The BES
Definition and Designations do not fully utilize this FERC wording convention.

Response: The SDT and the corresponding Rules of Procedure team have created a set of terminology that is consistent across the two projects and in line with
what they believe is the intent of FERC. No change made.
Modern Electric Water Company

Yes

Exclusion E1 and WECC Compliance Bulletin #4 (April 15, 2011) conflict. We support the intent of E1 and
have provided suggested language modifications to it in Question #7 herein.Link http://compliance.wecc.biz/Documents/2%20-%20WECC%20-%20Compliance%20Bulletins/01.04%20%20Compliance%20Bulletin%20-%204%20Interpretation%20PRC-004,%20PRC-005%20%20April%2015,%202011.pdf

Response: Exclusion E1 has been modified under the revised BES definition to address your concerns and those of others.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
American Municipal Power and
Members

No

In Ohio, 50 MW is the threshold for siting. Although 20 MW has recently been the criteria for the BES, if there
is no technical justification (a study of some kind) then we highly recommend raising the threshold for
generators to 50 MVA for a single unit. In our experience, registered generators, even those that have had
severe violations, have been routinely classified as not having an impact on the BES in the enforcement
process. Due to this truth, we can not understand the justification for keeping such a low threshold. We
suggest raising the threshold to 50 MVA for single units, unless a technical study justifies inclusion.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus

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Organization

Yes or No

Question 12 Comment

of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Tacoma Power

Tacoma Power is not aware of any conflicts at this time.

Independent Electricity System
Operator

No

At this point, we are not aware of conflicts for our own jurisdiction. However, NERC must exercise caution
while developing the exception criteria and the associated processes as these may result in jurisdictional
issues between state/provincial and federal entities. We repeat our earlier point that the BES definition and
TPC must be developed and approved simultaneously to provide assurances that mechanisms are in place to
exclude those Facilities from BES classification that are not impactive on the BES.

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

No

We are not currently aware of any conflict, but have not had a chance to thoroughly consider the potential
conflicts.

American Electric Power

No

AEP is not aware of any conflicts involving the proposed definition and any regulatory function, rule order,
tariff, rate schedule, legislative requirement or agreement, or jurisdictional issue.

City of Redding

No

Illinois Municipal Electric Agency

No

Tri-State Generation and
Transmission Association, Inc.

No

Imperial Irrigation District

No

Florida Municipal Power Agency

No

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Organization

Yes or No

NERC Staff Technical Review

No

SERC Planning Standards
Subcommittee

No

ACES Power Participating
Members

No

SERC OC Standards Review
Group

No

Overton Power District No. 5

No

Tennessee Valley Authority

No

Arizona Public Service Company

No

Western Electricity Coordinating
Council

No

ReliabilityFirst

No

Rayburn Country Electric
Cooperative, Inc.

No

New York Power Authority

No

Southern Company

No

Luminant Energy

No

Central Maine Power Company

No

New York State Electric & Gas

No

August 19, 2011

Question 12 Comment

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Organization

Yes or No

Question 12 Comment

and Rochester Gas & Electric
Western Area Power
Administration

No

Intellibind

No

US Bureau of Reclamation

No

Glacier Electric Cooperative

No

FHEC

No

Vermont Transco

No

South Texas Electric
Cooperative, Inc.

No

South Texas Electric
Cooperative, Inc.

No

Sweeny Cogeneration LP

No

Dayton Power and Light
Company

No

Duke Energy

No

South Carolina Electric and Gas

No

Fayetteville Public Works
Commission

No

MidAmerican Energy Company

No

August 19, 2011

No Comment

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Organization

Yes or No

Florida Keys Electric Cooperative

No

American Transmission
Company, LLC

No

Farmington Electric Utility System

No

Sierra Pacific Power Co d/b/a NV
Energy

No

Colorado Springs Utilities

No

Sacramento Municipal Utility
District (SMUD)

No

City of St. George

No

Puget Sound Energy

No

GTC

No

Idaho Power

No

Long Island Power Authority

No

Cogentrix Energy, LLC

No

PJM

No

Oncor Electric Delivery Company
LLC

No

City of Anaheim

No

August 19, 2011

Question 12 Comment

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Organization

Yes or No

MEAG Power

No

Xcel Energy

No

Golden Spread Electric
Cooperative, Inc.

No

Michgan Public Power Agency

No

Utility System Efficiencies, Inc.

No

Question 12 Comment

Response: Thank you for your response.

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13.Are there any other concerns with this definition that haven’t been covered in previous questions and
comments?

Summary Consideration: Comments received for Question 13 were mostly re-statements of comments expressed in the
previous question. No changes were made to the core definition or Inclusions or Exclusions based solely on question 13
comments. However, changes were made to the Implementation Plan to clarify the effective date of the revised definition.

Organization
Northeast Power Coordinating
Council

Yes or No

Question 13 Comment
Currently, the posted exception criterion is only a concept with many gaps and TBD, as posted details are
later to follow. The exception criteria should be a menu of technical items (load flows, stability analysis etc)
and non technical items (type of loads such as distribution companies versus major city center, national
security, etc). Entities should be required to assess and provide their own justification under each category
with a conclusion that takes into account all of the relevant items for element(s) under exception, in a
consistent template and table of contents. Suggest the SDT to avoid specification of any parameters as they
would differ under different design concepts, system configurations, system characteristics and regulatory
requirements.The comments herein reflect thoughts on the document posted. An “all encompassing”
comment is that the definition is too lengthy. The importance of the BES definition is recognized throughout
the industry for its importance, and as such it should be simple, clear, and straightforward. The first draft
definition posted was more along this line. I2, I3, and I5, being very similar, can they be combined into an
encompassing generator inclusion criteria?

Response: Comments concerning the Technical Principles (Exception Criteria) associated with the RoP Exception Process will be addressed through the dedicated
responses developed by the SDT and published in the specific Consideration of Comments document associated with that portion of the overall project.
The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the language and to provide as much certainty as possible in the
identification of Bulk Electric System (BES) and non-BES Elements. Although the clarifications added to the core definition and the inclusions and exclusions have
lengthened the definition as a whole, the SDT feels that the improvements in clarity and the increased ability to apply the definition to achieve consistent results
justify the overall length of the definition.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards

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Yes or No

Question 13 Comment

Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Tri-State Generation and
Transmission Association, Inc.

We believe that this definition is not consistent with the response from the SPCS in Project 2009-17,
“Interpretation of PRC-004-1 and PRC-005-1 for Y-W Electric and Tri-State” and could change its intent.
Existing tapped distribution transformers are clearly not BES Elements at this time. Under the proposed
definition that clarity is lost.There are instances where “automatic interruption device” or “automatic
interrupting device” is used. Each should be changed to include “fault” after “automatic.”

Response: The Interpretation speaks to which Protection Systems are applicable to the PRC Standards, not which Elements are BES or non-BES. The SDT
believes that the bright-line established by the draft BES definition is not necessarily the same bright-line that should be utilized to identify the Protection Systems
that are applicable to the PRC Reliability Standards and should be addressed by a separate development project. No change made.
Santee Cooper

What was the rationale for using aggregate capacity greater than 75 MVA on I2 and I5. I2 and I3 inclusions
are not the same as defined by the SERC Regional Entity for MOD-024. The SERC guideline does not
include an aggregate value for generating units.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
NERC Staff Technical Review

The definition should include variable frequency transformers and back-to-back HVdc converters that connect
portions of the system operated at 100 kV or higher, regardless of the dc voltage rating of the converter
equipment, which often is less than 100 kV.
Assuring reliable operation of nuclear plants requires that Elements subject to Nuclear Plant Interconnection
Requirements are planned, designed, maintained, and operated in accordance with NERC Reliability
Standards. An additional Inclusion I6 should be added to the definition to include “All transmission Elements
subject to Nuclear Plant Interface Requirements (NPIRs) as agreed to by a Nuclear Plant Generator Operator
and a Transmission Entity defined in NUC-001.”
Assuring reliable operation of the interconnected transmission network also is dependent on reliable operation

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Question 13 Comment
of generating units that system operators rely on for capacity and Contingency Reserves. Additional
Inclusions I7 and I8 should be added to include: * Real Power resources fully or partially relied on to fulfill a
capacity obligation, and * Real Power resources (supply-side or Demand-Side Management) relied on to
provide Contingency Reserves to its Balancing Authority.

Response: The SDT believes that the language contained in the core definition (all Transmission Elements operated at 100 kV or higher) adequately captures
specific components such as variable frequency transformers and back-to-back HVdc converters. No change made.
The SDT does not believe that additional clarification beyond the designations currently established by the core definition and accompanying Inclusions and
Exclusions are necessary to appropriately identify the vast majority of Elements that support the reliable operation of the interconnected transmission network.
Additionally, the RoP Exception Process can be utilized to include facilities that are deemed necessary for the reliable operation of the interconnected transmission
network but not captured by the BES definition. No change made.
NERC Transmission Issues
Subcommittee (TIS)

The definition should include variable frequency transformers and back-to-back HVdc converters that connect
portions of the system operated at 100 kV or higher, regardless of the dc voltage rating of the converter
equipment.

Response: The SDT believes that the language contained in the core definition (all Transmission Elements operated at 100 kV or higher) adequately captures
specific components such as, variable frequency transformers and back-to-back HVdc converters. No change made.
Dominion

Does the SDT assert that there is no reliability gap because the impact of load on the BES is covered
because the DP and LSE are registered and therefore must comply with applicable reliability standards? If so,
why shouldn’t the same apply to generation elements? GO and GOPs, just like DPs and LSEs are registered
users of the bulk power system and must adhere to applicable reliability standards.
Other comments Dominion also has the following comments which are based, to a large degree upon the
webinar of May 19th. Dominion is concerned that while the BES definition is going through the standards
development process, where stakeholders have the ability to ballot, the exception process is being treated as
a change to the Rules of Procedure, with no associated stakeholder ballot. For this reason, Dominion prefers
that the exception criteria itself be part of the BES definition standards development process. As Dominion
reviews the Inclusions and Exclusions included by the SDT in the BES definition, we believe that the SDT
could just have easily developed criteria to determine whether impact on the BES is material. We believe this
would negate the need for the exception process proposed for the Rules of Procedure. However, if this
course is not chosen, then Dominion requests the NERC BOT apply these changes in an ‘all or none’ fashion.
That is, the BES definition and the exception process should both require NERC BOT approval or neither
should be moved to FERC for its approval. We are confused as to how the definition, in particular the
Inclusions and Exclusions, and the exception process are meant to be applied to, or by, the registered entity.

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Question 13 Comment
We thought we heard differing views from the panel; one stating that, if the Element or Facility met the
Inclusion or Exclusion in the BES definition, then an exception request submittal is not required. On the other
hand, we thought we heard that, unless an exception request submittal had been approved then ‘status quo’
applies.
What is ‘status quo’ based on, the current BES definition or the BES definition being proposed? Would an
entity need to track the effective date of the BES definition change in order to determine ‘status quo’? How
will submittal or non-submittal of an exception request by the registered entity be applied for compliance
purposes? Dominion believes the correct answer is that and Element or Facility that meets the BES definition
is included and if it doesn’t meet the BES definition, isn’t included. Only when an exception request has been
submitted by an entity, approved and any appeal resolved, is inclusion or exclusion based on the impact to
the bulk power system as determined by the criteria used in the exception process.

Response: The SDT scope was determined by the language contained in Order Nos. 743 & 743a in which the Commission provided guidance to the ERO to
clarify the definition for continent-wide application. The Commission did not propose significant changes to the current application of the existing definition over
the majority of the continent. Therefore the SDT has developed a draft core definition, together with BES designations (Inclusions and Exclusions) that provide
the specificity necessary to identify the vast majority of BES Elements by utilizing the existing definition and criteria previously approved for this purpose. Although
load is a component that can impact the reliability of the BES, the development of the definition is bound by the limitations documented in Section 215 of the
Federal Power Act. Expanding the definition to include load would exceed the jurisdictional boundaries into the area of local distribution facilities. No change
made.
Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the appropriate
mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles associated with
the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed through the RoP
process for the revision of the Rules of Procedure. The approvals will follow the applicable revision process. No change made.
The BES definition (core definition and Inclusions & Exclusions) will be applied to classify BES vs. non-BES Elements. The SDT believes that this will cover the vast
majority of the facilities in question. The remaining facilities will be candidates for the Exception Process (RoP) where the Technical Principles will be utilized to
determine if the facility is necessary for the reliable operation of the interconnected transmission network. The term ‘status quo’ was referring to the draft BES
definition. Once approved (BES definition, Exception Process and the Technical Principles) the current BES definition will be retired. No change made.
MRO's NERC Standards Review
Forum

In order to provide a clear and concise definition, please add the Brightline Criteria that all facilities less than a
100kV are excluded unless those facilities meet the criteria of an Inclusion.

Response: The SDT believes that the current draft BES definition provides sufficient clarity in establishing the bright-line of 100 kV and the identification of
facilities operated at less than 100 kV for exclusion would be redundant and jeopardize the SDTs efforts of establishing clarity in the language of the definition. In
an effort to provide additional guidance and in support of comments provided in response to Question 11, the SDT has modified the BES core definition with a

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Question 13 Comment

statement that specifically excludes ‘local distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
SERC Planning Standards
Subcommittee

The comments expressed herein represent a consensus of the views of the above-named members of the
SERC EC Planning Standards Subcommittee only and should not be construed as the position of SERC
Reliability Corporation, its board, or its officers.

Response: The SDT appreciates the clarification.
ACES Power Participating
Members

It is not clear if E1 covers networked sub-transmission. Consider the situation where a 138 kV line terminates
into a 138/69 kV transformer, the 69 kV is networked and only serves load and possibly generation that does
not meet any of the inclusion criteria. This is a situation that appears to meet the intent to exclude radial load
under E1 and local distribution networks under E3 but does not appear to explicitly meet either criteria. E1 is
not met because the 69 kV network is not radial and E3 is not met because it specifically limits the exclusion
to 100 kV and above. This issue could be solved by making clear that E1 applies to even networked subtransmission or by removing the voltage limit on E3 so that sub-transmission could be included within this
exclusion criterion.

Response: Exclusions E1 & E3 identify facilities operated at a voltage of 100 kV or higher in an attempt to exclude those types of facilities that do not support
the reliable operation of the interconnected transmission network. Facilities operated at a voltage level less than 100 kV are excluded by the ‘bright-line’
established by the BES core definition unless included through the RoP Exception Process. The SDT is unable to comment on specific system configurations
without detailed information pertaining to the facility in question; however, the SDT believes that the application of the BES definition should start with the
application of the ‘bright-line’ established at the 100 kV threshold.
BPA

As presently written, this BES definition says that “Real Power resources … and Reactive Power resources
connected at 100kV or higher” are to be considered as part of the BES unless one of the specified exclusions
applies. Though exclusion E2 specifically excludes “generating units that serve all or part of a retail Load …
on the customer’s side of the meter”, there is not a similar exclusion for Reactive Power resources that
similarly provide such reactive support solely “on the customer’s side of the meter”. It seems that this results
in such Reactive Power resources (i.e. capacitors, inductors, SVCs, etc.), customer side of the meter being
defined as part of the BES. If this was not the SDT’s intent, BPA requests a new exclusion to specifically
exclude such Reactive Power resources “on the customer’s side of the meter”.

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Question 13 Comment

Response: The SDT agrees with the commenter’s concerns regarding retail customer-owned Reactive Power resources and has drafted an additional Exclusion
E4 to address these concerns.
E4 – Reactive Power devices owned and operated by the retail customer solely for their own use.
Hydro One Networks Inc

We believe that the concepts of inclusions and exclusions as part of the bright-line definition are excellent.
However, these exclusions do not address adequately several complex issues along with directives in Order
No. 743 and 743A, such as: differentiation between Transmission and Distribution, non-jurisdictional
concerns, or distribution. BES definition itself is not a venue to address these complex issues and suggest
that these should be addressed by the ERO’s exception procedure.
We suggest that SDT consider: Removing I5 and adding E4 to exclude intermittent renewable generation
(wind and solar). As stated earlier, such units are intermittent and the planning and operational standards and
practices ensure that their unavailability or unexpected (sudden) loss of generation won’t jeopardize reliability
of the network; therefore, they should not be BES. That the definition and/or exception process should provide
acknowledgement and flexibility to avoid any regulatory conflicts. Introducing a concept of a new category of
registration or BES Support (BESS) elements. These elements are NOT BES but support the reliable
operation of the interconnected transmission network.
A sub-set of relevant NERC Standards should still apply to BESS elements such as planning, design, and
maintenance. However, they may not be contiguous or subject to mandatory compliance.
We do plan to submit our comments on exception criteria and procedure as part of its process. However, we
do suggest that the SDT: Carefully craft the exception criteria that is flexible and technically sound to
adequately allow entities to present their case to the ERO for exception. Verify that the exception criteria
should be at a high-level with key menu items of assessment that can be followed continent-wide by entities
to put forward their exception for element(s) mentioned in exclusions or inclusions based on technical
assessment, evidence and justification for its unique characteristics, configuration, and utilization.
Acknowledge and provide provisions in both NERC exception criteria and exception process for federal, state
and provincial jurisdictions.

Response: The SDT agrees with the commenter that the Exception Process should be the primary mechanism for addressing the concerns surrounding issues
such as: differentiation between Transmission and Distribution, non-jurisdictional concerns, or distribution. However, the SDT has made modifications to the BES
core definition to address the issues associated with the jurisdictional concerns related to local distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.

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Yes or No

Question 13 Comment

Although dispersed power producing resources (wind, solar, etc.) can be intermittent suppliers of electrical generation to the interconnected transmission
network, the SDT has been made aware of geographical areas that depend on these types of generation resources for the reliable operation of the interconnected
transmission network which has prompted the development of Inclusion I4 (previously Inclusion I5). Inclusion I4 has been revised to address industry concerns
identified in responses to Question 6.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
The development of Reliability Standards is not limited in applicability to BES Elements. Reliability Standards are written against facilities that support the reliable
operation of the interconnected transmission network. Therefore the SDT believes that the clarification of the BES definition does not require identification of
these types of facilities and that the specific facilities in question are better addressed by the applicability of individual Reliability Standards and not through the
BES definition or the Exception Process. No change made.
Comments concerning the Technical Principles (Exception Criteria) associated with the RoP Exception Process will be addressed through the dedicated responses
developed by the SDT and published in the specific Consideration of Comments document associated with that portion of the overall project.
Edison Electric Institute

Comments: EEI appreciates the efforts of the SDT and offers these comments to help guide its efforts. EEI
believes that the statutory framework of the Federal Power Act and Section 215 specifically must govern the
definition of BES. While FERC has declined to further define the term “Bulk-Power System” (“BPS”) and
suggested in Order No. 743 that the BPS “reaches farther than those facilities that are included” in the BES, it
is clear that the BES cannot extend further than the BPS, and therefore the statutory definition of BPS must
be the guide for the SDT’s efforts, particularly with regard to the treatment of local distribution facilities.The
BPS definition in Section 215 includes:(1) facilities and control systems necessary for operating an
interconnected electric energy transmission network; and (2) electric energy from generation facilities needed
to maintain transmission system reliability. But the term BPS does not include facilities used in the local
distribution of electric energy. The definition of BES must comply with the statutory definition.EEI points to
several issues to which it believes the SDT should pay particular attention. First, the facilities and control
systems to be included within the BPS/BES must be necessary for operating an interconnected electric
transmission network. Therefore, each of the proposed inclusions and exclusions must be measured against
this requirement - are they necessary? It is insufficient to include a particular facility or element within the
BES definition merely because it would be desirable to have such a facility covered under the BES or a
particular standard.
In addition, EEI believes that imposing a requirement that all contiguous elements be included is too broad
and may sweep in facilities to the BES definition that are statutorily excluded because they are not necessary.
For example, while blackstart resources may be “necessary,” including all facilities that are contiguous
between a particular blackstart resource and the transmission system is likely to include elements that are not

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Question 13 Comment
“necessary” to the operation of the interstate transmission network and therefore not within the statutory
definition. As a general rule, EEI believes it is appropriate to include contiguous elements or facilities above
100kV necessary for operating the interconnected transmission network, but not any below 100 kV unless the
element is necessary to operate the interconnected transmission network.There is no reason to require a
“contiguous” BES down to the local distribution facility level. Section 215 gives NERC and FERC jurisdiction
over “users, owners and operators” of the BPS. Therefore, FERC has authority to require an entity that is not
a BES facility to comply with applicable NERC requirements where necessary for BPS reliability. This
approach would achieve the goals of BPS reliability without extending the full reach of BES applicability to
facilities that may be local distribution facilities that are excluded from Section 215. Second, both the
transmission and the generation facilities included within the BPS/BES must be tied to maintaining the reliable
operation of the BPS. Section 215 defines the term “reliable operation” as “operating the elements of the
bulk-power system within equipment and electric system thermal, voltage, and stability limits so that
instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden
disturbance, including a cybersecurity incident, or unanticipated failure. The statute does not require that
there be no loss of load. The statute is aimed at avoiding uncontrolled separation or cascading failures.
Therefore, consistent with the statute, the definition of BES should only include elements that are necessary
to prevent these occurrences. Third, the statute contains a specific exclusion for facilities used in the local
distribution of electric energy (“local distribution facilities”). FERC has agreed in Orders No. 743 and 743-A
that local distribution facilities are not subject to Section 215. FERC, as the agency implementing Section
215, has the authority to interpret what that means. In Order 743-A, FERC left it to NERC, and therefore to
the SDT, to determine in the first instance which facilities are local distribution and therefore excluded and
whether or not to use tests such as the Seven Factor Test from Order No. 888. Order No. 888 set out seven
indicators, a combination of functional and technical tests, to assist companies and state commissions with
separating local distribution facilities from FERC jurisdictional transmission facilities on a case by case basis.
The seven factors are: (1) Local distribution facilities are normally in close proximity to retail customers; (2)
Local distribution facilities are primarily radial in character; (3) Power flows into local distribution systems; it
rarely, if ever, flows out; (4) When power enters into a local distribution system, it is not reconsigned or
transported on to some other market; (5) Power entering a local distribution system is consumer in a
comparatively restricted geographical area; (6) Meters are based at the transmission/local distribution
interface to measure flows into the local distribution facilities; and (7) Local distribution systems will be of
reduced voltage. EEI acknowledges that the Seven Factor test does not draw a bright line between facilities
used in local distribution and transmission facilities and may not be a perfect fit for applying to specific pieces
of equipment as the SDT has tried to do. However, many state commissions have made determination of
what are local distribution facilities and FERC has concurred with these determinations. Therefore, EEI
proposes that if NERC or FERC seek to include facilities (or class of facilities) in the BES that have been
previously determined by a state commission to be local distribution through application of the Seven Factor
Test, that there is a rebuttable presumption that these are facilities used in local distribution for purposes of

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Question 13 Comment
the BES definition. In order to overcome this presumption, NERC/FERC must make a showing demonstrating
that these facilities “necessary” for the reliable operation of the BPS. EEI will address this and a procedure
for seeking exclusion of facilities that previously have been determined to be local distribution in its comments
to be submitted on the exceptions process.In applying the statutory exclusion for local distribution facilities,
the SDT should ensure that the inclusions do not include local distribution facilities and that the exclusions are
sufficient to exclude local distribution facilities. Similarly, it is not sufficient to include an element that would
otherwise be a local distribution facility merely to support a facility clearly within the BES. For example, the
SDT should consider the how the proposed criteria would classify types of equipment such as distribution
voltage equipment - some, such as cap banks in a generation switchyard do support the transmission system
versus a regulator on a distribution feeder - the former may be part of the BES and the latter unlikely or not at
all.

Response: The SDT has made modifications to the BES core definition to address the issues associated with the jurisdictional concerns related to local
distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
The SDT agrees that the establishment of a contiguous BES could have the unintended consequences of being overly-inclusive and has made corresponding
changes to the Inclusions to address this concern.
The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty as possible
in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current application of
the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support consistent
application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation that the
revision to the definition would not significantly expand or contract what is currently considered to be the BES. Limiting the draft definition to Elements where a
loss could result in instability, uncontrolled separation, or cascading failures is a significant departure from the current definition and not in alignment with the
expectations documented in the Orders (743 & 743a). No change made.
LG&E and KU Energy LLC

August 19, 2011

YesLG&E and KU Energy have a concern that the approval and adoption of the BES definition project and
BES exception procedure project are not linked. This would produce the possibility of the BES definition
project completing and Registered Entities having to comply without having the appropriate and promised
BES exception procedure in place to alleviate unreasonable compliance actions. More specifically, if the BES
definition gets approved and BES exception procedure has not yet been approved (whether due to project
delay or disapproval), then Registered Entities are required to ensure everything within the new definition is
compliant, even if doing so is unreasonable or entirely unnecessary.

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Question 13 Comment

Response: It is the intention of the SDT and the RoP team to file all portions of the project (BES definition, RoP Exception Process, and the Technical Principles)
as a single response to the directives contained in Order Nos. 743 & 743a with the expectation that all portions would be approved at the same time.
Alabama Public Service
Commission

The Alabama Public Service Commission (APSC) appreciates the fact that a member of the Oregon PUC
Staff is participating on this BES Definition drafting team. In reviewing the proposed definition, the APSC’s
focus is to ensure that appropriate definitional lines are drawn so that recognized jurisdictional boundaries are
acknowledged and respected. The concern underlying this focus of the APSC is the fact that utilities must
make significant investments to comply with mandatory reliability standards and, accordingly, compliance with
such standards must be necessary and not duplicative. Furthermore, there should be a commensurate
reliability benefit associated with the cost of the investments needed for compliance.The proposed definition
and NERC’s development of standards should focus on reliable operation of the interconnected electric
transmission network (BES) in order to prevent local events from affecting other regions, not to ensure
reliable operation at the local level.

Pennsylvania Public Utility
Commission

The Pennsylvania Public Utility Commission offers the following comments in response to Standards
Announcement Project 2010-17 BES Definition: As you know, Section 1211 of the Energy Policy Act of 2005,
amending Section 215 of the Federal Power Act, provided for the promulgation of standards for the bulk
power system by an Electric Reliability Organization subject to the approval of the U.S. Federal Energy
Commission. Section 215 (a) states:’SEC. 215. ELECTRIC RELIABILITY.’’(a) DEFINITIONS.-For purposes of
this section:(1) The term ‘bulk-power system’ means-(A) facilities and control systems necessary for operating
an interconnected electric energy transmission network (or any portion thereof); and (B) electric energy from
generation facilities needed to maintain transmission system reliability.The term does not include facilities
used in the local distribution of electric energy.EPAct 2005, Section 1211, 16 U.S.C. § 824 [emphasis
supplied] While the PaPUC acknowledges the need for a more explicit definition of the Bulk Electric System
(or, as it is stated in EPAct 2005, the “bulk power system”), we are concerned that the existing draft definition
and stated exclusions is insufficiently clear and may be erroneously extended to distribution facilities that are
currently subject to state jurisdiction expressly reserved by the language of EPAct 2005, Section 1211
(a).Exceptions E1-E4 are plainly drafted to address this issue, but there is a concern that the definition of
“local distribution networks” contained in Exception E3 may not fully comport with the intent of Congress,
particularly Exception E3 (d) which excepts facilities that are [n]ot used to transfer bulk power: The LDN is not
used to transfer energy originating outside the LDN for delivery through the LDN. The proposed language
appears to be contrary to Congressional intent as it implies that some local distribution facilities which
“transfer bulk power” are indeed subject to the ERO standards process. Additionally, the draft BES, which
distinguishes local distribution facilities between those that “transfer bulk power” and those that do not
appears insufficiently precise, as bulk power is ultimately transferred through every portion of the local
distribution network to end users.Our major concern is that this draft standard definition will collide with state

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Question 13 Comment
regulation of distribution facilities, particularly where state commissions are seeking to impose standards and
protective arrangements more stringent than might be required by the Electric Reliability Organization or
Regional Reliability Organization. Accordingly, it is recommended that the Draft BES be modified to
specifically define distribution facilities and exclude them from the ambit of the Bulk Electric System definition,
as well as making it clear that State reliability standards relating to the local distribution network are not
overridden or modified by standards applicable to the Bulk Electric System.

National Association of
Regulatory Utility Commissioners

Congress clearly recognized that State utility commissions are concerned about and committed to reliability at
the distribution level; that's why Congress explicitly limited FERC's reach, and directed FERC not to attempt to
regulate facilities used in local distribution.The NERC standard setting process for defining the Bulk Electric
System must respect the statutory limitations under Federal Power Act Section 215 that explicitly excluded
local distribution from the definition of the Bulk Power System (BPS). The Bulk Electric System, while not
necessarily equivalent to the BPS (See FERC Order 743 A P 102), cannot exceed the limitations of the BPS
and cannot include facilities used in the local distribution of electric energy. State Utility Commissions are
concerned about and committed to reliability. These Commissions are in the best position to provide reliability
oversight and standards for the local distribution system in their State.

Response: The SDT is developing a revised definition of the BES to identify the facilities that support the reliable operation of the interconnected transmission
network. The SDT has revised the draft BES definition to address the potential jurisdictional boundaries that currently exist in regards to local distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Western Electricity Coordinating
Council

The definition should also reference the exception process and technical justification allowed for further
inclusion or exclusion from the BES.

Utility System Efficiencies, Inc.

The definition should also reference the exception process and technical justification allowed for further
inclusion or exclusion from the BES.

Response: Such a statement was inadvertently left off of the first posted version of the definition.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.
Western Montana Electric
Generating and Transmission

August 19, 2011

WMG&T has these additional concerns: The current definition provides that “Elements may be included or
excluded on a case-by-case basis through the Rules of Procedure exception process.” WMG&T is concerned
that the SDT carefully delineate which entity has the burden of proof in the exclusion process. The WECC

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Organization
Cooperative

Yes or No

Question 13 Comment
BESDTF approach, which we commend to the SDT, laid out these burdens in some detail. Under that
approach, essentially, if a facility is excluded from the BES by virtue of the specific exclusions listed in the
definition, the Regional Entity bears the burden of proving that the facility nonetheless has a material impact
on the interconnected bulk transmission system and therefore should be included in the BES. On the other
hand, if a facility is classified as BES by virtue of the list of inclusions set forth in the BES definition, it can still
escape classification as BES, but bears the burden of demonstrating that its facility has no material impact on
the interconnected transmission system. We urge the SDT to give careful consideration to these burden-ofproof questions and to follow the lead of the WECC BES Task Force.
For the reasons we have explained in our answer to Question 11, we believe the Exception process is critical
both to ensure that the BES definition is effective in producing measurable gains to bulk system reliability and
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the Standards
Development Process. Accordingly, we urge that all elements of the BES definition, including those elements
that have been assigned to the Rules of Procedure Team, be vetted through the Standards Development
Process.

Response: The SDT believes that the burden of proof issue should be resolved through the development of the RoP Exception Process. Your comments will be
forwarded to the RoP team for consideration.
Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the appropriate
mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles associated with
the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed through the RoP
process for the revision of the Rules of Procedure.
PacifiCorp

Effective dates: While understanding that additional facilities will require up to two years to come into
compliance, several facilities will also be excluded that are currently under the current bright line definition.
Are utilities going to be responsible to maintain all NERC reliability standards during the two year period for
facilities or elements that will be excluded by the new bright line definition? PacifiCorp proposes that the
effective date for facilities being removed from the bright line become effective on the first day of the first
calendar quarter after applicable regulatory approval. It is reasonable to retain the two year period for facilities
that will be added to the BES.
NERC Staff has submitted written comments to this project stating that the BES “must be contiguous.”

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Organization

Yes or No

Question 13 Comment
Instituting a contiguous BES with Inclusion I2, for example, would result in a substantially over-inclusive BES
definition. The adoption of a “contiguous” BES is therefore likely to result in imposition of reliability standards
on a substantial number of distribution elements that have nothing to do with improving or protecting the
reliability of bulk transmission system.There is no compelling reason to adopt a “contiguous” BES that covers
local distribution systems. Section 215 of the FPA provides FERC with jurisdictional authority over “users” as
well as “owners” and “operators” of the bulk power system. Consequently, FERC has the jurisdictional
authority to require generation and other entities to comply with applicable NERC requirements. Hence, even
where an entity does not own or operate BES assets, it could still be required, for example, to provide
necessary information to the applicable Reliability Coordinator or Planning Coordinator and to participate in
programs to prevent instability, uncontrolled separation, or cascading outages to the bulk transmission
system. This approach would fully achieve the goals of bulk transmission system reliability without imposing
the full BES regulatory compliance burden on local distribution elements.
Although not specifically the responsibility of the SDT, it should closely coordinate its efforts with the team
developing the inclusion/exclusion process in the ROP. For instance, if the ROP team develops an overly
onerous process to exclude elements which are not required to reliably operate the interconnected BES yet
are not excluded through the bright-line definition then PacifiCorp would consider the bright-line definition to
be over-inclusive.

Response: The SDT agrees with the commenter and has made revisions to the Implementation Plan to address these concerns surrounding the implementation
dates.
The SDT agrees that the establishment of a contiguous BES could have the unintended consequences of being overly-inclusive. Inclusion I2 has been revised and
merged with Inclusion I3 (now Inclusion I2) and as a result the implication of the continuity of the BES has been removed. Additionally, the SDT recognizes the
limitations associated with FERC’s jurisdiction as defined in the FPA Section 215 and has therefore provided additional clarification in the core BES definition to
address these concerns.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
It is the intention of the SDT and the RoP team to file all portions of the project (BES definition, RoP Exception Process, and the Technical Principles) as a single
response to the directives contained in Order Nos. 743 & 743a with the expectation that all portions would be approved at the same time.

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Organization
Intellibind

Yes or No

Question 13 Comment
Generation that is BES significant that is not connected at 100kV or above.

Response: This ‘significant’ generation should be identified with the appropriate technical justification, established and presented by the Regional Entity, in
accordance with the Rules of Procedure Exception Process for ‘inclusion’ approval by the ERO. No change made.
City of Redding

Additional concerns:
The SDT has avoided directly addressing the predominate issues that plagues the industry. The two main
issues are: a sound definition of the term “necessary for operating the interconnected transmission network”
and “whether a particular facility is local distribution or transmission” as directed by FERC in both Orders 743
and 743A. As an example, in terms of pure operation of an interconnected transmission system there is only a
small amount of the generation connected to the BES system where the energy is actually “necessary for
operating the interconnected transmission network”. As the users of the system increase load and remote
generation responds then the transmission system only needs the VAR support and reserves from a select
set of generators, therefore the Definition goes too far, and creates a generalization that all generators over
20 MVA are “necessary”. This is especially not true if the generation is a load modifier embedded in a
Distribution system and the generator only requires reserves from the BES. These services are a function of
the BES and are paid for by the user.
Redding is concerned that the SDT is intertwining the BES Definition and the Statement of Compliance
Registry out of convenience. It is our view that the the NERC Registry Criteria serves a different function than
the Definition in that it does not clarify what elements are BES elements but identifies the Owners, Operators,
and Users of the BES and therefore the NERC Standards could be applied. The SDT does not have a
technical justification to adopt the current thresholds in the Compliance Registry as part of the BES Definition.
These thresholds have not been presented to the industry for validation or review. Additionally, the Statement
of Compliance Registry was an initial attempt of NERC to begin a new regulation requirement and was not
created through the NERC Standards Development Process.
Redding suggests that the SDT, in the interest of reliability, recommend that the NERC Statement of
Compliance Registry be modified to create a tiered level of responsibilities for entities. A 20 MVA generator
has a different level of responsibility to the BES then an 800 MVA generation unit. A LDN that does not qualify
for an exemption due to an impact on a path or flow gate should not be required to meet the full requirements
of a Transmission Operator. This in fact reduces reliability by diverting the local training focus from the
operation of a Local Control Center (LCC) and a sub-transmission system. Prior to the NERC Standards
WECC had training classes for Sub-transmission Operators that were applicable to the reliable operation of a
local Sub-transmission system. The implementation of the NERC Standards has decreased reliability in this
area because the focus of coordinating with the LCC and sub-transmission level has been lost.

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Organization

Yes or No

Question 13 Comment

Response: The SAR has clearly identified the responsibilities of the SDT in revising the definition of the BES. The scope does not include the additional definitions
noted above. No change made.
The Commission stated in Order Nos. 743 & 743a that they believe the current application of the definition is correct and should be maintained. The current
application of the definition is based on Commission language contained Order 693 which directs the use of the BES definition and NERC Statement of Compliance
Registry to identify the functional entities required to be registered and which Reliability Standards will apply. The linkage between the BES definition and Registry
Criteria was established by the Commission in Order No. 693 and uncontested by the industry at the time of filing. No change made.
The ERO Statement of Compliance Registry is governed by the Rules of Procedure and under the responsibilities of the ERO Certification and Registration
Department and does not fall under the current responsibility of the SDT as defined by the scope in the SAR for Project 2010-17. No change made.
Public Utility District No. 1 of
Snohomish County, Washington

Snohomish County PUD has these additional concerns:
We are concerned that the proposed 24-month delay in the effective date of the new definition will delay the
potentially beneficial effects of the SDT’s efforts, especially for utilities that have been inappropriately
registered for BES-related functions, which is a common situation in WECC. We therefore urge the new BES
definition to become effective immediately upon approval by FERC or other applicable regulatory agencies.
Entities that have been improperly registered for BES functions can then immediately file for deregistration
and obtain the benefits of the new definition as soon as possible. For entities that have not previously been
registered for BES-related functions but that would be required to register under the new definition, we do not
object to the 24-month transition period proposed by the SDT to allow the newly-registered entity to attain
compliance with newly-applicable reliability standards, many of which require new training for employees, new
maintenance procedures, and complex new operational protocols. However, the transition period for newlyregistered entities should be structured in a way that does not prevent entities seeking deregistration from
benefitting from the new definition at the earliest possible date.
The current definition provides that “Elements may be included or excluded on a case-by-case basis through
the Rules of Procedure exception process.” Snohomish is concerned that the SDT carefully delineate which
entity has the burden of proof in the exclusion process. The WECC BES Task Force approach, which we
commend to the SDT, laid out these burdens in some detail. Under that approach, essentially, if a facility is
excluded from the BES by virtue of the specific exclusions listed in the definition, the Regional Entity bears
the burden of proving that the facility nonetheless has a material impact on the interconnected bulk
transmission system and therefore should be included in the BES. On the other hand, if a facility is classified
as BES by virtue of the list of inclusions set forth in the BES definition, it can still escape classification as
BES, but bears the burden of demonstrating that its facility has no material impact on the interconnected
transmission system. We urge the SDT to give careful consideration to these burden-of-proof questions and
to follow the lead of the WECC BES Task Force.
For the reasons we have explained in our answer to Question 11, we believe the Exception process is critical

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Yes or No

Question 13 Comment
both to ensure that the BES definition is effective in producing measurable gains to bulk system reliability and
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the Standards
Development Process. Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of
Procedure upon approval of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3,
2010) (providing for, e.g., posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). Accordingly, we urge that all elements of the BES definition, including those
elements that have been assigned to the Rules of Procedure Team, be vetted through the Standards
Development Process. Further, we believe that the failure to vet all material elements of the BES definition
through the Standards Development Process would constitute a violation of NERC’s bylaws and the
requirements of the Standards Development Process.

Response: The SDT agrees with the commenter and has made revisions to the Implementation Plan to address these concerns surrounding the implementation
dates.
The SDT believes that the burden of proof issue should be resolved through the RoP Exception Process. Your comments will be forwarded to the RoP team for
consideration.
Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the appropriate
mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles associated with
the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed through the RoP
process for the revision of the Rules of Procedure.
Grand Haven Board of Light and
Power

I can not over emphasize how unreasonable it would be for our utility to have to register as a TO/TOP
because of one asset (138kV circuit switcher) that serves a radial, load serving system. It is equally
unreasonable for us to have to use a long and arduous exception process to qualify for deregistration. Please
take this into consideration as you prepare the final definition.

Response: The SDT is responsible for the revision of the BES definition. In fulfilling this responsibility the SDT is developing a definition that properly classifies
facilities as BES or non-BES Elements. Defining registration requirements is not within the scope of Project 2010-17. No change made.
National Grid

August 19, 2011

We are concerned that the proposed definition of BES and specified inclusions reaches farther into the
electric system than the Bulk Power System (BPS) definition. The statutory framework of the Federal Power

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Organization

Yes or No

Question 13 Comment
and section 215 specifically must govern the definition of BES. It is clear in FERC’s Order No. 743 that BES
should not extend further than BPS, therefore the statutory definition of BPS must be the guide for the SDT’s
efforts, particularly with regard to the treatment of local distribution facilities. The BPS definition includes (1)
facilities and control systems necessary for operating an interconnected electric energy transmission network;
and (2) electric energy from generation facilities needed to maintain transmission system reliability. It does
not include facilities used in the local distribution of electric energy. The definition of BES must comply with
the statutory definition.First, the facilities and control systems to be included within the BPS/BES must be
necessary for operating an interconnected electric transmission network. Therefore, one question to consider
for each of the proposed inclusions and exclusions is “are they necessary?” A particular facility or element
should not included in the BES definition just because it would be desirable to have the facility considered
BES or covered by a particular standard.
Imposing a requirement that all contiguous elements be included is too broad and may sweep in facilities to
the BES definition that are statutorily excluded because they are not necessary.
Second, both the transmission and the generation facilities included within the BPS/BES must be tied to
maintaining the reliable operation of the BPS. Section 215 defines the term “reliable operation” as “operating
the elements of the bulk-power system within equipment and electric system thermal, voltage, and stability
limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result
of a sudden disturbance, including a cybersecurity incident, or unanticipated failure”. The statute does not
require that there be no loss of load. The statute is aimed at avoiding uncontrolled separation or cascading
failures. Therefore, the definition of BES should only include elements that are necessary to prevent these
occurrences.

Response: The SDT recognizes the limitations associated with FERC’s jurisdiction as defined in the FPA Section 215 and has therefore provided additional
clarification in the core BES definition to address these concerns.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
The SDT agrees that the establishment of a contiguous BES could have the unintended consequences of being overly-inclusive. Inclusion I2 has been revised and
merged with Inclusion I3 (now Inclusion I2) and as a result the implication of the continuity of the BES has been removed.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty in the

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Organization

Yes or No

Question 13 Comment

identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current application of the
existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support consistent application
across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation of the revision to the
definition would not significantly expand or contract what is currently considered to be the BES. Limiting the draft definition to Elements where a loss could result
in instability, uncontrolled separation, or cascading failures is a significant departure from the current definition and not in alignment with the expectations
documented in the Orders (743 & 743a). No change made.
Northern Wasco County PUD

Northern Wasco County PUD has these additional concerns: The current definition provides that “Elements
may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.”
Northern Wasco County PUD is concerned that the SDT carefully delineate which entity has the burden of
proof in the exclusion process. The WECC BESDTF approach, which we commend to the SDT, laid out
these burdens in some detail. Under that approach, essentially, if a facility is excluded from the BES by virtue
of the specific exclusions listed in the definition, the Regional Entity bears the burden of proving that the
facility nonetheless has a material impact on the interconnected bulk transmission system and therefore
should be included in the BES. On the other hand, if a facility is classified as BES by virtue of the list of
inclusions set forth in the BES definition, it can still escape classification as BES, but bears the burden of
demonstrating that its facility has no material impact on the interconnected transmission system. We urge the
SDT to give careful consideration to these burden-of-proof questions and to follow the lead of the WECC BES
Task Force.
For the reasons we have explained in our answer to Question 11, we believe the Exception process is critical
both to ensure that the BES definition is effective in producing measurable gains to bulk system reliability and
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the Standards
Development Process. Accordingly, we urge that all elements of the BES definition, including those elements
that have been assigned to the Rules of Procedure Team, be vetted through the Standards Development
Process.

Clallam County PUD No.1
Chelan PUD – CHPD
Public Utility District No. 1 of
Franklin County

August 19, 2011

Clallam County PUD has these additional concerns: The current definition provides that “Elements may be
included or excluded on a case-by-case basis through the Rules of Procedure exception process.” Clallam is
concerned that the SDT carefully delineate which entity has the burden of proof in the exclusion process. The
WECC BES Task Force approach, which we commend to the SDT, laid out these burdens in some detail.
Under that approach, essentially, if a facility is excluded from the BES by virtue of the specific exclusions

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Organization
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc.
Cowlitz County PUD

Yes or No

Question 13 Comment
listed in the definition, the Regional Entity bears the burden of proving that the facility nonetheless has a
material impact on the interconnected bulk transmission system and therefore should be included in the BES.
On the other hand, if a facility is classified as BES by virtue of the list of inclusions set forth in the BES
definition, it can still escape classification as BES, but bears the burden of demonstrating that its facility has
no material impact on the interconnected transmission system. We urge the SDT to give careful
consideration to these burden-of-proof questions and to follow the lead of the WECC BES Task Force.
For the reasons we have explained in our answer to Question 11, we believe the exemption process is critical
both to ensure that the BES definition is effective in producing measurable gains to bulk system reliability and
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the exemption process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the Standards
Development Process. Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of
Procedure upon approval of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3,
2010) (providing for, e.g., posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). Accordingly, we urge that all elements of the BES definition, including those
elements that have been assigned to the Rules of Procedure Team, be vetted through the Standards
Development Process. Further, we believe that the failure to vet all material elements of the BES definition
through the Standards Development Process would constitute a violation of NERC’s bylaws and the
requirements of the Standards Development Process.

Response: The SDT believes that the burden of proof issue should be resolved through the development RoP Exception Process. Your comments will be
forwarded to the RoP team for consideration.
Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the appropriate
mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles associated with
the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed through the RoP
process for the revision of the Rules of Procedure.
PUD No. 2 of Grant County,
Washington

August 19, 2011

Grant has these additional concerns: We are concerned that the proposed 24-month delay in the effective
date of the new definition will delay the potentially beneficial effects of the SDT’s efforts, especially for utilities
that have been inappropriately required to meet BES reliability standards, which is a common situation in
WECC. We therefore urge the new BES definition become effective immediately upon approval by FERC or
other applicable regulatory agencies. Entities that have been improperly required to meet standards can then
immediately redirect resources to where they are truly needed. For entities that have not previously been

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Organization

Yes or No

Question 13 Comment
registered for BES-related functions but that would be required to register under the new definition, we agree
that 24 months is an appropriate transition period to allow the newly-registered entity to attain compliance with
newly-applicable reliability standards, many of which require new training for employees, new maintenance
procedures, and complex new operational protocols. However, the transition period for newly-registered
entities should be structured in a way that does not prevent entities seeking deregistration from benefitting
from the new definition at the earliest possible date.
The current definition provides that “Elements may be included or excluded on a case-by-case basis through
the Rules of Procedure exception process.” Grant is concerned that the SDT carefully delineate which entity
has the burden of proof in the exclusion process. The WECC BESDTF approach, which we commend to the
SDT, laid out these burdens in some detail. Under that approach, essentially, if a facility is excluded from the
BES by virtue of the specific exclusions listed in the definition, the Regional Entity bears the burden of proving
that the facility nonetheless has a material impact on the interconnected bulk transmission system and
therefore should be included in the BES. On the other hand, if a facility is classified as BES by virtue of the
list of inclusions set forth in the BES definition, it can still escape classification as BES, but bears the burden
of demonstrating that its facility has no material impact on the interconnected transmission system. We urge
the SDT to give careful consideration to these burden-of-proof questions and to follow the lead of the WECC
BES Task Force.

Response: The SDT agrees with the commenter and has made revisions to the Implementation Plan to address these concerns surrounding the implementation
dates.
The SDT believes that the burden of proof issue should be resolved through the development RoP Exception Process. Your comments will be forwarded to the
RoP DT for consideration.
Wells Rural Electric Company

Dear NERC Standards Drafting Team:Enclosed are Wells Rural Electric Company’s comments on NERC’s
Proposed Continent-wide Definition of Bulk Electric System. We believe that NERC’s proposed Continentwide Definition of Bulk Electric System is proceeding in the right direction on this important topic but that more
work needs to the done. We would like to thank the Standards Drafting Team for their hard work. We support
the detailed comments of the Snohomish County Public Utility District and Pacific Northwest Generating
Cooperative with regard to the questions posed by the Comment Form for Project 2010-17 Definition of
BES.We would like to emphasize these portions of Snohomish’s and PNGC’s comments:
Question 1, both PNGC and Snohomish suggest that NERC start by adopting the statutory definition of the
bulk power system as the core definition. We support that approach. That is, “(t) he term ‘Bulk Electric
System’ means: (A) Facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof); and,(B) Electric energy from generation facilities needed to
maintain transmission system reliability.The term does not include facilities used in the local distribution of

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Question 13 Comment
electric energy”. See 16 U.S.C. § 824o(a)(1).”
Question 7, we support the exclusion for radial lines as drafted.
Question 9, we support the categorical exclusion of Local Distribution Networks from the BES as defined
here, but with Snohomish’s clarifications.
Question 10, we support exclusion E4, for small utilities, but we are unclear how small utilities are defined in
the exclusion language presented here.
Question 11, we support the approach to exclusion of local distribution facilities discussed in the draft but
repeat that more work should be done on the definition so that facilities used in local distribution are not swept
up into the BES.The primary value of clearly defining the BES is for registration determinations. We realize
that clearly defining the BES also has value in determining which standards apply to registered entities. If a
registered entity does not own any Elements of the BES that that registered entity should be able to efficiently
and effectively demonstrate an exception. We encourage NERC to support the use of the BES definition for
registration-issues and to develop the exception procedure for registered entities that do not own or operate
any Elements of the BES.

Response: The SDT appreciates the industry support for this project. Please see the SDT responses in Questions 1, 7, 9, 10, and 11 of this document.
ExxonMobil Research and
Engineering

There are certain transmission network configurations in the south east portion of the country where the
majority of the interconnected transmission network is owned and maintained by a single utility company, but
approximately one hundred substations that are located along the interconnected transmission network and
utilized to transmit power between regions are owned by separate companies (i.e. many companies own a
single transmission substation). The SDT should consider this configuration and the lack of uniform operation
and maintenance practices that may exist due to the differences in how the companies implement NERC
compliance.

Response: The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty
as possible in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current
application of the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support
consistent application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation
of the revision to the definition would not significantly expand or contract what is currently considered to be the BES. The SDT is unable to comment on specific
system configurations without detailed information pertaining to the facility in question.
FortisBC

August 19, 2011

We believe that the concepts of inclusions and exclusions as part of the bright-line definition are excellent.
However, these exclusions do not address several directives in Order No. 743 and 743A, such as:

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Question 13 Comment
differentiation between Transmission and Distribution, non-jurisdictional concerns, or distribution. We believe
that the BES definition itself is not a venue to address these concerns but suggest that these issues should be
explicitly addressed by the ERO’s exception criteria and exception process. Currently, the posted exception
criterion is only a concept with many gaps and TBD, as posted details are later to follow. We suggest that the
exception criteria should be a menu of technical items (load flows, stability analysis etc) and non technical
items (type of loads such as distribution companies vs. major city center, national security etc). Entities should
be required to assess and provide their own justification under each category with a conclusion that takes into
account all of the relevant items for element(s) under exception, in a consistent template and table of
contents. We suggest the SDT to avoid specification of any parameters as they would differ under different
design concepts, system configurations, system characteristics and regulatory requirements.

Response: The SDT agrees with the commenter that the Exception Process should be the primary mechanism for addressing the concerns surrounding issues
such as: differentiation between Transmission and Distribution, non-jurisdictional concerns, or distribution. However the SDT has made modifications to the BES
core definition to address the issues associated with the jurisdictional concerns related to local distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Comments concerning the Technical Principles (Exception Criteria) associated with the RoP Exception Process will be addressed through the dedicated responses
developed by the SDT and published in the specific Consideration of Comments document associated with that portion of the overall project.
MidAmerican Energy Company

While there were no questions directed to the draft implementation plan in the comment form, if the intent was
to also solicit comments on that plan, the schedule in that plan is likely too agressive if the result of the
revised BES definition is that new facilites are brought into the BES and are thereby obligated to now comply
with standards they had not previously been required to meet. Perhaps a provision should be added to the
implementation plan to address this situation and allow an extended schedule for new BES facilities to comply
with applicable standards.

Response: The SDT believes that the 24 month schedule for implementation is a reasonable compromise considering the Commission suggested timeframe of 18
months and the burden of newly registered functional entities in establishing compliance with the applicable Reliability Standards. The SDT did, however, extend
the effective date by an additional quarter of a year based on stakeholder comments.
American Electric Power

August 19, 2011

Usage of the NERC term “Element” clearly excludes associated auxiliary equipment such as protective relay
systems and metering systems. If this is not the intent of the SDT, then there needs to be more
comprehensive BES nomenclature established that distinguishes among the applicable primary-voltage
equipment, the associated auxiliary equipment having an impact to the BES, and the associated ancillary

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equipment having no electrical impact to the BES.In addition, please see response to question 1 regarding
the request for industry input on concurrent, closely related projects (approved definition of BES, the technical
principles for demonstrating BES exception, and the exception process itself).

Response: The SDT has determined that the draft BES definition should identify BES Elements which are operated at a voltage of 100 kV or above. The SDT also
has recognized the existence of facilities (i.e., auxiliary equipment and Protection Systems) that support the reliable operation of the interconnected transmission
network but do not necessarily operate at voltages of 100 kV or above and should not necessarily be classified as BES Elements. Reliability of the interconnected
transmission network is established by the application of Reliability Standards and the development of Reliability Standards is not limited in applicability to BES
Elements. Reliability Standards are written against facilities that support the reliable operation of the interconnected transmission network. Therefore the SDT
believes that the clarification of the BES definition does not require identification of these types of facilities and that the specific facilities in question are better
addressed by the applicability of individual Reliability Standards and not through the BES definition or the Exception Process. No change made.
Farmington Electric Utility System

The Rules of Procedure for Exceptions should define the compliance expectation of the entity while an
exception is being considered; similar to the CIP TFE process.

Response: The SDT believes that compliance expectation issues should be resolved through the RoP Exception Process. Your comments will be forwarded to the
RoP team for consideration.
Colorado Springs Utilities

Colorado Springs Utilities supports the SDT’s efforts to create an acceptable BES definition directly linked to
an exemption process. Know that WECC has a task force, the Bulk Electric System Definition Task Force
(BESDTF), which has done some notable work on this task. See WECC BESDTF Proposal 6, Appendix C
(http://www.wecc.biz/Standards/Development/BES/default.aspx). The BES definition is very complex and the
BESDTF has already addressed many of the tough issues that have yet to be addressed in this process, such
as: o Local Distribution Network definition for automatic exemption o Determination of radial facilities o
Demarcation of BES and non-BES Elements o Alternate dispute resolution process o Assignment of the
burden of proof for the exemption process o Technical approach for the inclusion/exclusion determination

Sacramento Municipal Utility
District (SMUD)

SMUD supports the SDT’s efforts to create an acceptable BES definition directly linked to an exemption
process. SMUD would also like to bring to the BES SDT’s attention that the WECC the Bulk Electric System
Definition Task Force has constructed the framework on this task that we encourage the SDT to review their
work. SMUD would like to thank the BES SDT for consideration of these comments.

Tacoma Power

Tacoma Power supports the SDT’s efforts to create an acceptable BES definition directly linked to an
exemption process. Please be aware that the WECC has a task force, the Bulk Electric System Definition
Task Force (BESDTF), which has done some notable work on this task. See WECC BESDTF Proposal 6,
Appendix C (http://www.wecc.biz/Standards/Development/BES/default.aspx). The BES definition is very

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complex and the BESDTF has already addressed many of the tough issues that have yet to be addressed in
this process, such as: o Local Distribution Network definition for automatic exemption o Determination of
radial facilities o Demarcation of BES and non-BES Elements o Alternate dispute resolution process o
Assignment of the burden of proof for the exemption process o Technical approach for the
inclusion/exclusion determinationThank you for consideration of our comments.

Response: The SDT has taken into account the work product of several regional efforts in the development of the draft BES definition.
Consumers Energy Company

Yes.We propose an alternative core BES definition to read as follows: “All network System Elements
operated at 100 kV or higher, Real Power resources as described below, and Reactive Power resources
connected at 100 kV or higher unless such designation is modified by the list shown below.”
We support extending the transition period to 24 months.

Response: The SDT believes that the revised draft BES definition provides sufficient clarity in establishing the bright-line of 100 kV.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Thank you for your support.
Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

Occidental Energy Ventures Corp (“OEVC”) would like to emphasize that the proposed definition of the BES
does not only impact OEVC and its affiliates. The proposed BES definition would include numerous facilities
that are used for the local distribution of electric energy, not transmission, in direct contravention of Section
215 of the FPA. For example, there are likely hundreds, if not thousands, of retail customers that have selfprovided “hard-tapped” facilities behind the retail delivery point. Those retail customers, many of who are
likely unaware of the proposed BES definition, much less its impact, will have their facilities under the
proposed BES definition suddenly become transmission facilities simply because their facilities are not
separated from the BES by an automatic fault-interruption device.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenter’s. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the
normally open switch to a note, and clarified the generation allowed within the system.
In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local networks. The SDT
realizes that a bright-line definition may require entities to seek exceptions through the Rules of Procedure exception process.

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Chevron Global Power, a division
of Chevron U.S.A. Inc.

August 19, 2011

Yes or No

Question 13 Comment
Chevron U.S.A. Inc. has reviewed the proposed Bulk Electric System definition and is concerned that the
proposed changes designed to enhance reliability and accountability of Transmission and Generation are
inadvertently catching parties whose prime operations are distribution in nature. Chevron is proposing minor
changes that will not affect the necessary regulation of the bulk power industry, but will exempt parties that
are not crucial to reliability and provide mostly, if not entirely, distribution or self use service.In remote areas of
west Texas, Chevron has hundreds of non contiguous producing properties and facilities located over
hundreds of square miles. In some cases where the utility was close and had the capability to serve, Chevron
took utility service. Where service was not available or the utility did not have the capability, Chevron built its
own private power distribution system to service its own facilities. Chevron has no generation and takes all of
its power from transmission providers. In at least one instance Chevron takes power at over 100 kV from a
transmission provider. Chevron has an automated interruption device between its facilities and the
transmission facilities. Currently this field takes power from an ERCOT transmission owner at above 100 kV
and then distributes the power over a Chevron owned and operated power distribution system to Chevron
facilities. This Chevron system includes a substation, transformers and other facilities necessary to take
power at above 100 kV and distribute and step down the power as necessary. Chevron uses the power for
offices, repair facilities, oil wells, separation facilities, gas plants, drilling new wells and other related oil and
gas activities. Located within the area of the Chevron power distribution system are ranchers, pump stations,
third party oil wells and other small users. These parties are not located near any utility or coop facilities. For
decades Chevron has worked to accommodate these parties by working with the local utility, transmission
owners and the Texas Public Utility Commission to allow electrical service to these remote users. Many of
these ranchers and other users are not located near any utility lines. Costs could run to the hundreds of
thousands of dollars (or more) to provide an interconnect from the utility. Instead of leaving these parties with
no electrical service, a procedure was developed that allowed parties such as Chevron to accommodate the
small end user. For example if a utility/coop was unable or unwilling to serve a rancher at a reasonable cost,
the rancher could approach Chevron. The goal would be to execute a three party agreement between the
rancher, Chevron and the service provider. Under the terms of the agreement, the Rancher would
interconnect with the Chevron system. A utility quality meter capable of remote reading would be installed
and the rancher would be responsible for all costs beginning at the meter. The rancher contracts with a
power provider for his power. Every month the meter between the Transmission owner and Chevron would
be read. This smart meter located at the interconnect with the transmission system and its soft ware would
show all deduct metering (such as our rancher) so that any non Chevron parties on the Chevron distribution
system’s usage would clearly be listed. The transmission owner then provides the billing information to the
rancher’s power provider. Chevron receives no compensation from the rancher, power provider or
transmission owner. Chevron provides the service strictly on an accommodation basis. The Texas Public
Utility Commission recognizes the needs of parties in remote areas of Texas and has blessed this type of
service. Chevron is not considered a utility for providing this type of service.Chevron is concerned that the
above described private power distribution system may inadvertently be forced to register as a bulk electric

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system provider. This private distribution system is clearly at the terminus of a radial line and provides
service to Chevron owned and operated facilities. The system is large in area and has been built over a
period longer than any current employee’s memory. Through what can be called “accidents of history” and a
good neighbor policy, Chevron has accommodated parties that otherwise could not connect to utility quality
power. This arrangement is blessed and encouraged by the State PUC. Chevron charges nothing for the
service. The system is entirely distribution in nature and does not contribute to the reliability of the grid in any
manner. The intent of the current rule making is not to encompass such a system. NERC needs to
encourage parties such as Chevron to help bring power to remote areas and not discourage, or worse yet
greatly increase the cost to provide such service.Chevron requests that the NERC include in its definition a
statement making it clear that systems such as those described above should not be required to register.
Chevron supports the technical changes suggested by ELCON in its filing.A party’s facility should not be
considered an essential facility where the facility would otherwise be considered exempt except that it is
providing distribution services as an accommodation to third parties. This is especially true when1. The
incumbent utility or coop is unable or unwilling to serve the third parties at a reasonable cost2. The service to
the third party is provided as an accommodation3. The facility is not generating and/or selling power to the
third party4. The third party is purchasing power from a power provider

Response: The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty
as possible in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current
application of the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support
consistent application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation
of the revision to the definition would not significantly expand or contract what is currently considered to be the BES.
The SDT believes that establishing a ‘bright-line’ approach to identify BES Elements will inherently incorrectly identify a small number of facilities. The Exception
Process is designed to clear up these discrepancies and render the proper classification of those questionable facilities. The SDT believes that with the draft core
definition and the BES designations (Inclusions and Exclusions) the vast majority of facilities will be correctly identified as BES or non-BES Elements and therefore
will produce the consistent application and results as desired by the Commission’s language in Order Nos. 743 & 743a.
The SDT made several revisions to the definition that should address your concerns.
Muscatine Power and Water

In order to provide a unambiguous and concise definition of the BES, we ask the SDT to please include in the
bright-line criteria that “all facilities less than a 100kV are excluded unless those facilities meet the criteria of
an Inclusion.”

Response: The SDT believes that the current draft BES definition provides sufficient clarity in establishing the bright-line of 100 kV and the identification facilities
operated at less than 100 kV for exclusion would be redundant and jeopardize the SDTs efforts of establishing charity in the language of the definition. If an effort
to provide additional guidance and in support of comments provided in response to Question 11, the SDT has modified the BES core definition with a statement

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that specifically excludes ‘local distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

BGE agrees with the SDT’s position that support equipment such as UVLS and UFLS not be classified as
BES. BGE strongly believes that including control centers and other BES support equipment in the BES
definition is not necessary and will cause confusion. BGE commends the BES Definition Standards Drafting
Team for the informative webinar on 5/19/2011. We were encouraged that the SDT’s developed a transition
plan for the implementation of the new BES definition. BGE urges the SDT to also address the issue of the
addition of new BES elements (i.e., such as new designated blackstart resources which may include a
cranking path that is reclassified as BES). A transition period would also be required for these situations.
BGE appreciates the work of the drafting team and supports the goal to produce clear definition language so
that upwards of 95% of the assets are clearly distinguished as either included or excluded from the BES. We
are particularly sensitive to the potential for burdensome processes (e.g. TFEs) to be added to reliability
compliance, so we appeal to the team for continued, vigilant consideration of the arduousness of the BES
determination process.Also important to consider is that the subject of this comment form, the proposed BES
definition, is only one part of the BES definition project. The accompanying technical principles for BES
Exceptions and the Rule of Procedure Process must be evaluated together with the BES Definition to
sufficiently understand the revisions. In the end, the Technical Principles and the BES Definition must
coalesce and be clearly coordinated and understood. The BES Definition language must include reference to
the role of the associated defining documents. One unambiguous document must not be made ambiguous by
an associated document or process.

Response: The SDT appreciates the supportive comments and has taken into consideration the concerns raised by the commenter in its deliberations.
Exelon

The definition assumes some inclusions or exclusions based on levels of generation used in the NERC
Compliance Registry Criteria. Exelon does not view Orders 743 and 743-A as requiring a view or justification
of these thresholds. See Order No. 743-A at P 47 (“it was not our intent to disrupt the NERC Rules of
Procedure or the Statement of Compliance Registry Criteria”).

Response: The SDT agrees with the commenter.
Kootenai Electric Cooperative

August 19, 2011

Kootenai has these additional concerns: We are concerned that the proposed 24-month delay in the effective
date of the new definition will delay the potentially beneficial effects of the SDT’s efforts, especially for utilities
that have been inappropriately registered for BES-related functions, which is a common situation in WECC.

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We therefore urge the new BES definition to become effective immediately upon approval by FERC or other
applicable regulatory agencies. Entities that have been improperly registered for BES functions can then
immediately file for deregistration and obtain the benefits of the new definition as soon as possible. For
entities that have not previously been registered for BES-related functions but that would be required to
register under the new definition, we agree that 24 months is an appropriate transition period to allow the
newly-registered entity to attain compliance with newly-applicable reliability standards, many of which require
new training for employees, new maintenance procedures, and complex new operational protocols. However,
the transition period for newly-registered entities should be structured in a way that does not prevent entities
seeking deregistration from benefitting from the new definition at the earliest possible date. The current
definition provides that “Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.” Kootenai is concerned that the SDT carefully delineate which entity has the
burden of proof in the exclusion process. The WECC BESDTF approach, which we commend to the SDT,
laid out these burdens in some detail. Under that approach, essentially, if a facility is excluded from the BES
by virtue of the specific exclusions listed in the definition, the Regional Entity bears the burden of proving that
the facility nonetheless has a material impact on the interconnected bulk transmission system and therefore
should be included in the BES. On the other hand, if a facility is classified as BES by virtue of the list of
inclusions set forth in the BES definition, it can still escape classification as BES, but bears the burden of
demonstrating that its facility has no material impact on the interconnected transmission system. We urge the
SDT to give careful consideration to these burden-of-proof questions and to follow the lead of the WECC BES
Task Force.
For the reasons we have explained in our answer to Question 11, we believe the Exception process is critical
both to ensure that the BES definition is effective in producing measurable gains to bulk system reliability and
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the Standards
Development Process. Accordingly, we urge that all elements of the BES definition, including those elements
that have been assigned to the Rules of Procedure Team, be vetted through the Standards Development
Process.

Response: The SDT agrees with the commenter and has made revisions to the Implementation Plan to address these concerns surrounding the implementation
dates.
The SDT believes that the burden of proof issue should be resolved through the development RoP Exception Process. Your comments will be forwarded to the

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RoP team for consideration.
Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the appropriate
mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles associated with
the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed through the RoP
process for the revision of the Rules of Procedure.
Springfield Utility Board

Springfield Utility Board requests that NERC create a distinction between the terms BPS and BES. Are the
two to be used interchangeably, or will BPS no longer be used? SUB suggests NERC consider adopting the
statutory definition of the Bulk Power System as the core definition of the Bulk Electric System.
May 26, 2011Dear NERC Standards Drafting Team:Thank you for the opportunity to comment on NERC’s
proposed Continent-wide Definition of Bulk Electric System. We believe that NERC ‘s proposed Bulk Electric
System definition is proceeding in the right direction, but that more work needs to be done. SUB’s specific
concerns are as follows:
Bulk Power System (BPS) and Bulk Electric System (BES) - Springfield Utility Board requests that NERC
create a distinction between the terms BPS and BES. Are the two to be used interchangeably, or will BPS no
longer be used? SUB suggests NERC consider adopting the statutory definition of the Bulk Power System as
the core definition of the Bulk Electric System.
Clear definition of Radial - Because there still appears to be inconsistencies in both definition and application,
SUB encourages NERC to develop a concise definition of a radial system. For example, if a system is
normally operated as radial, but could be operated closed (by manually closing a breaker), would it be
considered a radial or close-looped system? If the answer is “that a closed system”, is this in all cases, or are
there exceptions?
Registration Status - SUB understands that one of the primary values of clearly defining the BES is for
registration determinations, as well as determining which of the Standards apply to registered entities. SUB
encourages NERC to support the use of the BES definition for entity registration, and to develop the
exception procedure for registered entities that do not own or operate any BES Elements.
Springfield Utility Board appreciates FERC and NERC’s efforts to create a continent-wide definition of Bulk
Electric System, and appreciates the opportunity to provide comment. Tracy Richardson Springfield Utility
Board SUB requests NERC to consider the situation where an entity has multiple, but separate systems. The
entity is required to become a Registered Entity because the sum of their individual systems meets the
thresholds, but portions of their physically separated systems taken individually would otherwise not reach the
threshold for registration. For example, an entity may be responsible for service over a third party’s
transmission for distribution service to a single end user with a load less than =<25MW that has a hard tap
into the third parties’ transmission. Because the load has a hard tap, it is technically served from more than

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one transmission source. If there are no other loads served along the tap or along the third party’s
transmission segment, SUB believes that this type of situation warrants exclusion from the BES as it would
otherwise be excluded - except for the fact that the combination of that service and other separate systems
that the entity is responsible for triggers registration.
SUB is concerned that devices such as shunt capacitor banks may be overlooked. For example, is a radial
system serving only load with a shunt capacitor bank included or excluded from BES? It does raise the issue
“what does “serving only load mean, exactly?” If a capacitor bank is used for purposes of managing reliability
within an local network and the local network would otherwise be classified as an LDN, is the local network
still classified as an LDN?

Springfield Utility Board

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause an inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: The SAR for Project 2010-17 identifies the scope of the SDTs responsibilities. The scope does not include revision or any level of assessment of the
term Bulk Power System. Therefore any recommended revision to the definition of the BPS or recommendation on the usage or application of the term is not
within the responsibilities of the SDT. No change made.
The SDT has crafted language in Exclusion E1 that clearly identifies what constitutes a radial facility.
The SDT is revising the definition of the BES and use or application of this definition for registration purposes solely resides under the responsibilities of the
Certification and Registration department at NERC.
The SDT is revising the definition of the BES to identify BES Elements without regard to the ownership of such facilities. Ownership is an issue better addressed by
the registration process or the applicability of specific Reliability Standards. The SDT is not in a position to comment on specific situations without the opportunity

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to review all available information pertaining to the facility in question.
The SDT agrees with the commenter and has crafted revised Inclusion I5 language that specifically addresses Reactive Power resources.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.
The vast array of functional qualities of generation does not lend itself to a ‘bright-line’ concept of identifying BES Elements. Therefore the SDT has opted for the
size threshold designation of generating facilities and allows for use of the Exception Process for further analysis of the facility and potential exclusion from or
inclusion to the BES. No change made.
City of St. George

What are proposed transition implementation plans for facilities that will now be included in the definition?
The implementation plan indicates 24 months which may or may not be enough depending on the response
time to exception process. How will a pending exception action affect compliance requirements and effective
dates? It should be at least 24 months after it has been determined that a facility must be included.

Response: The SDT believes that the proposed 24 month period is sufficient time for entities to achieve the appropriate level of compliance with the Reliability
Standards. Comments concerning the Exception Process will be directed to the Rules of Procedure team for review. The SDT did, however, extend the effective
date by an additional quarter of a year based on stakeholder comments.
CenterPoint Energy

August 19, 2011

CenterPoint Energy appreciates the opportunity to provide comments. In reviewing the draft definition,
CenterPoint Energy believes the SDT may have unintentionally expanded the definition of the BES beyond
the statutory definition in Section 215. Facilities included in the BES should be those facilities that are
necessary for the reliable operation of the BES. Many interconnected facilities operated at 100kV and above,
particularly those that are operated between 100kV and 200kV, are interconnected primarily to enhance the
service provided to customers, rather than to maintain reliable operation of the BES.In addition; CenterPoint
Energy is concerned with the addition of another exception process to the Rules of Procedure (ROP). In
orders 743 and 743-A, the Commission allowed the ERO latitude to develop a definition that varied from the
Commission’s recommendation. CenterPoint Energy supports the inclusion/exclusion approach of the SDT
and believes it should be possible to define what constitutes the BES without an exception process.
Historically, exception processes within the ROP have been cumbersome, labor intensive, confusing, and
require on-going maintenance and quarterly or annual updates. Indeed, in question 10 of this comment form
the SDT recognizes the burden of administrating an exception process. While CenterPoint Energy
understands the SDT may feel pressure to produce a product quickly, the Company does not believe the
expedited nature justifies an inferior product. CenterPoint Energy recommends the SDT continue developing
criteria that clearly defines BES facilities based on the Section 215 language. Once that is accomplished, an
exception process will not be needed.

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Response: The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty
as possible in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current
application of the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support
consistent application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation
of the revision to the definition would not significantly expand or contract what is currently considered to be the BES. No change made.
The SDT believes that establishing a ‘bright-line’ approach to identify BES Elements will inherently incorrectly identify a small number of facilities. The Exception
Process is designed to clear up these discrepancies and render the proper classification of those questionable facilities. The SDT believes that with the draft core
definition and the BES designations (Inclusions and Exclusions) the vast majority of facilities will be correctly identified as BES or non-BES Elements and therefore
will produce the consistent application and results as desired by the Commission’s language in Order Nos. 743 & 743a.
The SDT made several changes to the definition, based on stakeholder comments that provide additional clarity to the definition. Please see the revised definition.
Southern California Edison
Company

As discussed during the May 19, 2011 NERC Webinar, SCE supports having one-line diagrams illustrating
examples of the line and bus arrangements as they pertain to the BES Definition included as part of a set of
support documents. A good start for these diagrams would be the ones developed by the WECC Bulk Electric
System Definition Task Force (WECC BESDTF). These diagrams were developed by WECC to better
illustrate the demarcation between BES and non-BES facilities and provide important information and insight
into the WECC system.

Response: The SDT has taken into account the work product of several regional efforts in the development of the draft BES definition. The SDT also recognizes
the value of a supporting reference document and will consider future development based on the project timeline and available resources.
Midstate Electric Cooperative

Yes MSEC has these additional concerns: The current definition provides that “Elements may be included or
excluded on a case-by-case basis through the Rules of Procedure exception process.” MSEC is concerned
that the SDT carefully delineate which entity has the burden of proof in the exclusion process. The WECC
BESDTF approach, which we commend to the SDT, laid out these burdens in some detail. Under that
approach, essentially, if a facility is excluded from the BES by virtue of the specific exclusions listed in the
definition, the Regional Entity bears the burden of proving that the facility nonetheless has a material impact
on the interconnected bulk transmission system and therefore should be included in the BES. On the other
hand, if a facility is classified as BES by virtue of the list of inclusions set forth in the BES definition, it can still
escape classification as BES, but bears the burden of demonstrating that its facility has no material impact on
the interconnected transmission system. We urge the SDT to give careful consideration to these burden-ofproof questions and to follow the lead of the WECC BES Task Force.
For the reasons we have explained in our answer to Question 11, we believe the Exception process is critical
both to ensure that the BES definition is effective in producing measurable gains to bulk system reliability and

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Question 13 Comment
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the Standards
Development Process. Accordingly, we urge that all elements of the BES definition, including those elements
that have been assigned to the Rules of Procedure Team, be vetted through the Standards Development
Process.
Dear NERC Standards Drafting Team:Enclosed are MSEC’s comments on NERC’s Proposed Continent-wide
Definition of Bulk Electric System. We believe that NERC’s proposed Continent-wide Definition of Bulk
Electric System is proceeding in the right direction on this important topic but that more work needs to the
done. We would like to thank the Standards Drafting Team for their hard work. We support the detailed
comments of the Snohomish County Public Utility District and Pacific Northwest Generating Cooperative with
regard to the questions posed by the Comment Form for Project 2010-17 Definition of BES.We would like to
emphasize these portions of Snohomish’s and PNGC’s comments:
Question 1, both PNGC and Snohomish suggest that NERC start by adopting the statutory definition of the
bulk power system as the core definition. We support that approach. That is, “(t) he term ‘Bulk Electric
System’ means: (A) Facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof); and,(B) Electric energy from generation facilities needed to
maintain transmission system reliability.The term does not include facilities used in the local distribution of
electric energy”. See 16 U.S.C. § 824o(a)(1).”
Question 7, we support the exclusion for radial lines as drafted.
Question 9, we support the categorical exclusion of Local Distribution Networks from the BES as defined
here, but with Snohomish’s clarifications.
Question 10, we support exclusion E4, for small utilities, but we are unclear how small utilities are defined in
the exclusion language presented here.
Question 11, we support the approach to exclusion of local distribution facilities discussed in the draft but
repeat that more work should be done on the definition so that facilities used in local distribution are not swept
up into the BES.The primary value of clearly defining the BES is for registration determinations. We realize
that clearly defining the BES also has value in determining which standards apply to registered entities. If a
registered entity does not own any Elements of the BES that that registered entity should be able to efficiently
and effectively demonstrate an exception. We encourage NERC to support the use of the BES definition for
registration-issues and to develop the exception procedure for registered entities that do not own or operate

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Yes or No

Question 13 Comment
any Elements of the BES.

Response: The SDT believes that the burden of proof issue should be resolved through the development RoP Exception Process. Your comments will be
forwarded to the RoP DT for consideration.
Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the appropriate
mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles associated with
the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed through the RoP
process for the revision of the Rules of Procedure. No change made.
The SDT appreciates the industry support for this project. Please see the SDT responses in Questions 1, 7, 9, 10, and 11 of this document.
Illinois Municipal Electric Agency

Being a Joint Action Agency and Joint Registration Organization representing small municipal utility interests,
IMEA appreciates this initiative to better define electric systems that should and should not be considered part
of the Bulk Electric System. In addition to those comments provided above, IMEA supports comments
addressing other concerns as submitted by the Transmission Access Policy Study Group and the Small Entity
Working Group.

Response: Please see the SDT responses to the Transmission Access Policy Study Group and the Small Entity Working Group comments.
Long Island Power Authority

The SDT should clarify that Local Distribution Networks, including any facilities that are within the LDN, are
not subject to Reliability Standard Requirements pursuant to Section 215 of the Federal Power Act.

Response: The Local Distribution Network concept was developed to allow facilities operated at 100 kV or higher, that serve a distribution function, to be eligible
for exclusion if specific criteria are met. The use of the term ‘Local Distribution Network’ has resulted in some confusion by the industry in relation to the exclusion
of local distribution facilities indentified in Section 215 of the Federal Power Act. The SDT has elected to revise the Exclusion to be termed ‘Local Networks’ to
eliminate the confusion as to what type of facilities are being addressed by the Exclusion.
Clark Public Utilities

The process for identifying facilities as part of an LDN needs to be stated. Clark has heard that this will be
through a self-certification process, however, there is no written description how a utility classifies its
transmission facilities as an LDN.

Response: The SDT envisions that the current practice of self-identification continues with the revised definition of the BES. No change made.
Pepco Holdings Inc

August 19, 2011

1) It would be very helpful to include examples (with an explanation and diagram) of the various
configurations that meet each of the inclusions and exclusions. Can the next draft include such examples to
provide further clarity to the definitions? Consideration should be given to developing an attachment for this

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Question 13 Comment
material and a method to add appropriate examples in the future.
2) The proposal is silent on whether associated auxiliary and protection and control system equipment that
could automatically trip a BES facility independent of the protection and control equipment’s voltage level are
included as part of the BES. The RFC BES definition specially addresses this issue as an example. Does
IRO-005 cover those elements so it is not necessary to address these in this proposal? Consideration should
be given to referencing the issue in the BES document.

Response: 1) The SDT has taken into account the work product of several regional efforts in the development of the draft BES definition. The SDT also
recognizes the value of a supporting reference document and will consider future development based on the project timeline and available resources.
2) The SDT has determined that the draft BES definition should identify BES Elements which are operated at a voltage of 100 kV or above. The SDT also has
recognized the existence of facilities (i.e., auxiliary equipment and Protection Systems) that support the reliable operation of the interconnected transmission
network but do not necessarily operate at voltages of 100 kV or above and should not necessarily be classified as BES Elements. Reliability of the interconnected
transmission network is established by the application of Reliability Standards and the development of Reliability Standards is not limited in applicability to BES
Elements. Reliability Standards are written against facilities that support the reliable operation of the interconnected transmission network. Therefore the SDT
believes that the clarification of the BES definition does not require identification of these types of facilities and that the specific facilities in question are better
addressed by the applicability of individual Reliability Standards and not through the BES definition or the Exception Process. No change made.
Vigilante Electric Cooperative

Dear NERC Standards Drafting Team:Enclosed are Vigilante Electric Cooperative, Inc's (VIEC) comments on
NERC's Proposed Continent-wide Definition of the Bulk Electric System (BES).We believe that NERC's
proposed definition of the Bulk Electric System is moving in the right direction and we thank the Standards
Drafting Team for their hard work. We support the comments of the Snohomish County Public Utility Distric
and Pacific Northwest Generating Cooperative with regard to questions posed by the comment form for
Project 2010-17.We would like to add the following additional comments:
With regard to exclusion E3, part e) - we do not believe that just because an element is on a list that it cannot
be excluded. If an element meets all of the criteria to be excluded, then it should be excluded and removed
from the list. Otherwise, we strongly agree that LDNs have no material impact on the BES.We also strongly
encourage the continued development of a reasonable method for determination of inclusion/exclusion. We
believe that there should be a clearer path that would ultimately allow a utility to pursue being
included/excluded from registration with WECC. Many small utilities have an element that may actually have
no material impact on the BES yet is required to comply with all WECC standards.
We also would like to comment on the WECC compliance bulletin of April 15, 2011. While we greatly
appreciate the recognition that radial T-Taps with transformer or distribution protection schemes have no
material impact to the BES, we would encourage you to take this the additional logical step to actually remove
these instances from WECC responibilities. This would help reduce the burden both on WECC and the

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Yes or No

Question 13 Comment
individual entities and save everyone involved a tremendous amount of time, effort and money.We again
thank the Team for their efforts and appreciate the opportunity to be allowed to comment on these issues.

Response: The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty
as possible in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current
application of the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support
consistent application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation
of the revision to the definition would not significantly expand or contract what is currently considered to be the BES. No change made.
The SDT is drafting a definition with the expectation of consistent application across the continent. The introduction or removal of specific language to address
specific circumstances that may reside in the WECC footprint would not support this concept. No change made.
The SDT is not in a position to comment on a WECC Compliance Bulletin.
Central Lincoln

We believe the Exception process is critical both to ensure that the BES definition is effective in producing
measurable gains to bulk system reliability and to ensuring that the definition will comply with the limitations
Congress placed in Section 215. Hence, we believe the entire BES definition, including the Exception
process and related procedures, should be vetted through the NERC Standards Development Process,
including the full comment periods and a ballot approvals provided for in that process. We are concerned that
important elements of the BES definition have been assigned to the Rules of Procedure Team, and that
changes in the Rules of Procedure are subject to approval in a process that provides considerably less due
process and industry input than the Standards Development Process. Accordingly, we urge that all elements
of the BES definition, including those elements that have been assigned to the Rules of Procedure Team, be
vetted through the Standards Development Process.
We note also that the SAR still does not apply the definition to all registered entity types in violation of the
FERC order to provide a continent-wide definition. Please include PSEs in the SAR also.
We are concerned that the proposed 24-month delay in the effective date of the new definition will delay the
potentially beneficial effects of the SDT’s efforts, especially for utilities that have been inappropriately required
to meet BES reliability standards, which is a common situation in WECC. We therefore urge the new BES
definition to become effective immediately upon approval by FERC or other applicable regulatory agencies.
Entities that have been improperly required to meet standards can then immediately redirect resources to
where they are truly needed. For entities that have not previously been registered for BES-related functions
but that would be required to register under the new definition, we agree that 24 months is an appropriate
transition period to allow the newly-registered entity to attain compliance with newly-applicable reliability
standards, many of which require new training for employees, new maintenance procedures, and complex
new operational protocols. However, the transition period for newly-registered entities should be structured in

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Yes or No

Question 13 Comment
a way that does not prevent other entities from benefitting from the new definition at the earliest possible date.

Response: Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the
appropriate mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles
associated with the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed
through the RoP process for the revision of the Rules of Procedure. No change made.
The draft BES definition identifies assets that meet specific criteria for classification as a BES Element. The NERC Functional Model defines the Purchase Selling
Entity (PSE) as: The functional entity that purchases or sells, and takes title to, energy, capacity, and reliability related services. The ownership or responsibility of
assets should trigger the registration of the functional entity in question in another area of registration. No change made.
The SDT agrees with the commenter and has made revisions to the Implementation Plan to address these concerns surrounding the implementation dates.
New England States Committee
on Electricity

As a general matter, the definition should reference the Exception Process, which may cause assets and
facilities to be further “included” or “excluded.”
In particular, once a facility has qualified for Exclusion it is not clear how that status is maintained.

Response: The phrase requested was inadvertently omitted from the first posting.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.
The SDT believes that maintaining an approved Exclusion should be resolved through the RoP Exception Process. Your comments will be forwarded to the RoP DT
for consideration.
PPL Energy Plus and PPL
Generation

August 19, 2011

The BES definition strives to draw a line between transmission customers (load and generation) and the
“network” that makes up the bulk electric system. All transmission customers served by the network are not
necessarily part of the network just like an on-ramp is not part of the Interstate highway, even though onramps deliver cars to the Interstate highway. FERC Order 743 paragraph 115 clearly gives guidance to the
NERC BES Definition Team (BESDT) on developing fair exclusion criteria for facilities not necessary for the
operation of the grid. PPL Generation and PPL Energy Plus (PPL) are concerned that the FERC order is
being read overly expansively to include much more generation in the BES than FERC intended. In the NERC
BESDT's latest proposed version of a BES definition, the definition appears to apply to small radial generators
(Inclusions I2 and I3) but not to large radial loads (Exclusions E1 and E3). The BESDT has chosen to exclude
or include LDNs based solely on the direction of power flow (see for example Exclusion E3-c) when the
magnitude of the power flow is more critical than the direction. An example of the stark contrast between
treatment of looped and radial facilities is exemplified by the exclusion of looped load and generation
facilities of almost any size (Exclusion E3) from the BES, versus the seeming omission of any effort to

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Question 13 Comment
exclude radially connected generation facilities over 20 MVA. Clearly, FERC Order 743-A paragraph 55
instructs the BESDT to consider “additional facility characteristics” other than voltage to come up with a fair
inclusion/exclusion process.The exclusion of looped facilities serving load and generation and the inclusion of
radial facilities serving only generation does not appear consistent. Moreover, it ignores the physical reality
that radial generator lead lines cannot be overloaded by outages on parallel paths because there are no
parallel paths. Further, the MW flow on a radial line is well known and limited to a known maximum (limited to
the larger of the generation or load on the end of the line): clearly reasons for exclusion. The BESDT should
look carefully at FERC Order 743 paragraph 73 which describes the characteristics of the electrical network
that the BES is trying to define. In that order, FERC justified its bright-line, 100 kV threshold, explaining that
"many facilities operated at 100 kV and above have a significant effect on the overall functioning of the grid"
because they share the following characteristics: 1. "operate in parallel with other high voltage and extra high
voltage facilities"i. The “bright line” at 100 kV recognizes many 100 kV lines parallel other HV/EHV lines and
can be significantly loaded by failure of the HV/EHV lines. This does not apply to radial lines, even at 100 kV
and above.2. "interconnect significant amounts of generation sources"3. "operate as part of a defined flow
gate"4. have a "parallel nature" and are capable of “caus[ing] or contribute[ing] to significant bulk system
disturbances”.i. Radial lines cannot cause significant BES disturbances since the outage of a radial line is
studied in all N-1 planning studies and if the TPL standards are followed, an N-1 should not cause such
disturbances.To their credit, the BESDT recognizes part of paragraph 73 in Exclusion E3-d and E3-e
(possibly exempting many hundreds of MVA load) but yet fails to exclude radial lines serving generators from
the BES “network”. Generation should be excluded from the definition of the BES on the same basis as load.
PPL requests the BESDT clearly exclude radial generators up to 200 MVA (1200 amps at 100 kV). This
exclusion is clearly justified because it would recognize many (if not all) loads and generators served radially
do NOT possess the Network Transmission Facilities characteristics described in FERC Order 743 paragraph
73. PPL hopes that the NERC BESDT will recognize (as FERC Order 743 in paragraph 120 recognizes) that
radial facilities and distribution facilities can both be excluded.

Response: The SDT scope was determined by the language contained in Order Nos. 743 & 743a in which the Commission provided guidance to the ERO to
clarify the definition for continent-wide application. The Commission did not propose significant changes to the current application of the existing definition over
the majority of the continent. Therefore the SDT has developed a draft core definition, together with BES designations (Inclusions and Exclusions) that provide
the specificity necessary to identify the vast majority of BES Elements by utilizing the existing definition and criteria previously approved for this purpose. Although
load is a component that can impact the reliability of the BES, the development of the definition is bound by the limitations documented in Section 215 of the
Federal Power Act. Expanding the definition to include load would exceed the jurisdictional boundaries into the area of local distribution facilities. No change
made.
The BES definition (core definition and Inclusions & Exclusions) will be applied to classify BES vs. non-BES Elements. The SDT believes that this will cover the vast
majority of the facilities in question. The remaining facilities will be candidates for the Exception Process (RoP) where the Technical Principles will be utilized to
determine if the facility is necessary for the reliable operation of the interconnected transmission network. Please see the revisions made to the revised definition.

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Manitoba Hydro

Yes or No

Question 13 Comment
Manitoba Hydro supports a 100kV bright line definition of the BES (excluding radial systems) that is
consistent across all regions.
We do not agree with the proposed impact based exception procedure and believe that the BES definition
should be stand-alone.
In addition, the complexity of the proposed BES definition and associated exception process may not provide
the goal of uniform application of the BES definition and moves the burden of assessment and approval to the
ERO.

Response: The SDT believes that establishing a ‘bright-line’ approach to identify BES Elements will inherently incorrectly identify a small number of facilities. The
Exception Process, a Commission identified component of the project, is designed to clear up these discrepancies and render the proper classification of those
questionable facilities. The SDT believes that with the draft core definition and the BES designations (Inclusions and Exclusions) the vast majority of facilities will
be correctly identified as BES or non-BES Elements and therefore will produce the consistent application and results as desired by the Commission’s language in
Order Nos. 743 & 743a.
The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the language and to provide as much certainty in the identification
of BES and non-BES Elements. Although the clarifications added to the core definition and the inclusions and exclusions have lengthened and increased the
complexity of the definition as a whole, the SDT feels that the improvements in clarity have increased the ability to apply the definition to achieve consistent
results.
Consolidated Edison Co. of NY,
Inc.

The ‘core’ definition is not clear as to whether an Element would be included if it meets any one (or must meet
more than one) of the 5 Inclusion criteria for inclusion?

Response: As inclusions speak to specific facilities and are not necessarily related other than for identification of BES Elements; if a facility meets the criteria of a
single inclusion then the facility is classified as a BES Element. Therefore only one (1) inclusion must be met for a facility to be classified a BES Element.
Independent Electricity System
Operator

We have no other concerns with the definition but we believe a guide demonstrating the correct application of
the definition under various transmission system configurations would be useful.

Response: The SDT also recognizes the value of a supporting reference document and will consider future development based on the project timeline and
available resources.
NB Power Transmission

August 19, 2011

Currently, the posted exception criterion is only a concept with many gaps and TBD, as posted details are
later to follow. The exception criteria should be a menu of technical items (load flows, stability analysis etc).
Entities should be required to assess and provide their own justification under each category with a
conclusion that takes into account all of the relevant items for element(s) under exception, in a consistent

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Question 13 Comment
template and table of contents. Suggest the SDT to avoid specification of any parameters as they would differ
under different design concepts, system configurations, system characteristics and regulatory requirements.
An “all encompassing” comment is that the definition is too lengthy with an overly prescriptive exception
process. The importance of the BES definition is recognized throughout the industry for its importance, and
as such it should be simple, clear, and straightforward.

Response: Comments concerning the Technical Principles (Exception Criteria) associated with the RoP Exception Process will be addressed through the dedicated
responses developed by the SDT and published in the specific Consideration of Comments document associated with that portion of the overall project.
Orange and Rockland Utilities,
Inc.

It was mentioned that Cranking Paths of Blackstart Resources are defined as BES. How about the path(s) of
generation units that will be deemed as BES? Please clarify.

Response: The SDT has revised the Inclusion that identified Blackstart Cranking Paths as BES Elements. A significant number of comments identified that the
Cranking Path could utilize local distribution facilities and could cross jurisdictional boundaries which should not be classified as BES Elements. Additionally the
Inclusions related to generation facilities have been revised to eliminate the language which suggested paths between generation and the transmission are
required to be contiguous Elements of the BES.
AltaLink

We believe that the concepts of inclusions and exclusions as part of the bright-line definition are excellent.
However, these exclusions do not address several directives in Order No. 743 and 743A, such as:
differentiation between Transmission and Distribution, non-jurisdictional concerns, or distribution. We believe
that the BES definition itself is not a venue to address these concerns but suggest that these issues should be
explicitly addressed by the ERO’s exception criteria and exception process. Currently, the posted exception
criterion is only a concept with many gaps and TBD, as posted details are later to follow. We suggest that the
exception criteria should be a menu of technical items (load flows, stability analysis etc) and non technical
items (type of loads such as distribution companies vs. major city center, national security etc). Entities should
be required to assess and provide their own justification under each category with a conclusion that takes into
account all of the relevant items for element(s) under exception, in a consistent template and table of
contents. We suggest the SDT to avoid specification of any parameters as they would differ under different
design concepts, system configurations, system characteristics and regulatory requirements.

Response: The SDT agrees with the commenter that the Exception Process should be the primary mechanism for addressing the concerns surrounding issues
such as: differentiation between Transmission and Distribution, non-jurisdictional concerns, or distribution. However the SDT has made modifications to the BES
core definition to address the issues associated with the jurisdictional concerns related to local distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list

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Question 13 Comment

shown below. This does not include facilities used in the local distribution of electric energy.
Comments concerning the Technical Principles (Exception Criteria) associated with the RoP Exception Process will be addressed through the dedicated responses
developed by the SDT and published in the specific Consideration of Comments document associated with that portion of the overall project.
Modern Electric Water Company

1) The SDT states that “one of the basic tenets that the SDT is following is to avoid changes in registration
due the revised definition”. We stress the implications of a missed opportunity and the importance of a usable
BES definition, because if the revised definition does not allow the industry (both registered and nonregistered entities) as well as the regional reliability organizations to focus on and conduct business in a
fashion that promotes reliable and efficient system operation (not just ultra-conservative compliance
monitoring), then NERC has failed to do its job in this particular instance.
2) The proposed implementation plan indicates that the effective date of this definition is not for at least 24
months after regulatory approval. We strongly disagree with this suggested approach as it does not provide
for any benefit from this much-needed improvement. We believe the SDT intended to imply that entities not
currently registered would have at least 24 months to become compliant with applicable standards if the
improved BES definition suddenly swept them into the BES as it did for many small utilities on June 18, 2007.
The definition should become effective immediately upon regulatory approval, and transition plans for newlyregistered entities could specify longer timeframes.
3) As currently drafted, NERC’s Statement of Compliance Registry Criteria (Revision 5.0) contains the text of
NERC’s approved BES definition. Upon approval of any other language, the SCRC will become inaccurate
without review and modification.

Response: 1) The goals and assumptions established by the SDT are based on the documented Commission expectations in Orders Nos. 743 & 743a.
Opportunity does exist to further revise the definition beyond the clarification identified by the Commission in the Orders, however, technical justification is
required to deviate from the current application of the current BES definition. No change made.
2) The SDT agrees with the commenter and has made revisions to the Implementation Plan to address these concerns surrounding the implementation dates.
3) Review and potential revision of the NERC Statement of Compliance Registry is beyond the scope of the current SAR for this project. No change made.

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Diagram below refers to BGE comment for Q7:

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Consideration of Comments on Definition of the Bulk Electric System (BES)
Technical Principles for Demonstrating BES Exceptions — Project 2010-17
The Bulk Electric System (BES) Drafting Team thanks all commenters who submitted
comments on the first draft of the Project 2010-17: Definition of the Bulk Electric System
(BES) Technical Principles for Demonstrating BES Exceptions. These standards were posted
for a 30-day public comment period from May 11, 2011 through June 10, 2011. The
stakeholders were asked to provide feedback on the standards through a special Electronic
Comment Form. There were 91 sets of comments, including comments from approximately
182 different people from approximately 124 companies representing all 10 Industry
Segments as shown in the table on the following pages.

http://www.nerc.com/filez/standards/Project2010-17_BES.html
Based on industry response and further analysis, the SDT has abandoned the initial
exclusion criteria and developed a new methodology is intended to clarify the technical and
operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on
a comparison of an entity’s characteristics to a defined value and/or limit. It has become
apparent that it is not feasible to establish continent-wide values and/or limits due to
differences in operational characteristics. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as
appropriate through submittal of an exception request form along with any other supporting
documentation for the exception being sought. The appropriate Regional Entity will review
the submittal to validate information, make a recommendation of whether or not to support
the exclusion or inclusion, and then file the request and recommendation with the ERO as
established in the Rules of Procedure as presently being drafted.
The SDT is recommending that the project be moved to a parallel 45-day posting and ballot.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 404-443-2560 or at herb.schrayshuen@nerc.net. In addition, there is
a NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical
Principles for Demonstrating BES Exceptions — Project 2010-17

Index to Questions, Comments, and Responses
1.

Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. ............................................................ 14

2.

Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. ............................................................ 31

3.

Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. ............................................................ 44

4.

Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. ............................................................ 58

5.

Exclusions - The SDT has set up one path for evidence that includes technical analysis.
Do you agree with this requirement? .................................................................... 70
5a.

Comments on approach .............................................................................. 76

5b.

Comments on distribution factor measurement .............................................. 90

5c.

Comments on allowable transient voltage dip measurement ............................ 97

5d.

Comments on allowable transient frequency response .................................. 103

5e.

Comments on voltage deviation measurement ............................................. 108

6.

Exclusions – Do you have other methods that may be appropriate for proving an
exclusion claim? Or, other variables/measurements that may be added to the
requirements already shown in the posted Technical Principles for Demonstrating BES
Exceptions? .................................................................................................... 114

7.

Inclusions - The SDT has set up only one path for evidence that includes technical
analysis. Do you agree with this requirement?. ................................................... 126
7a.

Comments on approach ............................................................................ 133

7b.

Comments on distribution factor measurement ............................................ 142

7c.

Comments on allowable transient voltage dip measurement .......................... 147

7d.

Comments on allowable transient frequency response .................................. 151

7e.

Comments on voltage deviation measurement ............................................. 155

8.

Do you have concerns about an entity’s ability to obtain the data they would need to do
the indicated technical analyses?. ...................................................................... 159

9.

Are you aware of any conflicts between the proposed approach and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement, or
jurisdictional issue?.......................................................................................... 167

10. Are there any other concerns with this approach that haven’t been covered in previous
questions and comments? Please be as specific as possible with your comments. .... 177

2

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Connie Lowe

Electric Market Policy

X

2

3

X

4

5

X

6

7

8

9

10

X

Additional Member Additional Organization Region Segment Selection
1. Mike Crowley

SERC

1, 3, 5

2. Mike Garton

MRO

5

3. Louis Slade

RFC

5, 6

4. Michael Gildea

NPCC

5

2.

Group
Additional Member

Guy Zito

Northeast Power Coordinating Council
Additional Organization

Region Segment Selection

1. Alan Adamson

New York State Reliability Council, LLC

NPCC 10

2. Gregory Campoli

New York Independent System Operator

NPCC 2

3. Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC 3

4. Sylvain Clermont

Hydro-Quebec TransEnergie

5. Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC 1

6. Gerry Dunbar

Northeast Power Coordinating Council

7. Brian Evans-Mongeon Utility Services

X

NPCC 1
NPCC 10
NPCC 8

3

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

8. Mike Garton

Dominion Resources Services, Inc.

NPCC 5

9. Kathleen Goodman

ISO - New England

NPCC 2

10. Chantel Haswell

FPL Group, Inc.

NPCC 5

11. Brian Gooder

Ontario Power Generation Incorporated

NPCC 5

12. David Kiguel

Hydro One Networks Inc.

NPCC 1

13. Michael Lombardi

Northeast Utilities

NPCC 1

14. Randy MacDonald

New Brunswick Power Transmission

NPCC 1

15. Bruce Metruck

New York Power Authority

NPCC 6

16. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

17. Robert Pellegrini

The United Illuminating Company

NPCC 1

18. Si Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

19. Saurabh Saksena

National Grid

NPCC 1

20. Michael Schiavone

National Grid

NPCC 1

21. Wayne Sipperly

New York Power Authority

NPCC 5

22. Donald Weaver

New Brunswick System Operator

NPCC 1

23. Ben Wu

Orange and Rockland Utilities

NPCC 1

3.

Group

Charles W. Long

Additional Member

SERC Planning Standards Subcommittee

Additional Organization
Entergy Services, Inc.

SERC

1

2. Darrin Church

Tennesee Valley Authority

SERC

1

3. John Sullivan

Ameren Services Co.

SERC

1

4. James Manning

North Carolina Electric Cooperatives SERC

1

5. Bob Jones

Southern Company Services

SERC

1

6. Phil Kleckley

South Carolina Electric &Gas Co.

SERC

1

7. Pat Huntley

SERC

SERC

NA

Group
Additional Member

1. Clem Cassmeyer

Robert Rhodes

X

3

4

5

6

7

8

9

10

X

Region Segment Selection

1. Charles W. Long

4.

2

SPP Standards Review Group

Additional Organization
Western Farmers Electric Cooperative

X

Region Segment Selection
SPP

1, 3, 5

4

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2. John Mason

Independence Power & Light

SPP

1, 3, 5

3. John Kerr

Southwest Power Pool

SPP

2

4. Matthew Bordelon

CLECO

SPP

1, 3, 5

5. Michelle Corley

CLECO

SPP

1, 3, 5

6. Ron Gunderson

Nebraska Public Power District

MRO

1, 3, 5

7. Jonathan Hayes

SPP

SPP

2

8. Sean Simpson

Board of Publlic Utilities, City of McPherson SPP

1, 3, 5

9. Tom Hestermann

Sunflower Electric

SPP

1, 3, 5

10. Tony Eddleman

Nebraska Public Power District

MRO

1, 3, 5

11. Valerie Pinamonti
12. Doug Callison

American Electric Power
Grand River Dam Authority

SPP
SPP

1, 3, 5
1, 3, 5

13. Sean Simpson
14. Tom Hestermann

Board of Public Utilities, City of McPherson SPP
Sunflower Electric
SPP

1, 3, 5
1, 3, 5

5.

Group

David Taylor

2

3

4

5

6

7

8

9

10

NERC Staff Technical Review

No additional members listed.
6.

Group

Mark Gray

Edison Electric Institute

http://www.eei.org/whoweare/ourmembers/USElectricCompanies/Pages/USMemberCoLinks.aspx
7.

Group

Frank Gaffney

Florida Municipal Power Agency

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Tim Beyrle

City of New Smyrna Beach FRCC

4

2. Jim Howard

Lakeland Electric

FRCC

3

3. Cairo Vanegas

Fort Pierce Utility Authority FRCC

4

4. Lynne Mila

City of Clewiston

FRCC

3

5. Joe Stonecipher

Beaches Energy Services FRCC

1

5

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

6. Randy Hahn

Ocala Electric Utility

FRCC

3

7. Greg Woessner

Kissimmee Utility Authority FRCC

3

Group

8.

Cynthia S. Bogorad

Transmission Access Policy Study Group

2

X

3

X

4

X

5

6

X

X

X

X

7

8

9

10

No additional members listed.
Group

9.

Albert DiCaprio

ISO/RTO Standards Review Committee

X

Additional Member Additional Organization Region Segment Selection
1. Terry Bilke

MISO

RFC

2

2. Patrick Brown

PJM

RFC

2

3. Greg Campoli

NY ISO

NPCC

2

4. Kurtis Chong

IESO

NPCC

2

5. Ben Li

IESO

NPCC

2

6. Steve Myers

ERCOT

ERCOT 2

7. Bill Phillips

MISO

RFC

2

8. Don Weaver

NBSO

NPCC

2

9. Mark Westendorf

MISO

RFC

2

10. Charles Yeung

SPP

SPP

2

10.

Group

Additional Member

John Allen
Additional Organization

Iberdrola USA
Region Segment Selection

1. Raymond Kinney

New York State Electric & Gas NPCC 1

2. Kevin Howes

Central Maine Power

11.

Group

Additional Member
1. Bill Middaugh

Mark Conner

X

NPCC 1

Tri-State Generation and Transmission
Association

Additional Organization

X

X

Region Segment Selection

Tri-State Generation and Transmission Association WECC 1, 3, 5, 6

6

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

12.

Group

David Curtis

Hydro One

X

2

3

4

5

6

X

7

8

9

10

X

Additional Member Additional Organization Region Segment Selection
1. Ajay Garg

Transmission

NPCC

1

2. David Kiguel

Distribution

NPCC

2

3. Oded Hubert

Regulatory Affairs

NPCC

9

13.

Group
Additional Member

Carol Gerou

MRO's NERC Standards Review Forum

Additional Organization

Region Segment Selection

1. Mahmood Safi

Omaha Public Utility District

MRO

1, 3, 5, 6

2. Chuck Lawrence

American Transmission Company

MRO

1

3. Tom Webb

Wisconsin Public Service Corporation MRO

3, 4, 5, 6

4. Jodi Jenson

Western Area Power Administration

MRO

1, 6

5. Ken Goldsmith

Alliant Energy

MRO

4

6. Alice Ireland

Xcel Energy

MRO

1, 3, 5, 6

7. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

8. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

9. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

10. Scott Nickels

Rochester Public Utilties

MRO

4

11. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

12. Marie Knox

Midwest ISO Inc.

MRO

2

13. Lee Kittelson

Otter Tail Power Company

MRO

1, 3, 4, 5

14. Scott Bos

Muscatine Power and Water

MRO

1, 3, 5, 6

15. Tony Eddleman

Nebraska Public Power District

MRO

1, 3, 5

16. Mike Brytowski

Great River Energy

MRO

1, 3, 5, 6

17. Richard Burt

Minnkota Power Cooperative, Inc.

MRO

1, 3, 5, 6

14.

Group
Additional Member

1. Steve Larson

Denise Koehn

Bonneville Power Administration

Additional Organization
BPA, Legal Department

X

X

X

X

X

Region Segment Selection
WECC 1, 3, 5, 6

7

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2. Rebecca Berdahl

BPA, Power Services, Long Term Sales and Purchases WECC 3

3. Erika Doot

BPA, Power Services, Generation Support

WECC 3, 5, 6

4. Sara Sundborg

BPA, Transmission Technical Operations

WECC 1

5. Lorissa Jones

BPA, Transmission Reliability Program

WECC 1

6. Fran Halpin

BPA, Power Services, Duty Scheduling

WECC 5

15.

Individual

Sandra Shaffer

PacifiCorp

16.

Individual

Jim Uhrin

ReliabilityFirst

17.

Individual

Richard Dearman

Tennessee Valley Authority

18.

Individual

Richard Malloy

Idaho Falls Power

19.

Individual

Michelle Mizumori

Western Electricity Coordinating Council

20.

Individual

John Cummings

PPL Supply

21.

Individual

Roger Clayton

New York State Reliability Council

Individual

John P. Hughes

Electricity Consumers Resource Council
(ELCON)

X

23.

Individual

Randy D. Crissman

New York Power Authority

X

24.

Individual

John Free

Alabama Public Service Commission

25.

Individual

Antonio Grayson

Southern Company

X

26.

Individual

Michael Moltane

ITC

X

22.

X

2

3

X

4

5

X

6

7

8

9

10

X
X

X

X

X

X

X
X

X
X

X

X

X

X

X

X
X
X

8

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

27.

Individual

Michael Jones

National Grid

X

X

28.

Individual

Scott Bos

Muscatine Power and Water

X

X

29.

Individual

Bud Tracy

Blachly Lane Electric Cooperative

30.

Individual

RoLynda Shumpert

South Carolina Electric and Gas

31.

Individual

Josh Dellinger

Glacier Electric Cooperative

Individual

Diane Barney

New York State Department of Public
Service

33.

Individual

John Bee

Exelon

X

34.

Individual

Bob Casey

Georgia Transmission Corporation

X

35.

Individual

Chris de Graffenried

Consolidated Edison Co. of NY, Inc.

X

36.

Individual

Tracy Richardson

Springfield Utility Board

37.

Individual

John Pearson

ISO New England

38.

Individual

Jonathan Appelbaum

The United Illuminating Company

39.

Individual

Neil Phinney

Georgia System Operations Corporation

X

40.

Individual

Michelle R DAntuono

Occidental Energy Ventures Corp.

X

41.

Individual

Russ Schneider

Flathead Electric Cooperative, Inc.

X

32.

4

5

6

X

X

X

X

7

8

9

10

X
X

X

X
X

X

X

X

X

X
X
X

X

X

X

X

9

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

42.

Individual

Ed Davis

Entergy Services

X

X

43.

Individual

Jack Stamper

Clark Public Utilities

X

44.

Individual

Dave Markham

Central Electric Cooperative

X

45.

Individual

Dave Hagen

Clearwater Power Electric Cooperative

X

46.

Individual

Roman Gillen

Consumer's Power Inc.

X

47.

Individual

Roger Meader

Coos-Curry Electric Cooperative

X

48.

Individual

Dave Sabala

Douglas Electric Cooperative

X

49.

Individual

Bryan Case

Fall River Electric Cooperative

X

50.

Individual

Rick Crinklaw

Lane Electric Cooperative

X

51.

Individual

Michael Henry

Lincoln Electric Cooperative

X

52.

Individual

Richard Reynolds

Lost River Electric Cooperative

X

53.

Individual

Annie Terracciano

Northern Lights Electric Cooperative

X

54.

Individual

Doug Adams

Okanogan Electric Cooperative

X

55.

Individual

Heber Carpenter

Raft River Rural Electric Cooperative

X

56.

Individual

Ken Dizes

Salmon River Electric Cooperative

X

4

5

X

6

7

8

9

10

X

10

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

57.

Individual

Steve Eldrige

Umatilla Electric Cooperative

X

58.

Individual

Marc Farmer

West Oregon Electric Cooperative

X

59.

Individual

Rick Paschall

Pacific Northwest Generating Cooperative

X

60.

Individual

Aleka Scott

PNGC Power

61.

Individual

Stuart Sloan

Consumer's Power Inc.

X

62.

Individual

Bill Keagle

BGE

X

63.

Individual

Rick

Spyker

X

64.

Individual

Clint Gerkensmeyer

Benton Rural Electric Association

65.

Individual

Robert Ganley

Long Island Power Authority

X

66.

Individual

Thad Ness

American Electric Power

X

X

67.

Individual

David Burke

Orange and Rockland Utilities, Inc.

X

X

68.

Individual

David Thorne

Pepco Holdings Inc

X

X

69.

Individual

Paul Titus

Northern Wasco County PUD

X

X

70.

Individual

Alice Ireland

Xcel Energy

X

X

71.

Individual

Jianmei Chai

Consumers Energy Company

4

5

6

7

8

9

10

X

X

X

X

X

X

X

X

X

11

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

72.

Individual

Jo Elg

United Electric Co-op Inc.

73.

Individual

Ned Ratterman

Oregon Trail Electric Cooperative, Inc.

74.

Individual

Steve Alexanderson

Central Lincoln

75.

Individual

Darryl Curtis

Oncor Electric Delivery

76.

Individual

Jerome Murray

Oregon Public Utility Commission Staff

77.

Individual

Anthony Schacher

Salem Electric

78.

Individual

Laura Lee

Duke Energy

X

X

79.

Individual

Bill Dearing

Grant County PUD No. 2 (Grant)

X

X

X

X

80.

Individual

Si Truc PHAN

Hydro-Quebec TransEnergie

X

81.

Individual

Eric Lee Christensen

for Snohomish County PUD

X

X

X

X

Individual

Bill Dearing

Northwest Public Power Association
(NWPPA)

X

X

X

83.

Individual

Ben Friederichs

Big Bend Electric Cooperative, Inc.

84.

Individual

Andrew Z Pusztai

American Transmission Company, LLC

X

85.

Individual

Joe Petaski

Manitoba Hydro

X

86.

Individual

Heather Hunt

NESCOE

82.

6

7

8

9

10

X
X

X
X

X

X

X
X
X
X

X

X

X

X

X
X

12

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

87.

Individual

Michael Falvo

Independent Electricity System Operator

88.

Individual

Shane Sweet

Harney Electric Cooperative, Inc.

X

89.

Individual

David Kahly

Kootenai Electric Cooperative

X

90.

Individual

Keith Morisette

Tacoma Power

X

91.

Individual

Terry Harbour

MidAmerican Energy

X

4

5

6

7

8

9

10

X

X

X

X

X

13

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

1. Exclusions - The SDT has set up one path for evidence that does not include extensive technical
analysis. It consists of 4 items, all of which must be addressed in order to submit a completed
request for exclusion. The first item involves proximity to Load and requests industry feedback on
how to measure this variable. Do you agree with this requirement? If you do not support this
requirement or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. In addition, in the comment field, please
provide your thoughts on the appropriate impedance value to replace ‘TBD,’ including technical
rationale for your argument.
Summary Consideration: A vast majority of the commenters disagreed with, or had significant questions about the validity
of using electrical proximity as a metric to reflect the importance of an element or group of elements to the operation of an
interconnected transmission network. Commenters pointed out that the proximity, electrical or otherwise, of an element to
Load is not a reliable basis to determine functionality of an element, nor its impact upon the interconnected network.
Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new
methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a
comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to
establish values and/or limits that would be valid across all regions and systems. The new process requires an entity to clarify
the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of
an exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization
Northeast Power Coordinating
Council

Yes or No
No

Question 1 Comment
1.a.i. Electrical Proximity - If impedance is to be used as a measure of electrical proximity, which in turn is a
replacement for geographical proximity, then how would the presence of parallel lines, capacitors, phaseangle regulators (PARs), tap-changing transformers, generation and reactors be treated in determining
electrical proximity?
How does this approach effectively differentiate between transmission and distribution lines of the same
voltage and length?

14

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment
When using impedance, how is “greater than” determined?
Sum of the Impedances - Would the filing entity simply add up the in-series impedances for each radial
Element to demonstrate its electrical proximity? For example, would the sum of the impedances from this
radial path example be equal to the sum of the two feeder and transformer impedances, i.e., measured from a
230 kV bus along a 230 kV feeder, through a 230/138 kV step-down transformer, and an in-series 138 kV
feeder to a 138/13.8 kV step-down distribution transformer? What impedance would the SDT apply to a PAR
(or tap-changing transformer) and to the overall path if a PAR (or tap-changing transformer) were located inseries with the measured Elements?
1.a.ii. Power Flows - What is the meaning of “power flow data” as the term is used here and how is the
meaning different from the term when used under 1.c. Power flows into the system, but rarely flows out?
Should this sentence use the phrase “impedance data extracted from a load flow study” instead?
Entities should be required to identify the significance of the element’s physical characteristics. Such
identification can be done through a simple checklist along with any relevant comments.
The SDT should revise the exception criteria to seek an alternative language and/or revise exclusion criteria
(a), which will require entities to provide the previously stated information for their element.

SERC Planning Standards
Subcommittee

No

The PSS disagrees with the assumption that the proximity of a BES facility to Load is indicative of it's
importance to BES reliability. Some lower voltage facilities can be quite short and thus have lower impedance
but be important to BES reliability. Furthermore, the term "Load centers" is not defined leaving it subject to
interpretation. Assuming a load center has many busses, where would the measurement be made - From the
most distant load bus in the load center or the nearest? Similarly - does a single facility get measured from
it's terminal to the load center or does the presence or lack of breakers need to be considered when selecting
the measurement point?

SPP Standards Review Group

No

Physical characteristics as described in 1.a.i. do not capture the true picture of the functionality of an Element.
Rather than use impedance perhaps the SDT should use ‘radial’ or ‘having one source’ as the descriptive
term.

City of Redding

This could serve as one characteristic of a distribution system and is generally a good indicator that the
facilities have been installed and are operating to serve a distinct geographical area (the end user). The intent
should be changed to indicate it is geographical and not electrical. The electrical reference should be
removed from this section and moved to the engineering section.

15

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

NERC Staff Technical Review

No

Electrical proximity to load is not an informative measure of whether Element(s) are necessary for reliable
operation or the potential reliability impact of excluding Element(s) from the BES. Establishing a maximum
impedance threshold as proposed would assure only that the excluded Element(s) do not span a large
electrical distance. While minimizing impedance may be beneficial for some aspects of reliability, other
aspects of BES reliability are improved with higher impedance. For example, higher impedance minimizes
through-flow of power and minimizes impacts to BES reliability associated with faults and switching errors.

ISO/RTO Standards Review
Committee

No

The SRC fails to see how electrical proximity to load qualifies an element for exclusion from the BES. Such
elements may indeed be involved in serving electricity to those loads. If those loads are critical loads, then
why should the element be excluded from the BES?

Iberdrola USA

No

We do not agree with this requirement. These exclusion exception criteria should be deleted in their entirety
and replaced with criteria that are objective, specific, and repeatable, or preferably not replaced at all.
Specific problems with the criteria as stated are: 1. A facility is not BES if all of “a” through “d” below apply:
a. “System elements” are in “close electrical proximity to load” - this is vague, and a lower impedance
between systems is higher likelihood of interaction between systems. Proximity measured in ohms should be
related to the load level itself. A pair of values (ohms, load) is necessary for this purpose. Transient stability is
affected by this value-pair. For a load pocket, an equivalent impedance (e.g., a sort of Thevenin impedance)
between the network source and the load location could be defined. The impedances within the network
source can also affect the assessment. Re-evaluation over time would be necessary if this path were
adopted.
This path of evidence (i.e., the path of engineering judgment) which does not include extensive technical
analysis is an attempt to provide a definitive criteria for exception without going through the other path of
evidence (i.e., the analytical path) which includes extensive technical analysis. Unless the analytical path has
been clearly defined and sufficient data obtained from/on it, the path of engineering judgment could become
difficult to establish. System parameters such as proximity to load, radial (or non-radial) configuration, power
flow direction over time (either unintended or intended) will directly influence results of technical analysis
evaluated for distribution factors, transient voltage dip and frequency excursions, voltage deviations, transient
and steady-state stability, and sequence of events following a disturbance (i.e., either a cascading outage or
a controlled outage). The two paths of evidence cannot be in conflict with each other.

Tri-State Generation and
Transmission Association

No

A long radial line with a small transformer could have a relatively high impedance. Proximity to load has no
real bearing on this procedure. Requirement 1.(a) should be deleted.

16

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization
Hydro One

Yes or No

Question 1 Comment

No

We agree with this concept to allow entities to submit an exception application that does not include extensive
technical analysis. Such an option will make the process efficient for all stakeholders, such as entities,
Regions, NERC and relevant regulatory authority. However, our opinion is that there is no real relationship
between reliability and the proximity of load. If impedance is to be used as a measure of electrical proximity,
which in turn is a replacement for geographical proximity, then how would the presence of parallel lines,
capacitors, phase-angle regulators (PARs), tap-changing transformers, generation and reactors be treated in
determining electrical proximity?
Consistent with references in the FERC Order, we feel that it is much more important to identify and ensure if
the BES element(s) are serving load pockets associated with large metropolitan load centers, loads of
significance to national security and/or as identified by relevant Federal, State or Provincial Regulatory
Authority.
We urge the SDT to clarify the exception criteria for exclusions, based on the following questions: oHow does
the proximity impedance approach effectively differentiate between transmission and distribution lines of the
same voltage and length?
oWhen using impedance, how is “greater than” determined?
oWhat impedance would the SDT apply to a PAR (or tap-changing transformer) and to the overall path if a
PAR (or tap-changing transformer) were located in-series with the measured Elements?
oWhat is the meaning of “power flow data” used here and how is the meaning different from the term when
used under “1c) Power flows into the system, but rarely flows out”? Should this sentence use the phrase
“impedance data extracted from a load flow study” instead?
Finally we suggest that entities should be required to identify the significance of the element’s physical
characteristics. Such identification can be done through a simple checklist along with any relevant comments.

MRO's NERC Standards Review
Forum

No

NSRF believes the relevance and rationale for this criterion is unknown. If this criterion is intended to exempt
elements, like circuit switchers, that are part of the distribution transformer circuits operated above 100 kV,
and located within a mile of the BES interconnection point, then NSRF would expect the wording to be “in
close electric proximity to the BES” rather than in “close electric proximity to Load”. Otherwise, NSRF
requests the SDT explain the relevance and rationale for this criterion before agreeing on its inclusion.

ReliabilityFirst

No

it is far too complicated for the smaller entities

New York State Reliability

No

NERC’s Glossary definition of Load is “An end-use device or customer that receives power from the electric

MidAmerican Energy
Muscatine Power and Water

17

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Council

Question 1 Comment
system.” which is not specific enough to permit the definition of an appropriate impedance value.
It is not clear from the proposed wording whether the exception applies to the Loads or the electrically close
System Elements or both. In any case, the concept of a single impedance value as a metric is flawed
because it could be a low impedance breaker or a relatively high impedance transformer connecting the BES
to a “radial” Load center. This exclusion is superfluous given the radial test in item 2. Suggest dropping this
exclusion test.
N.B. The proposed criteria in items 1 - 4 must all be met in order for an element to qualify for an exclusion.

New York Power Authority

No

NYPA does not see a need for this requirement. A radial element that specifically serves a load center will
perform that task regardless of the electrical distance from the source to the load. Similarly, any loss of load
in the load center will result in a corresponding need to reduce generation in the source system, regardless of
the proximity of the load.

ITC

No

Please explain the rationale to require electrical proximity. Is it to limit fault exposure? Perhaps 2 miles of
line could be shown to typically have few faults, thus limiting the number of voltage sags to nearby buses. At
approximately 0.7 ohms per mile 1.5 ohms (for overhead) might be a reasonable number. Does it make a
difference if the load is connected via underground cable?

South Carolina Electric and Gas

No

SCE&G disagrees with the assumption that the proximity of a BES facility to Load is indicative of it's
importance to BES reliability. Some lower voltage facilities can be quite short and thus have lower impedance
but be important to BES reliability.

Georgia Transmission
Corporation

Furthermore, the term "Load centers" is not defined leaving it subject to interpretation. Assuming a load center
has many busses, where would the measurement be made - From the most distant load bus in the load
center or the nearest? Similarly - does a single facility get measured from it's terminal to the load center or
does the presence or lack of breakers need to be considered when selecting the measurement point?
Glacier Electric Cooperative

No

I do not think that the proximity to load should be a factor in determining whether or not an element should be
included in the BES. Rather, the purpose of the element should be the important factor. If an element only
serves load, then that should be the most important factor and the proximity (electrical or physical) to that load
should not matter.

Consolidated Edison Co. of NY,
Inc.

No

We generally support this exclusion option concept, to the extent that it is fashioned after the FERC Seven
Factor test. However, we have a number of questions as to how it might work in practice.1.a.i. Electrical
Proximity - If impedance is to be used as a measure of electrical proximity, which in turn is a replacement for

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment
geographical proximity, then how would the presence of parallel lines, capacitors, phase-angle regulators
(PARs), tap-changing transformers, generation and reactors be treated in determining electrical proximity?
How does this approach effectively differentiate between transmission and distribution lines of the same
voltage and length? When using impedance, how is “greater than” determined?
Sum of the Impedances - Would the filing entity simply add up the in-series impedances for each radial
Element to demonstrate its electrical proximity? For example, would the sum of the impedances from this
example radial path be equal to the sum of the two feeder and transformer impedances, i.e., measured from a
230 kV bus along a 230 kV feeder, through a 230/138 kV step-down transformer, and an in-series 138 kV
feeder to a 138/13.8 kV step-down distribution transformer? What impedance would the SDT apply to a PAR
(or tap-changing transformer) and to the overall path if a PAR (or tap-changing transformer) were located inseries with the measured Elements?
1.a.ii. Power Flows - What is the meaning of “power flow data” as the term is used here and how is the
meaning different from the term when used under 1.c. Power flows into the system, but rarely flows out?
Should this sentence use the phrase “impedance data extracted from a load flow study” instead?

ISO New England

No

We disagree with this exception and believe that Section 1.a. should be deleted in it’s entirety and replaced
with a definition that excludes remote areas of a generally lesser overall value to reliability and includes areas
that are heavily networked serving large loads.
The premise of the existing section 1.a. seems at odds with overall system reliability and possibly removes
large metropolitan areas from the BES definition. How is close electrical proximity to load defined? A
maximum number of Ohms? Heavily networked areas will have lower impedance and are more likely to
serve larger amounts of demand and are therefore more likely to be impactful on the overall integrity of the
BES.

Flathead Electric Cooperative,
Inc.

No

agree in principle that one characteristic of local distribution systems is that they are usually confined to a
relatively limited geographic area, as opposed to transmission systems, which (especially in the West) tend to
cover very large distances. We also believe the proximity test may be a sensible way to identify local
distribution facilities. However, we believe that the proximity test may be unnecessary, and if an Element or
group of Elements meets other tests proposed by the SDT, it should be excluded from the BES, even if it
does not meet the proximity test.

Entergy Services

No

Entergy does not agree with the assumption that the proximity of a BES facility to Load is indicative of it's
importance to BES reliability. Some lower voltage facilities can be quite short and thus have lower impedance
but be important to BES reliability. Likewise some facilites remote from load centers may have virtually no

19

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment
impact on BES reliability.
There is also insufficient information as to how the impedance would be measured (locations of
measurements within and outside of the "Load pockets". This Exemption Criteria should be removed.
The term "Load centers" is not defined leaving it subject to interpretation. "Loads" are not BES Elements and
therefore can not be exempted from being considered BES Elements.
Item 1.a.i - "Loads within the system seeking exception are in close electrical proximity if they are separated
by an impedance of no greater than TBD." This sentence needs to be deleted.

BGE

No

BGE is not clear as to why “close electrical proximity to load” is appropriate to use as a factor in determining
exclusion.

Spyker

No

We agree with this concept to allow entities to submit an exception application that does not include extensive
technical analysis. Such an option will make the process efficient for all stakeholders, such as entities,
Regions, NERC and relevant regulatory authority. However, our opinion is that there is no real relation
between reliability and the proximity of load. Consistent with references in the FERC Order, we feel that it is
much more important to identify and ensure if the element(s) are serving load pockets associated with large
metropolitan load centers (e.g. New York City, Washington DC, Toronto), loads of significance to national
security and/or as identified by relevant Federal, State or Provincial Regulatory Authority.
We believe that entities should be required to identify the significance of the elements’ physical
characteristics, such as the proximity of element or, being served or impacted by the element to a load of
significant interest. Such identification can be done through a simple checklist along with any relevant
comments.
Therefore, we suggest the SDT to revise the exception criteria to seek an alternative language and/or re-craft
exclusion criteria (a), which will require entities to provide the previously stated information for their element.

Benton Rural Electric
Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc.

No

We believe that the proximity test may be unnecessary, and if an Element or group of Elements meets the
other three tests proposed by the SDT, it should be excluded from the BES, even if it does not meet the
proximity test. Secondly, using impedance to benchmark system load proximity would likely not yield clear
demarcations. High voltage relative or per-unit impedances are considered typically much lower than low
voltage impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest impedance.

20

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

Salem Electric
Grant County PUD No. 2 (Grant)
Big Bend Electric Cooperative,
Inc.
Big Bend Electric Cooperative,
Inc.
Kootenai Electric Cooperative
Orange and Rockland Utilities,
Inc.

No

The approach does not differentiate between transmission and distribution. There is no direct relation
between impedance and load. A study of the particular system should be performed to assess impact on
BES.

Pepco Holdings Inc

No

A specific impedance value would not be appropriate for all regions and all configurations.

Consumers Energy Company

No

Consumers Energy Company (CECo) proposes that this criterion be eliminated, as it is not a definitive BES
criterion. There is no correlation between the proximity of Elements that are 100kV and above to load.

Central Lincoln

No

Central Lincoln agrees in principle that one characteristic of local distribution systems is that they are usually
confined to a relatively limited geographic area, as opposed to transmission systems, which (especially in the
West) tend to cover very large distances. We also believe the proximity test may be a sensible way to identify
local distribution facilities. However, as explained in more detail in our response to Question 10, we believe
that the proximity test may be unnecessary, and if an Element or group of Elements meets the other three
tests proposed by the SDT, it should be excluded from the BES, even if it does not meet the proximity test.
Secondly, using impedance to benchmark system load proximity would likely not yield consistent
demarcations. High voltage relative or per-unit impedances are typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other mitigation
factors, power typically flows over the highest voltage lines, which offer the lowest impedance. Central Lincoln
proposes that “proximity” be determined in the dictionary manner with units of distance.

Duke Energy

No

Duke Energy does not agree that this characteristic materially demonstrates that an Element is not necessary
for operating an interconnected electric transmission network. There is no correlation between the electrical
proximity of an element to load and its necessity for operating an interconnected transmission network. In
general, the path that does not include extensive technical analysis is not adequate to distinguish between the

21

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment
Elements that are and that are not necessary for said operation.

Hydro-Quebec TransEnergie

No

Close electrical proximity to load does not appear to be an appropriate criteria. There is no reason that this
criteria would prevent exclusion of a radial system with long lines feeding far away loads. Instead of
considering proximity to load, it would be better to consider the way the Element is connected to the BES and
the function of the excluded part of the system, mainly to deserve loads or integrate some generation, but not
to transfer power to another Balancing Authority. Those are covered by criteria b., c. and d., so we believe
that criteria a. should not be maintained.

American Transmission
Company, LLC

No

ATC believes the relevance and rationale for this criterion is unknown. If this criterion is intended to exempt
elements, like circuit switchers, that are part of the distribution transformer circuits operated above 100 kV,
and located within a mile of the BES interconnection point, then ATC would expect the wording to be “in close
electric proximity to the BES” rather than in “close electric proximity to Load”. Otherwise, ATC requests the
SDT explain the relevance and rationale for this criterion before agreeing on its inclusion.

Manitoba Hydro

No

The purpose of this exception is unclear. It would be possible that a large transmission station with many
network connections, which is close to a load (irrespective of size), would be excluded from the BES
definition. Similarly, a reduction of system impedance, by transmission line re-conductoring for example, could
remove assets out of the scope of the BES definition. The listed proposed criteria suggest values yet to be
determined. It is unclear how this exception would support BES reliability.

NESCOE

No

The New England States Committee on Electricity (“NESCOE”) appreciates the work of NERC’s standard
drafting team as well as the opportunity to provide comments on this matter. NESCOE is New England’s
Regional State Committee and the comments provided herein reflect the collective views of the six New
England states. NESCOE’s comments below reflect its general perspective that any new costs imposed as a
result of the BES and its implementation, which costs ultimately fall on consumers, should provide meaningful
reliability benefits. NESCOE questions the concept as presented and seeks further clarification.
As a general matter, NESCOE believes the requirement that a proposed exception must meet all four criteria
is overly restrictive and will result in only a narrow category of elements qualifying for exclusion from the BES.
NESCOE suggests that a better approach would allow exclusions to be based on one or more criteria,
depending on the nature of the element that is the subject of the application.
With respect to the proposal, NESCOE does not believe it is possible to obtain agreement on the “proximity to
load” criterion for additional exclusions from the BES when the underlying impedance value has not been
determined and may be the subject of significant debate.

22

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment
While it is possible that NESCOE could support a single impedance value that would govern exclusion
determinations, it notes that a uniform value may not adequately address varying system configurations
throughout ISO-New England and neighboring control areas. NESCOE suggests that the standards setting
process allow for further deliberation on possible proposed values.
Other terms, such as “load center,” also need definition.

Independent Electricity System
Operator

No

We agree with this concept to allow entities to submit an exception application that does not include extensive
technical analysis. Such an option will make the process efficient for all stakeholders, such as entities,
Regions, NERC and relevant regulatory authority. However, we believe that an Element’s electrical proximity
to load is not necessarily a relevant consideration for determining whether the Element is required for reliable
operations.

Tacoma Power

No

Tacoma Power does not believe that a proximity to Load criteria is useful in BES designation when the other
3 exclusion criteria of this path are applied. However, if the SDT retains this item, we suggest an impedance
value of < 0.3 ohms on a 100 MVA base.

Georgia System Operations
Corporation
ACES

The concept of “Load centers” is vague and needs more specificity for this to be clear.

Yes

This seems like a reasonable approach although we have no recommendations for impedance thresholds.
Some analysis of various load pockets might provide data to consider for the threshold.

Clark Public Utilities

Yes

Clark believes the proximity test should be considered be a valid factor in determining whether a facility is part
of the BES or not. Just as this factor is used in the consideration on whether a facility is part of a Local
Distribution Network. Clark is not convinced that “proximity” and “impedance” are interchangeable. While
impedance will be lower for shorter distances it will also be affected by other factors that are not indicative of
close proximity. Distance seems more appropriate to use since it would complement a literal interpretation of
the term proximity.

Blachly Lane Electric
Cooperative

Yes

First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related efforts to
revise the definition of the BES. In response to question #1, we note only that using impedance to benchmark
system load proximity would likely not yield clear demarcations. High voltage relative or per-unit impedances
are considered typically much lower than low voltage impedances. Hence, in the absence of phase shifting
transformers, service compensation, or other mitigation factors, power typically flows over the highest voltage

Central Electric Cooperative
Clearwater Power Electric

23

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Cooperative

Question 1 Comment
lines, which offer the lowest impedance.

Consumer's Power Inc.
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Long Island Power Authority

Yes

Agree with close proximity to load concept but further direction (define suggested methodology) is required for
how to calculate impedance value. In addition to impedance value suggest consideration of adding mileage
or relative phase angle differences between locations be also an allowable criteria.

American Electric Power

Yes

Using “proximity to load” is a reasonable metric, but would require further consideration given the impedance
value eventually chosen to replace “TBD”.

24

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

Oregon Public Utility
Commission Staff

Yes

Use of the 100 kV brightline and the core BES definition as proposed is an overreach into local distribution
systems and an overreach of FERC’s authority as set out in the FPA 215. A full engineering technical
analysis - required every 2 years - is too onerous and not necessary for identifying most local distribution
elements miss-identified as BES Elements. A simple screening methodology consistent with the 7-Factor
Test (from FERC Order 888) is needed as the first stage of the exception process.

Harney Electric Cooperative, Inc.

Yes

I don't have a suggestion for an appropriate impedance.

Bonneville Power Administration

Yes

BPA suggests that correlation between the size of the Load and the size of an element is needed. BPA would
like the word “close” in the description “close electric proximity to load” to be better defined. For example, a
line that carries 600 MWs in close electrical proximity to a 20-MW Load may not meet the intent of this
characteristic. In planning models, loads are often aggregated to a higher voltage while, in a distribution
system model, the loads are explicitly represented along the distribution feeder. Because of this, the criteria
should define where the load is located/represented for the measure of electrical proximity.

Western Electricity Coordinating
Council

Yes

As long as this remains an “AND” statement, WECC supports this concept. It helps to support the concept
that the element is used as distribution to serve Load, rather than to transfer bulk power. However, some
correlation between the size of the Load and the size of an element may be needed. For example, a line that
can carry 600 MW in close electrical proximity a 20-MW Load may not meet the intent of this characteristic.
Furthermore, the criteria must define where the load is located for the measure of electrical proximity. In
planning models, loads are often aggregated to a higher voltage substation bus, while in a distribution system
model they are typically modeled along a distribution feeder.
The SDT should clarify how it intends for the load to be modeled for this analysis of close proximity.

Electricity Consumers Resource
Council (ELCON)

Yes

Occidental Energy Ventures
Corp.

Yes

Xcel Energy

Yes

Oncor Electric Delivery

Yes

We recommend that this item be added to the BES definition.

Oncor Electric Delivery agrees with the proposed language as it is stated, related to load proximity.

25

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the
system Element being located in close electrical proximity of Load and the use of impedance as qualifying criteria. Based on industry response and further
analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics
that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a
comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be
valid across all regions and systems. The new process requires an entity to clarify the characteristics of the facilities in question and to document the operational
performance as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being sought. The
appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and
then file the request and recommendation with the ERO as established in the draft Rules of Procedure.
Edison Electric Institute

No

We do not believe that a meaningful “not to exceed” impedance value can be proffered which would be
appropriately useful across all regions. EEI recommends that Exclusion benchmarks should directly correlate
to the BES definition exclusions as written. Although the “4 Item” approach was obviously intended to provide
a simple approach, the outcome suggested in the draft was less than satisfactory and we submit it does not
hold true to the exclusions provided by the Drafting Committee in their proposed BES Definition. (see
additional comments provided at the end of the Comment form)

PacifiCorp

No

All of PacifiCorp’s responses are based on the application of these items to a given interconnection and not
on a continental basis. See comments on question 10. Setting a standard for close electrical proximity using
an impedance measurement does not address a proper measurement in all interconnections. A better, more
accurate measurement would be to utilize fault duty. Low fault duties provide a good measurement of impact
on the BES. Fault Duty at adjacent BES substations should not exceed 5,000 MVA.

for Snohomish County PUD

No

Snohomish agrees in principle that one characteristic of local distribution systems is that they are usually
confined to a relatively limited geographic area, as opposed to transmission systems, which (especially in the
West) tend to cover very large distances. We also believe the proximity test may be a sensible way to identify
local distribution facilities. However, as explained in more detail in our response to Question 10, we believe
that the proximity test may be unnecessary, and if an Element or group of Elements meets the other three
tests proposed by the SDT, it should be excluded from the BES, even if it does not meet the proximity test.
Further, using impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage impedances.
Hence, in the absence of phase shifting transformers, service compensation, or other mitigation factors,
power typically flows over the highest voltage lines, which offer the lowest impedance.

Response:

The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the

26

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

system Element being located in close electrical proximity of Load and the use of impedance as qualifying criteria. Based on industry response and further
analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics
that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a
comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be
valid across all regions and systems. The new process requires an entity to clarify the characteristics of the facilities in question and to document the operational
performance as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being sought. The
appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and
then file the request and recommendation with the ERO as established in the draft Rules of Procedure.
Also see response to Question 10.
Florida Municipal Power Agency
Transmission Access Policy
Study Group

No

Impedance is a function of a line’s length; it does not measure whether a line serves a BES function. A very
long line can exist only to serve load, and a short line in an urban area (where the load is physically close to
the grid) could be needed for transmission but would have low impedance. This proposed metric is thus both
over- and under-inclusive, and should be discarded.
Transfer distribution factor is a more appropriate metric, as described in FMPA’ response to Question 4.
FMPA supports having two paths for exclusions, one that includes extensive technical analysis and another
that does not. The path with less technical analysis is appropriate for Elements that a relatively high-level
examination shows to be not relevant to the reliability of the grid. This opportunity should be available in the
context of exclusions to reduce the burden on small entities. Reliability will not be impaired by this option; all
exception requests will be reviewed by NERC, and in any case where NERC is less than certain that an
exception is appropriate, NERC can perform any or all of the analyses that would be required for a more
technical exclusion or inclusion, and a positive result on any one of the analyses would be sufficient
justification to deny the exclusion request.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the
system Element being located in close electrical proximity of Load and the use of impedance as qualifying criteria. Based on industry response and further
analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics
that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a
comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be
valid across all regions and systems. The new process requires an entity to clarify the characteristics of the facilities in question and to document the operational
performance as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being sought. The
appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and
then file the request and recommendation with the ERO as established in the draft Rules of Procedure.

27

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

Also see response to Question 4.
In regards to a two-path approach, the SDT has broadened the exception methodology to allow an entity to submit the characteristics of the Facilities in question
without supplying engineering evidence if they feel there is ample supporting documentation for the exception being sought.
Idaho Falls Power

No

We do not agree that all four criteria under exclusion #1 need be applied in combination to an element to
determine its material impact. Assets satisfying all four defining criteria would seem exceedingly small and
likely already excluded by the BES definition. This exception criteria appears redundant to, and shadows the
NERC BES definition draft’s language excluding radial elements and local distribution networks, and as such
add little value to the exclusions built into the BES definitions.
Further, the language of the exception criteria addresses transmission elements and doesn’t provide
exclusion criteria for generation assets. We would hope that NERC could develop criteria to exempt certain
generation, especially those small resources on local distribution networks wherein the generation is
completely allocated to local load. Language in section 215 of the FPA excludes distribution “elements.” We
assert that generation on a distribution network serving only load on that network is an “element” of the
network and deserves exclusionary defining criteria.

Response: The SDT appreciates the comments associated with the Element characteristics and the suggestions for language or clarifications to the proposed
language for technical exception criterion associated with generation. Based on industry response and further analysis, the SDT has abandoned the initial
exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to
a defined value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The
new process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through
submittal of an exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review
the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and
recommendation with the ERO as established in the draft Rules of Procedure.
The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.
PPL Supply

No

See comments in Questions 9 and 10

Response: See response to Q9 & 10.
Southern Company

No

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization
The United Illuminating
Company

Yes or No

Question 1 Comment

No

Response: Thank you for your response but without specific comments there is nothing that the SDT can do to address your opinion. However, based on industry
response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and
operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES.. The initial
proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to establish
values and/or limits that would be valid across all regions and systems. The new process requires an entity to clarify the characteristics of the facilities in question
and to document the operational performance as appropriate through submittal of an exception request form along with any other supporting documentation for
the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support
the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of Procedure.
National Grid

No

We feel that there is no relation between the proximity to load and system reliability. The impedance is
technically irrelevant, and we suggest that this criteria be dropped.
If the criteria is not dropped, there should be clarification on what is meant by “Load”. For instance are you
really referring to “major load centers”? In many areas of the country Load is connected all along a 100kV line
and hence much of a line is in close proximity to Load - but it could be small industrial loads and not
significant load centers. If significant Load Centers is what the drafting team was driving at then, we believe it
should be explicit.
We also believe that if the drafting team is defining some technical criteria, then it should not be in the
exception process. It should be included as part of the core definition. The exception process should be
strictly limited to the procedures for application and approval and should not include substantive elements.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the
system Element being located in close electrical proximity of Load and the use of impedance as qualifying criteria. Based on industry response and further
analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics
that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a
comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be
valid across all regions and systems. The new process requires an entity to clarify the characteristics of the facilities in question and to document the operational
performance as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being sought. The
appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and
then file the request and recommendation with the ERO as established in the draft Rules of Procedure.
The technical criteria are being developed through the Standards Development Process, consistent with the directives in Order 743 and 743A. The scope of the

29

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

Rules of Procedure is strictly focused on the process that entities shall use to seek and be granted or denied exceptions.
Exelon

No

The term “close proximity” is ambiguous and open ended. Exelon believes that all facilities used in local
distribution of electric energy that are presently under state jurisdiction should be excluded from the BES
regardless of system impedance.

Response: The SDT appreciates your comments. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or
limit. It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires
an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception
request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate
information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as
established in the draft Rules of Procedure.
In regards to the facilities used in local distribution that are presently under state jurisdiction the SDT has added language to the core BES definition that
addresses the exclusion of distribution facilities.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

2. Exclusions - The SDT has set up one path for evidence that does not include extensive technical
analysis. It consists of 4 items, all of which must be addressed in order to submit a completed
request for exclusion. The second item involves Element(s) treated as radial. Do you agree with this
requirement? If you do not support this requirement or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: A significant portion of the comments disagreed with, or had significant concerns about using
various undefined terms such as “regional dispatch”, “disconnection procedures”, and “radial in character”. Comments also
indicated that the example was not clear and many comments indicated that the entire wording of this exception should be
abandoned. Several comments indicated that assessments, studies, and drawings/diagrams should be allowed as evidence to
provide the validity of the exception.
Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is
intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity
with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined
value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be valid across all
regions and systems. The new process requires an entity to clarify the characteristics of the facilities in question and to
document the operational performance as appropriate through submittal of an exception request form along with any other
supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate
information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and
recommendation with the ERO as established in the draft Rules of Procedure.

Organization
Northeast Power Coordinating
Council

Yes or No
No

Question 2 Comment
The term “regional dispatch” is not defined. Provide a definition or reference to a definition to be used in
making this determination. Recommend adoption of the alternate term “operational control.”
1.b.ii, Operational Control - The SDT should consider using the terms “under the operational control of a
Balancing Authority.” It is instructive that the overarching requirement for a finding of transmission system
integration in Mansfield was that the facilities be under operational control of the Independent System
Operator (ISO).** Southern Cal. Edison Co., 92 FERC ¶ 61,070 at 61,255 (2000), reh'g denied 108 FERC
¶ 61,085 (2004).
Replace the example in 1.b.i. with a clearer example.
Entities should be allowed to demonstrate the radial characteristics to determine if they are permitted for an
exception, and demonstrate compliance with radial defining criteria.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization
SPP Standards Review Group

Yes or No
No

Question 2 Comment
Could the SDT clarify what is meant by ‘disconnection procedures’ in 1.b.ii? It appears that the SDT is okay
with excluding an element that can be switched out of service without removing another element. How are
automatic breaker operations or manual switching factored into disconnection procedures? We need
clarification on this.
More and better examples, including the type of connectivity to the grid, would be helpful.

Transmission Access Policy
Study Group

No

Florida Municipal Power Agency

ISO/RTO Standards Review
Committee

We believe that this criterion is intended, like those in 1(a) and (d), to determine whether an Element is
planned and operated to function as part of the interconnected grid. It is, however, too vague to be useful and
should be discarded.
We believe that this criterion is intended, like those in 1(a) and (d), to determine whether an Element is
planned and operated to function as part of the interconnected grid. It is, however, too vague to be useful and
should be discarded.

No

The SRC generally agrees that radial elements likely may be excluded from the BES. However, there is
insufficient information given as to what it means to be “not operated as part of the BES with disconnection
procedures for when a Disturbance occurs”.
Further, is it possible that such radial elements are serving a remote “critical” load? One would think that,
normally, critical loads would have arrangements for multiple sources, but could those multiple sources be
individually considered to be radial?

Iberdrola USA

No

We do not agree with this requirement. These exclusion exception criteria should be deleted in their entirety
and replaced with criteria that are objective, specific, and repeatable, or preferably not replaced at all.
Specific problems with the criteria as stated are: 1. A facility is not BES if all of “a” through “d” below apply:
b. “System elements” are “treated as” radial “in character” - this is also vague, and based on operating
procedures... what does “treated” involve? What is “character” in the context of system elements?

Tri-State Generation and
Transmission Association

No

While we generally agree, 1.(b) should be changed to “normally radial.” “Radial” should not be defined
differently in the Rule of Procedure than in the BES Definition.

Hydro One

No

Entities should be allowed to demonstrate the radial characteristics to determine if they are permitted for an
exception, and demonstrate compliance with radial defining criteria.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment
The term “regional dispatch” is not defined. Therefore we suggest the SDT to provide a definition or reference
to clarify regional dispatch in 1 b) II.
We recommend adoption of the alternate term “operational control” and suggest that the SDT consider using
the terms “under the operational control of a Balancing Authority” (It is instructive that the overarching
requirement for a finding of transmission system integration in Mansfield was that the facilities be under
operational control of the Independent System Operator.*)* Southern Cal. Edison Co., 92 FERC ¶ 61,070 at
61,255 (2000), reh'g denied 108 FERC ¶ 61,085 (2004).

MRO's NERC Standards Review
Forum

No

Radial in Character - NSRF proposes that this criterion be eliminated because it does not describe any
materially different characteristics beyond Exclusion E1 of the bright-line BES definition.

MidAmerican Energy

No

MidAmerican supports the NSRF comments. The NSRF proposes that this criterion be eliminated because it
does not describe any materially different characteristics beyond Exclusion E1 of the bright-line BES
definition. If not eliminated, the IEEE definition of a radial system should be used.

Bonneville Power Administration

No

BPA requests clarification on what the SDT considers radial through additional examples of i “the way the
connections to the BES are operated” and ii “the way the Element(s) are treated in operations.”
BPA emphasizes that this assessment should be conducted using normal system operations.

Muscatine Power and Water

No

Radial in Character -propose that this criterion be removed for the reason that it does not illustrate any
materially different characteristics beyond Exclusion E1 of the bright-line BES definition.

Exelon

No

The term “rarely” is ambiguous and should be removed or quantified.
Furthermore, the requirement for power flow analysis will be viewed by many entities as extensive technical
analysis.

Consolidated Edison Co. of NY,
Inc.

No

We generally support this exclusion option concept, to the extent that it is fashioned after the FERC Seven
Factor test. However, we have a number of questions as to how it might work in practice. For example, the
term “regional dispatch” is not defined. Please provide a definition or reference to a definition to be used in
making this determination.
Below we recommend adoption of the alternate term “operational control.”1.b.ii, Operational Control - The
SDT should consider using the terms “under the operational control of a Balancing Authority.” It is instructive
that the overarching requirement for a finding of transmission system integration in Mansfield was that the

33

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment
facilities be under operational control of the Independent System Operator (ISO).** Southern Cal. Edison Co.,
92 FERC ¶ 61,070 at 61,255 (2000), reh'g denied 108 FERC ¶ 61,085 (2004).
Replace the example in 1.b.i. with a clearer example.

ISO New England

No

This three part definition of radial presented in section 1.b. appears cumbersome and requires more
definition.
With regard to b.i - Where is the disturbance? Is sending a person to the field to perform manual
disconnection a requirement of this exception? This item is so vague that we have difficulty providing
replacement language as we do not understand its intent.
With regard to b.ii - Elements (Excluding generators) are not dispatched in operations. If this approach were
to be taken, what would be the criteria for the way the Element is treated in Operations? Again, this item is so
vague that we have difficulty providing replacement language.
The existing definition appears to require a good deal of technical scrutiny and be at odds with the goal of
having a path for evidence that does not include extensive technical analysis. Overall it seems simpler to
replace section b with a simpler definition of radial such as - all load served from a single substation at a
single voltage level.

The United Illuminating Company

No

Pepco Holdings Inc

No

Radial system is already an explicit Exclusion by definition (E1). Does this imply that ALL radial systems
require a request to be submitted for the RE and NERC approval that the elements are in fact radial?
There may not be internal written procedures describing the radial system operation. The evidence that an
entity can provide should include a description or justification of the radial operation and non impact to the
BES.

Duke Energy

No

This second characteristic does not add clarity to the E1 Exclusion in the proposed BES definition. And in
general, the path that does not include extensive technical analysis is not adequate to distinguish between the
Elements that are and that are not necessary for operating an interconnected electric transmission network.

American Transmission
Company, LLC

No

Radial in Character - ATC proposes that this criterion be eliminated because it does not describe any
materially different characteristics beyond Exclusion E1 of the bright-line BES definition.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment

Manitoba Hydro

No

The proposed criteria to substantiate a request for an exception should be removed as it does not introduce
anything different than what is already proposed under the exclusions in the bright line BES definition.
Specifically, radial systems are already excluded in the bright line definition E1.

NESCOE

No

As noted in Response 1, NESCOE believes exclusion determinations should not require a finding that all four
proposed criteria are met.
In addition, NESCOE believes that the criterion proposed here is overly complex and that developing the
evidence may be overly burdensome to the applicant. Radial paths should have a simple definition related to
how the path is connected from a topological perspective. NESCOE suggests that a radial path be defined
simply as a path having only one connection point to the BES, thereby presenting no opportunity for power
flows parallel to the BES network. Under fault situations, these excluded paths can be isolated from the BES
with suitable NERC compliant protection systems. Note the radial path may be comprised of parallel lines that
terminate at the BES connection point.
In addition, NESCOE believes that a radial path should qualify for exclusion as long as the power flowing into
the BES is less than a threshold MVA.
NESCOE does not at this point have a recommendation as to this specific threshold but believes it should be
developed through the standards-setting process. NESCOE suggests this approach to avoid burdening the
development of generation including renewable generation. As New England is working on facilitating the
development of renewable resources located in and around the region to serve customers most costeffectively, this process should take specific care not to impose undue burdens on renewable resources.

Idaho Falls Power

Blachly Lane Electric Cooperative
Flathead Electric Cooperative,
Inc.
Central Electric Cooperative
Clearwater Power Electric

Using these criteria assumes that every asset must be radial in nature in order to receive consideration that it
may not be material to the BES. This then implies that the BES is a contiguous connected system as only
radial off-shoots could receive exemption consideration. We disagree. Our assertion is that the BES is
comprised of assets that due to their size or location are vital to a sound BES but may or may not necessarily
be connected to each other. This defining criteria in the exception could be a stand-alone criteria or stricken.
Yes

We agree conceptually that facilities operating as radials rather than as integrated portions of the integrated
bulk transmission system should be excluded from the BES definition. However, to be consistent with the
draft BES definition, the term “radial in character” should be explicitly defined as facilities that may include one
or more lines into a load area or referenced as a local distribution network.
In addition, we agree that the manner in which a system is operated during BES disturbances may be an
indication of whether that facility is radial in character. That being said, we are concerned that, to the extent

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Cooperative

Question 2 Comment
the SDT considers regional disconnect procedures, it should be careful to note that UFLS and UVLS relays
are often embedded within local distribution facilities and, while it is necessary for the UFLS and UVLS relays
to be properly armed to protect the BES in the event of a severe system disturbance, the local distribution
facilities interconnected with those relays should not, and cannot legally, be classified as BES.

Consumer's Power Inc.
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc.

South Carolina Electric and Gas
Georgia Transmission
Corporation

Yes

SCE&G agrees with the requirement of an element being radial in character as being a qualifier for exclusion
thru the non-technical analysis.
However, we recommend that the term "radial in character" be better defined.
In addition, the language is confusing and we would like to recommend the following: i.: suggest replacing

36

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment
“disconnection procedures” with “automatic disconnection devices”
ii.: The intent of this item is not clear, and the term "regional dispatch" is not defined. Recommend the item be
clarified or deleted.

Springfield Utility Board

Yes

SUB agrees with providing an exclusion exception for System Elements that are treated as “radial in
character”, but feels this should be part of the core definition in NERC’s Proposed Continent-wide Definition of
Bulk Electric System rather than requiring an exclusion/exemption application process.
In SUB’s May 27, 2011 BES definition comments SUB expressed concern that there still appears to be
inconsistencies in both definition and application of “radial.” SUB encourages NERC to develop a concise
definition. For example, if a system is normally operated as radial, but could be operated closed (for example,
by manually closing a breaker), would it be considered a radial or close-looped system?

Entergy Services

Yes

Entergy agrees that radial facilities should be excluded directly. However, the "radial in character" language is
nebulous. A simpler approach could be to allow exceptions for facilities which become radial as a
consequence of a normal system response to a disturbance (breakers opening during normal clearing of a
fault).

Clark Public Utilities

Yes

Clark agrees conceptually that systems operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. That is because local
distribution systems typically operate adjacent to, or at the end of transmission lines, and function
operationally to move power from the Transmission Service Provider’s point of delivery of bulk power that has
moved across the integrated bulk transmission system to end-users located within the local distribution
utility’s service territory.

Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc.
Central Lincoln
Salem Electric
Grant County PUD No. 2 (Grant)
for Snohomish County PUD

To be consistent with the draft BES definition, the term “radial in character” should be explicitly defined as a
system that may include one or more lines into a load area or referenced as a local distribution network. In
addition, Clark agrees that the manner in which a system is operated during BES disturbances may be an
indication of whether that system is radial in character. That being said, we are concerned that, to the extent
the SDT considers regional disconnect procedures, it should be careful to note that UFLS and UVLS relays
are often embedded within local distribution systems and, while it is necessary for the UFLS and UVLS relays
to be properly armed to protect the BES in the event of a severe system disturbance, the local distribution
system interconnected with those relays should not.

Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment

Inc.
Kootenai Electric Cooperative
Oregon Public Utility Commission
Staff

Yes

Use of the 100 kV brightline and the core BES definition as proposed is an overreach into local distribution
systems and an overreach of FERC’s authority as set out in the FPA 215.
A full engineering technical analysis - required every 2 years - is too onerous and not necessary for
identifying most local distribution elements miss-identified as BES Elements. A simple screening
methodology consistent with the 7-Factor Test (from FERC Order 888) is needed as the first stage of the
exception process.

Hydro-Quebec TransEnergie

Yes

However, the point B.i. is hard to understand and would need clarification. Here is a proposal: "For an
Element to be excluded from BES, its should be demonstrated that there are a proper disconnection
procedure when facing a disturbance that would prevent this Element to impact the BES" ?.
The point should be to make sure a fault on the Element will be isolated effectively without adverse impact on
the BES, even when we have a second transmission source for the syb system seeking exclusion.
Also, for point B. ii., it should be explained what is meant by the expression "regional dispatch". Is it an
alternate way of transfer of power outside the Balancing Authority ?

PacifiCorp

Yes

All of PacifiCorp’s responses are based on the application of these items to a given interconnection and not
on a continental basis. See comments on question 10. If this requirement is added to the four requirements to
capture local distribution networks, which are often operated in a looped configuration, which may still be
included in the BES by the proposed BES bright-line due to generator inclusions, then this requirement has
merit. Otherwise, exclusion E1 in the proposed BES bright-line definition already covers this item and it
becomes redundant.

Independent Electricity System
Operator

Yes

We agree with this concept. Entities should be allowed to demonstrate the radial characteristics to determine
if they are permitted for an exception. However, we believe some further clarification of the meaning of “radial
in character” is needed. The example given in (b)I does not clarify the matter. Would a transmission line
operated with a normally open point to form two radial lines be considered “radial in character”? Please
clarify.
The location of the Disturbance needs to be clarified. For example, if the Disturbance (e.g. a fault) occurs at
the radial part of the Element, then it is necessary for the Element to have the capability to disconnect itself
from the Disturbance to preserve BES reliability but the Element can be by itself a legitimate radial facility that

38

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment
is used solely for supplying load. The phrase “are not included in a regional dispatch” is unclear. We do not
understand what this means.

Tacoma Power

Yes

Tacoma Power generally agrees that radial elements should be an item in this path and we suggest that
radial element operated at below 300 kV should be excluded from the BES. The 300 kV level is linked with
NERC CIP’s proposed version 4 definition of critical asset and should be applied here with the BES definition.

SERC Planning Standards
Subcommittee

Yes

The PSS agrees with the requirement of an element being radial in character as being a qualifier for exclusion
thru the non-technical analysis. However, the PSS recommends that the term "radial in character" needs to be
better defined.
In addition, the language is confusing and the PSS would like to recommend the following:i.: suggest
replacing “disconnection procedures” with “automatic disconnection devices”ii.: The intent of this item is not
clear, and the term "regional dispatch" is not defined. Recommend the item be clarified or deleted.

Tennessee Valley Authority

Yes

We agree with the requirement of an element being radial in character as being a qualifier for exclusion thru
the non-technical analysis. However, we recommend that the term "radial in character" needs to be better
defined.
In addition, the language is confusing and we recommend the following:i.: suggest replacing “disconnection
procedures” with “automatic disconnection devices”
ii.: The intent of this item is not clear, and the term "regional dispatch" is not defined.
Recommend the item be clarified or deleted.

New York State Reliability
Council

Yes

It should be clarified that radial Element(s) include all system elements in load pockets.

Electricity Consumers Resource
Council (ELCON)

Yes

We recommend that that the item be added to the BES definition.

New York Power Authority

Yes

The definition of radial systems needs to be modified to include radials that are connected to a single
transmission source by more than one automatic interruption devices, such as occurs with a “breaker and a
half” arrangement.

Southern Company

Yes

We agree with the requirement of an element being radial in character as being a qualifier for exclusion thru

39

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment
the non-technical analysis. However, we recommend tha the term "radial in character" be better defined.
Item ii.: The intent of this item is not clear, and the term "regional dispatch" is not defined. Recommend the
item be clarified.

ITC

Yes

ITC is in agreement if we are correct in assuming that any one of the three ways ( i, ii, or iii ) can be used to
satisfy the exclusion.
We would also like to request additional clarification as to what "disconnection procedures" would be valid for
consideration in this requirement.

National Grid

Yes

We agree that elements that are treated as radial should be allowed to request an exception.
We would like more clarification about what is meant by “regional dispatch”. To the extent definitions of terms
such as “regional dispatch” are necessary; they should be addressed in the core definition development
process. The exception process should be strictly limited to the procedures for application and approval and
should not include substantive elements.
We would also like clarification on whether all three criteria under bullet b are required to show if the element
is treated as radial, or if meeting one is enough.

Harney Electric Cooperative, Inc.

Yes

Oncor Electric Delivery

Yes

Xcel Energy

Yes

Consumers Energy Company

Yes

Long Island Power Authority

Yes

Elements could be included in a regional dispatch such as a large regional ISO, but still serve only local load
and therefore should still be treated as radial.

American Electric Power

Yes

Considering whether or not the element is treated as radial is a reasonable approach.

Orange and Rockland Utilities,
Inc.

Yes

Oncor Electric Delivery agrees with the proposed language that describes the exclusion criteria for system
Elements that are radial in character.

40

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment

BGE

Yes

No comment.

Spyker

Yes

We agree with this concept. Entities should be allowed to demonstrate the radial characteristics to determine
if they are permitted for an exception.

Occidental Energy Ventures
Corp.

Yes

ReliabilityFirst

Yes

Electric Market Policy

Yes

ACES

Yes

yes only true radial without any impact should be excluded otherwise include it

We agree with this path.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the system
Element being treated as radial in character as qualifying criteria. Based on industry response and further analysis, the SDT has abandoned the initial exclusion
criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and
provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value
and/or limit. It has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new
process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to
validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as
established in the Rules of Procedure as presently being drafted.
NERC Staff Technical Review

No

We believe that restating this measure as “System performance impacts are similar to radial systems” would
be more in-line with the SDT intent and a better measure of whether Element(s) are necessary for reliable
operation.
We also believe that the best measure of whether Element(s) affect system performance in a manner similar
to radial systems is through distribution factor analysis. Such analysis, when limited to this purpose, does not
require extensive technical analysis. Analysis for a limited number of stressed transfer conditions, and
contingencies involving the Element(s) under consideration and in the area of the Element(s) under
consideration, is sufficient to demonstrate whether the system performance impacts are similar to radial
systems.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment

Western Electricity Coordinating
Council

No

This characteristic is vague and subjective. It is unclear what “radial in character” means, and the methods for
demonstration do not appropriately clarify the meaning. WECC recommends that the SDT determine what it is
looking for to show “radial in character” and clearly identify that concept in the methods for demonstration. It is
not clear how Operating Procedures can demonstrate that an element is “radial in character” nor is it clear
how a re-evaluation might be processed if such Operating Procedures, ownership, or operations change.
WECC believes that BES inclusion or exclusion should be based on physical, technical characteristics of the
element, and requests a justification for use of procedural or contractual documentation as evidence of a
technical principle.

Edison Electric Institute

Yes

The verbiage used in the BES Principles document does not closely match the verbiage used in the NERC
Bright-line Exclusion. For that reason, we submit the following alternative language.
System Elements and Facilities treated in total as a radial system shall have the following characteristics:1.
Shall be separated from the BES with an Automatic Interrupting Device, AND2. Only load serving and must
be isolated from other radial systems through a normally open switching device, OR3. Only include
generation resources but cannot include any of the Inclusions (i.e., I2, I3, I4 and I5) identified in the BES
Definition, OR4. Is a combination of Load and Generation but cannot include any of the Inclusions (i.e., I2, I3,
I4 and I5) identified in the BES
DefinitionEvidences to be supplied shall include: o One-line Diagram clearly showing all demarcations
between BES Facilities and the Radial System (including the Automatic Interrupting Device, AND o
Operating procedures or interconnection agreements that indicate Generating Units contained within the
Radial System are not dispatchable (if applicable), AND/OR o Operating procedures that show that the
Radial System is not operated as part of the BES

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the system
Element being treated as radial in character as qualifying criteria.
The new proposed process allows an entity to submit a specified and consistent list of studies that should support the entity’s request and that can then be utilized by
the ERO panel judging the request in making their decision.
Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the
technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The
initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish
continent-wide values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of the facilities in
question and to document the operational performance as appropriate through submittal of an exception request form along with any other supporting documentation
for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment

the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as presently being drafted.
PPL Supply

No

See comments in Questions 9 and 10

Glacier Electric Cooperative

No

I do agree that radial elements should definitely be excluded. However, I believe that non-radial elements
should be able to be excluded by Path 1 as well. If a small local distribution system is operated non-radially
for the purpose of improving reliability for its loads, then that system should be eligible for exclusion from the
BES. I also believe that language needs to be included that makes the provision for radial elements that can
be temporarily and briefly looped together during switching to prevent an outage (e.g. for transformer
maintenance) to also be excluded from the BES.

City of Redding

Yes

The term Radial could cause confusion. Clarification needs to be added to indicate that the system can have
more than one connection to the BES.

Response: See response to Q9 & Q10.

Response: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to
clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of
BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible
to establish continent-wide values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of the
facilities in question and to document the operational performance as appropriate through submittal of an exception request form along with any other supporting
documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether
or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as presently being
drafted.
Exclusion E1 of the definition allows normally open switches and Exclusion E3 can be used for systems that support load with multiple connections to the BES.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

3. Exclusions - The SDT has set up one path for evidence that does not include extensive technical
analysis. It consists of 4 items, all of which must be addressed in order to submit a completed
request for exclusion. The third item involves power flow. Do you agree with this requirement? If you
do not support this requirement or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments. In addition, in the comment
field, please provide your thoughts on the appropriate MWh value to replace ‘TBD,’ including
technical rationale for your argument.
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion
criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be
considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was
dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not
feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new process
requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as
appropriate through submittal of an exception request form along with any other supporting documentation for the exception
being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of
whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established
in the Rules of Procedure as presently being drafted.

Organization
Northeast Power Coordinating
Council

Yes or No
No

Question 3 Comment
If an entity provides hourly MWh power flow data on a radial for a 12-month period (under v.) showing no
power flow reversals, would transaction data (under i. through iv.) still be required?
Could the entity just say “no transactional records?”
If there were power flow reversals, wouldn’t the power flow data (provided under v.) also show those, e.g., the
amount and duration?
Isn’t this request redundant?
If reversing power flows on a feeder caused it to fail one of the criteria, could the radial still be excluded, or is
it necessary for the Element to pass all requirements?
Alternatively, could the entity choose to file for Exclusion of that Element under the technical analysis option?
What happens and what are the implications when the two approaches produce different outcomes?

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
Recommend that “iv. The maximum amount of energy flowing out” limit be set to no more than 24 hours of
reverse power flows within any rolling 12-month period.
Consider avoiding prescribing values and eliminate bullet (iv). The intended performance outcome should be
described, but without setting values.
This should not have any impact on the reliability of the transmission network if items 1, 2 and 3 are satisfied.

SPP Standards Review Group

No

Rather than combining two conflicting criterion - ‘rarely’ and the number of MHh of backflow allowed annually
- we would suggest the following. 1) That the maximum outflow doesn’t create an issue on the BES. This
would be determined by study of the system and conditions. Or 2) when the condition exists, be able to
mitigate the condition within a prescribed time relevant to the prevailing system conditions.

NERC Staff Technical Review

No

Requiring that power flows into, and rarely out of, the Element(s) considered for exclusion is an appropriate
measure, as is requiring an entity to define the conditions under which power will flow out.
In addition to information such as specified contingencies in item (ii), details on the conditions should include
other relevant information such as the system load level, generation dispatch, system transfer levels, etc., and
the number of hours per year these conditions are expected.
An exception request also should include the maximum flow expected. E.g., the following information would
be useful in evaluating a request for exception: “Power will flow out only when line A is out of service, system
load is at or below X percent of peak load, and generator B is on-line; based on the load duration curve for
this area and the number of hours generator B is dispatched at these load levels, the exposure to power flow
out for this contingency is limited to N hours per year and the maximum flow if the contingency occurred
during these hours would be Y MW.” This type of information will be far more informative than a pass/fail test
as to whether a MWh threshold is expected to be exceeded. While a MWh threshold may be useful for
evaluating requests, it is unlikely that a one-size-fits-all threshold could be established for evaluating
exception requests.

ISO/RTO Standards Review
Committee

No

The SRC believes that, if power EVER flows out, then the area is either not radial or it includes generation
resources. There is insufficient information to determine whether this “limited quantity of energy” is indeed
small. There could be very large amounts of load and generation resources within that area. Such large
quantities could represent a significant potential for sudden increases in load or unexpected energy injections.

Iberdrola USA

No

We do not agree with this requirement. These exclusion exception criteria should be deleted in their entirety
and replaced with criteria that are objective, specific, and repeatable, or preferably not replaced at all.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
Specific problems with the criteria as stated are: 1. A facility is not BES if all of “a” through “d” below apply:
c. Power flows into “the system” most of the time - this is vague and covers much of the 115 kV system.

Hydro One

No

We agree with the criteria set out in 1(c), but suggest the SDT to avoid prescribing values and eliminate bullet
(IV).
The SDT should also consider allowing: a) Power flow-out up to 20% of the minimum forecasted load for the
element(s) over a 12 month period; or b) Maximum amount of energy flowing out be set to no more than 24
hours of reverse power flows within any rolling 12-month period. The intended performance outcome should
be described, but without setting values. This should not have any impact on the reliability of the transmission
network if items 1, 2 and 3 are satisfied.

MRO's NERC Standards Review
Forum

No

NSRF proposes that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the bright-line BES definition.

MidAmerican Energy

No

MidAmerican supports the NSRF comments. The NSRF proposes that this criterion be eliminated because it
does not describe any materially different characteristics beyond Exclusion E3 of the bright-line BES
definition.

ReliabilityFirst

No

All power flow studies can be don eto show a small impact, this is how the system is planned. This will only
cause more confusion and debate between the FERC, NERC the Regions and registered entities

Idaho Falls Power

No

We agree in general, however believe there is little distinction between the defining criteria in this exception
and the local distribution network exclusion already provided for in the BES definition.
We would like to see added language that provides an exclusion for all elements on such a system, to include
generation regardless of MVA rating, wherein the power flows are generally into the system.
We would agree that a number of MWh of annual outflow needs to be established as a limitation to the size
and amount of generation under consideration. This exclusion should be geared towards smaller municipal or
like sized systems having no material impact upon a BA much less the region.

Muscatine Power and Water

No

Proposing that this criterion be eliminated because it does not describe any materially different characteristics
beyond Exclusion E3 of the bright-line BES definition.

Glacier Electric Cooperative

No

Regarding using power flow into and out of a system as a criterion fro BES exclusion, I do not think that

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
establishing a hard MWh per year is the proper approach to take. Once again, I believe that the purpose of
the system should be the most important factor. If the purpose of a system is to serve load or transport nonessential generation (i.e. wind power), then that system should be able to be exluded.

Consolidated Edison Co. of NY,
Inc.

No

We generally support this exclusion option concept, to the extent that it is fashioned after the FERC Seven
Factor test. However, we have a number of questions as to how it might work in practice. For example: o If
an entity provides hourly MWh power flow data on a radial for a 12-month period (under v.) showing no power
flow reversals, would transaction data (under i. through iv.) still be required? Couldn’t the entity just say “no
operating records?”
o If there were power flow reversals, wouldn’t the power flow data (provided under v.) also show those, e.g.,
the amount and duration? Isn’t this request redundant? If not, why not? Please explain.
o If reversing power flows on a feeder caused it to fail one of the criteria, could the radial still be excluded, or
is it necessary for the Element to pass all requirements? Alternatively, could the entity choose to file for
Exclusion of that Element under the technical analysis option? What happens and what are the implications
when the two approaches produce different outcomes?
We recommend that “iv. The maximum amount of energy flowing out” limit be set to no more than 24 hours of
reverse power flows within any rolling 12-month period.Replace “transactional records” with “operating
records.”

ISO New England

No

Section 1.c again appears to allow the exclusion of large portions of the system in metropolitan areas. How
does this differ from the LDN exclusion already presented in the definition?
Section c should simply be deleted.

The United Illuminating Company

No

What does rarely mean? How is maintenance conditions considered? This is simply worded but conceptually
extremely complicated.

Entergy Services

No

Power flows into or out of a portion of the BES may characterize BES facilities less important to BES reliability
but without limits to the size of the area, it would be difficult to show compliance. An entire state could be
excluded from the BES.
Additionally, there is no process specified to review the characteristics as transmission topology and
resources change over time.

BGE

No

BGE is generally opposed to this requirement because the MWh factor is too variable and/or may be utilized

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
in a way contrary to reliable system operation.

Pepco Holdings Inc

No

The characteristic statement should be reworded to say: “Power flow is generally load serving.”The criteria as
written have very burdensome MWh record requirements. Yearly totals for flows in and out and an overall
description or justification for this exception should be allowable.

Duke Energy

No

This third characteristic does not add clarity to the E3 Exclusion in the proposed BES definition. And in
general, the path that does not include extensive technical analysis is not adequate to distinguish between the
Elements that are and that are not necessary for operating an interconnected electric transmission network.

American Transmission
Company, LLC

No

ATC proposes that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the bright-line BES definition.

Manitoba Hydro

No

Vague language such as “rarely” or “not intentionally” does not support a “bright line” approach, and is not
measureable or auditable. Also, the sample evidence should not be included as part of the criteria.In addition,
the proposed criteria to substantiate a request for an exception should be removed as it does not introduce
anything different than what is already proposed under the exclusions in the bright line BES definition.
Specifically, this item is already excluded in the bright line definition E3.

NESCOE

No

As noted in Response 1, NESCOE believes exclusion determinations should not require a finding that all four
proposed criteria are met. Generally, NESCOE is in agreement with an exception criteria for additional
exclusions that takes into account power flows into the system that rarely flows out. However, additional
clarity is necessary for criteria 1(c)(i),(ii) and (iv). Specifically, what is meant by “very limited set of conditions”
under 1(c)(i) and (ii) and “limited quantity of energy” under 1(c)(i)?
Further, is it appropriate to establish a fixed value of X megawatt hours for the maximum amount of energy
flowing out of the system?
While it is possible that NESCOE could agree upon a uniform value, NESCOE is not in a position to provide
specific comment or support when the MWh value is unspecified. In addition, a fixed value may not
adequately address varying system configurations throughout ISO-New England and neighboring control
areas.

Independent Electricity System
Operator

No

There is an inconsistency between the language used in bullet (c) - “rarely flows out”, and that used in
Exclusion E3(c) of the BES definition - “Power flows only into the LDN”. We have commented during the BES
Definition comment period that Exclusion E3 needs to be modified to match the Exception Principles.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
We agree with the criteria set out in 1(c) except for bullets (iv) and (v). We do not believe it is possible to
establish a limit on the energy flow out of a system for which an exception has been requested.
Further, we suggest that the SDT avoid prescribing set values in the exception criteria since these would only
serve to limit the flexibility of the process.
As an alternative to the proposed bullet (iv), we suggest that power flow study results could be used to
support the exception request. We therefore propose the following wording to replace bullets (iv) and (v).iv.
Power flow simulation results to demonstrate that BES reliability is not dependent upon the power flows
through the Element(s) for which an exception has been submitted, for the conditions specified in (ii).

Georgia System Operations
Corporation

If the BES Definition itself is clarified to allow for some de minimis amount of power flow out of a customarily
radial line that is excluded by definition, this justification for an exclusion may not be necessary. We
encourage the Drafting Team to pursue that approach because we believe it is technically justified and could
significantly reduce the need for exceptions.

Florida Municipal Power Agency

The third item is “power flows into the system, but rarely flows out.” This criterion is vague. FMPA suggests
instead the following language, which is consistent with FMPA’ comments on Exclusion E3 of the BES
definition: “Neither the Element, nor any Elements that it connects to the grid (in aggregate), includes more
than 75 MVA of generation used to meet the resource-adequacy requirements of electric utilities.”

Transmission Access Policy
Study Group
ACES

Yes

We agree with this path although iii and v may be in conflict. One requires 24 months data and the other
requires 12 months of data.

National Grid

Yes

We agree with this requirement, but feel that assigning a specific value to the energy flowing out of the
system in MWh is unnecessary. The energy flowing out of a system depends on the size of the area, and
thus could vary widely.
Another concern is about non-wires alternatives (NWA). One type of non-wires alternative that is considered
during planning studies is to reduce the amount of load on our system by paying customers to not operate
during peak hours. One scenario to consider is a generator connected on a radial line that qualifies as BES,
and will need upgrades if the generator runs frequently. If this generator produces power close to the MWh
threshold in the specified time frame per NERC criteria, does it mean the utility company will have to consider
paying the generator owner money to shut down in order to keep total MWh generation below the threshold
and avoid BES criteria required radial line upgrades? This is another reason assigning a specific value to the
energy flowing out of the system is unnecessary.
We would like clarification on whether all criteria (i,ii,iii,iv,v) need to be met, or if just meeting one criteria is

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
sufficient. We feel that meeting criteria 1.c.1, 1.c.ii OR 1.c.iii is sufficient in showing that power rarely flows
out of the system. Criteria 1.c.iv and 1.c.v should be removed.
The exception process should be strictly limited to the procedures for application and approval and should not
include substantive elements.

Blachly Lane Electric Cooperative
Flathead Electric Cooperative,
Inc
Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative

Yes

We agree conceptually that one critical characteristic distinguishing facilities that must be excluded from the
BES from facilities that should be included is the manner in which power flows on those facilities. Hence, the
SDT has properly identified power flows as one important characteristic that identifies BES facilities. We also
agrees conceptually that the fact that power may flow out of facilities onto the grid during a few hours in a
year or during extreme contingencies should not change the characterization of the facilities in question as
excluded from the BES. Accordingly, we support inclusion of power flow analysis as one element of
characteristics that can be used to exclude facilities from the BES even if the facilities do not pass each of the
bright-line thresholds laid down in the BES definition.
We also agree that transactional and hourly generation records are an appropriate basis for making the
determination since these can be used to demonstrate that demand within a system exceeds generation
within that system in most hours and that power therefore does not flow onto the grid, and also to determine
the number of hours where this is not the case and the amount by which generation within the system
exceeds demand. In order to identify facilities that are not necessary for the operation of the BES under this
text, we propose that any facility where real power flows in 90 percent of the time or more under normal (“N-0”
or All Lines in Service) operating conditions should be held to meet this test. That facilities meet this test
could be demonstrated using metering or supervisory control and data acquisition ("SCADA") data records
over the course on two years.

Raft River Rural Electric
Cooperative

While we agree with the SDT’s view that power should flow predominantly in the direction of load for excluded
facilities, we are concerned that this characteristic may no longer be a defining characteristic as the electric
industry evolves in the future. If distributed generation becomes the future norm for new power generation
facilities, it may no longer make sense to look at power flow as a defining characteristic. That is, even if a
sufficient number of small distributed generation facilities were constructed on certain facilities to cause power
to flow out of those facilities more than ten percent of the time, the fundamental character of those facilities
will not have changed.

Salmon River Electric
Cooperative

Finally, we believe that power flow analysis under this item should consider actual power flow, not scheduled
power flow.

Northern Lights Electric
Cooperative
Okanogan Electric Cooperative

Umatilla Electric Cooperative
West Oregon Electric

50

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment

Yes

Clark agrees conceptually that one critical characteristic distinguishing local distribution facilities that must be
excluded from the BES from transmission facilities that should be included is the manner in which power flows
on those facilities. Power on local distribution systems generally flows only from the interconnected
transmission source and across the distribution system for delivery to end-use customers. By contrast, power
on transmission systems generally flows in two (or multiple, in networked systems) directions and is delivered
in bulk to distribution utilities rather than to end-users. Hence, the SDT has properly identified power flows as
one important characteristic that distinguishes BES transmission systems from local distribution systems. In
order to identify systems that are not necessary for the operation of the BES under this text, we propose that
any system where real power flows into the local distribution system 90 percent of the time or more under
normal operating conditions.

Spyker

Yes

We agree with the criteria set out in 1(c), but suggest the SDT to avoid prescribing values and eliminate bullet
(iv). The SDT should describe the intended performance outcome but avoid setting values. This should have
little, if any impact on reliability of the transmission network if the items 1, 2 and 3 are satisfied.

American Electric Power

Yes

Requiring that “power flows into the system, but rarely flows out” is a reasonable approach, but would require
further consideration given the MWh value eventually chosen to replace “TBD”.

Orange and Rockland Utilities,
Inc.

Yes

The “TBD” value should be reasonable and well justified.

Cooperative
Pacific Northwest Generating
Cooperative

Clark Public Utilities
Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc.
Salem Electric
Grant County PUD No. 2 (Grant)
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc
Kootenai Electric Cooperative

51

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment

Central Lincoln

Yes

Central Lincoln agrees that one critical characteristic distinguishing local distribution facilities that must be
excluded from the BES from transmission facilities that should be included is the manner in which power flows
on those facilities. Power on local distribution systems generally flows only from the interconnected
transmission source and across the distribution system for delivery to end-use customers. By contrast, power
on transmission systems generally flows in two (or multiple, in networked systems) directions and is delivered
in bulk to distribution utilities rather than to end-users. Hence, the SDT has properly identified power flows as
one important characteristic that distinguishes BES transmission systems from local distribution systems.
Central Lincoln also agrees that the fact that power may flow out of a local distribution system onto the grid
during a few hours in a year or during extreme contingencies should not change the characterization of the
system as local distribution. Accordingly, we support inclusion of power flow analysis as one element of
characteristics that can be used to exclude local distribution facilities from the BES even if the facilities do not
pass each of the bright-line thresholds laid down in the BES definition.
We also agree that transactional and hourly generation records are an appropriate basis for making the
determination since these can be used to demonstrate that demand within a local distribution system exceeds
generation within that system in most hours and that power therefore does not flow onto the grid, and also to
determine the number of hours where this is not the case and the amount by which generation within the
system exceeds demand. In order to identify systems that are not necessary for the operation of the BES
under this test, we propose that any system where real power flows into the local distribution system 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should be held to
meet this test. That a system meets this test could be demonstrated using metering or supervisory control
and data acquisition ("SCADA") data records over the course of two years. In addition, the presence of
generation within a local distribution system that only modifies the level of the load served by the bulk system,
but does not result in power being injection into the bulk system, does not change the reliability effect of the
local network and therefore should not require the local network to be classified as BES.

Oregon Public Utility Commission
Staff

Yes

Use of the 100 kV brightline and the core BES definition as proposed is an overreach into local distribution
systems and an overreach of FERC’s authority as set out in the FPA 215. A full engineering technical
analysis - required every 2 years - is too onerous and not necessary for identifying most local distribution
elements miss-identified as BES Elements. A simple screening methodology consistent with the 7-Factor
Test (from FERC Order 888) is needed as the first stage of the exception process.

Hydro-Quebec TransEnergie

Yes

However, this is only part of an exclusion.
The point c. iv and v, MWh is not relevant for real-time operation. It would be more simple to put a time
reference, such as a total number of days or a % of the time.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
In number iii, do you mean the first self certification ? In fact, the evidence for exclusion will be done once, but
ROP suppose that the self certification will be done many times (every two years).

for Snohomish County PUD

Yes

Snohomish agrees conceptually that one critical characteristic distinguishing local distribution facilities that
must be excluded from the BES from transmission facilities that should be included is the manner in which
power flows on those facilities. Power on local distribution systems generally flows only from the
interconnected transmission source and across the distribution system for delivery to end-use customers. By
contrast, power on transmission systems generally flows in two (or multiple, in networked systems) directions
and is delivered in bulk to distribution utilities rather than to end-users. Hence, the SDT has properly
identified power flows as one important characteristic that distinguishes BES transmission systems from local
distribution systems.
Snohomish also agrees conceptually that the fact that power may flow out of a local distribution system onto
the grid during a few hours in a year or during extreme contingencies should not change the characterization
of the system as local distribution. Accordingly, we support inclusion of power flow analysis as one element
of characteristics that can be used to exclude local distribution facilities from the BES even if the facilities do
not pass each of the bright-line thresholds laid down in the BES definition.
We also agree that transactional and hourly generation records are an appropriate basis for making the
determination since these can be used to demonstrate that demand within a local distribution system exceeds
generation within that system in most hours and that power therefore does not flow onto the grid, and also to
determine the number of hours where this is not the case and the amount by which generation within the
system exceeds demand. In order to identify systems that are not necessary for the operation of the BES
under this test, we propose that any system where real power flows into the local distribution system 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should be held to
meet this test. That a system meets this test could be demonstrated using metering or supervisory control
and data acquisition ("SCADA") data records over the course on two years.
In addition, the presence of generation within a local distribution system that only modifies the level of the
load served by the bulk system, but does not result in power being injection into the bulk system, does not
change the reliability effect of the local network and therefore should not require the local network to be
classified as BES.

New York Power Authority

Yes

NYPA generally agrees with this item. However, the term “system” needs to be better defined.
It is not clear how power could flow out of a load only system. If reversing power flows on a feeder caused it
to fail one of the criteria, could the radial still be excluded, or is it necessary for the Element to pass all
requirements? Alternatively, could the entity choose to file for Exclusion of that Element under the technical

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
analysis option?
What happens and what are the implications when the two approaches produce different outcomes?
An example of revised wording for “iv. The maximum amount of energy flowing out” would be no more than
24 hours of reverse power flows within any rolling 12-month period.
Consider avoiding prescribing values and eliminate bullet (iv). The intended performance outcome should be
described, but without setting values. This should not have any impact on the reliability of the transmission
network if items 1, 2 and 3 are satisfied.

New York State Reliability
Council

Yes

It should be clarified that this exclusion should not apply to inter-regional transfers, which clearly are
candidates for inclusion as BES.

Western Electricity Coordinating
Council

Yes

WECC agrees in concept with this characteristic, but it needs to be clarified whether the items i-v are “AND”
statements
WECC also suggests that i and ii be switched and re-worded. Suggested language for ii would be “A limited
set of conditions where power flows out must be identified; for example, only under specified Contingency
events.” Then i can become a sub-bullet of ii. It must also be clarified that the specified conditions must have
a technical justification to show that the element is not “necessary for reliable operation.” Otherwise it is not
clear that the “limited conditions” are truly a justification for exclusion.
Any non-zero MWh limit must have a technical justification, otherwise zero should be used. In addition to the
imports/exports from the system, the size of the system (in MW) should also be defined.

Bonneville Power Administration

Yes

BPA generally agrees with the power flow concept, but suggests including language that the assessment
should be “based on normal system operating conditions.”
A MWh value to replace ‘TBD’ for maximum energy flowing out per year could be determined based on on an
annual average MW load level of 25 MW average and below with distribution service of 50MVA and below,
because 25MW loads can be served by lines under 100kv. The energy flowing out per year would be limited
by the size of the load and the ability to import power to the load area (i.e. the export would never be larger
than the initial distribution service minus the local area losses and load).
BPA requests that the drafting team perform a cross-walk analysis on each of the 4 items to ensure the
consistent application of an existing industry process, practice, or standard.

Tri-State Generation and

Yes

It may be more appropriate to use a threshold based on maximum power rather than on an annual energy

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Transmission Association

Question 3 Comment
threshold.

Electric Market Policy

Yes

Harney Electric Cooperative, Inc.

Yes

Oncor Electric Delivery

Yes

Southern Company

Yes

Occidental Energy Ventures
Corp.

Yes

Consumers Energy Company

Yes

The word rarely should be struck from this item. It is meaningless in the context for which it is used and offers
little to characterize an element or connection since it does not contain a measure.

Oncor Electric Delivery agrees with the proposed language that describes the exclusion criteria based upon
power flows.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the
magnitude, direction and time duration of power flow on a system Element as qualifying criterion. Based on industry response and further analysis, the SDT has
abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered
in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s
characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in
operational characteristics. The new process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance
as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the
request and recommendation with the ERO as established in the Rules of Procedure as presently being drafted.
Edison Electric Institute

Yes

Although EEI agrees in principle to the exclusion, we feel the current language has some problems which
need to be addresses. Note the following:The word “rarely should be struck. It is meaningless in the context
for which it is used and offers little to characterize an element or connection since it does not contain a
measure. A more appropriate statement to broadly characterize a Non-BES element or connection would be
the following:”Power flows are broadly characterized as Load Serving.”
Items i. and iii. are excessive requirements which do not aide in defining what is “necessary for operating an
interconnected electric transmission network”. What might be more a more useful measure is a comparison
of total MW hours of load consumed vs. MW hours fed back into the BES as measured on an annual

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
basis.Item v. - Hourly energy data (MWh) for the most recent 12 month period for every excluded BES
element is an excessive requirement. Annual records indicating that MW hours consumed annually verses
MW hours that flow through the non-BES element would be a better indicator in line with the definition.

SERC Planning Standards
Subcommittee

Yes

Tennessee Valley Authority

One possible starting point for selecting a MWh threshold: Generators of 20 MVA or less are typically exempt
from detailed modeling requirements. Suggest that reverse flows of this level or less, for a period of 24 hours
or less would be an acceptable threshold. Therefore, this would provide a basis for selecting a threshold
MWh level for reverse flows into the system under part iv. of 20 MW x 24 hours = 480 MWh per year.

Response: The SDT appreciates your comments and your suggestions for the amount of power flow allowed to still be eligible for an exclusion. However, based
on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the
technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The
initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to
establish continent-wide values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of
the facilities in question and to document the operational performance as appropriate through submittal of an exception request form along with any other
supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a
recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of
Procedure as presently being drafted.
PPL Supply

No

See comments in Questions 9 and 10

City of Redding

Yes

To be consistent with E2 of the proposed BES Definition a distribution system should be allowed to export at
least 75 mw. This would be the same as a commercial retail customer can export into the distribution system.

Electricity Consumers Resource
Council (ELCON)

Yes

The thresholds for power flows out of the system should be made consistent with Exclusion E2 in the
definition.We recommend that this item be added to the BES definition.

Response: See responses to Q9 & Q10.

Response: The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.
South Carolina Electric and Gas
Georgia Transmission
Corporation

Yes

One possible starting point for selecting a MWh threshold: Generators of 20 MVA or less are typically exempt
from detailed modeling requirements.
Suggest that reverse flows of this level or less, for a period of 24 hours or less would be an acceptable
threshold. Therefore, this would provide a basis for selecting a threshold MWh level for reverse flows into the

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
system under part iv. of 20 MW x 24 hours = 480 MWh per year

Long Island Power Authority

Yes

Item iv. The maximum amount of energy flowing out is (TBD-1,752,000) MWh per year.
Another measure that may be more appropriate is a percent % of total energy requirements in the area.

Xcel Energy

Yes

Regarding the question on MWH, one possible approach is to use 175,000 MWH/ year which would be just
under the annual hourly output from the smallest generator (not at a plant) that must be registered under the
registry criteria.

Tacoma Power

Yes

Tacoma Power generally agrees that elements primarily serving load, allowing a limited flow out of the local
distribution network, should be excluded from the BES.
We support an annual limitation of 219,000 MWhs, equivalent to 25 aMW, since a system of elements that
primarily serve load under this limit are insignificant to the BES.

PacifiCorp

Yes

All of PacifiCorp’s responses are based on the application of these items to a given interconnection and not
on a continental basis. See comments on question 10. This criterion is very similar to a part of exclusion 3 of
the proposed bright-line, which requires that power flows into the system. If the intent of this requirement is to
capture local distribution networks that may be included under the proposed bright-line definition, then this
requirement has merit. PacifiCorp proposes that instead of using a measure of energy, that the SDT utilize a
measure of time and recommends that flow out of the system be limited to 15% on an annual basis.
PacifiCorp does not have a technical justification for 15%, nor does it believe that a technical justification can
be provided for any reasonable percent of time used, or MWh used to be applied equally to all
interconnections.

Response: The SDT appreciates your comments and your suggestions to fill in some of the gaps in the first posting. However, based on industry response and
further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational
characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was
dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of the facilities in question
and to document the operational performance as appropriate through submittal of an exception request form along with any other supporting documentation for
the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support
the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as presently being drafted.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

4. Exclusions - The SDT has set up one path for evidence that does not include extensive technical
analysis. It consists of 4 items, all of which must be addressed in order to submit a completed
request for exclusion. The fourth item involves power transport. Do you agree with this requirement?
If you do not support this requirement or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an
entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as
presently being drafted.

Organization
SERC Planning Standards
Subcommittee

Yes or No
No

Tennessee Valley Authority

Question 4 Comment
There is not sufficient evidence provided by the SDT to distinguish between this fourth item for exclusion and
the third item for exclusion. They both seem to fall in line with what is excluded per the bright line exclusion
E3 (or Local Distribution Networks), but as written, it would be difficult to measure what is meant by “is not
intentionally transported through” in this fourth item just as it would be difficult to measure what’s meant by
“flows into the system, but rarely flows out” for the third item.
Such an exclusion should be required to include some technical analysis, but not extensive technical analysis
(at least the inclusion of power flow base case as a minimum).

SPP Standards Review Group

No

It may be better to focus on the purpose, or need, of a facility, the functionality of the facility, rather than how
electric flows impacted the facility during a given situation. Therefore, we would suggest moving away from
the term ‘intent’.

NERC Staff Technical Review

No

Limitations on through-flow of power is an appropriate consideration; however, whether the power flow is
intentional should not be a primary consideration. Intent is not measurable and most major disturbances are
the result of unintentionally placing the system in an unreliable operating condition. The main clause in item

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment
(d) should be modified to reflect that transporting power to another system through the Element(s) to be
excluded is prevented (such as by system configuration and/or impedance) or restricted (such as by
Operating Procedures). Sub-items (i) and (ii) already are consistent with this revision to the main clause.

ISO/RTO Standards Review
Committee

No

Hasn’t the reliability concern associated with “loop flows” been related to the unintentional flow of power
through parts of the system?

Iberdrola USA

No

We do not agree with this requirement. These exclusion exception criteria should be deleted in their entirety
and replaced with criteria that are objective, specific, and repeatable, or preferably not replaced at all.
Specific problems with the criteria as stated are: 1. A facility is not BES if all of “a” through “d” below apply:
d. Power “entering” “the system” does not “intentionally” flow into another “system” - what does intentionally
versus unintentionally mean?

MRO's NERC Standards Review
Forum

No

NSRF proposes that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the BES definition.

MidAmerican Energy

No

MidAmerican support the NSRF comments. The NSRF proposes that this criterion be eliminated because it
does not describe any materially different characteristics beyond Exclusion E3 of the BES definition.

ReliabilityFirst

No

no one knows when some event will occur, putting this limitation will only cause debate. Any impact is an
impact and should be included

Idaho Falls Power

No

We generally agree with this requirement. If a system has redundant transmission to move power that is
normally wheeled through, the question of materiality could be addressed by technical analysis.

Southern Company

No

National Grid

No

Muscatine Power and Water

We feel that this requirement is not specific enough. “System” is too general. It should be clear what is
intended by “system”. Also, we would like more clarification about what is meant by “intentionally transport”.
Is the intent to mean there is a contract between a generator and load?
The exception process should be strictly limited to the procedures for application and approval and should not
include substantive elements.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization
South Carolina Electric and Gas

Yes or No

Question 4 Comment

No

There is not sufficient evidence provided by the SDT to distinguish between this fourth item for exclusion and
the third item for exclusion. They both seem to fall in line with what is excluded per the bright line exclusion
E3 (or Local Distribution Networks), but as written, it would be difficult to measure what is meant by “is not
intentionally transported through” in this fourth item just as it would be difficult to measure what’s meant by
“flows into the system, but rarely flows out” for the third item.
Such an exclusion should be required to include some technical analysis, but not extensive technical analysis
(at least the inclusion of power flow base case as a minimum).

Glacier Electric Cooperative

No

I believe that there should be a provision for systems that intentionally transport variable, non-essential
generation (such as systems that transport wind power) to be excluded from the BES. By nature, these types
of systems cannot be essential to the BES due to the variability of the generation, and, therefore, should be
able to be excluded from the BES.

Springfield Utility Board

No

NERC’s Proposed Continent-wide Definition of Bulk Electric System contains Exclusion E3 (LDNs) as part of
the BES core definition. Why would this fourth item be necessary in demonstrating BES Exceptions if LDNs
are already excluded as part of NERC’s core BES definition?

ISO New England

No

This appears to be the same as section 1.c and again possibly allows for the exclusion of large portions of the
system in metropolitan areas. Section 1.d. should simply be deleted.

The United Illuminating Company

No

The wording is ambiguous. What is meant by system?
Different voltage levels, Owners?

Entergy Services

No

There is not sufficient evidence provided by the SDT to distinguish between this fourth item for exclusion and
the third item for exclusion. They both seem to fall in line with what is excluded per the bright line exclusion
E3 (or Local Distribution Networks), but as written, it would be difficult to measure what is meant by “is not
intentionally transported through” in this fourth item just as it would be difficult to measure what’s meant by
“flows into the system, but rarely flows out” for the third item.
Such an exclusion should be required to include some technical analysis, but not extensive technical analysis
(at least the inclusion of power flow base case as a minimum).

Pepco Holdings Inc

No

This criterion is very similar to the third item. Written operating procedures may not exist. The entity should
be allowed to summit a description and justification.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment

Central Lincoln

No

Central Lincoln agrees that the SDT’s fourth test, which asks whether power is intentionally transported
through a system, identifies a key characteristic of local distribution facilities that distinguishes such facilities
from interconnect bulk transmission facilities that are properly considered part of the BES. In fact, we believe
this may be the most important and readily identifiable distinction. As a matter of operation, power is
scheduled across transmission lines. Further, transmission lines in the Western Interconnection (either
individually or as part of a transmission path) are rated for total transmission capacity and available
transmission capacity, and transmission rights can be purchased on such lines, if available, on an OASIS.
Local distribution systems do not share any of these operational characteristics. Accordingly, Central Lincoln
agrees that if power is not intentionally transported through a particular system, that system is not used for
transmission and should not be considered part of the BES.
We also agree that examining the Operating Procedures applicable to a particular system will provide a ready
guide to whether power is intentionally scheduled across that system.
We suggest, however, that the SDT look beyond those protocols that fall within the NERC Glossary’s
definition of Operating Procedure. For example, in the West, transmission paths are almost all listed in the
WECC Path Rating Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and
the other factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test.

Duke Energy

No

This fourth characteristic does not add clarity to the E3 Exclusion in the proposed BES definition. And in
general, the path that does not include extensive technical analysis is not adequate to distinguish between the
Elements that are and that are not necessary for operating an interconnected electric transmission network.

American Transmission
Company, LLC

No

ATC proposes that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the BES definition.

Manitoba Hydro

No

Vague language such as “rarely” or “not intentionally” does not support a “bright line” approach, and is not
measureable or auditable. Also, the sample evidence should not be included as part of the criteria.
In addition, the proposed criteria to substantiate a request for an exception should be removed as it does not
introduce anything different than what is already proposed under the exclusions in the bright line BES
definition. Specifically, this item is already excluded in the bright line definition E3.

NESCOE

No

As noted in Response 1, NESCOE believes exclusion determinations should not require a finding that all four
proposed criteria are met. NESCOE further notes that New England’s network has numerous parallel paths
operated at voltages less than 200 kV which may parallel 230 kV and 345 kV BES network paths. If flows on

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment
a given <200 kV path only exceed 200 MVA under contingency conditions and if these paths are connected to
the higher voltage BES elements with suitable NERC compliant protection systems, these paths may be
EXCLUDED from the BES. NESCOE suggests the value of 200 MVA based on typical thermal ratings of 115
kV transmission lines but is open to other values that the drafting team may suggest. NESCOE also
suggests that the phrase “to some other system” be broadened to include any other higher voltage BES
element.

City of Redding

Yes

The SDT needs to address renewable energy and customer owned generation. If an aggregator adds up one
thousand roof top PV units or the power from plugged in electric cars and sells them to an entity outside of
this system it should not affect the ability of the distribution system to qualify for this exclusion, especially if
the power is consumed inside of the distribution system.

Blachly Lane Electric Cooperative

Yes

Central Electric Cooperative

As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in the
Western Interconnection (either individually or as part of a transmission path) are rated for total transmission
capacity and available transmission capacity, and transmission rights can be purchased on such lines, if
available, on an OASIS. Facilities that do not share any of these operational characteristics should not be
part of the BES.

Clearwater Power Electric
Cooperative

Accordingly, we agree that if power is not intentionally transported through particular facilities, those facilities
should not be considered part of the BES.

Consumer's Power Inc.

We also agree that examining the Operating Procedures applicable to particular facilities will provide a ready
guide to whether power is intentionally scheduled across those facilities.

Flathead Electric Cooperative,
Inc.

Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative

We suggest, however, that the SDT look beyond those protocols that fall within the NERC Glossary’s
definition of Operating Procedure. For example, in the West, transmission paths are almost all listed in the
WECC Path Rating Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and
the other factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test.
Finally, as noted in our answer to Question 3, we are concerned that, if distributed generation advances
significantly, power transport may cease to be a meaningful measure for determining whether a facility is part
of the BES, and we believe that power flow analysis should consider actual power flow, not scheduled power
flow.

Okanogan Electric Cooperative
Raft River Rural Electric

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment

Clark Public Utilities

Yes

Clark agrees that the SDT’s fourth test, which asks whether power is intentionally transported through a
system, identifies a key characteristic of local distribution facilities that distinguishes such facilities from
interconnect bulk transmission facilities that are properly considered part of the BES. Clark believes this may
be the most important and readily identifiable distinction. Accordingly, Clark agrees that if power is not
intentionally transported through a particular system, that system is not used for transmission and should not
be considered part of the BES.

BGE

Yes

BGE generally agrees with this requirement, but believes that the term “system” should be clarified.

Benton Rural Electric Association

Yes

Benton REA agrees that the SDT’s fourth test, which asks whether power is intentionally transported through
a system, identifies a key characteristic of local distribution facilities that distinguishes such facilities from
interconnect bulk transmission facilities that are properly considered part of the BES. In fact, we believe this
may be the most important and readily identifiable distinction.

Cooperative
Salmon River Electric
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc

Northern Wasco County PUD
United Electric Co-op Inc.
Oregon Trail Electric
Salem Electric
Grant County PUD No. 2 (Grant)

Accordingly, Benton REA agrees that if power is not intentionally transported through a particular system, that
system is not used for transmission and should not be considered part of the BES. One exception may be for
a small embedded generation unit owned by a different party that may be “scheduled” out of an area, but in
reality, does not produce any physical flow. These circumstances should not trigger inclusion.

Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc
Kootenai Electric Cooperative

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment

Long Island Power Authority

Yes

In addition to Operating Procedures, electrical elements that restrict or control flow over the line should be
allowed to be used as evidence.

Xcel Energy

Yes

It is not clear what ‘some other system’ would be. Is this another point on the BES in general?

for Snohomish County PUD

Yes

Snohomish agrees that the SDT’s fourth test, which asks whether power is intentionally transported through a
system, identifies a key characteristic of local distribution facilities that distinguishes such facilities from
interconnect bulk transmission facilities that are properly considered part of the BES. In fact, we believe this
may be the most important and readily identifiable distinction. As a matter of operation, power is scheduled
across transmission lines. Further, transmission lines in the Western Interconnection (either individually or as
part of a transmission path) are rated for total transmission capacity and available transmission capacity, and
transmission rights can be purchased on such lines, if available, on an OASIS. Local distribution systems do
not share any of these operational characteristics. Accordingly, Snohomish agrees that if power is not
intentionally transported through a particular system, that system is not used for transmission and should not
be considered part of the BES.
We also agree that examining the Operating Procedures applicable to a particular system will provide a ready
guide to whether power is intentionally scheduled across that system. We suggest, however, that the SDT
look beyond those protocols that fall within the NERC Glossary’s definition of Operating Procedure. For
example, in the West, transmission paths are almost all listed in the WECC Path Rating Catalog.
Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other factors listed above
qualify as Operating Procedures.
Hence, we urge the SDT to list such specific operational characteristics as part of this test.

Independent Electricity System
Operator

Yes

There is an inconsistency between the language used in bullet (c) - “rarely flows out”, and that used in
Exclusion E3(c) of the BES definition - “Power flows only into the LDN”. We have commented during the BES
Definition comment period that Exclusion E3 needs to be modified to match the Exception Principles.
We agree with the criteria set out in 1(c) except for bullets (iv) and (v). We do not believe it is possible to
establish a limit on the energy flow out of a system for which an exception has been requested. Further, we
suggest that the SDT avoid prescribing set values in the exception criteria since these would only serve to
limit the flexibility of the process.
As an alternative to the proposed bullet (iv), we suggest that power flow study results could be used to
support the exception request. We therefore propose the following wording to replace bullets (iv) and (v).iv.
Power flow simulation results to demonstrate that BES reliability is not dependent upon the power flows

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment
through the Element(s) for which an exception has been submitted, for the conditions specified in (ii).

Tacoma Power

Yes

Tacoma Power generally agrees with fourth item (power transport) when not intentionally transporting power
through a system. In development of the supporting evidence for this item, we suggest a demonstration by
operating studies or the option to demonstrate the criteria by the use of operational procedures.

Tri-State Generation and
Transmission Association

Yes

While we generally agree, "system" needs to be clarified, and should be changed to "transmission system." It
may also need to be qualified by indicating a change in ownership of transmission systems.
We also wonder if the concept of scheduling should be addressed rather than using the word "intentionally?"

Florida Municipal Power Agency

Yes

FMPA supports the criterion in concept, but “intention[]” is a vague term and not relevant to an Element’s
impact on the grid. We suggest instead that to obtain an exclusion for such a quasi-radial Element, the owner
be required to demonstrate that the Element has no more than a 5% transfer distribution factor on any BES
Element for transfers that could be curtailed through the NAESB TLR procedure (e.g., interchange
transactions, or generator to load distribution factors (GLDF) for BES generators). Transfer distribution factor
(or GLDF) is a good measure of an Element’s impact on the grid and is not subject to varying interpretations.
In addition, NAESB standards are also approved by FERC and mandatory to jurisdictional entities. Hence, the
5% TDF “Curtailment Threshold” has already been approved by FERC as indicating an insufficient impact on
the BES to be considered for TLR. And, it shows consistency between NERC and NEASB standards.

Transmission Access Policy
Study Group

Yes

TAPS supports the criterion in concept, but “intention[]” is a vague term and not relevant to an Element’s
impact on the grid. We suggest instead that to obtain an exclusion for such a quasi-radial Element, the owner
be required to demonstrate that energy transfers subject to NAESB TLR procedures (Interchange
Transactions or BES generator to load) have no more than a 5% transfer distribution factor (TDF) on the
Element that is a candidate for exception. Transfer distribution factor is a good measure of an Element’s
impact on the grid and is not subject to varying interpretations.

Edison Electric Institute

Yes

A radial system by definition transports power from the BES System to a Distribution System, similarly an
LDN operates in a like manner. A strict reading of the above criteria would exclude both from consideration
yet the definition allows both. We believe that in an attempt to develop a set of criteria useful for all situations,
the outcome has weakened the original intent as set in the Definition. Although much of the criteria used is
largely appropriate, a stricter adherence to the BES definition criteria would substantially help to avoid
confusion between what was developed as principles and what was developed as the BES Definition.

Bonneville Power Administration

Yes

BPA suggests that the SDT provide a method for assessing power transport based on intake to serve load

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Organization

Yes or No

Question 4 Comment
versus outflow. BPA requests that the SDT clarify that the qualifying statements i-v for the fourth item are “or”
statements.

PacifiCorp

Yes

All of PacifiCorp’s responses are based on the application of these items to a given interconnection and not
on a continental basis. See comments on question 10. This criterion is very similar to parts of exclusion 3 of
the proposed bright-line, which states “d) Not used to transfer bulk power: The LDN is not used to transfer
energy originating outside the LDN for delivery through the LDN; and e) Not part of a Flowgate or transfer
path: The LDN does not contain a monitored Facility of a permanent flowgate in the Eastern Interconnection,
a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable
monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).”If the intent of this requirement is to capture local
distribution networks that may be included under the proposed bright-line definition, then this requirement has
merit.

Western Electricity Coordinating
Council

Yes

WECC agrees in concept with this characteristic, but believes that there needs to be more clarity of what
constitutes the evidence. Since flow data is used for characteristic c, it seems that the same sort of data (but
separated into hourly flow in and hourly flow out) could be used to demonstrate this. Otherwise, a simple
procedure that claims “power entering this system is not intentionally transported through the system to some
other system” would meet the letter of the law, but gives no description of how this is achieved. If Operating
Procedures are allowed, more clarity must be provided on what those procedures must entail.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the
unintentional transporting of power through a system Element with delivery to another system Element as qualifying criterion. Based on industry response and
further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational
characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was
dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of the facilities in question
and to document the operational performance as appropriate through submittal of an exception request form along with any other supporting documentation for
the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support
the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as presently being drafted.
Electricity Consumers Resource
Council (ELCON)

Yes

This requirement should be further relaxed to allow for intentional flows that are provided as a courtesy to the
local distribution company. In such cases, private, customer-owned facilities may be used to deliver power
from a DP to a small number of the DP's retail customers who are unaffiliated with the owner/operator of the
private network. These flows are generally de minimis.

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Organization

Yes or No

Question 4 Comment
We also recommend that this item (with our qualification) be added to the BES definition.

Oregon Public Utility Commission
Staff

Yes

Use of the 100 kV brightline and the core BES definition as proposed is an overreach into local distribution
systems and an overreach of FERC’s authority as set out in the FPA 215. A full engineering technical
analysis - required every 2 years - is too onerous and not necessary for identifying most local distribution
elements miss-identified as BES Elements. A simple screening methodology consistent with the 7-Factor
Test (from FERC Order 888) is needed as the first stage of the exception process.

Response: The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.
The SDT appreciates your comments. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a
new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide greater
continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It
has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new process
requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to
validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO
as established in the Rules of Procedure as presently being drafted.
Georgia System Operations
Corporation

The concept of “intentional” transport of power is vague and needs more specificity for this to be clear.
Also, it would help to have more information about the sort of “operational procedures” that would be
acceptable as evidence.

Response: The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.
PPL Supply

No

See comments in Questions 9 and 10

Response: See response to Q9 & Q10.
Harney Electric Cooperative, Inc.

Yes

Hydro-Quebec TransEnergie

Yes

Oncor Electric Delivery

Yes

Oncor Electric Delivery agrees with the proposed language that describes the exclusion criteria based upon
the non - intentional flow of power through the system to some other system.

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Organization

Yes or No

Consumers Energy Company

Yes

American Electric Power

Yes

Orange and Rockland Utilities,
Inc.

Yes

Spyker

Yes

Occidental Energy Ventures
Corp.

Yes

Consolidated Edison Co. of NY,
Inc.

Yes

New York Power Authority

Yes

New York State Reliability
Council

Yes

Hydro One

Yes

Electric Market Policy

Yes

Northeast Power Coordinating
Council

Yes

ACES

Yes

Question 4 Comment

Requiring that “power entering the system is not intentionally transported through the system to some other
system” is a reasonable approach.

NYPA agrees that power flow wheeled through a system indicates that the system potentially has more than
one source. Therefore, the element in question is not radial.

We agree with this path.

Response: Thank you for your support. However, based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or

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Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment

limit. It has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new
process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of
an exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the
submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation
with the ERO as established in the Rules of Procedure as presently being drafted.

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5. Exclusions - The SDT has set up one path for evidence that includes technical analysis. Do you agree
with this requirement? If you do not support this requirement or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. In addition, in the comment field, please provide your thoughts on the proposed metrics
for analysis and the appropriate values to replace ‘TBD,’ including technical rationale for your
argument.
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion
criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be
considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The new process
requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as
appropriate through submittal of an exception request form along with any other supporting documentation for the exception
being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of
whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established
in the draft Rules of Procedure.

Organization

Yes or No

Northeast Power Coordinating
Council

No

SERC Planning Standards
Subcommittee

No

SPP Standards Review Group

No

NERC Staff Technical Review

No

Iberdrola USA

No

Tri-State Generation and
Transmission Association

No

Question 5 Comment

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Organization

Yes or No

Hydro One

No

MRO's NERC Standards Review
Forum

No

PacifiCorp

No

ReliabilityFirst

No

Tennessee Valley Authority

No

PPL Supply

No

Southern Company

No

Muscatine Power and Water

No

South Carolina Electric and Gas

No

Glacier Electric Cooperative

No

Exelon

No

Georgia Transmission
Corporation

No

Consolidated Edison Co. of NY,
Inc.

No

ISO New England

No

The United Illuminating Company

No

Question 5 Comment

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Organization

Yes or No

Entergy Services

No

Orange and Rockland Utilities,
Inc.

No

Pepco Holdings Inc

No

American Transmission
Company, LLC

No

Consumers Energy Company

No

Independent Electricity System
Operator

No

United Electric Co-op Inc.

Yes

Oregon Trail Electric
Cooperative, Inc.

Yes

Central Lincoln

Yes

Oncor Electric Delivery

Yes

Salem Electric

Yes

Duke Energy

Yes

Grant County PUD No. 2 (Grant)

Yes

Hydro-Quebec TransEnergie

Yes

for Snohomish County PUD

Yes

Question 5 Comment

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Organization

Yes or No

Northwest Public Power
Association (NWPPA)

Yes

Big Bend Electric Cooperative,
Inc.

Yes

NESCOE

Yes

Kootenai Electric Cooperative

Yes

Tacoma Power

Yes

MidAmerican Energy

Yes

Edison Electric Institute

Yes

Florida Municipal Power Agency

Yes

Transmission Access Policy
Study Group

Yes

ISO/RTO Standards Review
Committee

Yes

Western Electricity Coordinating
Council

Yes

New York State Reliability
Council

Yes

Electricity Consumers Resource
Council (ELCON)

Yes

New York Power Authority

Yes

Question 5 Comment

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Exceptions — Project 2010-17

Organization

Yes or No

Blachly Lane Electric Cooperative

Yes

Springfield Utility Board

Yes

Flathead Electric Cooperative,
Inc.

Yes

Clark Public Utilities

Yes

Central Electric Cooperative

Yes

Clearwater Power Electric
Cooperative

Yes

Consumer's Power Inc.

Yes

Coos-Curry Electric Cooperative

Yes

Douglas Electric Cooperative

Yes

Fall River Electric Cooperative

Yes

Lane Electric Cooperative

Yes

Lincoln Electric Cooperative

Yes

Lost River Electric Cooperative

Yes

Northern Lights Electric
Cooperative

Yes

Okanogan Electric Cooperative

Yes

Question 5 Comment

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Exceptions — Project 2010-17

Organization

Yes or No

Raft River Rural Electric
Cooperative

Yes

Salmon River Electric
Cooperative

Yes

West Oregon Electric
Cooperative

Yes

Pacific Northwest Generating
Cooperative

Yes

Umatilla Electric Cooperative

Yes

Consumer's Power Inc.

Yes

BGE

Yes

Spyker

Yes

Benton Rural Electric Association

Yes

American Electric Power

Yes

Northern Wasco County PUD

Yes

Xcel Energy

Yes

Question 5 Comment

Response: Thank you for your response.

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5a. Comments on approach:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion
criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be
considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The new process
requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as
appropriate through submittal of an exception request form along with any other supporting documentation for the exception
being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of
whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established
in the draft Rules of Procedure.

Organization
Northeast Power Coordinating
Council

Yes or No

Question 5a Comment
This method may allow an entity to exclude Elements which perform a transmission function, but that are not
the most limiting Element. “
Not being necessary for reliability operation” needs definition.
The SDT should consider developing a Guidance Document to provide examples and insights to guide
prospective filing entities.
The TPL Reliability Standards already describe the full set of requirements for a reliable system. Why are
added requirements necessary? Why would any such added criteria not conflict with the TPL Reliability
Standards to the extent that they were either more or less restrictive?
Entities should be given an option to conduct an analysis to demonstrate if an element is necessary for the
operation of a transmission network. NERC should specify all the relevant criteria categories to be listed as
under 2 (a). NERC should avoid prescribing numerical values, but instead establish a range of values (or
reference industry standards) that would be consistent with industry/ regional standards or practices without
compromising the reliability of the transmission network.

SERC Planning Standards
Subcommittee
Tennessee Valley Authority
Southern Company

As written, most of this approach makes no sense. The words imply that if you have planned the system
properly, you can exclude it from the BES! In TPL studies you make sure that voltage dips, frequency
excursions, voltage deviations are acceptable, oscillations are damped, and no cascading outages occur. So
if you meet the performance requirements of TPL studies, you can exclude the element from the BES. What
good is this?

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Organization

Yes or No

Question 5a Comment

Georgia Transmission
Corporation
City of Redding

It appears the industry experts have a very difficult time identifying any set of measurement factors that can
be applied on a consistant basis to any system and produce similar results, therefore there needs to be
geographical variation where the experts in the local systems can make a determination.

NERC Staff Technical Review

NERC staff is not opposed to development of evidence based on technical analysis; however, the type of
analysis included in this exception criterion requires extensive resources and lacks sufficient detail to allow for
consistent and repeatable application. Concerns with this approach include (1) the ability to provide sufficient
guidance on the system conditions and contingencies necessary to support an exception request,
(2) difficulty with identifying thresholds for items iv-1 through iv-4, and
(3) the ability to address interdependencies among exception requests.
These concerns can be addressed by deleting this second path for evidence and including technical analysis
on a limited basis to assess performance as described in our response to Question 2. If the SDT elects to
retain this second path for evidence, then our three concerns must be addressed. In particular with regard to
our third concern, the ERO must be able to deny requests for exception based on the cumulative impact of all
previously approved exceptions.

ACES

Overall, the approach is reasonable. However, we disgree with 2.b which states that the ERO can override
the criteria. Once criteria is established, the ERO should not be able to override the determination. The
ability of the ERO to override implies the criteria is not sufficient and needs to be modified. Rather than
override, the ERO should seek to modify the criteria if it is not sufficient.

Edison Electric Institute

In general, we agree that an alternative path allowing a technical analysis to demonstrate that a Facility (or
Element) should not be considered part of the BES is appropriate. However, we disagree with the measures
offered and suggest an alignment with efforts already being developed within NERC’s Event Analysis Working
Group.EEI proposes that the technical analysis criterion which has been proposed is too complicated,
inconsistent with what is currently being done across the regions and submits that a better approach would be
to align reliability impacts with the Event Analysis Criteria being developed by NERC’s EAWG.
These criteria would be a better benchmark as to whether a Facility or Element should be excluded from the
BES. The proposed alternate criteria are as follows:(1) The loss of the Facility (or Element) would not
interfere or negatively impact the BES from staying within acceptable limits (i.e., frequency, voltage and

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Organization

Yes or No

Question 5a Comment
System Operating limits) following a fault on or loss of that Facility (or Element);
(2) The loss of the Facility (or Element) would not interfere or negatively impact the BES from performing
acceptably after credible contingences;
(3) Facility (or Element) faults, failures, or trips do not push the system to a point of Instability or otherwise
initiate cascading outages;
(4) BES facilities are protected from unacceptable damage by operating the Facility (or Element) within its
ratings; and
(5) The unexpected loss of the Facility (or Element) does not negatively impact the BES from achieving its
mission of to supply the aggregate electric power and energy requirements of its customers.

Florida Municipal Power Agency

FMPA supports including specific technical criteria that Elements must meet to obtain an exclusion through
the exception process. This approach will facilitate uniform application of the exception process. FMPA
responds to the first five proposed criteria in response to 5b-5e below. In the sixth proposed criterion, “steady
state stability” is ambiguous, does the SDT mean voltage stability, power angle curve stability, or small signal
stability?
The seventh proposed criterion, “No cascading outages,” is insufficiently granular and should be discarded.
The criteria are intended to measure whether, among other things, a particular Element can cause a
cascading outage. They need to set out how decision-makers will determine whether an Element can cause
a cascading outage, not simply state that an Element that can cause a cascading outage cannot be excluded
from the BES.

Transmission Access Policy
Study Group

TAPS supports including specific technical criteria that Elements must meet to obtain an exclusion through
the exception process. This approach will facilitate uniform application of the exception process. TAPS
responds to the first five proposed criteria in response to 5b-5e below. The seventh proposed criterion, “No
cascading outages,” is insufficiently granular and should be discarded. The criteria are intended to measure
whether, among other things, a particular Element can cause a cascading outage. They need to set out how
decision-makers will determine whether an Element can cause a cascading outage, not simply state that an
Element that can cause a cascading outage cannot be excluded from the BES.

ISO/RTO Standards Review
Committee

Predictive analysis of an accurate model is useful in determining the importance of various elements of the
system.

Iberdrola USA

A facility is not BES if it is not necessary for reliable system operation, based on a TPL-type analysis similar to

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Organization

Yes or No

Question 5a Comment
NPCC Document A-10 “Classification of Bulk Power System Elements” - this type of analysis was rejected by
FERC. Besides, at 115kV, calculated distribution factors for interfaces between areas (where higher voltage
lines, e.g., at 230kV and 345kV, are included as part of the interface definition) tend to be small and
inaccurate. The method used to calculate distribution factors is an approximate method which must be reevaluated for small values of distribution factors.

Tri-State Generation and
Transmission Association

This appears very similar to the “material impact” proposal that FERC has previously disallowed, so we
recommend removing 2.
If retained, remove 2.(b) because allowing the ERO to override the technical justification and analysis
devalues such analysis to the point of it being meaningless.

Hydro One

We agree that entities should be given an option to conduct an analysis to demonstrate whether or not an
element is necessary for the operation of the transmission network.
We also support that NERC should specify the entire relevant criteria category to be listed under exclusion
criteria 2 (a). However, we suggest that NERC should avoid prescribing numerical values but establish a
range of value (or reference industry standard) that would be consistent with industry/ regional standards or
practices without compromising the reliability of the transmission network.

MRO's NERC Standards Review
Forum

NSRF proposes that this technical analysis criterion be replaced by criteria that are more closely tied to the
Adequate Level of Reliability (ALR) characteristics.
The following alternate criteria are offered as possible examples, “(1) the BES can be controlled to stay within
acceptable limits following a fault on or loss of the Element; (2) the BES performs acceptably after credible
contingences of the Element; (3) the Element does not limit the impact and scope of instability and cascading
outages when they occur; (4) BES facilities are protected from unacceptable damage by operating the
Element within its ratings; (5) the integrity of the BES can be restored promptly following a fault on or loss of
the Element; and (6) the BES has the ability to supply the aggregate electric power and energy requirements
of the electricity consumers at all times, taking into account scheduled or reasonably expected unscheduled
outages of the Element.
In addition, NSRF is not aware of any continent-wide appropriate BES performance measures for voltage dip,
frequency excursion, voltage deviation, stability, etc. and NSRF speculates that different values are likely for
different regions and system characteristics across the continent. As a result, NSRF believes it is not
advisable to try to adopt unproven values without reasonable industry investigation and development.

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Organization
Bonneville Power Administration

Yes or No

Question 5a Comment
BPA comments on the technical analysis are as follows:1. Who is responsible for running these studies (the
BA, individual utilities....?)
.2. The analysis and criteria need to be better defined for the technical analysis.
3. What did SDT mean by “having a distribution factor of TBD% for any other Element”? This should
probably reference a specific PTDF for a path or source/sink group.
4. What contingencies are studied to show the elements meet the transient voltage dip, frequency excursion,
etc. (i.e. are they 3 phase delayed cleared faults, single phase faults, etc.)? Furthermore, the exclusion
criteria needs to be much more specific about how the study is to be conducted in general - i.e.: Regional
Entities have established study guidelines and procedures to determine voltage and frequency criteria.
Specifically, is it the intent that the element being proposed for exclusion be opened in the study and then the
standard contingency list applied to the rest of the system? Presumably, if there is no difference in system
performance with the element in or out, then it could be excluded. Alternatively, is it intended that the
contingency to be tested is simply the loss of the element proposed for exclusion?
5. What elements and/or flow gates should be monitored for these analyses?
6. In “Other”, the SDT should add “The limiting element for a flow-gate cannot be excluded from the BES”.
7. How will the criteria be set? Will they follow current standards? (i.e. TPL-001)? The technical principles
must identify what category(ies) of TPL studies must be run. BPA requests clarification on what the values for
the threshold criteria and/or disturbances would be?

PacifiCorp

5a. Comments on approach: All of PacifiCorp’s responses are based on a given interconnection and not on a
continental basis. See comments on question 10. Using any technical criteria will allow many elements to be
excluded from the BES regardless of the element’s criticality to the interconnected system.
Whatever technical criteria is established should only be applied to elements under 200 kV and any radial
elements above 200 kV

ReliabilityFirst

to complicated and will only raise debate between FERC, NERC, the Regions and the Registered Entities

Western Electricity Coordinating
Council

WECC agrees in concept that a technical analysis can be used and should be allowed to show that an
element is not necessary for reliable operation. However, the technical analysis must be based on sound
reasoning and a justification must be given as to why the analysis makes a showing that the element is not
necessary for reliable operation. Furthermore, the technical principles must identify what category(ies) of TPL

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Organization

Yes or No

Question 5a Comment
studies must be run.
Finally, the values used for the threshold criteria and/or disturbances must be more stringent than the
applicable TPL criteria/disturbances. Otherwise the argument becomes circular because all BES elements
must meet the TPL criteria, so by meeting them all elements could be excluded.

New York State Reliability
Council

A single threshold value for performance based testing does not recognize differences in regional system
characteristics. Therefore, regional approaches for at least generation exclusions should be used, like
NPCC's A-10 criterion.

National Grid

We do not agree with all the criteria listed in point 2.a.iv. For example we believe that the term in 2.a.vi.6
“Steady-state Stability - positively damped” does not relate to the concept of steady-state stability. We
believe an acceptable measure of steady-state stability would be an angle difference across the transmission
line. That difference can vary depending on the line; however, a rule of thumb is typically 45 degrees which
provides a 30% steady state stability margin. As mentioned previously, the exception process should be
strictly limited to the procedures for application and approval and should not include substantive elements.

Muscatine Power and Water

Would like to propose that this technical analysis criterion be changed to criteria that are more closely tied to
the Adequate Level of Reliability (ALR) characteristics.
Would like to offer the following alternate criteria as possible examples, “(1) the BES can be controlled to stay
within acceptable limits following a fault on or loss of the Element;
(2) the BES performs acceptably subsequent to credible contingences of the Element;
(3) the Element does not limit the impact and scope of instability and cascading outages once they occur;
(4) BES Facilities are protected from undesirable damage by operating the Element within its ratings;
(5) the reliability of the BES can be restored promptly subsequent to a fault on or loss of the Element; and
(6) the BES has the ability to supply the aggregate electric power and energy requirements of the electricity
consumers at all times, taking into account scheduled or reasonably expected unscheduled outages of the
Element.
Currently not aware of any continent-wide appropriate BES performance metrics for voltage dip, frequency
excursion, voltage deviation, stability, etc. and would speculate that different values are likely for the different
regions and system characteristics across the continent. Thus, it is not advisable to try to adopt unproven
values without reasonable industry investigation and development.

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Organization
Blachly Lane Electric Cooperative
Flathead Electric Cooperative,
Inc
United Electric Co-op Inc.
Oregon Trail Electric
Cooperative, Inc.
Central Lincoln
Salem Electric
Grant County PUD No. 2 (Grant)
for Snohomish County PUD
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc.

Yes or No

Question 5a Comment
We agree conceptually with the idea that two different paths to exclusion should be adopted, one relying upon
readily identifiable characteristics that are ordinarily associated with non-BES transmission facilities, and one
relying on technical analysis to determine whether or not an Element or group of Elements has a measurable
impact on the threat of cascading outages, separation events, or instability on the interconnected bulk system.
If technical analysis demonstrates that Elements create no material threat of such reliability events, they
should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based approach to
support the technical determination whether Elements should be excluded from the BES, which we commend
to the SDT for study.
We also commend the work of the WECC BES Task Force and the WECC Technical Studies Subcommittee,
both of which have devoted substantial time and resources to developing a workable and technically
defensible process for excluding Elements classified as BES based upon their electrical characteristics. See
WECC BES Task Force Proposal 6, App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011)
(available at: http://www.wecc.biz/Standards/Development/BES/default.aspx).
We recommend that the SDT modify its approach to the technical exclusion process to match the approach
advocated in Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES
Task Force.

Kootenai Electric Cooperative

South Carolina Electric and Gas

As written, most of this approach makes no sense. The words imply that if you have planned the system
properly, you can exclude it from the BES! In TPL studies you make sure that voltage dips, frequency
excursions, voltage deviations are acceptable, oscillations are damped, and no cascading outages occur. So
if you meet the performance requirements of TPL studies, you can exclude the element from the BES. This
does not seem to be what was intended.

Glacier Electric Cooperative

I strongly agree that there should be a way for elements to be excluded from the BES based on a technical
analysis. However, the current approach only provides one technical avenue for exclusion and that is through
a transmission planning study. Performing and analyzing such a study could be very, very difficult for a small
entity to do. If this is the approach that NERC continues with, then I believe there needs to be some extra
language outlining who is responsible for performing and analyzing these transmission planning studies. The
question is should the RRO (WECC, etc.) be responsible for performing the study and determining through
the technical criteria what elements are included and excluded in the BES, or should that resposiblity fall on

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Organization

Yes or No

Question 5a Comment
control area operators within an RRO, or should that responsibility fall on individual entities? I believe it
should fall on either the RROs or the control area operators within the RROs.
Perhaps an alternative approach could be to establish a few techincal checks that could be evaluated first
before a transmission planning study is required. For example, a max fault MVA value could be established
and if the available fault MVA at an element is less than the established value, then that element and could be
excluded without having to go through a transmission planning study. If the available fault MVA at the
element is above the established value, then the study would have to be done for determination.

Exelon

This item calls for the use of criteria in order to prove that a facility should be excluded the BES. First of all,
the items 5b - 5e do indeed require extensive technical analysis which will be outside of the capabilities of
many users of the BES.
Furthermore, it is not clear who’s criteria will be used? The user’s? The Transmission Owner’s? The Planning
Authority’s? This question of ownership needs to be resolved and in itself poses a problem for this process.
If differing criteria levels are used across the continent, there remains the possibility that similarly-situated
facilities in different Regions will not be treated consistently.

Consolidated Edison Co. of NY,
Inc.

The technical analysis approach may have merit. However, we have a number of questions about how it
would be implemented in practice. We are concerned that this method may allow an entity to exclude
Elements simply because they are not the most limiting Element in a particular TPL analysis. What does “not
being necessary for reliability operation” mean? Please define.
The SDT should consider developing a Guidance Document to provide examples and insights to guide
prospective filing entities.
The TPL Reliability Standards already describe the full set of requirements for a reliable system. Why are
added requirements necessary? Why would any such added criteria not conflict with the TPL Reliability
Standards to the extent that they were either more or less restrictive?

ISO New England

The use of distribution factors is a significant concern. The term distribution factor is used a number of ways
in the industry. Is this determined using the percentage pickup on the element in question following the loss
of another element, or is this the percentage of a transfer that is picked up on the element in question, or a
combination of both?
Item 2.a.ii states that the TPL studies have to be run if the model is updated. The distribution factor is not
required to be calculated as part of the TPLs and therefore will require additional analysis in all
circumstances, not just when the model is updated.

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Question 5a Comment

The United Illuminating Company

This is not very different from trying to demonstrate no adverse impact outide the local area.

Georgia System Operations
Corporation

It would be helpful to specify which TPL Standard(s) the referenced studies are usually prescribed for.

Entergy Services

The entire approach seems overly complex and difficult to document.

Clark Public Utilities

Clark agrees conceptually with the idea that two different paths to exclusion should be adopted, one relying
upon readily identifiable characteristics that are ordinarily associated with local distribution and not BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element or group
of Elements has a measurable impact on the threat of cascading outages, separation events, or instability on
the interconnected bulk system. If technical analysis demonstrates that Elements create no material threat of
such reliability events, they should properly be excluded from the BES.

Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc.
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative

Clark supports the technical arguments and the White Paper presented by Snohomish County PUD in their
comments. Clark recommends that the SDT modify its approach to the technical exclusion process to match
the approach advocated in the White Paper, which is based upon the approach recommended by the WECC
BES Task Force.

Lane Electric Cooperative
Lincoln Electric Cooperative
Lost Rive Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric

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Yes or No

Question 5a Comment

Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc
Benton Rural Electric Association
Northern Wasco County PUD

BGE

BGE believes that there is value in allowing for exclusions through a technical analysis path.
Because multiple entities may perform “planning assessments” using different models, the phrase, “*the*
most recent *applicable* planning assessment” should be clarified to avoid ambiguity as to which model(s)
are acceptable. It may be useful to designate the models used in the Planning Authority analyses as
acceptable.

Spyker

We agree that entities should be given an option to conduct an analysis to demonstrate if an element is
necessary or not for the operation of transmission network. We also support that NERC should specify all the
relevant criteria category to be listed as under 2 (a). However, we suggest that NERC should avoid
prescribing numerical values but establish a range of value (or reference industry standard) that would be
consistent with industry/ regional standards or practices without compromising the reliability of transmission
network.

Long Island Power Authority

Exclusion under this criteria would require that the analysis be performed by the registered TP. Criteria
identified is based on interconnection to neighboring utilities.

Orange and Rockland Utilities,
Inc.

This approach is not necessary since NERC TPL Reliability Standards already addressed how to maintain a
reliable electric system.

Pepco Holdings Inc

Generally agree that a specific technical analysis approach (power flow studies) showing no impact on BES is
appropriate, but don’t know how to define specific criteria on which to base decision.

Duke Energy

Duke Energy agrees with the approach of using a technical analysis based on transmission system modeling
but the specific criteria do not need to be specified here - they should be consistent with the latest revision of

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Question 5a Comment
the TPL-001. R5 of TPL-001-2, Transmission System Planning Performance Requirements states that each
Transmission Planner and Planning Coordinator shall have criteria for acceptable System steady state
voltage limits, post-Contingency voltage deviations, and the transient voltage response for its System. The
technical analysis required for exclusion of an Element from the BES should evaluate the loss of the Element
against a more conservative set of criteria than that specified by the Transmission Planner and Planning
Coordinator responsible for that Element. There are currently no continent-wide performance levels defined
for these evaluations, and there is no technical basis for developing performance levels that would be
applicable continent wide.

American Transmission
Company, LLC

ATC proposes that this technical analysis criterion be replaced by criteria that are more closely tied to the
Adequate Level of Reliability (ALR) characteristics. The following alternate criteria are offered as possible
examples, “(1) the BES can be controlled to stay within acceptable limits following a fault on or loss of the
Element;
(2) the BES performs acceptably after credible contingences of the Element;
(3) the Element does not limit the impact and scope of instability and cascading outages when they occur;
(4) BES facilities are protected from unacceptable damage by operating the Element within its ratings; and
(5) the BES has the ability to supply the aggregate electric power and energy requirements of the electricity
consumers at all times, taking into account scheduled or reasonably expected unscheduled outages of the
Element. In addition, ATC is not aware of any continent-wide appropriate BES performance measures for
voltage dip, frequency excursion, voltage deviation, stability, etc. and ATC speculates that different values are
likely for different regions and system characteristics across the continent.
As a result, ATC believes it is not advisable to try to adopt unproven values without reasonable industry
investigation and development.

Manitoba Hydro

Manitoba Hydro does not agree with an impact based approach to establishing BES elements as we believe it
will result in regional differences in the application of the BES definition.
In addition, the resources required to verify the assumptions made in the models used to substantiate a BES
exception would be substantial with no benefit to reliability.
As well, this section appears to be an incomplete process. As currently worded, if the model was not updated
in step ii, then there is no requirement to run the TPL studies indicated in the remainder of step ii.

NESCOE

NESCOE supports the concept of allowing an additional path to justifying an exclusion from the BES.

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Question 5a Comment
NESCOE could support development of technical criteria such as those proposed, but does not have specific
recommendations at this time.
As stated earlier, any excluded elements must be connected to the BES using fully NERC compliant
protection systems.

Independent Electricity System
Operator

The technical analysis path for exclusions and inclusions allows for override of the listed “criterion”. It is not
clear what will be the basis for overriding, and what process will be followed? Is the “criterion” meant to be all
of (1) to (7) in (a), or is it any one of them? This needs to be clarified.
We agree that entities should be given an option to conduct an analysis to demonstrate if an element is or is
not necessary for the operation of transmission network. However, consistent with our earlier comments, we
suggest that the exception criteria avoid prescribing numerical values.
A transmission element is not necessary for the reliable operation of an interconnected electric transmission
system, if it can be removed without effecting bulk transfer capabilities. In our view, testing in accordance
with the TPL standards should be the basis for establishing this. One way of demonstrating that an element is
not required for the transfer of bulk power is to show that with the element out of service (and with all
elements that received exemptions in the past also out of service) and at the required power transfers:1. Precontingency and post-contingency loadings on all BES elements are within applicable ratings.2. Precontingency and post-contingency voltages on the BES are within established ratings.3. All units on the BES
remain synchronized following contingencies.4. All voltage declines on the BES are within established limits
(if any limits were defined).5. All steady-state oscillations and oscillations following a contingency are
positively damped.6. Transient voltage dips do not exceed established limits anywhere on the BES (if any
limits were defined).7. Frequency excursions do not exceed established limits anywhere on the BES (if any
limits were defined). Our view is that the exception criteria should NOT specify the voltage decline limits,
allowable frequency excursion or the allowable transient voltage dip because every region will have different
limits depending on the characteristics of their power system. This would be consistent with Requirement R5
of the recently balloted standard TPL-001-2, which requires each Transmission Planner and Planning
Coordinator to have criteria for acceptable System steady state voltage limits, post-Contingency voltage
deviations, and the transient voltage response for its System. Required power transfers are the transfers
required to meet the “one day in ten year” loss of load expectation criteria.
Further, exception criteria for generators must also be defined. A power system is typically planned to be able
to service the load under multiple dispatch scenarios and, therefore, multiple generators disconnected from
the transmission system will unlikely reduce the ability of the power system to supply the load. In fact, market
forces typically determine whether or not a generator is connected. However, transmission lines are built to
achieve specific transfer capabilities and, therefore, directly affect the power system’s ability to meet the

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Question 5a Comment
electricity demand. Since, generators and transmission elements contribute to reliability in a very different
ways, the criteria exempting generators should be different from the criteria exempting transmission elements.

MidAmerican Energy

The concept of using TPL analyses and normalized Transmission Distribution Factors makes basic sense as
a way to determine what elements react to system transfers and what elements react primarily to distribution
load.In general all facilities below 100 kV should be exlcuded by default as distribution according to the 2005
Federal Power Act.
Transmission Distribution Factors tend to show low bulk power system transfers (less than 2%) based on their
inherent high impedance when normalized. Normalizing the transmission impedance means diving the ohmic
value by a base impedance which is dominated by a (kV^2) term. Per Unit Impedance = (transmission line
ohms / base impedance) where base impedance = (kV^2 / MVA). Using a common MVA base value of 100
MVA, a base impedance at 69kV = 47.6 ohms versus at 161 kV = 259.2 or at 345 kV = 1190.2 ohms. The
rapid increase of the denominator as kV goes higher insures that a 69 kV system is high impedance
compared to any high kV facilities and therefore nearly insure the 69 kV system is local in nature and reacts
primarily to load. Therefore it is distribution.
This all supports the conclusion that all facilites below 100 kV should be classified as distribution according to
the 2005 FPA and exempted by default. Facilities below 100 kV could be brought into scope if TPL analyses
show instability, uncontrolled separation, or cascading as defined in the 2005 FPA.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters
utilized to analyze system Elements for potential exclusion from the BES. Based on industry response and further analysis, the SDT has abandoned the initial
exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to
a defined value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The
new process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through
submittal of an exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review
the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and
recommendation with the ERO as established in the draft Rules of Procedure.
PPL Supply

See comments in Questions 9 and 10

Response: See response to Q9 & Q10.
Tacoma Power

Tacoma Power generally agrees with approach used on the technical analysis path for exclusions.

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Question 5a Comment

Idaho Falls Power

We generally agree with having two paths towards exclusion.

New York Power Authority

In general, NYPA agrees with this approach except as noted below.

Springfield Utility Board

In general, SUB supports a technical analysis approach as a secondary/ alternative option for qualifying to
apply for BES Element exclusions.

Consumers Energy Company

Generally, this approach seems sound.

Oncor Electric Delivery

Oncor Electric Delivery agrees with the proposed language that describes the exclusion criteria based
technical analysis.

Response: The SDT appreciates your support. However, based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.

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5b. Comments on distribution factor measurement:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization
Northeast Power Coordinating
Council

Yes or No

Question 5b Comment
2.a. The term “Planning Assessment” is not a defined term in the NERC Glossary of Terms Used and should
not be capitalized, or it should be defined.
2.a.iv.1. Distribution Factor - This is a judgment of what feeder power flow participation level is material and
what is non-material. While TDF and OTDF analysis is an indication of contributions from the element, the
SDT should avoid setting values and instead describe the intended performance outcome from a distribution
factor measurement. Note that ultimately NERC as an ERO or relevant regulatory authority will approve the
application and can assess the performance outcome in their decision making presented in an entity’s
application.

SERC Planning Standards
Subcommittee

This is the only part of this technical analysis that may make sense. If the loss of any element of the BES
results in a distribution factor of less than X% on the element being considered for exclusion, then exclude it.

Tennessee Valley Authority

We suggest a value of 3% for this, since 3% is the threshold typically used in transfer studies.

Southern Company
South Carolina Electric and Gas
Georgia Transmission
Corporation
SPP Standards Review Group

There are situations where setting a minimum TDF will not work due to the nature of the TDF. For example, a
radial line connected to a bus with two networked lines. The radial line serves only load and would normally

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Question 5b Comment
be excluded from the BES. However, if we use the TDF as a factor the radial line would be included in the
BES since the TDFs would be high.

Edison Electric Institute

In general, we do not agree this is a relevant factor for consideration and should be excluded.

Florida Municipal Power Agency

The first proposed criterion, “Having a distribution factor of 5% for any other Element,” should instead be
“Having a distribution factor of 5% for Interchange Transactions or BES generator to load curtailable in
Transmission Loading Relief stages one through five.”

Transmission Access Policy
Study Group

The first proposed criterion, “Having a distribution factor of 5% for any other Element,” should instead be
“Having a distribution factor of 5% for curtailable Interchange Transactions or BES generator to load identified
in Transmission Loading Relief stages one through five.”
An Element with a higher distribution factor only on a non-BES Element should not be considered part of the
BES on that account.

ACES

Yes

The IDC uses 5% as a distribution factor cutoff so this might be a reasonable value. “Transmission Transfer
Capability” which was published by NERC in 1995 recommends using 3% on page 18 for transfer capability
studies.

ISO/RTO Standards Review
Committee

Distribution factors by themselves are not sufficient evidence that elements are not important to the system.
Multiple elements may have significant distribution factors related to various portions of the system, but that
doesn’t necessarily mean that loss of those elements will result in a reliability risk to the system.

Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

Hydro One

Distribution Factor is an estimate of what feeder power flow participation level material is and what nonmaterial is.While TDF and OTDF analysis is an indication of contributions from the element, hence the SDT
should avoid setting values and instead describe the intended performance outcome from a distribution factor
measurement. Note that ultimately NERC as an ERO or relevant regulatory authority will approve the
application and can assess the performance outcome in their decision making presented in an entity’s
application.

MRO's NERC Standards Review

NSRF proposes replacing this factor with those cited above because a distribution factor measurement
indicates how much system changes affect the element, not how much a fault or loss of the element would

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Organization
Forum

Yes or No

Question 5b Comment
compromise the ALR of the BES.
There is no clear correlation between this factor and any of the six characteristics of Adequate Level of
Reliability (ALR) of the BES.

PacifiCorp

5b.Comments on distribution factor measurement: All of PacifiCorp’s responses are based on a given
interconnection and not on a continental basis. See comments on question 10. Distribution factor has little to
no bearing on entities in the Western Interconnection.

ReliabilityFirst

any impact is an impact, even generation is re-dispatched at 0% in some cases.

New York Power Authority

NYPA does not agree with this measurement. Distribution factors are dependent on the number of radial
transmission lines that connect a single source to a load. For example, if two lines connect a single source to
a load, and one line trips, the distribution factor provides a 100% increase in flow on the remaining line. If
three lines connect the source to the load, and one line trips, the distribution factor for the remaining lines
would be 50%. The SDT should avoid setting values and instead describe the intended performance
outcome from a distribution factor measurement. Note that ultimately NERC as an ERO or relevant regulatory
authority will approve the application and can assess the performance outcome in their decision making
presented in an entity’s application.

National Grid

We don’t think this measurement is necessarily relevant in determining whether an element is necessary to
system reliability. This criterion can be removed from the list.
The exception process should be strictly limited to the procedures for application and approval and should not
include substantive elements.

Muscatine Power and Water

Suggest replacing this aspect with those cited above because a distribution factor measurement indicates
how much system changes influence the element, not how much a loss of the element would compromise the
ALR of the BES.
Currently unable to establish a clear correlation between this factor and any of the six characteristics of
Adequate Level of Reliability (ALR) of the BES.

Blachly Lane Electric Cooperative
Flathead Electric Cooperative,
Inc

The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage Transfer
Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring systems. However in
the Western Interconnection it has never been a definitive indicator of whether a system fault with delayed
clearing would impact a neighboring electric system. While we understand that many entities from the

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Organization
Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative

Yes or No

Question 5b Comment
Eastern Interconnection support the use of such factors, we believe the approach is unlikely to work in the
Western Interconnection.
Based on the significant differences between the four major interconnections in North America, we suggest
that a detailed technical exemption process be allowed on an interconnections wide basis. The Western
Interconnection is a “hub and spoke system” where loads are very remote from large generation plants, with
margins that are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system
with loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the Western
Interconnection uses a rated-paths methodology while the Eastern Interconnection uses transmission load
relief mechanisms.
Consistent with FERC order 743-A, we support exemption criteria for individual frequency independent
regions, or interconnections.

Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc.
Central Lincoln
for Snohomish County PUD

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Organization
Consolidated Edison Co. of NY,
Inc.

Yes or No

Question 5b Comment
2.a. The term “Planning Assessment” is not a defined term in the NERC Glossary of Terms Used and should
not be capitalized, or alternatively it should be defined.
2.a.iv.1. Distribution Factor - The issue comes down to a judgment call concerning what feeder power flow
participation level is material and what is non-material. In New York, the NYISO has traditionally used a 1%
power transfer distribution factor (power TDF) cut-off. Feeders showing less than a 1% power transfer in a
study are not materially participating in transmission.

ISO New England

The use of distribution factors is a significant concern. The term distribution factor is used a number of ways
in the industry. Is this determined using the percentage pickup on the element in question following the loss
of another element, or is this the percentage of a transfer that is picked up on the element in question, or a
combination of both?
Item 2.a.ii states that the TPL studies have to be run if the model is updated. The distribution factor is not
required to be calculated as part of the TPLs and therefore will require additional analysis in all
circumstances, not just when the model is updated.

The United Illuminating Company

Distribution factor requires a definition.

Clark Public Utilities

The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage Transfer
Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring systems. However in
the Western Interconnection it has never been a definitive indicator of whether a system fault with delayed
clearing would impact a neighboring electric system. While we understand that many entities from the Eastern
Interconnection support the use of such factors, we believe the approach is unlikely to work in the Western
Interconnection.

Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc.
Oregon Trail Electric
Cooperative, Inc.
Salem Electric
Grant County PUD No. 2 (Grant)
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc.

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Yes or No

Question 5b Comment

Kootenai Electric Cooperative
BGE

BGE requests that it be made clear that the 2(a) iv.1 criteria refers to the of the distribution factor for the loss
of any other facility on the subject Element, whereas criteria 2 through 7 refer to the performance following the
loss of the subject Element.

Spyker

The SDT should avoid setting values and instead describe the intended performance outcomes from the
measurement

Consumers Energy Company

This criterion raises concerns. If based on transfer distribution factor it may have some merit, depending on
the TBD value. However, the criteria should not be based on outage transfer distribution factor, as Draft 1
implies, since loss of certain local distribution facilities can result in local distribution load being transferred to
other local distribution facilities. Distribution facilities should not be prevented from exclusion from BES.

Duke Energy

This should be removed - there is no correlation between distribution factor and whether or not an element is
necessary for reliable operation of the interconnected transmission network.

Hydro-Quebec TransEnergie

Comments on distribution factor measurement: The choice of the maximum distribution factor could be
difficult to establish. For this point, the comparison of the distribution factor prior and after the events could be
considered.

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 5a because a distribution factor measurement
indicates how much system changes affect the element, not how much a fault or loss of the element would
compromise the ALR of the BES. There is no clear correlation between this factor and any of the six
characteristics of Adequate Level of Reliability (ALR) of the BES.

Independent Electricity System
Operator

We do not agree with setting values for this criterion. This should be left to the relevant Transmission Planner
and Planning Coordinator. See our comments in response to Q5a.

Tacoma Power

Tacoma Power generally agrees with the distribution factor measurement in the technical analysis path for
exclusions. We suggest adopting a distribution factor not exceeding 30% on an adjacent system.

MidAmerican Energy

The Distribution Factor measurement is acceptable and should exclude facilities that show a low distribution
factor for bulk power system transfers. An arbitrary low value could be those facilities that show less than a
2% distribution factor.

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Question 5b Comment

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential exclusion from the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.
Iberdrola USA

See 5a.

Response: See response to Q5a.

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5c. Comments on allowable transient voltage dip measurement:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization

Yes or No

Question 5c Comment

Northeast Power Coordinating
Council

Voltage dip is specified in terms of duration and retained voltage, usually expressed in percentage. Suggest
that either the SDT avoid using voltage dip as a criteria, or clearly specify that the transient voltage not
exceed the X limit of Y cycles (time). References to relevant industry standards such as IEEE standard 13461998 should be made.

SERC Planning Standards
Subcommittee

As stated above, it does not make sense to use this category.

Tennessee Valley Authority
Southern Company
South Carolina Electric and Gas
Georgia Transmission
Corporation
Edison Electric Institute

Presently no regional standards exist for allowable transient voltage dip beyond WECC. It is also doubtful a
useful standard could be developed for all regions or interconnections.

Florida Municipal Power Agency

The second criterion, “Allowable transient voltage dip - criteria TBD,” should specify where the transient
voltage dip is, i.e. “Allowable transient voltage dip on another BES Element for events on the Element that is a
candidate of the Exception Request-criteria TBD.”

Transmission Access Policy

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Organization

Yes or No

Question 5c Comment

Study Group
ISO/RTO Standards Review
Committee

These “transient” and “voltage deviation” analyses are highly dependent upon sound and accurate dynamic
system models. Much has been said in recent days about the suspicions that many such models are not truly
accurate enough to predict system response that is close to what actually occurs.

Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

Hydro One

Voltage dip is specified in terms of duration and retained voltage, usually expressed in percentage. We advise
against prescribing limits by the SDT, and instead suggest that either the SDT avoid relating voltage dip
altogether or clearly specify that the transient voltage not exceed the X limit of Y cycles (time). We suggest
SDT to make references to relevant industry standard such as IEEE standard 1346-1998.For example, a
document effective in 2007 titled Ontario Resource and Transmission Assessment Criteria Issue 5.0 mentions
that: “The minimum post-fault positive sequence voltage sag must remain above 70% of nominal voltage and
must not remain below 80% of nominal voltage for more than 250 milliseconds within 10 seconds following a
fault. Specific locations or grandfathered agreements may stipulate minimum post-fault positive sequence
voltage sag criteria higher than 80%. IEEE standard 1346-1998 supports these limits.”

MRO's NERC Standards Review
Forum

NSRF proposes replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable transient voltage dip performance level for evaluating whether a fault or loss of the
element would not compromise the ALR of the BES.
In addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.

ReliabilityFirst

any impact is an impact, planning criteria between 3 & 5 % is often used and not allowed, why inject this into
what define the BES. the criteria is applied it should be included

New York Power Authority

Suggest that either the SDT avoid using voltage dip as a criteria, or clearly specify that the transient voltage
not exceed the X limit of Y cycles (time).
References to relevant industry standards such as IEEE standard 1346-1998 should be made.

Muscatine Power and Water

Suggest replacing this factor with those cited above because there is presently no established, continentwide, acceptable transient voltage dip performance level for evaluating whether a fault or loss of the element

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Organization

Yes or No

Question 5c Comment
would not compromise the ALR of the BES.
In addition, the appropriate performance level for this factor may be different in other areas and system
characteristics across the continent.

Blachly Lane Electric Cooperative
Flathead Electric Cooperative,
Inc.
Clark Public Utilities

Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element should
produce no more than a 20% voltage drop for no more than 20 cycles in a Category B contingency and no
more than a 20% drop for 40 cycles in a Category C contingency. Technical justification for these thresholds
is provided on pages 12-16 of Snohomish’s White Paper.

Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric

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Organization

Yes or No

Question 5c Comment

Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc
Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc.
Salem Electric
Grant County PUD No. 2 (Grant)
for Snohomish County PUD
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc.
Kootenai Electric Cooperative

ISO New England

Is the requirement to evaluate the voltage dip on the element or is the test to evaluate the voltage dip on the
BES due to a contingency on the element? Under the draft TPL standards, this will have to be tested and
investigated anyway, so it is unclear as to what is being added or evaluated here.

The United Illuminating Company

Measured where on the BES?

BGE

For PJM members, this figure is set at 5%. BGE suggests a lower figure such as 2-3%.

Spyker

We suggest SDT to make references to relevant industry standard such as IEEE standards

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Organization

Yes or No

Question 5c Comment

Consumers Energy Company

The criterion related to Transient Voltage Deviations should be removed. This criterion, regardless of value
TBD, would be impossible to achieve, and would render this process meaningless.A fault on non-BES
elements will cause significant transient voltage dips on nearby BES elements until the fault is cleared. If the
non-BES element is at the same voltage level, the dip will result in near-zero voltages; if at different voltage
levels, the dip magnitude will be determined by the ratio of the system Thévinen impedance at the BES to
the intervening transformer impedance - if the system Thévinen impedance is 2% and the transformer
impedance is 18%, the voltage on the BES will dip to 10%.

Central Lincoln

Fault induced transient voltage measurements will always be low if taken at a point electrically close to the
fault during the fault. The question should be about voltage recovery following the clearing of the fault as in
the TPL standards. The Technical Principles do not make this distinction, and the resulting effect would be the
exclusion of elements that should be included and the inclusion of elements that should be excluded.

Duke Energy

See general comment on approach.

Hydro-Quebec TransEnergie

Comments on allowable transient voltage dip measurement: The TPL-001 to 004 do not specify any reference
measurement for stability (such as Allowable transient voltage, frequency excursion, voltage deviation, etc.).
Instead, it request that the system shall remain stable, without cascading or uncontrolled islanding. Also, it is
requested that the Planning Entities shall define and document the criteria or methodology used in the
analysis to identify System instability for conditions such as Cascading, voltage instability, or uncontrolled
islanding. This is exactly what should be requested in the analysis and demonstration of Element seeking
exclusion from BES. The analysis and burden of proof should be left to the Entity as is done in the TPL,
considering that there are no common values with the different interconnection.

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 5a because there is presently no established,
continent-wide, acceptable transient voltage dip performance level for evaluating whether a fault or loss of the
element would not compromise the ALR of the BES.
In addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.

Independent Electricity System
Operator

We do not agree with setting values for this criterion. This should be left to the relevant Transmission Planner
and Planning Coordinator. See our comments in response to Q5a.

Tacoma Power

Tacoma Power generally agrees with allowable transient voltage dip measurement in the technical analysis

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Organization

Yes or No

Question 5c Comment
path for exclusions.
We suggest adopting an allowable transient voltage dip not exceeding 20% for more than 20 cycles on an
adjacent system’s bus.

MidAmerican Energy

There isn't a nation wide transient voltage dip measurement.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential exclusion from the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.
Iberdrola USA

See 5a.

Response: See response to Q5a.

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5d. Comments on allowable transient frequency response:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization
ISO/RTO Standards Review
Committee

Yes or No

Question 5d Comment
See 5c

Response: see response to 5c.
Iberdrola USA

See 5a.

Response: see response to 5a.
Northeast Power Coordinating
Council

Suggest that for assigning a value for transient frequency response, entities conduct and submit to the SDT
their quantitative and qualitative technical assessment based on the conditions of the element(s) under the
application. Do not establish a fixed binary value within the exception criteria but rather focus on the
performance outcome. See 5 (a) above.

SERC Planning Standards
Subcommittee

As stated above, it does not make sense to use this category.

Tennessee Valley Authority
Southern Company
South Carolina Electric and Gas

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Organization

Yes or No

Question 5d Comment

Georgia Transmission
Corporation
Edison Electric Institute

Presently no regional standards exist for allowable transient frequency response beyond WECC. It is also
doubtful a useful standard could be developed for all regions or interconnections.

Florida Municipal Power Agency

The third proposed criterion, “Allowable transient frequency excursion - criteria TBD,” should be rephrased
like the second: “Allowable transient frequency excursion on another BES Element for events on the Element
that is a candidate of the Exception Request - criteria TBD.”

Transmission Access Policy
Study Group
Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

Hydro One

We suggest that, in terms of assigning a value for transient frequency response, entities conduct and submit
to the SDT their quantitative and qualitative technical assessment based on the conditions of the element(s)
under the application.
We suggest not to establish a fixed binary value within the exception criteria but rather focus on the
performance outcome. See 5 (a)

MRO's NERC Standards Review
Forum

NSRF proposes replacing this factor with those cited above because there are established, continent-wide
transient frequency performance levels in the PRC-006-1 standard, but the elements that are applicable to the
standard do not have to be BES elements and the transient frequency response requirements are not
intended to be a criterion for BES classification.

ReliabilityFirst

any impact is an impact, planning criteria between 5 & 10 % is often used and restricted to guard against
these changes, why inject this into what define the BES. the criteria is applied it should be included

New York Power Authority

Suggest that for assigning a value for transient frequency response, entities conduct and submit to the SDT
their quantitative and qualitative technical assessment based on the conditions of the element(s) under the
application.
Do not establish a fixed binary value within the exception criteria but rather focus on the performance
outcome.

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Organization

Yes or No

Question 5d Comment

Muscatine Power and Water

Suggest replacing this factor with those cited above. There are recognized, continent-wide transient
frequency performance levels in the PRC-006-1 standard; however, the elements that are applicable to this
standard are not necessarily BES elements and the transient frequency response requirements are not
intended to be a criterion for BES classification.

Blachly Lane Electric Cooperative

Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of that
Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical justification for
these thresholds is provided on pages 12-16 of the White Paper.

Flathead Electric Cooperative,
Inc
Clark Public Utilities
Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc.
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative

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Organization

Yes or No

Question 5d Comment

West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc.
Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc.
Central Lincoln
Salem Electric
Grant County PUD No. 2 (Grant)
for Snohomish County PUD
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc
Kootenai Electric Cooperative
Spyker

The SDT should avoid setting values and instead describe the intended performance outcomes from the
measurement

Consumers Energy Company

The criterion relative to frequency response should be removed. Frequency deviations can result from large
changes in distribution load.
Distribution facilities should not be prevented from being excluded from BES.

Duke Energy

See general comment on approach.

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Organization

Yes or No

Question 5d Comment

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 5a because there are established, continentwide transient frequency performance levels in the PRC-006-1 standard, but the elements that are applicable
to the standard do not have to be BES elements and the transient frequency response requirements are not
intended to be a criterion for BES classification.

Independent Electricity System
Operator

We do not agree with setting values for this criterion. This should be left to the relevant Transmission Planner
and Planning Coordinator. See our comments in response to Q5a.

Tacoma Power

Tacoma Power generally agrees with the allowable transient frequency response in the technical analysis
path for exclusions. We suggest adopting an allowable transient frequency response of not below 59.6 Hz for
up to 6 cycles on an adjacent system’s bus.

MidAmerican Energy

There isn't a nation wide transient frequency response

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential exclusion from the BES.. Based on industry response and further analysis, the SDT has abandoned the initial exclusion
criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and
provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value
and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process
requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to
validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as
established in the draft Rules of Procedure.

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5e. Comments on voltage deviation measurement:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization
ISO/RTO Standards Review
Committee

Yes or No

Question 5e Comment
See 5c

Response: See response to 5c.
Iberdrola USA

See 5a.

Response: See response to 5a.
Blachly Lane Electric Cooperative

Please see our response to Question 5d.

Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative

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Organization

Yes or No

Question 5e Comment

Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc
Benton Rural Electric Association
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc
Central Lincoln
Salem Electric
Grant County PUD No. 2 (Grant)
for Snohomish County PUD
Northwest Public Power
Association (NWPPA)

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Organization

Yes or No

Question 5e Comment

Big Bend Electric Cooperative,
Inc.
Kootenai Electric Cooperative
Response: See response to 5d.
Clark Public Utilities

See Clark’s comments on 5c and 5d.

Response: See responses to 5c and 5d.
Northeast Power Coordinating
Council
Hydro One

Voltage deviation is generally expressed as a percentage, between the voltage at a given instant at a point in
the system. Do not establish a fixed binary value within the exception criteria but rather focus on the
performance outcome.
Adequate voltage performance does not guarantee system voltage stability. Steady state stability is the ability
of the grid to remain in synchronism during relatively slow or normal load or generation changes, and to damp
out oscillations caused by such changes. The requirement should suggest that following checks are carried
out to ensure system voltage stability for both the pre-contingency period and the steady state postcontingency period: o Properly converged pre- and post-contingency power flows are to be obtained with the
critical parameter increased up to 10% with typical generation as applicable;
o All of the properly converged cases obtained must represent stable operating points. This is to be
determined for each case by carrying out P-V analysis at all critical buses to verify that for each bus the
operating point demonstrates acceptable margin on the power transfer; and
o The damping factor must be acceptable (the real part of the eigen values of the reduced
are positive).

SERC Planning Standards
Subcommittee

Jacobian matrix

As stated above, it does not make sense to use this category.

Tennessee Valley Authority
Southern Company
South Carolina Electric and Gas
Georgia Transmission

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Organization

Yes or No

Question 5e Comment

Corporation
Edison Electric Institute

Presently no regional standards exist for allowable voltage deviation beyond WECC. It is also doubtful a
useful standard could be developed for all regions or interconnections.

Florida Municipal Power Agency

The fourth proposed criterion should be revised in the same way as the second and third: “Voltage deviation
on another BES Element for events on the Element that is a candidate of the Exception Request - criteria
TBD.”The fifth proposed criterion should be similarly revised: “Transient Stability on another BES Element for
events on the Element that is a candidate of the Exception Request - positively damped.”

Transmission Access Policy
Study Group
Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

MRO's NERC Standards Review
Forum

NSRF proposes replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable (steady state) voltage deviation performance level for evaluating whether a fault or
loss of the element would not compromise the ALR of the BES.
In addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.

ReliabilityFirst

any impact is an impact, planning criteria is often used and restricted to guard against these changes, why
inject this into what define the BES. If the criteria is applied to the facility as a BES element it should be
included

New York Power Authority

Voltage deviation is generally expressed as a percentage, between the voltage at a given instant at a point in
the system. Do not establish a fixed binary value within the exception criteria but rather focus on the
performance outcome.

Muscatine Power and Water

Requesting the STD replace this factor with those cited above. At this time there is no established, continentwide, acceptable (steady state) voltage deviation performance level for evaluating whether a fault or loss of
the element would not compromise the ALR of the BES.
Moreover, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.

Consolidated Edison Co. of NY,

The NYISO uses a 0.95 to 1.05 p.u. as the acceptable range for post-transient system conditions.

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Organization

Yes or No

Question 5e Comment

Inc.
ISO New England

Is the requirement to evaluate the voltage dip on the element or is the test to evaluate the voltage dip on the
BES due to a contingency on the element? Under the draft TPL standards, this will have to be tested and
investigated anyway, so it is unclear as to what is being added or evaluated here.

The United Illuminating Company

Measured where on BES?

BGE

BGE believe the loss of the facility in question should cause only a small voltage deviation to the BES (on the
order of 1%).

Spyker

The SDT should avoid setting values and instead describe the intended performance outcomes from the
measurement

Northern Wasco County PUD

Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of that
Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical justification for
these thresholds is provided at pages 12-16 of the White Paper.

Flathead Electric Cooperative,
Inc.

we propose that, if an Element is to be excluded from the BES, removal of that Element should not cause any
load bus to drop below 59.6 Hz for 6 cycles or more.

Consumers Energy Company

This criterion may be reasonable, depending on the TBD value. The TBD value may need to vary for different
voltage levels or system configurations. The criteriona needs to recognize that loss of multiple capacitors at
the distribution level could result in significant voltage deviation at the BES and this must not prevent
distribution facilities from being excluded from BES.

Duke Energy

See general comment on approach.

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 5a because there is presently no established,
continent-wide, acceptable (steady state) voltage deviation performance level for evaluating whether a fault or
loss of the element would not compromise the ALR of the BES.
In addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.

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Organization
Independent Electricity System
Operator

Yes or No

Question 5e Comment
We do not agree with setting values for this criterion. This should be left to the relevant Transmission Planner
and Planning Coordinator. See our comments in response to Q5a.
We suggest that the exception criteria could include the following checks to be carried out in the course of the
TPL analysis referred to above to ensure system voltage stability for both the pre-contingency period and the
steady state post-contingency period: o Properly converged pre- and post-contingency power flows are to be
obtained with the critical parameter increased up to 10% with typical generation as applicable;
o All of the properly converged cases obtained must represent stable operating points. This is to be
determined for each case by carrying out P-V analysis at all critical buses to verify that for each bus the
operating point demonstrates acceptable margin on the power transfer as shown in the following section; and
o The damping factor must be acceptable (the real part of the eigen values of the reduced Jacobian matrix
are positive).”

Tacoma Power

Tacoma Power generally agrees with the voltage deviation measurement in the technical analysis path for
exclusions. We suggest adopting a voltage deviation not exceeding 10% on an adjacent system’s bus.

MidAmerican Energy

Determining a nation wide voltage deviation would be difficult.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential exclusion from the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.

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Exceptions — Project 2010-17

6. Exclusions – Do you have other methods that may be appropriate for proving an exclusion claim? Or,
other variables/measurements that may be added to the requirements already shown in the posted
Technical Principles for Demonstrating BES Exceptions? If so, please provide your comments here
with technical rationale for why they should be considered.

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an
entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as
presently being drafted.

Organization

Yes or No

NERC Staff Technical Review

No

Edison Electric Institute

No

Iberdrola USA

No

Tri-State Generation and
Transmission Association

No

ReliabilityFirst

No

Idaho Falls Power

No

New York Power Authority

No

Question 6 Comment

None beyond what was offered under question 5

No comments

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Organization

Yes or No

Blachly Lane Electric Cooperative

No

Clark Public Utilities

No

Central Electric Cooperative

No

Clearwater Power Electric
Cooperative

No

Consumer's Power Inc.

No

Coos-Curry Electric Cooperative

No

Douglas Electric Cooperative

No

Fall River Electric Cooperative

No

Lane Electric Cooperative

No

Lincoln Electric Cooperative

No

Lost River Electric Cooperative

No

Northern Lights Electric
Cooperative

No

Okanogan Electric Cooperative

No

Raft River Rural Electric
Cooperative

No

Salmon River Electric
Cooperative

No

Question 6 Comment

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Organization

Yes or No

Umatilla Electric Cooperative

No

West Oregon Electric
Cooperative

No

Pacific Northwest Generating
Cooperative

No

Long Island Power Authority

No

American Electric Power

No

PNGC Power

No

Consumer's Power Inc.

No

BGE

No

Pepco Holdings Inc

No

Northern Wasco County PUD

No

United Electric Co-op Inc.

No

Oregon Trail Electric
Cooperative, Inc.

No

Central Lincoln

No

Oncor Electric Delivery

No

Salem Electric

No

Question 6 Comment

No comment.

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Organization

Yes or No

Question 6 Comment

Duke Energy

No

Grant County PUD No. 2 (Grant)

No

No comments

Northwest Public Power
Association (NWPPA)

No

None

Big Bend Electric Cooperative,
Inc.

No

Manitoba Hydro

No

Independent Electricity System
Operator

No

Harney Electric Cooperative, Inc.

No

Kootenai Electric Cooperative

No

Tacoma Power

No

ISO New England

No

Southern Company

Yes

Tacoma Power is not suggesting any other methods at this time.

Response: Thank you for your response.
Flathead Electric Cooperative,
Inc.
for Snohomish County PUD

No

supports the exemption of generation interconnected to local distribution networks if the generation is less
than 300 MW capacity and where the power generated is consumed within the LDN and rarely flows out of
the LDN consistent with the section III.c.4 [Exclusion] of the NERC Statement of Compliance Registry Criteria
as well as the Load modifiers used in the Eastern Interconnection. "Load Modifiers" (small generators that
only affect load at the distribution level).”

Response: The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.

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Organization

Yes or No

Question 6 Comment

The United Illuminating Company

No

Procees is complicated and fraught with interpretations.

Bonneville Power Administration

No

BPA emphasizes that exclusion criteria and analysis should be based on normal operations. An exclusion
should not be unavailable based on temporary system configuration such as load service by a different
transmission segment temporarily used to mitigate system operations due to planned maintenance outages,
i.e. a system that is operated radially over 90% of the time and closed for maintenance outages for safety
and/or reliability purposes, etc.
BPA recommends that the SDT consider not only the single-phase faults, also the effect of more severe
events such as two- or three-phase faults, with delayed clearing and evaluate the necessity of the element in
those cases.

ISO/RTO Standards Review
Committee

SERC Planning Standards
Subcommittee

Very small elements may be candidates for exclusion because such a small loss cannot cause reliability risk.
An exception to this statement may be that, though small, the element is important to the service of a critical
load.
Yes

Tennessee Valley Authority
South Carolina Electric and Gas

Section “Exception Criteria - Exclusions”:Add 1.e. “Generation that is inoperable and not planned to be
placed back into service but not yet officially decommissioned.”Technical rationale: These facilities are not
relied on to insure the reliability of the BES.

Georgia Transmission
Corporation
Entergy Services
Florida Municipal Power Agency
Transmission Access Policy
Study Group

Revise second paragraph to read “Due to the importance of designated Blackstart Resources and their
Cranking Paths to restore efforts, no exceptions will be allowed for those items that are included in a system
restoration plan.”Technical rationale: Multiple Blackstart Resources and Cranking Paths are frequently
available but are not included in a system restoration plan. System restoration plans describe the Blackstart
resources and cranking paths thar are deemed to be necessary for system restoration.

Yes

TAPS proposes a simpler set of exclusion exception criteria:1. Having a distribution factor of 5% for
curtailable Interchange Transactions or BES generator - load identified in Transmission Loading Relief stages
one through five, and
2. Category B and C contingencies on the Element that is the subject of the Exception Request meet the TPL002 criteria for other BES Elements. (With the new TPL-001-3 standard recently approved by ballot, Category
P0 through P7 contingencies on the Element that is subject of the Exception Request meets the criteria of P0
through P3 for other BES Elements)
3. The Element that is the subject of the Exception Request is not: (1) part of an IROL, (ii) part of a blackstart
or cranking path used in a TOP’s restoration plan, and (iii) is not used in NUC-001 to provide service to a

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Yes or No

Question 6 Comment
nuclear plant.TAPS believes these three criteria meet the intent of all of the criteria presented by the SDT.

Hydro One

Yes

Technical Analysis must fundamentally use NERC - TPL methodology and testing requirements.
We believe that an element may “not be necessary for the operation of the interconnected transmission
system” if the remaining system can be operated without the element(s) for over 30 days and during peak
load conditions. This assumption considers that loss of element(s) may result in outage to the connected load
or generation during this period but will not have any adverse impact on the operation of the interconnected
transmission network.
Following are technical assessment categories that entities could be required when filing for
exception:1.Power flow
oPrimarily unidirectional (less than 20% of min load)2.TPL Assessment
oLoad Flows Analysis
oThermal and Voltage Stability
oTransient Stability3.TDF and OTDF
assessment
For entities filing an exception:[Step 1]Entities should undertake relevant and detailed technical
assessment/analysis and describe their findings under each of the technical categories. Finally, the findings
and conclusions should be listed in the form of maximum 6 bullets.
[Step 2]Findings and conclusions from each of the technical categories should be presented in a spreadsheet
including the categories that may not be relevant to the element(s). If a category is not relevant, it should be
explained why.
[Step 3]The final conclusion should be presented by taking the overall assessment in Step 2 by assessing
contributions of each item and demonstrating that the element(s) is or is not necessary for the operation of
interconnected transmission network.
We suggest the above method and request entities to complete the table below, as this will allow entities to
present their assessment of the element(s) that are under the consideration of exception.
Measured Value==============
------------------------

Load || Critical Load Affected? [yes][No]-------------------

oRadial oLocal supply, e.g. distribution in nature
oLarge load center, critical load, national security
Generation Characteristics || Critical Load Affected?
[yes][No]--------------------------------------------------------------oLocal load modifier, peak shaver oBehind meter or industrial load displacement
oMust Run

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Organization

Yes or No

Question 6 Comment
oFlow contribution outside of the elements under exception
Cascading Outage || Critical Load Affected? [yes][No]----------------------------------------------------Measured Value ==============Max Dip
Practice (IEEE/CSA,Market Rules,etc.)Acceptable Level
Assessment Results
[Yes] [No]
Transient Voltage Dip
Transient Frequency Excursion
[Voltage]

[Voltage] Applicable Industry
[in cycles]

[in cycles]Does the assessment confirm successful recovery?
[voltage]
[Hertz]Voltage deviation

Transient Stability Steady State Stability
MRO's NERC Standards Review
Forum

Yes

A. NSRF recommends this process address the six characteristics of the Definition of Adequate Level of
Reliability (ALR) as listed in the comments above in Question #5.
B. Recommend municipalities and other small entities having transmission systems designed to serve local
load, operated below 200 kV and not having any IROL’s or SOL’s be excluded from the BES definition.
Rational: The standards, especially those for Transmission Operators (TO) aren’t written for the smaller
utilities. A utility may have over 75 MWs of generation and have installed a 115 kV loop around their city that
is used primarily to serve load and get forced into significant compliance requirements that don’t enhance the
reliability of the BES.

PacifiCorp

Yes

All of PacifiCorp’s responses are based on a given interconnection and not on a continental basis. Fault duty
may be appropriate for certain interconnections only.

Western Electricity Coordinating
Council

Yes

WECC recommends that the SDT consider not only the single-phase faults used in the TPL standards, but
also the effect of more severe events such as two- or three-phase faults, with delayed clearing and the
necessity of the element in those cases.

Electricity Consumers Resource
Council (ELCON)

Yes

We recommend an additional method (or alternatively this be added to the BES Definition Exception E1):
System Elements are part of facilities, generally radial in nature, supplying a retail customers from the point of
delivery to the load regardless of voltage. Evidence to support this position could be an interconnection
agreement indicating the point of delivery, a one-line diagram showing the point of delivery and load etc. The
technical rationale is that protection of the BES for facilities serving load is the responsibility of the service

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Yes or No

Question 6 Comment
provider (e.g., TO/TOP). These facilities are distribution facilities and are not now part of the BPS.

National Grid

Yes

The NERC process could potentially by very lengthy and could interfere with the timely completion of our
studies. In the technical paths for exclusions, bullet v states “If within the criteria in all cases, then the
Elements can be excluded.” This could lead to a very high number of studies that need to be done to prove
an element should be excluded. For this reason, National Grid endorses a more streamlined process. We
propose a process where entities would only need to submit a short form that briefly describes what they
would like to exempt and the reason why, along with a one-line diagram. The entity who is requesting the
exception would have to maintain records that show why the elements can be exempted until NERC performs
an audit. At the audit, the entity can show the proof of why the element should be granted an exception. This
process also allows for the application to remain public and reduces documentation burdens, because the
non-public, CEII, or NERC CIP protected supporting documentation is maintained by the applicant.In this
process, the entity first submits the application to their RE, and if approved by the RE, the application is
submitted to NERC. The entity should be able to appeal if either the RE or NERC denies the application;
however, it should be clear that for the second appeal to NERC, the decision is made by a different group
than whoever decided on the first appeal. The appeal process in this exception procedure could be similar to
the appeal process set by CMEP (compliance, monitoring and enforcement program).For entities that don’t
wish to wait until the next audit, there can be an optional process by which the proposed exception can be
reviewed to provide an immediate ruling. Also, there should be a grace period after the audit is performed if
audit staff concludes that an exception or inclusion granted by the initial application is not supported by
adequate evidence. NERC’s approval of an exception during this initial application process should stand until
an Entity is audited and a final audit report is issued. There should also be an implementation period
included in the audit report for the entity to come into compliance if the audit report disagrees with the initial
exception approval. Absent evidence of fraud or intentional misrepresentation by the entity, there should be
no non-compliance assessed for the period from initial exception approval to the final audit report. This
process would need to allow participation or comments by Regional Entities, Reliability Coordinators, and/or
Balancing Authorities in the application process, but should not allow participation by other third parties.

Muscatine Power and Water

Yes

Recommending that this process address the six characteristics of the Definition of Adequate Level of
Reliability (ALR) as listed in the comments above in Question #5.
Also recommend that municipalities and other small entities having transmission systems designed to serve
local load only, operated below 200 kV and not having any IROL’s or SOL’s be excluded from the BES
definition. Rationale: this could affect smaller registered entities within a BA. The standards, especially those
for Transmission Operators, aren’t written for the smaller utilities. A small, municipal utility could have 75 MW
of generation and operate a 115 kV looped system around their service area that is used primarily to serve
their own load. Subsequently, they get forced into significant compliance requirements that does not enhance

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Organization

Yes or No

Question 6 Comment
the reliability of the BES whatsoever.

Glacier Electric Cooperative

Yes

Perhaps using an element's available fault MVA as a "quick screening" method to quickly determine if an
element should be included or excluded. If an element's available fault MVA exceeds a properly established
value, then a more detailed technical analysis can be done to determine whether or not the element truly
should be included in the BES. But if the elemet's available fault MVA is less than the established value, then
that element could quickly be excluded.

Orange and Rockland Utilities,
Inc.

Yes

FERC Order No. 888 - Seven Factor Test.

Xcel Energy

Yes

Xcel Energy would like the SDT to consider a Capacity Factor exclusion for generating resources that are
rarely used. For example, at least two standards that are currently being drafted exempt generators that have
an average Capacity Factor of 5% or less over a three year period.

American Transmission
Company, LLC

Yes

ATC recommends this process address the five characteristics of the Definition of Adequate Level of
Reliability (ALR) as listed in the comments above in Question #5a.

NESCOE

Yes

Please refer to comments under item 4., above. If the parallel power flow in a given < 200 kV path only
exceed 200 MVA under contingency conditions and if the applicable BES points have fully NERC compliant
protection systems, disturbances on this lower voltage path will not adversely affect the reliability of the BES.
The exclusion determination process should be flexible enough to recognize that any requirement that may
impose substantial new costs on New England transmission owners, and ultimately on consumers, should
also provide meaningful reliability benefits

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the technical exception criterion. Based on
industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and
operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal
was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of the facilities in question and to
document the operational performance as appropriate through submittal of an exception request form along with any other supporting documentation for the
exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as presently being drafted.
Northeast Power Coordinating

Yes

An impact-based method should be available for entities seeking Exclusions and Inclusions. The method

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Organization

Yes or No

Council

Question 6 Comment
should not allow excess regional discretion and unintended continent-wide variation. Recommend the power
Transfer Distribution Factor (power TDF) approach mentioned in the reply to Question 5 above. If the
Transmission Planner (TP) or Planning Authority (PA), were tasked with performing such analyses using
standardized assumptions, then regional discretion could be minimized.
Technical Analysis must fundamentally use NERC - TPL methodology and testing requirements.

Consolidated Edison Co. of NY,
Inc.

Yes

An impact-based method should be available for entities seeking Exclusions and Inclusions. The method
should not allow excess regional discretion and unintended continent-wide variation. We recommend the
power Transfer Distribution Factor (power TDF) approach mentioned in the reply to Question 6 above.
If the Transmission Planner (TP) or Planning Authority (PA), e.g., the NYISO, were tasked with performing
such analyses, using standardized assumptions, then regional discretion could be minimized.

Spyker

Yes

Technical Analysis must fundamentally use NERC - TPL methodology and testing requirements.

Hydro-Quebec TransEnergie

Yes

Technical demonstration should not be limited to technical principles stated in the "Technical Principles for
Demonstrating BES Exceptions". Entities should be allowed to do their own demonstration with their own
technical arguments. As an example, an Entity could consider a few level of application for the standards. As
an example, the level #1 being the most important level, all standards would apply to this level, including more
stringent criteria than the TPL standards. This would bring BES level #1 very robust and reliable, ensuring the
reliability of the main system. A second BES level #2 could be define for local transmission to which would be
applied most standards but excluding some of the C section of TPL. Attention would be given to proper
reliable operation of the BES level #2, but with smaller level of investment on the design aspect, those
regional transmission part of the system being able to face higher risk for loss of continuity of service. Finally,
for generation or Load Facility that would be excluded from both level of BES, minimum standards would still
apply such as in protection or for generation. Through its own technical principles, the Entity could
demonstrate that the highest level of BES is more reliable than what is expected by NERC's standard, but that
in regional transmission part of the system, the C TPL standard would not apply with the only risk of lower
continuity of service.

Response: The SDT appreciates your comments. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or
limit. It has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new
process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of
an exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the

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Organization

Yes or No

Question 6 Comment

submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation
with the ERO as established in the Rules of Procedure as presently being drafted.
Your specific concerns will be accommodated under the revised process.
SPP Standards Review Group

Yes

We would suggest that the SDT consider an exclusion for networked municipal systems operating below
200kV which have more than 75 MVA of generation and whose systems do not include flowgates or IROLs.

Response: The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.
PPL Supply

Yes

See comments in Questions 9 and 10

Yes

See answer to 5a.

Yes

Suggested additional method. The Element(s) meet all the following characteristics: 1) generally radial in
nature, and

Response: See response to Q9 & Q10.
New York State Reliability
Council
Response: See response to 5a.
Occidental Energy Ventures
Corp.

2) used to supply a retail customer from the point of delivery to the load regardless of voltage.
Evidence to support this position could be an interconnection agreement indicating the point of delivery, a
one-line diagram showing the point of delivery and load, etc. The technical rationale is that protection of the
BES for facilities serving a retail customer is the responsibility of the service provider (e.g., transmission
owner/operator). These facilities are distribution facilities and are not now part of the BPS. Alternatively, this
could be an Exclusion in the BES Definition as it is in the current definition.
MidAmerican Energy

Yes

In general all facilities below 100 kV should be exlcuded by default as distribution according to the 2005
Federal Power Act. Transmission Distribution Factors tend to show low bulk power system transfers (less
than 2%) based on their inherent high impedance when normalized. Normalizing the transmission impedance
means diving the ohmic value by a base impedance which is dominated by a (kV^2) term. Per Unit
Impedance = (transmission line ohms / base impedance) where base impedance = (kV^2 / MVA). Using a
common MVA base value of 100 MVA, a base impedance at 69kV = 47.6 ohms versus at 161 kV = 259.2 or
at 345 kV = 1190.2 ohms. The rapid increase of the denominator as kV goes higher insures that a 69 kV

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Exceptions — Project 2010-17

Organization

Yes or No

Question 6 Comment
system is high impedance compared to any high kV facilities and therefore nearly insure the 69 kV system is
local in nature and reacts primarily to load. Therefore it is distribution. This all supports the conclusion that all
facilites below 100 kV should be classified as distribution according to the 2005 FPA and exempted by
default. Facilities below 100 kV could be brought into scope if TPL analyses show instability, uncontrolled
separation, or cascading as defined in the 2005 FPA.

Response: The SDT appreciates your comments. Your specific concerns will be accommodated under the revised process.
Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the
technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The
initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to
establish continent-wide values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of
the facilities in question and to document the operational performance as appropriate through submittal of an exception request form along with any other
supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a
recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of
Procedure as presently being drafted.
The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.

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7. Inclusions - The SDT has set up only one path for evidence that includes technical analysis. Do you
agree with this requirement? If you do not support this requirement or you agree in general but feel
that alternative language would be more appropriate, please provide specific suggestions in your
comments. In addition, in the comment field, please provide your thoughts on the proposed metrics
for analysis and the appropriate values to replace ‘TBD,’ including technical rationale for your
argument.
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization

Yes or No

Northeast Power Coordinating
Council

No

SERC Planning Standards
Subcommittee

No

SPP Standards Review Group

No

NERC Staff Technical Review

No

Iberdrola USA

No

Tri-State Generation and
Transmission Association

No

Hydro One

No

Question 7 Comment

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Organization

Yes or No

MRO's NERC Standards Review
Forum

No

Bonneville Power Administration

No

ReliabilityFirst

No

Tennessee Valley Authority

No

PPL Supply

No

Southern Company

No

Muscatine Power and Water

No

South Carolina Electric and Gas

No

Exelon

No

Georgia Transmission
Corporation

No

Consolidated Edison Co. of NY,
Inc.

No

Springfield Utility Board

No

ISO New England

No

The United Illuminating Company

No

Entergy Services

No

Question 7 Comment

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Organization

Yes or No

American Electric Power

No

Orange and Rockland Utilities,
Inc.

No

Pepco Holdings Inc

No

Consumers Energy Company

No

American Transmission
Company, LLC

No

Manitoba Hydro

No

Independent Electricity System
Operator

No

MidAmerican Energy

No

New York Power Authority

Yes

Blachly Lane Electric Cooperative

Yes

Glacier Electric Cooperative

Yes

Flathead Electric Cooperative,
Inc.

Yes

Clark Public Utilities

Yes

Central Electric Cooperative

Yes

Consumer's Power Inc.

Yes

Question 7 Comment

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Exceptions — Project 2010-17

Organization

Yes or No

Coos-Curry Electric Cooperative

Yes

Douglas Electric Cooperative

Yes

Fall River Electric Cooperative

Yes

Lane Electric Cooperative

Yes

Lincoln Electric Cooperative

Yes

Lost River Electric Cooperative

Yes

Northern Lights Electric
Cooperative

Yes

Okanogan Electric Cooperative

Yes

Raft River Rural Electric
Cooperative

Yes

Salmon River Electric
Cooperative

Yes

Umatilla Electric Cooperative

Yes

West Oregon Electric
Cooperative

Yes

Pacific Northwest Generating
Cooperative

Yes

PNGC Power

Yes

Question 7 Comment

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Organization

Yes or No

Consumer's Power Inc.

Yes

BGE

Yes

Spyker

Yes

Benton Rural Electric Association

Yes

Clearwater Power Electric
Cooperative

Yes

Long Island Power Authority

Yes

Northern Wasco County PUD

Yes

Xcel Energy

Yes

United Electric Co-op Inc.

Yes

Oregon Trail Electric
Cooperative, Inc.

Yes

Central Lincoln

Yes

Oncor Electric Delivery

Yes

Salem Electric

Yes

Duke Energy

Yes

Grant County PUD No. 2 (Grant)

Yes

Hydro-Quebec TransEnergie

Yes

Question 7 Comment

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Exceptions — Project 2010-17

Organization

Yes or No

for Snohomish County PUD

Yes

Northwest Public Power
Association (NWPPA)

Yes

Big Bend Electric Cooperative,
Inc.

Yes

Kootenai Electric Cooperative

Yes

Tacoma Power

Yes

Edison Electric Institute

Yes

ISO/RTO Standards Review
Committee

Yes

PacifiCorp

Yes

Idaho Falls Power

Yes

Western Electricity Coordinating
Council

Yes

New York State Reliability
Council

Yes

Electric Market Policy

Yes

Question 7 Comment

Response: Thank you for your response. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a
new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide greater
continuity with the existing definition of BES. The new process requires an entity to clarify the characteristics of the facilities in question and to document the
operational performance as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being
sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or

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Exceptions — Project 2010-17

Organization

Yes or No

Question 7 Comment

inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of Procedure.

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7a. Comments on approach:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization

Yes or No

Question 7a Comment

Northeast Power Coordinating
Council

Inclusions criteria should mirror the Exclusion criteria, and that consistent values should be employed for
Inclusions here and for Exclusions above. That is, for example, if 0.95 to 1.05 (+/- 5%) p.u. is adopted as an
acceptable voltage deviation range for Exclusions, then Elements resulting in post-transient system voltage
deviations outside that range should be candidates for Inclusion. Further, all assumptions should also be fully
documented for any proposed Inclusions. Also refer to comments on exclusions.

SERC Planning Standards
Subcommittee

The PSS recommends that applications for inclusion of facilities into the BES should include justification for
doing so. However, there should not necessarily be specific criteria that must be met, but the importance of
the facility to the BES should be clearly demonstrated.

Tennessee Valley Authority
Southern Company
South Carolina Electric and Gas
Georgia Transmission
Corporation
NERC Staff Technical Review

NERC staff is not opposed to development of evidence based on technical analysis; however, we have the
same concerns with the exception criterion for including Element(s) as with exception criterion 1 for excluding
Element(s). The type of analysis included in this exception criterion requires extensive resources and lacks
sufficient detail to allow for consistent and repeatable application.
Additional concerns with this approach include (1) the ability to provide sufficient guidance on the system

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Organization

Yes or No

Question 7a Comment
conditions and contingencies necessary to support an exception request,
(2) difficulty with identifying thresholds for items iv-1 through iv-4, and
(3) the ability to address interdependencies among exception requests.

Independent Electricity System
Operator

We support the concept of technical analysis in support of Inclusions but disagree with the approach that
involves setting specific values for criteria. Please refer to our comments on exclusions.

Florida Municipal Power Agency

FMPA supports using a uniform set of technical criteria to decide inclusion exceptions. Such an approach will
facilitate uniform application of the criteria. In addition to having clear and uniform criteria, the technical
analysis for inclusions and exclusions should use the same criteria (though one should of course be the
inverse of the other). We note that the steps laid out for Inclusions do not quite track those in Exclusions 2(a).
For example, Inclusions 1(b) states, confusingly, “Monitor the contribution of the disputed Element(s),” but
there is no corresponding step in Exclusions 2(a). FMPA suggests that Inclusions 1 be revised to mirror
Exclusions 2.

Transmission Access Policy
Study Group

TAPS supports using a uniform set of technical criteria to decide inclusion exceptions. Such an approach will
facilitate uniform application of the criteria. It is appropriate for there to be only one path, using technical
analysis, for inclusions, because the analysis for inclusions should be performed by Regional Entities and
NERC (see TAPS comments on the BES Exception Process, also submitted today), which have more
resources available than do the small entities that TAPS believes are likely to request exclusions based on
the path for exclusions that does not include extensive technical analysis.In addition to having clear and
uniform criteria, the technical analysis for inclusions and exclusions should use the same criteria (though one
should of course be the inverse of the other). We note that the steps laid out for Inclusions do not quite track
those in Exclusions 2(a). For example, Inclusions 1(b) states, confusingly, “Monitor the contribution of the
disputed Element(s),” but there is no corresponding step in Exclusions 2(a). TAPS suggests that Inclusions 1
be revised to mirror Exclusions 2.

ISO/RTO Standards Review
Committee

The SRC generally agrees with the technical analysis approach to determining whether an element should be
included in the BES. However, consideration should also be given to valid and supported evidence given by
RCs and PCs, and, possibly TOPs and BAs to actual historical events that indicate significant importance of
elements which, when lost, have resulted in reliability risk to the system.

Iberdrola USA

A facility is BES if it is necessary for reliable system operation, based on a TPL-type analysis similar to NPCC
Document A-10 “Classification of Bulk Power System Elements” - this type of analysis was rejected by FERC.
In addition, applicable threshold values for these parameters could differ from one system to another, and

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Organization

Yes or No

Question 7a Comment
would require extensive analysis.

Tri-State Generation and
Transmission Association

This appears very similar to the “material impact” proposal that FERC has previously disallowed, so we
recommend removing it, but allowing elements that are included in Regional Entity defined bulk transfer paths
that are not already included in the BES definition.
If retained, remove 1.(f) because allowing the ERO to override the technical justification and analysis
devalues such analysis to the point of it being meaningless.

Hydro One

Inclusions criteria should mirror the Exclusion criteria, and that consistent values should be employed for
Inclusions here and for Exclusions above. [See our comments on exclusions]

MRO's NERC Standards Review
Forum

NSRF proposes that the technical analysis criterion be replaced by criteria that are more closely tied to the
Adequate Level of Reliability (ALR) characteristics.
The following alternate criteria are offered as possible examples, “(1) the BES cannot be controlled to stay
within acceptable limits following a fault on or loss of the Element;
(2) the BES does not perform acceptably after credible contingences of the Element;
(3) the Element limits the impact and scope of instability and cascading outages when they occur;
(4) BES facilities are not protected from unacceptable damage by operating the Element within its ratings;
(5) the integrity of the BES cannot be restored promptly following a fault on or loss of the Element; and
(6) the BES does not have the ability to supply the aggregate electric power and energy requirements of the
electricity consumers at all times, taking into account scheduled or reasonably expected unscheduled outages
of the Element.
In addition, NSRF is not aware of any continent-wide appropriate BES performance measures for voltage dip,
frequency excursion, voltage deviation, stability, etc. and NSRF speculates that different values are likely for
different regions and system characteristics across the continent. As a result, NSRF believes it is not
advisable to try to adopt unproven values without reasonable industry investigation and development.

ReliabilityFirst

to complicated and will only raise debate between FERC, NERC, the Regions and the Registered Entities

New York Power Authority

In general, NYPA agrees with this approach except as noted below. Inclusions criteria should mirror the
Exclusion criteria, and that consistent values should be employed for Inclusions here and for Exclusions

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Organization

Yes or No

Question 7a Comment
above.

National Grid

There should be a non-technical process for inclusions similar to the exclusions process.

Muscatine Power and Water

Would like to propose that the technical analysis criterion be replaced by criteria that are more closely tied to
the Adequate Level of Reliability (ALR) characteristics. The following alternate criteria are offered as possible
examples, “(1) the BES cannot be controlled to stay within acceptable limits following a fault on or loss of the
Element;
(2) the BES does not perform acceptably after credible contingences of the Element;
(3) the Element limits the impact and scope of instability and cascading outages when they occur;
(4) BES facilities are not protected from unacceptable damage by operating the Element within its ratings;
(5) the integrity of the BES cannot be restored promptly following a fault on or loss of the Element; and
(6) the BES does not have the ability to supply the aggregate electric power and energy requirements of the
electricity consumers at all times, taking into account scheduled or reasonably expected unscheduled outages
of the Element. Currently not aware of any continent-wide appropriate BES performance measures for voltage
dip, frequency excursion, voltage deviation, stability, etc. and would speculate that different values are likely
for different regions and system characteristics across the continent.
Therefore, would like to state that it is not advisable to try to adopt unproven values without reasonable
industry investigation and development.

Blachly Lane Electric Cooperative
Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative

As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should be
included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the interconnection
bulk transmission system. We also agree that the SDT has, in general, identified the correct technical
approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion analysis)
be modified as discussed in Snohomish’s White Paper, in the WECC BES Task Force Proposal 6, and in our
answer to Question 5.
While we support the SDT’s overall approach, we believe subsection (f) of the proposed inclusion criteria,
which would allow NERC to “override this criterion” if it provides “additional justification” for doing so is both
unnecessary and creates confusion and uncertainty in what is otherwise a clear and concise process.
Subsection (f) is unnecessary because if the technical process laid out in subsections (a) through (e) fails to
provide any evidence that the contested Element(s) create a material impact on the reliability of the bulk

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Organization
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative

Yes or No

Question 7a Comment
interconnected transmission network, there is no reason to classify those Element(s) as BES, and that should
be the end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but there is
no suggestion as to what this additional justification might be. Nor is there any explanation as to why
additional justification might be necessary after the criteria in subsections (a) through (e) have been
exhausted.

Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc.
Central Lincoln
for Snohomish County PUD
Glacier Electric Cooperative

I do strongly agree that there should be an avenue for elements to be included or excluded from the BES
based on technical analysis.
I do believe who's responsibility it will be to perform and analyze the transmission planning studies needs to
be clarified.

Exelon

: Exelon points out that most of the Regions don’t have Region-wide criteria for distribution factor
measurement, voltage excursions, or transient frequency response for use in this proposed Inclusion
Process.
In addition, most of the Regions do not have region-wide criteria developed for these attributes. If differing
criteria levels are used across the continent, there remains the possibility that similarly-situated facilities in
different Regions will not be treated consistently.

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Organization
Consolidated Edison Co. of NY,
Inc.

Yes or No

Question 7a Comment
We believe that Inclusions criteria should mirror the Exclusion criteria, and that consistent values should be
employed for Inclusions here and for Exclusions above. That is, for example, if 0.95 to 1.05 (+/- 5%) p.u. is
adopted as an acceptable voltage deviation range for Exclusions, then Elements resulting in post-transient
system voltage deviations outside that range should be candidates for Inclusion.
Further, all assumptions should also be fully documented for any proposed Inclusions.

Springfield Utility Board

NERC’s Exception Criteria for Inclusions states that, “Entities can submit an application to see an exception
for an inclusion in the BES...”, but SUB would ask NERC to clarify whether an entity can 1) seek an inclusion
exception for them only, or
2) can an entity seek an inclusion exception for another entity? SUB would not support another entity having
the ability to file for another entity.

Flathead Electric Cooperative,
Inc.

Elements otherwise excluded from the BES should be included only upon a technically valid showing that the
Elements contribute substantially to the potential for cascading outages, separation events, or instability on
the interconnection bulk transmission system.

Entergy Services

It is unclear why an inclusion process should be necessary. Including facilities not otherwise included in the
basic definition should be at the discretion of the TO.

Clark Public Utilities

As a general matter, Clark agrees with the SDT that Elements otherwise excluded from the BES should be
included only upon a technically valid showing that the Elements contribute substantially to the potential for
cascading outages, separation events, or instability on the interconnection bulk transmission system. Clark
also agrees that the SDT has, in general, identified the correct technical approach, although Clark
recommends that the inclusion analysis (which mirrors the technical exclusion analysis) be modified as
discussed in the Snohomish PUD White Paper, in the WECC BES Task Force Proposal 6, and in Clark’s
answer to Question 5.

Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc
Salem Electric
Grant County PUD No. 2 (Grant)
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,

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Organization

Yes or No

Question 7a Comment

Inc
Kootenai Electric Cooperative
BGE

BGE believes that there is a value in allowing for inclusions through a technical analysis path; however, it is
critical that such a path does not allow for unreasonable inclusion of facilities that do not warrant BES status.

Spyker

We agree that entities should be allowed to conduct an analysis to demonstrate if an element is necessary or
not for the operation of transmission network. We also support that NERC should specify all the relevant
criteria category to be listed as under 2 (a). However, we suggest that NERC should avoid prescribing
numerical values but establish a range of value (or reference industry standard) that would be consistent with
industry/ regional standards or practices without compromising the reliability of transmission network.

Consumers Energy Company

We believe all of the Inclusion criteria should be replaced by a single criterion, which would include any
element that could cause cascading outages of greater than 1,000 MW.

Oncor Electric Delivery

Oncor Electric Delivery agrees with the proposed language that describes the inclusion criteria based
technical analysis.

Tacoma Power

Tacoma Power generally agrees with approach used on the technical analysis path for inclusions.

Duke Energy

The approach and evaluation values should be consistent with those for the Exclusions.

American Transmission
Company, LLC

ATC proposes that the technical analysis criterion be replaced by criteria that are more closely tied to the
Adequate Level of Reliability (ALR) characteristics. The following alternate criteria are offered as possible
examples, “(1) the BES cannot be controlled to stay within acceptable limits following a fault on or loss of the
Element;
(2) the BES does not perform acceptably after credible contingences of the Element;
(3) the Element limits the impact and scope of instability and cascading outages when they occur;
(4) BES facilities are not protected from unacceptable damage by operating the Element within its ratings; and
(5) the BES does not have the ability to supply the aggregate electric power and energy requirements of the
electricity consumers at all times, taking into account scheduled or reasonably expected unscheduled outages
of the Element.

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Question 7a Comment
In addition, ATC is not aware of any continent-wide appropriate BES performance measures for voltage dip,
frequency excursion, voltage deviation, stability, etc. and ATC speculates that different values are likely for
different regions and system characteristics across the continent. As a result, ATC believes it is not advisable
to try to adopt unproven values without reasonable industry investigation and development.

Manitoba Hydro

Manitoba Hydro does not agree with an impact based approach to establishing BES elements as we believe it
will result in regional differences in the application of the BES definition. In addition, the resources required to
verify the assumptions made in the models used to substantiate a BES exception would be substantial with
no benefit to reliability.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential inclusion in the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.
New York State Reliability
Council

See answer to 5a.

Response: See response to Q5a.
PPL Supply

See comments in Questions 9 and 10

Response: See response to Q9 & Q10.
PacifiCorp

Please refer to additional comments in question 13 regarding a contiguous BES.

Response: See response to Q13.
Edison Electric Institute

See comments for Question 5 above

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Question 7a Comment

Bonneville Power Administration

Please refer to BPA’s comments on Question #5.

Orange and Rockland Utilities,
Inc.

The Inclusion criteria should mirror Exclusion criteria. See comments 5.

Pepco Holdings Inc

Same comments as question #5

Response: See response to Q5.

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7b. Comments on distribution factor measurement:
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization

Yes or No

Northeast Power Coordinating
Council

Question 7b Comment
See reply to Questions 5b and 6 above.

Response: See response to Q5b and Q6.
Consolidated Edison Co. of NY,
Inc.

See reply to Question 6.

Response: See response to Q6.
SPP Standards Review Group

Please see our comment in 5b above.

Hydro One

[See Comment 5b]

Central Lincoln

Please see 5b.

for Snohomish County PUD

Please see our response to Question 5b.

Response: See response to Q5b.
Edison Electric Institute

See comments for Question 5 above

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Organization

Yes or No

Question 7b Comment

Florida Municipal Power Agency

See FMPA comments in response to Question 5.

Transmission Access Policy
Study Group

See TAPS comments in response to Question 5.

Blachly Lane Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Clark Public Utilities

See comments in 5.

Central Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Clearwater Power Electric
Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Consumer's Power Inc.

Please see our corresponding answers to Question 5 for 7b-7e.

Coos-Curry Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Douglas Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Fall River Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Lane Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Lincoln Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Lost River Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Northern Lights Electric
Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Okanogan Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

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Organization

Yes or No

Question 7b Comment

Raft River Rural Electric
Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Salmon River Electric
Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Umatilla Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

West Oregon Electric
Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Pacific Northwest Generating
Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Consumer's Power Inc.

Please see our corresponding answers to Question 5 for 7b-7e.

Spyker

See comments in section 5

Benton Rural Electric Association

See exclusion comments Question 5

United Electric Co-op Inc.

See exclusion comment.

Oregon Trail Electric
Cooperative, Inc.

See exclusion comment

Salem Electric

See exclusion comment

Grant County PUD No. 2 (Grant)

See exclusion comment

Northwest Public Power
Association (NWPPA)

See exclusion comment

Big Bend Electric Cooperative,
Inc.

See exclusion comment

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Organization
Kootenai Electric Cooperative

Yes or No

Question 7b Comment
See Exclusion comment.

Response: See response to Q5.
Iberdrola USA

See 7a.

Independent Electricity System
Operator

[See Comment 7a]

Response: See response to Q7a.
Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

MRO's NERC Standards Review
Forum

NSRF proposes replacing this factor with those cited above because a distribution factor measurement
indicates how much system changes affect the element, not how a fault or loss of the element would
compromise the ALR of the BES. There is no clear correlation between this factor and any of the six
characteristics of Adequate Level of Reliability (ALR) of the BES.

ReliabilityFirst

any impact is an impact, even generation is re-dispatched at 0% in some cases

New York Power Authority

NYPA does not agree with this measurement. Distribution factors are dependent on the number of radial
transmission lines that connect a single source to a load. For example, if two lines connect a single source to
a load, and one line trips, the distribution factor provides a 100% increase in flow on the remaining line. If
three lines connect the source to the load, and one line trips, the distribution factor for the remaining lines
would be 50%.

Muscatine Power and Water

Proposing to replace this factor with those cited above because a distribution factor measurement indicates
how much system changes affect the element, not how a fault or loss of the element would compromise the
ALR of the BES. There is no clear correlation between this factor and any of the six characteristics of
Adequate Level of Reliability (ALR) of the BES.

Consumers Energy Company

If our suggestion in 7a is not adopted, we propose the following: If based on transfer distribution factor this
criterion may have some merit, depending on the TBD value. However, the criterion should not be based on

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Organization

Yes or No

Question 7b Comment
outage transfer distribution factor, as Draft 1 implies since loss of certain distribution facilities can result in
distribution load being transferred to other interconnection points. Distribution facilities should not be
classified as BES.

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 7a because a distribution factor measurement
indicates how much system changes affect the element, not how a fault or loss of the element would
compromise the ALR of the BES. There is no clear correlation between this factor and any of the six
characteristics of Adequate Level of Reliability (ALR) of the BES.

Tacoma Power

Tacoma Power generally agrees with the distribution factor measurement in the technical analysis path for
inclusions.
We suggest adopting a distribution factor of 30%, or more, on an adjacent system.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential inclusion in the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.

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7c. Comments on allowable transient voltage dip measurement:
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization

Yes or No

Question 7c Comment

Northeast Power Coordinating
Council

Refer to the response to Question 5c

Hydro One

[See Comment 5c]

New York Power Authority

Refer to the response to Question 5c.

Central Lincoln

Please see 5c.

for Snohomish County PUD

Please see our response to Question 5c.

Response: See response to Q5c.
Edison Electric Institute

See comments for Question 5 above

Florida Municipal Power Agency

See FMPA comments in response to Question 5.

Transmission Access Policy
Study Group

See TAPS comments in response to Question 5.

Clark Public Utilities

See comments in 5.

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Organization

Yes or No

Question 7c Comment

Spyker

See comments in section 5

Benton Rural Electric Association

See exclusion comments Question 5

United Electric Co-op Inc.

See exclusion comment.

Oregon Trail Electric
Cooperative, Inc.

See exclusion comment

Salem Electric

See exclusion comment

Grant County PUD No. 2 (Grant)

See exclusion comment

Northwest Public Power
Association (NWPPA)

See exclusion comment

Big Bend Electric Cooperative,
Inc.

See exclusion comment

Kootenai Electric Cooperative

See Exclusion comment.

Response: See response to Q5.
Iberdrola USA

See 7a.

Independent Electricity System
Operator

[See Comment 7a]

Response: See response to Q7a.
Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

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Organization
MRO's NERC Standards Review
Forum

Yes or No

Question 7c Comment
NSRF proposes replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable transient voltage dip performance level for evaluating whether a fault or loss of the
element would compromise the ALR of the BES. In addition, the appropriate performance level for this factor
may vary for different areas and system characteristics across the continent.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential inclusion in the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.
ReliabilityFirst

any impact is an impact, planning criteria between 3 & 5 % is often used and not allowed, why inject this into
what define the BES. the criteria is applied it should be included

Muscatine Power and Water

Propose replacing this factor with those cited above because there is presently no established, continentwide, acceptable transient voltage dip performance level for evaluating whether a fault or loss of the element
would compromise the ALR of the BES. In addition, the appropriate performance level for this factor may vary
for different areas and system characteristics across the continent.

Consumers Energy Company

If our suggestion in 7a is not adopted, we propose the following: The criterion related to Transient Voltage
Deviations should be removed from the Inclusion Process. This criterion, regardless of value TBD, would
cause any element, perhaps even including radial Primary Distribution Facilities (8.2 kV, etc.) to be
sequentially included as BES.A fault on non-BES elements will cause significant transient voltage dips on
nearby BES elements until the fault is cleared. If the non-BES element is at the same voltage level, the dip
will result in near-zero voltages; if at different voltage levels, the dip magnitude will be determined by the ratio
of the system Thévinen impedance at the BES to the intervening transformer impedance - if the system
Thévinen impedance is 2% and the transformer impedance is 18%, the voltage on the BES will dip to 10%.

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 7a because there is presently no established,
continent-wide, acceptable transient voltage dip performance level for evaluating whether a fault or loss of the
element would compromise the ALR of the BES. In addition, the appropriate performance level for this factor

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Organization

Yes or No

Question 7c Comment
may vary for different areas and system characteristics across the continent.

Tacoma Power

Tacoma Power generally agrees with allowable transient voltage dip measurement in the technical analysis
path for inclusions.
We suggest adopting the criteria that includes a transient voltage dip exceeding 20% for more than 20 cycles
on an adjacent system’s bus.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential inclusion in the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.

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7d. Comments on allowable transient frequency response:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization

Yes or No

Question 7d Comment

Northeast Power Coordinating
Council

Refer to the response to Question 5d

Hydro One

[See comment 5d]

New York Power Authority

Refer to the response to Question 5d.

Central Lincoln

Please see 5d.

for Snohomish County PUD

Please see our response to Question 5d.

Response: See response to Q5d.
Edison Electric Institute

See comments for Question 5 above

Florida Municipal Power Agency

See FMPA comments in response to Question 5.

Transmission Access Policy
Study Group

See TAPS comments in response to Question 5.

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Organization

Yes or No

Question 7d Comment

Clark Public Utilities

See comments in 5.

Spyker

See comments in section 5

Benton Rural Electric Association

See exclusion comments Question 5

United Electric Co-op Inc.

See exclusion comment.

Oregon Trail Electric
Cooperative, Inc.

See exclusion comment

Salem Electric

See exclusion comment

Grant County PUD No. 2 (Grant)

See exclusion comment

Northwest Public Power
Association (NWPPA)

See exclusion comment

Big Bend Electric Cooperative,
Inc.

See exclusion comment

Kootenai Electric Cooperative

See Exclusion comment.

Response: See response to Q5.
Iberdrola USA

See 7a.

Independent Electricity System
Operator

[See Comment 7a]

Response: See response to Q7a.
Tri-State Generation and

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for

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Organization

Yes or No

Question 7d Comment

Transmission Association

determining the threshold value.

MRO's NERC Standards Review
Forum

NSRF proposes replacing this factor with those cited above because there are established, continent-wide
transient frequency performance levels in the PRC-006-1 standard, but the elements that are applicable to the
standard do not have to be BES elements and the transient frequency response requirements are not
intended to be a criterion for BES classification.

ReliabilityFirst

any impact is an impact, stability and planning criteria are often used and restricted and guard against these
changes, why inject this into what define the BES. if the criteria is applied it should be included

Muscatine Power and Water

Propose replacing this factor with those cited above because there are established, continent-wide transient
frequency performance levels in the PRC-006-1 standard, but the elements that are applicable to the
standard do not have to be BES elements and the transient frequency response requirements are not
intended to be a criterion for BES classification.

Consumers Energy Company

If our suggestion in 7a is not adopted, we propose the following: The criterion relative to frequency response
should be removed. Frequency deviations can result from large changes in distribution load. Distribution
facilities should not be classified as BES.

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 7a because there are established, continentwide transient frequency performance levels in the PRC-006-1 standard, but the elements that are applicable
to the standard do not have to be BES elements and the transient frequency response requirements are not
intended to be a criterion for BES classification.

Tacoma Power

Tacoma Power generally agrees with the allowable transient frequency response in the technical analysis
path for inclusions. We suggest adopting the criteria that includes a transient frequency response that goes
below 59.6 Hz for up to 6 cycles on an adjacent system’s bus.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential inclusion in the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft

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Organization

Yes or No

Question 7d Comment

Rules of Procedure.

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7e. Comments on voltage deviation measurement:
Summary Consideration: The SDT appreciates your comments. Based on industry response and further analysis, the SDT has
abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics that
are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The new process requires an
entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate
through submittal of an exception request form along with any other supporting documentation for the exception being sought.
The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to
support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules
of Procedure.

Organization

Yes or No

Northeast Power Coordinating
Council

Question 7e Comment
See reply to Questions 5e and 6 above.

Response: See response to Q5e and Q6.
Consolidated Edison Co. of NY,
Inc.

See reply to Question 6.

Response: See response to Q6.
Hydro One

[See comment 5e]

New York Power Authority

Refer to the response to Question 5e.

Central Lincoln

Please see 5e.

Response: See response to Q5e.
Edison Electric Institute

See comments for Question 5 above

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Organization

Yes or No

Question 7e Comment

Florida Municipal Power Agency

See FMPA comments in response to Question 5.

Transmission Access Policy
Study Group

See TAPS comments in response to Question 5.

Clark Public Utilities

See comments in 5.

Spyker

See comments in section 5

Benton Rural Electric Association

See exclusion comments Question 5

United Electric Co-op Inc.

See exclusion comment.

Oregon Trail Electric
Cooperative, Inc.

See exclusion comment

Salem Electric

See exclusion comment

Grant County PUD No. 2 (Grant)

See exclusion comment

Northwest Public Power
Association (NWPPA)

See exclusion comment

Big Bend Electric Cooperative,
Inc.

See exclusion comment

Kootenai Electric Cooperative

See Exclusion comment.

Response: See response to Q5.
Iberdrola USA

See 7a.

Independent Electricity System

[See Comment 7a]

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Organization

Yes or No

Question 7e Comment

Operator
Response: See response to Q7a.
Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

MRO's NERC Standards Review
Forum

NSRF proposes replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable (steady state) voltage deviation performance level for evaluating whether a fault or
loss of the element would compromise the ALR of the BES. In addition, the appropriate performance level for
this factor may vary for different areas and system characteristics across the continent

ReliabilityFirst

any impact is an impact, planning criteria is often used and restricted to guard against these changes, why
inject this into what define the BES. the criteria is applied to the facility as a BES element it should be
included

Muscatine Power and Water

Propose replacing this factor with those cited above because there is presently no established, continentwide, acceptable (steady state) voltage deviation performance level for evaluating whether a fault or loss of
the element would compromise the ALR of the BES.
In addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.

Consumers Energy Company

If our suggestion in 7a is not adopted, we propose the following: This criterion may be reasonable, depending
on the TBD value. The TBD value may need to vary for different voltage levels or system configurations.
Loss of multiple capacitors at the distribution level could result in significant voltage deviation at the BES and
the criterion should be developed so as not to result in Distribution facilities being classified as BES.

for Snohomish County PUD

Please see our response to Question 5d.

Response: See response to Q5d.
American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 7a because there is presently no established,
continent-wide, acceptable (steady state) voltage deviation performance level for evaluating whether a fault or
loss of the element would compromise the ALR of the BES.

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Organization

Yes or No

Question 7e Comment
In addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent

Tacoma Power

Tacoma Power generally agrees with the voltage deviation measurement in the technical analysis path for
inclusions. We suggest adopting a voltage deviation that exceeds 10% on an adjacent system’s bus.
We have an additional concern with how the language is constructed on items d. and e. The inclusion criteria
may work for simply inverting the exclusion language but in this initial draft, it does not appear to work as
intended. Our suggestions above are describing criteria for defining elements that can be included in the BES.
If that is the result to be adopted by the SDT, items d. and e. must be rewritten to state that elements within
such criteria can be included in the BES.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential inclusion in the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.

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8. Do you have concerns about an entity’s ability to obtain the data they would need to do the indicated
technical analyses? If so, please be specific with your concerns so that the SDT can fully understand
the problem and address it in future drafts.
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an
entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as
presently being drafted.

Organization

Yes or No

Northeast Power Coordinating
Council

No

SERC Planning Standards
Subcommittee

No

NERC Staff Technical Review

No

Iberdrola USA

No

Hydro One

No

MRO's NERC Standards Review
Forum

No

Question 8 Comment

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Organization

Yes or No

Question 8 Comment

Bonneville Power Administration

No

The owner of the asset should have all the data necessary to perform the analysis for an Exclusion. The
Exclusion analysis should use the same data request and sharing requirements of other NERC standards and
the owner conducting the Exclusion analysis should consult with other entities as necessary.

PacifiCorp

No

Tennessee Valley Authority

No

Idaho Falls Power

No

No comments

New York State Reliability
Council

No

NPCC A-10 criteria data is freely available.

New York Power Authority

No

Southern Company

No

National Grid

No

Muscatine Power and Water

No

South Carolina Electric and Gas

No

Georgia Transmission
Corporation

No

ISO New England

No

The United Illuminating Company

No

Entergy Services

No

BGE

No

NERC modeling Standards should be sufficient

No comment.

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Organization

Yes or No

Question 8 Comment

Spyker

No

Orange and Rockland Utilities,
Inc.

No

Xcel Energy

No

Oncor Electric Delivery

No

Duke Energy

No

Hydro-Quebec TransEnergie

No

American Transmission
Company, LLC

No

Tacoma Power

No

MidAmerican Energy

No

American Electric Power

Yes

Each criterion specified would not be able to be provided, or even applicable, for each exclusion requested. If
the criteria provided may be selected from as necessary for each request, then we have no concerns on our
ability to provide the data. Our only concern would be if the intent is that each and every criterion specified
must be provided for each request made.

Pepco Holdings Inc

Yes

The entity may not have the tools, model or resources to do a full transmission planning study

Flathead Electric Cooperative,
Inc.

Yes

Obtaining data creates a cost and should be minimized as possible.

Exelon

Yes

As mentioned above, this process will require extensive technical analysis from users, owners, operators and
the Regions. In many cases, the Principles anticipate the use of criteria that is not in existence today. Rather
than reinforcing the bright line approach, these Principles have the potential to create processes that will
result in high costs with little to no corresponding benefits to reliability.

Tacoma Power has no comment at this time.

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Organization

Yes or No

Question 8 Comment

Glacier Electric Cooperative

Yes

It could be very, very difficult and costly for small utilities to perform the necessary transmission planning
studies described in the proposal. I think there needs to be language clarifying how smaller utilities should be
able to obtain this data.

Electricity Consumers Resource
Council (ELCON)

Yes

NERC (and the BES SDT) should not assume that data pursuant to Large Generator Interconnection
Agreements (LGIA) or the Large Generator Interconnection Procedures (LGIP) will be forthcoming on a timely
basis for the purpose of demonstrating BES exceptions. While such information is generally available from
ISOs and RTOs, it is not so forthcoming from vertically-integrated utilities in regions of the country not served
by ISOs or RTOs because such utilities are generally hostile to third-party generation in their service territory.
They are capable of delaying or otherwise obstructing requests for data and information. We recommend that
NERC or the SDT identify mechanisms for requesting and getting the necessary data and information. This
process should be included in the NERC Rules of Procedure.

Western Electricity Coordinating
Council

Yes

The Owner should have all of the data to perform this analysis for an Exclusion; however, an Inclusion would
likely be sought by an entity other than the Owner (i.e., Regional Entity, RC, BA, TOP) that may not have
sufficient data. It should be clarified in the Rules of Procedure that such an entity has the right to request such
data and that the Owner must provide such data.

ReliabilityFirst

Yes

many smaller entities would require assistance and or consultants to perform this analysis and some data
many not be available or be shared etc.

Edison Electric Institute

Yes

Method 2 is largely based on System Planning Criteria developed by WECC. At the present time, we do not
believe that any of the other regions have similar planning criteria for which they could use or could easily
integrate similar criteria into useable Planning Standards which could be applied in useful manner across all
regions. For this reason, it is recommended that a separate Design Committee be created which would
include representatives from all regions. It is expected that this effort may be substantial but is necessary
before Method 2 or the Inclusion Process as written could be used.
We would further caution the use or imposition of such a process since some transmission owners may not
have the necessary skills or tools required to conduct studies of this type (in-house) and imposing this level of
evidence will likely cause many who cannot meet this requirement to include unnecessary elements diluting
the BES as defined and negating the value of the exclusion process.

Electric Market Policy

Yes

Generation Owners and Generation Operators are typically not given access to non-public transmission
information, especially that where a NDA or CEII signature is required. It would be virtually impossible for a
GO to refute proposed inclusion of an Element owned by the GO unless they procure the services of a

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Organization

Yes or No

Question 8 Comment
consulting firm with access to the data. And, even then, the consultant couldn’t provide specifics of the
evaluation only their findings.

Tri-State Generation and
Transmission Association

Yes

Response: The SDT appreciates the comments concerning an entity’s ability to obtain the required information and technical analysis to meet the requirements of
the technical exception criterion. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new
methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity
with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become
apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form along with
any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a
recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.
Blachly Lane Electric Cooperative
Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative

No

As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where additional
data will need to be provided to run a valid technical analysis under the criteria set forth in the Exception
Procedure. These cases should be exceedingly rare, however, because the starting point for the technical
analysis we recommend is the current base case operated by the relevant RE, and in nearly every case, the
base case can be expected to model any Element that conceivably has a material impact on the reliable
operation of the bulk system. In those rare cases where it does not, we believe the owner or operator of the
subject Element should be able to provide the needed data, although we propose that the relevant owner or
operator be relieved of this burden if it can be demonstrated that the nearest electrically interconnected
Element has no material impact on the bulk system.

Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative

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Organization

Yes or No

Question 8 Comment

No

As discussed on page 12 of the Snohomish White Paper, there may be a few isolated cases where additional
data will need to be provided to run a valid technical analysis under the criteria set forth in the Exception
Procedure. These cases should be exceedingly rare, however, because the starting point for the technical
analysis Clark recommends is the current base case operated by the relevant Regional Entity, and in nearly
every case, the base case can be expected to model any Element that conceivably has a material impact on
the reliable operation of the bulk system. In those rare cases where it does not, we believe the owner or
operator of the subject Element should be able to provide the needed data.

Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc
Central Lincoln
Clark Public Utilities
Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc.
Oregon Trail Electric
Cooperative, Inc
Salem Electric
Grant County PUD No. 2 (Grant)
for Snohomish County PUD
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc.
Kootenai Electric Cooperative
Response: The SDT believes that the technical criteria represent a base line of information to be presented for justification of the exception. If the applicant

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Organization

Yes or No

Question 8 Comment

believes that additional information is needed to justify their request, the SDT agrees that the entity should be able to provide any additional information it believes
necessary. The SDT disagrees that the Regional Entity should assess the adequacy of the application. In order to ensure consistency and uniformity across the
continent, the ERO, not the Regional Entity, can be the only institution to conduct this analysis.
Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the
technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The
initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to
establish values and/or limits that would be valid across all regions and systems. The new process requires an entity to clarify the characteristics of the facilities in
question and to document the operational performance as appropriate through submittal of an exception request form along with any other supporting
documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of
whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of Procedure.
Manitoba Hydro

No

We are concerned however that assumptions could be made to complete the technical analysis to support an
exclusion that may not be appropriate.

Response: The SDT believes that unwarranted assumptions will be identified in the process and such information will be made available to the industry to
prevent others from utilizing similar assumptions.
Independent Electricity System
Operator

No

We anticipate that entities would be granted access to any required historical operations records and
modeling data after signing of non-disclosure agreements as necessary.

Response: Thank you for your comment.
Consumers Energy Company

Yes

CECo is not able to formulate detailed comments at this time, as the criteria have not been finalized. There
are a number of items that are somewhat open ended, i.e. TBD and Other. Once those gray areas are filled
in, we will have a better idea of our ability to obtain the necessary data.

Response: The SDT looks forward to your future comments.
Long Island Power Authority

Yes

The Reliability Coordinator would be required to provide much of the data needed to perform the technical
analyses.

Response: The SDT believes that the burden of proof for the exception is on the applying entity. The applying entity can utilize any resource including other
Registered Entities in presenting their case to the ERO.

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Organization

Yes or No

PPL Supply

Yes

Question 8 Comment
See comments in Questions 9 and 10

Response: See response to Q9 & Q10.

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9. Are you aware of any conflicts between the proposed approach and any regulatory function, rule
order, tariff, rate schedule, legislative requirement or agreement, or jurisdictional issue? If so, please
identify them here and provide suggested language changes that may clarify the issue.
Summary Consideration: Most of the commenters expressed that they were not aware of specific conflicts associated with the BES
exception technical principles and regulatory/jurisdictional matters. However, a substantial number of commenters answering “no” and “yes”
raised concerns that the BES Definition and the Exception Technical Principles should respect FPA Section 215 authority limitations. Commenters
to this question did not provide suggestions for addressing this concern.
Based on the extensive comments received by entities about FPA Section 215 authority excluding local distribution systems, the SDT modified the
BES definition to provide additional clarity in this regard. Specifically, the SDT inserted language into the core of the revised BES definition.
WECC and another commenter brought up concerns associated with the applicability of a specific NERC reliability standard (i.e., IRO-010).
ReliabilityFirst expressed concerns about the proposed BES definition changing the NERC Statement of Compliance Registry Criteria (SCRC). It
should be emphasized that the goal of the SDT is to provide clarity to the BES definition and the technical principles for the NERC Rules of
Procedure (RoP) exception process. The SDT’s scope of work does not include potential changes to the SCRC. The SDT has debated this matter
extensively and believes that NERC reliability standards may be applied to non-BES Elements.
A few commenters brought up concerns about specific unique situations (e.g., black start Cranking Paths in local distribution systems). The SDT
cannot address each and every unique regulatory situation in the BES definition and technical principles for the Rules of Procedure (RoP)
exception process. Entities would need to submit relevant regulatory evidence on a case by case basis using the RoP exception process.
However, the SDT did delete the reference to Cranking Paths.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements operated at 100 kV or higher and Real Power
and Reactive Power resources connected at 100 kV or higher. This does not include facilities used in the local distribution of electric energy.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.

Organization

Yes or No

Question 9 Comment

Bonneville Power Administration

No

Under NERC Standard IRO-010, the Transmission Operators are required to obtain information relating to the
operation of the bulk power system within their respective areas. Transmission Operators may still need
information relating to network facilities that ultimately are determined not to be BES facilities. BPA is
concerned that an exclusion could eliminate a requirement that such information be provided.

ReliabilityFirst

Yes

FERC stated that entities registered were not to be taken off the registry without sound reasons and the
definition sole intent was not to restrict or remove entities, but put in place a sound definition that everyone

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Organization

Yes or No

Question 9 Comment
can use. I do not think this is a help, it is very detailed and allot of entities will be confused and lost

Western Electricity Coordinating
Council

Yes

It must be clear that under NERC Standard IRO-010, the Reliability Coordinators are required to obtain
information relating to the operation of the bulk power system within their respective areas. In light of this
requirement, Reliability Coordinators may request the submittal of information for network facilities that
ultimately are not determined to be BES facilities. It would be reasonable to also include a requirement that
Reliability Coordination staff will explain why they require the requested information from non-BES facilities
when seeking such information.

Response: The goal of the SDT is to provide clarity to the BES Definition and the technical principles for the Rules of Procedure exception process not to
address the NERC Statement of Compliance Criteria Registry (SCRC) and the applicability of specific reliability standards. NERC reliability standards may be
applied to non-BES Elements that are necessary for operating the interconnected transmission network.
City of Redding

Yes

State and court rulings that have defined Transmission and Distribution. One possible solution is to state that
the determination made via this methodology is for reliability purposes only and is not intended to redefine
established market and rate determinations.

Northeast Power Coordinating
Council

Yes

It is imperative to understand that the NERC’s revised definition will have a direct impact on entities across
North America and may conflict with regulatory requirements, Codes, and Licenses. FERC in its Orders 743
and 743A has directed NERC to address these concerns. For Ontario, the BES exception criteria shall meet
the expectations of Ontario's regulator (Ontario Energy Board) which has the sole authority and responsibility
for the reliability of customer connections and loads within Ontario. Therefore, it will be necessary to
accommodate NERC's proposed definition of BES or the exception process with the Ontario situation.

Hydro One
Spyker

The SDT and RoP teams should: o Modify the exception criteria and procedure to provide regulatory
flexibility with requirements to conduct basic technical analysis , to allow entities to consistently present their
case to the ERO and/or the regulator for a step by step expedited evaluation.
o Include provisions in both the NERC exception criteria and exception process for federal, state and
provincial jurisdictions. These provisions should provide clear guidance so that, if and when there are
deviations from the exception criteria, they are identified with technical and regulatory justifications ensuring
there is no adverse impact on the interconnected transmission network.
o Understand that the path to generating facilities need not be always BES contiguous. Generating units
can/should be required to be planned, designed, and operated in accordance with a subset of NERC
Standards, but should not always require contiguous paths.

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Organization

Yes or No

Question 9 Comment

Edison Electric Institute

Yes

EEI is concerned that under the technical principles, some facilities that are local distribution facilities may be
included the BES. This is in conflict with the definition of the Bulk Power System in Section 215 which
excludes facilities used in local distribution. In particular, EEI is concerned that the provision of the technical
principles prohibiting the seeking an Exclusion for a cranking path will include local distribution within the
definition of BES.

Consolidated Edison Co. of NY,
Inc.

Yes

See the EEI reply to BES Definition and Designations Question 11.

PacifiCorp

Yes

The SDT proposal combined with the ROP proposal may be in conflict with Section 215 of the Federal Power
Act, which requires “facilities used in the local distribution of electric energy” be excluded. The processes
proposed may be over inclusive and by default require several elements which are not required for the
reliable operation of the BES to in fact be included in the definition of “BES.”

Flathead Electric Cooperative,
Inc.

No

the proposed BES Definition could conflict with Section 215 of the Federal Power Act if the Definition, the
Exception Process, and the Technical Criteria do not effectively exclude facilities used in local distribution
from the BES or if the BES definition does not focus on cascading outages, separation events, and instability
on the interconnected bulk system. These statutory limits on the scope of the BES and reliability standards
are a minimum that must be met.

Electricity Consumers Resource
Council (ELCON)

Yes

The proposed technical principles violate the exemption in FPA section 215 against the inclusion in the BES
of facilities used in the local distribution of electric energy, given that the BES is a subset of the BPS.

Exelon

Yes

To the extent facilities used in local distribution of electric energy may be included in the BES, the proposed
principles are in conflict with the Federal Power Act.

Occidental Energy Ventures
Corp.

Yes

The proposed technical principles seem to be in contradiction to the exemption in FPA Section 215 against
the inclusion in the BES of facilities used in the local distribution of electric energy.

Central Lincoln

No

As we explained in our response to Question 1 of the Comment Form on the 1st Draft of Definition of BES,
filed on May 27, Central Lincoln believes that the proposed BES Definition could conflict with Section 215 of
the Federal Power Act if the Definition, the Exception Process, and the Technical Criteria do not effectively
exclude facilities used in local distribution from the BES or if the BES definition does not focus on cascading
outages, separation events, and instability on the interconnected bulk system. These statutory limits on the

for Snohomish County PUD

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Organization

Yes or No

Question 9 Comment
scope of the BES and reliability standards are a minimum that must be met.

The United Illuminating Company

Yes

under the technical principles, some facilities that are local distribution facilities may be included the BES.
This is in conflict with the definition of the Bulk Power System in Section 215 which excludes facilities used in
local distribution. In particular, Local distribution facilities can not be included in the BES even if they are part
of a cranking path.

Pepco Holdings Inc

Yes

Facilities defined as local distribution facilities should not be forced into BES classification due to this new
bright line definition.

Consumers Energy Company

Yes

The Technical Principles for Demonstrating BES Exceptions should not conflict with the seven-factor test
provisions of FERC Order 888. In particular, provisions should not be established by the Standard Drafting
Team that contradict prior Commission rulings associated with seven-factor test provisions.

Hydro-Quebec TransEnergie

Yes

However, there is a conflict between the proposed approach and the regulatory framework applicable in the
Quebec's Interconnexion or at least there are some important differences between both. Paragraph 95 of
FERC Order 743 acknowledged the situation of non-FERC juridiction. As for the Quebec's Interconnexion, the
BES definition and exclusion approach shall meet the expectations of Quebec's regulator, the Régie de
l'Énergie du Québec, (Quebec Energy Board) which has the responsibility to ensure that electric power
transmission in Quebec is carried out according to the reliability standards it adopts. In a recent order (D2011-068), the Régie de l'Énergie du Québec has recognized several level of application for the
Reliability Standards in Québec. It stated specifically that most reliability standards in Québec shall be
applied to the Main Transmission System (MTS). One other level of application recognised by this decision is
the NPCC Bulk Power System (BPS) to which the standards related to the protection system (PRC-004-1 and
PRC-005-1) and those related to the design of the transmission system (TPL 001-0 to TPL-004-0) will be
applicable (including the rest of the standards). The Main Transmission System definition is somewhat
different than the Bulk Electric System definition. The Main Transmission System includes elements that
impact the reliability of the grid, supply-demand balance and interchanges. It can be described as follows :The
transmission system comprised of equipments and lines generally carrying large quantities of energy and of
generating facilities of 50 MVA or more controlling reliability parameters: o Generation/load balancing o
Frequency control o Level of operating reserves o Voltage control of the system and tie lines o Power flows
within operating limits o Coordination and monitoring of interchange transactions o Monitoring of special
protection systems o System restoration
Therefore, it will be necessary to accommodate NERC's proposed definition of BES or the exception process
with the Quebec situation where Entities are under a different jurisdiction. These differences include more

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Organization

Yes or No

Question 9 Comment
than one level of application for the reliability standards, the Main Transmission System definition being the
main one to which most reliability standards apply.

Manitoba Hydro

Yes

Canadian Entities are not under FERC jurisdiction, so the revised BES Definition may not apply.
A number of Canadian Entities have the BES defined within their provincial legislation. This may introduce
differences and even contradictions between elements that are included in the BES according to provincial
legislation and the NERC definition.

Independent Electricity System
Operator

Yes

Similar to the BES Exception Procedure, the document “Technical Principles for Demonstrating BES
Exceptions” must explicitly recognize the authority of Canadian and Mexican Governmental Entities to adopt
the Technical Principles for Demonstrating BES Exceptions in its entirety or in part with their own deviations,
while ensuring there will be no adverse impact on the interconnected transmission system. Footnote 2 of the
“Procedure for Requesting and Receiving an Exception from the Application of the NERC Definition of Bulk
Electric System” should be repeated in the “Technical Principles” document.

Response: The SDT has clarified this position.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements operated at 100 kV or higher and Real Power and
Reactive Power resources connected at 100 kV or higher. This does not include facilities used in the local distribution of electric energy.
Electric Market Policy

Yes

Dominion is concerned that the provision of the proposed technical principles prohibiting the seeking of an
exclusion for a cranking path for blackstart resources will include local distribution facilities within the definition
of the BES. This conflicts with the definition of “Bulk Power System” in Section 215 of the Federal Power Act,
which excludes facilities used in local distribution.

Response: The SDT has deleted the reference to Cranking Paths.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
PPL Supply

Yes

Based on FERC Order 743 paragraph 120, radial and local distribution facilities should be excluded from the
definition of the Bulk Electric System (BES). The exclusion of non-networked facilities such as radial lines is
further re-enforced with Order 743 paragraph 73 which describes the characteristics of a network and does
not include most generator interconnection facilities. In that order, FERC justified its bright-line, 100 kV
threshold, explaining that "many facilities operated at 100 kV and above have a significant effect on the
overall functioning of the grid" because they share the following characteristics: 1. "operate in parallel with
other high voltage and extra high voltage facilities"i. The “bright line” at 100 kV recognizes many 100 kV lines

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Exceptions — Project 2010-17

Organization

Yes or No

Question 9 Comment
parallel other HV/EHV lines and can be significantly loaded by failure of the HV/EHV lines. This does not
apply to radial lines, even at 100 kV and above.2. "interconnect significant amounts of generation sources"
(emphasis added)3. "operate as part of a defined flow gate"4. have a "parallel nature" and are capable of
“caus[ing] or contribute[ing] to significant bulk system disturbances”.i. Radial lines cannot cause significant
BES disturbances since the outage of a radial line is studied in all N-1 planning studies and if the TPL
standards are followed, an N-1 should not cause such disturbances.Excluding generator lead lines is very
practical because the physical reality of a radial generator lead line is that it cannot be overloaded by outages
on parallel paths because there are no parallel paths. Further, the MW flow on a radial line is well known and
limited to a known maximum (limited to the larger of the generation or load on the end of the line); clearly
these are reasons for excluding radial lines. When and if a generator lead line is tapped by another generator
or load, it is possible that the line between the tap point and the original point of interconnection might need to
be rolled into the electrical network. However, at that time, it might also be possible for the transmission
owner to purchase the line and make the tap point the new point of interconnection.

Response: The SDT cannot address each and every unique situation in the technical principles for the Rules of Procedure (RoP) exception process. Entities
would need to bring relevant evidence on a case by case basis using the RoP exception process.
Springfield Utility Board

Yes

o The four characteristics defined in the “Exception Criteria - Exclusions” portion of Technical Principles for
Demonstrating BES Exceptions appears to be in conflict with, rather than in parallel to, the exceptions which
are part of the proposed “core definition” in the Proposed Continent-wide Definition of Bulk Electric System.
SUB proposes that NERC postpone work related to Technical Principles for Demonstrating BES Exceptions
until a continent-wide BES definition is approved.
o FERC Order No. 743 states, “We believe that it would be worthwhile for NERC to consider formalizing the
criteria for inclusion of critical facilities operated below 100 kV in developing the exemption process”.
However, there is no mention of critical facilities operated below 100 kV in NERC’s Exception Criteria. SUB
would encourage NERC to include critical facilities consideration in their exception criteria.

Response: The SDT is responsible for completing NERC Project 2010-17 (related to the BES Definition process and the exception technical principles process)
before year-end. The SDT does not have sufficient time to bifurcate the two processes.
The technical principles for the Rules of Procedure exception process as proposed by the SDT allows for presenting exception evidence for including critical
Elements energized below 100 kV into the Bulk Electric System.
SERC Planning Standards
Subcommittee

No

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Organization

Yes or No

SPP Standards Review Group

No

NERC Staff Technical Review

No

Iberdrola USA

No

Tri-State Generation and
Transmission Association

No

MRO's NERC Standards Review
Forum

No

Idaho Falls Power

No

New York Power Authority

No

Southern Company

No

ITC

No

National Grid

No

Muscatine Power and Water

No

Blachly Lane Electric Cooperative

No

South Carolina Electric and Gas

No

Glacier Electric Cooperative

No

Georgia Transmission
Corporation

No

Question 9 Comment

We believe that the final drafts of the definition and exemptions should comport to the legal requirements of
Section 215.

Insufficient time was provided to fully undertake this inquiry.

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Organization

Yes or No

Entergy Services

No

Clark Public Utilities

No

Central Electric Cooperative

No

Clearwater Power Electric
Cooperative

No

Consumer's Power Inc.

No

Coos-Curry Electric Cooperative

No

Douglas Electric Cooperative

No

Fall River Electric Cooperative

No

Lane Electric Cooperative

No

Lincoln Electric Cooperative

No

Lost River Electric Cooperative

No

Northern Lights Electric
Cooperative

No

Okanogan Electric Cooperative

No

Raft River Rural Electric
Cooperative

No

Salmon River Electric
Cooperative

No

Question 9 Comment

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Organization

Yes or No

Question 9 Comment

Umatilla Electric Cooperative

No

West Oregon Electric
Cooperative

No

Pacific Northwest Generating
Cooperative

No

PNGC Power

No

Consumer's Power Inc.

No

Benton Rural Electric Association

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

American Electric Power

No

AEP is not aware of any conflicts between the proposed approach and any regulatory function, rule order,
tariff, rate schedule, legislative requirement or agreement, or jurisdictional issue.

Orange and Rockland Utilities,
Inc.

No

BGE

No

No comment.

Northern Wasco County PUD

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

Xcel Energy

No

United Electric Co-op Inc.

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

Oregon Trail Electric
Cooperative, Inc.

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

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Organization

Yes or No

Question 9 Comment

Oncor Electric Delivery

No

Salem Electric

No

Duke Energy

No

Grant County PUD No. 2 (Grant)

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

Northwest Public Power
Association (NWPPA)

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

Big Bend Electric Cooperative,
Inc.

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section 215

American Transmission
Company, LLC

No

Kootenai Electric Cooperative

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

Tacoma Power

No

Tacoma Power is not aware of any conflicts at this time.

MidAmerican Energy

No

ACES

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

Response: Thank you for your response.

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Exceptions — Project 2010-17

10. Are there any other concerns with this approach that haven’t been covered in previous questions
and comments? Please be as specific as possible with your comments.
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an
entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as
presently being drafted.

Organization

Yes or No

SERC Planning Standards
Subcommittee

No

Iberdrola USA

No

Bonneville Power Administration

No

ReliabilityFirst

No

Tennessee Valley Authority

No

Idaho Falls Power

No

New York State Reliability
Council

No

Question 10 Comment
The comments expressed herein represent a consensus of the views of the above-named members of the
SERC EC Planning Standards Subcommittee only and should not be construed as the position of SERC
Reliability Corporation, its board, or its officers.

No comments

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Exceptions — Project 2010-17

Organization

Yes or No

South Carolina Electric and Gas

No

Glacier Electric Cooperative

No

Exelon

No

Georgia Transmission
Corporation

No

Consolidated Edison Co. of NY,
Inc.

No

Entergy Services

No

Clark Public Utilities

No

Orange and Rockland Utilities,
Inc.

No

Xcel Energy

No

Duke Energy

No

Hydro-Quebec TransEnergie

No

New York Power Authority

No

Question 10 Comment

Response: Thank you for your response. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a
new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide greater
continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It
has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new process
requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to
validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO

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Exceptions — Project 2010-17

Organization

Yes or No

Question 10 Comment

as established in the Rules of Procedure as presently being drafted.
BGE

No

It is important to consider that the Technical Principles for Demonstrating BES Exceptions is only one part of
the BES definition project. The Technical Principles and the Rule of Procedure Process must be evaluated
together with the BES Definition to sufficiently understand the revisions. In the end, the Technical Principles
and the BES Definition must coalesce and be clearly coordinated and understood. The BES Definition
language must include reference to the role of the associated defining documents. One unambiguous
document must not be made ambiguous by an associated document or process.
We appreciate the work of the drafting team and support the goal to produce clear definition language so that
upwards of 95% of the assets are clearly distinguished as either included or excluded from the BES. We are
particularly sensitive to the potential for burdensome processes (e.g. TFEs) to be added to reliability
compliance. We appeal to the team for continued, vigilant consideration of the arduousness of the BES
determination process.

Response: The upcoming posting of the BES definition and the technical principals will be posted simultaneously in order for industry to adequately evaluate the
two documents and their relationship to each other.
Oncor Electric Delivery

No

Although Oncor Electric Delivery understands the need for the ERO to be in a position to override the
inclusion criterion,
Oncor desires more clarity on what factors contribute to an overriding action.

ACES

Yes

The term interconnected transmission network is used throughout this document. Bulk Electric System
should be used in its place. The purpose of the technical principles is to determine if an Element is needed to
support the operation of the Bulk Electric System. Using interconnected transmission network adds more
uncertainty to the document.

Northeast Power Coordinating
Council

Yes

Exception criteria should be crafted at a high-level with key menu items of assessment that can be followed
continent-wide by entities to put forward their exception(s) for element(s) that are not necessary for the
interconnected transmission network based on technical assessment, evidence and justification for unique
characteristics, configuration, and utilization. (Also see suggestions/ comments in Question 6)

SPP Standards Review Group

Yes

In Question 5 regarding the Transient and Steady State Stability criteria, we would suggest establishing
criteria for the damping such that the time required to return to normal is limited. Damping in 1-5% range may
be sufficient to accomplish this.

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Exceptions — Project 2010-17

Organization

Yes or No

Question 10 Comment
Also, delete 2.a.iv.8. in the Exclusion Criteria and 1.c.8. in the Inclusion Criteria.

NERC Staff Technical Review

Yes

A criterion should be added for supporting a request for inclusion of an Element. If an Element has been
identified as causal or contributory to a Category 2 or higher event as defined in the ERO Event Analysis
Process, that should be sufficient evidence that it is necessary for the Element to be planned, designed,
maintained, and operated in accordance with NERC Reliability Standards. An assessment of the Element
should include consideration of any corrective actions that have been implemented to prevent a reoccurrence.
The Exception criteria also should include a list of characteristics of Elements that will not be considered for
exclusion, on the basis that this list of characteristics already identifies the importance of such Elements to
reliable operation of the interconnected transmission network. Characteristics should include: (1) Elements
that are relied on in the determination of an Interconnection Reliability Operating Limit (IROL); (2) Blackstart
resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration
plan regardless of voltage, (3) Elements subject to Nuclear Plant Interface Requirements (NPIRs) as agreed
to by a Nuclear Plant Generator Operator and a Transmission Entity defined in NUC-001, and (4) Elements
identified as required to comply with a NERC Reliability Standard by application of criteria defined within the
standard (e.g., the test defined in PRC-023 to identify sub-200 kV Elements to which the standard is
applicable.)

Florida Municipal Power Agency

Yes

The third paragraph of the introduction to the Technical Principles is awkwardly worded and might be
misconstrued. FMPA suggests the following rewording: “Entities are not required to seek exceptions under
the Exception Procedure to exclude from the BES Element(s) that are already excluded under the BES
definition and designations.”For the sake of consistency, Exclusions (1) should contain a provision analogous
to Exclusions (2)(b) and Inclusions (1)(f) addressing the circumstances under which the ERO can override a
demonstration based on these criteria. As noted above, one of those circumstances would be a
demonstration by NERC that the Element in question meets the criteria for inclusion in the BES.

Yes

The proposed principles seem preliminary and immature. In addition as noted in earlier comments they are
not fully consistent with the proposed BES definition, particularly with respect to radial elements and local
distribution networks. Such consistency should be incorporated before the next posting.

Transmission Access Policy
Study Group

Tri-State Generation and
Transmission Association

We further feel that it is very unlikely that the technical evidence path can be placed on a sound technical
foundation and matured by the end of this year as directed by the FERC.
Key definitions are lacking and should be added to the document. For instance “distribution factor” is not
carefully defined even though such factors can be calculated in a variety of ways.

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Exceptions — Project 2010-17

Organization

Yes or No

Question 10 Comment

Hydro One

Yes

Exception criteria should be crafted at a high-level with key menu items of assessment that can be followed
continent-wide by entities to put forward their exception for element(s) that are not necessary for the
interconnected transmission network and based on technical assessment, evidence and justification for its
unique characteristics, configuration, and utilization. (Also see suggestions/ comments on Question 6)

MRO's NERC Standards Review
Forum

Yes

1. NSRF proposes replacing the wording in the Exclusion preface, Exclusion 2 preface, and Inclusion 1
preface of “not necessary to reliably operate the interconnected transmission network” with “necessary to
maintain an Adequate Level of Reliability (ALR) of the Bulk Electric System”.
2. NSRF has reservations on the following statement made in the introduction of this document:” Due to the
importance of Blackstart Resources and their designated blackstart Cranking Paths to restoration efforts, no
exceptions will be allowed for those items.” This does not allow for a provision to exclude any designated
Blackstart Cranking Path (at any voltage) even though there may be technical justification for it.
3. The first page states that “Specific content of this application is spelled out elsewhere in this appendix.”
NSRF requests the SDT describe where this appendix will be published. Furthermore, is it a compliance
document or just technical “guidance”?
4. Having the following statement included for both exclusions and inclusions will create disagreement:”The
ERO can override this criterion but would need to provide additional justification to support their finding.”
NSRF believes any override should have adequate technical justification and not interfere with other statutory
requirements. Also, it does not clarify or identify who would make the determination whether NERC has made
adequate justification to override the criterion.
5. NSRF believes that the “Inclusion” process should be completely removed from BES Definition. We
recommend using bright-line criteria indentifying everything 100 kV and above to be BES and then allow for
the “Exception” process to take out facilities that do not impact the reliability of the BES. Selecting BES
facilities based on a right-line criteria is what FERC requested in its Order regarding BES Definition. This
would streamline the process and remove some unnecessary paperwork.

MidAmerican Energy

Yes

MidAmerican supports the NSRF comments.

PacifiCorp

Yes

The SDT has proposed several technical criteria to be used to determine if an element has an impact on the
reliability of the BES. PacifiCorp believes that the majority of non-BES elements can be excluded using a
modified proposed bright-line and/or using the non-technical approach. However, in the event an entity
requires additional justification to remove non-BES elements from the BES, then PacifiCorp feels the
technical criteria should be established on an interconnection basis, not on a continent-wide basis. Because

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Organization

Yes or No

Question 10 Comment
of the number of operating and geographic differences among the interconnections, to try to establish
technical criteria on a continental basis would introduce confusion. PacifiCorp believes it is impossible to
establish technical criteria that will allow unique interconnections to be treated in a comparable manner.

Western Electricity Coordinating
Council

Yes

The biggest concern is that the Technical Principles and the reasoning behind them need to be fully
explained. The SDT has mentioned on calls the possibility of a white paper or resource document, and WECC
fully supports the creation of such a document. This white paper should describe the rationale for the criteria
as well as how that indicates that the element is necessary for reliable operation.
Also, the justification for the ERO to override these criteria should be clarified. It should be clear that the
ERO’s ability to override these criteria is on a case-by-case basis.

Electricity Consumers Resource
Council (ELCON)

Yes

The bright-line tests used in the revised BES definition and technical principles may capture the facilities of
hundreds of entities that may not know that NERC exists or the enforceability of NERC Reliability Standards.
The technical principles should be supplemented with a technical guide or appendix that provides examples
of the steps that may be necessary to demonstrate BES exceptions.

Alabama Public Service
Commission

Yes

The second paragraph of the proposed Technical Principles states that “[d]ue to the importance of Blackstart
Resources and their designated blackstart Cranking Paths to restoration efforts, no exceptions will be allowed
for those items.” This sentence should be deleted from the technical principles. An unintended consequence
of subjecting all blackstart cranking pathways to inclusion in the BES by default would be to cause a
Registered Entity, in order to minimize costs, to not declare every possible cranking path but instead limit to
the minimum required cranking paths in order to comply with the standards, as opposed to designating
multiple pathways. This consequence could be avoided by allowing blackstart cranking pathways to be
evaluated for exceptions just like any other element.

Southern Company

Yes

The Technical Principles document suggests that no exceptions be allowed for Blackstart Resources and
designated Cranking Paths. Southern Company is concerned with the treatment of these facilities and
recommends that certain statements be removed. In Project 2010-17 Definition of the BES, Southern
Company commented that the proposed inclusion, Inclusion I4, be removed from the BES Definition because
an existing NERC Reliability Standard, EOP-005-2 System Restoration from Blackstart Resources, already
addresses these facilities regardless of voltage.
Further, the proposed inclusion will expand the applicability of some NERC Reliability Standards to facilities
below 100 kV. Southern Company believes this position will unnecessarily cause more facilities to become
applicable to reliability standards without any benefit to reliability. Therefore, we recommend the following
statement be deleted: “Due to the importance of Blackstart Resources and their designated blackstart

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Organization

Yes or No

Question 10 Comment
Cranking Paths to restoration efforts, no exceptions will be allowed for those items.”

National Grid

Yes

The exception process should be strictly limited to the procedures for application and approval and should not
include substantive elements.

Muscatine Power and Water

Yes

1. Propose replacing the wording in the Exclusion preface, Exclusion 2 preface, and Inclusion 1 preface of
“not necessary to reliably operate the interconnected transmission network” with “necessary to maintain an
Adequate Level of Reliability (ALR) of the Bulk Electric System”.
2. Currently having reservations concerning the following statement made in the introduction of this
document:” Due to the importance of Blackstart Resources and their designated blackstart Cranking Paths to
restoration efforts, no exceptions will be allowed for those items.” This does not allow for a provision to
exclude any designated Blackstart Cranking Path (at any voltage) even though there may be technical
justification for it.
3. The first page states that “Specific content of this application is spelled out elsewhere in this appendix.”
Request the SDT describe where this appendix will be published and indicate if this is a compliance
document or just technical “guidance”?
4. By having the following statement included for both exclusions and inclusions will lead to
disagreement:”The ERO can override this criterion but would need to provide additional justification to support
their finding.” Suggesting that any override should include adequate technical justification and not interfere
with other statutory requirements. Also, it does not clarify or identify who would make the determination
whether NERC has made adequate justification to override the criterion.
5. Do not believe that the “Inclusion” process should be completely removed from BES Definition. Would like
to recommend using bright-line criteria indentifying everything 100 kV and above to be considered BES and
then allow for the “Exception” process to take out Facilities that do not have an impact on the reliability of the
BES. Selecting BES Facilities based on bright-line criteria is what FERC requested in its Order regarding
BES Definition. This would streamline and simplify the process by removing a large quantity of exceedingly
unnecessary paperwork.

Blachly Lane Electric
Cooperative
Central Electric Cooperative
Clearwater Power Electric

Yes

In general, , as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES definition itself
does not clearly resolve. However, we caution that these principles for demonstrating exceptions cannot, and
must not, take the place of a consideration of, and criteria under whether, any specific piece of equipment is
subject to FERC, the ERO, and Regional Entity jurisdiction in the first instance. Section 215 of the Federal
power Act (FPA) sets out clear limits of jurisdiction of FERC, the ERO, and Regional Entities for purposes of

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Organization
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative

Yes or No

Question 10 Comment
developing and enforcing reliability standards. Specifically, Section 215(i) provides that the ERO “shall have
authority to develop and enforce compliance with reliability standards for only the Bulk-Power System.” 16
U.S.C. § 824o(a)(1) (emphasis added). Section 215(a)(1) of the statute defines the term “Bulk-Power
System” or “BPS” as: (A) facilities and control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof); and (B) electric energy from generation facilities needed
to maintain transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition should
expressly account for these jurisdictional limitations up front. This would allow for the jurisdictional limitation
consideration as the very first step in determining whether or not a particular piece of equipment is part of the
BES.
The Technical Principles for Demonstrating BES Exceptions, on the other hand, provides a completely
separate set of criteria for exclusion from the BES and would come into play only after application of the full
BES definition to a particular piece of equipment and determination that the BES definition does not provide a
satisfactory answer as to whether that piece of equipment is or is not part of the BES. This is acceptable
insofar as it goes, but, because (1) the criteria in the Technical Principles are distinct from the jurisdictional
limits of Section 215 of the FPA, and (2) consideration of the Technical Principles would essentially be the
last, or one of the last, steps in the process, the Technical Principles cannot substitute for, in any way,
consideration of the jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how
important it is to have the jurisdictional consideration be the very first step in the process of determining
whether a particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES definition
that is both workable and lawful.

West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc
New York State Department of
Public Service

The core BES definition based on a 100 kV brightline is an overreach of bulk system designation under the
provisions of the Federal Power Act; a properly specified BES core definition would avoid the extensive
analysis required under the exceptions procedure. That said, the proposed principles for use in the
exceptions process are consistent with previous FERC efforts to distinguish between transmission and local
distribution.
The upfront exclusion of applying the proposed principles to blackstart cranking path facilities is a potential

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Question 10 Comment
overreach into the local distribution system and can be counter productive reliability. Mandating compliance
of NERC standards to cranking paths will result in the specification of only one cranking path by host utilities
to minimize costs, where designating multiple paths in restoration paths would provide the flexibility needed to
minimize customer outage duration.

Springfield Utility Board

Yes

SUB has the following concerns regarding NERC’s Technical Principles for Demonstrating BES Exceptions:
o Clear Definition of Radial - As previously addressed in our BES Definition comments, SUB would encourage
a more clear definition of a “radial” versus “closed-loop” system. Because there still appears to be
inconsistencies in both definition and application, SUB encourages NERC to develop a concise definition of a
radial system. For example, if a system is normally operated as radial, but could be operated as closed (by
manually closing a breaker), would it be considered a radial or close-looped system? If the answer is closelooped, then is this in all cases, or are there exceptions?
o Approval of Exceptions - SUB would like for NERC to clarify the process for receiving, reviewing, and
accepting or rejecting exception applications. The Technical Principles for Demonstrating BES Exceptions
states that, “...will be subject to review and remand by the ERO itself, or by any agency having regulatory or
statutory oversight of NERC as the ERO.” During NERC’s presentation at APPA’s BES Definition webinar, it
was explained that the exception process would look like the following:1. Entity applies for expemption,2.
Region receives application, verifies received, and forward to NERC with recommendation(s), and 3. NERC
makes final determination (decision is appealable by entity).For consistent application of the expemption
procedure, SUB would encourage NERC to adopt the process as it was communicated during the APPA
webinar, with regions making recommendations, but NERC making the final decision.
o Duration of Approved Exclusions/Inclusions - The Technical Principles for Demonstrating BES Exceptions
does not indicate the duration for approved exclusions or inclusions. How long are granted
exclusions/inclusions? Permanent? Annual? Other?
o Publication of Exceptions - For consistent application, as well as transparency and accountability, SUB
would request that all exceptions be published ; those applied for, as well as whether they were rejected or
accepted, as well as decision rationale.

ISO New England

Yes

Any generator that is studied individually will not be shown as material since the electric system is designed to
allow the outage of any individual generator. Generators must be studied within the context of the electric
system to assess materiality. The generator and its interconnecting transmission facilities would likely be able
to be excluded based on this process although they meet the Registry Criteria thresholds requiring inclusion.

The United Illuminating

Yes

UI is concerned that the method used to characterize exclusions in Method 1 did not follow the proposed BES

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Yes or No

Company

Question 10 Comment
Definition and believe the process developed for Method 2 (and reused for Sub-100kV Inclusions) is overly
complicated, lacks necessary regional standards to support the process and may prove too difficult for some
companies to fully comply with thereby discouraging a consistent and uniform application of the definition
across all regions and affected BES element owners.
These Principles are not technical Principles. Further the use of these Planning criteria and impact
assessments is not very different from the NPCC functional test that drew the ire of FERC. The Drafting
Team is attempting to develop definitions and identifiers for the fringes of the bulk power system, but they are
replacing one set of ambiguities with a set of technical ambiguity. This product is poor because given the
very first term, that is the first principle to be met, is those facilities necessary for the reliable operation of an
interconnected transmission system, is full of undefined concepts such that anything attempting to define it in
a subtle manner is immediately lost in the ether.
Recognizing that these technical principles will be permanent, UI suggests excluding them and sticking with
the bright line exclusions and inclusions in the proposed definition.

Occidental Energy Ventures
Corp.

Yes

The Technical Principles and the new BES Definition seem to include a significant number of retail customers
as proposed. Surely this is not the intent of these changes.
There should be an exclusion along the lines of Comment 6.

Flathead Electric Cooperative,
Inc.

Grant County PUD No. 2 (Grant)

supports the approach to the exclusion process proposed by the SDT, which provides two different paths to
exclusion, one based on readily-identifiable operational characteristics of a system, and one based on
technical reliability analysis. We believe it is important to provide for the first path, based on operational
characteristics, so that systems that are marginally disqualified under the BES Definition (because, for
example, generation within the system exceeds demand for a few hours a year) can obtain an exclusion
without the large investment of resources that otherwise might be required for a full-scale technical analysis.
we question whether the first subsection of the characteristic test, relating to system proximity, is necessary,
and we are concerned that the requirement that a system meet all four requirements of the characteristics test
may be overly restrictive. For example, it is easy to imagine a distribution system in a rural area that covers a
widely dispersed area, so that load is many miles from the relevant generation/transmission source, and that
the system therefore does not meet the electrical proximity element, but meets the other three elements of the
characteristics test. Such a system should be excluded because it clearly serves a local distribution function,
and not a transmission function, as demonstrated by the fact that the system meets subsections (c) (power
flows into the system but rarely flows out ) and (d) (power is not intentionally transported over the system).
Accordingly, we recommend that the SDT consider eliminating the first test.

Big Bend Electric Cooperative,

In the alternative, the SDT should consider allowing exempting a system from the BES if it, for example,

Benton Rural Electric
Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc
Central Lincoln
Salem Electric

Yes

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Inc

Question 10 Comment
meets three of the four criteria rather than all four.

Northwest Public Power
Association (NWPPA)
Kootenai Electric Cooperative
Spyker

Yes

Exception criteria should be crafted at a high-level with key menu items of assessment that can be followed
continent-wide by entities to put forward their exception for element(s) that are not necessary for the
interconnected transmission network and based on technical assessment, evidence and justification for its
unique characteristics, configuration, and utilization.

American Electric Power

Yes

AEP appreciates the work that the drafting teams have done within the various deliverables related to the
BES definition, technical principles for demonstrating BES exceptions, and the BES definition exception
process. AEP acknowledges the benefits of agreeing to a BES definition and exception process, and
appreciates the drafting teams’ requests for industry involvement.
Due to the interrelated nature of the deliverables currently out for review regarding the BES definition and
exception processes, it is difficult if not impossible, to comment “in isolation” on any individual facet of the
project. For example, there needs to be a defined relationship between an approved definition of BES, the
technical principles for demonstrating BES exception, and the exception process itself. When closely related
projects such as these are done simultaneously, no individual deliverable can rely on the completed work of
another. As a result, we risk having conflicting decision making across these projects. As a result, AEP is not
in the position to make further comments at this time beyond those recently and concurrently made regarding
the BES definition and technical principles for demonstrating BES exceptions. We suggest that further work
on these efforts, when appropriate, become more consolidated and that care be taken to not undertake
concurrent efforts before sufficient progress has been made on important aspects of the project. AEP
appreciates the drafting teams’ requests for industry input, and looks forward to its future involvement after
additional progress has been made on these issues.

Consumers Energy Company

Yes

In addition to the owner, only those with jurisdictional authority, such as the ERO and RRO, should be
permitted to register Exception Requests. A third party may have a business reason for wishing to encumber
another entity with regulatory compliance risk and responsibility. In addition, this could create an additional
strain on the Exception Request process due to an excessive number of requests from third parties.
We do want to ensure that the term "Other", used in Exclusion Section 2.a.iv.8., and Inclusion Section 1.c.8.,
not remain in the final Technical Principles document.

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Organization
for Snohomish County PUD

Yes or No

Question 10 Comment

Yes

Snohomish County PUD generally supports the approach to the exclusion process proposed by the SDT,
which provides two different paths to exclusion, one based on readily-identifiable operational characteristics of
a system, and one based on technical reliability analysis.
We believe it is important to provide for the first path, based on operational characteristics, so that systems
that are marginally disqualified under the BES Definition (because, for example, generation within the system
exceeds demand for a few hours a year) can obtain an exclusion without the large investment of resources
that otherwise might be required for a full-scale technical analysis.
That being said, we question whether the first subsection of the characteristic test, relating to system
proximity, is necessary, and we are concerned that the requirement that a system meet all four requirements
of the characteristics test may be overly restrictive. For example, it is easy to imagine a distribution system in
a rural area that covers a widely dispersed area, so that load is many miles from the relevant
generation/transmission source, and that the system therefore does not meet the electrical proximity element,
but meets the other three elements of the characteristics test. Such a system should be excluded because it
clearly serves a local distribution function, and not a transmission function, as demonstrated by the fact that
the system meets subsections (c) (power flows into the system but rarely flows out ) and (d) (power is not
intentionally transported over the system). Accordingly, we recommend that the SDT consider eliminating the
first test.
In the alternative, the SDT should consider allowing exempting a system from the BES if it, for example,
meets three of the four criteria rather than all four.We have pasted in the text of our White Paper below.
Please contact us for a more readable version of the White Paper.White PaperA Performance-Based
Exemption Process to Exclude Local Distribution Facilities from the Bulk Electric System April 2011 This
White Paper proposes a transmission planning (“TPL”) “performance-based” process to determine the local
distribution facilities the North American Electric Reliability Corporation (“NERC”) must exclude from the Bulk
Electric System (“BES”) pursuant to Section 215(a)(1) of the Federal Power Act (“FPA”).
This process would apply to those local distribution facilities that are not automatically excluded under a
bright-line BES definition. Consistent with Federal Energy Regulatory Commission (“FERC”) Order Nos. 743
and 743-A, a performance-based exemption process would be objective, consistent, and transparent, and
would adequately differentiate between local distribution and transmission, i.e., BES, facilities.
I. What Is Reliability? FPA Section 215 authorizes NERC to promulgate “reliability standards,” subject to
FERC approval. Section 215 defines “reliability standard” to mean a properly-approved requirement “to
provide for the reliable operation of the bulk-power system.” The statute, in turn, defines “reliable operation”
to mean “operating the elements of the bulk-power system within equipment and electric system thermal,
voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will

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Question 10 Comment
not occur as a result of sudden disturbances, including . . . unanticipated failure of system elements.”
II. What Is “Customer Service” or “Level of Service” (“LOS”)? Local customer service or LOS relates to
service failures on local utility systems that are wholly internalized rather than spilling onto the interconnected
regional grid. These types of service failures relate to local customer service and LOS standards. The
customers of those utilities will bear the full cost of complying with internal LOS standards and will obtain the
full benefit of compliance to the extent that service levels on those systems improve. Accordingly, state public
utility commissions (for regulated utilities) and independent boards (for non-regulated utilities) can fully and
accurately weigh whether the benefits of compliance with such standards are justified by the costs they will
pay. Intervention by NERC and a Regional Entity is not needed because a utility’s actions related to level of
service on its own system will neither unduly burden the customers of other systems, threaten the reliable
delivery of power to those customers, nor create incidental benefits to those remote customers. In the
absence of the need to protect customers of systems remote from the consequences of decisions made by an
individual utility, there is no warrant for NERC or a Regional Entity to interfere with a utility’s internal decisionmaking about the appropriate LOS to its own customers, and the costs that will be borne by those customers
to achieve any particular level of service. In fact, in the “Savings Provisions” of Section 215, Congress
specifically included language prohibiting NERC and Regional Entities from enforcing “compliance with
standards for adequacy” of electric service. By law, these remain the exclusive province of local decisionmakers.
III. The Need for a Material Impact Test In Order No. 743-A, FERC clarified that a material impact test is
appropriate in the reliability context if the test can be shown to identify facilities needed for reliable operation.
The following example of an outage demonstrates the need for an impact test to distinguish between LOS
and Reliability, i.e., local distribution facilities and BES facilities.
A. Pre-Event Facts Local Utility Administration (“LUA”) owns a 115 kV system that moves power from two
points of delivery (“POD”) and serves 1000 MW of load. A DC battery rack had an unexpected failure a few
days after it was routinely inspected and LUA has not implemented Supervisory Control and Data Acquisition
(“SCADA”) so the DC battery voltage is not continuously monitored. The LUA system interconnects with BES
Company’s system which consists of 230 kV and 500 kV lines.
B. Event Facts A fault occurs and the breakers in substation 2 fail to operate due to a battery failure (Figure
1). This results in an outage for customers served by substations 1, 2, and 3 on the LUA system. Figure 1
C. Post-Event Facts Immediately after the outage, LUA customer service receives numerous customer calls
followed by a call from its Public Utility Commission/Local Utility Board (“/PUC/LUB”). LUA dispatches crews
immediately after being informed of the outage to identify and resolve the problem. Within 45 minutes, the
fault is sectionalized and the all load is restored. The PUC/LUB receives complaints from LUA customers
who identify economic and other adverse impacts of the outage. The PUC/LUB demands a report from the

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LUA that describes the event and restoration, as well as potential solutions. LUA submits a report which finds
that the main solution to this problem involves the implementation of a SCADA system. The SCADA system
scope of work includes battery voltage telemetry and would have identified the DC system issue and
prevented the protection system failure, resulting in only the loss of substation 3. The SCADA plan cost
estimate is $30 million and was presented three years earlier. The PUC/LUB evaluated the costs and
benefits of the new SCADA system, but did not approve the project in order to reduce the budget and/or
provide rate stability for the struggling local economy. LUA, the PUC/LUB, and customers will re-evaluate the
merits of adding SCADA as well as other solutions such as increasing substation inspection runs, updating
the batter fleet, and further investigating battery manufacture reliability records. Based on the LUA report, the
battery bank failure rate immediately after routine inspections is expected to occur once every 3,500 years.
Seventy battery banks are used on the LUA system, so a bank failure should be expected every 50 years.
BES Company’s neighboring 230kV and 500kV system does not experience an adverse system impact.
Subsequently, BES Company identifies that one of its breakers operated at the LUA South POD. BES
Company and LUA coordinate a review of the system protection scheme and BES Company determines that
it operated correctly. BES Company verifies that the LUA outage did not create any thermal, voltage, or
transient stability limit violations on the BES Company system. The Regional Entity, NERC, and FERC treat
the outage as a Reliability Standards issue. The LUA System (highlighted in yellow) is considered part of the
BES because it meets the “bright line” 20 MVA and 100 kV thresholds under the current BES definition and
the NERC Statement of Compliance Registry Criteria (“SCRC”). The event would most likely be considered a
TPL-003 category C event specifically C8 SLG Fault, with delayed clearing that may include a stuck breaker
or protection system failure. The LUA Substation Department reviews its inspection records and has
adequate documentation for the battery banks involved in the outage. As a result, LUA avoids substantial
fines. However, during the inspection review, LUA notices that the battery bank in a similar distribution
substation inspection schedule was completed three days late. Upon following further internal procedures,
LUA finds that the battery bank was inspected three days late due to restorations efforts after a major wind
storm. Although there were no LOS impacts, and the inspection schedule was unrelated to the outage, the
Reliability Standards triggered a LUA self report to its Regional Entity which ultimately resulted in a $50,000
penalty.
D. Summary This example identifies that in addition to a “bright line” BES exclusion process a more refined
process such as a “performance based” reliability assessment is needed to distinguish BES facilities from
distribution facilities if the NERC Statement of Compliance Registry Criteria (“SCRC”) continues to be the
benchmark for assessing BES facilities. It is clear from this example that the current 100 kV and 20 MVA
thresholds cannot accurately classify what is and is not considered part of the BES. Defining BES facilities is
important from the “Reliability Standard” and “LOS” perspectives as well as from a local and regional
jurisdictional standpoint. There are multiple agencies identifying and approving what facilities should and
should not be built, what programs should and should not be implemented, and if a fine should be paid by

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Question 10 Comment
customers experiencing an outage without determining if it could have had an adverse impact on neighboring
electric systems. Without a performance-based process, many small and medium electric utilities would be
unnecessarily burdened.  
IV. Neighboring System Rule It is important but not always easy to distinguish the difference between
“reliability” and “LOS” impacts. One way to resolve this is to use the “neighboring system rule.”
Simplistically, if events on the host system’s facilities can create an “adverse” or “material” impact on a
neighboring electric (TO, TOP, BA) system, those facilities should be considered part of the BES as they are
creating a reliability impact. If not, these facilities should not be considered part of the BES.
V. “Adverse” or “Material” Impact A key question in applying the “neighboring system rule” is what is an
“adverse” or “material” impact, and what “performance based” assessment should be used to benchmark
adverse or material. Because the electric system within an interconnection is frequency interdependent,
theoretically every system change impacts the interconnected system to some degree. Turning on a lightswitch that is connected to an operational 20 watt CFL (light bulb) theoretically impacts frequency, although to
an undetectable degree. Therefore the term “material” or “adverse” impacts must be defined to distinguish
observable impacts that affect reliability from minutia. A number of performance based exclusion examples
have been proposed that use, Power Transfer Distribution Factors (“PTDF”), Line Outage Distribution Factors
(“LODF”), fault duty or short circuit levels, reactive margin studies (P-V and Q-V), abbreviated or focused
powerflow and transient stability analysis, as well as complete TPL assessment using multiple seasonal base
cases, loading conditions, transfer levels. These methods demonstrate various metrics, they rank system
strength (both real and reactive), the ability of power to flow through system under normal and outage
conditions, and they determine steady state, voltage stability and transient (angular) stability performance.
Although there may be advantages to a multi-step “performance based” approach that includes the exclusion
examples above, this paper proposes a TPL-based assessment that is consistent with BES performance
benchmarks used in assessing transmission system performance in North America. The Western Electricity
Coordinating Council (“WECC”) BES Exclusion/Inclusion Assessment - 2-16-11 version provides a sound
metrics in assessing the performance of a system as well as determining if a system can materially impact a
neighboring system (Figure 2). It would be envisioned that each interconnection would develop a
“Disturbance Performance Table of Allocable Effects on Other System”. This table is necessary because the
NERC TPL Performance Table does not provide actual performance details on acceptable transient and post
transient voltage perturbations or minimum transient voltage frequencies. Figure 2 show the approved TPL001 through TPL-004 performance tables.Figure 3 - Table 1 from the NERC TPL Reliability Standards 
VI. Performance Based Assessment Process The “performance based” methodology below is based on the
“neighboring system rule” and the WECC BES Exclusion/Inclusion Assessment - 2-16-11 that was developed
by the WECC Bulk Electric System Definition Task Force (“BESDTF”). The process focuses on exclusions
rather than inclusion and specific response times, schedules, and process details have been removed as this

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will likely need to be determined by each, Regional Entity Representing the Interconnection (“RERI”)
A. Purpose The purpose of this document is to set forth a “performance based” technical process for
assessing whether elements with a nominal operating voltage greater than 100 kV and outside the NERC
SCRC based excursion process should be excluded from the Bulk Electric System. An element is necessary
to reliably operate an interconnected transmission system if it significantly affects neighboring Transmission
Owners, Operators, and Balancing Authorities as described in Table 1 below. This paper proposes a method
for assessing whether an element is necessary to support the reliability of an interconnected transmission
system or if the element is limited to supporting local customer service levels.
B. TermsExclusion Assessment (EA) An assessment of whether a Subject Element or System has a material
impact on neighboring Transmission Owners, Operators, and Balancing Authorities as described in Table 1
below and conducted in accordance with the process set forth in this document.EA Base Case The
interconnection approved, Base Case as modified to include the Subject Element, used to perform the
assessment described in this document.Regional Entity Representing the Interconnection The regional entity
representing the interconnectionRegistered Entity The entity registered to comply with mandatory reliability
standards for a Registered Function.Responsible Entity The entity responsible for performing the EA and
verifying the results of the EA to the interconnection.Subject System or Element of a System The System or
Element of a System that is being examined by the EA.
C. Applicabilitya. An EA may be performed:i. By a registered entity, or by a third party on behalf of a
registered entity, to assess whether a Subject Element or system has a material impact on neighboring
Transmission Owners, Operators, and Balancing Authorities as described in Table 1 may be excluded from
the BES as set forth by the RERI. ii. The RERI, or by a third party on behalf of the RERI, to assess whether a
Subject Element or system has a material impact on neighboring Transmission Owners, Operators, and
Balancing Authorities as described in Table 1 should be included as part of the BES as set by the RERI.b.
Frequency of analysis. The confirmed findings of an EA are valid until reversed by a subsequent EA. A new
EA is required if:i. Significant changes are made to the network topology in the vicinity of the Subject
Element; orii. RERI staff requests a new EA. Such request shall be provided in writing and shall include
reasonable justification for the request.
D. Notifying the RERI of the Responsible Entity’s intent to submit an EA finding or to perform an EA.The
Responsible Entity shall notify the RERI in writing of its intent to submit such a finding. Such notice shall
include:a. A general description of the Subject Element(s);b. One-line diagrams representing the Subject
Element and applicable neighboring Elements; andc. A description of the base case that will be used in
performing the EA and how that case will be stressed for the analysis.
E. Performing the Analysis Base Case The base case(s) used for the studies shall be developed from current
interconnection Operating Cases and shall simulate stressed conditions in the area of the element to be

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analyzed which (1) are reasonably expected to be achieved, consistent with the study period selected (e.g.,
hydro generation shall reflect seasonal water availability patterns) and (2) are expected to provide “worstcase” results (i.e., the greatest impact on voltage, flow, or transfer capability) during the upcoming operating
year. The base case(s) shall be “stressed” by committing or de-committing generating units and adjusting
generating unit output to increase the flow on the candidate element and the electrically nearest rated
interconnection transfer path to the greatest extent possible, but not beyond their continuous ratings, for the
initial set of conditions. To help minimize the possibility of dispute as to whether the base case(s) are suitably
stressed, entities are encouraged to solicit input from subregional planning groups or other planning entities
as the suitability of the base case(s) before undertaking the analyses described below.i. Non-represented
Elements. If the Subject Element is not represented in the EA Base case:1. The Responsible Entity shall
provide to the RERI a written request to add the Responsible Entities data to the cases:o all data reasonably
necessary to accurately and completely model the Subject Element in the EA Base case; ando A one-line
diagram showing this element and other nearby Elements. If the nearest connected Element is not found to
be necessary for the operation of an interconnected transmission system, the RERI shall notify the
Responsible Entity to take no further action.
F. Performance Based Methodology The impact an System or Element has on neighboring Transmission
Owners, Operators, and Balancing Authorities as described in Table 1 shall be determined by assessing the
performance of key measures of BES reliability through power flow, post-transient, and transient stability
analysis with (1) the system, and the Subject Element, operating at reasonably stressed conditions that
replicate expected system conditions under which the loss of the Subject Element would have the greatest
impact on the key measures of reliability, and (2) the Subject Element removed from service, but without
allowing for system readjustment. For the purposes of this analysis, “Elements” may be: (1) lines; (2)
transformers; (3) buses or bus sections; (4) generating units; (5) shunt devices . i. Simulation 1: Requirement:
Meet applicable NERC Reliability Standard (TPL-002 and TPL-003) and the RERI Disturbance Performance
Table of Allocable Effects on Other System” Criteria performance for NERC TPL-002 and TPL-003
disturbances.Step 1: Run appropriate TPL-002 (N-1 contingency) studies of elements in the electrical vicinity
of and including the Candidate Element (i.e., simulate primary protection operates as intended)Step 2: Run
appropriate TPL-003 (N-2 contingency) studies of elements in the electrical vicinity of and including the
Candidate Element. This would include both N-2 contingencies in which the Candidate Element would
simultaneously be lost as part of a common mode failure, as well as contingencies in which the Candidate
Element’s primary protection fails.Automatic Remedial Action Schemes (“RAS”) or Special Protection
Schemes (“SPS”) that are fully redundant (i.e., their failure is not credible) may be triggered during this
simulation. If the failure of the RAS/SPS is a credible event, it should be considered as part of the N-2
analysis. ii. Simulation 2:Requirement: Remove the Candidate Element. Do not allow for system
adjustment, and re-solve the base case. Then conduct applicable NERC Reliability Standard (TPL-002 and
TPL-003) contingencies. Step 1: Remove Candidate Element (i.e., simulate unplanned opening of

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facility).Step 2: Assume no system adjustment. At this point, elements may be loaded above their continuous
ratings but may not be loaded above their emergency ratings. Step 3: Perform NERC TPL-002 and TPL-003
(N-1 and N-2 contingency) studies.Step 4: If the analysis demonstrates performance that meets or exceeds
that called for in the NERC Reliability Standards and RERI System Performance Criteria, the Candidate
Element would be determined to not be necessary for the operation of an interconnected transmission
system. Note: Consequential load tripping is allowed, and consequential and out-of-step generation tripping
is allowed.CriteriaTable 1: RERI Disturbance-Performance Table of Allowable Effects on Other
SystemsNERC and WECC Categories Outage Frequency Associated with the Performance Category
(outage/year) Transient Voltage Dip Standard Minimum Transient Frequency Standard Post Transient
Voltage Deviation StandardASystem normal Not Applicable Nothing in addition to NERCBOne elementout-ofservice  0.33 Not to exceed 25% at load busses or 30% at non-load busses.Not to exceed 20% for more
than 20 cycles at load busses. Not below 59.6Hz for 6 cycles or more at a load bus. Not to exceed 5% at any
bus.CTwo or more elementsout-of-service 0.033 - 0.33 Not to exceed 30% at any bus.Not to exceed 20% for
more than 40 cycles at load busses. Not below 59.0Hz for 6 cycles or more at a load bus. Not to exceed 10%
at any bus.DExtreme multiple-element outages < 0.033 Nothing in addition to NERC Figure 1. Voltage
Performance Parameters RERI TPL criteria related to reactive power resources:1. For transfer paths,
voltage stability is required with the pre-contingency path flow modeled at a minimum of 105% of the path
rating for system normal conditions (Category A) and for single contingencies (Category B). For multiple
contingencies (Category C), post-transient voltage stability is required with the pre-contingency transfer path
flow modeled at a minimum of 102.5% of the path rating.2. For load areas, voltage stability is required for the
area modeled at a minimum of 105% of the reference load level for system normal conditions (Category A)
and for single contingencies (Category B). For multiple contingencies (Category C), post-transient voltage
stability is required with the area modeled at a minimum of 102.5% of the reference load level. For this
criterion, the reference load level is the maximum established planned load limit for the area under study.3.
Specific requirements that exceed the minimums specified in 1 and 2 may be established, to be adhered to by
others, provided that technical justification has been approved by the RERI.4. Item 3 applies to internal
interconnection Systems.Submitting a Proposed Finding of Exclusion to the Regional EntityInformation
required. Once the analysis has been performed and the Subject Element/System has been determined to
not have a material impact on neighboring Transmission Owners, Operators, and Balancing Authorities as
described in Table 1, and is unnecessary for the operation of an interconnected transmission system, the
Responsible Entity shall submit the findings to the RERI.RERI Review of Proposed Findings The RERI
operational/planning staff with technical expertise in powerflow studies shall review Proposed Findings of
Exclusion submittals and shall determine if the assessment is deficient or agrees with the finding of exclusion.
The RERI shall exempt the system elements from the BES, if the elements are approved for exclusion. If the
exclusion of the BES elements change the Responsible Entities NERC functional registrations the Region
shall support the Responsible Entity through the NERC deregistration process.

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Question 10 Comment
Dispute Resolution A Responsible Entity or Registered Entity or Owner may appeal a Disputed Finding of
Exclusion with the RERI to NERC.
Ongoing Responsibilitiesa. Logging. The RERI shall create and maintain a comprehensive list, available for
public review, of:i. All Elements with nominal operating voltages at or above 100 KV that have Confirmed
Findings of Exclusion, or, through other aspects of the BES definition, have been excluded from the BES
including an explanation of how the element was excluded through the definition;ii. All Elements with nominal
operating voltages below 100 kV that have Findings of Inclusion; andiii. The status of all EAs in dispute.iv.
The Responsible Entity would continue to provide system data to the neighboring Balancing Authorities and
Transmission Owners and Operators and if applicable continue to coordinate underfrequency load shed and
under voltage load shed scheme information.VII. Conclusion NERC should adopt the TPL-based assessment
as proposed herein. A bright-line BES test will not exclude all load distribution facilities as required by the
FPA. Further, a performance-based exemption process would be objective, consistent, and transparent, and
would adequately differentiate between local distribution and transmission, i.e., BES, facilities.

American Transmission
Company, LLC

Yes

1. ATC proposes replacing the wording in the Exclusion preface, Exclusion 2 preface, and Inclusion 1 preface
of “not necessary to reliably operate the interconnected transmission network” with “necessary to maintain an
Adequate Level of Reliability (ALR) of the Bulk Electric System”.
2. ATC has reservations on the following statement made in the introduction of this document:” Due to the
importance of Blackstart Resources and their designated blackstart Cranking Paths to restoration efforts, no
exceptions will be allowed for those items.” This does not allow for a provision to exclude any designated
Blackstart Cranking Path (at any voltage) even though there may be technical justification for it.
3. The first page states that “Specific content of this application is spelled out elsewhere in this appendix.”
ATC requests the SDT describe where this appendix will be published. Furthermore, is it a compliance
document or just technical “guidance”?
4. Having the following statement included for both exclusions and inclusions will create disagreement:”The
ERO can override this criterion but would need to provide additional justification to support their finding.” ATC
believes any override should have adequate technical justification and not interfere with other statutory
requirements. Also, it does not clarify or identify who would make the determination whether NERC has made
adequate justification to override the criterion.

Manitoba Hydro

Yes

The exception procedure is a complicated and resource intensive process. To be most effective, the BES
definition should be a stand-alone 100kV bright line with any exception criteria being specified within the
definition. Additionally:-FERC Order 743 directed the revision of the Bulk Electric System (BES) definition to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions. The proposed impact

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Question 10 Comment
based exception procedure undermines all three of these targets. -The Technical Exceptions eliminate the
100kV ‘bright-line’ definition and introduce regional differences, both of which are contradictory to the goals of
the BES revision project. -The commitment for NERC to review and continuously monitor BES exceptions
made through this process would be extremely onerous and resource intensive with little benefit to reliability.
-To obtain industry consensus on the precise limits to determine if an element has sufficient impact on the
BES to be included in the BES is not a reasonable or attainable endeavor.

NESCOE

Yes

NESCOE believes that exclusion determinations should be based on clear but flexible criteria that do not
result in the unnecessary inclusion of elements into the BES that do not adversely impact the reliability of the
BES. The process described here is too limiting in its requirement that an application meet all of those four
listed criteria not requiring technical analysis.
Applicants and reviewers should have a broader menu of decision criteria available to them.
Regarding those criteria related to exclusions based on technical analysis, NESCOE suggests that ranges of
values, in recognition of regional differences in network characteristics, be suggested by the drafting team for
further consideration.
Finally, as discussed above in response to questions 1 through 4, NESCOE believes that additional exclusion
determinations should not require a finding that all four proposed criteria are met. Rather, the various criteria
set forth under 1(a) through 1(d) should be treated as alternative criteria to qualify for an additional exclusion,
and entities seeking additional exclusions to the BES should be allowed to demonstrate that one or more
criteria is met, depending on the nature of the element that is the subject of the application.

Response: The SDT appreciates your comments. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or
limit. It has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new
process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of
an exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the
submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation
with the ERO as established in the Rules of Procedure as presently being drafted.
Edison Electric Institute

Yes

We are concerned that the method used to characterize exclusions in Method 1 did not follow the proposed
BES Definition and believe the process developed for Method 2 (and reused for Sub-100kV Inclusions) is
overly complicated, lacks necessary regional standards to support the process and may prove too difficult for
some companies to fully comply with thereby discouraging a consistent and uniform application of the

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Question 10 Comment
definition across all regions and affected BES element owners.
In the proposed (BES) definition and accompanying Inclusions and Exclusions, the Drafting Committee went
to some effort to clearly and methodically define what was included and what was permissible to exclude.
Unfortunately the NERC proposed “Technical Principles for Demonstrating BES Exceptions” did not follow
that same clear and concise manner adding some confusion which could lead to inconsistent application of
the Exclusion (and Inclusion) Criteria. For example, at no point did the “Principles” ever identify Inclusions I2
through I5 which were liberally used in the exclusion criteria within the BES definition.
Additionally within the body of the Proposed BES definition, there are three (3) approved Exclusions (E1 Radial System; E2 - Small Customer Generator/Generation System and E3 - Local Distribution Networks).
Each of the Exclusions have its own set of criteria used to define and characterize the methodology
necessary to meet each exclusion, however, the “Principles” contained in this document only loosely follow
the criteria provided and in some cases miss that criteria all together.
We refer the SDT to the EEI comments previously submitted on the BES Definition regarding the relationship
of the BES definition to the statutory exclusion of local distribution facilites.

PPL Supply

Yes

General PPL Supply concerns with draft Technical Principles for exclusion/inclusion:1. It may be premature to
work on an exclusion/exemption/inclusion process since the BES definition is not established yet. A lot of
work could be done on the Exclusion/Inclusion that is meaningless because there is some chance the
exclusion/inclusion process will not complement or might duplicate the BES definition.
2. The proposal will result in inclusion of generation facilities that are not significant to BES reliability.
3. The exclusion/inclusion drafting team does not appear to have considered the FERC assessment in Order
743-A (17-Mar-11) that “material impact assessments” cannot be unduly subjective and must be technically
based as stated in paragraph 47.
a. For the material impact tests in the Exclusion/Inclusion Technical Principles to be technically based, it is
important that the tests actually measure what FERC states are the characteristics of the BES (see Order 743
paragraph 73), namely 1) operate in parallel, 2) carry significant amounts of generation, 3) operate as part of
a defined flowgate, 4) are parallel in nature and 5) are capable of causing or contributing to significant
disturbances. The proposed tests do not make these measurements.
b. Further, since all facilities already meet the technically based NERC planning and operating standards, any
additional measure beyond these standards such as those created by the BES Exclusion/Inclusion drafting
team will be unduly subjective, as these new measures go beyond the technical basis of the NERC
standards.

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Question 10 Comment
4. It is unclear how the exclusion/inclusion drafting team considered FERC’s concerns with the use of
“material impact assessments,” as described in Order 743, paragraph 85 (“no grounds on which to reasonably
assume that the results of the material impact assessment are accurate, consistent, and comprehensive”).
Specific comments on Technical Principles paper from NERC DT 20110510A. Please add wording to make
complete sentences as needed in order to clarify whether facilities meeting these criteria are included or
excluded. For example, the clarifying words are added to the following Exclusion 1 to help the reader better
understand the meaning. 1. “The elements that meet all of the following characteristics are not necessary for
the reliable operation of the grid and are thus excluded:”a. System elements that are located in close
electrical proximity to Load are exempt from inclusion in the BES.B. Notwithstanding the need for complete
sentences to assure proper interpretation, the following comments should be considered by the drafting team:
o Exclusion 1 a) uses an unduly subjective, non-technically based material impact test.
o Exclusion 1 b) i and ii attempts to introduce disconnect procedures in the classification as “radial” which
may hurt reliability by disconnecting radial equipment that could provide voltage support. The exclusion also
introduces commercial (dispatch) considerations which may not be appropriate in a reliability-based
document.
o Exclusion 1 c) assuming “system” is short for “system elements”, this requirement for exclusion is overly
discriminatory to generators which flow power out.
o Exclusion 1 d) is too vague to be useful because “system” seems to have more than one meaning in this
requirement.
o Exclusion 2 and Inclusion 1 in their entirety are unduly subjective, non-technically based material impact
tests.We are concerned that the proposed inclusion and exclusion procedures could result in not only
significant generation interconnection facilities being included in the BES - but also less significant generation
interconnection facilities. Such a result would be inconsistent with FERC Order 743.
Accordingly, PPL Supply respectfully requests NERC to:o Exclude radial facilities less than 100 kV and not
black start (these facilities are excluded in the latest definition of the BES).
o Exclude radial facilities greater than 100 kV but less than 200 MVA (proposed BES now includes generators
over 20 MVA)o Exclude local distribution networks (LDNs) with flow into network up to 200 MVA
o Currently, LDNs are excluded if they only absorb (not produce) net power (Technical Principles Exclusion 1c). It is also appropriate to exclude LDNs with less than net 200 MVA flow into the BES electrical network.
o Inclusion efforts should not consider such issues as proximity to markets, proximity to load or nuclear
facilities, or length of generator lead line.

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Independent Electricity System
Operator

Yes or No
Yes

Question 10 Comment
We hold the view that the path to generating facilities need not be always BES contiguous. Generating units
should be required to meet a subset of NERC Standards, but should not always require contiguous BES
paths.
Finally, we reiterate that exception criteria should be crafted at a high-level with key menu items of
assessment that can be followed continent-wide by entities to put forward their exception for element(s) that
are not necessary for the interconnected transmission network and based on technical assessment, evidence
and justification for its unique characteristics, configuration, and utilization.

Response: The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.
The SDT appreciates the comments and suggestions for the technical exception criterion. Based on industry response and further analysis, the SDT has
abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be
considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an
entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide values and/or limits due to
differences in operational characteristics. The new process requires an entity to clarify the characteristics of the facilities in question and to document the
operational performance as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being
sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or
inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as presently being drafted.
Electric Market Policy

Yes

Although Dominion didn’t see a specific form to address comments on Appendix 5B to the NERC ROP,
Dominion would like to point out a particular area of concern with that Appendix. Dominion requests that
NERC include explicit language stating that exclusion or inclusion of an element (for compliance purposes)
begins only after approval/disapproval and any associated appeal has been reviewed and a final decision
reached. Dominion would also like to point out that it assisted in the preparation of the Edison Electric
Institute’s comments and therefore agrees with the comments raised by EEI.

Response: The SDT has forwarded your comments to the RoP team for their consideration.
Pepco Holdings Inc

Yes

Concern that as this proposal is written such that each exclusion in the BES definition (E1, E2 and E3) will
require a submittal to approve that is an exclusion.

City of Redding

Yes

The SDT is encouraged to address generators installed as load modifiers to distribution load.>>>>
As additional evidence of distribution line, if there is not an OATT filed on a line then it is not transmission per
FERC rules.

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Tacoma Power

Yes or No
Yes

Question 10 Comment
Tacoma Power supports the SDT’s efforts to create an acceptable BES definition directly linked to an
exception process. We do have a concerned about the application of the standards to Elements that change
status due to the Exception process. Any Elements that are determined to be newly included in the BES
should have a 24-month period before the standards will apply as a BES Elements. Conversely, a
determination that removes an Element from the BES should apply as soon as practicable.
Please be aware that the WECC has a task force, the Bulk Electric System Definition Task Force(BESDTF),
which has done some notable work on this task. See WECC BESDTF Proposal 6, Appendix C
(http://www.wecc.biz/Standards/Development/BES/default.aspx).
The BES definition is very complex and the BESDTF has already addressed many of the tough issues that
have yet to be addressed in this process, such as: o Local Distribution Network definition for automatic
exemption o Determination of radial facilities o Demarcation of BES and non-BES Elements o Alternate
dispute resolution process o Assignment of the burden of proof for the exemption process o Technical
approach for the inclusion/exclusion determination
Thank you for consideration of our comments.

Response: The SDT has addressed comments on the BES definition under the Consideration of Comments form for the BES definition posting.

END OF REPORT

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Consideration of Comments

Definition of the Bulk Electric System Exception Criteria (Project 2010-17)
The Bulk Electric System Drafting Team thanks all commenters who submitted comments on the
second draft of the Project 2010-17: Definition of the Bulk Electric System (BES) Exception Criteria.

These standards were posted for a 45-day public comment period from August 26, 2011 through
October 10, 2011. Stakeholders were asked to provide feedback on the standards and associated
documents through a special electronic comment form. There were 72 sets of comments, including
comments from approximately 137 different people from approximately 83 companies representing all
10 Industry Segments as shown in the table on the following pages.
The SDT made the following changes to the request form due to industry comments received:
• General – Clarified the use of facility versus Element(s).
• Page 1 – Corrected typo: List any attached supporting documents and any additional information that is
included to supports the request:
• Generation - Q1. Replaced ‘generator’s or generator facility’s’ with ‘generation resource’s’: What is the
MW value of the host Balancing Authority’s most severe single Contingency and what is the generator’s,
or generator facility’s generation resource’s, percent of this value?
• Generation - Q2. Replaced ‘generator’s or generator facility’s’ with ‘generation resource’s’: Is the
generator or generator facility generation resource used to provide reliability- related Ancillary Services?
• Generation - Q3. Replace ‘generator’ with ‘generation resource’: Is the generator generation resource
designated as a must run unit for reliability?
The SDT feels that it is important to remind the industry that Phase II of this project will begin immediately after the
conclusion of Phase I as SDT resources clear up. The same SDT will follow through with Phase II.
The SDT is recommending that this project be moved forward to the recirculation ballot stage.
There were two comments that were repeated multiple times throughout the various documents. The first topic
was about how to sort through the definition inclusions and exclusions, i.e., which takes precedence. The SDT
offers this guidance on that issue:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied
will identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide
basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation
point between BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and
Reactive Power resources connected at 100 kV or higher as included in the BES. To fully appreciate the scope of
the ‘core’ definition an understanding of the term Element is needed. Element is defined in the NERC Glossary of
Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator,
transformer, circuit breaker, bus section, or transmission line. An element may be comprised of one or more
components. “

Element is basically any electrical device that is associated with the transmission or the generation (generating
resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included
through the application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and
Reactive Power resources with specific criteria to provide for a consistent determination of whether an Element is
classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES
Elements). The exclusion language is written to specifically identify Elements or groups of Elements for potential
exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific
criteria identified in the exclusion language. This does not include the exclusion of Real Power and Reactive
Power resources captured by Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of
the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner. Therefore, the
only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the
customer’s side) and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and
supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the
reliable operation of the interconnected transmission network or an Element as non-BES that is necessary for the
reliable operation of the interconnected transmission network, the Rules of Procedure exception process may be
utilized on a case-by-case basis to either include or exclude an Element.
The second item is about providing specific guidance on how the information on the exception request form will be
used in making decisions on inclusions/exclusions in the exception process. The SDT provides the following
information on this item:
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this
issue. The SDT would like nothing better than to be able to provide a simple continent-wide resolution to this
matter. However, after many hours of discussion and an initial attempt at doing so, it has become obvious to the
SDT that the simple answer that so many desire is not achievable. If the SDT could have come up with the simple
answer, it would have been supplied within the bright-line. The SDT would also like to point out to the
commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very
little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up
front. There are always going to be extenuating circumstances that will influence decisions on individual cases.
One could take this statement to say that the regional discretion hasn’t been removed from the process as
dictated in the Order. However, the SDT disagrees with this position. The exception request form has to be taken
in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks
at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has
been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination.
The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts as an
intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

2

being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the visibility of the
process would belie such an action by the Regional Entity and also believes that one has to have faith in the
integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This
panel’s findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed
NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the Regional Entity
with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the
exception request. On the other side of this equation, one could make an argument that the Regional Entity has
no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to
be provided and how to interpret the information aren’t shown in the request process. The SDT again points to
the variations that will abound in the requests as negating any hard and fast rules in this regard. However, one is
not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there is
a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this
equation. Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as
to what information needs to be supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for
them to follow in making their decision. The SDT re-iterates the problem with providing such hard and fast rules.
There are just too many variables to take into account. Providing concrete guidelines is going to tie the hands of
the ERO Panel and inevitably result in bad decisions being made. The SDT also refers the commenters to
Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an
exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating
the elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits
so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a
sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT
firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the experience
gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent
approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue
that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form
will mandate a negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the
proposed NERC Rules of Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece
of evidence provided as part of an Exception Request or response to a question will be solely dispositive in the
determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in
response to industry comments. The SDT believes that these clarifications will make the process tighter and
easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after
12 months of experience. The SDT believes that this time period will allow industry to see if the process is
working correctly and to suggest changes to the process based on actual real-world experience and not just on
suppositions of what may occur in the future. Given the complexity of the technical aspects of this problem and
the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed
a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of
these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

3

All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-17_BES.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Standards Processes Manual:
http://www.nerc.com/docs/standards/sc/Standard_Processes_Manual_Approved_May_2010.pdf.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

4

Index to Questions, Comments, and Responses
1.

Page one of the ‘Detailed Information to Support an Exception Request’ contains
general instructions. Do you agree with the instructions presented or is there
information that you believe needs to be on page one that is missing? Please be as
specific as possible with your comments. ....................................................... 13
2. Pages two and three of the Detailed Information to Support an Exception Request
contain a checklist of items that deal with transmission facilities. Do you agree with
the information being requested or is there information that you believe needs to be
on page two or three that is missing? Please be as specific as possible with your
comments. ......................................................................................................49
3. Page four of the ‘Detailed Information to Support an Exception Request’ contains a
checklist of items that deal with generation facilities. Do you agree with the
information being requested or is there information that you believe needs to be on
page four that is missing? Please be as specific as possible with your comments.
....................................................................................................................... 88
4. Do you have concerns about an entity’s ability to obtain the data they would need to
file the ‘Detailed Information to Support an Exception Request’? If so, please be
specific with your concerns so that the SDT can fully understand the problem.108
5. Are there other specific characteristics that you feel would be important for
presenting a case and which are generic enough that they belong in the request? If
so, please identify them here and provide suggested language that could be added to
the document. ............................................................................................... 120
6. Are you aware of any conflicts between the proposed approach and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement, or
jurisdictional issue? If so, please identify them here and provide suggested language
changes that may clarify the issue. ............................................................... 133
7. Are there any other concerns with the proposed approach for demonstrating BES
Exceptions that haven’t been covered in previous questions and comments (bearing
in mind that the definition itself and the proposed Rules of Procedure changes are
posted separately for comments)? Please be as specific as possible with your
comments. .................................................................................................... 142
END OF REPORT ..................................................................................................... 167

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

5

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group
Additional Member

Guy Zito

Northeast Power Coordinating Council
Additional Organization

Region Segment Selection

1.

Alan Adamson

New York State Reliability Council, LLC

NPCC 10

2.

Gregory Campoli

New York Independent System Operator

NPCC 2

3.

Kurtis Chong

Independent Electricity System Operator

NPCC 2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5.

Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC 1

6.

Gerry Dunbar

Northeast Power Coordinating Council

7.

Brian Evans-Mongeon Utility Services

NPCC 8

8.

Mike Garton

Dominion Resources Services, Inc.

NPCC 5

9.

Kathleen Goodman

ISO - New England

NPCC 2

FPL Group, Inc.

NPCC 5

10. Chantel Haswell

NPCC 10

2

3

4

5

6

7

8

9

10

X

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

11. David Kiguel

Hydro One Networks Inc.

NPCC 1

12. Michael Lombardi

Northeast Utilities

NPCC 1

13. Randy MacDonald

New Brunswick Power Transmission

NPCC 9

14. Bruce Metruck

New York Power Authority

NPCC 6

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

16. Robert Pellegrini

The United Illuminating Company

NPCC 1

17. Si Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

18. David Ramkalawan

Ontario Power Generation, Inc.

NPCC 5

19. Saurabh Saksena

National Grid

NPCC 1

20. Michael Schiavone

National Grid

NPCC 1

21. Wayne Sipperly

New York Power Authority

NPCC 5

22. Donald Weaver

New Brunswick System Operator

NPCC 2

23. Ben Wu

Orange and Rockland Utilities

NPCC 1

24. Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC 3

2.

Group

Charles Long

Additional Member

Additional Organization

SERC Planning Standards Subcommittee

SERC

SERC

10

2. John Sullivan

Ameren Services Co.

SERC

1

3. James Manning

NC Electric Membership Corp.

SERC

1

4. Philip Kleckley

SC Electric & Gas Co.

SERC

1

5. Bob Jones

Southern Company Services

SERC

1

6. Jim Kelley

PowerSouth Energy Cooperative SERC

1

Group
Brent Ingebrigtson
No additional members listed.

LG&E and KU Energy

4.

ACES Power Marketing Standards
Collaborators

Group

Jean Nitz

Additional Member

Additional Organization
Buckeye Power, Inc.

2. Susan Sosbe

Wabash Valley Power Association SERC

Group

Jonathan Hayes

4

5

6

7

X

RFC

X

X

X

X

X

3, 4
3

Southwest Power Pool Standards Review

8

9

10

X

Region Segment Selection

1. Mohan Sachdeva

5.

3

Region Segment Selection

1. Pat Huntley

3.

2

X

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

7

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

7

8

9

10

Team
Additional Member

Additional Organization

Region Segment Selection

1. Mark Wurm

Board of Public Utilities City of McPherson SPP

1, 3, 5

2. John Allen

City Utilities of Springfield

1, 4

3. Sean Simpson

Board of Public Utilities City of McPherson SPP

4. Stephen McGie

Coffeyville

SPP

5. Robert Rhodes

Southwest Power Pool

SPP

2

6. Jonathan Hayes

Southwest Power Pool

SPP

2

SPP

6.

1, 3, 5

Group
Steve Rueckert
No additional members listed.

WECC Staff

7.

Bonneville Power Administration

Group

Chris Higgins

Additional Member

Additional Organization
Transmission Internal Ops

WECC 1

2. Chuck Matthews

Transmission Planning

WECC 1

3. Steve Larson

General Counsel

WECC 1, 3, 5, 6

4. Rebecca Berdahl

Long Term Sales and Purchases WECC 3

5. John Anasis

Technical Operations

WECC 1

6. Erika Doot

Generation Support

WECC 1, 3, 5

7. Don Watkins

System Operations

WECC 1

8. Fran Halpin

Duty Scheduling

WECC 5

9. Joe Rogers

Transfer Services

WECC 3

Louis Slade

Dominion

Group

X

X

X

X

X

X

X

X

Region Segment Selection

1. Lorissa Jones

8.

X

Additional Member Additional Organization Region Segment Selection
1. Connie Lowe

RFC

5, 6

2. Mike Garton

MRO

5, 6

3. Michael Gildea

NPCC 5, 6

4. Michael Crowley

Electric Transmission

SERC

1, 3

5. Sean Iseminger

Fossil & Hydro

SERC

5

9.

Group

Bill Middaugh

TSGT G&T

X

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

8

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

7

No additional members listed.
10.

Group

David Thorne

Pepco Holdings Inc

X

X

Additional Member Additional Organization Region Segment Selection
1. Carl Kinsley

Delmarva Power & Light Co RFC

1, 3

11.

Group
Cynthia S. Bogorad
No additional members listed.

Transmission Access Policy Study Group

X

X

12.

Electricity Consumers Resource Council
(ELCON)

X

X

Group
John P. Hughes
No additional members listed.
13.

Group

William D Shultz

Additional Member

Southern Company Generation

Additional Organization

X

X

X

X

X

X

Region Segment Selection

1. Tom Higgins

Southern Company Generation SERC

5

2. Terry Crawley

Southern Company Generation SERC

5

3. Therron Wingard

Southern Company Generation SERC

5

4. Ed Goodwin

Southern Company Generation SERC

5

14.

Group
John Bussman
No additional members listed.

AECI and member G&Ts

15.

Tri-State Generation and Transmission
Assn., Inc. Energy Mangement

16.

Group
David Taylor
No additional members listed.

NERC Staff Technical Review

17.

IRC Standards Review Committee

Group
Janelle Marriott Gill
No additional members listed.

Group

X

Al DiCaprio

X

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Steve Myers

ERCOT

ERCOT 2

2. Mark Thompson

AESO

WECC 2

3. Don Weaver

NBSO

NPCC

2

4. Charles Yeung

SPP

SPP

2

5. Ben Li

IESO

NPCC

2

6. Greg Campoli

NYISO

NPCC

2

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

9

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

7. Katherine Goodman ISO-NE

NPCC

2

8. Terry Bilke

MRO

2

MISO

2

3

4

5

6

8

9

10

X

18.

Individual

William Bush

Holland Board of Public Works

19.

Individual

Silvia Parada Mitchell

Transmission

X

X

X

X

20.

Individual

Sandra Shaffer

PacifiCorp

X

X

X

X

21.

Individual

Janet Smith

Arizona Public Service Company

X

X

X

X

22.

Individual

David Kiguel

Hydro One Networks Inc.

X

X

23.

Individual

John Bee

Exelon

X

X

24.

Individual

Eric Lee Christensen

Snohomish County PUD

X

X

25.

Individual

Greg Rowland

Duke Energy

X

X

26.

Individual

Richard Salgo

NV Energy

X

27.

Individual

Thomas C. Duffy

Central Hudson Gas & Electric Corporation

28.

Individual

Chris de Graffenried

Consolidated Edison Co. of NY, Inc.

X

29.

Individual

Thad Ness

American Electric Power

X

Individual
31. Individual

Anthony Jablonski
Joe Petaski

ReliabilityFirst
Manitoba Hydro

X

32.

Individual

Robert Ganley

Long Island Power Authority

X

33.

Individual

Eric Salsbury

Consumers Energy

34.

Individual

David Burke

Orange and Rockland Utilities, Inc.

35.

Individual

Kathleen Goodman

ISO New England Inc

36.

Individual

Diane Barney

New York State Dept. of Public Service

37.

Individual

John Seelke

PSEg Services Corp

X

38.

Individual

Sylvain Clermont

Hydro-Quebec TransEnergie

X

39.

Individual

Rick Hansen

40.

Individual

41.

Individual

30.

7

X
X

X
X

X

X

X

X

X

X

X

X

X
X
X
X

X
X

X

X

X
X
X
X

X

City of St. George

X

X

Bud Tracy

Blachly-Lane Electric Cooperative

X

Dave Markham

Central Electric Cooperative (CEC)

X

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

X
X

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

42.

Individual

2

3

Clearwater Power Company (CPC)

Individual
44. Individual

Roman Gillen
Dave Sabala

Consumer's Power Inc. (CPI)
Douglas Electric Cooperative (DEC)

45.

Individual

Bryan Case

Fall River Electric Cooperative (FALL)

46.

Individual

Rick Crinklaw

Lane Electric Cooperative (LEC)

47.

Individual

Michael Falvo

Independent Electricity System Operator

48.

Individual

Michael Henry

Lincoln Electric Cooperative (Lincoln)

49.

Individual

Jon Shelby

Individual

Ray Ellis

Individual

Rick Paschall

Northern Lights Inc. (NLI)
Okanogan County Electric Cooperative
(OCEC)
Pacific Northwest Generating Cooperative
(PNGC)

52.

Individual

Heber Carpenter

Raft River Rural Electric Cooperative (RAFT)

53.

Individual

Steve Eldrige

Umatilla Electric Cooperative

54.

Individual

Marc Farmer

West Oregon Electric Cooperative (WOEC)

X

55.

Individual

Steve Alexanderson

Central Lincoln

X

56.

Individual

Saurabh Saksena

National Grid

X

57.

Individual

Darryl Curtis

Oncor Electric Delivery Company LLC

X

58.

Individual

Roger Meader

Coos-Curry Electric Coooperative

59.

Individual

Kirit Shah

Ameren

60.

Individual

Guy Andrews

Georgia System Operations Corporation

Individual
62. Individual

Andrew Gallo
Andy Pusztai

City of Austin dba Austin Energy
ATC LLC

63.

Individual

David Kahly

Kootenai Electric Cooperative

64.

Individual

Linda Jacobson-Quinn

Farmington Electric Utility System

X
X

65.

Individual

Mary Downey

City of Redding Electric Utility

X

50.
51.

61.

5

6

7

8

9

X

Dave Hagen

43.

4

X

X
X
X
X
X
X
X
X
X

X

X

X
X

X
X

X

X
X

X
X

X

X

X

X

X

X

X

X

X

X

X

X

X

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

11

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

66.

Individual

Paul Cummings

Individual

Edwin Tso

City of Redding
Metropolitan Water District of Southern
California

Individual
69. Individual

Rex Roehl
Keith Morisette

Indeck Energy Services
Tacoma Power

70.

Individual

Tracy Richardson

Springfield Utility Board

71.

Individual

Frank Cumpton

BGE

72.

Individual

Gary Carlson

Michigan Public Power Agency

67.
68.

2

3

4

5

6

X
X
X
X

X

X

X

X

X
X

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

X

12

7

8

9

10

1.

Page one of the ‘Detailed Information to Support an Exception Request’ contains general instructions. Do you agree with the
instructions presented or is there information that you believe needs to be on page one that is missing? Please be as specific
as possible with your comments.

Summary Consideration: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on
this issue. The SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However,
after many hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so
many desire is not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the brightline. The SDT would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of
the criteria and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception application form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as
a single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the application to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred
in rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the application process. The SDT again points to the variations that
will abound in the applications as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here.
This is not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on
both the submitter’s and the Regional Entity’s side of this equation. Having viewed the application details, the SDT believes that both
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

13

sides can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO
panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of
the Bulk Electric System. The SDT firmly believes that the technical prowess of the ERO panel, the visibility of the process, and the
experience gained by having this same panel review multiple applications will result in an equitable, transparent, and consistent
approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are outlined in
the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception application form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved
or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the SAR for Phase II of this project that calls for a review of the process after 12 months of experience.
The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the
process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of
the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes
that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all
of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable outcome.
The SDT clarified the point that an entity may submit any information that it feels will help support its request as follows:
Page 1 - List any attached supporting documents and any additional information that is included to supports the request:

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

14

Organization
Northeast Power Coordinating
Council

Yes or No

Question 1 Comment

No

How an exception application will be assessed by the RE and NERC is not
addressed in the document. Stakeholders need to know how the exception
application will be evaluated and processed. Suggest that the SDT develop a
reference or a guidance document as part of the RoP that will provide
guidance to Registered Entities, Regional Entities and the ERO on how an
exception application will be processed. Of particular concern is the lack of
clarity and specificity with respect to what analyses and study results are
required under the third bullet on page 1 and under question 4 on both
pages 2 and 4. This lack of clarity and specificity will lead to inconsistent
application of the Technical Principles by both Registered Entities and
Regional Entities.
We recommend the following: the impact and performance analyses
required by the 3rd bullet on page 1 and by #4 on pages 2 and 4 should be
stipulated to be all analyses, scenarios, and contingencies required under
NERC Standard TPL-002-1 with the “exception element” removed from the
base system model. Entities shall report on all key performance measures of
BES reliability specified in the TPL-002-1 attributable to the removed
“exception element”.
On page 1 under General Instructions, it is stated that:”A one-line breaker
diagram identifying the facility for which the exception is requested must be
supplied with every application. The diagram(s) supplied should also show
the Protection Systems at the interface points associated with the Elements
for which the exception is being requested.”What is meant by interface
points?

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

15

Organization

Yes or No

Question 1 Comment

would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

16

Organization

Yes or No

Question 1 Comment

bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
As far as developing reference or guidance documents, the SDT will consider this recommendation in Phase II of the project.
The recommendation to use “the impact and performance analyses required by the 3rd bullet on page 1 and by #4 on pages 2 and 4
should be stipulated to be all analyses, scenarios, and contingencies required under NERC Standard TPL-002-1 with the “exception
element” removed from the base system model” could be viable as a form of evidence an entity may want to submit if the entity
believes this test provides evidence for the exception of an Element(s). The SDT encourages the submitting entity to provide any
additional information or explanation in the comments section of the questions that it believes will assist in the review of its
Exception Request. The SDT has made a clarifying change to the page 1 instructions to make this point clearer. Also see the answer
to question #4.
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Organization

Yes or No

Question 1 Comment

Page one: List any attached supporting documents and any additional information that is included to supports the request:
As far as interface points, the SDT agrees with BPA’s suggestion that the interface point is the point requested by the entity seeking
the exception where the Element or Elements interconnect(s) to Bulk Electric System Elements.
ACES Power Marketing Standards
Collaborators

No

The first sentence only refers to element(s) designated as excluded.
Element(s) designated as included under the BES definition, shouldn’t have
to go through the exception process either.

Response: The SDT agrees with this comment. This language was added to clarify that Elements that are excluded (or included) do
not have to go through the Exception Process unless they are attempting to change to classification of their Elements.
WECC Staff

No

WECC has several concerns with the instructions on the checklist regarding
the studies: o Study Case - The instructions state the study case that should
be used, “Be based on an Interconnection-wide base case that is suitably
complete and detailed to reflect the facility’s electrical characteristics and
system topology.” The phrase “suitably complete and detailed” is vague.
WECC recommends clarification of this phrase and the addition of specific
requirements for what will constitute an appropriate case. Allowing the
entity requesting an exception to choose any Interconnection-wide case
could allow an inappropriate choice of case and could lead to inconsistent
study results. If there are no requirements for the chosen case, then it is
possible that the most favorable case to an entity’s argument will be chosen.
In some instances that choice would likely be appropriate, but in others it
would not necessarily be appropriate. At a minimum, there should be
further description - and preferably, specific requirements - guiding the
determination of which study case is most appropriate.
Of particular importance in clarifying what case is an appropriate case, is the
timeliness of the case. WECC recommends requiring that a recent case be
used. In addition, if each entity is able to chose its own case, without further

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Yes or No

Question 1 Comment
requirements, there will be no way for the Regional Entity or NERC to ensure
consistency of determinations with respect to the elements tested.
o The entities are asked to address key performance measures of BES
reliability through the studies. This instruction is vague concerning what the
study must investigate and it leaves it up to the entity to determine the key
performance measures. The “key performance” measures should be
consistent with respect to similar elements and there is no way to ensure
that if there are no specifications regarding such measures. The exceptions
process must be objective and clear as to what performance measures need
to be met for the process to be implemented consistently. WECC
recommends further clarification and the addition of specific requirements
beyond the guidance related to consistency with Transmission Planning
(TPL) standards.
o The background information on the comment form states: “The same
checklist will be utilized for exceptions dealing with inclusions or exclusions.”
But there is no mention of this in the document. A note should be added to
the checklist instruction to state that the same checklist will be used for
exclusions and inclusions.

Response: In response to the comment about an appropriate base case, the SDT expects the entity seeking an exception to supply
an appropriate base case that the Regional Entity will acknowledge as appropriate. Not indicating the explicit types of studies or
base cases to be provided and how to interpret the information in the application process does not fail to provide a basis for the
Regional Entity to determine what constitutes an acceptable submittal.
The SDT again points to the variations that will abound in the applications as negating any hard and fast rules in this regard.
However, this is not something that hasn’t been handled before and there is a great deal of professional experience involved on
both the submitter’s and the Regional Entity’s side of this equation. Having viewed the application details, the SDT believes that
both sides can quickly arrive at a resolution as to what information needs to be supplied for the submittal to move upward to the
ERO panel for a final determination.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
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Yes or No

Question 1 Comment

like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
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Organization

Yes or No

Question 1 Comment

made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
As to the last comment, the SDT finds this wording redundant and not providing any additional clarity. No change made.
Dominion

No

Given that the second sentence in the 1st paragraph of this comment form
reads “This same process would be used by Registered Entities to justify
including Elements in the BES that might otherwise be excluded according to
the proposed definition and designations.”, Dominion suggests that the 1st

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Yes or No

Question 1 Comment
sentence under General Instructions be revised to read “A one-line breaker
diagram identifying the facility for which the exception (or inclusion) is
requested must be supplied with every application. The diagram(s) supplied
should also show the Protection Systems at the interface points associated
with the Elements for which the exception (or inclusion) is being
requested.”

Response: The SDT reviewed the suggestion to add the phrase “(or inclusion)”and has elected to keep the original language
because the term Exception includes both Exclusions and Inclusions.
Pepco Holdings Inc

No

1) Why must the one-line diagram supplied show the Protection Systems at
the interface points associated with the elements for which the
exception is being requested? Since Protection Systems are not part of
the new bright-line BES definition why would their presence, or absence,
on the one-line diagram influence the exception process?
2) The third bullet needs additional detail of what is being requested. The
phrase “...key performance measures..” and use of methodologies
described in TPS Standards does not provide sufficient direction needed.
(see question #4)

Response: In response to the question about including Protection Systems, the SDT has used the term “should also show the
Protection Systems”. This is not mandatory; however the SDT has suggested this because the criterion for the evaluation of an
exception is “the Elements are necessary for the reliable operation of the interconnected bulk power transmission system”. As an
example, the elements could be part of a Special Protection System or RAS thus they could help the ERO to identify the Elements
“necessary for Reliable Operation…” No change made.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
Also, see the answer to question #4.
Electricity Consumers Resource
Council (ELCON)

No

The exception request form should begin with a question asking if the
inclusion was triggered by the entity responding to an emergency request by
the applicable BA, RC or TOP. The entity’s response to support recovery
from an emergency may have resulted in (1) power flows through the
entity’s facility into the BES, and/or (2) power injections to the BES that
exceed the 20/75-MVA thresholds. The entity should not be required to
provide detailed data and studies (as described in the “General
Instructions”) if either of those conditions would not have occurred but for

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Yes or No

Question 1 Comment
an emergency situation.

Response: While the SDT seriously doubts that such a situation will occur, the entity can choose the amount of and type of
evidence to present; if the entity feels that abnormal operation should be considered in the evaluation of the Element(s) then they
should supply that information to help explain its position.
AECI and member G&Ts

No

An opening statement of this form should make it clear that, prior to its
determination, the Facilities within scope of this exemption request, remain
included or excluded based upon the basic BES Definition Bright Line criteria
Inclusions and Exclusions.

Response: This is a question that relates to the proposed ERO Rules of Procedure Appendix 5C. This question was forwarded to
the RoP team.
Hydro One Networks Inc.

No

On the posted document, we did not find how an exception application will
be assessed by the RE and NERC. We believe that there is a huge gap and a
lack of transparency for all stakeholders on how the exception application
will be evaluated and processed.
We strongly suggest that the SDT develop a reference or a guidance
document as part of the RoP that will provide guidance to Registered
Entities, Regional Entities and the ERO on how an exception application
would/should be processed.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

25

Organization

Yes or No

Question 1 Comment

that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
In response to the comment about developing reference or guidance documents, the SDT will consider this recommendation in Phase
II.
Duke Energy

No

Need to include identification of any System Protection Coordination
considerations per PRC-001-1.
Also, we believe that a system map showing the geographical location of the
facility(s) should be supplied with the request.

Response: The detail of the diagrams and the type of diagrams suggested by Duke could be viable forms of evidence that an entity
may want to submit if the entity believes they provide evidence to support the exception of an Element.
Additionally, the SDT encourages the submitting entity to provide any additional information or explanation in the comments
section of the questions that it believes will assist in the review of its Exception Request.

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Consolidated Edison Co. of NY, Inc.

Yes or No

Question 1 Comment

No

Con Edison’s overall concern is the lack of clarity and specificity with respect
to what analyses and study results are required under the 3rd bullet on page
1 and under #4 on pages 2 and 4. This lack of clarity and specificity will lead
to inconsistent application of the Technical Principles by both Registered
Entities and Regional Entities. We recommend the following: the impact and
performance analyses required by the 3rd bullet on page 1 and by #4 on
pages 2 and 4 should be stipulated to be all analyses, scenarios, and
contingencies required under NERC Standard TPL-002-1 with the “exception
element” removed from the base system model. Entities shall report on all
key performance measures of BES reliability specified in the TPL-002-1
attributable to the removed “exception element”.
Note that references to NERC Standard TPL-001-2 should not be made in the
Technical Principles document as TPL-001-2 has not yet been filed with (nor
approved by) FERC.
General Instructions One-Line Breaker Diagram questions and comments:
Page 1, paragraph 2: Please explain the phrase “at the interface points.”
Where is this location? Please provide several examples, i.e., for a radial, a
local network, a generator, a transformer, a substation buss, and for other
Elements (PARs, reactors, UFLS panels, relays and switches).

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

29

Organization

Yes or No

Question 1 Comment

Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
2. TPL-001-2 has been approved by the NERC Board of Trustees. As per drafting team guidelines, this document is now to be used in
all cases where the TPL standards are referenced in other standards projects.
3. In response to the comment about interface points, the SDT agrees with BPA’s suggestion that the interface point is the point
requested by the entity seeking the exception were the Element or Elements interconnect(s) to Bulk Electric System Elements.
New York State Dept. of Public
Service

No

Missing from the document are any indicators as to how much information
is sufficient, how the information will be evaluated, what weight will be
given to the individual pieces of information, etc.

ReliabilityFirst

No

These instructions are at a very high level and provide no clear guidance on
what is required. ReliabilityFirst Staff believes each bulleted item needs to
provide clear expectations. As an example in bullet #2 “Clearly document all
assumptions used”, the document and this bullet should include guidance
such as what base case transfers were included, a list of facilities that were

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment
assumed out of service, new facilities places in service and system load
levels, etc.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

31

Organization

Yes or No

Question 1 Comment

adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
Manitoba Hydro

No

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

Response: Without any specific comment the SDT is unable to respond.
Orange and Rockland Utilities, Inc.

No

In the first paragraph “Entities that have Element(s) designated as excluded,
under the BES definition and designations, do not have to seek exception for
those Elements under the Exception Procedure.”, before the “General
Instruction” it should have had another sentence saying that “for those who
do not clearly meet the Inclusions and Exclusions should use the following
instructions”. Otherwise, it’s still not very clear.

Response: The SDT would like to point out that the “Detailed Information to Support an Exception Request” is only one section of
the Exception Form. For clarity, please refer to the complete form contained as part of the proposed ERO Rules of Procedure
Appendix 5C; also, see the RoP’s flow chart that outlines the process.
ISO New England Inc

No

It is unclear what the purpose of submitting diagrams showing the
Protection Systems is and we do not feel that it should be a requirement at
the onset of the exception process.
In the first bullet, we do not feel that the term “Interconnection-wide base
case” is required as the phrase “suitably complete and detailed” should
provide enough guidance to the submitter that inappropriate equivalent
representations would not be accepted. The concern is that one could
interpret “Interconnection-wide base case” as the entire Eastern
Interconnection model is a requirement.

Response: In response to the question about including Protection Systems, the SDT used the term “should also show the Protection
Systems”. This is not mandatory; however the SDT has suggested this because the criterion for the evaluation of an Exception is “the
Elements are necessary for the Reliable Operation of the interconnected bulk power transmission system”. As an example, the
elements could be part of a special protection system or RAS thus they could help the ERO to identify the Elements “necessary for
Reliable Operation…” No change made.
In response to the comment about a base case, the SDT expects the entity seeking an exception to supply a Base Case that the
Regional Entity will acknowledge as appropriate. The SDT points to the variations that will abound in the applications as negating
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

33

Organization

Yes or No

Question 1 Comment

any hard and fast rules in this regard. However, this is not something that hasn’t been handled before and there is a great deal of
professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having viewed the
application details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be supplied
for the submittal to move upward to the ERO panel for a final determination. No change made.
PSEg Services Corp

No

What is meant by “key performance measures of BES reliability” in the third
bullet? A descriptive list would be helpful.

Response: As to the lack of key performance measures, the SDT refers the commenters to Appendix 5C of the proposed ERO Rules
of Procedure, Section 3.1 where the basic premise on evaluating an exception request must be based on whether the Elements are
necessary for the reliable operation of the interconnected transmission system. Further, reliable operation is defined in the Rules
of Procedure as operating the elements of the bulk power system within equipment and electric system thermal, voltage, and
stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden
disturbance, including a cyber security incident, or unanticipated failure of system elements. No change made.
Hydro-Quebec TransEnergie

No

We believe that the new Technical Principles are better than the previous
ones, as they allow flexibility for an Entity to make their case with technical
justifications. However, without any guide or specific criteria, it does not
allow an Entity to identify the real possibility to obtain an exception. It is not
clear at all what will guide the Region or ERO to make their decision to grant
or not the exception. In order give confidence to the Industry in the
procedure, it would be necessary to define the elements that will guide the
decision.
Will impact base study be accepted?
Will the threshold differences with Quebec Interconnection be accepted?

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

34

Organization

Yes or No

Question 1 Comment

received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

35

Organization

Yes or No

Question 1 Comment

separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
The SDT refers Hydro-Quebec to Appendix 5C of the proposed ERO Rules of Procedure, Section 3.1 where the basic premise on
evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected bulk transmission system. Further, Reliable Operation is defined in the Rules of Procedure as operating the elements
of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements.
As far as a difference for the Quebec Interconnection, the SDT encourages the submitting entity to provide any additional information
or explanation in the comments section of the questions that it believes will assist in the review of its Exception Request.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

36

Organization
City of St. George

Yes or No

Question 1 Comment

No

While the general instruction information outlined is applicable, it lacks
sufficient detail to know exactly what is needed to be submitted. More
importantly the general instructions and the overall document lacks criteria
that if met (through study and other documentation methods) would allow
for exclusion from or inclusion to the BES. Something similar to the criteria
or concepts used in the Appendix 1 of the Local Network Exclusion
justification document is needed. Clear criteria should allow an entity to
determine with a reasonable degree of certainty that if the criteria are met
as demonstrated by the associated study effort that an exemption can be
obtained. Otherwise without that criteria, the process will be not far from
where the exemption process is today, which will be costly, time consuming
and frustrating for the registered entities as well as the regions and NERC.
The process needs to be repeatable and consistent between all regions and
entities. Entities need to know what is expected and where the finish line is.
As presently written each region and NERC would have to develop their own
criteria individually and will be open to opinions which could change as
personnel changes occur in a given position or panel.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

37

Organization

Yes or No

Question 1 Comment

plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

38

Organization

Yes or No

Question 1 Comment

response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
In response to clear criteria, the SDT refers the commenters to Appendix 5C of the proposed ERO Rules of Procedure, Section 3.1
where the basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable
operation of the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating
the elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber
security incident, or unanticipated failure of system elements.
Georgia System Operations
Corporation

No

: The last half of the first sentence should be changed to “do not have to
seek an Exclusion Exception under the Exception Procedure for the
Element(s).” The use of “Element(s)” relates back to that term at the start of
the sentence, and the reference to an “Exclusion Exception” is necessary
because an entity (albeit probably not the Owner), still may choose to seek
an Inclusion Exception for such an Element(s).
In the 3rd bullet, the reference should be to TPL standards (plural).

Response: In response to the suggestion to change the first sentence, the SDT would like to point out that the “Detailed Information
to Support an Exception Request” is only one section of the Exception Form. For further clarity, please refer to the complete
Exception form contained as part of the proposed ERO Rules of Procedure Appendix 5C; also, see the RoP’s flow chart that outlines

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

the process. No change made.
The SDT notes that there is now only one TPL standard, TPL-001-2; TPL-001-2 has been approved by the NERC Board of Trustees. As
per drafting team guidelines, this document is now to be used in all cases where the TPL standards are referenced in other standards
projects. No change made.
ATC LLC

No

Since an Exception Request may be for approval to designate identified
Element(s) as either excluded from or included in the BES, the wording of
the first sentence should be changed and the request should clearly indicate
(e.g. exclusion/inclusion check boxes) whether the request regards exclusion
or inclusion of the Element(s). Here is some draft wording for consideration:
Entities that have Element(s) that are included under the BES definition and
designations, but seek to have them designated as excluded from the BES or
that that have Element(s) that are excluded under the BES definition and
designations, but seek to have them designated as included in the BES
should submit an Exception Request according to the NERC Exception
Procedures and provide detailed information to support the Exception
Request as indicated below.
In addition, ATC suggests the following clarifying edit. Entities that have BES
Element(s) considered as excluded under the BES definition and
designations, do not have to seek exception for those Elements under the
Exception Procedure.

Response: In response to the suggestion to change the first sentence, the SDT would like to point out that the “Detailed Information
to Support an Exception Request” is only one section of the Exception Form. For further clarity, please refer to the complete form
contained as part of the proposed ERO Rules of Procedure Appendix 5C; also, see the RoP’s flow chart that outlines the process.
The SDT would refer the commenter to the first line of page 1 which clearly states this fact. No change made.
Farmington Electric Utility System

No

The general instructions presented are primarily components to substantiate
an Exception Request. However, a cover sheet (template) should be created
that includes overall identifying information of the Submitting Entity and the

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40

Organization

Yes or No

Question 1 Comment
and the Owner if the if they are not the same - the template should align
with the draft Appendix 5C Section 4.5.1 of the NERC Rules of Procedure. An
Exception Request can be submitted for Inclusion or Exclusion of the BES.
The first sentence in the form, “Entities that have Element(s) designated as
excluded, under the BES definition and designations, so not have to seek
exception for those Element(s) under the Exception Procedure. This would
not be true if a Submitting Entity is seeking an Inclusion Exception. FEUS
recommends revising to include Inclusion Exception Requests.

Response: The SDT acknowledges that the “Detailed Information to Support an Exception Request” is only one section of the
Exception Form and in itself lacks required information; the complete form contains the information suggested by the commenter.
The full Exception form is part of the proposed ERO Rules of Procedure Appendix 5C; also, see the RoP’s flow chart that outlines
the process.
Transmission Access Policy Study
Group

Glossary terms should be capitalized throughout the document. Lowercase
“facility,” especially, should not be used. The document should use
“Element” instead.
The term “interface points,” while common, may not have a sufficiently
common understanding to be used in this context. “Boundaries of the
Element(s) for which the exception is being requested” may express the
SDT’s meaning more clearly.

Response: The SDT agrees with the commenter and the form was edited to use the term Element instead of Facility where
appropriate.
In response to the comment about interface points, the SDT agrees with BPA’s suggestion that the interface point is the point
requested by the entity seeking the exception were the Element or Elements interconnect(s) to Bulk Electric System Elements.
Tri-State Generation and
Transmission Assn., Inc. Energy
Mangement

This question is actually asking two questions; Tri-State’s answers would be
No & Yes. There needs to be a better introduction to what and why the
exception is being requested.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

41

Organization

Yes or No

TSGT G&T

Question 1 Comment
This question is actually asking two questions; Tri-State’s answers would be
No & Yes. There needs to be a better introduction to what and why the
exception is being requested.

Response: This is a question that relates to the proposed ERO Rules of Procedure Appendix 5C. This question was forwarded to
the RoP team.
American Electric Power

Yes

Though we have no objections to the proposed content, this is contingent
on the number and type of elements eventually found included or excluded
as a result of the BES definition itself which is still being drafted. Any
changes in that definition could in turn cause us concern regarding these
general instructions.
There needs to some provision for cases where specific elements which are
not specifically contained within the studies. It needs to be clear what
additional analysis needs to be provided under those circumstances.
We recommend that the owner of the asset be identified as part of the
general instructions.
In the case of wind resources, how is individual gross nameplate information
to be reported?

Response: In response to a provision for specific elements not contained in studies, the SDT encourages the submitting entity to
provide any additional information or explanation in the comments section of the questions that it believes will assist in the review of
its Exception Request. Additionally, the exception form has been clarified to bring home that point.
Page one: List any attached supporting documents and any additional information that is included to supports the request:
The owner of the asset is identified in the instructions that are being proposed as part of the ERO Rules of Procedures changes.
This revised definition does not change the way that wind resources are reported.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization
Snohomish County PUD
Blachly-Lane Electric Cooperative
Central Electric Cooperative (CEC)
Clearwater Power Company (CPC)
Consumer's Power Inc. (CPI)
Douglas Electric Cooperative (DEC)
Fall River Electric Cooperative (FALL)
Lane Electric Cooperative (LEC)
Lincoln Electric Cooperative (Lincoln)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)

Yes or No

Question 1 Comment

Yes

SNPD agrees generally that the General Instructions set forth the basic
information that would be necessary to support an Exception Request.
SNPD is concerned, however, that the statement “diagram(s) supplied
should also show the Protection Systems at the interface points associated
with the Elements for which the exception is being requested” may be
subject to differing interpretations. SNPD envisions that at least four
different kinds of documents would be responsive to the description: oneline diagrams with breakers and switches (status); identification of relays by
their ANSI device numbers; details of the DC control logic for ANSI devices;
and, operational scheme descriptions of the type used by system operators.
Accordingly, we suggest that the language be refined to identify the specific
kinds of diagrams necessary to identify protection systems at the interface
with the Elements for which the Exception is sought, including any required
details.
SNPD suggests that a generic example of a completed form be provided to
the industry to help ensure that Exception Requests are supported by
consistent and complete information. Such a generic example could be
addressed in the Phase 2 BES efforts.

Raft River Rural Electric Cooperative
(RAFT)
Umatilla Electric Cooperative
West Oregon Electric Cooperative
(WOEC)
Coos-Curry Electric Coooperative
City of Austin dba Austin Energy
Kootenai Electric Cooperative
Response: The various diagrams suggested by SNPD could be viable as forms of evidence that an entity may want to submit if the
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

entity believes they provide evidence to support the exception of an Element.
As far as developing generic examples, reference, or guidance documents, the SDT agrees with SNPD that this should be considered in
Phase II of the project.
Southern Company Generation

Yes

In the third bullet under the list of study attributes, it is very important to
specifically list the "key performance indicators of BES reliability". This will
assist in pointing the studies to focus on the issues relevant to determining
the signifacance of the exception request.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
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Organization

Yes or No

Question 1 Comment

provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
Also, see the answer to question #4.
Holland Board of Public Works

Yes

The requirement to base flow studies on an “interconnection-wide base
case" is likely to include many more lines and buses than necessary to model
the impact of a facility that is not material to the BES. Holland BPW request
the words “or regional reduction of such a case” be added after
“interconnection-wide base case” to avoid unnecessary expense and detail if
a more limited study set is adequate to demonstrate the lack of material
impact of the facility(ies) in question.

Michigan Public Power Agency

Yes

The requirement to base flow studies on an “interconnection-wide base
case" is likely to include many more lines and buses than necessary to model
the impact of a facility that is not material to the BES. MPPA and its
members request the words “or regional reduction of such a case” be added
after “interconnection-wide base case” to avoid unnecessary expense and
detail if a more limited study set is adequate to demonstrate the lack of
material impact of the facility(ies) in question.

Response: In response to the comment about a reduction base case, the SDT expects the entity seeking an exception to supply a
Base Case that the Regional Entity will acknowledge as appropriate. The SDT points to the variations that will abound in the
applications as negating any hard and fast rules in this regard. However, this is not something that hasn’t been handled before and
there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the application details, the SDT believes that both sides can quickly arrive at a resolution as to what information
needs to be supplied for the submittal to move upward to the ERO panel for a final determination. No change made.
Bonneville Power Administration

Yes

BPA suggests clarifying that the interface point is the point where the entity
seeking the exception’s facility or facilities interconnect(s) to the Bulk
Electric System facility.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

46

Organization

Yes or No

Question 1 Comment
Page 1 states “Supporting statements for your position from other entities
are encouraged.” BPA believes coordination with affected systems should
be required under the exemption process.

Response: In response to the comment about interface points, the SDT agrees with BPA’s suggestion that the interface point is the
point requested by the entity seeking the exception were the Element or Elements interconnect(s) to Bulk Electric System
Elements.
As for the comment about coordination, the SDT refers the commenter to Appendix 5C of the proposed NERC Rules of Procedure,
Section 4.5.2. This section requires the submitting entity to submit a copy of the Exception Request Form Section II to each
Planning Coordinator, Reliability Coordinator, Transmission Operator, Transmission Planner, and Balancing Authority that has (or
will have upon inclusion of the Element(s) in the BES) the Elements covered by an Exception Request within its Scope of
Responsibility.
Independent Electricity System
Operator

Yes

Central Lincoln

Yes

National Grid

Yes

Oncor Electric Delivery Company LLC

Yes

Ameren

Yes

Long Island Power Authority

Yes

Consumers Energy

Yes

NV Energy

Yes

Central Hudson Gas & Electric

Yes

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

Corporation
Exelon

Yes

Transmission

Yes

PacifiCorp

Yes

NERC Staff Technical Review

Yes

IRC Standards Review Committee

Yes

City of Redding Electric Utility

Yes

City of Redding

Yes

Tacoma Power

Yes

Tacoma Power supports the instructions as written.

Springfield Utility Board

Yes

SUB agrees with the instructions, finding them to be clear and reasonable.

BGE

Yes

No comment.

Southwest Power Pool Standards
Review Team

Yes

SERC Planning Standards
Subcommittee

Yes

Response: Thank you for your support.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

48

2. Pages two and three of the Detailed Information to Support an Exception Request contain a checklist of items that deal with
transmission facilities. Do you agree with the information being requested or is there information that you believe needs to be on
page two or three that is missing? Please be as specific as possible with your comments.
Summary Consideration: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on
this issue. The SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter.
However, after many hours of discussion and an initial attempt at doing so, it had become obvious to the SDT that the simple
answer that so many sought is not achievable. If the SDT could have come up with the simple answer, it would have been supplied
within the bright-line. The SDT would also like to point out to the commenters that it directly solicited assistance in this matter in
the first posting of the criteria and received very little in the form of substantive comments.
There are many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to
say that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with
this position. The exception application form has to be taken in concert with the changes to the ERO Rules of Procedure and
looked at as a single package. When one looks at the rules being formulated for the Exception process, it becomes clear that the
role of the Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of
reviewing the submittal for completion and making a recommendation to the ERO panel, not to make the final determination. The
Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter
that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to
be supplied. The SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes
that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC
Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review
Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part
of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides
NERC the option to remand the application to the Regional Entity with the mandate to process the exception if it finds the
Regional Entity erred in rejecting or disapproving the Exception Request. Conversely, an argument could be raised that the
Regional Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies
to be provided and how to interpret the information are not shown in the application process. The SDT again points to the
variations that will abound in the applications as negating any hard and fast rules. However, this is not something that has not
been handled before and there is a great deal of professional experience involved on both the submitter’s and the Regional
Entity’s side of the Exception process. Having viewed the application details, the SDT believes that both sides can quickly arrive at

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

49

a resolution as to what information needs to be supplied for the submittal to move upward to the ERO panel for a final
determination.
While commenters point to lack of direction being supplied to the ERO panel as to specific guidelines for them to follow in making
their decision, the SDT re-iterates the problem with providing such hard and fast rules. There are too many variables to consider.
Providing concrete guidelines is going to tie the hands of the ERO panel and inevitably result in poor decisions. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an
exception request must be based on whether the Elements are necessary for the reliable operation of the interconnected
transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power
system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or
cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or
unanticipated failure of system elements. The SDT firmly believes that the technical expertise of the ERO panel, the visibility of the
process, and the experience gained by having the hindsight resulting from reviewing multiple applications will result in an
equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper
decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception application form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2, which states “No single piece of evidence provided as part of an Exception Request or response to a
question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT has made several minor changes made to the specific items in the form in response to industry comments. The SDT
believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in
a favorable outcome.
The SDT affirms the requirement to provide the most recent consecutive two calendar year period minimum and maximum
magnitude of the power flow out of the Element(s) for which an Exception is sought. The SDT believes that a single year’s data is

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

50

insufficient to determine a pattern of flow on the Element(s). Moreover, many of the NERC Standards already require longer data
retention periods; typically for a full audit period which is either three or six years. See NERC Compliance Process Bulletin #2009005, Current In-Force Document Data Retention Requirements for Registered Entities, Version 1.0, at 1 (Jun.29, 2009). It should be
noted that retaining three second data from an Energy Management System (EMS) or a Supervisory Control And Data Acquisition
(SCADA) system is not sought in this instance.
The SDT declines to further define the “maximum magnitude of the power flow.” It is up to the submitting entity to determine
how best to present the information supporting their request and any responses provided by the submitting entity can be further
described or qualified under the comments section.
The SDT has determined that information on Flowgate impacts and whether Element(s) are included in an Interconnection
Reliability Operating Limit (IROL) are necessary to the Regional Entity’s determination of whether an Element(s) is used to provide
bulk power transfers within the Interconnections or whether the Element(s) is distribution. A number of interchange coordination
Reliability Standards apply to these transfer paths and Flowgates. Accordingly, the SDT believes such facilities are necessary for
the reliable operation of an interconnected electric transmission network and would not be excluded from the definition of the
BES. Furthermore, the SDT understands that each Flowgate list may be added to or subtracted from based on prevailing system
conditions, however, a core set of Flowgates will remain the same. It is up to the submitting entity to determine how best to
present the information supporting their request and the nature of the Element(s) impact on a permanent flowgate can be further
described or qualified under the comments section.
Due to comments received, the SDT made the following clarifying changes to the request form:
Page 1 - List any attached supporting documents and any additional information that is included to supports the request:
Q3. Please provide the appropriate list for yourthe operating area where the Element(s) is located:
Q6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan?
Q7. If yes, then using metered or SCADA data for the most recent consecutive two calendar year period, what is the minimum and
maximum magnitude of the power flow out of the facility Element(s)? and dDescribe the conditions and the time duration when
this could occurs?
Organization

Yes or No

Question 2 Comment

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51

Organization
Northeast Power Coordinating
Council

Yes or No
No

Question 2 Comment
For question 2 on page 2 For Transmission Facilities: o What standards will
define the “impact”? o What is a material impact and a non-material impact?
o What kinds and types of impacts are acceptable/unacceptable? o How are
impacts determined?
Question 6 on page 3 reads “Is the facility part of a Cranking Path associated
with a Blackstart Resource?”, suggest removing the reference to “Cranking
Path” because the Drafting Team does not require that the BES be contiguous,
and black start resource Cranking Paths were deleted from Inclusion I3.
Question 7 on page 3 asks, “Does power flow through this facility into the BES?”
This can only apply to a Local Network with two or more connections to the
BES. No power should normally flow through a Local Network (or Radial system)
to another portion of the BES. There may be occasional, brief reverse power
flows may be acceptable during short periods under abnormal operating
conditions.
Question 7 also requests “data for the most recent consecutive two calendar
year period.” Why is two years worth of data necessary? One year of data
would be sufficient.
From Question 7, “what is the minimum and maximum magnitude of the power
flow out of the facility ...” What is intended by the use of magnitude?
Suggest that the Drafting Team adopt the FERC Seven Factor test for question 7.
Suggest deleting the “% of the calendar year” check boxes in favor of a
statement either that power does not flow through the Local Network, or
alternatively, a blank space for reporting the net peak MWs and MWHs
transferred annually through the facility, and the percentage of these
transferred amounts to the peak and annual MWH demands served by the Local
Network.
Suggest requesting only one year (8,760 hours) of data covering four seasons,

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Organization

Yes or No

Question 2 Comment
including Summer and Winter capability periods.

Consolidated Edison Co. of NY,
Inc.

No

Application Form Page 2For Transmission Facilities:Impacts:Flowgates: The
Application form at 2 states, “How does the facility impact permanent
Flowgates in the Eastern Interconnection ...” o What standards for “impact”
does the BES SDT envision? o What is a material impact and a non-material
impact? o What kinds and types of impacts are acceptable and/or
unacceptable? o How are impacts determined, e.g., Power TFD method, short
circuit analysis, A-10 method?Impact-Based Studies: Note that the FERC Seven
Factor test is a time-tested method and FERC has identified it as an acceptable
method for reliability purposes; for gauging the expected impact of an Element
on the interconnected transmission grid. The NPCC A-10 method has been used
extensively in the Northeastern U.S. and Canada, and is an impact-based
approach. The power TDF (transfer distribution factor) method is also used by
some to assess the impact of changing power flows on individual Elements
within a system. FERC has studied using the ‘TIER’ method for classifying system
Elements based on LBMP impacts. WECC uses a short circuit test.
Page 3Cranking Path Issue: The Application form at 6 asks, “Is the facility part of
a Cranking Path associated with a Blackstart Resource?”We understand that:(i)
The drafting team does not require that the BES be contiguous, and (ii)
Blackstart resource Cranking Paths were deleted from Inclusion I3.
Recommendation: Delete the reference to “Cranking Paths” in this Application
form.
Power Flow Issue: The Application form at 7 asks, “Does power flow through
this facility into the BES?” We assume that this can only apply to a Local
Network with two or more connections to the BES. We believe that no power
should normally flow through a Local Network (or Radial system) to another
portion of the BES. Occasional, brief reverse power flows may be acceptable
during short periods under abnormal operating conditions, e.g., a switch

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Organization

Yes or No

Question 2 Comment
normally open is briefly closed during a forced maintenance outage.
The Application form at 7 requests the following: “data for the most recent
consecutive two calendar year period.” o Please explain why the BES SDT felt
that two years worth of data was necessary, as one year of data would appear
sufficient? Our experience has been that one year (8,760 hours) of data covers
four seasons, including Summer and Winter capability periods, and is therefore
sufficient. Requiring an extra year is perhaps unnecessarily burdensome on
filing Entities, whether asset owners or Regional Entities.
The Application form at 7 asks, “[W]hat is the minimum and maximum
magnitude of the power flow outflow of the facility ...” o Please explain why
the BES SDT used the term “magnitude” when requesting power outflow data?
Recommendations: 1) We strongly recommend that the BES SDT adopt the
FERC Seven Factor test for these purposes. The FERC Seven Factor test states
that, o “Power flows into local distribution systems, and rarely, if ever flows
out,” and o “When power enters a local distribution system, it is not
reconsigned or transported on to some other market.”
2) We recommend deleting the “% of the calendar year” check boxes in favor of
a statement either that power does not flow through the Local Network, or
alternatively, a blank space for reporting the net peak MWs and MWH’s
transferred annually, and the percentage of these transferred amounts to the
peak and annual MWH demands served by with the Local Network.3) We
recommend requesting only one year (8,760 hours) of data covering four
seasons, including Summer and Winter capability periods.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on the Exception
criteria. The SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However,
after many hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that a simple answer is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
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received very little in the form of substantive comments.
Not indicating the explicit types of studies to be provided and how to interpret the information in the application process does not
fail to provide a basis for the Regional Entity to determine what constitutes an acceptable submittal. The SDT again points to the
variations that will abound in the applications as negating any hard and fast rules in this regard. However, this is not something that
hasn’t been handled before and there is a great deal of professional experience involved on both the submitter’s and the Regional
Entity’s side of this equation. Having viewed the application details, the SDT believes that both sides can quickly arrive at a resolution
as to what information needs to be supplied for the submittal to move upward to the ERO panel for a final determination.
As to the lack of direction being supplied to the ERO panel in the form of specific guidelines to follow, the SDT refers the commenters
to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception request
must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system.
Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within
equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures
of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or unanticipated failure of
system elements. The SDT firmly believes that the technical expertise of the ERO panel, the visibility of the process, and the
experience gained by having the hindsight resulting from reviewing multiple applications will result in an equitable, transparent, and
consistent approach to the problem.
Finally, there are options for a submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they
feel that an improper decision has been made on their submittal.
The SDT disagrees with eliminating the question pertaining to Cranking Path. It is important to realize a distinction between the BES
definition and the Exception process. While the BES definition established bright-line criteria for the determination between BES and
non-BES Element(s), the Exception Process requires an evaluation of all the responses and supporting materials provided as part of
the Exception Request Form. No single response or piece of supporting information will be solely dispositive in an Exception Request
evaluation. It is not correct to assume that simply because an evaluation criterion was removed from the bright-line definition it
should also be eliminated from consideration in the Exception Process. The SDT believes that consideration of Cranking Paths is
among the factors to be given consideration in the evaluation for an Exception Request application. Any further discussion of this
issue is within the scope of the Phase II SAR. No change made.
With respect to concerns about including power flowing through a local network in the Exception Request Form, these concerns fail
to recognize the distinction between the BES definition and the Exception Process. As stated above, while the BES definition

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established bright-line criteria for the determination between BES and non-BES Element(s), the Exception Process requires an
evaluation of all the responses and supporting materials provided as part of the Exception Request Form. The SDT believes that
power flow through an Element into the BES is among the factors to be given consideration in the evaluation of an Exception
Request. In fact, the example identified by commenters identifies one situation that requires such consideration; where occasional,
brief reverse power flows may be acceptable during short periods under abnormal operating conditions. Further discussion of this
issue is within the scope of the Phase II SAR. No change made.
The SDT affirms the requirement to provide the most recent consecutive two calendar year period minimum and maximum
magnitude of the power flow out of the Element(s) for which an Exception is sought. The SDT believes that a single year’s data is
insufficient to determine a pattern of flow on the Element(s). Moreover, many of the NERC Standards already require longer data
retention periods; typically for a full audit period which is either three or six years. See NERC Compliance Process Bulletin #2009-005,
Current In-Force Document Data Retention Requirements for Registered Entities, Version 1.0, at 1 (Jun.29, 2009). It should be noted
that retaining three second data from an Energy Management System (EMS) or a Supervisory Control And Data Acquisition (SCADA)
system is not sought in this instance. No change made.
The SDT declines to further define the “maximum magnitude of the power flow.” It is up to the submitting entity to determine how
best to present the information supporting their request and any responses provided by the submitting entity can be further
described or qualified under the comments section. No change made.
The General Instruction area on page one has been modified to clarify that a submitting entity may provide documents and any
additional information, including Seven Factor Test related information, which supports their request. It is up to the Submitting
entity to determine how best to present the information supporting their request. If the submitting entity wishes to provide this
additional information it may do so by listing this information in the area provided under General Instructions in the Exception
Request Form.
Page one: List any attached supporting documents and any additional information that is included to supports the request:
The SDT has deleted the checkboxes in Question 7. To replace the checkboxes, language has been added requesting the submitting
entity to describe the conditions and the time duration when power flow through Element(s) into the BES. It is up to the submitting
entity to determine how best to present the information supporting their request.
Q7. If yes, then using metered or SCADA data for the most recent consecutive two calendar year period, what is the minimum
and maximum magnitude of the power flow out of the facility Element(s)? and dDescribe the conditions and the time duration
when this could occurs?
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ACES Power Marketing
Standards Collaborators

Yes or No
No

Question 2 Comment
Q1, Q5 and Q6 have a “Description/Comments” section. What type of
information should be included under the Description for each of these
questions? Providing more guidance here would help achieve the
“standardization, clarity and continuity of process” that we seek.
Regarding Q2: A permanent flowgate should not be part of the detailed
information to support an exception. First, there is no definition for what
constitutes a permanent flowgate. Second, flowgates are often created for a
myriad of reasons that have nothing to do with them being necessary to
operate the BES. While section c) in E3 attempts to limit the applicability to
permanent flowgates, there is no definition for what constitutes a permanent
flowgate particularly since no flowgate is truly permanent. The NERC Glossary
of Terms definition of flowgate includes flowgates in the IDC. This is a problem
because flowgates are included in the IDC for many reasons not just because
reliability issues are identified. Flowgates could be included to simply study the
impact of schedules on a particular interface as an example. It does not mean
the interface is critical. As an example, it could be used to generate evidence
that there are no transactional impacts to support exclusion from the BES.
Furthermore, the list of flowgates in the IDC is dynamic. The master list of IDC
flowgates is updated monthly and IDC users can add temporary flowgates at
anytime. While the "permanent" adjective applied to flowgates probably limits
the applicability from the “temporary” flowgates, it is not clear which of the
monthly flowgates would be included from the IDC since they might be added
one month and removed another. Flowgates are created for many reasons that
have nothing to do with them being necessary to operate the BES. First,
flowgates are created to manage congestion. The IDC is more of a congestion
management tool than a reliability tool. FERC recognized this in Order 693,
when they directed NERC to make clear in IRO-006 that the IDC should not be
relied upon to relieve IROLs that have been violated. Rather, other actions such
as re-dispatch must be used in conjunction. Second, flowgates are used as a
convenient point to calculate flows to sell transmission service. The

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characteristics of the flowgate make it a good proxy for estimating how much
contractual use has been sold not necessarily how much flow will actually occur.
While some flowgates definitely are created for reliability issues such as IROLs,
many simply are not.
We are unclear about what “an appropriate list” in Q3 is supposed to be. Is it
supposed to be a list of all IROLs or only those for which the answer is yes?
Why is a list even necessary since the answer to the question answers Exclusion
E3.c? If the answer is no, is this asking the submitter to prove the negative?

Response: The SDT believes the guidance provided on Page 1 of the Exception Request Form is sufficient. A submitting entity may
provide any additional information or explanation in the comments section of the questions that it believes will assist in the review of
its Exception Request. No single response or piece of supporting information will be solely dispositive in an Exception Request
evaluation and all responses and supporting information provided will receive consideration. It is up to the submitting entity to
determine how best to present the information supporting their request in the comment area provided for each question. No change
made.
The SDT has determined that information on Flowgate impacts and whether Element(s) are included in an Interconnection Reliability
Operating Limit (IROL) are necessary to the Regional Entity’s determination of whether an Element(s) is used to provide bulk power
transfers within the Interconnections or whether the Element(s) is distribution. A number of interchange coordination Reliability
Standards apply to these transfer paths and Flowgates. Accordingly, the SDT believes such facilities are necessary for the reliable
operation of an interconnected electric transmission network and would not be excluded from the definition of the BES.
Furthermore, the SDT understands that each Flowgate list may be added to or subtracted from based on prevailing system
conditions, however, a core set of Flowgates will remain the same. It is up to the submitting entity to determine how best to present
the information supporting their request and the nature of the Element(s) impact on a permanent flowgate can be further described
or qualified under the comments section. No change made.
The SDT has clarified that the submitting entity is to provide the appropriate list of IROLs for the operating area where the Element(s)
is/are located.
Q3. Please provide the appropriate list for yourthe operating area where the Element(s) is located:
Bonneville Power

No

Regarding #4 on page 2: BPA believes the impact to the over-all reliability of

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Question 2 Comment
the BES needs to consider more than just an outage of the facility requesting
exclusion. One example is a contingency outage of a parallel facility that could
cause an overload. Item 4 needs to include impacts of either the outage of the
facility, or with the facility in service.BPA believes that the entity requesting an
exception may not have information on impacts of the facility on parallel
higher-voltage facilities because the NERC requirements for data sharing for
these types of facilities does not necessarily include owners and operators of
lower voltage systems. The entity requesting an exemption would likely need
to coordinate with affected systems, and this coordination should be required
in the exemption process so that affected systems are aware of the possible
exclusion.

Response: The SDT will continue to monitor the process over next 12 months and if it is determined additional information is
needed, such as how outages of BES facilities impact the Element(s) for which an exception is sought, it will be addressed in Phase II.
Nevertheless, submitting entities are free to include information in response to any question that best supports their request for an
exception. No change made.
Coordination of an exception request with affected systems is already addressed in the Exception Rules of Procedure, Appendix 5C
Sections 4.1, 4.4, 4.5.1, and 4.5.2, requiring the submitting entity, if not the facility owner, to provide a copy of the request to the
facility owner, all involved Regional Entities if it is a cross-border facility, and to the Planning Coordinator, Reliability Coordinator,
Transmission Operator, Transmission Planner, and Balancing Authority that has (or will have upon inclusion in the BES) the Elements
covered by an exception request within its scope of responsibility.
Pepco Holdings Inc

No

1) Why is Item 5 (Question pertaining to whether the facility is used for off-site
power to a nuclear plant) included, since this criteria is not part of the proposed
bright-line BES definition.
2) Similarly, why is Item 6 (Question pertaining to whether the facility is part of
a Cranking Path associated with a Black Start Resource) included, since Black
Start Cranking Paths were removed from the latest BES definition.
Both Items 5 and 6 should be removed from the Exception Request Form.

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Response: The SDT disagrees with eliminating Questions 5 and 6. It is important to realize a distinction between the BES definition
and the Exception Procedure. While the BES definition established bright-line criteria for the determination between BES and nonBES Element(s), the Exception Process requires an evaluation of all the responses and supporting materials provided as part of the
Exception Request Form. No single response or piece of supporting information will be solely dispositive in an Exception Request
evaluation. It is not correct to assume that simply because an evaluation criterion was removed from the bright-line definition it
should also be eliminated from consideration in the Exception Process. The SDT believes that Cranking Paths and off-site power
supply to a nuclear power plants are among the factors to be given consideration in the evaluation for an Exception Request. Further
discussion of this issue is within the scope of the Phase II SAR. No change made.
Electricity Consumers
Resource Council (ELCON)

No

A sub-question should be added to Question 1 asking: (1) Does the generation
serve all or a part of retail customer Load, and (2) If so, the maximum net
capacity of each unit injected to the BES during non-emergency conditions.

Response: The General Instruction area on page one has been modified to clarify that a submitting entity may provide documents
and any additional information that supports their request. If the submitting entity wishes to provide this additional information it
may do so by listing this information in the area provided under General Instructions. No change made.
AECI and member G&Ts

No

There is no basis in this draft Standard for including Item 6).
Item 7) does appear appropriate within the Standard, but the intent of the four
check-boxes is ambiguous.

Response: The SDT disagrees with eliminating the question pertaining to Cranking Path. It is important to realize a distinction
between the BES definition and the Exception Procedure. While the BES definition established bright-line criteria for the
determination between BES and non-BES Element(s), the Exception Procedure requires an evaluation of all the responses and
supporting materials provided as part of the Exception Request Application Form. No single response or piece of supporting
information will be solely dispositive in an Exception Request evaluation. The SDT believes that the Cranking Path is among the
factors to be given consideration in the evaluation for an Exception Request application. Further discussion of this issue is within the
scope of the Phase II SAR. No change made.
The SDT has deleted the checkboxes in Question 7. To replace the checkboxes, language has been added requesting the submitting
entity to describe the conditions and the time duration when power flow through Element(s) into the BES. It is up to the submitting
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Question 2 Comment

entity to determine how best to present the information supporting their request.
Q7. If yes, then using metered or SCADA data for the most recent consecutive two calendar year period, what is the minimum
and maximum magnitude of the power flow out of the facility Element(s)? and dDescribe the conditions and the time duration
when this could occurs?
NERC Staff Technical Review

No

In addition to describing how an outage of the facility under consideration
affects the rest of the BES, the Submitting entity also should be required to
provide an assessment of how outages of BES facilities affect the facility under
consideration. This could be achieved with powerflow studies or distribution
factor analysis.

Response: The SDT will continue to monitor the process over next 12 months and if it is determined additional information is
needed, such as how outages of BES facilities impact the Element(s) for which an Exception is sought, it will be addressed in Phase II.
Nevertheless, the General Instruction area on page one has been modified to clarify that a submitting entity may provide documents
and any additional information that supports their request. If the submitting entity wishes to provide this additional information it
may do so by listing this information in the area provided under General Instructions. No change made.
IRC Standards Review
Committee

No

We agree with most parts on P.2 and P.3, but question the need for Q6, which
asks:”Is the facility part of a Cranking Path associated with a Blackstart
Resource?”I3 in the BES definition stipulates that Blackstart Resources
identified in the Transmission Operator’s restoration plan be included (which
we disagree and commented in the BES Definition Comment Form). There is no
inclusion of any transmission facilities that are part of the cranking path. We
suggest this item (Q6) be removed.

Response: The SDT disagrees with eliminating the question pertaining to Cranking Path. It is important to realize a distinction
between the BES definition and the Exception Procedure. While the BES definition established bright-line criteria for the
determination between BES and non-BES Element(s), the Exception Procedure requires an evaluation of all the responses and
supporting materials provided as part of the Exception Request Form. No single response or piece of supporting information will be
solely dispositive in an Exception Request evaluation. It is not correct to assume that simply because an evaluation criterion was
removed from the bright-line definition it should also be eliminated from consideration in the Exception Procedure. The SDT believes
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Question 2 Comment

that Cranking Path is among the factors to be given consideration in the evaluation for an Exception Request application. Further
discussion of this issue is within the scope of the Phase II SAR. No change made.
PacifiCorp

No

Question 6 implies that if the facility is part of a designated blackstart cranking
path then an exception request would most likely be denied. To the extent that
was the intent, such an assumption would only be reasonable if the blackstart
cranking path is the only path available. However, PacifiCorp suggests modifying
the current Question 6 to reflect a situation in which multiple cranking paths
are available, as follows:”6A. Is the facility part of a Cranking Path associated
with a Blackstart Resource? 6B. If yes, does the Blackstart Resource have other
viable Cranking Paths?”

Response: Several commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will
mandate a negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed ERO Rules of
Procedure, Section 3.2 that states “No single piece of evidence provided as part of an Exception Request or response to a question
will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT has adopted clarifying language to differentiate between multiple Cranking Paths by requiring the Cranking Path “identified
in a Transmission Operator’s restoration plan.”
Q6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan?
Snohomish County PUD

No

SNPD agrees that the checklist of items on pages two and three lists most of the
information that would be necessary to determine if an Exceptions Request is
justified. We suggest three modifications to the proposed language to ensure
consistency with Section 215 of the Federal Power Act, with the BES Definition,
and to provide an entity seeking an Exception with the opportunity to submit all
relevant information: (1) SNPD suggests that a new question should be added
concerning the function of the facility, which would read: “Does the facility
function as a local distribution facility rather than a Transmission facility? If yes,
please provide a detailed explanation of your answer.” Section 215(a)(1) of the

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Question 2 Comment
FPA makes clear that “facilities used in the local distribution of electric energy”
are excluded from the BES, 16 U.S.C. § 824o(a)(1), and the most recent draft of
the BES definition incorporates the same language. SNPD believes a question to
address the function of the Element or system subject to an Exception Request
is necessary to determine whether the Element or system is “used” in local
distribution and thereby to ensure that this statutory limit on the BES is
observed in the Exceptions process. Further, we believe a variety of
information may be relevant to determining whether a particular facility
functions as local distribution rather than as part of the BES. For example, if
power is not scheduled across the facility or if capacity on the system is not
posted on the relevant OASIS, it is likely to function as local distribution, not
transmission. Similarly, if power enters the system and is delivered to load
within the system rather than moving to load located on another system, its
function is local distribution rather than transmission. SNPD proposes the
language above as an open-ended question so that the entity submitting the
Exceptions Request can provide this and any other information it deems
relevant to facility function.
(2) SNPD suggests modifying question 6 to “Is the facility part a designated
Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan.” This language reflects the most recent revision of
the BES Definition, which removes the reference to “Cranking Paths,” and also
helps distinguish between generators which have Blackstart capability and
those generators that are designated as a Blackstart Resource in the
Transmission Operator’s restoration plan. It is only the latter that are included
in the BES under the current draft of the definition.
(3) A general “catch-all” question should be added that will prompt the entity
submitting an Exception Request to submit any information it believes is
relevant to the Exception that is not captured in the other questions. We
suggest the following language:"Is there additional information not covered in
the questions above that supports the Exception Request? If yes, please

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Question 2 Comment
provide the information and explain why it is relevant to the Exception
Request."While SNPD believes the questions set forth in the draft capture the
information that generally would be necessary to determine whether an
Exception Request should be granted, it is foreseeable that there may be
unusual circumstances where the information called for either does not capture
the full picture or where studies other than the specific types called for in the
draft form support the Exception. An entity seeking an Exception should have
the opportunity to present any information it believes is relevant.

Response: The General Instruction area on page one has been modified to clarify that a submitting entity may provide documents
and any additional information that supports their request. It is up to the submitting entity to determine how best to present the
information supporting their request. If the submitting entity wishes to provide this additional information it may do so by listing this
information in the area provided under General Instructions.
Page one: List any attached supporting documents and any additional information that is included to supports the request:
The SDT has adopted clarifying language to differentiate between multiple Cranking Paths by requiring the Cranking Path “identified
in a Transmission Operator’s restoration plan.”
Q6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan?
Duke Energy

No

Modify wording on #3 as follows: “Please provide the appropriate list for the
operating area where the facility is located.”
Modify the wording on #6 as follows: “Is the facility part of a Cranking Path
identified in an entity’s restoration plan for a Blackstart Resource as required by
EOP-005-2?”

Response: The SDT has accepted the recommended wording change to Question 3.
Q3. Please provide the appropriate list for yourthe operating area where the Element(s) is located:
The SDT has adopted clarifying language to differentiate between multiple cranking paths by requiring the cranking path “identified

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in a Transmission Operator’s restoration plan.”
Q6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan?
ReliabilityFirst

No

All generating units, to some degree, affect the transmission elements that
make-up the BES. What role will this effect have on the determination? If the
systems are planned properly and the day-ahead analysis is done for
maintenance work, the outage of any one element is moot. What is the phrase
“impact the over-all reliability” getting at? These studies and analysis will need
to look at multiple outages and groups of elements being taken out and
excluded. Will this be on a first come, first out process?
As for the Nuclear Plant Interface Requirement (NPIR) question, ReliabilityFirst
Staff believes these facilities should always be included as part of the BES and
taken out of the Detailed Information to Support an Exception Request.
For question 6 ReliabilityFirst Staff believes the Cranking Path should be
included in the BES definition. . ReliabilityFirst Staff feels that without including
the Cranking Paths, the reliability of the system could be jeopardized if a
restoration is required and the Cranking Paths are unavailable due to nonadherence to Reliability Standards.
Omit question 7, E3 (LN) of the definition already talks to power flow and even
if there is a small percentage of flow, it makes that entity a user of the BES,
which should be included.

Response: The SDT refers the commenter to the phrase consistent ‘with TPL methodologies’ which the SDT believes will cover the
item in question. The SDT reminds the commenter that the evaluation in question is not for removing the Element from service but
simply from inclusion or exclusion in the BES. Therefore, there should be no problem with evaluating multiple requests in the same
area and no first in, first out scenario.
The questions on nuclear interface facilities and Cranking Paths will be retained. They are just one piece of information in the process

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and the SDT considers them as important considerations. No change made.
Question 7 will be retained. It is important to realize a distinction between the BES definition and the Exception Procedure. While
the BES definition established bright-line criteria for the determination between BES and non-BES Element(s), the Exception
Procedure requires an evaluation of all the responses and supporting materials provided as part of the Exception Request Form. No
single response or piece of supporting information will be solely dispositive in an Exception Request evaluation. The SDT believes
that power flow through this Element(s) into the BES is among the factors to be given consideration in the evaluation for an
Exception Request application.
Hydro-Quebec TransEnergie

No

Manitoba Hydro

No

Response: Without additional information, the SDT is unable to respond.
Consumers Energy

No

We believe that item 6, should read "Is the facility part of a Primary Cranking
Path associated with a Blackstart Resource?" Currently, the word "Primary" is
not included.

Response: The SDT has adopted clarifying language to differentiate between multiple cranking paths by requiring the cranking path
“identified in a Transmission Operator’s restoration plan.”
Q6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan?
Orange and Rockland Utilities,
Inc.

No

Please clarify “facility” and include “N-1” for power-flow studying.

Response: In order to maintain consistency with the nomenclature used in the Exception Process Document, draft Appendix 5C of
the NERC Rules of Procedure, the SDT has replaced “facilities” with “Element(s)”, where appropriate.
The SDT has pointed to the TPL methodology in the document and that should address your comment. No change made.

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ISO New England Inc

Yes or No
No

Question 2 Comment
- Question 1o The use of the words “connected to” is unclear. Some may read
this as generation “directly” connected to while others could interpret it more
generically.
o A generation cut-off should be included in the requirement to list all indiv

Response: The SDT acknowledges and appreciates the comments but has determined no additional clarity is needed to Question 1.
It is up to the submitting entity to determine how best to present the information supporting their request and any responses can be
further described or qualified under the comments section to Question 1. No change made.
The SDT does not believe a generation threshold is appropriate for listing all connected units. The SAR for Phase II of this project calls
for a review of the process after 12 months of experience. The SDT believes that this time period will allow industry to see if the
process is working correctly and to suggest changes to the process based on actual real-world experience and not just on
suppositions of what may occur in the future. No change made.
PSEg Services Corp

No

Questions #4 requires an analysis of the “most severe impact” associated an
outage of the Element proposed for exception. a. Both the newly Board
approved TPL-001-2 standard and the existing TPL-004-1 require that severe
contingencies be evaluated, but there are no performance requirements for
them. If the team intended the “most-severe impact” analysis to only evaluate
TPL outages that incorporate performance requirements, it should make that
clear. b. The most-severe-outage impact question does not ask key relevant
information such as: i. What is the probability that the “most severe impact
“will occur? ii. Could the impact be readily mitigated and service restored? This
point is critical because the impact of an outage lasting several minutes before
restoration versus several hours before restoration should affect the analysis.
What does question #7 (“Does power flow through this facility into the BES?”)
with check boxes for various % of a calendar year that power flows into the BES)
imply with respect to a transmission facility’s exception request? Also, is the %
of a calendar year data intended to be forecasted data or historic data? It
would seem that forecasted data would need to be supplied that is consistent

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with the TPL models.
Finally, why are historic flows requested - they have no relevance except for
perhaps explaining historic and forecasted differences?

Response: The document cites that the TPL methodology should be followed and that should address your concern. An entity does
not have to duplicate TPL studies. No change made.
The SDT has replaced the checkboxes and language has been added requesting the submitting entity to describe the conditions and
the time duration when power flow through Element(s) into the BES. It is up to the submitting entity to determine how best to
present the information supporting their request.
Q7. If yes, then using metered or SCADA data for the most recent consecutive two calendar year period, what is the minimum
and maximum magnitude of the power flow out of the facility Element(s)? and dDescribe the conditions and the time duration
when this could occurs?
Historic flows are requested because they are an indication of power flow patterns. It is up to the submitting entity to determine
how best to present the information supporting their request and any responses can be further described or qualified under the
comments section.
City of St. George

No

The questions for transmission facilities seem to be appropriate; however, how
the answers are to be used by the region or NERC is unclear. Will a given
response to a question make exclusion impossible? If so this needs to be known
upfront and clearly documented.
For example question 4, on page 2 is open for interpretation and debate as to
what the impact to the over-all reliability of the BES is. The definition of
“impact” is really the key to the whole definition effort. Load flow, voltage,
frequency change limits may all be pieces to the puzzle. Are these criteria to be
met in normal, N-1, N-2, etc. system configurations?

Response: Several commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception application form will
mandate a negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules
of Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an
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Yes or No

Question 2 Comment

Exception Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be
approved or disapproved.”
The document cites that an entity should follow the TPL methodology.
Blachly-Lane Electric
Cooperative
Central Electric Cooperative
(CEC)
Clearwater Power Company
(CPC)
Consumer's Power Inc. (CPI)
Douglas Electric Cooperative
(DEC)
Fall River Electric Cooperative
(FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(Lincoln)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric

No

BLEC agrees that the checklist of items on pages two and three lists most of the
information that would be necessary to determine if an Exceptions Request is
justified. We suggest two modifications to the proposed language to ensure
consistency with the BES Definition and to provide an entity seeking an
Exception with the opportunity to submit all relevant information:
(1) We suggest modifying question 6 to “Is the facility part of a designated
Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan.” This language reflects the most recent revision of
the BES Definition and also helps distinguish between generators which have
Blackstart capability and those generators that are designated as a Blackstart
Resource in the Transmission Operator’s restoration plan. It is only the latter
that are included in the BES under the current draft of the definition.
(2) A general “catch-all” question should be added that will prompt the entity
submitting an Exception Request to submit any information it believes is
relevant to the Exception that is not captured in the other questions. We
suggest the following language: Is there additional information not covered in
the questions above that supports the Exception Request? If yes, please
provide the information and explain why it is relevant to the Exception Request.
While we believes the questions set forth in the draft capture the information
that generally would be necessary to determine whether an Exception Request
should be granted, it is foreseeable that there may be unusual circumstances
where the information called for either does not capture the full picture or
where studies other than the specific types called for in the draft form support
the Exception. An entity seeking an Exception should have the opportunity to
present any information it believes is relevant.

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Question 2 Comment

Cooperative (RAFT)
Umatilla Electric Cooperative
West Oregon Electric
Cooperative (WOEC)
Coos-Curry Electric
Coooperative
City of Austin dba Austin
Energy
Kootenai Electric Cooperative
Response: The SDT has clarified the language of question 6.
Q6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan?
The General Instruction area on page one has been modified to clarify that a submitting entity may provide documents and any
additional information that supports their request. It is up to the submitting entity to determine how best to present the information
supporting their request. If the submitting entity wishes to provide this additional information it may do so by listing this information
in the area provided under General Instructions on the Exception Request Form.
Page one: List any attached supporting documents and any additional information that is included to supports the request:
Central Lincoln

Yes

We note that if Q7 is yes, an entity is asked to provide meter or SCADA data.
Evidently the team assumes the facility in question is existing. We propose that
study data could be provided instead for facilities that are in the planning stage.

Response: The SDT recommends that each submitting entity work with its Regional Entity to resolve issues with information
availability or access and, in the event such information is not available, whether suitable replacement data is acceptable. The SDT
further recommends that where information is unavailable, the submitting entity state such in the comment area and provide the
reason for this unavailability. This will signal the Regional Entity that an issue concerning information availability will need to be

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Yes or No

Question 2 Comment

resolved as part of the review process. No change made.
National Grid

No

We agree with the information requested on pages 2 and 3, however we would
like more clarification regarding Item 7. When answering what % of the
calendar year power flows through the facility into BES, should this be
calculated on an hourly basis?
We would also like clarification for Item 7 regarding the request for SCADA data
from the last 2 years to determine the minimum and maximum magnitude of
the power flow out of the facility. What data should be used in situations with
new facilities or in situations or where the system configuration (topology) has
changed in such a way that the power flows in the area have changed, so the
last 2 years of SCADA data is no longer relevant

Response: The SDT has deleted the checkboxes in Question 7. To replace the checkboxes, language has been added requesting the
submitting entity to describe the conditions and the time duration when power flow through Element(s) into the BES. It is up to the
submitting entity to determine how best to present the information supporting their request.
Q7. If yes, then using metered or SCADA data for the most recent consecutive two calendar year period, what is the minimum
and maximum magnitude of the power flow out of the facility Element(s)? and dDescribe the conditions and the time duration
when this could occurs?
The SDT recommends that each submitting entity work with its Regional Entity to resolve issues with information availability or
access and, in the event such information is not available, whether suitable replacement data is acceptable. The SDT further
recommends that where information is unavailable, the submitting entity state such in the comment area and provide the reason for
this unavailability. This will signal the Regional Entity that an issue concerning information availability will need to be resolved as part
of the review process.
Ameren

No

From our perspective, the first question should be “Is the facility connected at
100 kV or above?” The questions should be reordered. Of the questions listed,
question #3 should be #1, and questions #1 should be the last question in this
section.

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Yes or No

Question 2 Comment
Regarding the word “permanent” as it is used to describe Flowgates, it is
suggested that the word “limiting” or “constrained” be used instead.

Response: The SDT does not believe the order of the questions is significant since no single response or piece of supporting
information will be solely dispositive in an Exception Request evaluation and all responses and supporting information provided will
receive consideration. No change made.
The SDT believes that the continued qualifier of “permanent” associated with the term “Flowgate” addresses the intent of the
definition. No change made.
ATC LLC

No

ATC proposes the following changes to Item #7:7a. Are Firm Power Transfers
scheduled to flow out of, or through, this facility into the BES in the operating
horizon? [for BES designations applicable to the operating horizon] Note: The
consideration for power flowing into the BES should be based on normal
operating conditions or base case (n-0 contingency analysis), not on historical
real-time telemetry. 7b. Are Firm Power Transfers reserved to flow out of, or
through, this facility into the BES in the planning horizon? [for BES designations
applicable to the planning horizon)

Response: The General Instruction area on page one has been modified to clarify that a submitting entity may provide documents
and any additional information that supports the request. It is up to the submitting entity to determine how best to present the
information supporting their request. If the submitting entity wishes to provide this additional information it may do so by listing this
information in the area provided under General Instructions on the Exception Request Form.
Page one: List any attached supporting documents and any additional information that is included to supports the request:
Farmington Electric Utility
System

No

The form should be titled “For Transmission Elements” rather than “Facilities”
to align with the BES definition and Appendix 5C of the NERC Rules of
Procedure.
The form should align with section 4.5.1 and 4.5.2 of Appendix 5C. It should
include a listing of the Element(s) and the status based on the application of the

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Yes or No

Question 2 Comment
BES Definition.
Question 6 relates to a ‘facility’ that is part of a Cranking Path. The latest
revision of the BES Definition removed the designated blackstart Cranking Paths
from the Inclusion of the BES in I3. Having a question regarding the Cranking
Path in the Exception Request makes it appear Cranking Paths are still
automatically included in the BES.
Question 7; what is an alternate method if a Requesting Entity does not have
SCADA data for the most recent two consecutive calendar years.

Response: In order to maintain consistency with the nomenclature used in the Exception Process Document, draft Appendix 5C of
the NERC Rules of Procedure, the SDT has replaced “facilities” with “Element(s)”, where appropriate.
A checkbox for indicating the current BES status and a space for listing elements for which an exception is sought is included in
Sections I and II, respectively, of the Exception Request Form provided by the Rules of Procedure Team in their posting.
The SDT disagrees with eliminating the question pertaining to Cranking Path. It is important to realize a distinction between the BES
definition and the Exception process. While the BES definition established bright-line criteria for the determination between BES and
non-BES Element(s), the Exception Process requires an evaluation of all the responses and supporting materials provided as part of
the Exception Request Form. No single response or piece of supporting information will be solely dispositive in an Exception Request
evaluation. It is not correct to assume that simply because an evaluation criterion was removed from the bright-line definition it
should also be eliminated from consideration in the Exception process. The SDT believes that cranking paths is among the factors to
be given consideration in the evaluation for an Exception Request application. Any further discussion of this issue is within the scope
of the Phase II SAR. No change made.
The SDT further disagrees that including Question 6 in the Exception Request Form, relating to Element(s) that are a part of a
Cranking Path, makes it appear that Cranking Paths are automatically included in the BES. The BES definition and the Exception
Request Procedure are separate processes.
The SDT recommends that each submitting entity work with its Regional Entity to resolve issues with information availability or
access and, in the event such information is not available, whether suitable replacement data is acceptable. The SDT further
recommends that where information is unavailable, the submitting entity state such in the comment area and provide the reason for
this unavailability. This will signal the Regional Entity that an issue concerning information availability will need to be resolved as part
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Yes or No

Question 2 Comment

of the review process. No change made.
Metropolitan Water District of
Southern California

No

General Comments: Metropolitan Water District of Southern California
(“MWDSC”) believes that additional work is necessary to explain how this
Detailed Information to Support an Exception Request will be used in evaluating
whether a transmission facility will be an exception to the BES.
In addition, MWDSC agrees WECC that the proposed Technical Principles for
Demonstrating BES Exceptions Request is lack of clarity. It does not provide
detail information as to what entities must provide to support their requests,
nor does it provide any criteria for consistency among regions in their
assessment of requests.
Lastly, the current proposal leaves it to each region to develop its own
methodology and criteria for evaluating the technical studies. MWDSC believes
that drafting team should establish a common method and criteria to apply
continent-wide in achieving uniformity and consistency among regions in their
assessment of exception requests.
Comments to Checklist #4: MWDSC recommends the following changes to
emphasize facility impact on the interconnection of the BES:”How does an
outage of the facility impact the over-all reliability of to the interconnection of
the BES?”
Comments to Checklist #7: What percentage of power flow through entity’s
facility into the BES will be considered as an exception to the BES?

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
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Question 2 Comment

There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is
not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both
the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides
can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of
the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements
of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
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Question 2 Comment

separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved
or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a
favorable outcome.
The SDT believes no further clarification is needed in Question 4. The General Instruction area on page one has been modified to
clarify that a submitting entity may provide documents and any additional information that supports their request. It is up to the
submitting entity to determine how best to present the information supporting their request. If the submitting entity wishes to
provide this additional information it may do so by listing this information in the area provided under General Instructions on the
Exception Request Form.
Page one: List any attached supporting documents and any additional information that is included to supports the request:
The Exception Process requires an evaluation of all the responses and supporting materials provided as part of the Exception Request
Form. There are no set thresholds, the percentage of power flow through and entity’s facility into the BES will be but one factor
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Yes or No

Question 2 Comment

among others considered when evaluating a BES Exception Request.
Transmission Access Policy
Study Group

Question 7 asks, “[d]oes power flow through this facility into the BES?” As in
the rest of the document, the reference should be to an “Element(s),” rather
than to a “facility.” In addition, we suggest that the meaning of power flowing
“through” the Element(s) be clarified, consistent with clarification of the same
point in Exclusion E3 of the BES Definition.
In TAPS’ comments on the BES Definition, also submitted today, TAPS suggests
that the first sentence of Exclusion E3 be revised to state: “Power flows only
into the LN, that is, at each individual connection at 100 kV or higher, the precontingency flow of power is from outside the LN into the LN for all hours of the
previous 2 years.” We propose that Question 7 in the Detailed Information to
Support an Exception Requests be similarly revised: “Does power flow from this
facility into the BES, i.e., at any individual connection at 100kV or higher, is the
pre-contingency flow of power from the LN to the BES for any hour of the
previous 2 years?”

Response: In order to maintain consistency with the nomenclature used in the Exception Process Document, draft Appendix 5C of
the NERC Rules of Procedure, the SDT has replaced “facilities” with “Element(s)” where appropriate.
The SDT disagrees with the use of parallel language for exclusions in the BES Definition and Exception Request Form. It is
important to realize a distinction between the BES definition and the Exception process. While the BES definition established
bright-line criteria for the determination between BES and non-BES Element(s), the Exception Process requires an evaluation of
all the responses and supporting materials provided as part of the Exception Request Application Form.
Tri-State Generation and
Transmission Assn., Inc.
Energy Mangement

Again Yes/No is conflicting in the question. The requested information in#2 is
too vague and may be subjective. If the information in#7 is requested in the
planning stage the data would not be available.
What objective criteria would be used to determine the state of the exception
request?

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TSGT G&T

Yes or No

Question 2 Comment
Again Yes/No is conflicting in the question. The requested information in#2 is
too vague and may be subjective.
If the information in#7 is requested in the planning stage the data would not be
available.
What objective criteria would be used to determine the state of the exception
request?

Response: The SDT disagrees that the information requested in Question 2 is too vague and subjective but understands the concerns
raised by the commenters in not receiving hard and fast guidance on the Exception criteria. The SDT would like nothing better than
to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and an initial
attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could
have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the
commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of
substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
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Yes or No

Question 2 Comment

rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is
not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both
the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides
can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of
the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements
of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved
or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
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Question 2 Comment

experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a
favorable outcome.
As to the availability of needed information to support an exception request, the SDT recommends that each submitting entity
work with its Regional Entity to resolve issues with information availability or access, and in the event such information is not
available, whether suitable replacement data is acceptable. The SDT further recommends that where information is
unavailable, the submitting entity state such in the comment area and provide the reason for this unavailability. This will signal
the Regional Entity that an issue concerning information availability will need to be resolved as part of the review process.
Finally, there are options for a submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if
they feel that an improper decision has been made on their submittal.
WECC Staff

Yes

The requested information in the checklist is appropriate. However; the
exceptions process as drafted, with no objective criteria defining how to assess
the submittals, leaves it to each Regional Entity to develop their own criteria to
evaluate the responses to the checklist included in the submittals, leading to
inconsistency between Regional Entities.
In addition, WECC recommends clarifying Question 7. On its face it is unclear
what defines power flowing through a facility in the BES. It should be clear
whether a qualitative or quantitative response is required.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.

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Yes or No

Question 2 Comment

There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is
not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both
the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides
can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of
the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements
of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
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81

Organization

Yes or No

Question 2 Comment

separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved
or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a
favorable outcome.
The SDT has deleted the checkboxes under Question 7. To replace the checkboxes, language has been added requesting the
submitting entity to describe the conditions and the time duration when power flow through Element(s) into the BES. If the
answer is yes to the question “Does power flow through this Element(s) into the BES,” the sub-question seeks a quantitative
amount. However, it is up to the submitting entity to determine how best to present the information supporting their request
and any responses can be further described or qualified under the comments section.
Q7. If yes, then using metered or SCADA data for the most recent consecutive two calendar year period, what is the minimum and
maximum magnitude of the power flow out of the facility Element(s)? and dDescribe the conditions and the time duration when this
could occurs?

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Organization

Yes or No

Transmission

Yes

Question 2 Comment
“Impact” and “degree of impact” in question 2 should be framed with the
criteria expected.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is
not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both
the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides
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83

Organization

Yes or No

Question 2 Comment

can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of
the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements
of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved
or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future.
Given the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of
this project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT
asks the commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes

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Organization

Yes or No

Question 2 Comment

will result in a favorable outcome.
American Electric Power

Yes

We recommend capitalizing “facility”.

Response: In order to maintain consistency with the nomenclature used in the Exception Process Document, draft Appendix 5C
of the NERC Rules of Procedure, the SDT has replaced “facilities” with “Element(s)”, where appropriate.
Long Island Power Authority

Yes

On page 3 why reference if a facility is part of a Cranking Path after the SDT has
deleted Cranking Paths from the Inclusion list as part of the BES definition.

Response: It is important to realize a distinction between the BES definition and the Exception Procedure. While the BES definition
established bright-line criteria for the determination between BES and non-BES Element(s), the Exception Procedure requires an
evaluation of all the responses and supporting materials provided as part of the Exception Request Application Form. No single
response or piece of supporting information will be solely dispositive in an Exception Request evaluation. It is not correct to assume
that simply because an evaluation criterion was removed from the bright-line definition it should also be eliminated from
consideration in the Exception process. The SDT believes that Cranking Path is among the factors to be given consideration in the
evaluation for an Exception Request application. Further discussion of this issue is within the scope of the Phase II SAR. No change
made.
City of Redding Electric Utility

Yes

City of Redding

Yes

Georgia System Operations
Corporation

Yes

Oncor Electric Delivery
Company LLC

Yes

Independent Electricity
System Operator

Yes

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Organization

Yes or No

Question 2 Comment

NV Energy

Yes

Central Hudson Gas & Electric
Corporation

Yes

Exelon

Yes

Hydro One Networks Inc.

Yes

Holland Board of Public Works

Yes

Southern Company
Generation

Yes

Dominion

Yes

Southwest Power Pool
Standards Review Team

Yes

SERC Planning Standards
Subcommittee

Yes

Tacoma Power

Yes

Tacoma Power supports the information requested on page 2 and 3.

Springfield Utility Board

Yes

SUB agrees with the instructions, finding them to be clear and reasonable.

BGE

Yes

No comment.

Michigan Public Power Agency

Yes

We believe that the SDT’s proposed approach for exception criteria is
reasonable; recognizing that one method/criteria can not be applicable to
everyone and every situation within the ERO foot print. See our comment in Q1.

We agree with the information being requested.

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Organization

Yes or No

Question 2 Comment

Response: Thank you for your support.

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87

3. Page four of the ‘Detailed Information to Support an Exception Request’ contains a checklist of items that deal with generation
facilities. Do you agree with the information being requested or is there information that you believe needs to be on page four that is
missing? Please be as specific as possible with your comments.
Summary Consideration: Several respondents suggested better clarity on whether responses should be market or reliability related.
The SDT made slight modifications to the “Detailed Information to Support an Exception Request” form to request responses that are
specifically reliability related.
Based on the comments received and past history for such situations, the SDT believes that entities will be able to obtain the requisite
information necessary to submit a request. However, should an entity have difficulty, they will need to obtain the assistance of their
Regional Entity to secure the data. If the entity still can’t obtain the needed data, then the SDT fully expects that entity’s Regional Entity
to work with them to come up with a plan that will allow that entity to fill out the request form in a manner that will be acceptable to
the Regional Entity so that processing of the request can continue.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like
nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion
and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the
SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point
out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the
form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single
package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity
has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for
completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in
actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a
position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes
that the visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the
integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3,
and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity
decides to reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

88

NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the
Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception
request. On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an
acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information
aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard and
fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by
either party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this
equation. Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information
needs to be supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or
unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section
3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to
a question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

89

complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
Page 1 - List any attached supporting documents and any additional information that is included to supports the request:
Generation - Q1. What is the MW value of the host Balancing Authority’s most severe single Contingency and what is the generator’s, or
generator facility’s generation resource’s, percent of this value?
Generation - Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Generation - Q3. Is the generator generation resource designated as a must run unit for reliability?

Organization

Yes or No

Northeast Power Coordinating
Council

No

Question 3 Comment
This Application generally applies to traditionally fueled generating facilities.
Application form and justifications would be required for non-traditional resources
such as solar and wind?
Question 2 on page 4 asks, “Is the generator or generator facility used to provide
Ancillary Services?” If some of these Generator check list items are market-related
and not reliability-related, they should not be present. If the Ancillary Services are
reliability-related, please explain their relation to BES reliability.
Suggest inserting the word “reliability” before the words “must run” in question 3.
Question 5 on page 4 asks, “Does the generator use the BES to deliver its actual or
scheduled output, or a portion of its actual or scheduled output, to Load?” This
could mean the generator may serve local loads through non-BES facilities. In order
to serve these local loads the generator would need to be connected to a Radial
system, a Local Network or to local distribution facilities. Is this what is intended?
Were there any other possibilities envisioned by the BES SDT?

Response: The SDT believes the form can be used for any type of generation resource as there are no restrictions on type in the
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90

Organization

Yes or No

Question 3 Comment

questions. No change made.
The form has been modified to request only reliability related functions be included.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Q3. Is the generator generation resource designated as a must run unit for reliability?
If the entity serves the indicated Load through a radial system, etc., it should supply that information as part of its supporting
information. No change made.
ACES Power Marketing
Standards Collaborators

No

Q5 has a “Description/Comments” section. Further clarification on what type of
information to include under the Description would help “standardize” the
supporting information and “will provide more clarity and continuity to the process.”
The definition of ancillary services varies and can be quite broad. It can include
reactive power and voltage support for example. All generators provide some
reactive power and voltage support. Thus, ancillary services should be further
defined or one could construe it to limit any generator from being excepted.

Response: Entities applying for an exception can include any information they deem appropriate in the general and specific sections
of the form. It would be difficult to establish specific criteria that would be applicable to all systems.
Questions regarding ancillary services have been further clarified.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Farmington Electric Utility
System

No

Question 1, the SDT team should consider if the Submitting entity or Owner is part of
a Reserve Sharing Group. The host BA’s most single severe Contingency vs the
obligation of reserves required as part of a Reserve Sharing Group may be
substantial.
The SDT team should clarify if it is a single generator or if it is the aggregate at a
facility.

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Organization

Yes or No

Question 3 Comment

Response: An entity can supply that information as part of its supporting information in its request. No change made.
The assumption is that the request is being made as a result of the application of the definition which is for single units or aggregate
as appropriate.
Dominion

No

The SDT language specifying services acceptable for inclusion in an exclusion request
references ancillary services identified under a Transmission Service Provider’s OATT.
However, there is great variation in the services that have actually been implemented
and posted across North America under those OATTs. There is no consistent
description or terminology to characterize those services. In short, Transmission
Providers have been permitted to individualize OATT services to fit regional market
structures and vernacular. For example, PJM’s OATT includes a schedule for
Blackstart Service. The FERC pro-forma tariff does not. ISO-NE’s tariff includes the
following ancillary services (which are performed by the ISO and TSP): o Scheduling,
System Control and Dispatch Service o Energy Imbalance Service o Generator
Imbalance Service Therefore, Dominion suggests that the SDT provide a specific list of
ancillary services that would be eligible for exclusion, rather than rely on OATT
references. Examples might include: reactive, voltage control or regulation services,
frequency response and blackstart services.
Dominion is also aware that the phrase “ ‘must run” is used in some RTO/ISO market
systems to indicate intent to self-schedule the generator. Dominion suggests that
question 3 be revised to read “Is the generator designated as a “must run” unit by
either the Balancing Authority, Resource Planner or Reliability Coordinator?

Response: The form has been modified to request only reliability related functions are included.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Q3. Is the generator generation resource designated as a must run unit for reliability?
Southern Company

No

We do not agree completely with the information being requested. For checklist
item #2, please specify what is included in "providing Ancillary Services" for a

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Organization

Yes or No

Generation

Question 3 Comment
generator.
For #4, can the question include a measure of evaluating the "most severe system
impact"? Can the specific study that is required to be evaluated be outlined?

Response: Questions regarding ancillary services have been further clarified.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
The SDT refers the commenter to the statement that TPL methodologies should be followed in formulating the supporting
information for the request.
AECI and member G&Ts

No

Most of these questions appear relevant to the LN concept paper, but irrelevant to
this standard's requirements. The last conditional of Item 5) must always be
answered Yes, unless the local-network is islanded.

Response: The SDT does not see a need for a one-to-one correspondence between the definition items and the information
requested. The form contains questions that will supply information the review panel will need to evaluate the request.
NERC Staff Technical Review

No

For units designated as must run, the Submitting entity should be required to
describe the reasons for which the unit has been so designated. We believe the
general requirement to provide an appropriate reference is too vague, and should be
appended with “. . . including a description of why the unit has been designated as
must run and if applicable, the contingencies that would result in violation of the
NERC Reliability Standards if the unit was not must run.”

Response: The form has been modified to request only reliability related functions are included. Information such as shown in the
comment can be entered as needed by the requesting entity. In general, an entity should supply any and all information that it feels
is needed to support its request.
Q3. Is the generator generation resource designated as a must run unit for reliability?

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Organization

Yes or No

Duke Energy

No

Question 3 Comment
Modify wording on #3 as follows: “Please provide the appropriate reference for the
operating area where the facility is located.”

Response: The SDT does not believe that the suggested wording provides any additional clarity. No change made.
NV Energy

No

In question #7 of the form, it would be useful to the analysis for technical exception
to include not only the minimum and maximum power flow out of the candidate
facility, but also a description or demonstration of the “typical” magnitude or the
“average” of such flow. An entity may provide this sort of information anyhow, but a
prompt for this type of information could be useful and prevent having to solicit
more information during the review.
Should be included in Question 2.

New York State Dept. of Public
Service

No

Question 6 should be dropped. Facilities in a cranking path for a blackstart resource
should not be a consideration.
Question 7 is circular. If a facility is used to flow power into the BES, by definition it is
outside the BES. Needs clarification as to the information the question is seeking.
Should be question 2.

Response: Please see the response to Q2.
Consolidated Edison Co. of NY,
Inc.

No

For Generation Facilities: This Application form would appear to generally apply to
traditional generating facilities. o What Application form and justifications would be
required for non-traditional resources, e.g., solar and wind?
o The Application form at 2 asks, “Is the generator or generator facility used to
provide Ancillary Services?”If some of these Generator check list items are marketrelated and not reliability-related, then they should not be present.
o If the Ancillary Services are reliability-related, please explain their relation to BES

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Organization

Yes or No

Question 3 Comment
reliability.
Recommendation: Insert the word “reliability” before the words “must run” in
question 3.
The Application form at 5 asks, “Does the generator use the BES to deliver its actual
or scheduled output, or a portion of its actual or scheduled output, to Load?” We
assume this mean the generator may serve local loads through non-BES facilities. In
order to serve these local loads the generator would need to be connected to a
Radial system, a Local Network or to local distribution facilities. o Is this meaning
above implied and intended by this question? o Were there any other possibilities
envisioned by the BES SDT?

Response: The SDT believes the form can be used for any type of generation resource as there are no restrictions on type in the
questions.
The form has been modified to request only reliability related functions be included.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Q3. Is the generator generation resource designated as a must run unit for reliability?
Entities applying for an exception can include any information they deem appropriate in the general and specific sections of the form.
If the entity serves the indicated Load through a radial system, etc., it should supply that information as part of its supporting
information. No change made.
American Electric Power

No

It is unclear how the process will work with the interaction among the various NERC
Functions. For instance, an exception request from generation might require
collaboration among other functional entities, i.e. GOP, TOP, and RC.
The question “How does an outage of the generator impact the over-all reliability of
the BES” may be subjective and dependent on contingencies at any given time. It
would be dependent on what state the BES would be in the area the generator is
located. More detail would be needed in describing the study required to have

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Question 3 Comment
consistent results.

Response: Please refer to the Rules of Procedure for clarity on how the process will provide consistency.
As every generator will have different impact it is up to the entity to complete the studies and to respond appropriately in the
written section of the question.
ReliabilityFirst

No

If the systems are planned properly and the day-ahead analysis is done for
maintenance work, the outage of any one unit and even with the most serve outage
happening, the system should be capable of withstanding. These studies and analysis
will need to look at multiple outages and groups of units being taken out and
excluded before any could be exempt. What is the phrase “impact the over-all
reliability” getting at?
These studies and analysis will need to look at multiple outages and groups of
elements being taken out and excluded. Will this be on a first come, first out
process?
As for the Ancillary Services question, ReliabilityFirst Staff believes that if a unit
provides this service, it should be included in the BES.
The same applies for the “must run units” in question 3.
Omit question 5, E3 (LN) of the definition already talks to power flow and even if
there is a small percentage of unit’s output flowing onto the BES, it makes that entity
a user of the BES, which should be included.

Response: The SDT refers the commenter to the phrase consistent ‘with TPL methodologies’ which the SDT believes will cover the
item in question.
The SDT reminds the commenter the evaluation in question is not for removing the Element from service but simply from inclusion or
exclusion in the BES. Therefore, there should be no problem with evaluating multiple requests in the same area and no first in, first
out scenario.
Ancillary services or must run status is only one piece of information in a total review of the impact of the Element on the BES. The
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Question 3 Comment

SDT does not believe that simply because a generator provides ancillary services or that it is must run that it should be automatically
included.
There is more to the BES than just the local networks. No change made.
Hydro-Quebec TransEnergie

No

Manitoba Hydro

No

Response: Without any specific comments, the SDT is unable to respond.
ISO New England Inc

No

- Question 1o The question would be better worded as “How many MW are lost
following the host Balancing Authority’s most severe single Contingency...”.o The
question becomes difficult to answer when the most severe single Contingency can
change on a

Response: A slight revision has been made to Question 1 which should provide more clarity in this regard.
Q1. What is the MW value of the host Balancing Authority’s most severe single Contingency and what is the generator’s, or
generator facility’s generation resource’s, percent of this value?
PSEg Services Corp

No

With regards to question #2 (“Is the generator or generating facility used to provide
Ancillary Services”), the answer for most synchronous generators is probably “yes”
unless they are in a bid-based market that selects specific generators for Reactive
Power delivery. Since most generators (with the exception of those with nuclear
prime movers) provide Reactive Power to meet a Transmission Operator-specified
voltage, they would provide that Ancillary Service. Other generators (again, with the
exception of generators with nuclear prime movers) may be eligible to provide other
Ancillary Services such as Spinning Reserve, but may have rarely done so. However,
they still may be “used do provide” Spinning Reserve at any time. How would those
generators respond to question #2?
Questions #4 requires an analysis of the “most severe impact” associated an outage

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Question 3 Comment
of the Element proposed for exception. a. Both the newly Board approved TPL-001-2
standard and the existing TPL-004-1 require that severe contingencies be evaluated,
but there are no performance requirements for them. For consistency, performance
requirements for the most-severe-impact analysis needed to be defined by the team.
If the team intended the “most-severe impact” analysis to only evaluate TPL outages
that incorporate performance requirements, it should make that clear.b. The mostsevere-outage impact question does not ask key relevant information such as: i.
What is the probability that the “most severe impact “will occur?ii. Could the impact
be readily mitigated and service restored? This point is critical because the impact of
an outage lasting several minutes before restoration versus several hours before
restoration should affect the analysis.
What does the answer to the question #5 in the Generator Facilities section (“Does
the generator use the BES to deliver its actual or scheduled output, or a portion of its
actual or scheduled output, to Load?”) imply with respect to a generator’s exclusion?
Also, the phrase “deliver its actual or scheduled output ...to load” needs explanation.
The use of “actual output” and “scheduled output” may have several contexts. a. For
example, in a market, a generator’s actual output may suddenly go to zero due a
forced outage, but the generator has financial obligations that accrue for delivering
its scheduled output, which is in fact provided by other sources since the generator is
unavailable. Is the question asking about the use of BPS facilities by resources that
may be substituted for delivery of a generator’s scheduled output when it differs
from its actual output?b. Now assume that a generator’s actual output equals its
scheduled output and that several generators are forced out of service in another
Balancing Authority, resulting in a frequency decline. Generators within the
interconnection with active governors and available spinning capacity will
automatically increase their output above their scheduled output, resulting in
Inadvertent Interchange. Is the question related to the BES facilities used to deliver
such Inadvertent Interchange?c. Again assume that a generator’s actual output
equals its scheduled output. Is the question related to the actual BES facilities that
may be used to deliver the generator’s power to Load? That would require an

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Question 3 Comment
analysis of generator and load shift factors to determine what actual facilities carry
the power generated from a generator to a specific load for a given set of
assumptions on the system topology. In a market, this analysis would not be possible
for generators that do not self-schedule for delivery to specific loads.

Response: The form has been modified to request only reliability related functions are included.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
The SDT reminds the commenter the requirement is only to follow the TPL methodologies which have been spelled out in TPL-001-2.
An entity can supply any and all information that it thinks will support its request.
Entities applying for an exception can include any information they deem appropriate in the general and specific sections of the form.
It is simply just one piece of information that is considered as useful for the review panel in making its ultimate decision. Any
clarifying points an entity wants to make in its request can be supplied as the entity thinks appropriate.
City of St. George

No

The questions for generation facilities seem to be appropriate; however, how the
answers are to be used by the region or NERC is unclear. Will a given response to a
question make exclusion impossible? If so this needs to be known upfront and clearly
documented. For example question 4, on page 4 is open for interpretation and
debate as to what the impact to the over-all reliability of the BES is. The definition of
“impact” is really the key to the whole definition effort. Load flow, voltage,
frequency change limits may all be pieces to the puzzle.
Are these criteria to be met in normal, N-1, N-2, etc. system configurations?

Response: Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will
mandate a negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules
of Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an
Exception Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be
approved or disapproved.”
The SDT refers the commenter to the statement that TPL methodologies should be followed in formulating the supporting

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Yes or No

Question 3 Comment

information for the request.
Ameren

No

It is suggested that question #2 be deleted and replaced with “Is the generator
designated as a black-start unit in an entity’s restoration plan?”

Response: The SDT assumes the commenter is actually referring to the sixth question for transmission. Please see the detailed
response to Q2.
Georgia System Operations
Corporation

No

Item 2 asks about “the generator or generator Facility,” but 3, 4 and 5 only refer to
the generator. There is no immediately apparent reason for them to be different.
The language in Item 2 seems preferable.

Response: The SDT has reviewed all of the terminology for consistency and made clarifying changes as necessary. For example:
Q1. What is the MW value of the host Balancing Authority’s most severe single Contingency and what is the generator’s, or
generator facility’s generation resource’s, percent of this value?
IRC Standards Review
Committee

We do not agree with the detailed information requirements for generators. In a
deregulated environment, generators are free to bid into the market or offer their
availability, to dispatched based on bid price and resource needs, or overall
generation dispatch plans. A generator may be on line but not dispatched, or not on
line at all due to maintenance outage or a decision to not start. Its status and
generation level have little to do in determining whether or not it needs to be
included as a BES facility. Rather, it is the generator’s active contribution to the BES
performance, namely, its protective relay setting and coordination with those of
related facilities and its ability to control voltage, respond to contingencies, ride
through frequency and voltage excursion, provide accurate model with verification,
etc., are critical to BES reliability performance. There are currently no standards or
requirements that mandate a generator to be on line or to attain a specific level of
output, and we do not see such a need at all in the future. Whether or not the unit is
designed as a MUST RUN will depend on whether the generator is (a) on line and bid
into the market or be included in the dispatch plan, and (b) the prevailing system

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Organization

Yes or No

Question 3 Comment
conditions such as flow pattern, potential constraints, etc. A generator may be
designated as a MUST RUN one day but not the others. Similar argument applies to a
generator bidding in the ancillary service markets, or be dispatched to provide
reserve or AGC control capability. In our view, generators’ physical characteristics and
their response to changes on the BES are important considerations for them to be
included in the BES. These characteristics affect the assessment and actual
performance of the BES in the following key areas: o Voltage and frequency ride
through capability o Voltage control (AVR, etc.) o Underfrequency trip setting o
Protection relay setting coordination o Data submission for modeling; verification of
capability and model We therefore suggest that the entire P.4 be removed as the
information it asks for has nothing to do with a generator’s physical characteristics or
material impact on BES reliability. Having a threshold by MVA suffices to determine if
a generator needs to be included as a BES facility, whose characteristics, expected
performance and data provision are important to achieve target BES performance
and hence should be governed by reliability standards.

Response: The form has been modified to request only reliability related functions are included.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Q3. Is the generator generation resource designated as a must run unit for reliability?
Tri-State Generation and
Transmission Assn., Inc.
Energy Mangement

Again Yes/No is conflicting in the question. Information requested in#4 is subjective
and too vague.

TSGT G&T

Again Yes/No is conflicting in the question. Information requested in #4 is subjective
and too vague.

Response: The SDT has attempted to build in maximum flexibility within the form while still providing the review panel information
that will be needed in evaluating a request. No change made.

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Organization

Yes or No

Hydro One Networks Inc.

Yes

Question 3 Comment
See comments in Q1.

Response: Please see response to Q1.
Long Island Power Authority

Yes

Need to define the term "must run unit"

PacifiCorp

Yes

PacifiCorp suggests modifying Question 3 as follows: “Is the generator designated as
a must run unit by the Balancing Authority?”

Response: The form has been modified to request only reliability related functions are included.
Q3. Is the generator generation resource designated as a must run unit for reliability?
Electricity Consumers
Resource Council (ELCON)

Yes

Our “Yes” response is conditioned on the comments to Questions 1 and 2 above.

Response: Please see responses to Q1 and Q2.
Bonneville Power
Administration

Yes

Regarding #1 on page 4: BPA Believes seasonality may need to be considered when
comparing the generator with the most severe single contingency.

Response: Seasonality issues can be explained in the written response areas of the application form or additional documentation
can be provided as needed. No change made.
WECC Staff

Yes

The requested information in the checklist is appropriate. However; the exceptions
process as drafted, with no objective criteria defining how to assess the submittals,
leaves it to each region to develop their own criteria to evaluate the responses to the
checklist included in the submittals, leading to inconsistency between Regional
Entities.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
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Yes or No

Question 3 Comment

hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is
not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both
the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides
can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
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Organization

Yes or No

Question 3 Comment

being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of
the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements
of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved
or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a
favorable outcome.
Kootenai Electric Cooperative
Snohomish County PUD
Blachly-Lane Electric

Yes

KEC agrees that the items listed on page 4 of the Detailed Information to Support an
Exception Request capture the information that generally would be necessary to
make a reasoned determination concerning the BES status of a generation facility.
KEC suggests three refinements to the questions: (1) Question 2 should be modified

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Organization

Yes or No

Cooperative
Central Electric Cooperative
(CEC)
Clearwater Power Company
(CPC)
Consumer's Power Inc. (CPI)
Douglas Electric Cooperative
(DEC)
Fall River Electric Cooperative
(FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(Lincoln)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
Umatilla Electric Cooperative

Question 3 Comment
by adding “necessary for the operation of the interconnected bulk transmission
system” to the end of the question, so that it reads: “Is the generator or the
generator facility used to provide Ancillary Services necessary for the operation of the
interconnected bulk transmission system?” The italicized language is necessary to
distinguish between a generator that provides, for example, reactive power or
regulating reserves that support operation of the interconnected bulk grid, and, for
example, a behind-the-meter generator that provides back-up generation to a
specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter is not.
(2) The current draft of the BES Definition contains Exclusions for radials and for Local
Networks. To be consistent with these aspects of the revised BES definition, KEC
suggests modifying question 5 by adding “radial, or Local Network” to the question,
so that it would read: “Does the generator use the BES, a radial system, or a Local
Network to deliver its actual or scheduled output, or a portion of its actual or
scheduled output, to Load?
(3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an
Exception Request for a generator to submit any information it believes is relevant to
the Exception that is not captured in the previous questions. We suggest the
following language:Is there additional information not covered in questions 1 through
5 that supports the Exception Request? If yes, please provide the information and
explain why it is relevant to the Exception Request.This will allow an entity seeking an
Exception for a generator to identify any unusual circumstances or non-standard
information that might support its Exception Request. An entity seeking such an
Exception should have the opportunity to present any information it believes is
relevant.

West Oregon Electric
Cooperative (WOEC)
Coos-Curry Electric
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Yes or No

Question 3 Comment

Coooperative
City of Austin dba Austin
Energy
Response: (1) Questions regarding ancillary services have been further clarified.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
(2) If the entity serves the indicated Load through a radial system, etc., it should supply that information as part of its supporting
information. No change made.
(3) This type of question is covered by the clarified line item on page 1 of the form:
List any attached supporting documents and any additional information that is included to supports the request:
Central Lincoln

Yes

Oncor Electric Delivery
Company LLC

Yes

Independent Electricity
System Operator

Yes

Consumers Energy

Yes

Central Hudson Gas & Electric
Corporation

Yes

Exelon

Yes

Holland Board of Public Works

Yes

Transmission

Yes

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Organization

Yes or No

Question 3 Comment

Pepco Holdings Inc

Yes

ATC LLC

Yes

Southwest Power Pool
Standards Review Team

Yes

SERC Planning Standards
Subcommittee

Yes

City of Redding Electric Utility

Yes

City of Redding

Yes

Tacoma Power

Yes

Tacoma Power supports the information requested on page 4.

BGE

Yes

No comment.

Michigan Public Power Agency

Yes

Response: Thank you for your support. The SDT did make some clarifying changes due to comments received.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Q3. Is the generator generation resource designated as a must run unit for reliability?

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4. Do you have concerns about an entity’s ability to obtain the data they would need to file the ‘Detailed Information to Support
an Exception Request’? If so, please be specific with your concerns so that the SDT can fully understand the problem.

Summary Consideration: Based on the comments received, the SDT believes that entities will be able to obtain the requisite
information necessary to submit a request. However, should an entity have difficulty, they will need to obtain the assistance of their
Regional Entity to secure the data. If the entity still can’t obtain the needed data, then the SDT fully expects that entity’s Regional
Entity to work with them to come up with a plan that will allow that entity to fill out the request form in a manner that will be
acceptable to the Regional Entity so that processing of the request can continue. The SDT recognizes that there will be costs associated
with the request. The SDT feels that an entity may have to conduct a cost and benefit analysis in order to determine the value of
pursuing a request.
No significant changes were made to the request form as a result of comments received to this question. There were suggestions to
use some terms more consistently, and this suggestion was adopted. The SDT had used, “facility” and “element” to mean the same
things, and has now adopted the word, “Element” throughout the revised document. Similarly the team changed the word,
“application” to “request” for greater clarity.

Organization

Yes or No

AECI and member G&Ts

No

Ameren

No

ATC LLC

No

BGE

No

Central Hudson Gas & Electric
Corporation

No

Central Lincoln

No

Question 4 Comment

No comment.

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Organization

Yes or No

City of Redding

No

Hydro One Networks Inc.

No

Hydro-Quebec TransEnergie

No

IRC Standards Review
Committee

No

ISO New England Inc

No

Long Island Power Authority

No

National Grid

No

NERC Staff Technical Review

No

NV Energy

No

Oncor Electric Delivery
Company LLC

No

PacifiCorp

No

SERC Planning Standards
Subcommittee

No

Springfield Utility Board

No

Question 4 Comment

All concerns were captured in comments provided to the previous questions.

The information appears to be readily available to entities seeking exceptions.

PacifiCorp is speaking from a perspective where the Company is registered for
multiple functions (i.e., TO, GO, TOP, GOP, BA, TPL, etc.) and the requested
information is currently available from Company resources.

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Organization

Yes or No

Tacoma Power

No

Question 4 Comment
Tacoma Power supports the expectation that entities will be able to supply the
information requested.

Response: Thank you for your support.
American Electric Power

No

As stated in the response to question #3, the question “How does an outage of the
generator impact the over-all reliability of the BES” may be subjective and dependent
on contingencies at any given time. It would be dependent on what state the BES
would be in the area the generator is located. More detail would be needed in
describing the study required to have consistent results.

No

Throughout the document, because it will be part of a larger Exception Request Form,
it should, when possible, use terms consistent with the rest of that form (e.g.,
“Request” rather than “application”).

Response: See response to Q3.
Georgia System Operations
Corporation

Similarly, defined terms (even if only defined in the context of the Request Form in
which these Principles will be used) such as “Exception,” “Request,” “Element” or
“Facility” should be capitalized; if the use of lower case is intended to convey a
different meaning than what is defined, another term should be used to avoid
confusion.
The Definition and Request Form generally use the term “Element,” so it is unclear
why this document should so consistently use “facility.” For consistency, “Element(s)”
or possibly “Element(s) or Facility” should be used.
Response: The SDT has made changes to the Request Form based upon your comments, changing the word, “facility” to “Element”
and “application” to “request” for consistency throughout the document.
Independent Electricity
System Operator

No

We anticipate that entities will be granted access to the required historical operations
records and modeling data after signing of non-disclosure agreements with the

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Organization

Yes or No

Question 4 Comment
providers of the information.

Response: The SDT concurs that it may be necessary for entities to execute such agreements.
Northeast Power Coordinating
Council

No

According to the Applicability section, the TPL Reliability Standards are only applicable
to the Planning Coordinator (PC) and the Transmission Planner (TP). Was it the BES
SDT’s assumption that Applicants would have the PC or TP run studies for them, or
that all Applicants would gain access to those models and run the models themselves?
(Ref. TPL-002-1b, Applicability: Planning Authority, and Transmission Planner.)

Pepco Holdings Inc

No

Not all TOs have the capability to perform the power flow and stability analysis on
their own, necessary to meet the exception request. It may be burdensome for the
TO to hire a consultant or to have their affiliated TPL perform the rigorous
study/analysis as contained in the TPL standards. Additional details should be
provided as to what part of the TPL standards apply. Should the Affiliated TPL be
required to perform TOs studies for exception requests? If so should that be stated in
a related standard as a requirement?

Southern Company
Generation

Yes

An IPP with no Transmission Planning department may find it very difficult to perform
an interconnection wide base case as required in the general instructions.

Bonneville Power
Administration

Yes

BPA believes the studies discussed in pages 2-4 would likely need to be completed and
the required information supplied by the Transmission Planner/Operator of the
Balancing Authority Area since many of the assumptions regarding performance of the
BES to delivery under a variety of operating conditions is known only to the TP and
TOP of the system.

Consolidated Edison Co. of NY,
Inc.

Yes

According to the Applicability section, the TPL Reliability Standards are only applicable
to the Planning Coordinator (PC) and the Transmission Planner (TP). Was it the BES
SDT’s assumption that Applicants would have the PC or TP run studies for them, or
that all Applicants would somehow gain access to those models and run the models

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Organization

Yes or No

Question 4 Comment
themselves? (Ref. TPL-002-1, Applicability: Planning Coordinator, and Transmission
Planner.)

Response: The Request Form includes language indicating that studies need to be consistent with the methodologies described in
the TPL standards, not that the studies need to be the actual Planning Coordinator or Transmission Planner studies. The SDT feels that
it is up to the Registered Entity to work out the details for studies needed for a request.
Orange and Rockland Utilities,
Inc.

No

However, please clarify “facility” and include “N-1” for power-flow studying.

Response: The SDT has modified the document to consistently use the term, “Element” rather than facility throughout the document.
The SDT believes that solely relying upon a single case study, i.e., N-1; would be inappropriate for the purposes of making a decision
under this definition. Entities will need to consider the use of the Elements in a variety of cases to determine whether or not the
Elements would be BES or not.
WECC Staff

Yes

Entities would have a difficult time deciding what data to obtain. Getting the data for
their own specific facilities should be relatively simple for the majority of entities.
However, it is possible smaller entities may have a higher burden putting together the
appropriate information for inclusion in a study case that they currently may not do. In
addition, because the instructions state that a case will be “suitably complete and
detailed,” WECC believes there is insufficient guidance as to what amount and degree
of detail in the data is sufficient for the submittal process. Without thresholds it is
difficult to determine whether the entities will have the ability to obtain necessary
data to file for an exception. At this time, WECC views the instructions as insufficient
for these reasons.

Response: The SDT understands the concerns raised by the commenter in not receiving hard and fast guidance on this issue. The SDT
would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would
also like to point out to the commenter that it directly solicited assistance in this matter in the first posting of the criteria and received
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2

Organization

Yes or No

Question 4 Comment

very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the application to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred
in rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the application process. The SDT again points to the variations that
will abound in the applications as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here.
This is not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on
both the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both
sides can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO
Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1, where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
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3

Organization

Yes or No

Question 4 Comment

bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple applications will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 that states “No single piece of evidence provided as part of an Exception Request or response to a question will be solely
dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
Blachly-Lane Electric
Cooperative
Central Electric Cooperative
(CEC)
City of Austin dba Austin
Energy
Clearwater Power Company

Yes

The Standards Drafting Team should consider whether it is necessary to require
entities other than the entity filing the Exception Request to provide relevant
information, either to the entity filing the Exception Request or to the Registered
Entity receiving the Exceptions Request. For example, in order to answer Question 1
on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its
Most Severe Single Contingency (“MSSC”) to the registered entity seeking an
Exception. Similarly, the relevant Transmission Operator or Balancing Authority may

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4

Organization

Yes or No

(CPC)
Consumer's Power Inc. (CPI)
Coos-Curry Electric
Coooperative

Question 4 Comment
have information that is necessary to determine whether the generator has been
designated as reliability-must-run or if it provides ancillary services supporting reliable
operation of the interconnected transmission grid.

Douglas Electric Cooperative
(DEC)
Fall River Electric Cooperative
(FALL)
Kootenai Electric Cooperative
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(Lincoln)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
Snohomish County PUD
Umatilla Electric Cooperative
West Oregon Electric
Cooperative (WOEC)

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Organization

Yes or No

Question 4 Comment

Response: Based on the comments received, the SDT believes that entities will be able to obtain the requisite information necessary
to submit a request. However, should an entity have difficulty, it will need to obtain the assistance of its Regional Entity to secure the
data. If the entity still can’t obtain the needed data, then the SDT fully expects that entity’s Regional Entity to work with them to
come up with a plan that will allow that entity to fill out the request form in a manner that will be acceptable to the Regional Entity so
that processing of the request can continue.
Exelon

Yes

This may be a burden on small entities and generators because they would need to
use contractors to run studies in order to obtain the required data. Smaller entities
and generators may not have the expertise, the software or the necessary personnel
to perform studies.

Response: The SDT recognizes that there will be costs associated with the request. The SDT feels that an entity may have to conduct
a cost and benefit analysis in order to determine the value of pursuing a request.
PSEg Services Corp

Yes

It would depend upon the clarifications to the points raised above.

Response: The SDT suggests that you review the responses to the points raised above and if concerns still exist, please submit those
concerns to the SDT as we proceed to the second phase of this project.
Holland Board of Public Works
Michigan Public Power Agency

Yes

On Page 4 Question 1, information on the host Balancing Authority’s most severe
single contingency may not be publically available and therefore difficult or impossible
for a smaller entity to obtain. Even if the data is available, it may not be meaningful in
a larger Balancing Authority area such as within MISO where the most severe
contingency may be geographically and electrically remote. A more readily available
and meaningful measure would be a comparison of the generator’s capability as a
percent of the peak load for the local Balancing Authority or sub-Balancing Authority,
as applicable.

Response: The SDT believes that an entity can use any data or information available to it in order to make its request, especially if
other information is not available. Note that the SDT modified the form to clarify that entities may submit additional information

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Organization

Yes or No

Question 4 Comment

(beyond the information listed on the form as “required”) to support their request for an exception.
Duke Energy

Yes

What is the process for obtaining data from a 3rd party that is either unregistered or
unwilling to supply the data?

Response: The SDT is not aware of any instance where an unregistered entity would have vital information relevant to a request. For
an organization unwilling to share, the SDT expects that entities may need to execute confidentiality or other agreements in order to
obtain the use of the necessary information and data.
ACES Power Marketing
Standards Collaborators

Yes

Some generation owners may not be able to obtain their BA’s most severe single
Contingency. Many generator owners will not have access to the data necessary to
demonstrate the reliability impact to the BES. This is particularly true for transmission
dependent utilities.

City of St. George

Yes

The access to the required data would be potentially be a concern especially for
smaller entities. Small entities will typically have to outsource the required studies to
consultants and obtaining the data may be difficult for the consultants. The entities
most likely to obtain exemptions (smaller & lower impact entities) are the ones that
probably will have the most difficulty in obtaining the data. Generally larger utilities
“upstream” from the smaller ones are hesitant to give information to other entities.
Depending on the study requirements and criteria for application, this could be a very
costly process.

Dominion

Yes

It has been Dominion’s experience that CEII or Code/Standards of Conduct rules may
restrict generation entities (GO/GOP) from obtaining some of the information
necessary to perform the analysis needed to file the “Detailed Information to Support
an Exception Request”. Dominion is also aware that, in some cases, generation entities
do not have the technical expertise (transmission planning, power flow and or stability
analysis background) to perform such analysis.

Electricity Consumers

Yes

It may be necessary that the exception request form explicitly address this potential

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Organization

Yes or No

Resource Council (ELCON)

Question 4 Comment
problem by allowing the entity seeking an exception to state that for reasons beyond
its control it failed to acquire the necessary data, base case or supporting document to
enable completion of the filing.

ReliabilityFirst

Yes

In some cases, models and even knowledge of the system configurations, operating
protocols and procedures may not be well known by all the entities. System
adjustments, load levels, topologies, maintenance and outage schedules, which
happen daily, will or may be unknown to many entities, including the Regional Entities
who may submit a request to include facilities. For cross regional boundaries, the
problem becomes even larger. That coupled with generation unit owners/operators
not permitted to know transmission information (i.e. Questions 4 and 5); this will put
them at a huge disadvantage to participate in the exception request process.

Southwest Power Pool
Standards Review Team

Yes

SCADA line flow data might be hard to capture for the last two years. Specifically the
line flows may not be available.

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

Yes

It may be hard for a GO to get the information requested in #1 or #4.

TSGT G&T

Yes

It may be hard for a GO to get the information requested in #1 or #4.

Response: Based on the comments received, the SDT believes that entities will be able to obtain the requisite information necessary
to submit a request. However, should an entity have difficulty, it will need to obtain the assistance of its Regional Entity to secure the
data. If the entity still can’t obtain the needed data, then the SDT fully expects that entity’s Regional Entity to work with them to
come up with a plan that will allow that entity to fill out the request form in a manner that will be acceptable to the Regional Entity so
that processing of the request can continue. The SDT expects that entities my need to execute confidentiality type or other
agreements in order to obtain the use of the necessary information and data.
Farmington Electric Utility
System

Yes

See response to question 2

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Organization

Yes or No

Question 4 Comment

Response: Please see response to Q2.
Consumers Energy

Yes

City of Redding Electric Utility

Yes

Response: Without any specific comment, the SDT is unable to respond.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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9

5.

Are there other specific characteristics that you feel would be important for presenting a case and which are generic enough
that they belong in the request? If so, please identify them here and provide suggested language that could be added to the
document.

Summary Consideration: Based on the responses to this question, the SDT offers the following for summary consideration.
Regarding the FERC seven factor test, an entity requesting an exception can always submit data related to that test for the Regional
Entity and ERO to evaluate.
In response to the suggestions for additional inclusion in the technical criteria document, there are no restrictions on what data can be
submitted in an exception request. An entity requesting an exception can always submit data it believes will be beneficial to its
exception request for the Regional Entity and ERO to evaluate.
Finally, if an entity that is submitting an exception request cannot gain access to certain information that is listed in the technical criteria
document, it should work with its Regional Entity to come up with substitute data that is acceptable. The submitting entity should state
in its exception request submittal that it is unable to access certain data from other parties and explain the reasons why that is the case.
Organization
Northeast Power Coordinating
Council

Yes or No

Question 5 Comment

Yes

There is no guidance provided as to how the information asked for in this form will be
evaluated, and what the decision making process will entail. As such, a reference
document should be developed and provide some guidance how to evaluate
applications.
Suggest that the BES SDT adopt the FERC Seven Factor test.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT
would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would
also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received
very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

12
0

Organization

Yes or No

Question 5 Comment

always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package.
When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been
drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and
making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving
or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a position to
effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the
visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity of
the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4,
provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity decides to
reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to NERC.
Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the Regional
Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception request.
On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an acceptable
submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t shown in
the request process. The SDT again points to the variations that will abound in the requests as negating any hard and fast rules in this
regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and
there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take
into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made.
The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on
evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the interconnected
transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system
within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading
failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or unanticipated failure of
system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the experience
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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1

Organization

Yes or No

Question 5 Comment

gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent approach to the
problem. The SDT would also point out that there are options for a submitting entity to pursue that are outlined in the proposed ERO
Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2
of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a
question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to
the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of
the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes
that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of
these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable outcome.
Regarding the FERC seven factor test, an entity requesting an exception can always submit data related to that test for the Regional
Entity and ERO to evaluate.
Hydro One Networks Inc.

Yes

The general approach, information, data, and assessments proposed seem to be
reasonable. However, guidance is not provided as to how this information may be
evaluated in the decision making process. As such, a reference document should be
developed and provide guidance how applications will be assessed. For example”1)
Does the element(s)? o Would have qualified under one of the exclusions or
inclusions but have marginally different threshold as prescribed in the definition; o
transfer bulk power within (intra) or between (inter) two Balancing Authority Areas;
o monitor facilities included in an Interconnection Reliability Operating Limit (IROL);
o are not considered necessary for the operation of interconnected transmission

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Organization

Yes or No

Question 5 Comment
system under normal conditions, contingency or prolonged outage conditions.2) Are
System Element(s) located in close electrical proximity to Load? o Electrical
proximity may be a measurement of system impedance between load centers within
the system seeking exception. o Other physical characteristics.3) Are System
Elements treated as primarily radial in character? o Smaller deviation from the
exclusion E1. o This can be demonstrated by the way the connections to the BES are
operated (e.g., the local area is not operated as part of the BES with disconnection
procedures when events occur in the local area to separate it.) o This can also be
demonstrated by the way resources in the local area are treated in operations, for
example, they are not included in a regional dispatch or secured by an ISO/RTO. o
Power flows into the system, but rarely flows out. i. This can be demonstrated
through transactional records or load flow analysis where it is shown that flow out
does not occur or occurs only under a very limited set of conditions and for a limited
quantity of energy. a. The limited set of conditions must clearly state the conditions
where power flows out, for example, only under specified contingency events. b.
Transactional records provided must be for the same time specified in the Exception
Rules of Procedure for performing periodic exception self-certifications (presently two
years). c. Power entering the system is not recognized or regularly transported on
to some other system. (This can be demonstrated by operational procedures that
restrict use of delivered power to that system, e.g., the absence of a wheeling
agreement or an agreement that generally restricts wheeling under normal) d. The
System Element(s) have a very small Distribution Factor on any other BES Element(s).
o System Elements are not necessary for the operation of interconnected transmission
under normal, contingency or prolonged outage conditions.

WECC Staff

Yes

In order to make a determination of BES status of an element, there should be a listing
of effects of the outage on certain facilities, frequencies, voltages, transmission
elements, or other information that should be included in the submittal by the entity.
Without further specification of requirements for presenting a case it is likely that the
Regional Entity will receive inconsistent submittals of data. Leaving open the question
of what constitutes a sufficient presentation of a case would likely lead to a wide

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Organization

Yes or No

Question 5 Comment
spectrum of submittals with respect to the amount of data and level of detail in the
data.

Response: The technical criteria document currently includes a request for information related to an outage of an element on the BES.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like
nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion
and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the
SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out
to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form
of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package.
When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been
drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and
making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving
or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a position to
effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the
visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity of
the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4,
provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity decides to
reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to NERC.
Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the Regional
Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception request.
On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an acceptable
submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t shown in
the request process. The SDT again points to the variations that will abound in the requests as negating any hard and fast rules in this
regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

12
4

Organization

Yes or No

Question 5 Comment

there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take
into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made.
The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on
evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the interconnected
transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system
within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading
failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or unanticipated failure of
system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the experience
gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent approach to the
problem. The SDT would also point out that there are options for a submitting entity to pursue that are outlined in the proposed ERO
Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2
of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a
question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to
the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of
the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes
that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of
these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable outcome.
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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5

Organization

Yes or No

City of Redding Electric Utility

Yes

Georgia System Operations
Corporation

Yes

Bonneville Power
Administration

Yes

Question 5 Comment

Response: Without specific comments, the SDT is unable to respond.
IRC Standards Review
Committee

Yes

One acid test to determine if a facility needs to be included or can be excluded from a
BES facility is to simulate an uncleared fault at that facility. If the simulation shows a
stable BES performance, then it suggests that even if the fault is not cleared due to
whatever reason, the facility has no adverse impact that can lead to instability,
cascading or collapse of the BES.

Response: There are no restrictions on what data can be submitted in an exception request. Regarding an uncleared fault test, an entity
requesting an exception can always submit data related to that test for the RE and NERC to evaluate.
Snohomish County PUD
Blachly-Lane Electric
Cooperative
Central Electric Cooperative
(CEC)
Clearwater Power Company
(CPC)

Yes

As discussed in our responses to Questions 1 through 3, SNPD believes that certain
additional questions are necessary to elicit all information that may be relevant to an
Exceptions Request. As discussed in our answer to Question 4, we are also concerned
that it may be necessary to obtain information that is in the hands of the relevant
Balancing Authority, Transmission Provider, or other entity, and not in the hands of
the entity submitting an Exceptions Request, to develop a complete record upon
which a reasoned decision concerning an Exceptions Request can be based.

Consumer's Power Inc. (CPI)
Douglas Electric Cooperative
(DEC)

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6

Organization

Yes or No

Question 5 Comment

Fall River Electric Cooperative
(FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(Lincoln)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
Umatilla Electric Cooperative
West Oregon Electric
Cooperative (WOEC)
Coos-Curry Electric
Coooperative
City of Austin dba Austin
Energy
Kootenai Electric Cooperative
Response: Please see the detailed responses to Q1 – Q4.
Consolidated Edison Co. of NY,
Inc.

Yes

We strongly recommend that the BES SDT adopt the FERC Seven Factor test for local
distribution.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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7

Organization

Yes or No

Question 5 Comment

Response: There are no restrictions on what data can be submitted in an exception request. Regarding the FERC seven factor test, an
entity requesting an exception can always submit data related to that test for the Regional Entity and ERO to evaluate.
American Electric Power

No

As stated in the response to question #3, it is unclear how the process will work with
the interaction among the various NERC Functions. For instance, an exception request
from generation might require collaboration among other functional entities, i.e. GOP,
TOP, and RC.
The existence of a must run unit means that unit has a material impact on any
configuration of the BES and as such would need a serious waiver to not be considered
a BES facility. As such, a must run unit would not receive an exception. As a result,
should question #3 be removed?
Criteria for applying for an exception should be outlined before filling out the form.

Response: If an entity that is submitting an exception request cannot gain access to certain information that is listed in the technical
criteria document, it should work with its Regional Entity to come up with substitute data that is acceptable. The submitting entity
should state in its exception request submittal that it is unable to access certain data from other parties and explain the reasons why
that is the case.
As stated in the proposed ERO Rules of Procedure, ““No single piece of evidence provided as part of an Exception Request or response
to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”.
Please see the proposed ERO Rules of Procedure for details on filling out a form.
Farmington Electric Utility
System

Yes

The SDT should consider additional limits on Generation. For example, if a generation
prime mover (turbine) has a maximum output of 35 MW but is coupled to a generator
with a rating in excess of 75 MVA. The generator output is limited by the turbine - thus
the rating of the turbine should be a taken into consideration rather than the
generator rating.

Hydro-Quebec TransEnergie

Yes

The general characteristics of the Interconnection (such as frequency or voltage
variation), as they may guide the decision for exclusion of specific elements.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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8

Organization

Yes or No

Question 5 Comment

Response: Regarding the suggestions for inclusion in the technical criteria document, there are no restrictions on what data can be
submitted in an exception request. An entity requesting an exception can always submit data it believes will be beneficial to its
exception request for the RE and NERC to evaluate. No change made.
Indeck Energy Services

Yes

As acknowledged in the response to Question 12 comments on the previous BES
definition, the BES definition is expansive compared to the definition of the BPS in the
FPA Section 215. The inclusion of the limited Exclusions is an attempt to remedy the
situation. However, the Exclusions need to include a fifth one that if, based on studies
or other assessments, it can be shown that any tranmission or generator element
otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There
has never been a study to show that elements, such as a 20 MW wind farm, 60 MW
merchant generator (which operates infrequently in the depressed market) in a large
BA (eg NYISO) or a radial transmission line connecting a small generator are important
to the reliability of the BPS. They are covered by the mandatory standards program
through the registration criteria. The BES Definition is the opportunity to permit an
entity to demonstrate that an element is unimportant to reliability of the BPS. The
SDT has identified a small subset of elements that it is willing to exclude. By their very
nature, these exclusions dim the bright line that is the stated goal of this project.
However, the SDT’s foresight seems limited in its selections. Analytical studies are
used to evaluate contingencies that could lead to the Big Three (cascading outages,
instability or voltage collapse). Such a study showing that a transmission or
generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable
Disturbance of approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW
merchant generator or numerous other smaller facilities would be bounded by larger
contingencies. It would take more than six 60 MW merchant generators with close
location and common mode failure to even be a Reportable Disturbance, much less
become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 - Any
facility that can be demonstrated to the Regional Entity by analytical study or other

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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9

Organization

Yes or No

Question 5 Comment
assessment to be unimportant to the reliability of the BPS (with periodic reports by
the Regional Entity to NERC of any such assessments).”

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline
of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that
would warrant a change from the current values that exist through the application of the definition today. These and similar issues
have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in
conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and
provide compelling justification for modifications to the existing values.
City of Redding

No

ATC LLC

No

Ameren

No

Central Lincoln

No

National Grid

No

Oncor Electric Delivery
Company LLC

No

Independent Electricity
System Operator

No

City of St. George

No

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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0

Organization

Yes or No

PSEg Services Corp

No

ReliabilityFirst

No

Long Island Power Authority

No

Consumers Energy

No

Orange and Rockland Utilities,
Inc.

No

ISO New England Inc

No

Duke Energy

No

NV Energy

No

Central Hudson Gas & Electric
Corporation

No

Exelon

No

Transmission

No

PacifiCorp

No

NERC Staff Technical Review

No

Dominion

No

TSGT G&T

No

Question 5 Comment

All concerns were captured in comments provided to the previous questions.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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1

Organization

Yes or No

Question 5 Comment

Pepco Holdings Inc

No

Southern Company
Generation

No

Tri-State Generation and
Transmission Assn., Inc.
Energy Mangement

No

SERC Planning Standards
Subcommittee

No

ACES Power Marketing
Standards Collaborators

No

Southwest Power Pool
Standards Review Team

No

Tacoma Power

No

Tacoma Power does not know of any characteristics to add at this time.

BGE

No

No comment.

Michigan Public Power Agency

No

Response: Thank you for your support.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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2

6.

Are you aware of any conflicts between the proposed approach and any regulatory function, rule order, tariff, rate schedule,
legislative requirement or agreement, or jurisdictional issue? If so, please identify them here and provide suggested language
changes that may clarify the issue.

Summary Consideration: The majority of commenters responded that they were not aware of any conflicts. However, some
comments were supplied indicating concerns.
Three commenters expressed the need to address the function of an Element or system that is subject to an exception request to
determine whether it is a “facilit[y] used in the local distribution of electric energy” and therefore excluded from the BES under
Section 215(a)(1) of the Federal Power Act. Those commenters have been directed to question 2 for detailed responses on this
issue.
Two commenters submitted concerns that the ERO does not have the authority to apply the BES definition in Canada. The SDT is
attempting to craft a BES definition that can be applied within the ERO footprint. It is neither within the scope of the SDT nor is it
appropriate for the SDT to provide a Canadian regulatory resolution within the definition. As such, the SDT agrees that the ERO
will have to address these types of non-jurisdictional situations with relevant Regions through the exception procedure.
Two commenters expressed a concern that information necessary to perform an analysis may be restricted either by federal/state Codes/Standards of Conduct and/or CEII prohibitions. Based on the comments received, the SDT believes that entities will
be able to obtain the requisite information necessary to submit a request. However, should an entity have difficulty, it will need to
obtain the assistance of its Regional Entity to secure the data. If the entity still can’t obtain the needed data, then the SDT fully
expects that entity’s Regional Entity to work with them to come up with a plan that will allow that entity to fill out the request
form in a manner that will be acceptable to the Regional Entity so that processing of the request can continue.
One comment stated that organized markets have a “must run” generator concept that has nothing to do with reliability. Thus, Q3
for generation facilities might be confused with market tariff provisions. To resolve this concern, the SDT has clarified Q3 for
generation resources as follows:
3. Is the generator generation resource designated as a must run unit for reliability?
Organization

Yes or No

Northeast Power Coordinating

Question 6 Comment

No

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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3

Organization

Yes or No

Question 6 Comment

Council
SERC Planning Standards
Subcommittee

No

Southwest Power Pool
Standards Review Team

No

WECC Staff

No

Bonneville Power
Administration

No

TSGT G&T

No

Pepco Holdings Inc

No

Southern Company
Generation

No

Tri-State Generation and
Transmission Assn., Inc.
Energy Mangement

No

NERC Staff Technical Review

No

Transmission

No

PacifiCorp

No

Hydro One Networks Inc.

No

We believe, and support that RoP exception procedures are adequately dealing with

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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4

Organization

Yes or No

Question 6 Comment
this issue.

Exelon

No

Duke Energy

No

NV Energy

No

Central Hudson Gas & Electric
Corporation

No

American Electric Power

No

Consumers Energy

No

Orange and Rockland Utilities,
Inc.

No

ISO New England Inc

No

PSEg Services Corp

No

City of St. George

No

Blachly-Lane Electric
Cooperative

No

Central Electric Cooperative
(CEC)

No

AEP is not aware of any conflicts between the proposed approach and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement, or
jurisdictional issue.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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5

Organization

Yes or No

Clearwater Power Company
(CPC)

No

Consumer's Power Inc. (CPI)

No

Douglas Electric Cooperative
(DEC)

No

Fall River Electric Cooperative
(FALL)

No

Lane Electric Cooperative
(LEC)

No

Independent Electricity
System Operator

No

Lincoln Electric Cooperative
(Lincoln)

No

Northern Lights Inc. (NLI)

No

Okanogan County Electric
Cooperative (OCEC)

No

Pacific Northwest Generating
Cooperative (PNGC)

No

Raft River Rural Electric
Cooperative (RAFT)

No

Question 6 Comment

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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6

Organization

Yes or No

Umatilla Electric Cooperative

No

West Oregon Electric
Cooperative (WOEC)

No

Central Lincoln

No

National Grid

No

Oncor Electric Delivery
Company LLC

No

Coos-Curry Electric
Coooperative

No

Ameren

No

Georgia System Operations
Corporation

Yes

ATC LLC

No

Farmington Electric Utility
System

No

City of Redding

No

Tacoma Power

No

Springfield Utility Board

No

Question 6 Comment

Tacoma Power is not aware of any conflicts at this time.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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7

Organization

Yes or No

BGE

No

Michigan Public Power Agency

No

Long Island Power Authority

Question 6 Comment
No comment.

Not aware of any

Response: Thank you for your response.
Indeck Energy Services

Yes

As acknowledged in the response to Question 12 comments on the previous BES
definition, the BES definition is expansive compared to the definition of the BPS in the
FPA Section 215. The inclusion of the limited Exclusions is an attempt to remedy the
situation. However, the Exclusions need to include a fifth one that if, based on studies
or other assessments, it can be shown that any tranmission or generator element
otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There
has never been a study to show that elements, such as a 20 MW wind farm, 60 MW
merchant generator (which operates infrequently in the depressed market) in a large
BA (eg NYISO) or a radial transmission line connecting a small generator are important
to the reliability of the BPS. They are covered by the mandatory standards program
through the registration criteria. The BES Definition is the opportunity to permit an
entity to demonstrate that an element is unimportant to reliability of the BPS. The
SDT has identified a small subset of elements that it is willing to exclude. By their very
nature, these exclusions dim the bright line that is the stated goal of this project.
However, the SDT’s foresight seems limited in its selections. Analytical studies are
used to evaluate contingencies that could lead to the Big Three (cascading outages,
instability or voltage collapse). Such a study showing that a transmission or
generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable
Disturbance of approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW
merchant generator or numerous other smaller facilities would be bounded by larger
contingencies. It would take more than six 60 MW merchant generators with close

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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8

Organization

Yes or No

Question 6 Comment
location and common mode failure to even be a Reportable Disturbance, much less
become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 - Any
facility that can be demonstrated to the Regional Entity by analytical study or other
assessment to be unimportant to the reliability of the BPS (with periodic reports by
the Regional Entity to NERC of any such assessments).”

Response: The SDT has already incorporated a note at the bottom of the definition stating that exceptions can be pursued through
the exception process. The SDT feels that this note is sufficient to address the concerns raised herein. In addition, the SDT reminds
the commenter that all threshold values will be examined in Phase II of this project. No change made.
City of Redding Electric Utility

Yes

Response: Without a specific comment, the SDT is unable to respond.
Hydro-Quebec TransEnergie

Yes

For HQT's system, the proposed BES definition combined with the exception
procedure are presently incompatible or at least inconsistent with the regulatory
framework applicable in Quebec. The proposed changes have not address this
concern, neither the SDT's responses to our previous comments last May (Q.9).We
reiterate that the definition and the exception procedure shall be determined by
Quebec's regulator, the Régie de l'Énergie du Québec, (Quebec Energy Board)
which has the responsibility to ensure that electric power transmission in Quebec is
carried out according to the reliability standards it adopts. Per se, it would be
necessary that E1 and E3 grant exclusions with much higher level of generation. It
would also be necessary to allow for several levels of application for the Reliability
Standards, in accordance with the Régie de l’énergie du Québec approach: the
Bulk Power System (BPS) as determined using an impact-based methodology, the
Main Transmission System (MTS), and other parts of Regional System. Standards
related to the protection system (PRC-004-1 and PRC-005-1) and those related to the
design of the transmission system (TPL 001-0 to TPL-004-0) shall be applicable to the
first level, but all other reliability standards shall be applied to the second level, the
MTS. The MTS definition is somewhat different than the Bulk Electric System

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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9

Organization

Yes or No

Question 6 Comment
definition, and it includes elements that impact the reliability of the grid, supplydemand balance and interchanges.We argue that it would be necessary for NERC to
address the regulatory issues outside ot the present context of the SDT and ROP team.

Manitoba Hydro

Yes

Canadian Entities are not under FERC jurisdiction, so the revised BES Definition may
not apply. A number of Canadian Entities have the BES defined within their provincial
legislation. This may introduce differences and even contradictions between elements
that are included in the BES according to provincial legislation and the NERC definition.

Response: The SDT is attempting to craft a BES definition that can be applied within the ERO footprint. It is neither within the scope
of the SDT nor is it appropriate for the SDT to provide a Canadian regulatory resolution within the definition. As such, the SDT agrees
that the ERO will have to address these types of non-jurisdictional situations with relevant Regions through the exception procedure.
Kootenai Electric Cooperative

Yes

As discussed in more detail in our response to Question 2, KEC believes it is necessary
to address the function of an Element or system that is subject to an Exceptions
Request to determine whether it is a “facilit[y] used in the local distribution of electric
energy” and therefore excluded from the BES under Section 215(a)(1) of the Federal
Power Act.

City of Austin dba Austin
Energy

Yes

As discussed in more detail in our response to Question 2, AE believes it is necessary
to address the function of an Element or system subject to an Exceptions Request to
determine whether it is a “facilit[y] used in the local distribution of electric energy”
and, therefore, excluded from the BES under Section 215(a)(1) of the Federal Power
Act.

Snohomish County PUD

Yes

As discussed in more detail in our response to Question 2, SNPD believes it is
necessary to address the function of an Element or system that is subject to an
Exceptions Request to determine whether it is a “facilit[y] used in the local distribution
of electric energy” and therefore excluded from the BES under Section 215(a)(1) of the
Federal Power Act.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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0

Organization

Yes or No

Question 6 Comment

Response: Please see response to Q2.
ReliabilityFirst

Yes

Since the inception of the Open Access Transmission Tariff, transmission models and
even knowledge of the systems, operating protocols and procedures may not be well
known or known at all by all the entities. System adjustments, load levels, topologies,
maintenance and outage schedules (i.e. market sensitive information), which happens
daily is not permitted to be known by the generation side of the industry. An unknown
at this point and without a common set of criteria to be used by the Regional Entities
and NERC Staff and Panels, it will be difficult to make consistent determinations across
the ERO Enterprise.

Dominion

Yes

Much of the information necessary to perform the analysis required is restricted
either by federal and/or state Codes/Standards of Conduct and/or CEII prohibitions.

Response: Please see response to Q4.
ACES Power Marketing
Standards Collaborators

Yes

Some organized markets have a must run concept that has nothing to do with
reliability. Thus, Q3 for generation facilities might be confused with these tariff
provisions.

Response: To resolve this concern, the SDT has clarified question 3 for generation resources to read:
3. Is the generator generation resource designated as a must run unit for reliability?

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

14
1

7.

Are there any other concerns with the proposed approach for demonstrating BES Exceptions that haven’t been covered in
previous questions and comments (bearing in mind that the definition itself and the proposed Rules of Procedure changes are
posted separately for comments)? Please be as specific as possible with your comments.

Summary Consideration: Based on the responses to this question, the SDT offers the following for summary consideration.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria
and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to
say that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with
this position. The exception application form has to be taken in concert with the changes to the ERO Rules of Procedure and
looked at as a single package. When one looks at the rules being formulated for the exception process, it becomes clear that the
role of the Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of
reviewing the submittal for completion and making a recommendation to the ERO panel, not to make the final determination. The
Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter
that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to
be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and
also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the
proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent
Technical Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s
findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure,
Section 7.0, provides NERC the option to remand the application to the Regional Entity with the mandate to process the exception
if it finds the Regional Entity erred in rejecting or disapproving the exception request. On the other side of this equation, one
could make an argument that the Regional Entity has no basis for what constitutes an acceptable submittal. Commenters point
out that the explicit types of studies to be provided and how to interpret the information aren’t shown in the application process.
The SDT again points to the variations that will abound in the applications as negating any hard and fast rules in this regard.
However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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2

is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the application details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to
be supplied for the submittal to travel upward to the ERO panel for adjudication.
In addition, the SDT would point to the SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in
a favorable outcome.
NERC and the industry cannot wait until Phase 2 for the development of the exception process as it is an Order No. 743 directive
that must be addressed by the FERC established deadline of January 25, 2012.
If an entity that is submitting an exception request cannot gain access to certain information that is listed in the technical criteria
document, it should work with its Regional Entity to come up with substitute data that is acceptable. In addition, the submitting
entity should state in its exception request submittal that it is unable to access certain data from other parties and explain the
reasons why that is the case.
Organization

Yes or No

LG&E and KU Energy

Yes

Question 7 Comment
LG&E and KU Energy request clarification as to how the two year data requirement
would apply to a new facility for which the owner/operator requests an exemption.

Response: The SDT recommends that a submitting entity work with its Regional Entity to determine how best to handle this type of a
situation.
Tacoma Power

Yes

Tacoma Power has a concern that the form may be too general in nature. The task
before NERC and the industry is to promote consistency in the application of the BES
definition. The form will require the regions to develop individual criteria for assessing
an exception request and making a recommendation on the request. We recommend
in Phase 2 that the SDT develop specific evaluation criteria for the regions to apply to

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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3

Organization

Yes or No

Question 7 Comment
an exception request. Thank you for consideration of our comments.

City of Redding
City of Redding Electric Utility

Yes

Redding acknowledges there is an immediate need for a method where an entity can
present evidence that their facilities are “not necessary for the Reliable Operation of
the interconnected bulk power transmission system” as stated in the NERC Rules of
Procedure Section 3.0. “BASIS FOR APPROVAL OF AN EXCEPTION.” Without a process
to present the evidence then the RE and the ERO are under no mandate to review
facilities in light of any criteria besides the BES definition as NERC clearly pointed out
in the City of Holland case where Holland was forced to register by the RE (RFC).
However, Redding is very concerned that under the proposed Exception process the
final evaluation of an element or facility is left to the sole judgment of NERC. The
concern is there is no method, criteria, measurement, or standard that NERC will use
for the evaluation. It is also a concern that NERC has a predetermined definition of
Distribution Facilities and will not evaluate networked Distribution Facilities fairly.
NERC has already stated their predetermined position as to what they determine to be
distribution and not distribution facilities in their “MOTION TO INTERVENE AND
COMMENTS OF THE NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION” filed in
the case of the City of Holland, Michigan (Docket No. RC11-5-000). On page 10 and 11
of this motion, under the section labeled “A. Holland’s 138 kV lines are transmission
rather that local distribution facilities” NERC states “Distribution facilities generally are
characterized as elements that are designed and can carry electric energy (Watts/MW)
in one direction only at any given time from a single source point (distribution
substation) to final load centers.” NERC has clearly stated that only radial facilities are
considered distribution facilities and were unwilling to consider that network facilities
over 100Kv could be classified as Distribution Facilities in this case. Holland’s claim of
NERC over-reaching their authority appears to have credibility. In conclusion, Redding
supports the proposed exception process as it stands on the grounds that it allows an
entity the right to a process which NERC is currently not obligated to allow, it requires
that NERC judge the facilities on the merit of “necessary for the Reliable Operation of
the interconnected bulk power transmission system”, and it allows an appeals process
that must judge if NERC evaluated facilities on the standard set forth. However,

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Redding’s vote is conditional on the completion of phase 2 where the term “necessary
for the Reliable Operation of the interconnected bulk power transmission system”
needs to be defined.

Independent Electricity
System Operator

Yes

We believe that the SDT proposed approach for exception criteria is reasonable
recognizing that one method/criteria cannot be applicable to everyone and every
situation within the ERO foot print. However, we believe that there is huge gap and
lack of any transparency on how the exception application will be evaluated and
processed. We strongly suggest that SDT develop a reference or a guidance document
as part of the RoP that should provide some guidance to Registered Entities, Regional
Entities and the ERO on how an exception application should be processed. The
absence of such guidance will pose a challenge for each entity including the ERO, and
may result in discrepancies amongst Regional Entities. The process may be perceived
by registered entities as being non-transparency.

City of St. George

Yes

Clear, concise criteria with consistent repeatable results are a must for a successful
outcome of the project effort. The included questions are appropriate questions but
the use of those questions and the ultimate outcome is unclear with the current
version. The background information indicates that continent wide criteria are not
feasible. It is understood that this is a very difficult task and will be difficult to achieve
(especially in the time allotted). However, if the decisions are left up to a “panel” to
decide the results will be inconsistent and will vary region by region, as well as differ
over time. The process involved will be very time consuming (i.e. expensive) and will
be difficult to control especially during the initial timeframe. History has
demonstrated that review and approval processes that pass from the entity to the
regions, then to NERC and then on to FERC backup very easily due to limited staff and
resources.The drafting team may want to consider moving this topic to Phase 2 of the
project. However, Phase 2 needs to have fairly quick time frame in order to provide
the needed direction to the industry in a timely manner.

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Question 7 Comment

PSEg Services Corp

Yes

An applicant should be able to clearly tell whether or not an exception request will
likely be granted before it is submitted. It is nearly impossible to divine the whether a
request will be granted from a set of data questions. The team is urged to state the
exclusion criteria explicitly; data questions required to evaluate a request should
directly reference each criterion. See Order 743, paragraph 115: “NERC should
develop an exemption process that includes clear, objective, transparent, and
uniformly applicable criteria for exemption of facilities that are not necessary for
operating the grid.”

ISO New England Inc

Yes

Given all of these decisional inputs requested by the Exception Application there
needs to be some guidance or clarification here regarding the criteria that will be used
to render a yes or no decision other than simply filling out the Application and
allowing the Rules of Procedure process to take place. The Application process for
Exceptions (inclusions or exclusions) appears to be subjective and lacks the decisional
technical criteria for the applicant to be confident of the outcome.

Manitoba Hydro

Yes

Manitoba Hydro strongly disagrees with the proposed ‘Detailed Information to
Support an Exception Request’ document and associated exception process for the
following reasons: -It is not clear what elements or situations beyond what is covered
in the core definition and associated inclusions and exclusions that the drafting team
is hoping to capture through the exception process. Further, it is unclear what the
benefit to reliability would be by allowing an impact based exception process given
that entities will be extremely unlikely to use the exception process to include
elements in the BES. -The exception process will be extremely resource intensive,
particularly in the absence of any Industry approved threshold criteria. The costs to
properly administer and monitor the process to ensure that impact based modeling is
done accurately and that it captures the frequent changes on a dynamic system will
occupy a wealth of Industry, NERC and Regional Entity time to the detriment of
reliability.-It is not reasonable for industry to approve the exception process without
knowing what thresholds are required to demonstrate an element as being part of the

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Question 7 Comment
BES or not. We are concerned that BES determinations would be subjective and would
vary from case to case with the particular staff examining the request. BES elements
should be established and agreed upon by Industry, not set by a NERC panel. We
understand that the drafting team has made this change in the interests of time, but
the impact of the BES definition is too broad for this project to be rushed. -The
2010-17 project goals to increase the clarity of the BES definition and establish a
‘bright-line’ are compromised by the exception process. Changes and alterations to
the BES definition should be approved by Industry through the Standards Under
Development Process. An interpretation request or SAR should be developed by an
entity if they feel that the core definition and associated exceptions and inclusions
should be modified. We ask that NERC requests that FERC re-examines the directive to
develop an exception process given that the BES definition, which already includes a
list of exceptions, is sufficient to standalone without an associated exception process.

ReliabilityFirst

Yes

FERC Order 743-A, paragraph 1, discusses that NERC should “...establish an exemption
process and criteria for excluding facilities that are not necessary for operating the
interconnected transmission network”. It also directed in paragraph 4 that “Order No.
743 also directed the ERO to develop an exemption process that includes clear,
objective, transparent and uniformly applicable criteria for exempting facilities that
are not necessary for operating the interconnected transmission grid.” The SDT
proposed a set of questions titled “Detailed Information to Support an Exception
Request” to assist in the exemption process but in our mind is not “exception criteria”
as stated in the FERC Orders. ReliabilityFirst Staff believes that NERC should develop
criteria for which facilities or Elements could be exempted from the core definition; an
example being Local Networks as outlined in the current draft of the definition.
ReliabilityFirst Staff believes the Local Network exclusion is not “bright line” and could
be removed from the core definition and used as criteria for exclusion in the
exemption process. Item b of the LN (E3) exclusion would need evidence to support
the historical and future power flows. Historical data and future power flow study
results would be needed to support this exception. Additionally, another example for
exemption criterion for inclusion to the BES could be any 69 kV network facilities that

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Question 7 Comment
provide a parallel path to the BES. Evidence such as one-line diagrams along with
power flow studies would need to be provided through the exemption process for
these types of facilities to be included in the BES. ReliabilityFirst Staff believes that any
BES facilities should not be candidates for exemption based upon the arbitrary
determination of a panel that considers the aspects stated in the document “Detailed
Information to Support an Exception Request”. Without uniform criteria as stated in
the FERC Orders, it will be difficult for the panels to make consistent determinations
across the ERO Enterprise.

Hydro One Networks Inc.

Yes

As mentioned above, we strongly suggest and encourage that SDT to develop a
reference or a guidance document that will provide guidance to Registered Entities,
Regional Entities and the ERO on how an exception application should/would be
processed.

Arizona Public Service
Company

Yes

In accordance with WECC’s position paper issued on October 5, 2011, AZPS agrees
with WECC in that the proposed Technical Principles for Demonstrating BES Exceptions
Request does not provide the necessary clarity as to what applying entities must
provide to support their request, nor does it provide any criteria for consistency
among regions in their assessment of requests.

SRP

Yes

SRP agrees with WECC Staff comments.

WECC Staff

Yes

WECC is very concerned that there are no specific qualifications or requirements,
either for the entities or for the Regional Entity, with respect to: o the determination
of which studies need to be conducted; o the format of the study data that should be
submitted; or o the key performance measures that should be evaluated. This
vagueness will lead to inconsistency in studies run, data submitted, and measures of
data evaluation. If this inconsistency occurs, it will result in a potentially subjective and
discordant process on multiple levels for both the submitting entities and the Regional
Entities. It may result in submitting entity having to run multiple studies in order to
determine what will be acceptable proof, which is overly burdensome on both the

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Question 7 Comment
submitting entity requesting the exception and the Regional Entity reviewing the
request. It also makes the consistency that FERC has requested difficult to assess and
achieve. If the goal of the exceptions process is to result in consistent determinations
across the regions, then WECC recommends that to the extent possible, the process
be objective, clear, and include detailed instructions. The development of such an
objective and detailed process is a difficult task and will require additional time. WECC
believes it is better to not have an exceptions process in the interim period than to
have an inefficient and overly burdensome process in place. To allow adequate time to
complete the task of developing a detailed and consistent process WECC recommends
that the Detailed Information to Support BES Exceptions Request be included in Phase
II of the BES definition project.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT
would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would
also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received
very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package.
When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been
drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and
making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving
or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a position to
effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the
visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity of
the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4,
provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity decides to
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Yes or No

Question 7 Comment

reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to NERC.
Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the Regional
Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception request.
On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an acceptable
submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t shown in
the request process. The SDT again points to the variations that will abound in the requests as negating any hard and fast rules in this
regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and
there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take
into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made.
The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on
evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the interconnected
transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system
within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading
failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or unanticipated failure of
system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the experience
gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent approach to the
problem. The SDT would also point out that there are options for a submitting entity to pursue that are outlined in the proposed ERO
Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2
of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a
question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
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Question 7 Comment

Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to
the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of
the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes
that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of
these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable outcome.
In addition, NERC and the industry cannot wait until Phase 2 for the development of the exception process as it is an Order No. 743
directive that must be addressed by the FERC established deadline of January 25, 2012.
Dominion

Yes

The Detailed Information to Support an Exception Request form has 2 sections; one
for transmission facilities and another for generation facilities. Yet, the Project 201017 Definition of Bulk Electric System document uses other terms such as real and
reactive power resources, dispersed power producing resources, static or dynamic
devices, blackstart resources, radial systems, local networks (LN), and reactive power
devices. Dominion suggests that the Detailed Information to Support an Exception
Request form be revised to conform to the Project 2010-17 Definition of Bulk Electric
System document through either use of some sort of ‘selection’ (checkbox, drop
down, write in) or revision of transmission facilities and generation facilities to be
more inclusive.

Response: The SDT is only determining the content of the technical criteria document. NERC will be responsible for addressing the
format and user features of the final technical criteria document.
TSGT G&T

Yes

Tri-State Generation and
Transmission Assn., Inc.
Energy Mangement

TSGT believes that the proposed “Technical Principles for Demonstrating BES
Exceptions Request” does not clearly define the basis for decisions to exclude or
include, which will lead to inconsistent application by the Regions. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective criteria
defining how to assess the materials submitted, the current methodology leaves it to

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Question 7 Comment
each region to develop their own methodology and criteria for evaluating the
submittals. We believe the lack of clarity regarding what studies must be submitted
and what must be demonstrated by the studies submitted will be overly burdensome
on the submitting entity and the Region, as multiple studies may be required for the
two to agree that there is sufficient justification for an exemption request. We believe
that additional work is necessary to develop clear, objective methods and criteria for
identifying which facilities may be excluded from or should be included in the Bulk
Electric System. Clear, objective methods and criteria will enable the submitter of
requests to understand what is necessary for submitting an exception request and will
provide for consistency among the regions in their initial assessment and
recommendations to the ERO.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT
would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would
also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received
very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package.
When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been
drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and
making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving
or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a position to
effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the
visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity of
the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4,
provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity decides to
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Yes or No

Question 7 Comment

reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to NERC.
Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the Regional
Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception request.
On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an acceptable
submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t shown in
the request process. The SDT again points to the variations that will abound in the requests as negating any hard and fast rules in this
regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and
there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take
into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made.
The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on
evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the interconnected
transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system
within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading
failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or unanticipated failure of
system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the experience
gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent approach to the
problem. The SDT would also point out that there are options for a submitting entity to pursue that are outlined in the proposed ERO
Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2
of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a
question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
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Question 7 Comment

Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to
the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of
the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes
that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of
these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable outcome.
NERC Staff Technical Review

Yes

At a minimum, we believe there are some facilities which should not be excluded from
the BES under any circumstances and a list of such facilities should be documented,
including facilities such as (1) Elements that are relied on in the determination of an
Interconnection Reliability Operating Limit (IROL); (2) Blackstart resources and the
designated blackstart Cranking Paths identified in the Transmission Operator’s
restoration plan regardless of voltage, (3) Elements subject to Nuclear Plant Interface
Requirements (NPIRs) as agreed to by a Nuclear Plant Generator Operator and a
Transmission Entity defined in NUC-001, (4) Elements identified as required to comply
with a NERC Reliability Standard by application of criteria defined within the standard
(e.g., the test defined in PRC-023 to identify sub-200 kV Elements to which the
standard is applicable), and (5) a generating unit that is designated as a must run unit
to assure reliability of the BES.
Also, to make the process of reviewing exception applications consistent and
transparent some high level guidance should be developed as to how the information
provided will be assessed by the Regional Entities and NERC. In addition to supporting
the objectives of consistency and transparency, this also would provide benefit to
entities submitting an exception application by allowing them to understand how the
Required Information will be evaluated.

Response: The SDT notes that all BES definition exception requests are considered unique and will be handled on a case-by-case basis.
In addition, there is no prohibition on what facilities can be included in an exception request. To say that an Element(s) can be
automatically excluded or included on a continent-wide basis is contrary to the SDT’s intent. While most of the items noted do reside
on the exception request form, the SDT reminds the commenter that the proposed ERO Rules of Procedure state that “No single piece
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Question 7 Comment

of evidence provided as part of an Exception Request or response to a question will be solely dispositive in the determination of
whether an Exception Request shall be approved or disapproved.”
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like
nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion
and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the
SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out
to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form
of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package.
When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been
drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and
making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving
or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a position to
effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the
visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity of
the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4,
provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity decides to
reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to NERC.
Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the Regional
Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception request.
On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an acceptable
submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t shown in
the request process. The SDT again points to the variations that will abound in the requests as negating any hard and fast rules in this
regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and
there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Yes or No

Question 7 Comment

supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take
into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made.
The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on
evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the interconnected
transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system
within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading
failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or unanticipated failure of
system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the experience
gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent approach to the
problem. The SDT would also point out that there are options for a submitting entity to pursue that are outlined in the proposed ERO
Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2
of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a
question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.

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Organization

Yes or No

Michigan Public Power Agency

Yes

Question 7 Comment
The following revisions should be made to the procedures: 1. The Technical Review
Panel (TRP) provided for in Section 5.3 should not include any staff from the host
Regional Entity.
2. The Regional Entity should be required to include an attestation of a qualified
individual or individuals to support the factual and technical bases for the decision.
This is necessary for purposes of establishing a record in the event of an appeal. If a
dispute is appealed, there must be someone at the Regional Entity level that serves as
the witness supporting the Regional Entity decision. Currently, there is no
accountability for the arguments and suppositions put forth by the Regional Entity; no
individuals that stand behind the technical bases proffered in the Regional Entity’s
written decision. Requiring a qualified individual to attest to the facts and technical
arguments relied upon in arriving at the decision will ensure that someone at the
Regional Entity level is prepared to take responsibility for reviewing a decision before
it is issued, to stand behind the assertions and conclusions reached by the Regional
Entity, and whom the Submitting Party may cross examine at hearing.
3. A party seeking an exception should have the right to request a hearing and should
not be limited to a paper process.
4. The procedures should not permit the TRP or the Regional Entity to make a decision
based upon information that is outside of the record placed before it. That is, the TRP
and the Regional Entity may not, on their own, conduct an investigation or seek
information independently from what has been presented to it. If the TRP or the
Regional Entity requires additional information, it must be requested and provided
transparently, and the Submitting Party must have an opportunity to comment upon
or challenge that information before the TRP or the Regional Entity relies upon it in
any way. This is not currently happening at the Regional Entity and NERC level decisions have been made based upon documents and information that are not part
of the record; the information is not shared with the Submitting Party (the party
challenging registration) prior to (or after) a decision is made.

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Organization

Yes or No

Question 7 Comment
5. Section 5.2.2. should be revised as follows: “Upon Acceptance of the Exception
Request, the Regional Entity and Submitting Party (and Owner, if different) shall
confer to establish milestones in order to complete the substantive review of the
Exception Request within six months after Acceptance of the Exception Request or
within an alternative time period under Section 5.0. The Regional Entity and the
Submitting Party (and Owner, if different) shall also discuss whether and to what
extent a reduced compliance burden is appropriate during the review period. At the
conclusion of the review period, the Regional Entity shall issue a notice (in accordance
with Sections 5.2.3) stating is Recommendation that the Exception Request be
approved or disapproved.”

Holland Board of Public Works

Yes

The following revisions should be made to the procedures: 1. The Technical Review
Panel (TRP) provided for in Section 5.3 should not include any staff from the host
Regional Entity.
2. The Regional Entity should be required to include an attestation of a qualified
individual or individuals to support the factual and technical bases for the decision.
This is necessary for purposes of establishing a record in the event of an appeal. If a
dispute is appealed, there must be someone at the Regional Entity level that serves as
the witness supporting the Regional Entity decision. Currently, there is no
accountability for the arguments and suppositions put forth by the Regional Entity; no
individuals that stand behind the technical bases proffered in the Regional Entity’s
written decision. Requiring a qualified individual to attest to the facts and technical
arguments relied upon in arriving at the decision will ensure that someone at the
Regional Entity level is prepared to take responsibility for reviewing a decision before
it is issued, to stand behind the assertions and conclusions reached by the Regional
Entity, and whom the Submitting Party may cross examine at hearing.
3. A party seeking an exception should have the right to request a hearing and should
not be limited to a paper process.
4. The procedures should not permit the TRP or the Regional Entity to make a decision

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Organization

Yes or No

Question 7 Comment
based upon information that is outside of the record placed before it. That is, the TRP
and the Regional Entity may not, on their own, conduct an investigation or seek
information independently from what has been presented to it. If the TRP or the
Regional Entity requires additional information, it must be requested and provided
transparently, and the Submitting Party must have an opportunity to comment upon
or challenge that information before the TRP or the Regional Entity relies upon it in
any way. This is not currently happening at the Regional Entity and NERC level decisions have been made based upon documents and information that are not part
of the record; the information is not shared with the Submitting Party (the party
challenging registration) prior to (or after) a decision is made.
5. Section 5.2.2. should be revised as follows: “Upon Acceptance of the Exception
Request, the Regional Entity and Submitting Party (and Owner, if different) shall
confer to establish milestones in order to complete the substantive review of the
Exception Request within six months after Acceptance of the Exception Request or
within an alternative time period under Section 5.0. The Regional Entity and the
Submitting Party (and Owner, if different) shall also discuss whether and to what
extent a reduced compliance burden is appropriate during the review period. At the
conclusion of the review period, the Regional Entity shall issue a notice (in accordance
with Sections 5.2.3) stating is Recommendation that the Exception Request be
approved or disapproved.”

Response: Your comments are not focused on the technical criteria document and they have been forwarded to the BES ROP team for
consideration in their separate process.
Central Hudson Gas & Electric
Corporation

Yes

The ‘Technical Principles for Demonstrating BES Exceptions’ process was intended to
establish technical exception ‘criteria’ which would be used by the industry to
understand what facilities would qualify for inclusions and exclusions from the BES.
What has been produced, however, is essentially a listing of ‘electrical system
indicators’, identified on the form, which may be material to making a decision
regarding, ‘is it BES or not’. The thresholds (or acceptable values) for the indicators,

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Organization

Yes or No

Question 7 Comment
however, have not been determined. It is understood that in Phase II of the BES
Definition development process, the SDT will attempt to address these issues but until
that work has been completed, the industry will remain enmeshed in confusion and
inefficient application of resources and funding. Without these criteria, it is very
difficult to believe that this process can be transparent and consistent. Re: Question 4.
(For Transmission Facilities)For the purposes of responding to this question, what
constitutes the BES? It would seem that you must exclude the elements you are
seeking exceptions for or else the exception request is rendered essentially worthless.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT
would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would
also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received
very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception application form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single
package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity
has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for
completion and making a recommendation to the ERO panel, not to make the final determination. The Regional Entity plays no role in
actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a
position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that
the visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity
of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and
5.2.4, provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity decides
to reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to NERC.
Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the application to the Regional
Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception request.
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Organization

Yes or No

Question 7 Comment

On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an acceptable
submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t shown in
the application process. The SDT again points to the variations that will abound in the applications as negating any hard and fast rules in
this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and
there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the application details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO panel for adjudication.
Finally, the SDT would point to the SAR for Phase II of this project that calls for a review of the process after 12 months of experience.
The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process
based on actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the
technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it
has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these
facts in making your decision and casting your ballot and hopes that these changes will result in a favorable outcome.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects (i.e.,
the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being responsive
to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not
afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a change from the current
values that exist through the application of the definition today. These and similar issues have prompted the SDT to separate the project
into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT
will consider all recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17
Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop
analyses which will properly assess the threshold values and provide compelling justification for modifications to the existing values.
National Grid

Yes

We are assuming that "yes" answers on this checklist are not intended to result in
automatic rejection of the application. We think the procedure would benefit from a
general statement noting that all answers taken together will be considered to make
clear that no single answer will necessarily be dispositive of the outcome.

Response: Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception application form will
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1

Organization

Yes or No

Question 7 Comment

mandate a negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
Indeck Energy Services

Yes

As acknowledged in the response to Question 12 comments on the previous BES
definition, the BES definition is expansive compared to the definition of the BPS in the
FPA Section 215. The inclusion of the limited Exclusions is an attempt to remedy the
situation. However, the Exclusions need to include a fifth one that if, based on studies
or other assessments, it can be shown that any tranmission or generator element
otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There
has never been a study to show that elements, such as a 20 MW wind farm, 60 MW
merchant generator (which operates infrequently in the depressed market) in a large
BA (eg NYISO) or a radial transmission line connecting a small generator are important
to the reliability of the BPS. They are covered by the mandatory standards program
through the registration criteria. The BES Definition is the opportunity to permit an
entity to demonstrate that an element is unimportant to reliability of the BPS. The
SDT has identified a small subset of elements that it is willing to exclude. By their very
nature, these exclusions dim the bright line that is the stated goal of this project.
However, the SDT’s foresight seems limited in its selections. Analytical studies are
used to evaluate contingencies that could lead to the Big Three (cascading outages,
instability or voltage collapse). Such a study showing that a transmission or
generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable
Disturbance of approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW
merchant generator or numerous other smaller facilities would be bounded by larger
contingencies. It would take more than six 60 MW merchant generators with close
location and common mode failure to even be a Reportable Disturbance, much less
become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 - Any
facility that can be demonstrated to the Regional Entity by analytical study or other

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2

Organization

Yes or No

Question 7 Comment
assessment to be unimportant to the reliability of the BPS (with periodic reports by
the Regional Entity to NERC of any such assessments).”

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline
of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that
would warrant a change from the current values that exist through the application of the definition today. These and similar issues
have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in
conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and
provide compelling justification for modifications to the existing values.
American Electric Power

No

AEP agrees with the overall approach demonstrated by the exception request form;
however, its appropriateness will be largely dependent on the process eventually used
for its implementation.AEP would like guidance on how moth-balled generation
should be treated. Perhaps this could be added to the exception form as well.

Response: The SDT is not able to respond to specific requests related to potential future exception requests. Please use the BES
definition and the exception request form, after its approval by the NERC Board of Trustees and FERC, for such a request. Also, please
consider working with your Regional Entity to determine how moth-balled facilities should be treated.
Snohomish County PUD
Blachly-Lane Electric
Cooperative
Central Electric Cooperative
(CEC)
Clearwater Power Company

No

As a general matter, SNPD believes the SDT has provided a reasonable check list that
will work in most cases to elicit necessary information from the entity submitting an
Exception Request. With the added language suggested in our answers to the
previous questions, we believe the proposed form will serve its intended purpose of
ensuring that decisions regarding Exception Requests are based upon consistent
information and are consistent with the requirements of the Federal Power Act and
the BES Definition as developed by the Standards Drafting Team. SNPD also supports
the Standards Drafting Team’s determination to abandon its initial approach to

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Organization

Yes or No

(CPC)
Consumer's Power Inc. (CPI)
Douglas Electric Cooperative
(DEC)
Fall River Electric Cooperative
(FALL)

Question 7 Comment
technical criteria, which would have required adherence to specific numerical
thresholds. SNPD agrees that this approach was not workable on a nationwide basis,
and that the approach embodied in the current draft of the Technical Principles, which
would require specific kinds of information on a generic basis but would leave
engineering judgment about the significance of that information to the relevant RE, is
more workable and provides appropriate deference to the experience and judgment
of the REs.

Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(Lincoln)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
Umatilla Electric Cooperative
West Oregon Electric
Cooperative (WOEC)
Coos-Curry Electric
Coooperative
City of Austin dba Austin
Energy

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4

Organization

Yes or No

Question 7 Comment

Kootenai Electric Cooperative
BGE

No

Farmington Electric Utility
System

No

ATC LLC

No

Ameren

No

Georgia System Operations
Corporation

No

Oncor Electric Delivery
Company LLC

No

Central Lincoln

No

Long Island Power Authority

No

Consumers Energy

No

Orange and Rockland Utilities,
Inc.

No

Duke Energy

No

NV Energy

No

Exelon

No

No comment.

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5

Organization

Yes or No

Transmission

No

PacifiCorp

No

Pepco Holdings Inc

No

Southern Company
Generation

No

Bonneville Power
Administration

No

Southwest Power Pool
Standards Review Team

No

ACES Power Marketing
Standards Collaborators

No

Northeast Power Coordinating
Council

No

SERC Planning Standards
Subcommittee

No

Question 7 Comment

Response: Thank you for your support.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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END OF REPORT

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Consideration of Comments on Initial Ballot
Project 2010-17 BES Technical Exceptions
Date of Initial Ballot: September 30 – October 10, 2011

Summary Consideration: Many commenters followed instructions and cast their ballot while simply pointing to their detailed comments in the
posted comment report. The SDT thanks those commenters as this greatly reduces the administrative workload on the SDT. Those who decided
to place comments in the ballot report for the most part echoed comments that had already been seen by the SDT in the posted comment
report which was administered first by the SDT. As a result, there were no changes to the definition due to comments received in the ballot
report. However, for ease of reference, the changes to the definition made as a result of those comments are repeated here.
The SDT made the following changes to the request form due to industry comments received:
• General – Clarified the use of facility versus Element(s).
• Page 1 – Deleted ‘s’ : List any attached supporting documents and any additional information that is included to supports the request:
• Generation - Q1. Replaced ‘generator’s or generator’s facility’ with ‘generation resource’: What is the MW value of the host Balancing
Authority’s most severe single Contingency and what is the generator’s, or generator facility’s generation resource’s, percent of this
value?
• Generation - Q2. Replaced ‘generator’s or generator’s facility’ with ‘generation resource’: Is the generator or generator facility
generation resource used to provide reliability- related Ancillary Services?
• Generation - Q3. Replaced ‘generator’s or generator’s facility’ with ‘generation resource’: Is the generator generation resource
designated as a must run unit for reliability?
The SDT feels that it is important to remind the industry that Phase II of this project will begin immediately after the conclusion of Phase I as SDT
resources clear up. The same SDT will follow through with Phase II.
The SDT is recommending that this project be moved forward to the recirculation ballot stage.
There were two comments that were repeated multiple times throughout the various documents. The first topic was about how to sort through
the definition inclusions and exclusions, i.e., which takes precedence. The SDT offers this guidance on that issue:

The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast majority
of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and non-BES
Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or higher as included in
the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed. Element is defined in the NERC
Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker, bus
section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application of the
‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific criteria to provide for
a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion language
is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the exclusion
language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The exclusion (E1) only
speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner.
Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and supersedes
inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected transmission
network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude an Element.
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

2

The second item is about providing specific guidance on how the information on the exception request form will be used in making decisions on
inclusions/exclusions in the exception process. The SDT provides the following information on this item:
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like nothing
better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and an initial
attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could have come
up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the commenters that it
directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the Regional
Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the
proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to
remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or
disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis for
what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be supplied
for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making their
decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

3

reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric system
thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a
sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the technical
prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests will result
in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a submitting
entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their
submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Herb
Schrayshuen, at 404-446-2560 or at herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Standards Processes Manual: http://www.nerc.com/docs/standards/sc/Standard_Processes_Manual_Approved_May_2010.pdf.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

4

Voter
Kirit Shah

Entity
Ameren
Services

Segment
1

Vote
Negative

Comment
Please refer to Ameren comments submitted using the Comment Form.

Andrew Z
Pusztai

American
Transmission
Company, LLC
Arizona Public
Service Co.

1

Negative

Comments submitted.

1

Negative

Comments submitted

1

Negative

comments posted on comment form

1

Negative

comments submitted for both BES ballots

1

Negative

See Con Edison’s comments on the Technical Principles submitted separately by
electronic survey form.

Michael S
Crowley

Associated
Electric
Cooperative,
Inc.
Bonneville
Power
Administration
Consolidated
Edison Co. of
New York
Dominion
Virginia Power

1

Negative

Please see Dominion’s submitted comments

Bernard
Pelletier

Hydro-Quebec
TransEnergie

1

Negative

Please see our comments on the Technical Information to Support BES Exception.

Chris W Bolick

Associated
Electric
Cooperative,
Inc.
Southwest
Power Pool,
Inc.

3

Negative

Please see comments of Associated Electric Cooperative

2

Negative

2

Negative

SPP's comments on this concurrent ballot/comment period have been submitted
and provide support for our Negative vote. In addition, SPP is a member of the IRC
SRC and is in support of those comments on this standard. Please refer to these
sets of comments for our recommendations.
please refer to detailed comments submitted for this project.

Robert Smith
John Bussman

Donald S.
Watkins
Christopher L
de Graffenried

Charles Yeung

Kathleen
Goodman

ISO New
England, Inc.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

5

Voter
Tracy Sliman

Rebecca
Berdahl
Andrew Gallo

Peter T Yost

Richard
Blumenstock
Michael F.
Gildea
Janelle
Marriott
David Frank
Ronk
Francis J.
Halpin
Jeanie Doty

Wilket (Jack)
Ng

Entity
Tri-State G & T
Association,
Inc.
Bonneville
Power
Administration
City of Austin
dba Austin
Energy
Consolidated
Edison Co. of
New York
Consumers
Energy
Dominion
Resources
Services
Tri-State G & T
Association,
Inc.
Consumers
Energy
Bonneville
Power
Administration
City of Austin
dba Austin
Energy
Consolidated
Edison Co. of
New York

Segment
1

Vote
Negative

Comment
Comments submitted on electronic form.

3

Negative

Please see BPA's responses on the comment form submitted seperately.

3

Negative

Austin Energy (AE) has submitted detailed comments on this issue through its
official Comment document. Please refer to those comments.

3

Negative

Con Edison comments have been submitted separately.

3

Negative

See Consumers Energy's comments on the official submittal form.

3

Negative

See Dominin's submitted comments.

3

Negative

Tri-State G&T Load Serving Entity comments were submitted through the formal
electronic comment process.

4

Negative

See Comments of Consumers Energy Company

5

Negative

Please see BPA's responses on the comment form submitted seperately.

5

Negative

Austin Energy (AE) has submitted detailed comments on this issue through its
official Comment document. Please refer to those comments.

5

Negative

See Con Edison’s comments on the Technical Principles submitted separately by
electronic survey form.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

6

Voter
David C
Greyerbiehl

Entity
Consumers
Energy
Company
Dominion
Resources, Inc.

Segment
5

Vote
Negative

Comment
See Consumers Energy's comments on the official comment submittal forms.

5

Negative

See comments filed on this project.

Dan
Roethemeyer

Dynegy Inc.

5

Negative

Comments to be submitted with the SERC OC Standards Review Group.

Christopher
Schneider

MidAmerican
Energy Co.

5

Negative

Mahmood Z.
Safi

Omaha Public
Power District

5

Negative

See the MidAmerican submitted comments. The BES definition needs additional
specific inclusion or exclusion provisions that clearly exclude variable resource
generation collector circuits rated below 100 kV and generators less than 20 MVA
connected to those collector circuits in accordance with the registration criteria.
See Doug Peterchuck’s comments

Glen Reeves

Salt River
Project

5

Negative

See comments submitted

Brenda S.
Anderson

Bonneville
Power
Administration
City of Austin
dba Austin
Energy
Consolidated
Edison Co. of
New York
Dominion
Resources, Inc.

6

Negative

Please see BPA's responses on the comment form submitted seperately.

6

Negative

Austin Energy (AE) has submitted detailed comments on this issue through its
official Comment document. Please refer to those comments.

6

Negative

Con Edison comments have been submitted separately.

6

Negative

See comments submitted by Dominion.

10

Negative

Comments Submitted

Mike Garton

Lisa L Martin

Nickesha P
Carrol
Louis S. Slade
Steven L.
Rueckert

Western
Electricity
Coordinating
Council

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

7

Voter
Ajay Garg

Entity
Hydro One
Networks, Inc.

Segment
1

Anthony E
Jablonski

ReliabilityFirst
Corporation

10

Guy V. Zito

Northeast
Power
Coordinating
Council, Inc.
Central Lincoln
PUD

10

Affirmative NPCC will be submitting comments on behalf of our members through the formal
comment process along with suggestions to address those comments.

9

Affirmative I support the additional comments prepared by Steve Alexanderson of Central
Lincoln PUD

Pacific
Northwest
Generating
Cooperative
FirstEnergy
Solutions

8

Affirmative Please see PNGC's separate comment form.

6

Florida
Municipal
Power Agency
Florida
Municipal
Power Pool
Southern
Company
Generation
AEP Marketing

6

Affirmative FirstEnergy supports the proposed technical information to support BES
exceptions and offers comments and suggestions through the formal comment
period.
Affirmative Please see comments submitted through the formal comments

6

Affirmative See FMPA's comments

5

Affirmative Comments from Southern Company Generation are being submitted via the
electronic comment form found on the project page.

6

Affirmative Comments are being submitted via electronic form by Thad Ness on behalf of
American Electric Power.

Bruce Lovelin
Margaret Ryan

Kevin Querry

Richard L.
Montgomery
Thomas
Washburn
William D
Shultz
Edward P. Cox

Vote
Negative

Comment
After careful analysis of the proposed documents, Hydro One Networks Inc. is
casting a negative vote. We commend the SDT for the effort in facing the
challenge. However, we believe that the proposed definition and the exception
request criteria still need further work. Some issues need to be resolved before a
final approval is granted. Please see our detailed comments as provided in the online system.
Affirmative Comments submitted

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

8

Voter
Gary Carlson

Entity
Michigan
Public Power
Agency
Florida
Municipal
Power Agency
Lakeland
Electric

Segment
5

Vote
Affirmative Comments submitted separately

5

Affirmative Please see comments submitted through the formal comments

5

Affirmative Refer to comments from FMPA.

Brock Ondayko

AEP Service
Corp.

5

Affirmative Comments are being submitted via electronic form by Thad Ness on behalf of
American Electric Power.

Aleka K Scott

Pacific
Northwest
Generating
Cooperative
Ohio Edison
Company

4

Affirmative Please see PNGC's separate comment form.

4

David
Schumann
James M
Howard

Douglas
Hohlbaugh

Comment

Georgia
System
Operations
Corporation
Madison Gas
and Electric
Co.
Illinois
Municipal
Electric Agency

4

Affirmative FirstEnergy supports the proposed technical information to support BES
exceptions and offers comments and suggestions through the formal comment
period.
Affirmative See electronic comment form submitted by Georgia System Operations Corp

4

Affirmative Please see the MRO NSRF comments concerning this project.

4

Shamus J
Gamache

Central Lincoln
PUD

4

Affirmative Illinois Municipal Electric Agency (IMEA) appreciates the SDT’s diligence in
developing technical inforamtion to support the BES Exception process. With its
Affirmative vote, IMEA supports and recommends comments submitted by the
Transmission Access Policy Study Group.
Affirmative See Central Lincoln PUD comments (CLPUD) Posted by Steve Alexanderson.

John Allen

City Utilities of
Springfield,

4

Affirmative City Utilities of Springfield, Missouri supports the comments from SPP.

Guy Andrews

Joseph
DePoorter
Bob C. Thomas

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

9

Voter

Frank Gaffney

Steve Eldrige

Marc Farmer

Ian S Grant

Jon Shelby
Ray Ellis

John S Bos

Rick Crinklaw

Michael Henry

Stephan Kern

Entity
Missouri

Segment

Florida
Municipal
Power Agency
Umatilla
Electric
Cooperative
West Oregon
Electric
Cooperative,
Inc.
Tennessee
Valley
Authority
Northern
Lights Inc.

4

Affirmative Please see comments submitted through the formal comments

3

Affirmative Please see UEC's separate comment form.

3

Affirmative Please see WOEC's separate comment form.

3

Affirmative My company has submitted comments via the comment form.

3

Affirmative Please see NLI's separate comment form.

3

Affirmative Please see Okanogan's separate comment form.

3

Affirmative MPW agrees with the comments submitted by the MRO NERC Standards Review
Forum (NSRF)

3

Affirmative Please see LEC's separate comment form.

3

Affirmative Please see Lincoln's separate comment form.

3

Affirmative FirstEnergy supports the proposed technical information to support BES
exceptions and offers comments and suggestions through the formal comment

Okanogan
County Electric
Cooperative,
Inc.
Muscatine
Power &
Water
Lane Electric
Cooperative,
Inc.
Lincoln Electric
Cooperative,
Inc.
FirstEnergy
Energy

Vote

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

Comment

10

Voter

Joe McKinney

William N.
Phinney

William Bush

Dave Sabala

Bryan Case

Dave Hagen

Entity
Delivery

Segment

Vote

Comment

Florida
Municipal
Power Agency
Georgia
Systems
Operations
Corporation
Holland Board
of Public
Works
Douglas
Electric
Cooperative
Fall River Rural
Electric
Cooperative
Clearwater
Power Co.

3

Affirmative Please see comments submitted through the formal comments

3

Affirmative See electronic comment form from Georgia System Operations Corporation

3

Affirmative Please see Holland Board of Public Works' comment form.

3

Affirmative Please see DEC's separate comment form.

3

Affirmative Please see FREC's separate comment form.

3

Affirmative Please see Clearwater's separate comment form.

period.

Roman Gillen

Consumers
Power Inc.

3

Affirmative Please see CPI's separate comment form.

Roger Meader

Coos-Curry
Electric
Cooperative,
Inc
Central Lincoln
PUD

3

Affirmative Please see CCEC's separate comment form.

3

Affirmative Comments previously submitted.

Steve
Alexanderson
Dave Markham

Central Electric 3
Cooperative,
Inc. (Redmond,
Oregon)

Affirmative Please see Central's separate comment form.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

11

Voter
Bud Tracy

Entity
Blachly-Lane
Electric Co-op

Segment
3

Vote
Comment
Affirmative Please see BLEC's separate comment form.

Rich Salgo

Sierra Pacific
Power Co.

1

Affirmative Comments Submitted

Electric
Reliability
Council of
Texas, Inc.
David Thorne
Potomac
Electric Power
Co.
Richard Burt
Minnkota
Power Coop.
Inc.
Gordon Pietsch Great River
Energy

2

Affirmative ERCOT ISO has joined the IRC SRC comments submitted.

1

Affirmative Comments submitted

1

Affirmative While MPC is voting affirmative, we ask that you see the comments submitted by
the MRO NERC Standards Review Forum (NSRF).

1

Affirmative Please see MRO NSRF comments

William J Smith FirstEnergy
Corp.

1

Paul B.
Johnson

American
Electric Power

1

Affirmative FirstEnergy supports the proposed technical information to support BES
exceptions and offers comments and suggestions through the formal comment
period.
Affirmative Comments are being submitted via electronic form by Thad Ness on behalf of
American Electric Power.

Stuart Sloan

Consumers
Power Inc.

1

Charles B
Manning

Affirmative Please see CPI's separate comment form.

Response: The SDT thanks you for following the instructions with regard to comments. This greatly reduces the administrative burden for the
SDT and will help accelerate the process.
Paul Morland

Colorado
Springs
Utilities

1

Negative

Colorado Springs Utilities believes that the proposed Technical Information to
Support BES Exceptions Request does not provide the necessary clarity as to what
applying entities must provide to support their request. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. We believe the lack of clarity
regarding what studies must be submitted and what must be demonstrated by the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

12

Voter

Entity

Segment

Vote

Comment
studies submitted will be overly burdensome on our staff. We believe that
additional work is necessary to develop clear, objective methods and criteria for
identifying which facilities may be excluded from or should be included in the Bulk
Electric System. Clear, objective methods and criteria will enable us to understand
what is necessary for submitting an exception request.
To allow sufficient time to complete this difficult task, we believe that the Detailed
Information to Support BES Exceptions Request should not be part of the Phase 1
Bulk Electric System Definition effort, but should be postponed and included in the
Phase 2 effort.
Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and
an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could
have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the
commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive
comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the
Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of
the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of
the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting
or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis
for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

13

Voter
Entity
Segment
Vote
Comment
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making
their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric
system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the
technical prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests
will result in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
The SDT is required to submit the exception process as part of the revised definition on January 25, 2012 as specified in Order743.
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

14

Voter
Martyn Turner

Entity
Lower
Colorado River
Authority

Segment
1

Vote
Negative

Comment
1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support these
changes or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments. Yes: X No:
Comments:
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: No: X Comments: LCRA TSC supports the inclusion of transformers (with both
the primary and secondary windings operated at 100-kV or higher) in the BES
definition; however, additional clarification is suggested. The term transformers
needs to be further defined with respect to function (auto transformers, phase
angle regulators, generator step-up transformers, etc.). Similarly, a separate
definition for “Transformer” could be developed and included in the NERC
Glossary of Terms.
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: No: X Comments:
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: X No: Comments:
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: No: X Comments: LCRA TSC suggests consistency between this inclusion
criteria and the criteria used in I2 for “generation”.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

15

Voter

Entity

Segment

Vote

Comment
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: No: X Comments: This inclusion conflicts with exclusion E4. Which one takes
priority?
7. The SDT has revised the specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E1 (radial system)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: No: X Comments: The current wording is unclear with respect to the
treatment of normally open switching devices. LCRA TSC suggests the following
language to replace the existing language on the note to E1: “Two radial systems
connected by a normally open, manually operated switching device, as depicted
on prints or one-line diagrams for example, may be considered as radial systems
under this exclusion.” The current wording is unclear with respect to “non-retail
generation”. The sudden loss of large, radial-supplied load may result in reliability
deficiencies. LCRA TSC suggests stating a load level or a load capacity in the
exclusion.
8. The SDT has revised the specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel that
alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: No: X Comments:
9. The SDT has revised the specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E3 (local network)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: X No: Comments:
10. The SDT has added specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E4 (reactive resources)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

16

Voter

Comment
Yes: No: X Comments: This exclusion conflicts with inclusion item I5. Which one
takes priority?
11. Are there any other concerns with this definition that haven’t been covered in
previous questions and comments remembering that the exception criteria are
posted separately for comment? Yes: X No: Comments: LCRA TSC supports the
direction the standards drafting team taking with this project on the BES Definition
and encourages further clarification as noted in these comments for proper
application.
Response: The SDT directs LCRA to the detailed responses in the regular comment form as these comments are identical to those contained
there.
Greg C. Parent

Entity

Manitoba
Hydro

Segment

3

Vote

Negative

Manitoba Hydro strongly disagrees with the proposed ‘Detailed Information to
Support an Exception Request’ document and associated exception process for the
following reasons: -It is not clear what elements or situations beyond what is
covered in the core definition and associated inclusions and exclusions that the
drafting team is hoping to capture through the exception process. Further, it is
unclear what the benefit to reliability would be by allowing an impact based
exception process given that entities will be extremely unlikely to use the
exception process to include elements in the BES. -The exception process will be
extremely resource intensive, particularly in the absence of any Industry approved
threshold criteria. The costs to properly administer and monitor the process to
ensure that impact based modeling is done accurately and that it captures the
frequent changes on a dynamic system will occupy a wealth of Industry, NERC and
Regional Entity time to the detriment of reliability. -It is not reasonable for industry
to approve the exception process without knowing what thresholds are required
to demonstrate an element as being part of the BES or not. We are concerned that
BES determinations would be subjective and would vary from case to case with the
particular staff examining the request. BES elements should be established and
agreed upon by Industry, not set by a NERC panel. We understand that the drafting
team has made this change in the interests of time, but the impact of the BES
definition is too broad for this project to be rushed. -The 2010-17 project goals to
increase the clarity of the BES definition and establish a ‘bright-line’ are
compromised by the exception process. Changes and alterations to the BES

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

17

Voter

S N Fernando

Entity

Manitoba
Hydro

Segment

5

Vote

Negative

Comment
definition should be approved by Industry through the Standards Under
Development Process. An interpretation request or SAR should be developed by an
entity if they feel that the core definition and associated exceptions and inclusions
should be modified. We ask that NERC requests that FERC re-examines the
directive to develop an exception process given that the BES definition, which
already includes a list of exceptions, is sufficient to standalone without an
associated exception process.
Manitoba Hydro strongly disagrees with the proposed ‘Detailed Information to
Support an Exception Request’ document and associated exception process for the
following reasons: -It is not clear what elements or situations beyond what is
covered in the core definition and associated inclusions and exclusions that the
drafting team is hoping to capture through the exception process. Further, it is
unclear what the benefit to reliability would be by allowing an impact based
exception process given that entities will be extremely unlikely to use the
exception process to include elements in the BES. -The exception process will be
extremely resource intensive, particularly in the absence of any Industry approved
threshold criteria. The costs to properly administer and monitor the process to
ensure that impact based modeling is done accurately and that it captures the
frequent changes on a dynamic system will occupy a wealth of Industry, NERC and
Regional Entity time to the detriment of reliability. -It is not reasonable for industry
to approve the exception process without knowing what thresholds are required
to demonstrate an element as being part of the BES or not. We are concerned that
BES determinations would be subjective and would vary from case to case with the
particular staff examining the request. BES elements should be established and
agreed upon by Industry, not set by a NERC panel. We understand that the drafting
team has made this change in the interests of time, but the impact of the BES
definition is too broad for this project to be rushed. -The 2010-17 project goals to
increase the clarity of the BES definition and establish a ‘bright-line’ are
compromised by the exception process. Changes and alterations to the BES
definition should be approved by Industry through the Standards Under
Development Process. An interpretation request or SAR should be developed by an
entity if they feel that the core definition and associated exceptions and inclusions
should be modified. We ask that NERC requests that FERC re-examines the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

18

Voter

Daniel Prowse

Entity

Manitoba
Hydro

Segment

6

Vote

Negative

Comment
directive to develop an exception process given that the BES definition, which
already includes a list of exceptions, is sufficient to standalone without an
associated exception process.
Manitoba Hydro strongly disagrees with the proposed ‘Detailed Information to
Support an Exception Request’ document and associated exception process for the
following reasons: -It is not clear what elements or situations beyond what is
covered in the core definition and associated inclusions and exclusions that the
drafting team is hoping to capture through the exception process. Further, it is
unclear what the benefit to reliability would be by allowing an impact based
exception process given that entities will be extremely unlikely to use the
exception process to include elements in the BES. -The exception process will be
extremely resource intensive, particularly in the absence of any Industry approved
threshold criteria. The costs to properly administer and monitor the process to
ensure that impact based modeling is done accurately and that it captures the
frequent changes on a dynamic system will occupy a wealth of Industry, NERC and
Regional Entity time to the detriment of reliability. -It is not reasonable for industry
to approve the exception process without knowing what thresholds are required
to demonstrate an element as being part of the BES or not. We are concerned that
BES determinations would be subjective and would vary from case to case with the
particular staff examining the request. BES elements should be established and
agreed upon by Industry, not set by a NERC panel. We understand that the drafting
team has made this change in the interests of time, but the impact of the BES
definition is too broad for this project to be rushed. -The 2010-17 project goals to
increase the clarity of the BES definition and establish a ‘bright-line’ are
compromised by the exception process. Changes and alterations to the BES
definition should be approved by Industry through the Standards Under
Development Process. An interpretation request or SAR should be developed by an
entity if they feel that the core definition and associated exceptions and inclusions
should be modified. We ask that NERC requests that FERC re-examines the
directive to develop an exception process given that the BES definition, which
already includes a list of exceptions, is sufficient to standalone without an
associated exception process.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

19

Voter
Joe D Petaski

Entity
Manitoba
Hydro

Segment
1

Vote
Negative

Danny Dees

MEAG Power

1

Negative

Comment
Manitoba Hydro strongly disagrees with the proposed ‘Detailed Information to
Support an Exception Request’ document and associated exception process for the
following reasons: -It is not clear what elements or situations beyond what is
covered in the core definition and associated inclusions and exclusions that the
drafting team is hoping to capture through the exception process.
Further, it is unclear what the benefit to reliability would be by allowing an impact
based exception process given that entities will be extremely unlikely to use the
exception process to include elements in the BES. -The exception process will be
extremely resource intensive, particularly in the absence of any Industry approved
threshold criteria. The costs to properly administer and monitor the process to
ensure that impact based modeling is done accurately and that it captures the
frequent changes on a dynamic system will occupy a wealth of Industry, NERC and
Regional Entity time to the detriment of reliability. -It is not reasonable for industry
to approve the exception process without knowing what thresholds are required
to demonstrate an element as being part of the BES or not. We are concerned that
BES determinations would be subjective and would vary from case to case with the
particular staff examining the request. BES elements should be established and
agreed upon by Industry, not set by a NERC panel. We understand that the drafting
team has made this change in the interests of time, but the impact of the BES
definition is too broad for this project to be rushed. -The 2010-17 project goals to
increase the clarity of the BES definition and establish a ‘bright-line’ are
compromised by the exception process. Changes and alterations to the BES
definition should be approved by Industry through the Standards Under
Development Process. An interpretation request or SAR should be developed by an
entity if they feel that the core definition and associated exceptions and inclusions
should be modified. We ask that NERC requests that FERC re-examines the
directive to develop an exception process given that the BES definition, which
already includes a list of exceptions, is sufficient to standalone without an
associated exception process.
We believe that the proposed Technical Principles for Demonstrating BES
Exceptions Request does not provide the necessary clarity as to what applying
entities must provide to support their request, nor does it provide any criteria for
consistency among regions in their assessment of requests. We believe that the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

20

Voter

Ernest Hahn

Entity

Metropolitan
Water District
of Southern
California

Segment

1

Vote

Negative

Comment
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective
criteria defining what must be submitted and how to assess the materials
submitted, the current methodology leaves it to each region to develop their own
methodology and criteria for evaluating the submittals. We believe the lack of
clarity regarding what studies must be submitted and what must be demonstrated
by the studies submitted will be overly burdensome on the submitting entity and
the Region, as multiple studies may be required for the two to agree that there is
sufficient justification for an exemption request. We believe that additional work is
necessary to develop clear, objective methods and criteria for identifying which
facilities may be excluded from or should be included in the Bulk Electric System.
Clear, objective methods and criteria will enable the submitter of requests to
understand what is necessary for submitting an exception request and will provide
for consistency among the regions in their initial assessment and
recommendations to the ERO. We believe that a Yes vote for the Technical
Principles for Demonstrating BES Exceptions Request will result in minimal or no
changes to today’s process under the current definition which includes the
language “as defined by the Regional Reliability Organization.” While the proposed
Technical Principles for Demonstrating BES Exceptions Request includes a checklist
that must be submitted with exception requests, a yes vote will still require each
region to develop their own methods and criteria for assessing materials
submitted with exemption requests. We believe that a No vote with guidance to
the drafting team that objective methods and criteria must be developed and
applied continent-wide will result in the desired uniformity and consistency among
regions in their assessment of exception requests. To allow sufficient time to
complete this difficult task, we believe that the Detailed Information to Support
BES Exceptions Request should not be part of the Phase 1 Bulk Electric System
Definition effort, but should be postponed and included in the Phase 2 effort.
MWDSC supports WECC's comments that proposed Technical Information to
Support BES Exceptions does not provide the necessary clarity, nor does it provide
any criteria for consistency among regions. This detail should be postponed and
included in the Phase 2 SAR effort.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

21

Voter
Kevin Smith

Entity
Balancing
Authority of
Northern
California

Segment
1

Vote
Negative

Terry L Baker

Platte River
Power
Authority

3

Negative

Roland Thiel

Platte River
Power
Authority

5

Negative

Comment
We believe that additional work is necessary to develop clear, objective methods
and criteria for identifying which facilities may be excluded from or should be
included in the Bulk Electric System. Clear, objective methods and criteria will
enable the submitter of requests to understand what is necessary for submitting
an exception request and will provide for consistency among the regions in their
initial assessment and recommendations to the ERO.
Platte River believes that a Yes vote for the Technical Principles for Demonstrating
BES Exceptions Request will result in minimal changes to today’s process under the
current definition which includes the language “as defined by the Regional
Reliability Organization.” While the proposed Technical Principles for
Demonstrating BES Exceptions Request includes a checklist that must be submitted
with exception requests, a yes vote will still require each region to develop their
own methods and criteria for assessing materials submitted with exemption
requests. We believe that a No vote with guidance to the drafting team that
objective methods and criteria must be developed and applied continent-wide will
result in the desired uniformity and consistency among regions in their assessment
of exception requests.
Definition of BES Platte River believes that the SDT has made substantial progress
towards a clear and workable definition of the BES. Although Platte River ballots
“Negative” we strongly support the approach to defining the Bulk Electric System
as proposed here. Platte River recognizes that, given the deadlines imposed by
FERC in Order No. 743, it will not be possible for the SDT to conduct a technical
analysis within the time available. Accordingly, Platte River agrees with the
approach taken by the SDT, which is to propose a Phase II of the standards
development process that would address the generator threshold level and other
issues. However, it is our opinion that the second draft would benefit from further
clarification or modification. That said, Platte River is prepared to support the BES
definition as proposed by the SDT going forward. Platte River has taken the
opportunity to provide this industry feedback, as it is our understanding that we
will be afforded another ballot opportunity. If this were to be our sole occasion to
ballot, we would vote “Affirmative” at this time. We are encouraged by the work
that has been completed and we commend the SDT for their commitment and
extensive work thus far. Detailed Information to Support BES Exceptions Requests

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

22

Voter

Entity

Segment

Vote

Carol
Ballantine

Platte River
Power
Authority

6

Negative

John C. Collins

Platte River
Power
Authority

1

Negative

Comment
Platte River believes that a Yes vote for the Technical Principles for Demonstrating
BES Exceptions Request will result in minimal changes to today’s process under the
current definition which includes the language “as defined by the Regional
Reliability Organization.” While the proposed Technical Principles for
Demonstrating BES Exceptions Request includes a checklist that must be submitted
with exception requests, a yes vote will still require each region to develop their
own methods and criteria for assessing materials submitted with exemption
requests. We believe that a No vote with guidance to the drafting team that
objective methods and criteria must be developed and applied continent-wide will
result in the desired uniformity and consistency among regions in their assessment
of exception requests.
Platte River believes that a Yes vote for the Technical Principles for Demonstrating
BES Exceptions Request will result in minimal changes to today’s process under the
current definition which includes the language “as defined by the Regional
Reliability Organization.” While the proposed Technical Principles for
Demonstrating BES Exceptions Request includes a checklist that must be submitted
with exception requests, a yes vote will still require each region to develop their
own methods and criteria for assessing materials submitted with exemption
requests. We believe that a No vote with guidance to the drafting team that
objective methods and criteria must be developed and applied continent-wide will
result in the desired uniformity and consistency among regions in their assessment
of exception requests.
Platte River believes that a Yes vote for the Technical Principles for Demonstrating
BES Exceptions Request will result in minimal changes to today’s process under the
current definition which includes the language “as defined by the Regional
Reliability Organization.” While the proposed Technical Principles for
Demonstrating BES Exceptions Request includes a checklist that must be submitted
with exception requests, a yes vote will still require each region to develop their
own methods and criteria for assessing materials submitted with exemption
requests. We believe that a No vote with guidance to the drafting team that
objective methods and criteria must be developed and applied continent-wide will
result in the desired uniformity and consistency among regions in their assessment
of exception requests.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

23

Voter
Dana
Wheelock

Entity
Seattle City
Light

Segment
3

Vote
Negative

Hao Li

Seattle City
Light

4

Negative

Comment
Comments: Seattle City Light (SCL) believes that the SDT has made substantial
progress towards a clear and workable definition of the BES. Although SCL ballots
“Negative” we agree with and strongly support the Technical Exceptions Principles
as a concept. However, SCL finds that the Principles as written do not provide the
necessary clarity as what applying entities must provide to support their request,
nor do they provide adequate criteria for consistency among regions in their
assessment of requests. SCL recommends the development of objective methods
and criteria for identifying which facilities may be excluded from or included in the
BES. SCL also recommends the development of one or more examples that
illustrate what studies must be submitted and what must be documented as part
of an exception request. SCL recognizes that, given the deadlines imposed by FERC
in Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address issues such as the exception process. SCL has taken the opportunity
to provide this industry feedback, as it is our understanding that we will be
afforded another ballot opportunity. If this were to be our sole occasion to ballot,
we would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far. SCL is prepared to support the BES Exception process as proposed
by the SDT going forward.
Comments: Seattle City Light (SCL) believes that the SDT has made substantial
progress towards a clear and workable definition of the BES. Although SCL ballots
“Negative” we agree with and strongly support the Technical Exceptions Principles
as a concept. However, SCL finds that the Principles as written do not provide the
necessary clarity as what applying entities must provide to support their request,
nor do they provide adequate criteria for consistency among regions in their
assessment of requests. SCL recommends the development of objective methods
and criteria for identifying which facilities may be excluded from or included in the
BES. SCL also recommends the development of one or more examples that
illustrate what studies must be submitted and what must be documented as part
of an exception request. SCL recognizes that, given the deadlines imposed by FERC
in Order No. 743, it will not be possible for the SDT to conduct a technical analysis

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

24

Voter

Entity

Segment

Vote

Michael J.
Haynes

Seattle City
Light

5

Negative

Dennis Sismaet

Seattle City
Light

6

Negative

Comment
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address issues such as the exception process. SCL has taken the opportunity
to provide this industry feedback, as it is our understanding that we will be
afforded another ballot opportunity. If this were to be our sole occasion to ballot,
we would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far. SCL is prepared to support the BES Exception process as proposed
by the SDT going forward.
Comments: Seattle City Light (SCL) believes that the SDT has made substantial
progress towards a clear and workable definition of the BES. Although SCL ballots
“Negative” we agree with and strongly support the Technical Exceptions Principles
as a concept. However, SCL finds that the Principles as written do not provide the
necessary clarity as what applying entities must provide to support their request,
nor do they provide adequate criteria for consistency among regions in their
assessment of requests. SCL recommends the development of objective methods
and criteria for identifying which facilities may be excluded from or included in the
BES. SCL also recommends the development of one or more examples that
illustrate what studies must be submitted and what must be documented as part
of an exception request. SCL recognizes that, given the deadlines imposed by FERC
in Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address issues such as the exception process. SCL has taken the opportunity
to provide this industry feedback, as it is our understanding that we will be
afforded another ballot opportunity. If this were to be our sole occasion to ballot,
we would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far. SCL is prepared to support the BES Exception process as proposed
by the SDT going forward.
Comments: Seattle City Light (SCL) believes that the SDT has made substantial
progress towards a clear and workable definition of the BES. Although SCL ballots
“Negative” we agree with and strongly support the Technical Exceptions Principles

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

25

Voter

Pawel Krupa

Entity

Seattle City
Light

Segment

1

Vote

Negative

Comment
as a concept. However, SCL finds that the Principles as written do not provide the
necessary clarity as what applying entities must provide to support their request,
nor do they provide adequate criteria for consistency among regions in their
assessment of requests. SCL recommends the development of objective methods
and criteria for identifying which facilities may be excluded from or included in the
BES. SCL also recommends the development of one or more examples that
illustrate what studies must be submitted and what must be documented as part
of an exception request. SCL recognizes that, given the deadlines imposed by FERC
in Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address issues such as the exception process. SCL has taken the opportunity
to provide this industry feedback, as it is our understanding that we will be
afforded another ballot opportunity. If this were to be our sole occasion to ballot,
we would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far. SCL is prepared to support the BES Exception process as proposed
by the SDT going forward.
Comments: Seattle City Light (SCL) believes that the SDT has made substantial
progress towards a clear and workable definition of the BES. Although SCL ballots
“Negative” we agree with and strongly support the Technical Exceptions Principles
as a concept. However, SCL finds that the Principles as written do not provide the
necessary clarity as what applying entities must provide to support their request,
nor do they provide adequate criteria for consistency among regions in their
assessment of requests. SCL recommends the development of objective methods
and criteria for identifying which facilities may be excluded from or included in the
BES. SCL also recommends the development of one or more examples that
illustrate what studies must be submitted and what must be documented as part
of an exception request. SCL recognizes that, given the deadlines imposed by FERC
in Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address issues such as the exception process. SCL has taken the opportunity

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

26

Voter

Entity

Segment

Vote

Tim Kelley

Sacramento
Municipal
Utility District

1

Negative

Richard K Vine

California ISO

2

Negative

Barbara
Independent
Constantinescu Electricity

2

Negative

Comment
to provide this industry feedback, as it is our understanding that we will be
afforded another ballot opportunity. If this were to be our sole occasion to ballot,
we would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far. SCL is prepared to support the BES Exception process as proposed
by the SDT going forward.
We believe that additional work is necessary to develop clear, objective methods
and criteria for identifying which facilities may be excluded from or should be
included in the Bulk Electric System. Clear, objective methods and criteria will
enable the submitter of requests to understand what is necessary for submitting
an exception request and will provide for consistency among the regions in their
initial assessment and recommendations to the ERO.
The ISO believes that the proposed Technical Principles for Demonstrating BES
Exceptions Request does not provide the necessary clarity as to what applying
entities must provide to support their request, nor does it provide any criteria for
consistency among regions in their assessment of requests. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective
criteria defining what must be submitted and how to assess the materials
submitted, the current methodology leaves it to each region to develop their own
methodology and criteria for evaluating the submittals. The lack of clarity
regarding what studies must be submitted and what must be demonstrated by the
studies submitted will be overly burdensome on the submitting entity and the
Region, as multiple studies may be required for the two to agree that there is
sufficient justification for an exemption request. The ISO believes that additional
work is necessary to develop clear, objective methods and criteria for identifying
which facilities may be excluded from or should be included in the Bulk Electric
System. Clear, objective methods and criteria will enable the submitter of requests
to understand what is necessary for submitting an exception request and will
provide for consistency among the regions in their initial assessment and
recommendations to the ERO.
We believe that the SDT proposed approach for exception criteria is reasonable
recognizing that one method/criteria cannot be applicable to everyone and every

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

27

Voter

Alden Briggs

Steven Grego

Entity
System
Operator

Segment

Vote

New
Brunswick
System
Operator
MEAG Power

2

Negative

5

Negative

Comment
situation within the ERO foot print. However, we believe that there is huge gap
and lack of any transparency on how the exception application will be evaluated
and processed. We strongly suggest that SDT develop a reference or a guidance
document as part of the RoP that should provide some guidance to Registered
Entities, Regional Entities and the ERO on how an exception application should be
processed. The absence of such guidance will pose a challenge for each entity
including the ERO, and may result in discrepancies amongst Regional Entities. The
process may be perceived by registered entities as being non-transparency.
The NBSO has concern about the lack of clarity and specificity with respect to what
analyses and study results are required. This lack of clarity and specificity may lead
to inconsistent application of the Technical Principles by both Registered Entities
and Regional Entities.
We believe that the proposed Technical Principles for Demonstrating BES
Exceptions Request does not provide the necessary clarity as to what applying
entities must provide to support their request, nor does it provide any criteria for
consistency among regions in their assessment of requests. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective
criteria defining what must be submitted and how to assess the materials
submitted, the current methodology leaves it to each region to develop their own
methodology and criteria for evaluating the submittals. We believe the lack of
clarity regarding what studies must be submitted and what must be demonstrated
by the studies submitted will be overly burdensome on the submitting entity and
the Region, as multiple studies may be required for the two to agree that there is
sufficient justification for an exemption request. We believe that additional work is
necessary to develop clear, objective methods and criteria for identifying which
facilities may be excluded from or should be included in the Bulk Electric System.
Clear, objective methods and criteria will enable the submitter of requests to
understand what is necessary for submitting an exception request and will provide
for consistency among the regions in their initial assessment and
recommendations to the ERO. We believe that a Yes vote for the Technical
Principles for Demonstrating BES Exceptions Request will result in minimal or no
changes to today’s process under the current definition which includes the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

28

Voter

Steven M.
Jackson

Entity

Municipal
Electric
Authority of
Georgia

Segment

3

Vote

Negative

Comment
language “as defined by the Regional Reliability Organization.” While the proposed
Technical Principles for Demonstrating BES Exceptions Request includes a checklist
that must be submitted with exception requests, a yes vote will still require each
region to develop their own methods and criteria for assessing materials
submitted with exemption requests. We believe that a No vote with guidance to
the drafting team that objective methods and criteria must be developed and
applied continent-wide will result in the desired uniformity and consistency among
regions in their assessment of exception requests. To allow sufficient time to
complete this difficult task, we believe that the Detailed Information to Support
BES Exceptions Request should not be part of the Phase 1 Bulk Electric System
Definition effort, but should be postponed and included in the Phase 2 effort.
We believe that the proposed Technical Principles for Demonstrating BES
Exceptions Request does not provide the necessary clarity as to what applying
entities must provide to support their request, nor does it provide any criteria for
consistency among regions in their assessment of requests. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective
criteria defining what must be submitted and how to assess the materials
submitted, the current methodology leaves it to each region to develop their own
methodology and criteria for evaluating the submittals. We believe the lack of
clarity regarding what studies must be submitted and what must be demonstrated
by the studies submitted will be overly burdensome on the submitting entity and
the Region, as multiple studies may be required for the two to agree that there is
sufficient justification for an exemption request. We believe that additional work is
necessary to develop clear, objective methods and criteria for identifying which
facilities may be excluded from or should be included in the Bulk Electric System.
Clear, objective methods and criteria will enable the submitter of requests to
understand what is necessary for submitting an exception request and will provide
for consistency among the regions in their initial assessment and
recommendations to the ERO. We believe that a Yes vote for the Technical
Principles for Demonstrating BES Exceptions Request will result in minimal or no
changes to today’s process under the current definition which includes the
language “as defined by the Regional Reliability Organization.” While the proposed

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

29

Voter

Entity

Segment

Vote

John H Hagen

Pacific Gas and
Electric
Company

3

Negative

Mike Ramirez

Sacramento
Municipal
Utility District

4

Negative

Bethany
Hunter

Sacramento
Municipal
Utility District

5

Negative

Claire
Warshaw

Sacramento
Municipal
Utility District

6

Negative

Comment
Technical Principles for Demonstrating BES Exceptions Request includes a checklist
that must be submitted with exception requests, a yes vote will still require each
region to develop their own methods and criteria for assessing materials
submitted with exemption requests. We believe that a No vote with guidance to
the drafting team that objective methods and criteria must be developed and
applied continent-wide will result in the desired uniformity and consistency among
regions in their assessment of exception requests. To allow sufficient time to
complete this difficult task, we believe that the Detailed Information to Support
BES Exceptions Request should not be part of the Phase 1 Bulk Electric System
Definition effort, but should be postponed and included in the Phase 2 effort.
This does not provide clarity on the criteria that will be used to manage the
inclusion/exclusion process. Leaving it up to the regions will only create variances
that this effort was chartered to eliminate. To support a bright line BES defintion,
the exclusion process must not have subjective results baed on regional variances.
We may be better off without an exclusion process and include the exclusions as
written into the definition.
We believe that additional work is necessary to develop clear, objective methods
and criteria for identifying which facilities may be excluded from or should be
included in the Bulk Electric System. Clear, objective methods and criteria will
enable the submitter of requests to understand what is necessary for submitting
an exception request and will provide for consistency among the regions in their
initial assessment and recommendations to the ERO.
We believe that additional work is necessary to develop clear, objective methods
and criteria for identifying which facilities may be excluded from or should be
included in the Bulk Electric System. Clear, objective methods and criteria will
enable the submitter of requests to understand what is necessary for submitting
an exception request and will provide for consistency among the regions in their
initial assessment and recommendations to the ERO.
We believe that additional work is necessary to develop clear, objective methods
and criteria for identifying which facilities may be excluded from or should be
included in the Bulk Electric System. Clear, objective methods and criteria will
enable the submitter of requests to understand what is necessary for submitting
an exception request and will provide for consistency among the regions in their

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

30

Voter

Entity

Segment

Vote

James LeighKendall

Sacramento
Municipal
Utility District

3

Negative

Mark B
Thompson

Alberta
Electric System
Operator

2

Negative

Lisa C
Rosintoski

Colorado
Springs
Utilities

6

Negative

Comment
initial assessment and recommendations to the ERO.
We believe that additional work is necessary to develop clear, objective methods
and criteria for identifying which facilities may be excluded from or should be
included in the Bulk Electric System. Clear, objective methods and criteria will
enable the submitter of requests to understand what is necessary for submitting
an exception request and will provide for consistency among the regions in their
initial assessment and recommendations to the ERO.
The AESO agrees with the WECC, who say: WECC Staff believes that the proposed
Technical Principles for Demonstrating BES Exceptions Request does not provide
the necessary clarity as to what applying entities must provide to support their
request, nor does it provide any criteria for consistency among regions in their
assessment of requests. We believe that the checklist items for transmission and
generation facilities are appropriate questions that must be answered in
considering all requests. However, without objective criteria defining what must
be submitted and how to assess the materials submitted, the current methodology
leaves it to each region to develop their own methodology and criteria for
evaluating the submittals. We believe the lack of clarity regarding what studies
must be submitted and what must be demonstrated by the studies submitted will
be overly burdensome on the submitting entity and the Region, as multiple studies
may be required for the two to agree that there is sufficient justification for an
exemption request. We believe that additional work is necessary to develop clear,
objective methods and criteria for identifying which facilities may be excluded
from or should be included in the Bulk Electric System. Clear, objective methods
and criteria will enable the submitter of requests to understand what is necessary
for submitting an exception request and will provide for consistency among the
regions in their initial assessment and recommendations to the ERO.
Colorado Springs Utilities believes that the proposed Technical Information to
Support BES Exceptions Request does not provide the necessary clarity as to what
applying entities must provide to support their request. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. We believe the lack of clarity
regarding what studies must be submitted and what must be demonstrated by the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

31

Voter

Entity

Segment

Vote

Jennifer Eckels

Colorado
Springs
Utilities

5

Negative

Spencer Tacke

Modesto
Irrigation
District

4

Negative

Comment
studies submitted will be overly burdensome on our staff. We believe that
additional work is necessary to develop clear, objective methods and criteria for
identifying which facilities may be excluded from or should be included in the Bulk
Electric System. Clear, objective methods and criteria will enable us to understand
what is necessary for submitting an exception request. To allow sufficient time to
complete this difficult task, we believe that the Detailed Information to Support
BES Exceptions Request should not be part of the Phase 1 Bulk Electric System
Definition effort, but should be postponed and included in the Phase 2 effort.
Colorado Springs Utilities believes that the proposed Technical Information to
Support BES Exceptions Request does not provide the necessary clarity as to what
applying entities must provide to support their request. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. We believe the lack of clarity
regarding what studies must be submitted and what must be demonstrated by the
studies submitted will be overly burdensome on our staff. We believe that
additional work is necessary to develop clear, objective methods and criteria for
identifying which facilities may be excluded from or should be included in the Bulk
Electric System. Clear, objective methods and criteria will enable us to understand
what is necessary for submitting an exception request. To allow sufficient time to
complete this difficult task, we believe that the Detailed Information to Support
BES Exceptions Request should not be part of the Phase 1 Bulk Electric System
Definition effort, but should be postponed and included in the Phase 2 effort.
We believe that the proposed Technical Principles for Demonstrating BES
Exceptions Request does not provide the necessary clarity as to what applying
entities must provide to support their request, nor does it provide any criteria for
consistency among regions in their assessment of requests. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective
criteria defining what must be submitted and how to assess the materials
submitted, the current methodology leaves it to each region to develop their own
methodology and criteria for evaluating the submittals. We believe the lack of
clarity regarding what studies must be submitted and what must be demonstrated
by the studies submitted will be overly burdensome on the submitting entity and

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

32

Voter

Entity

Segment

William M
Chamberlain

California
Energy
Commission

9

Allen Mosher

American
Public Power
Association

4

Vote

Comment
the Region, as multiple studies may be required for the two to agree that there is
sufficient justification for an exemption request. We believe that additional work is
necessary to develop clear, objective methods and criteria for identifying which
facilities may be excluded from or should be included in the Bulk Electric System.
Clear, objective methods and criteria will enable the submitter of requests to
understand what is necessary for submitting an exception request and will provide
for consistency among the regions in their initial assessment and
recommendations to the ERO. Thank you.
Negative
We agree with WECC that the proposed Technical Principles for Demonstrating
BES Exceptions Request does not provide the necessary clarity as to what applying
entities must provide to support their request, nor does it provide any criteria for
consistency among regions in their assessment of requests. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective
criteria defining what must be submitted and how to assess the materials
submitted, the current methodology leaves it to each region to develop their own
methodology and criteria for evaluating the submittals. We believe the lack of
clarity regarding what studies must be submitted and what must be demonstrated
by the studies submitted will be overly burdensome on the submitting entity and
the Region, as multiple studies may be required for the two to agree that there is
sufficient justification for an exemption request. We believe that additional work is
necessary to develop clear, objective methods and criteria for identifying which
facilities may be excluded from or should be included in the Bulk Electric System.
Clear, objective methods and criteria will enable the submitter of requests to
understand what is necessary for submitting an exception request and will provide
for consistency among the regions in their initial assessment and
recommendations to the ERO. We are voting No to allow the drafting team to
develop objective methods and criteria that can be applied continent-wide,
resulting in the desired uniformity and consistency among regions in their
assessment of exception requests.
Affirmative See comments submitted in response to BES Definition. APPA also requests more
specificity on the detailed information required to support BES exceptions
processed through the NERC Rules of Procedure drafting process. Additional

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

33

Voter

Entity

Segment

Vote

Comment
technical specificity will help ensure consistency between regions and
transparency for registered entities on the technical studies and data required to
support exception requests. These issues should be addressed in Phase 2.
Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and
an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could
have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the
commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive
comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the
Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of
the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of
the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting
or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis
for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making
their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

34

Voter
Entity
Segment
Vote
Comment
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric
system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the
technical prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests
will result in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
3
Negative
1. Page one of the ‘Detailed Information to Support an Exception Request’
Marilyn Brown New York
contains general instructions. Do you agree with the instructions presented or is
Power
there information that you believe needs to be on page one that is missing? Please
Authority
be as specific as possible with your comments. Yes: X No: Comments: No
comments. 2. Pages two and three of the Detailed Information to Support an
Exception Request contain a checklist of items that deal with transmission
facilities. Do you agree with the information being requested or is there
information that you believe needs to be on page two or three that is missing?
Please be as specific as possible with your comments. Yes: No: X Comments: For
Question 2 on page 2, recommend that the specific types of studies to be provided
are defined to add consistency and transparency to the Exception request process.
Recommend that the concept and the words “material to” be included as part of
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

35

Voter

Entity

Segment

Vote

Comment
the question as follows “Is the facility material to permanent Flowgates in the
Eastern Interconnection.....” For Question 4 on page 2, recommend that single
contingency analysis be performed and submitted to demonstrate impacts to the
BES. For Question 6 on page 3, recommend that “Cranking Path” be removed to be
consistent with the draft BES Definition. Recommend that the concept and the
words “material to and designated as part of” be included as part of the question.
Recommend rewording Question 6 as follows “Is the facility a Blackstart resource
material to and designated as part of the Transmission Operator’s restoration
plan?” For Question 7 on page 3, facilities less than two years old or under
construction would not be able to provide SCADA data for the most recent
consecutive two calendar year period. Facility rating changes and the magnitude of
such changes which trigger application or reapplication of the exception process
are not addressed. Recommend that Question 7 be revised to address these
issues. 3. Page four of the ‘Detailed Information to Support an Exception Request’
contains a checklist of items that deal with generation facilities. Do you agree with
the information being requested or is there information that you believe needs to
be on page four that is missing? Please be as specific as possible with your
comments. Yes: No: X Comment Form for 2nd Draft of Project 2010-17: Definition
of BES (BES) Technical Principles for Demonstrating BES Exceptions Page 4 of 5
Comments: For Question 2 on page 4, recommend that the specific generator
ancillary service products be defined to add consistency and transparency to the
Exception Request process. For Question 3 on page 4, recommend that
confirmation of must-run generation be provided by the Reliability Coordinator,
Reliability Planner, or the Balancing Authority as a clarification to the “appropriate
reference”. 4. Do you have concerns about an entity’s ability to obtain the data
they would need to file the ‘Detailed Information to Support an Exception
Request’? If so, please be specific with your concerns so that the SDT can fully
understand the problem. Yes: No: X Comments: No comments. Comment Form for
2nd Draft of Project 2010-17: Definition of BES (BES) Technical Principles for
Demonstrating BES Exceptions Page 5 of 5 5. Are there other specific
characteristics that you feel would be important for presenting a case and which
are generic enough that they belong in the request? If so, please identify them
here and provide suggested language that could be added to the document. Yes:

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

36

Voter

Gerald
Mannarino

Entity

New York
Power
Authority

Segment

5

Vote

Negative

Comment
No: X Comments: No comments. 6. Are you aware of any conflicts between the
proposed approach and any regulatory function, rule order, tariff, rate schedule,
legislative requirement or agreement, or jurisdictional issue? If so, please identify
them here and provide suggested language changes that may clarify the issue. Yes:
No: X Comments: No comments. 7. Are there any other concerns with the
proposed approach for demonstrating BES Exceptions that haven’t been covered
in previous questions and comments (bearing in mind that the definition itself and
the proposed Rules of Procedure changes are posted separately for comments)?
Please be as specific as possible with your comments. Yes: X No: Comments:
Completing the exception form does not provide the entity with any indication of
whether the Exception will be granted or rejected. It would be more effective and
efficient to revise the Exception request questions to provide confirmation or
rejection after completion of the form. Consistent application of the exception
process across regions may become challenging with separate exception request
review teams.
Comments: For Question 2 on page 2, recommend that the specific types of
studies to be provided are defined to add consistency and transparency to the
Exception request process. Recommend that the concept and the words “material
to” be included as part of the question as follows “Is the facility material to
permanent Flowgates in the Eastern Interconnection.....” For Question 4 on page
2, recommend that single contingency analysis be performed and submitted to
demonstrate impacts to the BES. For Question 6 on page 3, recommend that
“Cranking Path” be removed to be consistent with the draft BES Definition.
Recommend that the concept and the words “material to and designated as part
of” be included as part of the question. Recommend rewording Question 6 as
follows “Is the facility a Blackstart resource material to and designated as part of
the Transmission Operator’s restoration plan?” For Question 7 on page 3, facilities
less than two years old or under construction would not be able to provide SCADA
data for the most recent consecutive two calendar year period. Facility rating
changes and the magnitude of such changes which trigger application or
reapplication of the exception process are not addressed. Recommend that
Question 7 be revised to address these issues. Comments: For Question 2 on page
4, recommend that the specific generator ancillary service products be defined to

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

37

Voter

William
Palazzo

Entity

New York
Power
Authority

Segment

6

Vote

Negative

Comment
add consistency and transparency to the Exception Request process. For Question
3 on page 4, recommend that confirmation of must-run generation be provided by
the Reliability Coordinator, Reliability Planner, or the Balancing Authority as a
clarification to the “appropriate reference”.
1. Page one of the ‘Detailed Information to Support an Exception Request’
contains general instructions. Do you agree with the instructions presented or is
there information that you believe needs to be on page one that is missing? Please
be as specific as possible with your comments. Yes: X No: Comments: No
comments. 2. Pages two and three of the Detailed Information to Support an
Exception Request contain a checklist of items that deal with transmission
facilities. Do you agree with the information being requested or is there
information that you believe needs to be on page two or three that is missing?
Please be as specific as possible with your comments. Yes: No: X Comments: For
Question 2 on page 2, recommend that the specific types of studies to be provided
are defined to add consistency and transparency to the Exception request process.
Recommend that the concept and the words “material to” be included as part of
the question as follows “Is the facility material to permanent Flowgates in the
Eastern Interconnection.....” For Question 4 on page 2, recommend that single
contingency analysis be performed and submitted to demonstrate impacts to the
BES. For Question 6 on page 3, recommend that “Cranking Path” be removed to be
consistent with the draft BES Definition. Recommend that the concept and the
words “material to and designated as part of” be included as part of the question.
Recommend rewording Question 6 as follows “Is the facility a Blackstart resource
material to and designated as part of the Transmission Operator’s restoration
plan?” For Question 7 on page 3, facilities less than two years old or under
construction would not be able to provide SCADA data for the most recent
consecutive two calendar year period. Facility rating changes and the magnitude of
such changes which trigger application or reapplication of the exception process
are not addressed. Recommend that Question 7 be revised to address these
issues. 3. Page four of the ‘Detailed Information to Support an Exception Request’
contains a checklist of items that deal with generation facilities. Do you agree with
the information being requested or is there information that you believe needs to
be on page four that is missing? Please be as specific as possible with your

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

38

Voter

Arnold J.
Schuff

Entity

New York
Power
Authority

Segment

1

Vote

Negative

Comment
comments. Yes: No: X Comments: For Question 2 on page 4, recommend that the
specific generator ancillary service products be defined to add consistency and
transparency to the Exception Request process. For Question 3 on page 4,
recommend that confirmation of must-run generation be provided by the
Reliability Coordinator, Reliability Planner, or the Balancing Authority as a
clarification to the “appropriate reference”. 4. Do you have concerns about an
entity’s ability to obtain the data they would need to file the ‘Detailed Information
to Support an Exception Request’? If so, please be specific with your concerns so
that the SDT can fully understand the problem. Yes: No: X Comments: No
comments.
You do not have to answer all questions. Enter all comments in simple text format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas. 1.
Page one of the ‘Detailed Information to Support an Exception Request’ contains
general instructions. Do you agree with the instructions presented or is there
information that you believe needs to be on page one that is missing? Please be as
specific as possible with your comments. Yes: X No: Comments: No comments.
2. Pages two and three of the Detailed Information to Support an Exception
Request contain a checklist of items that deal with transmission facilities. Do you
agree with the information being requested or is there information that you
believe needs to be on page two or three that is missing? Please be as specific as
possible with your comments. Yes: No: X Comments: For Question 2 on page 2,
recommend that the specific types of studies to be provided are defined to add
consistency and transparency to the Exception request process.
Recommend that the concept and the words “material to” be included as part of
the question as follows “Is the facility material to permanent Flowgates in the
Eastern Interconnection.....”
For Question 4 on page 2, recommend that single contingency analysis be
performed and submitted to demonstrate impacts to the BES.
For Question 6 on page 3, recommend that “Cranking Path” be removed to be
consistent with the draft BES Definition. Recommend that the concept and the
words “material to and designated as part of” be included as part of the question.
Recommend rewording Question 6 as follows “Is the facility a Blackstart resource
material to and designated as part of the Transmission Operator’s restoration

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

39

Voter

Entity

Segment

Vote

Comment
plan?”
For Question 7 on page 3, facilities less than two years old or under construction
would not be able to provide SCADA data for the most recent consecutive two
calendar year period. Facility rating changes and the magnitude of such changes
which trigger application or reapplication of the exception process are not
addressed. Recommend that Question 7 be revised to address these issues.
3. Page four of the ‘Detailed Information to Support an Exception Request’
contains a checklist of items that deal with generation facilities. Do you agree with
the information being requested or is there information that you believe needs to
be on page four that is missing? Please be as specific as possible with your
comments. Yes: No: X Comments: For Question 2 on page 4, recommend that the
specific generator ancillary service products be defined to add consistency and
transparency to the Exception Request process.
For Question 3 on page 4, recommend that confirmation of must-run generation
be provided by the Reliability Coordinator, Reliability Planner, or the Balancing
Authority as a clarification to the “appropriate reference”.
4. Do you have concerns about an entity’s ability to obtain the data they would
need to file the ‘Detailed Information to Support an Exception Request’? If so,
please be specific with your concerns so that the SDT can fully understand the
problem. Yes: No: X Comments: No comments.
5. Are there other specific characteristics that you feel would be important for
presenting a case and which are generic enough that they belong in the request? If
so, please identify them here and provide suggested language that could be added
to the document. Yes: No: X Comments: No comments.
6. Are you aware of any conflicts between the proposed approach and any
regulatory function, rule order, tariff, rate schedule, legislative requirement or
agreement, or jurisdictional issue? If so, please identify them here and provide
suggested language changes that may clarify the issue. Yes: No: X Comments: No
comments.
7. Are there any other concerns with the proposed approach for demonstrating
BES Exceptions that haven’t been covered in previous questions and comments
(bearing in mind that the definition itself and the proposed Rules of Procedure
changes are posted separately for comments)? Please be as specific as possible

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

40

Voter

Entity

Segment

Vote

Comment
with your comments. Yes: X No: Comments: Completing the exception form does
not provide the entity with any indication of whether the Exception will be granted
or rejected. It would be more effective and efficient to revise the Exception
request questions to provide confirmation or rejection after completion of the
form. Consistent application of the exception process across regions may become
challenging with separate exception request review teams.

Response: 1. Thank you for your support.
2. See response to #10 below. Material is an unmeasurable concept. No change made. The SDT believes that an entity should follow the TPL
methodology in formulating its request. If the entity believes that an n-1 analysis is all that is needed then it can submit just an n-1 analysis. No
change made. Cranking Path information is just one piece of information that may be of value to the ERO Panel in making its decision. No
change made. If two years worth of data are not available, the SDT believes that a Regional Entity will accept what is available and will work
with the submitter to come up with an acceptable plan to move forward.
3. Ancillary service products differ from region to region so providing a list in the form would be problematic. The form has sufficient flexibility
for the entity to specify which products it is dealing with. However, the SDT has clarified the language concerning ancillary service products and
must run units to indicate that only reliability-based information is pertinent.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Q3. Is the generator generation resource designated as a must run unit for reliability?
4. 5. & 6. Without a specific comment, the SDT is unable to respond.
7. The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like
nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and an
initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could
have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the
commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive
comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

41

Voter
Entity
Segment
Vote
Comment
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the
Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of
the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of
the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting
or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis
for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making
their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric
system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the
technical prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests
will result in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

42

Voter
Entity
Segment
Vote
Comment
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
Doug
Omaha Public
1
Negative
The technical document on exceptions is appropriate, but there should be a
Peterchuck
Power District
guideline on what a typical exception is. The guideline can easily be created by
what is now listed within the four-item “Exclusion List”. For example when looking
at the current Local Network exclusion (E3), it looks to be based on a regional
request and thus is in direct conflict with FERC’s order. We interpret the creation
of a technical document regarding a proposed BES exclusion as a case that should
be examined during the Exception Process and not during the BES definition
process. The simple question that FERC could eventually ask is why don’t all listed
exclusions include a technical justification?
Response: The SDT did not provide a technical justification for items that are simply being copied from the existing definition. Technical
justification was only provided for items that are new with this revision.
John T.
Underhill

Salt River
Project

3

Negative

Definition of Bulk Electric System (BES) The Blackstart “Cranking Path” has been
deleted from Inclusion 3 of the BES definition. However, NERC standards EOP-005
and CIP-002, R1.2.4 require documenting the Cranking Path. In addition, CIP-002-4
identifies the Cranking Path as a Critical Asset in Attachment 1. Compliance to the
NERC Standards needs to be an exact science whenever possible. SRP does not
argue the inclusion or exclusion of Cranking Path. However, if it is excluded,
guidance must be provided on whether or not a Cranking Path is subject to the
previously mentioned Standards. Detailed Information to Support BES Exceptions
Request SRP agrees with the WECC Staff recommendation on the “Detailed
Information to Support BES Exceptions Request.” “WECC Staff believes that the
proposed Technical Principles for Demonstrating BES Exceptions Request does not
provide the necessary clarity as to what applying entities must provide to support

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Steven J Hulet

Entity

Salt River
Project

Segment

6

Vote

Negative

Comment
their request, nor does it provide any criteria for consistency among regions in
their assessment of requests. We believe that the checklist items for transmission
and generation facilities are appropriate questions that must be answered in
considering all requests. However, without objective criteria defining what must
be submitted and how to assess the materials submitted, the current methodology
leaves it to each region to develop their own methodology and criteria for
evaluating the submittals. We believe the lack of clarity regarding what studies
must be submitted and what must be demonstrated by the studies submitted will
be overly burdensome on the submitting entity and the Region, as multiple studies
may be required for the two to agree that there is sufficient justification for an
exemption request. We believe that additional work is necessary to develop clear,
objective methods and criteria for identifying which facilities may be excluded
from or should be included in the Bulk Electric System. Clear, objective methods
and criteria will enable the submitter of requests to understand what is necessary
for submitting an exception request and will provide for consistency among the
regions in their initial assessment and recommendations to the ERO.”
SRP agrees with the WECC Staff recommendation on the “Detailed Information to
Support BES Exceptions Request.” “WECC Staff believes that the proposed
Technical Principles for Demonstrating BES Exceptions Request does not provide
the necessary clarity as to what applying entities must provide to support their
request, nor does it provide any criteria for consistency among regions in their
assessment of requests. We believe that the checklist items for transmission and
generation facilities are appropriate questions that must be answered in
considering all requests. However, without objective criteria defining what must
be submitted and how to assess the materials submitted, the current methodology
leaves it to each region to develop their own methodology and criteria for
evaluating the submittals. We believe the lack of clarity regarding what studies
must be submitted and what must be demonstrated by the studies submitted will
be overly burdensome on the submitting entity and the Region, as multiple studies
may be required for the two to agree that there is sufficient justification for an
exemption request. We believe that additional work is necessary to develop clear,
objective methods and criteria for identifying which facilities may be excluded
from or should be included in the Bulk Electric System. Clear, objective methods

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Voter

Robert
Kondziolka

Entity

Salt River
Project

Segment

1

Vote

Negative

Comment
and criteria will enable the submitter of requests to understand what is necessary
for submitting an exception request and will provide for consistency among the
regions in their initial assessment and recommendations to the ERO.”
Definition of Bulk Electric System (BES) The Blackstart “Cranking Path” has been
deleted from Inclusion 3 of the BES definition. However, NERC standards EOP-005
and CIP-002, R1.2.4 require documenting the Cranking Path. In addition, CIP-002-4
identifies the Cranking Path as a Critical Asset in Attachment 1. Compliance to the
NERC Standards needs to be an exact science whenever possible. SRP does not
argue the inclusion or exclusion of Cranking Path. However, if it is excluded,
guidance must be provided on whether or not a Cranking Path is subject to the
previously mentioned Standards.
Detailed Information to Support BES Exceptions Request SRP agrees with the
WECC Staff recommendation on the “Detailed Information to Support BES
Exceptions Request.” “WECC Staff believes that the proposed Technical Principles
for Demonstrating BES Exceptions Request does not provide the necessary clarity
as to what applying entities must provide to support their request, nor does it
provide any criteria for consistency among regions in their assessment of requests.
We believe that the checklist items for transmission and generation facilities are
appropriate questions that must be answered in considering all requests.
However, without objective criteria defining what must be submitted and how to
assess the materials submitted, the current methodology leaves it to each region
to develop their own methodology and criteria for evaluating the submittals. We
believe the lack of clarity regarding what studies must be submitted and what
must be demonstrated by the studies submitted will be overly burdensome on the
submitting entity and the Region, as multiple studies may be required for the two
to agree that there is sufficient justification for an exemption request. We believe
that additional work is necessary to develop clear, objective methods and criteria
for identifying which facilities may be excluded from or should be included in the
Bulk Electric System. Clear, objective methods and criteria will enable the
submitter of requests to understand what is necessary for submitting an exception
request and will provide for consistency among the regions in their initial
assessment and recommendations to the ERO.”

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Response: Cranking Path information is just one piece of information that may be of value to the ERO Panel in making its decision. No change
made.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like nothing
better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and an initial
attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could have
come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the commenters
that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the
Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of
the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of
the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting
or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis
for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making
their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
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request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric
system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the
technical prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests
will result in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
Marie Knox
Midwest ISO,
2
Negative
We support the SDT’s decision to exclude the cranking paths from the BES
Inc.
definition since testing and verification of the use of facilities in the cranking path
is already covered by the appropriate EOP standards. However Inclusion I3
(blackstart) is extraneous given there is already designation specific for system
restoration covered by an existing standard; EOP-005-2. Therefore, information on
whether the facility is part of a Cranking Path associated with a Blackstart
Resource, should not be required to receive consideration for an exception.
Response: The SDT disagrees that Blackstart Resources should not be included in the BES Definition. The Commission directed NERC to revise
its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission
network. The SDT interprets this to include operation under both normal and emergency conditions, which includes situations related to black
starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be energized without
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connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for Real and Reactive
Power capability, frequency, and voltage control. The associated resources of the electric system that can be isolated and then energized to
deliver electric power during a restoration event are essential to enable the startup of one or more other generating units as defined in the
Transmission Operator’s restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the Transmission
Operator’s restoration plan as BES elements. No change made.
Cranking Path information is just one piece of information that may be of value to the ERO Panel in making its decision. EOP-005-2 has no
relevance in this regard. No change made.
Linda Jacobson City of
3
Negative
FEUS appreciates the efforts of the SDT. However, the Detailed Information to
Farmington
Support an Exception Request does not align with the Draft Appendix 5C as it is
applied to ‘Facilities’ rather than ‘Elements’ and is unclear how it is applied for an
Inclusion Exception. Additional Comments have been submitted using the
comment form.
Response: Please see the detailed responses to comments for Farmington in the general consideration of comments document for the
technical criteria.
Gregg R Griffin

City of Green
Cove Springs

3

Affirmative GCS appreciates the SDT’s work on this project. For the most part,GCS supports
what it believes to be the intent of the proposed language. The proposed specific
exclusion of facilities used in the local distribution of electric energy is appropriate
and consistent with Section 215 of the Federal Power Act. However, we have
suggestions to better carry out what we believe to be the SDT’s intent. The first
sentence can be read as: “... all ... Real Power and Reactive Power resources
connected at 100 kV or higher”, which is surely not what the SDT intends. The
basic problem is that Inclusions I2 and I4 do not modify the first sentence, e.g.,
from a set theory perspective, the set described by the first sentence includes the
sets described in inclusions I2 and I4; hence, I2 and I4 do not modify the first
sentence. From a literal reading, this would cause any size generator connected at
100 kV to be included, which is surely not the intent of the SDT. For similar
reasons, the core definition and Inclusion I5 now has the effect of including all
generators connected at 100 kV since a generator is a “dynamic device ... supplying
or absorbing Reactive Power”. The word “dedicated” in I5 is not sufficient in GCS’s
mind to unambiguously exclude generators from this statement. FMPA suggests
the following wording to address these issues: "Transmission Elements (not
including elements used in the local distribution of electric energy) and Real Power

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and Reactive Power resources as described in the list below, unless excluded by
Exclusion or Exception: a. Transmission Elements other than transformers and
reactive resources operated at 100 kV or higher. b. Transformers with primary and
secondary terminals operated at 100 kV or higher. c. Generating resource(s) (with
gross individual or gross aggregate nameplate rating per the ERO Statement of
Compliance Registry Criteria) including the generator terminals through the highside of the step-up transformer(s) connected at a voltage of 100 kV or above. d.
Blackstart Resources identified in the Transmission Operator’s restoration plan. e.
Dispersed power producing resources with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing a system designed primarily for
aggregating capacity, connected at a common point at a voltage of 100 kV or
above, but not including generation on the retail side of the retail meter. f. Nongenerator static or dynamic devices dedicated to supplying or absorbing more than
6 MVAr of Reactive Power that are connected at 100 kV or higher, or through a
dedicated transformer with a high-side voltage of 100 kV or higher, or through a
transformer that is designated in bullet 2 above." 2. The SDT has revised the
specific inclusions to the core definition in response to industry comments. Do you
agree with Inclusion I1 (transformers)? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. Yes: Yes No: Comments:
Please see comments to Question 1 3. The SDT has revised the specific inclusions
to the core definition in response to industry comments. Do you agree with
Inclusion I2 (generation) including the reference to the ERO Statement of
Compliance Registry Criteria? If you do not support this change or you agree in
general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. Yes: yes No: Comments: Please see
comments to Question 1 4. The SDT has revised the specific inclusions to the core
definition in response to industry comments. Do you agree with Inclusion I3
(blackstart)? If you do not support this change or you agree in general but feel that
alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: Yes No: Comments: Please see comments to
Question 1. 5. The SDT has revised the specific inclusions to the core definition in
response to industry comments. Do you agree with Inclusion I4 (dispersed power)?

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If you do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: Yes No: Comments: We recommend clarifying that the dispersed
power resources covered by this inclusion do not include generators on the retail
side of the retail meter. Specifically, we recommend that the Inclusion read:
“Dispersed power producing resources with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing a system designed primarily for
aggregating capacity, connected at a common point at a voltage of 100kV or
above, but not including generation on the retail side of the retail meter.” 6. The
SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I5 (reactive resources)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: No: Comments: To help clarify and to avoid inclusion of de minimis reactive
resources, we propose a size threshold of 6 MVAr consistent with the smallest size
generator included in the BES at a 0.95 power factor, which is a common leading
power factor used in Facility Connection Requirements for generators. In other
words, 6 MVAr is consistent with typically the least amount of MVAr required to
be absorbed by the smallest generator meeting the registry criteria. 7. The SDT has
revised the specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E1 (radial system)? If you do not support
this change or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments. Yes: Yes
No: Comments: FMPA supports the exclusion of radial systems from the BES
Definition. Such systems are generally not “necessary for operating an
interconnected electric transmission network,” the standard in Orders 743 and
743-A. We have several suggestions to clarify the proposed language for this
Exclusion. Proposed Exclusion E1 refers to “[a] group of contiguous transmission
Elements that emanates from a single point of connection of 100 kV or higher.”
We appreciate the SDT’s clarification of the point of connection requirement, but
the term “a single point of connection” should be further defined (more clearly
than just by voltage), and should be generic enough to encompass the various bus
configurations. It is not the case, for example, that each individual breaker position

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in a ring bus is a separate point of connection for this purpose; in that situation, a
bus at one voltage level at one substation should be considered “a single point of
connection.” Some examples of configurations that should be considered a single
point of connection for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf,
Examples 1-6. Although the core definition (appropriately) refers to “Transmission
Elements” (with a capital “T”), proposed Exclusion E1 refers to “transmission
Elements” (with a lowercase “t”). To avoid confusion, either “Transmission” should
be capitalized in both locations, or the word “transmission” should simply be
deleted from Exclusion E1, leaving a “group of contiguous Elements.” We
understand that the lack of capitalization may have been a deliberate choice by
the SDT in an attempt to avoid confusion that SDT members believe exists in the
Glossary definition. If the Glossary definition of Transmission is unclear-which GCS
does not necessarily believe is the case-the answer is not to simply abandon the
Glossary definition in favor of an entirely und
Response: Please see the detailed responses to comments for Green Cove in the ballot consideration of comments document for the definition.
Jose Escamilla

Entity

CPS Energy

Segment

3

Vote

Negative

The sample form "Request for Exception to the Bulk Electric System Definition"
developed by the BES ROP Team is a more complete form.

Response: The SDT believes that the indicated form was an early draft and is no longer applicable. The SDT has worked closely with the Rules
of Procedure team to make certain that the form is coordinated with the proposed ERO Rules of Procedure changes.
David Kiguel

Hydro One
Networks, Inc.

3

Negative

After careful analysis of the proposed documents, Hydro One Networks Inc. is
casting a negative vote. We commend the SDT for the effort in facing the
challenge. However, we believe that the proposed definition and the exception
request criteria still needs further work. Some issues need to be resolved before a
final approval is granted. Please see our detailed comments as provided in the online system.
Response: Please see the detailed responses to comments for Hydro One in the general consideration of comments document for the technical
criteria.
Jack W Savage

Modesto
Irrigation

3

Negative

MID is voting No with the following comments. Inclusions and exclusions are based
upon the ERO Statement of Compliance Registry Criteria - currently 75MVA. What

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is the SDT's technical justification for using this generation level? If 75MVA is the
criteria for including facilities as part of the BES, why is that same criteria not
applied at voltages below 100kv? Is 75MVA of generation within an area whose
load far exceeds that 75MVA cause to classify that entire area as part of the BES
and not exclude it as a Local Network?
Why are customer owned generators treated differently than other generators?
Where is "non-retail generation" defined?
The Detailed Information to Support an Exception Request requests information
that is not included or mentioned in the definition of the BES. One example is
reference to a Balancing Authorities most severe single contingency outage. How
does the SDT justify inclusion of these type of questions which are not supported
by the actual definition of the BES?
Response: The SDT recognizes that some candidate local networks will have far in excess of 75 MVA of load demand, yet it believes that the 75
MVA threshold value given in Exclusion E3.a is an appropriate level regardless of the amount of load. This value is consistent with the existing
threshold of aggregate generation in the ERO Statement of Compliance Registry Criteria. The generation values used in the BES definition will
receive more attention and refinement as part of Phase 2 of this Project 2010-17.
The SDT assumes the commenter is referring to Exclusion E2. This exclusion is simply clarifying what already exists in the ERO Statement of
Compliance Registry Criteria for behind-the-meter generation.
Non-retail generation is the generation on the system (supply) side of the meter.
The indicated information is simply one piece of data that the SDT felt might be of value in the decision process and does not believe that data
requested has to match one for one with the actual language of the definition.
Jeff Nelson
Springfield
3
Negative
Excellent progress has been made, but the technical information to support BES
Utility Board
exceptions needs strengthening. For example, unscheduled flows in or out of a
local network should not be used as a determination of whether a network is
excluded.
Reactive devices needs clarification as there are some reactive devices used for
power factor correction, for example, on systems above 100kV that SUB believes
should be exempt from the BES
Response: The SDT believes it is vital to ensure both that power flow is always in the direction from the BES toward the LN at all points of
connection, and that the LN facilities not be used for “wheeling” type transactions. The SDT believes the existing language accomplishes this.
The suggested language in this comment touches on an important aspect, the scheduled use of the facilities, but the SDT believes that the
existing language is more appropriate to express this point. No change made.
Special circumstances such as described by SUB will need to be submitted to the exception process. In general, the SDT believes that reactive
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devices above 100 kV should be part of the BES.
Mark
Ringhausen

Old Dominion
Electric Coop.

4

Comment

Negative

I cannot vote for this as it references in I2 the ERO Statement of Compliance
Registry Criteria, which can be changed without stakeholder review and approval.
The industry would be held to a changing standard that is not included in the
Standars itself.
Response: This is a factor for the definition and not the criteria. Voting on the two separate issues should be done separately on their own
individual merits.
In response to comments, the SDT has deleted the reference to the ERO Statement of Compliance Registry and replaced it with the existing
numeric values. This way, any changes to the ERO Statement of Compliance Registry prior to resolution of threshold values in Phase II will not
affect the definition
Michelle R
Occidental
5
Negative
1. Page 1 of the Detailed Information to Support an Exception Request contains
DAntuono
Chemical
general instructions. Do you agree with the instructions presented or is there
information that you believe needs to be on page one and is missing? Please be as
specific as possible with your comments. No: X Comments: It would be helpful to
specify what the “key performance measures of BES reliability” are in the
instructions (or at least examples of what these measures are in relation to the TPL
Table 1). There must be some guidance on the relative level that should be
considered acceptable to exclude a facility. Since the Regional Entities are
responsible under the proposed Rules of Procedure to recommend the approval or
disapproval of an exception request, it makes sense that they should provide this
guidance. However, the DBESSDT should suggest an acceptable minimum perhaps 10% of the allowed voltage transient dip or frequency excursion as
assessed under a single contingency scenario.
2. Pages two and three of the Detailed Information to Support an Exception
Request contain a checklist of items that deal with transmission facilities. Do you
agree with the information being requested or is there information that you
believe needs to be on page three and is missing? Please be as specific as possible
with your comments. No: X Comments: Item 4 needs to be expanded to provide
some guidance on what an acceptable “impact to the over-all reliability of the BES”
is. Also, there needs to be some sort of qualifier for the request to specify the
“most severe system impact of an outage of the facility,” i.e., at least add the
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qualifier that it only requires a credible scenario. For example, what is the status of
the BES when the outage of the facility occurs such that it represents the “most
severe impact.” Most Regional Entities have settled on Transmission Planning
models and thresholds that any new transmission deployment must minimally
meet before it goes online. In some Regions, power transfer distribution factor
may be gating factor - others may look at transient response. Whatever the case,
the Regions should use those same criteria for BES exceptions - reduced to some
conservative percentage level; perhaps 10% of the available margin.
3. Page four of the Detailed Information to Support an Exception Request contains
a checklist of items that deal with generation facilities. Do you agree with the
information being requested or is there information that you believe needs to be
on page four and is missing? Please be as specific as possible with your comments.
No: X Comments: Item 4 needs to be expanded to provide some guidance on what
an acceptable “impact to the over-all reliability of the BES” is. Also, there needs to
be some sort of qualifier for the request to specify the “most severe system impact
of an outage of the facility,” i.e., at least add the qualifier that it only requires a
credible scenario. For example, what is the status of the BES when the outage of
the facility occurs such that it represents the “most severe impact.” Most Regional
Entities have settled on Transmission Planning models and thresholds that any
new generation deployment must minimally meet before it goes online. In some
Regions, power transfer distribution factor may be gating factor - others may look
at transient response. Whatever the case, the Regions should use those same
criteria for BES exceptions - reduced to some conservative percentage level;
perhaps 10% of the available margin.
4. Do you have concerns about an entity’s ability to obtain the data they would
need to file the Detailed Information to Support an Exception Request? If so,
please be specific with your concerns so that the SDT can fully understand the
problem. Yes: X Comments: Having the data to perform studies of generator
outage effects on the BES may require sharing of potentially confidential and/or
classified information between the generator and transmission entities. Obviously,
“base case” and possibly “N-1” information would need to be shared. Hence, there
needs to be some assurance that information will be provided (Possibly in the
proposed Appendix 5C of the NERC Rules of Procedure).

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5. Are there other specific characteristics that you feel would be important for
presenting a case and generic enough that they belong in the request? If so, please
identify them here and provide suggested language that could be added to the
document. Yes: No: Comments:
6. Are you aware of any conflicts between the proposed approach and any
regulatory function, rule order, tariff, rate schedule, legislative requirement or
agreement, or jurisdictional issue? If so, please identify them here and provide
suggested language changes that may clarify the issue. Yes: X Comments: This
Detailed Information to Support an Exemption Request document obviously does
not conform to FERC Order 743, Sections 115,116 “NERC should develop an
exemption process that includes clear, objective, transparent, and uniformly
applicable criteria for exemption of facilities that are not necessary for operating
the grid.” The question is will the justification for declining to observe this FERC
directive be sufficient. We would assert that is it a lesser consequence for the BES
to raise the single generation threshold to 75 MVA than it is to violate this FERC
directive by not providing clear, objective, transparent and uniform criteria for the
exemption process. We understand that the FERC directive was not well conceived
in that if a bright line criteria could be developed for the exemption process, it
should be included in the BES Definition itself. However, it leaves the exemption
process that FERC had originally conceived non-attainable and causes angst to the
industry.
7. Are there any other concerns with this approach that haven’t been covered in
previous questions and comments bearing in mind that the definition itself and the
proposed Rules of Procedure changes are posted separately for comments? Please
be as specific as possible with your comments. Yes: No: Comments:
Response: 1. 2. & 3. The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If
the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to
the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of
substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
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Entity
Segment
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Comment
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the
Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of
the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of
the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting
or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis
for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making
their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric
system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the
technical prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests
will result in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
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Voter
Entity
Segment
Vote
Comment
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
4. If confidential data is involved in the submittal, the SDT expects the Regional Entity to work with the submitter to get around this problem.
5. & 7. Thank you for your response.
6. The SDT believes the process is in alignment with Order 743 directives as explained above.
Negative
OPG has cast a negative ballot in the BES Definition poll. Since we disagree with
Colin Anderson Ontario Power 5
the Definition, and the justification for it, we don't see the need for an exception
Generation
process. OPG continues to question the need for the changes required (and costs
Inc.
imposed) as a result of the new BES definition. OPG disagrees in general with
proceeding to implement a 100 kV brightline definition in the absence of a
properly quantified cost/benefit analysis. Entities are being asked to incur a high
cost for no demonstrated benefit in wide-area reliability.
Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and
an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could
have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the
commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive
comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
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Voter
Entity
Segment
Vote
Comment
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the
Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of
the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of
the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting
or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis
for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making
their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric
system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the
technical prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests
will result in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
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Voter
Entity
Segment
Vote
Comment
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to improve
clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES Elements. The SDT’s
efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s concerns as expressed in the
directives contained in Orders No. 743 & 743-A. To accomplish these goals, the SDT has pursued a definition that remains as consistent as
possible with the existing definition, while not significantly expanding or contracting the current scope of the BES or driving registration or deregistration. With this in mind, the SDT acknowledges that the current BES definition has varying degrees of Regional application and has
resulted in different conclusions on what is currently considered to be part of the BES. This inconsistency in the application and subsequent
results were also identified by the Commission in Orders No. 743 & 743-A as a significant concern. The SDT acknowledges that by developing a
bright-line definition coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on
Regions. Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid on a
continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the development of Regional
transition plans once the definition has been approved by the Commission.
5
Negative
Process should make it easier to prove facility is a non-BES; process should take
Steven Grega
Public Utility
into account the plant load factor, if the plant is dispatchable and if it cricital
District No. 1
resource as determine by the BA. Most facilities should be able to prove they are
of Lewis
not part of the BES. In WECC, only critical cranking paths are part of BES.
County
Response: The SDT has attempted to make the exception process as easy as possible while still providing the information necessary to properly
process a request. Factors such as described by the commenter can be supplied with the submittal as there is no limit or constraint on
additional information that can be supplied by the submitter.
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Voter
Larry Nordell

Entity
Montana
Consumer
Counsel

Segment
8

Vote
Negative

Comment
The BES exception process must be cognizant of costs and benefits. In addition to
the explicit information required in the current proposal it needs to provide an
opportunity for an exception for elements whose failure would have no
consequential impacts on the bulk system, and a process for an exception for
elements for which the costs inclusion can be shown to be clearly in excess of the
benefits of inclusion.
Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES Elements. The
SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s concerns as expressed
in the directives contained in Orders No. 743 & 743-A. To accomplish these goals, the SDT has pursued a definition that remains as consistent as
possible with the existing definition, while not significantly expanding or contracting the current scope of the BES or driving registration or deregistration. With this in mind, the SDT acknowledges that the current BES definition has varying degrees of Regional application and has
resulted in different conclusions on what is currently considered to be part of the BES. This inconsistency in the application and subsequent
results were also identified by the Commission in Orders No. 743 & 743-A as a significant concern. The SDT acknowledges that by developing a
bright-line definition coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on
Regions. Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid on a
continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the development of Regional
transition plans once the definition has been approved by the Commission.
Diane J Barney National
9
Negative
The draft definition has a circularity issue with the Registry, lacks clarity in some
Association of
aspects, and lacks a technical basis and cost/benefit analysis. (See specific
Regulatory
comments submitted.)
Utility
Commissioners
Response: Please see the specific responses provided.
John D Varnell

Tenaska Power
Services Co.

6

Abstain

Which part of this definition has the highest priority inclusions or exclusions.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the
vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and non-BES
Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or higher as included
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Entity
Segment
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Comment
in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed. Element is defined in the
NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker, bus
section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application of the
‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific criteria to provide
for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion language
is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the exclusion
language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The exclusion (E1) only
speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner.
Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and supersedes
inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected transmission
network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude an Element.
Brenda Powell Constellation
6
Affirmative While the Technical Principles for BES Exception are acceptable, they are quite
Energy
complicated. Further simplification may ease the process.
Commodities
Group
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Entity
Segment
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Comment
Response: The SDT has attempted to make the exception process as easy as possible while still providing the information necessary to properly
process a request.
Greg Lange

Public Utility
District No. 2
of Grant
County

3

Affirmative Public Utility District No. 2 of Grant County (GCPD) agrees that the General
Instructions set forth the basic information that would be necessary to support an
Exception Request. GCPD is concerned, however, that the statement “diagram(s)
supplied should also show the Protection Systems at the interface points
associated with the Elements for which the exception is being requested” may be
subject to differing interpretations. GCPD envisions that at least four different
kinds of documents would be responsive to the description: one-line diagrams
with breakers and switches (status); identification of relays by their ANSI device
numbers; details of the DC control logic for ANSI devices; and, operational scheme
descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to
identify protection systems at the interface with the Elements for which the
Exception is sought, including any required details.
GCPD suggests that a generic example of a completed form be available to the
industry to help ensure that Exception Requests are supported by consistent and
complete information. Such a generic example could be addressed in the Phase 2
BES efforts.
GCPD agrees that the items listed on page 4 of the Detailed Information to Support
an Exception Request capture the information that generally would be necessary
to make a reasoned determination concerning the BES status of a generation
facility. GCPD suggests three refinements to the questions: (1) Question 2 should
be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator
or the generator facility used to provide Ancillary Services necessary for the
operation of the interconnected bulk transmission system?” The italicized
language is necessary to distinguish between a generator that provides, for
example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that
provides back-up generation to a specific industrial facility. The former may be
necessary for the reliable operation of the interconnected bulk transmission
system, but the latter is not.

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Comment
(2) The current draft of the BES Definition contains Exclusions for radials and for
Local Networks. To be consistent with these aspects of the revised BES definition,
GCPD suggests modifying question 5 by adding “radial, or Local Network” to the
question, so that it would read: “Does the generator use the BES, a radial system,
or a Local Network to deliver its actual or scheduled output, or a portion of its
actual or scheduled output, to Load?
(3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an
Exception Request for a generator to submit any information it believes is relevant
to the Exception that is not captured in the previous questions. We suggest the
following language: Is there additional information not covered in questions 1
through 5 that supports the Exception Request? If yes, please provide the
information and explain why it is relevant to the Exception Request. This will allow
an entity seeking an Exception for a generator to identify any unusual
circumstances or non-standard information that might support its Exception
Request. An entity seeking such an Exception should have the opportunity to
present any information it believes is relevant.
Response: The SDT believes that the form allows for the flexibility of an entity supplying any types of diagrams that it believes will support its
request. This is a preferable situation to coming up with a hard coded list. No change made.
The SDT will consider completing a sample form in Phase II.
The SDT has modified the wording of the question to clarify the intent.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
The SDT does not believe that the suggested wording change provides any additional clarification and may even cause confusion. No change
made.
The SDT agrees that any information that might support a request should be allowed and has clarified the wording on page 1 to that effect.
Page 1 - List any attached supporting documents and any additional information that is included to supports the request:
Jeffrey S
North Carolina 5
Affirmative In general, we support the “Detailed Information to Support an Exception
Brame
Electric
Request”. However, we have identified a few concerns that warrant the SDT’s
Membership
consideration. Q1, Q5 and Q6 in the Transmission Facilities section have a
Corp.
“Description/Comments” section. What type of information should be included
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Entity

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Comment
under the Description for each of these questions? Providing more guidance here
would help achieve the “standardization, clarity and continuity of process” that we
seek. Regarding Q2: A permanent flowgate should not be part of the detailed
information to support an exception. First, there is no definition for what
constitutes a permanent flowgate. Second, flowgates are often created for a
myriad of reasons that have nothing to do with them being necessary to operate
the BES. While section c) in E3 attempts to limit the applicability to permanent
flowgates, there is no definition for what constitutes a permanent flowgate
particularly since no flowgate is truly permanent. The NERC Glossary of Terms
definition of flowgate includes flowgates in the IDC. This is a problem because
flowgates are included in the IDC for many reasons not just because reliability
issues are identified. Flowgates could be included to simply study the impact of
schedules on a particular interface as an example. It does not mean the interface is
critical. As an example, it could be used to generate evidence that there are no
ransactional impacts to support exclusion from the BES. Furthermore, the list of
flowgates in the IDC is dynamic. The master list of IDC flowgates is updated
monthly and IDC users can add temporary flowgates at anytime. While the
permanent adjective applied to flowgates probably limits the applicability from the
“temporary” flowgates, it is not clear which of the monthly flowgates would be
included from the IDC since they might be added one month and removed
another. In the Transmission Facilities section, we are unclear about what “an
appropriate list” in Q3 is supposed to be. Is it supposed to be a list of all IROLs or
only those for which the answer is yes? Why is a list even necessary since the
answer to the question answers Exclusion E3.c? If the answer to Q3 is no, is this
asking the submitter to prove the negative? For Q2 in the Generation Facilities
section, the definition of ancillary services varies and can be quite broad. It can
include reactive power and voltage support for example. All generators provide
some reactive power and voltage support. Thus, ancillary services should be
further defined or one could construe it to limit any generator from being
excluded. For Q1 in the Generation Facilities section, some generation owners may
not be able to obtain their BA’s most severe single Contingency. Many generator
owners will not have access to the data necessary to demonstrate the reliability
impact to the BES. This is particularly true for transmission dependent utilities.

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Voter
Doug White

Entity
North Carolina
Electric
Membership
Corp.

Segment
3

Vote
Comment
Affirmative In general, we support the proposed definition of the BES. However, we have
identified a few concerns that warrant the SDT’s consideration. We’d prefer to see
the language from the ERO Statement of Compliance Registry Criteria repeated
within the BES Definition itself instead of referencing an outside document. As it
stands right now, the Compliance Registry Criteria needs to stay intact for Phase I
of this project. That makes the Compliance Registry Criteria reliant on the BES
Definition and vice versa. We understand that the Statement of Compliance
Registry Criteria may be reviewed/revised at the same time Phase 2 of this project
is being developed, therefore we agree with Inclusion I2 of this draft.
Blackstart Resources can actually be on the distribution system. There is still the
question of whether the distribution system would then be subjected to the
enforceable standards. If so, there would most likely be a significant cost increase
associated with tracking compliance for these distribution systems without a
commensurate increase in reliability since Blackstart Resources are rarely used.
This could very well cause entities to un-designate Blackstart Resources on
distribution systems to avoid these distribution systems from becoming part of the
BES. The same rationale that was used for eliminating cranking paths could also be
applied to Blackstart Resources.
A flowgate should not be used to limit applicability of E3. First, there is no
definition for what constitutes a permanent flowgate. Second, flowgates are often
created for a myriad of reasons that have nothing to do with them being necessary
to operate the BES. While section c) in E3 attempts to limit the applicability to
permanent flowgates, there is no definition for what constitutes a permanent
flowgate particularly since no flowgate is truly permanent. The NERC Glossary of
Terms definition of flowgate includes flowgates in the IDC. This is a problem
because flowgates are included in the IDC for many reasons not just because
reliability issues are identified. Flowgates could be included to simply study the
impact of schedules on a particular interface as an example. It does not mean the
interface is critical. As an example, it could be used to generate evidence that
there are no transactional impacts to support exclusion from the BES.
Furthermore, the list of flowgates in the IDC is dynamic. The master list of IDC
flowgates is updated monthly and IDC users can add temporary flowgates at
anytime. While the “permanent” adjective applied to flowgates probably limits the

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Entity

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Comment
applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month
and removed another. Flowgates are created for many reasons that have nothing
to do with them being necessary to operate the BES. First, flowgates are created to
manage congestion. The IDC is more of a congestion management tool than a
reliability tool. FERC recognized this in Order 693, when they directed NERC to
make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs that
have been violated. Rather, other actions such as re-dispatch must be used in
conjunction. Second, flowgates are used as a convenient point to calculate flows to
sell transmission service. The characteristics of the flowgate make it a good proxy
for estimating how much contractual use has been sold not necessarily how much
flow will actually occur. While some flowgates definitely are created for reliability
issues such as IROLs, many simply are not.
The term “non-retail generation” used in Exclusion E1 (item c) and again in E3
(item a) should be clarified (see comments for question 8 below). The Note after
item c should also be clarified to indicate that closing a normally open switch
doesn’t affect this exclusion.
Detailed Information to Support an Exception Request: Vote affirmative with the
comments below Comments for Ballot (these may be copied and pasted ): In
general, we support the “Detailed Information to Support an Exception Request”.
However, we have identified a few concerns that warrant the SDT’s consideration.
Q1, Q5 and Q6 in the Transmission Facilities section have a
“Description/Comments” section. What type of information should be included
under the Description for each of these questions? Providing more guidance here
would help achieve the “standardization, clarity and continuity of process” that we
seek. Regarding
Q2: A permanent flowgate should not be part of the detailed information to
support an exception. First, there is no definition for what constitutes a permanent
flowgate. Second, flowgates are often created for a myriad of reasons that have
nothing to do with them being necessary to operate the BES. While section c) in E3
attempts to limit the applicability to permanent flowgates, there is no definition
for what constitutes a permanent flowgate particularly since no flowgate is truly
permanent. The NERC Glossary of Terms definition of flowgate includes flowgates

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Voter

Entity

Segment

Vote

Comment
in the IDC. This is a problem because flowgates are included in the IDC for many
reasons not just because reliability issues are identified. Flowgates could be
included to simply study the impact of schedules on a particular interface as an
example. It does not mean the interface is critical. As an example, it could be used
to generate evidence that there are no transactional impacts to support exclusion
from the BES. Furthermore, the list of flowgates in the IDC is dynamic. The master
list of IDC flowgates is updated monthly and IDC users can add temporary
flowgates at anytime. While the permanent adjective applied to flowgates
probably limits the applicability from the “temporary” flowgates, it is not clear
which of the monthly flowgates would be included from the IDC since they might
be added one month and removed another.
In the Transmission Facilities section, we are unclear about what “an appropriate
list” in Q3 is supposed to be. Is it supposed to be a list of all IROLs or only those for
which the answer is yes? Why is a list even necessary since the answer to the
question answers Exclusion E3.c? If the answer to Q3 is no, is this asking the
submitter to prove the negative?
For Q2 in the Generation Facilities section, the definition of ancillary services varies
and can be quite broad. It can include reactive power and voltage support for
example. All generators provide some reactive power and voltage support. Thus,
ancillary services should be further defined or one could construe it to limit any
generator from being excluded.
For Q1 in the Generation Facilities section, some generation owners may not be
able to obtain their BA’s most severe single Contingency. Many generator owners
will not have access to the data necessary to demonstrate the reliability impact to
the BES. This is particularly true for transmission dependent utilities.
Response: In response to comments, the SDT has deleted the reference to the ERO Statement of Compliance Registry and replaced it with the
existing numeric values. This way, any changes to the ERO Statement of Compliance Registry prior to resolution of threshold values in Phase II
will not affect the definition.
The SDT has determined that it should be conservative with regard to allowing exclusion for radial systems that are depended upon for
blackstart functionality, as these will arguably be more important to the reliable operation of the transmission system than equivalent radial
systems without blackstart resources. No change made.
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Voter
Entity
Segment
Vote
Comment
The SDT believes that the language in Exclusion E3.c prohibiting “Flowgates” from qualifying for definitional exclusion is appropriate and
necessary. As a definitional exclusion characteristic, Exclusion E3.c must follow the principle of being a bright-line and easily identifiable, and as
such, the SDT feels that the definition cannot allow some types of Flowgates and disallow others. Flowgates must continue to be a prohibiting
characteristic under Exclusion E3, since these facilities are more likely to be used in the transfer of bulk power than not. An entity who wishes
to make a case for exclusion of a unique type of Flowgate facility can do so through the exception process. The SDT believes that the continued
qualifier of “permanent” associated with the term “Flowgate” addresses the majority of the concern in this comment. No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The requesting entity should supply any and all information that it feels will help support its request. No change made.
The SDT has modified the wording of the question to clarify the intent.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Any information that an entity believes will support its request should be included. No change made.
The SDT believes that the language in Exclusion E3.c prohibiting “Flowgates” from qualifying for definitional exclusion is appropriate and
necessary. As a definitional exclusion characteristic, Exclusion E3.c must follow the principle of being a bright-line and easily identifiable, and as
such, the SDT feels that the definition cannot allow some types of Flowgates and disallow others. Flowgates must continue to be a prohibiting
characteristic under Exclusion E3, since these facilities are more likely to be used in the transfer of bulk power than not. An entity who wishes
to make a case for exclusion of a unique type of Flowgate facility can do so through the exception process. The SDT believes that the continued
qualifier of “permanent” associated with the term “Flowgate” addresses the majority of the concern in this comment. No change made.
The SDT believes that the wording is clear as stated and that the list would be those IROLs that include the Element(s) in question. No change
made.
The SDT has modified the wording of the question to clarify the intent.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Based on the comments received, the SDT believes that entities will be able to obtain the requisite information necessary to submit a request.
However, should an entity have difficulty, they will need to obtain the assistance of their Regional Entity to secure the data. If the entity still
can’t obtain the needed data, then the SDT fully expects that entity’s Regional Entity to work with them to come up with a plan that will allow
that entity to fill out the request form in a manner that will be acceptable to the Regional Entity so that processing of the request can continue.
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Voter
Claston
Augustus
Sunanon

Entity
Orlando
Utilities
Commission

Segment
6

Vote
Comment
Affirmative Orlando Utilities Commission supports the new definition, although our support is
conditioned on: (1) a workable Exceptions process being developed in conjunction
with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II
of the standards development process in accordance with the SAR recently put
forward by the SDT, which would address a number of important technical issues
that have been identified in the standards development process to date.
Brad Chase
Orlando
1
Affirmative Orlando Utilities Commission supports the new definition, although our support is
Utilities
conditioned on: (1) a workable Exceptions process being developed in conjunction
Commission
with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II
of the standards development process in accordance with the SAR recently put
forward by the SDT, which would address a number of important technical issues
that have been identified in the standards development process to date. in
addition, phase II should include a clear distinction between the BES and BPS.
3
Affirmative Orlando Utilities Commission supports the new definition, although our support is
Ballard K
Orlando
conditioned on: (1) a workable Exceptions process being developed in conjunction
Mutters
Utilities
with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II
Commission
of the standards development process in accordance with the SAR recently put
forward by the SDT, which would address a number of important technical issues
that have been identified in the standards development process to date.
Response: The exception process is being worked on in parallel with the definition and will be part of the same filing.
Phase II will start up as soon as Phase I is completed and the SDT has the available resources to work on it.
Noman Lee
Williams

Sunflower
Electric Power
Corporation

1

Affirmative Q1, Q5 and Q6 in the Transmission Facilities section have a
“Description/Comments” section. What type of information should be included
under the Description for each of these questions? Providing more guidance here
would help achieve the “standardization, clarity and continuity of process” that we
seek.
Regarding Q2: A permanent flowgate should not be part of the detailed
information to support an exception. First, there is no definition for what
constitutes a permanent flowgate. Second, flowgates are often created for a
myriad of reasons that have nothing to do with them being necessary to operate
the BES. While section c) in E3 attempts to limit the applicability to permanent
flowgates, there is no definition for what constitutes a permanent flowgate
particularly since no flowgate is truly permanent. The NERC Glossary of Terms

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Voter

Entity

Segment

Vote

Comment
definition of flowgate includes flowgates in the IDC. This is a problem because
flowgates are included in the IDC for many reasons not just because reliability
issues are identified. Flowgates could be included to simply study the impact of
schedules on a particular interface as an example. It does not mean the interface is
critical. As an example, it could be used to generate evidence that there are no
transactional impacts to support exclusion from the BES. Furthermore, the list of
flowgates in the IDC is dynamic. The master list of IDC flowgates is updated
monthly and IDC users can add temporary flowgates at anytime. While the
permanent adjective applied to flowgates probably limits the applicability from the
“temporary” flowgates, it is not clear which of the monthly flowgates would be
included from the IDC since they might be added one month and removed
another. Flowgates are created for many reasons that have nothing to do with
them being necessary to operate the BES. First,flowgates are created to manage
congestion. The IDC is more of a congestion management tool than a reliability
tool. FERC recognized this in Order 693, when they directed NERC to make clear in
IRO-006 that the IDC should not be relied upon to relieve IROLs that have been
violated. Rather, other actions such as re-dispatch must be used in conjunction.
Second, flowgates are used as a convenient point to calculate flows to sell
transmission service. The characteristics of the flowgate make it a good proxy for
estimating how much contractual use has been sold not necessarily how much
flow will actually occur. While some flowgates definitely are created for reliability
issues such as IROLs, many simply are not.
In the Transmission Facilities section, we are unclear about what “an appropriate
list” in Q3 is supposed to be. Is it supposed to be a list of all IROLs or only those for
which the answer is yes? Why is a list even necessary since the answer to the
question answers Exclusion E3.c? If the answer to Q3 is no, is this asking the
submitter to prove the negative?
For Q2 in the Generation Facilities section, the definition of ancillary services varies
and can be quite broad. It can include reactive power and voltage support for
example. All generators provide some reactive power and voltage support. Thus,
ancillary services should be further defined or one could construe it to limit any
generator from being excluded.
For Q1 in the Generation Facilities section, some generation owners may not be

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Voter

James Jones

Entity

Southwest
Transmission
Cooperative,
Inc.

Segment

1

Vote

Comment
able to obtain their BA’s most severe single Contingency. Many generator owners
will not have access to the data necessary to demonstrate the reliability impact to
the BES. This is particularly true for transmission dependent utilities.
Affirmative In general, we support the “Detailed Information to Support an Exception
Request”. However, we have identified a few concerns that warrant the SDT’s
consideration. Q1, Q5 and Q6 in the Transmission Facilities section have a
“Description/Comments” section. What type of information should be included
under the Description for each of these questions? Providing more guidance here
would help achieve the “standardization, clarity and continuity of process” that we
seek.
Regarding Q2: A permanent flowgate should not be part of the detailed
information to support an exception. First, there is no definition for what
constitutes a permanent flowgate. Second, flowgates are often created for a
myriad of reasons that have nothing to do with them being necessary to operate
the BES. While section c) in E3 attempts to limit the applicability to permanent
flowgates, there is no definition for what constitutes a permanent flowgate
particularly since no flowgate is truly permanent. The NERC Glossary of Terms
definition of flowgate includes flowgates in the IDC. This is a problem because
flowgates are included in the IDC for many reasons not just because reliability
issues are identified. Flowgates could be included to simply study the impact of
schedules on a particular interface as an example. It does not mean the interface is
critical. As an example, it could be used to generate evidence that there are no
transactional impacts to support exclusion from the BES. Furthermore, the list of
flowgates in the IDC is dynamic. The master list of IDC flowgates is updated
monthly and IDC users can add temporary flowgates at anytime. While the
permanent adjective applied to flowgates probably limits the applicability from the
“temporary” flowgates, it is not clear which of the monthly flowgates would be
included from the IDC since they might be added one month and removed
another. Flowgates are created for many reasons that have nothing to do with
them being necessary to operate the BES. First,flowgates are created to manage
congestion. The IDC is more of a congestion management tool than a reliability
tool. FERC recognized this in Order 693, when they directed NERC to make clear in
IRO-006 that the IDC should not be relied upon to relieve IROLs that have been

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71

Voter

Entity

Segment

Vote

Comment
violated. Rather, other actions such as re-dispatch must be used in conjunction.
Second, flowgates are used as a convenient point to calculate flows to sell
transmission service. The characteristics of the flowgate make it a good proxy for
estimating how much contractual use has been sold not necessarily how much
flow will actually occur. While some flowgates definitely are created for reliability
issues such as IROLs, many simply are not.
In the Transmission Facilities section, we are unclear about what “an appropriate
list” in Q3 is supposed to be. Is it supposed to be a list of all IROLs or only those for
which the answer is yes? Why is a list even necessary since the answer to the
question answers Exclusion E3.c? If the answer to Q3 is no, is this asking the
submitter to prove the negative?
For Q2 in the Generation Facilities section, the definition of ancillary services varies
and can be quite broad. It can include reactive power and voltage support for
example. All generators provide some reactive power and voltage support. Thus,
ancillary services should be further defined or one could construe it to limit any
generator from being excluded.
For Q1 in the Generation Facilities section, some generation owners may not be
able to obtain their BA’s most severe single Contingency. Many generator owners
will not have access to the data necessary to demonstrate the reliability impact to
the BES. This is particularly true for transmission dependent utilities.
Response: Any information that an entity believes will support its request should be included. No change made.
The SDT believes that the language in Exclusion E3.c prohibiting “Flowgates” from qualifying for definitional exclusion is appropriate and
necessary. As a definitional exclusion characteristic, Exclusion E3.c must follow the principle of being a bright-line and easily identifiable, and as
such, the SDT feels that the definition cannot allow some types of Flowgates and disallow others. Flowgates must continue to be a prohibiting
characteristic under Exclusion E3, since these facilities are more likely to be used in the transfer of bulk power than not. An entity who wishes
to make a case for exclusion of a unique type of Flowgate facility can do so through the exception process. The SDT believes that the continued
qualifier of “permanent” associated with the term “Flowgate” addresses the majority of the concern in this comment. No change made.
Any information that an entity believes will support its request should be included. No change made.
The SDT has modified the wording of the question to clarify the intent.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Based on the comments received, the SDT believes that entities will be able to obtain the requisite information necessary to submit a request.
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Voter
Entity
Segment
Vote
Comment
However, should an entity have difficulty, they will need to obtain the assistance of their Regional Entity to secure the data. If the entity still
can’t obtain the needed data, then the SDT fully expects that entity’s Regional Entity to work with them to come up with a plan that will allow
that entity to fill out the request form in a manner that will be acceptable to the Regional Entity so that processing of the request can continue.
Paul
City of Redding 5
Affirmative Redding's vote is conditional on the adoption and dedication to Phase 2 of this
Cummings
project.
Response: Phase II will begin as soon as Phase I is over and the SDT has the resources available to continue.
Sam Nietfeld

Snohomish
County PUD
No. 1

5

Affirmative Below are SNPD’s responses to the NERC comment form for the Definition of the
BES (Project 2010-17)Technical Principles for Demonstrating BES Exceptions).
SNPD believes the refinements below will clarify the current draft of the BES
definition, without hanging the current intent. 1. Page one of the ‘Detailed
Information to Support an Exception Request’ contains general instructions. Do
you agree with the instructions presented or is there information that you believe
needs to be on page one that is missing? Please be as specific as possible with your
comments. Comments: SNPD agrees generally that the General Instructions set
forth the basic information that would be necessary to support an Exception
Request. SNPD is concerned, however, that the statement “diagram(s) supplied
should also show the Protection Systems at the interface points associated with
the Elements for which the exception is being requested” may be subject to
differing interpretations. SNPD envisions that at least four different kinds of
documents would be responsive to the description: one-line diagrams with
breakers and switches (status); identification of relays by their ANSI device
numbers; details of the DC control logic for ANSI devices; and, operational scheme
descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to
identify protection systems at the interface with the Elements for which the
Exception is sought, including any required details, such as breaker settings. SNPD
suggests that a generic example of a completed form be available to the industry
to help ensure that Exception Requests are supported by consistent and complete
information. Such a generic example could be addressed in the Phase 2 BES
efforts. 2. Pages two and three of the Detailed Information to Support an
Exception Request contain a checklist of items that deal with transmission
facilities. Do you agree with the information being requested or is there

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73

Voter

Entity

Segment

Vote

Comment
information that you believe needs to be on page two or three that is missing?
Please be as specific as possible with your comments. Comments: SNPD agrees
that the checklist of items on pages two and three lists most of the information
that would be necessary to determine if an Exceptions Request is justified. We
suggest three modifications to the proposed language to ensure consistency with
Section 215 of the Federal Power Act, with the BES Definition, and to provide an
entity seeking an Exception with the opportunity to submit all relevant
information: 1) SNPD suggests that a new question should be added concerning
the function of the facility, which would read: “Does the facility function as a local
distribution facility rather than a Transmission facility? If yes, please provide a
detailed explanation of your answer.” Section 215(a)(1) of the FPA makes clear
that “facilities used in the local distribution of electric energy” are excluded from
the BES, 16 U.S.C. § 824o(a)(1), and the most recent draft of the BES definition
incorporates the same language. SNPD believes a question to address the function
of the Element or system subject to an Exception Request is necessary to
determine whether the Element or system is “used” in local distribution and
thereby to ensure that this statutory limit on the BES is observed in the Exceptions
process. Further, we believe a variety of information may be relevant to
determining whether a particular facility functions as local distribution rather than
as part of the BES. For example, if power is not scheduled across the facility or if
capacity on the system is not posted on the relevant OASIS, it is likely to function
as local distribution, not transmission. Similarly, if power enters the system and is
delivered to load within the system rather than moving to load located on another
system, its function is local distribution rather than transmission. SNPD proposes
the language above as an open-ended question so that the entity submitting the
Exceptions Request can provide this and any other information it deems relevant
to facility function. 2) SNPD suggests modifying question 6 to “Is the facility part a
designated Cranking Path associated with a Blackstart Resource identified in a
Transmission Operator’s restoration plan.” This language reflects the most recent
revision of the BES Definition and also helps distinguish between generators which
have Blackstart capability and those generators that are designated as a Blackstart
Resource in the Transmission Operator’s restoration plan. It is only the latter that
are included in the BES under the current draft of the definition. 3) A general

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74

Voter

Entity

Segment

Vote

Comment
“catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following
language: Is there additional information not covered in the questions above that
supports the Exception Request? If yes, please provide the information and explain
why it is relevant to the Exception Request. While SNPD believes the questions set
forth in the draft capture the information that generally would be necessary to
determine whether an Exception Request should be granted, it is foreseeable that
there may be unusual circumstances where the information called for either does
not capture the full picture or where studies other than the specific types called
for in the draft form support the Exception. An entity seeking an Exception should
have the opportunity to present any information it believes is relevant. 3. Page
four of the ‘Detailed Information to Support an Exception Request’ contains a
checklist of items that deal with generation facilities. Do you agree with the
information being requested or is there information that you believe needs to be
on page four that is missing? Please be as specific as possible with your comments.
Comments: SNPD agrees that the items listed on page 4 of the Detailed
Information to Support an Exception Request capture the information that
generally would be necessary to make a reasoned determination concerning the
BES status of a generation facility. SNPD suggests three refinements to the
questions: 1) Question 2 should be modified by adding “necessary for the
operation of the interconnected bulk transmission system” to the end of the
question, so that it reads: “Is the generator or the generator facility used to
provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between
a generator that provides, for example, reactive power or regulating reserves that
support operation of the interconnected bulk grid, and, for example, a behind-themeter generator that provides back-up generation to a specific industrial facility.
The former may be necessary for the reliable operation of the interconnected bulk
transmission system, but the latter is not. 2) The current draft of the BES Definition
contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, SNPD suggests modifying question 5 by
adding “radial, or Local Network” to the question, so that it would read: “Does the

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75

Voter

John D
Martinsen

Entity

Public Utility
District No. 1
of Snohomish
County

Segment

4

Vote

Comment
generator use the BES, a radial system, or a Local Network to deliver its actual or
scheduled output, or a portion of its actual or scheduled output, to Load? 3) For
reasons similar to those explained in our response to Question 2, a general “catchall” question should be added that will prompt an entity submitting an Exception
Request for a generator to submit any information it believes is relevant to the
Exception that is not captured in the previous questions. We suggest the following
language: Is there additional in
Affirmative Below are SNPD’s responses to the NERC comment form for the Definition of the
BES (Project 2010-17)Technical Principles for Demonstrating BES Exceptions).
SNPD believes the refinements below will clarify the current draft of the BES
definition, without hanging the current intent. 1. Page one of the ‘Detailed
Information to Support an Exception Request’ contains general instructions. Do
you agree with the instructions presented or is there information that you believe
needs to be on page one that is missing? Please be as specific as possible with your
comments. Comments: SNPD agrees generally that the General Instructions set
forth the basic information that would be necessary to support an Exception
Request. SNPD is concerned, however, that the statement “diagram(s) supplied
should also show the Protection Systems at the interface points associated with
the Elements for which the exception is being requested” may be subject to
differing interpretations. SNPD envisions that at least four different kinds of
documents would be responsive to the description: one-line diagrams with
breakers and switches (status); identification of relays by their ANSI device
numbers; details of the DC control logic for ANSI devices; and, operational scheme
descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to
identify protection systems at the interface with the Elements for which the
Exception is sought, including any required details, such as breaker settings. SNPD
suggests that a generic example of a completed form be available to the industry
to help ensure that Exception Requests are supported by consistent and complete
information. Such a generic example could be addressed in the Phase 2 BES
efforts. 2. Pages two and three of the Detailed Information to Support an
Exception Request contain a checklist of items that deal with transmission
facilities. Do you agree with the information being requested or is there

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76

Voter

Entity

Segment

Vote

Comment
information that you believe needs to be on page two or three that is missing?
Please be as specific as possible with your comments. Comments: SNPD agrees
that the checklist of items on pages two and three lists most of the information
that would be necessary to determine if an Exceptions Request is justified. We
suggest three modifications to the proposed language to ensure consistency with
Section 215 of the Federal Power Act, with the BES Definition, and to provide an
entity seeking an Exception with the opportunity to submit all relevant
information: 1) SNPD suggests that a new question should be added concerning
the function of the facility, which would read: “Does the facility function as a local
distribution facility rather than a Transmission facility? If yes, please provide a
detailed explanation of your answer.” Section 215(a)(1) of the FPA makes clear
that “facilities used in the local distribution of electric energy” are excluded from
the BES, 16 U.S.C. § 824o(a)(1), and the most recent draft of the BES definition
incorporates the same language. SNPD believes a question to address the function
of the Element or system subject to an Exception Request is necessary to
determine whether the Element or system is “used” in local distribution and
thereby to ensure that this statutory limit on the BES is observed in the Exceptions
process. Further, we believe a variety of information may be relevant to
determining whether a particular facility functions as local distribution rather than
as part of the BES. For example, if power is not scheduled across the facility or if
capacity on the system is not posted on the relevant OASIS, it is likely to function
as local distribution, not transmission. Similarly, if power enters the system and is
delivered to load within the system rather than moving to load located on another
system, its function is local distribution rather than transmission. SNPD proposes
the language above as an open-ended question so that the entity submitting the
Exceptions Request can provide this and any other information it deems relevant
to facility function. 2) SNPD suggests modifying question 6 to “Is the facility part a
designated Cranking Path associated with a Blackstart Resource identified in a
Transmission Operator’s restoration plan.” This language reflects the most recent
revision of the BES Definition and also helps distinguish between generators which
have Blackstart capability and those generators that are designated as a Blackstart
Resource in the Transmission Operator’s restoration plan. It is only the latter that
are included in the BES under the current draft of the definition. 3) A general

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77

Voter

Entity

Segment

Vote

Comment
“catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following
language: Is there additional information not covered in the questions above that
supports the Exception Request? If yes, please provide the information and explain
why it is relevant to the Exception Request. While SNPD believes the questions set
forth in the draft capture the information that generally would be necessary to
determine whether an Exception Request should be granted, it is foreseeable that
there may be unusual circumstances where the information called for either does
not capture the full picture or where studies other than the specific types called
for in the draft form support the Exception. An entity seeking an Exception should
have the opportunity to present any information it believes is relevant. 3. Page
four of the ‘Detailed Information to Support an Exception Request’ contains a
checklist of items that deal with generation facilities. Do you agree with the
information being requested or is there information that you believe needs to be
on page four that is missing? Please be as specific as possible with your comments.
Comments: SNPD agrees that the items listed on page 4 of the Detailed
Information to Support an Exception Request capture the information that
generally would be necessary to make a reasoned determination concerning the
BES status of a generation facility. SNPD suggests three refinements to the
questions: 1) Question 2 should be modified by adding “necessary for the
operation of the interconnected bulk transmission system” to the end of the
question, so that it reads: “Is the generator or the generator facility used to
provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between
a generator that provides, for example, reactive power or regulating reserves that
support operation of the interconnected bulk grid, and, for example, a behind-themeter generator that provides back-up generation to a specific industrial facility.
The former may be necessary for the reliable operation of the interconnected bulk
transmission system, but the latter is not. 2) The current draft of the BES Definition
contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, SNPD suggests modifying question 5 by
adding “radial, or Local Network” to the question, so that it would read: “Does the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

78

Voter

William T
Moojen

Entity

Snohomish
County PUD
No. 1

Segment

6

Vote

Comment
generator use the BES, a radial system, or a Local Network to deliver its actual or
scheduled output, or a portion of its actual or scheduled output, to Load? 3) For
reasons similar to those explained in our response to Question 2, a general “catchall” question should be added that will prompt an entity submitting an Exception
Request for a generator to submit any information it believes is relevant to the
Exception that is not captured in the previous questions. We suggest the following
language: Is there additional in
Affirmative Below are SNPD’s responses to the NERC comment form for the Definition of the
BES (Project 2010-17)Technical Principles for Demonstrating BES Exceptions).
SNPD believes the refinements below will clarify the current draft of the BES
definition, without hanging the current intent. 1. Page one of the ‘Detailed
Information to Support an Exception Request’ contains general instructions. Do
you agree with the instructions presented or is there information that you believe
needs to be on page one that is missing? Please be as specific as possible with your
comments. Comments: SNPD agrees generally that the General Instructions set
forth the basic information that would be necessary to support an Exception
Request. SNPD is concerned, however, that the statement “diagram(s) supplied
should also show the Protection Systems at the interface points associated with
the Elements for which the exception is being requested” may be subject to
differing interpretations. SNPD envisions that at least four different kinds of
documents would be responsive to the description: one-line diagrams with
breakers and switches (status); identification of relays by their ANSI device
numbers; details of the DC control logic for ANSI devices; and, operational scheme
descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to
identify protection systems at the interface with the Elements for which the
Exception is sought, including any required details, such as breaker settings. SNPD
suggests that a generic example of a completed form be available to the industry
to help ensure that Exception Requests are supported by consistent and complete
information. Such a generic example could be addressed in the Phase 2 BES
efforts. 2. Pages two and three of the Detailed Information to Support an
Exception Request contain a checklist of items that deal with transmission
facilities. Do you agree with the information being requested or is there

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79

Voter

Entity

Segment

Vote

Comment
information that you believe needs to be on page two or three that is missing?
Please be as specific as possible with your comments. Comments: SNPD agrees
that the checklist of items on pages two and three lists most of the information
that would be necessary to determine if an Exceptions Request is justified. We
suggest three modifications to the proposed language to ensure consistency with
Section 215 of the Federal Power Act, with the BES Definition, and to provide an
entity seeking an Exception with the opportunity to submit all relevant
information: 1) SNPD suggests that a new question should be added concerning
the function of the facility, which would read: “Does the facility function as a local
distribution facility rather than a Transmission facility? If yes, please provide a
detailed explanation of your answer.” Section 215(a)(1) of the FPA makes clear
that “facilities used in the local distribution of electric energy” are excluded from
the BES, 16 U.S.C. § 824o(a)(1), and the most recent draft of the BES definition
incorporates the same language. SNPD believes a question to address the function
of the Element or system subject to an Exception Request is necessary to
determine whether the Element or system is “used” in local distribution and
thereby to ensure that this statutory limit on the BES is observed in the Exceptions
process. Further, we believe a variety of information may be relevant to
determining whether a particular facility functions as local distribution rather than
as part of the BES. For example, if power is not scheduled across the facility or if
capacity on the system is not posted on the relevant OASIS, it is likely to function
as local distribution, not transmission. Similarly, if power enters the system and is
delivered to load within the system rather than moving to load located on another
system, its function is local distribution rather than transmission. SNPD proposes
the language above as an open-ended question so that the entity submitting the
Exceptions Request can provide this and any other information it deems relevant
to facility function. 2) SNPD suggests modifying question 6 to “Is the facility part a
designated Cranking Path associated with a Blackstart Resource identified in a
Transmission Operator’s restoration plan.” This language reflects the most recent
revision of the BES Definition and also helps distinguish between generators which
have Blackstart capability and those generators that are designated as a Blackstart
Resource in the Transmission Operator’s restoration plan. It is only the latter that
are included in the BES under the current draft of the definition. 3) A general

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80

Voter

Entity

Segment

Vote

Comment
“catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following
language: Is there additional information not covered in the questions above that
supports the Exception Request? If yes, please provide the information and explain
why it is relevant to the Exception Request. While SNPD believes the questions set
forth in the draft capture the information that generally would be necessary to
determine whether an Exception Request should be granted, it is foreseeable that
there may be unusual circumstances where the information called for either does
not capture the full picture or where studies other than the specific types called
for in the draft form support the Exception. An entity seeking an Exception should
have the opportunity to present any information it believes is relevant. 3. Page
four of the ‘Detailed Information to Support an Exception Request’ contains a
checklist of items that deal with generation facilities. Do you agree with the
information being requested or is there information that you believe needs to be
on page four that is missing? Please be as specific as possible with your comments.
Comments: SNPD agrees that the items listed on page 4 of the Detailed
Information to Support an Exception Request capture the information that
generally would be necessary to make a reasoned determination concerning the
BES status of a generation facility. SNPD suggests three refinements to the
questions: 1) Question 2 should be modified by adding “necessary for the
operation of the interconnected bulk transmission system” to the end of the
question, so that it reads: “Is the generator or the generator facility used to
provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between
a generator that provides, for example, reactive power or regulating reserves that
support operation of the interconnected bulk grid, and, for example, a behind-themeter generator that provides back-up generation to a specific industrial facility.
The former may be necessary for the reliable operation of the interconnected bulk
transmission system, but the latter is not. 2) The current draft of the BES Definition
contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, SNPD suggests modifying question 5 by
adding “radial, or Local Network” to the question, so that it would read: “Does the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

81

Voter

Long T Duong

Entity

Snohomish
County PUD
No. 1

Segment

1

Vote

Comment
generator use the BES, a radial system, or a Local Network to deliver its actual or
scheduled output, or a portion of its actual or scheduled output, to Load? 3) For
reasons similar to those explained in our response to Question 2, a general “catchall” question should be added that will prompt an entity submitting an Exception
Request for a generator to submit any information it believes is relevant to the
Exception that is not captured in the previous questions. We suggest the following
language: Is there additional in
Affirmative Below are SNPD’s responses to the NERC comment form for the Definition of the
BES (Project 2010-17)Technical Principles for Demonstrating BES Exceptions).
SNPD believes the refinements below will clarify the current draft of the BES
definition, without hanging the current intent. 1. Page one of the ‘Detailed
Information to Support an Exception Request’ contains general instructions. Do
you agree with the instructions presented or is there information that you believe
needs to be on page one that is missing? Please be as specific as possible with your
comments. Comments: SNPD agrees generally that the General Instructions set
forth the basic information that would be necessary to support an Exception
Request. SNPD is concerned, however, that the statement “diagram(s) supplied
should also show the Protection Systems at the interface points associated with
the Elements for which the exception is being requested” may be subject to
differing interpretations. SNPD envisions that at least four different kinds of
documents would be responsive to the description: one-line diagrams with
breakers and switches (status); identification of relays by their ANSI device
numbers; details of the DC control logic for ANSI devices; and, operational scheme
descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to
identify protection systems at the interface with the Elements for which the
Exception is sought, including any required details, such as breaker settings. SNPD
suggests that a generic example of a completed form be available to the industry
to help ensure that Exception Requests are supported by consistent and complete
information. Such a generic example could be addressed in the Phase 2 BES
efforts. 2. Pages two and three of the Detailed Information to Support an
Exception Request contain a checklist of items that deal with transmission
facilities. Do you agree with the information being requested or is there

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

82

Voter

Entity

Segment

Vote

Comment
information that you believe needs to be on page two or three that is missing?
Please be as specific as possible with your comments. Comments: SNPD agrees
that the checklist of items on pages two and three lists most of the information
that would be necessary to determine if an Exceptions Request is justified. We
suggest three modifications to the proposed language to ensure consistency with
Section 215 of the Federal Power Act, with the BES Definition, and to provide an
entity seeking an Exception with the opportunity to submit all relevant
information: 1) SNPD suggests that a new question should be added concerning
the function of the facility, which would read: “Does the facility function as a local
distribution facility rather than a Transmission facility? If yes, please provide a
detailed explanation of your answer.” Section 215(a)(1) of the FPA makes clear
that “facilities used in the local distribution of electric energy” are excluded from
the BES, 16 U.S.C. § 824o(a)(1), and the most recent draft of the BES definition
incorporates the same language. SNPD believes a question to address the function
of the Element or system subject to an Exception Request is necessary to
determine whether the Element or system is “used” in local distribution and
thereby to ensure that this statutory limit on the BES is observed in the Exceptions
process. Further, we believe a variety of information may be relevant to
determining whether a particular facility functions as local distribution rather than
as part of the BES. For example, if power is not scheduled across the facility or if
capacity on the system is not posted on the relevant OASIS, it is likely to function
as local distribution, not transmission. Similarly, if power enters the system and is
delivered to load within the system rather than moving to load located on another
system, its function is local distribution rather than transmission. SNPD proposes
the language above as an open-ended question so that the entity submitting the
Exceptions Request can provide this and any other information it deems relevant
to facility function. 2) SNPD suggests modifying question 6 to “Is the facility part a
designated Cranking Path associated with a Blackstart Resource identified in a
Transmission Operator’s restoration plan.” This language reflects the most recent
revision of the BES Definition and also helps distinguish between generators which
have Blackstart capability and those generators that are designated as a Blackstart
Resource in the Transmission Operator’s restoration plan. It is only the latter that
are included in the BES under the current draft of the definition. 3) A general

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

83

Voter

Entity

Segment

Vote

Comment
“catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following
language: Is there additional information not covered in the questions above that
supports the Exception Request? If yes, please provide the information and explain
why it is relevant to the Exception Request. While SNPD believes the questions set
forth in the draft capture the information that generally would be necessary to
determine whether an Exception Request should be granted, it is foreseeable that
there may be unusual circumstances where the information called for either does
not capture the full picture or where studies other than the specific types called
for in the draft form support the Exception. An entity seeking an Exception should
have the opportunity to present any information it believes is relevant. 3. Page
four of the ‘Detailed Information to Support an Exception Request’ contains a
checklist of items that deal with generation facilities. Do you agree with the
information being requested or is there information that you believe needs to be
on page four that is missing? Please be as specific as possible with your comments.
Comments: SNPD agrees that the items listed on page 4 of the Detailed
Information to Support an Exception Request capture the information that
generally would be necessary to make a reasoned determination concerning the
BES status of a generation facility. SNPD suggests three refinements to the
questions: 1) Question 2 should be modified by adding “necessary for the
operation of the interconnected bulk transmission system” to the end of the
question, so that it reads: “Is the generator or the generator facility used to
provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between
a generator that provides, for example, reactive power or regulating reserves that
support operation of the interconnected bulk grid, and, for example, a behind-themeter generator that provides back-up generation to a specific industrial facility.
The former may be necessary for the reliable operation of the interconnected bulk
transmission system, but the latter is not. 2) The current draft of the BES Definition
contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, SNPD suggests modifying question 5 by
adding “radial, or Local Network” to the question, so that it would read: “Does the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

84

Voter

Comment
generator use the BES, a radial system, or a Local Network to deliver its actual or
scheduled output, or a portion of its actual or scheduled output, to Load? 3) For
reasons similar to those explained in our response to Question 2, a general “catchall” question should be added that will prompt an entity submitting an Exception
Request for a generator to submit any information it believes is relevant to the
Exception that is not captured in the previous questions. We suggest the following
language: Is there additional in
Response: Please see the detailed responses to comments for Snohomish in the general consideration of comments document for the technical
criteria.
Harold Taylor

Entity

Georgia
Transmission
Corporation

Segment

Vote

1

Affirmative Throughout the document, because it will be part of a larger Exception Request
Form, it should, when possible, use terms consistent with the rest of that form
(e.g., “Request” rather than “application”).
Similarly, defined terms (even if only defined in the context of the Request Form in
which these Principles will be used) such as “Exception,” “Request,” “Element” or
“Facility” should be capitalized; if the use of lower case is intended to convey a
different meaning than what is defined, another term should be used to avoid
confusion.
The Definition and Request Form generally use the term “Element,” so it is unclear
why this document should so consistently use “facility.” For consistency,
“Element(s)” or possibly “Element(s) or Facility” should be used.
Response: The SDT has attempted to clean up any inconsistencies in terminology.
Affirmative While the Technical Principles for BES Exception are acceptable, they are quite
Baltimore Gas 1
complicated. Further simplification may ease the process.
& Electric
Company
Response: The SDT would point the commenter to the Phase II draft SAR which contains wording to allow for a review of the principles after a
12 month period of real-world experience.
Gregory S
Miller

Charles A.
Freibert

Louisville Gas
3
Affirmative LG&E and KU Energy request clarification as to how the two year data requirement
and Electric
would apply to a new facility for which the owner/operator requests an
Co.
exemption.
Response: If two years worth of data are not available, the SDT believes that a Regional Entity will accept what is available and will work with
the submitter to come up with an acceptable plan to move forward.
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

85

Voter
Anthony
Schacher

Entity
Salem Electric

Segment
3

Thomas C
Duffy

Central
Hudson Gas &
Electric Corp.

3

Jason Fortik

Lincoln Electric
System

3

Benjamin
Friederichs

Big Bend
3
Electric
Cooperative,
Inc.
Response: Thank you for your support.

Vote
Comment
Affirmative Salem Electric is encouraged to see that the standard drafting team understands
the reality that in many circumstances many small radially fed utilities have no
effect on the bulk electric system. By permitting reasonable and prudent
exceptions it will allow many of the small utilities to be able to spend our limited
time and resources on the reliability of our systems for our end users, instead of
undertaking unnecessary steps to protect a system upon which we have no effect.
The exception process is thorough but still manageable for small utilities with
limited resources. Salem Electric would like to thank the Standards Drafting Team
for their hard work and dedication in defining the Bulk Electric System.
Affirmative The ‘Technical Principles for Demonstrating BES Exceptions’ process was intended
to establish technical exception ‘criteria’ which would be used by the industry to
understand what facilities would qualify for inclusions and exclusions from the
BES. What has been produced, however, is essentially a listing of ‘electrical system
indicators’, identified on the form, which may be material to making a decision
regarding, ‘is it BES or not’. The thresholds (or acceptable values) for the
indicators, however, have not been determined. It is understood that in Phase II of
the BES Definition development process, the SDT will attempt to address these
issues but until that work has been completed, the industry will remain enmeshed
in confusion and inefficient application of resources and funding. Without these
criteria, it is very difficult to believe that this process can be transparent and
consistent.
Affirmative No comments.
Affirmative These principles seem reasonable.

END OF REPORT
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

86

Consideration of Comments

Definition of the Bulk Electric System (Project 2010-17)
The Bulk Electric System Drafting Team thanks all commenters who submitted comments on the 2nd
draft of the Definition of the Bulk Electric System (Project 2010-17). These standards were posted
for a 45-day public comment period from August 26, 2011 through October 10, 2011. Stakeholders
were asked to provide feedback on the standards and associated documents through a special
electronic comment form. There were 113 sets of comments, including comments from approximately
255 different people from approximately 156 companies representing all 10 Industry Segments as
shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-17_BES.html
The SDT made the following changes to the definition due to industry comments received:
• Clarified the wording in Inclusion I1 to indicate that at least one secondary terminal must be at
100 kV or higher to accommodate multiple terminal transformers.
• Removed the reference to the ERO Statement of Compliance Registry Criteria in Inclusion I2 so
that there is no chance of the registry values being changed and affecting the definition prior to
resolution of threshold values in Phase 2 of this project.
• Clarified that generators were not part of Inclusion I5 to avoid improperly pulling in small
generators.
• Clarified the language of Exclusion E2 by re-ordering the text as suggested.
• Clarified the language of Exclusion E3.b as suggested.
• Clarified the compliance obligation date of the revised definition in the Implementation Plan.
The SDT feels that it is important to remind the industry that Phase 2 of this project will begin
immediately after the conclusion of Phase 1. For consistency, the same SDT will follow through with
Phase 2.
Minority opinions expressed in this document are as follows:
• Some commenters feel that threshold values should be resolved in Phase 1. The SDT
acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the
BES definition. However, the SDT has responsibilities associated with being responsive to the
directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline
of January 25, 2012, and this has not afforded the SDT with sufficient time for the development
of strong technical justifications that would warrant a change from the current values that exist

•

•

through the application of the definition today. These and similar issues have prompted the SDT
to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all
recommendations for modifications to the technical aspects of the definition for inclusion in
Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in
conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to
the existing values.
Several commenters suggested that the requirement under Exclusion E3.b should apply only
during normal operating conditions, in other words, commenters felt that some power flow
should be allowed to flow from the candidate local network back into the BES as long as it only
occurred under abnormal conditions. The SDT considered the addition of the phrase “under
normal operating conditions”, as a qualifier to Exclusion E3.b, and determined that in order to
maintain the intent of a bright-line characteristic in the BES definition such a qualifier could not
be accommodated. However, the SDT pointed out that for those circumstances where a
candidate for local network is unable to utilize the local network exclusion due to an abnormal
situation that caused power to flow out of the network, the network could be a suitable
candidate that could apply for exclusion under the Exception Process.
Some commenters expressed the opinion that Blackstart Resources are not required for the
normal operation of the interconnected transmission system. The directive by FERC to revise
the definition of the BES has been interpreted by the SDT to include all Facilities necessary for
reliably operating the interconnected transmission system under both normal and emergency
conditions. This interpretation by the SDT includes situations related to Blackstart Resources
and system restoration. Blackstart Resources have the ability to be started without the support
of the interconnected transmission system in order to meet a Transmission Operator’s
restoration plan requirements for Real and Reactive Power capability, frequency, and voltage
control. The SDT maintains that Blackstart Resources must be included in the definition.

The SDT is recommending that this project be moved forward to the recirculation ballot stage.
There were two comments that were repeated multiple times throughout the various documents. The
first topic was about how to sort through the definition inclusions and exclusions, i.e., which takes
precedence. The SDT offers this guidance on that issue:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when
appropriately applied will identify the vast majority of BES Elements in a consistent manner that can be
applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall
demarcation point between BES and non-BES Elements. Additionally, the ‘core’ definition identifies the

2

Real Power and Reactive Power resources connected at 100 kV or higher as included in the BES. To fully
appreciate the scope of the ‘core’ definition an understanding of the term Element is needed. Element
is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices
such as a generator, transformer, circuit breaker, bus section, or transmission line. An
element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation
(generating resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are
included through the application of the ‘core’ definition. The Inclusions address transmission Elements
and Real Power and Reactive Power resources with specific criteria to provide for a consistent
determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as
non-BES Elements). The exclusion language is written to specifically identify Elements or groups of
Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the
specific criteria identified in the exclusion language. This does not include the exclusion of Real Power
and Reactive Power resources captured by Inclusions I2 – I5. The exclusion (E1) only speaks to the
transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied
in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter
(on the customer’s side) and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices
and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for
the reliable operation of the interconnected transmission network or an Element as non-BES that is
necessary for the reliable operation of the interconnected transmission network, the Rules of
Procedure exception process may be utilized on a case-by-case basis to either include or exclude an
Element.
The second item is about providing specific guidance on how the information on the exception request
form will be used in making decisions on inclusions/exclusions in the exception process. While not

3

technically part of this document which is about the definition, since the question did come up in these
comments, the SDT provides the following information:
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance
on this issue. The SDT would like nothing better than to be able to provide a simple continent-wide
resolution to this matter. However, after many hours of discussion and an initial attempt at doing so, it
has become obvious to the SDT that the simple answer that so many desire is not achievable. If the
SDT could have come up with the simple answer, it would have been supplied within the bright-line.
The SDT would also like to point out to the commenters that it directly solicited assistance in this
matter in the first posting of the criteria and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover
everything up front. There are always going to be extenuating circumstances that will influence
decisions on individual cases. One could take this statement to say that the regional discretion hasn’t
been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of
Procedure and looked at as a single package. When one looks at the rules being formulated for the
exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in
the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for
completion and making a recommendation to the ERO Panel, not to make the final determination. The
Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts as an
intermediary. One can counter that this places the Regional Entity in a position to effectively block a
submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes
that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C
of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of
protection requiring an independent Technical Review Panel assessment where a Regional Entity
decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure,
Section 7.0, provides NERC the option to remand the request to the Regional Entity with the mandate
to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception
request. On the other side of this equation, one could make an argument that the Regional Entity has
no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of
studies to be provided and how to interpret the information aren’t shown in the request process. The
SDT again points to the variations that will abound in the requests as negating any hard and fast rules
in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been
handled before by either party and there is a great deal of professional experience involved on both
the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the
SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.

4

Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific
guidelines for them to follow in making their decision. The SDT re-iterates the problem with providing
such hard and fast rules. There are just too many variables to take into account. Providing concrete
guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made.
The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section
3.1 where the basic premise on evaluating an exception request must be based on whether the
Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power
system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result ofa sudden
disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT
firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the
experience gained by having this same panel review multiple requests will result in an equitable,
transparent, and consistent approach to the problem. The SDT would also point out that there are
options for a submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure
changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception
request form will mandate a negative response to the request. To that item, the SDT refers
commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the proposed
Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request
shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made
in response to industry comments. The SDT believes that these clarifications will make the process
tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase 2 of this project that calls for a review of the
process after 12 months of experience. The SDT believes that this time period will allow industry to see
if the process is working correctly and to suggest changes to the process based on actual real-world
experience and not just on suppositions of what may occur in the future. Given the complexity of the
technical aspects of this problem and the filing deadline that the SDT is working under for Phase 1 of
this project, the SDT believes that it has developed a fair and equitable method of approaching this
difficult problem. The SDT asks the commenter to consider all of these facts in making your decision
and casting your ballot and hopes that these changes will result in a favorable outcome.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,

5

you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.

6

Index to Questions, Comments, and Responses
1.

The SDT has made clarifying changes to the core definition in response to industry comments.
Do you agree with these changes? If you do not support these changes or you agree in general
but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments. ....................................................................................................... 20

2.

The SDT has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1 (transformers)? If you do not support this change or
you agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ............................................................................ 77

3.

The SDT has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I2 (generation) including the reference to the ERO
Statement of Compliance Registry Criteria? If you do not support this change or you agree in
general but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments. ....................................................................................................... 97

4.

The SDT has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I3 (blackstart)? If you do not support this change or
you agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ...........................................................................139

5.

The SDT has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I4 (dispersed power)? If you do not support this
change or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. ...............................................................158

6.

The SDT has added specific inclusions to the core definition in response to industry comments.
Do you agree with Inclusion I5 (reactive resources)? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments. ........................................................................................190

7.

The SDT has revised the specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E1 (radial system)? If you do not support this change
or you agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ...........................................................................223

8.

The SDT has revised the specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E2 (behind-the-meter generation)? If you do not
support this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments. .........................................269

9.

The SDT has revised the specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E3 (local network)? If you do not support this change
or you agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ...........................................................................289

10.

The SDT has added specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E4 (reactive resources)? If you do not support this
change or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. ...............................................................338

7

11.

Are there any other concerns with this definition that haven’t been covered in previous
questions and comments remembering that the exception criteria are posted separately for
comment?.........................................................................................................................................358

RFC Suggested changes to definition: ...................................................................................................411
Pacificorp additional comments: ............................................................................................................413
Rochester Diagrams:. ..............................................................................................................................415

8

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Gerald Beckerle

SERC OC Standards Review Group

Additional Member Additional Organization Region Segment Selection
1.

Jeff Harrison

AECI

1, 3, 5, 6

2.

Eugend Warnecke

Ameren

1, 3

3.

Dan Roethemeyer

Dynegy

5

4.

Danny Dees

MEAG

SERC

1, 3, 5

5.

Brad Young

LGE/KU

SERC

3

6.

Marc Butts

Southern

SERC

1, 5

7.

Scott Brame

NCEMC

SERC

1, 3, 4, 5

8.

Tim Hattaway

PowerSouth

SERC

1, 5

9.

Steve McElhaney

SMEPA

SERC

1, 3, 4, 5

TVA

SERC

1, 3, 5, 6

10. Joel Wise

X

2

3

X

4

5

6

7

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

11. Dwayne Roberts

OMU

SERC

3, 5

12. Jake Miller

Dynegy

SERC

5

13. Andy Burch

EEI

SERC

5

14. Tom Burns

PJM

SERC

2

15. M. R. Castello

Alabama Power

SERC

3

16. Bob Dalrymple

TVA

SERC

1, 3, 5, 6

17. Robert Thomasson BREC

SERC

1

18. Randy Hubbert

Southern

SERC

1, 5

19. Phil Whitmer

Southern

SERC

1, 5

20. Alvis Lanton

SIPC

SERC

1

21. Jim Case

Entergy

SERC

1, 3, 6

22. Mike Hirst

Cogentrix

SERC

5

23. Gene Delk

SCEandG

SERC

1, 3, 5, 6

24. Mike Bryson

PJM

SERC

2

25. John Troha

SERC

SERC

10

2.

Group
David Taylor
No additional members listed.

NERC Staff Technical Review

3.

Northeast Power Coordinating Council

Group
Additional Member

Guy Zito

Additional Organization

2

3

4

5

6

7

8

9

10

X

Region Segment Selection

1.

Alan Adamson

New York State Reliability Council, LLC

NPCC 10

2.

Gregory Campoli

New York Independent System Operator

NPCC 2

3.

Kurtis Chong

Independent Electricity System Operator

NPCC 2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5.

Chris de Graffenried Consolidated Edison Co. of New York Inc. NPCC 1

6.

Gerry Dunbar

Northeast Power Coordinating Council

7.

Peter Yost

Consoldiated Edison Co. of New York, Inc. NPCC 3

8.

Mike Garton

Dominion Resources Services, Inc.

9.

Kathleen Goodman ISO - New England

NPCC 10
NPCC 5
NPCC 2

10. Chantel Haswell

FPL Group, Inc.

NPCC 5

11. David Kiguel

Hydro One Networks Inc.

NPCC 1

12. Michael Lombardi

Northeast Utilities

NPCC 1

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

13. Randy MacDonald

New Brunswick Power Transmission

NPCC 9

14. Bruce Metruck

New York Power Authority

NPCC 6

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

16. Robert Pellegrini

The United Illumianting Company

NPCC 1

17. Si Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

18. David Ramkalawan Ontario Power Generation, Inc.

NPCC 5

19. Saurabh Saksena

National Grid

NPCC 1

20. Michael Schiavone

National Grid

NPCC 1

21. Wayne Sipperly

New York Power Authority

NPCC 5

22. Donald Weaver

New Brunswick System Operator

NPCC 2

23. Ben Wu

Orange and Rockland Utilities

NPCC 1

4.

Charles Long

Group
Additional Member

Additional Organization

SERC Planning Standards Subcommittee

SERC

SERC

10

2. John Sullivan

Ameren Services Co.

SERC

1

3. James Manning

NC Electric Membership Corp.

SERC

1

4. Philip Kleckley

SC Electric and Gas Co.

SERC

1

5. Bob Jones

Southern Company Services

SERC

1

6. Jim Kelley

PowerSouth Energy Cooperative SERC

1

Group

Jonathan Hayes

Additional Member

X

3

4

5

6

7

8

9

10

X

Region Segment Selection

1. Pat Huntley

5.

2

Southwest Power Pool Standards Review
Team

Additional Organization

X

Region Segment Selection

1.

Gregory McAuley

Oklahoma Gas and Electric

SPP

1, 3, 5

2.

Harold Wyble

Kansas City Power and Light

SPP

1, 3, 5, 6

3.

Jamie Strickland

Oklahoma Gas and Electric

SPP

1, 3, 5

4.

Mark Wurm

Board of Public Utilities City of McPherson SPP

1, 3, 5

5.

John Allen

City Utilities of Springfield

SPP

1, 4

6.

Louis Guidry

CLECO

SPP

1, 3, 5

7.

Robert Cox

Lea County Electric

SPP

8.

Sean Simpson

Board of Public Utilities City of McPherson SPP

9.

Stephen McGie

Coffeyville

1, 3, 5

SPP

11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

10. Valerie Pinamonti

American Electric Power

SPP

11. Michael Bensky

2

3

4

5

6

7

8

9

10

1, 3, 5

SPP

12. Robert Rhodes

Southwest Power Pool

SPP

2

13. Jonathan Hayes

Southwest Power Pool

SPP

2

6.

Frank Gaffney

Group

Florida Municipal Power Agency

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Tim Beyrle

City of New Smyrna Beach FRCC

4

2. Greg Woessner

Kissimmee Utility Authority FRCC

3

3. Jim Howard

Lakeland Electric

FRCC

3

4. Lynne Mila

City of Clewiston

FRCC

3

5. Joe Stonecipher

Beaches Energy Services FRCC

1

6. Cairo Vanegas

FPUA

FRCC

4

7. Randy Hahn

Ocala Utility Services

FRCC

3

7.

Group
Steve Rueckert
No additional members listed.

WECC Staff

8.

Bonneville Power Administration

Group

Chris Higgins

Additional Member

Additional Organization
Transmission Internal Ops

WECC 1

2. Steve Larson

General Counsel

WECC 1, 3, 5, 6

3. Rebecca Berdahl

Long Term Sales and Purchases WECC 3

4. John Anasis

Technical Operations

WECC 1

5. Erika Doot

Generation Support

WECC 3, 5, 6

6. Don Watkins

System Operations

WECC 1

7. Fran Halpin

Duty Scheduling

WECC 5

8. Joe Rogers

Transfer Services

WECC 3

Group
Additional Member

Bruce Wertz
Additional Organization

X

X

X

X

Region Segment Selection

1. Lorissa Jones

9.

X

Texas RE NERC Standards Subcommittee
Region

X

Segment Selection

1.

David Baker

Bandera Electric Cooperative

ERCOT

NA

2.

Gary L. Rayborn

Wharton County Electric Cooperative ERCOT

NA

3.

Phillip Amaya

Magic Valley EC

ERCOT

NA

4.

Gary Nietsche

Fayette EC

ERCOT

NA

12

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

5.

Tim Soles

Occidental Power Services

ERCOT

NA

6.

Lee Stubblefield

City of Fredericksburg

ERCOT

NA

7.

Lowell Ogle

City of Brenham

ERCOT

NA

8.

John Ohlhausen

Medina EC

ERCOT

NA

9.

Jimmy Sikes

City of Georgetown

ERCOT

NA

10. Ron Hughes

San Patricio EC

ERCOT

NA

11. Lou White

City of San Marcos

ERCOT

NA

12. David Peterson

Central Texas EC

ERCOT

NA

13. Gerry Nunan

Karnes EC

ERCOT

NA

14. Joe Farley

City of Weatherford

ERCOT

NA

15. Flint Geagley

City of Lampasas

ERCOT

NA

16. William Bissette

City of Seguin

ERCOT

NA

17. Brian Green

Farmers EC

18. Jose Escamilla

CPS Energy

ERCOT

19. Pam Zdenek

Infigen

NA - Not Applicable NA

10.

Joe Tarantino

Group

2

3

4

5

6

7

8

9

10

NA
NA

Balancing Authority Northern California

X

Additional Member Additional Organization Region Segment Selection
1. SMUD

WECC 1, 3, 4, 5, 6

2. MID

WECC 4, 5

3. City of Redding

WECC 3, 4, 5, 6

4. City of Roseville

WECC NA

11.

Group

Additional Member

ACES Power Marketing Standards
Collaborators

Jean Nitz
Additional Organization

1. Mohan Sachdeva

Buckeye Power, Inc.

2. Susan Sosbe

Wabash Valley Power Association SERC

12.

Group

RFC

Louis Slade

X

Region Segment Selection
3, 4
3

Dominion

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Connie Lowe

RFC

5, 6

2. Mike Garton

MRO

5, 6

3. Michael Gildea

NPCC 5, 6

13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

4. Michael Crowley

SERC

1, 3

5. Sean Iseminger

SERC

5, 6

13.

Group

David Thorne

Pepco Holdings Inc and Affiliates

2

3

X

X

X

X

X

X

4

5

6

7

8

9

10

Additional Member Additional Organization Region Segment Selection
1. Carl Kinsley

Delmarva Power and Light
Co

RFC

1, 3

14.

Group
Cynthia S. Bogorad
Transmission Access Policy Study Group
Please see www.tapsgroup.org for TAPS’ more than 40 members.
Electricity Consumers Resource Council
15.
Group
John P. Hughes
(ELCON)
No additional members listed.
16.

Group

William D Shultz

Additional Member

Additional Organization

Southern Company Generation SERC

5

Southern Company Generation SERC

5

3. Therron Wingard

Southern Company Genreation SERC

5

4. Ed Goodwin

Southern Company Generation SERC

5

17.

David Dockery or John
Group
Bussman
No additional members listed.
18.

Group
Janelle Marriott Gill
No additional members listed.
Additional Member

X

X

X

X

Region Segment Selection

2. Terry Crawley

Group

X

X

Southern Company Generation

1. Tom Higgins

19.

X

Will Smith

AECI and member GandTs, Central Electric
Power Cooperative, KAMO Power, MandA
Electric Power Cooperative, Northeast
Missouri Electric Power Cooperative, NW
Electric Power Cooperative Sho-Me Power
Electric Power Cooperative
Tri-State Generation and Transmission
Assn., Inc. Energy Management
MRO NERC Standards Review Forum (NSRF)

Additional Organization

X

X

X

X

X

X

X

Region Segment Selection

1.

Mahmood Safi

Omaha Public Utility District

MRO

1, 3, 5, 6

2.

Chuck Lawrence

American Transmission Company

MRO

1

14

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

3.

Tom Webb

Wisconsin Public Service Corporation MRO

3, 4, 5, 6

4.

Jodi Jenson

Western Aera Power Administration

MRO

1, 6

5.

Ken Goldsmith

Alliant Energy

MRO

4

6.

Alice Ireland

Xcel Energy

MRO

1, 3, 4, 6

7.

Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

8.

Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

9.

Joe DePoorter

Madison Gas and Electric

MRO

3, 4, 5, 6

10. Scott Nickels

Rochester Public Utilities

MRO

4

11. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

12. Marie Knox

Midwest ISO Inc.

MRO

2

13. Lee Kittleson

Otter Tail Power Company

MRO

1, 3, 4, 5

14. Scott Bos

Muscantine Power and Water

MRO

1, 3, 5, 6

15. Tony Eddleman

Nebraska Public Power District

MRO

1, 3, 5

16. Mike Brytowski

Great River Energy

MRO

1, 3, 5, 6

17. Richard Burt

Minnkota Power Cooperative

MRO

1, 3, 5, 6

18. Will Smith

Midwest Reliability Orgnization

MRO

10

20.

Al DiCaprio

Group

2

3

4

5

6

7

8

9

10

X

IRC Standards Review Committee

Additional Member Additional Organization Region Segment Selection
1. Steve Myers

ERCOT

ERCOT 2

2. Terry Bilke

MISO

MRO

2

3. Don Weaver

NBSO

NPCC

2

4. Mark Thompson

AESO

WECC 2

5. Greg Campoli

NYISO

NPCC

2

6. Charles Yeung

SPP

SPP

2

7. Ben Li

IESO

NPCC

2

21.

Individual

Ian Grant

Tennessee Valley Authority

X

X

X

22.

Individual

Janet Smith

Arizona Public Service Company

Individual

David Kiguel

Hydro One Networks Inc.

X
X

X

23.

X
X

24.

Individual

Mark Conner

Tri-State GandT

X

25.

Individual

Brandy A. Dunn

Western Area Power Administration

X

X
X

15

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

26.

Individual

2

3

Holland Board of Public Works

Individual
28. Individual

Katie Coleman
Sandra Shaffer

Texas Industrial Energy Consumers
PacifiCorp

29.

Individual

Heather Hunt

NESCOE

30.

Individual

Antonio Grayson

Southern Company

31.

Individual

Irion A. Sanger

Industrial Customers of Northwest Utilities

32.

Individual

Doug Hohlbaugh

FirstEnergy Corp.

X

X

33.

Individual

John Bee

Exelon

X

X

34.

Individual

Gary Carlson

Michigan Public Power Agency

35.

Individual

Richard Malloy

Idaho Falls Power

36.

Individual

Anthony Jablonski

ReliabilityFirst

37.

Individual

Colin Anderson

X

Individual

Thomas C. Duffy

Ontario Power Generation Inc.
Central Hudson Gas and Electric
Corporation

39.

Individual

Manny Robledo

City of Anaheim

X

40.

Individual

Deborah J Chance

Chevron U.S.A. Inc.

41.

Individual

Alice Ireland

X

Individual

Edwin Tso

Xcel Energy
Metropolitan Water District of Southern
California

43.

Individual

Greg Rowland

Duke Energy

X

44.

Individual

David Proebstel

Clallam County PUD No.1

Individual
46. Individual

Richard Salgo
Jerome Murray

NV Energy
Oregon Public Utility Commission Staff

47.

Individual

Mary Jo Cooper

Z Global Engineering and Energy Solutions

48.

Individual

Eric Salsbury

Consumers Energy

X
X

49.

Individual

Tracy Richardson

Springfield Utility Board

X

38.

42.

45.

5

6

7

8

9

10

X

William Bush

27.

4

X
X

X

X

X
X

X

X
X
X

X

X

X
X

X

X
X
X

X
X

X

X

X

X

X

X

X

X

X

X
X
X
X

X

16

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

50.

Individual

Kerry Wiedrich

Mission Valley Power

Individual
52. Individual

Denise M. Lietz
Chris de Graffenried

Puget Sound Energy
Consolidated Edison Co. of NY, Inc.

53.

Individual

Gail Shaw

Tillamook PUD

54.

Individual

Thad Ness

55.

Individual

56.

2

3

4

5

6

9

10

X

X

X

X

X

X

American Electric Power

X

X
X

X

X

Joe Petaski

Manitoba Hydro

X

X

X

X

Individual

Robert Ganley

Long Island Power Authority

X

57.

Individual

John A. Gray

The Dow Chemical Company

58.

Individual

Rick Hansen

Individual

Donald E. Nelson

City of St. George
Massachusetts Department of Public
Utilities

60.

Individual

David Burke

Orange and Rockland Utilities, Inc.

61.

Individual

Bud Tracy

Blachly-Lane Electric Cooperative (BLEC)

X

62.

Individual

Roger Meader

Coos-Curry Electric Cooperative (CCEC)

X

63.

Individual

Kathleen Goodman

ISO New England Inc

64.

Individual

Dave Markham

Central Electric Cooperatve (CEC)

X

65.

Individual

Dave Hagen

Clearwater Power Company (CPC)

X

66.

Individual

Eric Lee Christensen

Snohomish County PUD

X

X

67.

Individual

Roman Gillen

Consumer's Power Inc.

X

X

68.

Individual

Dave Sabala

Douglas Electric Cooperative (DEC)

X

69.

Individual

Bryan Case

Fall River Rural Electric Cooperative (FALL)

X

70.

Individual

Rick Crinklaw

Lane Electric Cooperative (LEC)

X

71.

Individual

Michael Henry

Lincoln Electric Cooperative (LEC)

72.

Individual

Jon Shelby

Northern Lights Inc. (NLI)

73.

Individual

Randy MacDonald

NBPT

74.

Individual

Ray Ellis

Okanogan County Electric Cooperative

59.

8

X
X

51.

7

X
X

X
X

X

X

X

X
X

X

X

X

X

X

X
X
X
X

17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

7

8

9

10

(OCEC)
X

75.

Individual

Donald Jones

Texas Reliability Entity

76.

Individual

Diane Barney
Rick Paschall

New York State Dept of Public Service
Pacific Northwest Generating Cooperative
(PNGC)

Individual
79. Individual

Heber Carpenter
Marc Farmer

Raft River Rural Electric Cooperative (RAFT)
West Oregon Electric Cooperative

80.

Individual

John Seelke

PSEG Services Corp

81.

Individual

Sylvain Clermont

Hydro-Quebec TransEnergie

82.

Individual

Michael Falvo

X

Individual

John Allen

Independent Electricity System Operator
Rochester Gas and Electric and New York
State Electric and Gas

84.

Individual

Steve Eldrige

Umatilla Electric Cooperative (UEC)

X

85.

Individual

Steve Alexanderson

Central Lincoln

86.

Individual

Allan Long

Memphis Light, Gas and Water Division

87.

Individual

Shane Sweet

Harney Electric Cooperative, Inc.

X

88.

Individual

Russell Noble

Cowlitz County PUD

X

89.

Individual

Brian Evans-Mongeon

Utility Services, Inc.

90.

Individual

Martyn Turner

LCRA Transmission Services Corporation

X

91.

Individual

Saurabh Saksena

National Grid

X

X

92.

Individual

Jennifer Flandermeyer

Kansas City Power and Light Company

X

X

93.

Individual

Darryl Curtis

Oncor Electric Delivery Company LLC

X

94.

Individual

Joe Tarantino

Sacramento Municipal Utility District

X

X

Individual
96. Individual

Don Schmit
David M. Conroy

Nebraska Public Power District
Central Maine Power Company

X

X

X

97.

Individual

Kirit Shah

Ameren

X

X

98.

Individual

Guy Andrews

Georgia System Operations Corporation

X
X

77.

Individual

78.

83.

95.

X
X

X

X

X

X
X
X
X

X

X

X
X

X

X
X

X

X

X
X

X
X

X

X

X

X

X

X
X

X

18

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

99.

Individual

X

2

3

X

Scott Miller

MEAG Power

101. Individual

Paul Titus
Linda Jacobson-Quinn

Northern Wasco County PUD
Farmington Electric Utility System

102. Individual

Allen Rinard

South Houston Green Power, LLC

103. Individual

Angela P Gaines

Portland General Electric Company

X

X

104. Individual

Andrew Gallo

City of Austin dba Austin Energy

X

X

105. Individual

Martin Kaufman

ExxonMobil Research and Engineering

X

106. Individual

David Kahly

Kootenai Electric Cooperative

107. Individual

Andy Pusztai

ATC LLC

X

108. Individual

Bo Jones

Westar Energy

X

109. Individual

Mary Downey

Redding Electric Utility

110. Individual

Paul Cummings

City of Redding

111. Individual

Keith Morisette

Tacoma Power

112. Individual

Rex Roehl

Indeck Energy Services

113. Individual

Frank Cumpton

BGE

100. Individual

4

5

6

7

8

9

10

X

X
X

X

X
X

X
X

X

X

X
X
X
X

X

X

X

X

X

X
X

X

X

X

X

X
X

19

1.

The SDT has made clarifying changes to the core definition in response to industry comments. Do you agree with these
changes? If you do not support these changes or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.

Summary Consideration: After consideration of the comments below, the SDT has decided against making any changes to the draft
core definition as the changes suggested do not provide additional clarity. The SDT acknowledges and appreciates the comments and
recommendations associated with modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES
definition. However, the SDT has responsibilities associated with being responsive to the directives established in Orders No. 743 and
743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the
development of strong technical justifications that would warrant a change from the current values that exist through the application
of the definition today. These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT
to address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly
assess the threshold values and provide compelling justification for modifications to the existing values.
No changes were made to the core definition.
Organization
NERC Staff Technical Review

Yes or No

Question 1 Comment

No

The sentence, “This does not include facilities used in the local distribution
of electricity,” is a commentary or statement of objective rather than a
definition of what facilities comprise the BES. Including such information
that does not define the facilities to be included or excluded will be a source
of confusion in applying the definition. The BES definition as proposed by
the SDT may in fact include such facilities and as stated in paragraph 37 of
Order 743: “Determining where the line between “transmission” and “local
distribution” lies, which includes an inquiry into which lower voltage
“transmission” facilities are necessary to operate the interconnected
transmission system, should be part of the exemption process the ERO
develops.”If the drafting team believes that Exclusions E1 through E4 in the
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Question 1 Comment
definition are sufficient to not include any facilities used in the local
distribution of electricity then those exclusions, and not the aforementioned
sentence in the “core definition,” define the facilities that are not included
(i.e., the sentence is unnecessary).

Response: The SDT discussed your comment and decided against deletion of the sentence in the core definition that refers to
facilities used in the local distribution of electricity. There were many commenters who were in favor of the inclusion of the
sentence in the core definition. Additionally, the SDT does not agree with the premise that the exclusions are fully sufficient to not
include any facilities used in the local distribution of electricity in the definition. No change made.
Southwest Power Pool Standards
Review Team

No

The last sentence of the core states that no distribution facilities will be
included, but some of these facilities could be included due to blackstart
resources. We don’t disagree with the idea of removing distribution
facilities, but would like to see some clarification or qualifier.

Westar Energy

No

The last sentence of the core part of the definition states that no distribution
facilities will be included, but we feel that some of these facilities could be
included due to also being blackstart resources. We agree with the idea of
removing distribution facilities, but would like to see some clarification or a
qualifier with regards to blackstart resources.

Response: The inclusion of Blackstart Resources in Inclusion I3 is meant to include the blackstart generators but is not meant to
include any local distribution facilities at voltage levels < 100 kV that may connect the Blackstart Resources to the BES. No change
made.
Southern Company Generation

No

We have two concerns with the changes that are proposed. First, the use
of "effective dates" and "compliance obilgations ... shall begin" in the
implementation plan of the definition change is confusing. Effective date is
usually used to indicate the mandatory and enforceable date of a new item.
Second, a radial circuit from 100kV to a generating facility with two (2) 20
MVA generators seems to meet both the inclusion criteria (I2) and the
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Question 1 Comment
exculsion criteria (E1). Which criteria is dominant, inclusion or exclusion?

Response: See the responses addressing the Effective Dates and the C compliance Obligations in Question 11.
As to the second part of your question, the two generators would be included in the BES by virtue of their gross individual
nameplate ratings. However, the radial circuit itself would be excluded since the gross generation was not equal to or greater than
75 MVA.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the
vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES
and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100
kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is
needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 –
I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks)
should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
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Question 1 Comment

Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion
I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or
exclude an Element.
National Grid

No

While we agree that the BES should not include facilities used in the local
distribution of energy, we feel that this is already captured in Exclusion E3.
Stating it in the core definition is confusing, and should be eliminated. We
suggest removing “This does not include facilities used in the distribution of
electric energy” from the core definition.

IRC Standards Review Committee

No

While we agree with the changes to the definition, we do not understand
the purpose of the final sentence “This does not include facilities used in the
local distribution of electric energy.” Since the issue of local (distribution)
networks is addressed under Exclusion E3, we do not see the added benefit
of the referenced text.

Response: The SDT discussed your comment and decided against deletion of the sentence in the core definition that refers to
facilities used in the local distribution of electricity. There were many commenters who were in favor of the inclusion of the
sentence in the core definition. Furthermore, Exclusion E3 does not by itself define the entire population of facilities used in the
local distribution of electricity.
Hydro One Networks Inc.

No

Although we agree with the concept and commend the SDT for developing
explicit inclusions and exclusions as part of the definition, we believe there
are several outstanding issues and concerns listed as our response to Q11
that need to be addressed by the SDT and by NERC as the ERO.

Response: Please see the detailed response to Q11.
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Massachusetts Department of Public
Utilities

Yes or No

Question 1 Comment

No

The Massachusetts Department of Public Utilities (“MA DPU”) appreciates
the opportunity to provide comments on the second draft definition of the
Bulk Electric System (“BES”). Massachusetts is the largest state by
population and load in New England. It comprises 46% of both the region’s
population and electricity consumption. Generating plants located in
Massachusetts represent 42% of New England’s capacity and our capitol
city, Boston, is the largest load center in the region. Some of the revisions
since the last posting of the draft BES definition have improved the
proposed language. However, the MA DPU has a number of concerns
regarding both the substance of the definition and the process for
developing this standard: 1) Phased Approach. While well-intentioned,
separating the BES definition project into two separate phases is
problematic from both a procedural and substantive perspective. While we
recognize that the filing due date is rapidly approaching, the BES definition
cannot be considered in a vacuum, divorced from the concerns raised by a
number of parties in response to past postings of the BES definition. The
issues NERC has identified for consideration during the proposed “Phase 2”
are inseparable from the development of the BES definition (e.g., generation
thresholds, technical justification for the 100 kV threshold) and should be
squarely addressed before a definition is adopted and ratepayers incur costs
related to compliance with mandates that may or may not be revised
through the second phase of the project. The importance of considering
concerns before adopting a definition is heightened by the proposed twoyear implementation requirement. This short implementation period almost
guarantees that entities will commit resources shortly after adoption of the
definition to ensure compliance within the mandated period. In other
words, ratepayers will bear costs related to compliance irrespective of any
change resulting from the Phase 2 process or the exception process.
Expediency, while understandable given the filing deadline, must be
balanced against the risk that a multi-phased approach could lead to
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Question 1 Comment
significant consumer costs without attendant meaningful reliability benefits.
2) Cost-Benefit Analysis. A cost impact analysis should be performed as part
of developing any reliability standard. However, the development of the
BES definition has failed to consider the cost impacts of the definition (and
its inclusions and exclusions) and has not weighed these impacts against
identified benefits that the definition would achieve. The MA DPU
supported the May 21, 2011 comments from the New England States
Committee on Electricity (“NESCOE”) on the last posting of the BES
definition. In these comments, NESCOE stated that “any new costs a revised
definition imposes - which fall ultimately on consumers - should provide
meaningful reliability benefits.” A cost-benefit analysis should be integral to
the development of a BES definition and, indeed, any reliability standard.
This analysis should include a probabilistic risk assessment examining the
likelihood of an event and the costs and risks resulting from such event,
which should be weighed against the costs of complying with the proposed
reliability measures.
3) Technical Justification. In addition to performing a cost-benefit analysis, a
technical basis must be provided to justify a proposed reliability standard.
However, the proposed BES definition does not provide a technical
justification for the 100 kV threshold, the threshold for generation
resources, or other elements of the definition. As stated above, while wellintentioned and understandable, deferring this technical justification to a
later and separate phase of the project is a flawed and potentially costly
approach. Providing a technical justification for a reliability standard is a
core function of standards development and should be addressed at the
forefront of the process rather than relegated to a separate phase largely
undertaken after a standard is filed. In Order 743, the Federal Energy
Regulatory Commission (“FERC” or “the Commission”) directed NERC to
revise the BES definition. Revision to Electric Reliability Organization
Definition of Bulk Electric System, Order No. 743A, 134 FERC ¶ 61,210
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Yes or No

Question 1 Comment
(Mar. 17, 2011) at P 8, citing to Revision to Electric Reliability Organization
Definition of Bulk Electric System, Order No. 743, 133 FERC ¶ 61,150
(2010). The Commission stated that one way NERC could address the
technical and policy concerns FERC had identified would be to institute a
“bright-line threshold that includes all facilities operated at or above 100 kV
except defined radial facilities, and establish an exemption process and
criteria for excluding facilities [NERC] determines are not necessary for
operating the interconnected transmission network.” Id. at P 8. However,
the Commission made clear in Order 743 that NERC may propose an
alternative proposal and that the 100 kV threshold is an “initial line of
demarcation” to be refined through exclusions and exemptions. Id. at PP 8,
40. Accordingly, unless and until NERC provides a technical justification for
its approach, the Standard should use the 100 kV threshold concept in a way
that is consistent with the Commission’s guidance. Specifically, the two
criteria that bound the BES definition are (1) the statutory exclusion of
facilities used in local distribution, and (2) the requirement that the facilities
included be “necessary for reliable operation” of the interconnected
transmission system. A definition that recognizes these limits, coupled with
an efficient and transparent exception process, would appear to meet the
Commission’s expectations. For these reasons, absent a technical
justification for imposing a 100 kV threshold, the MA DPU supports the
revised core definition offered by NESCOE in comments filed on this 2nd
Draft: “All Transmission Elements operated at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher that are
necessary for the reliable operation of the interconnected transmission
network, including but not limited to the facilities listed below as Inclusions,
and excluding (1) facilities that are used in the local distribution of electric
energy, and (2) the facilities and systems listed below as Exclusions. Other
Elements may be included or excluded on a case-by-case basis through the
Rules of Procedure exception process.”
The definition of the BES is
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Yes or No

Question 1 Comment
critical to NERC’s role as ERO and will have a significant impact on system
reliability and cost to consumers. While FERC had concerns that the existing
definitions for the bulk power system were under-inclusive, the proposed
Standard, as drafted, risks erring in the opposite direction and appears
inconsistent with the Commission’s guidance in this area.

NESCOE

No

The New England States Committee on Electricity (“NESCOE”) appreciates
the opportunity to provide comments on the revised BES definition.
NESCOE is New England’s Regional State Committee and represents the
collective views of the six New England states. Please consider this
submission to reflect the views of the States of Connecticut, Maine,
Massachusetts, New Hampshire, Rhode Island and Vermont. Some of these
states may submit separate comments in addition to this joint filing.
NESCOE does not believe that the proposed changes address our
fundamental concerns. As NESCOE pointed out in its comments on the
previous draft, the definition’s reliance on a 100 kV “bright line” threshold
may impose substantial costs on New England ratepayers without achieving
meaningful reliability benefits. NERC and the drafting team have not
provided any technical justification for imposing the 100 kV test, despite its
potential for over-inclusiveness and significant costs. NESCOE believes that
the Federal Energy Regulatory Commission (“FERC” or “the Commission”)
recognizes the need to avoid this result. As the Commission pointed out in
Order 743A, Order 743 does not mandate the application of a 100 kV
threshold, and NERC is free to propose alternatives. Unless and until NERC
provides a technical justification for its approach, the Standard should use
the 100 kV threshold concept in a way that is consistent with the
Commission’s guidance. Specifically, the Standard should make clear that
the 100 kV threshold is an “initial line of demarcation,” and not the end of
the analysis. According to Order 743A, the two criteria that bound the BES
definition are (1) the statutory exclusion of facilities used in local
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Yes or No

Question 1 Comment
distribution, and (2) the requirement that the facilities included be
“necessary for reliable operation” of the interconnected transmission
system. A definition that recognizes these limits, coupled with an efficient
and transparent exceptions process, would meet FERC’s expectations. The
proposed definition does not meet this standard. For these reasons, absent
a technical justification for imposing a 100 kV threshold, NESCOE suggests
the following revised core definition: “All Transmission Elements operated
at 100 kV or higher and Real Power and Reactive Power resources connected
at 100 kV or higher that are necessary for the reliable operation of the
interconnected transmission network, including but not limited to the
facilities listed below as Inclusions, and excluding (1) facilities that are used
in the local distribution of electric energy, and (2) the facilities and systems
listed below as Exclusions. Other Elements may be included or excluded on
a case-by-case basis through the Rules of Procedure exception process.”
Where FERC had concerns that the existing definitions for the bulk power
system were under-inclusive, the proposed Standard risks erring in the
opposite direction. Because the definition of the BES is critical to NERC’s
role as ERO and will have a significant impact on ratepayers, NESCOE
believes the drafting team should track FERC’s guidelines as closely as
possible, or provide a specific technical justification for relying on the 100 kV
bright line threshold.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and
non-BES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT
has pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
contracting the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges the
current BES definition has varying degrees of Regional application and has resulted in different conclusions on what is currently
considered to be part of the BES. This inconsistency in the application and subsequent results were also identified by the
Commission in Orders No. 743 and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition
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Yes or No

Question 1 Comment

coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on Regions.
Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid on
a continent-wide basis. Therefore, the SDT believes that the best opportunity to address cost concerns will be through the
development of Regional transition plans once the definition has been approved by the Commission.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that
would warrant a change from the current values that exist through the application of the definition today. These and similar issues
have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in
conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
ReliabilityFirst

No

This seems very confusing, but should be clear and easy enough for anyone
to pickup, read, understand, apply and arrive at the same conclusion. The
term local distribution needs to be either defined or have some guidance
provided on what it is intended to cover. A suggestion for defining
distribution would be that radials and local networks makeup distribution
facilities. Radials usually terminate at distribution or customer substations
and local networks are primarily used for distribution also. The Commission
granted NERC the ability to define distribution in Order 743-A, paragraphs
67-71.
It is not clear if the BES is meant to be a contiguous system or not from the
language in the revised definition. ReliabilityFirst Staff believes that the BES
should be contiguous, and therefore, any facilities needed to connect real
and reactive resources to the BES need to be included. To maintain
reliability, the BES cannot have pockets of generation that are not connected
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Yes or No

Question 1 Comment
to the BES via BES facilities. ReliabilityFirst Staff believes that without
including the paths from BES generators in the BES, the reliable operation of
the system could be jeopardized if the paths are unavailable due to noncompliance to Reliability Standards. For example, wind farm collector
systems at voltages operated at less than 100 kV should be included in the
BES for the above reason.

Response: The SDT discussed your comment and decided against deletion of the sentence in the core definition that refers to
facilities used in the local distribution of electricity. There were many commenters who were in favor of the inclusion of the
sentence in the core definition. Additionally, the SDT does not agree that Exclusions E1 and E3 are fully sufficient to not include
any facilities used in the local distribution of electricity in the definition. No change made.
The SDT has previously stated the existing BES definition does not mandate contiguity of the BES and the proposed definition is
carrying that principle forward. Simply making a blanket statement the BES must be contiguous could have unintended
consequences. However, the BES understands the importance of the concept and has agreed to discuss contiguity issues in Phase
2 of this project.
Ontario Power Generation Inc.

No

OPG continues to question the need for the changes required (and costs
imposed) as a result of this new definition. This is particularly true in the
NPCC region where an impact based methodology is being used to
determine the set of BES elements. A very clear 100kV bright line, as
proposed in this draft, will dramatically increase the list of generation
elements that must meet reliability standards, without a corresponding
increase in wide-area reliability. OPG recommends that the work planned for
phase II, technical justification of the generation and voltage thresholds,
should be completed before implementing the new definition of BES.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
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Yes or No

Question 1 Comment

contracting the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the
current BES definition has varying degrees of Regional application and has resulted in different conclusions on what is currently
considered to be part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission
in Orders No. 743 and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with
the inconsistency in application of the current definition there is a potential for varying degrees of impact on Regions. Without an
approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results would have
little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid on a continentwide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the development of Regional
transition plans once the definition has been approved by the Commission.
Kansas City Power and Light
Company

No

There is no established basis for the generation thresholds referenced
through the ERO Statement of Compliance Registry Criteria in Appendix 5B
and the specificity of 75 MVA in the proposed BES definition. The objectives
identified in the Phase 2 SAR for the definition of the Bulk Electric System
include establishing an engineering basis for the generation thresholds.
Phase 2 will be critical in refining and improving the Bulk Electric System
definition and bringing additional clarity to the definition.

New York State Dept of Public
Service

No

The core definition is still deficient due to a lack of technical support for
basing the BES definition on 100 kV and for lack of any cost/benefit analysis.

City of Anaheim

No

The City of Anaheim recommends either changing the E1 (b) language back
to that of the previous BES definition draft, i.e. 75 MVA or above connected
at 100 kV or above, or limit the amount of generation allowed within a
Radial Element or Local Network to 300 MVA or less, which is the amount of
uncontrolled load loss that constitutes a reportable "disturbance" pursuant
to EOP-004 and DOE Form OE-417. If DOE and NERC do not consider a 300
MW uncontrolled loss of load a reportable event, then why would the
potential loss of a 75 MVA of non-critical generator connected at 69 kV
make a Radial Element or Local Network critical to the reliability of the BES?
The current ERO Statement of Compliance Criteria does not require GO/GOP
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Question 1 Comment
registration for generation connected below 100 kV as long as it's not critical
to the reliability of the BES, i.e. black start, etc., even if the amount of
generation is greater than 75 MVA. There is good reason for this because
the mere loss of 75 MVA generator would not affect the reliability of a
system as big as the Western Interconnection, at all, and a fault at say 69 kV
would have sufficient impedance not to affect the BES from an electrical
perspective.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow
the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the
threshold values and provide compelling justification for modifications to the existing values.
Consolidated Edison Co. of NY, Inc.

No

o Please clarify the phrase “facilities used in local distribution” as used in
the ‘core’ BES Definition. What is the purpose of this phrase in the BES
Definition? How does the SDT propose that an entity demonstrate that a
facility is used in local distribution?
o Does this phrase “facilities used in local distribution” establish a
jurisdictional boundary which takes precedence over all other parts of the
BES Definition and Designations?
o If this phrase does not take precedence over the remainder of the BES
Definition and Designations, i.e., perhaps only over some parts BES
Definition and Designations, or over none of the BES Definition and
Designations, then what was the drafting teams understanding of and intent
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Question 1 Comment
with regard to “facilities used in local distribution?”
o What are Entities supposed to do with respect to “facilities used in local
distribution” identified by State and Provincial regulators?
o How has NERC assured that the posted BES Definition and Designations
meet the intent of the Commission to establish an exemption process that
avoids identifying “facilities used in local distribution” as part of the BES
(¶37 and ¶39 below)? Recommendations: If “facilities used in local
distribution” are to be excluded on jurisdictional grounds, then o The last
sentence in the Core definition should be revised as follows: “This does not
include facilities used in the local distribution of electric energy, as identified
by a jurisdictional governmental authority.”
o We strongly recommend that the BES SDT adopt the FERC Seven Factor
test as a proven basis for establishing the boundary between jurisdictional
Transmission and non-jurisdictional “facilities used in local distribution.”
Supporting Discussion: In FERC Order 743-A the Commission stated69. We
agree ... that the Seven Factor Test could be relevant and possibly is a logical
starting point for determining which facilities are local distribution for
reliability purposes” By adopting this FERC Seven Factor test, the BES SDT
will have fulfilled its obligation to respond to these FERC mandates relating
to “local distribution” as stated in FERC Order 743: “Determining where the
line between ‘transmission’ and ‘local distribution’ lies,” (¶37),”To the
extent that any individual line would be considered to be local distribution,
that line would not be considered part of the bulk electric system” (¶39),
to establish “[A] means to track and review facilities that are classified as
local distribution to ensure accuracy and consistent application of the
definition” (¶119).Supporting References: FERC Order 743 observed some
believe that “the Commission’s [and by extension NERC’s] proposal exceeds
its jurisdiction by encompassing local distribution facilities that are not
necessary for operating the interconnected transmission network.” [FERC
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Question 1 Comment
Order 743, ¶27.]In this regard FERC Order 743 states: At ¶37, Congress
specifically exempted “facilities used in the local distribution of electric
energy” from the definition. ... Determining where the line between
“transmission” and “local distribution” lies, which includes an inquiry into
which lower voltage “transmission” facilities are necessary to operate the
interconnected transmission system, should be part of the exemption
process the ERO develops. And at ¶39, To the extent that any individual
line would be considered to be local distribution, that line would not be
considered part of the bulk electric system. And at ¶119, ... [W]e believe
that it would be beneficial for the ERO in maintaining a list of exempted
facilities, to consider including a means to track and review facilities that are
classified as local distribution to ensure accuracy and consistent application
of the definition. Similarly, the ERO could track exemptions for radial
facilities. [Emphasis added]Note that in ¶119 the Commission clearly
distinguishes between “radial facilities” and “local distribution” just as it
differentiates between jurisdictional radials and non-jurisdictional local
distribution facilities in footnote 82:82 As discussed further below, the
Commission uses the term “exclusion” herein when discussing facilities
expressly excluded by the statute (i.e., local distribution) and the term
“exemption” when referring to the exemption process NERC will develop for
use with facilities other than local distribution that may be exempted from
compliance with the mandatory Reliability Standards for other reasons. FERC
Order 743-A suggests:69. We agree with Consumers Energy, Portland
General and others that the Seven Factor Test could be relevant and possibly
is a logical starting point for determining which facilities are local
distribution for reliability purposes ...”

Response: The SDT discussed your comments and decided not to make changes to the core definition. The SDT included the last
sentence in the draft BES core definition as a reference to Section 215 of the Energy Power Act that excludes these facilities from
the bulk power system. In addition, FERC specifically excluded these facilities in Orders No. 743 and 743-A. By asking if this
sentence defines a jurisdictional boundary, you are asking the SDT for a legal conclusion that is beyond the scope of the project.
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Question 1 Comment

The SDT expects that most of the facilities used in the local distribution of energy will be covered by the 100 kV voltage level as
well as Exclusions E1 through E4. In the event the BES definition does not provide a definitive determination on whether an
Element is classified as BES or non-BES, the Rules of Procedure Exception Process may be utilized on a case-by-case basis to either
include or exclude an Element.
While the SDT does not agree with the premise that Exclusions E1 through E4 are fully sufficient to not include any facilities used in
the local distribution of electricity in the definition, the SDT declined to use the FERC Seven Factor Test to define the dividing line
between transmission and distribution as this is not an applicable test in all areas of North America which includes the Canadian
Provinces.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that
would warrant a change from the current values that exist through the application of the definition today. These and similar issues
have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in
conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
Hydro-Quebec TransEnergie

No

The proposed revision to the definition maintaining this bright line of 100 kV
would expand significantly what is considered to be BES in HQT's case (the
amount of added facilities could be ten times more). Since the main
structure of Quebec system is included in the BES where the best norms and
standards apply, the inclusion in the BES of sub-systems at lower voltage and
including generation will not bring significant impact on the reliable
operation of the interconnected system, because of the nature of the
Quebec Interconnection.
Furthermore for HQT's system, the proposed BES definition combined with
the exception procedure are presently incompatible or at least inconsistent
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with the regulatory framework applicable in Quebec. The proposed changes
have not address this concern, neither the SDT's responses to our previous
comments last May (Q.1 and 12).We reiterate that the definition and the
exception procedure shall be determined by Quebec's regulator, the Régie
de l'Énergie du Québec, (Quebec Energy Board) which has the
responsibility to ensure that electric power transmission in Quebec is carried
out according to the reliability standards it adopts. Per se, it would be
necessary that E1 and E3 grant exclusions with much higher level of
generation. It would also be necessary to allow for several levels of
application for the Reliability Standards, in accordance with the Régie de
l’énergie du Québec approach: the Bulk Power System (BPS) as
determined using an impact-based methodology, the Main Transmission
System (MTS), and other parts of Regional System. Standards related to the
protection system (PRC-004-1 and PRC-005-1) and those related to the
design of the transmission system (TPL 001-0 to TPL-004-0) shall be
applicable to the first level, but all other reliability standards shall be applied
to the second level, the MTS. The MTS definition is somewhat different than
the Bulk Electric System definition, and it includes elements that impact the
reliability of the grid, supply-demand balance and interchanges. We argue
that it would be necessary for NERC to address the regulatory issues outside
ot the present context of the SDT and ROP team.

Response: While the SDT appreciates the differences within the North American continent, it attempted to craft a BES definition
that can be applied within the ERO footprint. It is neither within the scope of the SDT nor is it appropriate for the SDT to provide
any regulatory resolution within the definition. As previously stated in our responses, the SDT believes that Acts and Regulations
supersede the requirements of any Standard setting body. As such, we agree that NERC along with relevant Regions will have to
address these types of non-jurisdictional situations directly or explicitly through the Exception Process.
Rochester Gas and Electric and New
York State Electric and Gas

No

The second sentence, “This does not include facilities used in the local
distribution of electric energy,” is vague and not sufficiently clear for
northeast industry expert colleagues to be certain of what is “not included.”
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Question 1 Comment
This sentence seems to apply only to distribution facilities that have already
been classified based on the FERC “Seven Factor Test” in Order 888. If so,
this sentence be re-written as follows for clarity: “This does not include
facilities classified as distribution facilities.” For US entities, this classification
is clearly delineated in our annual FERC Form 1 filing.

Central Maine Power Company

No

The second sentence, “This does not include facilities used in the local
distribution of electric energy,” is vague and not sufficiently clear for
northeast industry expert colleagues to be certain of what is “not included.”
This sentence seems to apply only to distribution facilities that have already
been classified based on the FERC “Seven Factor Test” in Order 888. If so,
this sentence should be restated as follows for clarity: “This does not
include facilities classified as distribution facilities.” For US entities, this
classification is clearly delineated in our annual FERC Form 1 filing.

Response: The SDT discussed your comment and decided against revision of the sentence in the core definition that refers to
facilities used in the local distribution of electricity. There were many commenters who were in favor of the inclusion of the
sentence as written in the core definition.
South Houston Green Power, LLC

No

South Houston Green Power, LLC [SHGP], a registered generator owner in
ERCOT, submits the following comments: Cogeneration facilities, some of
which are well over 75 MW in size, are located at a number of industrial
sites owned by SHGP and its affiliates. Some of these cogeneration facilities
generate power that is distributed within the industrial site and used for
manufacturing plant operations. In some instances, excess power not
required for plant operations is delivered back into the electric transmission
grid through the tie line(s) connecting the industrial site to the grid. While
the tie lines and some of the internal lines at these industrial sites operate at
100kV or higher, they do not perform anything that resembles a
transmission function. Rather than transmit power long distances from
generation to load centers, the tie lines and internal lines perform primarily
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an end user distribution function consisting of the distribution of power
brought in from the grid or generated internally to different plants within
each industrial site. In some cases, the facilities also perform an
interconnection function to the extent they enable power from
cogeneration facilities to be delivered into the grid. The voltage of the tie
lines and internal lines at these industrial sites is dictated by the load and
basic configuration of each site. Higher voltage lines are used when
necessary to meet applicable load requirements or to reduce line losses.
That does not mean that such lines perform a transmission function. SHGP
would oppose any BES definition that would by default subject either the tie
lines or the internal lines at such industrial sites to the mandatory reliability
standards applicable to Transmission Owners and Transmission Operators
when they more readily fit the Generation Owner / Generation Operator
standards. Such an expanded BES definition would subject registered
entities to substantial compliance costs and create potential exposure to
penalties, but would not likely substantially enhance the reliability of the
BES. Perhaps such costs and exposure could be justified in exceptional
circumstances, if subjecting these facilities to compliance with reliability
standards were to result in a material increase in reliability of the BES.
There is reason to believe, however, that in many cases the additional
reliability benefit would be minimal at best. The tie lines and internal lines
at industrial sites owned by SHGP and its affiliates have been operated for
years as end user distribution and interconnection facilities, and practices
and procedures have developed over the years that have enabled such
operations to achieve a high degree of reliability for such sites. Requiring
these facilities to now operate in a different manner as transmission
facilities may well result in a degradation of the reliability of the
manufacturing plants located at such sites. For example, outages would
have to be coordinated with the RTO, which may not be interested in
coordinating such outages with scheduled manufacturing plant outages. In
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light of these considerations, SHGP agrees with the proposed revisions to
the core definition, particularly the proposal to include a sentence expressly
excluding facilities used in the local distribution of electric energy, provided
it is understood that end user-owned delivery facilities located “behind-themeter” are, regardless of voltage level, by default outside the scope of this
definition.

Response: See the detailed comments on this issue in the responses to the comments on the Exception Process as well as the
Detailed Information to Support an Exception Request Form.
Indeck Energy Services

No

As acknowledged in the response to Question 12 comments on the previous
BES definition, the BES definition is expansive compared to the definition of
the BPS in the FPA Section 215. The inclusion of the limited Exclusions is an
attempt to remedy the situation. However, the Exclusions need to include a
fifth one that if, based on studies or other assessments, it can be shown that
any tranmission or generator element otherwise identified as part of the BES
is not important to the reliability of the BPS, then that element should be
excluded from the mandatory standards program. There has never been a
study to show that elements, such as a 20 MW wind farm, 60 MW merchant
generator (which operates infrequently in the depressed market) in a large
BA (eg NYISO) or a radial transmission line connecting a small generator are
important to the reliability of the BPS. They are covered by the mandatory
standards program through the registration criteria. The BES Definition is
the opportunity to permit an entity to demonstrate that an element is
unimportant to reliability of the BPS. The SDT has identified a small subset
of elements that it is willing to exclude. By their very nature, these
exclusions dim the bright line that is the stated goal of this project.
However, the SDT’s foresight seems limited in its selections. Analytical
studies are used to evaluate contingencies that could lead to the Big Three
(cascading outages, instability or voltage collapse). Such a study showing
that a transmission or generation element is bounded by the N-1 or N-2
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Question 1 Comment
contingency would exclude it from the BES definition. For example, in a BA
with a NERC definition Reportable Disturbance of approximately 400 MW
(eg NYISO), a 20 MW wind farm, 60 MW merchant generator or numerous
other smaller facilities would be bounded by larger contingencies. It would
take more than six 60 MW merchant generators with close location and
common mode failure to even be a Reportable Disturbance, much less
become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 Any facility that can be demonstrated to the Regional Entity by analytical
study or other assessment to be unimportant to the reliability of the BPS
(with periodic reports by the Regional Entity to NERC of any such
assessments).”

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow
the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values.
In the event that the BES definition does not provide a definitive determination on whether an Element is classified as BES or nonBES, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude an Element.
Snohomish County PUD
Kootenai Electric Cooperative

Yes

The Public Utility District No. 1 of Snohomish County (“SNPD”) believes the
SDT continues to make substantial progress towards a clear and workable
definition of the Bulk Electric System (“BES”) that markedly improves both
the existing definition and the SDT’s previous proposal. SNPD therefore
strongly supports the new definition, although our support is conditioned
on: (1) a workable Exceptions process being developed in conjunction with
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the BES definition; and, (2) the SDT moving forward expeditiously on Phase 2
of the standards development process in accordance with the SAR recently
put forward by the SDT, which would address a number of important
technical issues that have been identified in the standards development
process to date. SNPD strongly supports the following elements of the
revised BES definition:
(1) Clarification of how lists of Inclusions and Exclusions applies: The revised
core definition moves the phrase “Unless modified by the lists shown below”
to the beginning of the definition. This change makes clear that the
Inclusions and Exclusions apply to all Elements that would otherwise be
included in or excluded from the core definition (i.e., “all Transmission
Elements operated at 100 kV or higher and Real Time and Reactive Power
resources connected at 100 kV or higher”) and eliminates a latent ambiguity
in the first draft of the definition, discussed further in our comments on the
first draft.
(2) The exclusion for Local Distribution Facilities. As the starting point for
the BES definition, SNPD supports use of the phrase “all Transmission
Elements” and the qualifying sentence: “This does not include facilities used
in the local distribution of electric energy.” This language helps ensure that
FERC, NERC, and the Regional Entities (“REs”) will act within the
jurisdictional constrains Congress placed in Section 215 of the Federal Power
Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities
used in the local distribution of electric energy” from the keystone “bulkpower system” definition. 16 U.S.C. § 824o(a)(1). Including the same
language in the definition helps ensure that entities involved in enforcement
of reliability standards will act within their statutory limits. In addition, as a
practical matter, inclusion of the language will help focus both the industry
and responsible agencies on the high-voltage interstate transmission
system, where the reliability problems Congress intended to regulate “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. §
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Question 1 Comment
824o(a)(4) - will originate. At the same time, level-of-service issues arising
in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16
U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of
standards for adequacy of service). For similar reasons, Snohomish
believes use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements”
are already defined in the NERC Glossary of Terms Used, and the term
“Transmission” makes clear that the BES includes only Elements used in
Transmission and therefore excludes Elements used in local distribution of
electric power.
(3) Appropriate Generator Thresholds. In the standards development
process, it has become apparent that the thresholds for classifying
generators as BES in the current NERC Statement of Compliance Registry
Criteria (“SCRC”) (20 MVA for individual generators, 75 MVA for multiple
generators aggregated at a single site), which predate the adoption of FPA
Section 215, were never the product of a careful analysis to determine
whether generators of that size are necessary for operation of the
interconnected bulk transmission system. Ideally, such an analysis would be
conducted as part of the current standards development process.
Snohomish recognizes that, given the deadlines imposed by FERC in Order
No. 743, it will not be possible for the SDT to conduct such an analysis within
the time available. Accordingly, Snohomish agrees with the approach taken
by the SDT, which is to propose a Phase 2 of the standards development
process that would address the generator threshold issue and several other
technical issues that have arisen during the current process. As long as
Phase 2 proceeds expeditiously, Snohomish is prepared to support the BES
definition as proposed by the SDT. While Snohomish strongly supports the
overall approach adopted by the SDT and much of the specific language
incorporated into the second draft of the BES definition, we believe the
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Question 1 Comment
second draft would benefit from further clarification or modification in a
number of respects, most of which are detailed in our subsequent answers.
Our support for the definition is not contingent upon these changes being
adopted. Further, we believe a workable Exclusion Process is essential for a
BES Definition that will meet the legal requirements of FPA Section 215,
especially for systems operating in the Western Interconnection. As detailed
in our previous comments, Snohomish believes a 200-kV threshold would be
more appropriate for WECC than a 100-kV threshold. In addition, a 200-kV
threshold for the West is backed by solid technical analysis conducted by the
WECC Bulk Electric System Definition Task Force, and repeated claims that
there is no technical analysis to support this view is therefore incorrect.
That being said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions
process. These Exclusions and the Exceptions are essential for a definition
that works in the Western Interconnection because the core definition will
be over-inclusive in our region. As long as those Exclusions and the
Exceptions Process are retained in a form substantially equivalent to those
produced by the SDT at this juncture, Snohomish will support the SDT’s
proposal and will not further pursue its claims regarding the 200-kV
threshold.
Finally, we suggest that the SDT address the circumstance when an Element
is covered by both an Inclusion and an Exclusion. We note that some of the
inclusions already contain language addressing this question. For example,
Inclusion 1 indicates that transformers falling within the specified
parameters are part of the BES “. . . unless excluded under Exclusions E1 or
E3.” Where it is not already included, similar language should be included in
the other Inclusions and/or Exclusions to explain whether the SDT intends
the Inclusions or the Exclusions to predominate in situations where facilities
might be covered by both.

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Question 1 Comment
We suggest clarifying language in our responses to Questions 2 and 5.

Response: The exception process will be filed concurrently with the definition.
Phase 2 of this project will begin immediately following the conclusion of Phase 1 as SDT resources free up.
The goal of the SDT and the Rules of Procedure Team is to have the Exception Process begin concurrently with the implementation
of the revised BES Definition.
Please see responses to Q2 and Q5.
Metropolitan Water District of
Southern California

Yes

Metropolitan Water District of Southern California (“MWDSC”) generally
supports the core definition of the Bulk Electric System as proposed.
However, some of the proposed Inclusions and Exclusions need to be
clarified as identified in questionnaires #6 and #10 below.

Response: Please see the detailed responses in Q6 and Q11 below.
Clallam County PUD No.1
Blachly-Lane Electric Cooperative
(BLEC)
Coos-Curry Electric Cooperative
(CCEC)
Central Electric Cooperatve (CEC)
Clearwater Power Company (CPC)
Consumer's Power Inc.
Douglas Electric Cooperative (DEC)
Fall River Rural Electric Cooperative
(FALL)

Yes

The Public Utility District No. 1 of Clallam County (“CLPD”) believes the SDT
continues to make substantial progress towards a clear and workable
definition of the Bulk Electric System (“BES”) that markedly improves both
the existing definition and the SDT’s previous proposal. CLPD therefore
strongly supports the new definition, although our support is conditioned
on: (1) a workable Exceptions process being developed in conjunction with
the BES definition; and, (2) the SDT moving forward expeditiously on Phase 2
of the standards development process in accordance with the SAR recently
put forward by the SDT, which would address a number of important
technical issues that have been identified in the standards development
process to date.
CLPD strongly supports the following elements of the revised BES definition:
(1) Clarification of how lists of Inclusions and Exclusions applies: The revised
core definition moves the phrase “Unless modified by the lists shown below”
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Lane Electric Cooperative (LEC)
Lincoln Electric Cooperative (LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric Cooperative
(RAFT)
West Oregon Electric Cooperative
Umatilla Electric Cooperative (UEC)

Yes or No

Question 1 Comment
to the beginning of the definition. This change makes clear that the
Inclusions and Exclusions apply to all Elements that would otherwise be
included in or excluded from the core definition (i.e., “all Transmission
Elements operated at 100 kV or higher and Real Time and Reactive Power
resources connected at 100 kV or higher”) and eliminates a latent ambiguity
in the first draft of the definition, discussed further in our comments on the
first draft.
(2) The exclusion for Local Distribution Facilities. As the starting point for
the BES definition, CLPD supports use of the phrase “all Transmission
Elements” and the qualifying sentence: “This does not include facilities used
in the local distribution of electric energy.” This language helps ensure that
FERC, NERC, and the Regional Entities (“REs”) will act within the
jurisdictional constrains Congress placed in Section 215 of the Federal Power
Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities
used in the local distribution of electric energy” from the keystone “bulkpower system” definition. 16 U.S.C. § 824o(a)(1). Including the same
language in the definition helps ensure that entities involved in enforcement
of reliability standards will act within their statutory limits. In addition, as a
practical matter, inclusion of the language will help focus both the industry
and responsible agencies on the high-voltage interstate transmission
system, where the reliability problems Congress intended to regulate “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. §
824o(a)(4) - will originate. At the same time, level-of-service issues arising
in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16
U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of
standards for adequacy of service).For similar reasons, Clallam believes use
of the phrase “Transmission Elements” as the starting point for the base
definition is desirable because both “Transmission” and “Elements” are
already defined in the NERC Glossary of Terms Used, and the term
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Question 1 Comment
“Transmission” makes clear that the BES includes only Elements used in
Transmission and therefore excludes Elements used in local distribution of
electric power.
(3) Appropriate Generator Thresholds. In the standards development
process, it has become apparent that the thresholds for classifying
generators as BES in the current NERC Statement of Compliance Registry
Criteria (“SCRC”) (20 MVA for individual generators, 75 MVA for multiple
generators aggregated at a single site), which predate the adoption of FPA
Section 215, were never the product of a careful analysis to determine
whether generators of that size are necessary for operation of the
interconnected bulk transmission system. Ideally, such an analysis would be
conducted as part of the current standards development process. Clallam
recognizes that, given the deadlines imposed by FERC in Order No. 743, it
will not be possible for the SDT to conduct such an analysis within the time
available. Accordingly, Clallam agrees with the approach taken by the SDT,
which is to propose a Phase 2 of the standards development process that
would address the generator threshold issue and several other technical
issues that have arisen during the current process. As long as Phase 2
proceeds expeditiously, Clallam is prepared to support the BES definition as
proposed by the SDT. While Clallam strongly supports the overall approach
adopted by the SDT and much of the specific language incorporated into the
second draft of the BES definition, we believe the second draft would
benefit from further clarification or modification in a number of respects,
most of which are detailed in our subsequent answers. Our support for the
definition is not contingent upon these changes being adopted. Further, we
believe a workable Exclusion Process is essential for a BES Definition that will
meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our II proceeds
expeditiously, Clallam is prepared to support the BES definition as proposed
by the SDT. While Clallam strongly supports the overall approach adopted
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Question 1 Comment
by the SDT and much of the specific language incorporated into the second
draft of the BES definition, we believe the second draft would benefit from
further clarification or modification in a number of respects, most of which
are detailed in our subsequent answers. Our support for the definition is
not contingent upon these changes being adopted.
Further, we believe a workable Exclusion Process is essential for a BES
Definition that will meet the legal requirements of FPA Section 215,
especially for systems operating in the Western Interconnection. As detailed
in our previous comments, Clallam believes a 200-kV threshold would be
more appropriate for WECC than a 100-kV threshold. In addition, a 200-kV
threshold for the West is backed by solid technical analysis conducted by the
WECC Bulk Electric System Definition Task Force, and repeated claims that
there is no technical analysis to support this view is therefore incorrect.
That being said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions
process. These Exclusions and the Exceptions are essential for a definition
that works in the Western Interconnection because the core definition will
be over-inclusive in our region. As long as those Exclusions and the
Exceptions Process are retained in a form substantially equivalent to those
produced by the SDT at this juncture, Clallam will support the SDT’s proposal
and will not further pursue its claims regarding the 200-kV threshold.

Response: The exception process will be filed concurrently with the definition.
Phase 2 of this project will begin immediately following the conclusion of Phase 1 as SDT resources free up.
The goal of the SDT and the Rules of Procedure Team is to have the Exception Process begin concurrently with the implementation
of the revised BES Definition.
Michigan Public Power Agency

Yes

The Michigan Public Power Agency (MPPA) believes the SDT continues to
make substantial progress towards a clear and workable definition of the
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Question 1 Comment
Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. MPPA therefore strongly
supports the new definition, although our support is conditioned on: (1) A
workable Exceptions process being developed in conjunction with the BES
definition; and, (2) the SDT moving forward expeditiously on Phase 2 of the
standards development process in accordance with the SAR recently put
forward by the SDT, which would address a number of important technical
issues that have been identified in the standards development process to
date.
MPPA strongly supports the following elements of the revised BES
definition: (1) Clarification of how lists of Inclusions and Exclusions applies:
The revised core definition moves the phrase “Unless modified by the lists
shown below” to the beginning of the definition. This change makes clear
that the Inclusions and Exclusions apply to all Elements that would
otherwise be included in or excluded from the core definition (i.e., “all
Transmission Elements operated at 100 kV or higher and Real Time and
Reactive Power resources connected at 100 kV or higher”).
(2) The exclusion for Local Distribution Facilities. As the starting point for
the BES definition, MPPA supports use of the phrase “all Transmission
Elements” and the qualifying sentence: “This does not include facilities used
in the local distribution of electric energy.” This language helps ensure that
FERC, NERC, and the Regional Entities (“REs”) will act within the
jurisdictional constrains Congress placed in Section 215 of the Federal Power
Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities
used in the local distribution of electric energy” from the keystone “bulkpower system” definition. 16 U.S.C. § 824o(a)(1). Including the same
language in the definition helps ensure that entities involved in enforcement
of reliability standards will act within their statutory limits. In addition, as a
practical matter, inclusion of the language will help focus both the industry
and responsible agencies on the high-voltage interstate transmission
48

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Yes or No

Question 1 Comment
system, where the reliability problems Congress intended to regulate “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. §
824o(a)(4) - will originate. At the same time, level-of-service issues arising
in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16
U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of
standards for adequacy of service).
MPPA also believes the use of the phrase “Transmission Elements” as the
starting point for the base definition is desirable because both
“Transmission” and “Elements” are already defined in the NERC Glossary of
Terms Used, and the term “Transmission” makes clear that the BES includes
only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. MPPA believes this was one of the many
key elements addressed by FERC in Order No. 743 and reinforced by FERC
Order No. 743A and has been missing from the previous definition as well as
the original definition being used since Compliance efforts commenced in
June, 2007 . Because of this lack of clarity MPPA has had numerous
discussions with the region regarding all 17 of our member’s connection to
the TO/TOP in Michigan. Our discussions have resulted in defending 6 of our
members specifically from the “Bright Line definition” path while having no
tools in our tool box to substantiate our exclusion. When a small
municipality with a peak load of 12.6 MW and no generation must be
defended from a TO and/or TOP registration just because of its connection
to it’s TO/TOP the process requires needed adjustment for clarity. This was
too small to even qualify as a DP under the Statement of Compliance
Registry Criteria but must have to defend itself from a TO/TOP registration
issue.
(3) Appropriate Generator Thresholds. In the standards development
process, it has become apparent that the thresholds for classifying
generators as BES in the current NERC Statement of Compliance Registry
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Question 1 Comment
Criteria (“SCRC”) (20 MVA for individual generators, 75 MVA for multiple
generators aggregated at a single site), which predate the adoption of FPA
Section 215, were never the product of a careful analysis to determine
whether generators of that size are necessary for operation of the
interconnected bulk transmission system. Ideally, such an analysis would be
conducted as part of the current standards development process. A
member of MPPA has been involved in a registration issue and it has a 3rd
party study conducted by a nation consulting firm showing for the MISO
area, generation levels of 100 MVA and 300 MVA aggregate or above are
below the standard calculation mathematical significant impact criteria for
static and dynamic planning protocol. MPPA recognizes that, given the
deadlines imposed by FERC in Order No. 743, it will not be possible for the
SDT to conduct such an analysis within the time available. Accordingly,
MPPA agrees with the approach taken by the SDT, which is to propose a
Phase 2 of the standards development process that would address the
generator threshold issue and several other technical issues that have arisen
during the current process. As long as Phase 2 proceeds expeditiously,
MPPA is prepared to support the BES definition as proposed by the SDT.
While MPPA strongly supports the overall approach adopted by the SDT and
much of the specific language incorporated into the second draft of the BES
definition, we believe the second draft would benefit from further
clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Our support for the definition is not
contingent upon these changes being adopted. Further, we believe a
workable Exclusion Process is essential for a BES Definition that will meet
the legal requirements of FPA Section 215, especially for systems operating
in the Eastern Interconnection.
That being said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions
process. These Exclusions and the Exceptions are essential for a definition
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Question 1 Comment
that works in the Eastern Interconnection because the core definition will be
over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by
the SDT at this juncture, MPPA will support the SDT’s proposal.
Finally, we suggest that the SDT address the circumstances when a facility is
covered by both an Inclusion and an Exclusion. We note that some of the
inclusions already contain language addressing this question. For example,
Inclusion 1 indicates that transformers falling within the specified
parameters are part of the BES “. . . unless excluded under Exclusions E1 or
E3.” Where it is not already included, similar language should be included in
the other Inclusions and/or Exclusions to explain whether the SDT intends
the Inclusions or the Exclusions to predominate in situations where facilities
might be covered by both. We suggest clarifying language in our comments
to I1 and I4 below.

Response: The exception process will be filed concurrently with the definition.
Phase 2 of this project will begin immediately following the conclusion of Phase 1 as SDT resources free up.
The goal of the SDT and the Rules of Procedure Team is to have the Exception Process begin concurrently with the implementation
of the revised BES Definition.
See the detailed response to your comments regarding Inclusion I1 and I4 in the specific questions and responses below.
FirstEnergy Corp.

Yes

However, consider changing the last sentence to read "This does not include
facilities operated at less than 100kV, unless modified below, which are are
used in the local sub-transmission and distribution of electric energy."

Response: The SDT discussed your comments and decided not to change the core definition. The BES definition does not include
facilities operated at less than 100 kV.
Industrial Customers of Northwest

Yes

The Industrial Customers of Northwest Utilities (“ICNU”) submits the
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Utilities

Yes or No

Question 1 Comment
following comments regarding the North American Electric Reliability
Corporation’s (“NERC”) proposal for defining the Bulk Electric System
(“BES”). ICNU is an incorporated, non-profit association of large end-use
electric customers in the Pacific Northwest, with offices in Portland, Oregon.
ICNU previously submitted comments in the Western Electricity
Coordinating Council’s (“WECC”) process for defining the BES. ICNU’s
members are not electric utilities, but some ICNU members own substations
that are interconnected to utility transmission systems and utility
distribution systems. In addition, in some cases, ICNU members operate
local distribution facilities behind their substations to serve their end-use
loads. In some cases, the ICNU member’s interconnection to the utilityowned transmission system or distribution system is via a utility-owned
radial line; and, in others, the ICNU member’s distribution system is looped
into the utility’s transmission system for reliability purposes. Finally, some
ICNU members have local distribution systems that include the ICNU
member’s backup generating facilities. ICNU is submitting comments,
because these facilities arguably could fall within NERC’s proposed definition
of BES. ICNU appreciates the work that NERC has done to date, and
encourages NERC to develop a rule that recognizes the unique aspects of the
Pacific Northwest transmission system and the particular needs of end-use
customers. Given the arbitrary requirements and limitations imposed by the
Federal Energy Regulatory Commission, ICNU supports NERC’s overall
approach to defining the BES. NERC has proposed a bright line rule in which
all transmission elements operated 100 kV or higher will be included in the
definition, subject to certain inclusions and exclusions. ICNU supports
NERC’s goal of excluding facilities in the local distribution of electric energy.
NERC proposes three general classes of exclusions, which includes certain
radial systems, generating units that serve all or part of retail customer’s
load, and local networks. Specifically, NERC proposes that: 1) radial systems
100 kV and higher shall be excluded if they only serve load, or only include
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Question 1 Comment
certain generation resources less than 75 MVA; 2) generating units that
serve customer load on the customer meter are excluded if the net capacity
provided to the BES does not exceed 75 MVA and standby, back up and
maintenance power services are provided; 3) local networks operated less
than 300 kV that distribute power to load rather than transfer bulk power
across the interconnected system; and 4) reactive power owned and
operated by a retail customer solely for its own benefit. ICNU supports
these exclusions; however, ICNU is concerned that certain end-use retail
customer facilities that do not impact the BES may still be inappropriately
included. NERC appears to recognize this possibility and includes an
exception process to include or exclude facilities on a case-by-case basis.
ICNU urges NERC to develop this exception process, and to review the work
by WECC regarding how to structure an appropriate exception. At a
minimum, the exception process should not require end-use customers to
perform costly and complex studies, but should instead require utilities or
regional organizations that have the relevant expertise to conduct the
necessary studies to determine if a specific facility should be removed or
included in the BES.
ICNU is also concerned about the term “non-retail generation,” which does
not appear to have a corresponding definition. ICNU understands that nonretail generation is intended to apply to generation behind the retail
customer’s meter. ICNU recommends that net metered systems should not
count towards the generation limits for radial and local network systems.

Response: See the detailed comments on this issue in the responses to the comments on the Rules of Procedure Exception Process
as well as the Detailed Information to Support an Exception Request Form.
To address your second comment, the SDT declined to change the term “non-retail generation”. Non-retail generation is the
generation on the system (supply) side of the retail meter.

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PacifiCorp

Yes or No

Question 1 Comment

Yes

PacifiCorp believes the SDT continues to make substantial progress towards
a clear and workable definition of the Bulk Electric System (“BES”) that
markedly improves both the existing definition and the SDT’s previous
proposal. PacifiCorp strongly supports the new definition, conditioned on:
(1) a workable Exceptions process being developed in conjunction with the
BES definition; and,
(2) the SDT moving forward expeditiously on Phase 2 of the standards
development process in accordance with the SAR recently put forward by
the SDT.

Response: The SDT appreciates your support for the clarifying changes made to the core definition. The goal of the SDT and the
Rules of Procedure Team is to have the Exception Process begin concurrently with the implementation of the revised BES
Definition.
Phase 2 of this project will begin immediately following the conclusion of Phase 1 as SDT resources free up.
Holland Board of Public Works

Yes

Holland BPW believes that the proposed definition is an improvement to the
status quo, but requires additional work. The thresholds for classifying
generators as Bulk Electric System (BES) must be revised. There was little
technical support for proposing the current thresholds. No greater evidence
than that which was proffered for the initial thresholds should be required
to modify those standards. Four years of compliance experience and
industry feedback support increasing these thresholds. Holland BPW
supports increasing the generation thresholds from 20 MVA (individual gross
nameplate) and 75 MVA (aggregate gross nameplate) to not less than 100
MVA (individual gross nameplate) and 300 MVA (aggregate gross
nameplate). Holland BPW recognizes that the SDT and NERC have
committed to making these revisions as part of “Phase 2”, and are asking the
industry to trust that such an initiative will not succumb to work on other
initiatives. However, even if work on this initiative commences
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Question 1 Comment
immediately, entities that should be removed from the Compliance Registry
face costs of compliance or the risk of non-compliance penalties even
though their facilities are not necessary for the reliable operation of the
interconnected transmission system.
That said, there are two significant improvements in the revised draft. First,
it is essential to make clear that the “Inclusions” and “Exclusions” apply only
to the first sentence of the core definition (i.e., “Transmission Elements”).
The revised definition appears to address this. By placing “Unless modified
by the lists shown below” at the beginning of the first sentence of the
definition clarifies that the lists of Inclusions and Exclusions pertain only to
“Transmission Elements” that would otherwise be included or excluded from
the core definition. The revised definition and the lists of Inclusions and
Exclusions do not and cannot be applied in a manner to pull in facilities used
in the local distribution of electric energy as BES facilities because Congress,
by statute, has already determined that such facilities are outside of NERC’s
reach, as recognized by the second sentence of the definition.
Second, Holland BPW supports the addition of the second sentence of the
core definition that states, “This does not include facilities used in the local
distribution of electric energy.” This language provides necessary
recognition to the jurisdictional limitation provided for in Section 215 of the
Federal Power Act, and as recognized by the FERC in Orders 743 and 743-A
(see, e.g., ¶¶ 58-59 in 743-A).
Finally, if the revised definition goes forward, it is imperative that the rules
of procedure providing for an exception process be adopted at the same
time.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
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deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow
the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the
threshold values and provide compelling justification for modifications to the existing values.
As for your second group of comments, the SDT appreciates your support for the clarifying changes made to the core definition.
The goal of the SDT and the Rules of Procedure Team is to have the Exception Process begin concurrently with the implementation
of the revised BES Definition.
Dominion

Yes

Dominion agrees with the clarifying changes provided that the use of the
capitalized terms “Transmission” and “Elements” mean that an Element that
is radial is not part of the BES regardless of whether it is specifically included
in the Exclusions (E1 through E4).

Response: To the extent that a radial facility that is >100 kV does not meet the exclusion criteria as specified in Exclusions E1
through E4, the Exception Process can be used to provide a final decision on whether the facility is or is not a BES Element.
Sacramento Municipal Utility District

Yes

In an effort to avoid potential confusion and provide clarity we believe the
following sentence “This does not include facilities used in the local
distribution of electric energy” more appropriately fits under the
“exclusions,” rather than “inclusions,” section.

ISO New England Inc

Yes

The second sentence is unclear with respect to its intent. If it’s intended to
cover the exclusion described in E3, the sentence is not needed. If it’s
intended to mean something else, it is unclear as to what is intended and
likely should be deleted.

Manitoba Hydro

Yes

Manitoba Hydro agrees in general with the changes made to the core
definition but the sentence ‘This does not include facilities used in the local
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Question 1 Comment
distribution of electric energy’ should be removed as it is covered under
Exclusion E3 and reduces the clarity of the core definition.

City of Austin dba Austin Energy

Yes

In an effort to avoid potential confusion and provide clarity we believe the
sentence, “This does not include facilities used in the local distribution of
electric energy,” more appropriately fits under the “exclusions” (rather
“inclusions”) section.

Balancing Authority Northern
California

Yes

In an effort to avoid potential confusion and provide clarity we believe the
following sentence “This does not include facilities used in the local
distribution of electric energy” more appropriately fits under the
“exclusions,” rather than “inclusions,” section.

Response: The SDT discussed your comment and decided against moving the sentence in the core definition that refers to facilities
used in the local distribution of electricity to the Exclusions section. There were many commenters who were in favor of the
inclusion of the sentence in the core definition.
ExxonMobil Research and
Engineering

Yes

However, in Order 743, FERC directed NERC to further delineate the
differences between transmission systems (used to transfer electric power
between regions) and distribution systems (used to deliver electric power
locally). The inclusions and exclusions defined in the draft BES definition are
a step in the right direction, but further work is necessary during Phase 2 to
meet the intention of the order.
Additionally, the SDT should consider defining terms, such as non-retail
generation, or providing references (footnotes) that elaborate on the
referenced concept.

Response: Thank you for your support of Phase 2.
Non-retail generation is the generation on the system (supply) side of the retail meter.

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Yes or No

Question 1 Comment

Transmission Access Policy Study
Group

Yes

TAPS appreciates the SDT’s work on this project. For the most part, TAPS
supports what it believes to be the intent of the proposed language. The
proposed specific exclusion of facilities used in the local distribution of
electric energy is appropriate and consistent with Section 215 of the Federal
Power Act. However, we have one suggestion to better carry out what we
believe to be the SDT’s intent. The SDT proposes to change the core
generation definition from the prior version’s “...Real Power resources as
described below, and Reactive Power resources connected at 100 kV or
higher unless such designation is modified by the list shown below,” to
“Unless modified by the lists shown below, ... Real Power and Reactive
Power resources connected at 100 kV or higher....” Because of this change
from “as described below... unless... modified by the list shown below” to
simply “unless modified by the lists shown below,” the proposed core
definition now has the effect of including all generation, regardless of size,
that is connected at over 100kV. We do not think this is the SDT’s intent.
For the same reason, the core definition now has the effect of including all
Reactive Power resources connected at over 100kV, including generators;
Inclusion I5, which includes “[s]tatic or dynamic devices dedicated to
supplying or absorbing Reactive Power,” does not alter the core definition’s
inclusion of all Reactive Power resources connected at over 100kV (whether
“dedicated” or not). The most straightforward solution to this problem is to
simply delete Real and Reactive Power resources from the core definition, so
that such resources are instead handled entirely in the Inclusions. The core
definition would thus read: “Unless modified by the lists shown below, all
Transmission Elements operated at 100 kV or higher. This does not include
facilities used in the local distribution of electric energy.”

Florida Municipal Power Agency

Yes

FMPA appreciates the SDT’s work on this project. For the most part, FMPA
supports what it believes to be the intent of the proposed language. The
proposed specific exclusion of facilities used in the local distribution of
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Question 1 Comment
electric energy is appropriate and consistent with Section 215 of the Federal
Power Act. However, we have suggestions to better carry out what we
believe to be the SDT’s intent. The first sentence can be read as: “... all ...
Real Power and Reactive Power resources connected at 100 kV or higher”,
which is surely not what the SDT intends. The basic problem is that
Inclusions I2 and I4 do not modify the first sentence, e.g., from a set theory
perspective, the set described by the first sentence includes the sets
described in inclusions I2 and I4; hence, I2 and I4 do not modify the first
sentence. From a literal reading, this would cause any size generator
connected at 100 kV to be included, which is surely not the intent of the
SDT.
For similar reasons, the core definition and Inclusion I5 now has the effect of
including all generators connected at 100 kV since a generator is a “dynamic
device ... supplying or absorbing Reactive Power”. The word “dedicated” in
I5 is not sufficient in FMPA’s mind to unambiguously exclude generators
from this statement.
FMPA suggests the following wording to address these issues:"Transmission
Elements (not including elements used in the local distribution of electric
energy) and Real Power and Reactive Power resources as described in the
list below, unless excluded by Exclusion or Exception: a. Transmission
Elements other than transformers and reactive resources operated at 100 kV
or higher. b. Transformers with primary and secondary terminals operated
at 100 kV or higher. c. Generating resource(s) (with gross individual or gross
aggregate nameplate rating per the ERO Statement of Compliance Registry
Criteria) including the generator terminals through the high-side of the stepup transformer(s) connected at a voltage of 100 kV or above. d. Blackstart
Resources identified in the Transmission Operator’s restoration plan. e.
Dispersed power producing resources with aggregate capacity greater than
75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacity, connected at a common point at a
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Question 1 Comment
voltage of 100 kV or above, but not including generation on the retail side of
the retail meter. f. Non-generator static or dynamic devices dedicated to
supplying or absorbing more than 6 MVAr of Reactive Power that are
connected at 100 kV or higher, or through a dedicated transformer with a
high-side voltage of 100 kV or higher, or through a transformer that is
designated in bullet 2 above."

Response: The SDT discussed your comments and declined to make changes to the core definition. However, clarifying changes
were made to Inclusion I2 to specify the generation thresholds to be included in the BES. In addition, the SDT added a clarifying
phrase to Inclusion I5 to emphasize that the item is not meant to apply to generators.
MEAG Power

Yes

MEAG agrees to the clarifying changes to the core definition in general,
however, we maintain that 200kV and above is the correct bright line for the
BES.

Electricity Consumers Resource
Council (ELCON)

Yes

However, one of the FERC directives in Order 743 charged NERC with
delineating the difference between transmission and distribution. The
Inclusions and Exclusions are a step in that direction, but this subject will
need more consideration in Phase 2.

Texas RE NERC Standards
Subcommittee

Yes

However, one of the FERC directives in Order 743 charged NERC with
delineating the difference between transmission and distribution. The
Inclusions and Exclusions are a step in that direction, but this subject will
need more consideration in Phase 2.

SERC OC Standards Review Group

Yes

The SERC OC Standards Review Group agrees to the clarifying changes to the
core definition in general; however, we maintain that 200kV and above is the
correct bright line for the Bulk Electric System.

AECI and member GandTs, Central
Electric Power Cooperative, KAMO

Yes

In general, we agree with this revision. We however believe the correct
voltage thresholds to be, transformer primary voltage of 200 kV or higher and
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Yes or No

Power, MandA Electric Power
Cooperative, Northeast Missouri
Electric Power Cooperative, NW
Electric Power Cooperative Sho-Me
Power Electric Power Cooperative
Tennessee Valley Authority

Question 1 Comment
secondary voltage of 100 kV or higher.

Yes

TVA agrees to the clarifying changes to the core definition in general;
however, we maintain that 200kV and above is the correct bright line for the
Bulk Electric System, and requests that the Phase 2 for the project use 200kV
and above or develop a transmission voltage and/or an MVA threshold that is
technically based.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow
the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the
threshold values and provide compelling justification for modifications to the existing values. No change made.
Puget Sound Energy

Yes

This draft of the defintion is very much improved. We appreciate the work
of the Standard Development Team and its efforts to increase the clarity of
this important definition. For additional clarity, the first paragraph should
read "Unless specifically excluded under the list of exclusions below or
included or excluded through the Procedure for Requesting and Receiving an
Exception from the Application of the NERC Definition of Bulk Electric
System, all Transmission Elements operated at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher,
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Question 1 Comment
including those Transmission Elements described in the list of inclusions
below."
The sentence "This does not include facilities used in the local distribution of
electric energy." should be removed from the first paragraph. Because this
issue is specifically addressed in exclusions E1 and E3, the inclusion of this
general sentence here is unnecessary and could even be ambiguous (raising
the question of whether additional Transmission Elements might be
excluded even if not described in E1 or E2).

Response: The SDT discussed your comment and decided against deletion of the sentence in the core definition that refers to
facilities used in the local distribution of electricity. There were many commenters who were in favor of the inclusion of the
sentence in the core definition. Additionally, the SDT does not agree with the premise that the exclusions are fully sufficient to not
include any facilities used in the local distribution of electricity in the definition. No change made.
Z Global Engineering and Energy
Solutions

Yes

We support these changes however feel that further clarification needs to
be made regarding the E1 Note. This note currently states "Note - A
normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion" This
note is not clear. We recommend that the note is rewritten to be clear that
a normally open switching device should not be viewed as normally closed
as the regions are currently doing. Possible language: "Note: A normally
open switching device between radial systems, as depicted on prints or
oneline diagrams, for example, does not classify the two or more radial lines
as a loop line. The exclusion will still apply.”}"

Response: The SDT discussed your comment and declined to make the suggested change. It is the intent of the SDT that a switch
that is marked normally open as depicted on prints or one-lines be treated as normally open when deciding whether a facility is or
is not a BES Element.
Northern Wasco County PUD

Yes

We agree with the changes. We must point out that the overall flow, or how
one proceeds through the inclusions and exclusions is not clear. Can an item
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Question 1 Comment
that meets an inclusion be subsequently excluded? If so, this needs to be
explicitly stated. So far, we only have the flow chart produced by the ROP
team that indicates otherwise
(http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf).
This was made evident by the question at the 9/28 webinar regarding an I5
capacitor on an E3 local network. The questioner thought the capacitor was
BES per I5, but the answer was that it was excluded per E3. We can find no
support for the answer given. The listing of specific exclusions within I1
(exception proves the rule) argues for questioner’s stance that the capacitor
is BES as written. Also, if included items could subsequently be excluded,
they would be no different from any other item that met the voltage
threshold of 100kV. There would be no need for any of the inclusions if all
possible outputs from the inclusion tests go to the same exclusion test
inputs. We strongly support the addition of the language regarding local
distribution facilities, as it matches congressional intent to leave the
regulation of these facilities to state and local authorities.

Harney Electric Cooperative, Inc.

Yes

HEC agrees with the changes by the SDT. Although HEC believes that there
needs to be explicit language stating whether or not an item that meets
inclusion can be overridden by an exclusion. An example of this was given
during the Webinar on 9/28 regarding a Capacitor included under I5 yet
excluded under E3 according to the NERC representative.

Central Lincoln

Yes

We agree with the changes. We must point out that the overall flow, or how
one proceeds through the inclusions and exclusions is not clear. Can an item
that meets an inclusion be subsequently excluded? If so, this needs to be
explicitly stated. So far, we only have the flow chart produced by the ROP
team that indicates otherwise
(http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf).
This was made evident by the question at the 9/28 webinar regarding an I5
capacitor on an E3 local network. The questioner thought the capacitor was
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Yes or No

Question 1 Comment
BES per I5, but the answer was that it was excluded per E3. We can find no
support for the answer given. The listing of specific exclusions within I1
(exception proves the rule) argues for questioner’s stance that the capacitor
is BES as written. Also, if included items could subsequently be excluded,
they would be no different from any other item that met the voltage
threshold of 100kV. There would be no need for any of the inclusions if all
possible outputs from the inclusion tests go to the same exclusion test
inputs.We strongly support the addition of the language regarding local
distribution facilities, as it matches congressional intent to leave the
regulation of these facilities to state and local authorities.

Mission Valley Power

Yes

Mission Valley Power - We agree with the changes. We must point out that
the overall flow, or how one proceeds through the inclusions and exclusions
is not clear. Can an item that meets an inclusion be subsequently excluded?
If so, this needs to be explicitly stated. So far, we only have the flow chart
produced by the ROP team that indicates otherwise
(http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf).
This was made evident by the question at the 9/28 webinar regarding an I5
capacitor on an E3 local network. The questioner thought the capacitor was
BES per I5, but the answer was that it was excluded per E3. We can find no
support for the answer given. The listing of specific exclusions within I1
(exception proves the rule) argues for questioner’s stance that the capacitor
is BES as written. Also, if included items could subsequently be excluded,
they would be no different from any other item that met the voltage
threshold of 100kV. There would be no need for any of the inclusions if all
possible outputs from the inclusion tests go to the same exclusion test
inputs. We strongly support the addition of the language regarding local
distribution facilities, as it matches congressional intent to leave the
regulation of these facilities to state and local authorities.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
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Question 1 Comment

identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES
and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100
kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is
needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 –
I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks)
should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion
I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or
exclude an Element.
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Long Island Power Authority

Yes or No
Yes

Question 1 Comment
Need to define the term "local distribution"

Response: The SDT believes that with the last sentence in the core definition and Exclusions E1 and E3 that the term has been
sufficiently distinguished with regard to the BES. No change made.
Utility Services, Inc.

Yes

Upon reflection of the core definition and BES Inclusion Designations, Utility
Services believes that there is an unintended redundancy between the two.
Utility Services would like to suggest that the portion of the core definition
that refers to the Real and Reactive Power resources be removed from the
core and to leave the Inclusions as is.

Response: The SDT discussed your comment and decided against making a change to the core definition. However, a new
parenthetical was added in Inclusion I5 to clarify that the item is meant to exclude generators.
Cowlitz County PUD

Yes

Cowlitz County PUD No. 1 (Cowlitz) commends the SDT for the simplified
concise core definition. However, Cowlitz believes that only Real and
Reactive Power resources necessary for the support of the BES should be
included. Therefore, Cowlitz suggests the core definition or the Inclusions
section state this. This will allow basis for demonstrating resource Elements
should be excluded from the BES through the Rules of Procedure exception
process. This is not to say that owners of non-BES resource Elements should
not be registered, as such entities may still have an obligation to contribute
BES Reliability functions. Cowlitz votes affirmative and believes the above
concern can be addressed in Phase 2.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
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Question 1 Comment

industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow
the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the
threshold values and provide compelling justification for modifications to the existing values.
Ameren

Yes

a)The general concept is sound, but the Inclusion and Exclusion sections
create so many circular references it is virtually impossible to take a
definitive stance on whether an asset is included or excluded to the BES
definition. Please revise the inclusion and exclusion criteria to give
pinpointed statements that are final and do not reference other criteria, that
then again reference other criteria.
b)We believe that 200kV and above is the appropriate bright line for the
Bulk Electric System.
c)In I5, only those Reactive Power devices applied for the purpose of BES
support or BES voltage control should be included. A Reactive Power device
connected at >100kV but used for the purpose of voltage support to local
load should not be included.
d)The core definition uses "Transmission Elements" while E1 uses
"transmission Elements". What is the difference? If one or both terms are
applicable, their definition should be included.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES
and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100
kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is
needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
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Question 1 Comment

breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 –
I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks)
should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion
I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects
(i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being
responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
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Question 1 Comment

definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values.
The SDT points the commenter to Exclusion E4 for the handling of such a situation.
The SDT considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that retention of this
word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise
be included in the term “Element”.
The Dow Chemical Company

Yes

The Dow Chemical Company (“Dow) is an international chemical and plastics
manufacturing firm and a leader in science and technology, providing
chemical, plastic, and agricultural products and services to many essential
consumer markets throughout the world. Dow and certain of its worldwide
affiliates and subsidiaries, including Union Carbide Corporation, own and
operate electrical facilities at a number of industrial sites within the U.S.,
principally, in Texas and Louisiana. The electrical facilities at these various
industrial sites are configured similarly and perform similar functions. In
most cases, a tie line or lines connect the industrial site to the electric
transmission grid. Power is delivered from the electric transmission grid to
the industrial site through the tie line(s). Lines “behind-the-meter” within
the industrial site then deliver power to individual manufacturing plants
within the site. Additionally, cogeneration facilities, some of which are well
over 75 MW in size, are located at a number of industrial sites owned by
Dow and its subsidiaries. These cogeneration facilities generate power that
is distributed within the industrial site and used for manufacturing plant
operations. In some instances, excess power not required for plant
operations is delivered back into the electric transmission grid through the
tie line(s) connecting the industrial site to the grid. While the tie lines and
some of the internal lines at these industrial sites operate at 100kV or
higher, they do not perform anything that resembles a transmission
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function. Rather than transmit power long distances from generation to load
centers, the tie lines and internal lines perform primarily an end user
distribution function consisting of the distribution of power brought in from
the grid or generated internally to different plants within each industrial site.
In some cases, the facilities also perform an interconnection function to the
extent they enable power from cogeneration facilities to be delivered into
the grid. The voltage of the tie lines and internal lines at these industrial
sites is dictated by the load and basic configuration of each site. Higher
voltage lines are used when necessary to meet applicable load requirements
or to reduce line losses. That does not mean that such lines perform a
transmission function. At some sites, Dow is registered as a Generation
Owner and Generation Operator. At other sites, the applicable Regional
Entity has found that such registration is not required because of the
relatively small amount of power supplied to the grid from the applicable
cogeneration resources, even though those cogeneration resources have an
aggregate capacity greater than 75 MVA (gross aggregate nameplate rating).
Tie lines (to the grid) and internal lines at an industrial site that operate at
100kV or higher should be excluded from the BES definition if, due to the
relatively small amount of power supplied to the grid from the generation
resources at the site, the owner of those generation resources is not
required to be registered as a Generation Owner and the operator of those
generation resources is not required to be registered as a Generation
Operator. At sites where the owner of the generation resources is registered
as a Generation Owner and the operator of those generation resources is
registered as a Generation Operator, the internal lines (between the
generation resources and the manufacturing plants) that operate at 100kV
or higher should be excluded from the BES definition, because they are
distribution and not transmission facilities. The lines interconnecting the
generation resources at such sites to the transmission grid should be
included in the BES definition, but the owner and operator of such
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interconnection lines should not be registered as a Transmission Owner or
Transmission Operator. In no instance has a Regional Entity determined that
Dow or any subsidiary should be registered as a Transmission Owner or
Transmission Operator. Instead, such interconnection lines should be
considered as part of the generation resource and Generation Owners and
Generation Operators should be subject to reliability standards specifically
developed for such interconnection lines. Dow is strongly opposed to any
BES definition that would result in either the tie lines or the internal lines at
industrial sites being subject to the mandatory reliability standards
applicable to Transmission Owners and Transmission Operators.
Complying with reliability standards would cause Dow and its subsidiaries to
incur substantial compliance costs and create potential exposure to
penalties in the future for noncompliance. Perhaps such costs and exposure
could be justified if subjecting these facilities to compliance with reliability
standards resulted in a material increase in reliability of the BES, but there is
no reason to believe that will be the case. In fact, the opposite might be
true. The tie lines and internal lines at industrial sites owned by Dow and its
subsidiaries have been operated for decades as end user distribution and
interconnection facilities, and practices and procedures have developed
over the years that have enabled such operations to achieve a high degree
of reliability for such sites. Requiring these facilities to now operate in a
different manner as transmission facilities may well result in a degradation
of the reliability of the manufacturing plants located at such sites. For
example, outages would have to be coordinated with the RTO, which may
not be interested in coordinating such outages with scheduled
manufacturing plant outages. In light of these considerations, Dow agrees
with the proposed revisions to the core definition, particularly the proposal
to include a sentence expressly excluding facilities used in the local
distribution of electric energy, provided it is understood that end userowned delivery facilities located “behind-the-meter” are, regardless of
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voltage level, presumptively outside the scope of this definition.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and
non-BES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT
has pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
contracting the current scope of the BES or driving registration or de-registration.
City of Redding

Yes

Redding is concerned that NERC has a predetermined definition of
Distribution Facilities and will not evaluate networked distribution facilities
fairly. NERC stated their predetermined position in their “MOTION TO
INTERVENE AND COMMENTS OF THE NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION” filed in the case of the City of Holland, Michigan
(Docket No. RC11-5-000). On page 10 and 11 of this motion, under the
section labeled “A. Holland’s 138 kV lines are transmission rather that local
distribution facilities” NERC states “Distribution facilities generally are
characterized as elements that are designed and can carry electric energy
(Watts/MW) in one direction only at any given time from a single source
point (distribution substation) to final load centers.” NERC is clearly states
that only radial facilities are considered distribution facilities and are
unwilling to consider that network facilities over 100Kv could be classified as
Distribution Facilities. Holland’s claim of NERC over reaching their authority
appears to have credibility. In conclusion, Redding supports the addition of
Distribution Facilities as an exclusion but believes that the BES Definition
phase 2 needs to clearly define the difference between Distribution and
Transmission Facilities by identifying the equipment “necessary for the
Reliable Operation of the interconnected bulk power transmission system”.

Response: See the detailed comments on this issue in the Responses to the comments to the Question 2 of the Exception Process

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as well as the Detailed Information to Support an Exception Request Form.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that
would warrant a change from the current values that exist through the application of the definition today. These and similar issues
have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in
conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
Xcel Energy

In general, Xcel Energy supports the changes to the core definition of Bulk
Electric System. Some additional clarification may be required as suggested
below under the individual Inclusions or Exclusions.

Tacoma Power

Yes

Redding Electric Utility

Yes

ATC LLC

Yes

Portland General Electric Company

Yes

Farmington Electric Utility System

Yes

Georgia System Operations
Corporation

Yes

Nebraska Public Power District

Yes

Tacoma Power supports the core definition as currently written.

The drafting team has done a great job of adding clarity and to improving
the BES definition. Although more work is needed as noted in comments
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below, overall the drafting team is on the right track with the BES defintion.

Oncor Electric Delivery Company LLC

Yes

LCRA Transmission Services
Corporation

Yes

Memphis Light, Gas and Water
Division

Yes

Independent Electricity System
Operator

Yes

PSEG Services Corp

Yes

Orange and Rockland Utilities, Inc.

Yes

City of St. George

Yes

American Electric Power

Yes

Tillamook PUD

Yes

Consumers Energy

Yes

Springfield Utility Board

Yes

The core definition is acceptable as long as the concerns for inclusion and
exclusion are addressed as outlined in the other comments.

We strongly support the addition of the language regarding local distribution
facilities, as it matches congressional intent to leave the regulation of these
facilities to state and local authorities.

SUB particularly agrees with the addition of, “This does not include facilities
used in the local distribution of electric energy.” to the BES draft definition.

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NV Energy

Yes

The core definition is simpler than the prior version. We support the
addition of the last sentence regarding the exclusion of facilities used in the
local distribution of electric energy.

Duke Energy

Yes

Chevron U.S.A. Inc.

Yes

Central Hudson Gas and Electric
Corporation

Yes

Idaho Falls Power

Yes

Exelon

Yes

Southern Company

Yes

Texas Industrial Energy Consumers

Yes

Tri-State GandT

Yes

Western Area Power Administration

Yes

Tri-State Generation and
Transmission Assn., Inc. Energy
Management

Yes

MRO NERC Standards Review Forum

Yes

Yes. Very good progress was made in the process. The initial overly broad
language was inadvertently including parties that are not necessary to meet
the NERC and FERC goals. The current language has clarified some of the
ambiguities.

We generally support the changes made.

We believe that the new definition is a good clarification.

We believe that the new definiation is a good clarification.

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(NSRF)
Pepco Holdings Inc and Affiliates

Yes

ACES Power Marketing Standards
Collaborators

Yes

WECC Staff

Yes

Bonneville Power Administration

Yes

Northeast Power Coordinating
Council

Yes

SERC Planning Standards
Subcommittee

Yes

BGE

Yes

No comment.

Response: Thank you for your support.

76

2.

The SDT has revised the specific inclusions to the core definition in response to industry comments. Do you agree with Inclusion
I1 (transformers)? If you do not support this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.

Summary Consideration: Several commenters asked for additional clarity in the description of the types of transformers covered by
Inclusion I1 and in response the SDT has slightly revised the language in Inclusion I1 based upon comments received and to provide
additional clarity as shown below.
Several commenters suggested that Inclusion I1 contain a statement to identify the subset of transformers that are not covered by
Inclusion I1 and the SDT declined to make this revision. The SDT believes the use of language in the definition to state what is also
excluded is redundant and not needed in the definition.
Some comments were received suggesting modifying to Inclusion I1 to add a 200 kV threshold. Using a 200 kV voltage threshold and/or
an MVA threshold for inclusion of transformers in the BES and the addition of demarcation points will be considered in Phase 2 of this
effort. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a
change from the current values that exist through the application of the definition today. These and similar issues have prompted the
SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory
authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for
inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC
Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide compelling justification
for modifications to the existing values.
Several commenters asked for additional clarity on the hierarchy of inclusions and exclusions. The SDT provides the following guidance
on this topic.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
77

“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker,
bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application
of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific
criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The
exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied
in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude an
Element.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless excluded under
Exclusion E1 or E3.

Organization

Yes or No

Question 2 Comment

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Question 2 Comment

Northeast Power Coordinating
Council

No

More specific description is needed for the equipment intended to be included
in I1. For example, is it intended to include autotransformers, PARs, primary,
secondary, tertiary windings, etc.? There will be difficulty applying the
definition to facilities without this detail. Suggest rewording to: All
transformers (including auto-transformers, voltage regulators, and phase angle
regulators and all windings) with primary and secondary terminals operated at
or above 100kV, and generator step-up (GSU) transformers with one terminal
operated at or above 100KV, unless excluded by E1 or E3.

NESCOE

No

NESCOE supports the revised Inclusion I1 language that treats Exclusions E1 and
E3 as alternative exclusions, either of which may qualify as an exclusion.
However, specificity is needed regarding what equipment is included in I1 (e.g.,
autotransformers, PARs, primary, secondary, tertiary windings).

Massachusetts Department of
Public Utilities

No

The MA DPU supports the revised Inclusion I1 language that treats Exclusions E1
and E3 as alternative exclusions, either of which may qualify as an exclusion.
However, specificity is needed regarding what equipment is included in I1 (e.g.,
autotransformers, PARs, primary, secondary, tertiary windings).

Response: Several commenters indicated that additional specificity is needed to describe the transformers in Inclusion I1 and
the SDT added the word, “terminal” and the phrase, “at least one” to Inclusion I1 for additional clarity. The revised Inclusion I1
now reads:
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
The SDT provides the following guidance with respect to inclusions and exclusions to provide clarity on how to use the
definition and in response to your comment:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify
the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between
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Question 2 Comment

BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources
connected at 100 kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of
the term Element is needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified
in the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by
Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3
(local networks) should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is
Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes
Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element.
AECI and member GandTs,

No

“100 kV or above” should be modified to “200 kV or above with a registered
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Yes or No

Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power
Cooperative

Question 2 Comment
rating of 150 MVA or greater.”

Response: The issue of transformer voltage level and possibly an MVA threshold level will be discussed in Phase 2 of this
project. No change made.
Duke Energy

No

For clarity regarding 3 and 4 winding transformers, it should say “primary and at
least one secondary terminal operated at 100 kV or higher.

Response: The SDT has revised the language to provide the clarity suggested in the comment.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
New York State Dept of Public
Service

No

o I1 lacks specificity that can lead to confusion and required clarifications.
Suggested wording change: All transformers (including auto-transformers,
voltage regulators, and phase angle regulators and all windings) with primary
and secondary terminals operated at or above 100 kV, and generator step-up
(GSU) transformers with one terminal operated at or above 100 kV, unless
excluded by E1 or E3.

ISO New England Inc

No

I1 needs to be clarified such that it is clear on whether this includes
autotransformers, phase angle regulators, and devices which have a tertiary
winding. Using the tertiary winding as an example, it is not clear whether the
tertiary winding itself is considered BES, especially if it is serving a radial system
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Question 2 Comment
as described in E1.

Response: The SDT has slightly revised the language in Inclusion I1 based upon comments received and to provide clarity.
Since a transformer is one Element, any additional tertiary windings would be included in the BES if a transformer meets this
criterion for inclusion.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
Rochester Gas and Electric
and New York State Electric
and Gas

No

We generally agree, but suggest modification to the language of Inclusion I1 to
clarify its application for transformers with more than two windings:
“Transformers with two or more terminals operated at 100 kV or higher, unless
excluded under Exclusion E1 and E3.” Based on this wording, transformer
tertiary windings would also be BES - is that the intent?

Central Maine Power
Company

Yes

We generally agree, but suggest modification to the language of Inclusion I1 to
clarify its application for transformers with more than two windings:
“Transformers with two or more terminals operated at 100 kV or higher, unless
excluded under Exclusion E1 or E3.” Based on this wording, transformer tertiary
windings would also be BES - is that the intent?

Response: It is correct that associated tertiary windings are included in the BES if the transformer is based upon the language
in Inclusion I1. Also, the SDT has slightly revised the language in Inclusion I1 based upon comments received and to provide
clarity. Since a transformer is one Element, any additional tertiary windings would be included in the BES if a transformer
meets this criterion for inclusion.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
LCRA Transmission Services
Corporation

No

LCRA TSC supports the inclusion of transformers (with both the primary and
secondary windings operated at 100-kV or higher) in the BES definition;
however, additional clarification is suggested. The term transformers needs to
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Question 2 Comment
be further defined with respect to function (auto transformers, phase angle
regulators, generator step-up transformers, etc.). Similarly, a separate
definition for “Transformer” could be developed and included in the NERC
Glossary of Terms.

Response: The SDT believes the existing language is clear and the proposed additional language would be redundant.
However, in response to comments from others, the SDT has made clarifying changes to Inclusion I1 that should address your
concerns and obviate the need for a separate definition for transformers.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
ExxonMobil Research and
Engineering

Yes

The Inclusion I1 contains the phrase “unless excluded under Exclusion E1 or E3”.
While recognizing that this is a welcomed clarification on how I1 interacts with
the Exclusion section, it is inconsistent with Inclusions I2 through I5. The BES
SDT team should consider how to standardize the language around the
interactions between the Inclusions and Exclusions (perhaps add an “unless”
qualifier for each Inclusion).

Response: The SDT provides the following guidance with respect to inclusions and exclusions to provide clarity on how to use
the definition and in response to your comment:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify
the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between
BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources
connected at 100 kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of
the term Element is needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
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Organization

Yes or No

Question 2 Comment

electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified
in the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by
Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3
(local networks) should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is
Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes
Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element.
Ameren

Yes

Agree in general, but have the following comments: a) We agree in general with
the revisions to the specific inclusions for transformers in I1; however, we
believe the transformer voltage level should be 200kV or above.
b ) The inclusion is unclear since it includes a certain voltage transformers, but
excludes those that have E1 or E3 Exclusion criteria. Each exclusion criteria has
multiple stipulations to its applicability, and then has a final inclusive reference
to I3. Please make the wording exact and not dependent on clausal statements.
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Yes or No

Question 2 Comment

Response: The issue of transformer voltage level and possibly an MVA threshold level will be discussed in Phase 2 of this
project.
The SDT provides the following guidance with respect to inclusions and exclusions to provide clarity on how to use the
definition and in response to your comment:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify
the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between
BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources
connected at 100 kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of
the term Element is needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified
in the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by
Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3
(local networks) should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is
Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
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Yes or No

Question 2 Comment

Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes
Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element.
Memphis Light, Gas and
Water Division

Yes

We believe further clarification is needed to limit BES transformers only to
those serving the transmission system and not distribution loads, such as
excluding transformers with one or both terminals operating below 100 kV.

Response: Transformers are excluded from the BES if the secondary terminal operates below 100 kV. No change made.
Puget Sound Energy

Yes

Inclusion I1 references primary and secondary terminals of transformers, while
Inclusions I2 and I5 reference the high-side of transformers. The SDT should
consider using consistent terminology throughout the definition for this
concept.

Response: The SDT has reviewed the entire document for consistency in phrasing but in this particular situation finds no
problem in the terminology employed. No change made.
Michigan Public Power Agency
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)
Central Electric Cooperatve
(CEC)

Yes

MPPA supports the SDT’s changes to the first Inclusion because it is more clear
and simple than the initial approach. That being said, we suggest that an
additional sentence of clarification would help avoid future controversy about
the meaning of Inclusion 1. As MPPA understands it, the BES intends to include
transformers only if both the primary and secondary terminals operate at 100
kV or above, which is why the definition uses the word “and” (“the primary and
secondary terminals”). We support this approach since it would exclude
transformers where the secondary terminals serve distribution loads, and which
therefore function as distribution rather than transmission facilities. MPPA
believes the SDT’s intent would be clarified by adding a sentence at the end of
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Organization
Clearwater Power Company
(CPC)
Snohomish County PUD
Consumer's Power Inc.
Douglas Electric Cooperative
(DEC)
Fall River Rural Electric
Cooperative (FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric Cooperative
(UEC)
Kootenai Electric Cooperative

Yes or No

Question 2 Comment
Inclusion 1 that reads: “Transformers with either primary or secondary
terminals, or both, that operate at or below 100 kV are not part of the BES.”
This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary
terminals” was intentional.
We also support the SDT’s proposal to develop detailed guidance concerning
the point of demarcation between BES and non-BES elements in the Phase 2
SAR. In this regard, we note that, while Inclusion 1 at least implicitly suggests
that the dividing line between BES and non-BES Elements should be at the
transformer where transmission-level voltages are stepped down to
distribution-level voltages, we believe further clarification of this point of
demarcation between the BES and non-BES Elements is necessary. There are
many different configurations of transformers and other equipment that may
lie at the juncture between the BES and non-BES systems. If the point of
demarcation is designated at the transformer without further elaboration,
many entities that own equipment on the high side of a transformer will be
swept into the BES, and thereby exposed to inappropriately stringent
regulations and undue costs. For example, distribution-only utilities commonly
own the switches, bus and transformer protection devices on the high side of
transformers where they take delivery from their transmission provider.
Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners.
MPPA has some members who have been forced to sell of such assets in the
hopes of remove the necessity for a TO/TOP registration path in this region.
We also support the incorporation of language (“. . . unless excluded under
Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES
facilities, regardless of their operating voltage. Further clarification might be
achieved by using the phrase “. . . unless the transformer is operated as part of
a Radial System meeting the requirements of Exclusion E1 or a Local Network
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Yes or No

Question 2 Comment
meeting the requirements of Exclusion E2.”

Response: The SDT has slightly revised Inclusion I1 to provide additional clarity. The SDT believes it is not necessary to state
what transformers are not included in the BES, which would be redundant.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
The development of demarcation points will be included in Phase 2 of this project.
The SDT provides the following guidance with respect to inclusions and exclusions to provide clarity on how to use the
definition and in response to your comment:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify
the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between
BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources
connected at 100 kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of
the term Element is needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified
in the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by
Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3
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Yes or No

Question 2 Comment

(local networks) should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is
Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes
Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element.
Cowlitz County PUD

Yes

Cowlitz supports the SDT’s efforts to simplify this inclusion. However, Cowlitz
suggests the following change to clarify the inclusive nature of the use of “and:”
Transformers with primary and secondary terminals both operated at 100 kV or
higher...

City of Austin dba Austin
Energy

Yes

We believe additional clarification of transformers to be included may be
achieved with respect to auto transformers, phase angle regulators and
generator step-up transformers by adding the following sentence: All
transformers (including autotransformers, voltage regulators, and phase angle
regulators) with primary and secondary terminals operated at or above 100kV,
unless excluded by E1 or E3.

Sacramento Municipal Utility
District

Yes

We believe additional clarification of transformers that are to be included may
be achieved with respect to auto transformers, phase angle regulators and
generator step-up transformers by adding the following recommended
sentence: “All transformers (including autotransformers, voltage regulators, and
phase angle regulators) with primary and secondary terminals operated at or
above 100kV, unless excluded by E1 or E3.”
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Yes or No

Question 2 Comment

Utility Services, Inc.

Yes

Utility Services supports the comments offered by other commenters who
suggest that transformers and other related devices be mentioned in the
inclusion.

PacifiCorp

Yes

PacifiCorp suggests a clarification to I1 to provide as follows: “Transformers
with either primary or secondary terminals, or both, that operate at or below
100 kV are not part of the BES.”

Balancing Authority Northern
California

Yes

We believe additional clarification of transformers that are to be included may
be achieved with respect to auto transformers, phase angle regulators and
generator step-up transformers by adding the following recommended
sentence: “All transformers (including autotransformers, voltage regulators, and
phase angle regulators) with primary and secondary terminals operated at or
above 100kV, unless excluded by E1 or E3.”

Response: The SDT has slightly revised the language in Inclusion I1 based upon comments received and to provide clarity.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
PacifiCorp

Yes

PacifiCorp suggests a clarification to I1 to provide as follows: “Transformers
with either primary or secondary terminals, or both, that operate at or below
100 kV are not part of the BES.”

Response: The SDT believes it is not necessary to state what transformers are not included in the BES, which would be
redundant. No change made.
Florida Municipal Power
Agency

Yes

Please see comments to Question 1

Response: Please see response to Q1.
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Yes or No

Question 2 Comment

MEAG Power

Yes

We agree in general with the revisions to the specific inclusions for
transformers in I1; however, we believe the transformer voltage level should be
200kV or above.

Tennessee Valley Authority

Yes

TVA agrees in general with the revisions to the specific inclusions for
transformers in I1; however, we believe the low side transformer voltage level
should be 200kV or above, and requests that the Phase 2 for the project use
200kV and above or develop a transmission voltage and/or an MVA threshold
that is technically based.

SERC OC Standards Review
Group

Yes

We agree in general with the revisions to the specific inclusions for
transformers in I1; however, we believe the transformer voltage level should be
200kV or above.

Response: The issue of transformer voltage level and possibly an MVA threshold level will be discussed in Phase 2 of this
project. No change made.
National Grid

Yes

Farmington Electric Utility
System

Yes

South Houston Green Power,
LLC

Yes

Portland General Electric
Company

Yes

Northern Wasco County PUD

Yes

Northern Wasco County PUD strongly agrees with this inclusion as written. It is
consistent with the recent PRC-004 and PRC-005 interpretation and the NERC
definition of Transmission. We believe the recent changes to this inclusion add
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Yes or No

Question 2 Comment
clarity.

Georgia System Operations
Corporation

Yes

Nebraska Public Power District

Yes

Kansas City Power and Light
Company

Yes

Oncor Electric Delivery
Company LLC

Yes

Harney Electric Cooperative,
Inc.

Yes

HEC agrees with the inclusions to I1 and believes that add clarity to the
definition.

Central Lincoln

Yes

Central Lincoln strongly agrees with this inclusion as written. It is consistent
with the recent PRC-004 and PRC-005 interpretation and the NERC definition of
Transmission. We believe the recent changes to this inclusion add clarity.

PSEG Services Corp

Yes

Hydro-Quebec TransEnergie

Yes

Independent Electricity
System Operator

Yes

Orange and Rockland Utilities,
Inc.

Yes

Tillamook PUD

Yes

Tillamook PUD strongly agrees with this inclusion as written. It is consistent with
the recent PRC-004 and PRC-005 interpretation and the NERC definition of
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Organization

Yes or No

Question 2 Comment
Transmission. We believe the recent changes to this inclusion add clarity.

American Electric Power

Yes

Manitoba Hydro

Yes

Long Island Power Authority

Yes

The Dow Chemical Company

Yes

City of St. George

Yes

Mission Valley Power

Yes

Mission Valley Power - Comments: Mission Valley Power strongly agrees with
this inclusion as written. It is consistent with the recent PRC-004 and PRC-005
interpretation and the NERC definition of Transmission. We believe the recent
changes to this inclusion add clarity.

NV Energy

Yes

The changes made to I1 (Transformers) appropriately resolves several of the
industry concerns about three-winding transformers as well as an inadvertent
use of the word “and” rather than “or”.

Z Global Engineering and
Energy Solutions

Yes

Consumers Energy

Yes

Springfield Utility Board

Yes

SUB supports and appreciates the change in language from, “unless excluded
under Exclusions E1 and E3” to “Exclusion E1 or E3”. This makes it clear that
Radial System or Local Network transformers should not be considered BES
facilities, regardless of operating voltage.

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Organization

Yes or No

Chevron U.S.A. Inc.

Yes

Metropolitan Water District of
Southern California

Yes

Idaho Falls Power

Yes

ReliabilityFirst

Yes

Ontario Power Generation Inc.

Yes

Central Hudson Gas and
Electric Corporation

Yes

City of Anaheim

Yes

Southern Company

Yes

FirstEnergy Corp.

Yes

Exelon

Yes

Hydro One Networks Inc.

Yes

Tri-State GandT

Yes

Western Area Power
Administration

Yes

Texas Industrial Energy
Consumers

Yes

Question 2 Comment

We support the language as drafted.

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Organization

Yes or No

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

Yes

MRO NERC Standards Review
Forum (NSRF)

Yes

IRC Standards Review
Committee

Yes

ACES Power Marketing
Standards Collaborators

Yes

Dominion

Yes

Pepco Holdings Inc and
Affiliates

Yes

Electricity Consumers
Resource Council (ELCON)

Yes

Southern Company
Generation

Yes

WECC Staff

Yes

Bonneville Power
Administration

Yes

Texas RE NERC Standards

Yes

Question 2 Comment

The proposed changes are much clearer than proposed language in the 1st draft
of this BES definition.

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Organization

Yes or No

Question 2 Comment

Subcommittee
SERC Planning Standards
Subcommittee

Yes

Southwest Power Pool
Standards Review Team

Yes

NERC Staff Technical Review

Yes

ATC LLC

Yes

Westar Energy

Yes

Redding Electric Utility

Yes

City of Redding

Yes

Tacoma Power

Yes

Tacoma Power supports Inclusion I1 as currently written.

BGE

Yes

No comment.

Response: Thank you for your support. Due to comments received from others the SDT has made clarifying changes as follows:
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.

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3.

The SDT has revised the specific inclusions to the core definition in response to industry comments. Do you agree with Inclusion
I2 (generation) including the reference to the ERO Statement of Compliance Registry Criteria? If you do not support this change
or you agree in general but feel that alternative language would be more appropriate, please provide specific suggestions in
your comments.

Summary Consideration: Comments received regarding the threshold level for generators, the relationship between the NERC
Compliance Registry and the BES Definition and the need for contiguous BES elements will be considered in the Phase 2 review.
In response to comments regarding the reference to the ERO Statement of Compliance Registry Criteria (SCRC) the SDT made a clarifying
change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2, instead specifying the 20/75 MVA
reference threshold values in order to avoid the possibility of the registry values being changed and thus affecting the BES Definition
prior to the resolution of the threshold values in Phase 2 of this project.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects
(i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being
responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012,
and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have prompted the SDT to
separate the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities.
Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2
of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing
Committees, to develop analyses which will properly assess the threshold values and provide compelling justification for modifications
to the existing values.
Inclusion I2 was clarified as follows:
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate nameplate
rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the highside of the step-up transformer(s) connected at a voltage of 100 kV or above.

Organization

Yes or No

Question 3 Comment

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Organization

Yes or No

Question 3 Comment

Northeast Power Coordinating
Council

No

In deference to direction given to the Drafting Team, Inclusion I2 should remove the
reference to the Statement of Compliance Registry Criteria. The current language
induces circular arguments without a true governing document. The definition
should drive what appears in the registration criteria. I2 should be revised to read:
“Generating resources with a gross nameplate rating of 20MVA or greater, or
generating plant/facility connected at a common bus, with an aggregate nameplate
rating of 75MVA or greater and is directly connected to a BES Element.” This is
consistent with the proposed I2 and the current Compliance Registry Criteria.
Ultimately the definition should be the governing document and provide the details
of what generation should be included. It is understood that Phase 2 of this project
will address this.

Balancing Authority Northern
California

No

We recommend removing the reference of the ERO Statement of Compliance
Registry Criteria (Registry Criteria). The BES Definition should be the governing
document and independent of ERO registration requirements. The definition should
drive what appears in the Registry Criteria. Additionally, we support using the BES
Phase 2 technical analysis to identify and provide technical support for determining
the appropriate minimum MVA rating that a single unit, or the aggregation of
multiple units, must meet to be considered part of the BES.

Oregon Public Utility
Commission Staff

No

Reference to NERC Statement of Compliance Registry Criteria (SCRC) needs to be
eliminated from the BES Definition. This circularity must be eliminated. Proposed
revised language is:”I2 - Generating resource(s) with a gross individual nameplate
rating greater than 20 MVA or with a gross aggregate nameplate rating greater than
75 MVA including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above.”

American Electric Power

No

AEP is a proponent of cross-referencing related documents to avoid elements from
becoming out of sync, however, rather than having the BES Definition document
reference the ERO Statement of Compliance Registry Criteria, perhaps it should be
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Question 3 Comment
the other way around. This definition document undergoes a more thorough industry
development and review process. The ERO Statement of Compliance Registry Criteria
does not get specific in regards to device types. The BES Definition document is a
more appropriate place to designate inclusion criteria.

New York State Dept of Public
Service

No

In I2, there is a reference to the Statement of Compliance Registry Criteria. However,
the Statement references the BES definition. This circular logic results in a fatally
flawed definition. The statement reference should be replaced with the actual
intended words.

Rochester Gas and Electric
and New York State Electric
and Gas

No

Inclusion I2 should remove the reference to the Statement of Compliance Registry
Criteria. The definition should stand on its own. I2 should be revised to read:
“Generators with a gross nameplate rating of 20 MVA or greater, or a generating
plant/facility connected at a common bus, with a gross aggregate nameplate rating of
75 MVA or greater and is directly connected at a voltage of 100 kV or above. BES
includes the generator terminals through the high-side of the step-up transformer(s)
connected at a voltage of 100 kV or above.” This is consistent with the proposed I2
and the current Compliance Registry Criteria.

Sacramento Municipal Utility
District

No

We recommend removing the reference of the ERO Statement of Compliance
Registry Criteria (Registry Criteria). The BES Definition should be the governing
document and independent of ERO registration requirements. The definition should
drive what appears in the Registry Criteria. Additionally, we support using the BES
Phase 2 technical analysis to identify and provide technical support for determining
the appropriate minimum MVA rating that a single unit, or the aggregation of
multiple units, must meet to be considered part of the BES.

Central Maine Power
Company

No

Inclusion I2 should remove the reference to the Statement of Compliance Registry
Criteria. The definition should stand on its own. I2 should be revised to read:
“Generators with a gross nameplate rating of 20 MVA or greater, or a generating
plant/facility connected at a common bus, with a gross aggregate nameplate rating of
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Question 3 Comment
75 MVA or greater; and is directly connected at a voltage of 100 kV or above. BES
includes the generator terminals through the high-side of the step-up transformer(s)
connected at a voltage of 100 kV or above.” This is consistent with the proposed I2
and the current Compliance Registry Criteria.

Farmington Electric Utility
System

No

FEUS is concerned I2 is dependent on the Statement of Compliance Registry Criteria
(SCRC). Modification of the SCRC is not required to go through the same process of
modification of a Standard but section 1400 of the NERC Rules of Procedure. Section
1400 does allow for industry comment and requires multiple tiers of approval.
However, it seems by changing the SCRC generating resources may be included or
excluded from the BES - without requiring modification to the definition of the BES
through the Standards Development Process. In addition, Page 4 Section I of the SCRC
is dependent on the NERC definition of the BES. Logically, the SCRC should be
dependent on the definition of the BES not the inverse.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2,
instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and
thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Electricity Consumers
Resource Council (ELCON)

No

Since an aggregate of 75 MVA is allowed at a single site, there is no basis for
maintaining the 20 MVA for a single generator. The proposed MOD-026 assigns
thresholds by region that are much higher than 20 MVA for modeling purposes.
Since modeling generally would require more granularity than what is necessary for
the reliable operation of the interconnected transmission system (BES), the SDT
might want to review the threshold basis for NERC Project 2007-09 (Generator
Verification). It is understood that the threshold will be reconsidered in Phase 2 of
the BES Definition Project; however, a modest change from 20 to 75 MVA seems
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Question 3 Comment
appropriate on an interim basis justified by the current 75 MVA aggregate per site.
The following phrase should be added at the end “unless excluded under Exclusion
E2.”

Texas RE NERC Standards
Subcommittee

No

Since an aggregate of 75 MVA is allowed at a single site, there is no basis for
maintaining the 20 MVA for a single generator. The proposed MOD-026 assigns
thresholds by region that are much higher than 20 MVA for modeling purposes.
Since modeling generally would require more granularity than what is necessary for
the reliable operation of the interconnected transmission system (BES), the SDT
might want to review the threshold basis for NERC Project 2007-09 (Generator
Verification).

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values.
Coordination between the BES Definition and the MOD Standards will be addressed in Phase 2.
Tri-State GandT

No

1. The parenthetical phrase regarding the ERO SCRC is not clear. Is the intent that
the inclusion applies to any generating resource that is required to register as a
Generator or Generator Operator per the ERO SCRC? Or was a reference to the 75
MVA threshold inadvertently omitted? It also seems that it wouldn’t need to be in
parentheses, just make it a phrase in the sentence.
2. The wording of the sentence after the parenthetical phrase is also worded
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awkwardly. Suggest changing it to “including the generator terminals and all
electrical equipment up to and including the high side of generator step up
transformers, if they are connected at a voltage of 100 kV or higher.

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

No

1. The parenthetical phrase regarding the ERO SCRC is not clear. Is the intent that
the inclusion applies to any generating resource that is required to register as a
Generator or Generator Operator per the ERO SCRC? Or was a reference to the 75
MVA threshold inadvertently omitted? It also seems that it wouldn’t need to be in
parentheses, just make it a phrase in the sentence.
2. The wording of the sentence after the parenthetical phrase is also worded
awkwardly. Suggest changing it to “including the generator terminals and all
electrical equipment up to and including the high side of generator step up
transformers, if they are connected at a voltage of 100 kV or higher.

Pepco Holdings Inc and
Affiliates

No

The definition should not reference the ERO Statement of Compliance Registry
Criteria; rather the actual generation threshold criteria should be listed in the
definition itself. This way the definition can stand on it’s own without having to refer
to another document for applicability.
Also, the wording should be changed to read “including the generator terminals
through the high side of any dedicated generator step-up transformer(s), connected
at a voltage of 100kV or above.” Otherwise, the present wording could ensnare
distribution facilities (similar to the cranking path argument in I3) if a 21 MVA
generator was connected on a distribution line with no dedicated generator step-up
transformer. In that case the distribution line and substation feeder transformer
might be construed to be in scope.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion
I2, instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being
changed and thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
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nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
The I2 inclusion refers only to generation “ … through the high-side of the step-up transformer(s) connected at a voltage of 100
kV or above.” No change made.
ExxonMobil Research and
Engineering

No

The Inclusion I1 contains the phrase “unless excluded under Exclusion E1 or E3”.
While recognizing that this is a welcomed clarification on how I1 interacts with the
Exclusion section, it is inconsistent with Inclusions I2 through I5. The BES SDT team
should consider how to standardize the language around the interactions between
the Inclusions and Exclusions (perhaps add an “unless” qualifier for each Inclusion).

South Houston Green Power,
LLC

No

SHGP agrees with the proposed revisions to Inclusion I2, but requests the following
phrase added at the end “unless excluded under Exclusion E2”.

Nebraska Public Power District

No

Inclusion 2 does not take into consideration a later exclusion (Exclusion 3). At the end
of Inclusion 2 after the words “..100 kV or above.” Add the words “, unless excluded
under Exclusion 3”.

MRO NERC Standards Review
Forum (NSRF)

No

Unless excluded under E2.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer,
circuit breaker, bus section, or transmission line. An element may be comprised of one or more components. “
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Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application
of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific
criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The
exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied
in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element.
Harney Electric Cooperative,
Inc.

No

HEC would like to see the inclusion of specific thresholds that are technically justified.

City of St. George

No

The basis for the Compliance Registry Criteria generation levels for inclusion seems to
be arbitrary with little or no justification. As currently proposed, a small 20 MVA
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generator must comply with same requirements as large units of several hundred
MVA of generation capacity. Phase 2 of the BES project may help address the issue
but in the meantime many facilities must comply with numerous standards with little
or no benefit to the reliability of the actual BES. No timeline for Phase 2 is indicated.
Finding a bright line number for the generation levels on a per unit or overall plant
basis will be a difficult task, but the present MVA levels of the Registration Criteria
are very low for automatic inclusion. The compliance requirements of an entity
should match the impact to the system.

NV Energy

No

While we do not agree with making specific reference and linkage to the generator
thresholds of the SCRC, it is understood that a timely justification of any alternative
threshold was not possible. It is of paramount importance that the subject of
generation thresholds be addressed in subsequent development of this Definition.
We are of the opinion that generation ought to be considered as a “user” of the BES,
not necessarily a part of the BES, similar in concept to the way Load uses the BES.
Using this concept, the BES would be restricted to the “wires” type facilities.
Standards would nevertheless be applicable to generators that use the BES, so no gap
in reliability would exist.

Idaho Falls Power

No

Reliance upon the Registry Criteria falls back to the 20MVA threshold. We believe
this threshold is very low and unnecessarily draws in small entities for which there is
no impact to the BES. We understand the barriers and the volume of tenchnical
evidence required for any change and we therefore have no alternative language to
suggest.

PacifiCorp

No

Requiring owners of single generators (20 MVA - 75 MVA) to meet reliability
standards that owners of distributed power producing resources (See I4) do not have
to meet is discriminatory. The limit for a single unit should be set to 75 MVA until
such time as a technical review can determine the appropriate levels for all
generation resources. However, even with this concern, PacifiCorp supports the
entire BES definition in its current form based on the timeframe under which the SDT
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is operating and with an emphasis based on a phase II SAR to address PacifiCorp’s
objections regarding generation levels.

Holland Board of Public Works

No

It is essential that regional entities and NERC recognize that “facilities used in the
local distribution of electric energy” are not included in the definition of BES,
regardless of the gross individual or gross aggregate nameplate rating of generation
resources. While the addition of the second sentence in the core definition makes
this clarification, Holland BPW believes it is necessary that regional entities and NERC
recognize that neither this Inclusion nor any of the Inclusions may be used as a basis
to compel registration and compliance in such instances, regardless of the size of the
generators. The statutory exemption of facilities used in the local distribution of
electric energy is not limited by generator number or capability. NERC’s definitions
cannot impose limitations that are not set forth in the statute. For purposes of the
exclusion of facilities that might otherwise meet the definition of BES, the thresholds
for determining what generating resources constitute BES facilities should be
modified from the current levels (gross individual nameplate capacity of 20 MVA or
gross aggregate nameplate rating of 75 MVA). Holland BPW supports modification of
the thresholds to not less than 100 MVA (gross individual nameplate capacity) and
300 MVA (gross aggregate nameplate).

Hydro One Networks Inc.

No

We do not agree with the thresholds of 20 MVA for a single unit and 75 MVA
aggregate at a plant, carried forward from the compliance registry. We understand
the suggested phased approach and expect that the issue will be dealt with at that
future time. With the exception of units that are must runs for reliability reasons, we
suggest that the SDT should consider units smaller than 75 MVA or x MVA is
designated as BES support element and not BES element. These units should only be
required to comply with a handful of relevant NERC Standards. For example, o
Voltage and frequency ride through capability o Voltage control (AVR, etc.) o
Underfrequency trip setting o Protection relay setting coordination o Data
submission for modeling; verification of capability and model These smaller and
geographically dispersed generating resources should neither be designated as BES
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element nor be required to have its connection path be designated as BES. We
suggest removing the parentheses enclosing the text “with gross individual...” since
their inclusion may lead to an erroneous reading of provision to include generators
that do not meet ERO Statement of Compliance Registry Criteria.

Response: The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values. No change
made.
Ontario Power Generation Inc.

No

OPG does not agree that the question of the 20 MVA (single) versus 75 MVA
(aggregate) threshold should be deferred until a subsequent phase of the standard
development process ("Phase 2"). This question should be resolved now. In general,
key elements of the development process should not be parsed out into multiple
phases, in hopes that "Standard Development Fatigue" will eliminate critics of the
approach.
Further, selecting the generator terminals as the boundary for BES within the
generating station means that the Isolated Phase Bus (IPB), which connects the
generator terminals to the Low Voltage (LV) terminals of the generator step-up (GSU)
transformer, is now included as a BES element. The IPB is operated at low voltage, no
more than 22kV, so including it as a BES element is going beyond the FERC order 743
and 743a. OPG strongly recommends that the BES boundary be moved to the LV
terminals of the GSU transformer.
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Response: The SDT acknowledges and appreciates your perspective and frustration. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values. No change
made.
The I2 inclusion refers to generation“… including the generator terminals through the high-side of the step-up transformer(s)
connected at a voltage of 100 kV or above. Comments received regarding the threshold level for generators, the relationship
between the NERC Compliance Registry and the BES Definition and the need for contiguous BES elements will be considered in
the Phase 2 review.
Chevron U.S.A. Inc.

No

It is not logical to allow an aggregate of 75 MVA at a single site for multiple
generators while maintaining 20 MVA for a single generator.
Further, if a party exceeds export of 75 MVA to meet an emergency condition on the
grid, it should not be a triggering event for BES definition. Parties should be
concerned with keeping the grid operational rather than the adverse effect of
exceeding 75 MVA.

Response: The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
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System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values. No change
made.
Please see the detailed responses to Q9.
Massachusetts Department of
Public Utilities

No

Failing to establish a known MVA rating at this stage is problematic. The BES
definition cannot be considered in a vacuum, and adjusting or establishing thresholds
such as MVA ratings will create regulatory uncertainty and may result in additional
costs and unnecessary system upgrades.
Additionally, Inclusion I2 should remove the reference to the Statement of
Compliance Registry Criteria. The definition should be the governing document
regarding generation that is included in the BES.

NESCOE

No

Failing to establish a known MVA rating at this stage is problematic. The BES
definition cannot be considered in a vacuum, and adjusting or establishing thresholds
such as MVA ratings will create regulatory uncertainty and may result in additional
costs and unnecessary system upgrades.
Additionally, Inclusion I2 should remove the reference to the Statement of
Compliance Registry Criteria. The definition should be the governing document
regarding generation that is included in the BES.

Northern Wasco County PUD

No

Referencing the Criteria which in turn references the BES definition creates a circular
definition. Northern Wasco County PUD encourages the adoption of specific
thresholds that are technically justified. We also note that the Criteria and its
revisions do not go through the standards development process, so that thresholds
may change with little warning and without triggering an implementation plan for
facilities that may be swept into the BES as a result.

Central Lincoln

No

Referencing the Criteria which in turn references the BES definition creates a circular
definition. Central Lincoln encourages the adoption of specific thresholds that are
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technically justified. We also note that the Criteria and its revisions do not go through
the standards development process, so that thresholds may change with little
warning and without triggering an implementation plan for facilities that may be
swept into the BES as a result.

Tillamook PUD

No

Referencing the Criteria which in turn references the BES definition creates a circular
definition. Tillamook PUD encourages the adoption of specific thresholds that are
technically justified. We also note that the Criteria and its revisions do not go through
the standards development process, so that thresholds may change with little
warning and without triggering an implementation plan for facilities that may be
swept into the BES as a result.

Mission Valley Power

No

Mission Valley Power - Referencing the Criteria which in turn references the BES
definition creates a circular definition.
Mission Valley Power encourages the adoption of specific thresholds that are
technically justified. We also note that the Criteria and its revisions do not go through
the standards development process, so that thresholds may change with little
warning and without triggering an implementation plan for facilities that may be
swept into the BES as a result.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion
I2, instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being
changed and thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications
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that would warrant a change from the current values that exist through the application of the definition today. These and
similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will
allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the
threshold values and provide compelling justification for modifications to the existing values.
City of Austin dba Austin
Energy

No

We recommend removing the reference of the ERO Statement of Compliance
Registry Criteria (Registry Criteria). The BES Definition should be the governing
document and independent of ERO registration requirements. The definition should
drive what appears in the Registry Criteria.
Additionally, we support using the BES Phase 2 technical analysis to identify and
provide technical support for determining the appropriate minimum MVA rating that
a single unit, or the aggregation of multiple units, must meet to be part of the BES.

The Dow Chemical Company

No

Comments: Dow agrees with the proposed revisions to Inclusion I2, particularly the
proposal to expressly reference the ERO Statement of Compliance Registry Criteria,
but the following phrase should be added at the end “unless excluded under
Exclusion E2”.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2,
instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and
thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project due to numerous comments
received.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.

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Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer,
circuit breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application
of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific
criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The
exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied
in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
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include or exclude an Element.
LCRA Transmission Services
Corporation

No

Response: Without a specific comment the SDT is unable to respond.
Kansas City Power and Light
Company

No

Nameplate rating of the generator is not a reflection of what can be actually injected
into the transmission system with resulting electrical impacts on transmission loading
and behavior. Recommend the BES definition be based on a generators established
net accredited generating capacity instead of what it could do by nameplate rating.
In addition, many generators do not achieve their nameplate rating due to limitations
imposed by the limitations and capabilities of their turbine/boiler capabilities. Using
the nameplate rating will not allow the exclusion of some generators that should be
excluded. Recommend the following language: Generating resource(s) with a net
accredited capability per the ERO Statement of Compliance Registry Criteria and
including the generator terminals through the high-side of the step-up
transformer(s), connected at a voltage of 100 kV or above.

Response: For Phase 1, the SDT has used nameplate rating in order to maintain consistency with the ERO Statement of
Compliance Registry Criteria. No change made.
The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications
that would warrant a change from the current values that exist through the application of the definition today. These and similar
issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
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and provide compelling justification for modifications to the existing values.
Ameren

No

a) This definition becomes dependent on a document that can be changed without
direct correlation to the BES definition. Remove the reference to the ERO
Statement of Compliance Registry Criteria, and simply state the criteria as
currently used. There is no need to look up another definition in another
document to identify what is included in the BES definition.
b) All MOD Standards' requirements for generators should also follow this
definition.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2,
instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and
thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
b) Coordination between the BES Definition and the MOD Standards will be addressed in Phase 2.
Tacoma Power

Yes

Tacoma Power generally supports Inclusion I2 and deferring the appropriate
quantitative thresholds to those that will be determined in Phase 2. However, the
term “gross individual” and “gross aggregate” nameplate rating, although industry
used terms, are not industry defined or uniformly understood and applied.
Nameplate ratings are determined from discussions and negotiations between the
designer, supplier and the owner and it is the owner that makes the final
determination of the generating station equipment nameplate ratings. Nameplate
ratings for thermal or hydro plants may be based on such things as: fuel mix (best,
worst and average), fuel delivery capacity, reservoir level, best efficiency point,
normal operating point, ancillary equipment capacities, emissions and discharge
restrictions, continuous versus peak output and designed versus installed and tested
capacities. It would be more uniform to establish new or use existing criteria to
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define “gross individual” and “gross aggregate” nameplate ratings, such as that used
in the Code of Federal Regulations CFR 18, Part 11.1, “Authorized Installed Capacity”
for hydraulic units and CFR 18, Part 287.101, “Determination of Powerplant Design
Capacity” for steam electric, combustion turbine and combined cycle units.

Response: For Phase 1, the SDT has used nameplate rating in order to maintain consistency with the ERO Statement of
Compliance Registry Criteria. No change made.
The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications
that would warrant a change from the current values that exist through the application of the definition today. These and similar
issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
Hydro-Quebec TransEnergie

We believe that automatic inclusion of such generation and the path to connect them
to the BES would bring a great amount of facilities in the BES. Generation should be
considered on a different level such as "BES Support Elements" and provisions should
be made so that some specific reliability standards would apply to them.

Response: The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
115

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technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values. No change made.
Snohomish County PUD
Kootenai Electric Cooperative

Yes

SNPD supports the changes made in Inclusion 2 and believe that the definition in its
current form adds clarity. In particular, we support the SDT’s decision to collapse
Inclusions 2 and 3 from the previous draft definition into a single Inclusion that
addresses the treatment of generation for purposes of the BES definition. We also
support the SDT’s proposal for a Phase 2 of the BES Definition process to examine the
technical justification for these thresholds and to establish new thresholds based on a
careful technical analysis. It is our understanding that the generator threshold issue
will be vetted through the complete standards development process. We agree with
this approach because if the generator threshold is treated as merely an element of
NERC’s Rules of Procedure, it can be changed with considerably less due process and
industry input than the Standards Development Process. Compare NERC Rules of
Procedure § 1400 (providing for changes to Rules of Procedure upon approval of the
NERC board and FERC) with NERC Standards Process Manual (Sept. 3, 2010)
(providing for, e.g., posting of SDT proposals for comment, successive balloting, and
super-majority approval requirements). See also Order No. 743-A, 134 FERC ¶
61,210 at P 4 (2011) (“Order No. 743 directed the ERO to revise the definition of ‘bulk
electric system’ through the NERC Standards Development Process” (emph. added)).
Addressing all aspects of Phase 2 through the Standards Development Process will
improve the content of the definition by bringing to bear industry expertise on all
aspects of the definition and will ensure that, once firm guidelines are established,
they can be relied upon by both industry and regulators without threat that they will
be changed with little notice and little due process. SNPD also believes further
clarification of the proposed language would be appropriate. The SDT proposes
continued reliance upon the thresholds that are used in the NERC Statement of
Compliance Registry Criteria for registration of Generation Owners and Generation
Operators, which is currently 20 MVA for an individual generation unit and 75 MVA
for multiple units on a single site. Conceptually, we are concerned about this
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Question 3 Comment
approach because, as we understand it, the purpose of the Compliance Registry is to
sweep in all generators that might be material to the reliable operation of the BES,
and not to definitively determine whether a given generator is, in fact, material to the
reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to
identify “candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly,
we believe that the generator threshold determined in Phase 2 should be
incorporated directly into the BES Definition rather than being incorporated by
reference from the SCRC.We also believe that the specific language proposed by the
SDT could be further clarified. The SDT proposes to include generation in the BES if
the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder
for the results of the technical analysis that would occur in Phase 2 but we believe
simply stating that the threshold will be “per the ERO Statement of Compliance
Registry” is ambiguous. Further, for the reasons noted above, we believe the
threshold should be part of the BES Definition, and should not simply be a crossreference to the SCRC (and, given the different purposes of the BES Definition and
the SCRC, it is not clear that the same threshold should be used in both). We
therefore propose that Inclusion 2 be rewritten to state: “Qualifying Individual
Generation Resources or Qualifying Aggregate Resources connected at a voltage of
100 kV or above.” Two definitions would then be added to the note at the end of the
definition to read as follows:"For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality
threshold to be included in this definition or, in the absence of such a materiality
threshold, that meets the gross nameplate capacity voltage threshold requiring
registration of the owner of such a resource as a Generation Owner under the ERO
Statement of Compliance Registry Criteria.""For purposes of this BES Definition,
Qualifying Aggregate Generation Resources means any facility consisting of one or
more generating units that are connected at a common bus that meets the
materiality threshold to be included in this definition, or, in the absence of such a
threshold, that meets the gross nameplate capacity voltage threshold requiring
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Question 3 Comment
registration of the owner of multiple-unit generator as a Generation Owner under the
ERO Statement of Compliance Registry Criteria."The “materiality threshold” is
intended to refer to the generator threshold developed in Phase 2. We suggest using
definitions in this fashion for several reasons. First, we believe the language we
suggest more clearly states the intention of the SDT, which we understand is to
classify generation units as part of the BES if they are necessary for operation of the
BES, but to exclude smaller generating units because they are not material to the
operation of the interconnected transmission grid. Second, we believe use of the
defined terms better reflects the intention of the SDT to reserve the specific question
about generator thresholds to the technical analysis that will occur in Phase 2
without having to revise the BES Definition at the end of that process. That is, the
definitions are designed to allow the SDT to include revised thresholds in the
definition at the conclusion of the Phase 2 process based upon the technical analysis
planned for Phase 2, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the
SCRC would only be a fall-back, to be used only until Phase 2 is completed.Third, the
definitions can be incorporated into other parts of the BES Definition, which will add
consistency and clarity. As noted in our answers to several of the questions below,
the specific 75 MVA threshold is retained in several of the Exclusions and Inclusions,
and we believe the industry would be better served if the revised thresholds arrived
at after technical analysis in Phase 2 are automatically incorporated into all relevant
provisions of the BES Definition. There is no reason for the SDT to continue to rely on
the 75 MVA threshold once the analysis planned for Phase 2 on the threshold issue is
completed. Fourth, the phrase “or that meets the materiality threshold to be
included in this definition” is intended to preserve the SDT’s flexibility to make a
determination that generators below a specific threshold are not “necessary to”
maintain the reliability of the interconnected transmission system, and to incorporate
that finding as part of the definition itself, even if a different threshold is used in the
SCRC to identify potential candidates for registration. Accordingly, our proposed
language makes clear that a specific threshold in the definition controls over any
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Question 3 Comment
threshold that might be included in the SCRC. For the reasons stated above, we
believe is it highly desirable to include any material threshold in the BES Definition
itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Hence, we agree with the SDT’s
decision to examine the question of where the line between BES and non-BES
Elements should be drawn more closely in Phase 2 under the rubric of “contiguous vs.
non-contiguous BES,” and commend the work of the Project 2010-07 Standards
Drafting Team and the GO-TO Team as a good starting point for the SDT’s analysis on
this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities
interconnecting such generators to be part of the BES. As discussed more fully in our
answer to Question 9, based on extensive technical analysis that has already been
performed by the NERC Project 2010-07 Standards Drafting Team and its
predecessor, the NERC “GO-TO Team,” regulating as part of the BES a dedicated
interconnection facility connecting a BES generator to the interconnected bulk
transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no
improvement in bulk system reliability. We also believe the clauses at the end of
Inclusion 2 are somewhat confusing and that greater clarity would be achieved by
changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above” so that the Inclusion
covers transformers with terminals “connected at a voltage of 100 kV or above,
including the generator terminal(s) on the high side of the step-up transformer(s) if
operated at a voltage of 100 kV or above.”
Finally, as discussed further in our answer to Questions 5 and 6, SNPD believes more
clarity may be achieved by collapsing Inclusion 5, addressing Reactive Power
resources, and Inclusion 4, which addresses dispersed renewable resources, into a
single Inclusion that addresses “power producing resources” (the language used in
current Inclusion 4).

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Response: Thank you – the SDT acknowledges and appreciates your comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT
has responsibilities associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in
regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of
strong technical justifications that would warrant a change from the current values that exist through the application of the
definition today. These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT
to address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all
recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17
Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for modifications to the
existing values.
The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2, instead
specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and thus
affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Please see detailed responses to Q5 and Q6.
Independent Electricity
System Operator

Yes

While we agree with Inclusion I2, we suggest removing the parentheses enclosing the
text “with gross individual...” since their inclusion may lead to an erroneous reading
of provision to include generators that do not meet ERO Statement of Compliance
Registry Criteria.

Puget Sound Energy

Yes

The term "per" should be replaced by "greater than the levels specified for a
Generator Owner/Operator in". For a definition of this importance, the term "per" is
too vague.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2,
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instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed
and thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)
Central Electric Cooperatve
(CEC)
Clearwater Power Company
(CPC)
Consumer's Power Inc.
Douglas Electric Cooperative
(DEC)
Fall River Rural Electric
Cooperative (FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric

Yes

CLPD supports the changes made in Inclusion 2 and believe that the definition in its
current form adds clarity. In particular, we support the SDT’s decision to collapse
Inclusions 2 and 3 from the previous draft definition into a single Inclusion that
addresses the treatment of generation for purposes of the BES definition. We also
support that aspect of the SDT’s proposal for a Phase 2 of the BES Definition process
that would examine the technical justification for these thresholds and that would
establish new thresholds based on a careful technical analysis. It is our
understanding that the generator threshold issue will be vetted through the
complete standards development process. We agree with this approach becauseif
the generator threshold is treated as merely an element of NERC’s Rules of
Procedure, it can be changed with considerably less due process and industry input
than the Standards Development Process. Compare NERC Rules of Procedure §
1400 (providing for changes to Rules of Procedure upon approval of the NERC board
and FERC) with NERC Standards Process Manual (Sept. 3, 2010) (providing for, e.g.,
posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011)
(“Order No. 743 directed the ERO to revise the definition of ‘bulk electric system’
through the NERC Standards Development Process” (emph. added)). Addressing all
aspects of Phase 2 through the Standards Development Process will improve the
content of the definition by bringing to bear industry expertise on all aspects of the
definition and will ensure that, once firm guidelines are established, they can be
relied upon by both industry and regulators without threat that they will be changed
with little notice and little due process.CLPD believes further clarification of the
proposed language would be appropriate. The SDT proposes continued reliance
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Organization
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric Cooperative
(UEC)

Yes or No

Question 3 Comment
upon the thresholds that are used in the NERC Statement of Compliance Registry
Criteria for registration of Generation Owners and Generation Operators, which is
currently 20 MVA for an individual generation unit and 75 MVA for multiple units on
a single site. as we understand it, the purpose of the Compliance Registry is to sweep
in all generators that might be material to the reliable operation of the BES, and not
to definitively determine whether a given generator is, in fact, material to the reliable
operation of the BES. As the SCRC itself states, the SCRC is intended only to identify
“candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we
believe that the generator threshold determined in Phase 2 should be incorporated
directly into the BES Definition rather than being incorporated by reference from the
SCRC.We also believe that the specific language proposed by the SDT could be further
clarified. The SDT proposes that generation be included in the BES if the “Generation
resource(s)” has a “nameplate rating per the ERO Statement of Compliance Registry.”
We understand this language is intended to be a placeholder for the results of the
technical analysis that would occur in Phase 2 but we believe simply stating that the
threshold will be “per the ERO Statement of Compliance Registry” is ambiguous.
Further, for the reasons noted above, we believe the threshold should be part of the
BES Definition, and should not simply be a cross-reference to the SCRC (and, given
the different purposes of the BES Definition and the SCRC, it is not clear that the
same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying
Aggregate Resources connected at a voltage of 100 kV or above.” Two definitions
would then be added to the note at the end of the definition to read as follows:For
purposes of this BES Definition, Qualifying Individual Generation Resources means an
individual generating unit that meets the materiality threshold to be included in this
definition or, in the absence of such a materiality threshold, that meets the gross
nameplate capacity voltage threshold requiring registration of the owner of such a
resource as a Generation Owner under the ERO Statement of Compliance Registry
Criteria.For purposes of this BES Definition, Qualifying Aggregate Generation
Resources means any facility consisting of one or more generating unitsthat are
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Question 3 Comment
connected at a common bus that meets the materiality threshold to be included in
this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit
generator as a Generation Owner under the ERO Statement of Compliance
RegistryCriteria..The “materiality threshold” is intended to refer to the generator
threshold developed in Phase 2. We suggest using definitions in this fashion for
several reasons. First, we believe the language we suggest more clearly states the
intention of the SDT, which we understand is to classify generation units as part of
the BES if they are necessary for operation of the BES, but to exclude smaller
generating units because they are not material to the operation of the
interconnected transmission grid. Second, we believe use of the defined terms
better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase 2 without
having to revise the BES Definition at the end of that process. That is, the definitions
are designed to allow the SDT to include revised thresholds in the definition at the
conclusion of the Phase 2 process based upon the technical analysis planned for
Phase 2, and the revised thresholds will be automatically incorporated into the BES
Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase 2 is completed.Third, the definitions
can be incorporated into other parts of the BES Definition, which will add consistency
and clarity. As noted in our answers to several of the questions below, the specific 75
MVA threshold is retained in several of the Exclusions and Inclusions, and we believe
the industry would be better served if the revised thresholds arrived at after
technical analysis in Phase 2 are automatically incorporated into all relevant
provisions of the BES Definition. There is no reason for the SDT to continue to rely on
the 75 MVA threshold once the analysis planned for Phase 2 on the threshold issue is
completed. Fourth, the phrase “or that meets the materiality threshold to be
included in this definition” is intended to preserve the SDT’s flexibility to make a
determination that generators below a specific threshold are not “necessary to”
maintain the reliability of the interconnected transmission system, and to incorporate
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Question 3 Comment
that finding as part of the definition itself, even if a different threshold is used in the
SCRC to identify potential candidates for registration. Accordingly, our proposed
language makes clear that a specific threshold in the definition controls over any
threshold that might be included in the SCRC. For the reasons stated above, we
believe is it highly desirable to include any material threshold in the BES Definition
itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Finally, we agree with the SDT’s
decision to examine the question of where the line between BES and non-BES
Elements should be drawn more closely in Phase 2 under the rubric of “contiguous vs.
non-contiguous BES,” and commend the work of the Project 2010-07 Standards
Drafting Team and the GO-TO Team as a good starting point for the SDT’s analysis on
this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities
interconnecting such generators to be part of the BES. As discussed more fully in our
answer to Question 9, based on extensive technical analysis that has already been
performed by the NERC Project 2010-07 Standards Drafting Team and its
predecessor, the NERC “GO-TO Team,” regulating as part of the BES a dedicated
interconnection facility connecting a BES generator to the interconnected bulk
transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no
improvement in bulk system reliability. We also believe the clauses at the end of
Inclusion 2 are somewhat confusing and that greater clarity would be achieved by
changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above” so that the Inclusion
covers transformers with terminals “connected at a voltage of 100 kV or above,
including the generator terminal(s) on the high side of the step-up transformer(s) if
operated at a voltage of 100 kV or above.”

Response: The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
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Question 3 Comment

deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values.
The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2, instead
specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and thus
affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Southern Company
Generation

Yes

Yes, provided that the minimum gross individual nameplate rating threshold is the
same as the gross aggregate nameplate rating (currently > 75MVA).
The MVA ratings are specified in many places in the BES definition, where a reference
is made in I2 to using the Statement of Compliance Registry Criteria. We believe that
the BES definition should point to the Statement of Compliance Registry Criteria and
not include MVA values.
We also believe individual units < 75MVA should be excluded unless they have been
shown to be critical to BES reliability through a technical justification study
performed by the transmission planning authority.

Michigan Public Power Agency

Yes

MPPA supports the changes made in Inclusion 2 and believe that the definition in its
current form adds clarity. In particular, we support the SDT’s decision to collapse
Inclusions 2 and 3 from the previous draft definition into a single Inclusion that
addresses the treatment of generation for purposes of the BES definition. MPPA also
supports the SDT’s proposal for a Phase 2 of the BES Definition process that would
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Question 3 Comment
examine the technical justification for these thresholds and that would establish new
thresholds based on a careful technical analysis. It is our understanding that the
generator threshold issue will be vetted through the complete standards
development process. We agree with this approach because if the generator
threshold is treated as merely an element of NERC’s Rules of Procedure, it can be
changed with considerably less due process and industry input than the Standards
Development Process. Compare NERC Rules of Procedure § 1400 (providing for
changes to Rules of Procedure upon approval of the NERC board and FERC) with
NERC Standards Process Manual (Sept. 3, 2010) (providing for, e.g., posting of SDT
proposals for comment, successive balloting, and super-majority approval
requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011) (“Order
No. 743 directed the ERO to revise the definition of ‘bulk electric system’ through the
NERC Standards Development Process” (emph. added)). Addressing all aspects of
Phase 2 through the Standards Development Process will improve the content of the
definition by bringing to bear industry expertise on all aspects of the definition and
will ensure that, once firm guidelines are established, they can be relied upon by both
industry and regulators without threat that they will be changed with little notice and
little due process. MPPA also believes further clarification of the proposed language
would be appropriate.
The SDT proposes continued reliance upon the thresholds that are used in the NERC
Statement of Compliance Registry Criteria for registration of Generation Owners and
Generation Operators, which is currently 20 MVA for an individual generation unit
and 75 MVA for multiple units on a single site. Conceptually, we are concerned about
this approach because, as we understand it, the purpose of the Compliance Registry
is to sweep in all generators that might be material to the reliable operation of the
BES, and not to definitively determine whether a given generator is, in fact, material
to the reliable operation of the BES. As the SCRC itself states, the SCRC is intended
only to identify “candidates for registration.” SCRC at p.3, § 1 (emph. added).
Accordingly, we believe that the generator threshold determined in Phase 2 should
be incorporated directly into the BES Definition rather than being incorporated by
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Yes or No

Question 3 Comment
reference from the SCRC. We also believe that the specific language proposed by the
SDT could be further clarified. The SDT proposes to include generation in the BES if
the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder
for the results of the technical analysis that would occur in Phase 2 but we believe
simply stating that the threshold will be “per the ERO Statement of Compliance
Registry” is ambiguous. Further, for the reasons noted above, we believe the
threshold should be part of the BES Definition, and should not simply be a crossreference to the SCRC (and, given the different purposes of the BES Definition and
the SCRC, it is not clear that the same threshold should be used in both). We
therefore propose that Inclusion 2 be rewritten to state: “Qualifying Individual
Generation Resources or Qualifying Aggregate Resources connected at a voltage of
100 kV or above.”
Two definitions would then be added to the note at the end of the definition to read
as follows: For purposes of this BES Definition, Qualifying Individual Generation
Resources means an individual generating unit that meets the materiality threshold
to be included in this definition or, in the absence of such a materiality threshold,
that meets the gross nameplate capacity voltage threshold requiring registration of
the owner of such a resource as a Generation Owner under the ERO Statement of
Compliance Registry Criteria. For purposes of this BES Definition, Qualifying
Aggregate Generation Resources means any facility consisting of one or more
generating units that are connected at a common bus that meets the materiality
threshold to be included in this definition, or, in the absence of such a threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the
owner of multiple-unit generator as a Generation Owner under the ERO Statement of
Compliance Registry Criteria..The “materiality threshold” is intended to refer to the
generator threshold developed in Phase 2. We suggest using definitions in this
fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as
part of the BES if they are necessary for operation of the BES, but to exclude smaller
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Yes or No

Question 3 Comment
generating units because they are not material to the operation of the
interconnected transmission grid. Second, we believe use of the defined terms
better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase 2 without
having to revise the BES Definition at the end of that process. That is, the definitions
are designed to allow the SDT to include revised thresholds in the definition at the
conclusion of the Phase 2 process based upon the technical analysis planned for
Phase 2, and the revised thresholds will be automatically incorporated into the BES
Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase 2 is completed. Third, the definitions
can be incorporated into other parts of the BES Definition, which will add consistency
and clarity. As noted in our answers to several of the questions below, the specific 75
MVA threshold is retained in several of the Exclusions and Inclusions, and we believe
the industry would be better served if the revised thresholds arrived at after
technical analysis in Phase 2 are automatically incorporated into all relevant
provisions of the BES Definition. There is no reason for the SDT to continue to rely on
the 75 MVA threshold once the analysis planned for Phase 2 on the threshold issue is
completed. Fourth, the phrase “or that meets the materiality threshold to be
included in this definition” is intended to preserve the SDT’s flexibility to make a
determination that generators below a specific threshold are not “necessary to”
maintain the reliability of the interconnected transmission system, and to incorporate
that finding as part of the definition itself, even if a different threshold is used in the
SCRC to identify potential candidates for registration. Accordingly, our proposed
language makes clear that a specific threshold in the definition controls over any
threshold that might be included in the SCRC. For the reasons stated above, we
believe is it highly desirable to include any material threshold in the BES Definition
itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard.
Finally, we agree with the SDT’s decision to examine the question of where the line
between BES and non-BES Elements should be drawn more closely in Phase 2 under
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Yes or No

Question 3 Comment
the rubric of “contiguous vs. non-contiguous BES,” and commend the work of the
Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting
point for the SDT’s analysis on this issue. We understand Inclusion 2 would classify
generators exceeding specific thresholds as part of the BES, but would not necessarily
require facilities interconnecting such generators to be part of the BES. As discussed
more fully in our answer to Question 9, based on extensive technical analysis that has
already been performed by the NERC Project 2010-07 Standards Drafting Team and
its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a dedicated
interconnection facility connecting a BES generator to the interconnected bulk
transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no
improvement in bulk system reliability. We also believe the clauses at the end of
Inclusion 2 are somewhat confusing and that greater clarity would be achieved by
changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above” so that the Inclusion
covers transformers with terminals “connected at a voltage of 100 kV or above,
including the generator terminal(s) on the high side of the step-up transformer(s) if
operated at a voltage of 100 kV or above.”
MPPA and its members believe it is essential that regional entities and NERC
recognize that “facilities used in the local distribution of electric energy” are not
included in the definition of BES, regardless of the gross individual or gross aggregate
nameplate rating of generation resources. While the addition of the second sentence
in the core definition makes this clarification, MPPA and its members believes it is
necessary that regional entities and NERC recognize that neither this Inclusion nor
any of the Inclusions may be used as a basis to compel registration and compliance in
such instances, regardless of the size of the generators. The statutory exemption of
facilities used in the local distribution of electric energy is not limited by generator
number or capacity. NERC’s definitions cannot impose limitations that are not set
forth in the statute. For purposes of the exclusion of facilities that might otherwise
meet the definition of BES, the thresholds for determining what generating resources
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Question 3 Comment
constitute BES facilities should be modified from the current levels (gross individual
nameplate capacity of 20 MVA or gross aggregate nameplate rating of 75 MVA).
MPPA and its members would support modification of the thresholds to not less than
100 MVA (gross individual capacity) and 300 MVA (gross aggregate nameplate).

Response: The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values.
The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2, instead
specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and thus
affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Texas Industrial Energy
Consumers

Yes

The interplay between Inclusion I2, which references the Statement of Registry
Compliance, and Exclusions E1-E3 is unclear. Under the Registry criteria, “a
customer-owned or operated generator/generation that serves all or part of retail
load with electric energy on the customer’s side of the retail meter may be excluded
as a candidate for registration ... if (i) the net capacity provided to the bulk power
system does not exceed the criteria above.” It appears that the SDT intended to
invoke this provision by referencing the Statement of Registry Compliance, which
counts only the “net” capacity provided, by referencing the Statement of Compliance
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Question 3 Comment
Registry Criteria. However, Exclusions E1 and E3 exclude generation on the basis of
“gross nameplate ratings.” For customer-owned facilities, this treatment is
inconsistent with netting treatment provided in the Statement of Registry
Compliance. Exclusions E1-E3 should be revised to reference the Statement of
Compliance Registry Criteria as well so that customer-owned generation is included
or excluded based on its net capacity to the grid rather than its gross nameplate
capacity.
TIEC also supports revisiting and potentially raising the thresholds that trigger
registration as a Generation Owner or Operator. TIEC understands that the SDT has
decided to maintain the status quo as reflected in NERC’s Registry Criteria at this
time. TIEC looks forward to addressing potential modifications to the thresholds in
the appropriate context.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer,
circuit breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application
of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific
criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
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Question 3 Comment

Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The
exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied
in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude an
Element.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects
(i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being
responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012,
and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a
change from the current values that exist through the application of the definition today. These and similar issues have prompted the
SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory
authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for
inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC
Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide compelling
justification for modifications to the existing values.
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,

Yes

The word “identified” should be replaced with “designated”.

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Question 3 Comment

MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power
Cooperative
Response: The SDT believes this comment was intended for Q4 and directs you to the detailed response provided there.
Dominion

Yes

Dominion interprets the revised language to exclude generating resources connected
at less than 100 kV. If this interpretation is not accurate, then Dominion does not
support the revised language.

Response: The I2 inclusion refers only to generation “ … through the high-side of the step-up transformer(s) connected at a voltage
of 100 kV or above.”
Transmission Access Policy
Study Group

Yes

TAPS supports the intent of proposed Inclusion I2. For the sake of clarity, we suggest
revising “per the ERO Statement of Compliance Registry Criteria” to “as described in
the ERO Statement of Compliance Registry Criteria.”

ACES Power Marketing
Standards Collaborators

Yes

We’d prefer to see the language from the ERO Statement of Compliance Registry
Criteria repeated within the BES Definition itself instead of referencing an outside
document. As it stands right now, the Compliance Registry Criteria needs to stay
intact for Phase 1 of this project. That makes the Compliance Registry Criteria reliant
on the BES Definition and vice versa. We understand that the Statement of
Compliance Registry Criteria may be reviewed/revised at the same time Phase 2 of
this project is being developed, therefore we agree with Inclusion I2 of this draft.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2,
instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed
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Question 3 Comment

and thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Florida Municipal Power
Agency

Yes

Please see comments to Question 1

Response: Please see response to Q1.
Redding Electric Utility

Yes

Redding believes that the definition should drive what appears in the Registry
Criteria, therefore we only support this on a temporary basis based on the premise
that the BES Phase 2 technical analysis will identify and provide technical support for
determining the appropriate minimum MVA rating for a single unit or the aggregation
of multiple units.

City of Redding

Yes

Redding believes that the definition should drive what appears in the Registry
Criteria, therefore we only support this on a temporary basis based on the premise
that the BES Phase 2 technical analysis will identify and provide technical support for
determining the appropriate minimum MVA rating for a single unit or the aggregation
of multiple units.

MEAG Power

Yes

We agree in general with the revisions to I2 for generation; however, we maintain
that 200kV and above is the correct bright line for the Bulk Electric System.

Tennessee Valley Authority

Yes

TVA agrees in general with the revisions to I2 for generation; however, we maintain
that 200kV and above is the correct bright line for generation connected to the Bulk
Electric System, and requests that the Phase 2 for the project use 200kV and above or
develop a transmission voltage and/or an MVA threshold that is technically based.

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Question 3 Comment

SERC Planning Standards
Subcommittee

Yes

We are concerned that the generator MVA limits are too low and strongly support
addressing this issue in Phase 2 of this project.

NERC Staff Technical Review

Yes

The drafting team’s proposed approach for Inclusion I2 (generation), including the
reference to the ERO Statement of Compliance Registry Criteria, is generally
acceptable given the scope of this project and the breaking of the project into two
phases. Thresholds for generator MVA rating and interconnection voltage should be
considered in the second phase of this project.

SERC OC Standards Review
Group

Yes

We agree in general with the revisions to I2 for generation; however, we maintain
that 200kV and above is the correct bright line for the Bulk Electric System.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values. No change made.
ATC LLC

Yes

Westar Energy

Yes

Portland General Electric
Company

Yes

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Yes or No

Georgia System Operations
Corporation

Yes

Oncor Electric Delivery
Company LLC

Yes

National Grid

Yes

Cowlitz County PUD

Yes

Utility Services, Inc.

Yes

PSEG Services Corp

Yes

ISO New England Inc

Yes

Manitoba Hydro

Yes

Long Island Power Authority

Yes

Z Global Engineering and
Energy Solutions

Yes

Consumers Energy

Yes

Metropolitan Water District of
Southern California

Yes

Duke Energy

Yes

Question 3 Comment

Cowlitz also strongly supports Phase 2 to address the lack of technical justification of
the MVA bright line criteria.

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Yes or No

Central Hudson Gas and
Electric Corporation

Yes

City of Anaheim

Yes

ReliabilityFirst

Yes

Southern Company

Yes

FirstEnergy Corp.

Yes

Exelon

Yes

Western Area Power
Administration

Yes

IRC Standards Review
Committee

Yes

WECC Staff

Yes

Bonneville Power
Administration

Yes

Southwest Power Pool
Standards Review Team

Yes

BGE

Yes

Question 3 Comment

BPA agrees with the I2 changes and feels that they are excellent.

No comment.

Response: Thank you for your support. However, the SDT made a clarifying change removing the ERO Statement of Compliance
Registry Criteria reference in Inclusion I2, instead specifying the 20/75 MVA reference threshold values in order to avoid the
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Question 3 Comment

possibility of the registry values being changed and thus affecting the BES Definition prior to the resolution of the threshold values in
Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.

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4.

The SDT has revised the specific inclusions to the core definition in response to industry comments. Do you agree with Inclusion
I3 (blackstart)? If you do not support this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.

Summary Consideration: The directive by FERC to revise the definition of the BES has been interpreted by the SDT to include all
Facilities necessary for reliably operating the interconnected transmission system under both normal and emergency conditions. This
interpretation by the SDT includes situations related to Blackstart Resources and system restoration. Blackstart Resources have the
ability to be started without the support of the interconnected transmission system in order to meet a Transmission Operators
restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The SDT maintains that Blackstart
Resources must be included in the definition however their associated Cranking Paths are not included in the BES definition as they can
fall within distribution class levels. Cranking Paths will be discussed further in Phase 2 of this project.
No changes were made to Inclusion I3 from the previous posting.
Organization

Yes or No

Question 4 Comment

SERC OC Standards Review
Group

No

We agree with the changes but believe clarity would be added by changing the word
“identified” to “designated”.

Tennessee Valley Authority

No

TVA agrees with the changes but believe clarity would be added by changing the word
“identified” to “designated”.

Southern Company

No

We agree with the changes but believe clarity would be added by changing the word
“identified” to “designated”.

MEAG Power

No

We agree with the changes but believe clarity would be added by changing the word
“identified” to “designated”.

Response: ‘Identified’ is consistent with the wording in EOP-005-2. The SDT does not feel that this change would add any
additional clarity. No change made.

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Question 4 Comment

Texas Reliability Entity

No

We feel that the Cranking Path should be included in the BES definition. Inclusion of
the Cranking Path is vital to a functional, sustainable and reliable system restoration
(and restoration plan) regardless of where the Cranking Path is located. CIP-002-4
Attachment 1 recognizes the critical nature of the Cranking Path.

NERC Staff Technical Review

No

The cranking path(s) identified in the Transmission Operator’s restoration plan should
be included in the BES definition.

Response: Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system
Elements. The Transmission Operator’s restoration plans identify a number of possible system restoration scenarios to address the
uncertainty of the actual requirements needed to address a particular restoration event including Cranking Paths. Therefore, the SDT
maintains that Cranking Paths are not required to be included in the BES definition as they are essentially a moving target and could
include distribution Elements. The Cranking Paths issue will be discussed anew in Phase 2 of this project. No change made.
NESCOE

No

While NESCOE appreciates that cranking paths were excluded in response to industry
comments, as we stated in comments to the prior posting of the BES definition,
blackstart units should be excluded from the BES. Such units are appropriately
covered under regional restoration procedures and applicable NERC standards (see for
example, Emergency Operating Procedure EOP-005-2). However, should blackstart
units be included in subsequent postings of the definition, we suggest that the
language be revised to state that only those units “material to” the BES are included.

Ontario Power Generation Inc.

No

To assure availability of the generation blackstart resources identified in the
Transmission Operator’s Power System Restoration Plan the generators are tested
according to the requirements of reliability standard EOP-009. Blackstart resources are
only required post LOBES (Loss of Bulk Electric System) and in many cases do not
contribute to the reliability of the BES under normal operating conditions. OPG
recommends that this inclusion be removed from the new definition of BES.

IRC Standards Review

No

We support the SDT’s decision to exclude the cranking paths from the BES definition
since testing and verification of the use of facilities in the cranking path is already
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Committee

Question 4 Comment
covered by the appropriate EOP standards.
This inclusion is extraneous given there is already a designation specific for system
restoration covered by an existing standard to recognize their reliability impacts and
to ensure their expected performance. NERC Standards EOP-005-2 stipulates the
requirements for testing blackstart resource and cranking paths. This testing
requirement suffices to ensure that the facilities critical to system restoration are
functional when needed, which meets the intent of identifying their criticality to
reliability. We therefore suggest removing Inclusion I3.

Hydro One Networks Inc.

No

We agree with the SDT in excluding the cranking paths from the BES definition, a point
we had raised in our comments to the previous posting.
We also disagree with the inclusion of blackstart resources and reiterate our view that
their inclusion is superfluous given there is already a designation specific for system
restoration covered by an existing standard, to recognize their reliability impacts and
to ensure their expected performance. NERC Standard EOP-005-2 stipulates the
requirements for testing blackstart resources and cranking paths. This testing
requirement suffices to ensure that the facilities critical to system restoration are
functional when needed, which meets the intent of identifying their criticality to
reliability. We therefore suggest completely removing Inclusion I3.We suggest the SDT
to drop I3 on the basis that: o The availability and performance expectations of
blackstart resources are ensured by existing related standards; and o Unless they
meet the BES definition under inclusion I2, there is no perceived reliability value in
everyday operation of the BES.

Northeast Power Coordinating
Council

No

Eliminating I3 should be considered based on the availability and performance
expectations of black start resources being ensured by existing standards, and unless
they meet the BES definition under the I2 inclusion they do not have any reliability
impact on BES operation. If I3 is retained, suggest rewording Inclusion I3 to read as
follows: Black start resources material to and designated as part of the Transmission

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Yes or No

Question 4 Comment
Operator’s restoration plan.

Independent Electricity
System Operator

No

We thank the SDT for excluding the cranking paths from the BES definition, a point we
had raised in our comments to the previous posting. However, we had also disagreed
with the inclusion of Blackstart Resources and reiterate our view that their inclusion is
superfluous given there is already a designation specific for system restoration
covered by an existing standard, to recognize their reliability impacts and to ensure
their expected performance. NERC Standards EOP-005-2 stipulates the requirements
for testing blackstart resource and cranking paths. This testing requirement suffices to
ensure that the facilities critical to system restoration are functional when needed,
which meets the intent of identifying their criticality to reliability. We therefore
suggest removing Inclusion I3 entirely.

FirstEnergy Corp.

Yes

We agree with the team's conclusion to remove cranking paths from the BES
definition since NERC (i.e. EOP standards) specifically address reliability matters
associated with cranking paths. Although we believe item I3 (blackstart unit) is
unnecessary as part of the BES Definition, we will not object to its inclusion. A
blackstart unit is a facility necessary for BES restoration, but not necessarily required
to be included within the BES Definition.

Response: The SDT disagrees that Blackstart Resources should not be included in the BES Definition. The Commission directed
NERC to revise its BES definition to ensure that the definition encompasses all facilities necessary for operating an
interconnected electric transmission network. The SDT interprets this to include operation under both normal and emergency
conditions, which includes situations related to black starts and system restoration. Blackstart Resources have the ability to be
started without support from the System or can be energized without connection to the remainder of the System, in order to
meet a Transmission Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage
control. The associated resources of the electric system that can be isolated and then energized to deliver electric power
during a restoration event are essential to enable the startup of one or more other generating units as defined in the
Transmission Operator’s restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in
the Transmission Operator’s restoration plan as BES elements. No change made.
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Organization
ACES Power Marketing
Standards Collaborators

Yes or No

Question 4 Comment

No

Blackstart Resources can actually be on the distribution system. There is still the
question of whether the distribution system would then be subjected to the
enforceable standards. If so, there would most likely be a significant cost increase
associated with tracking compliance for these distribution systems without a
commensurate increase in reliability since Blackstart Resources are rarely used. This
could very well cause entities to un-designate Blackstart Resources on distribution
systems to avoid these distribution systems from becoming part of the BES. The same
rationale that was used for eliminating cranking paths could also be applied to
Blackstart Resources.

Response: Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system
Elements. The Transmission Operator’s restoration plans identify a number of possible system restoration scenarios to address
the uncertainty of the actual requirements needed to address a particular restoration event including Cranking Paths.
Therefore, the SDT maintains that Cranking Paths are not required to be included in the BES definition as they are essentially a
moving target and could include distribution Elements. The Cranking Paths issue will be discussed anew in Phase 2 of this
project. The SDT feels that the situation described would fall within a minimal percentage of units and therefore would be
subject to the Exception Process as applicable. No change made.
ReliabilityFirst

No

Blackstart Resource is a defined NERC term, but as outlined in the definition, it could
be read to include the transmission assets that also make up the resource as part of
the TOP plan. Is that the intent?
ReliabilityFirst Staff also feels that without including the Cranking Paths, the reliable
operation of the system could be jeopardized if a restoration is required and the
Cranking Paths are unavailable due to non-compliance to Reliability Standards.

Response: The SDT does not agree that the definition of Blackstart Resource necessarily encompasses transmission assets. No
change made.
Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system Elements.
The Transmission Operator’s restoration plans identify a number of possible system restoration scenarios to address the
uncertainty of the actual requirements needed to address a particular restoration event including Cranking Paths. Therefore,
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Question 4 Comment

the SDT maintains that Cranking Paths are not required to be included in the BES definition as they are essentially a moving
target and could include distribution Elements. The Cranking Paths issue will be discussed anew in Phase 2 of this project. No
change made.
Central Maine Power
Company

No

Inclusion I3 should be changed to include the phrase, “material to,” currently in the
Statement of Compliance Registry Criteria (Section 3C3). Based on the definition
wording, the Generator Step-Up transformer (GSU) would not be BES if the generator
would not otherwise already be included as BES under another definition provision.

Rochester Gas and Electric
and New York State Electric
and Gas

No

Inclusion I3 should be changed to include the phrase, “material to,” currently in the
Statement of Compliance Registry Criteria (Section 3C3). Based on the definition
wording, the Generator Step-Up transformer (GSU) would not be BES if the generator
would not otherwise already be included as BES under another definition provision.

Orange and Rockland Utilities,
Inc.

Minimum Power system and material? NERC registry criteria for generation section
"3C3"

Massachusetts Department of
Public Utilities

No

The inclusion should be revised to specify that only those blackstart units that are
“material to” the BES are included in the definition.

Consolidated Edison Co. of NY,
Inc.

No

We suggest using wording from the Statement of Compliance Registry Criteria:Any
generator regardless of size which is material to ... [Ref: Statement of Compliance
Registry Criteria, III.c.3-Blackstart]Define “material to” as a generator listed as a
necessary part of the TOP-defined minimum system to restore the BES. This term
“material to” should exclude Blackstart-capable generators not necessary for BES
restoration or only used for local distribution system restoration. Wording
Recommendation: Following the words “identified in” add the words “and material
to” so that the new Inclusion reads:I3 - Blackstart Resources identified in and material
to the Transmission Operator’s restoration plan.

Response: The SDT believes that adding language such as “material to” does not provide clarity and remains immeasurable. No
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Question 4 Comment

change made.
Manitoba Hydro

No

Inclusion I3 should specifically state that only the Blackstart Resources specified
through EOP-005-2 R1.4 are included in the BES since “Transmission Operator
restoration plan’ is not a NERC defined term. Suggested wording:”I3 - Blackstart
Resources identified through EOP-005-2 R1.4”

Response: The SDT appreciates your concern but does not believe it is appropriate to reference a standard in the definition.
Any modification to the standard including an interpretation or a simple re-versioning for errata would change the standard
number and thus require that the definition be updated. No change made.
ISO New England Inc

No

The SDT has interpreted the FERC Directive to revise the BES definition in a manner
that goes beyond the mandate of ensuring that the definition encompasses all
facilities necessary for operating an interconnected electric transmission network. The
SDT states that operation is interpreted as being under both normal and emergency
conditions. However, loss of all electric power is the end state condition when all
normal and emergency remediating actions have failed to prevent a collapse of the
grid. System restoration involves the use of blackstart generators that are not
resources necessary for operating the electrical grid but rather a means to recover
following (not part of the emergency itself) an extreme emergency. The SDT should
simply refer to the current Compliance Registry, which, for now, appears to
adequately deal with the issue of how to treat Blackstart resources. I3 states
“Blackstart Resources identified in the Transmission Operator’s restoration plan”. This
is contrary to the preferred language that is part of the approved ERO Statement of
Compliance Registry, III.C.3 that states, “Any generator, regardless of size, that is a
blackstart unit material to (emphasis added) and designated as part of a transmission
operator entity’s restoration plan”. This language is necessary to distinguish between
those Blackstart Resources that are depended upon to restore the BES following an
emergency (“Key Facilities”) as compared to those Blackstart Resources that are used
to restore power to customer load.

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Question 4 Comment
Additionally, discussions with others during the preparation of comments have
revealed that some interpret this requirement to include the GSU. We do not
interpret this in this manner, but this should be clarified to avoid confusion.

Response: The SDT disagrees that Blackstart Resources should not be included in the BES Definition. The Commission directed
NERC to revise its BES definition to ensure that the definition encompasses all facilities necessary for operating an
interconnected electric transmission network. The SDT interprets this to include operation under both normal and emergency
conditions, which includes situations related to black starts and system restoration. Blackstart Resources have the ability to be
started without support from the System or can be energized without connection to the remainder of the System, in order to
meet a Transmission Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage
control. The associated resources of the electric system that can be isolated and then energized to deliver electric power
during a restoration event are essential to enable the startup of one or more other generating units as defined in the
Transmission Operator’s restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in
the Transmission Operator’s restoration plan as BES elements. No change made.
The SDT does not agree that the definition of Blackstart Resource necessarily encompasses transmission assets such as GSUs.
SRP

No

The Blackstart ‘Cranking Path’ has been deleted from Inclusion 3 of the BES definition.
However, NERC Standards EOP-005 and CIP-002, R1.2.4, require documenting the
Cranking Path. In addition, CIP-002—4 identifies the Cranking Path as a Critical Asset
in Attachment 1. Compliance to the NERC Standards needs to be an exact science
whenever possible. SRP does not argue the inclusion or exclusion of Cranking Path.
However, if it is excluded, guidance must be provided on whether or not a Cranking
Path is subject to the previously mentioned Standards.

Response: Cranking Paths are subject to any standard in which they are specifically spelled out.
Tacoma Power

Yes

Tacoma Power generally support Inclusion I3 as written. We continue to believe the
BES should only include the Blackstart Resources that support a regional recovery. We
propose changing Inclusion I3 to read,”Blackstart Resources identified in the
Transmission Operator’s restoration plan and included in a regional restoration plan.”
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Yes or No

Question 4 Comment

Response: The SDT does not agree that the definition should specify Blackstart Resources included in regional restoration plans as
those regional systems may not be included in the BES nor have any impact on the BES. No change made.
Ameren

Yes

a)The definition should include only those black start generators connected 100 kV
and above and included in the restoration plan.
b)We agree with the changes but believe clarity would be added by changing the word
“identified” to “designated”.

Response: Blackstart Resources are required to be registered regardless of connected voltage level. The SDT is remaining consistent
with its earlier position on that point. No change made.
‘Identified’ is consistent with the wording in EOP-005-2. The SDT does not feel that this change would add any additional clarity at
this time. No change made.
Utility Services, Inc.

Yes

Utility Services supports suggestions by others that request that the language of the
Inclusion use the exact language of the SCRC III.3.c. Leaving the language as is will
likely increase the number of black start facilities beyond those currently applicable.

Response: Adding language such as “material to” found in the ERO Statement of Compliance Registry Criteria does not provide
clarity and remains immeasurable. No change made.
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power

Yes

In general, we agree with this revision. However, the aggregate MVA threshold should
be 150 MVA or greater, and threshold voltage level should be 200kV or higher.

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Yes or No

Question 4 Comment

Cooperative
Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values. No change made.
City of Redding

Yes

Redding recommends the following rewording: “The Primary Blackstart resources
designated in the Transmission Operator’s restoration plan.” We believe it reduces
reliability if all Blackstart generation either primary or secondary are required to be
BES. Requiring all Blackstart capable units to be BES creates an incentive to leave
certain blacstart units out of restoration plans in order to avoid BES inclusion. By
making only the primary Blackstart unit a BES element then Transmission Operators
will be more willing to include ALL Blackstart units in their plan thus creating a
complete procedure for the Transmission Operator to restore the system.

Redding Electric Utility

Yes

Redding recommends the following rewording: “The Primary Blackstart resources
designated in the Transmission Operator’s restoration plan.” We believe it reduces
reliability if all Blackstart generation either primary or secondary are required to be
BES. Requiring all Blackstart capable units to be BES creates an incentive to leave
certain blacstart units out of restoration plans in order to avoid BES inclusion. By
making only the primary Blackstart unit a BES element then Transmission Operators
will be more willing to include ALL Blackstart units in their plan thus creating a
complete procedure for the Transmission Operator to restore the system.
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Yes or No

Question 4 Comment

City of Austin dba Austin
Energy

Yes

We recommend rewording Inclusion I3 as follows: “Only Primary Blackstart resources
designated as part of the Transmission Operator’s restoration plan.” We have
concerns that making all Blackstart generation either primary or secondary BES
elements creates an incentive to remove those secondary Blackstart capable units in
an effort to avoid BES inclusion. We believe that making the primary Blackstart unit
the only BES element will remove this incentive. In so doing, this will allow the
secondary Blackstart units to remain in the Transmission Operator’s plan and training
program as an alternate tool for the Transmission Operator to restore the system.

Sacramento Municipal Utility
District

Yes

We recommend rewording Inclusion I3 as follows: “Only Primary Blackstart resources
designated as part of the Transmission Operator’s restoration plan.” We have
concerns that making all Blackstart generation either primary or secondary BES
elements will create an incentive to remove those secondary Blackstart capable units
in order to avoid BES inclusion. Making the primary Blackstart unit the only BES
element will remove this incentive. In so doing, this will allow the secondary
Blackstart units to remain in the Transmission Operator’s plan and training program as
an alternate tool for the Transmission Operator to restore the system.

Balancing Authority Northern
California

Yes

We recommend rewording Inclusion I3 as follows: “Only Primary Blackstart resources
designated as part of the Transmission Operator’s restoration plan.” We have
concerns that making all Blackstart generation either primary or secondary BES
elements will create an incentive to remove those secondary Blackstart capable units
in order to avoid BES inclusion. Making the primary Blackstart unit the only BES
element will remove this incentive. In so doing, this will allow the secondary
Blackstart units to remain in the Transmission Operator’s plan and training program as
an alternate tool for the Transmission Operator to restore the system.

Response: The SDT discussed the recommended wording and determined that it did not provide further clarity to the definition.
Utilizing “primary” and “secondary” as a deterministic method for inclusion would create regional inconsistencies with application of
the definition which is contrary to the intent to create a consistent continent-wide definition. No change made.
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WECC Staff

Yes or No

Question 4 Comment

Yes

WECC agrees with the inclusion of the blackstart units, but does not agree with the
deletion of the cranking path from the I3. The cranking path should be included in the
definition since the NERC standards EOP-005 and CIP-002 R1.2.4 require documenting
the cranking path. The revised CIP-002-4 Standard identifies the cranking path as a
critical asset in Attachment 1 (1.5).

Response: Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system
Elements. The Transmission Operator’s restoration plans identify a number of possible system restoration scenarios to address
the uncertainty of the actual requirements needed to address a particular restoration event including Cranking Paths.
Therefore, the SDT maintains that Cranking Paths are not required to be included in the BES definition as they are essentially a
moving target and could include distribution Elements. The Cranking Paths issue will be discussed anew in Phase 2 of this
project. No change made.
Florida Municipal Power
Agency

Yes

Please see comments to Question 1

Response: Please see response to Q1.
ExxonMobil Research and
Engineering

Yes

ATC LLC

Yes

Westar Energy

Yes

Northern Wasco County PUD

Yes

Farmington Electric Utility
System

Yes

We agree with the removal of the voltage language, since the inclusions and
exclusions apply only to equipment over 100 kV.

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Yes or No

Question 4 Comment

South Houston Green Power,
LLC

Yes

Portland General Electric
Company

Yes

Georgia System Operations
Corporation

Yes

Nebraska Public Power District

Yes

LCRA Transmission Services
Corporation

Yes

National Grid

Yes

Kansas City Power and Light
Company

Yes

Oncor Electric Delivery
Company LLC

Yes

Umatilla Electric Cooperative
(UEC)

Yes

UEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Central Lincoln

Yes

We agree with the removal of the voltage language, since the inclusions and
exclusions apply only to equipment over 100 kV.

Harney Electric Cooperative,

Yes

HEC agrees with the inclusions to the core definition.
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Yes or No

Question 4 Comment

Inc.
Cowlitz County PUD

Yes

PSEG Services Corp

Yes

Hydro-Quebec TransEnergie

Yes

Pacific Northwest Generating
Cooperative (PNGC)

Yes

PNGC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Raft River Rural Electric
Cooperative (RAFT)

Yes

RAFT supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

West Oregon Electric
Cooperative

Yes

WOEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Lincoln Electric Cooperative
(LEC)

Yes

LEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Northern Lights Inc. (NLI)

Yes

NLI supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
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Yes or No

Question 4 Comment
simply a specific type of such an interconnection facility.

Okanogan County Electric
Cooperative (OCEC)

Yes

OCEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Douglas Electric Cooperative
(DEC)

Yes

DEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Fall River Rural Electric
Cooperative (FALL)

Yes

FALL supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Lane Electric Cooperative
(LEC)

Yes

LEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Clearwater Power Company
(CPC)

Yes

CPC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Snohomish County PUD

Yes

SNPD supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.
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Yes or No

Question 4 Comment

Consumer's Power Inc.

Yes

CPI supports the removal of the Cranking Path language in I3. As noted in our response
to Question 9, there is no reason to classify as BES the facilities interconnecting a BES
generator to the bulk interstate system. A Cranking Path is simply a specific type of
such an interconnection facility.

Central Electric Cooperatve
(CEC)

Yes

CEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Coos-Curry Electric
Cooperative (CCEC)

Yes

CCEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Blachly-Lane Electric
Cooperative (BLEC)

Yes

BLEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Long Island Power Authority

Yes

The Dow Chemical Company

Yes

City of St. George

Yes

American Electric Power

Yes

Tillamook PUD

Yes

Tillamook PUD agrees with the removal of the voltage language since the inclusions
and exclusions only apply to equipment over 100 kV.

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Yes or No

NV Energy

Yes

Z Global Engineering and
Energy Solutions

Yes

Consumers Energy

Yes

Mission Valley Power

Yes

Puget Sound Energy

Yes

Central Hudson Gas and
Electric Corporation

Yes

City of Anaheim

Yes

Chevron U.S.A. Inc.

Yes

Metropolitan Water District of
Southern California

Yes

Duke Energy

Yes

Clallam County PUD No.1

Yes

Exelon

Yes

Question 4 Comment

Mission Valley Power - We agree with the removal of the voltage language, since the
inclusions and exclusions apply only to equipment over 100 kV.

CLPD supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

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Yes or No

Michigan Public Power Agency

Yes

Idaho Falls Power

Yes

Tri-State GandT

Yes

Western Area Power
Administration

Yes

Texas Industrial Energy
Consumers

Yes

PacifiCorp

Yes

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

Yes

MRO NERC Standards Review
Forum (NSRF)

Yes

Electricity Consumers
Resource Council (ELCON)

Yes

Southern Company
Generation

Yes

Pepco Holdings Inc and
Affiliates

Yes

Question 4 Comment

We support the inclusion as drafted.

PacifiCorp supports the removal of reference to Cranking Paths in I3. There is no
reason to classify as BES the facilities interconnecting a BES generator to the
interconnected transmission system.

Agree with the SDT decision to delete the inclusion of Black Start Cranking Paths.

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Yes or No

Dominion

Yes

Bonneville Power
Administration

Yes

Texas RE NERC Standards
Subcommittee

Yes

SERC Planning Standards
Subcommittee

Yes

Southwest Power Pool
Standards Review Team

Yes

BGE

Yes

Question 4 Comment

No comment.

Response: Thank you for your support.

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5.

The SDT has revised the specific inclusions to the core definition in response to industry comments. Do you agree with Inclusion
I4 (dispersed power)? If you do not support this change or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments.
Summary Consideration: Several comments sought clarification that Inclusion I4 was directed at including resources
such as wind and solar farms and sought a distinction between Inclusions I2 and I4. The SDT believes this is presently
clear in the definition. Inclusion I4 specifically addresses wind and solar farms being dispersed power producing
resources that “utilize[e] a system designed primarily for aggregating capacity.” The essential distinction between
Inclusion I2 and I4 is that Inclusion I2 may not include generating resources that use lower voltage collection systems
while Inclusion I4 is specifically designed to accomplish this purpose.
The SDT also clarifies that Inclusion I4 speaks towards the inclusion of the generation resources themselves, not the
transmission Element(s) of the collector systems operated below 100 kV or not included under Inclusion I2.
There were a number of comments seeking clarification on the location of the common point of connection. While the
SDT does not believe additional clarification of the term “common point” is needed in the BES definition, the following
guidance is provided. The common point of connection, which is the point from where generation is aggregated to
determine if the 75 MVA threshold is met, is the point where the individual transmission Element(s) of a collector system
ultimately meet the 100 kV transmission system.
Some stakeholders asked for clarity on the issue of units on the customer’s side of the retail meter. Generating units on
the customer’s side of the retail meter are not included under Inclusion I4 since customer-side retail generation typically
does not “utilize[e] a system designed primarily for aggregating capacity, connected at a common point at a voltage of
100 kV or above.”
Several comments sough clarification of the definitional difference between “dispersed power” and “distributed
generation” as used in the BES definition. While the SDT does not believe that further clarity of these terms is needed in
the BES definition, it clarifies that distributed generation is generally defined as: a generator that is located close to the
particular Load that it is intended to serve and is interconnected to the utility distribution system. The U.S Energy
Information Administration (EIA) and FERC generally use this as a basic definition. The language of Inclusion I4 stating
“Dispersed power producing resources . . . utilizing a system designed primarily for aggregating capacity, connected at a
common point at a voltage of 100 kV or above” was selected so as not to confuse what is traditionally considered
distributed generation with the types of systems to be included in Inclusion I4.

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The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has
responsibilities associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in
regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the
development of strong technical justifications that would warrant a change from the current values that exist through the
application of the definition today. These and similar issues have prompted the SDT to separate the project into phases
which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT
will consider all recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2 of
Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical
Standing Committees, to develop analyses which will properly assess the threshold values and provide compelling
justification for modifications to the existing values.
No changes were made to Inclusion I4 based on comments provided in response to this question.
Organization
Northeast Power
Coordinating Council

Yes or No

Question 5 Comment

No

Suggest the term “common point” needs clarification and/or definition
(is risk of single mode failure intended, i.e. where all the resources could
be lost for a single event?). Suggest the following wording: “connected
at a common point through a dedicated step-up transformer with a highside voltage of 100 KV or above.”
Dispersed power producing sources such as wind and solar should not be
included as BES elements because of the variable and intermittent nature
of these resources. If these dispersed power producing resources had
dedicated energy storage facilities only then that could make them BES
elements. Generally the collector systems for these resources (from the
bulk transmission system reliability perspective) do not differ from
distribution systems which are excluded from the BES.

Response: While the SDT does not believe that additional clarification of the term “common point” is needed in
the BES definition, the following guidance is provided. The common point of connection, which is the point
from where generation is aggregated to determine if the 75 MVA threshold is met, is the point where the
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Question 5 Comment

individual transmission Element(s) of a collector system ultimately meet the 100 kV transmission system. No
change made.
The SDT disagrees with excluding dispersed power producing sources such as wind and solar from the BES
definition. These resources comprise a significant share of the North American resource mix. No change made.
The SDT does not believe further clarification of Dispersed Power Resources is needed. Inclusion I4 is directed
at including resources such as wind and solar farms. This is denoted by the requirement that the dispersed
power producing resources “utilize[e] a system designed primarily for aggregating capacity.” Furthermore,
Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s) of the
collector systems operated below 100 kV or not included under Inclusion I2. No change made.
Southwest Power Pool
Standards Review Team

No

We believe that the removal of the wording “single site” in I2 would
remove the need to cover dispersed power producing resources in I4.
What is the reason for keeping I4 in this version?
Also we understand that 75MVA is held in I4 because of no direct link to
the registry criteria, but feel that this number could change in phase two
of the project which would create unnecessary work in the future.

Response: The essential distinction between Inclusions I2 and I4 is that Inclusion I2 may not include generating
resources that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this
purpose. Inclusion I4 is directed at including resources such as wind and solar farms. This is denoted by the
requirement that the dispersed power producing resources “utilize[e] a system designed primarily for
aggregating capacity.” No change made.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to
the technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT
has responsibilities associated with being responsive to the directives established in Orders No. 743 and 743-A,
particularly in regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with
sufficient time for the development of strong technical justifications that would warrant a change from the
current values that exist through the application of the definition today. These and similar issues have prompted
the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
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Yes or No

Question 5 Comment

stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications
to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk
Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for
modifications to the existing values. No change made.
Pepco Holdings Inc and
Affiliates

No

The SDT reworded Inclusion I4 to use the phrase “utilizing a system
designed primarily for aggregating capacity”. This was to address a
concern that the previous definition could ensnare distributed
generation or small generators in a distribution system. We agree with
the intent of this modification. I4 was intended solely to address wind
and solar farms that use a collector system to aggregate their capacity.
Therefore, to provide better clarity on the intent of this Inclusion,
perhaps it would be better to specifically mention these examples in the
wording: “Dispersed power producing resources (such as wind and solar
farms, etc.) which utilize a system designed primarily for aggregating
capacity, where the capacity is greater than 75MVA (gross aggregate
nameplate rating) and the facility is connected at a common point at a
voltage of 100kV or above.”

Response: Use of the term ‘etc.’ is not suitable for a definition as it is completely open ended. Inclusion of a list
is problematic as it may not be complete especially with regard to future technology enhancements which could
force a revision of the definition. The SDT does not believe the suggested change provides any additional
clarity. The SDT does not believe further clarification of Dispersed Power Resources is needed. Inclusion I4 is
directed at including resources such as wind and solar farms. This is denoted by the requirement that the
dispersed power producing resources “utilize[e] a system designed primarily for aggregating capacity.” No
change made.
Hydro One Networks Inc.

No

Although we agree with the I4 concept, we suggest that the SDT should
consider that this category primarily includes wind and solar farms and
their collector system. We believe these facilities should not be included
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Yes or No

Question 5 Comment
as BES elements but rather as supporting elements (see comments under
I2) for the following reasons: a) Any additional benefit of classifying
these resources as BES is insignificant for the reliability of supply
(capacity and energy), considering the intermittent and widely variable
nature of these resources. The planning and operational standards and
practices make sure that their unavailability or unexpected (sudden) loss,
which are significantly more likely due to the natural elements than
those due to mechanical or electrical causes, will not jeopardize the
reliability of the supply; and b) The reliability of the aspects of the
collector system of these resources (their impact on reliability of the bulk
transmission system) is not different from that of distribution systems
(load serving feeders) which are excluded from the BES.
We agree with the revised portion of Inclusion I4 which does indeed
clarify that there is no requirement for a contiguous BES path from the
dispersed generation resources to the point of interconnection to the
BES.

Response: The SDT disagrees with excluding dispersed power producing sources such as wind and solar from
the BES definition. These resources comprise a significant share of the North American resource base. No
change made.
Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s) of the
collector systems operated below 100 kV or not included under Inclusion I2. No change made.
Western Area Power
Administration

No

Need to clarify the systems associated with this inclusion. The phrase
“dispersed power producing resources” in inclusion (I4) is confusing and
does not clearly communicate the focus of this inclusion. Without
reviewing the reference information provided in the 1st draft comment
form, it’s not clear that dispersed power producing resources refer to
wind and solar resources. Recommendation: Include examples after
phrase “dispersed power producing resources” for clarification to this
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Question 5 Comment
inclusion. Change I4 to read - Dispersed power producing resources (i.e.
wind and solar resources) with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily
for aggregating capacity, connected at a common point at a voltage of
100 kV or above.

Response: The SDT does not believe that the suggestion provides any additional clarity. No change made.
PacifiCorp

No

Setting a dispersed power producing resource limit to 75 MVA at a
common point discriminates against single generator owners who own
generators between 20 MVA and 75 MVA (inclusion I1), typically
connected at a common point and requires such owners to be subject to
additional standards that dispersed power producing owners are not
required. However, even with this concern, PacifiCorp supports the
entire BES definition in its current form based on the timeframe under
which the SDT is operating and with an emphasis based on a phase II SAR
to address PacifiCorp’s objections regarding generation levels.
Under the attached scenario, please identify which elements would be
considered BES: This response included a drawing. This format will not
allow the submission of the drawing. The drawing will be sent separately
in an email. Reference "Proj 2010-17 PAC Drawing".

Response: The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition.
However, the SDT has responsibilities associated with being responsive to the directives established in Orders
No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded
the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. All recommendations for modifications to the technical
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Yes or No

Question 5 Comment

aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System will be
considered. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop
analyses which will properly assess the threshold values and provide compelling justification for modifications
to the existing values. No change made.
The examples provided will be reviewed as part of Phase 2.
Massachusetts
Department of Public
Utilities

No

The aggregate 75 MVA of connected generation does not appear to be
adequately supported by technical analysis and appears, on its face, as
too low. Among our concerns is that such a low level will have a
potential adverse impact on the development of renewable generation
resources.
In addition, the inclusion needs to be clarified in order that entities have
clear guidance on what is meant by “common point of interconnection.”

NESCOE

No

NESCOE continues to disagree with this proposed inclusion. NESCOE is
concerned with the potential adverse impact this may have on the
development of renewable generation resources.
In addition, NESCOE suggests that the aggregate 75 MVA of connected
generation is too low and is not adequately supported by technical
analysis. The threshold value should be related to the largest
contingency the applicable control area is designed to operate to. A level
of 300 MVA would be appropriate.
Finally, the inclusion needs to be clarified in order that entities have clear
guidance on what is meant by “common point of interconnection.”

Response: The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition.
However, the SDT has responsibilities associated with being responsive to the directives established in Orders
No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded
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the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. The SDT will consider all recommendations for modifications
to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk
Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for
modifications to the existing values. No change made.
While the SDT does not believe that additional clarification of the term “common point” is needed in the BES
definition, the following guidance is provided. The SDT believes the common point of connection, which is the
point from where generation is aggregated to determine if the 75 MVA threshold is met, is the point where the
individual transmission Element(s) of a collector system ultimately meet the 100 kV transmission system. No
change made.
Idaho Falls Power

No

As drafted, it appears to draw in all generation resources that sum to 75
MVA or higher. We question then if there is value of categorizing every
wind turbine on a >75MVA wind farm as a BES asset and, what would be
the unintended consequences.
Perhaps language delineating the point of aggregation as the
demarcation point of a BES asset would better serve.

Response: Inclusion I4 denotes an aggregate threshold. This is clear from the requirement inclusion threshold
of “aggregate capacity greater than 75 MVA (gross aggregate nameplate rating).” Once this aggregate threshold
is met, all generation resources that comprise the facility would be included. No change made.
While the SDT does not believe that additional clarification of the term “common point” is needed in the BES
definition, the following guidance is provided. The SDT believes the common point of connection, which is the
point from where generation is aggregated to determine if the 75 MVA threshold is met, is the point where the
individual transmission Element(s) of a collector system ultimately meet the 100 kV transmission system. No
change made.
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ReliabilityFirst

No

Question 5 Comment
The term “Dispersed Power Producing Resource” is not a defined term
and needs further clarification.
However, I4 is not needed and is already included in I2. I4 does not add
any additional facilities that are not already included in I2. How are
“dispersed power producing resources” different from “generating
resources” described in I2? If the intent of I4 is to include wind
generators but exclude wind farm collector systems in the BES,
ReliabilityFirst Staff disagrees.
To maintain reliability, the BES cannot have pockets of generation that
are not connected to the BES via BES facilities. ReliabilityFirst Staff
believes that without including the paths from BES generators in the BES,
the reliable operation of the system could be jeopardized if the paths are
unavailable due to non-compliance to Reliability Standards. For example,
wind farm collector systems at voltages operated at less than 100 kV
should be included in the BES for the above reason. I4 could be deleted.

Response: The SDT does not believe further clarification of Dispersed Power Resources is needed. Inclusion I4 is
directed at including resources such as wind and solar farms. This is denoted by the requirement that the
dispersed power producing resources “utilize[e] a system designed primarily for aggregating capacity.” No
change made.
The essential distinction between Inclusions I2 and I4 is that Inclusion I2 may not include generating resources
that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this purpose.
Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s) of the
collector systems operated below 100 kV or not included under Inclusion I2. No change made.
The contiguous nature of the BES will be discussed as part of Phase 2 of the project. No change made.
Xcel Energy

No

Xcel Energy believes that this inclusion is still a little vague and could use
some clarification. For instance, if a wind farm has an aggregated
capacity greater than 75 MVA (and therefore meets Inclusion I4) exactly
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what facilities are included as part of the BES, every turbine, all
distribution transformers and cables, etc. If all equipment is included,
what level of detail is required of this BES facility for modeling purposes,
and who is responsible for modeling this system. Or, is the intent to only
include the facilities at the common point of connection, whereby the
facility could be modeled as 1 large facility?

Response: Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission
Element(s) of the collector systems operated below 100 kV or not included under Inclusion I2. No change made.
Central Maine Power
Company

No

The term “common point” needs clarification and/or definition. (e.g., is it
intended to apply to the risk of single mode failure, where all the
resources could be lost for a single event?) Some northeast industry
expert colleagues interpret I2 to mean the collector system itself needs
to be 100 kV or above in order to be BES. I2 seems to not include the
collector system itself in BES. I4 should be restated as follows:
“Dispersed power producing resources with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) utilizing a collector
system connected at a common point. BES includes the interconnecting
substation with the step-up transformer(s) connected at a voltage of 100
kV or above.”[alternatively, replace "interconnecting substation with"
with, “generator terminals through the high-side of” if the entire
collector system is intended to be BES]Also note that some wind
collector systems require supplemental dynamic reactive resources or
special control system to met reliability standards. As written, these
reactive resources or controls may not be considered to be BES.

New York State Dept of
Public Service

No

I4 reference to a “common point” lacks clarity that can lead to confusion
and required clarifications. Suggested wording change: ... connected at
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side voltage of 100 kV or above.”

American Electric Power

No

We believe more clarity is needed as to where exactly the “common
point” is, for example in the case of a wind farm. This first common point
could be interpreted as the output voltage of the wind generator, would
be less than the 100kv threshold and thereby could (unintentionally?)
exclude the facility as a whole. If this was unintentional, we recommend
rewording I4 in a manner similar to I2.

Response: While the SDT does not believe that additional clarification of the term “common point” is needed in
the BES definition, the following guidance is provided. The SDT believes the common point of connection,
which is the point from where generation is aggregated to determine if the 75 MVA threshold is met, is the
point where the individual transmission Element(s) of a collector system ultimately meet the 100 kV
transmission system. No change made.
The Dow Chemical
Company

No

It is not clear how “Dispersed power producing resources” differ from
“Generating Resource (s)” in I2. Inclusion I4 should clarify this.
We suggest that the phrase “Variable Energy Resources” be used instead
of “Dispersed power producing resources”. Variable Energy Resources
should be defined as “Resources producing electricity using wind or solar
energy.”
The following phrase should be added at the end “unless excluded under
Exclusion E2”.

Response: The essential distinction between Inclusion I2 and I4 is that Inclusion I2 may not include generating
resources that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this
purpose. Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s)
of the collector systems operated below 100 kV or not included under Inclusion I2. No change made.
The SDT does not believe that the suggestion provides any additional clarity. No change made.
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The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately
applied will identify the vast majority of BES Elements in a consistent manner that can be applied on a
continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation
point between BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and
Reactive Power resources connected at 100 kV or higher as included in the BES. To fully appreciate the scope of
the ‘core’ definition an understanding of the term Element is needed. Element is defined in the NERC Glossary
of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator,
transformer, circuit breaker, bus section, or transmission line. An element may be comprised of one or more
components. “
An Element is basically any electrical device that is associated with the transmission or the generation
(generating resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included
through the application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power
and Reactive Power resources with specific criteria to provide for a consistent determination of whether an
Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES
Elements). The exclusion language is written to specifically identify Elements or groups of Elements for potential
exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific
criteria identified in the exclusion language. This does not include the exclusion of Real Power and Reactive
Power resources captured by Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of
the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner. Therefore, the
only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the
customer’s side) and supersedes inclusion I2.
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Question 5 Comment

Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and
supersedes Inclusion I5.
In the event that the BES definition does not provide a definitive determination on whether an Element is
classified as BES or non-BES, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element. No change made.
City of St. George

No

This language follows the 75 MVA plant requirements from the
Registration Criteria. See comments to question 3 (for I2) above.
Additional detail is needed to clarify exactly at what point in the
dispersed system the BES starts and what is not BES.

Response: Please see response to Q3.
While the SDT does not believe that additional clarification of the term “common point” is needed in the BES
definition, the following guidance is provided. The SDT believes the common point of connection, which is the
point from where generation is aggregated to determine if the 75 MVA threshold is met, is the point where the
individual transmission Element(s) of a collector system ultimately meet the 100 kV transmission system. No
change made.
ISO New England Inc

No

I4 is unclear as to whether or not the collector system (or system
designed primarily for aggregating capacity) itself is BES or just the
resource.”Utilizing a system designed primarily for aggregating capacity”
needs to be more clearly defined to account for multiple systems that
may exist out of one common point. A suggestion would be to modify the
end of the sentence to say “connected at any common point.”
I4 will allow for significant amounts of dispersed power producing
resources to be excluded from the BES. This includes wind resources
which are increasing in numbers and having a significant impact on
system operations. It does not seem appropriate that having ten 70 MVA
(total of 700 MVA) installations each with their own connection to a 115
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Question 5 Comment
kV bus should fall outside of the BES. As currently written, they would
fall outside of the inclusion if they do not utilize the same collector
system. It is unclear whether or not supplemental equipment associated
with the dispersed power producing resources is included in the BES. As
an example, many wind resources are being interconnected utilizing
supplemental dynamic and static reactive devices which are crucial to the
operation of these resources. The dynamic devices are often controlling
themselves and static reactive devices, which may or may not be
connected above 100 kV. Leaving these devices out of the BES definition
seems to be a potential gap.

Response: The essential distinction between Inclusion I2 and I4 is that Inclusion I2 may not include generating
resources that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this
purpose. Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s)
of the collector systems operated below 100 kV or not included under Inclusion I2. No change made.
The clustering of dispersed power producing resources and supplemental equipment will be discussed as part of
Phase 2 of the project. No change made.
Rochester Gas and Electric
and New York State
Electric and Gas

No

The term “common point” needs clarification and/or definition. (e.g., is it
intended to apply to the risk of single mode failure, where all the
resources could be lost for a single event?)
Some northeast industry expert colleagues interpret I2 to mean the
collector system itself needs to be 100 kV or above in order to be BES. I2
seems to not include the collector system itself in BES. I4 be restated as
follows:”Dispersed power producing resources with aggregate capacity
greater than 75 MVA (gross aggregate nameplate rating) utilizing a
collector system connected at a common point. BES includes the
interconnecting substation with the step-up transformer(s) connected at
a voltage of 100 kV or above.”[alternatively, replace the bold italics with,

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Question 5 Comment
“generator terminals through the high-side of”]
Also note that some wind collector systems require supplemental
dynamic reactive resources or special control system to met reliability
standards. As written, these reactive resources or controls may not be
considered to be BES.

Response: While the SDT does not believe that additional clarification of the term “common point” is needed in
the BES definition, the following guidance is provided. The SDT believes the common point of connection,
which is the point from where generation is aggregated to determine if the 75 MVA threshold is met, is the
point where the individual transmission Element(s) of a collector system ultimately meet the 100 kV
transmission system. No change made.
The essential distinction between Inclusion I2 and I4 is that Inclusion I2 may not include generating resources
that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this purpose.
Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s) of the
collector systems operated below 100 kV or not included under Inclusion I2. No change made.
The inclusion of supplemental equipment will be discussed as part of Phase 2 of the project. No change made.
LCRA Transmission Services
Corporation

No

LCRA TSC suggests consistency between this inclusion criteria and the
criteria used in I2 for “generation”.

Response: The essential distinction between Inclusion I2 and I4 is that Inclusion I2 may not include generating
resources that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this
purpose. Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s)
of the collector systems operated below 100 kV or not included under Inclusion I2. No change made.
Kansas City Power and
Light Company

No

It is not clear that it is the injection at the collection point that is the
defining point for the injection. Nameplate rating of the generator is not
a reflection of what can be actually injected into the transmission system
with resulting electrical impacts on transmission loading and behavior.
Recommend the BES definition be based on a generating resource(s)
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Question 5 Comment
established net accredited generating capacity at the common point
instead of what it could do by nameplate rating that may not be
achievable. Recommend the following language: Dispersed power
producing resources utilizing a system designed primarily for aggregating
capacity connected through a common point at a voltage of 100 kV or
above with aggregate net accredited capacity at the common point of
greater than 75 MVA.

Response: For Phase 1, the SDT has used nameplate rating in order to maintain consistency with the ERO
Statement of Compliance Registry Criteria. No change made.
This can be discussed in Phase 2 of the project. The SDT acknowledges and appreciates the comments and
recommendations associated with modifications to the technical aspects (i.e., the bright-line and component
thresholds) of the BES definition. However, the SDT has responsibilities associated with being responsive to the
directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the
definition today. These and similar issues have prompted the SDT to separate the project into phases which will
enable the SDT to address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT
will consider all recommendations for modifications to the technical aspects of the definition for inclusion in
Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the
NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and
provide compelling justification for modifications to the existing values. No change made.
Farmington Electric Utility
System

No

FEUS feels additional clarity should be added to I4. It appears I4 is not
intended to include each individual wind turbine generating unit in a
wind farm as a BES element, but rather to include the point at which the
aggregation becomes large enough to meet the aggregate capacity
threshold of 75MVA.

Response: inclusion I4 denotes an aggregate threshold. This is clear from the requirement inclusion threshold
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Question 5 Comment

of “aggregate capacity greater than 75 MVA (gross aggregate nameplate rating).” Once this aggregate threshold
is met, all generation resources that comprise the facility would be included. No change made.
South Houston Green
Power, LLC

No

Further clarification of “Dispersed power producing resources” is
needed. Multiple small resources should not be included.
The following phrase should be added at the end of Inclusion I4 “unless
excluded under Exclusion E2”.

Response: The SDT does not believe that additional clarification is needed. Inclusion I4 speaks towards the
inclusion of the resources themselves, not the transmission Element(s) of the collector systems operated below
100 kV or not included under Inclusion I2. No change made.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately
applied will identify the vast majority of BES Elements in a consistent manner that can be applied on a
continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation
point between BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and
Reactive Power resources connected at 100 kV or higher as included in the BES. To fully appreciate the scope of
the ‘core’ definition an understanding of the term Element is needed. Element is defined in the NERC Glossary
of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator,
transformer, circuit breaker, bus section, or transmission line. An element may be comprised of one or more
components. “
An Element is basically any electrical device that is associated with the transmission or the generation
(generating resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included
through the application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power
and Reactive Power resources with specific criteria to provide for a consistent determination of whether an
Element is classified as BES or non-BES.
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Question 5 Comment

Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES
Elements). The exclusion language is written to specifically identify Elements or groups of Elements for potential
exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific
criteria identified in the exclusion language. This does not include the exclusion of Real Power and Reactive
Power resources captured by Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of
the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner. Therefore, the
only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the
customer’s side) and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and
supersedes Inclusion I5.
In the event that the BES definition does not provide a definitive determination on whether an Element is
classified as BES or non-BES, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element. No change made.
Westar Energy

No

We believe that the removal of the wording “single site” in I2 would
eliminate the need to include dispersed power producing resources in I4.
We feel that I4 should be removed to reduce redundancy in the
definition, unless there is some other reason to include it.
Also, we understand that 75 MVA is retained in I4 because there is no
direct link to the ERO Statement of Compliance Registry Criteria, but we
have concerns that this number could change in phase two of the
project, creating unnecessary work in the future.

Response: The essential distinction between Inclusion I2 and I4 is that I2 may not include generating resources
that use lower voltage collection systems while I4 is specifically designed to accomplish this purpose, therefore
I4 is needed. No change made.
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Question 5 Comment

The SDT acknowledges and appreciates the comments and recommendations associated with modifications to
the technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT
has responsibilities associated with being responsive to the directives established in Orders No. 743 and 743-A,
particularly in regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with
sufficient time for the development of strong technical justifications that would warrant a change from the
current values that exist through the application of the definition today. These and similar issues have prompted
the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. The SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop
analyses which will properly assess the threshold values and provide compelling justification for modifications
to the existing values. No change made.
Hydro-Quebec
TransEnergie

Same comment than Q. 3.
Also, since the path to connect the dispersed generation is often done at
distribution voltage, that lower voltage path should not be included in
BES.

Response: Please see response to Q3.
Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s) of the
collector systems operated below 100 kV or not included under Inclusion I2. No change made.
Tacoma Power

Yes

Tacoma Power generally supports the Inclusion I4 as currently written.
However, we support further refinement of the aggregate nameplate
rating definition and support deferring the appropriate quantitative
thresholds to those that will be determined in Phase 2.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition.
However, the SDT has responsibilities associated with being responsive to the directives established in Orders
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Question 5 Comment

No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded
the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. The SDT will consider all recommendations for modifications
to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk
Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for
modifications to the existing values. No change made.
Ameren

Yes

a)For a consistent application, we suggest that the definition of the terms
"Dispersed power producing resources" is included. Consider including
some examples also.

Response: The SDT does not believe further clarification of Dispersed Power Resources is needed. Inclusion I4 is
directed at including resources such as wind and solar farms. This is denoted by the requirement that the
dispersed power producing resources “utilize[e] a system designed primarily for aggregating capacity.” No
change made.
Cowlitz County PUD

Yes

However, Cowlitz suggests Inclusion 4 be made parallel with Inclusion 2:
...(greater than the gross aggregate name plate rating per the ERO
Statement of Compliance Registry Criteria) utilizing...

Response: The SDT believes that Inclusions I2 and I4 do use consistent language and this point has been clarified
with the clarifying language changes to Inclusion I2. No change made.
Long Island Power
Authority

Yes

Need to define the term "common point"

Response: While the SDT does not believe that additional clarification of the term “common point” is needed in
the BES definition, the following guidance is provided. The SDT believes the common point of connection,
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which is the point from where generation is aggregated to determine if the 75 MVA threshold is met, is the
point where the individual transmission Element(s) of a collector system ultimately meet the 100 kV
transmission system.
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative ShoMe Power Electric Power
Cooperative

Yes

This inclusion should be limited to reactive devices 150 MVAR or greater
(gross aggregate nameplate rating) connected through a common point
at the 200 kV level or higher level.

Manitoba Hydro

Yes

Manitoba Hydro agrees with I4 but it does create a discrepancy between
the BES Definition and the Registration Criteria Document. The
Registration Criteria document should be updated and I2 and I4 should
be combined into a single Inclusion.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition.
However, the SDT has responsibilities associated with being responsive to the directives established in Orders
No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded
the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. The SDT will consider all recommendations for modifications
to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk
Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for
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Question 5 Comment

modifications to the existing values. Possible revisions to the ERO Statement of Compliance Registry Criteria will
be discussed as part of Phase 2 of the project. No change made.
Consumers Energy

Yes

We agree, but would like further clarification on what wind farm
equipment (e.g., collector systems or other equipment) would be
considered a part of the BES. Is the system designed for aggregating
capacity considered to be part of the dispersed plant or part of the BES.

Response: Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission
Element(s) of the collector systems operated below 100 kV or not included under Inclusion I2. No change made.
Michigan Public Power
Agency
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)
Central Electric Cooperatve
(CEC)
Clearwater Power
Company (CPC)

Yes

MPPA supports the revised language generally, but believes additional
changes would make the language clearer. Specifically, we believe
Inclusion 4 should not incorporate a hard 75 MVA generation threshold
(i.e, “resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating)”). Instead, we urge the SDT to replace this
language with the defined term “Qualifying Aggregate Generation
Resources,” which is discussed in more detail in our response to
Question 3. This language, or some equivalent, will preserve the SDT’s
ability to revise the 75 MVA threshold in Phase 2, with the result of Phase
2 included in the BES Definition by operation rather than requiring
further revision of the Definition.

Douglas Electric
Cooperative (DEC)

More generally, we are not certain what is accomplished by Inclusion 4
that is not already accomplished by Inclusion 2, which also addresses
whether generation should be defined as BES. The SDT’s stated concern
is with variable generation units such as wind and solar plants. It is not
clear to us why this concern is not fully addressed in Inclusion 2, which
addresses multiple generation units connected at a common bus, the
configuration of most variable generation plants with multiple units.

Fall River Rural Electric

We are also concerned that the language, as proposed, could have

Snohomish County PUD
Consumer's Power Inc.

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Organization
Cooperative (FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric
Cooperative (LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest
Generating Cooperative
(PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric
Cooperative (UEC)
Kootenai Electric
Cooperative

Yes or No

Question 5 Comment
unintended consequences and improperly classify local distribution
systems as BES in certain circumstances. This is because multiple
distributed generation units could render a local distribution system a
“collector system” and the entire system the equivalent of an aggregated
generation unit, causing the local distribution system to be improperly
denied status as a LN. If many different distributed generation units are
connected to a local distribution system, it is very unlikely that more than
a few of those units would fail simultaneously, and it is therefore unlikely
that multiple generation units would produce a measureable impact on
the interconnected bulk transmission system, especially if the units
individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase 2.
Further, we are concerned that, if small distributed generation units
become the industry norm, Inclusion 4 could unintentionally sweep in
local distribution systems, especially where local policies favor the
growth of small solar or other renewable generation systems for public
policy reasons.
Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the
requirements of Exclusion E1 or a Local Network meeting the
requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that
dispersed small-scale generators scattered throughout a Radial System or
Local Network serving retail load would not convert the Radial System or
Local Network into a BES system, even if the aggregate capacity of those
small generators exceeds the relevant threshold.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition.
However, the SDT has responsibilities associated with being responsive to the directives established in Orders
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Question 5 Comment

No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded
the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. The SDT will consider all recommendations for modifications
to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk
Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for
modifications to the existing values. No change made.
The essential distinction between Inclusions I2 and I4 is that Inclusion I2 may not include generating resources
that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this purpose.
No change made.
Inclusion I4 is directed at including resources such as wind and solar farms. This is denoted by the requirement that
the dispersed power producing resources “utilize[e] a system designed primarily for aggregating capacity.”
Furthermore, Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s)
of the collector systems operated below 100 kV or not included under Inclusion I2. Therefore distribution systems
would not be inadvertently included. No change made.
National Grid

Yes

We agree with Inclusion I4, however we feel that the inclusion could be
interpreted in some different ways. This inclusion could be interpreted
to exclude dispersed generation greater than 75 MVA if the first common
point is less than 100 kV. To eliminate any confusion in the
interpretation of this inclusion, we suggest this wording: Dispersed
power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) connected to a Transmission Element
at 100 kV or above, utilizing a system designed primarily for aggregating
capacity which includes all transformers between the generator(s) and
the Transmission Element.

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MRO NERC Standards
Review Forum (NSRF)

Yes or No

Question 5 Comment

Yes

I4 - Dispersed power producing resources with aggregate capacity
greater than 75 MVA (gross aggregate nameplate rating) utilizing a
system designed primarily for aggregating capacity, connected at a
common point at a voltage of 100 kV or above starting at the point of
aggregation to 75 MVA or more through to the point of interconnection
at 100 kV or above.”

Response: The SDT does not believe that the suggested change provides additional clarity. No change made.
Electricity Consumers
Resource Council (ELCON)

Yes

The term “dispersed power” and “dispersed generation” are often
synonymous with distributed generation, which includes behind-themeter generation (CHP). The Inclusion should be clarified by specifically
referencing wind and solar, or adopt the FERC term “Variable Energy
Resources.”
Also, to distinguish this Inclusion from Inclusion I2, the SDT might want to
clarify that the collection system (usually at voltage below 100 KV
anyway) is not part of the BES-just the resources and any transformers
included by I1, if this is indeed the intent of this Inclusion. The following
phrase should be added at the end “unless excluded under Exclusion E2.”

Response: The SDT believes that inclusion of a list is problematic as it may not be complete especially with
regard to future technology enhancements which could force a revision of the definition. Furthermore, the SDT
does not believe further clarification of Dispersed Power Resources is needed. Inclusion I4 is directed at
including resources such as wind and solar farms. This is denoted by the requirement that the dispersed power
producing resources “utilize[e] a system designed primarily for aggregating capacity.” No change made.
The SDT does not believe that additional clarification is needed. Inclusion I4 speaks towards the inclusion of the
resources themselves, not the transmission Element(s) of the collector systems operated below 100 kV or not
included under Inclusion I2. No change made.

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ACES Power Marketing
Standards Collaborators

Yes or No

Question 5 Comment

Yes

Further clarification on what “dispersed power” means would be helpful.
How does it compare to distributed generation?

Response: While the SDT believes that further clarity of the terms “dispersed power” and “distributed
generation” is not needed, it notes that distributed generation is generally defined as: a generator that is
located close to the particular load that it is intended to serve and is interconnected to the utility distribution
system. The U.S EIA and FERC generally use this as a basic definition. The language of Inclusion I4 stating
“Dispersed power producing resources . . . utilizing a system designed primarily for aggregating capacity,
connected at a common point at a voltage of 100 kV or above” was selected so as not to confuse what is
traditionally considered distributed generation with the types of systems to be included in Inclusion I4. No
change made.
Texas RE NERC Standards
Subcommittee

Yes

To distinguish this Inclusion from Inclusion I2, the SDT might want to
clarify that the collection system (usually at voltage below 100 KV
anyway) is not part of the BES-just the resources and any transformers
included by I1, if this is indeed the intent of this Inclusion.

Response: The SDT does not believe that additional clarification is needed. Inclusion I4 speaks towards the
inclusion of the resources themselves, not the transmission Element(s) of the collector systems operated below
100 kV or not included under Inclusion I2. No change made.
ExxonMobil Research and
Engineering

Yes

The BES SDT should clarify the difference between “dispersed power
producing resources” and “generation resources” in such a manner that
it is clear that an industrial plant containing providing the BES with power
from ten 7.5MVA machines connected at a common point at a voltage of
100 kV or higher meets the qualifications for generation resources and
does not meet the qualifications for a “dispersed power producing
resource”.

Portland General Electric

Yes

PGE requests additional clarity in the wording of Inclusion 4. Inclusion 4 is
not intended to include each individual wind turbine generating unit in a
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Yes or No

Company

Question 5 Comment
wind farm as a BES element, but rather to include the point at which the
aggregation becomes large enough to meet the aggregate capacity
threshold of 75 MVA. However, the response to comments from the last
comment posting and the current wording of Inclusion 4 does not
provide sufficient clarity to answer this question.

Bonneville Power
Administration

Yes

BPA suggests adding, “Including generating terminals of the high side” as
clarifying language to the end of the sentence. (Specifically where the
100kV is to be measured as clarified in I2). BPA believes that Inclusion 4
is not intended to include each individual wind turbine/generator unit in
a wind farm as a BES element, but rather to include the point at which
the aggregation becomes large enough to meet the aggregate capacity
threshold of 75 MVA.

WECC Staff

Yes

WECC seeks further clarification on Inclusion 4. Several comments were
submitted in the last round of comments whether each individual wind
turbine in a wind farm, will be included in the BES. WECC believes the
language change to I4 by the SDT did not address this issue. The current
language in I4 could be interpreted as each individual turbine (example
1MW) would be part of the BES. WECC believes that I4 is not intended to
include each individual wind turbine in a wind farm as a BES element but
rather to include the point at which the aggregation becomes large
enough to meet the aggregate capacity threshold of 75 MVA. WECC
recommends the SDT modify the language in I4 to clarify this issue.

Response: The SDT does not believe that additional clarification is needed. Inclusion I4 denotes an aggregate
threshold. This is clear from the requirement wording of “aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating).” Once this aggregate threshold is met, all generation resources that comprise the
facility would be included. No change made.
Transmission Access Policy

Yes

We recommend clarifying that the dispersed power resources covered by
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Yes or No

Study Group

Florida Municipal Power
Agency

Question 5 Comment
this inclusion do not include generators on the retail side of the retail
meter. Specifically, we recommend that the Inclusion read: “Dispersed
power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily
for aggregating capacity, connected at a common point at a voltage of
100kV or above, but not including generation on the retail side of the
retail meter.”

Yes

We recommend clarifying that the dispersed power resources covered by
this inclusion do not include generators on the retail side of the retail
meter. Specifically, we recommend that the Inclusion read: “Dispersed
power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily
for aggregating capacity, connected at a common point at a voltage of
100kV or above, but not including generation on the retail side of the
retail meter.”

Response: The SDT does not believe that additional clarification is needed. The SDT further clarifies that
generating units on the customer’s side of the retail meter are not included under Inclusion I4 since customerside retail generation typically does not “utilize[e] a system designed primarily for aggregating capacity,
connected at a common point at a voltage of 100 kV or above.” No change made.
Redding Electric Utility

Yes

City of Redding

Yes

ATC LLC

Yes

City of Austin dba Austin
Energy

Yes

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Yes or No

Question 5 Comment

Georgia System Operations
Corporation

Yes

MEAG Power

Yes

Northern Wasco County
PUD

Yes

Northern Wasco County PUD agrees both with the inclusion and with the
revised language. The revised language removes the need to provide a
separate definition for “Collector System”.

Sacramento Municipal
Utility District

Yes

We support using the BES Phase 2 technical analysis to identify and
provide technical support for determining the appropriate minimum
MVA rating that the aggregation of multiple units must meet to be
considered part of the BES.
We also support using the Phase 2 studies to identify an appropriate
minimum MVA level that a single unit of the aggregation of multiple units
must be considered BES.

Oncor Electric Delivery
Company LLC

Yes

Utility Services, Inc.

Yes

Harney Electric
Cooperative, Inc.

Yes

HEC agrees with the inclusions and revised language to the definition

Central Lincoln

Yes

Central Lincoln agrees both with the inclusion and with the revised
language. The revised language removes the need to provide a separate
definition for “Collector System”.

Independent Electricity

Yes

The revised Inclusion I4 does indeed clarify that there is no requirement
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Yes or No

System Operator

Question 5 Comment
for a contiguous BES path from the dispersed generation resources to the
point of interconnection to the BES.

PSEG Services Corp

Yes

Mission Valley Power

Yes

Mission Valley Power agrees both with the inclusion and with the revised
language.
The revised language removes the need to provide a separate definition
for “Collector System”.

Puget Sound Energy

Yes

Tillamook PUD

Yes

Tillamook PUD agrees both with the inclusion and with the revised
language.
The revised language removes the need to provide a separate definition
for “Collector System”.

NV Energy

Yes

Z Global Engineering and
Energy Solutions

Yes

Metropolitan Water
District of Southern
California

Yes

Duke Energy

Yes

Ontario Power Generation
Inc.

Yes

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Yes or No

Central Hudson Gas and
Electric Corporation

Yes

City of Anaheim

Yes

Chevron U.S.A. Inc.

Yes

Southern Company

Yes

FirstEnergy Corp.

Yes

Texas Industrial Energy
Consumers

Yes

Tri-State GandT

Yes

Tennessee Valley Authority

Yes

IRC Standards Review
Committee

Yes

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

Yes

Southern Company
Generation

Yes

Dominion

Yes

Question 5 Comment

This is OK because the 75 MVA is connected at 100 kV or above.

The revised Inclusion I4 does clarify that there is no requirement for a
contiguous BES path from the dispersed generation resources to the
point of interconnection to the BES.

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Yes or No

Balancing Authority
Northern California

Yes

SERC Planning Standards
Subcommittee

Yes

SERC OC Standards Review
Group

Yes

NERC Staff Technical
Review

Yes

BGE

Yes

Question 5 Comment

No comment.

Response: Thank you for your support.

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6.

The SDT has added specific inclusions to the core definition in response to industry comments. Do you agree with Inclusion I5
(reactive resources)? If you do not support this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.

Summary Consideration: In response to comments, the SDT added further clarification to Inclusion I5 to exclude small generators that
would be improperly brought into the BES.
The SDT believes Inclusion I5 incorporates the necessary resources for the reliable operation of the BES, without unintentionally
including any distribution devices, or including any of the dedicated transformers which are not identified in the core definition or
Inclusion I1.
Additionally, Exclusion E4 will further exclude those non-generator Reactive Power resource devices that were identified through the
core definition or through Inclusion I5 which are on the load side of the customer meter solely for the customer’s own use.
Using a threshold for inclusion of non-generator Reactive Power resource devices in the BES will be considered in Phase 2 of this effort.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects
(i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being
responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012,
and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have prompted the SDT to
separate the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities.
Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2
of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing
Committees, to develop analyses which will properly assess the threshold values and provide compelling justification for modifications
to the existing values.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are connected at 100 kV
or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated
in Inclusion I1.

Organization

Yes or No

Question 6 Comment
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Yes or No

Question 6 Comment

SERC OC Standards Review
Group

No

We feel that this inclusion should be limited to dynamic devices with an aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating) connected through a
common point.

Tennessee Valley Authority

No

TVA feels that this inclusion should be limited to dynamic devices with an aggregate
capacity greater than 75 MVAR (gross aggregate nameplate rating) connected through
a common point at a voltage of 200kV or above, and requests that the Phase 2 for the
project use 75 MVAR connected at 200kV or above or develop a transmission voltage
and/or an MVAR threshold that is technically based.

Tri-State GandT

No

There should be a limitation on what reactive components needs to be included. The
limits could be based on capacity of the units or on the voltage step that occurs upon
switching of the device.

Western Area Power
Administration

No

This inclusion should be worded to only include static or dynamic reactive devices
which are necessary to meet the NERC Planning Criteria in terms of normal and postdisturbance voltage profiles. We shouldn't have to include smaller shunt cap banks
and reactors which are used primarily for voltage support (not voltage collapse).
Recommendation: Change I5 to read - Static or dynamic devices dedicated to
supplying or absorbing Reactive Power which are necessary to meet the NERC
Planning Criteria in terms of normal and post-disturbance voltage profiles that are
connected at 100 kV or higher, or through a dedicated transformer with a high-side
voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1

Southern Company

No

We believe that the size of the reactive power resource should be considered as a key
factor to be part of BES. When considering generating resources, the size, e.g.,
greater than 75 MVA, was a key part of criteria to be included or excluded as BES. A
similar approach should be applied when considering reactive power resources. We
also suggest the removal of static reactive resources from this inclusion.

Response: Using a threshold for inclusion of non-generator Reactive Power resource devices in the BES will be considered in
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Yes or No

Question 6 Comment

Phase 2 of this effort. The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT
has responsibilities associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in
regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of
strong technical justifications that would warrant a change from the current values that exist through the application of the
definition today. These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT
to address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all
recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17
Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for modifications to the
existing values. No change made.
New York State Dept of Public
Service

No

I5 - which has been newly added and significantly expands the BES definition - should
be dropped due to lack of technical justification.

Northeast Power Coordinating
Council

No

Technical studies need to be conducted to confirm reactive resource impacts on the
reliability of the BES. The inclusion of reactive resources is a significant expansion of
the current BES definition and therefore requires technical justification for inclusion.
Inclusion I5 as written is confusing with a reference to Inclusion I1 in the definition.
Suggest removing references to reactive resources from Phase 1 until technical
justification can be demonstrated (as part of Phase 2).

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects of the definition. However, the SDT has responsibilities associated with being responsive to the directives
established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not
afforded the SDT with sufficient time for the development of strong technical justifications. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will provide compelling justification.

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Yes or No

Question 6 Comment

No change made.
Southwest Power Pool
Standards Review Team

No

We understand that this inclusion is used to capture those devices other than
generation resources, but the language leads us to believe that it could include all
generators used to supply or absorb reactive power. We would suggest that I5 be
changed to read “-Static or dynamic devices specifically used for supplying or
absorbing Reactive Power that are connected at 100 kV or higher, or through a
dedicated transformer with a high-side voltage of 100 kV or higher, or through a
transformer that is designated in Inclusion I1.

Consumers Energy

No

This inclusion appears to pull small generators that have an AVR that are connected to
138 kV into the BES. These generators are primarily intended to provide real power.

Response: The SDT added further clarifications to Inclusion I5 to specifically exclude generators.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are connected at
100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through a transformer that
is designated in Inclusion I1.
Dominion

No

The language in the last part of Inclusion I5 “....or through a transformer that is
designated in Inclusion I1” introduces ambiguity. Specifically, it is not clear how
implememtation of this language would result in the inclusion of any Static or dynamic
device that is not already included. Dominion suggests that the language in I5 be
revised to read “Static or dynamic devices dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or connected through a
dedicated transformer with at least one terminal voltage of 100 kV or higher.”
Dominion understands that the SDT intended for this Inclusion to not address
generators or power producing resources because they are covered elsewhere (I2 and
I4) and requests that the SDT confirm this understanding.

Response: The SDT believes these qualifications on non-generator Reactive Power resource devices in Inclusion I5 do include the
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Question 6 Comment

necessary resources for the reliable operation of the BES, without unintentionally including any distribution devices, or including
any of the dedicated transformers which are not identified in the core definition or Inclusion I1. No change made.
The SDT confirms that Dominion’s understanding of the intent of this inclusion is correct.
In response to comments, the SDT added further clarifications to Inclusion I5.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are
connected at 100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through
a transformer that is designated in Inclusion I1.
Pepco Holdings Inc and
Affiliates

No

Agree in principle. However, the last phrase “or through a transformer that is
designated in Inclusion I1” is unnecessary, since if the resource were connected
through a transformer meeting Inclusion I1 it would by nature be connected at 100kV
or higher.

Response: The SDT believes the Inclusion I1 wording is necessary to capture those devices dedicated to supplying or absorbing
Reactive Power. No change made.
MRO NERC Standards Review
Forum (NSRF)

No

NSRF recommends the following proposed language for I5 to address the concern:"I5 Static or dynamic devices which 1) are dedicated to supplying or absorbing Reactive
Power that are connected at 100 kV or higher, or through a dedicated transformer
with a high-side voltage of 100 kV or higher, or through a transformer that is
designated in Inclusion I1 and 2) are pertinent to meeting the NERC Planning Criteria
in terms of normal and post-disturbance voltage profiles."

Response: The SDT does not believe this change provides additional clarity as it diverts from the bright-line concept. No change
made.
PacifiCorp

No

PacifiCorp recommends the addition of the phrase “...unless excluded under E1 or E3.”
Otherwise, PacifiCorp believes that I5 is currently acceptable. However, phase II
should identify limits and technically justify the appropriate limit(s).

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Yes or No

Question 6 Comment

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element.
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Yes or No

Question 6 Comment

Using a threshold for inclusion of non-generator Reactive Power resource devices in the BES will be considered in Phase 2 of this
effort. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values.
Massachusetts Department of
Public Utilities

No

The inclusion of all devices that supply reactive power to the BES is unnecessary and
will result in unjustified costs to the ratepayer. Static devices (fixed capacitors) should
remain excluded from the BES as they are dispatched by operations personnel, and if
one fixed capacitor bank fails, the operator can replace its impact by switching in
another fixed bank. This represents routine operation of the system. On the other
hand, dynamic devices may be important to maintaining voltage stability of the
system. These installations typically are rated to supply or absorb 75 MVA or more to
or from the BES. Therefore, the MA DPU suggests that dynamic reactive power devices
rated at 75 MVA or more could be included in the BES.
Further, revised inclusion I5 is a new inclusion that lacks definition (and appears to be
redundant with the general BES definition). NERC should provide technical
justification for the additional language under Inclusion I5.

NESCOE

No

NESCOE believes that inclusion of all devices that supply reactive power to the BES is
unnecessary and will result in transferring unjustified costs to the ratepayer. Static
devices (fixed capacitors) should remain excluded from the BES as they are dispatched
by operations personnel, and if one fixed capacitor bank fails, the operator can replace
its impact by switching in another fixed bank. This represents routine operation of the
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Question 6 Comment
system. On the other hand, dynamic devices may be important to maintaining voltage
stability of the system. These installations typically are rated to supply or absorb 75
MVA or more to or from the BES. Therefore, NESCOE suggests that dynamic reactive
power devices rated at 75 MVA or more be included in the BES.
Further, revised inclusion I5 is a new inclusion that lacks definition (and appears to be
redundant with the general BES definition). NERC should provide additional technical
justification for the additional language under Inclusion I5.

Response: The SDT believes these qualifications on non-generator Reactive Power resource devices in Inclusion I5 do include the
necessary resources for the reliable operation of the BES, without unintentionally including any distribution devices, or including
any of the dedicated transformers which are not identified in the core definition or Inclusion I1. No change made.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects of the BES definition. However, the SDT has responsibilities associated with being responsive to the directives
established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not
afforded the SDT with sufficient time for the development of strong technical justifications. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will provide compelling justifications.
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)

No

CLPD has several concerns about the new language in Inclusion 5. First, because
Reactive Power devices produce power, they are “power producing resources” and we
therefore believe Inclusion 5 is duplicative of Inclusion 4, which addresses “power
producing devices.”

Central Electric Cooperatve
(CEC)

Second, there is no capacity threshold specified in Inclusion 5 for Reactive Power
devices that would be considered part of the BES. This is inconsistent with the
approach taken in the balance of the definition, where thresholds are specified for
generators and other types of power producing devices.

Clearwater Power Company

Finally, CLPD believes the appropriate threshold for inclusion or exclusion of Reactive
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(CPC)
Snohomish County PUD

Yes or No

Question 6 Comment
Power devices from the BES should be subject to the same technical analysis that will
cover generators in the Phase 2 process.

Consumer's Power Inc
Douglas Electric Cooperative
(DEC)
Fall River Rural Electric
Cooperative (FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric Cooperative
(UEC)
Kootenai Electric Cooperative
Cowlitz County PUD
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Michigan Public Power Agency

Yes or No

Question 6 Comment

No

MPPA has several concerns about the new language in Inclusion 5. First, because
Reactive Power devices produce power, they are “power producing resources” and we
therefore believe Inclusion 5 is duplicative of Inclusion 4, which addresses “power
producing devices.”
Second, there is no capacity threshold specified in Inclusion 5 for Reactive Power
devices that would be considered part of the BES. This is inconsistent with the
approach taken in the balance of the definition, where thresholds are specified for
generators and other types of power producing devices.
Finally, MPPA believes the appropriate threshold for inclusion or exclusion of Reactive
Power devices from the BES should be subject to the same technical analysis that will
cover generators in the Phase 2 process. Without such analysis either: 1) no threshold
except for those connected at 100kV, or: 2) of .95 power factor of a 20 MVA
generator, or 6 MVAr and use the fact that most Facility Connection Requirements
require a power factor in the range of between 0.85 - 0.9 lagging to 0.9 - 0.95 leading
for a generator. Hence, a 20 MVA generator (the smallest to meet the registry
criteria) will need to absorb a minimum of 6 MVAr and use that as the technical
justification.

Response: The SDT added further clarifications to Inclusion I5 to address your concerns and those of others.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are
connected at 100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through
a transformer that is designated in Inclusion I1.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications
that would warrant a change from the current values that exist through the application of the definition today. These and similar
issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
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Yes or No

Question 6 Comment

aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values. No change made. .
Ontario Power Generation Inc.

No

OPG recommends that the wording of this inclusion be made clear that the BES
boundary extends to the Low Voltage terminals of the transformer, used in the
interface connection, and does not include the static or dynamic reactive power
source itself unless it is directly connected to the BES.

Response: The SDT refers the commenter to Inclusion I1 which addresses the situation presented here when used in
conjunction with Inclusion I5. No change made.
Metropolitan Water District of
Southern California

No

Inclusion 5 should be changed to be consistent with the core definition and to clarify
Reactive Power devices. Under I5, the additional phrase "or through a dedicated
transformer with a high side voltage of 100 kV or higher," appears to conflict with the
core definition's phrase "and Real Power and Reactive Power resources connected at
100 kV or higher". For example, if you have a device connected to a 69Kv system
which is used solely for an end-user's load, but the 69kv system is transformed up to a
115kV system, such device could be included as BES or you would have to define what
is meant by "dedicated. If Reactive Power is meant to agree with the definition under
NERC's Glossary of Terms, there should be consistency and less verbiage.
MWDSC also agrees with WECC's comment that there should be some minimum
threshold for Reactive Power devices similar to that identified for generating
resources in Inclusion 2.
MWDSC recommends that Inclusion 5 be changed as follows: I5 - "Reactive Power
devices dedicated to support the BES that are connected at 100kV or higher, or
through a transformer that is designated in Inclusion I1."

Response: The SDT does not believe that a contradiction exists. Proper application of the definition and inclusions (see
explanation of process immediately following) would seem to preclude the situation described by the commenter. No change
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Question 6 Comment

made.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify
the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between
BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected
at 100 kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term
Element is needed. Element as defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions
I2 – I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local
networks) should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion
I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion
I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
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Yes or No

Question 6 Comment

the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications
that would warrant a change from the current values that exist through the application of the definition today. These and similar
issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values. No change made.
The SDT does not believe this change provides additional clarity. No change made.
LCRA Transmission Services
Corporation

No

This inclusion conflicts with exclusion E4. Which one takes priority?

Duke Energy

No

Need to add the exception for exclusions under E1 or E3, and also reword to exclude
devices connected to a transformer winding less than 100 kV unless that is the only
connection to that winding. Suggested rewording of I5 : “Unless excluded under
Exclusions E1 or E3, static or dynamic devices dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage or 100 kV or higher, or through a transformer
winding less than 100 kV that is designated in Inclusion I1 if the winding does not have
any circuits or load connected to it.” This would eliminate having to include a
capacitor connected to the 69 kV winding of a three winding BES transformer such as
230/138/69 kV if that winding had other connections such as 69 kV circuits. The
voltage threshold of 100 kV and above should capture devices connected to 100 kV or

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Yes or No

Question 6 Comment
higher windings of transformers designated in Inclusion I1.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
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Yes or No

Question 6 Comment

Tacoma Power

No

Tacoma Power generally supports the intent of Inclusion I5 as currently written.
However, we believe the definition of the MVAr threshold level must be included in
the Phase 2 evaluation and should be determined in a similar manner to the generator
threshold that will be determined for I2.

Farmington Electric Utility
System

No

I5 should be modified to identify a minimum Reactive Power threshold for static or
dynamic devices. As drafted a 1 MVA device supplying or absorbing Reactive Power
that is connected at 100 kV or higher would be included in the BES.

MEAG Power

No

We feel that this inclusion should be limited to dynamic devices with an aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating) connected through a
common point.

Harney Electric Cooperative,
Inc.

No

HEC believes this inclusion should include a technically justified capacity limit on
reactive resources to warrant inclusion.

City of St. George

No

A reasonable minimum value for inclusion should be added. As presently written all
static or dynamic devices would be included in the BES regardless of size.

Tillamook PUD

No

While we agree that reactive devices of sizable capacity connected at 100 kV or higher
are needed for BES reliability, Tillamook PUD fails to see why this inclusion is needed
as they are already captured by the 100 kV threshold. We would propose instead to
eliminate this inclusion and substitute an exclusion for smaller capacity devices.

include or exclude an Element.

If the SDT really believes an inclusion for reactive devices is needed, we suggest the
SDT provide a technically justified capacity limit within the inclusion. In addition we
suggest also including the phrase “...unless excluded under Exclusion E1, E2 or E4”
similar to that in I1.

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Mission Valley Power

Yes or No

Question 6 Comment

No

Mission Valley Power - While we agree that reactive devices of sizable capacity
connected at 100 kV or higher are needed for BES reliability, Mission Valley Power fails
to see why this inclusion is needed as they are already captured by the 100 kV
threshold. We would propose instead to eliminate this inclusion and substitute an
exclusion for smaller capacity devices. If the SDT really believes an inclusion for
reactive devices is needed, we suggest the SDT provide a technically justified capacity
limit within the inclusion. In addition we suggest also including the phrase “...unless
excluded under Exclusion E1, E2 or E4” similar to that in I1. Please see the answer to
Q1 above Q10 below.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values. No change
made.
Consolidated Edison Co. of NY,
Inc.

No

Normally, static and dynamic devices supply Reactive Power (VARs) to or absorb VARs
from the surrounding system. By their nature, VARs do not travel far, e.g., miles. So,
VARs by their nature only produce local impacts. Please explain the meaning of the
phrase “dedicated to supplying or absorbing Reactive Power,” with emphasis on
explaining why the term “dedicated” was employed?
How does an Entity determine if a particular static or dynamic device is “dedicated” to
the BES? What Guidance documents can the BES SDT provide describing “dedicated”

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Yes or No

Question 6 Comment
static and dynamic devices?

Response: The word 'dedicated' was used to identify those Elements whose sole purpose is supplying or absorbing Reactive Power.
The language limits those devices dedicated to voltages at 100 kV and higher (via the core definition or through Inclusion I5),
unless it can be excluded via Exclusion E4.
American Electric Power

No

I5 only specifies voltage limits, and makes no mention of reactive limits. We suggest
that the drafting team consider adding reactive capacity to these criteria as well.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values. No change
made.
South Houston Green Power,
LLC

No

The phrase should be added at the end “unless excluded under Exclusion E4”.

National Grid

No

We see some potential conflicts between this inclusion and the exclusions. Without
some additional wording, it seems like some devices that are in a Local Distribution
Network would be considered BES. In addition, reference to a transformer in Inclusion
I1 is not necessary since the definition includes “all Transmission Elements operated at
100 kV”, thus by definition and I5, those connected to 100 kV and higher are already
included. We suggest: Static or dynamic devices dedicated to supplying or absorbing
Reactive Power that are connected at 100kV or higher unless the device is in an area
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Question 6 Comment
excluded from BES by Exclusion E1 or E3, or through a dedicated transformer with a
high-side voltage of 100kV or higher, unless excluded by Exclusion E4.

Orange and Rockland Utilities,
Inc.

No

Should also mention "unless excluded under Exclusion E1 or E3".

The Dow Chemical Company

No

The phrase “or through a dedicated transformer with a high-side voltage of 100 kV or
higher” is inconsistent with I1 and would bring Reactive Power Equipment that is
lower than 100Kv into the BES definition. This phrase should be deleted.
The following phrase should be added at the end “unless excluded under Exclusion
E4”.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
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Yes or No

Question 6 Comment

exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element. No change made.
Hydro-Quebec TransEnergie

No

Response: Without specific comments the SDT is unable to respond.
Northern Wasco County PUD

No

While we agree that reactive devices of sizable capacity connected at 100 kV or higher
are needed for BES reliability, Northern Wasco County PUD fails to see why this
inclusion is needed as they are already captured by the 100 kV threshold. We would
propose instead to eliminate this inclusion and substitute an exclusion for smaller
capacity devices. If the SDT really believes an inclusion for reactive devices is needed,
we suggest the SDT provide a technically justified capacity limit within the inclusion. In
addition we suggest also including the phrase “...unless excluded under Exclusion E1,
E2 or E4” similar to that in I1.
Please see the answer to Q1 above Q10 below.

Central Lincoln

No

While we agree that reactive devices of sizable capacity connected at 100 kV or higher
are needed for BES reliability, Central Lincoln fails to see why this inclusion is needed
as they are already captured by the 100 kV threshold. We would propose instead to
eliminate this inclusion and substitute an exclusion for smaller capacity devices.If the
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Yes or No

Question 6 Comment
SDT really believes an inclusion for reactive devices is needed, we suggest the SDT
provide a technically justified capacity limit within the inclusion.
In addition we suggest also including the phrase “...unless excluded under Exclusion
E1, E2 or E4” similar to that in I1. Please see the answer to Q1 above Q10 below.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values. No change
made.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
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Yes or No

Question 6 Comment

specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element. No change made.
Please see detailed responses to Q1 and Q10.
Ameren

No

a)Only those Reactive Power devices applied for the purpose of BES support or BES
voltage control should be included. A Reactive Power device connected at >100kV but
used for the purpose of voltage support to local load and/or needed to support local
networks should be excluded.
b)We believe that this inclusion should be limited to dynamic devices with an
aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
connected through a common point.
c)See the response to question 2: The inclusion is unclear since it includes a certain
voltage transformers, but excludes those that have E1 or E3 Exclusion criteria. Each
exclusion criteria has multiple stipulations to its applicability, and then has a final
inclusive reference to I3. Please make the wording exact and not dependent on
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Question 6 Comment
clausal statements.

Response: a) The SDT believes that the proper application of the core definition with Inclusion i1 and I5 plus the application of
Exclusions E1, E3, and E4 will cover the situation described in most applications. In the event that the BES definition incorrectly
designates an Element as BES that is not necessary for the reliable operation of the interconnected transmission network or an
Element as non-BES that is necessary for the reliable operation of the interconnected transmission network, the Rules of
Procedure exception process may be utilized on a case-by-case basis to either include or exclude an Element. No change made.
b) The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications
that would warrant a change from the current values that exist through the application of the definition today. These and similar
issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values.
c) The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the
vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
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Yes or No

Question 6 Comment

application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element. No change made.
ExxonMobil Research and
Engineering

No

The BES SDT should work on clarifying the differences between Inclusion I5 and
Exclusion E4.
The phrase “solely for its own use” in Exclusion E4 is vague and open to interpretation.
It is unclear whether equipment, such as power factor correction facilities, surge
capacitors located in motor terminal boxes and excitation capacitors installed for use
by a motor located on the low side of a 138 kV primary transformer would be
excluded from the BES. Is the intent of this requirement to capture “reactive
resources” that provide VARs to the BES in regions that exhibit voltage stability issues?

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
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Yes or No

Question 6 Comment

non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element. No change made.
The BES definition is predicated on operations at 100 kV or higher. In the example cited, the equipment in question appears to
be below that threshold and thus is not included in the BES. No change made.
ATC LLC

No

ATC agrees with the inclusion provided the last clause is removed, as noted below.
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Organization

Yes or No

Question 6 Comment
The BES definition is intended to establish a bright line BES definition. The clause
“dedicated transformer” is undefined and unclear. Inclusion I5 -Static or dynamic
devices dedicated to supplying or absorbing Reactive Power that are connected at 100
kV or higher (deletion of remainder of clause).

Response: The SDT considered the disposition of the word “dedicated” and determined that retention of this word is necessary
to show the SDT’s intent that the conditions described by the inclusion are for configurations where the intended device is only
going through one transformation. No change made.
Westar Energy

No

We understand that I5 is being used to capture those devices other than generation
resources, but the language used leads us to believe that it could include all
generators that supply or absorb reactive power.
We also believe the language should be changed to be consistent with I1. We suggest
that I5 be changed to read: “Static or dynamic devices specifically used for supplying
or absorbing Reactive Power that are connected at 100 kV or higher, or through a
dedicated transformer with a high-side terminal operated at 100 kV or higher, or
through a transformer that is designated in Inclusion I1.”

Response: The SDT has clarified the wording of Inclusion I5 to address your concern.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are
connected at 100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through
a transformer that is designated in Inclusion I1.
The SDT does not believe your suggested wording provides additional clarity. No change made.
Florida Municipal Power
Agency

To help clarify and to avoid inclusion of de minimis reactive resources, we propose a
size threshold of 6 MVAr consistent with the smallest size generator included in the
BES at a 0.95 power factor, which is a common leading power factor used in Facility
Connection Requirements for generators. In other words, 6 MVAr is consistent with
typically the least amount of MVAr required to be absorbed by the smallest generator
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Yes or No

Question 6 Comment
meeting the registry criteria.

Redding Electric Utility

Yes

Redding believes that an appropriate MVAr level should be established during Phase
2.

City of Redding

Yes

Redding believes that an appropriate MVAr level should be established in during
Phase 2.

City of Austin dba Austin
Energy

Yes

Appropriate MVAr level should be established. Reactive resources should be treated
similar to generation criteria and included in the technical studies associated with the
Phase 2 technical analysis in order to establish the appropriate MVAr level included as
BES.

Sacramento Municipal Utility
District

Yes

However, appropriate MVAr level should be established. Reactive resources should be
treated similar to generation criteria and included in the technical studies associated
with the Phase 2 technical analysis in order to establish the appropriate MVAr level
included as BES.

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

No

There should be a limitation on what reactive components needs to be included. The
limits could be based on capacity of the units or on the voltage step that occurs upon
switching of the device

AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power

Yes

This inclusion should be limited to reactive devices 150 MVAR or greater (gross
aggregate nameplate rating) connected through a common point at the 200 kV level
or higher level.

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Question 6 Comment

Memphis Light, Gas and
Water Division

Yes

We are in general agreement with this inclusion, except that there is no threshold for
reactive resources as there is for generators and transformers. We recommend that a
minimum level be established for this equipment, such as 100 MVAr, or that studies
be conducted to determine an appropriate threshold.

Southern Company
Generation

Yes

We believe that the size of the reactive power resource should be considered as a key
factor to be part of BES. When considering generating resources, the size, e.g.,
greater than 75 MVA, was a key part of criteria to be included or excluded as BES. A
similar approach should be applied when considering reactive power resources.
Moreover, the language at the end of I5, "or through a transformer that is designated
in Inclusion I1," appears to be redundant since the reactive power resources are
connected to 100 kV or higher already without this additional language. The following
language is suggested: I5 - Static or dynamic devices dedicated to supplying or
absorbing Reactive Power that are connected at 100 kV or higher, or through a
dedicated transformer with a high-side voltage of 100 kV or higher, and with an
aggregate continuous nameplate rating greater than 30 MVA.

ACES Power Marketing
Standards Collaborators

Yes

We understand the SDT’s logic behind not setting any threshold values for reactive
resources during Phase 1 of this project. Ample time and effort should be given to
developing the technical justification behind such values. However, we encourage the
SDT to consider adding threshold values in Phase 2 of the project to provide even
more clarity to this inclusion.

Balancing Authority Northern
California

Yes

However, appropriate MVAr level should be established. Reactive resources should be
treated similar to generation criteria and included in the technical studies associated
with the Phase 2 technical analysis in order to establish the appropriate MVAr level
included as BES.

WECC Staff

Yes

WECC believes I5 should be modified to identify a minimum Reactive Power threshold

Cooperative

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Question 6 Comment
for static or dynamic devices similar to the threshold identified for generating
resources in I2. As worded, any size device dedicated to supplying or absorbing
Reactive Power that is conected at 100 kV or higher, no matter how small, would be
included in the BES.

Response: Using a threshold for inclusion of non-generator Reactive Power resource devices in the BES will be considered in Phase 2
of this effort. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values. No change made.
Springfield Utility Board

Yes

SUB agrees in general, but does not agree that ALL reactive resources should be
automatically included in the BES Definition. For example, is a local network (100 kV
or above), which is otherwise excluded, but has a reactive device used for power
factor correction (100 kV or above), still excluded? There are a significant number of
reactive resources that are used to serve systems that provide service primarily to
load, with either no or a minimal amount of generation. If this section is included, the
Exclusion language needs to be modified to exclude those reactive resources from the
BES that are radial serving only load or local networks that serve load (with less than
75MVa of generation).
SUB does not agree with the language referring to only those “retail customer”
reactive power devices for Exclusion E.4. This is too narrow and does not accurately
reflect the use of reactive power devices installed by registered entities when retail
customers do not “fix” their reactive power issues on their own. SUB recommends
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Question 6 Comment
that the language in I5 and E4 be consistent, and that “retail customer” should include
Registered Entities as well as end users. This present language is overly broad and,
absent modifications to the BES definition, will generate a significant amount of
paperwork. SUB suggests the following language change:I5 -Static or dynamic devices
dedicated to supplying or absorbing Reactive Power that:a)are connected at 100 kV or
higher and are not part of a radial system or area network that are excluded from the
BES, or;b)are connected through a dedicated transformer with a high-side voltage of
100 kV or higher and are not part of a radial system or area network that are excluded
from the BES, or;c)are connected through a transformer that is designated in Inclusion
I1 and are not part of a radial system or area network that are excluded from the BES .

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
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Organization

Yes or No

Question 6 Comment

The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element. No change made.
The SDT team considered the disposition of the word “retail” in the context of Inclusion I5, and determined that retention of this word
is important and correct. This is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the load
side of a customer meter). No change made.
FirstEnergy Corp.

Yes

While we do not object to I5, we question its need based on item I2 and believe I2 also
covers this item

Response: The SDT added further clarifications to Inclusion I5 to address your concern.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are connected at
100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through a transformer that
is designated in Inclusion I1.
Central Maine Power
Company

Yes

There is no such thing as “supplying or absorbing Reactive Power” but the intended
meaning is sufficiently clear since it is industry ‘shorthand’. We suggest an alternative
wording of: “Static or dynamic Reactive Power resources that are connected at 100
kV or higher, or...”

Rochester Gas and Electric
and New York State Electric
and Gas

Yes

There is no such thing as “supplying or absorbing Reactive Power” but the intended
meaning is sufficiently clear since it is industry ‘shorthand’. Suggest alternative
wording:”Static or dynamic Reactive Power resources that are connected at 100 kV or
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Yes or No

Question 6 Comment
higher, or...”

Response: The SDT elected to also include the word 'dedicated' in front of the quotation listed to identify those Elements whose sole
purpose is supplying or absorbing Reactive Power. Re-arranging the words as suggested would not capture the same effect. No
change made.
Portland General Electric
Company

Yes

Georgia System Operations
Corporation

Yes

Kansas City Power and Light
Company

Yes

Oncor Electric Delivery
Company LLC

Yes

Utility Services, Inc.

Yes

Independent Electricity
System Operator

Yes

PSEG Services Corp

Yes

ISO New England Inc

Yes

Manitoba Hydro

Yes

Long Island Power Authority

Yes

The provisions of Inclusion I5 fully address the concerns we expressed in our previous
comments.

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Organization

Yes or No

Puget Sound Energy

Yes

NV Energy

Yes

Z Global Engineering and
Energy Solutions

Yes

Central Hudson Gas and
Electric Corporation

Yes

City of Anaheim

Yes

Chevron U.S.A. Inc.

Yes

Idaho Falls Power

Yes

ReliabilityFirst

Yes

Exelon

Yes

Texas Industrial Energy
Consumers

Yes

Hydro One Networks Inc.

Yes

IRC Standards Review
Committee

Yes

Transmission Access Policy
Study Group

Yes

Question 6 Comment

The SDT has appropriately captured the necessary inclusion of high voltage
transmission reactive resources.

We have no comments.

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Organization

Yes or No

Electricity Consumers
Resource Council (ELCON)

Yes

Bonneville Power
Administration

Yes

Texas RE NERC Standards
Subcommittee

Yes

SERC Planning Standards
Subcommittee

Yes

NERC Staff Technical Review

Yes

BGE

Yes

Question 6 Comment

No comment.

Response: Thank you for your support.

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7.

The SDT has revised the specific exclusions to the core definition in response to industry comments. Do you agree with
Exclusion E1 (radial system)? If you do not support this change or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: Exclusion E1 is an exclusion for the contiguous transmission Elements connected at or above 100 kV.
Generation resources connected within the radial system are qualifiers for this exclusion.
The “single point of connection of 100 kV or higher” is where the radial system will begin if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the radial
system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the transmission line
will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker and a half bus
configuration could also be the beginning of the radial system and the owner of the bus would need to insure the reliability of the
substation.
Furthermore, the SDT believes that radial systems cannot have multiple connections at 100 kV or higher. Networks that have multiple
connections at 100 kV or higher may qualify for exclusion under Exclusion E3. The owner always has the option to seek exclusion
through the exception process.
The SDT considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that retention of this word – in
lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be included in the term
“Element”.

The SDT has determined that it should be conservative with regard to allowing exclusion for radial systems that are depended upon for
blackstart functionality, as these will arguably be more important to the reliable operation of the transmission system than equivalent
radial systems without blackstart resources.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “non-retail
generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is important to retain
this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation to be unfairly biased against
obtaining this exclusion.

Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of connected
(non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the interconnected
transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be consistent with the existing

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threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of further review under Phase 2
development of the BES definition.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not prevent the
owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is operated in the
normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in the normal operating
environment.
No changes were made to Exclusion E1 due to received comments.
Organization
NERC Staff Technical Review

Yes or No

Question 7 Comment

No

While we appreciate the improvement in the text for Exclusion E1, but we continue to
believe that E1 should require (i) the normally open switch must not be used to make
a parallel connection if the normally switch is operated at 100 kV or higher and
(ii) an automatic interrupting device that is part of the BES must be provided at the
point of interconnection between the radial system and the BES.

American Electric Power

No

AEP supports the concept of the exclusion of radial systems, however further
clarification is needed regarding whether or not the source equipment is included as
part of the radial system (for example, ring bus or breaker and a half bus
configurations).
Regarding the following text: “Note - A normally open switching device between radial
systems, as depicted on prints or one-line diagrams for example, does not affect this
exclusion.” We interpret this as not including two radial lines which could be tied
together through a normally open switch, are we correct? Additional clarity may be
needed regarding this note.

Response: Radial systems should be assessed with the normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch
is used in the normal operating environment. No change made.
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Organization

Yes or No

Question 7 Comment

The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the
radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial and the owner of the bus would need to insure the
reliability of the substation. No change made.
Northeast Power Coordinating
Council

No

E1 can be simplified by not dividing in three subsets of a, b and c. The end result is
that a Radial system is excluded if it does not have more than 75 MVA aggregate nonretail generation.
There seems to be an error with reference to I3. Black start unit paths are not
designated as BES and were taken out in this version under I3 so E1 and E3 should not
reference I3. This contradicts the radial or LN exclusion from I3. Suggest deleting the
reference to I3 in E1 and E3 because this reference is in contradiction to I3. I3 does
not require a path to be BES, but it implied that a radial cannot be excluded if there is
a black start unit on the radial.
Further clarification is needed to the language in the Note referring to the “Normally
Open switch”. The E1 reference Note should be re-worded to state “Radial systems
shall be assessed with all normally open switching devices in their open positions.”
Explanatory figures should be included to illustrate the system configurations
addressed. Black start unit paths must be considered in the construction of E1.
In E1c, what is meant by “non-retail”?

Response: The SDT believes that the distinction between Load only, generation only, and Load with generation provides a
bright-line exclusion for radial systems that is needed to cover all of the possible scenarios. No change made.
The SDT appreciates the suggestion that there could be an appearance of an inconsistency between Inclusion I3 and Exclusions
E1 and E3. The SDT has determined that it should be conservative with regard to allowing exclusion for radial systems that are
depended upon for blackstart functionality, as these will arguably be more important to the reliable operation of the
transmission system than equivalent radial systems without Blackstart Resources. No change made.
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Organization

Yes or No

Question 7 Comment

The SDT agrees that the radial systems should be assessed with all normally open (NO) switches in the open position and these
NO switches will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to
indicate the switch is operated in the normally open position; however, it is the owner and operator’s responsibility to indicate
how a switch is used in the normal operating environment.
Non-retail generation is the generation on the system (supply) side of the meter.
Consumers Energy

No

In general we agree, but believe the word "transmission" should be removed from "A
group of contiguous transmission Elements..."

Southwest Power Pool
Standards Review Team

No

Why was the defined term for “T”ransmission dropped in this version of the
definition? This should be kept in this version of the definition as well.

Response: The SDT team considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that
retention of this word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would
otherwise be included in the term “Element”. No change made.

Bonneville Power
Administration

No

BPA believes that a system left connected in a network configuration, via use of a
normally open switch for temporary network connection, without the protections
afforded through the standards that apply to BES should be limited to less than 24
hours.
BPA believes that the term “non-retail generation” in E1(c) should be clearly defined.
In addition, BPA believes that there needs to be a means to isolate the radial system
from the BES during a fault on the radial system by means of a automatic fault
interrupting device. Automatic fault interrupting device should be a defined term.

Response: The exclusion for radial systems does not provide requirements in the operating environment. Any attempt to hard
code time duration into the exclusion language will create any number of one off situations when applied on a continent-wide
basis. It is the owner and operator’s responsibility to indicate how a switch is used in the normal operating environment. No
change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “non226

Organization

Yes or No

Question 7 Comment

retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation to
be unfairly biased against obtaining this exclusion. No change made.

The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the
radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. No change made.
Dominion

No

Dominion does not agree that exclusion of a radial should be based upon the
aggregate capacity of generation. A radial serving only generation should be excluded
just as it is for load (as proposed by the SDT in 1a). No reliability gaps exist since the
owner and/or operator of generation (with an individual with gross individual or gross
aggregate nameplate rating per the ERO Statement of Compliance Registry Criteria)
must comply with applicable reliability standards.
Dominion requests that the SDT provide technical justification for E1a and E1b as it did
for E3, and explain the intent of the footnote in E1.

Response: The SDT believes that a limit on the aggregate amount of connected (non-retail) generation within the radial system
is necessary to ensure that there is no reliability impact on the interconnected transmission system; however, the threshold of
the allowable generation – 75 MVA – was chosen to be consistent with the existing threshold in the NERC Statement of
Compliance Registry Criteria, and this threshold is a subject of further review under Phase 2 of the BES definition. No change
made.
Exclusion E1.a is a retained exclusion form the existing definition and as such requires no technical justification at this time.
As for Exclusion E1.b, the SDT acknowledges and appreciates the comments and recommendations associated with modifications to
the technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
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Organization

Yes or No

Question 7 Comment

justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
The SDT believe that the radial systems should be assessed with all normally open (NO) switches in the open position and these
NO switches will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to
indicate the switch is operated in the normally open position; however, it is the owner and operator’s responsibility to indicate
how a switch is used in the normal operating environment.
Pepco Holdings Inc and
Affiliates

No

1) Additional clarification is needed on whether certain bus sections supplying radial
systems would be considered part of the BES. It is critical that the BES definition
address this issue, since it will define what transmission Protection Systems fall in
scope for PRC-004 and 005. One way to address this issue would be to add a qualifier
to Exclusion E1 that states, “if a radial system is supplied from a bus section in a
substation, then this bus section is considered part of the radial system and is not
considered part of the BES if the tripping of this bus section does not result in an
interruption to any BES facilities when the station is operating in its normal
configuration.”
2) Since the SDT deleted the inclusion of Black Start Cranking Paths in I3 then
reference to I3 in criteria E1b and E1c should also be removed. Limits on connected
generation should only be constrained by the 75MVA limit. In summary, delete the
phrase “not identified in Inclusion I3” from both Exclusions E1b and E1c.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial and the owner of the bus would need to insure
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the reliability of the substation. No change made.
The SDT appreciates the suggestion that there could be an appearance of an inconsistency between Inclusion I3 and Exclusions
E1 and E3. The SDT has determined that it should be conservative with regard to allowing exclusion for radial systems that are
depended upon for blackstart functionality, as these will arguably be more important to the reliable operation of the
transmission system than equivalent radial systems without Blackstart Resources. No change made.
Southern Company
Generation

No

Subpart (b) uses the term "generation resources" while subpart (c) uses the term
"non-retail generation", why are these different terms used?
Further, why is it important that the term "non-retail generation" is used in subpart
(c)? In addition, the SDT needs to clarify what the term "non-retail generation"
means. Is this what is commonly referred to as "customer owned" or "behind-themeter" generation?
The change in version 2 that removed the requirement that an excluded radial system
have an automatic interruption device at the single point of connection to the rest of
the BES creates a problem. Three-terminal circuits are common below 230 kV. The
"tapped portion" should not be left out of the BES since a fault on that portion takes
out the whole line. We propose this revised language in the first sentence on E1: “E1
- Radial systems: A group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher, where the connection has an automatic
interruption device,...”
Exclusion E1, subpart (c) uses the phrase "an aggregate capacity of ... less than or
equal to 75 MVA ...". Exclusion E3. subpart (a) provides that the local networks "do
not have an aggregate capacity of ... greater than 75 MVA ...". Why are these phrases
stated differently even though they appear to address the same resources?

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the
term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter.
It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation
to be unfairly biased against obtaining this exclusion.

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The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the
radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial and the owner of the bus would need to insure the
reliability of the substation. No change made.
The SDT believes that a limit on the aggregate amount of connected (non-retail) generation within the radial system is necessary
to ensure that there is no reliability impact on the interconnected transmission system; however, the threshold of the allowable
generation – 75 MVA – was chosen to be consistent with the existing threshold in the ERO Statement of Compliance Registry
Criteria, and this threshold is a subject of further review under Phase 2 of the BES definition. No change made.
IRC Standards Review
Committee

No

While we support the provisions of E1 in principle, we are seeking clarification to the
following issues. Does the connection voltage of generation referred to in E1.b affect
whether a radial system could be excluded under E1?
Please clarify the meaning of “non-retail” generation used in E1.c.

Response: Exclusion E1 is an exclusion for the contiguous transmission Elements connected at or above 100 kV. Generation
resources connected within the radial system are qualifiers for this exclusion. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term
“non-retail generation” in E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail
generation to be unfairly biased against obtaining this exclusion. No change made.
Hydro One Networks Inc.

No

Although we agree with the exclusion of radial systems, we believe that the reliability
of the interconnected transmission network should not be determined by the amount
of installed generation on the radial system. We believe that the generation limit is
restrictive and has little or no technical basis. It is not the size of a unit on the radial
system that should determine the reliability impact on the BES but more importantly
its location, configuration and system characteristics such as reliability must run unit.
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We believe that there is no reason to divide E1 in three subsets of a, b and c. The end
result is that a radial system is excluded if it does not have more than 75 MW of
aggregate non-retail generation. However, consistent with E2 we suggest replacing
"an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating)" with "a maximum net capacity of non-retail generation provided to
the BES of 75 MVA."
We suggest deleting the references to I3 in E1 and E3 because we believe that this
reference is in contradiction to I3 and probably an oversight and should be corrected.
I3 does not require path to be BES but it implies here that a radial system cannot be
excluded if there is a Blackstart unit on it.

Response: The SDT believes that the distinction between Load only, generation only, and Load with generation provides a
bright-line exclusion for radial systems that is needed to cover all of the possible scenarios. No change made.
Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
The SDT appreciates the suggestion that there could be an appearance of an inconsistency between Inclusion I3 and Exclusions
E1 and E3. The SDT has determined that it should be conservative with regard to allowing exclusion for radial systems that are
depended upon for blackstart functionality, as these will arguably be more important to the reliable operation of the
transmission system than equivalent radial systems without Blackstart Resources. No change made.
Southern Company

No

Subpart (b) uses the term "generation resources" while subpart (c) uses the term
"non-retail generation", why are these different terms used? Further, why is it
important that the term "non-retail generation" is used in subpart (c)? In addition, the
SDT needs to clarify what the term "non-retail generation" means. Is this what is
commonly referred to as "customer owned" or "behind-the-meter" generation?
The change in version 2 that removed the requirement that an excluded radial system
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have an automatic interruption device at the single point of connection to the rest of
the BES creates a problem. Three-terminal circuits are common below 230 kV. The
"tapped portion" should not be left out of the BES since a fault on that portion takes
out the whole line. We propose this revised language in the first sentence on E1: “E1
- Radial systems: A group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher, where the connection has an automatic
interruption device,...”Exclusion E1, subpart (c) uses the phrase "an aggregate capacity
of ... less than or equal to 75 MVA ...".
Exclusion E3. subpart (a) provides that the local networks "do not have an aggregate
capacity of ... greater than 75 MVA ...". Why are these phrases stated differently even
though they appear to address the same resources?

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the
term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter.
It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation
to be unfairly biased against obtaining this exclusion. No change made.
The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the
radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. No change made.
The SDT believes that a limit on the aggregate amount of connected (non-retail) generation within the radial system is necessary
to ensure that there is no reliability impact on the interconnected transmission system; however, the threshold of the allowable
generation – 75 MVA – was chosen to be consistent with the existing threshold in the ERO Statement of Compliance Registry
Criteria, and this threshold is a subject of further review under Phase 2 of the BES definition. No change made.
ReliabilityFirst

No

The term radial must be specifically defined in this application. ReliabilityFirst Staff
believes this to mean a true radial in the sense that an adverse impact by the radial
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Question 7 Comment
facilities does NOT affect or impact BES facilities.
In the first sentence the word “Element” is capitalized but “transmission” is not, we
believe both terms should be capitalized.
The phrase “single point of connection” should have guidance so that everyone
reading this definition reads the single point of interconnection the same. Some have
read this phrase to be a single substation, while others have read this phrase to be one
and only one line or supply (i.e. interconnection point), which is it?
The “Note” we disagree with. In any and all cases if there is any operation or use of
the BES, the facilities should be included. By the wording of this exclusion, one cannot
determine if taps (sections of line from a BES transmission line to a single substation)
are intended to be included in the BES or not. More specifically, where does the radial
facility begin and the BES end? This determination was clearer in the previous version
of the definition with the use of the language “...originating with an automatic
interruption device...”.

Response: The SDT team considered the disposition of the word “transmission” in the context of Exclusion E1, and determined
that retention of this word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the
generation that would otherwise be included in the term “Element”. No change made.
The “single point of connection of 100 kV or higher” is where the radial will begin, if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the
radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial and the owner of the bus would need to insure the
reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at 100 kV or
higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner always has the
option to seek exclusion through the exception process. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
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Question 7 Comment

in the normal operating environment. No change made.
Ontario Power Generation Inc.

No

Non-retail generation needs to be properly defined in the text of the exclusion.

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized
the term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the
retail meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local
networks with retail generation to be unfairly biased against obtaining this exclusion.
City of St. George

No

Radial systems should be excluded as generally outlined in E1, however the generation
levels (of 75 MVA) are too restrictive. The primary criteria should be, does power flow
into the radial system? If there is always flow into the radial system, generation levels
should not prevent exclusion from the BES.

City of Anaheim

No

The City of Anaheim recommends either changing the E1 (b) language back to that of
the previous BES definition draft, i.e. 75 MVA or above connected at 100 kV or above,
or limit the amount of generation allowed within a Radial Element or Local Network to
300 MVA or less, which is the amount of uncontrolled load loss that constitutes a
reportable "disturbance" pursuant to EOP-004 and DOE Form OE-417. If DOE and
NERC do not consider a 300 MW uncontrolled loss of load a reportable event, then
why would the potential loss of a 75 MVA of non-critical generator connected at 69 kV
make a Radial Element or Local Network critical to the reliability of the BES? The
current ERO Statement of Compliance Criteria does not require GO/GOP registration
for generation connected below 100 kV as long as it's not critical to the reliability of
the BES, i.e. black start, etc., even if the amount of generation is greater than 75 MVA.
There is good reason for this because the mere loss of 75 MVA generator would not
affect the reliability of a system as big as the Western Interconnection, at all, and a
fault at say 69 kV would have sufficient impedance not to affect the BES from an
electrical perspective.

Response: Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate
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Question 7 Comment

amount of connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on
the interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the NERC Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
Xcel Energy

No

Xcel Energy believes that some more definition is required to clarify the intent of the
note under Exclusion E1 related to normal open switching device. A direct statement
would remove any ambiguity, such as “a normally open switch in a system that could
be interconnected or experience loop flows will be considered (BES/non BES)”.

Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch
is used in the normal operating environment. No change made.
Northern Wasco County PUD

No

Northern Wasco County PUD notes that a new term has been introduced, “non-retail
generation,” with no definition provided. The answer to the question on this during
the 9/28 webinar indicated that non-retail generation was behind the retail
customer’s meter. We can see no reason why the net-metered PV systems should
count toward the aggregate limit (exceeding the limit means no exclusion) while a
non-blackstart thermal plant doesn’t (the radial system is excluded if any amount of
load is present). We have also heard the SDT meant just the opposite of what was
stated in the webinar. We ask that a reasonable definition for non-retail be provided
within the BES definition document.
We strongly agree that radial systems should be excluded and that the presence of
normally open switching devices between radial systems should not cause them to be
considered non-radial. Such a result would cause the removal of these devices to the
detriment of the local level of service. We note that the singular “A normally open
switching device” is used and suggest that an allowance be made for the possibility of
multiple devices. “Normally open switching devices...”
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Question 7 Comment

LCRA Transmission Services
Corporation

No

The current wording is unclear with respect to the treatment of normally open
switching devices. LCRA TSC suggests the following language to replace the existing
language on the note to E1: “Two radial systems connected by a normally open,
manually operated switching device, as depicted on prints or one-line diagrams for
example, may be considered as radial systems under this exclusion.” The current
wording is unclear with respect to “non-retail generation”. The sudden loss of large,
radial-supplied load may result in reliability deficiencies. LCRA TSC suggests stating a
load level or a load capacity in the exclusion.

Tillamook PUD

No

Tillamook PUD notes that a new term has been introduced, “non-retail generation,”
with no definition provided. The answer to the question on this during the 9/28
webinar indicated that non-retail generation was behind the retail customer’s meter.
We can see no reason why the net-metered PV systems should count toward the
aggregate limit (exceeding the limit means no exclusion) while a non-blackstart
thermal plant doesn’t (the radial system is excluded if any amount of load is present).
We have also heard the SDT meant just the opposite of what was stated in the
webinar. We ask that a reasonable definition for non-retail be provided within the BES
definition document.We strongly agree that radial systems should be excluded and
that the presence of normally open switching devices between radial systems should
not cause them to be considered non-radial. Such a result would cause the removal of
these devices to the detriment of the local level of service. We note that the singular
“A normally open switching device” is used and suggest that an allowance be made for
the possibility of multiple devices. “Normally open switching devices...”

Mission Valley Power

No

Mission Valley Power notes that a new term has been introduced, “non-retail
generation,” with no definition provided. The answer to the question on this during
the 9/28 webinar indicated that non-retail generation was behind the retail
customer’s meter. We can see no reason why the net-metered PV systems should
count toward the aggregate limit (exceeding the limit means no exclusion) while a
non-blackstart thermal plant doesn’t (the radial system is excluded if any amount of
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Question 7 Comment
load is present). We have also heard the SDT meant just the opposite of what was
stated in the webinar. We ask that a reasonable definition for non-retail be provided
within the BES definition document.
We strongly agree that radial systems should be excluded and that the presence of
normally open switching devices between radial systems should not cause them to be
considered non-radial. Such a result would cause the removal of these devices to the
detriment of the local level of service. We note that the singular “A normally open
switching device” is used and suggest that an allowance be made for the possibility of
multiple devices. “Normally open switching devices...”

Central Lincoln

No

Central Lincoln notes that a new term has been introduced, “non-retail generation,”
with no definition provided. The answer to the question on this during the 9/28
webinar indicated that non-retail generation was behind the retail customer’s meter.
We can see no reason why the net-metered PV systems should count toward the
aggregate limit (exceeding the limit means no exclusion) while a non-blackstart
thermal plant doesn’t (the radial system is excluded if any amount of load is present).
We have also heard the SDT meant just the opposite of what was stated in the
webinar. We ask that a reasonable definition for non-retail be provided within the BES
definition document.
We strongly agree that radial systems should be excluded and that the presence of
normally open switching devices between radial systems should not cause them to be
considered non-radial. Such a result would cause the removal of these devices to the
detriment of the local level of service. We note that the singular “A normally open
switching device” is used and suggest that an allowance be made for the possibility of
multiple devices. “Normally open switching devices...”

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the
term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter.
It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation
to be unfairly biased against obtaining this exclusion. No change made.

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Question 7 Comment

Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used
in the normal operating environment. No change made.
BGE

No

During the previous comment period, BGE asked for clarification regarding the
exclusion of “radial facilities”. The particular example configuration in question
involved two 115 kV lines emanating from two different points of connection and
“tied” on the “low side” at 34.5 kV. The SDT responded that this was not a radial
facility but would be excluded under the E3-Local Network exclusion. BGE believes
that this particular configuration should be excluded under the E1-Radial Systems
exclusion. BGE does not beleive that two otherwise radial lines are made “non-radial”
because they are tied at a voltage lower than 100 kV.

Orange and Rockland Utilities,
Inc.

No

Please clarify on “single point of connection”. It seems like less confusion if “single
source” is used here instead of “single point of connection”.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
ISO New England Inc

No

The term “single point” is not clear. A better explanation is necessary. For example,
the same bus in a bus/branch model should suffice as a “single point”. There should
not be a requirement to be at the same node as found in a nodal model.
The term “a group of contiguous transmission elements” is ambiguous and needs to
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Question 7 Comment
be clarified.
The “Non-retail” qualifier in E1.c) should be deleted. It adds confusion to the
exclusion and is not defined.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
The SDT team considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that
retention of this word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation
that would otherwise be included in the term “Element”. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term
“non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail
meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks
with retail generation to be unfairly biased against obtaining this exclusion. No change made.
Kansas City Power and Light
Company

No

Nameplate rating of the generator is not a reflection of what can be actually injected
into the transmission system with resulting electrical impacts on transmission loading
and behavior. Recommend the BES definition be based on a generating resource(s)
established net accredited generating capacity instead of what it could do by
nameplate rating that may not be achievable. Recommend the following change to
the b) and c) parts of E1:b) Only includes generation resources not identified in
Inclusion I3 with an aggregate net accredited capacity less than or equal to 75 MVA.
Or, c) Where the radial system serves Load and includes generation resources not
identified in Inclusion I3 with an aggregate net accredited capacity of non-retail
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Question 7 Comment
generation less than or equal to 75 MVA.

Hydro-Quebec TransEnergie

No

Even with the modification proposed, it is too much restrictive to refuse exclusion of
radial system when they have generator or multiple generating units of aggregate
capacity greater than 75 MVA, especially when a system is able to function reliably
with the loss of generation much higher than this amount. To count on the exception
procedure to exclude radial system with greater generation is risky since no specific
criteria have been given to guide such exclusion. In most cases for radial or local
system including generation, the path that connects the generation should not be
included in the BES. Generators should be allowed to be considered "BES support
elements" and reliability standards should apply to them in specific.

Response: Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate
amount of connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on
the interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
Independent Electricity
System Operator

No

We support the provisions of E1 in principle but require clarification of some issues
and suggest alternative wording in some cases. It is unclear if the connection voltage
of generation referred to in E1.b affects whether a radial system could be excluded
under E1 although from the context it appears that it would. For clarity we suggest
appending “connected at 100 kV or higher.”
Please provide in the BES definition document an explanation of “non-retail” and
“retail” generation used in E1.c.
Additionally, despite the fact the revisions to Inclusion I3 (Blackstart Resources)
removed any reference to Cranking Paths, Exclusion 1 (b) and (c) both indicate that
the exclusion of a radial system would not be allowed if generation identified in I3
were connected to it. This implies that the Cranking Path for this Blackstart Resource
would have to be BES. This appears to be an inconsistency. We suggest removing the
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Question 7 Comment
phrase “not identified in Inclusion I3” in both instances.
We disagree with notion that the capacity of generation connected to a radial system
ought to determine whether that radial system should be classified as BES. Firstly, it is
a given that the generation connected to the subject radial that meets the registry
criteria would already be captured within the core BES definition and Inclusion I2. The
function served by a radial that is of importance in the current context is that of
delivering surplus power to the rest of the bulk power system and so, the impact on
the BES of loss of the radial system or its connected generation needs to be
considered. In our view, the “BES-status” of the radial itself is immaterial and so too is
the aggregate capacity of generation resources connected to it. Detailed arguments
regarding impact on the BES can be made in support of an application for an exclusion
under the Exception Process, but it would be beneficial to avoid unnecessarily
including a radial merely because it has more than 75 MVA of qualifying generation
connected to it, without equal consideration of the connected load. To put a “bright
line” on the consideration of impact referred to above, we suggest: In E1 (b): Replace
"an aggregate capacity less than or equal to 75 MVA (gross nameplate rating)" with "a
net capacity provided to the BES of less than or equal to 75 MVA." In E1 (c): Replace
"an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating)" with "a net capacity of non-retail generation provided to the BES of
75 MVA."This wording would be consistent with E2 (i).
Finally the word “affect” stated in the note accompanying E1 lends itself to misinterpretation. We therefore suggest the following revision to achieve greater
clarity:”This exclusion applies to radial systems connected by a normally open switch.”

Response: Exclusion E1 is an exclusion for the contiguous transmission Elements connected at or above 100 kV. Generation
resources connected within the radial system are qualifiers for this exclusion. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “nonretail generation” in ExclusionE1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation to

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Question 7 Comment

be unfairly biased against obtaining this exclusion. No change made.

The SDT appreciates the suggestion that there could be an appearance of an inconsistency between Inclusion I3 and Exclusions
E1 and E3. The SDT has determined that it should be conservative with regard to allowing exclusion for radial systems that are
depended upon for blackstart functionality, as these will arguably be more important to the reliable operation of the
transmission system than equivalent radial systems without Blackstart Resources. No change made.
Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
in the normal operating environment. No change made.
Central Maine Power
Company

No

E1 needs to be revised to make it less confusing. “Radial systems” leaves the
impression that E1 is not simply a “radial line exclusion”, because of the plural and the
word “systems.” Northeast industry expert colleagues are not clear what this sentence
specifies: “A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher.” o Does E1 apply only to a single radial
transmission line (and its associated “group of Elements”)? o Alternatively, does E1
apply to multiple radial lines “emanating from” the same substation regardless of the
bus configuration - would a ring bus or a two-bus system that is connected with a tie
breaker be considered as “a single point of connection”? o If the radial line is simply
tapped off a BES line without any automatic interruption device, should not the radial
line be included as part of the BES since a permanent fault on this radial line will take
out the BES line it is tapping off of? If the radial line is defined as part of the BES, it
could be subject to certain requirements such as vegetation management for
overhead lines. o Should not the exclusion include some description of the
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operational requirements to help resolve the ambiguity? As it is, the exclusion is
scenarios-based. When a specific scenario is overlooked, the oversight becomes a
source of ambiguity.This definition is not clear. Clarity is imperative.E1(c) should
define or replace the term “non-retail”. Industry needs clarity on exactly what
generation this clause applies to, in order to properly apply this definition. The Note
referring to the “Normally Open switch” needs further clarification. As written, it
seems to conflict with FERC order 743, paragraph 55:”While commenters would like to
expand the scope of the term “radial” to exclude certain transmission facilities such as
tap lines and secondary feeds via a normally open line, we are not persuaded that
such categorical exemption is warranted.” E1 should be restated as follows: “Radial
systems: A single transmission line or transformer not otherwise identified in the
Inclusions above, with a single point of connection of 100 kV or higher and: a) Only
serves Load. Or, b) Only includes generation resources, not identified in the Inclusions
above. Or, c) Both serves Load and only includes generation resources not identified in
the Inclusions above."

Rochester Gas and Electric
and New York State Electric
and Gas

No

E1 needs to be revised to make it less confusing. “Radial systems” leaves the
impression that E1 is not simply a “radial line exclusion”, because of the plural and the
word “systems.” Northeast industry expert colleagues are not clear at all what this
sentence specifies: “A group of contiguous transmission Elements that emanates from
a single point of connection of 100 kV or higher.” o Does E1 apply only to a single
radial transmission line (and its associated “group of Elements”)? o Alternatively,
does E1 apply to multiple radial lines “emanating from” the same substation
regardless of the bus configuration - would a ring bus or a two-bus system that is
connected with a tie breaker be considered as “a single point of connection”? This
definition is not clear. Clarity is imperative.
E1(c) should define or replace the term “non-retail”. Industry needs clarity on exactly
what generation this applies to, in order to properly apply this definition.
The Note referring to the “Normally Open switch” needs further clarification. As
written, it seems to conflict with FERC order 743, paragraph 55:”While commenters
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Question 7 Comment
would like to expand the scope of the term “radial” to exclude certain transmission
facilities such as tap lines and secondary feeds via a normally open line, we are not
persuaded that such categorical exemption is warranted.”
E1 should be restated as follows:”Radial systems: A single transmission line or
transformer not otherwise identified in the Inclusions above, with a single point of
connection of 100 kV or higher and: a) Only serves Load. Or, b) Only includes
generation resources, not identified in the Inclusions above. Or, c) Both serves Load
and only includes generation resources, not identified in the Inclusions above.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term
“non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail
meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks
with retail generation to be unfairly biased against obtaining this exclusion. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
in the normal operating environment. No change made.
The SDT does not believe that the suggested wording provides any additional clarity. No change made.
South Houston Green Power,
LLC

No

SHGP generally supports with the proposed revisions to Exclusion E1, but suggests
several additional clarifying revisions should be made. First, the phrase “a single point
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Question 7 Comment
of connection” in the introductory sentence should be revised to read “a single point
of connection (including multiple connections to the same ring bus or substation
where the energy normally flows in the same direction)”. This revision is intended to
ensure that radial systems which involve multiple parallel lines and are designed to
operate as a single radial system, but that nevertheless connect to the grid through
more than line for reliability.
Second, for this same reason, an additional (i.e., second) note should be added to the
end of Exclusion E1 that reads as follows: “Note, a normally closed switching device
that enables multiple lines emanating from the same grid ring bus or different grid
buses to operate as a single radial system does not affect this exclusion.”
Third, the phrase “with an aggregate capacity of non-retail generation less than or
equal to 75 MVA should be eliminated.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
in the normal operating environment. No change made.
Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
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Question 7 Comment

further review under Phase 2 of the BES definition. No change made.
Tacoma Power

Yes

Tacoma Power generally supports the Exclusion E1 as currently written. However, the
“note” at the end of E1 is confusing and can be interpreted inconsistently. We
recommend moving the language from the “note” to part of the exclusion as its own
section, as follows:(d) Normally-open switching devices between radial elements as
depicted and properly identified on system one-line diagrams should not be used to
deny this exclusion.
Additionally, we believe it is not appropriate for E1 to state an MVA threshold in
Section b) when determining such thresholds is the purpose for Phase 2. We urge the
SDT to defer the determination of a MVA threshold in E1 to Phase 2.

Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch
is used in the normal operating environment. No change made.
Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be consistent
with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of further review
under Phase 2 of the BES definition. No change made.
City of Austin dba Austin
Energy

Yes

For the E1 reference “Note,” we would benefit from additional clarification identifying
the treatment of a normally open switch and offer the following: “Radial systems shall
be assessed with all normally open switching devices in their open positions.”
The wording in Exclusion 1-c should more clearly reflect what is intended by using the
term “non-retail generation.”
Also, as with the technical justification for Inclusions I2 and I4, we recommend that
the generation threshold, i.e. gross nameplate values, be deferred to Phase 2.
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Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch
is used in the normal operating environment. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term
“non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail
meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks
with retail generation to be unfairly biased against obtaining this exclusion. No change made.
Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount
of connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
Ameren

Yes

a)We suggest the wording “non-retail generation’ should be clarified with an
explanation of why it is used in this exclusion.
b)This exclusion criterion has multiple stipulations to its applicability, and also has a
final inclusive reference to I3. Please make the wording exact and not dependent on
clausal statements.

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized
the term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the
retail meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local
networks with retail generation to be unfairly biased against obtaining this exclusion. No change made.
The SDT believes that the distinction between Load only, generation only, and Load with generation provides a bright-line
exclusion for radial systems that is needed to cover all of the possible scenarios. In addition, the SDT has determined that it
should be conservative with regard to allowing exclusion for radial systems that are depended upon for blackstart functionality,
as these will arguably be more important to the reliable operation of the transmission system than equivalent radial systems
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Question 7 Comment

without blackstart resources. No change made.
Utility Services, Inc.

Yes

Utility Services is very concerned that the "single point of connection" lacks clarity and
applications need to be identified.
Utility Services suggests that the SDT publish illustrative one-line diagrams to aid the
industry in determining when the designations are best applied.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does necessarily include an automatic interrupting device (AID). For example, the start
of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of
the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
Publishing diagrams will be considered in Phase 2.
PSEG Services Corp

Yes

1. If a 50 MVA generator that is included per I2 is connected to an excluded radial
system, would the generator be excluded or included per E1b)? If yes, then the
language “unless excluded under Exclusion E1 and E3” in I1 needs to be added to I2,
I4, and I5.
2. Non-retail generation in E1c) was described behind-the-meter generation in the
Webinar. The term “non-retail generation” should be defined because one could infer
that generation defined by E2 is “retail generation.”
Also, is the 75 MVA limit intended apply to the generator (as stated) or its net capacity
as defined in E2? If it means the generator MVA, does that mean that generation
excluded in E2 cannot exceed 75 MVA when connected to an excluded radial
system?3. In general, the definition needs to better define the impact that “exclusion”
has on a different “inclusion” or “exclusion.”
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Question 7 Comment

Response: Exclusion E1 is an exclusion for the contiguous transmission Elements connected at or above 100 kV. Generation
resources connected within the radial system are qualifiers for this exclusion. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “nonretail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation to
be unfairly biased against obtaining this exclusion. No change made.

Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be consistent
with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of further review
under Phase 2 of the BES definition. No change made.
Massachusetts Department of
Public Utilities

Yes

The aggregate 75 MVA of connected generation appears too low and would benefit
from additional technical justification.

Response: Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate
amount of connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on
the interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
The Dow Chemical Company

Yes

Dow generally agrees with the proposed revisions to Exclusion E1, but believes that
several additional clarifying revisions should be made. First, the phrase “a single point
of connection” in the introductory sentence should be revised to read “a single point
of connection (including multiple connections to the same ring bus or different buses
where the energy normally flows in the same direction)”. This revision is intended to
ensure that radial systems include arrangements involving multiple parallel lines that
are designed to operate as a single radial system, but that nevertheless connect at the
grid ring bus or different buses on the grid for reliability.
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Second, for this same reason, an additional (i.e., second) note should be added to the
end of Exclusion E1 that reads as follows: “Note, a normally closed switching device
that enables multiple lines emanating from the same grid ring bus or different grid
buses to operate as a single radial system does not affect this exclusion.”
Third, in “c),” the phrase “with an aggregate capacity of non-retail generation less
than or equal to 75 MVA (gross nameplate rating)” is confusing and potentially
inconsistent to the extent that “non-retail generation” may be different from “gross
nameplate rating.” The apparent intent of the clause is to exclude radial systems that
serve both load and generation, provided the generation capacity made available to
the transmission grid does not exceed 75 MVA. Dow would recommend that the
phrase be revised to read “where the net capacity provided to the transmission grid
does not exceed 75 MVA.” This revision would provide greater clarity and is
consistent with the language used in Exclusion E2.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
in the normal operating environment. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “nonretail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail
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Question 7 Comment

generation to be unfairly biased against obtaining this exclusion. No change made.
ExxonMobil Research and
Engineering

Yes

The removal of the requirement for an automatic fault interrupting device from this
requirement is a welcomed change from the first posting. This Exclusion helps
preserve the current NERC Registry and explicitly excludes many facilities used in the
distribution of electric power.

Long Island Power Authority

Yes

Need to clarify what is a "single point of interconnection" e.g. is it a bus section or a
substation

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start
of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker
and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to insure the
reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at 100 kV or higher.
Networks that have multiple connections at 100kV or higher may qualify under Exclusion E3. The owner always has the option to seek
exclusion through the exception process. No change made.
Manitoba Hydro

Yes

Manitoba Hydro agrees with E1 but the wording of the note regarding ‘normally open
switching devices’ is unclear. In the Industry Webinar on September 28th, the Drafting
Team made it clear that the note means that if an element can be connected to the
BES from multiple points but under normal operating conditions it is only connected
to the BES at a single point by means of normally open switches, then the element is
still excluded from the BES provided it meets either the E1 a, b, or c criteria. The team
also noted that the discretion to operate the normally open switching devices in the
best interests of reliability rests with the operating entity. Suggested wording:”Note:
The ability to connect a group of contiguous transmission Elements from multiple
connection points of 100kV or higher through normally open switching devices does
not negate this Exclusion. “

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Question 7 Comment
As well, part c) of E1 should be changed to “c) Only serves Load and includes...”

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not prevent
the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is operated in
the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used in the normal
operating environment. No change made.
ATC LLC

Yes

Unless there is a specific reason to the contrary, ATC suggests that Exclusion E1b
include the qualification of “aggregate capacity of non-retail generation less than or
equal to 75 MVA” to be consistent with the wording in E1c.

Puget Sound Energy

Yes

The language addressing generation resources in sections b and c of E1 could be more
clear (an example of clearer language is section a of E3). At the least, the language in
these two sections should be revised to read "... includes generation resources that
are not identified in Inclusion I3 and that do not have an aggregate capacity exceeding
75 MVA ...".

Response: Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate
amount of connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on
the interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
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NV Energy

Yes or No

Question 7 Comment

Yes

There may be an opportunity to consolidate the sub-items of E1 into a single inclusion
statement in order to simplify this exclusion designation. We propose the following
replacement option: “E1 - Radial systems: A group of contiguous transmission
Elements that emanates from a single point of connection of 100 kV or higher and
serves any combination of load and/or generation, provided that the generation
resources are not identified in Inclusion I3 and do not have an aggregate capacity of
non-retail generation greater than 75 MVA (gross nameplate rating).”

Response: The SDT believes that the distinction between Load only, generation only, and Load with generation provides a
bright-line exclusion for radial systems that is needed to cover all of the possible scenarios. No change made.
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)
Central Electric Cooperatve
(CEC)
Clearwater Power Company
(CPC)
Snohomish County PUD
Consumer's Power Inc.
Douglas Electric Cooperative
(DEC)
Fall River Rural Electric
Cooperative (FALL)
Lane Electric Cooperative

Yes

CLPD continues to support the radial system exclusion, which is necessary as a legal
matter, because, for example, FERC in Orders No. 743 and 743-A has required that the
existing radial exemption in the NERC Statement of Compliance Registry Criteria be
maintained. As a practical matter, radial systems are used for service to retail loads,
usually in remote or rural areas, and not for the transmission of bulk power. Hence,
operation of the radials has little or nothing to do with the reliable operation of the
interconnected bulk transmission network. We also support the inclusion of the note
discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of
this language, which is that a radial system should not be considered part of the BES if
it is interconnected at a single point, even if there is an alternative point of delivery
that is normally open. While we support the Exclusion for Radial Systems, we believe
several clarifications and refinements are necessary. (1) The term “transmission
Elements” in the initial paragraph should be changed to “Elements.” Radial systems
are not transmission systems and including the word “transmission” in the Radial
System exclusion is therefore unnecessary and confusing.
(2) Subparagraph (b) of Exclusion 1 refers to”generation resources . . . with aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating)”). We urge the SDT
to replace this language with the defined term “Qualifying Aggregate Generation
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(LEC)
Lincoln Electric Cooperative
(LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric Cooperative
(UEC)
Kootenai Electric Cooperative

Yes or No

Question 7 Comment
Resources,” discussed in more detail in our response to Question 3. This language, or
some equivalent, will preserve the SDT’s ability to revise the 75 MVA threshhold in
Phase 2, with the result of Phase 2 included in the BES Definition by operation rather
than requiring further revision of the Definition.
(3) Subparagraph (b) also seems to assume that if a Radial System contains a
generator exceeding the 75 MVA threshhold, the Radial System itself must be included
in the BES because it links the generator to the interconnected bulk transmission
system. As discussed more fully in our response to Question 9, below, NERC’s Project
2010-17 Standards Drafting Team and GO-TO Task Force have both concluded that
this assumption is unwarranted.
(4) The “Note” as drafted by the SDT indicates that “a normally open switching device
between radial systems” will not serve to disqualify the Radial from exclusion under
Exclusion 1. As noted above, CLPD strongly supports the note conceptually. However,
we believe this language should be included in a separate subparagraph (d), rather
than a note, because treatment as a “note” suggests it is less important than other
portions of the Exclusion. We also suggest the language be changed to read: (d)
Normally-open switching devices between radial elements as depicted and properly
identified on system one-line diagrams does not affect this exclusion.This will make
clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is
whether switches operating between Radials are normally open, not whether there is
more than one normally-open switch.

Response: 1) The SDT team considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that
retention of this word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that
would otherwise be included in the term “Element”. No change made.
2) Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be consistent
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Question 7 Comment

with the existing threshold in the NERC Statement of Compliance Registry Criteria, and this threshold is a subject of further review
under Phase 2 of the BES definition. No change made.
3) See response to Q9.
4) Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is
operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used in the
normal operating environment. No change made.
Michigan Public Power Agency

Yes

MPPA and its members continue to support the radial system exclusion, which is
necessary as a legal matter, because, for example, FERC in Orders No. 743 and 743-A
has required that the existing radial exemption in the NERC Statement of Compliance
Registry Criteria be maintained. As a practical matter, radial systems are used for
service to retail loads, usually in remote or rural areas, and not for the transmission of
bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. But we believe
that further clarification is necessary. First, the deletion of “originating with an
automatic interruption device” is a step in the right direction. However, “emanates
from a single point of connection” could be too narrowly interpreted (i.e., multiple
buses within a single substation could be viewed as multiple points of connection).
MPPA and its members proposes the following modification: “emanates from a single
substation connected to the BES at 100 kV or higher ...”. Entities whose only
connection emanates from a single substation and otherwise meet the BES definition
should not be denied exclusion under E1 solely because they connect to multiple
buses within a single substation. Additionally, adoption of “E3- Local Networks”
renders specious any argument that clams that connecting to multiple buses within a
single suvstation makes a material difference for reliability purposes since local
networks would have multiple connections anyway.
Additionally, it is not clear why it is necessary to include the note at the end of the
revised definition. (“A normally open switching device between radial systems, as
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Question 7 Comment
depicted on prints or one-line diagrams for example, does not affect this exclusion.”)
This rasies questions as to what “normally open” means, and wheither the only
evidence demonstrating what “normally open” means will be prints or one-line
diagrams. Further, it is not entirely clear what is meant by the language “does not
affect this exclusion”. If the note remains, it should be modified to read something
like, “a normally open switching device between radial systems does not prevent
application of this exclusion.”
Finally, the generation threshold limit in E1(b) and E1(c) should be revised as discussed
in response to Q1. Specifically, the proposed threshold of 75 MVA for this exclusion
should be raised to not lessd than 300 MVA in both E1(b) and E1 (c).

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
in the normal operating environment. No change made.
Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be consistent
with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of further review
under Phase 2 of the BES definition. No change made.

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NESCOE

Yes or No

Question 7 Comment

Yes

NESCOE suggests that the aggregate 75 MVA of connected generation is too low and
would benefit from additional technical justification. The threshold value should be
related to the largest contingency to which the applicable control area is designed to
operate. A level of 300 MVA would be appropriate. This 300 MVA limit represents
25% of the 1200 MVA loss of source that is typically assumed for operation of the
Northeast portion of the Eastern Interconnection. Depending on system conditions,
this number may be as high as 1500 MVA. Therefore, the suggested value of 300 MVA
has a technical basis and falls well within typical loss of source expectations for the
Northeast.

Response: The SDT believes that a limit on the aggregate amount of connected (non-retail) generation within the radial system
is necessary to ensure that there is no reliability impact on the interconnected transmission system; however, the threshold of
the allowable generation – 75 MVA – was chosen to be consistent with the existing threshold in the ERO Statement of
Compliance Registry Criteria, and this threshold is a subject of further review under Phase 2 of the BES definition. No change
made.
Z Global Engineering and
Energy Solutions

Yes

As stated in comment one. I recommend the Note is rewritten: "Note - A normally
open switching device between radial systems, as depicted on prints or oneline
diagrams, for example, does not classify the two or more radial lines as a loop line.
The exclusion will still apply."

Harney Electric Cooperative,
Inc.

Yes

HEC strongly agrees that radial systems should be excluded from the BES and that the
presence of a normally open switching device between radial systems should not
cause them to be considered non-radial

PacifiCorp

Yes

: The note in E1 as written is ambiguous and requires clarification. PacifiCorp assumes
the note means that two radial systems separated by a normally open switching
device allows for the exclusion of both radial systems. PacifiCorp recommends that
the SDT revise the note to serve as a paragraph clarifying E1 that, “Radial systems
separated by normally open switching device(s) as depicted on prints or one-line
diagrams for example, and operated in the normally open position, except during
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Question 7 Comment
abnormal operating conditions, qualifies both radial systems under this exclusion.”

Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch
is used in the normal operating environment. No change made.
Texas Industrial Energy
Consumers

Yes

As noted in response to Question 3, above, Exclusion E1 would only allow exclude
radial systems with “aggregate capacity of non-retail generation less than or equal to
75 MVA (gross nameplate rating).” The reference to “non-retail” generation in
subsection (c) indicates that the SDT may have intended to preserve the “netting”
approach set forth in the Statement of Registry Compliance, but this should be made
clearer. The description in subsection (c) should be revised to exclude “Where the
radial system serves Load and includes generation resources not identified in
Inclusions I2 or I3,” and the remainder of that sentence referencing a 75 MVA gross
nameplate rating should be removed. This will provide a reference back to the
Statement of Registry Compliance and clarify that only net capacity is considered for
customer-owned facilities.

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized
the term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the
retail meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local
networks with retail generation to be unfairly biased against obtaining this exclusion. The SDT believes that a limit on the
aggregate amount of connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability
impact on the interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen
to be consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject
of further review under Phase 2 of the BES definition. No change made.
Holland Board of Public Works

Yes

Holland BPW supports the exclusion of radial systems from the BES definition, but
believes that further clarification is necessary. First, the deletion of “originating
with an automatic interruption device” is a step in the right direction. However,
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Question 7 Comment
“emanates from a single point of connection” could be too narrowly interpreted (i.e.,
multiple buses within a single substation could be viewed as multiple points of
connection). Holland BPW proposes the following modification: “emanates from a
single substation connected to the BES at 100 kV or higher...” Entities whose only
connection emanates from a single substation and otherwise meet the BES definition
should not be denied exclusion under E1 solely because they connect to multiple
buses at that single substation. Additionally, adoption of “E3 - Local Networks”
renders specious any argument that claims that connecting to multiple buses within a
single substation makes a material difference for reliability purposes since local
networks would have multiple connections anyway.
Additionally, it is not clear why it is necessary to include the note at the end of the
revised definition. (“A normally open switching device between radial systems, as
depicted on prints or one-line diagrams for example, does not affect this exclusion.”)
This raises questions as to what “normally open” means, and whether the only
evidence demonstrating what “normally open” means will be prints or one-line
diagrams. Further, it is not entirely clear what is meant by the language “does not
affect this exclusion”. If the note remains, it should be modified to read something
like, “a normally open switching device between radial systems does not prevent
application of this exclusion.”
Finally, the generation threshold limit in E1(b) and E1(c) should be revised as discussed
in response to Q1. Specifically, the proposed threshold of 75 MVA for this exclusion
should be raised to not less than 300 MVA in both E1(b) and E1(c).

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
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Question 7 Comment

always has the option to seek exclusion through the exception process. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
in the normal operating environment. No change made.
The threshold of the allowable generation – 75 MVA – was chosen to be consistent with the existing threshold in the ERO Statement
of Compliance Registry Criteria, and this threshold is a subject of further review under Phase 2 of the BES definition. No change made.
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power
Cooperative

Yes

Remove “non-retail” because it is irrelevant to reliability.
In general, we agree with the remaining concepts. However transformer voltage
threshold should be 200 kV or higher, the power thresholds should be 150 MVA or
greater.

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the
term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail
meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with
retail generation to be unfairly biased against obtaining this exclusion. No change made.
The SDT believes that a limit on the aggregate amount of connected (non-retail) generation within the radial system is necessary to
ensure that there is no reliability impact on the interconnected transmission system; however, the threshold of the allowable
generation – 75 MVA – was chosen to be consistent with the existing threshold in the NERC Statement of Compliance Registry Criteria,
and this threshold is a subject of further review under Phase 2 of the BES definition. No change made.
Electricity Consumers

Yes

ELCON supports the changes made from the first posting for both E1 and E3 (which
complements E1), as this will help maintain the status quo referred to in the
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Resource Council (ELCON)

Question 7 Comment
introductory text. We seek one clarification: Some large industrial customers that
operate in remote, rural locations provide distribution services to third parties (usually
on a pro bono basis) where the local utility (LSE) is unable or unwilling to serve. These
transactions, which are akin to “border-line sales” in utility parlance, are typically de
minimis relative to the Load of the entity that delivers the power. While the
distribution is at low voltages (less than 100 kV), the power may have been received
by the entity at a higher voltage. We seek affirmation by the SDT that such situations
are not precluded by Exclusion E1.

Response: This is a bright-line definition for the BES and Exclusion E1 can be used to exclude radial systems for the contiguous
transmission Elements connected at or above 100 kV and lower voltage systems are already excluded from the BES. The
definition does not draw a distinction between ownership or connection arrangements. Without an exact configuration it is
impossible for the SDT to comment further but if this situation somehow slips through the cracks, there is always the option to
seek an exception. No change made.
ACES Power Marketing
Standards Collaborators

Yes

The term “non-retail generation” used in Exclusion E1 (item c) and again in E3 (item a)
should be clarified (see comments for question 8 below).
The Note after item c should also be clarified to indicate that closing a normally open
switch doesn’t affect this exclusion.

Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch
is used in the normal operating environment. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “nonretail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail
generation to be unfairly biased against obtaining this exclusion. No change made.
Sacramento Municipal Utility

Yes

For the E1 reference “Note,” we would benefit from additional clarification identifying
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District

Question 7 Comment
the treatment of a normally open switch and offer the following: “Radial systems shall
be assessed with all normally open switching devices in their open positions.”
The wording in Exclusion 1-c should more clearly reflect what is intended by using the
term “non-retail generation.”
Also, as with the technical justification for Inclusions I2 and I4, it is recommended that
the generation threshold, i.e. gross nameplate values, be deferred to Phase 2.

Balancing Authority Northern
California

Yes

For the E1 reference “Note,” we would benefit from additional clarification identifying
the treatment of a normally open switch and offer the following: “Radial systems shall
be assessed with all normally open switching devices in their open positions.”
The wording in Exclusion 1-c should more clearly reflect what is intended by using the
term “non-retail generation.”
Also, as with the technical justification for Inclusions I2 and I4, it is recommended that
the generation threshold, i.e. gross nameplate values, be deferred to Phase 2.

Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch
is used in the normal operating environment. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term
“non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail
meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks
with retail generation to be unfairly biased against obtaining this exclusion. No change made.
The SDT believes that a limit on the aggregate amount of connected (non-retail) generation within the radial system is necessary to
ensure that there is no reliability impact on the interconnected transmission system; however, the threshold of the allowable
generation – 75 MVA – was chosen to be consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria,
and this threshold is a subject of further review under Phase 2 of the BES definition. No change made.

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Florida Municipal Power
Agency
Transmission Access Policy
Study Group

Yes or No

Question 7 Comment

Yes

FMPA supports the exclusion of radial systems from the BES Definition. Such systems
are generally not “necessary for operating an interconnected electric transmission
network,” the standard in Orders 743 and 743-A. We have several suggestions to
clarify the proposed language for this Exclusion. Proposed Exclusion E1 refers to “[a]
group of contiguous transmission Elements that emanates from a single point of
connection of 100 kV or higher.” We appreciate the SDT’s clarification of the point of
connection requirement, but the term “a single point of connection” should be further
defined (more clearly than just by voltage), and should be generic enough to
encompass the various bus configurations. It is not the case, for example, that each
individual breaker position in a ring bus is a separate point of connection for this
purpose; in that situation, a bus at one voltage level at one substation should be
considered “a single point of connection.” Some examples of configurations that
should be considered a single point of connection for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf,
Examples 1-6.
Although the core definition (appropriately) refers to “Transmission Elements” (with a
capital “T”), proposed Exclusion E1 refers to “transmission Elements” (with a
lowercase “t”). To avoid confusion, either “Transmission” should be capitalized in
both locations, or the word “transmission” should simply be deleted from Exclusion
E1, leaving a “group of contiguous Elements.” We understand that the lack of
capitalization may have been a deliberate choice by the SDT in an attempt to avoid
confusion that SDT members believe exists in the Glossary definition. If the Glossary
definition of Transmission is unclear-which FMPA does not necessarily believe is the
case-the answer is not to simply abandon the Glossary definition in favor of an entirely
undefined term; it is to submit a SAR to improve the Glossary definition.
Exclusion E1(c) refers to “an aggregate capacity of non-retail generation less than or
equal to 75 MVA.” “Non-retail generation” is potentially ambiguous, because it could
be read as distinguishing between generation that will be sold at wholesale and
generation that is used by the retail provider to meet retail load. On the
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Question 7 Comment
understanding that the intent is in fact to describe generation behind the end-user
meter, sometimes referred to as “behind-the-second-meter generation,” we suggest
the following revision: “an aggregate generation capacity less than or equal to 75
MVA, not including generation on the retail customer’s side of the retail meter.”
Exclusion E1 concludes with a “Note”: “A normally open switching device between
radial systems, as depicted on prints or one-line diagrams for example, does not affect
this exclusion.” The Note should not specify the types of evidence required to prove a
normally open switch, and the phrase “as depicted on prints or one-line diagrams”
should be deleted. This phrase is equivalent to a “Measure” in a standard and should
not be embedded in the equivalent of a “Requirement.” Since the phrase only gives
an “example,” it does not in fact add anything to the Note, but may lead to confusion
over what sort of evidence is required.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start
of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker
and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to insure the
reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at 100kV or higher.
Networks that have multiple connections at 100kV or higher may qualify under Exclusion E3. The owner always has the option to seek
exclusion through the exception process. No change made.
The SDT team considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that retention of
this word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would
otherwise be included in the term “Element”. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “nonretail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail
generation to be unfairly biased against obtaining this exclusion. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not prevent
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Question 7 Comment

the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is operated in
the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in the normal
operating environment. No change made.
MRO NERC Standards Review
Forum (NSRF)

Yes

Unless there is a specific reason to the contrary the NSRF suggests that E1b include
the qualification of “aggregate capacity of non-retail generation less thatn or equal to
75 MVA” be added to be consistent with the wording in E1c.

MEAG Power

Yes

We suggest the wording “non-retail generation’ should be clarified with an
explanation of why it is used in this exclusion.

SERC OC Standards Review
Group

Yes

We suggest the wording “non-retail generation’ should be clarified with an
explanation of why it is used in this exclusion.

Consolidated Edison Co. of NY,
Inc.

Yes

Please define the term “non-retail generation.”

Tennessee Valley Authority

Yes

TVA suggests the wording “non-retail generation’ should be clarified with an
explanation of why it is used in this exclusion.

SERC Planning Standards
Subcommittee

Yes

The SDT needs to clarify what is meant by "non-retail generation." Is this what is
commonly referred to as "customer owned" or "behind-the-meter" generation?

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the
term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail
meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with
retail generation to be unfairly biased against obtaining this exclusion. No change made.
WECC Staff

Yes

The use of the word “affect” in the note may cause problems with interpretation by
users. WECC suggests replacing the term "affect" with “alter”.

Response: The SDT considered your comments and chose to leave the existing wording unchanged as it does not provide any
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Question 7 Comment

additional clarity.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not prevent
the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is operated in
the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in the normal
operating environment. No change made.
Westar Energy

Yes

Redding Electric Utility

Yes

City of Redding

Yes

Portland General Electric
Company

Yes

Farmington Electric Utility
System

Yes

Georgia System Operations
Corporation

Yes

Oncor Electric Delivery
Company LLC

Yes

National Grid

Yes

Cowlitz County PUD

Yes

Memphis Light, Gas and
Water Division

Yes

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Yes or No

Springfield Utility Board

Yes

Oregon Public Utility
Commission Staff

Yes

Metropolitan Water District of
Southern California

Yes

Duke Energy

Yes

Chevron U.S.A. Inc.

Yes

Central Hudson Gas and
Electric Corporation

Yes

Idaho Falls Power

Yes

FirstEnergy Corp.

Yes

Exelon

Yes

Tri-State GandT

Yes

Western Area Power
Administration

Yes

Tri-State Generation and
Transmission Assn., Inc.

Yes

Question 7 Comment
SUB supports a radial system exclusion.

This is very important exclusion for an entity operating in remote areas of the country
that provides distribution service to third parties where utilities are unable or
unwilling to serve. While the distribution is at a low voltage, the power was initially
received by the operating entity at a high voltage.

We support the exclusion as drafted.

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Question 7 Comment

Energy Management
Texas RE NERC Standards
Subcommittee

Yes

This is a much needed change from the first posting, as this will maintain the status
quo referred to in the introduction text.

Response: Thank you for your support.

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8.

The SDT has revised the specific exclusions to the core definition in response to industry comments. Do you agree with
Exclusion E2 (behind-the-meter generation)? If you do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: The majority of commenters are in agreement with Exclusion E2 but there were some requests for additional
clarification and the SDT responded by clarifying the language as shown below.
There were also questions raised about threshold levels in the exclusion. The SDT acknowledges and appreciates the comments and
recommendations associated with modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES
definition. However, the SDT has responsibilities associated with being responsive to the directives established in Orders No. 743 and
743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the
development of strong technical justifications that would warrant a change from the current values that exist through the application of
the definition today. These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to
address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System.
This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the
threshold values and provide compelling justification for modifications to the existing values.
Some commenters have questioned the reasoning behind Exclusion E2 (ii). Condition (ii) in Exclusion E2 is derived from FERC or
provincial regulations applicable to qualifying cogeneration and small power production facilities. For example, see 18 CFR §292.101 and
§292.305(b) for the requirements specific to the US. The SDT believes that condition (ii), which requires that the generation serving the
retail customer load self provide reserves, is essential for the integrity of the exclusion. This is not new ground and is simply clarifying
language that has been present in the ERO Statement of Compliance Registry Criteria for quite some time. The SDT believes that the
meaning of the definition will be understood in Balancing Authority Areas where it is applicable as it reflects existing practice.
Therefore, the SDT has declined to delete condition (ii).
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail customer
Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does not exceed 75 MVA,
and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple generating units or to the
retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator Operator, or
under terms approved by the applicable regulatory authority.

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Yes or No

Question 8 Comment

MEAG Power

No

Clarification needs to be provided for what is meant by E2 (ii), regarding generation on
the customer’s side of the retail meter; otherwise we have trouble developing a
position on this question.

SERC OC Standards Review
Group

No

Clarification needs to be provided for what is meant by E2 (ii), regarding generation on
the customer’s side of the retail meter; otherwise we have trouble developing a
position on this question.

Tennessee Valley Authority

No

Clarification needs to be provided for what is meant by E2 (ii), regarding generation on
the customer’s side of the retail meter; otherwise we have trouble developing a
position on this question.

ReliabilityFirst

No

It is not clear why “ii” is needed. If the net generation exceeds 75 MVA, then it is
included in the BES whether or not there are ancillary services provided for that
generation. Would customer owned generation less than a net of 75 MVA but greater
than 20 MVA be included in the BES if item ii was not met?

FirstEnergy Corp.

No

We suggest striking item "ii"

Dominion

No

Dominion supports exclusion for behind-the-meter generation, (if connected at >100
kV) if the load behind the meter (to which that generation is intended to support)
does not rely on generation outside that metered point for purposes of back-up
energy or any type of ancillary services at any time. The proposed language appears
to suggest that standby, back-up, and maintenance power services are always
required. There are alternative means to provide these services, such as reducing load
to match ‘reliability services’ provided by the available behind-the-meter generation.
Further, even if standby, back-up, and maintenance power services are always
required, the exclusion criteria obligation should be placed on the retail load, not the
generation outside the metered point

Response: Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying cogeneration and
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Question 8 Comment

small power production facilities. For example, see 18 CFR §292.101 and §292.305(b) for the requirements specific to the US. The
SDT believes that condition (ii), which requires that the generation serving the retail customer load self provide reserves, is
essential for the integrity of the exclusion. This is not new ground and is simply clarifying language that has been present in the
ERO Statement of Compliance Registry Criteria for quite some time. The SDT believes that the meaning of the definition will be
understood in Balancing Authority Areas where it is applicable. No change made.
Northeast Power Coordinating
Council

No

Why are references to Balancing Authority, Generator Owner, and Generator
Operator included in E2 which is part of the BES definition? The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in Section
III.c.4.

Response: The roles of the Balancing Authority, Generator Owner, and Generator Operator are implied in the ERO Statement of
Compliance Registry Criteria and the terms were added as the result of industry requests for clarification. No change made.
Southern Company

No

We suggest that clarification is needed for what is meant by E2 (ii), regarding
generation on the customer’s side of the retail meter.
Also, we would like for a clarification of the difference between the terms "retail load"
and "retail customer load" as used in exclusions E2 and E3.

Response: Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying cogeneration and small
power production facilities. For example, see 18 CFR §292.101 and §292.305(b) for the requirements specific to the US. The SDT
believes that condition (ii), which requires that the generation serving the retail customer load self provide reserves, is essential for
the integrity of the exclusion. This is not new ground and is simply clarifying language that has been present in the ERO Statement of
Compliance Registry Criteria for quite some time. The SDT believes that the meaning of the definition will be understood in Balancing
Authority Areas where it is applicable. No change made.
The SDT accepts your recommendation regarding “retail Load” and has clarified Exclusion E2 to read:
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail
customer Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does not
exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple
generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator
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Yes or No

Question 8 Comment

Owner or Generator Operator, or under terms approved by the applicable regulatory authority.
Southwest Power Pool
Standards Review Team

No

This number could change in phase two of the project which would create
unnecessary work in the future.

Farmington Electric Utility
System

No

E2 should be modified to include a size and threshold for individual generating units,
similar to that identified in I2. As currently worded E2 places the same threshold (75
MVA) on a single generating unit as is placed on multiple generating units.

Westar Energy

No

As expressed in our comment to question 5, we have concerns that the 75 MVA
number could change in phase two of the project, creating unnecessary work in the
future.

American Electric Power

No

It appears an entity with less than 75 MVA would not have been included as part of
the earlier inclusions. Is it necessary to note this threshold once again in the exclusion
section? Might it be possible to add some of the “behind the meter load” to the
inclusion section to reduce the amount of both the inclusions and exclusions? Doing
so would likely provide more clarity to the standard.

City of Anaheim

No

Again, 75 MVA should be increased to 300 MVA in E2 for the reasons stated in
response to Question 7.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
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Question 8 Comment

and provide compelling justification for modifications to the existing values. No change made.
City of St. George

No

Same basic comments and concerns as question #7.

No

Exclusion E2 is confusing as written and seems counter intuitive. As an example, a 400
MW generator which is behind the meter with a 400 MW load could be excluded. This
generator could have a significant impact on the performance of the system and yet it
is excluded. As a simple example, loss of the 400 MW generator would require that
the 400 MW load be supplied from the system, possibly leading to low voltages and
thermal overloads. Additionally, a machine of this size could adversely impact the
dynamic response of the system, leading to damping concerns or unit instability.

Response: See response to Q7.
ISO New England Inc

If E2 is to be retained, it is not clear under what load conditions should the load at the
facility be measured. Load levels, and resulting net flows to the system, can be
significantly different between seasons, time of day, and the status of end user
equipment at large industrial/manufacturing sites.
The term “Retail Customer Load” needs to be defined.
The Balancing Authority should not be included as an entity providing this service. In
general the Statement of Compliance Registry has provided the preferred language to
use here (Page 9, [Exclusions: second paragraph).
Response: The SDT believes that Exclusion E2 should be dedicated to the situation faced by behind-the-meter (i.e., retail customer
owned) generation that are PURPA qualifying facilities (in the US) (e.g., see 18 CFR Part 292 for the regulations that are applicable in
the US), and similarly situated generators in Canada. Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations
applicable to qualifying facilities. The SDT believes that condition (ii), which requires that the generation serving the retail customer
load self provide reserves, is essential for the integrity of the exclusion. No change made.
The roles of the Balancing Authority, Generator Owner, and Generator Operator are implied in the ERO Statement of Compliance
Registry Criteria and the terms were added to Exclusion E2 as the result of industry requests for clarification.
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Question 8 Comment

The SDT has clarified Exclusion E2 to read:
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail
customer Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does not
exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple
generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator
Owner or Generator Operator, or under terms approved by the applicable regulatory authority.
Central Maine Power
Company

No

E2 should be consistent with the Statement of Compliance Registry Criteria.
References to Balancing Authority, Generator Owner, and Generator Operator should
not be included in the BES definition. “Net capacity” is unclear - must flow never
exceed 75 MVA on an instantaneous or integrated hourly energy basis per either
design or operating experience? There is a potential for hundreds of MW to be
interconnected at a customer facility, with the “net capacity” (= flow into the
transmission system? Instantaneous? Annual average? On an integrated hourly basis
at any hour?) being less than 75 MVA - are hundreds of MW of generation “not
material” to BES reliability? The conditions under which direction of flow (i.e., “net
capacity”) is assessed are critical, but E2(i) is silent on this.In E2(ii), the “and”, “or”,
and “or” are not clear - what are the necessary terms of the referenced “binding
obligation” and what is an “applicable regulatory authority”? Are “standby” and “backup” and “maintenance” power services independently defined and provided by a GOP,
GO, or BA? Northeast industry expert colleagues do not understand the relevance of
E2(ii) to BES reliability.E2 should be restated as follows:”A generating unit or multiple
generating units that serve all or part of retail customer Load with electric energy on
the customer’s side of the meter if the flow to or from the BES can never exceeds 75
MVA."

Rochester Gas and Electric
and New York State Electric
and Gas

No

E2 should be consistent with the Statement of Compliance Registry Criteria.
References to Balancing Authority, Generator Owner, and Generator Operator should
not be included in the BES definition.
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Question 8 Comment
“Net capacity” is unclear - must flow never exceed 75 MVA on an instantaneous or
integrated hourly energy basis per either design or operating experience? There is a
potential for hundreds of MW to be interconnected at a customer facility, with the
“net capacity” (= flow into the transmission system? Instantaneous? Annual average?
On an integrated hourly basis at any hour?) being less than 75 MVA - are hundreds of
MW of generation “not material” to BES reliability? The conditions under which
direction of flow (i.e., “net capacity”) is assessed are critical, but E2(i) is silent on this.
In E2(ii), the “and”, “or”, and “or” are not clear - what are the necessary terms of the
referenced “binding obligation” and what is an “applicable regulatory authority”?
Are “standby” and “back-up” and “maintenance” power services independently
defined and provided by a GOP, GO, or BA?
Northeast industry expert colleagues do not understand the relevance of E2(ii) to BES
reliability.E2 should be restated as follows:”A generating unit or multiple generating
units that serve all or part of retail customer Load with electric energy on the
customer’s side of the meter if the flow to or from the BES never exceeds 75 MVA”

Response: The wording of (ii) is essentially the same as the wording on this topic in the ERO Statement of Registry Criteria which
has been in existence for several years and is well understood in the industry. Qualifying for Exclusion E2 will be determined the
same as every other inclusion or exclusion; there is nothing special about Exclusion E2 that separates it from the rest of the
definition. The roles of the Balancing Authority, Generator Owner, and Generator Operator are implied in the ERO Statement of
Compliance Registry Criteria and the terms were added to Exclusion E2 as the result of industry requests for clarification.
The SDT believes that Exclusion E2 should be dedicated to the situation faced by behind-the-meter (i.e., retail customer owned)
generation that are PURPA qualifying facilities (in the US) (e.g., see 18 CFR Part 292 for the regulations that are applicable in the
US), and similarly situated generators in Canada. Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations
applicable to qualifying facilities. The primary purpose of retail customer owned generation in the context of Exclusion E2 is the
integrity of steam production that supports a manufacturing process. The electrical load of that process does not exist without
steam.
The SDT believes that condition (ii), which requires that the generation serving the retail customer load self provide reserves (i.e.,
standby, backup and maintenance power), is essential for the integrity of the exclusion. These reserves maintain steam generation
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Question 8 Comment

and the load to sustain the manufacturing process. In the US, the terms and conditions of standby, backup and maintenance
services are defined and administered by State PSCs (i.e., the “applicable regulatory authority” in the US) subject to FERC oversight.
These services are provided under contract or tariff with GOs, GOPs or BAs in regions that do not have ISOs or RTOs, and provided
by ISOs and RTOs where so-called “organized markets” operate.
The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated,
and the residual (“net”) amount exported to the BES that was deemed relevant to the exclusion and reliability, not the nameplate
rating. The export is subject to the 75 MVA threshold; the requirement for reserves under a “binding obligation” (standby, backup
and maintenance power) matches part or all of the on-site load and is not subject to the threshold.
No change made.
LCRA Transmission Services
Corporation

No

Response: Without any specific comment, the SDT is unable to respond.
Kansas City Power and Light
Company

No

Any facilities that are customer owned regardless of size or configuration are not
under the jurisdiction or responsibility of the Registered Entity and should not be
considered as included with a Registered Entity.

Response: Exclusion E2 was based on the ERO Statement of Compliance Registry Criteria. No change made.
Ameren

No

a)If retail generation fails to meet (i) or (ii) it appears that the retail generation would
be included. The wording of (ii) is complex. Who will police this with retail behindthe-meter generators?
b)Clarification needs to be provided for what is meant by E2 (ii), regarding generation
on the customer’s side of the retail meter; otherwise we have trouble developing a
position on this question.

Response: The wording of (ii) is essentially the same as the wording on this topic in the ERO Statement of Registry Criteria which has
been in existence for several years and is well understood in the industry. Qualifying for the E2 Exclusion will be determined the same
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Question 8 Comment

as every other inclusion or exclusion; there is nothing special about Exclusion E2 that separates it from the rest of the definition.
Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying facilities. The SDT believes that
condition (ii), which requires that the generation serving the retail customer load self provide reserves, is essential for the integrity of
the exclusion. The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was
operated that was deemed relevant to the exclusion, not the nameplate rating. No change made.
Nebraska Public Power District

Yes

However the exclusion needs to be noted in I2, so as to non conflict with I2. (See
comment on #2 above.)

Response: Any retail generation that meets the criteria in Exclusion E2 is not in the BES so there is no conflict. No change made.
National Grid

Yes

We agree with this exclusion, but the intention of point (i), the net capacity provided
to the BES does not exceed 75 MVA, is not clear. We suggest this wording:”the net
capacity provided to the BES for 90% of the hours of the year does not exceed 75
MVA”.

Response: The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was
operated that was deemed relevant to the exclusion, not the nameplate rating. The threshold level for generators will be considered
in the Phase 2 review. No change made.
Utility Services, Inc.

Yes

Utility Services supports the comments offered by others suggesting that the language
be revised to be identical to the language in the SCRC.

Response: The SDT modified the language in response to industry requests for clarification. For example, the terms Balancing
Authority, Generator Owner, and Generator Operator are implied in the ERO Statement of Compliance Registry Criteria. No change
made.
South Houston Green Power,
LLC

Yes

SHGP generally agrees with the proposed revisions to Exclusion E2, but believes that a
clarifying revision should be made. Substitute “transmission grid” for “BES” in the
phrase “provided to the BES” to insure that the metering is to the grid.

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The Dow Chemical Company

Yes or No
Yes

Question 8 Comment
Dow generally agrees with the proposed revisions to Exclusion E2, but believes that a
clarifying revision should be made. Substitute “transmission grid” for “BES” in the
phrase “provided to the BES” to insure that the measurement is to the grid.

Response: The SDT believes that BES is the appropriate point of measurement because Exclusion E2 is defined in relation to the BES.
No change made.
Manitoba Hydro

Yes

Manitoba Hydro agrees with E2 but suggests that the phrase ‘A generating unit or
multiple generating units’ be replaced with ‘Generating resource(s)’ for clarity and
consistency.

Response: The SDT does not see where the suggested change will add any additional clarity. No change made.
Michigan Public Power Agency
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)
Central Electric Cooperatve
(CEC)
Clearwater Power Company
(CPC)
Snohomish County PUD
Consumer's Power Inc.
Douglas Electric Cooperative
(DEC)

Yes

MPPA and its members support the revised language. The language provides clarity
regarding the BES status of customer-owned cogeneration facilities. However, MPPA
and its members urge the SDT to remove the reference to the 75 MVA threshhold and
replace it with the defined term “Qualifying Aggregate Generation Resources” or some
equivalent language for the reasons stated in our responses to Questions 3, 5, and 7.
In addition, we are concerned that Exclusion 2 will place local distribution utilities in a
difficult position because, under Exclusion 1 or Exclusion 3 as drafted, they could lose
their status as a Radial System or a Local Network through the actions of a customer
constructing behind-the-meter generation, With respect to Radial Systems, the
appearance of behind-the-meter generators could cause the Radial System to exceed
the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no fault of
the Radial System owner. Similar, a Local Network could lose its status because
behind-the-meter generation could be of sufficient size that power moves into the
interconnected grid in certain hours or under certain contingencies, rather than
moving purely onto the Local Network, as required in subparagraph (b) of Exclusion 3.
The Exclusions for Radial Systems and Local Networks should be made consistent with
the Exclusion for behind-the-meter generation. There is no technical reason to believe
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Fall River Rural Electric
Cooperative (FALL)
Lane Electric Cooperative
(LEC)

Yes or No

Question 8 Comment
the power flowing from a behind-the-meter customer-owned generator will have less
impact on the bulk system than an equivalent-sized generator owned by a utility
operating a Radial System or LN.

Lincoln Electric Cooperative
(LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric Cooperative
(UEC)
Cowlitz County PUD
Kootenai Electric Cooperative
Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
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Yes or No

Question 8 Comment

technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
The thresholds in Exclusions E1 and E3 apply only to non-retail generators (i.e., generation on the system (supply) side of the retail
meter) and are not affected by presence of retail generation. No change made.
Massachusetts Department of
Public Utilities

Yes

While the MA DPU generally supports Exclusion E2, no information has been provided
by NERC demonstrating that the 75 MVA rating is based on any sound technical
analysis.

NESCOE

Yes

While NESCOE generally supports Exclusion E2, no information has been provided by
NERC demonstrating that the 75 MVA rating is based on any sound technical analysis.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values. No change made.
Texas Industrial Energy
Consumers

Yes

Please see the response to Question 3, above. Unlike exclusions E1 and E3, this
exclusion refers specifically to the “net capacity” provided, which is consistent with
existing treatment for generation that is netted against internal load under the
Statement of Registry Compliance.

Response: See response to Q3.
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AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power
Cooperative

Yes or No
Yes

Question 8 Comment
E2 “retail meter” should read “retail meter(s)”.
(i)
(ii)

Should be reworded as “the maximum net impact to the BES does not exceed
150 MVA, connected at 200 kV or higher.”
if we understand this clause correctly, we believe our proposed (i) wording will
handle the issue. Also, all load’s inclusion, within a BA, is dictated within the
BAL standards and so remove entirely or additional clarification is needed.

Response: It is accepted use in NERC Reliability Standards that singular words and terms apply to plural conditions as well. No change
made.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects
(i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being
responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012,
and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a
change from the current values that exist through the application of the definition today. These and similar issues have prompted the
SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory
authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for
inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC
Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide compelling
justification for modifications to the existing values.
Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying cogeneration and small power
production facilities. For example, see 18 CFR §292.101 and §292.305(b) for the requirements specific to the US. The SDT believes
that condition (ii), which requires that the generation serving the retail customer load self provide reserves, is essential for the
integrity of the exclusion. This is not new ground and is simply clarifying language that has been present in the ERO Statement of
Compliance Registry Criteria for quite some time. The SDT believes that the meaning of the definition will be understood in Balancing
Authority Areas where it is applicable. No change made.
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Southern Company
Generation

Yes or No

Question 8 Comment

Yes

Some editing is needed. The second part, (ii), of the and logic provided for the
exclusion criteria E2 is confusing. The initial criteria, (i), seems to be adequate
regarding impact to the BES. The criteria listed after "(ii)" does not seem to be
relevant to the impact on the BES. What does it mean to provide standby, back-up,
and maintenance power services to a generating unit or multiple generating units? It
is unclear who is providing the power service. If this is needed, the statement needs
to be simplified so it can be understood.
What is the difference between the terms "retail Load" and "retail customer Load" as
used in Exclusions E2 and E3?

Response: Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying cogeneration and small
power production facilities. For example, see 18 CFR §292.101 and §292.305(b) for the requirements specific to the US. The SDT
believes that condition (ii), which requires that the generation serving the retail customer load self provide reserves, is essential for
the integrity of the exclusion. This is not new ground and is simply clarifying language that has been present in the ERO Statement of
Compliance Registry Criteria for quite some time. The SDT believes that the meaning of the definition will be understood in Balancing
Authority Areas where it is applicable.
The SDT accepts your recommendation regarding “retail Load” and hasl clarified Exclusion E2 to read:
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail
customer Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does
not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple
generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator
Owner or Generator Operator, or under terms approved by the applicable regulatory authority.
ACES Power Marketing
Standards Collaborators

Yes

“A generating unit or multiple generating units that serve all or part of retail customer
Load with electric energy on the customer’s side of the retail meter” sounds a lot like
“non-retail generation” that is used in E1 and E3 which was described in the webinar
as generation that resides on the customer side of the retail meter and is used to
supply energy to that customer’s load and is owned by the customer. Is E2 assuming
that this generation is not owned by the customer?
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Question 8 Comment
Also, part ii) adds to the confusion. Conceptually we agree with this exclusion but
further clarification is preferred.

Response: Exclusion E2 does not apply to non-retail generation, which the SDT defines as generation on the system (supply) side of
the retail meter.
Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying cogeneration and small power
production facilities. For example, see 18 CFR §292.101 and §292.305(b) for the requirements specific to the US. The SDT believes
that condition (ii), which requires that the generation serving the retail customer load self provide reserves, is essential for the
integrity of the exclusion. This is not new ground and is simply clarifying language that has been present in the ERO Statement of
Compliance Registry Criteria for quite some time. The SDT believes that the meaning of the definition will be understood in Balancing
Authority Areas where it is applicable. No change made.
Bonneville Power
Administration

Yes

BPA believes that if E2 is intended to exclude behind-the-meter generation, the phrase
“on the customer’s side of the retail meter” should immediately follow “generating
units” in the first line. Otherwise, the phrase could be seen as modifying “retail
customer Load.”

Response: The SDT has clarified Exclusion E2 as suggested.
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail
customer Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does
not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple
generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator
Owner or Generator Operator, or under terms approved by the applicable regulatory authority.
WECC Staff

Yes

E2 is inconsistent with Section III.c. of the NERC Statement of Compliance Registry
Criteria and is in conflict with I2. As written, E2 uses a net capacity threshold of
75MVA, which does not distinguish between a single generating unit and multiple
generating units. The threshold in the NERC Statement of Compliance Registry Criteria
for a single generating unit is 20MVA. As a result, E2 would appear to exclude
generators from 20MVA to 75MVA that serve any amount of retail load behind the
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Yes or No

Question 8 Comment
meter. WECC recommends replacing “(i) the net capacity provided to the BES does
not exceed 75 MVA” with “(i) the net capacity provided to the BES does not exceed
the individual or gross nameplate ratings provided in the NERC Statement of
Compliance Registry Criteria.” WECC’s recommended change makes E2 consistent
with I2 and the SDT’s plan to address generator thresholds in Phase 2.

Response: Comments received on Inclusion I2 made it clear that industry did not want circular references in the definition so the SDT
has refrained from using the wording suggested here both in Inclusion I2 and Exclusion E2. The threshold levels of generators and the
relationship between the ERO Statement of Compliance Registry Criteria and the BES definition will be considered in the Phase 2
review. However, the SDT believes that a value was needed for Phase 1 and decided to proceed with the single 75 MVA threshold.
No change made.
ATC LLC

Yes

Portland General Electric
Company

Yes

City of Austin dba Austin
Energy

Yes

ExxonMobil Research and
Engineering

Yes

Northern Wasco County PUD

Yes

Georgia System Operations
Corporation

Yes

Oncor Electric Delivery
Company LLC

Yes

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Yes or No

Central Lincoln

Yes

Harney Electric Cooperative,
Inc.

Yes

PSEG Services Corp

Yes

Independent Electricity
System Operator

Yes

Long Island Power Authority

Yes

Mission Valley Power

Yes

Puget Sound Energy

Yes

Tillamook PUD

Yes

NV Energy

Yes

Oregon Public Utility
Commission Staff

Yes

Z Global Engineering and
Energy Solutions

Yes

Consumers Energy

Yes

Metropolitan Water District of
Southern California

Yes

Question 8 Comment

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Yes or No

Duke Energy

Yes

Chevron U.S.A. Inc.

Yes

Ontario Power Generation Inc.

Yes

Central Hudson Gas and
Electric Corporation

Yes

Idaho Falls Power

Yes

Exelon

Yes

PacifiCorp

Yes

Hydro One Networks Inc.

Yes

Tri-State GandT

Yes

Western Area Power
Administration

Yes

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

Yes

MRO NERC Standards Review
Forum (NSRF)

Yes

Question 8 Comment

This is a very important exclusion for Combined Heat and Power facilities that utilize
large amounts of steam and power, and secure and/or provide their own operating
reserves.

We support the exclusion as drafted.

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Organization

Yes or No

Question 8 Comment

IRC Standards Review
Committee

Yes

Pepco Holdings Inc and
Affiliates

Yes

Transmission Access Policy
Study Group

Yes

Electricity Consumers
Resource Council (ELCON)

Yes

Texas RE NERC Standards
Subcommittee

Yes

Florida Municipal Power
Agency

Yes

SERC Planning Standards
Subcommittee

Yes

Redding Electric Utility

Yes

City of Redding

Yes

Tacoma Power

Yes

Tacoma Power supports the Exclusion E2 as currently written.

BGE

Yes

No comment.

NERC Staff Technical Review

Yes

ELCON supports the proposed revisions to Exclusion E2.

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Question 8 Comment

Response: Thank you for your support. Due to other comments received, the SDT has made a slight clarifying change to Exclusion E2
as shown:
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail
customer Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does
not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple
generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator
Owner or Generator Operator, or under terms approved by the applicable regulatory authority.

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9.

The SDT has revised the specific exclusions to the core definition in response to industry comments. Do you agree with
Exclusion E3 (local network)? If you do not support this change or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: Commenters were generally supportive of the concept of the local network Exclusion E3 as proposed
in the second posting of the BES definition. The most prevalent comments, and the SDT’s response to those comments, were as
follows:
Several commenters suggested that the requirement under Exclusion E3.b should apply only during normal operating
conditions. In other words, commenters felt that some power flow should be allowed to flow from the candidate local network
back into the BES as long as it only occurred under abnormal conditions. To address this suggestion, the SDT considered the
addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, but determined that such a
qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. . However, the SDT
believes that, in circumstances where a local network is unable to utilize the local network exclusion solely because, under
abnormal system conditions power flows out of the network, the same network could be a suitable candidate for exclusion
under the Exception Process.
Numerous comments were received that either challenged the generator thresholds in Exclusion E3.a or suggested that the
Exclusion for local networks should be silent on generator thresholds until the question of appropriate generation thresholds is
addressed in Phase 2 of Project 2010-17. The SDT agrees that the threshold(s) for generation throughout the BES definition
should be addressed in Phase 2 of this effort. However, to satisfy to the Commission’s directives in Orders 743 and 743-A743-A
in a timely fashion, the SDT believes it is necessary to use a generation threshold that is consistent with the in-force ERO
Statement of Compliance Registry Criteria.
The SDT introduced the term “non-retail generation” in the E3 Exclusion, and a number of commenters questioned the SDT’s
understanding of the term. For the purpose of Exclusion E3 (and Exclusion E1), the SDT intends “non-retail generation” to mean
generation that is on the system (supply) side of the retail meter.
Numerous commenters suggested that the word “transmission” be removed from the phrase in the first paragraph of Exclusion
E3. The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word
– in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
included in the term “Element”.
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Several commenters expressed some confusion about Exclusion E3.b. Commenters felt that two separate and distinct ideas
were being addressed in Exclusion E3.b, and that the expression following the colon is expected to clarify the expression
preceding the colon. The SDT agrees that these two ideas are separate, but related. The SDT decided to revise Exclusion E3.b to
provide this clarity, as follows:
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;

This minor revision is clarifying only, and does not represent any material change to the Exclusion provision.
Organization

Yes or No

Question 9 Comment

SERC OC
Standards
Review Group

No

We would agree with the exclusion if the wording of the exclusion includes the following phrase (in
quotation marks) added at the end of E3 b): Power flows only into the LN: The LN does not transfer
energy originating outside the LN for delivery through the LN “under normal operating conditions”.

Tennessee
Valley
Authority

No

TVA would agree with the exclusion if the wording of the exclusion includes the following phrase (in
italics) added at the end of E3 b): “Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN under normal operating conditions; and”

MEAG Power

No

We would agree with the exclusion if the wording of the exclusion includes the following phrase (in
italics) added at the end of E3 b): Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN “under normal operating conditions”.

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition.
For those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power
to flow out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No
change made.
NERC Staff
Technical
Review

No

While we appreciate the improvement in the text of Exclusion E3, but we continue to believe that E3
should require automatic interrupting devices that are part of the BES must be provided at the points
of interconnection between the Local Network and the BES.

Response: The SDT considered the suggested requirement for separation of the LN via automatic fault interrupting devices during the
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Organization

Yes or No

Question 9 Comment

development of the language for the second posting, and determined that such a qualifier could not be enforced for facilities that are
not essential for the reliable operation of an interconnected transmission network. No change made.
Northeast
Power
Coordinating
Council

No

What is the technical justification for 300kv and higher?
Local Network is capitalized (network not capitalized at the beginning of E3) throughout E3, yet it is
not defined in the NERC Glossary.
The installed generation limit in a Local Network should be addressed in Phase 2.
Any studies supporting E3 should be made available.

Response: The threshold of 300 kV is used as a cap, not a minimum. Please refer to the companion document in the second posting
of the BES Definition under Project 2010-17 for a description of the technical justification for local network exclusion.
The term “local network” is not capitalized anywhere in the Exclusion E3 section of the definition except where it is placed as a section
title, and when abbreviated. The SDT understands that “local network” is not a NERC Glossary term.
The SDT agrees that the threshold(s) for generation throughout the BES definition should be addressed in Phase 2 of this effort;
however, to satisfy the Commission’s directives in Order 743 and 743-A in a timely fashion, it is necessary to use a generation
threshold that is consistent with the in-force Statement of Compliance Registry Criteria. No change made.
Please refer to the companion document in the second posting of the BES Definition under Project 2010-17 for a description of the
technical justification for local network exclusion.
Bonneville
Power
Administration

No

BPA has several concerns regarding Exclusion E3. First, BPA strongly believes that Exclusion E3 must
retain the requirement that the local network (LN) be separable from the BES by an automatic fault
interrupting device wherever the LN interconnects with the BES. BPA believes that this is necessary in
order to protect both the BES and the LN during faults, especially if there is any possibility that
backfeed could occur. BPA recommends retaining the original language: Separable by automatic fault
interrupting devices: Wherever connected to the BES, the LN must be connected through automatic
fault interrupting devices.
In addition, as stated in our comments in May, 2011, “automatic fault interrupting device” should be a
defined term.
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Question 9 Comment
BPA strongly believes that Exclusion E3 should not be allowed for any facilities above 200kV instead of
the 300kV limit in shown in the current proposal. Networks operated above 200kV have significant
fault duties, carry much more power, and have a greater potential for cascading if something does not
operate properly than networks operated below 200kV. Therefore, BPA believes that these networks
should be part of the BES.
BPA believes the term “non-retail generation” in E3(a) should also be defined.

Response: The SDT considered the suggested requirement for separation of the LN via automatic fault interrupting devices during the
development of the language of the second posting, and determined that such a qualifier could not be enforced for facilities that are
not essential for the reliable operation of an interconnected transmission network. No change made.
As the SDT does not propose the inclusion of the requirement for an automatic fault interrupting device, the definition of the term is
not necessary.
The threshold cap of 300 kV was a modification added for the second posting of the definition. The prior version of the definition had
no upper bound on operating voltage for the local network, and the SDT has now adopted a 300 kV upper limit pursuant to comments
received. Please refer to the technical justification document for local networks that accompanied the second posting under Project
2010-17 for details about the selection of 300kV as the cap for local networks. No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter. This is a well understood
interpretation which the SDT took from official literature and does not need to be officially defined.
ACES Power
Marketing
Standards
Collaborators

No

The term “non-retail generation” used in Exclusion E1 (item c) and again in E3 (item a) should be
clarified.
The following applies to E3 (item c): A flowgate should not be used to limit applicability of E3. First,
there is no definition for what constitutes a permanent flowgate. Second, flowgates are often created
for a myriad of reasons that have nothing to do with them being necessary to operate the BES. While
section c) in E3 attempts to limit the applicability to permanent flowgates, there is no definition for
what constitutes a permanent flowgate particularly since no flowgate is truly permanent. The NERC
Glossary of Terms definition of flowgate includes flowgates in the IDC. This is a problem because
flowgates are included in the IDC for many reasons not just because reliability issues are identified.
Flowgates could be included to simply study the impact of schedules on a particular interface as an
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Yes or No

Question 9 Comment
example. It does not mean the interface is critical. As an example, it could be used to generate
evidence that there are no transactional impacts to support exclusion from the BES. Furthermore, the
list of flowgates in the IDC is dynamic. The master list of IDC flowgates is updated monthly and IDC
users can add temporary flowgates at anytime. While the "permanent" adjective applied to flowgates
probably limits the applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month and removed
another. Flowgates are created for many reasons that have nothing to do with them being necessary
to operate the BES. First, flowgates are created to manage congestion. The IDC is more of a
congestion management tool than a reliability tool. FERC recognized this in Order 693, when they
directed NERC to make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs that
have been violated. Rather, other actions such as re-dispatch must be used in conjunction. Second,
flowgates are used as a convenient point to calculate flows to sell transmission service. The
characteristics of the flowgate make it a good proxy for estimating how much contractual use has
been sold not necessarily how much flow will actually occur. While some flowgates definitely are
created for reliability issues such as IROLs, many simply are not.

Response: Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT believes that the language in Exclusion E3.c prohibiting “Flowgates” from qualifying for definitional exclusion is appropriate
and necessary. As a definitional exclusion characteristic, Exclusion E3.c must follow the principle of being a bright-line and easily
identifiable, and as such, the SDT feels that the definition cannot allow some types of Flowgates and disallow others. Flowgates must
continue to be a prohibiting characteristic under Exclusion E3, since these facilities are more likely to be used in the transfer of bulk
power than not. An entity who wishes to make a case for exclusion of a unique type of Flowgate facility can do so through the
exception process. The SDT believes that the continued qualifier of “permanent” associated with the term “Flowgate” addresses the
majority of the concern in this comment. No change made.
Dominion

No

Dominion could support if E3a were eliminated.

Response: The SDT continues to believe that it is necessary to establish a limit on the allowable quantity of generation that may be
significant to the reliable operation of the surrounding interconnected transmission system. Please note that the issues surrounding
the appropriate generation threshold, among other topics, will be taken up in Phase 2 of this BES definition effort. No change made.
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Question 9 Comment

Pepco
Holdings Inc
and Affiliates

No

1) In the Drafting Teams Consideration of Comments on the previous version, it was stated, “....It is
not the SDT’s intent to specifically exclude any facilities in major metropolitan areas; it expects that
the specific examples mentioned (NYC, Washington DC) would not qualify for exclusion under the
revised Exclusion E3.” The currently proposed E3 will result in specific exclusion of major local
networks in major metropolitan areas. These major LNs qualify for exclusion under proposed E3, and
its qualifiers, in that they distribute power to the local load rather than act as facilities to transfer bulk
power across the interconnected system. However, the LNs that supply large amounts of load in very
dense load areas should have some transmission reliability considerations. To capture the
appropriate LNs in question, consideration should be given to limiting the amount of load supplied by
a LN to some load level. For example if an LN has a peak load level of less than 1,000MVA it would
qualify for LN exclusion and if it exceeds 1,000MVA it would not qualify for exclusion. There are
certainly many LNs that supply relatively small amounts of load, just as radial facilities. They should be
excluded. It is important to develop a load level that would provide the proper balance between the
small LNs and the major LNs.
2) Since the SDT deleted the inclusion of Black Start Cranking Paths in I3 then reference to I3 in
criteria E3a should also be removed. Limits on connected generation should only be constrained by
the 75MVA limit. Therefore E3a should then read “Limits on connected generation: The LN and its
underlying Elements do not include generation resources with an aggregate capacity of non-retail
generation greater than 75 MVA (gross nameplate rating);”

Response: The SDT appreciates your concern about the possible exclusion of large metropolitan load centers through the exclusion
for local networks in Exclusion E3. However, the SDT feels that it has accurately captured the characteristics of facilities that are used
in the local distribution of electric energy within Exclusion E3 (and Exclusion E1), which the Commission’s Order specifically targeted
for exclusion. To the suggestion of a 1,000 MW demand cap on the exclusion for local networks, the SDT sees no technical basis upon
which to make such a change. Also, the SDT is unaware of any situations of a network of facilities serving a load of that size that
would not be precluded in some way under at least one of the three characteristics of Exclusion E3. Finally, an Exception Process will
exist in the event that an entity seeks an inclusion of such facilities. No change made.
The SDT appreciates the suggestion that the elimination of the inclusion for Cranking Paths, while maintaining the qualifier prohibiting
blackstart resources from existing in a qualifying local network could be viewed as an inconsistency. Given that the concept of
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Question 9 Comment

exclusion of ‘local networks’ is already an issue requiring careful technical justification, the SDT has determined that it should be
conservative with regard to allowing such an exclusion for facilities that are depended upon for blackstart functionality, as these will
arguably be more important to the reliable operation of the transmission system than equivalent networks without blackstart resources.
It is nevertheless possible to achieve exclusion through the Exception Process. No change made.

Tri-State
Generation
and
Transmission
Assn., Inc.
Energy
Management

No

Tri-State
GandT

No

1. b) should be reworded to “Normally there is power flow only into the LN: The LN is not normally
used to transfer power originating outside of the LN for delivery through the LN.” There could be
conditions inside the LN, such as large loads shut down for maintenance, which would allow the
parallel transmission Elements to allow power to flow through the LN. Those conditions would have
no negative or adverse effect on the BES.
2. Capitalize “Network” at the beginning of the Exclusion
1. b) should be reworded to “Normally there is power flow only into the LN: The LN is not normally
used to transfer power originating outside of the LN for delivery through the LN.” There could be
conditions inside the LN, such as large loads shut down for maintenance, which would allow the
parallel transmission Elements to allow power to flow through the LN. Those conditions would have
no negative or adverse effect on the BES.2. Capitalize “Network” at the beginning of the Exclusion.

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For
those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow
out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
The word “network” as used in “local network” is not intended as a defined term; therefore, it is not capitalized. When expressed in
abbreviation, “LN” is properly capitalized. No change made.
MRO NERC
Standards
Review Forum
(NSRF)

No

THE NSRF suggestion considering a different approach for the power flow criteria in [E]3b. [E]3b: No
[Firm] Power Transfers are scheduled out of, or [through], the LN in the operating horizon [for BES
designations applicable to the operating horizon] and [no] Firm Power Transfers are reserved to flow
out of, or through, the LN in the planning horizon [for BES designations applicable to the planning
horizon].
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Question 9 Comment

Response: The SDT believes it is vital to ensure both that power flow is always in the direction from the BES toward the LN at all
points of connection, and that the LN facilities not be used for “wheeling” type transactions. The SDT believes the existing language
accomplishes this. The suggested language in this comment touches on an important aspect, the scheduled use of the facilities, but
the SDT believes that the existing language is more appropriate to express this point. No change made.
Hydro One
Networks Inc.

No

We agree with the exclusion concept of LN. However, the reliability of the interconnected
transmission network should not be determined by the amount of installed generation in the local
network. We believe that the generation limit is restrictive and has little or no technical basis. It is not
the size of a unit in the LN that will determine the reliability impact on the BES but more importantly
its location, configuration and system characteristics such as reliability must run unit. We suggest that
the SDT should address this in phase 2 to increase the installed generation limit in a LN.
We suggest deleting the references to I3 in E1 and E3 because we believe that this reference is in
contradiction to I3 and probably an oversight and should be corrected. I3 does not require a path to
be BES but it implies here that a radial system cannot be excluded if there is a Blackstart unit on it.

Response: The SDT agrees that the threshold(s) for generation throughout the BES definition should be addressed in Phase 2 of this
effort; however, to satisfy the Commission’s directives in Order 743 and 743-A in a timely fashion, it is necessary to use a generation
threshold that is consistent with the in-force Statement of Compliance Registry Criteria. No change made.
The SDT appreciates the suggestion that the elimination of the inclusion for Cranking Paths, while maintaining the qualifier prohibiting
blackstart resources from existing in a qualifying local network could be viewed as an inconsistency. Given that the concept of
exclusion of ‘local networks’ is already an issue requiring careful technical justification, the SDT has determined that it should be
conservative with regard to allowing such an exclusion for facilities that are depended upon for blackstart functionality, as these will
arguably be more important to the reliable operation of the transmission system than equivalent networks without blackstart
resources. It is nevertheless possible to achieve exclusion through the Exception Process. No change made.
Holland Board
of Public
Works

Yes

Holland BPW supports the exclusion of Local Networks (LN) from the definition of BES. Such systems
are generally not necessary for the reliable operation of the interconnected transmission network.
However, some revisions are necessary. Holland BPW believes that E3(a) and E3(b) can and should be
eliminated, provided E3(c) remains. E3(c) provides that an LN is BES if it is classified as a Flow Gate or
Transfer Path. The bases for removing E3(a) and E3(b) are as follows: (1) Provision E3(a) establishes a
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Question 9 Comment
75 MVA limit on connected generation. This is inconsistent with the concept of a LN and should be
removed. If not removed, it should be increased to not less than 300 MVA, consistent with the
discussion in response to Q1.
If an LN does not accommodate bulk power transfer across the interconnected system, the amount of
generation that exists and is distributed within that system is immaterial for purposes of the reliable
operation of the interconnected transmission system. During the NERC Webinar, NERC
representatives suggested that placing an upper limit on generation within a LN might be desirable
based upon an assumption that if that entity’s internal generation is lost, then replacement
generation would have to come from the BES, and could therefore affect reliability. This assumption
has not been substantiated. In most instances, generation resources are dispersed throughout the LN
- it is unlikely an event would result in the loss in the amount of the aggregate generation.
Additionally, LNs have local load shedding and system restoration plans for such contingencies.
(2) E3(b) is unnecessary and should be removed. The proposed language in E3(b) appears to be
concerned with flows originating from outside of the LN, coming into the LN, and then exiting the LN
to loads outside of the LN. As noted above, E3(c) appears to address this concern. If E3(b) is
maintained, then the introductory clause (“Power flows only into the LN:”) should be deleted, because
it is inconsistent with the second clause (“The LN does not transfer energy originating outside the LN
for delivery through then LN.”) If E3(b) is retained, Holland BPW supports the second clause (“The LN
does not transfer energy originating outside the LN for delivery through then LN”) because it appears
to be the portion of the provision that addresses the concern about flows into, through, and then out
of, the LN.
(3) E3(b) should also be removed or modified because it fails to recognize typical municipal system
operations. An LN may have internal generation that is less than its peak load but in excess of offpeak or holiday load levels. The language “Load flows only into the LN” does not recognize this
situation and prevents an LN from making the most economic use of surplus generation. There are
no reliability reasons to discourage such sales since with or without such transactions, this generation
is not necessary for the reliable operation of the interconnected transmission system.

Response: The SDT believes that a limit on the amount of connected (non-retail) generation within the LN is necessary to ensure that
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Question 9 Comment

there is no reliability impact on the interconnected transmission system; however, the threshold of the allowable generation – 75
MVA – was chosen to be consistent with the existing threshold in the NERC Statement of Compliance Registry Criteria, and this
threshold is a subject of further review under the Phase 2 development of the BES definition. The SDT believes that Exclusion E3.b
continues to be necessary to ensure that qualifying LN’s do not participate in “wheel-through” transactions, and that power always
flows in a direction from the BES toward the LN. The SDT has clarified Exclusion E3.b as follows due to your comments and those of
others.
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
Texas
Industrial
Energy
Consumers

Yes

As noted in response to Question 3, above, subsection (a) of Exclusion E3 would only exclude Local
Networks with “aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating).” The reference to “non-retail” generation in subsection (a) indicates that the SDT
may have intended to preserve the “netting” approach set forth in the Statement of Registry
Compliance, but this should be made clearer. The description in subsection (a) should be revised to
exclude “Where the radial system serves Load and includes generation resources not identified in
Inclusions I2 or I3,” and the remainder of that sentence referencing a 75 MVA gross nameplate rating
should be removed. This will provide a reference back to the Statement of Registry Compliance and
clarify that only net capacity is considered for customer-owned facilities.
TIEC also disagrees with the 300 kV upper limitation on transmission elements within a Local Network.
Consistent with TIEC’s comments to FERC, if these facilities are serving a distribution function, their
voltage level is irrelevant. The transmission versus distribution distinction should be based on
function, not voltage level. The remainder of this exclusion clarifies what constitutes a distribution
function, so the 300 kV limit is unnecessary and should be removed.

Response: The SDT evaluated this comment and has concluded that the exclusion must necessarily be based on the gross aggregate
nameplate of the generation connected within the candidate systems. The approach that is suggested in your comment could result
in significant amounts of generation existing within the excluded area. No change made.
The SDT does not agree with the removal of the 300 kV cap that limits the qualification of a group of facilities for local network
exclusion. The SDT feels that an upper bound is essential to prevent inappropriate exclusions of facilities that may be important to
the reliable operation of the interconnected transmission system. The Exception Process is available for specific circumstances where
a 300 kV cap is problematic. No change made.
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Organization
PacifiCorp

Yes or No
Yes

Question 9 Comment
PacifiCorp strongly supports the categorical exclusion of Local Networks (“LNs”) from the BES.
PacifiCorp believes the exclusion is necessary to ensure that the BES definition complies with FERC’s
statutory jurisdictional requirements. PacifiCorp recommends the following modifications: o Change
“contiguous transmission Elements” to “contiguous Elements”.
o Modify item b to state, “Power flows only into the LN during normal operating conditions: The LN
does not transfer energy originating outside the LN for delivery to loads located outside the LN...”
o Add an item (may be included in item b) to provide as follows: “The LN is not critical (or is not relied
upon) to maintain the reliability of the interconnected system during abnormal operating conditions.”

Response: The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word
– in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
included in the term “Element”. No change made.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
The SDT does not believe that the statement “The LN is not critical (or is not relied upon) to maintain the reliability of the
interconnected system during abnormal operating conditions” lends itself to determination by inspection; hence, it is not an
appropriate “bright-line” characteristic for ExclusionE3. No change made.
Southern
Company

No

We would agree with the exclusion if the wording of the exclusion includes the following phrase (in
italics) added at the end of E3 b): “Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN “under normal operating conditions”.
What does the term "non-retail generation" mean?
Can the term "non-retail generation in E3a be changed to simply "generation"?

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition.
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Question 9 Comment

For those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power
to flow out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No
change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT has intentionally utilized the term “non-retail generation” in Exclusion E3.a in order to specifically isolate that generation
which is not situated behind the retail meter. It is important to retain this concept, since removal of the clarifier “non-retail” would
cause candidate local networks with retail generation to be unfairly biased against obtaining this exclusion. No change made.
ReliabilityFirst

No

ReliabilityFirst Staff proposes to use the LN exclusion as part of the definition of what elements make
up the facilities used in the local “distribution” of electric energy and could be included in the
Exception Process as a criterion for exclusion.

Response: The SDT believes that Exclusion E3 has sufficient clarity and that its provisions can be readily demonstrated without the
need to be handled through the Exception Process. Therefore, it is more appropriately handled within the definition. No change
made.
Ontario Power
Generation
Inc.

No

Non-retail generation needs to be properly defined in the text of the exclusion.

Mission Valley
Power

No

Mission Valley Power - : We strongly agree that local networks should be excluded, since they act
much like the radial systems excluded in E1 while providing a higher level of service to customers.
These networks should not be discouraged in the name of reliability.
We again object to the introduction of the new confusing term “non-retail generation” with no
definition provided.

Tillamook PUD

No

We strongly agree that local networks should be excluded, since they act much like the radial systems
excluded in E1 while providing a higher level of service to customers. These networks should not be
discouraged in the name of reliability.

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Question 9 Comment
We again object to the introduction of the new confusing term “non-retail generation” with no
definition provided.

Central Lincoln

No

We strongly agree that local networks should be excluded, since they act much like the radial systems
excluded in E1 while providing a higher level of service to customers. These networks should not be
discouraged in the name of reliability.
We again object to the introduction of the new confusing term “non-retail generation” with no
definition provided.

Northern
Wasco County
PUD

No

We strongly agree that local networks should be excluded, since they act much like the radial systems
excluded in E1 while providing a higher level of service to customers. These networks should not be
discouraged in the name of reliability. We again object to the introduction of the new confusing term
“non-retail generation” with no definition provided.

Response: Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
Central
Hudson Gas
and Electric
Corporation

No

Under the proposed definition, clause E3.b. stipulates that ‘power only flows into the Local Network
(LN): The LN does not transfer energy originating outside the LN for delivery through the LN.’ Clearly,
this is a bright line. The Local Network Exclusion document, however, describes that ‘power flow
“shifts”‘ of ‘negligible fraction’ are acceptable. Further, the document acknowledges that parallel
flows through the LN, ‘as governed by the fundamentals of parallel circuits’ will occur. Finally, the
document goes on to exhibit that flows through the LN, however minimal, will result from both power
transfer distribution factor (PTDF) and line outage distribution factor (LODF) analysis. If this is the
case, what bright line criterion should be applied for this Exclusion Principal if no maximum PTDF
and/or LODF are specified?

Response: Exclusion E3.b does in fact prohibit power flow at the BES interface points of the LN from entering the BES. The
accompanying technical justification document merely addresses the insignificance of the power flow shifts that will occur in an
example system. Clearly, in the example system of the technical justification document, power flow is shown to always be in a
direction from the BES toward the LN, albeit with only a slight magnitude shift in the PTDF and LODF analyses. The technical
justification document does not attempt to set any threshold on the magnitude of this shift; it merely is a demonstration on a sample
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Question 9 Comment

system. The only bright-line criterion that is applicable to this question is that power flow shall always be from the BES toward the LN.
City of
Anaheim

No

Again, 75 MVA should be increased to 300 MVA in E2 for the reasons stated in response to Question
7.

Response: The SDT has determined that it must retain the 75 MVA threshold on generation allowed within a qualifying LN in order to
remain consistent with the existing ERO Statement of Compliance Registry Criteria. There has not been sufficient technical
justification to this point that would support a change from this threshold; however, such threshold will be considered in Phase 2 of
this Project 2010-17. No change made.
Consumers
Energy

No

In general we agree, but believe the word "transmission" should be removed from "A group of
contiguous transmission Elements..."

Response: The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word
– in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
included in the term “Element”. No change made.
Manitoba
Hydro

No

Manitoba Hydro agrees with the Local Network Exclusion but disagrees with the drafting team’s
removal of the requirement to have protective devices protecting the BES from the LN. We suggest
that the following requirement is re-inserted into E3 to meet the LN Exclusion:”a) Wherever
connected to the BES, the LN must be connected with a Protection System.”

Response: The SDT considered the suggested requirement for separation of the LN via automatic fault interrupting devices during the
development of the language of the second posting, and determined that, consistent with Order 743 and 743a, such a qualifier could
not be enforced for facilities that are not essential for the reliable operation of an interconnected transmission network. No change
made.
Long Island
Power
Authority

No

Main paragraph and items E3b and E3c adequately define a Local Network. It seems like the intent to
exclude non bulk distribution systems would still be included because of E3a.
E3a should be eliminated. If not eliminated, need to define the term "underlying Elements".

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Question 9 Comment

Response: The SDT continues to believe that it is necessary to establish a limit on the allowable quantity of generation that may be
significant to the reliable operation of the surrounding interconnected transmission system. Please note that the issues surrounding
the appropriate generation threshold, among other topics, will be taken up in Phase 2 of this BES definition effort. No change made.
The SDT believes that the existing phrase in ExclusionE3.a “and its underlying Elements” has sufficient clarity and meets the intent of
the exclusion with brevity. No change made.
City of St.
George

No

The exclusion of Local Networks should be provided, however the generation level limits are too
restrictive. As long as the power flow is into the system the generation level of the local network
shouldn’t matter as long as it is being used to serve local load.
E3a should be deleted from the definition, or at least some higher level of allowed generation should
be included. Another possibility would be a ratio of local load to local generation. Areas with local
generation serving local load will have similar characteristics or affects to the BES system as were used
in the Local Network justification paper (Appendix 1) included with the documents. If some
reasonable level of local generation was added to the example system it is unlikely that the affects to
the BES flows would change from what was presented in the example.

Response: The SDT has determined that it must retain the 75 MVA threshold on generation allowed within a qualifying LN in order to
remain consistent with the existing ERO Statement of Compliance Registry Criteria. There has not been sufficient technical
justification to this point that would support a change from this threshold; however, such threshold will be considered in Phase 2 of
this Project 2010-17.
The SDT continues to believe that it is necessary to establish an upper limit on the allowable quantity of generation that may be
included in the local network since generation in a local network may be significant to the reliable operation of the surrounding
interconnected transmission system. Please note that the issues surrounding the appropriate generation threshold, among other
topics, will be taken up in Phase 2 of this BES definition effort.
Orange and
Rockland
Utilities, Inc.

No

We know that N-1 is assumed when power-flow study is performed, however, N-1 should be
mentioned here for clarification.

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Question 9 Comment

Response: The SDT understands this comment to be in reference to the technical justification document that accompanied the
definition in its second posting. This technical justification document was merely intended to be illustrative of the insignificance of
the interaction of a sample local network on its surrounding interconnected transmission system. The “LODF” values were for a single
element taken out of service. No change made.
ISO New
England Inc

No

E3 could result in many large load pockets being excluded from the BES definition and should be
deleted. Assuming that it is retained, we offer the following additional comments.
The term “a group of contiguous transmission elements” is ambiguous and needs to be clarified.
Please clarify in the exclusion if the flows into the LN as described in E3.b) are pre-contingency flows
only.
Please clarify the system conditions (time of year, peak or off-peak) that should be considered in
determining of flow is only into the LN.
The “Non-retail” qualifier in E3.a) should be deleted.

Response: The SDT appreciates your concern about the possible exclusion of large metropolitan load centers through the exclusion
for local networks in Exclusion E3. However, the SDT feels that it has accurately captured the characteristics of facilities that are used
in the local distribution of electric energy within Exclusion E3 (and Exclusion E1), which the Commission’s Order specifically targeted
for exclusion. No change made.
The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word – in lowercase – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be included in the
term “Element”. No change made.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
There are no specified conditions applicable to item Exclusion E3.b. In order to qualify for exclusion under this item, this characteristic
must be demonstrated under all conditions. This exclusion has been re-stated as follows for additional clarity:
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E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
The SDT has intentionally utilized the term “non-retail generation” in Exclusion E3.a in order to specifically isolate that generation
which is not situated behind the retail meter. It is important to retain this concept, since removal of the clarifier “non-retail” would
cause candidate local networks with retail generation to be unfairly biased against obtaining this exclusion. No change made.
Texas
Reliability
Entity

No

There should be language that includes UFLS, UVLS, or load fully removable for Reserves even in a
local network to avoid a lapse in reliability in operation of the BES. Even if it is to be included in any
Phase 2 work, it should be mentioned here to avoid gaps.

Response: The SDT is uncertain whether this comment suggests that facilities used in UFLS, UVLS, or as interruptible load for reserve,
should be prohibited from exclusion from the BES under Exclusion E3. At any rate, even a facility that is excluded under Exclusion E3
may continue to have obligations under the reliability standards for UFLS, UVLS or other load shedding requirements.
Independent
Electricity
System
Operator

No

Consistent with our comments in response to Q7, we propose removing E3 (a) since, as explicitly
described in E3 (b), one of the characteristic of the LN is that power flows only into the LN. The level of
generation contained within the LN is therefore immaterial, particularly where the most onerous
contingency or system operating condition occurring within the LN, results in acceptable BES
performance as defined by the applicable criteria of the NERC transmission planning standards. The
generation connected within the LN that meets the registry criteria would already be captured within
the definition of the BES as provided for in Inclusion I2.

Response: The SDT continues to believe that it is necessary to establish a limit on the allowable quantity of generation that may be
significant to the reliable operation of the surrounding interconnected transmission system. Please note that the issues surrounding
the appropriate generation threshold, among other topics, will be taken up in Phase 2 of this BES definition effort. No change made.
Rochester Gas
and Electric
and New York
State Electric
and Gas

No

“Local Network” is capitalized (network not capitalized at the beginning of E3) throughout E3, yet it is
not defined in the NERC Glossary.
This exclusion is vague. This exclusion applies to a network with “multiple points of connection” with
the purpose “to improve the level of service to retail customer load” - this phrase is intent-based and
not reliability-based - most/all transmission “improves service” compared to it not being there. In
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Organization
Central Maine
Power
Company

Yes or No

Question 9 Comment
essence, this exclusion can be obtained if a portion of the network:1. Doesn’t have significant
generation (again, “non-retail” phrase is unclear)2. Power only flows “into” this portion of the
network, and not (ever? Even under any TPL design contingencies?) “out.” Is this considering only precontingency steady state conditions? During contingency conditions and for the period following a
contingency the LN could supply power to other parts of the network depending on the nature of the
contingency. The conditions under which direction of flow is assessed are critical, but E3(b) is silent on
this.3. This portion of the network is not part of a monitored transmission interfaceThis “Local
Network Exclusion” is supported by a technical analysis which relied on transfer distribution factors
(see
http://www.nerc.com/docs/standards/sar/bes_definition_technical_justification_local_network_201
10819.pdf on the NERC BES Definition standard page
http://www.nerc.com/filez/standards/Project2010-17_BES.html ). This transfer distribution factor
(TDF) method was rejected by FERC in Order 743. Paragraph 85 of the Order states: “Given the
questionable and inconsistent exclusions of facilities from the bulk electric system by the material
impact assessment and the variable results of the Transmission Distribution Factor test proposed in
NPCC’s compliance filing in Docket No. RC09-3, there are no grounds on which to reasonably assume
that the results of the material impact assessment are accurate, consistent, and comprehensive.93
Additionally, we have noted how the results of multiple material impact tests can vary depending on
how the test is implemented.”Unless E3 is made more specific and clear, it should be stricken.

Response: The term “local network” is not capitalized anywhere in the Exclusion E3 section of the definition except where it is placed
as a section title, and when abbreviated. The SDT understands that “local network” is not a NERC Glossary term. No change made.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
The SDT recognizes that the TDF methodology suggested by various entities as a threshold for determining inclusion in the BES was
not favored by the Commission. However, as used in the technical justification document, the transfer distribution factors for power
flow transfer as well as line outage factors are merely illustrative of the de minimis impact that a sample local network has on its
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Question 9 Comment

surrounding interconnected transmission system. The SDT does not propose the use of TDF as a threshold for determination of BES.
Kansas City
Power and
Light Company

No

Although the Technical Justification Local Network guidance document is helpful in explaining the
principles and concepts involved with determination of what constitutes a Local Network, criteria
needs to be established regarding the impacts of LODF and PTDF that will clearly define what
constitutes a Local Network to avoid debate and controversy.

Response: As used in the technical justification document, the transfer distribution factors for power flow transfer as well as line
outage factors are merely illustrative of the de minimis impact that a sample local network has on its surrounding interconnected
transmission system. The SDT does not propose the use of TDF as a threshold for determination of BES. No change made.
Nebraska
Public Power
District

No

In E3 (a): please define “non-retail generation” as usued in E3(a).
Also, what is the criterion that makes this genertion BES generation? The MVA rating only, or is there
other criteria? A generator may have a 75 MVA gross nameplate rating, but may be limited physically
or electrically to below the 75 MVA. Is this a basis for exclusion for this generator?

Response: Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
Consistent with the ERO Statement of Compliance Registry Criteria, the SDT has used language in describing generation thresholds in
Exclusion E3.a as being gross aggregate nameplate ratings.
Ameren

No

a) The exclusion should also be extended to reactive resources needed to support the local area
network (see response to Q10).
It is also suggested that “local network” be renamed to “local area network” to better describe or
distinguish itself from a wide-area network such as the BES.
b) We would agree with the exclusion if the wording of the exclusion includes the following phrase
(in italics) added at the end of E3 b): Power flows only into the LN: The LN does not transfer
energy originating outside the LN for delivery through the LN “under normal operating
conditions”.
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Question 9 Comment

Response: If a candidate local network is granted exclusion under Exclusion E3, the exclusion would apply to the reactive resources
within that network as well. No change made.
The SDT believes that renaming the local network to “local area network” (LAN) will lead to industry confusion with the identical term
used to refer to communications infrastructure. No change made.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
Georgia
System
Operations
Corporation

No

Item (b) is unclear: Although the first sentence says “Power flows only into the LN,” which suggests
there will be no exports, the second sentence says “The LN does not transfer energy originating
outside the LN for delivery through the LN,” which suggests it could deliver power originating within
the LN. This would seem to be reasonable by comparison to E-2, so long as no more than 75 MVA is
exported (which is indeed the limitation on the quantity of “non-retail generation” in the LN).
On a related point, if the limit on connected generation is not intended to be a limit on possible
exports, and therefore any power from interconnected non-retail generation must be sold within the
LN, why does the limit need to be so low; why should the aggregate quantity of such internallyconsumed generation be an issue?
Also, is the “non-retail” designation intended to exclude customer-owned generation from the 75
MVA calculation?

Response: The SDT has re-stated item Exclusion E3.b for additional clarity.
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
The limit placed on the aggregate generation within the local network only applies to non-retail generation. To clarify, in order to
qualify under Exclusion E3, exports are not permissible from the local network.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.

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Organization
ATC LLC

Yes or No

Question 9 Comment

No

ATC agrees in general with the exclusions for E3 pending the following changes: Power flows only into
the LN: The LN does not transfer energy originating outside the LN for delivery through the LN under
normal operating conditions (n-0 contingency); and
ATC suggests considering a different approach for the power flow criteria in Exclusion E3b:Inclusion
E3b - No Firm Power Transfers are scheduled to flow out of, or through, the LN in the operating
horizon [for BES designations applicable to the operating horizon] and no Firm Power Transfers are
reserved to flow out of, or through, the LN in the planning horizon [for BES designations applicable to
the planning horizon).

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition.
For those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power
to flow out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No
change made.
The SDT believes it is vital to ensure both that power flow is always in the direction from the BES toward the LN at all points of
connection, and that the LN facilities not be used for “wheeling” type transactions. The SDT believes the existing language
accomplishes this. This suggested language in this comment touches on an important aspect, the scheduled use of the facilities, but
the SDT believes that the existing language is more appropriate to express this point. No change made.
Tacoma Power

No

Tacoma Power does not support the Exclusion E3 as currently written. We strongly believe that
Section c) of E3 must replace the term “transfer path” with “Major Transfer Path” to distinguish these
paths from any common ATC path. This revision is consistent with the existing language used in the
form, Detailed Information to Support an Exception Request.
Additionally, we believe it is not appropriate for E3 to state an MVA threshold in Section a) when
determining such thresholds is the purpose for Phase 2. We urge the SDT to defer the determination
of a MVA threshold in E3 to Phase 2.
Finally, the term “non-retail generation” is not a universally understood term in the industry. We
suggest that the SDT replace the phrase “non-retail generation” with “generation located on the retail
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Question 9 Comment
customer’s side of the meter.”

Response: The existing language posted in the second draft of the BES definition does include the word “major” as a modifier of
transfer paths in the Western Interconnection. The definition cannot have this word “major” capitalized, as it is not part of the NERC
Glossary of Terms. Accordingly, the SDT believes that there is no need to make the suggested change to Exclusion E3.c.
The SDT agrees that the threshold(s) for generation throughout the BES definition should be addressed in Phase 2 of this effort;
however, to satisfy the Commission’s directives in Order 743 and 743-A in a timely fashion, it is necessary to use a generation
threshold that is consistent with the in-force Statement of Compliance Registry Criteria. No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter. The exclusion language of
Exclusion E3.a intends to consider only the non-retail (supply side) generation; whereas your comment suggests that the generation
to be counted is on the retail side of the meter. With the clarification of the use of the term “non-retail generation", the SDT believes
that Exclusion E3.c is appropriate. No change made.
MEAN

No

MEAN does not agree with the language of E3, b). This language is arbitrary and could be represented in
several ways, dependent on the entity making their case. As we all know, electricity doesn’t always take
the shortest path. MEAN would recommend eliminating E3, b) due to its subjective language and rely on
the current E3, c) to evaluate reliability and system impacts. If the language does not change, MEAN
would argue to any applicable RE that the language intent was to address facilities that have
documentation stating that the facilities are used for transferring energy across (e.g. joint ownership,
contribution in aid of construction, etc.) and have an E3 exception denied based on power flow models
or other transmission modeling.

Response: The SDT has reviewed the language of Exclusion E3.b, and does not find it to be subjective or arbitrary. However, the SDT
does propose a minor revision to re-state E3.b for additional clarity:
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
South Houston
Green Power,
LLC

SHGP would like to broaden the scope of Local Networks. If a Local Network does not allow transfer
of Bulk Power across the Interconnected System, then the Local Network should be excluded
regardless of the amount of generation behind the meter. Often, large industrial sites install large
combined Heat and Power cogeneration units due to a hefty steam load. Subjecting industrial
facilities to additional reporting and coordination efforts [other than those already required by the TO
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Organization

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Question 9 Comment
and RTO] may have little, if any, increase in grid reliability. The 75 MVA (gross nameplate rating) needs
to be eliminated. To date, none of the Regional Entities has suggested that SHGP or its affiliates
register as a Transmission Owner or Transmission Operator with respect to any SHGP or affiliated
delivery facilities.

Response: The SDT has determined that it must retain the 75 MVA threshold on generation allowed within a qualifying LN in order to
remain consistent with the existing ERO Statement of Compliance Registry Criteria. There has not been sufficient technical
justification to this point that would support a change from this threshold; however, such threshold will be considered in Phase 2 of
this Project 2010-17. No change made.
Hydro-Quebec
TransEnergie

Same comment than Q7.

Response: See response to Q7.
ExxonMobil
Research and
Engineering

Yes

Exclusion E1 and E3 aid in the delineation of distribution and transmission facilities. However, we
request that the BES SDT review paragraphs 108 and 109 of FERC Order 743. In order to meet
reliability target requirements to safely and economically operate manufacturing and production
facilities, many industrial facilities are fed by two or more utility transmission lines that originate at
independently fed utility substations. Due to the magnitude of an industrial site’s load, these
transmission lines are typically designed to operate at levels in excess of 100 kV at the request of the
utility company. These transmission lines typically terminate into an interconnection facility, owned
by the industrial facility, that spot networks the transmission lines via a ring buss or breaker and a half
substation within the industrial facility’s private use network in order to serve the load of the facility’s
private use network. These private use networks typically satisfy the requirements set forth in the
definition of a Local Network (power flows in, not a flowgate, etc.); however, the term “non-retail
generation” is not a term that is implicitly defined or consistent with this documents use of “net
capacity provided...” phrasing in similar exclusions.

Response: Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.

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Question 9 Comment

Sacramento
Municipal
Utility District

Yes

It is preferred to hold reference to gross nameplate rating/threshold values until generation technical
justification is completed as part of Phase 2; these studies should apply to any real or reactive power
threshold reference.
For Exclusion E3-b using the phrase “[p]ower flows only into the LN” is too restrictive. An allowable
MW threshold of LN power producing resources should be deferred to the Phase 2 BES technical
analysis. Where no generation is present in the LN, it is recommended that an allowance for residual
flow through the LN.

City of Austin
dba Austin
Energy

Yes

We prefer to hold reference to gross nameplate rating/threshold values until generation technical
justification is completed as part of Phase 2; these studies should apply to any real or reactive power
threshold reference.
For Exclusion E3-b using the phrase “[p]ower flows only into the Local Network” is too restrictive. An
allowable MW threshold of Local Network power producing resources should be deferred to the
Phase 2 BES technical analysis. Where no generation is present in the Local Network, it is
recommended that an allowance for residual flow through the Local Network.

Response: The SDT agrees that the threshold(s) for generation throughout the BES definition should be addressed in Phase 2 of this
effort; however, to satisfy the Commission’s directives in Order 743 and 743-A in a timely fashion, it is necessary to use a generation
threshold that is consistent with the in-force Statement of Compliance Registry Criteria. No change made.
The SDT feels strongly that in order for a network to qualify for exclusion under the Exclusion E3 section of the definition, there must
be strict bounds and limits placed on the characteristics of the candidate facilities. Allowances for minor “out-flow” from the local
network, or “minimal” flow, as suggested in this comment, will lead to an inconsistent application of the definition and therefore, a
lack of bright-line quality in the definition. Situations such as what is proposed in this comment can be referred to the Exception
Process for possible exclusion from the BES. No change made.
Portland
General
Electric
Company

Yes

PGE agrees with Exclusion E3, but believes additional clarification is necessary to facilitate a complete
understanding and application of the exclusion criteria. First, there is no specific definition of “nonretail” generation provided.
Additionally, E3 b) states “Power flows only into the LN: The LN does not transfer energy originating
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Question 9 Comment
outside the LN for delivery through the LN.” PGE believes that a local network should still qualify for
the LN exclusion if power may flow out of the LN at a discrete point or certain discrete points during
abnormal operating conditions, but power still flows into the LN on an aggregate basis during all
operating conditions, and power flows only into the LN at all discrete points during normal operating
conditions.

Response: Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
Cowlitz
County PUD

Yes

Cowlitz strongly supports the categorical exclusion of Local Networks (“LNs”) from the BES. This
exclusion will allow conversion of radial systems to LNs without compliance impact, and should be
encouraged rather than discouraged as networked systems generally reduce losses, increase system
efficiency, and increase the level of service to retail customers. The decision of whether to network
radial systems should be made on the basis of costs and benefits to the retail customers served by
those radials, and not on the basis of disparate regulatory treatment. Consumers will ultimately
benefit from the path chosen by the SDT.
Cowlitz believes that the word “transmission” does not add clarity to the Exclusion; simply stating
“Elements” is sufficient. This will allow for a gradual acceptance that transmission is not defined by a
certain voltage, but more a medium in which electrical power is efficiently transported from power
resources to load centers where it is distributed. The old convention of transmission versus
distribution no longer fits in the current regulatory environment, and as such should be retired.
Cowlitz also believes that subparagraphs (a) and (b) are redundant; subparagraph (a) is duplicated by
the limit in subparagraph (b) requiring no flow out of the LN. However, Cowlitz also believes that
removing (a) will complicate FERC’s acceptance of this exclusion. Therefore this should be addressed
in Phase 2.
Cowlitz is confused by the use of the term “non-retail generation” in subparagraph (a). From context,
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we believe the SDT considers “non-retail generation” to mean generation that is not connected
through a dedicated step-up transformer to voltages at or above 100 kV, is consumed by the retail
customer’s load, or consumed within the LN rather than being physically exported and sold to markets
outside the LN.
Cowlitz suggests that the SDT rewrite subparagraph (a) to read “Limits on connected generation: The
LN and its underlying Elements do not include generation resources identified in Inclusion I3 and does
not have any generation net power flow greater than 75 MVA across any single retail revenue
metering point into an Element operated at or greater than 100 kV.”

Response: The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word
– in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
included in the term “Element”.
The SDT agrees that the threshold(s) for generation throughout the BES definition should be addressed in Phase 2 of this effort;
however, to satisfy the Commission’s directives in Order 743 and 743-A in a timely fashion, it is necessary to use a generation
threshold that is consistent with the in-force Statement of Compliance Registry Criteria. No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT appreciates the suggested language change for item Exclusion E3.a. The SDT considered this language, and has determined
that retention of the existing (non-retail) generation limit of 75 MVA is essential to meet the Commission’s order in the first phase of
Project 2010-17. No change made.
National Grid

Yes

We agree with Exclusion E3 on local networks, however we suggest this clarification to the first
sentence: A group of contiguous transmission Elements operated at or above 100kV but less than
300kV that distribute power to Load rather than transfer bulk power across the interconnected
system under normal (“all-lines-in”) configuration and conditions.
We also suggest the following clarification to part c, so that the IROLs don’t get overlooked: Not part
of Flowgate, transfer path, or an Interconnected Reliability Operating Limit (IROL). The LN does not
contain a monitored Facility of a permanent Flowgate in the Easter Interconnection, a major transfer
path within the Western Interconnection, or a comparable monitored Facility in the ERCOT or Quebec
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Interconnection, and is not a monitored Facility included in an IROL.

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition.
For those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power
to flow out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No
change made.
The SDT believes it has adequately and concisely addressed the IROL characteristic with Exclusion E3.c. No change made.
Pacific
Northwest
Generating
Cooperative
(PNGC)
Raft River
Rural Electric
Cooperative
(RAFT)
West Oregon
Electric
Cooperative
Blachly-Lane
Electric
Cooperative
(BLEC)
Coos-Curry
Electric
Cooperative

Yes

PNGC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of
radial systems to local networks should be encouraged because networked systems generally reduce
losses, increase system efficiency, and increase the level of service to retail customers. If the BES
definition were to provide an exclusion for radials without providing a similar exclusion for LNs,
however, it would discourage networking local distribution systems because of the significantly
increased regulatory burdens faced by the local distribution utility if it elected to network its radial
facilities. By placing radial systems and LNs on the same regulatory footing, the proposed definition
will ensure that decisions about whether to network radial systems are made on the basis of costs and
benefits to the retail customers served by those radials, and not on the basis of disparate regulatory
treatment. Consumers would ultimately benefit.PNGC also supports specific refinements made to the
LN exclusion by the SDT in the current draft of the BES definition. In particular, PNGC supports the
clarification of the purposes of a LN. The current draft states that LNs connect at multiple points to
“improve the level of service to retail customer Load and not to accommodate bulk power transfer
across the interconnected system.” PNGC supports this change in language because it reflects the
fundamental purposes of a LN and emphasizes one of the key distinctions between LNs and bulk
transmission facilities, namely, that LNs are designed primarily to serve local retail load while bulk
transmission facilities are designed primarily to move bulk power from a bulk source (generally either
the point of interconnection of a wholesale generator or a the point of interconnection with another
bulk transmission system) to one or more wholesale purchasers.
PNGC believes further improvement of the language could be achieved with additional modifications
and clarifications. With respect to the core language of Exclusion 3, we believe the language making
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Organization
(CCEC)
Central
Electric
Cooperatve
(CEC)
Clearwater
Power
Company
(CPC)
Consumer's
Power Inc.
Douglas
Electric
Cooperative
(DEC)
Fall River Rural
Electric
Cooperative
(FALL)
Lane Electric
Cooperative
(LEC)
Lincoln
Electric
Cooperative
(LEC)
Northern

Yes or No

Question 9 Comment
a “group of contiguous transmission Elements operated at or above 100kV” the starting point for
identifying a LN would be improved by deleting the term “transmission” from this phrase. This is so
because LNs are not used for transmission and the use of the term “transmission Elements” is
therefore both confusing and unnecessary. There would be no room for argument about what the
SDT intended by including the word “transmission” if the word is deleted and the Exclusion applies to
any “group of Elements operated at 100kV or above” that meets the remaining requirement of the
Exclusion. Further, any definitional value that is added by using the term “transmission Elements” is
accomplished by using that term in the core definition, and there is no reason to carry the term
through in the Exclusions.
PNGC also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3 and
simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects more
than 75 MVA of generation, the interconnected generation interconnected will have no significant
interaction with the interconnected bulk transmission system. It will only interact with the LN. And,
with the advent of distributed generation, it is easy to foresee a situation in which a large number of
very small distributed generators are interconnected into a LN, so that the aggregate capacity of these
generators exceeds 75 MVA. However, because the generators are small and dispersed and, under
the criterion in subparagraph (b), would be wholly absorbed within the LN rather than transmitting
power onto the interconnected grid, those generators would not have a material impact on the grid.
We also suggest that subparagraph (b) of Exclusion 3 could be more clearly drafted. Subparagraph
(b), as part of the requirement that power flow into a LN rather than out of it, includes this
description: “The LN does not transfer energy originating outside the LN for delivery through the LN.”
We understand this language is intended to distinguish a LN from a link in the transmission system power on a transmission link passes through the transmission link to a load located elsewhere, while
power in a LN enters the LN and is consumed by retail load within the LN. While we agree with the
concept proposed by the SDT, we believe the language would be clearer if it read: “The LN does not
transfer energy originating outside the LN for delivery through the LN to loads located outside the
LN.” We believe the italicized language is necessary to distinguish between a transmission system,
where power that originates outside a system is delivered through the system and passes through the
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Organization
Lights Inc.
(NLI)
Okanogan
County
Electric
Cooperative
(OCEC)
Umatilla
Electric
Cooperative
(UEC)

Yes or No

Question 9 Comment
system to a sink located somewhere outside the system, from a LN, in which power originating
outside the LN passes through the LN and is delivered to retail load within the LN. To put it another
way, the italicized language helps distinguish a transmission system from an LN, in which the LN
“transfers energy originating outside the LN for delivery through the LN to loads located within the
LN.”
We also believe the language of subparagraph (a) of Exclusion 3 could be improved. Subparagraph
(d) would make LNs part of the BES if they interconnect “non-retail generation greater than 75 MVA
(gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and 7, we urge
the SDT to replace the reference to a hard 75 MVA threshold with the defined term “Qualifying
Aggregate Generation Resources” or some equivalent.
We are also uncertain what is meant by the use of the term “non-retail generation” in subparagraph
(a). From context, we believe the SDT considers “non-retail generation” to be the equivalent of
generation that is located behind the retail meter, usually but not always owned by the customer and
used to serve the customer’s own load. We therefore suggest that the SDT replace the term “nonretail generation” with “generation located behind the retail customer’s meter.”
Similarly, we are unsure what is meant by the phrase “the LN and its underlying Elements.” We
believe the phrase “and its underlying Elements” could simply be deleted from the definition without
loss of meaning. In the alternative, the SDT might consider using the phrase “the LN, including all
Elements located on the distribution side of any Automatic Fault Interrupting Devices (or other points
of demarcation) separating the LN from the bulk interstate transmission system.” We believe this
phrase more accurately reflects the SDT’s intent, which appears to be that generation exceeding 75
MVA in aggregate capacity interconnected anywhere within the LN disqualifies that LN from being
excluded from the BES under Exclusion 3.
PNGC also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as
long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as a
Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that
allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
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Question 9 Comment
transmission of electricity on the interconnected bulk system.
Apart from these specific improvements that we believe could be achieved by modifying the language
of Exclusion 3, we believe the SDT may need to re-examine certain assumptions that appear to
underlie the current draft. Specifically, subparagraph (a) suggests that if BES generation is embedded
within a LN, the LN itself must also be BES. But two NERC bodies have already addressed similar
questions and concluded there is no technical basis for such concerns. NERC’s Standards Drafting
Team for Project 2010-07 and its predecessor, the “GO-TO Task Force” were formed to address how
the dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. The GO-TO Team concluded that by complying with a
handful of reliability standards, primarily related to vegetation management, reliable operation of the
bulk interconnected system could be protected without unduly burdening the owners of such
interconnection systems. Therefore, there is no reason, according to the GO-TO Team, that dedicated
high-voltage interconnection facilities must be treated as “Transmission” and classified as part of the
BES in order to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for
Generator Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO
Task Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most
often not part of the integrated bulk power system, and as such should not be subject to the same
level of standards applicable to Transmission Owners and Transmission Operators who own and
operate transmission Facilities and Elements that are part of the integrated bulk power system.”
White Paper Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at
the Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to
comply with the same standards as BES Transmission Owners and Operators “would do little, if
anything, to improve the reliability of the Bulk Electric System,” especially “when compared to the
operation of the equipment that actually produces electricity - the generation equipment itself.” Id.
We believe that interconnection of BES generators within a LN is analogous and that, based on the
findings of the Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply
because a large generator is embedded in the LN will result in substantial overregulation and
unnecessary expense with little gain for bulk system reliability. If anything, generation interconnected
through a LN is less likely to produce material impacts on the interconnected bulk transmission system
than the equivalent generator interconnected through a single dedicated line because an LN is
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Question 9 Comment
interconnected to the bulk system at several points, so that if one interconnection goes down, power
can still flow from the BES generator to the bulk system on other interconnection points. Where a
dedicated interconnection facility is involved, by contrast, if the interconnection line fails, the
generator is unavailable to the interconnected bulk system. Similarly, we suggest that the SDT reexamine the assumptions underlying subparagraph (b), which seems to suggest that a local
distribution system cannot be classified as a Local Network if power flows out of that system at any
time, even if the amount is de minimis, the outward flow is only for a few hours, a year, or the
outward flow occurs only in an extreme contingency. Accordingly, we suggest that the initial clause of
subparagraph (b) be revised to read: “Except in unusual circumstances, power flows only into the LN.”
Finally, we note that the LN exclusion must not operate in any way as a substitution for the statutory
prohibition on including “facilities used in the local distribution of electric energy” in the BES.
Therefore, even with the LN exclusion, the SDT must retain this statutory language in the core
definition of the BES, as discussed in our answer to Question One. If a certain piece of equipment is a
“facility used in the local distribution of electric energy,” then it is not part of the BES in the first
instance, and so consideration of the LN Exclusion, or of any other Exclusion, any Inclusion, or any
Exception, would be both unnecessary and uncalled for.

Response: The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word
– in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
included in the term “Element”.
The SDT continues to believe that it is necessary to establish a limit on the allowable quantity of generation that may be significant to
the reliable operation of the surrounding interconnected transmission system. Please note that the issues surrounding the
appropriate generation threshold, among other topics, will be taken up in Phase 2 of this BES definition effort. No change made.
The intent of the SDT in structuring the language of Exclusion E3.b was to ensure two things: first that power flow is always in the
direction from the BES toward the LN, and second that the LN is not used for “wheel-through” transactions. The suggestion in your
comment places an unnecessary qualifier on the “wheel-through” whereby it would only apply if the transaction were serving “loads”.
The SDT believes this qualifier would inadvertently allow a wholesale transaction to be scheduled through the subject facilities, and
this is contrary to the intent of the exclusion provision of Exclusion E3.b. Given the high degree of certainty and assurances regarding
the high priority of the Phase 2 efforts on this Project 2010-17, for the purpose of completing the posting of the definition in the first
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Question 9 Comment

phase of the Project, the SDT believes that it is preferable to continue to use the specific value of 75 MVA within item Exclusion E3.a.
No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT believes that the existing phrase in Exclusion E3.a “and its underlying Elements” has sufficient clarity and meets the intent of
the exclusion with brevity. No change made.
The SDT acknowledges the work of Project 2010-07 “GO-TO” task force in identification of various NERC Standard requirements that
would promote reliability of the generator-to-transmission interface. This Project 2010-17 SDT believes that the body of work in
Project 2010-07 is most pertinent to generator lead-line facilities, rather than the looped and parallel-operated facilities contemplated
in Exclusion E3, and therefore, the SDT finds it necessary to continue to require all of the characteristics of Exclusion E3 to be met in
order to qualify for exclusion from the BES. No change made.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
The SDT has retained the statutory language “facilities used in the local distribution of electric energy” in the core definition section.
Massachusetts
Department of
Public Utilities

Yes

The MA DPU generally supports this exclusion but believes it is too narrow. As noted in the response
to question 7, Exclusion E3 should likely allow a higher level of aggregate generation MVA on a Local
Network.
In addition, local networks should not necessarily be ineligible for Exclusion E3 simply because an
amount of power may transfer out of the network at times. NERC’s draft technical network exclusions
document should be amended such that local networks would be permitted to qualify for network
exclusions under E3 if power flowing out of the network is minimal and would not likely adversely
impact the BES.

Response: The SDT has determined that it must retain the 75 MVA threshold on generation allowed within a qualifying LN in order to
remain consistent with the existing ERO Statement of Compliance Registry Criteria. There has not been sufficient technical
justification to this point that would support a change from this threshold; however, such threshold will be considered in Phase 2 of
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Question 9 Comment

this Project 2010-17. No change made.
The SDT feels strongly that in order for a network to qualify for exclusion under the Exclusion E3 section of the definition, there must
be strict bounds and limits placed on the characteristics of the candidate facilities. Allowances for minor “out-flow” from the local
network, or “minimal” flow, as suggested in this comment, will lead to an inconsistent application of the definition and therefore, a
lack of bright-line quality in the definition. Situations such as what is proposed in this comment can be referred to the Exception
Process for possible exclusion from the BES. No change made.
The Dow
Chemical
Company

Yes

Dow is uncertain whether end user-owned, behind-the-meter delivery facilities of the sort it has
described above would fall within the scope of the core BES definition proposed by NERC. To date,
none of the Regional Entities has suggested that Dow should register as a Transmission Owner or
Transmission Operator with respect to any of these Dow-owned delivery facilities. If a literal
application of the proposed BES Definition would, because of their voltage level or for any other
reason, include such facilities, then Dow has an interest in assuring that the E3 exclusion for "local
network" facilities is structured to embrace them. To that end, Dow would propose, first, the
elimination of the 300 Kv cap for these facilities. Dow has systems that operate above 300 Kv due
solely to the capacity of the lines to supply power over the distance required at our large
manufacturing sites.
Second, for the same reasons discussed above (in response to question #7), the phrase “do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating)” in “a)”
should be changed to “the net capacity provided to the transmission grid does not exceed 75 MVA.”
Third, the introductory phrase in “b)” -- “Power flows only into the LN” -- is inconsistent with the
recognition in “a)” (as amended pursuant to Dow’s above suggestion) that power may flow out of an
LN and into the transmission grid if there is generation connected to the LN and the 75 MVA limit is
observed. Dow recommends either deleting the introductory clause or correcting it to read “Power is
not transferred through the LN.”

Response: The SDT does not agree with the removal of the 300 kV cap that limits the qualification of a group of facilities for local
network exclusion. The SDT feels that an upper bound is essential to prevent inappropriate exclusions of facilities that may be
important to the reliable operation of the interconnected transmission system. The Exception Process is available for specific
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circumstances where a 300kV cap is problematic.
The SDT evaluated your comment in regard to Question 7 (Radial) as well as to the local network exclusion, and has concluded that
both exclusions must necessarily be based on the gross aggregate nameplate of the generation connected within the candidate
systems. The approach that is suggested in your comment could result in significant amounts of generation existing within the
excluded area.
It remains the intent of the SDT to uphold a 75 MVA limit on the connected (non-retail) generation within a qualifying LN and, at the
same time, reinforcing that power flow is always from the BES toward the LN at all points of connection. We believe these
characteristics are essential in order to ensure that qualifying LN facilities are not being relied upon for reliable operation of the
interconnected transmission system.
Springfield
Utility Board

Yes

SUB strongly supports the exclusion of Local Networks from the BES. SUB particularly agrees with the
addition of, “LN’s emanate from multiple points of connection at 100 kV or higher to improve the level
of service to customer Load and not to accommodate bulk power transfer across the interconnected
system.” language to the draft E3 Exclusion, as well as the LN characterization being more clearly
defined.SUB is concerned that the E3 Exclusion does not specify that these power flows would be
“under normal operating conditions” and specify if all power flow is considered.
SUB recommends that unscheduled power flow should not be considered, but that it is applicable only
to scheduled power flow.
While SUB supports the exclusion of LNs from the BES, we believe there is additional work that needs
to done regarding the Local Network Exclusion Technical Justification. Without specific parameters,
determining inclusions and exclusions will be left to the discretion of too many. This will create
ambiguity and inconsistency of application.

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition.
For those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power
to flow out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No
change made.
The suggestion that only the “scheduled” portion of flow be considered under Exclusion E3.b would ignore the physical impact that the
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Question 9 Comment

candidate network has on the surrounding interconnected transmission system; therefore, the SDT must retain the provisions of
Exclusion E3.b. However, the SDT has made a clarifying change to the exclusion language to address various comments that were
received.
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
The SDT does not intend to perform additional work on the technical justification document at this time. It was not intended to have
any specific thresholds or parameters from which exclusions would be granted; it merely illustrates the negligible effects that a
sample local network has upon the flows in the surrounding transmission network. No change made.
Michigan
Public Power
Agency
Clallam
County PUD
No.1
Snohomish
County PUD
Kootenai
Electric
Cooperative

Yes

MPPA and its members strongly supports the categorical exclusion of Local Networks (“LNs”) from the
BES. We believe the exclusion is necessary to ensure that the BES definition complies with the
statutory requirement, discussed in our response to Question 1, to exclude all facilities used in the
local distribution of electric power. LNs are, of course, probably the most common form of local
distribution facility. Further, the conversion of radial systems to local distribution networks should be
encouraged because networked systems generally reduce losses, increase system efficiency, and
increase the level of service to retail customers. If the BES definition were to provide an exclusion for
radials without providing a similar exclusion for LNs, however, it would discourage networking local
distribution systems because of the significantly increased regulatory burdens faced by the local
distribution utility if it elected to network its radial facilities. By placing radial systems and LNs on the
same regulatory footing, the proposed definition will ensure that decisions about whether to network
radial systems are made on the basis of costs and benefits to the retail customers served by those
radials, and not on the basis of disparate regulatory treatment. Consumers will ultimately benefit
from the path chosen by the SDT.MPPA and its members also support specific refinements made to
the LN exclusion by the SDT in the current draft of the BES definition. In particular, MPPA supports
the clarification of the purposes of a LN. The current draft states that LNs connect at multiple points
to “improve the level of service to retail customer Load and not to accommodate bulk power transfer
across the interconnected system.” Snohomish supports this change in language because it reflects
the fundamental purposes of a LN and emphasizes one of the key distinctions between LNs and bulk
transmission facilities, namely, that LNs are designed primarily to serve local retail load while bulk
transmission facilities are designed primarily to move bulk power from a bulk source (generally either
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Question 9 Comment
the point of interconnection of a wholesale generator or a the point of interconnection with another
bulk transmission system) to one or more wholesale purchasers.
MPPA believes further improvement of the language could be achieved with additional modifications
and clarifications. With respect to the core language of Exclusion 3, we believe the language making
a “group of contiguous transmission Elements operated at or above 100 kV” the starting point for
identifying a LN would be improved by deleting the term “transmission” from this phrase. This is so
because LNs are not used for transmission and the use of the term “transmission Elements” is
therefore both confusing and unnecessary. There would be no room for argument about what the
SDT intended by including the word “transmission” if the word is deleted and the Exclusion applies to
any “group of Elements operated at 100 kV or above” that meets the remaining requirement of the
Exclusion. Further, any definitional value that is added by using the term “transmission Elements” is
accomplished by using that term in the core definition, and there is no reason to carry the term
through in the Exclusions.
MPPA also believes that subparagraphs (a) and (b) are redundant in the sense that whatever
protection is offered by the generation limit in subparagraph (a) is duplicated by the limit in
subparagraph (b) requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a)
of Exclusion 3 and simply rely on subparagraph (b) because if power only flows into the LN even if it
interconnects more than 75 MVA of generation, the interconnected generation interconnected will
have no significant interaction with the interconnected bulk transmission system. It will only interact
with the LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a
large number of very small distributed generators are interconnected into a LDN, so that the
aggregate capacity of these generators exceeds 75 MVA. However, because the generators are small
and dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN
rather than transmitting power onto the interconnected grid, those generators would not have a
material impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more
clearly drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than
out of it, includes this description: “The LN does not transfer energy originating outside the LN for
delivery through the LN.” We understand this language is intended to distinguish a LN from a link in
the transmission system - power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
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Question 9 Comment
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.”
We also believe the language of subparagraph (a) of Exclusion 3 could be improved. Subparagraph
(d) would make LNs part of the BES if they interconnect “non-retail generation greater than 75 MVA
(gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and 7, we urge
the SDT to replace the reference to a hard 75 MVA threshold with the defined term “Qualifying
Aggregate Generation Resources” or some equivalent.
We are also uncertain what is meant by the use of the term “non-retail generation” in subparagraph
(a). From context, we believe the SDT considers “non-retail generation” to mean generation that is
used by retail customers located within a LN rather than being exported and sold on wholesale
markets outside the LN. We therefore suggest that the SDT replace the phrase “non-retail
generation” with the phrase “generation sold in wholesale markets and transmitted outside the LN.”
Similarly, we are unsure what is meant by the phrase “the LN and its underlying Elements.” We
believe the phrase “and its underlying Elements” could simply be deleted from the definition without
loss of meaning. In the alternative, the SDT might consider using the phrase “the LN, including all
Elements located on the distribution side of any Automatic Fault Interrupting Devices (or other points
of demarcation) separating the LN from the bulk interstate transmission system.” We believe this
phrase more accurately reflects the SDT’s intent, which appears to be that generation exceeding 75
MVA in aggregate capacity interconnected anywhere within the LN disqualifies that LN from being
excluded from the BES under Exclusion 3. Finally, MPPA believes that both subparagraphs (a) and (b)
of Exclusion 3 could be safely eliminated as long as subparagraph (c) is retained. Subparagraph (c)
makes a LN part of the BES if it is classified as a Flow Gate or Transfer Path. Flow Gates and Transfer
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Question 9 Comment
Paths are, by definition, the key facilities that allow reliable transmission of bulk electric power on the
interconnected grid. If a LN has not been identified as either a Flow Gate or a Transfer Path, it is
unlikely the LN is necessary for the reliable transmission of electricity on the interconnected bulk
system.
Apart from these specific improvements that we believe could be achieved by modifying the language
of Exclusion 3, we believe the SDT may need to re-examine certain assumptions that appear to
underlie the current draft. Specifically, subparagraph (a) suggests that if BES generation is embedded
within a LN, the LN itself must also be BES. But two NERC bodies have already addressed similar
questions and concluded there is no technical basis for such concerns. NERC’s Standards Drafting
Team for Project 2010-07 and its predecessor, the “GO-TO Task Force” were formed to address how
the dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. The GO-TO Team concluded that by complying with a
handful of reliability standards, primarily related to vegetation management, reliable operation of the
bulk interconnected system could be protected without unduly burdening the owners of such
interconnection systems. Therefore, there is no reason, according to the GO-TO Team, that dedicated
high-voltage interconnection facilities must be treated as “Transmission” and classified as part of the
BES in order to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for
Generator Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO
Task Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most
often not part of the integrated bulk power system, and as such should not be subject to the same
level of standards applicable to Transmission Owners and Transmission Operators who own and
operate transmission Facilities and Elements that are part of the integrated bulk power system.”
White Paper Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at
the Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to
comply with the same standards as BES Transmission Owners and Operators “would do little, if
anything, to improve the reliability of the Bulk Electric System,” especially “when compared to the
operation of the equipment that actually produces electricity - the generation equipment itself.” Id.
We believe that interconnection of BES generators within a LN is analogous and that, based on the
findings of the Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply
because a large generator is embedded in the LN will result in substantial overregulation and
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Yes or No

Question 9 Comment
unnecessary expense with little gain for bulk system reliability. If anything, generation interconnected
through a LN is less likely to produce material impacts on the interconnected bulk transmission system
than the equivalent generator interconnected through a single dedicated line because an LN is
interconnected to the bulk system at several points, so that if one interconnection goes down, power
can still flow from the BES generator to the bulk system on other interconnection points. Where a
dedicated interconnection facility is involved, by contrast, if the interconnection line fails, the
generator is unavailable to the interconnected bulk system.
Similarly, we suggest that the SDT re-examine the assumptions underlying subparagraph (b), which
seems to suggest that a local distribution system cannot be classified as a Local Network if power
flows out of that system at any time, even if the amount is de minimis, the outward flow is only for a
few hours a year, or the outward flow occurs only in an extreme contingency. Accordingly, we suggest
that the initial clause of subparagraph (b) be revised to read: “Except in unusual circumstances, power
flows only into the LN.”

Response: The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word
– in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
included in the term “Element”.
The SDT continues to believe that it is necessary to establish a limit on the allowable quantity of generation that may be significant to
the reliable operation of the surrounding interconnected transmission system. Please note that the issues surrounding the
appropriate generation threshold, among other topics, will be taken up in Phase 2 of this BES definition effort. No change made.
The intent of the SDT in structuring the language of Exclusion E3.b was to ensure two things: first that power flow is always in the
direction from the BES toward the LN, and second that the LN is not used for “wheel-through” transactions. The suggestion in your
comment places an unnecessary qualifier on the “wheel-through” whereby it would only apply if the transaction were serving “loads”.
The SDT believes this qualifier would inadvertently allow a wholesale transaction to be scheduled through the subject facilities, and
this is contrary to the intent of Exclusion E3.b. Given the high degree of certainty and assurances regarding the high priority of the
Phase 2 efforts on Project 2010-17, for the purpose of completing the posting of the definition in the first phase of the Project, the
SDT believes that it is preferable to continue to use the specific value of 75 MVA within ExclusionE3.a. No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT believes that the existing phrase in ExclusionE3.a “and its underlying Elements” has sufficient clarity and meets the intent of
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the exclusion with brevity. No change made.
The SDT acknowledges the work of the Project 2010-07 “GO-TO” task force in identification of various NERC Reliability Standard
requirements that would promote reliability of the generator-to-transmission interface. The Project 2010-17 SDT believes that the
body of work in Project 2010-07 is most pertinent to generator lead-line facilities, rather than the looped and parallel-operated
facilities contemplated in the Exclusion E3, and therefore, the SDT finds it necessary to continue to require all of the characteristics of
Exclusion E3 to be met in order to qualify for exclusion from the BES. No change made.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
NESCOE

Yes

NESCOE generally supports this exclusion but believes it is too narrow. As noted in the response to
question 7, Exclusion E3 should allow a higher level of aggregate generation MVA on a Local Network
(at least 300 MVA). In addition, NESCOE believes that local networks should not necessarily be
ineligible for Exclusion E3 simply because an amount of power may transfer out of the network at
times. NERC’s draft technical network exclusions document should be amended such that local
networks would be permitted to qualify for network exclusions under E3 if power flowing out of the
network is minimal and would not likely adversely impact the BES. For example, transfers of less than
or equal to 100 MVA should not have any adverse impact on the BES. The draft technical network
exclusions document should be amended to state that transfers of 100 MVA MVA into the BES from
the local distribution network are acceptable. The 100 MVA limit suggested here represents 25% of
the rated value of a typical 345/115 substation (typically on the order of 400 MVA). Rarely does more
than a fraction of the rated MVA flow from the low voltage side to the high voltage side. An allowance
of 100 MVA represents a flow level will have no significant impact to the interconnected bulk power
network.

Response: The SDT feels strongly that in order for a network to qualify for exclusion under the Exclusion E3 section of the definition,
there must be strict bounds and limits placed on the characteristics of the candidate facilities. Allowances for minor “out-flow” from
the local network, or “minimal” flow, as suggested in this comment, will lead to an inconsistent application of the definition and
therefore, a lack of bright-line quality in the definition. Situations such as what is proposed in this comment can be referred to the
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Exception Process for possible exclusion from the BES. No change made.
AECI and
member
GandTs,
Central
Electric Power
Cooperative,
KAMO Power,
MandA
Electric Power
Cooperative,
Northeast
Missouri
Electric Power
Cooperative,
NW Electric
Power
Cooperative
Sho-Me Power
Electric Power
Cooperative

Yes

We would agree in principle with the LN exclusion if the wording of the exclusion includes the
following phrase (in italics) added at the end of E3 b): Power flows only into the LN: The LN does not
transfer energy originating outside the LN for delivery through the LN “under normal operating
conditions”.
Also, the correct BES threshold level should be 200 kV rather than 100 kV.
Finally, the nomenclature of Flowgate (FG) components appears to be confused. AECI believes E3 c)
should be changed to read “contingent Facility” rather than “monitored Facility”. Although
unspecified within the NERC Glossary, we believe FG monitored Facilities are typically the impacted
facilities in danger of overload, while the contingent facilities are those which, if lost, would cause the
monitored Facility to become overloaded. As currently written, a formerly qualified LN could later
become disqualified due to an external entity’s ill-designing a parallel EHV line, thereby causing one or
more potential (N-1) overloaded Facility within that LN. Further, operational FG loading conditions
are often relieved by opening-up LN elements near the monitored Facility, with little impact upon BES
reliability, yet with lesser reliability to the underlying LN loads. This implies that the monitored
elements of Flowgates are typically non-essential to the BES reliability. AECI can support “contingent”
FG Facilities disqualifying a LN claim, but it cannot support “monitored” Facilities as disqualifying
factors for rejecting a LN claim.

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition.
For those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power
to flow out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No
change made.
The SDT appreciates the suggestion of an alternate BES threshold level of 200 kV rather than 100 kV; however, in the absence of a
strong technical justification, the SDT must retain the 100 kV threshold in the core definition. No change is being made at this time
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but all threshold values will be examined in Phase 2.
The SDT continues to believe that “monitored” is the most appropriate modifier of “Flowgate” in the text of Exclusion E3.c. Exclusion
E3.c is intended to identify the elements that are part of these Flowgates, not necessarily those whose contingency can affect the
Flowgate. The elements comprising Flowgates (and major transfer paths in the West) must continue to be prohibited from exclusion
via Exclusion E3.c, since these facilities are more likely to be used in the transfer of bulk power than not; therefore, they are more
characteristic of serving an interconnected transmission function than distribution. No change made.
Southern
Company
Generation

Yes

What does the term "non-retail generation" mean?
Can the term "non-retail generation" in E3a be changed to simply "generation."

Response: Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT has intentionally utilized the term “non-retail generation” in Exclusion E3.a in order to specifically isolate that generation
which is not situated behind the retail meter. It is important to retain this concept, since removal of the clarifier “non-retail” would
cause candidate local networks with retail generation to be unfairly biased against obtaining this exclusion. No change made.
Electricity
Consumers
Resource
Council
(ELCON)

Yes

This Exclusion and Exclusion E1 aid in the delineation of local distribution versus transmission. We
suggest three clarifying revisions. First, the phase “but less than 300 kV” should be deleted. Many
large industrial facilities have on-site distribution systems that operate above 300 kV due solely to the
capacity of the lines to supply power over the distance required at the manufacturing sites.
Second, for the same reasons discussed above (in response to question #7), the phrase “do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating)” in “a)”
should be changed to “the net capacity provided to the transmission grid does not exceed 75 MVA.”
Third, the introductory phrase in “b)” -- “Power flows only into the LN” -- is inconsistent with the
recognition in “a)” that power may flow out of an LN and into the transmission grid if there is
generation connected to the LN and the 75 MVA limit is observed. We recommend either deleting the
introductory clause or correcting it to read “Power is not transferred through the LN.”

Response: The SDT does not agree with the removal of the 300 kV cap that limits the qualification of a group of facilities for local
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network exclusion. The SDT feels that an upper bound is essential to prevent inappropriate exclusions of facilities that may be
important to the reliable operation of the interconnected transmission system. The Exception Process is available for specific
circumstances where a 300 kV cap is problematic. No change made.
The SDT evaluated your comment in regard to Question 7 as well as to the local network exclusion, and has concluded that both
exclusions must necessarily be based on the gross aggregate nameplate of the generation connected within the candidate systems.
The approach that is suggested in your comment could result in significant amounts of generation existing within the excluded area.
No change made.
It remains the intent of the SDT to uphold a 75 MVA limit on the connected (non-retail) generation within a qualifying LN and, at the
same time, reinforcing that power flow is always from the BES toward the LN at all points of connection. The SDT believes these
characteristics are essential in order to ensure that qualifying LN facilities are not being relied upon for reliable operation of the
interconnected transmission system. However, the SDT has clarified Exclusion E3.b in response to industry comments:
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
Transmission
Access Policy
Study Group

Yes

TAPS supports the exclusion of Local Networks from the BES. Such systems are generally not
“necessary for operating an interconnected electric transmission network,” the standard in Orders
743 and 743-A. We have several suggestions to clarify the proposed language for this Exclusion. TAPS’
comments in response to Question 7 above regarding “points of connection at 100kV or higher” and
“non-retail generation” are applicable to Exclusion E3 as well.
The term “bulk power,” which occurs twice in Exclusion E3, is vague and could be read incorrectly as a
reference to the statutorily-defined “bulk-power system,” which is not, we think, the SDT’s intent.
The word “bulk” should be deleted, so that the Exclusion simply refers to transferring “power” across
the interconnected system. TAPS raised this concern in response to the last posting of the BES
Definition. In response, the SDT removed some instances of “bulk power” but left the remaining two,
stating that “the SDT believes it provides conceptual value to the exclusion principle.” The SDT does
not state what conceptual value the term is intended to provide; on the assumption that it relates to a
distinction between transferring power from local generation to serve local load, and transferring
power over longer distances, TAPS suggests, as an alternative to simply deleting the word “bulk,” that
the Exclusion be revised to refer to “transfers of power from non-LN generation to non-LN
load.”Exclusion E3(c) states: “Power flows only into the LN: The LN does not transfer energy
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Question 9 Comment
originating outside the LN for delivery through the LN.” This statement is unclear because the two
parts mean different things. TAPS proposes rewriting this sentence to state: “Power flows only into
the LN, that is, at each individual connection at 100 kV or higher, the pre-contingency flow of power is
from outside the LN into the LN for all hours of the previous 2 years” to help clarify the intent. Two
years is suggested because it is the time period set out in the draft exception application form for
which an applicant should state whether power flows through an Element to the BES.

Response: See response to Q7.
The SDT prefers to continue the use of the word “bulk” in the core paragraph of Exclusion E3. The SDT believes this clarifies an
important conceptual idea to the industry, and the term “bulk” is not intended to be definitional in this context. This paragraph
merely provides an introduction to the concept of the local network, and retaining the term “bulk” conveys the concept effectively.
The lettered sub-items under the core paragraph are the prescriptive and precise characteristics that the industry will use to
determine qualification for exclusion under Exclusion E3. No change made.
The SDT prefers not to add demonstration criteria, such as the suggestion to provide a minimum of 2 years worth of data, within the
text of the BES definition. The SDT believes the language, particularly the word “always” adds sufficient clarity. No change made.
Florida
Municipal
Power Agency

Yes

: FMPA supports the exclusion of Local Networks from the BES. Such systems are generally not
“necessary for operating an interconnected electric transmission network,” the standard in Orders
743 and 743-A. However, we have several suggestions to clarify the proposed language for this
Exclusion. Exclusion E3(c) states: “Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN.” This statement is unclear because the two
parts mean different things. FMPA proposes rewriting this sentence to state: “Power flows only into
the LN, that is, at each individual connection at 100 kV or higher, the pre-contingency flow of power is
from outside the LN into the LN for all hours of the previous 2 years” to help clarify the intent. Two
years is suggested because it is the time period set out in the draft exception application form for
which an applicant should state whether power flows through an Element to the BES.
FMPA’ comments in response to Question 7 above regarding “points of connection at 100kV or
higher” and “non-retail generation” are applicable to Exclusion E3 as well.
The term “bulk power,” which occurs twice in Exclusion E3, is vague and could be read incorrectly as a
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Question 9 Comment
reference to the statutorily-defined “bulk-power system,” which is not, we think, the SDT’s intent.
The word “bulk” should be deleted, so that the Exclusion simply refers to transferring “power” across
the interconnected system. FMPA raised this concern in response to the last posting of the BES
Definition. In response, the SDT removed some instances of “bulk power” but left the remaining two,
stating that “the SDT believes it provides conceptual value to the exclusion principle.” The SDT does
not state what conceptual value the term is intended to provide; on the assumption that it relates to a
distinction between transferring power from local generation to serve local load, and transferring
power over longer distances, FMPA suggests, as an alternative to simply deleting the word “bulk,” that
the Exclusion be revised to refer to “transfers of power from non-LN generation to non-LN load.”

Response: Exclusion E3.b was intended to be a combination of two similar properties when it was drafted for the second posting of the
BES definition. The SDT has received a number of comments indicating that these are two separate and distinct concepts, and has
revised Exclusion E3.b to provide more clarity.
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
The SDT prefers not to add demonstration criteria, such as the suggestion to provide a minimum of 2 years worth of data, within the
text of the BES definition. The SDT believes the language, particularly the word “always” adds sufficient clarity. No change made.
See response to Q7.
The SDT prefers to continue the use of the word “bulk” in the core paragraph of Exclusion E3. The SDT believes this clarifies an
important conceptual idea to the industry, and the term “bulk” is not intended to be definitional in this context. This paragraph
merely provides an introduction to the concept of the local network, and retaining the term “bulk” conveys the concept effectively.
The lettered sub-items under the core paragraph are the prescriptive and precise characteristics that the industry will use to
determine qualification for exclusion under Exclusion E3. No change made.
SERC Planning
Standards
Subcommittee

Yes

The term "non-retail generation" in E3a should be changed to simply "generation."

Response: The SDT has intentionally utilized the term “non-retail generation” in Exclusion E3.a in order to specifically isolate that
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Question 9 Comment

generation which is not situated behind the retail meter. It is important to retain this concept, since removal of the clarifier “nonretail” would cause candidate local networks with retail generation from obtaining this exclusion. No change made.
Balancing
Authority
Northern
California

Yes

It is preferred to hold reference to gross nameplate rating/threshold values until generation technical
justification is completed as part of Phase 2; these studies should apply to any real or reactive power
threshold reference.
For Exclusion E3-b using the phrase “[p]ower flows only into the LN” is too restrictive. An allowable
MW threshold of LN power producing resources should be deferred to the Phase 2 BES technical
analysis. Where no generation is present in the LN, it is recommended that an allowance for residual
flow through the LN.

Response: The SDT agrees that the threshold(s) for generation throughout the BES definition should be addressed in Phase 2 of this
effort; however, to satisfy the Commission’s directives in Order 743 and 743-A in a timely fashion, it is necessary to use a generation
threshold that is consistent with the in-force Statement of Compliance Registry Criteria. No change made.
The SDT feels strongly that in order for a local network to qualify for exclusion under the Exclusion E3 section of the definition, there
must be strict bounds and limits placed on the characteristics of the candidate facilities. Allowances for minor “out-flow” from the
local network, or “minimal” flow, as suggested in this comment, will lead to an inconsistent application of the definition and
therefore, a lack of bright-line quality in the definition. Situations such as what is proposed in this comment can be referred to the
Exception Process for possible exclusion from the BES. No change made.
Westar Energy

Yes

Redding
Electric Utility

Yes

City of
Redding

Yes

Farmington
Electric Utility

Yes

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Question 9 Comment

System
Oncor Electric
Delivery
Company LLC

Yes

Utility
Services, Inc.

Yes

LCRA
Transmission
Services
Corporation

Yes

Memphis
Light, Gas and
Water Division

Yes

Harney
Electric
Cooperative,
Inc.

Yes

PSEG Services
Corp

Yes

Puget Sound
Energy

Yes

American
Electric Power

Yes

HEC believes that local networks should be excluded from the BES and agrees with exclusions to the
definition.

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Yes or No

NV Energy

Yes

Oregon Public
Utility
Commission
Staff

Yes

Z Global
Engineering
and Energy
Solutions

Yes

Chevron
U.S.A. Inc.

Yes

Metropolitan
Water District
of Southern
California

Yes

Duke Energy

Yes

Idaho Falls
Power

Yes

FirstEnergy
Corp.

Yes

Exelon

Yes

Western Area

Yes

Question 9 Comment

This provision complements E1 in defining the difference between distribution and transmission

We support the exclusion as drafted.

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Question 9 Comment

Power
Administration
IRC Standards
Review
Committee

Yes

Texas RE NERC
Standards
Subcommittee

Yes

WECC Staff

Yes

Southwest
Power Pool
Standards
Review Team

Yes

BGE

Yes

This Exclusion and Exclusion E1 aid in the delineation of distribution versus transmission.

No comment.

Response: Thank you for your support.

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10.

The SDT has added specific exclusions to the core definition in response to industry comments. Do you agree with Exclusion E4
(reactive resources)? If you do not support this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.

Summary Consideration: Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices. The
comments received identified overwhelming support of Exclusion E4 as written.
Some commenters questioned the use of the word ‘retail’ in Exclusion E4. The SDT determined that retention of this word is important
and correct. This is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the Load side of a
customer meter) and would otherwise be included via the core definition and/or Inclusion I5.
Other commenters proposed adding the same threshold qualification language contained in other exclusions. Using a threshold for
inclusion of non-generator Reactive Power resource devices in the BES will be considered in Phase 2 of this effort. The SDT
acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects (i.e., the
bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being responsive to
the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not
afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a change from the
current values that exist through the application of the definition today. These and similar issues have prompted the SDT to separate the
project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities. Therefore,
the SDT will consider all recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2 of Project
2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for modifications to the existing
values.
No changes were made to the definition as a result of these comments.
Organization
Westar Energy

Yes or No

Question 10 Comment

No

This particular Exclusion doesn’t address the qualifier as to the impact to the BES. We
believe the qualification language in E2, in regards to behind the meter generation,
should also be included in Exclusion E4 for clarification purposes.

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Organization
Southwest Power Pool
Standards Review Team

Yes or No

Question 10 Comment

No

This particular Exclusion doesn’t address the qualifier as to the impact to the BES. We
request that it emulate the language provided for E2 (behind the meter gen) and
classified for this specific exclusion.

Response: Using a threshold for inclusion of non-generator Reactive Power resource devices in the BES will be considered in Phase 2
of this effort. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
ISO New England Inc

No

The term “retail customer” is unclear and will lead to confusion.
This exclusion should be removed as there are many instances where a generator may
be using the reactive power device to meet other interconnection requirements and
the reactive device should be held to the same BES requirements as the generator.

Response: The SDT team considered the disposition of the word “retail” in the context of E4, and determined that retention of this
word is important and correct. This is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the
load side of a customer meter). No change made.
Exclusion E4 is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the load side of a
customer meter) and would otherwise be included via the core definition and/or Inclusion I5. No change made.
Central Maine Power
Company

No

Consider using other wording to replace “retail”

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Question 10 Comment

Response: The SDT team considered the disposition of the word “retail” in the context of E4, and determined that retention of this
word is important and correct. This is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the
load side of a customer meter). No change made.
Metropolitan Water District of
Southern California

No

Exclusion 4 appears to limit the devices just to retail customers. However, any enduser load, including wholesale or retail, should be included. NERC's Glossary of Terms
uses the phrase "end-use customer", not retail customers to describe loads. MWDSC
recommends that Exclusion 4 be changed as follows: E4 - Reactive Power devices
owned and operated by an end-use customer solely for its own use.

Response: The SDT team considered the disposition of the word “retail” in the context of E4, and determined that retention of this
word is important and correct. This is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the
load side of a customer meter). No change made.
The Dow Chemical Company

No

The term “solely” should be replaced by the term “primarily”. All devices to control
Reactive power behind-the-meter arguably provide some benefit to the transmission
grid.

Response: The SDT does not believe these changes provide additional clarity. No change made.
LCRA Transmission Services
Corporation

No

This exclusion conflicts with inclusion item I5. Which one takes priority?

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
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Question 10 Comment

breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
Ameren

No

a)Reactive Power devices connected 100 kV and above applied for the purpose of
voltage support to local load and/or local area network should also be excluded.

Response: Reactive Power devices connected at 100kV and above are included in the core definition. Exclusion E1 provides for the
exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the exclusion language. This does
not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The exclusion (E1) only speaks to
the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner.

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Question 10 Comment

The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element as defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind-the-retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
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Yes or No

Question 10 Comment

An entity can always request an exception through the Exception Process. No change made.
Tillamook PUD

No

Any device that might be excluded under E4 has already been included per I5. Unless
I5 is removed, or rewritten as suggested above; this exclusion will exclude nothing.

Central Lincoln

No

Please see Central Lincoln’s answers to Q1 and Q6. Any device that might be excluded
under E4 has already been included per I5. Unless I5 is removed, or rewritten as
suggested above; this exclusion will exclude nothing.

Northern Wasco County PUD

No

Please see Northern Wasco County PUD’s answers to Q1 and Q6. Any device that
might be excluded under E4 has already been included per I5. Unless I5 is removed, or
rewritten as suggested above; this exclusion will exclude nothing.

Response: Please see responses to Q1 and Q6.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element as defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
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Yes or No

Question 10 Comment

language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind-the-retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices. No change made.
Northeast Power Coordinating
Council

No

Consider using other wording to replace “retail”. The statement “owned or operated
by the retail customer” is confusing and arguably inaccurate and should be revised.
Refer to comments related to reactive resources for Question 6 regarding Inclusion I5.
Retail and non-retail generation should be defined.

Response: The SDT team considered the disposition of the word “retail” in the context of E4, and determined that retention of this
word is important and correct. This is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the
load side of a customer meter). No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
American Electric Power

No

Does this refer to distribution level or reactive power resources? If so, it would appear
these are not included as part of I5. Or instead, does this refer to customer equipment
at BES voltages? If it is the latter, we recommend E4 be reworded to state “Reactive
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Yes or No

Question 10 Comment
Power devices that meet the Inclusion criteria of I5 that are owned and operated by
the retail customer solely for its own use...”

Response: Distribution devices are not included.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
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Yes or No

Question 10 Comment

interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power
Cooperative

Yes

Ownership is irrelevant, so “owned and operated by the retail customer solely for its
own use”, should be replaced by “owned and operated solely in conjunction with
specific industrial customer loads.”

Response: The SDT does not believe this change provides additional clarity. No change made.
NESCOE

Yes

While we are generally supportive of this exclusion, the term “retail” needs to be
clarified (i.e., are retail customers of all sizes intended to be excluded?).

Massachusetts Department of
Public Utilities

Yes

While we are generally supportive of this exclusion, the term “retail” needs to be
clarified (i.e., are retail customers of all sizes intended to be excluded?).

Response: The SDT reviewed your comment and believes that ‘retail’ is the correct terminology. This is meant to eliminate nongenerator Reactive Power devices that (are owned and operated on the load side of a customer meter. No change made.
Using a threshold for non-generator Reactive Power resource devices in the BES will be considered in Phase 2 of this effort.
Long Island Power Authority

Yes

Exclusion should identify a maximum value.

Response: Using a threshold for non-generator Reactive Power resource devices in the BES will be considered in Phase 2 of this
effort. No change made.
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Organization
ExxonMobil Research and
Engineering

Yes or No

Question 10 Comment

Yes

The BES SDT should work on clarifying the differences between Inclusion I5 and
Exclusion E4. The phrase “solely for its own use” in Exclusion E4 is vague and open to
interpretation. It is unclear whether equipment, such as power factor correction
facilities, surge capacitors located in motor terminal boxes and excitation capacitors
installed for use by a motor located on the low side of a 138 kV primary transformer
would be excluded from the BES.

Response: It is the intent of the SDT that distribution devises are not included in the BES.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify
the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between
BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected
at 100 kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term
Element is needed. Element as defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions
I2 – I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local
networks) should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion
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Yes or No

Question 10 Comment

I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind-the-retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion
I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element.
No change made.
Springfield Utility Board

Yes

Reactive power devices used to serve radial networks or Local Networks are often
owned and operated by the registered entity (not the “retail customer”) to address
Area Network - wide reactive power issues. This language should read:”E4. Reactive
power devices that are within a radial system excluded under E1 or within a local
network excluded under E3” If the current draft language is left as it is, there will likely
be a lot of unnecessary paperwork to exclude reactive power devices within radial
system or local networks from the BES through the exclusion process. SUB suggests
that the language in the E4 Exclusion be consistent with that in the I5 Inclusion.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
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Yes or No

Question 10 Comment

Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
SERC OC Standards Review
Group

Yes

NERC Staff Technical Review

Yes

SERC Planning Standards
Subcommittee

Yes

Florida Municipal Power

Yes
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Yes or No

Question 10 Comment

Agency
WECC Staff

Yes

Bonneville Power
Administration

Yes

Texas RE NERC Standards
Subcommittee

Yes

Balancing Authority Northern
California

Yes

ACES Power Marketing
Standards Collaborators

Yes

Dominion

Yes

Pepco Holdings Inc and
Affiliates

Yes

Transmission Access Policy
Study Group

Yes

Electricity Consumers
Resource Council (ELCON)

Yes

Southern Company
Generation

Yes

This is a needed exception to Inclusion I5 as these reactive power resources are used
by retail customers for power factor correction at their own facilities in order avoid
imposed power factor penalties.

This is a needed exception to Inclusion I5 as these reactive power resources are used
by retail customers for power factor correction at their own facilities in order avoid
imposed power factor penalties.

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Organization

Yes or No

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

Yes

MRO NERC Standards Review
Forum (NSRF)

Yes

IRC Standards Review
Committee

Yes

Tennessee Valley Authority

Yes

Hydro One Networks Inc.

Yes

Tri-State GandT

Yes

Western Area Power
Administration

Yes

Texas Industrial Energy
Consumers

Yes

PacifiCorp

Yes

Southern Company

Yes

FirstEnergy Corp.

Yes

Exelon

Yes

Michigan Public Power Agency

Yes

Question 10 Comment

Yes, MPPA and its members support the revised language because retail reactive
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Yes or No

Question 10 Comment
devices are used to address local customer or retail voltage issues, rather than voltage
issues on the interconnected bulk grid, and such local devices should therefore be
excluded from the BES definition.

Idaho Falls Power

Yes

ReliabilityFirst

Yes

Ontario Power Generation Inc.

Yes

Central Hudson Gas and
Electric Corporation

Yes

City of Anaheim

Yes

Chevron U.S.A. Inc.

Yes

Duke Energy

Yes

Clallam County PUD No.1

Yes

NV Energy

Yes

Z Global Engineering and
Energy Solutions

Yes

Consumers Energy

Yes

We have no comments.

Yes, CLPD supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

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Organization

Yes or No

Question 10 Comment

Puget Sound Energy

Yes

Manitoba Hydro

Yes

City of St. George

Yes

Orange and Rockland Utilities,
Inc.

Yes

Blachly-Lane Electric
Cooperative (BLEC)

Yes

BLEC supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Coos-Curry Electric
Cooperative (CCEC)

Yes

CCEC supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Central Electric Cooperatve
(CEC)

Yes

CEC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Clearwater Power Company
(CPC)

Yes

CPC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Snohomish County PUD

Yes

Yes, SNPD supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
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Yes or No

Question 10 Comment
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Consumer's Power Inc.

Yes

CPI supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Douglas Electric Cooperative
(DEC)

Yes

DEC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Fall River Rural Electric
Cooperative (FALL)

Yes

FALL supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Lane Electric Cooperative
(LEC)

Yes

LEC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Lincoln Electric Cooperative
(LEC)

Yes

LEC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Northern Lights Inc. (NLI)

Yes

NLI supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
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Organization

Yes or No

Question 10 Comment
the BES definition.

Okanogan County Electric
Cooperative (OCEC)

Yes

OCEC supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Pacific Northwest Generating
Cooperative (PNGC)

Yes

PNGC supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Raft River Rural Electric
Cooperative (RAFT)

Yes

RAFT supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

West Oregon Electric
Cooperative

Yes

WOEC supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

PSEG Services Corp

Yes

Hydro-Quebec TransEnergie

Yes

Independent Electricity
System Operator

Yes

Umatilla Electric Cooperative
(UEC)

Yes

UEC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
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Organization

Yes or No

Question 10 Comment
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Memphis Light, Gas and
Water Division

Yes

Harney Electric Cooperative,
Inc.

Yes

Cowlitz County PUD

Yes

Utility Services, Inc.

Yes

National Grid

Yes

Kansas City Power and Light
Company

Yes

Oncor Electric Delivery
Company LLC

Yes

Sacramento Municipal Utility
District

Yes

Georgia System Operations
Corporation

Yes

MEAG Power

Yes

Farmington Electric Utility
System

Yes

HEC agrees with E4.

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Organization

Yes or No

Question 10 Comment

South Houston Green Power,
LLC

Yes

Portland General Electric
Company

Yes

City of Austin dba Austin
Energy

Yes

Kootenai Electric Cooperative

Yes

ATC LLC

Yes

Redding Electric Utility

Yes

City of Redding

Yes

Tacoma Power

Yes

Tacoma Power supports the Exclusion E4 as currently written.

BGE

Yes

No comment.

KEC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Response: Thank you for your support.

357

11.

Are there any other concerns with this definition that haven’t been covered in previous questions and comments remembering
that the exception criteria are posted separately for comment?

Summary Consideration: Comments received for Question 11 were mostly re-statements of comments expressed in the previous
questions. No changes were made to the core definition or Inclusions or Exclusions based solely on question 11 comments. However,
changes were made to the Implementation Plan to clarify the compliance obligation date of the revised definition as shown below.
Some commenters have expressed frustration over the lack of high level guidance for the exception process. The SDT understands the
concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like nothing better than to be
able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and an initial attempt at
doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could have come up
with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the commenters that
it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive
comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single
package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity
has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for
completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in
actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a
position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes
that the visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the
integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3,
and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity
decides to reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to
NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the
Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception
request. On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an
acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information
aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard and
fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by
358

either party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this
equation. Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information
needs to be supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result ofa sudden disturbance, including a cyber security incident, or
unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section
3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to
a question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase 2 of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase 1 of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.

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Some comments were received about the lack of a cost benefit analysis with regard to revision to the definition. The responsibilities
assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to improve clarity, to reduce
ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES Elements. The SDT’s efforts are
directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s concerns as expressed in the
directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has pursued a definition that remains as
consistent as possible with the existing definition, while not significantly expanding or contracting the current scope of the BES or
driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES definition has varying degrees of
Regional application and has resulted in different conclusions on what is currently considered to be part of the BES. This inconsistency in
the application and subsequent results were also identified by the Commission in Orders No. 743 and 743-A as a significant concern. The
SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in application of the current definition
there is a potential for varying degrees of impact on Regions. Without an approved BES definition any assumptions utilized in a cost
benefit analysis would be purely speculative and the results would have little meaning in regards to potential improvements in the
reliable operation of the interconnected transmission grid on a continent-wide basis. Therefore, the SDT believes that best opportunity
to address cost concerns will be through the development of Regional transition plans once the definition has been approved by the
Commission.
Several comments were received questioning how to apply the definition with the inclusions and exclusions. The application of the
draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast majority of BES
Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker,
bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application
of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific
criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.

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Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The
exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied
in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude an
Element.
Finally, there were comments on the lack of a technical basis for the threshold values employed in the definition. The SDT
acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects (i.e., the
bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being responsive to
the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not
afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a change from the
current values that exist through the application of the definition today. These and similar issues have prompted the SDT to separate the
project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities. Therefore,
the SDT will consider all recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2 of Project
2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for modifications to the existing
values.
Implementation Plan - Compliance obligations for all newly identified Elements included by the definition shall begin 24 months after
the applicable effective date of the definition.

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SERC OC Standards Review
Group

Yes or No

Question 11 Comment

Yes

The definition of the BES is referenced in several existing standards and the Statement
of Compliance Registry Criteria. The SERC OC standards Review Group is concerned
how this revised definition will impact entity registration, i.e., how will the revised
definition be integrated into the Compliance Registry Criteria. The implementation
plan should include how the integration is going to occur.
The Rules of Procedure exception process should be further defined or referenced in
this definition.”The comments expressed herein represent a consensus of the views of
the above named members of the SERC OC Standards Review Group only and should
not be construed as the position of SERC Reliability Corporation, its board or its
officers.”

Southern Company

Yes

The definition of the BES is referenced in several existing standards and the Statement
of Compliance Registry Criteria. Southern Companies are concerned how this revised
definition will impact entity registration, i.e., how will the revised definition be
integrated into the Compliance Registry Criteria. The implementation plan should
include how the integration is going to occur.
The Rules of Procedure exception process should be further defined or referenced in
this definition.

Response: The revised definition of Bulk Electric System will be applied in the same manner as it is today. This is based on language
contained in FERC Order No. 693, which states: “…the Commission will rely on the NERC definition of bulk electric system and NERC’s
registration process to provide as much certainty as possible regarding the applicability to and the responsibility of specific entities to
comply with the Reliability Standards in the start-up phase of a mandatory Reliability Standard regime”. As the SDT progresses
through Phase 2 of the project, it is envisioned that the technical aspects contained in the definition and in the ERO Statement of
Compliance Registry will be merged and ultimately incorporated into the definition of the Bulk Electric System. At that time the ERO
Statement of Compliance Registry Criteria will be revised to point to the BES definition for the technical aspects in regards to BES
Elements. No change made.
The Rules of Procedure exception process is referenced in the current draft version of the BES definition in a note which states: “Note
- Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process”. No change made.
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Northeast Power Coordinating
Council

Yes or No
Yes

Question 11 Comment
Technical bases have not been provided for the proposed definition of the BES.
Additionally, the cost impacts have not been assessed and weighed against
thepotential benefits of this proposal.
There is confusion arising from the construction and interactions of the Inclusion, and
Exclusion sections.
System diagrams, put in a separate guidance document, would help in understanding.
The situation of using Exceptions to understand Exclusions must be avoided. Suggest
consider incorporating Inclusions directly, and leave the Exclusions as is format wise.
The Implementation period discusses a 24 month timeframe ( the Order suggests 18)
from when the standard becomes effective to begin Compliance obligations. If
construction is required to become compliant or meet performance requirements
with standards, or CIP Version 5 standards increase the amount of BES assets this will
be insufficient when considering budgeting, designing, siting requirements, and
permitting.
Concern exists over the paradigm that the definition should “mirror” the NERC
Compliance Registry Criteria regarding who is registered. Some RSC members believe
the definition should drive any changes to the registry criteria and not the criteria
perpetuating the thresholds in the definition. However, there is a need to confirm
that Phase 2 of this project will address this.
The Inclusions and Exclusions listed need clarifications and perhaps diagrams and
accompanying guidelines to clarify and explain the intent.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
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Question 11 Comment

and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s
concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has pursued a
definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting the
current scope of the BES or driving registration or de-registration. The technical aspects of the definition have remained identical to
the current definition and identical to the application of the ERO Statement of Compliance Registry Criteria and therefore do not
require a technical justification to support maintaining the status-quo.
The SDT acknowledges that the current BES definition has varying degrees of Regional application and has resulted in different
conclusions on what is currently considered to be part of the BES. This inconsistency in the application and subsequent results were
also identified by the Commission in Orders No. 743 and 743-A as a significant concern. The SDT acknowledges that by developing a
bright-line definition coupled with the inconsistency in application of the current definition there is a potential for varying degrees of
impact on Regions. Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative
and the results would have little meaning in regards to potential improvements in the reliable operation of the interconnected
transmission grid on a continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be
through the development of Regional transition plans once the definition has been approved by the Commission.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
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Question 11 Comment

breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
The development of a guidance document which contains generic diagrams is a portion of the overall project that the SDT feels is
necessary to ensure the consistent application of the BES definition going forward. Therefore the SDT has determined that such a
document will be developed during Phase 2 of the project.
The SDT agrees that a potential reformatting of the definition (core, Inclusions and Exclusions) would improve the understanding of
the application of the definition. However, these types of changes would require a significant amount of revisions to the current draft
and could be seen as substantive in nature and prevent the SDT from moving forward with a recirculation ballot. This scenario would
require a successive ballot which would place the project schedule in jeopardy of achieving a successful filing by January 25, 2012. The
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Question 11 Comment

SDT will be exploring the reformatting of the definition (core, Inclusions and Exclusions) during Phase 2 of the project.
In proposing a 24 month period in the Implementation Plan before the definition is applied in assessing compliance obligations, the
SDT considered several activities that may require additional time to complete for an entity to become fully compliant. One of these
activities is the development of transition plans in cases where significant issues may have been identified as potentially preventing an
entity from meeting the compliance obligations within the 24 month period. These transition plans are to be developed by the
Regional Entity and the Registered Entity in a cooperative manner to best address the identified concerns and establish an agreed to
mitigation plan which results in full compliance by the Registered Entity.
Phase 1 of the project, as explained above, is addressing Commission directives established in Order No. 743 within a relatively short
time period. The SDT has decided to maintain the status quo with respect to applicability and the technical aspects contained in the
ERO Statement of Compliance Registry Criteria as the prudent path to take to ensure a successful conclusion to Phase 1 of the project.
The status quo was established in FERC Order No. 693, which states: “…the Commission will rely on the NERC definition of bulk
electric system and NERC’s registration process to provide as much certainty as possible regarding the applicability to and the
responsibility of specific entities to comply with the Reliability Standards in the start-up phase of a mandatory Reliability Standard
regime”. As the SDT progresses through Phase 2 of the project, it is envisioned that the technical aspects contained in the definition
and in the ERO Statement of Compliance Registry will be merged and ultimately incorporated into the definition of the Bulk Electric
System. At which time the ERO Statement of Compliance Registry Criteria will be revised to point to the BES definition for the
technical aspects in regards to BES Elements.
Westar Energy

Yes

We believe a reference should be made to the ROP changes which also provide a
mechanism whereby Elements may be excluded or included in the BES. Without that
reference, the proposed definition is not all inclusive of all means for exclusions or
inclusions. We would suggest the definition be expanded to say “Unless modified by
the lists shown below or as provided by Appendix 5C of the NERC Rules of Procedure,
all Transmission...” This comment was submitted in response to the original posting
and the response received was that it was inadvertently left out and that it would be
placed back in, but we don’t see the reference in this draft of the definition.

Southwest Power Pool
Standards Review Team

Yes

A reference needs to be made to the ROP changes which also provide a mechanism
whereby Elements may be excluded/included in the BES. Without that reference the
proposed definition does not completely include all means for exceptions/inclusions.
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Yes or No

Question 11 Comment
We would suggest the definition be expanded to say ‘...modified by the list shown
below or as provided by Appendix 5C of the NERC Rules of Procedure. We submitted
this in the original posting and the response received was that it was inadvertently left
out and that it would be placed back in. We don’t see the reference in this draft of the
definition.

Response: The Rules of Procedure exception process is referenced in the current draft version of the BES definition in a note which
states: “Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process”. No
change made.
WECC Staff

Yes

Following are additional comments not covered in previous questions: o Under the
section “Effective Dates”: There may be confusion with the statement “Compliance
Obligations for Elements included by definition shall begin 24 months after the
applicable effective data of the definition.” The phrase “included by definition” can be
interpreted broadly.
o WECC notes that a generation threshold of 75MVA is specified in Exclusions E1, E2,
and E3. WECC believes that generation thresholds for Exclusions should be addressed
in Phase 2 when generation thresholds for Inclusions are being considered.

Response: The complete statement from the Implementation Plan states: “Compliance obligations for all newly identified Elements
included by the definition shall begin 24 months after the applicable effective date of the definition.” The SDT’s intent with this
language is to identify newly identified BES Elements based on the revised definition. In other words, Elements that were not
considered to be BES Elements based on the exiting definition of BES in the NERC Glossary of Terms, but are now included as a result
of revising the exiting definition. The Implementation Plan has been clarified as shown:
Implementation Plan - Compliance obligations for all newly identified Elements included by the definition shall begin 24 months
after the applicable effective date of the definition.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects
(i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being
responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012,
and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a
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Organization

Yes or No

Question 11 Comment

change from the current values that exist through the application of the definition today. Phase 1 of the project is addressing
Commission directives established in Order No. 743 within a relatively short time period. Therefore the decision to maintain the status
quo as far as application of the definition and the technical aspects contained in the ERO Statement of Compliance Registry Criteria is
the prudent path to take to ensure a successful conclusion to Phase 1 of the project. The status quo was established in FERC Order No.
693, which states: “…the Commission will rely on the NERC definition of bulk electric system and NERC’s registration process to
provide as much certainty as possible regarding the applicability to and the responsibility of specific entities to comply with the
Reliability Standards in the start-up phase of a mandatory Reliability Standard regime”. These and similar issues have prompted the
SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory
authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for
inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC
Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide compelling
justification for modifications to the existing values. No change made.
ExxonMobil Research and
Engineering

Yes

It would be worthwhile to explain the relationship (timeline) between the BES
Definition implementation plan and the compliance implementation plan proposed in
the BES RoP team’s new Appendix 5C for the NERC Rules of Procedure.

Texas RE NERC Standards
Subcommittee

Yes

It might be worthwhile to explain the relationship (timeline) between the BES
Definition implementation plan and the compliance implementation plan proposed in
the BES RoP team’s new Appendix 5C for the NERC Rules of Procedure.

Response: For a newly identified Element(s) under the revised BES definition, the time period to be in full compliance with all
applicable Reliability Standards is 24 months from the effective date of the definition. If the entity wishes to file for an exception of a
newly identified Element(s) under the revised BES definition through the Rules of Procedure Exception Process, the entity will have 12
months from the effective date of the revised BES definition in which to file such a request. If the exception request is rejected or
disapproved and the classification of the Element(s) remains as a BES Element, the Regional Entity and the owner of such a BES
Element(s) shall agree to an Implementation Plan for full compliance obligations, which will establish an implementation date no
earlier than the date established by the definition Implementation Plan (24 months from the effective date of the definition).
Dominion

Yes

As a general policy, Dominion believes that attempting to precisely refine the
definition of the BES may not be the best way to insure BES reliability. Instead,
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Question 11 Comment
industry effort should be focused on developing specific reliability standard
requirements targeted toward solving problems that need to be addressed. Stated
differently, every Element that could have an impact on the BES does not need to be
included in the definition of the BES. NERC’s Functional Model addresses the broad
range of functions performed by the electric utility industry. When reliability concerns
are identified and can best be addressed via a standard, modifying the requirements
in that standard as applicable to that functional model should occur rather than
attempting to modify the BES definition. Effort spent on developing specific reliability
standard requirements mentioned above is superior to the industry engaging in
definitional debates that do not address to the underlying reliability drivers. It is not
essential that each reliability standard explicitly apply to each registered entity. The
existing reliability requirements, as applied to the various functional entities require
communication of information necessary to insure there are no reliability gaps, either
directly or indirectly among the various entities. The existing standards typically have a
hierarchy wherein: o Planners (PA, TP) receive information predominately from the
owners (GO, DP, TO) and those that represent end-use customers (LSE and PSE); o
Reliability entities (BA, RC and TOP) receive information predominately from operating
entities (GOP, TOP) and those that represent end-use customers (LSE and PSE); o
Planners provide reliability assessments to Reliability entities (BA, RC and TOP) and
receive feedback on these reliability assessments (including validity of assumptions
and result); and o Reliability entities (BA, RC and TOP) give instructions (including
when necessary directives) to operating entities (GOP, TOP) and those that represent
end-use customers (LSE and PSE). This is how the industry has historically operated,
how it operates today and why the standards in place today are structured as they
are. Reliability is best served when the standards themselves contain the appropriate
requirements and are applied to either an Element or Facility or to the appropriate
functional entity (DP, GO, GOP, LSE, TO, TOP, etc.). Definitional boundaries can create
the potential for false positives in reliability and, in fact, may be detrimental to
reliability in the longer term if they impose additional compliance burdens without
closing a reliability gap.
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Question 11 Comment

Response: The SDT acknowledges and appreciates the comments and recommendations associated with concepts for alternatives to
the revision of the exiting definition of BES. However, the SDT has responsibilities associated with being responsive to the directives
established in Orders No. 743 and 743-A, and is bound to answering those directives in a manner that achieves industry consensus
while remaining responsive to the language contained in the Orders. No change made.
Pepco Holdings Inc and
Affiliates

Yes

1) From the proposed BES definition and Exclusion E1 it is very clear that a 138-12kV
distribution transformer serving radial load would not be considered part of the BES.
However, suppose this transformer was connected to a position in a ring-bus or a
breaker-and-a-half arrangement. Would the physical bus between the transformer
high side terminals and the two breakers in the ring-bus, or breaker-and-a-half-bus, be
considered part of the BES? They would be contiguous transmission elements (bus)
operating at 138kV and supplying a radial distribution transformer. Also, tripping of
this “radial” bus section would not interrupt any BES facilities, due to the station bus
arrangement. As such, by definition and Exclusion E1 this 138kV bus section (element)
would not be part of the BES, and no special exclusion filing would be required. Is this
correct? However, take the same 138-12kV transformer but this time connected in a
typical line-bus arrangement. The transformer by definition is not a BES element. As
was the case above, the bus section between the transformer and the two breakers in
the line-bus would be contiguous elements (bus) operating at 138kV and supplying a
radial distribution transformer. Again, by definition and Exclusion E1 this bus section
(element) would not be part of the BES. However, in this case tripping of the “radial”
bus section would result in an interruption to the through path of the station, and
could therefore interrupt the through flow on BES facilities. Does this make either the
transformer, or its associated bus section, or both part of the BES? Based on the
above examples, if the type of bus connection could influence whether an element is
included in the BES or not, then additional language needs to be added to the
definition (either as an Inclusion or Exclusion) to make this point clear. The BES
definition needs to be specific enough to eliminate any confusion as to what is
included, and what is not included, and thereby greatly minimize, if not eliminate, the
need to request interpretations. A sample FAQ document, with examples, would be
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Question 11 Comment
extremely helpful, but should not be a substitute for a BES description which leaves
little room for interpretation.
2) As seen from the above attempt to describe issues that need clarification, without
a diagram to show specific situations, it is difficult to fully explain the concerns on
ensuring that the BES definition stands on its own. Since the commenting process
does not accommodate diagrams, PHI is sending separately a white paper with
diagrams in an attempt to clarify the definition and make it as unambiguous as
possible, leaving little room for interpretation. This paper may be helpful in developing
a FAQ document.
3) The definition should state that it applies to a system “normal” configuration. It
does not include maintenance or N-1 or any abnormal configurations.
4) There was no place on the comment forms to comment on the proposed
Implementation Plan for the BES definition. So comments are included here. The
proposed plan states “compliance obligations for Elements included by the definition
shall begin 24 months after the applicable effective date of the definition." This is
fine for most applications; however, there is an effect with PRC-005 compliance. PRC005 (Protection System Maintenance Standard) requires that evidence for the last two
maintenance intervals, in order to demonstrate that you are following the prescribed
intervals in your maintenance plan. If additional facilities are brought into scope by
the new BES definition, and the protection systems associated with these facilities
were not previously maintained on the same interval as other BES facilities, then it
may not be possible within the allotted 24 months to demonstrate the facilities were
maintained within the prescribed intervals for BES facilities. An implementation plan
at least as long as one full maintenance cycle would be required to assure compliance.
This issue needs to be addressed or coordinated with PRC-005.

Response: 1) Exclusion E1 identifies a Radial system as “a group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher” (with additional criteria identified in parts E1a, b and c). The SDT interprets the language
‘single point of connection’ as a tapped point where the radial system originates. Therefore in a ring-bus, a breaker-and-a-half or a
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typical line bus arrangement, the bus between the breakers and the breakers themselves are considered to be BES Elements. Under
these circumstances the bus position is the ‘single point of connection’, not a contiguous group of Elements as suggested in the
comment.
2) The development of a guidance document which contains generic diagrams is a portion of the overall project that the SDT feels is
necessary to ensure the consistent application of the BES definition going forward. Therefore the SDT has determined that such a
document will developed during Phase 2 of the project.
3) The SDT does not believe that system state affects the definition and therefore there is no need to declare that the definition only
applies to normal state. No change made.
4) The BES definition Implementation Plan addresses the implementation of the revised definition. The SDT is not in a position to
comment on compliance obligations associated with the Reliability Standards. However, in circumstances where data may not be
available due to the revised definition requirements, the SDT expects an entity to work with its Regional Entity to come up with a plan
to satisfy the obligation.
Southern Company
Generation

Yes

1) On page 1, the year of the anticipated date for the BOT adoption is correctly 2012.
2) We believe that the last two sentences of the first paragraph of the Background
Information section of the 2nd draft of the definition document is incorrect. The
statements read: " It should be noted that the revised definition does not address
functional entity registration or standards requirements applicability. Those are
separate issues." The definition of the BES that is approved will govern the scope of
the equipment that is relevant to many of the reliability standards. This issue cannot
be separated from the applicability of the requirements of the reliability standards.
What is the purpose of creating a continent wide definition of the BES if is is not to
provide instruction the enetties subject to the requirements of the standards? Refer
to these sample standard requirements to see that this definition already plays a
major part in the applicability of the requirements: EOP-005-2 R1, R4; EOP-006-2 R1;
EOP-008-1 R1; FAC-008-1 R1.2; and PRC-005-1a for example - there are many
others.

Response: 1) The SDT has made the revision to the BOT adoption date to correctly identify the year as 2012.
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2) The SDT acknowledges that the linkage between the BES definition and the Reliability Standards may have been understated in the
Background Information contained in the comment form. However, the goal of the SDT in addressing the Commission directives is to
develop modifications to the definition in response to the directives without significantly expanding or contracting the scope of the
BES and not drive registration changes in the industry. The SDT believes that they have met these goals, as evidenced by a detailed
review of the NERC Reliability Standards. The SDT determined that potentially the scope of applicability of certain requirements may
change due to the establishment of a bright-line definition. However, this potential change did not dictate a need for modification of
the language contained in the requirements.
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power
Cooperative

Yes

: AECI supports the bright-line concept, but believes the SDT should adopt a core
voltage threshold of “200 kV or higher”, and MVA capacity of “150 MVA or greater”. A
proper threshold is critical, because an inappropriately low threshold will divert
significant industry attention and resource away from what truly benefits the BES
reliability. (The number of facilities tend to rise more geometrically than linearly as
the voltage threshold drops.)We believe that an evaluation of the transmission-line
Surge Impedance Loading (SIL), at various kV levels, could provide technical insight as
to why many industry planning engineers believe sub-230kV Facilities, in general do
not belong within the BES. AECI suggests that the SDT consider a more consistent
bright-line facility threshold of 150 MVA capability for all equipment. This would
include transmission lines as well, where an Surge Impedance Loading analysis
demonstrates that lines below 230 kV, can support 150 MVA flow up to 280 miles
(applying 1.1 p.u. line-loadability of SIL, IEEE Transactions on Power Apparatus and
Systems, Vol.PAS-98, No.2 March/April 1979, p 609, Figure 7),without additional
reactive compensation. In comparison, single-conductor 138 kV lines, in same table,
can support 150 MVA transfers no more than 50 miles, while 345 kV lines are capable
of supporting 150 MVA transfers well over 600 miles.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
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and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values. No change made.
MRO NERC Standards Review
Forum (NSRF)

Yes

NSRF recommends that the following statement be added after I5. If an element is not
included based upon the core definition or I1 - I5, the elements is not consider to be a
part of the BES.

Response: The SDT is attempting through the BES definition to identify facilities that should be classified as BES Elements. Adding a
statement that emphasizes the opposite of what the definition is intending to accomplish would be redundant and would negate the
efforts of the SDT to improve clarity and remove the ambiguity that currently exists the definition today. No change made.
IRC Standards Review
Committee

Yes

(1) We support a phased approach proposed in the draft supplemental SAR.
Development of the revised BES definition is an important and complex undertaking.
The product of this work is fundamental to establishing the applicability of NERC
Reliability Standards. The issues identified for attention in Phase 2 of this project
warrant careful investigation and as such allowing additional time to properly research
and provide for stakeholders to vett them is justified. Specific to the assessment of
raising the generator rating threshold from 20 MVA to 75 MVA per unit, we would
point out that this needs to be looked at from a different perspective. Industry
debates so far have been on the apparent lack of reliability contribution and economic
benefits for keeping the threshold at 20 MVA. The former point implies that any
negative reliability impact that could be contributed by a generator higher than 20
MVA but lower than 75 MVA could be negligible. Some examples of the standards that
the 20-75 MVA units may need to comply with to ensure reliability are: o Voltage and
frequency ride through capability o Voltage control (AVR, etc.) o Underfrequency trip
setting o Protection relay setting coordination o Data submission for modeling;
verification of capability and model A Venn diagram developed by an industry group
shows that generators at 20 to 74.99 MVA account for about 13.8% of the total
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installed capacity in the US. Out of this, 3.0% are currently deemed non-BES whereas
the other 10.8% are BES. We do not know how the BES reliability may be affected if
these 10.8% generators are no longer deemed BES facilities (after an increase of
threshold to 75 MVA) and subject to compliance with NERC standards, including those
mentioned above. An assessment from both a positive contribution and a negative
impact viewpoints are thus required to aid the determination of the merit of raising
the rating threshold.
(2) The draft Implementation Plan for the BES definition states “Compliance
obligations for Elements included by the definition shall begin 24 months after the
applicable effective date of the definition.” We are concerned that the stated
implementation period may be insufficient time to complete transition plans for newly
identified BES Elements and Facilities, where those plans require procurement,
installation and commissioning of additional equipment. We believe a period of 24
months may be more appropriate.

Response: 1) The SDT agrees with the commenter that the best opportunity to address the industry concerns associated with the
technical aspects of the definition is through Phase 2 of the project. The SDT also agrees with the commenter in that any assessment
utilized to determine the correct threshold for generating resources should be accomplished without any preconceived threshold
value as a target for justification. The full scope of the assessments will be determined through a joint effort between the SDT and the
appropriate NERC Technical Committee.
2) In proposing a 24 month period in the Implementation Plan before the definition is applied in assessing compliance obligations, the
SDT considered several activities that may require additional time to complete for an entity to become fully compliant. One of these
activities is the development of transition plans in cases where significant issues may have been identified as potentially preventing an
entity from meeting the compliance obligations within the 24 month period. These transition plans are to be developed by the
Regional Entity and the Registered Entity in a cooperative manner to best address the identified concerns and establish an agreed to
mitigation plan which results in full compliance by the Registered Entity.
Tennessee Valley Authority

Yes

The definition of the BES is referenced in several existing standards and the Statement
of Compliance Registry Criteria. TVA is concerned with this revised definition’s impact
on entity registrations, i.e., how will the revised definition be integrated into the
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Compliance Registry Criteria.
The implementation plan should include how the integration is going to occur. The 24
month period for new facilities that are to become BES elements as a result of this
definition is very important to successful implementation of the definition. An period
shorter that 24 months would be very problematic for the industry.

Response: Phase 1 of the project, as explained above, is addressing Commission directives established in Order No. 743 within a
relatively short time period. The SDT has decided to maintain the status quo with respect to applicability and the technical aspects
contained in the ERO Statement of Compliance Registry Criteria as the prudent path to take to ensure a successful conclusion to Phase
1 of the project. The status quo was established in FERC Order No. 693, which states: “…the Commission will rely on the NERC
definition of bulk electric system and NERC’s registration process to provide as much certainty as possible regarding the applicability
to and the responsibility of specific entities to comply with the Reliability Standards in the start-up phase of a mandatory Reliability
Standard regime”. As the SDT progresses through Phase 2 of the project, it is envisioned that the technical aspects contained in the
definition and in the ERO Statement of Compliance Registry will be merged and ultimately incorporated into the definition of the Bulk
Electric System. At which time the ERO Statement of Compliance Registry Criteria will be revised to point to the BES definition for the
technical aspects in regards to BES Elements.
The SDT agrees with the commenter in regards to the implementation time period of 24 months. In proposing a 24 month period in
the Implementation Plan before the definition is applied in assessing compliance obligations, the SDT considered several activities that
may require additional time to complete for an entity to become fully compliant. One of these activities is the development of
transition plans in cases where significant issues may have been identified as potentially preventing an entity from meeting the
compliance obligations within the 24 month period. These transition plans are to be developed by the Regional Entity and the
Registered Entity in a cooperative manner to best address the identified concerns and establish an agreed to mitigation plan which
results in full compliance by the Registered Entity.
Hydro One Networks Inc.

Yes

o The definition of the Bulk Electric System (BES) is a foundational construct for the
North American Electric Reliability Corporation (NERC). FERC Orders 743 and 743-A do
not mandate a 100 kV approach. Instead, it states that a 100 kV bright line threshold
is one approach to defining the BES. It further states that only “some” 115/138 kV
facilities are necessary for the reliable operation of the bulk system. We believe that if
one subset issue (such as 20 MVA vs. 75 MVA) of the entire definition, requires more
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time and resources to arrive at the correct answer, the much larger and more
fundamental issue of how to define BES should not have been dismissed without the
appropriate analysis before another definition is proposed to be adopted by the ERO.
o The proposed definition, in combination with other new and/or modified Reliability
Standards such as newly modified and approved TPL Standards will require significant
system upgrades with high dollar investments. We are deeply concerned that a) no
such assessment has been undertaken by the SDT and/or the ERO and b) the proposed
definition of the BES is not based on a technical analysis that will enhance the
reliability of the interconnected transmission network.
o The NERC as the ERO should at least undertake a cost and incremental reliability
benefit analysis for its proposed definition of BES. Furthermore, cost impacts and
reliability benefit assessments of the BES definition coupled with other new and
modified reliability standards (such as the TPL Standards) must also be undertaken
and weighed against the potential benefits, if any, of this or any proposal. Not
providing such an assessment but using the 100 kV level as a starting point for the BES
definition, gives no assurances of benefits for any stakeholder including respective
governmental and regulatory authorities and rate payers in Canada or the USA.
o The proposed definition would significantly increase the population of BES elements.
Many of the standards requirements for these new elements will introduce
administrative burden and operating expenses. This would impose significant costs,
costs that ratepayers will have to bear, with little or no gain in reliability benefits for
the interconnected transmission system. We suggest that the resulting BES definition
must identify incremental reliability benefits by the ERO for the interconnected
transmission network based on sound technical analysis to justify the change to those
who will pay for any required system upgrades - the ratepayer.
o The draft Implementation Plan for the BES definition states “Compliance obligations
for Elements included by the definition shall begin 24 months after the applicable
effective date of the definition.” We are concerned that the stated implementation
period will give insufficient time to complete transition plans for newly identified BES
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Elements and Facilities, where those plans require approval, procurement, installation
and commissioning of additional equipment. We believe a period of 60 months at a
minimum is more appropriate.
Finally, we believe that the SDT proposed approach for exception criteria is reasonable
recognizing that one method/criteria can not be applicable to everyone and every
situation within the ERO footprint. However, we believe that there is a huge gap and
lack of any transparency on how the exception application will be evaluated and
processed. We strongly suggest that the SDT develop a reference or a guidance
document as part of the RoP that should provide guidance to Registered Entities,
Regional Entities and the ERO on how an exception application should be processed.
Else, (a) it will pose a challenge for each of the entities including ERO, and (b) may
introduce Regional discretion and be perceived as having no transparency for the
registered entities.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System including the 100
kV bright-line level. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which
will properly assess the threshold values and provide compelling justification for modifications to the existing values.
Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid on a
continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the development of
Regional transition plans once the definition has been approved by the Commission.
The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
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improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s
concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has pursued a
definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting the
current scope of the BES or driving registration or de-registration. The technical aspects of the definition have remained identical to
the current definition and identical to the application of the ERO Statement of Compliance Registry Criteria and therefore do not
require a technical justification to support maintaining the status-quo.
In proposing a 24 month period in the Implementation Plan before the definition is applied in assessing compliance obligations, the
SDT considered several activities that may require additional time to complete for an entity to become fully compliant. One of these
activities is the development of transition plans in cases where significant issues may have been identified as potentially preventing an
entity from meeting the compliance obligations within the 24 month period. These transition plans are to be developed by the
Regional Entity and the Registered Entity in a cooperative manner to best address the identified concerns and establish an agreed to
mitigation plan which results in full compliance by the Registered Entity.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like
nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion
and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If
the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to
point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little
in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
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has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result ofa sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
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disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase 2 of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase 1 of this project,
the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter
to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
Western Area Power
Administration

Yes

Yes, the definition should also provide clarification on mobile equipment installed to
support maintenance or equipment failures. Adding mobile equipment is a common
practice for our industry and should be addressed in the definition to bring a general
awareness and common understanding of the practice regarding the NERC standards.
Recommendation: Add the following Exclusion to BES definition for mobile
equipment. Exclude all mobile equipment on stand-by that has not been placed into
service as well as all components of mobile equipment that does not meet the
inclusion criteria for the primary function of the device being installed (e.g. ,battery
bank on mobile transformer installed on radial feed would also be excluded)

Response: The SDT acknowledges the commenter’s concern and has determined that the need for an exclusion identifying mobile
equipment is not appropriate. The SDT believes that the BES definition is identifying Elements that support the reliable operation of
the interconnected transmission grid. This premise implies that the Element is electrically connected to the system and is performing
a reliability related service. The SDT believes that the time the mobile equipment is placed in service is when the equipment would be
classified as a BES Element and subject to compliance obligations. No change made.
NESCOE

Yes

NESCOE offers the following additional comments: 1) Phased Approach. While wellintentioned, separating the BES definition project into two separate phases is
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problematic from both a procedural and substantive perspective. While we recognize
that the filing due date is rapidly approaching, the BES definition cannot be considered
in a vacuum, divorced from the concerns raised by a number of parties in response to
past postings of the BES definition. The issues NERC has identified for consideration
during the proposed “Phase 2” are inseparable from the development of the BES
definition and should be squarely addressed before a definition is adopted. In
particular, the development of criteria for determining what facilities are “necessary
for the reliable operation” of the interconnected system cannot be put off for a
second phase. Contrary to FERC’s direction, NERC’s proposal will force ratepayers to
incur costs related to compliance with mandates that may or may not be revised
through the second phase of the project. The importance of considering and resolving
such concerns before adopting a definition is heightened by the proposed two-year
implementation requirement. This short implementation period almost guarantees
that entities will commit resources shortly after adoption of the definition to ensure
compliance within the mandated period. In other words, ratepayers will bear costs
related to compliance irrespective of any change resulting from the Phase 2 process or
the exception process. Expediency, while understandable given the filing deadline,
must be balanced against the risk that a multi-phased approach could lead to
significant consumer costs without attendant meaningful reliability benefits.
2) Cost-Benefit Analysis. A cost impact analysis should be performed as part of
developing any reliability standard. However, the development of the BES definition
has failed to consider the cost impacts of the definition (and its inclusions and
exclusions) and weigh these impacts against identified benefits that the definition
would achieve. NESCOE stated in its May 21, 2011 comments on the last posting of
the BES definition that “any new costs a revised definition imposes - which fall
ultimately on consumers - should provide meaningful reliability benefits.” A costbenefit analysis should be integral to the development of a BES definition and, indeed,
any reliability standard. This analysis should include a probabilistic risk assessment
examining the likelihood of an event and the costs and risks resulting from such event,
which should be weighed against the costs of complying with the proposed reliability
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measures.
3) Technical Justification. In addition to performing a cost-benefit analysis, a technical
basis must be provided to justify a proposed reliability standard. However, as we state
above, the proposed BES definition does not provide a technical justification for the
100 kV threshold. Nor does it provide a technical justification for the threshold for
generation resources or other elements of the definition. As stated above, while wellintentioned and understandable, deferring this technical justification to a later and
separate phase of the project is a flawed and potentially costly approach. Providing a
technical justification for a reliability standard is a core function of standards
development and should be addressed at the forefront of the process rather than
relegated to a separate phase largely undertaken after a standard is filed.

Response: 1) The SDT acknowledges the commenter’s concerns; however the SDT (and the ERO) has an obligation to respond to the
Commission directives established in Order No. 743 within the time frame allotted by the Order. The narrow scope of the directives
and the limited timeframe for project completion has prevented the SDT from fully vetting the concerns of the industry as expressed
through the development process. To best address the Commission directives and stakeholder concerns, the SDT has opted to
separate the project into phases. The revised project plan has been fully endorsed by the NERC Members Representative Committee
and the Board of Trustees. Additionally the NERC Standards Committee has committed to the continued development of a revised
definition by retaining the project as a high priority project and by dedicating the resources necessary to fully vet the issues raised by
stakeholders.
2) The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s
concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has pursued a
definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting the
current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. Without an approved BES definition
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any assumptions utilized in a cost benefit analysis would be purely speculative and the results would have little meaning in regards to
potential improvements in the reliable operation of the interconnected transmission grid on a continent-wide basis. Therefore, the
SDT believes that best opportunity to address cost concerns will be through the development of Regional transition plans once the
definition has been approved by the Commission.
3) The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s
concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has pursued a
definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting the
current scope of the BES or driving registration or de-registration. The technical aspects of the definition have remained identical to
the current definition and identical to the application of the ERO Statement of Compliance Registry Criteria and therefore do not
require a technical justification to support maintaining the status-quo.
ReliabilityFirst

Yes

This definition needs to be clear and easy enough for anyone to pickup, read,
understand, apply and arrive at the same conclusion on whether the facility or
element is included or excluded. This definition leaves room for continued debate and
interpretation. To help make this definition clearer, ReliabilityFirst Staff has provided
a redline version of the core definition under a separate cover (file titled “Bulk Electric
System definition by RFC Staff 10-4-2011”).

Response: The SDT believes that the revised definition of the BES has provided the necessary clarity to allow for consistent application
on a continent-wide basis. The issues identified in the commenter’s redline (provided following the responses to question 11) have
been fully vetted by the SDT and addressed in the responses to the comments for the applicable question related to the specific issue.
Ontario Power Generation Inc.

Yes

Further to comments submitted in Question #1, OPG disagrees in general with
proceeding to implement a 100 kV brightline definition in the absence of a properly
quantified cost/benefit analysis. Entities are being asked to incur a high cost for no
demonstrated benefit in wide-area reliability.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
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pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. Without an approved BES definition
any assumptions utilized in a cost benefit analysis would be purely speculative and the results would have little meaning in regards to
potential improvements in the reliable operation of the interconnected transmission grid on a continent-wide basis. Therefore, the
SDT believes that best opportunity to address cost concerns will be through the development of Regional transition plans once the
definition has been approved by the Commission.
Central Hudson Gas and
Electric Corporation

Yes

Due to the movement to a phased BES definition development process and assuming
the definition is approved as proposed, there is an urgent need for NERC to provide
clear guidance to Registered Entities regarding how to proceed with facilities and
address changes to the NERC Compliance Registry registration obligations brought
in/on by the application of the new definition. The problem stems from a likely
scenario whereby the affected Registered Entities may be faced with an
Implementation Plan and an Exception Request Procedure which must be completed
prior to the completion of the Phase 2 definition development process. If that is the
case, many Registered Entities will be confronted with either (1) spending large
amounts of human and financial resources, not yet acquired, to address
facilities/procedures necessary to address possible new compliance obligations only to
find their efforts rendered unnecessary by the results produced in Phase 2 or, (2)
waiting until the results of Phase 2 are provided and risking being found noncompliant and subject to substantial penalties in the future. Neither option can be
viewed as a desirable, or for that matter, an acceptable position to be placed in.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
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pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. Therefore, the SDT believes that
best opportunity to address cost and resources issues will be through the development of Regional transition plans once the definition
has been approved by the Commission. The SDT recommends that the commenter pursue achieving full compliance with the revised
definition in the appropriate time period (see Implementation Plan) while utilizing the Rules of Procedure exception process to
specific exceptions from the BES definition.
Springfield Utility Board

Yes

When submitting BES Definition comments, SUB would suggest a “not-applicable”,
“no-impact” or “abstain” option in addition to “yes” or “no”. In some cases, the draft
language has no impact on an entity’s system, yet that entity’s selection of “yes” or
“no” may imply agreement or disagreement rather than expressing lack of
applicability. This could skew the perception of agreement or disagreement, and
create a potential issue for those who are directly impacted by the changes.

Response: The SDT understands the commenter’s concern; however the formatting of the comment form (including the electronic
version) is governed by the ERO and beyond the control of the SDT. Your comment will be forwarded to the NERC Standards staff for
consideration.
Mission Valley Power

Yes

Mission Valley Power - In order to help meet the fast approaching target date, Mission
Valley Power will be voting affirmative in this ballot, with the hope these comments
will be addressed in Phase 2. If the ballot should fail, please address these comments
in this phase. Thanks to the team for their good work.

Response: The SDT acknowledges and appreciates the continued support of the project. The SDT will consider all recommendations
for modifications to the technical aspects of the definition for project inclusion at the appropriate time during Project 2010-17
Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for modifications to the existing
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Yes

Con Edison shares the concerns raised by the State of New York Department of Public
Service (NYPSC) in its September 12, 2011 letter to NERC Chairman Anderson. The
NYPSC expressed concern that the proposed BES Definition “would impose significant
costs, costs that New York ratepayers will be expected to bear, with little or no
increase in reliability benefits.” The BES definition is being revised without an
assessment of costs or benefits. The SDT is encouraged to work with NERC Staff to
perform such an assessment prior to providing the revised BES definition to the NERC
Board. Regional Entities share this concern with cost effectiveness. In NPCC, the Board
of Directors directed NPCC Staff to develop a methodology to assess the cost and
benefit of Standards. This NPCC Cost Effectiveness Analysis Procedure (CEAP)
establishes a process to address those concerns. The CEAP introduces two
assessments of the estimated industry-wide costs of requirements into that
Standard’s development process. The procedure adds supporting information and
background for the NPCC stakeholders, ballot body and the NPCC Board of Directors.
Moreover, during a 2010 FERC technical conference the Commission recognized that
“reliability does not come without cost.” As a result, significant interest was expressed
in development of a process to identify the costs for draft reliability Standards and the
ability of the proposed standards to achieve the reliability objective(s) sought in a cost
effective manner. We understand that it is a NERC priority to define adequate level of
reliability and use it as the basis for determining the cost effectiveness of a proposed
rule. While this has not yet been finalized, NERC could use this proposed standard as
a test case for determining the relationship between costs and benefits.

values.
Consolidated Edison Co. of NY,
Inc.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
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definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. Without an approved BES definition
any assumptions utilized in a cost benefit analysis would be purely speculative and the results would have little meaning in regards to
potential improvements in the reliable operation of the interconnected transmission grid on a continent-wide basis. Therefore, the
SDT believes that best opportunity to address cost concerns will be through the development of Regional transition plans once the
definition has been approved by the Commission.
Northern Wasco County PUD

Yes

In order to help meet the fast approaching target date, Northern Wasco County PUD
will be voting affirmative in this ballot, with the hope these comments will be
addressed in Phase 2. If the ballot should fail, please address these comments in this
phase. Thanks to the team for their good work.

Tillamook PUD

Yes

If Tillamook PUD had signed up to ballot in time, we would be voting yes with the
hope that these comments would be addressed in Phase 2. If the ballot fails, please
address these comments in this phase.

Response: The SDT acknowledges and appreciates the continued support of the project. The SDT will consider all recommendations
for modifications to the technical aspects of the definition for project inclusion at the appropriate time during Project 2010-17
Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for modifications to the existing
values.
American Electric Power

Yes

There needs to be some clarification regarding the default status of an asset, as well as
the order and priority of the inclusion and exclusion classifications within the
definition. First, prior to any evaluation by virtue of the definition, is an asset by
default excluded from the BES, or rather, it is included? In addition, once the definition
is used to evaluate an asset which has both inclusion attributes and exclusion
attributes, which of the two classifications has greater weight? For example, if an asset
is first included by the BES definition inclusion criteria can it then be excluded by BES
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definition exclusion criteria? Or instead, if an asset is first excluded by BES definition
exclusion criteria can it then be included by the BES definition inclusion criteria? AEP’s
recommendation is that an asset, by default, not be considered part of the BES. Next,
the asset would be evaluated by the inclusion criteria as specified within the
definition. Next, any asset explicitly included by the inclusion criteria is then evaluated
using the exclusion criteria. Once the entity has made their determination based on
the definition, exception requests could then be made to include or exclude assets as
appropriate. We believe our interpretation is what is implied by the draft definition,
however, this needs to be explicitly communicated within the definition itself.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
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applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
City of St. George

Yes

The small utility exclusion issues discussed in the first draft of the documents are not
included (draft 1 proposed E4) nor addressed in the draft 2 documentation. Under the
present definition many small utilities with local generation to serve its own local load
will be required to register for additional functions, or at a minimum go through a
long, expensive, time consuming process to get an individual exclusion from the BES.
The topics that have been postponed to Phase 2 of the project are critical to and will
have a direct impact to many utilities. Phase 2 needs to have specific shorter than
normal timelines established, similar to what Phase 1 has had. The present definition
and standards in general makes little or no consideration for the actual impact of an
entity or facility on the bulk system. As such small utilities with a few miles of 115 kV
or 138 kV lines and some generation are required to meet the same requirements as
large utilities with 100’s or 1,000’s of miles of 345 kV or 500 kV lines and that operate
very large generation plants of several hundred MVA of capacity. All utilities support
reliability improvement, but the requirements and associated costs need to match
their actual impact to the overall system.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., potential small utility exclusion) of the BES definition. However, it is important to emphasize the fact that the
SDT is developing a definition to identify the Elements that support the reliable operation of the interconnected transmission network
regardless of ownership or operational responsibility. Small utility issues are very similar to the issues raised through the GOTO
project and are best addressed through the applicability of the individual reliability standards, not through the definition of the BES.
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Yes

There are a number of possible scenarios where an element falls under both an
inclusion and exclusion. The definition is unclear as to whether or not this would have
the element be BES or not. During the webinar an example was given about a static
shunt device meeting the requirements of I5, but is part of a radial network. The
response during the webinar was that this would be excluded. If this is correct, it
means that an exclusion takes precedence over an inclusion. Is this always the case?
This needs to be clarified and stated somewhere in this document.

No change made.
ISO New England Inc

To be consistent with regard to the terms “Operated at 100 kV” and “Connected at
100 kV “, we suggest that reference to generators should state, “Connected at a
transmission element operated at 100 kV”. This will avoid confusion in cases where a
generator is connected to a transmission element rated at 100 kV but operated at a
lower voltage.
Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
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Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
The BES definition refers to operating voltage (as emphasized in FERC Order No. 743-A) and the SDT does not feel that the language
“connected at a voltage of 100kV or above” creates any confusion on the intent of the Inclusion. No change made.
NBPT

Yes

o When an exclusion and inclusion principles overlap which takes precedence? For
example I5 may be excluded if in a LN (E3)
o The Local Network Exclusion criterion does not appear to consider voltage support
and the effects of shifting of load or impacts due to a loss of load. The 75 MW
generation threshold has no technical basis. The LN exclusion should allow for studies
demonstrating no through flow benefit regardless if there is.
o 75 MW Generation has no technical justification.
o Black Start resources should not be included in all GO/GOP standards except for
those standards specific to black start units.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
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identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
The local network exclusion has established a bright-line with specific characteristics that must be met to be eligible for exclusion.
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Exclusion E3b states: “Power flows only into the LN and the LN does not transfer energy originating outside the LN for delivery
through the LN". This characteristic applies under all operating conditions including any variations in network load. It is not clear to
the SDT what the commenter is referring to in regards to voltage support. Exclusion E3 addresses transmission Elements and does not
exclude Real Power or Reactive Power resources from the BES.
The concept of the 75 MVA threshold is based on the generation inclusion criteria for plant/facility arrangements by carrying through
the concept of the reliability impact that the aggregated loss of 75 MVA or greater would have on the overall reliability of the
interconnected transmission grid. The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has
responsibilities associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to
the filing deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
The SDT has determined that Blackstart Resources serve a reliability benefit to the interconnected transmission grid and therefore
have been included in the scope of the BES. This is consistent with current practice and specifically with the registration requirements
that identify the owner, operators, and users of Blackstart Resources be registered as Generator Owner/Generator Operator. Specific
concerns with the applicability of individual standards should be addressed through the Standard Development Process for the
individual Reliability Standards in question.
Texas Reliability Entity

Yes

(1) It is unclear exactly what is intended by “non-retail generation” in Exclusion E1(c).
We suggest that the term be explained or defined in the BES definition or in a
collateral document. This term does not have a commonly understood unambiguous
meaning in our Region.
(2) Phase 2 has to be completed or explicitly defined/scoped to fully capture all of the
components necessary for reliable operation of the BES.

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Response: (1) Non-retail generation is the generation on the system (supply) side of the retail meter.
(2) The supplemental SAR for Phase 2 of the project will be posted for industry comment at which time the SDT will be accepting
recommendations for specific issues to be addressed by the SDT during phase 2 of the project.
New York State Dept of Public
Service

Yes

o Per NERC’s obligations under the Energy Power Act of 2005 to provide FERC
technical advice, no technical justification has been provided for basing the BES
definition on the 100 kV and MVA thresholds.
o No cost analysis on either the reliability benefits of the overall definition or on the
implementation plan has been performed to determine whether the likely high cost of
the definition to ratepayers is justified.
o The definition of the BES should be the driver for the application of all other NERC
reliability standards and criteria. The definition uses the Statement of Compliance
Registry Criteria as a driver of the definition when the reverse should be taking place;
contents of the Statement should be driven by the BES definition.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the definition has not been altered in regards
to the bright-line or the generation thresholds and therefore does not require the development of technical justification to maintain
the status quo.
SDT acknowledges that the current BES definition has varying degrees of Regional application and has resulted in different conclusions
on what is currently considered to be part of the BES. This inconsistency in the application and subsequent results were also identified
by the Commission in Orders No. 743 and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line
definition coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on
Regions. Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the
results would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission
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grid on a continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the
development of Regional transition plans once the definition has been approved by the Commission.
The SDT has revised the language in Inclusion I2 to eliminate the circular reference to the ERO Statement of Compliance Registry
Criteria. Inclusion I2 has been revised to read:
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Hydro-Quebec TransEnergie

Yes

In the Implementation plan, it is given only 24 months for compliance after applicable
regulatory approval. Considering the possibility that a proposed transition plan may
involve commissioning of long term projects, a provision for such situation should be
made with longer delay.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. With that being said, the SDT
believes that an implementation time period of 24 months is sufficient time to address the development of regional transition plans,
address any necessary registration changes, file for exceptions through the Rules of Procedure exception process and address any
required training. The SDT also acknowledges that the potential exists for extenuating circumstances that will need to be addressed
through the regional transition plans.
Independent Electricity
System Operator

Yes

We wish to also express our support for phased approach proposed in the draft
supplemental SAR. Development of the revised BES definition is an important and
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complex undertaking. The product of this work is fundamental to establishing the
applicability of NERC Reliability Standards. The issues identified for attention in Phase
2 of this project warrant careful investigation and as such allowing additional time to
properly research and stakeholder them is justified. The draft Implementation Plan for
the BES definition sates “Compliance obligations for Elements included by the
definition shall begin 24 months after the applicable effective date of the definition.”
We are concerned that the stated implementation period may be insufficient time to
(1) prepare and file exception requests and have these assessed; and (2) in cases
where these exception requests are not approved, to develop and complete transition
plans for newly identified BES Elements and Facilities, particularly where those plans
require major investments for the procurement, installation and commissioning of
additional equipment. We therefore propose the following alternative wording for the
Implementation Plan: “Compliance obligations for elements included by the definition
shall be evaluated and an implementation schedule established within 24 months.”
Throughout the document various phrases are used to describe generating
units/resource, viz. “generation resources”, “generating resources”, “generating unit”
and “power producing resources”. Please review these to identify and address any
possible inconsistencies.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. With that being said, the SDT
believes that an implementation time period of 24 months is sufficient time to address the development of regional transition plans,
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address any necessary registration changes, file for exceptions through the Rules of Procedure exception process and address any
required training. The SDT also acknowledges that the potential exists for extenuating circumstances that will need to be addressed
through the regional transition plans.
The SDT has reviewed the applicable documents for inconsistencies related to the terms generating units/resource, viz. “generation
resources”, “generating resources”, “generating unit” and “power producing resources”. The SDT has made the appropriate
modifications to address any issues resulting from the inconsistencies.
Central Lincoln

Yes

We note that the SAR for Phase 2, like that for Phase 1, does not include all entity
types. We see no reason to maintain dual definitions for the different entity types, and
the resulting confusion.
In order to help meet the fast approaching January target date, Central Lincoln will be
voting affirmative in this ballot, with the hope these comments will be addressed in
Phase 2. If the ballot should fail, please address these comments in this phase. Thanks
to the team for their good work.

Response: The draft SAR developed for Phase 2 of Project 2010-17 Definition of the Bulk Electric System, similar to the SAR for Phase
1 has purposefully omitted the Interchange Authority and the Purchase Selling Entity functional entities because these entities do not
own or operate BES Elements. This conclusion does not necessitate the need for dual definitions; the definition of the BES does not
impact the functional responsibilities of these entities.
The SDT acknowledges and appreciates the continued support of the project. The SDT will consider all recommendations for
modifications to the technical aspects of the definition for project inclusion at the appropriate time during Project 2010-17 Definition
of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses
which will properly assess the threshold values and provide compelling justification for modifications to the existing values.
Utility Services, Inc.

Yes

Utility Services would like to raise the question of whether SCRC III.3.d (the so-called
"Generator Materiality" clause) is incorporated within the BES Inclusion Designations.
One theory suggests that given that I2 is designed to deal with III.3.a and III.3.b and I3
reflects the need to incorporate black start generation; then generators under the
materiality clause are not identified with the inclusion criteria. However, the second
theory suggests that resources identifed through I2 reflect the entire III.c.1-4 language
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of the SCRC, then the generators in the material clause are captured under I2. But if
this is the case, then I3 is redundant to I2 and does not need to separately addressed.

Response: The SDT has revised the language in Inclusion I2 to clearly identify the applicability of generating resources. The revised
language is as follows:
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
FirstEnergy Corp.

Yes

FE supports the SDT's phased project approach which was well articulated in the NERC
BES Definition Fact Sheet

LCRA Transmission Services
Corporation

Yes

LCRA TSC supports the direction the standards drafting team taking with this project
on the BES Definition and encourages further clarification as noted in these comments
for proper application.

Response: The SDT acknowledges and appreciates the continued support of the project.
National Grid

Yes

The proposed implementation period in the draft definition is too short. The new BES
definition will likely result in increased operational costs during the implementation
period that will ultimately be borne by customers. Implicit in the Commission's
directive to change the BES definition is the Commission's determination that the
benefits of this change, including consistency among the regions, outweigh the
ratepayer impacts. However, National Grid remains concerned that the ratepayer
impacts have not been fully taken into account. The implementation period is a tool
that can allow NERC to meet the Commission's directive while softening any resulting
ratepayer impacts. Implementation can and should be staged in order to mitigate and
even out rate increases. National Grid suggests that the implementation period be
flexible to allow entities who anticipate that large and/or expensive upgrades to the
BES will be necessary to meet compliance can submit an alternate implementation
plan to spread compliance and the associated rate changes over a longer period; we
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Question 11 Comment
would suggest a minimum of 7 years. This time period was also recognized as a
reasonable implementation time period in the recent TPL-001-2 for those portions of
the standard that would also result in plans that would require siting, permitting and
construction activities. This BES definition is likely to have similar impacts for some
entities and allowing for an implementation timeline with the definition change
enables achievement of the goals while recognizing the realities of constructing
facilities in today's environment.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. With that being said, the SDT
believes that an implementation time period of 24 months is sufficient time to address the development of regional transition plans,
address any necessary registration changes, file for exceptions through the Rules of Procedure exception process and address any
required training. The SDT also acknowledges that the potential exists for extenuating circumstances that will need to be addressed
through the regional transition plans.
In proposing a 24 month period in the Implementation Plan before the definition is applied in assessing compliance obligations, the
SDT considered several activities that may require additional time to complete for an entity to become fully compliant. One of these
activities is the development of transition plans in cases where significant issues may have been identified as potentially preventing an
entity from meeting the compliance obligations within the 24 month period. These transition plans are to be developed by the
Regional Entity and the Registered Entity in a cooperative manner to best address the identified concerns and establish an agreed to
mitigation plan which results in full compliance by the Registered Entity.
Rochester Gas and Electric

Yes

If the definition and inclusions and exclusions are not sufficiently specific and clear,
400

Organization

Yes or No

and New York State Electric
and Gas

Question 11 Comment
stakeholders will flood NERC and RROs with interpretation requests and/or apply the
definition and its inclusions or exclusions incorrectly. Explanatory figures with one-line
diagrams should be developed and shared to illustrate the system configurations
included and excluded in this BES Definition. This would be very helpful for definition
clarity. This should be done as part of an “Application Guide” for the BES Definition this has precedence in CIP-002 version 5. Attached is a sample set of one-line diagrams
with interpretations based upon the inclusions and exclusions developed by Northeast
Power Coordinating Council members for discussion purposes as an example, but note
that there is not a uniform agreement on these diagrams based on the BES Definition
as written, due to lack of clarity.

Response: The development of a guidance document which contains generic diagrams is a portion of the overall project that the SDT
feels is necessary to ensure the consistent application of the BES definition going forward. Therefore the SDT has determined that
such a document will be developed during Phase 2 of the project. The SDT thanks Rochester for the appended drawings but wishes to
point out that the SDT does not agree with some of the depictions shown on the drawings thus pointing out the need for an eventual
guidance document.
Central Maine Power
Company

Yes

If the definition and inclusions and exclusions are not sufficiently specific and clear,
stakeholders will flood NERC and RROs with interpretation requests and/or apply the
definition and its inclusions or exclusions incorrectly. Explanatory figures with one-line
diagrams should be developed and shared to illustrate the system configurations
included and excluded in a BES Definition. This would be very helpful for definition
clarity. This should be done as part of an “Application Guide” for the BES Definition there is precedence for an “Application Guide” with graphical support in CIP-002
version 5. A sample set of one-line diagrams with interpretations based upon the
inclusions and exclusions developed by Northeast Power Coordinating Council
members for discussion purposes is available as an example, but note that there is not
a uniform agreement on these diagrams based on the BES Definition as written, due to
lack of clarity.

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Nebraska Public Power District

Yes or No

Question 11 Comment

Yes

Regarding the Local Network: Can there be some additional technical documents or
examples provided for the most common configurations? The LN document is a good
document to provide guidance, however the supply of common configuration
examples would be very helpful in determining LN applicability. Examples where
technical document with examples would be helpful: 1. If a breaker and a half source
substation provides two parallel 115 kV lines feeding a load only substation from
separate breaker and a half legs at the source substation, would the two parallel lines
feeding the load be a LN distribution network feed since they are from the same
source substation? 2. if there is a radial feed from a ring bus or a breaker and a half
configuration to a radial load on a single line can the portion of the ring bus or breaker
and a half bus between the line breakers and the breakers themselves at the source
substation be excluded from the BES? 3. Can some legs of a 115kV breaker and a half
substation be disgnated BES and the other legs be non BES depending on how the BES
lines and loads tie in to the breaker and half legs? 4. In determining if elements are
BES is there any consideration to fault locations and if these faults would interrupt BES
flow on ring bus or breaker and a half configurations to help determine what is BES? If
so, how many contingencies would be considered to interrupt BES flow?

Response: The development of a guidance document which contains generic diagrams is a portion of the overall project that the SDT
feels is necessary to ensure the consistent application of the BES definition going forward. Therefore the SDT has determined that
such a document will be developed during Phase 2 of the project.
Ameren

Yes

a) We believe this revised definition is an improvement over the previous posting, a
step in the right direction.
b) The definition of the BES is referenced in several existing standards and the
Statement of Compliance Registry Criteria. Our concern is how this revised
definition will impact entity registration, i.e., how will the revised definition be
integrated into the Compliance Registry Criteria. The implementation plan should
include how the integration is going to occur. The Rules of Procedure exception
process should be further defined or referenced in this definition.
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Question 11 Comment
c) See Question 1 response: The general concept is sound, but the Inclusion and
Exclusion sections create so many circular references it is virtually impossible to
take a definitive stance on whether an asset is included or excluded to the BES
definition. Please revise the inclusion and exclusion criteria to give pinpointed
statements that are final and do not reference other criteria, that then again
reference other criteria

Response: a) The SDT acknowledges and appreciates the continued support of the project.
b) The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s
concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has pursued a
definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting the
current scope of the BES or driving registration or de-registration. The BES definition will be utilized in conjunction with the ERO
Statement of Compliance Registry Criteria to determine how entities will be registered. As the SDT progresses through phase 2 of the
project, consideration will be given to establish a definition that will eventually be the definitive document to determine registration
requirements.
The Rules of Procedure exception process is referenced in the current draft version of the BES definition in a note which states: “Note
- Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process”.
c) The SDT has made several revisions that the address the clarity issues raised by commenter’s. For a detailed response concerning
the specific clarifications made by the SDT, see the individual responses for the appropriate question. The application of the brightline definition of the BES is explained in the detail in the Summary Consideration at the beginning of this question.
MEAG Power

Yes

The definition of the BES is referenced in several existing standards and the Statement
of Compliance Registry Criteria. We are concerned how this revised definition will
impact entity registration, i.e., how will the revised definition be integrated into the
Compliance Registry Criteria.
The implementation plan should include how the integration is going to occur.

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Yes or No

Question 11 Comment

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. The BES definition will be utilized in conjunction with the ERO
Statement of Compliance Registry Criteria to determine how entities will be registered. As the SDT progresses through phase 2 of the
project, consideration will be given to establish a definition that will eventually be the definitive document to determine registration
requirements.
The current Implementation Plan is determining the effective dates of the revised definition and the extended time period for
meeting compliance obligations. The revised definition and the current ERO Statement of Compliance Registry Criteria will continue to
be utilized in the same manner as today for registration determinations. In proposing a 24 month period in the Implementation Plan
before the definition is applied in assessing compliance obligations, the SDT considered several activities that may require additional
time to complete for an entity to become fully compliant. One of these activities is the development of transition plans in cases where
significant issues may have been identified as potentially preventing an entity from meeting the compliance obligations within the 24
month period. These transition plans are to be developed by the Regional Entity and the Registered Entity in a cooperative manner to
best address the identified concerns and establish an agreed to mitigation plan which results in full compliance by the Registered
Entity.
Redding Electric Utility

Yes

City of Redding

Yes

Redding is concerned that phase 2 will not produce significant rules or criteria that
further define the BES; the desire to dedicate adaquate resourses is currently high
since FERC has a looming deadline upon NERC, however without deadlines Redding
believes that NERC will find it difficult to find the expertise or desire to finish the
Project.

Response: The NERC Standards Committee (SC) has approved Phase 2 of Project 2010-17 Definition of the Bulk Electric System as a
‘high priority’ project. Additionally, the SC has retained the existing SDT and committed to providing the necessary resources through
the NERC Technical Committees in providing analysis of technical issues to be addressed in Phase 2 of the project. Furthermore, the
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Yes or No

Question 11 Comment

SDT will be developing a project schedule for Phase 2, subject to approval by the SC, which will identify the appropriate deadlines
throughout the project.
Indeck Energy Services

Yes

As acknowledged in the response to Question 12 comments on the previous BES
definition, the BES definition is expansive compared to the definition of the BPS in the
FPA Section 215. The inclusion of the limited Exclusions is an attempt to remedy the
situation. However, the Exclusions need to include a fifth one that if, based on studies
or other assessments, it can be shown that any tranmission or generator element
otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There
has never been a study to show that elements, such as a 20 MW wind farm, 60 MW
merchant generator (which operates infrequently in the depressed market) in a large
BA (eg NYISO) or a radial transmission line connecting a small generator are important
to the reliability of the BPS. They are covered by the mandatory standards program
through the registration criteria. The BES Definition is the opportunity to permit an
entity to demonstrate that an element is unimportant to reliability of the BPS. The
SDT has identified a small subset of elements that it is willing to exclude. By their very
nature, these exclusions dim the bright line that is the stated goal of this project.
However, the SDT’s foresight seems limited in its selections. Analytical studies are
used to evaluate contingencies that could lead to the Big Three (cascading outages,
instability or voltage collapse). Such a study showing that a transmission or
generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable
Disturbance of approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW
merchant generator or numerous other smaller facilities would be bounded by larger
contingencies. It would take more than six 60 MW merchant generators with close
location and common mode failure to even be a Reportable Disturbance, much less
become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 - Any
facility that can be demonstrated to the Regional Entity by analytical study or other
assessment to be unimportant to the reliability of the BPS (with periodic reports by
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Organization

Yes or No

Question 11 Comment
the Regional Entity to NERC of any such assessments).”

Response: The concerns of the commenter are addressed by the implementation of the Rules of Procedure exception process, which
establishes the exclusion methods described by the commenter. The commenter’s suggested language leaves Regional discretion in
the process, which is a cited concern requiring elimination by the Commission, in the Orders No. 743 and 743-A. The SDT has provided
a reference to the Rules of Procedure exception process in the definition with the following language: “Note - Elements may be
included or excluded on a case-by-case basis through the Rules of Procedure exception process.”
Kootenai Electric Cooperative
Michigan Public Power Agency
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)
Central Electric Cooperatve
(CEC)
Clearwater Power Company
(CPC)
Snohomish County PUD
Consumer's Power Inc.
Douglas Electric Cooperative
(DEC)
Fall River Rural Electric
Cooperative (FALL)
Lane Electric Cooperative

No

KEC extends its thanks to the SDT and to the many industry entities that have actively
participating in the Standards Development Process. KEC strongly supports the
current draft and believes, with certain refinements discussed in our comments, that
the definition will serve the industry and reliability regulators well for many years to
come. In addition, as noted earlier, KEC is encouraged that the 20/75 MVA generation
thresholds referred to in the NERC Statement of Compliance Registry Criteria, which
have been relied upon by the SDT largely as a matter of necessity, will be reviewed
and a technical assessment will be performed to identify the appropriate generation
unit and plant size threshold to ensure a reliable North America. Finally, we
understand that the Rules of Procedure Team will continue to move forward with
developing an Exceptions Process that will complement the BES Definition and ensure
that, to the extent the BES Definition is over-inclusive, facilities that should not be
classified as BES will be excluded from the BES. Because the Exceptions Process is
integral to a workable BES Definition, we support the current process for moving
forward with the Exceptions Process and the BES Definition on parallel paths. We note
that KEC specifically supports the changes made by the SDT in the “Effective Date”
provision of the BES Definition, which shortens the effective date of the new definition
to the beginning of the first calendar quarter after regulatory approval (as opposed to
the first calendar quarter twenty-four months after regulatory approval), with a 24month transition period. KEC supports this conclusion because it will allow entities
seeking deregistration under the terms of the new BES definition to obtain the
benefits of the new definition without an unreasonable wait, while allowing any
entities that may be newly-classified as BES owners or operators sufficient time to
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Organization

Yes or No

(LEC)

Question 11 Comment
come into compliance with newly-applicable Reliability Standards. KEC also supports
the 24-month transition period for the reasons laid out by the SDT.

Lincoln Electric Cooperative
(LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric Cooperative
(UEC)

Response: The SDT acknowledges and appreciates the continued support of the project.
PacifiCorp

No

It is absolutely imperative that phase II continue as proposed by the STD. If phase II
was not proposed PacifiCorp would vote no on this proposal.

Response: Phase 2 will start as soon as Phase 1 is completed and the SDT resources are freed up. .
Farmington Electric Utility
System

No

Portland General Electric
Company

No

407

Organization

Yes or No

City of Austin dba Austin
Energy

No

Georgia System Operations
Corporation

No

Kansas City Power and Light
Company

No

Oncor Electric Delivery
Company LLC

No

Memphis Light, Gas and
Water Division

No

Harney Electric Cooperative,
Inc.

No

Cowlitz County PUD

No

PSEG Services Corp

No

Massachusetts Department of
Public Utilities

No

Manitoba Hydro

No

Long Island Power Authority

No

The Dow Chemical Company

No

Question 11 Comment

We appreciate the work the drafting team has done in preparing this document.

Cowlitz appreciates the opportunity to comment, and the hard work of the SDT.

408

Organization

Yes or No

Puget Sound Energy

No

NV Energy

No

Z Global Engineering and
Energy Solutions

No

Consumers Energy

No

City of Anaheim

No

Chevron U.S.A. Inc.

No

Metropolitan Water District of
Southern California

No

Duke Energy

No

Idaho Falls Power

No

Exelon

No

Texas Industrial Energy
Consumers

No

Tri-State GandT

No

ATC LLC

No

Tacoma Power

No

Question 11 Comment

Tacoma Power does not have any other concerns at this time. Thank you for
consideration of our comments.
409

Organization

Yes or No

Arizona Public Service
Company

No

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

No

Electricity Consumers
Resource Council (ELCON)

No

ACES Power Marketing
Standards Collaborators

No

Bonneville Power
Administration

No

SERC Planning Standards
Subcommittee

No

NERC Staff Technical Review

No

BGE

No

Question 11 Comment

The comments expressed herein represent a consensus of the views of the abovenamed members of the SERC EC Planning Standards Subcommittee only and should
not be construed as the position of SERC Reliability Corporation, its board, or its
officers”

No comment.

Response: Thank you for your support.

410

RFC Suggested changes to definition:
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements operated at 100 kV or higher and
Real Power and Reactive Power resources connected at 100 kV or higher. This does not include facilities used in the local distribution
of electric energy. The BES includes:
Inclusions:

•
•
•
•

•

I1 - Transformers with primary and secondary terminals operated at 100 kV or higher. unless excluded under
Exclusion E1 or E3for local distribution or retail customers.
I2 - Generating resources as described in the ERO Statement of Compliance Registry Criteria including the
generator terminals through the high-side of the step-up transformer(s), connected at a voltage of 100 kV or above.
I3 - Blackstart Resources and associated designated blackstart Cranking Paths operated at 100 kV or higher,
identified in the Transmission Operator’s restoration plan. regardless of voltage level.
I4 - Dispersed power producing resources as described in the ERO Statement of Compliance Registry Criteria
utilizing a system designed primarily for aggregating capacity, connected at common point at a voltage of 100 kV
or above.
I45 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or
higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through a transformer
that is designated in Inclusion I1.

This definition does not include facilities used in the local distribution of electric energy or retail customers, which are:.
Exclusions:

•

E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single point of connection
of 100 kV or higher from a single Transmission source originating with a singlen automatic interruption device and:
a) Only serves Load. Or,
b) Only includes generation resources not identified in Inclusion I3, with an aggregate capacity less
than or equal to 75 MVA (gross nameplate rating). Or,
c) Where the radial system serves Load and includes generation resources, not identified in Inclusion
I3, with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating).
Note - A normally open switching device between radial systems, as depicted on prints or one-line
diagrams for example, does not affect this exclusion.
411

•

•

E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy
on the customer’s side of the retail meter if:
o (i) the net capacity provided to the BES does not exceed 75 MVA, and
o (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple
generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation
with a Generator Owner or Generator Operator, or under terms approved by the applicable regulatory
authority.
E3 - Local Network (LN): A group of contiguous transmission Elements operated at or above 100 kV but less than
300 kV that distribute power to Load rather than transfer bulk power across the interconnected system. LN’s
emanate from multiple points of connection at 100 kV or higher to improve the level of service to retail customer
Load and not to accommodate bulk power transfer across the interconnected system. The LN is characterized by all
of the following:
a) Limits on connected generation: The LN and its underlying Elements do not include generation
resources identified in Inclusion I3 and do not have an aggregate capacity of non-retail generation
greater than 75 MVA (gross nameplate rating);
b) Power flows only into the LN: The LN does not transfer energy originating outside the LN for
delivery through the LN; and;

•

c) Not part of a Flowgate or transfer path: The LN does not contain a monitored Facility of a permanent
Flowgate in the Eastern Interconnection, a major transfer path within the Western Interconnection,
or a comparable monitored Facility in the ERCOT or Quebec Interconnections, and is not a
monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices owned and operated by the retail customer solely for its own use.

Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.

412

Pacificorp additional comments:
5.

The SDT has revised the specific inclusions to the core definition in response to industry comments. Do you
agree with Inclusion I4 (dispersed power)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific suggestions in your comments.

Yes:
No: X
Comments: Setting a dispersed power producing resource limit to 75 MVA at a common point discriminates
against single generator owners who own generators between 20 MVA and 75 MVA (inclusion I1), typically
connected at a common point and requires such owners to be subject to additional standards that dispersed
power producing owners are not required.
However, even with this concern, PacifiCorp supports the entire BES definition in its current form based on the
timeframe under which the SDT is operating and with an emphasis based on a phase II SAR to address
PacifiCorp’s objections regarding generation levels.
Under the attached scenario, please identify which elements would be considered BES:

413

414

Rochester Diagrams: These diagrams were supplied by Rochester as examples and do not reflect the SDT’s opinion of what is
and isn’t a BES Element.

415

416

417

418

419

420

421

422

423

Consideration of Comments on Initial Ballot — Definition of BES (Project 2010-17)
Date of Initial Ballot: September 30, 2011 - October 10, 2011
Summary Consideration: Many commenters followed instructions and cast their ballot while simply pointing to their detailed comments in the posted
comment report. The SDT thanks those commenters as this greatly reduces the administrative workload on the SDT. Those who decided to place
comments in the ballot report for the most part echoed comments that had already been seen by the SDT in the posted comment report which was
administered first by the SDT. As a result, there were no changes to the definition due to comments received in the ballot report. However, for ease of
reference, the changes to the definition made as a result of those comments are repeated here.
The SDT made the following changes to the definition due to industry comments received:
• Clarified the wording in Inclusion I1 to indicate that at least one secondary terminal must be at 100 kV or higher to accommodate multiple terminal
transformers.
• Removed the reference to the ERO Statement of Compliance Registry Criteria in Inclusion I2 so that there is no chance of the registry values
being changed and affecting the definition prior to resolution of threshold values in Phase II of this project.
• Clarified that generators were not part of Inclusion I5 to avoid improperly pulling in small generators.
• Clarified the language of Exclusion E2 by re-ordering the text as suggested.
• Clarified the language of Exclusion E3.b as suggested.
The SDT feels that it is important to remind the industry that Phase II of this project will begin immediately after the conclusion of Phase I as SDT
resources clear up. The same SDT will follow through with Phase II.
The SDT is recommending that this project be moved forward to the recirculation ballot stage.
There were two comments that were repeated multiple times throughout the various documents. The first topic was about how to sort through the
definition inclusions and exclusions, i.e., which takes precedence. The SDT offers this guidance on that issue:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast majority of BES
Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and non-BES Elements.
Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or higher as included in the BES. To fully
appreciate the scope of the ‘core’ definition an understanding of the term Element is needed. Element is defined in the NERC Glossary of Terms as:

“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker, bus section, or
transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application of the ‘core’
definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific criteria to provide for a consistent
determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion language is
written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the exclusion language.
This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The exclusion (E1) only speaks to the
transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner. Therefore, the only inclusion
that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and supersedes inclusion
I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the interconnected
transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected transmission network, the Rules of
Procedure exception process may be utilized on a case-by-case basis to either include or exclude an Element.
The second item is about providing specific guidance on how the information on the exception request form will be used in making decisions on
inclusions/exclusions in the exception process. While not technically part of this document which is about the definition, since the question did come up in
these comments, the SDT provides the following information:
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like nothing better
than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and an initial attempt at doing so, it
has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could have come up with the simple answer, it
would have been supplied within the bright-line. The SDT would also like to point out to the commenters that it directly solicited assistance in this matter in
the first posting of the criteria and received very little in the form of substantive comments.

Project 2010-17 BES Definition Ballot Comments

2

There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going to be
extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional discretion hasn’t been
removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception request form has to be taken in concert
with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at the rules being formulated for the exception
process, it becomes clear that the role of the Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now
one of reviewing the submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a
position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the visibility of the
process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a
process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection
requiring an independent Technical Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s
findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides
NERC the option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or
disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis for what
constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t
shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard and fast rules in this regard.
However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there is a great deal of
professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT
believes that both sides can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel
for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making their decision.
The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account. Providing concrete
guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers the commenters to Appendix
5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception request must be based on whether the
Elements are necessary for the reliable operation of the interconnected transmission system. Further, reliable operation is defined in the Rules of
Procedure as operating the elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or
unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the
experience gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent approach to the problem.
The SDT would also point out that there are options for a submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if
they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative response to the
request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the proposed Rules of

Project 2010-17 BES Definition Ballot Comments

3

Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be solely dispositive in the
determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The SDT
believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The SDT
believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on actual real-world
experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this problem and the filing
deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and equitable method of approaching this
difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and casting your ballot and hopes that these
changes will result in a favorable outcome.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious consideration in
this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 4041
446-2560 or at herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.

Voter

Segment

Vote

Comment

Ameren
Services

1

Negative

Please refer to Ameren comments submitted using the Comment Form.

Andrew Z
Pusztai

American
Transmission
Company, LLC
Associated
Electric
Cooperative,
Inc.
Dominion
Virginia Power

1

Negative

Comments submitted.

1

Negative

comments posted on comment form

1

Negative

Please see Dominion’s submitted comments

John Bussman

Michael S
Crowley

1

Entity

Kirit Shah

The appeals process is in the Standards Processes Manual: http://www.nerc.com/docs/standards/sc/Standard_Processes_Manual_Approved_May_2010.pdf.

Project 2010-17 BES Definition Ballot Comments

4

Vote

Comment

Bernard
Pelletier

Voter

Hydro-Quebec
TransEnergie

1

Negative

Please see our comments on the BES Definition

Terry Harbour

MidAmerican
Energy Co.

1

Negative

Tracy Sliman

Tri-State G & T
Association,
Inc.
ISO New
England, Inc.

1

Negative

See the MidAmerican submitted comments. The BES definition needs additional
specific inclusion or exclusion provisions that clearly exclude variable resource
generation collector circuits rated below 100 kV and generators less than 20 MVA
connected to those collector circuits in accordance with the registration criteria.
Comments submitted by electronic form.

2

Negative

please refer to detailed comments submitted for this project.
SPP's comments on this concurrent ballot/comment period have been submitted
and provide support for our Negative vote. In addition, SPP is a member of the
IRC SRC and is in support of those comments on this standard. Please refer to
these sets of comments for our recommendations.
Please see comments of AECI.

Kathleen
Goodman

Entity

Segment

Charles Yeung

Southwest
Power Pool,
Inc.

2

Negative

Chris W Bolick

3

Negative

Linda
Jacobson

Associated
Electric
Cooperative,
Inc.
City of
Farmington

3

Negative

Richard
Blumenstock

Consumers
Energy

3

Negative

FEUS appreciates the SDT work in defining the BES. While the proposed definition
is an improvement over the current definition, FEUS feels there is some additional
clarification necessary before approval. Seperate comments have been submitted.
See Consumers Energy's comments on the official submittal form.

Michael F.
Gildea

Dominion
Resources
Services
Hydro One
Networks, Inc.

3

Negative

See Dominion's submitted comments.

3

Negative

After careful analysis of the proposed documents, Hydro One Networks Inc. is
casting a negative vote. We commend the SDT for the effort in facing the
challenge. However, we believe that the proposed definition and the exception
request criteria still need further work. Some issues need to be resolved before a

David Kiguel

Project 2010-17 BES Definition Ballot Comments

5

Voter

Entity

Segment

Vote

Comment
final approval is granted. Please see our detailed comments as provided in the
on-line system.

Tony
Eddleman

Nebraska
Public Power
District
Tri-State G & T
Association,
Inc.
Consumers
Energy

3

Negative

Comments were submitted through the Nebraska Public Power District comment
form.

3

Negative

Tri-State G&T Load Serving Entity comments were submitted via electronic
comment process.

4

Negative

See Comments provided by Consumers Energy Company

Brock Ondayko

AEP Service
Corp.

5

Negative

Francis J.
Halpin

Bonneville
Power
Administration
Consumers
Energy
Company
Dominion
Resources, Inc.

5

Negative

AEP believes the drafting team is on the correct path, and the concepts expressed
appear to be appropriate. However, AEP has a number of questions and
recommended refinements that if addressed by the drafting team, will make the
definition more clear to industry. These comments are being submitted via
electronic form by Thad Ness on behalf of American Electric Power.
Please refer to formal BPA Comments submitted on 10/7/2011.

5

Negative

See Consumers Energy's comments on the official comment submittal forms.

5

Negative

See comments filed on this project.

Dan
Roethemeyer

Dynegy Inc.

5

Negative

Comments will be included with those to be submitted with the SERC OC
Standards Review Group.

Christopher
Schneider

MidAmerican
Energy Co.

5

Negative

See the MidAmerican submitted comments. The BES definition needs additional
specific inclusion or exclusion provisions that clearly exclude variable resource
generation collector circuits rated below 100 kV and generators less than 20 MVA
connected to those collector circuits in accordance with the registration criteria.

Janelle
Marriott
David Frank
Ronk

David C
Greyerbiehl
Mike Garton

Project 2010-17 BES Definition Ballot Comments

6

Voter
Don Schmit

Entity

Segment

Vote

Comment

5

Negative

Please see comments submitted by Nebraska Public Power District on
10/10/2011.

Mahmood Z.
Safi

Nebraska
Public Power
District
Omaha Public
Power District

5

Negative

see Doug Peterchuck’s comments

Bo Jones

Westar Energy

5

Negative

Please see comments submitted electronically.

Edward P. Cox

AEP Marketing

6

Negative

Louis S. Slade

Dominion
Resources, Inc.

6

Negative

AEP believes the drafting team is on the correct path, and the concepts expressed
appear to be appropriate. However, AEP has a number of questions and
recommended refinements that if addressed by the drafting team, will make the
definition more clear to industry. These comments are being submitted via
electronic form by Thad Ness on behalf of American Electric Power.
See comments submitted by Dominion.

David Ried

Omaha Public
Power District

6

Negative

See Doug Peterchucks comments from OPPD.

Donald G
Jones

Texas
Reliability
Entity, Inc.
Rochester Gas
and Electric
Corp.
American
Electric Power

10

Negative

See comment form submitted separately.

1

Negative

Comments to be submitted separately.

1

Negative

Hydro One
Networks, Inc.

1

Negative

AEP believes the drafting team is on the correct path, and the concepts expressed
appear to be appropriate. However, AEP has a number of questions and
recommended refinements that if addressed by the drafting team, will make the
definition more clear to industry. These comments are being submitted via
electronic form by Thad Ness on behalf of American Electric Power.
After careful analysis of the proposed documents, Hydro One Networks Inc. is
casting a negative vote. We commend the SDT for the effort in facing the
challenge. However, we believe that the proposed definition and the exception

John C. Allen
Paul B.
Johnson

Ajay Garg

Project 2010-17 BES Definition Ballot Comments

7

Voter

Vote

Comment

10

Affirmative

request criteria still need further work. Some issues need to be resolved before a
final approval is granted. Please see our detailed comments as provided in the
on-line system.
Comments Submitted

1

Affirmative

Comments submitted

Consolidated
Edison Co. of
New York
Consumers
Power Inc.

1

Affirmative

See Con Edison’s comments on the BES Definition submitted separately by
electronic survey form.

1

Affirmative

Please see CPI's separate comment form.

William J
Smith

FirstEnergy
Corp.

1

Affirmative

FirstEnergy supports the proposed BES definition and offers comments and
suggestions through the formal comment period.

Gordon Pietsch

Great River
Energy

1

Affirmative

Please see MRO NSRF comments.

Joe D Petaski

Manitoba
Hydro

1

Affirmative

Please see comments provided by Manitoba Hydro in formal commenting period

David Thorne

Potomac
Electric Power
Co.
Puget Sound
Energy, Inc.

1

Affirmative

Comments submitted

1

Affirmative

See comments of Denise Lietz.

Sierra Pacific
Power Co.

1

Affirmative

Comments submitted.

Steven L.
Rueckert
Robert Smith
Christopher L
de Graffenried
Stuart Sloan

Denise M Lietz
Rich Salgo

Entity

Western
Electricity
Coordinating
Council
Arizona Public
Service Co.

Segment

Project 2010-17 BES Definition Ballot Comments

8

Voter

Vote

Comment

Minnkota
Power Coop.
Inc.
Muscatine
Power & Water

1

Affirmative

While MPC is voting affirmative, we ask that you see the comments submitted by
the MRO NERC Standards Review Forum (NSRF).

1

Affirmative

MPW agrees with the comments submitted by the MRO NERC Standards Review
Forum (NSRF).

David
Boguslawski

Northeast
Utilities

1

Affirmative

NU contributed to and joins with NPCC comments.

Larry Akens

Tennessee
Valley
Authority
Electric
Reliability
Council of
Texas, Inc.
Blachly-Lane
Electric Co-op

1

Affirmative

TVA has submitted comments through the Comment Form for 2nd Draft of
Definitions of BES (Project 2010-17)

2

Affirmative

ERCOT ISO has joined the IRC SRC comments submitted.

3

Affirmative

Please see BLEC's separate comment form.

Central Electric
Cooperative,
Inc.
(Redmond,
Oregon)
Central Lincoln
PUD

3

Affirmative

Please see Central's separate comment form.

3

Affirmative

Comments previously submitted.

Dave Hagen

Clearwater
Power Co.

3

Affirmative

Please see Clearwater Power's separate comment form.

Peter T Yost

Consolidated
Edison Co. of
New York

3

Affirmative

Con Edison comments have been submitted separately.

Richard Burt
Tim Reed

Charles B
Manning
Bud Tracy
Dave Markham

Steve
Alexanderson

Entity

Segment

Project 2010-17 BES Definition Ballot Comments

9

Voter

Entity

Segment

Vote

Comment

Roman Gillen

Consumers
Power Inc.

3

Affirmative

Please see CPI's separate comment form.

Roger Meader

Coos-Curry
Electric
Cooperative,
Inc
Cowlitz County
PUD

3

Affirmative

Please see CCEC's separate comment form.

3

Affirmative

Comments submitted.

Douglas
Electric
Cooperative
Fall River Rural
Electric
Cooperative
FirstEnergy
Energy
Delivery
Florida
Municipal
Power Agency
Georgia
Systems
Operations
Corporation
Holland Board
of Public Works

3

Affirmative

Please see DEC's separate comment form.

3

Affirmative

Please see FREC's separate comment form.

3

Affirmative

FirstEnergy supports the proposed BES definition and offers comments and
suggestions through the formal comment period.

3

Affirmative

Please see comments submitted through the formal comments

3

Affirmative

See electronic comment form from Georgia System Operations Corporation

3

Affirmative

Please see comment form.

Kootenai
Electric
Cooperative

3

Affirmative

Reference the comments of KEC in response to the SDT comment form.

Russell A
Noble
Dave Sabala
Bryan Case
Stephan Kern
Joe McKinney
William N.
Phinney
William Bush
Dave Kahly

Project 2010-17 BES Definition Ballot Comments
1
0

Voter
Rick Crinklaw
Michael Henry
Greg C. Parent

Entity
Lane Electric
Cooperative,
Inc.
Lincoln Electric
Cooperative,
Inc.
Manitoba
Hydro

Segment

Vote

Comment

3

Affirmative

Please see LEC's separate comment form.

3

Affirmative

Please see Lincoln's separate comment form.

3

Affirmative

Please see comments provided by Manitoba Hydro in formal commenting period

Jeff Franklin

Mississippi
Power

3

Affirmative

"Comments Submitted"

John S Bos

Muscatine
Power & Water

3

Affirmative

MPW agrees with the comments submitted by the MRO NERC Standards Review
Forum (NSRF)

Jon Shelby

Northern Lights
Inc.

3

Affirmative

Please see NLI's separate comment form.

Ray Ellis

Okanogan
County Electric
Cooperative,
Inc.
Raft River
Rural Electric
Cooperative
Springfield
Utility Board

3

Affirmative

Please see Okanogan's separate comment form.

3

Affirmative

Please see RREC's separate comment form.

3

Affirmative

Please refer to SUB's comments on the BES Definition.

Tennessee
Valley
Authority
Umatilla
Electric
Cooperative

3

Affirmative

My company has submitted comments via the comment form.

3

Affirmative

Please see UEC's separate comment form.

Heber
Carpenter
Jeff Nelson
Ian S Grant
Steve Eldrige

Project 2010-17 BES Definition Ballot Comments
1
1

Voter
Marc Farmer

James R Keller
Shamus J
Gamache
John Allen
Frank Gaffney
Guy Andrews

Joseph
DePoorter
Douglas
Hohlbaugh
Aleka K Scott

Wilket (Jack)
Ng

Entity
West Oregon
Electric
Cooperative,
Inc.
Wisconsin
Electric Power
Marketing
Central Lincoln
PUD

Segment

Vote

Comment

3

Affirmative

Please see WOEC's separate comment form.

3

Affirmative

Comments submitted.

4

Affirmative

See Central Lincoln PUD comments (CLPUD) Posted by Steve Alexanderson.

City Utilities of
Springfield,
Missouri
Florida
Municipal
Power Agency
Georgia
System
Operations
Corporation
Madison Gas
and Electric
Co.
Ohio Edison
Company

4

Affirmative

City Utilities of Springfield, Missouri supports the comments from SPP.

4

Affirmative

Please see comments through the formal comments

4

Affirmative

See electronic comment form submitted by Georgia System Operations Corp

4

Affirmative

Please see the MRO NSRF comments concerning this project.

4

Affirmative

FirstEnergy supports the proposed BES definition and offers comments and
suggestions through the formal comment period.

Pacific
Northwest
Generating
Cooperative
Consolidated
Edison Co. of
New York

4

Affirmative

Please see PNGC's separate comment form.

5

Affirmative

See Con Edison’s comments on the BES Definition submitted separately by
electronic survey form.

Project 2010-17 BES Definition Ballot Comments
1
2

Voter
David
Schumann

Entity

Segment

Vote

Comment

Preston L
Walsh

Florida
Municipal
Power Agency
Great River
Energy

James M
Howard

Lakeland
Electric

5

Affirmative

Refer to comments from FMPA.

Gary Carlson

Michigan Public
Power Agency

5

Affirmative

Comments submitted separately

William D
Shultz

Southern
Company
Generation
Wisconsin
Electric Power
Co.
Consolidated
Edison Co. of
New York
FirstEnergy
Solutions

5

Affirmative

Comments from Southern Company Generation are being submitted via the
electronic comment form available on the project web page.

5

Affirmative

Comments submitted.

6

Affirmative

Con Edison comments have been submitted separately.

6

Affirmative

FirstEnergy supports the proposed BES definition and offers comments and
suggestions through the formal comment period.

Florida
Municipal
Power Agency
Florida
Municipal
Power Pool
Manitoba
Hydro

6

Affirmative

Please see comments submitted through the formal comments

6

Affirmative

See FMPA's comments

6

Affirmative

Please see comments provided by Manitoba Hydro in formal commenting period

Linda Horn
Nickesha P
Carrol
Kevin Querry
Richard L.
Montgomery
Thomas
Washburn
Daniel Prowse

5

Affirmative

Please see comments submitted through the formal comments

5

Affirmative

Please see the comments submitted by the MRO / NSRF

Project 2010-17 BES Definition Ballot Comments
1
3

Voter

Entity

Margaret Ryan

Pacific
Northwest
Generating
Cooperative
Central Lincoln
PUD

8

Affirmative

Please see PNGC's separate comment form.

9

Affirmative

I support the comments sent in by Steve Alexanderson of Central Lincoln PUD

New York State
Reliability
Council
Northeast
Power
Coordinating
Council, Inc.
ReliabilityFirst
Corporation

10

Affirmative

The New York State Reliability Council will be separately submitting a commemt
form.

10

Affirmative

NPCC will be submitting comments regarding concerns expressed by our
members through the formal comment process along with suggestions to address
those comments.

10

Affirmative

Comments submitted

Bruce Lovelin
Alan Adamson
Guy V. Zito

Anthony E
Jablonski

Segment

Vote

Comment

Response: The SDT thanks you for following the instructions on submitting comments. This greatly decreases the amount of
administrative work for the SDT and will help accelerate the process.
Mike Ramirez

Sacramento
Municipal
Utility District

4

Negative

SMUD believes that the SDT has made substantial progress towards a clear and
workable definition of the BES. Although SMUD in balloting “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. SMUD recognizes that, given the deadlines imposed by FERC in Order No.
743, it will not be possible for the SDT to conduct a technical analysis within the
time available. Accordingly, SMUD agrees with the approach taken by the SDT,
which is to propose a Phase II of the standards development process that would
address the generator threshold level and other issues. However, it is our opinion
that the second draft would benefit from further clarification or modification in a
number of respects, as are detailed in our comments. That said, SMUD is
prepared to support the BES definition as proposed by the SDT going forward.
SMUD has taken the opportunity to provide this industry feedback, as it is our
understanding that we will be afforded another ballot opportunity. If this were to
be our sole occasion to ballot, we would vote “Affirmative” at this time. We are

Project 2010-17 BES Definition Ballot Comments
1
4

Voter

Entity

Segment

Vote

James LeighKendall

Sacramento
Municipal
Utility District

3

Negative

Terry L Baker

Platte River
Power
Authority

3

Negative

Comment
encouraged by the work that has been completed and we commend the SDT for
their commitment and extensive work thus far. Detailed Comments submitted
separately.
SMUD believes that the SDT has made substantial progress towards a clear and
workable definition of the BES. Although SMUD in balloting “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. SMUD recognizes that, given the deadlines imposed by FERC in Order No.
743, it will not be possible for the SDT to conduct a technical analysis within the
time available. Accordingly, SMUD agrees with the approach taken by the SDT,
which is to propose a Phase II of the standards development process that would
address the generator threshold level and other issues. However, it is our opinion
that the second draft would benefit from further clarification or modification in a
number of respects, as are detailed in our comments. That said, SMUD is
prepared to support the BES definition as proposed by the SDT going forward.
SMUD has taken the opportunity to provide this industry feedback, as it is our
understanding that we will be afforded another ballot opportunity. If this were to
be our sole occasion to ballot, we would vote “Affirmative” at this time. We are
encouraged by the work that has been completed and we commend the SDT for
their commitment and extensive work thus far. Detailed Comments submitted
separately.
Platte River believes that the SDT has made substantial progress towards a clear
and workable definition of the BES. Although Platte River ballots “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. Platte River recognizes that, given the deadlines imposed by FERC in Order
No. 743, it will not be possible for the SDT to conduct a technical analysis within
the time available. Accordingly, Platte River agrees with the approach taken by
the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold level and other issues. However, it is
our opinion that the second draft would benefit from further clarification or
modification. That said, Platte River is prepared to support the BES definition as
proposed by the SDT going forward. Platte River has taken the opportunity to
provide this industry feedback, as it is our understanding that we will be afforded

Project 2010-17 BES Definition Ballot Comments
1
5

Voter

Entity

Segment

Vote

Jeanie Doty

City of Austin
dba Austin
Energy

5

Negative

Lisa L Martin

City of Austin
dba Austin
Energy

6

Negative

Comment
another ballot opportunity. If this were to be our sole occasion to ballot, we
would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far.
AE believes the SDT has made substantial progress towards a clear and workable
definition of the BES. Although AE voted “Negative,” we strongly support the
approach to defining the Bulk Electric System as proposed here. AE recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be
possible for the SDT to conduct a technical analysis within the time available.
Accordingly, AE agrees with the approach taken by the SDT, which is to propose
a Phase II of the standards development process that would address the
generator threshold level and other issues. However, it is our opinion that the
second draft would benefit from further clarification or modification in a number
of respects, as detailed in our comments. That said, AE is prepared to support the
BES definition as proposed by the SDT going forward. AE has taken the
opportunity to provide this industry feedback, as it is our understanding that we
will be afforded another ballot opportunity. If this were to be our sole occasion to
ballot, we would vote “Affirmative” at this time. We are encouraged by the work
that has been completed and we commend the SDT for their commitment and
extensive work thus far.
AE believes the SDT has made substantial progress towards a clear and workable
definition of the BES. Although AE voted “Negative,” we strongly support the
approach to defining the Bulk Electric System as proposed here. AE recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be
possible for the SDT to conduct a technical analysis within the time available.
Accordingly, AE agrees with the approach taken by the SDT, which is to propose
a Phase II of the standards development process that would address the
generator threshold level and other issues. However, it is our opinion that the
second draft would benefit from further clarification or modification in a number
of respects, as detailed in our comments. That said, AE is prepared to support the
BES definition as proposed by the SDT going forward. AE has taken the
opportunity to provide this industry feedback, as it is our understanding that we

Project 2010-17 BES Definition Ballot Comments
1
6

Voter

Entity

Segment

Vote

Andrew Gallo

City of Austin
dba Austin
Energy

3

Negative

Kevin Smith

Balancing
Authority of
Northern
California
NCR11118

1

Negative

Comment
will be afforded another ballot opportunity. If this were to be our sole occasion to
ballot, we would vote “Affirmative” at this time. We are encouraged by the work
that has been completed and we commend the SDT for their commitment and
extensive work thus far.
Austin Energy (AE) believes the SDT has made substantial progress toward a
clear and workable definition of the BES. Although AE votes “Negative,” we
strongly support the approach to defining the BES as proposed here. AE
recognizes that, given the deadlines imposed by FERC in Order No. 743, it will not
be possible for the SDT to conduct a technical analysis within the time available.
Accordingly, AE agrees with the approach taken by the SDT, which is to propose
a Phase II of the standards development process that would address the
generator threshold level and other issues. However, we believe the second draft
would benefit from further clarification or modification in a number of respects, as
detailed in our comments (filed separately). That said, AE is prepared to support
the BES definition as proposed by the SDT going forward. AE has taken the
opportunity to provide this industry feedback, as it is our understanding that we
will have another ballot opportunity (on a recirculation ballot). If this were to be
our sole opportunity to vote, we would vote “Affirmative” at this time. We are
encouraged by the work completed to date and commend the SDT for their
commitment and extensive work thus far.
BANC believes that the SDT has made substantial progress towards a clear and
workable definition of the BES. Although BANC in balloting “Negative” we strongly
support the approach to defining the Bulk Electric System as proposed here.
BANC recognizes that, given the deadlines imposed by FERC in Order No. 743, it
will not be possible for the SDT to conduct a technical analysis within the time
available. Accordingly, BANC agrees with the approach taken by the SDT, which is
to propose a Phase II of the standards development process that would address
the generator threshold level and other issues. However, it is our opinion that the
second draft would benefit from further clarification or modification in a number
of respects, as are detailed in our comments. That said, BANC is prepared to
support the BES definition as proposed by the SDT going forward. BANC has
taken the opportunity to provide this industry feedback, as it is our understanding

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Vote

Carol
Ballantine

Platte River
Power
Authority

6

Negative

John C. Collins

Platte River
Power
Authority

1

Negative

Comment
that we will be afforded another ballot opportunity. If this were to be our sole
occasion to ballot, we would vote “Affirmative” at this time. We are encouraged
by the work that has been completed and we commend the SDT for their
commitment and extensive work thus far. Detailed Comments submitted
separately.
Platte River believes that the SDT has made substantial progress towards a clear
and workable definition of the BES. Although Platte River ballots “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. Platte River recognizes that, given the deadlines imposed by FERC in Order
No. 743, it will not be possible for the SDT to conduct a technical analysis within
the time available. Accordingly, Platte River agrees with the approach taken by
the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold level and other issues. However, it is
our opinion that the second draft would benefit from further clarification or
modification. That said, Platte River is prepared to support the BES definition as
proposed by the SDT going forward. Platte River has taken the opportunity to
provide this industry feedback, as it is our understanding that we will be afforded
another ballot opportunity. If this were to be our sole occasion to ballot, we
would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far.
Platte River believes that the SDT has made substantial progress towards a clear
and workable definition of the BES. Although Platte River ballots “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. Platte River recognizes that, given the deadlines imposed by FERC in Order
No. 743, it will not be possible for the SDT to conduct a technical analysis within
the time available. Accordingly, Platte River agrees with the approach taken by
the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold level and other issues. However, it is
our opinion that the second draft would benefit from further clarification or
modification. That said, Platte River is prepared to support the BES definition as
proposed by the SDT going forward. Platte River has taken the opportunity to

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Vote

Bethany
Hunter

Sacramento
Municipal
Utility District

5

Negative

Claire
Warshaw

Sacramento
Municipal
Utility District

6

Negative

Comment
provide this industry feedback, as it is our understanding that we will be afforded
another ballot opportunity. If this were to be our sole occasion to ballot, we
would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far.
SMUD believes that the SDT has made substantial progress towards a clear and
workable definition of the BES. Although SMUD in balloting “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. SMUD recognizes that, given the deadlines imposed by FERC in Order No.
743, it will not be possible for the SDT to conduct a technical analysis within the
time available. Accordingly, SMUD agrees with the approach taken by the SDT,
which is to propose a Phase II of the standards development process that would
address the generator threshold level and other issues. However, it is our opinion
that the second draft would benefit from further clarification or modification in a
number of respects, as are detailed in our comments. That said, SMUD is
prepared to support the BES definition as proposed by the SDT going forward.
SMUD has taken the opportunity to provide this industry feedback, as it is our
understanding that we will be afforded another ballot opportunity. If this were to
be our sole occasion to ballot, we would vote “Affirmative” at this time. We are
encouraged by the work that has been completed and we commend the SDT for
their commitment and extensive work thus far. Detailed Comments submitted
separately.
SMUD believes that the SDT has made substantial progress towards a clear and
workable definition of the BES. Although SMUD in balloting “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. SMUD recognizes that, given the deadlines imposed by FERC in Order No.
743, it will not be possible for the SDT to conduct a technical analysis within the
time available. Accordingly, SMUD agrees with the approach taken by the SDT,
which is to propose a Phase II of the standards development process that would
address the generator threshold level and other issues. However, it is our opinion
that the second draft would benefit from further clarification or modification in a
number of respects, as are detailed in our comments. That said, SMUD is

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Voter

Tim Kelley

Entity

Sacramento
Municipal
Utility District

Segment

1

Vote

Negative

Comment
prepared to support the BES definition as proposed by the SDT going forward.
SMUD has taken the opportunity to provide this industry feedback, as it is our
understanding that we will be afforded another ballot opportunity. If this were to
be our sole occasion to ballot, we would vote “Affirmative” at this time. We are
encouraged by the work that has been completed and we commend the SDT for
their commitment and extensive work thus far. Detailed Comments submitted
separately.
SMUD believes that the SDT has made substantial progress towards a clear and
workable definition of the BES. Although SMUD in balloting “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. SMUD recognizes that, given the deadlines imposed by FERC in Order No.
743, it will not be possible for the SDT to conduct a technical analysis within the
time available. Accordingly, SMUD agrees with the approach taken by the SDT,
which is to propose a Phase II of the standards development process that would
address the generator threshold level and other issues. However, it is our opinion
that the second draft would benefit from further clarification or modification in a
number of respects, as are detailed in our comments. That said, SMUD is
prepared to support the BES definition as proposed by the SDT going forward.
SMUD has taken the opportunity to provide this industry feedback, as it is our
understanding that we will be afforded another ballot opportunity. If this were to
be our sole occasion to ballot, we would vote “Affirmative” at this time. We are
encouraged by the work that has been completed and we commend the SDT for
their commitment and extensive work thus far. Detailed Comments submitted
separately.

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step in
Phase II will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit comments
for the inclusion of items and issues to be considered by the SDT in Phase II.
Philip Riley

Public Service
Commission of
South Carolina

9

Negative

The Public Service Commission of South Carolina does not believe adequate
technical evaluations have been done for basing the BES definition on the 100 kV
and 20 MVA thresholds as proposed.
In addition, the Public Service Commission of South Carolina does not believe
adequate cost benefit studies have been done to justify the proposal for the 100

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kV and 20 MVA thresholds. Lack of cost benefit analyses has been a recurring
comment of the Public Service Commission of South Carolina on proposed NERC
standards.

Response: Both the 20 MVA and 100 kV thresholds are items for consideration in Phase II. At that time, technical evaluations and
studies will be performed to provide the details the SDT needs to have to adequately address the issues.
The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 & 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
contracting the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the
current BES definition has varying degrees of Regional application and has resulted in different conclusions on what is currently
considered to be part of the BES. This inconsistency in the application and subsequent results were also identified by the
Commission in Orders No. 743 & 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition
coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on Regions.
Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid
on a continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the
development of Regional transition plans once the definition has been approved by the Commission.
Dale Bodden

CenterPoint
Energy
Houston
Electric

1

Negative

Inclusion I5 provides for the inclusion of static devices dedicated to supplying or
absorbing Reactive Power based upon their connection to the transmission
system. The wording concerning their connection to the transmission system
appears reasonable; however, CenterPoint Energy believes the size of a static
reactive device should be taken into consideration. Static reactive devices are
more widely distributed across a transmission system than generation resources.
We recommend that only static reactive devices that are greater than 150 MVAR
be included. CenterPoint Energy could support Draft 2 if a reasonable size
threshold is established for static reactive devices.

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Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow
the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values. No change made.
Robert Ganley

Long Island
Power
Authority

1

Negative

LIPA has voted NO to the proposed definition of Bulk Electric System as posted
and offers the following comments with our vote: 1. The SDT needs to provide
clarifying language for the following terms so that facilities can be adequately
addressed in determining whether they are BES elements or not:
a. “local distribution” as used in the BES core definition
b. “common point” as used in Inclusion I4
c. “single point of interconnection” as used in Exclusion E1
d. “underlying Elements” as used in Exclusion E3a
2. The core definition and exclusion E3b and E3c adequately define a Local
Network. It seems like the intent to exclude non bulk distribution systems would
still be included because of E3a. ( limits on connected generation ) We believe
E3a should be eliminated in defining a Local Network.

Response: a) The SDT believes that the wording in the core definition plus Exclusions E1 and E3 provide the basis for defining local
distribution. In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable
operation of the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element.
b) While the SDT has determined no additional clarification of the term “common point” is needed in the BES definition, the
following guidance is provided. The SDT believes the common point of connection, which is the point from where generation is
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aggregated to determine if the 75 MVA threshold is met, to be the point where the individual transmission Element(s) of a collector
system ultimately meet the 100 kV transmission system.
c) The “single point of connection of 100 kV or higher” is where the radial system will begin if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the radial
system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the transmission
line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker and a half
bus configuration could also be the beginning of the radial system and the owner of the bus would need to insure the reliability of
the substation.
d) The SDT believes that the existing phrase in ExclusionE3.a “and its underlying Elements” has sufficient clarity and meets the
intent of the exclusion with brevity. No change made.
e) The SDT continues to believe that it is necessary to establish a limit on the allowable quantity of generation that may be
significant to the reliable operation of the surrounding interconnected transmission system. Please note that the issues
surrounding the appropriate generation threshold, among other topics, will be taken up in Phase 2 of this BES definition effort. No
change made.
Martyn Turner

Lower
Colorado River
Authority

1

Negative

1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. Yes:
X No: Comments:
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: LCRA TSC supports the inclusion of
transformers (with both the primary and secondary windings operated at 100-kV
or higher) in the BES definition; however, additional clarification is suggested.
The term transformers needs to be further defined with respect to function (auto
transformers, phase angle regulators, generator step-up transformers, etc.).
Similarly, a separate definition for “Transformer” could be developed and included

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in the NERC Glossary of Terms.
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments:
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments:
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: LCRA TSC suggests consistency between this
inclusion criteria and the criteria used in I2 for “generation”.
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: This inclusion conflicts with exclusion E4.
Which one takes priority?
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The current wording is unclear with respect to
the treatment of normally open switching devices. LCRA TSC suggests the
following language to replace the existing language on the note to E1: “Two
radial systems connected by a normally open, manually operated switching

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device, as depicted on prints or one-line diagrams for example, may be
considered as radial systems under this exclusion.” The current wording is unclear
with respect to “non-retail generation”. The sudden loss of large, radial-supplied
load may result in reliability deficiencies. LCRA TSC suggests stating a load level
or a load capacity in the exclusion.
8. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: No: X Comments:
9. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E3 (local network)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments:
10. The SDT has added specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E4 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: This exclusion conflicts with inclusion item I5.
Which one takes priority?
11. Are there any other concerns with this definition that haven’t been covered in
previous questions and comments remembering that the exception criteria are
posted separately for comment? Yes: X No: Comments: LCRA TSC supports the
direction the standards drafting team taking with this project on the BES
Definition and encourages further clarification as noted in these comments for
proper application.

Response: The SDT refers LCRA to the individual comment responses in the definition comment form as the comments expressed
here are exactly identical to the comments submitted by LCRA on that form.
Danny Dees

MEAG Power

1

Negative

MEAG believes that a Yes vote for the draft BES Definition will result in minimal or
no changes. We have identified a few changes that if made will secure a Yes vote
on the next ballot.

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Comment
The most important change is needed in I5 reactive resources noted below. I5
reactive resources - We feel that this inclusion should be limited to dynamic
devices with an aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) connected through a common point.
E1 - Non-retail generation needs to be defined to clarify why it is used in this
exclusion.
E2 (ii) The reference to generation on the customer’s side of the retail meter
needs to be clarified to provide a better understanding as to what is intended
with this phrase.
E3 b - We would agree with the exclusion if the wording of the exclusion includes
the following phrase (in italics) added at the end of E3 b): Power flows only into
the LN: The LN does not transfer energy originating outside the LN for delivery
through the LN “under normal operating conditions”.

Response: The SDT refers MEAG to the individual comment responses in the definition comment form as the comments expressed
here are exactly identical to the comments submitted by MEAG on that form.
Ernest Hahn

Metropolitan
Water District
of Southern
California

1

Affirmative

MWDSC generally supports the core definition of the Bulk Electric System as
proposed. However, some of the proposed Inclusions and Exclusions need to be
clarified as identified below.
Inclusion 5 should be changed to be consistent with the core definition and to
clarify Reactive Power devices. Under I5, the additional phrase "or through a
dedicated transformer with a high-side voltage of 100 kV or higher," appears to
conflict with the core definition's phrase "and Real Power and Reactive Power
resources connected at 100 kV or higher". For example, if you have a device
connected to a 69Kv system which is used solely for an end-user's load, but the
69kv system is transformed up to a 115kV system, such device could be included
as BES or you would have to define what is meant by "dedicated. If Reactive
Power is meant to agree with the definition under NERC's Glossary of Terms,
there should be consistency and less verbiage.
MWDSC also agrees with WECC's comment that there should be some minimum
threshold for Reactive Power devices similar to that identified for generating
resources in Inclusion 2.
MWDSC recommends that Inclusion 5 be changed as follows: I5 - "Reactive

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Power devices dedicated to support the BES that are connected at 100kV or
higher, or through a transformer that is designated in Inclusion I1."
Exclusion 4 appears to limit the devices just to retail customers. However, any
end-user load, including wholesale or retail, should be included. NERC's Glossary
of Terms uses the phrase "end-use customer", not retail customers to describe
loads. MWDSC recommends that Exclusion 4 be changed as follows: E4 - Reactive
Power devices owned and operated by an end-use customer solely for its own
use.

Response: The SDT refers MWDSC to the individual comment responses in the definition comment form as the comments
expressed here are exactly identical to the comments submitted by MWDSC on that form.
William
Palazzo

New York
Power
Authority

6

Negative

1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. Yes:
X No: Comments: In general NYPA agrees with the definition. However, NYPA
believes that clarifying revisions need to be made as described in the responses
to Questions 2 -11 below.
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The wording of Inclusion I1 is not clear. The
term transformers needs to be further defined with respect to auto transformers,
phase angle regulators and generator step-up transformers. Recommend the
following wording: “All transformers (including auto-transformers, voltage
regulators, and phase angle regulators) with primary and secondary terminals
operated at or above 100kV, and generator step-up transformers (GSU) with one
terminal operated at or above 100KV, unless excluded by E1 or E3.”
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language

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would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Recommend removing the reference to the
Statement of Compliance Registry Criteria. The definition should be the governing
document and provide the details of what generating resources should be
included. The current language induces circular arguments without a true
governing document. The definition should drive what appears in the Registry
Criteria. Inclusion I2 should be revised to read: “Generating resources with a
gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion I2 and the current Compliance Registry Criteria.
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Recommend that the concept and the words
“material to and designated as part of” be included in Inclusion I3. Recommend
rewording Inclusion I3 as follows “Blackstart resources material to and designated
as part of the Transmission Operator’s restoration plan.”
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The term “common point” needs clarification
with respect to connection to the BES. Recommend the following wording:
“connected at a common point through a dedicated step-up transformer with a
high-side voltage of 100 KV or above.”
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Technical studies need to be conducted to

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confirm reactive resource impacts on the reliability of the BES. The inclusion of
reactive resources is a significant expansion of the current BES definition and
therefore requires technical justification for inclusion. Inclusion I5 as written is
generally confusing with multiple references to other inclusions and exclusions in
the definition. Recommend removing references to reactive resources from Phase
1 until technical justification can be demonstrated (as part of Phase 2).
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The wording in E1c should more clearly reflect
what is intended by using the term “non-retail”. The E1 reference Note should be
re-worded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. Recommend that the potential inclusion in the BES of protective
relay systems which protect radial lines emanating from a ring bus or breaker and
a half bus design be confirmed in Phase 2 pursuant to technical studies.
8. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: No: X Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E3 (local network)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments: It is our understanding that a sub-team of the
SDT performed a technical study to support the limits outlined in Exclusion E3.

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Marilyn Brown

Entity

New York
Power
Authority

Segment

3

Vote

Negative

Comment
This study should be made available. Recommend removing the sentence in the
definition that states: “This does not include facilities used in the local distribution
of electric energy.” This sentence leads to confusion as it overlaps with language
in Exclusion E3.
10. The SDT has added specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E4 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The statement “owned or operated by the
retail customer” is confusing and arguably inaccurate and should be revised.
Refer to comments related to reactive resources for Question 6 regarding
Inclusion I5.
11. Are there any other concerns with this definition that haven’t been covered in
previous questions and comments remembering that the exception criteria are
posted separately for comment? Yes: X No: Comments: Recommend integrating
the Inclusions into the base definition wording to eliminate confusion. Format of
the definition is confusing by referencing both Inclusions and Exclusions. NYPA
supports many of the comments
1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. Yes:
X No: Comments: In general NYPA agrees with the definition. However, NYPA
believes that clarifying revisions need to be made as described in the responses
to Questions 2 -11 below.
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The wording of Inclusion I1 is not clear. The
term transformers needs to be further defined with respect to auto transformers,
phase angle regulators and generator step-up transformers. Recommend the

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following wording: “All transformers (including autotransformers, voltage
regulators, and phase angle regulators) with primary and secondary terminals
operated at or above 100kV, and generator step-up transformers (GSU) with one
terminal operated at or above 100KV, unless excluded by E1 or E3.”
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Recommend removing the reference to the
Statement of Compliance Registry Criteria. The definition should be the governing
document and provide the details of what generating resources should be
included. The current language induces circular arguments without a true
governing document. The definition should drive what New York Power
Authority’s Comments Final: October 05, 2011 Comment Form for 2nd Draft of
Definition of BES (Project 2010-17) Page 4 of 6 appears in the Registry Criteria.
Inclusion I2 should be revised to read: “Generating resources with a gross
nameplate rating of 20MVA or greater, or generating plant/facility connected at a
common bus, with an aggregate nameplate rating of 75MVA or greater and is
directly connected to a BES Element.” This is consistent with proposed Inclusion
I2 and the current Compliance Registry Criteria.
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Recommend that the concept and the words
“material to and designated as part of” be included in Inclusion I3. Recommend
rewording Inclusion I3 as follows “Blackstart resources material to and designated
as part of the Transmission Operator’s restoration plan.”
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language

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would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The term “common point” needs clarification
with respect to connection to the BES. Recommend the following wording:
“connected at a common point through a dedicated step-up transformer with a
high-side voltage of 100 KV or above.”
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Technical studies need to be conducted to
confirm reactive resource impacts on the reliability of the BES. The inclusion of
reactive resources is a significant expansion of the current BES definition and
therefore requires technical justification for inclusion. Inclusion I5 as written is
generally confusing with multiple references to other inclusions and exclusions in
the definition. Recommend removing references to reactive resources from Phase
1 until technical justification can be demonstrated (as part of Phase 2). New York
Power Authority’s Comments Final: October 05, 2011 Comment Form for 2nd
Draft of Definition of BES (Project 2010-17) Page 5 of 6
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The wording in E1c should more clearly reflect
what is intended by using the term “non-retail”. The E1 reference Note should be
re-worded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. Recommend that the potential inclusion in the BES of protective
relay systems which protect radial lines emanating from a ring bus or breaker and
a half bus design be confirmed in Phase 2 pursuant to technical studies.
8. The SDT has revised the specific exclusions to the core definition in response

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Arnold J.
Schuff

Entity

New York
Power
Authority

Segment

1

Vote

Negative

Comment
to industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: No: X Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E3 (local network)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments: It is our understanding that a sub-team of the
SDT performed a technical study to support the limits outlined in Exclusion E3.
This study should be made available. Recommend removing the sentence in the
definition that states: “This does not include facilities used in the local distribution
of electric energy.” This sentence leads to confusion as it overlaps with language
in Exclusion E3. New York Power Authority’s Comments Final: October 05, 2011
Comment Form for 2nd Draft of Definition of BES (Project 2010-17) Page 6 of 6
10. The SDT has added specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E4 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The statement “owned or operated by the
retail customer” is confusing and arguably inaccurate and should be revised.
Refer to comments related to reactive resources for Question 6 regarding
Inclusion I5.
11.Are there any other concerns with this definition that haven’t been covered in
previous questions and comments remembering
You do not have to answer all questions. Enter All Comments in Simple Text
Format. Insert a “check” mark in the appropriate boxes by double-clicking the
gray areas. The SDT has asked one specific question for each specific aspect of
the definition.
1. The SDT has made clarifying changes to the core definition in response to

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industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. Yes:
X No: Comments: In general NYPA agrees with the definition. However, NYPA
believes that clarifying revisions need to be made as described in the responses
to Questions 2 -11 below.
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The wording of Inclusion I1 is not clear. The
term transformers needs to be further defined with respect to auto transformers,
phase angle regulators and generator step-up transformers. Recommend the
following wording: “All transformers (including auto-transformers, voltage
regulators, and phase angle regulators) with primary and secondary terminals
operated at or above 100kV, and generator step-up transformers (GSU) with one
terminal operated at or above 100KV, unless excluded by E1 or E3.”
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Recommend removing the reference to the
Statement of Compliance Registry Criteria. The definition should be the governing
document and provide the details of what generating resources should be
included. The current language induces circular arguments without a true
governing document. The definition should drive what appears in the Registry
Criteria. Inclusion I2 should be revised to read: “Generating resources with a
gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion I2 and the current Compliance Registry Criteria.

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4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Recommend that the concept and the words
“material to and designated as part of” be included in Inclusion I3. Recommend
rewording Inclusion I3 as follows “Blackstart resources material to and designated
as part of the Transmission Operator’s restoration plan.”
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The term “common point” needs clarification
with respect to connection to the BES. Recommend the following wording:
“connected at a common point through a dedicated step-up transformer with a
high-side voltage of 100 KV or above.”
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Technical studies need to be conducted to
confirm reactive resource impacts on the reliability of the BES. The inclusion of
reactive resources is a significant expansion of the current BES definition and
therefore requires technical justification for inclusion. Inclusion I5 as written is
generally confusing with multiple references to other inclusions and exclusions in
the definition. Recommend removing references to reactive resources from Phase
1 until technical justification can be demonstrated (as part of Phase 2).
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The wording in E1c should more clearly reflect

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what is intended by using the term “non-retail”. The E1 reference Note should be
re-worded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. Recommend that the potential inclusion in the BES of protective
relay systems which protect radial lines emanating from a ring bus or breaker and
a half bus design be confirmed in Phase 2 pursuant to technical studies.
8. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: No: X Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E3 (local network)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments: It is our understanding that a sub-team of the
SDT performed a technical study to support the limits outlined in Exclusion E3.
This study should be made available. Recommend removing the sentence in the
definition that states: “This does not include facilities used in the local distribution
of electric energy.” This sentence leads to confusion as it overlaps with language
in Exclusion E3.
10. The SDT has added specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E4 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The statement “owned or operated by the
retail customer” is confusing and arguably inaccurate and should be revised.
Refer to comments related to reactive resources for Question 6 regarding

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Inclusion I5.
11. Are there any other concerns with this definition that haven’t been covered in
previous questions and comments remembering that the exception criteria are
posted separately for

Response: 1. The SDT refers NYPA to the responses below for Q2 – Q10.
2. The SDT believes the existing language is clear and the proposed additional language would be redundant. No change made.
3. The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2, instead
specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and thus
affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
4. The SDT believes that adding language such as “material to” does not provide clarity and remains immeasurable. No change
made.
5. The “single point of connection of 100 kV or higher” is where the radial system will begin if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the radial
system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the transmission
line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker and a half
bus configuration could also be the beginning of the radial system and the owner of the bus would need to insure the reliability of
the substation.
6. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects of the definition. However, the SDT has responsibilities associated with being responsive to the directives established in
Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with
sufficient time for the development of strong technical justifications. These and similar issues have prompted the SDT to separate
the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities.
Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for inclusion in
Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical
Standing Committees, to develop analyses which will provide compelling justification. No change made.
7. “Non-retail generation” means that generation which is on the system (supply) side of the retail meter. Radial systems should be
assessed with all normally open (NO) switches in the open position and these NO switches will not prevent the owner or operator
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from using this exclusion. The note provides an example that can be used to indicate the switch is operated in the normally open
position; however, it is the owner and operator’s responsibility to indicate how a switch is used in the normal operating
environment. The “single point of connection of 100 kV or higher” is where the radial system will begin if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of
the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Treatment of protection systems is but one of many items to be studied and clarified in
Phase II.
8. The threshold levels of generators and the relationship between the ERO Statement of Compliance Registry Criteria and the BES
definition will be considered in the Phase 2 review. However, the SDT believes that a value was needed for Phase I and decided to
proceed with the single 75 MVA threshold. No change made.
9. No study was run by the SDT concerning the limits in E3. The SDT does not see any conflict between the cited statement and the
language in E3.
10. The SDT believes the wording is clear and absent any concrete suggestions has not made a change in this regard.
Doug
Peterchuck

Omaha Public
Power District

1

Negative

We believe that this version of the definition and associated Inclusion and
Exclusion criteria will again create regional inconsistency in identifying BES
facilities. We believe the best way to address this is to condense the definition by
applying a bright-line threshold within the definition itself that uses the defined
inclusions to describe transmission and generation facilities operating or
connecting at 100 kV or above as BES facilities.
Further, the definition should include existing registration criteria for generation
facilities (including real and reactive resources), which includes both single units
at or above 20 MVA and aggregate units at 75 MVA or above that are directly
connected to facilities at 100kV or higher.
The proposed Exception Process should only allow Registered Entities to remove
facilities from BES designation based on technical justification (i.e. perform
system impact studies to show facility not impacting reliable operation of BES).
If the BES definition is properly created and defined, there should not be a need

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to have an exception process for a registered entity to add a facility to the BES.
With coordination led by NERC, the RE should have the final approval of any
registered entity requesting a facility exemption. Exemptions should be granted
based on result of the system impact study performed. Saying this, the proposed
exclusion list should actually be listed as “Typical Exceptions to be considered by
Regional Entities and NERC”.

Response: The SDT strived to create a bright-line as requested in the comment. The inclusions and exclusions are seen as
necessary clarifications to the core definition and every attempt was made to make them bright-line as well.
The SDT has reverted to specific numeric thresholds consistent with the ERO Statement of Compliance Registry Criteria for Phase I.
The exception process has been designed with maximum flexibility in mind to allow for all possible conditions. Therefore, it is set
up to allow for both deletion and inclusion requests.
Order 743 directs that the ERO be the final arbiter of exception requests.
Robert
Kondziolka

Salt River
Project

1

Negative

Definition of Bulk Electric System (BES) The Blackstart “Cranking Path” has been
deleted from Inclusion 3 of the BES definition. However, NERC standards EOP005 and CIP-002, R1.2.4 require documenting the Cranking Path. In addition,
CIP-002-4 identifies the Cranking Path as a Critical Asset in Attachment 1.
Compliance to the NERC Standards needs to be an exact science whenever
possible. SRP does not argue the inclusion or exclusion of Cranking Path.
However, if it is excluded, guidance must be provided on whether or not a
Cranking Path is subject to the previously mentioned Standards.
Detailed Information to Support BES Exceptions Request SRP agrees with the
WECC Staff recommendation on the “Detailed Information to Support BES
Exceptions Request.” “WECC Staff believes that the proposed Technical Principles
for Demonstrating BES Exceptions Request does not provide the necessary clarity
as to what applying entities must provide to support their request, nor does it
provide any criteria for consistency among regions in their assessment of
requests. We believe that the checklist items for transmission and generation
facilities are appropriate questions that must be answered in considering all
requests. However, without objective criteria defining what must be submitted
and how to assess the materials submitted, the current methodology leaves it to

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John T.
Underhill

Entity

Salt River
Project

Segment

3

Vote

Negative

Comment
each region to develop their own methodology and criteria for evaluating the
submittals. We believe the lack of clarity regarding what studies must be
submitted and what must be demonstrated by the studies submitted will be
overly burdensome on the submitting entity and the Region, as multiple studies
may be required for the two to agree that there is sufficient justification for an
exemption request. We believe that additional work is necessary to develop clear,
objective methods and criteria for identifying which facilities may be excluded
from or should be included in the Bulk Electric System. Clear, objective methods
and criteria will enable the submitter of requests to understand what is necessary
for submitting an exception request and will provide for consistency among the
regions in their initial assessment and recommendations to the ERO.”
Definition of Bulk Electric System (BES) The Blackstart “Cranking Path” has been
deleted from Inclusion 3 of the BES definition. However, NERC standards EOP005 and CIP-002, R1.2.4 require documenting the Cranking Path. In addition,
CIP-002-4 identifies the Cranking Path as a Critical Asset in Attachment 1.
Compliance to the NERC Standards needs to be an exact science whenever
possible. SRP does not argue the inclusion or exclusion of Cranking Path.
However, if it is excluded, guidance must be provided on whether or not a
Cranking Path is subject to the previously mentioned Standards.
Detailed Information to Support BES Exceptions Request SRP agrees with the
WECC Staff recommendation on the “Detailed Information to Support BES
Exceptions Request.” “WECC Staff believes that the proposed Technical Principles
for Demonstrating BES Exceptions Request does not provide the necessary clarity
as to what applying entities must provide to support their request, nor does it
provide any criteria for consistency among regions in their assessment of
requests. We believe that the checklist items for transmission and generation
facilities are appropriate questions that must be answered in considering all
requests. However, without objective criteria defining what must be submitted
and how to assess the materials submitted, the current methodology leaves it to
each region to develop their own methodology and criteria for evaluating the
submittals. We believe the lack of clarity regarding what studies must be

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submitted and what must be demonstrated by the studies submitted will be
overly burdensome on the submitting entity and the Region, as multiple studies
may be required for the two to agree that there is sufficient justification for an
exemption request. We believe that additional work is necessary to develop clear,
objective methods and criteria for identifying which facilities may be excluded
from or should be included in the Bulk Electric System. Clear, objective methods
and criteria will enable the submitter of requests to understand what is necessary
for submitting an exception request and will provide for consistency among the
regions in their initial assessment and recommendations to the ERO.”

Response: Cranking Paths are subject to any standard in which they are specifically spelled out.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria
and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to
say that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with
this position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at
as a single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional
Entity plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this
places the Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be
supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also
believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the
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proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent
Technical Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s
findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure,
Section 7.0, provides NERC the option to remand the request to the Regional Entity with the mandate to process the exception if it
finds the Regional Entity erred in rejecting or disapproving the exception request. On the other side of this equation, one could
make an argument that the Regional Entity has no basis for what constitutes an acceptable submittal. Commenters point out that
the explicit types of studies to be provided and how to interpret the information aren’t shown in the request process. The SDT
again points to the variations that will abound in the requests as negating any hard and fast rules in this regard. However, one is
not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there is a great deal of
professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having viewed the request
details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be supplied for the
submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables
to take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation
of the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the
elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result ofa sudden disturbance, including a cyber
security incident, or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel,
the visibility of the process, and the experience gained by having this same panel review multiple requests will result in an
equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision
has been made on their submittal.
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Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be
approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in
a favorable outcome.
Barbara
Constantinescu

Independent
Electricity
System
Operator

2

Negative

This is our response to Question 4 in the comment form: We thank the SDT for
excluding the cranking paths from the BES definition, a point we had raised in our
comments to the previous posting. However, we had also disagreed with the
inclusion of Blackstart Resources and reiterate our view that their inclusion is
superfluous given there is already a designation specific for system restoration
covered by an existing standard, to recognize their reliability impacts and to
ensure their expected performance. NERC Standards EOP-005-2 stipulates the
requirements for testing blackstart resource and cranking paths. This testing
requirement suffices to ensure that the facilities critical to system restoration are
functional when needed, which meets the intent of identifying their criticality to
reliability. We therefore suggest removing Inclusion I3 entirely.

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We support the provisions of E1 in principle but require clarification of some
issues and suggest alternative wording in some cases. It is unclear if the
connection voltage of generation referred to in E1.b affects whether a radial
system could be excluded under E1 although from the context it appears that it
would. For clarity we suggest appending “connected at 100 kV or higher.” Please
provide in the BES definition document an explanation of “non-retail” and “retail”
generation used in E1.c.
Additionally, despite the fact the revisions to Inclusion I3 (Blackstart Resources)
removed any reference to Cranking Paths, Exclusion 1 (b) and (c) both indicate
that the exclusion of a radial system would not be allowed if generation identified
in I3 were connected to it. This implies that the Cranking Path for this Blackstart
Resource would have to be BES. This appears to be an inconsistency. We suggest
removing the phrase “not identified in Inclusion I3” in both instances. We
disagree with notion that the capacity of generation connected to a radial system
ought to determine whether that radial system should be classified as BES.
Firstly, it is a given that the generation connected to the subject radial that meets
the registry criteria would already be captured within the core BES definition and
Inclusion I2.
This is our response to Question 7 in the comment form: The function served by
a radial that is of importance in the current context is that of delivering surplus
power to the rest of the bulk power system and so, the impact on the BES of loss
of the radial system or its connected generation needs to be considered. In our
view, the “BES-status” of the radial itself is immaterial and so too is the aggregate
capacity of generation resources connected to it. Detailed arguments regarding
impact on the BES can be made in support of an application for an exclusion
under the Exception Process, but it would be beneficial to avoid unnecessarily
including a radial merely because it has more than 75 MVA of qualifying
generation connected to it, without equal consideration of the connected load. To
put a “bright line” on the consideration of impact referred to above, we suggest:
In E1 (b): Replace "an aggregate capacity less than or equal to 75 MVA (gross

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nameplate rating)" with "a net capacity provided to the BES of less than or equal
to 75 MVA." In E1 (c): Replace "an aggregate capacity of non-retail generation
less than or equal to 75 MVA (gross nameplate rating)" with "a net capacity of
non-retail generation provided to the BES of 75 MVA." This wording would be
consistent with E2 (i).
Finally the word “affect” stated in the note accompanying E1 lends itself to misinterpretation. We therefore suggest the following revision to achieve greater
clarity: “This exclusion applies to radial systems connected by a normally open
switch.”
This is our response to Question 9 of the comment form: Consistent with our
comments in response to Q7, we propose removing E3 (a) since, as explicitly
described in E3 (b), one of the characteristic of the LN is that power flows only
into the LN. The level of generation contained within the LN is therefore
immaterial, particularly where the most onerous contingency or system operating
condition occurring within the LN, results in acceptable BES performance as
defined by the applicable criteria of the NERC transmission planning standards.
The generation connected within the LN that meets the registry criteria would
already be captured within the definition of the BES as provided for in Inclusion
I2.

Response: The SDT refers IESO to the individual comment responses in the definition comment form as the comments expressed
here are exactly identical to the comments submitted by IESO on that form.
Marie Knox

Midwest ISO,
Inc.

2

Negative

While we agree with the changes to the definition of the Bulk Electric System
(BES), there are a few key refinements left to be addressed. The BES drafting
team needs to clarify that facilities below 100 kV are defined “local distribution
facilities”, are beyond NERC jurisdiction, and are excluded from the NERC BES.
Facilities below 100 kV are used for the local distribution of electric energy. We
fear that equipment that is connected to the BES, would be considered a part of
the BES as well, and we disagree.

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Response: The SDT points the commenter to the core definition which clearly states that the BES is 100 kV and above unless
modified by the inclusions/exclusions and also clearly states that local distribution facilities are not included. The
inclusions/exclusions were carefully developed to try to avoid bringing in any equipment that is truly local distribution. The SDT
would also point out that the way the definition has been framed that it would not bring in local distribution facilities simply
because they were connected to the BES at some location.
Alden Briggs

New Brunswick
System
Operator

2

Negative

Please see comments submitted by the Reliability Standards Committee. The draft
definition will significantly increase the number of BES elements. Many elements
and connected facilities will be added to the BES and subject to NERC standards
under the draft definition. Most of these requirements for elements will
unnecessary introduce administrative burden and operating expenses. As a NPCC
study identifies, this would impose significant costs to the ratepayer, with little or
no increase in reliability benefits to the Bulk Power System (BPS) as currently
defined by NPCC.

Response: The SDT refers NBSO to the individual comment responses in the definition comment form as the comments expressed
here are identical to the comments submitted by NBSO on that form.
Jack W Savage

Modesto
Irrigation
District

3

Negative

MID is voting No with the following comments. Inclusions and exclusions are
based upon the ERO Statement of Compliance Registry Criteria - currently
75MVA. What is the SDT's technical justification for using this generation level?
If 75MVA is the criteria for including facilities as part of the BES, why is that same
criteria not applied at voltages below 100kv?
Is 75MVA of generation within an area whose load far exceeds that 75MVA cause
to classify that entire area as part of the BES and not exclude it as a Local
Network?
Why are customer owned generators treated differently than other generators?
Where is "non-retail generation" defined?
As worded, I5 will make any and all reactive devices connected at 100kv or
higher part of the BES. Is is intended that capacitors attached to the tertiary of a
115/69kv transformer for local voltage support be included as part of the BES? By
implication, if they are, then the 115/69kv transformer should also be included. Is
that the intent?
Did the SDT consider and attempt to include and reconcile the WECC BES Task

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Force's definition of the BES and their technical basis for defining exclusions?
Please explain.

Response: As has been previously stated in the first posting consideration of comments, the SDT is using the existing thresholds for
generation due to the scope limitations of the FERC Order. Phase II of this project will include a thorough investigation of, and a
technical justification for, any threshold values used in the definition.
The SDT is using the same criteria that exists in today’s definition for generation threshold values and will be exploring all issues
associated with these threshold values in Phase II of this project when more time will be available for technical analysis of the
issues.
The SDT recognizes that some candidate local networks will have far in excess of 75 MVA of load demand, yet it believes that the 75
MVA threshold value given in Exclusion E3.a is an appropriate level regardless of the amount of load. This value is consistent with
the existing threshold of aggregate generation in the ERO Statement of Compliance Registry Criteria. The generation values used in
the BES definition will receive more attention and refinement as part of phase 2 of this Project 2010-17.
Customer owned generation has traditionally been treated differently and the SDT is retaining this important distinction.
Non-retail generation is a widely used and understood term and is not defined here.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
The SDT considered all of the previous work done by several of the regional entities in the revision of the definition. WECC is well
represented on the SDT.
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Steven M.
Jackson

Municipal
Electric
Authority of
Georgia

3

Negative

Steven Grego

MEAG Power

5

Negative

Comment
MEAG believes that a Yes vote for the draft BES Definition will result in minimal or
no changes. We have identified a few changes that if made will secure a Yes vote
on the next ballot. The most important change is needed in I5 reactive resources
noted below. I5 reactive resources - We feel that this inclusion should be limited
to dynamic devices with an aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) connected through a common point.
E1 - Non-retail generation needs to be defined to clarify why it is used in this
exclusion.
E2 (ii) The reference to generation on the customer’s side of the retail meter
needs to be clarified to provide a better understanding as to what is intended
with this phrase.
E3 b - We would agree with the exclusion if the wording of the exclusion includes
the following phrase (in italics) added at the end of E3 b): Power flows only into
the LN: The LN does not transfer energy originating outside the LN for delivery
through the LN “under normal operating conditions”.
MEAG believes that a Yes vote for the draft BES Definition will result in minimal or
no changes. We have identified a few changes that if made will secure a Yes vote
on the next ballot. The most important change is needed in I5 reactive resources
noted below. I5 reactive resources - We feel that this inclusion should be limited
to dynamic devices with an aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) connected through a common point.
E1 - Non-retail generation needs to be defined to clarify why it is used in this
exclusion.
E2 (ii) The reference to generation on the customer’s side of the retail meter
needs to be clarified to provide a better understanding as to what is intended
with this phrase.
E3 b - We would agree with the exclusion if the wording of the exclusion includes
the following phrase (in italics) added at the end of E3 b): Power flows only into
the LN: The LN does not transfer energy originating outside the LN for delivery
through the LN “under normal operating conditions”.

Response: The SDT refers MEAG to the individual comment responses in the definition comment form as the comments expressed
here are identical to the comments submitted by MEAG on that form.
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Voter
Spencer Tacke

Entity
Modesto
Irrigation
District

Segment
4

Vote
Negative

Comment
The choice of 75 MVA as the determining generating capacity seems to have
been an arbitrary choice with no technical basis. We strongly support the E3
(Local Networks) exception, if it were not for the 75 MVA generation requirement.
So I believe a technical basis for selecting 75 MVA as the generator size needs to
be developed before the definition would be acceptable. Thank you.

Response: Comments were received that either posed a challenge to the generator thresholds in Exclusion E3.a or suggested that
the Exclusion for local networks should be silent on generator thresholds until such time as the additional consideration of
appropriate generation thresholds is addressed in Phase 2 of Project 2010-17. The SDT agrees that the threshold(s) for generation
throughout the BES definition are appropriately addressed in Phase 2 of this effort; however, in the meantime and for the purpose
of satisfying the Commission’s Order in 743 and 743a in a timely fashion, the SDT believes it is necessary to use a generation
threshold that is consistent with the in-force ERO Statement of Compliance Registry Criteria.
Chifong
Thomas

BrightSource
Energy, Inc.

5

Negative

BrightSource Energy supports the core definition of the Bulk Electric System as
proposed. However, we believe the following clarification will be needed. For
Inclusion 3 we agree that Blackstart units should be considered vital to the overall
operation of the BES, and therefore included in the definition of the BES.
However, we do not agree with the deletion of the cranking path from Inclusion
3. The cranking path should be included in the definition since NERC standards
EOP-005 and CIP-002, R1.2.4 require documenting the cranking path and the
revised CIP-002-4 identifies the cranking path as a critical asset. To be able to
count on a Blackstart unit to perform as designed in the Blackstart Restoration
Plan, it must be ensured that the cranking path is available.
We believe that additional clarity is needed in the wording of Inclusion 4. It is our
understanding, for example, that Inclusion 4 is not intended to include each
individual wind turbine generating unit in a wind farm, or each PV panel as a BES
element, but rather to include the point at which the aggregated capacity reaches
the threshold of 75 MVA. However, the current wording of Inclusion 4 does not
provide sufficient clarity. We believe that the wording of Inclusion 4 could be
modified to add clarity on this topic.
We believe that Inclusion 5 should be modified to identify some minimum
Reactive Power threshold for static or dynamic devices similar to that identified
for generating sources in Inclusion 2. As worded a 1 MVA device supplying or

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absorbing Reactive Power that is connected at 100 kV or higher would be
included in the BES.
We believe that Exclusion 2 should be modified to include a size threshold for
individual generating units, similar to that identified in Inclusion 2. As currently
worded Exclusion 2 places the same threshold (75 MVA) on a single generating
unit as is placed on multiple generating units.

Response: Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system
Elements. The Transmission Operator’s restoration plans identify a number of possible system restoration scenarios to address the
uncertainty of the actual requirements needed to address a particular restoration event including Cranking Paths. Therefore, the
SDT maintains that Cranking Paths are not required to be included in the BES definition as they are essentially a moving target and
could include distribution Elements. The Cranking Paths issue will be discussed anew in Phase II of this project. No change made.
Inclusion I4 denotes an aggregate threshold. This is clear from the requirement inclusion threshold of “aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating).”
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
The threshold levels of generators and the relationship between the ERO Statement of Compliance Registry Criteria and the BES
definition will be considered in the Phase 2 review. However, the SDT believes that a value was needed for Phase I and decided to
proceed with the single 75 MVA threshold. No change made.
Rex A Roehl

Indeck Energy
Services, Inc.

5

Negative

As acknowledged in the response to Question 12 comments on the previous BES
definition, the BES definition is expansive compared to the definition of the BPS in

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the FPA Section 215. The inclusion of the limited Exclusions is an attempt to
remedy the situation. However, the Exclusions need to include a fifth one that if,
based on studies or other assessments, it can be shown that any tranmission or
generator element otherwise identified as part of the BES is not important to the
reliability of the BPS, then that element should be excluded from the mandatory
standards program. There has never been a study to show that elements, such as
a 20 MW wind farm, 60 MW merchant generator (which operates infrequently in
the depressed market) in a large BA (eg NYISO) or a radial transmission line
connecting a small generator are important to the reliability of the BPS. They are
covered by the mandatory standards program through the registration criteria.
The BES Definition is the opportunity to permit an entity to demonstrate that an
element is unimportant to reliability of the BPS. The SDT has identified a small
subset of elements that it is willing to exclude. By their very nature, these
exclusions dim the bright line that is the stated goal of this project. However, the
SDT’s foresight seems limited in its selections. Analytical studies are used to
evaluate contingencies that could lead to the Big Three (cascading outages,
instability or voltage collapse). Such a study showing that a transmission or
generation element is bounded by the N-1 or N-2 contingency would exclude it
from the BES definition. For example, in a BA with a NERC definition Reportable
Disturbance of approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW
merchant generator or numerous other smaller facilities would be bounded by
larger contingencies. It would take more than six 60 MW merchant generators
with close location and common mode failure to even be a Reportable
Disturbance, much less become the N-1 contingency for the Big Three. Exclusion
E5 should be “E5 - Any facility that can be demonstrated to the Regional Entity by
analytical study or other assessment to be unimportant to the reliability of the
BPS (with periodic reports by the Regional Entity to NERC of any such
assessments).”

Response: The SDT refers Indeck to the individual comment responses in the definition comment form as the comments expressed
here are identical to the comments submitted by Indeck on that form.

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Gerald
Mannarino

Entity
New York
Power
Authority

Segment
5

Vote
Negative

Comment
Comments: For Question 2 on page 2, recommend that the specific types of
studies to be provided are defined to add consistency and transparency to the
Exception request process. Recommend that the concept and the words “material
to” be included as part of the question as follows “Is the facility material to
permanent Flowgates in the Eastern Interconnection.....”
For Question 4 on page 2, recommend that single contingency analysis be
performed and submitted to demonstrate impacts to the BES.
For Question 6 on page 3, recommend that “Cranking Path” be removed to be
consistent with the draft BES Definition. Recommend that the concept and the
words “material to and designated as part of” be included as part of the question.
Recommend rewording Question 6 as follows “Is the facility a Blackstart resource
material to and designated as part of the Transmission Operator’s restoration
plan?”
For Question 7 on page 3, facilities less than two years old or under construction
would not be able to provide SCADA data for the most recent consecutive two
calendar year period. Facility rating changes and the magnitude of such changes
which trigger application or reapplication of the exception process are not
addressed. Recommend that Question 7 be revised to address these issues.
Comments: For Question 2 on page 4, recommend that the specific generator
ancillary service products be defined to add consistency and transparency to the
Exception Request process.
For Question 3 on page 4, recommend that confirmation of must-run generation
be provided by the Reliability Coordinator, Reliability Planner, or the Balancing
Authority as a clarification to the “appropriate reference”.

Response: These questions have been provided to those members of the SDT who are working on responses to the criteria posting
questions. They will be responded to in detail in those documents.
Colin Anderson

Ontario Power
Generation Inc.

5

Negative

OPG continues to question the need for the changes required (and costs
imposed) as a result of this new definition. This is particularly true in the NPCC
region where an impact based methodology is being used to determine the set of
BES elements. A very clear 100kV bright line, as proposed in this draft, will
dramatically increase the list of generation elements that must meet reliability
standards, without a corresponding increase in wide-area reliability.

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OPG recommends that the work planned for phase II, technical justification of the
generation and voltage thresholds, should be completed before implementing the
new definition of BES. OPG does not agree that the question of the 20 MVA
(single) versus 75 MVA (aggregate) threshold should be deferred until a
subsequent phase of the standard development process ("Phase II"). This
question should be resolved now. In general, key elements of the development
process should not be parsed out into multiple phases, in hopes that "Standard
Development Fatigue" will eliminate critics of the approach.
Further, selecting the generator terminals as the boundary for BES within the
generating station means that the Isolated Phase Bus (IPB), which connects the
generator terminals to the Low Voltage (LV) terminals of the generator step-up
(GSU) transformer, is now included as a BES element. The IPB is operated at low
voltage, no more than 22kV, so including it as a BES element is going beyond the
FERC order 743 and 743a. OPG strongly recommends that the BES boundary be
moved to the LV terminals of the GSU transformer.
To assure availability of the generation blackstart resources identified in the
Transmission Operator’s Power System Restoration Plan the generators are tested
according to the requirements of reliability standard EOP-009. Blackstart
resources are only required post LOBES (Loss of Bulk Electric System) and in
many cases do not contribute to the reliability of the BES under normal operating
conditions. OPG recommends that this inclusion be removed from the new
definition of BES.
OPG disagrees in general with proceeding to implement a 100 kV brightline
definition in the absence of a properly quantified cost/benefit analysis. Entities
are being asked to incur a high cost for no demonstrated benefit in wide-area
reliability.

Response: The SDT refers OPG to the individual comment responses in the definition comment form as the comments expressed
here are identical to the comments submitted by OPG on that form.
Roland Thiel

Platte River
Power
Authority

5

Negative

Definition of BES Platte River believes that the SDT has made substantial progress
towards a clear and workable definition of the BES. Although Platte River ballots
“Negative” we strongly support the approach to defining the Bulk Electric System
as proposed here. Platte River recognizes that, given the deadlines imposed by

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FERC in Order No. 743, it will not be possible for the SDT to conduct a technical
analysis within the time available. Accordingly, Platte River agrees with the
approach taken by the SDT, which is to propose a Phase II of the standards
development process that would address the generator threshold level and other
issues. However, it is our opinion that the second draft would benefit from further
clarification or modification. That said, Platte River is prepared to support the BES
definition as proposed by the SDT going forward. Platte River has taken the
opportunity to provide this industry feedback, as it is our understanding that we
will be afforded another ballot opportunity. If this were to be our sole occasion to
ballot, we would vote “Affirmative” at this time. We are encouraged by the work
that has been completed and we commend the SDT for their commitment and
extensive work thus far.
Detailed Information to Support BES Exceptions Requests Platte River believes
that a Yes vote for the Technical Principles for Demonstrating BES Exceptions
Request will result in minimal changes to today’s process under the current
definition which includes the language “as defined by the Regional Reliability
Organization.” While the proposed Technical Principles for Demonstrating BES
Exceptions Request includes a checklist that must be submitted with exception
requests, a yes vote will still require each region to develop their own methods
and criteria for assessing materials submitted with exemption requests. We
believe that a No vote with guidance to the drafting team that objective methods
and criteria must be developed and applied continent-wide will result in the
desired uniformity and consistency among regions in their assessment of
exception requests.

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step in
Phase II will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit comments
for the inclusion of items and issues to be considered by the SDT in Phase II.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
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would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria
and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to
say that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with
this position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at
as a single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional
Entity plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this
places the Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be
supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also
believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the
proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent
Technical Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s
findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure,
Section 7.0, provides NERC the option to remand the request to the Regional Entity with the mandate to process the exception if it
finds the Regional Entity erred in rejecting or disapproving the exception request. On the other side of this equation, one could
make an argument that the Regional Entity has no basis for what constitutes an acceptable submittal. Commenters point out that
the explicit types of studies to be provided and how to interpret the information aren’t shown in the request process. The SDT
again points to the variations that will abound in the requests as negating any hard and fast rules in this regard. However, one is
not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there is a great deal of
professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having viewed the request
details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be supplied for the
submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables
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to take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation
of the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the
elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result ofa sudden disturbance, including a cyber
security incident, or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel,
the visibility of the process, and the experience gained by having this same panel review multiple requests will result in an
equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision
has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be
approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in
a favorable outcome.
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Steven Grega

Entity
Public Utility
District No. 1
of Lewis
County

Segment
5

Vote
Negative

Comment
The bright line definition makes the BES too inclusive. Many smaller facilities are
cought in the definition that are NOT BES facilities. Would suggest only the major
transmission cranking paths, in our area, as defined by WECC, should be
included. Why subject so many to these regulation when there is no or little
return on reliability to the system. We worry about compliance not reliability. In
our case, our small public utility has a run-of-river 70MW hydro (29MWave), nondispatchable, similar to wind. We made the mistake of connection to BPA's 230kV
system rather than our 69kV system. Our portion of the 230kV is uncontrolled by
a SCADA system. In our utility, we rely on phone calls for all outage reporting.
Since the 230kV line our feeds our utility substation and we have an alternitive
69kV connection, many time it is not a concern if the 230kV line is out. The
definition of the BES should be limited to truly only the major transmission paths
and major generation plants. I beleive it is good utility practce to make sure right
of ways are clear and relays are tested, but a number of Standards go way too
far with little or no benefit to the system, especially for smaller utilities. I think it
is time that we step back and evaluate what is truly important in making the BES
more reliable. Limiting the BES definition would be a good start.

Response: The bright-line definition is a continent-wide definition. In these instances, there will always be one off situations where
the bright-line might not apply. With the changes to the ERO Rules of Procedure for exception requests, an entity will have the right
to request exception from the definition even if the application of the bright-line would have brought them into the fold.
Dennis Kimm

MidAmerican
Energy Co.

6

Negative

The BES definition needs additional specific inclusion or exclusion provisions that
clearly exclude variable resource generation collector circuits rated below 100 kV
and generators less than 20 MVA connected to those collector circuits in
accordance with the registration criteria.

Response: Inclusion I4 denotes an aggregate threshold. This is clear from the requirement inclusion threshold of “aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating).”
Steven J Hulet

Salt River
Project

6

Negative

The Blackstart “Cranking Path” has been deleted from Inclusion 3 of the BES
definition. However, NERC standards EOP-005 and CIP-002, R1.2.4 require
documenting the Cranking Path. In addition, CIP-002-4 identifies the Cranking
Path as a Critical Asset in Attachment 1. Compliance to the NERC Standards
needs to be an exact science whenever possible. SRP does not argue the

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inclusion or exclusion of Cranking Path. However, if it is excluded, guidance must
be provided on whether or not a Cranking Path is subject to the previously
mentioned Standards.

Response: Cranking Paths are subject to any standard in which they are specifically spelled out.
Donald Nelson

Commonwealth
of
Massachusetts
Department of
Public Utilities

9

Negative

Please refer to our detailed comments filed today. As described further in our
comments, the MA DPU is primarly concerned with the substance of the definition
and the process for developing this standard as follows: 1) Phased Approach.
While well-intentioned, separating the BES definition project into two separate
phases is problematic from both a procedural and substantive perspective. While
we recognize that the filing due date is rapidly approaching, the BES definition
cannot be considered in a vacuum, divorced from the concerns raised by a
number of parties in response to past postings of the BES definition. The issues
NERC has identified for consideration during the proposed “Phase 2” are
inseparable from the development of the BES definition (e.g., generation
thresholds, technical justification for the 100 kV threshold) and should be
squarely addressed before a definition is adopted and ratepayers incur costs
related to compliance with mandates that may or may not be revised through the
second phase of the project. The importance of considering concerns before
adopting a definition is heightened by the proposed two-year implementation
requirement. This short implementation period almost guarantees that entities
will commit resources shortly after adoption of the definition to ensure
compliance within the mandated period. In other words, ratepayers will bear
costs related to compliance irrespective of any change resulting from the Phase 2
process or the exception process. Expediency, while understandable given the
filing deadline, must be balanced against the risk that a multi-phased approach
could lead to significant consumer costs without attendant meaningful reliability
benefits.
2) Cost-Benefit Analysis. A cost impact analysis should be performed as part of
developing any reliability standard. However, the development of the BES
definition has failed to consider the cost impacts of the definition (and its
inclusions and exclusions) and has not weighed these impacts against identified

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benefits that the definition would achieve. The MA DPU supported the May 21,
2011 comments from the New England States Committee on Electricity
(“NESCOE”) on the last posting of the BES definition. In these comments,
NESCOE stated that “any new costs a revised definition imposes - which fall
ultimately on consumers - should provide meaningful reliability benefits.” A costbenefit analysis should be integral to the development of a BES definition and,
indeed, any reliability standard. This analysis should include a probabilistic risk
assessment examining the likelihood of an event and the costs and risks resulting
from such event, which should be weighed against the costs of complying with
the proposed reliability measures.
3) Technical Justification. In addition to performing a cost-benefit analysis, a
technical basis must be provided to justify a proposed reliability standard.
However, the proposed BES definition does not provide a technical justification
for the 100 kV threshold, the threshold for generation resources, or other
elements of the definition. As stated above, while well-intentioned and
understandable, deferring this technical justification to a later and separate phase
of the project is a flawed and potentially costly approach. Providing a technical
justification for a reliability standard is a core function of standards development
and should be addressed at the forefront of the process rather than relegated to
a separate phase largely undertaken after a standard is filed.

Response: 1. Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step
in Phase II will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit
comments for the inclusion of items and issues to be considered by the SDT in Phase II. Since the revised definition relies heavily
on the status quo of the current definition, the SDT does not anticipate that many entities will be burdened with additional costs.
2. The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 & 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
contracting the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the
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current BES definition has varying degrees of Regional application and has resulted in different conclusions on what is currently
considered to be part of the BES. This inconsistency in the application and subsequent results were also identified by the
Commission in Orders No. 743 & 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition
coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on Regions.
Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid
on a continent-wide basis. Therefore, the SDT believes the best opportunity to address cost concerns will be through the
development of Regional transition plans once the definition has been approved by the Commission.
3. Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step in Phase II
will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit comments for the
inclusion of items and issues to be considered by the SDT in Phase II. Technical justifications for all variables involved in the
definition will be done in Phase II.
Diane J Barney

National
Association of
Regulatory
Utility
Commissioners

9

Negative

There is a lack of clarity as to how the information is to be used and by what
weight in the exception process.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire
is not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The
SDT would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the
criteria and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to
say that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with
this position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at
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as a single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional
Entity plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this
places the Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be
supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also
believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the
proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent
Technical Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s
findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure,
Section 7.0, provides NERC the option to remand the request to the Regional Entity with the mandate to process the exception if it
finds the Regional Entity erred in rejecting or disapproving the exception request. On the other side of this equation, one could
make an argument that the Regional Entity has no basis for what constitutes an acceptable submittal. Commenters point out that
the explicit types of studies to be provided and how to interpret the information aren’t shown in the request process. The SDT
again points to the variations that will abound in the requests as negating any hard and fast rules in this regard. However, one is
not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there is a great deal of
professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having viewed the request
details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be supplied for the
submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables
to take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation
of the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the
elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result ofa sudden disturbance, including a cyber
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security incident, or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel,
the visibility of the process, and the experience gained by having this same panel review multiple requests will result in an
equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision
has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be
approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in
a favorable outcome.
Thomas
Dvorsky

New York State
Department of
Public Service

9

Negative

The currently proposed definition of the BES is based neither on a technical
analysis nor on a cost impact study.

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step in
Phase II will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit comments
for the inclusion of items and issues to be considered by the SDT in Phase II. Technical justifications for all variables involved in the
definition will be done in Phase II.
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The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 & 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
contracting the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the
current BES definition has varying degrees of Regional application and has resulted in different conclusions on what is currently
considered to be part of the BES. This inconsistency in the application and subsequent results were also identified by the
Commission in Orders No. 743 & 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition
coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on Regions.
Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid
on a continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the
development of Regional transition plans once the definition has been approved by the Commission.
Larry Nordell

Montana
Consumer
Counsel

8

Abstain

The BES definition must be cognizant of costs and benefits. At the very least it
needs to have an exclusion for elements whose failure would have no
consequential impacts on the bulk system, and an exclusion for elements for
which the costs inclusion are clearly in excess of the benefits of inclusion.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and
non-BES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 & 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
contracting the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the
current BES definition has varying degrees of Regional application and has resulted in different conclusions on what is currently
considered to be part of the BES. This inconsistency in the application and subsequent results were also identified by the
Commission in Orders No. 743 & 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition
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coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on Regions.
Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid
on a continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the
development of Regional transition plans once the definition has been approved by the Commission.
John D Varnell

Tenaska Power
Services Co.

6

Abstain

Which part of this definition has the highest priority inclusions or exclusions.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES
and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100
kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is
needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
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Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 –
I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks)
should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
William M
Chamberlain

California
Energy
Commission

9

Affirmative

While we are voting in favor of this definition as an improvement over the current
status quo, we agree with WECC that additional improvements are necessary as
set forth below. For Inclusion 3 we agree that Blackstart units should be
considered vital to the overall operation of the BES, and therefore included in the
definition of the BES. However, we do not agree with the deletion of the cranking
path from Inclusion 3. The cranking path should be included in the definition
since NERC standards EOP-005 and CIP-002, R1.2.4 require documenting the
cranking path and the revised CIP-002-4 identifies the cranking path as a critical
asset in Attachment 1. To be able to count on a Blackstart unit to perform as
designed in the Blackstart Restoration Plan, it must be ensured that the cranking
path is available.
We believe that additional clarity is needed in the wording of Inclusion 4. It is our
understanding, for example, that Inclusion 4 is not intended to include each
individual wind turbine generating unit in a wind farm as a BES element, but

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rather to include the point at which the aggregation becomes large enough to
meet the aggregate capacity threshold of 75 MVA. However, the response to
comments from the last comment posting and the current wording of Inclusion 4
do not provide sufficient clarity to answer this question. We believe that the
wording of Inclusion 4 could be modified to add clarity on this topic.
We believe that Inclusion 5 should be modified to identify some minimum
Reactive Power threshold for static or dynamic devices similar to that identified
for generating sources in Inclusion 2. As worded a 1 MVA device supplying or
absorbing Reactive Power that is connected at 100 kV or higher would be
included in the BES. We believe that Exclusion 2 should be modified to include a
size threshold for individual generating units, similar to that identified in Inclusion
2.
As currently worded Exclusion 2 places the same threshold (75 MVA) on a single
generating unit as is placed on multiple generating units.

Response: Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system
Elements. The Transmission Operator’s restoration plans identify a number of possible system restoration scenarios to address the
uncertainty of the actual requirements needed to address a particular restoration event including Cranking Paths. Therefore, the
SDT maintains that Cranking Paths are not required to be included in the BES definition as they are essentially a moving target and
could include distribution Elements. The Cranking Paths issue will be discussed anew in Phase II of this project. No change made.
Inclusion I4 denotes an aggregate threshold. This is clear from the requirement inclusion threshold of “aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating).”
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
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with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
The threshold levels of generators and the relationship between the ERO Statement of Compliance Registry Criteria and the BES
definition will be considered in the Phase 2 review. However, the SDT believes that a value was needed for Phase I and decided to
proceed with the single 75 MVA threshold. No change made.
Claston
Augustus
Sunanon

Orlando
Utilities
Commission

6

Affirmative

Orlando Utilities Commission supports the new definition, although our support is
conditioned on: (1) a workable Exceptions process being developed in
conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date.

Response: The exceptions process and the definition are being worked on in parallel and will b efiled as one document.
Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step in Phase II
will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit comments for the
inclusion of items and issues to be considered by the SDT in Phase II.
Brenda Powell

Constellation
Energy
Commodities
Group

6

Affirmative

While we support the proposed definition to satisfy the FERC Order, we also
support continued work on the threshold questions slated for "Phase II", in
particular the refinement of the generation thresholds.

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. Thresholds will
be analyzed at that time.
Michelle R
DAntuono

Occidental
Chemical

5

Affirmative

1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. Yes:
X Comments: However, one of the FERC directives in Order 743 charged NERC
with delineating the difference between transmission and distribution. The
Inclusions and Exclusions are a step in that direction, but this subject will need
more consideration in Phase II.

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2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments:
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. No: X Comments: Since an aggregate of 75 MVA is allowed at a single
site, there is no basis for maintaining the 20 MVA for a single generator. The
proposed MOD-026 assigns thresholds by region that are much higher than 20
MVA for modeling purposes. Since modeling generally would require more
granularity than what is necessary for the reliable operation of the interconnected
transmission system (BES), the SDT might want to review the threshold basis for
NERC Project 2007-09 (Generator Verification). It is understood that the threshold
will be reconsidered in Phase II of the BES Definition Project; however, a modest
change from 20 to 75 MVA seems appropriate in the interim period justified by
the current 75f MVA aggregate per site. For clarity purposes the following should
be added at the end "unless excluded under Exclusion E2".
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments:
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments: To distinguish this Inclusion from Inclusion I2, the
SDT might want to clarify that the collection system (usually at voltage below 100

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KV anyway) is not part of the BES-just the resources and any transformers
included by I1, if this is indeed the intent of this Inclusion.
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments:
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments: A much needed change from the first posting, as
this will maintain the status quo referred to in the introduction text.
8. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: X Comments:
9. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E3 (local network)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments: This Exclusion and Exclusion E1 aid in the
delineation of distribution versus transmission.
10. The SDT has added specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E4 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments: This is a needed exception to Inclusion I5 as these
reactive power resources are used by retail customers for power factor correction
at their own facilities in order avoid imposed power factor penalties.
11. Are there any other concerns with this definition that haven’t been covered in

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previous questions and comments remembering that the exception criteria are
posted separately for comment? Yes: X Comments: It might be worthwhile to
explain the relationship (timeline) between the BES Definition implementation
plan and the compliance implementation plan proposed in the BES RoP team’s
new Appendix 5C for the NERC Rules of Procedure.

Response: 1. Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step
in Phase II will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit
comments for the inclusion of items and issues to be considered by the SDT in Phase II.
2. Thank you for your support.
3. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. Correlation to MOD standards would be included in Phase II.
4. Thank you for your support.
5. The essential distinction between Inclusions I2 and I4 is that Inclusion I2 may not include generating resources that use lower
voltage collection systems while Inclusion I4 is specifically designed to accomplish this purpose. Inclusion I4 speaks towards the
inclusion of the resources themselves, not the transmission Element(s) of the collector systems operated below 100 kV or not
included under Inclusion I2.
6. – 10. Thank you for your support.
11. For a newly identified Element(s) under the revised BES definition, the time period to be in full compliance with all applicable
Reliability Standards is 24 months from the effective date of the definition. If the entity wishes to file for an exception of a newly
Project 2010-17 BES Definition Ballot Comments
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Comment
identified Element(s) under the revised BES definition through the Rules of Procedure Exception Process, the entity will have 12
months from the effective date of the revised BES definition in which to file such a request. If the exception request is rejected or
disapproved and the classification of the Element(s) remains as a BES Element, the Regional Entity and the owner of such a BES
Element(s) shall agree to an Implementation Plan for full compliance obligations, which will establish an implementation date no
earlier than the date established by the definition Implementation Plan (24 months from the effective date of the definition).
Gary Ofner

North Carolina
Electric
Membership
Corp.

1

Affirmative

In general, we support the proposed definition of the BES. However, we have
identified a few concerns that warrant the SDT’s consideration. We’d prefer to see
the language from the ERO Statement of Compliance Registry Criteria repeated
within the BES Definition itself instead of referencing an outside document. As it
stands right now, the Compliance Registry Criteria needs to stay intact for Phase I
of this project. That makes the Compliance Registry Criteria reliant on the BES
Definition and vice versa.
We understand that the Statement of Compliance Registry Criteria may be
reviewed/revised at the same time Phase 2 of this project is being developed,
therefore we agree with Inclusion I2 of this draft.
Blackstart Resources can actually be on the distribution system. There is still the
question of whether the distribution system would then be subjected to the
enforceable standards. If so, there would most likely be a significant cost increase
associated with tracking compliance for these distribution systems without a
commensurate increase in reliability since Blackstart Resources are rarely used.
This could very well cause entities to un-designate Blackstart Resources on
distribution systems to avoid these distribution systems from becoming part of
the BES. The same rationale that was used for eliminating cranking paths could
also be applied to Blackstart Resources.
A flowgate should not be used to limit applicability of E3. First, there is no
definition for what constitutes a permanent flowgate. Second, flowgates are often
created for a myriad of reasons that have nothing to do with them being
necessary to operate the BES. While section c) in E3 attempts to limit the
applicability to permanent flowgates, there is no definition for what constitutes a
permanent flowgate particularly since no flowgate is truly permanent. The NERC
Glossary of Terms definition of flowgate includes flowgates in the IDC. This is a

Project 2010-17 BES Definition Ballot Comments
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Voter

Jeffrey S
Brame

Entity

North Carolina
Electric
Membership
Corp.

Segment

5

Vote

Affirmative

Comment
problem because flowgates are included in the IDC for many reasons not just
because reliability issues are identified. Flowgates could be included to simply
study the impact of schedules on a particular interface as an example. It does not
mean the interface is critical. As an example, it could be used to generate
evidence that there are no transactional impacts to support exclusion from the
BES. Furthermore, the list of flowgates in the IDC is dynamic. The master list of
IDC flowgates is updated monthly and IDC users can add temporary flowgates at
anytime. While the “permanent” adjective applied to flowgates probably limits the
applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month
and removed another. Flowgates are created for many reasons that have nothing
to do with them being necessary to operate the BES. First, flowgates are created
to manage congestion. The IDC is more of a congestion management tool than a
reliability tool. FERC recognized this in Order 693, when they directed NERC to
make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs
that have been violated. Rather, other actions such as re-dispatch must be used
in conjunction. Second, flowgates are used as a convenient point to calculate
flows to sell transmission service. The characteristics of the flowgate make it a
good proxy for estimating how much contractual use has been sold not
necessarily how much flow will actually occur. While some flowgates definitely are
created for reliability issues such as IROLs, many simply are not. The term “nonretail generation” used in Exclusion E1 (item c) and again in E3 (item a) should
be clarified (see comments for question 8 below). The Note after item c should
also be clarified to indicate that closing a normally open switch doesn’t affect this
exclusion.
In general, we support the proposed definition of the BES. However, we have
identified a few concerns that warrant the SDT’s consideration. We’d prefer to see
the language from the ERO Statement of Compliance Registry Criteria repeated
within the BES Definition itself instead of referencing an outside document. As it
stands right now, the Compliance Registry Criteria needs to stay intact for Phase I
of this project. That makes the Compliance Registry Criteria reliant on the BES
Definition and vice versa.

Project 2010-17 BES Definition Ballot Comments
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Entity

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Comment
We understand that the Statement of Compliance Registry Criteria may be
reviewed/revised at the same time Phase 2 of this project is being developed,
therefore we agree with Inclusion I2 of this draft.
Blackstart Resources can actually be on the distribution system. There is still the
question of whether the distribution system would then be subjected to the
enforceable standards. If so, there would most likely be a significant cost increase
associated with tracking compliance for these distribution systems without a
commensurate increase in reliability since Blackstart Resources are rarely used.
This could very well cause entities to un-designate Blackstart Resources on
distribution systems to avoid these distribution systems from becoming part of
the BES. The same rationale that was used for eliminating cranking paths could
also be applied to Blackstart Resources.
A flowgate should not be used to limit applicability of E3. First, there is no
definition for what constitutes a permanent flowgate. Second, flowgates are often
created for a myriad of reasons that have nothing to do with them being
necessary to operate the BES. While section c) in E3 attempts to limit the
applicability to permanent flowgates, there is no definition for what constitutes a
permanent flowgate particularly since no flowgate is truly permanent. The NERC
Glossary of Terms definition of flowgate includes flowgates in the IDC. This is a
problem because flowgates are included in the IDC for many reasons not just
because reliability issues are identified. Flowgates could be included to simply
study the impact of schedules on a particular interface as an example. It does not
mean the interface is critical. As an example, it could be used to generate
evidence that there are no transactional impacts to support exclusion from the
BES. Furthermore, the list of flowgates in the IDC is dynamic. The master list of
IDC flowgates is updated monthly and IDC users can add temporary flowgates at
anytime. While the “permanent” adjective applied to flowgates probably limits the
applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month
and removed another. Flowgates are created for many reasons that have nothing
to do with them being necessary to operate the BES. First, flowgates are created
to manage congestion. The IDC is more of a congestion management tool than a

Project 2010-17 BES Definition Ballot Comments
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Entity

Segment

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Comment
reliability tool. FERC recognized this in Order 693, when they directed NERC to
make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs
that have been violated. Rather, other actions such as re-dispatch must be used
in conjunction. Second, flowgates are used as a convenient point to calculate
flows to sell transmission service. The characteristics of the flowgate make it a
good proxy for estimating how much contractual use has been sold not
necessarily how much flow will actually occur. While some flowgates definitely are
created for reliability issues such as IROLs, many simply are not.
The term “non-retail generation” used in Exclusion E1 (item c) and again in E3
(item a) should be clarified (see comments for question 8 below).
The Note after item c should also be clarified to indicate that closing a normally
open switch doesn’t affect this exclusion.

Response: The SDT has reverted to specific numeric thresholds consistent with the ERO Statement of Compliance Registry Criteria
for Phase I.
Thank you for your support.
The SDT disagrees that Blackstart Resources should not be included in the BES Definition. The Commission directed NERC to revise
its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric
transmission network. The SDT interprets this to include operation under both normal and emergency conditions, which includes
situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from
the System or can be energized without connection to the remainder of the System, in order to meet a Transmission Operator’s
restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of
the electric system that can be isolated and then energized to deliver electric power during a restoration event are essential to
enable the startup of one or more other generating units as defined in the Transmission Operator’s restoration plan. For these
reasons, the SDT continues to include Blackstart Resources indentified in the Transmission Operator’s restoration plan as BES
elements. No change made.
The SDT believes that the language in Exclusion E3.c prohibiting “Flowgates” from qualifying for definitional exclusion is appropriate
and necessary. As a definitional exclusion characteristic, Exclusion E3.c must follow the principle of being a bright-line and easily
identifiable, and as such, the SDT feels that the definition cannot allow some types of Flowgates and disallow others. Flowgates
must continue to be a prohibiting characteristic under Exclusion E3, since these facilities are more likely to be used in the transfer
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Comment
of bulk power than not. An entity who wishes to make a case for exclusion of a unique type of Flowgate facility can do so through
the exception process. The SDT believes that the continued qualifier of “permanent” associated with the term “Flowgate”
addresses the majority of the concern in this comment. No change made.
“Non-retail generation” means that generation which is on the system (supply) side of the retail meter.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is
operated in the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in
the normal operating environment.
Paul
Cummings

City of Redding

5

Affirmative

An affirmative vote is conditional on NERC's dedication to phase 2 of the Project.

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up.
Pawel Krupa

Seattle City
Light

1

Affirmative

Comments: 1. Core Definition: Yes Comments: Seattle City Light (SCL) believes
that the SDT has made substantial progress towards a clear and workable
definition of the BES. We strongly support the approach to defining the Bulk
Electric System as proposed here. SCL recognizes that, given the deadlines
imposed by FERC in Order No. 743, it will not be possible for the SDT to conduct
a technical analysis within the time available. Accordingly, SCL agrees with the
approach taken by the SDT, which is to propose a Phase II of the standards
development process that would address the generator threshold level and other
issues. However, it is our opinion that the second draft would benefit from further
clarification or modification in a number of respects, as are detailed in our
comments.
2. I1 - Transformer inclusions: No Comments: The wording of Inclusion I1 is not
clear. The term transformers needs to be further defined with respect to
multiphase transformers and generator step-up transformers. Recommend the
following wording: “All transformers with at least two primary and secondary
terminals operated at or above 100kV, and generator step-up transformers (GSU)
with one terminal operated at or above 100kV, unless excluded by E1 or E3.”
3. I2 - Generation Thresholds: Yes Comments: Recommend removing the

Project 2010-17 BES Definition Ballot Comments
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Comment
reference to the Statement of Compliance Registry Criteria. The definition should
be the governing document and provide the details of what generating resources
should be included. The current language induces circular arguments without a
true governing document. The definition should drive what appears in the
Registry Criteria. Inclusion I2 should be revised to read: “Generating resources
with a gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion.
4. I3 - Blackstart Units: Yes Comments: None
5. I4 - Dispersed Power: No Comments: The term “common point” needs
clarification with respect to connection to the BES. Recommend the following
wording: “connected at a common point through a dedicated step-up transformer
with a high-side voltage of 100 KV or above.”
6. I5 - Reactive Power devices: No Comments: Technical studies need to be
conducted to confirm reactive resource impacts on the reliability of the BES. The
inclusion of reactive resources is a significant expansion of the current BES
definition and therefore requires technical justification for inclusion. Inclusion I5
as written is generally confusing with multiple references to other inclusions and
exclusions in the definition. Recommend removing references to reactive
resources from Phase 1 until technical justification can be demonstrated (as part
of Phase 2).
7. E1 - Radial System: Yes Comments: (1) The E1 Reference Note should be reworded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. (2) Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. (3) Recommend that the potential inclusion in the BES of
protective relay systems which reach beyond a load network or ring bus should
be confirmed in Phase 2 pursuant to technical studies.
8. E2 - Behind-the-Meter-Generation: Yes Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in

Project 2010-17 BES Definition Ballot Comments
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Voter

Dana
Wheelock

Entity

Seattle City
Light

Segment

3

Vote

Affirmative

Comment
Section III.c.4.
9. E3 - Local Network: Yes Comments: Defining characteristic b) “Power flows
only into the LN” is confusing. For example, is this condition meant as an
absolute, that power never under any circumstances flows out? Are exceptions
allowed, such as during a switching operation or a catastrophic outage? Does
power flow through a local net load sink, as might be determined by
superposition of supply sources over time, negate that sink from exclusion as a
LN? Recommend additional clarity for this characteristic.
10. E4 - Customer Reactive Power devices: No Comments: Refer to comments
related to reactive resources for Question 6 regarding Inclusion I5.
11. Other concerns: No Comments: Seattle City Light (SCL) believes that the SDT
has made substantial progress towards a clear and workable definition of the
BES. We strongly support the approach to defining the Bulk Electric System as
proposed here. SCL recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address the generator threshold level and other issues. However, it is our
opinion that the second draft would benefit from further clarification or
modification in a number of respects, as are detailed in our comments.
Comments: 1. Core Definition: Yes Comments: Seattle City Light (SCL) believes
that the SDT has made substantial progress towards a clear and workable
definition of the BES. We strongly support the approach to defining the Bulk
Electric System as proposed here. SCL recognizes that, given the deadlines
imposed by FERC in Order No. 743, it will not be possible for the SDT to conduct
a technical analysis within the time available. Accordingly, SCL agrees with the
approach taken by the SDT, which is to propose a Phase II of the standards
development process that would address the generator threshold level and other
issues. However, it is our opinion that the second draft would benefit from further
clarification or modification in a number of respects, as are detailed in our
comments.
2. I1 - Transformer inclusions: No Comments: The wording of Inclusion I1 is not

Project 2010-17 BES Definition Ballot Comments
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Entity

Segment

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Comment
clear. The term transformers needs to be further defined with respect to
multiphase transformers and generator step-up transformers. Recommend the
following wording: “All transformers with at least two primary and secondary
terminals operated at or above 100kV, and generator step-up transformers (GSU)
with one terminal operated at or above 100kV, unless excluded by E1 or E3.”
3. I2 - Generation Thresholds: Yes Comments: Recommend removing the
reference to the Statement of Compliance Registry Criteria. The definition should
be the governing document and provide the details of what generating resources
should be included. The current language induces circular arguments without a
true governing document. The definition should drive what appears in the
Registry Criteria. Inclusion I2 should be revised to read: “Generating resources
with a gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion.
4. I3 - Blackstart Units: Yes Comments: None
5. I4 - Dispersed Power: No Comments: The term “common point” needs
clarification with respect to connection to the BES. Recommend the following
wording: “connected at a common point through a dedicated step-up transformer
with a high-side voltage of 100 KV or above.”
6. I5 - Reactive Power devices: No Comments: Technical studies need to be
conducted to confirm reactive resource impacts on the reliability of the BES. The
inclusion of reactive resources is a significant expansion of the current BES
definition and therefore requires technical justification for inclusion. Inclusion I5
as written is generally confusing with multiple references to other inclusions and
exclusions in the definition. Recommend removing references to reactive
resources from Phase 1 until technical justification can be demonstrated (as part
of Phase 2).
7. E1 - Radial System: Yes Comments: (1) The E1 Reference Note should be reworded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. (2) Recommend that

Project 2010-17 BES Definition Ballot Comments
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8

Voter

Dennis
Sismaet

Entity

Seattle City
Light

Segment

6

Vote

Affirmative

Comment
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. (3) Recommend that the potential inclusion in the BES of
protective relay systems which reach beyond a load network or ring bus should
be confirmed in Phase 2 pursuant to technical studies.
8. E2 - Behind-the-Meter-Generation: Yes Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. E3 - Local Network: Yes Comments: Defining characteristic b) “Power flows
only into the LN” is confusing. For example, is this condition meant as an
absolute, that power never under any circumstances flows out? Are exceptions
allowed, such as during a switching operation or a catastrophic outage? Does
power flow through a local net load sink, as might be determined by
superposition of supply sources over time, negate that sink from exclusion as a
LN? Recommend additional clarity for this characteristic.
10. E4 - Customer Reactive Power devices: No Comments: Refer to comments
related to reactive resources for Question 6 regarding Inclusion I5.
11. Other concerns: No Comments: Seattle City Light (SCL) believes that the SDT
has made substantial progress towards a clear and workable definition of the
BES. We strongly support the approach to defining the Bulk Electric System as
proposed here. SCL recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address the generator threshold level and other issues. However, it is our
opinion that the second draft would benefit from further clarification or
modification in a number of respects, as are detailed in our comments.
Comments: 1. Core Definition: Yes Comments: Seattle City Light (SCL) believes
that the SDT has made substantial progress towards a clear and workable
definition of the BES. We strongly support the approach to defining the Bulk
Electric System as proposed here. SCL recognizes that, given the deadlines
imposed by FERC in Order No. 743, it will not be possible for the SDT to conduct
a technical analysis within the time available. Accordingly, SCL agrees with the

Project 2010-17 BES Definition Ballot Comments
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Voter

Entity

Segment

Vote

Comment
approach taken by the SDT, which is to propose a Phase II of the standards
development process that would address the generator threshold level and other
issues. However, it is our opinion that the second draft would benefit from further
clarification or modification in a number of respects, as are detailed in our
comments.
2. I1 - Transformer inclusions: No Comments: The wording of Inclusion I1 is not
clear. The term transformers needs to be further defined with respect to
multiphase transformers and generator step-up transformers. Recommend the
following wording: “All transformers with at least two primary and secondary
terminals operated at or above 100kV, and generator step-up transformers (GSU)
with one terminal operated at or above 100kV, unless excluded by E1 or E3.”
3. I2 - Generation Thresholds: Yes Comments: Recommend removing the
reference to the Statement of Compliance Registry Criteria. The definition should
be the governing document and provide the details of what generating resources
should be included. The current language induces circular arguments without a
true governing document. The definition should drive what appears in the
Registry Criteria. Inclusion I2 should be revised to read: “Generating resources
with a gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion.
4. I3 - Blackstart Units: Yes Comments: None
5. I4 - Dispersed Power: No Comments: The term “common point” needs
clarification with respect to connection to the BES. Recommend the following
wording: “connected at a common point through a dedicated step-up transformer
with a high-side voltage of 100 KV or above.”
6. I5 - Reactive Power devices: No Comments: Technical studies need to be
conducted to confirm reactive resource impacts on the reliability of the BES. The
inclusion of reactive resources is a significant expansion of the current BES
definition and therefore requires technical justification for inclusion. Inclusion I5
as written is generally confusing with multiple references to other inclusions and
exclusions in the definition. Recommend removing references to reactive

Project 2010-17 BES Definition Ballot Comments
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Entity

Segment

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Comment
resources from Phase 1 until technical justification can be demonstrated (as part
of Phase 2).
7. E1 - Radial System: Yes Comments: (1) The E1 Reference Note should be reworded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. (2) Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. (3) Recommend that the potential inclusion in the BES of
protective relay systems which reach beyond a load network or ring bus should
be confirmed in Phase 2 pursuant to technical studies.
8. E2 - Behind-the-Meter-Generation: Yes Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. E3 - Local Network: Yes Comments: Defining characteristic b) “Power flows
only into the LN” is confusing. For example, is this condition meant as an
absolute, that power never under any circumstances flows out? Are exceptions
allowed, such as during a switching operation or a catastrophic outage? Does
power flow through a local net load sink, as might be determined by
superposition of supply sources over time, negate that sink from exclusion as a
LN? Recommend additional clarity for this characteristic.
10. E4 - Customer Reactive Power devices: No Comments: Refer to comments
related to reactive resources for Question 6 regarding Inclusion I5.
11. Other concerns: No Comments: Seattle City Light (SCL) believes that the SDT
has made substantial progress towards a clear and workable definition of the
BES. We strongly support the approach to defining the Bulk Electric System as
proposed here. SCL recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address the generator threshold level and other issues. However, it is our
opinion that the second draft would benefit from further clarification or
modification in a number of respects, as are detailed in our comments.

Project 2010-17 BES Definition Ballot Comments
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1

Voter
Michael J.
Haynes

Entity
Seattle City
Light

Segment
5

Vote

Comment

Affirmative

1. Core Definition: Yes Comments: Seattle City Light (SCL) believes that the SDT
has made substantial progress towards a clear and workable definition of the
BES. We strongly support the approach to defining the Bulk Electric System as
proposed here. SCL recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address the generator threshold level and other issues. However, it is our
opinion that the second draft would benefit from further clarification or
modification in a number of respects, as are detailed in our comments.
2. I1 - Transformer inclusions: No Comments: The wording of Inclusion I1 is not
clear. The term transformers needs to be further defined with respect to
multiphase transformers and generator step-up transformers. Recommend the
following wording: “All transformers with at least two primary and secondary
terminals operated at or above 100kV, and generator step-up transformers (GSU)
with one terminal operated at or above 100kV, unless excluded by E1 or E3.”
3. I2 - Generation Thresholds: Yes Comments: Recommend removing the
reference to the Statement of Compliance Registry Criteria. The definition should
be the governing document and provide the details of what generating resources
should be included. The current language induces circular arguments without a
true governing document. The definition should drive what appears in the
Registry Criteria. Inclusion I2 should be revised to read: “Generating resources
with a gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion.
4. I3 - Blackstart Units: Yes Comments: None
5. I4 - Dispersed Power: No Comments: The term “common point” needs
clarification with respect to connection to the BES. Recommend the following
wording: “connected at a common point through a dedicated step-up transformer
with a high-side voltage of 100 KV or above.”
6. I5 - Reactive Power devices: No Comments: Technical studies need to be

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Entity

Segment

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Comment
conducted to confirm reactive resource impacts on the reliability of the BES. The
inclusion of reactive resources is a significant expansion of the current BES
definition and therefore requires technical justification for inclusion. Inclusion I5
as written is generally confusing with multiple references to other inclusions and
exclusions in the definition. Recommend removing references to reactive
resources from Phase 1 until technical justification can be demonstrated (as part
of Phase 2).
7. E1 - Radial System: Yes Comments: (1) The E1 Reference Note should be reworded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. (2) Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. (3) Recommend that the potential inclusion in the BES of
protective relay systems which reach beyond a load network or ring bus should
be confirmed in Phase 2 pursuant to technical studies.
8. E2 - Behind-the-Meter-Generation: Yes Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. E3 - Local Network: Yes Comments: Defining characteristic b) “Power flows
only into the LN” is confusing. For example, is this condition meant as an
absolute, that power never under any circumstances flows out? Are exceptions
allowed, such as during a switching operation or a catastrophic outage? Does
power flow through a local net load sink, as might be determined by
superposition of supply sources over time, negate that sink from exclusion as a
LN? Recommend additional clarity for this characteristic.
10. E4 - Customer Reactive Power devices: No Comments: Refer to comments
related to reactive resources for Question 6 regarding Inclusion I5.
11. Other concerns: No Comments: Seattle City Light (SCL) believes that the SDT
has made substantial progress towards a clear and workable definition of the
BES. We strongly support the approach to defining the Bulk Electric System as
proposed here. SCL recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct a technical analysis

Project 2010-17 BES Definition Ballot Comments
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3

Voter

Hao Li

Entity

Seattle City
Light

Segment

4

Vote

Affirmative

Comment
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address the generator threshold level and other issues. However, it is our
opinion that the second draft would benefit from further clarification or
modification in a number of respects, as are detailed in our comments.
Comments: 1. Core Definition: Yes Comments: Seattle City Light (SCL) believes
that the SDT has made substantial progress towards a clear and workable
definition of the BES. We strongly support the approach to defining the Bulk
Electric System as proposed here. SCL recognizes that, given the deadlines
imposed by FERC in Order No. 743, it will not be possible for the SDT to conduct
a technical analysis within the time available. Accordingly, SCL agrees with the
approach taken by the SDT, which is to propose a Phase II of the standards
development process that would address the generator threshold level and other
issues. However, it is our opinion that the second draft would benefit from further
clarification or modification in a number of respects, as are detailed in our
comments.
2. I1 - Transformer inclusions: No Comments: The wording of Inclusion I1 is not
clear. The term transformers needs to be further defined with respect to
multiphase transformers and generator step-up transformers. Recommend the
following wording: “All transformers with at least two primary and secondary
terminals operated at or above 100kV, and generator step-up transformers (GSU)
with one terminal operated at or above 100kV, unless excluded by E1 or E3.”
3. I2 - Generation Thresholds: Yes Comments: Recommend removing the
reference to the Statement of Compliance Registry Criteria. The definition should
be the governing document and provide the details of what generating resources
should be included. The current language induces circular arguments without a
true governing document. The definition should drive what appears in the
Registry Criteria. Inclusion I2 should be revised to read: “Generating resources
with a gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion.

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4. I3 - Blackstart Units: Yes Comments: None
5. I4 - Dispersed Power: No Comments: The term “common point” needs
clarification with respect to connection to the BES. Recommend the following
wording: “connected at a common point through a dedicated step-up transformer
with a high-side voltage of 100 KV or above.”
6. I5 - Reactive Power devices: No Comments: Technical studies need to be
conducted to confirm reactive resource impacts on the reliability of the BES. The
inclusion of reactive resources is a significant expansion of the current BES
definition and therefore requires technical justification for inclusion. Inclusion I5
as written is generally confusing with multiple references to other inclusions and
exclusions in the definition. Recommend removing references to reactive
resources from Phase 1 until technical justification can be demonstrated (as part
of Phase 2).
7. E1 - Radial System: Yes Comments: (1) The E1 Reference Note should be reworded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. (2) Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. (3) Recommend that the potential inclusion in the BES of
protective relay systems which reach beyond a load network or ring bus should
be confirmed in Phase 2 pursuant to technical studies.
8. E2 - Behind-the-Meter-Generation: Yes Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. E3 - Local Network: Yes Comments: Defining characteristic b) “Power flows
only into the LN” is confusing. For example, is this condition meant as an
absolute, that power never under any circumstances flows out? Are exceptions
allowed, such as during a switching operation or a catastrophic outage? Does
power flow through a local net load sink, as might be determined by
superposition of supply sources over time, negate that sink from exclusion as a
LN? Recommend additional clarity for this characteristic.
10. E4 - Customer Reactive Power devices: No Comments: Refer to comments

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Comment
related to reactive resources for Question 6 regarding Inclusion I5.
11. Other concerns: No Comments: Seattle City Light (SCL) believes that the SDT
has made substantial progress towards a clear and workable definition of the
BES. We strongly support the approach to defining the Bulk Electric System as
proposed here. SCL recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address the generator threshold level and other issues. However, it is our
opinion that the second draft would benefit from further clarification or
modification in a number of respects, as are detailed in our comments.

Response: 1. Thank you for your support.
2. The SDT believes the existing language is clear and the proposed additional language would be redundant. No change made.
3. The SDT has reverted to specific numeric thresholds consistent with the ERO Statement of Compliance Registry Criteria for Phase
I.
4. Thank you for your support.
5. The “single point of connection of 100 kV or higher” is where the radial system will begin if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the radial
system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the transmission
line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker and a half
bus configuration could also be the beginning of the radial system and the owner of the bus would need to insure the reliability of
the substation.
6. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
Project 2010-17 BES Definition Ballot Comments
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Entity
Segment
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Comment
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
7. Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is
operated in the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in
the normal operating environment. The treatment of protection systems is but one of many items to be analyzed in Phase II.
8. The wording of Exclusion E2 is essentially the same as the wording on this topic in the ERO Statement of Registry Criteria which
has been in existence for several years and is well understood in the industry. The roles of the Balancing Authority, Generator
Owner, and Generator Operator are implied in the ERO Statement of Compliance Registry Criteria and the terms were added to
Exclusion E2 as the result of industry requests for clarification.
9. Several commenters suggested that the requirement under Exclusion E3.b should apply only during normal operating conditions,
in other words, commenters felt that some power flow should be allowed to flow from the candidate local network back into the
BES as long as it only occurred under abnormal conditions. To this suggestion, the SDT considered the addition of the phrase
“under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined that in order to maintain the intent of a
bright-line characteristic in the BES definition such a qualifier could not be accommodated. However, the SDT pointed out that for
those circumstances where a candidate for local network is unable to utilize the local network exclusion due to an abnormal
situation that caused power to flow out of the network, the network could be a suitable candidate that could apply for exclusion
under the Exception Process.
10. See response in #6 above.
11. Thank you for your support.
Long T Duong

Snohomish
County PUD
No. 1

1

Affirmative

The Public Utility District No. 1 of Snohomish County (“SNPD”) believes the SDT
continues to make substantial progress towards a clear and workable definition of
the Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. SNPD therefore strongly supports the
new definition, although our support is conditioned on: (1) a workable Exceptions
process being developed in conjunction with the BES definition; and,

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Comment
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date.
Below are SNPD’s responses to the NERC comment form for the 2nd Draft of
Definition of BES (Project 2010-17). SNPD believes the refinements below will
clarify the current draft of the BES definition, without changing the current intent.
1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments.
Comments: SNPD strongly supports the following elements of the revised BES
definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The
revised core definition moves the phrase “Unless modified by the lists shown
below” to the beginning of the definition. This change makes clear that the
Inclusions and Exclusions apply to all Elements that would otherwise be included
in or excluded from the core definition (i.e., “all Transmission Elements operated
at 100 kV or higher and Real Time and Reactive Power resources connected at
100 kV or higher”) and eliminates a latent ambiguity in the first draft of the
definition, discussed further in our comments on the first draft.
(2) The exclusion for Local Distribution Facilities. As the starting point for the BES
definition, SNPD supports use of the phrase “all Transmission Elements” and the
qualifying sentence: “This does not include facilities used in the local distribution
of electric energy.” This language helps ensure that FERC, NERC, and the
Regional Entities (“REs”) will act within the jurisdictional constrains Congress
placed in Section 215 of the Federal Power Act (“FPA”). In Section 215(a)(1),
Congress unequivocally excluded “facilities used in the local distribution of electric
energy” from the keystone “bulk-power system” definition. 16 U.S.C. §
824o(a)(1). Including the same language in the definition helps ensure that
entities involved in enforcement of reliability standards will act within their
statutory limits. In addition, as a practical matter, inclusion of the language will

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help focus both the industry and responsible agencies on the high-voltage
interstate transmission system, where the reliability problems Congress intended
to regulate - “instability, uncontrolled separation, [and] cascading failures,” 16
U.S.C. § 824o(a)(4) - will originate. At the same time, level-of-service issues
arising in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16 U.S.C.
§ 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). For similar reasons, Snohomish believes use of the
phrase “Transmission Elements” as the starting point for the base definition is
desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used, and the term “Transmission” makes clear that the
BES includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power.
(3) Appropriate Generator Thresholds. In the standards development process, it
has become apparent that the thresholds for classifying generators as BES in the
current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for
individual generators, 75 MVA for multiple generators aggregated at a single site),
which predate the adoption of FPA Section 215, were never the product of a
careful analysis to determine whether generators of that size are necessary for
operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development
process. Snohomish recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct such an analysis
within the time available. Accordingly, Snohomish agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold issue and several other technical
issues that have arisen during the current process. As long as Phase II proceeds
expeditiously, Snohomish is prepared to support the BES definition as proposed
by the SDT. While Snohomish strongly supports the overall approach adopted by
the SDT and much of the specific language incorporated into the second draft of
the BES definition, we believe the second draft would benefit from further
clarification or modification in a number of respects, most of which are detailed in

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Comment
our subsequent answers. Our support for the definition is not contingent upon
these changes being adopted.
Further, we believe a workable Exclusion Process is essential for a BES Definition
that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection.
As detailed in our previous comments, Snohomish believes a 200-kV threshold
would be more appropriate for WECC than a 100-kV threshold. In addition, a 200kV threshold for the West is backed by solid technical analysis conducted by the
WECC Bulk Electric System Definition Task Force, and repeated claims that there
is no technical analysis to support this view is therefore incorrect. That being said,
we raise the issue here to emphasize the importance of the Exclusions for Local
Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western
Interconnection because the core definition will be over-inclusive in our region. As
long as those Exclusions and the Exceptions Process are retained in a form
substantially equivalent to those produced by the SDT at this juncture,
Snohomish will support the SDT’s proposal and will not further pursue its claims
regarding the 200-kV threshold.
Finally, we suggest that the SDT language address the circumstance when a
facility is covered by both an Inclusion and an Exclusion. We note that some of
the inclusions already contain language addressing this question. For example,
Inclusion 1 indicates that transformers falling within the specified parameters are
part of the BES “. . . unless excluded under Exclusions E1 or E3.” Where it is not
already included, similar language should be included in the other Inclusions
and/or Exclusions to explain whether the SDT intends the Inclusions or the
Exclusions to predominate in situations where facilities might be covered by both.
We suggest clarifying language in our comments to I1 and I4 below. 2. The SDT
has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1 (transformers)? If you do not support
this change or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments.
Comments: We support the SDT’s changes to the first Inclusion because it is

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more clear and simple than the initial approach. That being said, we suggest that
an additional sentence o

William T
Moojen

Snohomish
County PUD
No. 1

6

Affirmative

The Public Utility District No. 1 of Snohomish County (“SNPD”) believes the SDT
continues to make substantial progress towards a clear and workable definition of
the Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. SNPD therefore strongly supports the
new definition, although our support is conditioned on: (1) a workable Exceptions
process being developed in conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date. Below are SNPD’s
responses to the NERC comment form for the 2nd Draft of Definition of BES
(Project 2010-17). SNPD believes the refinements below will clarify the current
draft of the BES definition, without changing the current intent.
1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments.
Comments: SNPD strongly supports the following elements of the revised BES
definition:
(1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the
beginning of the definition. This change makes clear that the Inclusions and
Exclusions apply to all Elements that would otherwise be included in or excluded
from the core definition (i.e., “all Transmission Elements operated at 100 kV or
higher and Real Time and Reactive Power resources connected at 100 kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition,
discussed further in our comments on the first draft.
(2) The exclusion for Local Distribution Facilities. As the starting point for the BES
definition, SNPD supports use of the phrase “all Transmission Elements” and the
qualifying sentence: “This does not include facilities used in the local distribution

Project 2010-17 BES Definition Ballot Comments
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1

Voter

Entity

Segment

Vote

Comment
of electric energy.” This language helps ensure that FERC, NERC, and the
Regional Entities (“REs”) will act within the jurisdictional constrains Congress
placed in Section 215 of the Federal Power Act (“FPA”). In Section 215(a)(1),
Congress unequivocally excluded “facilities used in the local distribution of electric
energy” from the keystone “bulk-power system” definition. 16 U.S.C. §
824o(a)(1). Including the same language in the definition helps ensure that
entities involved in enforcement of reliability standards will act within their
statutory limits. In addition, as a practical matter, inclusion of the language will
help focus both the industry and responsible agencies on the high-voltage
interstate transmission system, where the reliability problems Congress intended
to regulate - “instability, uncontrolled separation, [and] cascading failures,” 16
U.S.C. § 824o(a)(4) - will originate. At the same time, level-of-service issues
arising in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16 U.S.C.
§ 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). For similar reasons, Snohomish believes use of the
phrase “Transmission Elements” as the starting point for the base definition is
desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used, and the term “Transmission” makes clear that the
BES includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power.
(3) Appropriate Generator Thresholds. In the standards development process, it
has become apparent that the thresholds for classifying generators as BES in the
current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for
individual generators, 75 MVA for multiple generators aggregated at a single site),
which predate the adoption of FPA Section 215, were never the product of a
careful analysis to determine whether generators of that size are necessary for
operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development
process. Snohomish recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct such an analysis
within the time available. Accordingly, Snohomish agrees with the approach taken

Project 2010-17 BES Definition Ballot Comments
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Entity

Segment

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Comment
by the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold issue and several other technical
issues that have arisen during the current process. As long as Phase II proceeds
expeditiously, Snohomish is prepared to support the BES definition as proposed
by the SDT. While Snohomish strongly supports the overall approach adopted by
the SDT and much of the specific language incorporated into the second draft of
the BES definition, we believe the second draft would benefit from further
clarification or modification in a number of respects, most of which are detailed in
our subsequent answers. Our support for the definition is not contingent upon
these changes being adopted. Further, we believe a workable Exclusion Process is
essential for a BES Definition that will meet the legal requirements of FPA Section
215, especially for systems operating in the Western Interconnection. As detailed
in our previous comments, Snohomish believes a 200-kV threshold would be
more appropriate for WECC than a 100-kV threshold. In addition, a 200-kV
threshold for the West is backed by solid technical analysis conducted by the
WECC Bulk Electric System Definition Task Force, and repeated claims that there
is no technical analysis to support this view is therefore incorrect. That being said,
we raise the issue here to emphasize the importance of the Exclusions for Local
Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western
Interconnection because the core definition will be over-inclusive in our region. As
long as those Exclusions and the Exceptions Process are retained in a form
substantially equivalent to those produced by the SDT at this juncture,
Snohomish will support the SDT’s proposal and will not further pursue its claims
regarding the 200-kV threshold.
Finally, we suggest that the SDT language address the circumstance when a
facility is covered by both an Inclusion and an Exclusion. We note that some of
the inclusions already contain language addressing this question. For example,
Inclusion 1 indicates that transformers falling within the specified parameters are
part of the BES “. . . unless excluded under Exclusions E1 or E3.” Where it is not
already included, similar language should be included in the other Inclusions
and/or Exclusions to explain whether the SDT intends the Inclusions or the

Project 2010-17 BES Definition Ballot Comments
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Voter

Sam Nietfeld

Entity

Snohomish
County PUD
No. 1

Segment

5

Vote

Affirmative

Comment
Exclusions to predominate in situations where facilities might be covered by both.
We suggest clarifying language in our comments to I1 and I4 below. 2. The SDT
has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1 (transformers)? If you do not support
this change or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments.
Comments: We support the SDT’s changes to the first Inclusion because it is
more clear and simple than the initial approach. That being said, we suggest that
an additional sentence o
The Public Utility District No. 1 of Snohomish County (“SNPD”) believes the SDT
continues to make substantial progress towards a clear and workable definition of
the Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. SNPD therefore strongly supports the
new definition, although our support is conditioned on: (1) a workable Exceptions
process being developed in conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date. Below are SNPD’s
responses to the NERC comment form for the 2nd Draft of Definition of BES
(Project 2010-17). SNPD believes the refinements below will clarify the current
draft of the BES definition, without changing the current intent.
1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments.
Comments: SNPD strongly supports the following elements of the revised BES
definition:
(1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the
beginning of the definition. This change makes clear that the Inclusions and
Exclusions apply to all Elements that would otherwise be included in or excluded

Project 2010-17 BES Definition Ballot Comments
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4

Voter

Entity

Segment

Vote

Comment
from the core definition (i.e., “all Transmission Elements operated at 100 kV or
higher and Real Time and Reactive Power resources connected at 100 kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition,
discussed further in our comments on the first draft.
(2) The exclusion for Local Distribution Facilities. As the starting point for the BES
definition, SNPD supports use of the phrase “all Transmission Elements” and the
qualifying sentence: “This does not include facilities used in the local distribution
of electric energy.” This language helps ensure that FERC, NERC, and the
Regional Entities (“REs”) will act within the jurisdictional constrains Congress
placed in Section 215 of the Federal Power Act (“FPA”). In Section 215(a)(1),
Congress unequivocally excluded “facilities used in the local distribution of electric
energy” from the keystone “bulk-power system” definition. 16 U.S.C. §
824o(a)(1). Including the same language in the definition helps ensure that
entities involved in enforcement of reliability standards will act within their
statutory limits. In addition, as a practical matter, inclusion of the language will
help focus both the industry and responsible agencies on the high-voltage
interstate transmission system, where the reliability problems Congress intended
to regulate - “instability, uncontrolled separation, [and] cascading failures,” 16
U.S.C. § 824o(a)(4) - will originate. At the same time, level-of-service issues
arising in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16 U.S.C.
§ 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). For similar reasons, Snohomish believes use of the
phrase “Transmission Elements” as the starting point for the base definition is
desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used, and the term “Transmission” makes clear that the
BES includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power.
(3) Appropriate Generator Thresholds. In the standards development process, it
has become apparent that the thresholds for classifying generators as BES in the
current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for
individual generators, 75 MVA for multiple generators aggregated at a single site),

Project 2010-17 BES Definition Ballot Comments
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Entity

Segment

Vote

Comment
which predate the adoption of FPA Section 215, were never the product of a
careful analysis to determine whether generators of that size are necessary for
operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development
process. Snohomish recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct such an analysis
within the time available. Accordingly, Snohomish agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold issue and several other technical
issues that have arisen during the current process. As long as Phase II proceeds
expeditiously, Snohomish is prepared to support the BES definition as proposed
by the SDT. While Snohomish strongly supports the overall approach adopted by
the SDT and much of the specific language incorporated into the second draft of
the BES definition, we believe the second draft would benefit from further
clarification or modification in a number of respects, most of which are detailed in
our subsequent answers. Our support for the definition is not contingent upon
these changes being adopted. Further, we believe a workable Exclusion Process is
essential for a BES Definition that will meet the legal requirements of FPA Section
215, especially for systems operating in the Western Interconnection. As detailed
in our previous comments, Snohomish believes a 200-kV threshold would be
more appropriate for WECC than a 100-kV threshold. In addition, a 200-kV
threshold for the West is backed by solid technical analysis conducted by the
WECC Bulk Electric System Definition Task Force, and repeated claims that there
is no technical analysis to support this view is therefore incorrect. That being said,
we raise the issue here to emphasize the importance of the Exclusions for Local
Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western
Interconnection because the core definition will be over-inclusive in our region. As
long as those Exclusions and the Exceptions Process are retained in a form
substantially equivalent to those produced by the SDT at this juncture,
Snohomish will support the SDT’s proposal and will not further pursue its claims
regarding the 200-kV threshold.

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John D
Martinsen

Entity

Public Utility
District No. 1
of Snohomish
County

Segment

4

Vote

Affirmative

Comment
Finally, we suggest that the SDT language address the circumstance when a
facility is covered by both an Inclusion and an Exclusion. We note that some of
the inclusions already contain language addressing this question. For example,
Inclusion 1 indicates that transformers falling within the specified parameters are
part of the BES “. . . unless excluded under Exclusions E1 or E3.” Where it is not
already included, similar language should be included in the other Inclusions
and/or Exclusions to explain whether the SDT intends the Inclusions or the
Exclusions to predominate in situations where facilities might be covered by both.
We suggest clarifying language in our comments to I1 and I4 below. 2. The SDT
has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1 (transformers)? If you do not support
this change or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments.
Comments: We support the SDT’s changes to the first Inclusion because it is
more clear and simple than the initial approach. That being said, we suggest that
an additional sentence o
The Public Utility District No. 1 of Snohomish County (“SNPD”) believes the SDT
continues to make substantial progress towards a clear and workable definition of
the Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. SNPD therefore strongly supports the
new definition, although our support is conditioned on: (1) a workable Exceptions
process being developed in conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date. Below are SNPD’s
responses to the NERC comment form for the 2nd Draft of Definition of BES
(Project 2010-17). SNPD believes the refinements below will clarify the current
draft of the BES definition, without changing the current intent.
1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would

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be more appropriate, please provide specific suggestions in your comments.
Comments: SNPD strongly supports the following elements of the revised BES
definition:
(1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the
beginning of the definition. This change makes clear that the Inclusions and
Exclusions apply to all Elements that would otherwise be included in or excluded
from the core definition (i.e., “all Transmission Elements operated at 100 kV or
higher and Real Time and Reactive Power resources connected at 100 kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition,
discussed further in our comments on the first draft.
(2) The exclusion for Local Distribution Facilities. As the starting point for the BES
definition, SNPD supports use of the phrase “all Transmission Elements” and the
qualifying sentence: “This does not include facilities used in the local distribution
of electric energy.” This language helps ensure that FERC, NERC, and the
Regional Entities (“REs”) will act within the jurisdictional constrains Congress
placed in Section 215 of the Federal Power Act (“FPA”). In Section 215(a)(1),
Congress unequivocally excluded “facilities used in the local distribution of electric
energy” from the keystone “bulk-power system” definition. 16 U.S.C. §
824o(a)(1). Including the same language in the definition helps ensure that
entities involved in enforcement of reliability standards will act within their
statutory limits. In addition, as a practical matter, inclusion of the language will
help focus both the industry and responsible agencies on the high-voltage
interstate transmission system, where the reliability problems Congress intended
to regulate - “instability, uncontrolled separation, [and] cascading failures,” 16
U.S.C. § 824o(a)(4) - will originate. At the same time, level-of-service issues
arising in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16 U.S.C.
§ 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). For similar reasons, Snohomish believes use of the
phrase “Transmission Elements” as the starting point for the base definition is
desirable because both “Transmission” and “Elements” are already defined in the

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NERC Glossary of Terms Used, and the term “Transmission” makes clear that the
BES includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power.
(3) Appropriate Generator Thresholds. In the standards development process, it
has become apparent that the thresholds for classifying generators as BES in the
current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for
individual generators, 75 MVA for multiple generators aggregated at a single site),
which predate the adoption of FPA Section 215, were never the product of a
careful analysis to determine whether generators of that size are necessary for
operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development
process. Snohomish recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct such an analysis
within the time available. Accordingly, Snohomish agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold issue and several other technical
issues that have arisen during the current process. As long as Phase II proceeds
expeditiously, Snohomish is prepared to support the BES definition as proposed
by the SDT. While Snohomish strongly supports the overall approach adopted by
the SDT and much of the specific language incorporated into the second draft of
the BES definition, we believe the second draft would benefit from further
clarification or modification in a number of respects, most of which are detailed in
our subsequent answers. Our support for the definition is not contingent upon
these changes being adopted. Further, we believe a workable Exclusion Process is
essential for a BES Definition that will meet the legal requirements of FPA Section
215, especially for systems operating in the Western Interconnection. As detailed
in our previous comments, Snohomish believes a 200-kV threshold would be
more appropriate for WECC than a 100-kV threshold. In addition, a 200-kV
threshold for the West is backed by solid technical analysis conducted by the
WECC Bulk Electric System Definition Task Force, and repeated claims that there
is no technical analysis to support this view is therefore incorrect. That being said,
we raise the issue here to emphasize the importance of the Exclusions for Local

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Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western
Interconnection because the core definition will be over-inclusive in our region. As
long as those Exclusions and the Exceptions Process are retained in a form
substantially equivalent to those produced by the SDT at this juncture,
Snohomish will support the SDT’s proposal and will not further pursue its claims
regarding the 200-kV threshold.
Finally, we suggest that the SDT language address the circumstance when a
facility is covered by both an Inclusion and an Exclusion. We note that some of
the inclusions already contain language addressing this question. For example,
Inclusion 1 indicates that transformers falling within the specified parameters are
part of the BES “. . . unless excluded under Exclusions E1 or E3.” Where it is not
already included, similar language should be included in the other Inclusions
and/or Exclusions to explain whether the SDT intends the Inclusions or the
Exclusions to predominate in situations where facilities might be covered by both.
We suggest clarifying language in our comments to I1 and I4 below. 2. The SDT
has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1 (transformers)? If you do not support
this change or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments.
Comments: We support the SDT’s changes to the first Inclusion because it is
more clear and simple than the initial approach. That being said, we suggest that
an additional sentence o

Response: The SDT refers Snohomish to the individual comment responses in the definition comment form as the comments
expressed here are identical to the comments submitted by Snohomish on that form.
Thomas
Richards

Fort Pierce
Utilities
Authority

4

Affirmative

FPUA supports the exclusion of Local Networks from the BES. Such systems are
generally not “necessary for operating an interconnected electric transmission
network,” the standard in Orders 743 and 743-A. However, we have some
suggestions to clarify the proposed language for this Exclusion. We have a major
concern with the wording in E3 defining a Local Network. The requirement that
“Power flows only into the LN” fails to recognize that loop flows are inevitable in a
networked system, particularly during a contingency. It just doesn’t make sense

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that E3 allows flows out of the LN when exporting power that was generated
within the LN, yet de minimis loop flows are not. I am suggesting that the “Power
flows only into the LN” requirement be replaced with different criteria to allow
“minor” inadvertent transfers across the LN. Such a modification would bring E3
in line with the technical justification paper developed for this project. FPUA
supports FMPA’s suggested change: “Power flows only into the LN, that is, at
each individual connection at 100 kV or higher, the pre-contingency flow of power
is from outside the LN into the LN for all hours of the previous 2 years” to help
clarify the intent. Two years is suggested because it is the time period set out in
the draft exception application form for which an applicant should state whether
power flows through an Element to the BES.

Response: Several commenters suggested that the requirement under Exclusion E3.b should apply only during normal operating
conditions, in other words, commenters felt that some power flow should be allowed to flow from the candidate local network
back into the BES as long as it only occurred under abnormal conditions. To this suggestion, the SDT considered the addition of the
phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined that in order to maintain the intent of
a bright-line characteristic in the BES definition such a qualifier could not be accommodated. However, the SDT pointed out that
for those circumstances where a candidate for local network is unable to utilize the local network exclusion due to an abnormal
situation that caused power to flow out of the network, the network could be a suitable candidate that could apply for exclusion
under the Exception Process.
Allen Mosher

American
Public Power
Association

4

Affirmative

APPA would like to thank the Standard Drafting Team (SDT) for their work on this
standard and will continue to support approval of the current draft of the Bulk
Electric System (BES) definition to meet the FERC imposed deadline. APPA also
fully supports immediate consideration in Phase 2 of this project of the technical
issues raised by the drafting team and commenters in response to the current
draft definition.
The SDT should be applauded for addressing the issue of local distribution
facilities by placing the exclusion in the BES definition itself: “This does not
include facilities used in the local distribution of electric energy.” It is clearly
spelled out in Section 215 that local distribution facilities are not subject to
compliance with NERC standards. Including this statement in the definition
ensures consistency between NERC’s technical standards and the legal foundation

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upon which these standards are based. The current BES definition allows for
various interpretations which could allow for excessive compliance documentation
on facilities that are not part of the BES. The drafting team has provided
sufficient granularity through the specific inclusions and exclusions to provide
clear direction to NERC, regional entities and registered entities on the specific
subset of electric facilities that are included within (or excluded from) the BES.
APPA applauds the SDT for understanding that many utilities have unique system
configurations and there is a need to differentiate between networked and radial
systems. Allowing the exclusion for radial systems serving only load to have a
normally open switch between the BES and such a radial system provides an
important distinction. This clarifies the issue that a single radial fed system is the
same as a system with multiple feeds with normally open switches between them.
The SDT should be commended for identifying and addressing the issue of local
networks (LN). Even though these systems are built in a networked configuration,
the electric energy delivered is intended only to serve local distribution load. APPA
believes that level-of-service/quality-of-service issues arising in local distribution
systems must be left to the authority of state and local regulatory agencies and
governing bodies. Therefore local networks should be excluded from the BES.
APPA is concerned that the 20MVA & 75MVA generation threshold was not
addressed in Phase 1 of this project, but fully recognizes the difficulty in timely
completing development of the necessary technical studies and consensus
development required to include this improvement in Phase 1. For these reasons,
APPA supports the current draft BES definition and requests that the SDT move
quickly to the phase 2 process to study what generation is necessary for reliable
operation of the BES.
APPA also requests more specificity on the detailed information required to
support BES exceptions processed through the NERC Rules of Procedure drafting
process. Additional technical specificity will help ensure consistency between
regions and transparency for registered entities on the technical studies and data

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required to support exception requests.

Response: Thank you for your support.
Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria
and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to
say that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with
this position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at
as a single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional
Entity plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this
places the Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be
supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also
believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the
proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent
Technical Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s
findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure,
Section 7.0, provides NERC the option to remand the request to the Regional Entity with the mandate to process the exception if it
finds the Regional Entity erred in rejecting or disapproving the exception request. On the other side of this equation, one could
make an argument that the Regional Entity has no basis for what constitutes an acceptable submittal. Commenters point out that
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the explicit types of studies to be provided and how to interpret the information aren’t shown in the request process. The SDT
again points to the variations that will abound in the requests as negating any hard and fast rules in this regard. However, one is
not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there is a great deal of
professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having viewed the request
details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be supplied for the
submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables
to take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation
of the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the
elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result ofa sudden disturbance, including a cyber
security incident, or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel,
the visibility of the process, and the experience gained by having this same panel review multiple requests will result in an
equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision
has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be
approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
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Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in
a favorable outcome.
Greg Lange

Public Utility
District No. 2
of Grant
County

3

Affirmative

The Public Utility District No. 1 of Grant County (“GCPD”) believes the SDT
continues to make substantial progress towards a clear and workable definition of
the Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. GCPD therefore strongly supports the
new definition, although our support is conditioned on: (1) a workable Exceptions
process being developed in conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date.
GCPD strongly supports the addition of the language regarding local distribution
facilities, as it matches congressional intent to leave the regulation of these
facilities to state and local authorities.
We also support the SDT’s proposal to develop detailed guidance concerning the
point of demarcation between BES and non-BES elements in the Phase II SAR. In
this regard, we note that, while Inclusion 1 at least implicitly suggests that the
dividing line between BES and non-BES Elements should be at the transformer
where transmission-level voltages are stepped down to distribution-level voltages,
we believe further clarification of this point of demarcation between the BES and
non-BES Elements is necessary. Many different configurations of transformers and
other equipment that may lie at the juncture between the BES and non-BES
systems. If the point of demarcation is designated at the transformer without
further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately

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stringent regulations and undue costs. For example, distribution-only utilities
commonly own the switches, bus and transformer protection devices on the high
side of transformers where they take delivery from their transmission provider.
Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As
the Phase II process moves forward, we recommend that SDT consider the
extensive work performed on the point of demarcation question by the WECC
BESDTF.
GCPD does not support The inclusion of Reactive Power devices because Reactive
Power devices produce power, they are “power producing resources” and we
therefore believe Inclusion 5 is duplicative of Inclusion 4, which addresses “power
producing devices.”
Also, there is no capacity threshold specified in Inclusion 5 for Reactive Power
devices that would be considered part of the BES. This is inconsistent with the
approach taken in the balance of the definition, where thresholds are specified for
generators and other types of power producing devices. Reactive Power devices
should be subject to the same technical analysis for inclusion or exclusion that
will cover generators in the Phase II process.
GCPD strongly supports the revised Local Networks (“LNs”) exclusion from the
BES. GCPD also supports specific refinements made to the LN exclusion by the
SDT in the current draft of the BES definition. In particular, GCPD supports the
clarification of the purposes of a LN. The current draft states that LNs connect at
multiple points to “improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system.” GCPD
supports this change in language because it reflects the fundamental purposes of
a LN and emphasizes one of the key distinctions between LNs and bulk
transmission facilities. Similarly, we suggest that the SDT re-examine the
assumptions underlying subparagraph (b), which seems to suggest that a local
distribution system cannot be classified as a Local Network if power flows out of
that system at any time, even if the amount is very small, the outward flow is
only for a few hours a year, or the outward flow occurs only in an extreme
contingency. Accordingly, we suggest that the initial clause of subparagraph (b)

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be revised to read: “Except in unusual circumstances, power flows only into the
LN.”

Response: The exception process is being worked on in parallel with the definition.
Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up.
Thank you for your support.
The development of demarcation points will be included in Phase 2 of this project. Work done at WECC and other regions will be
utilized as appropriate.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
Several commenters suggested that the requirement under Exclusion E3.b should apply only during normal operating conditions, in
other words, commenters felt that some power flow should be allowed to flow from the candidate local network back into the BES
as long as it only occurred under abnormal conditions. To this suggestion, the SDT considered the addition of the phrase “under
normal operating conditions”, as a qualifier to Exclusion E3.b, and determined that in order to maintain the intent of a bright-line
characteristic in the BES definition such a qualifier could not be accommodated. However, the SDT pointed out that for those
circumstances where a candidate for local network is unable to utilize the local network exclusion due to an abnormal situation
that caused power to flow out of the network, the network could be a suitable candidate that could apply for exclusion under the
Exception Process.

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John H Hagen

Pacific Gas and
Electric
Company

Segment
3

Vote
Affirmative

Comment
We support the overall approach with the following concerns: 1) Clarify what is
included as a Blackstart Resource and do not rely on what is defined in local or
regional restoration plans, as this will create regional variances;
2) Inclusion of generating units >20mva seems to low and

Response: 1. Blackstart Resource is a defined term that can be found in the NERC Glossary.
2. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values.
Brad Chase

Orlando
Utilities
Commission

1

Affirmative

Ballard K
Mutters

Orlando
Utilities
Commission

3

Affirmative

Orlando Utilities Commission supports the new definition, although our support is
conditioned on: (1) a workable Exceptions process being developed in
conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date. in addition, phase II
should include a clear distinction between the BES and BPS.
Orlando Utilities Commission supports the new definition, although our support is
conditioned on: (1) a workable Exceptions process being developed in
conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date.

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Response: The exception process is being worked on in parallel with the definition.
Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up.
CJ Ingersoll

Constellation
Energy

3

Affirmative

While we support the proposed definition to satisfy the FERC Order, we also
support continued work on the threshold questions slated for "Phase II", in
particular the refinement of the generation thresholds.

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up.
Howard M.
Mott Jr.

Clay Electric
Cooperative

3

Affirmative

The Note under Exclusions: E1 - Radial Systems: should not include "...as
depicted on prints or one-line diagrams..." and should be changed. "Note - A
normally open switching device between radial systems, as depicted on prints or
one-line diagrams for example, does not affect this exclusion." I recommend the
note be changed to read: Note - A normally open switching device between radial
systems operated in a 'make-before-break' fashion does not affect this exclusion.

Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will
not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in
the normal operating environment.
Brian Fawcett

Clatskanie
People's Utility
District

3

Affirmative

1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. Yes:
Yes No: Comments: We agree with the changes. We must point out that the
overall flow, or how one proceeds through the inclusions and exclusions is not
clear. Can an item that meets an inclusion be subsequently excluded? If so, this
needs to be explicitly stated. So far, we only have the flow chart produced by the
ROP team that indicates otherwise
(http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf). This
was made evident by the question at the 9/28 webinar regarding an I5 capacitor
on an E3 local network. The questioner thought the capacitor was BES per I5, but
the answer was that it was excluded per E3. We can find no support for the

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answer given. The listing of specific exclusions within I1 (exception proves the
rule) argues for questioner’s stance that the capacitor is BES as written. Also, if
included items could subsequently be excluded, they would be no different from
any other item that met the voltage threshold of 100kV. There would be no need
for any of the inclusions if all possible outputs from the inclusion tests go to the
same exclusion test inputs.
We strongly support the addition of the language regarding local distribution
facilities, as it matches congressional intent to leave the regulation of these
facilities to state and local authorities.
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments: Clatskanie PUD strongly agrees with this
inclusion as written. It is consistent with the recent PRC-004 and PRC-005
interpretation and the NERC definition of Transmission. We believe the recent
changes to this inclusion add clarity.
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Referencing the Criteria which in turn
references the BES definition creates a circular definition. Clatskanie PUD
encourages the adoption of specific thresholds that are technically justified. We
also note that the Criteria and its revisions do not go through the standards
development process, so that thresholds may change with little warning and
without triggering an implementation plan for facilities that may be swept into the
BES as a result.
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language

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would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments: We agree with the removal of the voltage
language, since the inclusions and exclusions apply only to equipment over 100
kV.
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments: Clatskanie PUD agrees both with the inclusion
and with the revised language. The revised language removes the need to
provide a separate definition for “Collector System”.
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: While we agree that reactive devices of sizable
capacity connected at 100 kV or higher are needed for BES reliability, Clatskanie
PUD fails to see why this inclusion is needed as they are already captured by the
100 kV threshold. We would propose instead to eliminate this inclusion and
substitute an exclusion for smaller capacity devices. If the SDT really believes an
inclusion for reactive devices is needed, we suggest the SDT provide a technically
justified capacity limit within the inclusion. In addition we suggest also including
the phrase “...unless excluded under Exclusion E1, E2 or E4” similar to that in I1.
Please see the answer to Q1 above Q10 below.
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Clatskanie PUD notes that a new term has
been introduced, “non-retail generation,” with no definition provided. The answer
to the question on this during the 9/28 webinar indicated that non-retail
generation was behind the retail customer’s meter. We can see no reason why

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the net-metered PV systems should count toward the aggregate limit (exceeding
the limit means no exclusion) while a non-blackstart thermal plant doesn’t (the
radial system is excluded if any amount of load is present). We have also heard
the SDT meant just the opposite of what was stated in the webinar. We ask that
a reasonable definition for non-retail be provided within the BES definition
document. We strongly agree that radial systems should be excluded and that the
presence of normally open switching devices between radial systems should not
cause them to be considered non-radial. Such a result would cause the removal
of these devices to the detriment of the local level of service. We note that the
singular “A normally open switching device” is used and suggest that an
allowance be made for the possibility of multiple devices. “Normally open
switching devices...”
8. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: X No: Comments:
9. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E3 (local network)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: We strongly agree that local networks should
be excluded, since they act much like the radial systems excluded in E1 while
providing a higher level of service to customers. These networks should not be
discouraged in the name of reliability. We again object to the introduction of the
new confusing term “non-retail generation” with no definition provided.

Response: 1. The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES
and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100
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kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is
needed. Element as defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 –
I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks)
should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind-the-retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
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interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
2. Thank you for your support.
3. The SDT has reverted to specific numeric thresholds consistent with the ERO Statement of Compliance Registry Criteria for Phase
I.
4. Thank you for your support.
5. Thank you for your support.
6. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
7. “Non-retail generation” means that generation which is on the system (supply) side of the retail meter. Radial systems should be
assessed with all normally open (NO) switches in the open position and these NO switches will not prevent the owner or operator
from using this exclusion. The note provides an example that can be used to indicate the switch is operated in the normally open
position; however, it is the owner and operator’s responsibility to indicate how a switch is used in the normal operating
environment.
8. Thank you for your support.
9. Thank you for your support. “Non-retail generation” means that generation which is on the system (supply) side of the retail
meter.
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Voter
Gregg R Griffin

Entity
City of Green
Cove Springs

Segment
3

Vote

Comment

Affirmative

GCS appreciates the SDT’s work on this project. For the most part, GCS supports
what it believes to be the intent of the proposed language. The proposed specific
exclusion of facilities used in the local distribution of electric energy is appropriate
and consistent with Section 215 of the Federal Power Act. However, we have
suggestions to better carry out what we believe to be the SDT’s intent.
The first sentence can be read as: “... all ... Real Power and Reactive Power
resources connected at 100 kV or higher”, which is surely not what the SDT
intends. The basic problem is that Inclusions I2 and I4 do not modify the first
sentence, e.g., from a set theory perspective, the set described by the first
sentence includes the sets described in inclusions I2 and I4; hence, I2 and I4 do
not modify the first sentence. From a literal reading, this would cause any size
generator connected at 100 kV to be included, which is surely not the intent of
the SDT. For similar reasons, the core definition and Inclusion I5 now has the
effect of including all generators connected at 100 kV since a generator is a
“dynamic device ... supplying or absorbing Reactive Power”. The word
“dedicated” in I5 is not sufficient in GCS’s mind to unambiguously exclude
generators from this statement. GCS suggests the following wording to address
these issues: "Transmission Elements (not including elements used in the local
distribution of electric energy) and Real Power and Reactive Power resources as
described in the list below, unless excluded by Exclusion or Exception: a.
Transmission Elements other than transformers and reactive resources operated
at 100 kV or higher. b. Transformers with primary and secondary terminals
operated at 100 kV or higher. c. Generating resource(s) (with gross individual or
gross aggregate nameplate rating per the ERO Statement of Compliance Registry
Criteria) including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above. d. Blackstart
Resources identified in the Transmission Operator’s restoration plan. e. Dispersed
power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a system designed primarily for aggregating
capacity, connected at a common point at a voltage of 100 kV or above, but not
including generation on the retail side of the retail meter. f. Non-generator static
or dynamic devices dedicated to supplying or absorbing more than 6 MVAr of

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Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a
transformer that is designated in bullet 2 above."
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: Yes No: Comments: Please see comments to Question 1
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: yes No: Comments: Please see comments to Question 1
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: Yes No: Comments: Please see comments to Question 1.
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: Yes No: Comments: We recommend clarifying that the dispersed
power resources covered by this inclusion do not include generators on the retail
side of the retail meter. Specifically, we recommend that the Inclusion read:
“Dispersed power producing resources with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing a system designed primarily for
aggregating capacity, connected at a common point at a voltage of 100kV or
above, but not including generation on the retail side of the retail meter.”
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you

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do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: Comments: To help clarify and to avoid inclusion of de
minimis reactive resources, we propose a size threshold of 6 MVAr consistent with
the smallest size generator included in the BES at a 0.95 power factor, which is a
common leading power factor used in Facility Connection Requirements for
generators. In other words, 6 MVAr is consistent with typically the least amount
of MVAr required to be absorbed by the smallest generator meeting the registry
criteria.
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: Yes No: Comments: GCS supports the exclusion of radial systems
from the BES Definition. Such systems are generally not “necessary for operating
an interconnected electric transmission network,” the standard in Orders 743 and
743-A. We have several suggestions to clarify the proposed language for this
Exclusion. Proposed Exclusion E1 refers to “[a] group of contiguous transmission
Elements that emanates from a single point of connection of 100 kV or higher.”
We appreciate the SDT’s clarification of the point of connection requirement, but
the term “a single point of connection” should be further defined (more clearly
than just by voltage), and should be generic enough to encompass the various
bus configurations. It is not the case, for example, that each individual breaker
position in a ring bus is a separate point of connection for this purpose; in that
situation, a bus at one voltage level at one substation should be considered “a
single point of connection.” Some examples of configurations that should be
considered a single point of connection for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf,
Examples 1-6.
Although the core definition (appropriately) refers to “Transmission Elements”
(with a capital “T”), proposed Exclusion E1 refers to “transmission Elements”
(with a lowercase “t”). To avoid confusion, either “Transmission” should be

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capitalized in both locations, or the word “transmission” should simply be deleted
from Exclusion E1, leaving a “group of contiguous Elements.” We understand that
the lack of capitalization may have been a deliberate choice by the SDT in an
attempt to avoid confusion that SDT members believe exists in the Glossary
definition.

Response: 1. – 4. The SDT refers the commenter to the first phrase of the core definition starting with “Unless modified…” which
the SDT believes handles the concern brought out here. The SDT considered your wording changes in its deliberations and refers
the commenter to the revised redline of the definition posted in response to the consideration of comments.
5. The SDT further clarifies that generating units on the customer’s side of the retail meter are not included under Inclusion I4 since
customer-side retail generation typically does not “utilize[e] a system designed primarily for aggregating capacity, connected at a
common point at a voltage of 100 kV or above.”
6. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
7. The “single point of connection of 100 kV or higher” is where the radial system will begin if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the radial
system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the transmission
line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker and a half
bus configuration could also be the beginning of the radial system and the owner of the bus would need to insure the reliability of
the substation. The SDT considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that retention
of this word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
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Affirmative

Due to the movement to a phased BES definition development process and
assuming the definition is approved as proposed, there is an urgent need for
NERC to provide clear guidance to Registered Entities regarding how to proceed
with facilities and address changes to the NERC Compliance Registry registration
obligations brought in/on by the application of the new definition. The problem
stems from a likely scenario whereby the affected Registered Entities may be
faced with an Implementation Plan and an Exception Request Procedure which
must be completed prior to the completion of the Phase II definition development
process. If that is the case, many Registered Entities will be confronted with
either (1) spending large amounts of human and financial resources, not yet
acquired, to address facilities/procedures necessary to address possible new
compliance obligations only to find their efforts rendered unnecessary by the
results produced in Phase II or, (2) waiting until the results of Phase II are
provided and risking being found non-compliant and subject to substantial
penalties in the future. Neither option can be viewed as a desirable, or for that
matter, an acceptable position to be placed in.

included in the term “Element”.
Thomas C
Duffy

Central Hudson
Gas & Electric
Corp.

3

Response: Part of the implementation plan for this project is for NERC to work with regional entities on transition plans. Those
regional entities would then work with registered entities to try to avoid the situation described by the commenter.
Richard K Vine

California ISO

2

Affirmative

We support the SDT’s decision to exclude the cranking paths from the BES
definition since testing and verification of the use of facilities in the cranking path
is already covered by the appropriate EOP standards. However, we suggest
removing the entirety of Inclusion I3. This inclusion is extraneous given there is
already a designation specific for system restoration covered by an existing
standard to recognize their reliability impacts and to ensure their expected
performance. NERC Standards EOP-005-2 stipulates the requirements for testing
blackstart resource and cranking paths. This testing requirement suffices to
ensure that the facilities critical to system restoration are functional when
needed, which meets the intent of identifying their criticality to reliability.

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Response: The SDT disagrees that Blackstart Resources should not be included in the BES Definition. The Commission directed
NERC to revise its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected
electric transmission network. The SDT interprets this to include operation under both normal and emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without
support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated
resources of the electric system that can be isolated and then energized to deliver electric power during a restoration event are
essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s restoration plan.
For these reasons, the SDT continues to include Blackstart Resources indentified in the Transmission Operator’s restoration plan as
BES elements. No change made.
James Jones

Southwest
Transmission
Cooperative,
Inc.

1

Affirmative

In general, we support the proposed definition of the BES. However, we have
identified a few concerns that warrant the SDT’s consideration. We’d prefer to see
the language from the ERO Statement of Compliance Registry Criteria repeated
within the BES Definition itself instead of referencing an outside document. As it
stands right now, the Compliance Registry Criteria needs to stay intact for Phase I
of this project. That makes the Compliance Registry Criteria reliant on the BES
Definition and vice versa. We understand that the Statement of Compliance
Registry Criteria may be reviewed/revised at the same time Phase 2 of this
project is being developed, therefore we agree with Inclusion I2 of this draft.
Blackstart Resources can actually be on the distribution system. There is still the
question of whether the distribution system would then be subjected to the
enforceable standards. If so, there would most likely be a significant cost increase
associated with tracking compliance for these distribution systems without a
commensurate increase in reliability since Blackstart Resources are rarely used.
This could very well cause entities to un-designate Blackstart Resources on
distribution systems to avoid these distribution systems from becoming part of
the BES. The same rationale that was used for eliminating cranking paths could
also be applied to Blackstart Resources.
A flowgate should not be used to limit applicability of E3. First, there is no

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definition for what constitutes a permanent flowgate. Second, flowgates are often
created for a myriad of reasons that have nothing to do with them being
necessary to operate the BES. While section c) in E3 attempts to limit the
applicability to permanent flowgates, there is no definition for what constitutes a
permanent flowgate particularly since no flowgate is truly permanent. The NERC
Glossary of Terms definition of flowgate includes flowgates in the IDC. This is a
problem because flowgates are included in the IDC for many reasons not just
because reliability issues are identified. Flowgates could be included to simply
study the impact of schedules on a particular interface as an example. It does not
mean the interface is critical. As an example, it could be used to generate
evidence that there are no transactional impacts to support exclusion from the
BES. Furthermore, the list of flowgates in the IDC is dynamic. The master list of
IDC flowgates is updated monthly and IDC users can add temporary flowgates at
anytime. While the “permanent” adjective applied to flowgates probably limits the
applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month
and removed another. Flowgates are created for many reasons that have nothing
to do with them being necessary to operate the BES. First, flowgates are created
to manage congestion. The IDC is more of a congestion management tool than a
reliability tool. FERC recognized this in Order 693, when they directed NERC to
make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs
that have been violated. Rather, other actions such as re-dispatch must be used
in conjunction. Second, flowgates are used as a convenient point to calculate
flows to sell transmission service. The characteristics of the flowgate make it a
good proxy for estimating how much contractual use has been sold not
necessarily how much flow will actually occur. While some flowgates definitely are
created for reliability issues such as IROLs, many simply are not.
The term “non-retail generation” used in Exclusion E1 (item c) and again in E3
(item a) should be clarified (see comments for question 8 below).
The Note after item c should also be clarified to indicate that closing a normally
open switch doesn’t affect this exclusion.

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Noman Lee
Williams

Entity
Sunflower
Electric Power
Corporation

Segment
1

Vote

Comment

Affirmative

In general, we support the proposed definition of the BES. However, we have
identified a few concerns that warrant the SDT’s consideration.
We’d prefer to see the language from the ERO Statement of Compliance Registry
Criteria repeated within the BES Definition itself instead of referencing an outside
document. As it stands right now, the Compliance Registry Criteria needs to stay
intact for Phase I of this project. That makes the Compliance Registry Criteria
reliant on the BES Definition and vice versa. We understand that the Statement of
Compliance Registry Criteria may be reviewed/revised at the same time Phase 2
of this project is being developed, therefore we agree with Inclusion I2 of this
draft.
Blackstart Resources can actually be on the distribution system. There is still the
question of whether the distribution system would then be subjected to the
enforceable standards. If so, there would most likely be a significant cost increase
associated with tracking compliance for these distribution systems without a
commensurate increase in reliability since Blackstart Resources are rarely used.
This could very well cause entities to un-designate Blackstart Resources on
distribution systems to avoid these distribution systems from becoming part of
the BES. The same rationale that was used for eliminating cranking paths could
also be applied to Blackstart Resources.
A flowgate should not be used to limit applicability of E3. First, there is no
definition for what constitutes a permanent flowgate. Second, flowgates are often
created for a myriad of reasons that have nothing to do with them being
necessary to operate the BES. While section c) in E3 attempts to limit the
applicability to permanent flowgates, there is no definition for what constitutes a
permanent flowgate particularly since no flowgate is truly permanent. The NERC
Glossary of Terms definition of flowgate includes flowgates in the IDC. This is a
problem because flowgates are included in the IDC for many reasons not just
because reliability issues are identified. Flowgates could be included to simply
study the impact of schedules on a particular interface as an example. It does not
mean the interface is critical. As an example, it could be used to generate
evidence that there are no transactional impacts to support exclusion from the
BES. Furthermore, the list of flowgates in the IDC is dynamic. The master list of

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IDC flowgates is updated monthly and IDC users can add temporary flowgates at
anytime. While the “permanent” adjective applied to flowgates probably limits the
applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month
and removed another. Flowgates are created for many reasons that have nothing
to do with them being necessary to operate the BES. First, flowgates are created
to manage congestion. The IDC is more of a congestion management tool than a
reliability tool. FERC recognized this in Order 693, when they directed NERC to
make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs
that have been violated. Rather, other actions such as re-dispatch must be used
in conjunction. Second, flowgates are used as a convenient point to calculate
flows to sell transmission service. The characteristics of the flowgate make it a
good proxy for estimating how much contractual use has been sold not
necessarily how much flow will actually occur. While some flowgates definitely are
created for reliability issues such as IROLs, many simply are not.
The term “non-retail generation” used in Exclusion E1 (item c) and again in E3
(item a) should be clarified (see comments for question 8 below).
The Note after item c should also be clarified to indicate that closing a normally
open switch doesn’t affect this exclusion.

Response: The SDT has reverted to specific numeric thresholds consistent with the ERO Statement of Compliance Registry Criteria
for Phase I.
The SDT disagrees that Blackstart Resources should not be included in the BES Definition. The Commission directed NERC to revise
its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric
transmission network. The SDT interprets this to include operation under both normal and emergency conditions, which includes
situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from
the System or can be energized without connection to the remainder of the System, in order to meet a Transmission Operator’s
restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of
the electric system that can be isolated and then energized to deliver electric power during a restoration event are essential to
enable the startup of one or more other generating units as defined in the Transmission Operator’s restoration plan. For these
reasons, the SDT continues to include Blackstart Resources indentified in the Transmission Operator’s restoration plan as BES
Project 2010-17 BES Definition Ballot Comments
1
23

Voter
Entity
Segment
Vote
Comment
elements. No change made.
The SDT believes that the language in Exclusion E3.c prohibiting “Flowgates” from qualifying for definitional exclusion is appropriate
and necessary. As a definitional exclusion characteristic, Exclusion E3.c must follow the principle of being a bright-line and easily
identifiable, and as such, the SDT feels that the definition cannot allow some types of Flowgates and disallow others. Flowgates
must continue to be a prohibiting characteristic under Exclusion E3, since these facilities are more likely to be used in the transfer
of bulk power than not. An entity who wishes to make a case for exclusion of a unique type of Flowgate facility can do so through
the exception process. The SDT believes that the continued qualifier of “permanent” associated with the term “Flowgate”
addresses the majority of the concern in this comment. No change made.
“Non-retail generation” means that generation which is on the system (supply) side of the retail meter.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is
operated in the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in
the normal operating environment.
Jerome Murray

Oregon Public
Utility
Commission

9

Affirmative

With the condition that reference is not made to the NERC Statement of
Compliance Registry Criteria (SCRC) within the BES definition. This circularity
must be eliminated. Recommended language should be: “I2 - Generating
resource(s) with a gross individual nameplate rating greater than 20 MVA or with
a gross aggregate nameplate rating greater than 75 MVA including the generator
terminals through the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above.”

Response: The SDT has reverted to specific numeric thresholds consistent with the ERO Statement of Compliance Registry Criteria
for Phase I.
Gregory S
Miller

Baltimore Gas
& Electric
Company

1

Affirmative

While BGE supports the proposed definition to satisfy the FERC Order, we also
support continued work on the threshold questions slated for "Phase II".

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up.

Project 2010-17 BES Definition Ballot Comments
1
24

Voter

Vote

Comment

Gainesville
Regional
Utilities
Alberta Electric
System
Operator

1

Affirmative

2

Affirmative

Benjamin
Friederichs

Big Bend
Electric
Cooperative,
Inc.

3

Affirmative

James L
Layton

Blue Ridge
Electric

3

Affirmative

GVL feels that the effort to improve this standard is heading in the right direction.
We look forward to the phase 2 segment of the process where additional clairity
can be offered. Thanks for all your hard work.
The AESO agrees with the NERC BES definition. It should be noted however that
when the AESO adopts a NERC definition in Alberta the AESO must consider the
applicability of the NERC definition in Alberta which may result in revisions to
such definition to align it with our current electric energy market framework.
I believe this definition would include those elements necessary to the reliable
operation of the BES while excluding those elements that would not have a
material impact. NERC's willingness to exclude radial 115kv transmission lines is
especially beneficial to smaller utilities like us. Their inclusion would not improve
the reliability of the BES, but would vastly increase our costs and
regulatory/reporting burdens.
The SDT has done a good job of clearly defining the BES and developing a clear
inclusion and exculsion list.

Joe Noland

City of Cheney

3

Affirmative

The City of Cheney agrees with changes made to the BES definition

Jason Fortik

Lincoln Electric
System

3

Affirmative

No comments.

Anthony
Schacher

Salem Electric

3

Affirmative

Bob C.
Thomas

Illinois
Municipal
Electric Agency

4

Affirmative

Salem Electric is encouraged to see that the standard drafting team understands
the reality that in many circumstances many small radially fed utilities have no
effect on the bulk electric system. By permitting reasonable and prudent
exceptions it will allow many of the small utilities to be able to spend our limited
time and resources on the reliability of our systems for our end users, instead of
undertaking unnecessary steps to protect a system upon which we have no
effect. The exception process is thorough but still manageable for small utilities
with limited resources. Salem Electric would like to thank the Standards Drafting
Team for their hard work and dedication in defining the Bulk Electric System.
Illinois Municipal Electric Agency (IMEA) appreciates the SDT’s diligence in
developing bright-line BES Definition language; particularly, language clarifying
the exclusion of local distribution facilities, achieving more realistic/reasonable

Luther E. Fair
Mark B
Thompson

Entity

Segment

Project 2010-17 BES Definition Ballot Comments
1
25

Voter

Frank R.
McElvain

Entity

Siemens
Energy, Inc.

Segment

7

Vote

Affirmative

Comment
identification of radial systems, and recognizing the distinction of local networks.
With its Affirmative vote, IMEA supports and recommends comments submitted
by the Transmission Access Policy Study Group.
I am not completely satisfied with the arbitrary nature of the 100 kV demarcation.
I know of 60 kV systems that parallel 500 kV circuits. However, this draft
captures my concept of the Bulk Electric System pretty well.

Response: Thank you for your support.

Project 2010-17 BES Definition Ballot Comments
1
26

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF A REVISED DEFINITION OF “BULK ELECTRIC SYSTEM”
IN THE NERC GLOSSARY OF TERMS USED IN RELIABILITY STANDARDS

EXHIBIT E

COMPLETE DEVELOPMENT RECORD OF THE
PROPOSED REVISED DEFINITION OF “BULK ELECTRIC SYSTEM”

Project 2010-17
Proposed Definition of Bulk Electric System and Related Rules of Procedure Team
Related Files
BES Definition Project Fact Sheet
Rules of Procedure Development Team: BES Definition Exception Process page, click here.
Status:
The definition of Bulk Electric System, along with the application form to support requests
for BES exceptions, were approved by the ballot pool. The NERC Board of Trustees will
meet on January 18, 2012 to act on the definition and associated Rules of Procedure
changes.
Purpose/Industry Need:
On November 18, 2010 FERC issued Order 743 and directed NERC to revise the definition of
Bulk Electric System so that the definition encompasses all Elements and Facilities
necessary for the reliable operation and planning of the interconnected bulk power system.
Phase I of Project 2010-17 Definition of Bulk Electric System concluded on November 21,
2011 with stakeholder approval of a revised definition of Bulk Electric System and
application form titled ‘Detailed Information to Support an Exception Request’ referenced
in the Rules of Procedure Exception Process. The revised definition, modifications to the
Rules of Procedure to provide a process for determining exceptions to the definition, and
an application form to support that process, will all be presented to the NERC Board of
Trustees for adoption and then filed with regulatory authorities for approval.
Phase II of the project is being initiated to develop appropriate technical justification to
support refinements to the definition that were suggested by stakeholders during Phase I,
and to refine the definition as technically justified.
Related Rule of Procedure
Related to the development of the definition, there is a Rules of Procedure modification
underway. Click related files to see this activity.

Draft

Action

Dates

Results

Phase 2
Draft 1 SAR(65)
Supporting
Materials:
Definition of
Bulk Electric
System (last
approved)(66)

Comment
Period
Info(68)

01/04/12 - 02/03/12

Submit
Comments>
>

Unofficial
Comment Form
(Word)(67)

Draft 3
Definition of
Bulk Electric
System
Clean(55) |
Redline to Last
Posting(56)
Implementatio
n Plan for
Definition
Clean (57)|
Redline to Last
Posting(58)
Detailed
Information to
Support BES
Exceptions
Request

Summary
(62)

Recirculation
Ballots
Info(61)
Vote>>

11/10/11 - 11/21/11
(closed)

BES
Definition
Full
Record
(63)
BES
Exceptions
Full
Record
(64)

Consideration of
Comments

Clean (59)|
Redline to Last
Posting(60)
Draft 2
Definition of
Bulk Electric
System
Clean(37) |
Redline to Last
Posting(38)

Initial Ballot
of Definition
of BES
Updated
Info(46)
Info(47)

Summary
(50)
09/30/11 - 10/10/11
(closed)

Full
Record
(51)

Consideration of
Comments(53)

Vote>>
Implementatio
n Plan for
Definition
Clean (39)|
Redline to Last
Posting(40)

Join Ballot
Pool>>

08/26/11 -09/26/11
(closed)

Supporting
Materials
Comment Form
(Word)(41)
Draft
Supplemental
SAR(42)
090111 Letter
to A. Mosher
from Chairman
Anderson(43)
082411 Letter
to Chairman
Anderson from
from A.
Mosher(44)
Technical
Justification for
Local Network

Comment
Period
Updated
Info(48)
Info(49)
Submit
Comments>
>

08/26/11 - 10/10/11
(closed)

BES
Definition
Comments
Received
(52)

Consideration of
Comments(54)

Exclusion(45)

Draft 2
Detailed
Information to
Support BES
Exceptions
Request(28)
Supporting
Materials
Comment Form
(Word)(29)

Initial Ballot
of Detailed
Information
to Support
BES
Exceptions
Request

Summary
(32)
09/30/11 - 10/10/11

Info(30)
Vote>>
Join Ballot
Pool>>

08/26/11 -09/26/11

Comment
Period
Info(31)

08/26/11 - 10/10/11

BES
Exceptions
Comments
Received
(34)

Consideration of
Comments(36)

5/11/11 -6/10/11
(closed)

Comments
Received
(26)

Technical Principles
Consideration of
Comments(27)

Submit
Comments>
>

Draft 1
Technical
Principles for
Demonstrating
BES Exceptions
(23)
Comment Form
(Word)(24)

Full
Record
(33)

Consideration of
Comments(35)

Comment
Period
Submit
Comments>
>
Info(25)
Bulk Electric

Definition of Bulk

SAR Version 2
Clean(13) |
Redline to last
posting(14)

System
Definition
Revision
Status

Definition of
Bulk Electric
System
Clean(15) |
Redline to last
posting(16)

Info(19)

Implementatio
n Plan for
Definition
Clean(17)
Comment Form
(Word)(18)

Electric
System Consideratio
n of Comments(22)

Comment
Period
Info(20)
Submit
Comments>
>

4/28/11 -5/27/11
(closed)

Draft SAR
Version 1
Definition of
Bulk Electric
System(1)
Clean (2)|
Redline to last
approval(3)

Comments
Received
(21)

BES
Definition
Exception
Process
Comment
s Received

Comment
Period
12/17/10 – 1/21/11

Supporting
Materials:

Info(7)

Concept
Paper(4)

Submit
Comments>
>

Unofficial BES
SAR &
Definition
Comment Form
(Word)(5)

Comments
Received
(8)
Broken
down into
files 8A8N)

BES SAR & Definition
Consideration of
Comments(9)

BES Definition
Exception Process
Consideration of
Comments
Q1(10)
Q2(11)
Q3(12)

Official BES
Definition
Exception
Process
Comment Form
(Word)(6)

August 8, 2011
Bulk Electric System Drafting Team
c/o Peter Heidrich, Chairman
pheidrich@frcc.com
Dear Peter and members of the Bulk Electric System Drafting Team:
I first want to acknowledge the dedication and extraordinary effort that the members of
the drafting team have devoted and will continue to devote to the important issues
surrounding the assignment to develop a revised definition of “bulk electric system”.
One of the greatest strengths of the ERO model is its ability to bring together for the
common good subject matter experts from across North America, and your work is
strong evidence of that.
I am taking the unusual step of writing to you to raise a legal issue that I recently
learned of. At the recent NERC Member Representatives Committee meeting in
Vancouver, Peter Heidrich described a number of changes that the drafting team is
considering for inclusion in its next draft of the proposed BES definition. One of those
changes was to include in the definition the following sentence:
The bulk electric system shall not include facilities used in local distribution as
determined by the applicable regulatory authority.
I fully agree with commenters and the drafting team that it would be useful and
appropriate to include a statement in the BES definition that the BES does not include
facilities used in local distribution. Such a statement would track a similar statement in
section 215 of the Federal Power Act:
The term [bulk power system] does not include facilities used in the local
distribution of electric energy. (Federal Power Act, Section 215(a)(1)).
However, the proposed statement goes beyond what is in section 215 and includes the
phrase “as determined by the applicable regulatory authority.” The term “applicable
regulatory authority” is not defined, but it is very broad. It could include state
commissions, provincial governments, local city councils, and perhaps boards of
directors of co-operatives. It could lead to a patchwork of different results.
What that means is every regulatory authority could be making a determination as to the
scope of NERC’s authority and the scope of FERC’s authority under section 215. That
situation is unworkable for NERC, and I believe it will be unacceptable to FERC.
1120 G Street, NW, Suite 990
Washington, DC 20005
202-393-3998 | www.nerc.com

BES Standard Drafting Team
August 8, 2011
Page 2
The issue of where to draw the line between local distribution and transmission has
been addressed in many places over the years, for many purposes, under several
different criteria. When the issue arises in the reliability context, it can be addressed by
reference to those criteria. But It would be a mistake (and unnecessary) for NERC to put
its thumb on the scale of where the line falls between state and federal jurisdiction by
saying responsibility for making that decision is in the hands of whatever regulatory
chooses to make the decision.
To repeat, I fully support the inclusion of a statement that the “bulk electric system” does
not include facilities used in local distribution. My request is that you not include the
additional phrase, “as determined by the applicable regulatory authority.”
I would be happy to discuss this matter with the team or team leadership.
Thank you for your attention.
Sincerely,

David N. Cook
Senior Vice President & General Counsel
NERC
1120 G St. NW, Suite 990
Washington, DC 20005
(o) 202-393-3998
(c) 609-915-3063
david.cook@nerc.net

Standard Authorization Request Form
Title of Proposed Standard: NERC Glossary of Terms: Revision of the Bulk Electric System
definition.
Request Date:

December 6, 2010

SC Approval Date:

December 8, 2010

SAR Type (Check a box for each one
that applies.)

SAR Requester Information
Name: Regional Bulk Electric System Definition
Coordination Group

New Standard

Primary Contact: Peter Heidrich (Manager of
Reliability Standards, FRCC)

Revision to existing Definition

Regional Participation: Michelle Mizumori, WECC;
Phil Fedora, NPCC; Jeff Mitchell, RFC
Telephone: (813) 207-7994

Withdrawal of existing Standard

Fax: (813) 289-5646
E-mail: pheidrich@frcc.com

Urgent Action

Purpose (Describe what the standard action will achieve in support of bulk power system
reliability.)

Revise the definition of Bulk Electric System (BES) to address the Federal Energy Regulatory
Commission’s (FERC) concerns as identified in FERC Order 693 issued on March 16, 2007 and directives
in Order 743 issued on November 18, 2010 (Order 743) so that the definition encompasses all Elements
and Facilities necessary for the reliable operation and planning of the interconnected bulk power
system.
Industry Need (Provide a justification for the development or revision of the standard,
including an assessment of the reliability and market interface impacts of implementing or
not implementing the standard action.)

This project supports the EROs obligation to respond to the Commission’s directives and
recommendations relative to the definition of Bulk Electric System identified in Order No. 743.
Brief Description (Provide a paragraph that describes the scope of this standard action.)

Revise the definition of Bulk Electric System (BES) contained in the NERC Glossary of Terms to improve
clarity, to reduce ambiguity and to establish consistency across all Regions in distinguishing between BES
and non-BES Elements and Facilities.
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

Standards Authorization Request Form

Detailed Description (Provide a description of the proposed project with sufficient details
for the standard drafting team to execute the SAR.)

Revise the definition of Bulk Electric System (BES) to address the Federal Energy Regulatory
Commission’s (FERC) concerns as identified in FERC Order 693 issued on March 16, 2007 and directives
in Order 743 issued on November 18, 2010 (Order 743) so that the definition encompasses all Elements
and Facilities necessary for the reliable operation and planning of the interconnected bulk power
system.
Existing NERC Glossary of Terms Definition of Bulk Electric System:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated
equipment, generally operated at voltages of 100 kV or higher. Radial transmission
facilities serving only load with one transmission source are generally not included in this
definition.
The authors are proposing a revised definition of the term BES to provide for improved clarity, to reduce
ambiguity and to establish a universal “bright-line” for distinguishing between BES and non-BES
Elements and Facilities.
This proposed definition provides consistency across the continent’s reliability regions by establishing a
definition that clearly describes what constitutes BES and non-BES Elements and Facilities. The BES
definition references an exemption process (which may include regional differences as defined by Order
672 or jurisdictional exemptions as appropriate for those entities not subject to Section 215 of the
Federal Power Act) that can be used to:
•
•
•

Identify the Radial Transmission systems that are excluded from the BES;
Identify Elements and Facilities operated at voltages of 100kV or higher that may be excluded
from the BES; and
Identify Elements and Facilities operated at voltages less than 100kV that may be included in
the BES.
Proposed continent-wide definition of Bulk Electric System:
Bulk Electric System: All Transmission and Generation Elements and Facilities operated
at voltages of 100 kV or higher necessary to support bulk power system reliability.
Elements and Facilities operated at voltages of 100kV or higher, including Radial
Transmission systems, may be excluded and Elements and Facilities operated at voltages
less than 100kV may be included if approved through the BES definition exemption
process.

The development, approval and application of the BES definition exemption process (including periodic
review of exempted facilities) will be governed by revisions to the NERC Rules of Procedure, in close
coordination with the revision of the BES definition.
However, as envisioned, the standard drafting team will work closely with the team developing the BES
definition exemption process to develop a single coordinated implementation plan. It is also envisioned,
that the team working to develop the BES definition exemption process will solicit input from drafting
SAR–2

Standards Authorization Request Form

teams, stakeholders, and Regional Reliability Organizations in identifying physical and operational
characteristics for consideration in developing the BES definition exemption process.

SAR–3

Standards Authorization Request Form

Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Assurer

Monitors and evaluates the activities related to planning and
operations, and coordinates activities of Responsible Entities to
secure the reliability of the bulk power system within a Reliability
Assurer Area and adjacent areas.

Reliability
Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing
Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.

Interchange
Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.

Planning
Coordinator

Assesses the longer-term reliability of its Planning Coordinator
Area.

Resource
Planner

Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.

Transmission
Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.

Transmission
Planner

Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.

Transmission
Service
Provider

Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).

Distribution
Provider

Delivers electrical energy to the End-use customer.

Generator
Owner

Owns and maintains generation facilities.

Generator
Operator

Operates generation unit(s) to provide real and reactive power.

PurchasingSelling Entity

Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.

LoadServing
Entity

Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.

SAR–4

Standards Authorization Request Form

Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes

SAR–5

Standards Authorization Request Form

Related Standards
Standard No.

Explanation

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

FRCC
MRO
NPCC
SERC
TRE
RFC
SPP
WECC

SAR–6

Proposed Continent-wide Definition of Bulk Electric System:
Bulk Electric System: All Transmission and Generation Elements and Facilities
operated at voltages of 100 kV or higher necessary to support bulk power system
reliability. Elements and Facilities operated at voltages of 100kV or higher,
including Radial Transmission systems, may be excluded and Elements and
Facilities operated at voltages less than 100kV may be included if approved
through the BES definition exemption process.

116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

Proposed Continent-wide Definition of Bulk Electric System:
As defined by the Regional Reliability Organization, the electrical generation
resources, transmission lines, interconnections with neighboring systems, Bulk
Electric System: All Transmission and associated equipment, generallyGeneration
Elements and Facilities operated at voltages of 100 kV or higher. necessary to
support bulk power system reliability. Elements and Facilities operated at
voltages of 100kV or higher, including Radial transmission facilities serving only
load with one transmission source are generally notTransmission systems, may be
excluded and Elements and Facilities operated at voltages less than 100kV may be
included in thisif approved through the BES definition exemption process.

116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

Project 2010-17 Definition of Bulk Electric System
Background Information
Purpose
In support of the ERO’s ability to respond to Commission directives and recommendations, this
project will address the issues raised by the Commission, the ERO, the Regional Entities, and the
industry as stated in FERC Order No. 693 and Order No. 743. In Order No. 743, the Commission
directed the following:
A. Utilize the NERC Standard Development Process to revise the definition of Bulk Electric
System (BES) contained in the NERC Glossary of Terms.
B. Develop a single Implementation Plan to address the application of the revised
definition of the BES and the implementation of the exemption process.
C. Utilize the NERC Rules of Procedure to develop and implement an ’exemption process’
used to identify Elements and Facilities which will be included in or excluded from the
BES.
This project will address items ‘A’ and ‘B’ and will coordinate efforts between the Standard
Drafting Team (SDT) and the group working to develop the exemption process for inclusion in
the NERC Rules of Procedure to ensure that the revised BES definition and exemption process
result in an accurate, repeatable, and transparent method for the identification of BES and nonBES Elements and Facilities.
Introduction
The Regional Bulk Electric System Definition Coordination Group was established at the request
of NERC senior management, prior to the issuance of Order 743, to gain continent-wide
consistency in a revised definition of the Bulk Electric System (BES). The results of several
industry driven Regional (FRCC, NPCC, RFC, and WECC) projects addressing the issue were
compared and consolidated to achieve a common approach to defining the BES.
The Regional Bulk Electric System Definition Coordination Group is proposing a common
approach to defining the BES to provide for improved clarity, to reduce ambiguity, and to
establish a universal method (“bright-line”) of distinguishing between BES and non-BES
Elements and Facilities that is reflected in the Standards Authorization Request (SAR).
A common approach to the identification of BES Elements and Facilities will establish a
repeatable method of correctly applying the NERC Reliability Standard requirements by the
industry and facilitate consistent application of compliance efforts by the entities involved
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

internally and across Regional boundaries (i.e., FERC, ERO, Regional Entities, and registered
entities).
This proposal would provide consistency across the nation’s reliability regions by establishing a
BES ‘Framework’ definition and a common set of criteria that clearly provide guidance for
determining what constitutes BES and non-BES Elements and Facilities. The BES ‘Framework’
will also allow for application of an exemption process (which may include regional differences
as defined by Order 672 or jurisdictional exemptions as appropriate for those entities not
subject to Section 215 of the Federal Power Act) consistent with the criteria to technically
assess whether or not an Element or Facility should be included or excluded from the BES as
exceptions to the definition and criteria (with concurrence from the ERO). The development,
approval, and utilization of the exemption process will be governed by revisions to the NERC
Rules of Procedure to address this specific issue.
Proposed BES Criteria
The Regional Bulk Electric System Definition Coordination Group proposed a set of criteria for
the identification of BES Elements and Facilities recommended for inclusion in the proposed
continent-wide definition of BES:
1. Transformers, other than Generator Step-up (GSU) transformers, including Phase
Angle Regulators, with both primary and secondary windings of 100 kV or higher;
2. Individual generation resources (including GSU transformers and the associated
generator interconnecting line lead(s)) greater than 20 MVA (gross nameplate
rating) directly connected via a step-up transformer(s) to Transmission Facilities
operated at voltages of 100 kV or above;
3. Generation plants (including GSU transformers and the associated generator
interconnecting line lead(s))with aggregate capacity greater than 75 MVA (gross
nameplate rating) directly connected via a step-up transformer(s) to Transmission
Facilities operated at voltages of 100 kV or above;
4. Blackstart Resources and the designated blackstart Cranking Paths identified in the
Transmission Operator’s (TOP’s) restoration plan;
5. Transmission Elements or Facilities operated at voltages below 100kV where the
exemption process deems the Element or Facility to be included in the BES;
6. Individual generation resources greater than 20 MVA (gross nameplate rating)
directly connected via a step-up transformer(s) to Facilities operated at voltages
below 100kV where the exemption process deems the generation resources to be
included in the BES; and
7. Generation plants with aggregate capacity greater than 75 MVA (gross nameplate
rating) directly connected via a step-up transformer(s) to Facilities operated at

2

voltages below 100kV where the exemption process deems the generation plants to
be included in the BES.
The proposed criteria recommended for the exclusion of Elements and Facilities from the BES
consist of:
1. Any radial Transmission Element or System, connected from one Transmission
source to a Load-serving Element and/or generation resources not included in items
2, 3, 4, 6, and 7 above are excluded from the BES;
2. Elements and Facilities identified through application of the exemption process,
consistent with the criteria, where the exemption process deems that the Element
or Facility should be excluded from the BES (with concurrence from the ERO); and
3. Generating plant control and operation functions which include relays and systems
that control and protect the unit for boiler, turbine, environmental, and/or other
plant restrictions.
These criteria will be vetted by the industry through the Standards Development Process via
industry comments and eventual ballot. As envisioned, criteria that are applicable on a
continent-wide basis will be added to the definition of BES; criteria that apply in some, but not
all areas, will be addressed through the exemption process.

3

Unofficial Comment Form for SAR and Proposed Definition of BES (Project 2010-17)
Please DO NOT use this form to submit comments. Please use the electronic comment form
located at the link below to submit comments on the SAR and proposed modification to the
definition of Bulk Electric System (Project 2010-17). The electronic comment form must be
submitted by January 21, 2011.
http://www.nerc.com/filez/standards/Project2010-17_BES.html
If you have questions please contact Ed Dobrowolski at Ed.Dobrowolski@nerc.net or by
telephone at 609-947-3673.

Background:
FERC issued Order 743 on November 18, 2010 with the directives identified below:
16. After consideration of the comments submitted, the Commission adopts the NOPR’s proposal with
some modifications. The Commission directs the ERO to revise the definition of “bulk electric system”
through the NERC Standards Development Process to address the Commission’s concerns discussed herein.
The Commission believes the best way to address these concerns is to eliminate the Regional Entities’
discretion to define “bulk electric system” without ERO or Commission review, maintain a bright-line
threshold that includes all facilities operated at or above 100 kV except defined radial facilities, and adopt
an exemption process and criteria for excluding facilities that are not necessary to operate an
interconnected electric transmission network. However, NERC may propose a different solution that is as
effective as, or superior to, the Commission’s proposed approach in addressing the Commission’s technical
and other concerns so as to ensure that all necessary facilities are included within the scope of the
definition.
The BES SAR authors are proposing a revised definition of the term BES to provide improved clarity, to
reduce ambiguity and to establish a universal “bright-line” for distinguishing between BES and non-BES
Elements and Facilities.
Proposed continent-wide definition of Bulk Electric System:
Bulk Electric System: All Transmission and Generation Elements and Facilities operated at
voltages of 100 kV or higher necessary to support bulk power system reliability. Elements
and Facilities operated at voltages of 100kV or higher, including Radial Transmission
systems, may be excluded and Elements and Facilities operated at voltages less than 100kV
may be included if approved through the BES definition exemption process.
This proposed definition provides consistency across the continent’s reliability regions by establishing a
definition that clearly describes what constitutes BES and non-BES Elements and Facilities. The BES
definition references an exemption process (which may include regional differences as defined by Order
672 or jurisdictional exemptions as appropriate for those entities not subject to Section 215 of the Federal
Power Act) that can be used to:
•

Identify the Radial Transmission systems that are excluded from the BES;

Unofficial Comment Form for SAR and Proposed Definition of BES (Project 2010-17)

•
•

Identify Elements and Facilities operated at voltages of 100kV or higher that may be excluded from
the BES; and
Identify Elements and Facilities operated at voltages less than 100kV that may be included in the
BES.

The development, approval and application of the BES definition exemption process (including periodic
review of exempted facilities) will be governed by revisions to the NERC Rules of Procedure, in close
coordination with the revision of the BES definition.
Information collected from the following questions will assist both the BES Drafting Team and the group
working to develop a BES Definition Exception Process.

1. Should the following should be classified as part of the BES?
• Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle
Regulators, with both primary and secondary windings of 100 kV or higher
Yes

No

Comments:

2. Should the following be classified as part of the BES?
• Individual generation resources (including GSU transformers and the associated generator
interconnecting line lead(s)) greater than 20 MVA (gross nameplate rating) directly
connected via a step-up transformer(s) to Transmission Facilities operated at voltages of
100 kV or above
Yes

No

Comments:

3. Should the following be classified as part of the BES?
• Generation plants (including GSU transformers and the associated generator
interconnecting line lead(s))with aggregate capacity greater than 75 MVA (gross nameplate
rating) directly connected via a step-up transformer(s) to Transmission Facilities operated
at voltages of 100 kV or above
Yes

No

Comments:

4. Should the following be classified as part of the BES?
• Blackstart Resources and the designated blackstart Cranking Paths identified in the
Transmission Operator’s (TOP’s) restoration plan
Yes

No

Unofficial Comment Form for SAR and Proposed Definition of BES (Project 2010-17)

Comments:

5. Should the following be classified as part of the BES?
• Transmission Elements or Facilities operated at voltages below 100kV where the
exemption process deems the Element or Facility to be included in the BES
Yes

No

Comments:

6. Should the following be classified as part of the BES?
• Individual generation resources greater than 20 MVA (gross nameplate rating) directly
connected via a step-up transformer(s) to Facilities operated at voltages below 100kV
where the exemption process deems the generation resources to be included in the BES
Yes

No

Comments:

7. Should the following be classified as part of the BES?
• Generation plants with aggregate capacity greater than 75 MVA (gross nameplate rating)
directly connected via a step-up transformer(s) to Facilities operated at voltages below
100kV where the exemption process deems the generation plants to be included in the BES
Yes

No

Comments:
8. Should the following be excluded from the Elements and Facilities classified as part of the BES?

•

Any radial Transmission Element or System, connected from one Transmission source to a
Load-serving Element and/or generation resources not included in items 2, 3, 4, 6, and 7
above are excluded from the BES
Yes

No

Comments:
9. Should the following be excluded from the Elements and Facilities classified as part of the BES?

•

Elements and Facilities identified through application of the exemption process, consistent
with the criteria, where the exemption process deems that the Element or Facility should
be excluded from the BES (with concurrence from the ERO)
Yes

No

Comments:
10. Should the following be excluded from the Elements and Facilities classified as part of the BES?

Unofficial Comment Form for SAR and Proposed Definition of BES (Project 2010-17)

•

Generating plant control and operation functions which include relays and systems that
control and protect the unit for boiler, turbine, environmental, and/or other plant
restrictions.
Yes

No

Comments:
11. Do you believe that the proposed definition of BES, accompanied by a separate BES Definition
Exception Process meets the reliability-related intent of the directives in Order 743?
Yes
No
Comments:
12. If you have a proposal for an equally efficient and effective method of achieving the reliability-related
intent of the directives in Order 743, please provide your proposal here.
Comments:
13. Please provide any other information that you feel would be helpful to the drafting team working on
the definition of BES.
Comments:

Official Comment form for BES Definition Exception Process

Please use this form to submit your recommendations for consideration in developing
criteria for deviating from the default criteria for classifying Elements and Facilities as part
of the BES.
Please send recommendations relative to the BES Definition Exception Process and
associated documentation to sarcomm@nerc.com with “BES Definition” in the subject line.
The information should be submitted no later than January 21, 2011.
If you have questions please contact Ed Dobrowolski at Ed.Dobrowolski@nerc.net or by
telephone at 609-947-3673.
Please provide your name, organization, telephone number and email address so that we
may contact you if we need clarification:

Name:
Organization:
Telephone:
Email:

Background:
FERC issued Order 743 on November 18, 2010 with the directives identified below:
16. After consideration of the comments submitted, the Commission adopts the NOPR’s proposal with
some modifications. The Commission directs the ERO to revise the definition of “bulk electric system”
through the NERC Standards Development Process to address the Commission’s concerns discussed
herein. The Commission believes the best way to address these concerns is to eliminate the Regional
Entities’ discretion to define “bulk electric system” without ERO or Commission review, maintain a
bright-line threshold that includes all facilities operated at or above 100 kV except defined radial
facilities, and adopt an exemption process and criteria for excluding facilities that are not necessary to
operate an interconnected electric transmission network. However, NERC may propose a different
solution that is as effective as, or superior to, the Commission’s proposed approach in addressing the
Commission’s technical and other concerns so as to ensure that all necessary facilities are included
within the scope of the definition.
NERC is working to address these directives with two activities – the definition of Bulk Electric System
(BES) is being revised through the standard development process and a BES Definition Exception Process
is being developed as a proposed modification to the Rules of Procedure.
The information you provide in response to the following questions may be used by the standard
drafting team working to revise the definition of BES or by the group working to develop a BES
Definition Exception Process.

Official Comment form for BES Definition Exception Process

1. If you believe there are Transmission or Generation Elements or Facilities operated at voltages
100kV and above which should be considered for exclusion from the Elements and Facilities
classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification:
d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide basis,
region-wide basis, or less than a region-wide basis. If you don’t know how widely this
exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Less than Region-wide
Unknown

Comments relative to the proposed exclusion(s):
2. If you believe there are Transmission or Generation Elements or Facilities operated at voltages
below 100kV which should be considered for inclusion in the Elements and Facilities classified as
part of the BES:
a. Identify the Element or Facility recommended for inclusion:
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification:
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide basis,
region-wide basis, or less than a region-wide basis. If you don’t know how widely this
inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Less than Region-wide
Unknown

Official Comment form for BES Definition Exception Process

Comments relative to the proposed inclusion(s):

3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:

Standards Announcement

Standards Authorization Request (SAR), Draft Definition and Exception
Process Informal Comment Period Open
December 17, 2010-January 21, 2011
Now available at: http://www.nerc.com/filez/standards/Project2010-17_BES.html
Project 2010-17: Definition of Bulk Electric System
A proposed SAR, a proposed revision to the definition of “Bulk Electric System,” and a set of concepts for use
in developing a BES Definition Exception Process have been posted for comment until 8 p.m. Eastern
on January 21, 2011.
Instructions
Due to the nature of the comments we are seeking from stakeholders, there are two different comment forms
and we ask that you complete both.
1. The SAR and BES comment form
Please use the electronic form to submit comments on the SAR and proposed definition of Bulk Electric
System. If you experience any difficulties in using the electronic form, please contact Monica Benson at
monica.benson@nerc.net.
An off-line, unofficial copy of the SAR and BES Definition comment form is posted on the project
page: http://www.nerc.com/filez/standards/Project2010-17_BES.html
2. The BES Definition Exception Process comment form
The BES Definition Exception Process comment form is also posted on the project page identified
above. Please use the BES Definition Exception Process comment form to submit comments and
supporting information relative to the concepts proposed for use in developing a BES Definition
Exception Process. The BES Definition Exception Process comment form must be submitted to
sarcomm@nerc.com with “BES Definition” in the subject line.
Next Steps
The drafting team will draft and post a summary of the responses to comments received during this period.
Project Background
2010 FERC issued Order 743 and directed NERC to revise the definition of Bulk Electric
System so that the definition encompasses all Elements and Facilities necessary for the reliable operation and
planning of the interconnected bulk power system. Additional specificity will reduce ambiguity and establish
consistency across all Regions in distinguishing between BES and non-BES Elements and Facilities.
On November 18,

In addition, NERC was directed to develop a process for identifying any Elements or Facilities that should be
excluded from the BES. NERC is working to address these directives with two activities – the definition of
Bulk Electric System (BES) is being revised through the standard development process and a BES Definition
Exception Process is being developed as a proposed modification to the NERC Rules of Procedure. Comments
received in response to this initial posting will be used by the drafting team working on the revision to the
definition and by the group working to develop the BES Definition Exception Process.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our thanks to
all those who participate.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Question 1:
If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
b. Provide a generic one‐line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
d. Identify if this exclusion should apply on a continent‐wide basis,
interconnection‐wide basis, region‐wide basis, or less than a region‐wide basis. If you
don’t know how widely this exclusion should apply, please select, “unknown.”
Commenters:
John A. Gray, The Dow Chemical Company ................................................................................. 3
Michael Moltane & John Zipp, ITC Holdings ................................................................................ 5
Frank Gaffney, Florida Municipal Power Agency, Et all ............................................................... 6
Josh Dellinger, Glacier Electric Cooperative................................................................................ 13
Michelle Mizumori, Western Electricity Coordinating Council................................................... 14
Brandy A. Dunn, Western Area Power Administration ............................................................... 16
Alain Pageau, Hydro-Québec TransÉnergie ................................................................................. 17
Guy Zito, Northeast Power Coordinating Council ....................................................................... 18
Jim Uhrin, ReliabilityFirst Corporation ........................................................................................ 20
Joe Petaski, Manitoba Hydro ........................................................................................................ 21
John W. Delucca, Lee County Electric Cooperative .................................................................... 22
Paul Cummings, City of Redding ................................................................................................. 24
Patrick Farrell, Southern California Edison Company ................................................................. 25
Ed Davis, Entergy Services, Inc ................................................................................................... 27
Manny Robledo, City of Anaheim ................................................................................................ 28
Lorissa Jones, Bonneville Power Administration ......................................................................... 30
Page 1 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

David Burke, Orange and Rockland Utilities ............................................................................... 31
Jim Case (Entergy), SERC OC Standards Review Group ........................................................... 33
Thad Ness, American Electric Power ........................................................................................... 34
Amir Hammad, Constellation Power Source Generation, Inc., Et all .......................................... 36
William J. Gallagher, Vermont Public Power Supply Authority ................................................. 38
David Angell, Idaho Power........................................................................................................... 44
Marc M. Butts, Southern Company .............................................................................................. 45
Andrew Z. Pusztai, American Transmission Company ................................................................ 46
Ronald Sporseen, PNGC Power, Et all ......................................................................................... 48
Jerome Murray, Oregon Public Utility Commission .................................................................... 50
John D. Martinsen , Public Utility District No. 1 of Snohomish County ..................................... 51
Steve Alexanderson P.E., Central Lincoln.................................................................................... 53

Page 2 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

John A. Gray, The Dow Chemical Company
Phone: 281‐966‐2390
Email: JAGray3@dow.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
As discussed in the comments of The Dow Chemical Company (“Dow”) on the
recommended definition of BES, the 100 kV standard is inapplicable to generation
and should not be used to identify generation facilities that are included in the BES,
or that are eligible for an exception or exclusion. Instead, the NERC Statement of
Compliance
Registry Criteria already sets forth criteria for determining when individual
generating units and generating plants/facilities are not part of the bulk electrical
system. Those existing standards and the generator‐specific registration
determinations that have been made using those standards should be preserved.
Dow does not object to retaining a 100 kV standard for identifying transmission
facilities that should be considered part of the BES, but exclusions must be made for
distribution facilities and interconnection facilities. If owners and/or operators of such
facilities are required to secure an “exception” or “exclusion” from the 100 kV
standard, then such process must ensure that exceptions or exclusions are available
before mandatory reliability standards become applicable.
b. Provide a generic one‐line diagram depicting the Element or Facility in question (if
available).
For a manufacturing site, distribution facilities deliver electricity from the generating
plants and or the transmission grid to the manufacturing plants. Interconnection
facilities are generally identified by reference to the point of interconnection with the
transmission grid. Facilities located on the generator’s side of this interconnection up
to the site transformers are generally considered interconnection facilities while
facilities located at or beyond the point of interconnection are generally considered
transmission facilities.
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: The NERC Statement of Compliance Registry Criteria excludes
certain generating facilities, because these generating facilities are not material to the
reliability of the BES. Distribution facilities are expressly excluded from the
definition of BES pursuant to Section 215 of the Federal Power Act. Distribution
facilities are typically operated differently from transmission facilities. As such,
Page 3 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

distribution facilities should not be subject to the same reliability standards as
transmission facilities. FERC has recognized that interconnection facilities may or
may not be material to the reliability of the BES. As such, FERC has held that a
facts‐and‐circumstances analysis should be used to determine whether and to what
extent such facilities should be considered part of the BES and, therefore, subject to
mandatory reliability standards. See New Harquahala Generating Company, LLC,
123 FERC ¶ 61,173 at P 44 (2008), clarified, 123 FERC ¶ 61,311 (2008).
d. Identify if this exclusion should apply on a continent‐wide basis,
interconnection‐wide basis, region‐wide basis, or less than a region‐wide basis. If you
don’t know how widely this exclusion should apply, please select, “unknown.”
Continent-wide
Comments relative to the proposed exclusion(s):
At minimum, the exclusions applicable to distribution facilities and interconnection
facilities should apply to all facilities that are subject to FERC’s reliability
jurisdiction under Section 215 of the Federal Power Act.

Page 4 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Michael Moltane & John Zipp, ITC Holdings
Telephone: 248-946-3093
Email:
mmoltane@itctransco.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
Comments relative to the proposed exclusion(s): It is unclear how we would identify
an individual element then in part d. declare it Region-wide. This needs to be made
more clear

Page 5 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Frank Gaffney, Florida Municipal Power Agency, Et all
Florida Municipal Power Agency is filing the comments below on behalf of its’ project
participants:
City of New Smyrna Beach
KUA
Lakeland Electric
City of Clewiston
Beaches Energy Services
Ocala Electric Utility
Telephone: 407-355-7767
Email: frank.Gaffney@fmpa.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a . Identify the Element or Facility recommended for exclusion:
This question refers to “exclusions”; we believe, however, that the intent of this
comment form is to elicit feedback on the process for “exemptions.” It is important
to distinguish between the two concepts, as FERC did in Order 743. See, e.g.,
Paragraph 1, which refers to “maintain[ing] a bright-line threshold that includes all
facilities operated at or above 100 kV except defined radial facilities,” as well as to
“establish[ing] an exemption process and criteria.” (emphasis added). In other
words, in brief, an “exclusion” is outside of the BES by definition, whereas exempt
Elements are removed on a case-by-case basis by going through a process.
FMPA draws the distinction as follows:
An exclusion is the removal of a category of Elements from the BES definition. The
current BES definition explicitly carves out radials serving only load with one
transmission source. This is a clear example of an exclusion. There is no “exclusion
process” now, nor should there be one in the future; the point of an exclusion is that
the class of excluded Elements can—without any process—be treated like sub100 kV transmission, in that they are presumed to be non-BES unless a particular
Element is demonstrated, on a case-by-case basis, to be properly included in the BES
(see responses to Questions 5 and 11 in FMPA’ comments on BES definition,
submitted today, and FMPA response to Question 2 below).
An exemption, on the other hand, is a finding that a particular Element, although
nominally part of the BES, does not need to be included in the BES because it is not
necessary for operating an interconnected transmission network.
Page 6 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Because exemptions are less clear-cut than exclusions, each exemption of an Element
needs to be approved by NERC so that the Registered Entity and compliance
authorities have certainty about the Elements with respect to which compliance is
required. In many, perhaps all, cases, this process will likely require a case-by-case
examination of each Element for which an exemption is requested.
FMPA responds to this question with respect to the one “exclusion” from the BES
definition that we advocate, that of radial Transmission Elements serving only load
and/or generation not registered pursuant to the Statement of Compliance Registry
Criteria. We also propose uniform criteria for deciding, on a case-by-case basis,
whether to grant requested exemptions from the BES, or to include nominally nonBES Elements in the BES. The process that we propose for exemption requests and
proposed inclusions is discussed below in response to the invitation of “[c]omments
relative to the proposed exclusion(s).”
Exclusion:
FMPA proposes only one exclusion from the BES definition, namely, “Radial
Transmission Elements serving only load with one Transmission source are generally
not included in this definition. A radial Transmission Element may be considered as
‘serving only load’ for purposes of the foregoing general exclusion even if it connects
generation, so long as that generation is not registered pursuant to the Statement of
Compliance Registry Criteria.” This formulation, which is discussed in FMPA’
comments submitted today on the BES definition, is intended to preserve the current
exclusion of radials serving only load with one transmission source, and to clarify that
the presence of a generator that is not registered under the Compliance Registry
Criteria does not convert a radial into a BES Element. The end result is that radial
transmission is excluded unless it connects generation that is registered pursuant to
the Statement of Compliance Registry Criteria. Consistent with the Compliance
Registry Criteria, a single generator under 20 MVA, or a plant under 75 MVA, if not
designated as a Blackstart Resource needed for system restoration, is unlikely to
affect the grid. Therefore, the presence of such generation should not require that an
otherwise non-BES radial be included in the BES. Rooftop photovoltaic cells, for
example, are increasingly common. If FMPA’ proposed clarification is not accepted,
the presence of such insignificant generation could nullify the exclusion of radials to
load with one transmission source, with no benefit to reliability.
Exemption criteria
FMPA has not yet developed a list of criteria that we believe to be exhaustive, though
we emphasize that such a list must be an ultimate goal of this process. We propose
the following criteria as a start:
FMPA proposes that at least two classes of elements be eligible to request an
exemption:

Page 7 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

i. Elements that are part of a radial “system” originating from a single BES source
serving only load, as in the Florida Keys. Clarifications: a) radial system means any
number of series and/or parallel Elements as long as they all originate from a single
BES source and do not have another BES source; b) “single BES source” means one
BES bus / substation / switching substation at one voltage level, and c) consistent
with FMPA’ proposed exclusion of radials serving only load and unregistered
generation, “serving only load” includes serving generation that is not registered
through the Statement of Compliance Registry Criteria.
ii. Elements that are part of a “looped” system that has two transmission sources
primarily for local quality of service to the retail customers supplied by the looped
system in question and is not used for bulk electric system flow (e.g., the transfer
distribution factor of flows across the looped system is low, representing a high
impedance path across the looped system). Specific criteria might be: a) a looped
system that participate in less than a 5% of transfer (e.g., 5% or less transfer
distribution factor); and b) that the looped system in question does not limit transfers.
A radial or looped system to be exempted must meet the following criteria:
1. The radial or looped system may not contribute to any Category D or C
contingency resulting in: 1) a supply / demand mismatch greater than the largest loss
of source contingency in the Reliability Coordinator area; or 2) an Adverse Reliability
Impact where, if the Element were not involved in those Category D or C
contingencies, those thresholds would not be exceeded.
Studies to determine whether this criterion is met would be conducted in accordance
with TPL-004-0 and TPL 003-0 standards (or corresponding contingencies in revision
to the TPL standards) in the Short Term Planning Horizon. Although the above
criteria are acceptable responses to a Category D contingency, the concept of the test
is to see if a radial or looped system would cause a significantly worse response to
Category C or D contingencies by testing the contingency with and without the radial
or looped system. FMPA believes that such criteria are good indicators that a radial
or looped system should be included in the BES as it highlights whether the
protection systems are important for critical clearing times, and whether the radial or
looped systems can contribute to an Adverse Reliability Impact in combination with
other contingencies;
2. No portion of the radial or looped system may meet any of the conditions of
Attachment 1 to CIP-002-4;
3. No portion of the radial or looped system may meet any of the conditions listed in
items B1 to B5 of Attachment B to PRC-023-2;
4. No portion of the radial or looped system may be a part of, or be a limiting
element of, any Path, Interchange, or Flowgate used in the calculation of ATC in
accordance with standards MOD-028, MOD 029 or MOD 030; and
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Summary Comment Report – Question 1 a-d
January 27, 2011

5. No portion of the radial or looped system may include a blackstart resource or
cranking path deemed significant to the TOP or RC restoration plans of EOP-005,
EOP-006 or EOP-007.
If a Registered Entity demonstrates to NERC that an Element that is nominally in the
BES meets all of these criteria, the exemption would be granted.
Conversely, if NERC demonstrates that a nominally non-BES Element meets the
negative of any of these criteria (e.g., if any portion of the radial or looped system
meets any of the conditions of Attachment 1 to CIP-002-4 or of Attachment B to
PRC-023-2), the Element would be included in the BES.
Throughout these comments, FMPA refers to “Elements” and not to “facilities.” This
is because “Facility” is defined in the NERC Glossary as “[a] set of electrical
equipment that operates as a single Bulk Electric System Element….” Because these
comments (and the BES definition) address whether Elements are or are not part of
the BES, it is incorrect to refer to the Elements in question as “Facilities,” because a
Facility is defined as a BES Element.
In developing the exemption/inclusion criteria and process, NERC and the SDT
should bear in mind the requirement of Order 743: “NERC should develop an
exemption process that includes clear, objective, transparent, and uniformly
applicable criteria for exemption of facilities that are not necessary for operating the
grid.” Paragraph 115 (emphasis added). NERC and the SDT should also bear in
mind that FERC anticipates that between the BES definition and the exemption
process, there will be only “minimal[]” effect on “small entities.” Order 743,
Paragraph 169. Order 743 is referring to the Small Business Act definition of a
“small electric utility” as one that has a total electric output of less than four million
MWh in the preceding year. See BES NOPR, 133 FERC ¶ 61,150, Paragraph 35 &
footnote 50.

b . Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c . Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Radial Transmission Elements serving only load have been
recognized for years as non-BES because such Elements are very unlikely to affect
the BES. FERC stated in Order 743 that NERC may retain that exclusion.
Similarly, generators under 20 MVA and generating plants under 75 MVA are not
subject to registration pursuant to the Statement of Compliance Registry Criteria,
which has been accepted by FERC, because of the recognition that such generators
are very unlikely to affect the BES. It is thus consistent with the Compliance
Registry Criteria to exclude from the BES definition radials serving load with one
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Summary Comment Report – Question 1 a-d
January 27, 2011

transmission source even if there is some generation on the radial, so long as none of
the generation is registered. If the generation is not significant enough to be
registered, it is not significant enough to transform an otherwise non-BES radial to
load into a BES Element.

d . Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide
The exclusion of radials to load and unregistered generation, as part of the BES
definition, should apply on a continent-wide basis.
Each Element proposed for exemption or inclusion should be considered individually,
under the same criteria (proposed above), applied uniformly continent-wide.

Comments relative to the proposed exclusion(s):
Exemption and Inclusion Processes:
The exemption and inclusion processes should be designed to ensure continent-wide
uniformity to the maximum extent possible. To that end, NERC must use a uniform
process; the criteria for approving or denying an exemption, or for including an
Element in the BES, must be clear; and entities must be able to appeal decisions to
another body within NERC or to FERC.
In order to obtain an exemption, a Registered Entity should be required to
demonstrate that the Element for which it is requesting an exemption is not
“necessary for operating an interconnected electric transmission network.” This is the
standard set out in Order 743; it is also part of the definition of the “bulk-power
system” in Section 215 of the Federal Power Act, 16 U.S.C. § 824o(a)(1)(A) (the
other part of the statutory definition is “electric energy from generation facilities
needed to maintain transmission system reliability,” 16 U.S.C. § 824o(a)(1)(B)).
Application of this standard should be informed by the statutory definitions of
“reliability standard” (“a requirement, approved by the Commission under this
section, to provide for reliable operation of the bulk-power system”) and “reliable
operation” (“operating the elements of the bulk-power system within equipment and
electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden
disturbance, including a cybersecurity incident, or unanticipated failure of system
elements”).

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Conversely, to include a nominally non-BES Element in the BES, NERC should be
required to demonstrate that the Element is necessary for operating an interconnected
electric transmission network.
Criteria for determining whether an Element is or is not “necessary for operating an
interconnected electric transmission network” are proposed in response to Question
1(a) above. The criteria should be uniform continent-wide, though they will be
applied to each Element on a case-by-case basis.
Exemption requests and proposed inclusions should be decided by NERC staff in the
first instance. FMPA does not believe that the exemption and inclusion processes
should be delegated to the Regional Entities. In Order 743, FERC emphasized the
need for continent-wide uniformity; in fact, it was inconsistency among regions that
prompted Order 743. FMPA members’ experience with Regional registration
processes suggests that Regional implementation of the BES exemption and inclusion
processes is unlikely to yield the uniformity that FERC directed. Furthermore,
implementing this FERC directive will unavoidably require significant personnel
resources, either at NERC or at the Regions. Delegating the process to the Regions
would impose additional costs due to the need for NERC to exercise strong oversight
to attempt to maintain uniformity. It may be that after the exemption and inclusion
processes have been in place for a few years and a body of precedent has been
accumulated, delegation will be appropriate. At this time, however, NERC staff
should make the initial decision on all exemption requests and proposed inclusions.
FMPA proposes, for the sake of consistency with the registration appeal process, that
appeals of decisions on exemptions and inclusions be to the Board of Trustees
Compliance Committee (BOTCC), with further appeals to FERC if necessary.
Appeals to the BOTCC would consist of the record compiled by NERC Staff, and
additional paper submissions by NERC Staff and the Registered Entity demonstrating
why the Element(s) in question is or is not “necessary for operating an interconnected
electric transmission network.” See NERC Rules of Procedure, Appendix 5A,
“Organization Registration and Certification Manual,” at 14-16. Registered Entities
should have the option of requesting a hearing. Hearing procedures could be modeled
on the Compliance and Certification Committee’s “Hearing Procedures for Use in
Appeals of Certification Matters,” in Appendix 4E of the NERC Rules of Procedure.
FMPA also suggests that decisions on exemptions and inclusions be made available
to others, either subject to CEII protection or in a form suitable for public release. As
precedent develops, Registered Entities will increasingly be able to judge for
themselves the likelihood that a particular exemption will be granted, or that an
appeal of an inclusion will succeed. We expect that giving Registered Entities more
information on which to base their decisions will significantly reduce the burden on
NERC of processing exemptions and inclusions.
We propose that BES Elements for which an exemption request is pending should
continue to be included in the BES until the exemption and any appeals are decided,
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Summary Comment Report – Question 1 a-d
January 27, 2011

and that non-BES Elements for which an inclusion is pending should continue to be
non-BES until the inclusion and any appeals are decided.
The transition process should include an important exception to the general rule
proposed for BES status during the pendency of an exemption request: to allow for a
smooth transition, to the extent that Elements that are currently considered non-BES
become BES under the new definition, those Elements should be permitted to request
exemptions and to continue to be considered non-BES until their exemption requests
and any appeals are decided.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Josh Dellinger, Glacier Electric Cooperative
Telephone: 406-873-5566
Email:

joshd@glacierelectric.com

1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Our delivery point,
which is a loop-fed 115kV switching station.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: This station’s main purpose is to be a delivery point for our system.
We are a distribution cooperative that serves mainly residential and small commercial
loads. Each year we peak around 35 MW and average around 22 MW. This station
is loop fed by two 115 kV lines to give our members more reliability. No
transmission planner, balancing authority, transmission operator, reliability
coordinator, etc. has included this station in any critical path lists or system
restoration plans. This station is not designated as critical asset by its balancing
authority or transmission operator. The available short-circuit MVA at this station is
677 MVA. If a fault were to occur at this station, outages would be limited to the
local area and the BES as a whole would not be adversely affected at all. It is our
belief that facilities such as this are insignificant to the BES and do not need to be
considered part of the BES.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Michelle Mizumori, Western Electricity Coordinating Council
Telephone: 801-819-7624
Email: mmizumori@wecc.biz
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Those elements or
facilities above 100 kV that are shown through engineering studies to not be necessary
to reliably operate an interconnected transmission system.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: An element or facility that is not necessary to reliably operate an
interconnected transmission system need not be included in the Bulk Electric System
(BES). This can be assessed using engineering studies that show the effect of worstcase disturbances on multiple indicators such as frequency, voltage, system flows,
operating limits, generator tripping, cascading outages, and/or islanding with the
element or facility removed from service. An element or facility is not necessary to
reliably operate if the system can maintain acceptable steady-state and dynamic
performance during and after a worst-case disturbance with the element removed from
service.
d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Comments relative to the proposed exclusion(s):
The BES functions to generate bulk power and transfer that bulk power to locations
from which it is then distributed to end-use load. Elements that generate bulk power,
transfer bulk power, or support the transfer of bulk power are part of the BES.
An element is necessary to reliably operate an interconnected transmission system if it
significantly affects the ability of the BES to generate bulk power or carry bulk power
to locations from which is it distributed to end-use load. While operating voltage (i.e.,
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Summary Comment Report – Question 1 a-d
January 27, 2011

the proposed 100 kV bright-line) may be a clear and repeatable proxy for identifying
those elements that are necessary to reliably operate an interconnected transmission
system, it is a broad approach that may not adequately address specific examples.
Moreover, engineering studies can be used to more granularly and accurately identify
elements that are not needed to reliably operate an interconnected transmission system.
The thresholds on the indicators listed above may vary between interconnections and
regions. For example, voltage deviation may be more relevant in the Western
Interconnection (which is primarily stability limited) than in the Eastern Interconnection
(which is primarily thermally limited).

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Brandy A. Dunn, Western Area Power Administration
Telephone: 720-962-7431
Email: dunn@wapa.gov
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Any Element above
100-kV that is shown (through system studies) to NOT be necessary to reliably
operate the interconnected transmission system.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: An Element that is not required to reliably operate the interconnected
transmission system does not need to be included in the BES (or specifically calledout in the definition). This can be assessed through engineering system studies that
show the worst-case results based on indicators such as voltage, frequency, OTC
limits, angular instability and/or cascading outages based on that Element being
removed from service.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Comments relative to the proposed exclusion(s): An Element is necessary to
reliably operate the interconnected transmission system if it significantly affects the
ability of the BES to carry bulk power to end-use load. While a brightline test
voltage (such as the proposed >100-kV) may be a clear and repeatable proxy for
identifying Elements that are necessary to reliably operate the interconnected
transmission system, this broad approach may not adequately address specific
examples. Engineering system studies can accurately identify Elements which are not
needed to reliably operate the interconnected transmission system.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Alain Pageau, Hydro-Québec TransÉnergie
Telephone: 514 879-4100 #5414
Email: pageau.alain@hydro.qc.ca
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: The transmission lines
dedicated to serve the native load in the Quebec Interconnection.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Guy Zito, Northeast Power Coordinating Council
Telephone: 212-840-1070
Email: gzito@npcc.org
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a . Identify the Element or Facility recommended for exclusion:
All step-down transformers with their low-side terminals operated at below 100 kV.
Radial taps from a BES feeder or bus connection to loads. All elements or facilities
in series with excluded or exempt elements or facilities -- upstream to a designated
point-of-demarcation with the BES and downstream to the customer meter or
interconnection. (Refer to the response to Question 3, New York Indicator [NY-2]
below, and the response to Question 13, proposed definition ‘Point-of-Demarcation’
in the BES Definition Comments provided separately). For example, upstream from
an exempt or excluded feeder to the upstream-side of the disconnect switch
connecting the excluded or exempted feeder to the BES, or if no disconnect switch is
present, to the upstream BES supply-bus connection. This exclusion or exemption
would extend to and also apply to related equipment, such as circuit switchers, circuit
breakers, ground switches, disconnect switches, busses, etc. that are down-stream of
the point-of-demarcation and in the same circuit with the exempted or excepted
feeders and transformers.
Local generation and any facility associated with local generation serving as a load
modifier to local load only. The power generated is demonstrated to be consumed
locally and does not flow back into the BES. The operation (or loss) of the local
generation and/or associated facilities does not materially impact any BES
transmission facilities. If a local generator functions as a load modifier, and does not
materially impact the BES, meaning that it is not necessary to maintain BES
reliability, then it should be excluded from the definition of BES under the BES
Exclusion process.
The transmission lines dedicated to serve the native load in the Quebec
Interconnection.
b . Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Not Applicable
c . Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: The FERC Seven Factor test has been shown to be a reliable,
repeatable method for identifying facilities that are local distribution and separating
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

them from those facilities which perform a transmission function. The indicators of
local distribution in the Commission’s seven-factor test 1 are:
1) Local distribution facilities are normally in close proximity to retail
customers;
2) Local distribution facilities are primarily radial in character;
3) Power flows into local distribution systems, and rarely, if ever flows out;
4) When power enters a local distribution system, it is not reconsigned or
transported on to some other market;
5) Power entering a local distribution system is consumed in a comparatively
restricted geographic area;
6) Meters are based at the transmission / local distribution interface to measure
flow into the local distribution system; and
7) Local distribution systems will be of reduced voltage.
1

Ref. FERC Order No. 888 at 31,771 and 31,981, e.g., Promoting Wholesale
Competition Through Open Access Non-Discriminatory Transmission Services
by Public Utilities

d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide
Less than Region-wide
Unknown

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Jim Uhrin

, ReliabilityFirst Corporation

Telephone: 330.247.3058
Email: jim.urhin@rfirst.org
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Those that have no
impact to the reliability of the BES for any reason or could at anytime. Those that
may or could through reconfiguration and or operating procedures must be
included.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).

In the diagram above, any equipment downstream of the “A” breaker that does not or
could not trip and lockout a BES facility (e.g. line, transformer, etc.) may be excluded,
however if equipment below the “A” breaker could or does trip and lockout a BES
facility for any reason, then it should be included.
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: If the facility could never trip and lockout a BES facility, there is no
reason to include it. However, caution and careful consideration must be used when
exclusions are considered. There maybe times during toplogy changes or system reconfigurations that certain facilities could trip and lockout a BES facility and
therefore must be included.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Joe Petaski, Manitoba Hydro
Telephone: 204-487-5332
Email: jpetaski@hydro.mb.ca
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Radial Transmission
Elements and Systems - See comment below
Comments relative to the proposed exclusion(s): Radial Transmission Elements and
Systems should be excluded from the Elements and Facilities classified as part of the
BES but a clear NERC definition of radial is required to prevent misunderstandings and
misapplications of the BES definition and exemption process. Also, there should be no
regional differences in the BES definition or in the BES definition exemption process.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

John W. Delucca, Lee County Electric Cooperative
Telephone: 239-656-2190
Email: john.delucca@lcec.net
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Radial load serving elements
that do not have an adverse effect upon the BES should be excluded. Also Transmission
systems that have no adverse impact on the BES as evidenced by engineering design and
criteria and load modeling should be excluded such as Non-FERC Jurisdictional Facilities;
Radial Non-Transmission Load Serving Elements; Looped Non-Transmission Load
Serving Elements; Looped Non-Transmission Load Serving Elements Designed &
Installed with No Intent to Provide Transmission Load Service.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Please refer to Attachment 1b.6 – 1b.9 the draft BES Definition currently
under review in the FRCC region. There are multiple single-lines included that represent
a fair cross section of elements that should be excluded.
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: The purpose of including facilities in the definition of BES is make them
subject to federal regulations that are designed to serve the reliability needs of the BES
and to prevent cascading of outages to a broad section of the BES. Certain elements
operated at voltages of 100kV or higher have zero measurable impact to the reliable
operation of the Interconnected BES. No practical purpose is served by including those
elements, and if they are, it unnecessarily increases the cost of delivered power. The
following list also should be considered, a). No FERC Jurisdiction; b) Facilities were/are
designed, installed, and operated to serve local non-transmission loads; c) Rates are
designed to provide revenue to meet local non-transmission service; d) Facilities were
never designed or intended to provide capability of entity-to-entity, region-to-region load
flows other than that required to meet local non-transmission service loads; e) Reactance
resources whose purpose is neutralizing non-transmission inductive loads and/or to
compensate for “within entity” losses.

d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how widely
this exclusion should apply, please select, “unknown.”
Continent-wide

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Comments relative to the proposed exclusion(s): The submitted diagrams are not intended
to represent every possible element that should be excluded Continent-wide. The complete
list should be determined by the proposed task force in order that regional differences in
system characteristics is taken into account. In addition, to insure continuity, but the final
decision as to what meets the exclusion criteria should reside in the Region with appeal
process to NERC and possibly FERC.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Paul Cummings, City of Redding
Telephone: 530-245-7016
Email: pcummings@ci.redding.ca.us
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Those elements or
facilities operated at or above 100kV that are shown through engineering studies
not to be necessary to reliably operate an interconnected transmission system.
Radial elements unless they are shown to be necessary to reliably operate an
interconnected transmission system. See Attachment 1. (Refer to Attachment 1b.5)
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Refer to Attachment 1b.5
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: “The impact an Element has on the BES shall be determined by
assessing the performance of key measures of BES reliability through power flow,
post-transient, and transient stability analysis with (1) the system, and the Subject
Element, operating at reasonably stressed conditions that replicate expected system
conditions under which the loss of the Subject Element would have the greatest
impact on the key measures of reliability, and (2) the Subject Element removed
from service, but without allowing for system readjustment.”
d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how widely
this exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Patrick Farrell, Southern California Edison Company
Telephone: 626-302-1321
Email: Patrick.Farrell@sce.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: The elements and
facilities above 100kV that are shown through engineering studies to not be necessary
to reliably operate an interconnected transmission system should be excluded.
Additionally, the transmission facilities at 100kV and above that are radial in nature,
used for load serving purposes, and which are not parallel to interconnected
transmission systems should be excluded. As an example, in SCE’s system, the
Valley 115kV system is radial in nature and the power flow is generally from 500kV
to 115kV to serve load.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: An element or facility that is not necessary to reliably operate an
interconnected transmission system need not be included in the BES. This can be
assessed using engineering studies that show the effect of worst-case disturbances on
multiple indicators such as frequency, voltage, system flows, operating limits,
generator tripping, and cascading outages and/or islanding with the element or facility
removed from service. If a system can maintain acceptable steady-state and dynamic
performance during and after a worst-case disturbance with the element removed
from service, that element or facility is not necessary to reliably operate the system.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
X Continent-wide
X Interconnection-wide
X Region-wide
Comments relative to the proposed exclusion(s): The Bulk Electric System (BES)
functions to generate bulk power and transfer that bulk power to locations from which
it is then distributed to end-use load. Elements that generate bulk power, transfer bulk
power, or support the transfer of bulk power are part of the BES.
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

An element is necessary to reliably operate an interconnected transmission system if
it significantly affects the ability of the BES to generate bulk power or carry bulk
power to locations from which it is distributed to end-use load. While operating
voltage (i.e. the proposed 100kV bright-line) may be a clear and repeatable proxy for
identifying those elements that are necessary to reliably operate an interconnected
transmission system, it is a broad approach that may not adequately address specific
examples. Engineering studies can be used to more granularly and accurately identify
elements which are not needed to reliably operate an interconnected transmission
system.
The thresholds on the indicators listed above may vary between interconnections and
regions. For example, SCE’s system has facilities rated at the 115kV level that are
radial in nature for load serving purposes. Therefore, applying a 100kV bright-line
may unnecessarily bring facilities that could be excluded through an engineering
study.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Ed Davis, Entergy Services, Inc
Telephone: 504-576-3029
Email: edavis@entergy.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
These questions and possible responses by entities are appropriate as the questions
relate to specific facilities and configurations to be considered for exemption. The
questions do not reflect principles (criteria) for the determination of if facilities or
configurations to be included / excluded in the definition of BES. We agree the
questions and responses may be appropriate here if the responses are to be used as
examples to develop exemption principles (criteria). However, we suggest the authors
should have also asked the industry for principles (criteria) they believe should be
included as exemption criteria.
These questions and responses also do not address a possible process for determining
if facilities or configurations should be included / excluded in the definition of BES.
We suggest the authors should have also asked the industry for process suggestions
they would like included in the final process.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Manny Robledo, City of Anaheim
Telephone: 714-765-5107
Email: mrobledo@anaheim.net
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: City of Anaheim LewisVermont 230kV radial transmission line and seven 230kV to 69kV transformer banks and
associated substation equipment, which are also radial transmission elements serving
load.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Refer to attachments:
1b.1 Anaheim System One-Line,
1b.2 Anaheim 220kV System,
1b.3 Anaheim 69kV Bus Impedance Diagram
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: The 220kV facilities owned and operated by Anaheim are radial
transmission elements fed from one transmission source, i.e. Lewis Substation. Southern
California Edison Company (SCE) and the California Independent System Operator
(CAISO) are the TO/TOPs for the interconnection of Lewis Substation to the BES,
including the protection system that de-energizes both Anaheim buses using SCE owned
breakers without interrupting any BES transmission lines. The 220kV system owned and
operated by the City of Anaheim is radial to the BES at Lewis Substation and feeds a
69kV sub-transmission system through three 220kV/69kV transformer banks. Anaheim is
able to reliably serve 100% of its load using only three of the four banks at Lewis;
however, to improve reliability within Anaheim, in 2008 Anaheim built a redundant
substation (Vermont Substation) 1.5 miles from Lewis, which is connected via a 220kV
transmission line. This line is not needed to maintain BES or Anaheim system reliability
because it is in parallel with four (4) 69kV lines, which also connect Lewis to Vermont.
Its only purpose is to provide backup transformation should there be a catastrophic failure
of the Lewis transformer banks. Pursuant to an SCE-Anaheim operating order only three
transformer banks may be in service at any time to limit short circuit duty, so the banks at
Vermont are truly redundant.
Transmission elements serving radial load, radial distribution systems, or non-GO/GOP
generation connected to such radial lines and excluded from BES. To eliminate reliability
gaps, such radial transmission elements should be classified as "Distribution" equipment
subject to DP standards, and the PRC and vegetation management standards should be
made applicable to Distribution Providers and this equipment. This is consistent with the
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

NERC Reliability Functional Model and is more efficient than requiring TO/TOP
registration for radial transmission facilities that function as Distribution and are not
required for the reliable operation of the BES.
d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how widely
this exclusion should apply, please select, “unknown.”
Continent-wide
Comments relative to the proposed exclusion(s): Transmission elements serving radial
load, radial distribution systems, or non-GO/GOP generation connected to such radial
lines and excluded from BES. To eliminate reliability gaps, such radial transmission
elements should be classified as "Distribution" equipment subject to DP standards, and
the PRC and vegetation management standards should be made applicable to Distribution
Providers and this equipment. This is consistent with the NERC Reliability Functional
Model and is more efficient than requiring TO/TOP registration for radial transmission
facilities that function as Distribution and are not required for the reliable operation of the
BES.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Lorissa Jones, Bonneville Power Administration
Telephone: 360-418-8978
Email: ljjones@bpa.gov
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Those elements or
facilities above 100kV that are shown through engineering studies not to be necessary to
reliably operate an interconnected transmission system.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: An element or facility that is not necessary to reliably operate an
interconnected transmission system need not be included in the BES. This can be
assessed using engineering studies that show the effect of worst-case disturbances on
multiple indicators such as frequency, voltage, system flows, operating limits,
generator tripping, cascading outages and/or islanding with the element or facility
removed from service. If a system can maintain acceptable steady-state and dynamic
performance during and after a worst-case disturbance with the element removed from
service, that element or facility is not necessary to reliably operate the system.
d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how widely
this exclusion should apply, please select, “unknown.”
Interconnection-wide
Region-wide

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

David Burke, Orange and Rockland Utilities
Telephone: 845-577-3076
Email: burkeda@oru.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
All step-down transformers with their low-side terminals operated at below 100 kV.
Radial taps from a BES feeder or bus connection to loads. All elements or facilities
in-series with excluded or exempt elements or facilities -- upstream to a designated
point-of-demarcation with the BES and downstream to the customer meter or
interconnection. For example, upstream from an exempt or excluded feeder to the
upstream-side of the disconnect switch connecting the excluded or exempted feeder
to the BES, or if no disconnect switch is present, to the upstream BES supply-bus
connection. This exclusion or exemption would extend to and also apply to related
equipment, such as circuit switchers, circuit breakers, ground switches, disconnect
switches, busses, etc. that are down-stream of the point-of-demarcation and in the
same circuit with the exempted or excepted feeders and transformers.
Local generation and any facility associated with local generation serving as a load
modifier to local load only. The power generated is demonstrated to be consumed
locally and does not flow back into the BES. The operation (or loss) of the local
generation and/or associated facilities does not materially impact any BES
transmission facilities. If a local generator functions as a load modifier, and does not
materially impact the BES, meaning that it is not necessary to maintain BES
reliability, then it should be excluded from the definition of BES under the BES
Exclusion process.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
Not Applicable
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: The FERC Seven Factor test has been shown to be a reliable,
repeatable method for identifying facilities that are local distribution and separating
them from those facilities which perform a transmission function. The indicators of
local distribution in the Commission’s seven-factor test 2 are:

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

1)
2)
3)
4)

Local distribution facilities are normally in close proximity to retail customers;
Local distribution facilities are primarily radial in character;
Power flows into local distribution systems, and rarely, if ever flows out;
When power enters a local distribution system, it is not reconsigned or transported
on to some other market;
5) Power entering a local distribution system is consumed in a comparatively
restricted geographic area;
6) Meters are based at the transmission / local distribution interface to measure flow
into the local distribution system; and
7) Local distribution systems will be of reduced voltage.
1

Ref. FERC Order No. 888 at 31,771 and 31,981, e.g., Promoting Wholesale
Competition Through Open Access Non-Discriminatory Transmission Services
by Public Utilities

d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
X

Continent-wide

X

Unknown

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Jim Case (Entergy), SERC OC Standards Review Group
Telephone: 601-985-2345
Email: jcase@entergy.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
Comments relative to the proposed exclusion(s): We agree

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Thad Ness, American Electric Power
Telephone: 614-716-2053
Email: tkness@aep.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Radial facilities and
elements operating at or above 100 kV, that are connected to only load serving
facilities operated at distribution voltage levels and that include a high side circuit
breaker or circuit switcher should be excluded from the BES classification. While
protective systems themselves are not by default part of the BES, nor should they be
classified as a BES element, the breaker failure schemes associated with the high side
circuit breaker or circuit switcher are part of a Protection System and should comply
with the appropriate standards.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).

Bus 1 (≥ 100 kV)

A

Load (< 100 kV)

c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Facilities such as that described in 1.a. are designed to support only
one way power flow; from the BES to the load. Operation of the high side circuit
breaker or circuit switcher, Device A, removes the transformer from service
interrupting power flow to the load but will not interrupt power flow on the BES nor
effect reliability of the BES. While protective systems themselves are not by default
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

part of the BES, nor should they be classified as a BES element, the breaker failure
scheme associated with Device A has the potential of interrupting BES power flow by
clearing Bus 1. For this reason, the breaker failure scheme is part of a Protection
System and should comply with the appropriate standards.

d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide

Page 35 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Amir Hammad, Constellation Power Source Generation, Inc., Et all
CPSG is filing the comments below on behalf of:
Constellation Energy Group, Inc.
Baltimore Gas & Electric Company
Constellation Energy Commodities Group, Inc.
Constellation Energy Control and Dispatch, LLC
Constellation NewEnergy, Inc. and its affiliates
Constellation Energy Nuclear Group, LLC, 3
Telephone: 410-787-5226
Email:
amir.hammad@constellation.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Constellation believes that
the exclusions mapped out in RFC’s BES definition, as well as the diagrams in
Appendix A of the RFC BES definition would be a good starting point for the standard
drafting team in developing exclusions.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Constellation believes that the exclusions mapped out in RFC’s BES
definition, as well as the diagrams in Appendix A of the RFC BES definition would be a
good starting point for the standard drafting team in developing exclusions.
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: The BES definition in RFC has been vetted through its members and
incorporates the essence of NERC’s BES definition but includes bright lines for its
members to abide by.
RFC Definition of BES:
https://www.rfirst.org/Documents/RFC%20BES%20Definition.pdf
d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how widely
this exclusion should apply, please select, “unknown.”
Continent-wide

3

On November 6, 2009, EDF, Inc. (“EDF”) and Constellation Energy Group, Inc. completed a transaction
pursuant to which EDF acquired a 49.99 percent ownership interest in CENG. CENG was previously a wholly
owned subsidiary of Constellation Energy Group, Inc.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Comments relative to the proposed exclusion(s):
As described in RFC’s BES definition, the following elements should be excluded:
(1) radial facilities connected to load serving facilities or individual generation resources
smaller than 20 MVA or a generation plant with aggregate capacity less than 75 MVA
where the failure of the radial facilities will not adversely affect the reliable steady-state
operation of other facilities operated at voltages of 100 kV or higher and
(2) balance of generating plant control and operation functions (other than protection systems
that directly control the unit itself and step-up transformer); these facilities would
include relays and systems that automatically trip a unit for boiler, turbine,
environmental, and/or other plant restrictions, and
(3) all other facilities operated at voltages below 100 kV.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

William J. Gallagher, Vermont Public Power Supply Authority
Telephone: (802) 839-0562
Email: bgallagher@vppsa.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
This question refers to “exclusions”; we believe, however, that the intent of this
comment form is to elicit feedback on the process for “exemptions.” It is important
to distinguish between the two concepts, as FERC did in Order 743. See, e.g.,
Paragraph 1, which refers to “maintain[ing] a bright-line threshold that includes all
facilities operated at or above 100 kV except defined radial facilities,” as well as to
“establish[ing] an exemption process and criteria” (emphasis added). In other
words, in brief, an “exclusion” is outside of the BES by definition, whereas exempt
Elements are removed on a case-by-case basis by going through a process.
TAPS draws the distinction as follows:
An exclusion is the removal of a category of Elements from the BES definition.
The current BES definition explicitly carves out radials serving only load with one
transmission source. This is a clear example of an exclusion. There is no “exclusion
process” now, nor should there be one in the future; the point of an exclusion is that
the class of excluded Elements can—without any process—be treated like sub-100
kV transmission, in that they are presumed to be non-BES unless a particular
Element is demonstrated, on a case-by-case basis, to be properly included in the BES
(see responses to Questions 5 and 11 in TAPS’ comments on BES definition,
submitted today, and TAPS response to Question 2 below).
An exemption, on the other hand, is a finding that a particular Element, although
nominally part of the BES, does not need to be included in the BES because it is not
necessary for operating an interconnected transmission network.
Because exemptions are less clear-cut than exclusions, each exemption of an
Element needs to be approved by NERC so that the Registered Entity and
compliance authorities have certainty about the Elements with respect to which
compliance is required. In many, perhaps all, cases, this process will likely require a
case-by-case examination of each Element for which an exemption is requested.
TAPS responds to this question with respect to the one “exclusion” from the
BES definition that we advocate, that of radial Transmission Elements serving only
load and/or generation not registered pursuant to the Statement of Compliance
Registry Criteria. We also propose uniform criteria for deciding, on a case-by-case
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

basis, whether to grant requested exemptions from the BES, or to include nominally
non-BES Elements in the BES. The process that we propose for exemption requests
and proposed inclusions is discussed below in response to the invitation of
“[c]omments relative to the proposed exclusion(s).”
Exclusion:
TAPS proposes only one exclusion from the BES definition, namely, “Radial
Transmission Elements serving only load with one Transmission source are
generally not included in this definition. A radial Transmission Element may be
considered as ‘serving only load’ for purposes of the foregoing general exclusion
even if it connects generation, so long as that generation is not registered pursuant to
the Statement of Compliance Registry Criteria.” This formulation, which is
discussed in TAPS’ comments submitted today on the BES definition, is intended to
preserve the current exclusion of radials serving only load with one transmission
source, and to clarify that the presence of a generator that is not registered under the
Compliance Registry Criteria does not convert a radial into a BES Element. The end
result is that radial transmission is excluded unless it connects generation that is
registered pursuant to the Statement of Compliance Registry Criteria. Consistent
with the Compliance Registry Criteria, a single generator under 20 MVA, or a plant
under 75 MVA, if not designated as a Blackstart Resource needed for system
restoration, is unlikely to affect the grid. Therefore, the presence of such generation
should not require that an otherwise non-BES radial be included in the BES.
Rooftop photovoltaic cells, for example, are increasingly common. If TAPS’
proposed clarification is not accepted, the presence of such insignificant generation
could nullify the exclusion of radials to load with one transmission source, with no
benefit to reliability.
Exemption criteria
TAPS has not yet developed a list of criteria that we believe to be exhaustive,
though we emphasize that such a list must be an ultimate goal of this process. We
propose the following criteria as a start:
TAPS proposes that at least two classes of facilities be eligible to request an
exemption:
i.
Elements that are part of a radial “system” originating from a single BES
source serving only load, as in the Florida Keys. Clarifications: a) radial system
means any number of series and/or parallel Elements as long as they all originate
from a single BES source and do not have another BES source; b) “single BES
source” means one BES bus / substation / switching substation at one voltage level,
and c) consistent with TAPS’ proposed exclusion of radials serving only load and
unregistered generation, “serving only load” includes serving generation that is not
registered through the Statement of Compliance Registry Criteria.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

ii.
Elements that are part of a “looped” system that has two transmission
sources primarily for local quality of service to the retail customers supplied by the
looped system in question and is not used for bulk power system flow (e.g., the
transfer distribution factor of flows across the looped system is low, representing a
high impedance path across the looped system). Specific criteria might be: a) a
looped system that participates in less than a 5% of transfer (e.g., 5% or less transfer
distribution factor); and b) that the looped system in question does not limit
transfers.
A radial or looped system to be exempted must meet the following criteria:
1.
The radial or looped system may not contribute to any Category D or C
contingency resulting in: 1) a supply / demand mismatch greater than the largest loss
of source contingency in the Reliability Coordinator area; or 2) an Adverse
Reliability Impact where, if the Element were not involved in those Category D or C
contingencies, those thresholds would not be exceeded.
Studies to determine whether this criterion is met would be conducted in
accordance with TPL-004-0 and TPL-003-0 standards (or corresponding
contingencies in revision to the TPL standards) in the Short Term Planning Horizon.
Although the above criteria are acceptable responses to a Category D contingency,
the concept of the test is to see if a radial or looped system would cause a
significantly worse response to Category C or D contingencies by testing the
contingency with and without the radial or looped system. TAPS believes that such
criteria are good indicators that a radial or looped system should be included in the
BES as it highlights whether the protection systems are important for critical
clearing times, and whether the radial or looped systems can contribute to an
Adverse Reliability Impact in combination with other contingencies;
2.
No portion of the radial or looped system may meet any of the conditions
of Attachment 1 to CIP-002-4;
3.
No portion of the radial or looped system may meet any of the conditions
listed in items B1 to B5 of Attachment B to PRC-023-2;
4.
No portion of the radial or looped system may be a part of, or be a limiting
element of, any Path, Interchange, or Flowgate used in the calculation of ATC in
accordance with standards MOD-028, MOD-029 or MOD-030; and
5.
No portion of the radial or looped system may include a Blackstart
Resource or cranking path deemed significant to the TOP or RC restoration plans of
EOP-005, EOP-006 or EOP-007.
If a Registered Entity demonstrates to NERC that an Element that is nominally in
the BES meets all of these criteria, the exemption would be granted.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Conversely, if NERC demonstrates that a nominally non-BES Element meets the
negative of any of these criteria (e.g., if any portion of the radial or looped system
meets any of the conditions of Attachment 1 to CIP-002-4 or of Attachment B to
PRC-023-2), the Element would be included in the BES.
Throughout these comments, TAPS refers to “Elements” and not to “facilities.”
This is because “Facility” is defined in the NERC Glossary as “[a] set of electrical
equipment that operates as a single Bulk Electric System Element…” Because these
comments (and the BES definition) address whether Elements are or are not part of
the BES, it is incorrect to refer to the Elements in question as “Facilities,” because a
Facility is defined as a BES Element.
In developing the exemption/inclusion criteria and process, NERC and the SDT
should bear in mind the requirement of Order 743: “NERC should develop an
exemption process that includes clear, objective, transparent, and uniformly
applicable criteria for exemption of facilities that are not necessary for operating the
grid.” Paragraph 115 (emphasis added). NERC and the SDT should also bear in
mind that FERC anticipates that between the BES definition and the exemption
process, there will be only “minimal[]” effect on “small entities.” Order 743,
Paragraph 169. Order 743 is referring to the Small Business Act definition of a
“small electric utility” as one that has a total electric output of less than four million
MWh in the preceding year. See March 18, 2010 BES Notice of Proposed
Rulemaking, Paragraph 35 & footnote 50.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Radial Transmission Elements serving only load have been
recognized for years as non-BES because such Elements are very unlikely to affect
the BES. FERC stated in Order 743 that NERC may retain that exclusion.
Similarly, generators under 20 MVA and generating plants under 75 MVA are not
subject to registration pursuant to the Statement of Compliance Registry Criteria,
which has been accepted by FERC, because of the recognition that such generators
are very unlikely to affect the BES. It is thus consistent with the Compliance
Registry Criteria to exclude from the BES definition radials serving load with one
transmission source even if there is some generation on the radial, so long as none of
the generation is registered. If the generation is not significant enough to be
registered, it is not significant enough to transform an otherwise non-BES radial to
load into a BES Element.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Continent-wide
The exclusion of radials to load and unregistered generation, as part of the BES
definition, should apply on a continent-wide basis.
Each Element proposed for exemption or inclusion should be considered
individually, under the same criteria (proposed above), applied uniformly continentwide.
Comments relative to the proposed exclusion(s):
Exemption and Inclusion Processes:
The exemption and inclusion processes should be designed to ensure continentwide uniformity to the maximum extent possible. To that end, NERC must use a
uniform process; the criteria for approving or denying an exemption, or for including
an Element in the BES, must be clear; and entities must be able to appeal decisions
to another body within NERC or to FERC.
In order to obtain an exemption, a Registered Entity should be required to
demonstrate that the Element for which it is requesting an exemption is not
“necessary for operating an interconnected electric transmission network.” This is
the standard set out in Order 743 (e.g., Paragraph 1); it is also part of the definition
of the “bulk-power system” in Section 215 of the Federal Power Act, 16 U.S.C.
§ 824o(a)(1)(A). Application of this standard should be informed by the statutory
definitions of “reliability standard” (“a requirement, approved by the Commission
under this section, to provide for reliable operation of the bulk-power system,”
16 U.S.C. § 824o(a)(3)) and “reliable operation” (“operating the elements of the
bulk-power system within equipment and electric system thermal, voltage, and
stability limits so that instability, uncontrolled separation, or cascading failures of
such system will not occur as a result of a sudden disturbance, including a
cybersecurity incident, or unanticipated failure of system elements,” 16 U.S.C.
§ 824o(a)(4)).
Conversely, to include a nominally non-BES Element in the BES, NERC should
be required to demonstrate that the Element is necessary for operating an
interconnected electric transmission network.
Criteria for determining whether an Element is or is not “necessary for operating
an interconnected electric transmission network” are proposed in response to
Question 1(a) above. The criteria should be uniform continent-wide, though they
will be applied to each Element on a case-by-case basis.
Exemption requests and proposed inclusions should be decided by NERC staff in
the first instance. TAPS does not believe that the exemption and inclusion processes
should be delegated to the Regional Entities. In Order 743, FERC emphasized the
need for continent-wide uniformity; in fact, it was inconsistency among regions that
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

prompted Order 743. TAPS members’ experience with Regional registration
processes suggests that Regional implementation of the BES exemption and
inclusion processes is unlikely to yield the uniformity that FERC directed.
Furthermore, implementing this FERC directive will unavoidably require significant
personnel resources, either at NERC or at the Regions. Delegating the process to the
Regions would impose additional costs due to the need for NERC to exercise strong
oversight to attempt to maintain uniformity. It may be that after the exemption and
inclusion processes have been in place for a few years and a body of precedent has
been accumulated, delegation will be appropriate. At this time, however, NERC
staff should make the initial decision on all exemption requests and proposed
inclusions.
TAPS proposes, for the sake of consistency with the registration appeal process,
that appeals of decisions on exemptions and inclusions be to the Board of Trustees
Compliance Committee (BOTCC), with further appeals to FERC if necessary.
Appeals to the BOTCC would consist of the record compiled by NERC Staff, and
additional paper submissions by NERC Staff and the Registered Entity
demonstrating why the Element(s) in question is or is not “necessary for operating
an interconnected electric transmission network.” See NERC Rules of Procedure,
Appendix 5A, Organization Registration and Certification Manual at 14-16.
Registered Entities should have the option of requesting a hearing. Hearing
procedures could be modeled on the Compliance and Certification Committee’s
“Hearing Procedures for Use in Appeals of Certification Matters,” in Appendix 4E
of the NERC Rules of Procedure.
TAPS also suggests that decisions on exemptions and inclusions be made
available to others, either subject to CEII protection or in a form suitable for public
release. As precedent develops, Registered Entities will increasingly be able to
judge for themselves the likelihood that a particular exemption will be granted, or
that an appeal of an inclusion will succeed. We expect that giving Registered
Entities more information on which to base their decisions will significantly reduce
the burden on NERC of processing exemptions and inclusions.
We propose that BES Elements for which an exemption request is pending
should continue to be included in the BES until the exemption and any appeals are
decided, and that non-BES Elements for which an inclusion is pending should
continue to be non-BES until the inclusion and any appeals are decided.
The transition process should include an important exception to the general rule
proposed for BES status during the pendency of an exemption request: to allow for a
smooth transition, to the extent that Elements that are currently considered non-BES
become BES under the new definition, those Elements should be permitted to
request exemptions and to continue to be considered non-BES until their exemption
requests and any appeals are decided.

Page 43 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

David Angell, Idaho Power
Telephone: 208-388-2701
Email: daveangell@idahopower.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Non-radial transmission
systems which provide reliable service to load-service substations. There are two
examples where this applies: 1.) The non-radial transmission system serving a metro
area load at 138 kV where 230 kV and higher voltage systems surround the area and
provide the bulk electric system transfer, and 2.) The non-radial transmission loops
that serve rural area load at 138 kV that are essentially tangential to the bulk electric
transfer path.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Refer to Attachment 1b.4
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Large load-serving substations require non-radial service to ensure
acceptable reliability performance. Such transmission systems do not carry bulk
power transfers as there are substantial higher voltage transmission lines that
surround the metro area which carry the bulk transfers. Idaho Power has evaluated
serving the area from systems that are sourced from only a single bulk substation.
Such a configuration would result in requiring an additional 100 miles of transmission
to compared to the existing network configuration.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide

Page 44 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Marc M. Butts, Southern Company
Telephone: 205-257-4839
Email: mmbutts@southernco.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
Individual
Generators < 75 MVA; this threshold also needs to be included in the NERC
Compliance Registry Criteria.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification:
Generators less than 75 MVA are not large enough to have a
significant impact on the bulk electric system.. However, aggregate generation that
exceeds 75 MVA should be considered for applications such as wind farms.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Unknown

Page 45 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Andrew Z. Pusztai, American Transmission Company
Telephone: 262-506-6913
Email: apusztai@atcllc.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Exclude transmission
lines that are operated at 100 kV and above that are operationally radial transmission
elements because of a operating restriction that prevents the line from being operated
as a network transmission element.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
The transmission line between Source Line #1 and Sources Line #2 would be a
Network element if the bus-tie circuit breaker was closed, However, Operating
Procedures require the bus-tie circuit breaker to be normally open (N.O.) So, the load
on Bus 1 is served by the radial line segment from Source Line #1 and the load on
Bus 2 is served by the radial line segment from Source Line #2.

Page 46 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011
To Distribution Load
13.2-kV

13.2-kV

60 MVA

60 MVA

T2

T1

Distribution
Substation

138-kV
Bus 2

138-kV Source Line #2

N.O.

Bus 1

138-kV Source Line #1

c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Although the transmission element (line) between network Source #1
and network Source #2 could be a network element if the bus-tie breaker is closed,
the two line sections are normally operated as two different radial elements. So, the
radial Transmission Element exclusion should apply.

Page 47 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Ronald Sporseen, PNGC Power, Et all
Email: RSporseen@pngcpower.com
Supporters of the following comments are as follows:
Bud Tracy, Blachly-Lane Electric Cooperative
Dave Hagen, Clearwater Power Cooperative
Dave Sabala, Douglas Electric Cooperative
Heber Carpenter, Raft River Rural Electric Cooperative
Dave Markham, Central Electric Cooperative
Jon Shelby, Northern Lights, Inc.
Ken Dizes, Salmon River Electric Cooperative
Ray Ellis, Okanogan County Electric Cooperative
Richard Reynolds, Lost River Electric Cooperative
Rick Crinklaw, Lane Electric Cooperative
Roger Meader, Coos-Curry Electric Cooperative
Roman Gillen, Consumer’s Power Inc.
Steve Eldrige, Umatilla Electric Cooperative
Marc Farmer, West Oregon Electric Cooperative
Michael Henry, Lincoln Electric Cooperative
Bryan Case, Fall River Electric Cooperative
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
•

Radial lines

•

Local distribution networks, generators, generation plants, loads, transformers,
reactive devices, and protection and control system found to not cause adverse
reliability impacts on neighboring bulk system Elements and Facilities using a
performance-based exclusion process.

b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
Assuming FERC continues to insist upon a 100kV “bright line” definition, we
support a process to exclude systems operating at 100kV and above that do not cause
adverse reliability impacts on the neighboring bulk transmission system. For
facilities operating at 100kV or above, the exclusion process should allow exclusion
of those elements that, using a performance-based assessment, are demonstrated to
operate without causing adverse reliability impacts on neighboring bulk system.

Page 48 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: The ultimate goal of the Reliability Standards process should be to
achieve reliable operation of the bulk transmission system, as defined by Congress.
The term “reliable operation” was a term specifically defined in FPA Section 215 to
include standards assuring the operation of bulk transmission system elements
“within equipment and electric system thermal, voltage, and stability limits so that
instability, uncontrolled separation, or cascading failures of such system will not
occur as a result of a sudden disturbance. . . or unanticipated failure of system
elements.” 16 U.S.C. § 825o(a)(4). Congress specifically precluded the mandatory
reliability system from enforcing standards for adequacy of service, which were left
to state and local authorities. 16 U.S.C. § 825o(i)(2).
Recognizing that Congress intended the mandatory reliability regime to focus on
thermal, voltage, and stability limits on the bulk system rather than more generally on
levels of service to retail customers, the Standards Development Team should define
the Bulk Electric System to include only those facilities whose failure or misoperation meaningfully threatens to produce instability, uncontrolled separation, or
cascading failures on the bulk system. As a legal matter, expanding the definition to
include local distribution facilities and facilities that do not threaten thermal, voltage
or stability impacts on the bulk system exceeds the permissible scope of NERC
Reliability Standards and FERC authority under FPA Section 215. As a practical
matter, mandating adherence to Reliability Standards for facilities, or equipment, that
do not cause adverse reliability impacts on the neighboring bulk system is a
significant diversion of funds and resources that will produce little or no benefits in
terms of improved reliability of the bulk system.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Comments relative to the proposed exclusion(s): The WECC Bulk Electric System
Definition Task Force (“BESDTF”) has carefully considered and provided an extensive
record of technical support for excluding Radial Facilities and Local Distribution
Networks from the BES. While we recognize that physical differences between the
electric system in WECC and other reliability regions may justify different approaches in
those regions, we commend the work of the BESDTF to the standard drafting team.

Page 49 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Jerome Murray, Oregon Public Utility Commission
Telephone: 503-378-6626
Email: Jerry.murray@state.or.us
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a . Identify the Element or Facility recommended for exclusion: An element or facility
that is not necessary to reliably operate an interconnected transmission system need
not be included in the BES
b.
c.

Provide a generic one-line diagram depicting the Element or Facility in question (if available).
Provide a technical justification for the exclus ion (provide justification here or attach a supplemental document or URL lin k to p ublicly pos ted document if available).

Justification:

d . Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Comments relative to the proposed exclusion(s): This should be assessed first using
engineering-based inspection (or screening) methodologies for 100 kV to 200 kV subtransmission elements to determine obvious exclusions from the BES. For questionable
sub-transmission elements, engineering-based studies evaluating worst-case scenarios need
to be performed to establish exclusion from the BES.
The thresholds associated with screening methodologies and worst-case studies may vary
between interconnections and regions. For example, voltage deviation may be more
relevant in the Western Interconnection (which is primarily stability limited) than in the
Eastern Interconnection (which is primarily thermally limited).

Page 50 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

John D. Martinsen , Public Utility District No. 1 of Snohomish County
Telephone: 425-783-8080
Email: jdmartinsen@snopud.com

1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a . Identify the Element or Facility recommended for exclusion:

•

Radial lines

•

Local distribution networks, generators, generation plants, loads,
transformers, reactive devices, and protection and control system found to
not cause adverse reliability impacts on neighboring bulk system Elements
and Facilities using a performance-based exclusion process.

b . Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Assuming FERC continues to insist upon a 100-kV “bright line”
definition, SNPD supports a process to exclude systems operating at 100 kV and
above that do not cause adverse reliability impacts on the neighboring bulk
transmission system. For facilities operating at 100 kV or above, the exclusion
process should allow exclusion of those elements that, using a performance-based
assessment, are demonstrated to operate without causing adverse reliability impacts
on neighboring bulk system.
Provide a technical justification for the exclusion (provide justification here or
attach a supplemental document or URL link to publicly posted document if
available).
Justification: The ultimate goal of the Reliability Standards process should be to achieve

reliable operation of the bulk transmission system, as defined by Congress. The term
“reliable operation” was a term specifically defined in FPA Section 215 to include
standards assuring the operation of bulk transmission system elements “within equipment
and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden
disturbance. . . or unanticipated failure of system elements.” 16 U.S.C. § 824o(a)(4).
Congress specifically precluded the mandatory reliability system from enforcing
standards for adequacy of service, which were left to state and local authorities. 16
U.S.C. § 824o(i)(2).
Recognizing that Congress intended the mandatory reliability regime to focus on thermal,
voltage and stability limits on the bulk system rather than more generally on levels of
service to retail customers, the Standards Development Team should define the Bulk
Page 51 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Electric System to include only those facilities whose failure or mis-operation
meaningfully threatens to produce instability, uncontrolled separation, or cascading
failures on the bulk system. As a legal matter, expanding the definition to include local
distribution facilities and facilities that do not threaten thermal, voltage or stability
impacts on the bulk system exceeds the permissible scope of NERC Reliability Standards
and FERC authority under FPA Section 215. As a practical matter, mandating adherence
to Reliability Standards for facilities that do not cause adverse reliability impacts on the
neighboring bulk system is a significant diversion of funds and resources that will
produce little or no benefits in terms of improved reliability of the bulk system.

c . Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide

Comments relative to the proposed exclusion(s): The WECC Bulk Electric System
Definition Task Force (“BESDTF”) has carefully considered and provided an extensive
record of technical support for excluding Radial Facilities and Local Distribution Networks
from the BES. While we recognize that physical differences between the electric system in
WECC and other reliability regions may justify different approaches in those regions, we
commend the work of the BESDTF to the standard drafting team.

Page 52 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

Steve Alexanderson P.E., Central Lincoln
Telephone: 541-574-2064
Email: salexanderson@cencoast.com

1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a . Identify the Element or Facility recommended for exclusion: All the SS_ 115 kV
buses in the attached one-lines as well as the connecting lines should be excluded
from consideration since they are radial serving load. Additional facilities may be put
through the exclusion process, and excluded if shown not to be needed for “reliable
operation” as defined in 16 U.S.C. § 824o(a)(4).
b . Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Refer to Attachment 1b.10 & 1b.11
c . Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: These SS_ facilities in the diagram are operated radially and are used to
distribute energy locally. The FPA specifically excludes “facilities used in the local
distribution of electric energy” (16 U.S.C. § 824o(a)(1)) and prohibits FERC from
enforcing standards for adequacy of service (16 U.S.C. § 824o(i)(2)). In addition, any
faults or failures in these facilities will only affect the local area, and not cause instability,
uncontrolled separation, or cascading outages (16 U.S.C. § 824o(a)(4)). These facilities
should be excluded by inspection, and should not be required to go through an exemption
process.
d . Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
X Continent-wide
Comments relative to the proposed exclusion(s): The two diagrams illustrate the
overreaching approach that WECC is presently using. Documents on the RFC web site
prove that the WECC approach is not at all universal.
The SS2 bus is presently considered by WECC to be BES because it has two
transmission sources, NON-RADIAL SUB 1 and NON-RADIAL SUB 3, even though
the K9-5 at SS3 is normally open. WECC considers any possible second source
regardless of the system is operated. Any faults at SS3 or in the supplying lines will result
only in a local outage. We hope the SDT will consider actual operating conditions when
it defines “radial” and “one transmission source.”
Page 53 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
January 27, 2011

The 115 kV bus at SS6 is considered by WECC to be BES because it has two
transmission sources, one by way of NON-RADIAL SUB 4 and the other by way of
NON-RADIAL SUB 5 (off the one-line to the right). We don’t think that is what NERC
meant by “transmission source.” A fault on the SS6 bus would result in a local outage
affecting only the four substations tapped off the NON-RADIAL SUB 4/SUB 5 line. We
assume that if the risk of such an outage was unacceptable, the serving transmission
company would have required protection at the tap points. We hope the SDT will
properly clarify what is meant by a transmission source.
All the SS 115 kV buses shown also have multiple transmission sources by way of
normally open tie switches on the 12.47 kV system. Again we hope the SDT will
consider operating philosophies when defining “radial” and “one transmission source.”
All the substation transformers in the diagrams are considered by WECC to be BES
because one winding exceeds 100 kV. We understand the SDT properly intends to look at
the lowest voltage winding rather than the highest.
Except for the fuses at SS8, all the SS transformer protection systems are considered by
WECC to be BES subject to PRC-005. This is not because the transformers are
considered to BES, but because relay operation results in tripping a circuit switcher that
exceeds 100 kV. We expect the SDT will properly consider the zone of protection rather
than the voltage of the interrupting device.
Please also consider the 115 kV lines joining the NON-RADIAL SUBs in the two
diagrams. While most of them cannot be considered to be radial with one transmission
source, they are not used to transport bulk power. Their purpose is the local distribution
of power. Parallel 230 kV lines (not shown in the diagrams) are responsible for the bulk
power transport. The WECC Bulk Electric System Definition Task Force has been
working on a definition of “local distribution networks” that would properly classify the
115 kV lines as non-BES. We hope the SDT will look at the work the BESDTF has done.

Page 54 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Question 2:
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion:
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or
attach a supplemental document or URL link to publicly posted document if
available).
d. Identify if this inclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this inclusion should apply, please select, “unknown.”
Commenters:
Michael Moltane and John Zipp, ITC Holdings ............................................................................ 3
Frank Gaffney, Florida Municipal Power Agency, Et all .............................................................. 4
Brandy A. Dunn, Western Area Power Administration ................................................................. 7
Alain Pageau, Hydro-Québec TransÉnergie .................................................................................. 8
Guy Zito, Northeast Power Coordinating Council ......................................................................... 9
Jim UhrinReliabilityFirst Corporation ......................................................................................... 11
Joe Petaski, Manitoba Hydro ....................................................................................................... 12
John W.Delucca, Lee County Electric Cooperative ..................................................................... 13
Paul Cummings, City of Redding ................................................................................................ 14
Patrick Farrell, Southern California Edison Company................................................................. 15
Manny Robledo, City of Anaheim ............................................................................................... 17
Lorissa Jones, Transmission Reliability Program Manager ......................................................... 18
David Burke, Orange and Rockland Utilities............................................................................... 19
Alice Ireland, Xcel Energy ........................................................................................................... 20
Amir Hammad, Constellation Power Source Generation, Inc., Et all .......................................... 21
Page 1 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

William J. Gallagher, Transmission Access Policy Study Group ................................................ 22
Marc M. Butts, Southern Company ............................................................................................. 23
Ronald Sporseen, PNGC Power, Et all ........................................................................................ 24

Page 2 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Michael Moltane and John Zipp, ITC Holdings
Telephone: 248-946-3093
Email: mmoltane@itctransco.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
Comments relative to the proposed inclusion(s): Again it is unclear what is meant by
Region wide when talking about an element inclusion. It is important that this be tied to the
PRC023 “Critical Element” definition/test. Why would I apply for an element inclusion
when there is no definition of what is required for the element to be included?

Page 3 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Frank Gaffney, Florida Municipal Power Agency, Et all
Florida Municipal Power Agency is filing the comments below on behalf of its’ project
participants:
City of New Smyrna Beach
KUA
Lakeland Electric
City of Clewiston
Beaches Energy Services
Ocala Electric Utility
Telephone: 407-355-7767
Email: frank.Gaffney@fmpa.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion:
FMPA’ proposed criteria for inclusion are listed above in response to Question 1(a).
As stated above, there should be no “generic” or “categorical” inclusions. Inclusions,
like exemptions, should be considered on a case-by-case basis. The criteria by which
proposed inclusions or requested exemptions are judged, however, should be uniform
across the continent.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Comments relative to the proposed inclusion(s): This question appears to assume that
all inclusions in the BES will be categorical, rather than case-by-case. This is
inappropriate. Inclusions, like exclusions, should involve case-specific consideration of
the uniform, continent-wide criteria.
The inclusion process should be the mirror image of the exemption process: it is NERC,
rather than the Registered Entity, who initiates the process, and the burden is on NERC to
demonstrate that the Element to be included is “necessary for operating an interconnected
electric transmission network.” The processes should otherwise be identical: the initial
determination should be made by NERC staff, with appeals to the Board of Trustees
Compliance Committee, and to FERC if necessary. The proposed process is discussed in
more detail in response to Question 1 above.

Page 4 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Michelle Mizumori, Western Electricity Coordinating Council
Telephone: 801-819-7624
Email: mmizumori@wecc.biz
3. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Elements or
Facilities that are shown through engineering studies to be necessary to reliably
operate an interconnected bulk electric system.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or
attach a supplemental document or URL link to publicly posted document if
available).
Justification: An element or facility that is necessary to reliably operate an
interconnected transmission system should be included in the BES. This can be
measured using engineering studies that show the effect of worst-case
disturbances on multiple indicators such as frequency, voltage, system flows,
operating limits, generator tripping, cascading outages, and/or islanding. If the
system cannot maintain acceptable steady-state and dynamic performance with a
disturbance at the element, it is necessary to reliably operate the system.
d. Identify if this inclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Comments relative to the proposed inclusion(s): While operating voltage (i.e., the
proposed 100 kV bright-line) may be a clear and repeatable proxy for identifying
those elements that are necessary to reliably operate an interconnected transmission
system, it is a broad approach that may not adequately address specific examples.
Moreover, engineering studies can be used to more granularly and accurately identify
such elements that are needed to reliably operate an interconnected transmission
system.
The thresholds on the indicators listed above may vary between interconnections and
regions. For example, voltage deviation may be more relevant in the Western
Page 5 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Interconnection (which is primarily stability limited) than in the Eastern
Interconnection (which is primarily thermally limited).

Page 6 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Brandy A. Dunn, Western Area Power Administration
Telephone: 720-962-7431
Email: dunn@wapa.gov
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Any Element above
100-kV that is shown (through system studies) to be necessary to reliably operate the
interconnected transmission system.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: An Element that is required to reliably operate the interconnected
transmission system should be included in the BES. This can be assessed through
engineering system studies that show the worst-case results based on indicators such
as voltage, frequency, OTC limits, angular instability and/or cascading outages based
on that Element being removed from service. If the system cannot maintain
acceptable performance without that Element, it is necessary to reliably operate the
interconnected transmission system.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Comments relative to the proposed inclusion(s): While a brightline test voltage (such
as the proposed >100-kV) may be a clear and repeatable proxy for identifying Elements
that are necessary to reliably operate the interconnected transmission system, this broad
approach may not adequately address specific examples. Engineering system studies can
accurately identify Elements which are not needed to reliably operate the interconnected
transmission system.

Page 7 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Alain Pageau, Hydro-Québec TransÉnergie
Telephone: 514 879-4100 #5414
Email: pageau.alain@hydro.qc.ca
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Common
interconnection between the two jurisdictions.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Common rules should applied to the common elements.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide

Page 8 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Guy Zito, Northeast Power Coordinating Council
Telephone: 212-840-1070
Email: gzito@npcc.org
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Transmission facilities
as determined to be necessary for reliability to the bulk electric system. Common
interconnections between two or more areas.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: The exemption process should allow for a registered entity to submit the
results of an objective, impact based assessment evaluation in support of its application
for exemption of facilities that would otherwise be classified as part of the BES. This
assessment process, when consistently applied in a non-arbitrary manner, would yield
results that demonstrate that the facilities for which the exemption is being sought do
not impact the BES whenever they are removed from service.
Any regional or registered entity can present technical studies to NERC for
consideration of the expansion of the Bulk Electric System. The primary consideration
by NERC Staff for inclusion must be that the addition of these recommended facilities
bring a measurable (not subjective) incremental reliability benefit to real-time grid
operations. Common rules should apply to elements common to the interconnections
between two or more areas.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Less than Region-wide
Comments relative to the proposed inclusion(s): Registered Entities must retain the
right to appeal any decisions with direct implications to their facilities. Broad
applications of “included facilities” could result in the designation of facilities, the
Page 9 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

inclusion of which is not warranted. Registered Entities need the right to seek exemption
when broad new inclusions are applied.

Page 10 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Jim Uhrin

ReliabilityFirst Corporation

Telephone: 330.247.3058
Email: jim.uhrin@rfirst.org
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Those facilities that
trip and lockout a BES facility at anytime must be included.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).

In the diagram above, the distribution transformer operated below 100 kV without a
high-side interrupting device and connected to the BES that does or could trip and
lockout a BES facility should be included since there is no way to isolate the transformer
without tripping/locking out another BES facility. However, if radial equipment has
sectionalizing (such as a high-side ground switch or circuit switcher) that prohibits its
operation from or does not trip and lockout a BES facility for any reason and therefore
could not affect operation of the BES, those facilities could also be excluded.
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: If the facility trips and lockouts a BES facility, then it should be
included as a part of the BES.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide

Page 11 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Joe Petaski, Manitoba Hydro
Telephone: 204-487-5332
Email: jpetaski@hydro.mb.ca
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
Comments relative to the proposed inclusion(s): No comment but there should be no
regional differences in the BES definition or in the BES definition exemption process.

Page 12 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

John W.Delucca, Lee County Electric Cooperative
Telephone: 239-656-2190
Email: john.delucca@lcec.net
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: No specific element
proposed.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: The only reason a lower voltage should be considered for inclusion is
if, under normal operating conditions, loss of these elements has a significant
reliability impact upon the BES
Comments relative to the proposed inclusion(s): Only where and if a rare case of BES
impact exists.

Page 13 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Paul Cummings, City of Redding
Telephone: 530-245-7016
Email: pcummings@ci.redding.ca.us
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Those elements or
facilities operated b elow 100kV that are shown through engineering studies to be
necessary to reliably operate an interconnected transmission system. See Attachment
1below.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
Refer to Attachment 1b.5
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: “The impact an Element has on the BES shall be determined by
assessing the performance of key measures of BES reliability through power flow,
post-transient, and transient stability analysis with (1) the system, and the Subject
Element, operating at reasonably stressed conditions that replicate expected system
conditions under which the loss of the Subject Element would have the greatest
impact on the key measures of reliability, and (2) the Subject Element removed from
service, but without allowing for system readjustment.”
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide

Page 14 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Patrick Farrell, Southern California Edison Company
Telephone: 626-302-1321
Email: Patrick.Farrell@sce.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Elements or Facilities
that are shown through engineering studies to be necessary to reliably operate an
interconnected bulk electric system may need to be included even if operated at
voltages below 100kV. Additionally, there are transmission facilities at 100kV and
above that are radial in nature and used for load serving purposes that are not parallel
to interconnected transmission systems. As an example, in SCE’s system the Valley
115kV system is radial in nature and the power flow is generally from 500kV to
115kV to serve load.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: An element or facility that is necessary to reliably operate an
interconnected transmission system should be included in the BES. This can be
measured using engineering studies that show the effect of worst-case disturbances on
multiple indicators such as frequency, voltage, system flows, operating limits,
generator tripping, and cascading outages and/or islanding. If the system cannot
maintain acceptable steady-state and dynamic performance without the subject
element in service, that element is necessary to reliably operate the system.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
X Continent-wide
X Interconnection-wide
X Region-wide
Comments relative to the proposed inclusion(s): While operating voltage (i.e. the
proposed 100kV bright-line) may be a clear and repeatable proxy for identifying
those elements that are necessary to reliably operate an interconnected transmission
system, it is a broad approach that may not adequately address specific examples.
Engineering studies can be used to more granularly and accurately identify elements
which are not needed to reliably operate an interconnected transmission system.
Page 15 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

The thresholds on the indicators listed above may vary between interconnections and
regions. For example, SCE’s system has facilities rated at the 115kV level that are
radial in nature for load serving purposes. Therefore, applying a 100kV bright-line
may unnecessarily bring facilities that could be excluded through an engineering
study.

Page 16 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Manny Robledo, City of Anaheim
Telephone: 714-765-5107
Email: mrobledo@anaheim.net
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
Comments relative to the proposed inclusion(s): Anaheim’s sub-transmission system is
operated at 69kV and is radial to the BES with one transmission source. There is no
transmission through Anaheim, and there are no generators connected to Anaheim’s
distribution system that are required for the reliable operation of the BES.

Page 17 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Lorissa Jones, Transmission Reliability Program Manager
Telephone: 360-418-8978
Email: ljjones@bpa.gov
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Elements or Facilities
that are shown through engineering studies to be necessary to reliably operate an
interconnected bulk electric system. Balancing Authorities need to have the authority
to recommend inclusion on a facility by facility basis based on impact to the larger
BES considerations for registration.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: An element or facility that is necessary to reliably operate an
interconnected transmission system should be included in the BES. This can be
measured using engineering studies that show the effect of worst-case disturbances on
multiple indicators such as frequency, voltage, system flows, operating limits,
generator tripping, cascading outages and/or islanding. If the system cannot maintain
acceptable steady-state and dynamic performance without the subject element in
service, it is necessary to reliably operate the system.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Interconnection-wide
Region-wide
Comments relative to the proposed inclusion(s): While operating voltage (i.e. the
proposed 100 kV brightline) may be a clear and, repeatable proxy for identifying those
elements that are necessary to reliably operate an interconnected transmission system, it
is a broad approach that may not adequately address specific examples. Moreover
engineering studies can be used to more granularly and accurately identify such
elements which are needed to reliably operate an interconnected transmission system.

Page 18 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

David Burke, Orange and Rockland Utilities
Telephone: 845-577-3076
Email: burkeda@oru.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Transmission facilities
as determined to be necessary for reliability to the bulk electric system.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Any regional or registered entity can present technical studies to
NERC for consideration of the expansion of the Bulk Electric System. The primary
consideration by NERC Staff for inclusion must be that the addition of these
recommended facilities bring a measurable (not subjective) incremental reliability
benefit to real-time grid operations.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
X

Continent-wide

X

Interconnection-wide

X

Region-wide

X

Less than Region-wide

Comments relative to the proposed inclusion(s): Registered Entities must retain the
right to appeal any decisions with direct implications to their facilities. Broad
applications of “included facilities” could result in the designation of facilities, the
inclusion of which is not warranted. Registered Entities need the right to seek exemption
when broad new inclusions are applied.

Page 19 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Alice Ireland, Xcel Energy
Telephone: 303-571-7868
Email: alice.murdock@xcelenergy.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
d. Identify if this inclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this inclusion should apply, please select, “unknown.”
Unknown
Comments relative to the proposed inclusion(s): The scenario below should be
considered and worked through as part of the development of the definition and
exemptions. As stated in questions 2, 3, 8 of the BES definition comment questionnaire
it is unclear as to how treatment of facilities would occur, especially if there are
multiple/separate owners of each wind farm, even thought they aggregate to a common
bus that connects to the transmission system. Treatment of the bus and breakers between
each wind farm and the transformer also needs to be contemplated and addressed in the
definition or exclusion process.

Page 20 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Amir Hammad, Constellation Power Source Generation, Inc., Et all
CPSG is filing the comments below on behalf of:
Constellation Energy Group, Inc.
Baltimore Gas & Electric Company
Constellation Energy Commodities Group, Inc.
Constellation Energy Control and Dispatch, LLC
Constellation NewEnergy, Inc. and its affiliates
Constellation Energy Nuclear Group, LLC, 1
Telephone: 410-787-5226
Email: amir.hammad@constellation.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Constellation believes
that the drafting team should incorporate the inclusions found in the Compliance
Registration criteria that have been excluded by the proposed BES definition. RFC
has adopted this approach in their BES definition.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Comments relative to the proposed inclusion(s): Constellation does not believe that there
are any Transmission or Generation Elements or Facilities operated at voltages below 100kV
that should be considered for inclusion in the Elements and Facilities classified as part of the
BES other than those provided for in the Compliance Registration Criteria and echoed in the
RFC BES Definition sited above.

1

On November 6, 2009, EDF, Inc. (“EDF”) and Constellation Energy Group, Inc. completed a transaction
pursuant to which EDF acquired a 49.99 percent ownership interest in CENG. CENG was previously a wholly
owned subsidiary of Constellation Energy Group, Inc.

Page 21 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

William J. Gallagher, Transmission Access Policy Study Group
Telephone: (802) 839-0562
Email: bgallagher@vppsa.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: TAPS’ proposed criteria for
inclusion are listed above in response to Question 1(a). As stated above, there should be
no “generic” or “categorical” inclusions. Inclusions, like exemptions, should be
considered on a case-by-case basis. The criteria by which proposed inclusions or
requested exemptions are judged, however, should be uniform across the continent.
Comments relative to the proposed inclusion(s): This question appears to assume that all
inclusions in the BES will be categorical, rather than case-by-case. This is inappropriate.
Inclusions, like exclusions, should involve case-specific consideration of the uniform,
continent-wide criteria.
The inclusion process should be the mirror image of the exemption process: it is NERC,
rather than the Registered Entity, who initiates the process, and the burden is on NERC to
demonstrate that the Element to be included is “necessary for operating an interconnected
electric transmission network.” The processes should otherwise be identical: the initial
determination should be made by NERC staff, with appeals to the Board of Trustees
Compliance Committee, and to FERC if necessary. The proposed process is discussed in
more detail in response to Question 1 above.

Page 22 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Marc M. Butts, Southern Company
Telephone: 205-257-4839
Email: mmbutts@southernco.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
Comments relative to the proposed inclusion(s): Subpart D should be deleted – any
inclusion should be a specific request for a specific facility, not on a generic Continent-wide,
Interconnection-wide or Region wide-basis.

Page 23 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Ronald Sporseen, PNGC Power, Et all
Email: RSporseen@pngcpower.com
Supporters of the following comments are as follows:
Bud Tracy, Blachly-Lane Electric Cooperative
Dave Hagen, Clearwater Power Cooperative
Dave Sabala, Douglas Electric Cooperative
Heber Carpenter, Raft River Rural Electric Cooperative
Dave Markham, Central Electric Cooperative
Jon Shelby, Northern Lights, Inc.
Ken Dizes, Salmon River Electric Cooperative
Ray Ellis, Okanogan County Electric Cooperative
Richard Reynolds, Lost River Electric Cooperative
Rick Crinklaw, Lane Electric Cooperative
Roger Meader, Coos-Curry Electric Cooperative
Roman Gillen, Consumer’s Power Inc.
Steve Eldrige, Umatilla Electric Cooperative
Marc Farmer, West Oregon Electric Cooperative
Michael Henry, Lincoln Electric Cooperative
Bryan Case, Fall River Electric Cooperative
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: In rare cases, facilities
operating below 100kV should be considered for inclusion in the BES, but only if the
RRO provides clear evidence that such facilities threaten to cause instability,
uncontrolled separation, or cascading outages on the bulk transmission system if
those facilities are not included as part of the BES.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: As discussed above, the ultimate goal of the standards drafting process
must be to ensure the reliable operation of the bulk transmission system, so that the
risks of instability, uncontrolled separation, and cascading outages on the bulk system
are reduced. In rare cases, it is possible that facilities operating at voltages below
100kV may create risks of this kind to the bulk system. However, caution should be
used when identifying parallel lower voltage systems that reduce transfers on higher
voltage systems as reliability concerns. In many cases these concerns are commercial
in nature and the burden to resolve these capacity issues should be placed on the TSP.

Page 24 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Comments relative to the proposed inclusion(s): The BESDTF has developed an approach in
which certain facilities operating at voltages below 100kV would be included in the BES, but
facilities not falling within these specific, defined categories would not be included in the
BES unless the RRO could demonstrate that the facility creates a material impact threatening
the reliable operation of the bulk interconnected system. We believe this is a sensible
approach to this question.

Page 25 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

John D. Martinsen, Public Utility District No. 1 of Snohomish County
Telephone: 425-783-8080
Email: jdmartinsen@snopud.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a . Identify the Element or Facility recommended for inclusion:
In rare cases, facilities operating below 100 kV should be considered for inclusion in
the BES, but only if the RRO provides clear evidence that such facilities threaten to
cause instability, uncontrolled separation, or cascading outages on the bulk
transmission system if those facilities are not included as part of the BES.
b . Attach a generic one-line diagram depicting the Element or Facility (if available).
c . Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: As discussed above, the ultimate goal of the standards drafting process must

be to ensure the reliable operation of the bulk transmission system, so that the risks of
instability, uncontrolled separation, and cascading outages on the bulk system are
reduced. In rare cases, it is possible that facilities operating at voltages below 100 kV
may create risks of this kind to the bulk system. However, caution should be used
when identifying parallel lower voltage systems that reduce transfers on higher
voltage systems as reliability concerns. In many cases these concerns are commercial
in nature and the burden to resolve these capacity issues should be placed on the TSP.
d . Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide

Comments relative to the proposed inclusion(s): The BESDTF has developed an approach
in which certain facilities operating at voltages below 100-kV would be included in the BES,
but facilities not falling within these specific, defined categories would not be included in the
BES unless the RRO could demonstrate that the facility creates a material impact threatening
the reliable operation of the bulk interconnected system. We believe this is a sensible
approach to this question.

Page 26 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
January 27, 2011

Steve Alexanderson P.E., Central Lincoln
Telephone: 541-574-2064
Email: salexanderson@cencoast.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: This burden would be
on the Regional Entity rather than the Registered Entity. Facilities that are not radial
serving only load may be put through an inclusion process (similar to, but with the
opposite effect of the exclusion process) to determine if they are needed for “reliable
operation” as defined in 16 U.S.C. § 824o(a)(4).
b.
c.

Attach a generic one-line diagram depicting the Element or Facility (if available). None.
Provide a technical justification for the exclus ion (provide justification here or attach a supplemental document or URL lin k to p ublicly pos ted document if available).

d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
X Continent-wide

Page 27 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Question 3:
Please provide any other information that you feel would be helpful to the group
working to develop a BES Definition Exception Process.
Commenters:
John A. Gray, The Dow Chemical Company ................................................................................. 3
Michael Moltane/John Zipp, ITC Holdings .................................................................................... 4
Laura Lee, Duke Energy ................................................................................................................. 5
Michelle Mizumori, Western Electricity Coordinating Council..................................................... 6
Brandy A. Dunn, Western Area Power Administration ................................................................. 7
Alain Pageau, Hydro-Québec TransÉnergie ................................................................................... 8
Guy Zito, Northeast Power Coordinating Council ......................................................................... 9
Jim UhrinReliabilityFirst Corporation .......................................................................................... 11
Joe Petaski, Manitoba Hydro ........................................................................................................ 12
John W. Delucca, Lee County Electric Cooperative .................................................................... 13
Paul Cummings, City of Redding ................................................................................................. 14
Patrick Farrell, Southern California Edison Company ................................................................. 15
Dan Rochester, Independent Electricity System Operator ........................................................... 16
Lorissa Jones, Transmission Reliability Program Manager ......................................................... 18
David Burke, Orange and Rockland Utilities ............................................................................... 19
Alice Ireland, Xcel Energy ........................................................................................................... 21
Allen Mosher, American Public Power Association .................................................................... 22
Jim Case, Entergy SERC OC Standards Review Group............................................................... 25
John P. Hughes, Electricity Consumers Resource Council (ELCON) ......................................... 26
Thad Ness, American Electric Power ........................................................................................... 31
Amir Hammad, Constellation Power Source Generation, Inc. (CPSG), Et All............................ 32

Page 1 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Marc M. Butts, Southern Company .............................................................................................. 35
Andrew Z. Pusztai, American Transmission Company ................................................................ 36
Al DiCaprio, PJM ......................................................................................................................... 37
Bud Tracy, Blachly-Lane Electric Cooperative ............................................................................ 38
Jerome Murray, Oregon Public Utility Commission .................................................................... 41
John D. Martinsen , Public Utility District No. 1 of Snohomish County ..................................... 42
Steve Alexanderson P.E., Central Lincoln.................................................................................... 45
Brian J. Murphy, NextEra Energy, Inc. ........................................................................................ 46

Page 2 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

John A. Gray, The Dow Chemical Company
281‐966‐2390
JAGray3@dow.com
3. Please provide any other information that you feel would be helpful to the group working
to develop a BES Definition Exception Process.
Comments: Dow has reviewed and generally supports the comments prepared by The
Electricity Consumers Resource Council (ELCON).

Page 3 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Michael Moltane/John Zipp, ITC Holdings
Telephone: 248-946-3093
Email: mmoltane@itctransco.com
3. Please provide any other information that you feel would be helpful to the group working
to develop a BES Definition Exception Process.
Comments: I would be motivated to apply for element exclusions and the process looks
good. I don’t see a reason for us to apply for any inclusions

Page 4 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Laura Lee, Duke Energy
Telephone: 704-382-3625
Email: Laura.Lee@duke-energy.com
3. Please provide any other information that you feel would be helpful to the group working
to develop a BES Definition Exception Process.
Comments: There are three parts to the work that need to be accomplished to fulfill the
intent of the Commission’s Order; 1) revision of the definition of Bulk Electric System, 2)
development of exemption criteria and 3) development of a process for applying the
exemption criteria. The first two parts of the work should be accomplished using the
standards development process. This work is technical in nature and therefore should be
developed by technical experts in the industry. The Rules of Procedure change process
should be reserved for the mechanics of administering the exemption process.
The Regions should administer the exemption process with NERC serving an oversight role
to ensure consistency among the Regions. This would fit logically with the Regions’
administration of other processes such as the registration process.
Each registered entity that identifies Transmission or Generation Elements or Facilities that
should be included or excluded from the Bulk Electric System should submit an application
to the Region, including the information sought in parts a, b and c of questions 1 and 2 in this
document (i.e., identification of the Element or Facility, diagram, and technical justification).
The Region should then review the request through a stakeholder technical committee using
the criteria approved through the standards development process. NERC should periodically
review all applications of the exemption process to ensure consistency in the Regions’
application of the criteria.

Page 5 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Michelle Mizumori, Western Electricity Coordinating Council
Telephone: 801-819-7624
Email: mmizumori@wecc.biz
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: In addition to defining functional characteristics that can be used for an
exemption process, the use of engineering studies that demonstrate the effect of an element
on system performance must also be allowed, but must include clearly-defined and
technically-justified assumptions, metrics, and thresholds. To the extent that there are
physical differences between regions or interconnections, variations between those regions
and interconnections must be allowed. However; all assumptions, metrics, and thresholds
must be thoroughly vetted and approved by NERC as part of the NERC Exemption Process.
Furthermore, it would be helpful if NERC could clarify the process that it will use to develop
the Exemption Process and Criteria, including how the team will be populated, how
coordination with the Drafting Team will be assured, and how the vetting process would
occur. It is important that the team developing the exemption criteria includes technical
experts from the stakeholder community.

Page 6 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Brandy A. Dunn, Western Area Power Administration
Telephone: 720-962-7431
Email: dunn@wapa.gov
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: The use of engineering system studies that demonstrate the impact of an
Element on system performance must be allowed to demonstrate inclusion/exclusion to the
BES. To the extent there are physical differences between Regions, variations between those
Regions must be allowed. Also – the Exception Definition Task Force needs to be a
stakeholder-populated/ -driven process.
The exemption process should be part and parcel of the definition. Exemption language
furthermore must be explicit and unambiguous. The WECC Bulk Electric Definition Task
Force (BESDTF) has expended considerable effort over the last two years exploring
important issues pertaining to exempting elements from the BES including;
a.
b.
c.
d.

Lines of demarcation between BES and non-BES elements
Definition of ‘radial’
High voltage distribution networks.
Impact assessment methodologies.

Page 7 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Alain Pageau, Hydro-Québec TransÉnergie
Telephone: 514 879-4100 #5414
Email: pageau.alain@hydro.qc.ca
3. Please provide any other information that you feel would be helpful to the group working
to develop a BES Definition Exception Process.
Comments: For the Canadian entities, the inclusion or exclusion of equipment and
facilities in the BES must be also approved by the Canadian regulators. (as answer 2c).
We believe that it is very difficult to propose first a definition for the BES and only after
an Exemption process. Both aspects influence each other and both should be carried out
together.

Page 8 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Guy Zito, Northeast Power Coordinating Council
Telephone: 212-840-1070
Email: gzito@npcc.org
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
[1] Seven Factor Test – NPCC participating members believe that the BES Exclusion
process should place substantial weight upon Factor 3 from the FERC Seven Factor test.
Factor 3 states, “Power flows into local distribution systems, and rarely, if ever flows out.” 1
We also believe that Factor 7 has been broadly interpreted by FERC, State Commissions and
the Courts to include facilities serving a distribution function and operated at 100 kV and
above. 2,3,4,5,6,7
[2] NPCC A-10 Methodology for Determine BPS Elements – NPCC participating member
believe the A-10 Criteria methodology that NPCC uses to determine its BPS elements can be
further utilized to identify critical system components that may be operated below the 100 kV
threshold. The Criteria may also be used be used in lieu of the use of “higher” thresholds
that appear or are contemplated in some of the ERO standards such as FAC-003 cites 200kV
and above, the TPL-001 currently under development may specify a 200 kV threshold for
some “more stringent” planning criteria. These higher thresholds may lend themselves to the
use of an “impact based” methodology that could be used to determine where more stringent
requirements may need to be applied.
[3] New York State Public Service Commission (NYSPSC) - In Opinion No. 97-12, Case
97-E-0251, the NYPSC provided utilities under its jurisdiction explicit guidance for
1

We view the term “rarely” as used in Factor 3 to be bounded on the upside by a reverse power flow rate of no
more than 10% of all hours and a peak reverse power flow (MW) amount of no more than 50% of peak inflows.
2
STATE OF IOWA DEPARTMENT OF COMMERCE UTILITIES BOARD, DOCKET NO. SPU-98-12, IN RE: MIDAMERICAN
ENERGY COMPANY, ORDER RECOMMENDING DELINEATION OF TRANSMISSION AND LOCAL DISTRIBUTION
FACILITIES, Issued April 30, 1999. See http://www.state.ia.us/iub/docs/orders/1999/0430_spu9812.pdf
3
Pacific Gas and Electric Company, et al., 77 FERC ¶ 61,077 at 61,325 (1996).
4
Puget Sound Energy, Inc., 110 FERC ¶ 61,229 at 61,856 (2005).
5
Case No. U-l3862, August 26, 2003 meeting of the Michigan Public Service Commission in Lansing, Michigan.
6
“With regard to the deference it would provide to recommendations by state regulatory authorities concerning
where to draw the jurisdictional line between FERC jurisdictional transmission facilities and state-jurisdictional
local distribution facilities, FERC provided the following guidelines:… (e) If the utility's classifications and/or cost
allocations are supported by the state regulatory authorities and are consistent with the principles established in
Order No. 888, FERC will defer to such classifications and/or cost allocations.” FERC comments filing by Central
Illinois Light Company, Docket EL03-39-000, filed Dec. 20, 2002.
7
Mansfield Municipal Electric Department v. New England Power Co., 97 FERC ¶ 61,134 (2001). “…the
Municipals' facilities have all of these [Seven Factor Test] indicators except the last one. The voltage of the lines is
115 kV, the same voltage as the transmission grid. As discussed supra, the voltage alone is not dispositive of the
issue as to whether a line is distribution or transmission. We must also look at the function.”

Page 9 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

determining the point-of-demarcation between transmission facilities under FERC
jurisdiction and distribution
facilities under NYSPSC jurisdiction. 8 Appendix C to this Order established three (3)
measures that utilities were instructed to use in determining the classification of transmission
and distribution assets.
[4] FERC non-jurisdictional entities such as the Canadian Provinces.
The exemption process should clearly address the process and requirements for FERC nonjurisdictional entities (such as the Canadian entities) with the exception of the
interconnections between them and those entities under FERC jurisdiction, and/or those
entities having a direct impact on those interconnections. See APPENDIX C

8

STATE OF NEW YORK PUBLIC SERVICE COMMISSION, OPINION NO. 97-12 in CASE 97-E-0251 - Proceeding on
Motion of the Commission to Distinguish Bulk Electric Transmission System from Local Distribution Facilities.

Page 10 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Jim Uhrin

ReliabilityFirst Corporation

Telephone: 330.247.3058
Email: jim.uhrin@rfirst.org
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: ReliabilityFirst would like to see this as a simple and easy-to-follow definition.
The exclusion process needs to be clear without room for discussion or interpretation.
•

There must be a common framework developed, along with a single NERC-wide
BES definition.

•

The definition should serve as a common approach for the identification of BES
Elements and Facilities that are subject to compliance.

•

The definition and approach for the determination must be repeatable.

•

The method must clearly identify the BES elements for use by the industry.

•

In order to obtain consistency, the definition, application and criteria must be used
across Regional Entity boundaries.

•

The revised BES definition should be consistent with the Statement of Compliance
Registry Criteria so as not to create a conflict between the two, and could possibly
simply reference the Criteria for issues such as size of generating units (e.g., 20 MVA
units and 75 MVA plants) included in the BES.

•

The criteria for exemption should be included within the BES definition, and the
exemption process should contain only the procedure for submitting and
determination of such. The exemption process should not contain a third set of
criteria (in addition to the BES definition itself and the Statement of Compliance
Registry Criteria) in which to make a determination of facilities to be monitored for
compliance to standards.

•

With the revised BES definition containing specific requirements for inclusion in the
BES, will the separate Statement of Compliance Registry Criteria even be needed?

Page 11 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Joe Petaski, Manitoba Hydro
Telephone: 204-487-5332
Email: jpetaski@hydro.mb.ca
3. Please provide any other information that you feel would be helpful to the group working
to develop a BES Definition Exception Process.
Comments:
a. A NERC definition of ‘radial’ is required to prevent misapplication of the BES
definition and exemption process.
b. There should be no regional differences in the BES definition or in the BES definition
exemption process.
c. There should be equal representation from the regions to draft this standard
d. There should be consistent wording to describe the process - exception or exemption.

Page 12 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

John W. Delucca, Lee County Electric Cooperative
Telephone: 239-656-2190
Email: john.delucca@lcec.net
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: The exception process under draft in the FRCC region should serve as a strong
basis that could be applied Continent-wide. Also while the exclusion process should be
administered within the Region there needs to be an appeals process in place that progresses
quickly. In addition, a Region should not be allowed to allege violations of reliability
standards related to a system while in the appeals process. If the appeal is not upheld the
entity should then be allowed time to bring the system into compliance. Also for
consideration Bright-line” methodology seems to be the “easy button” solution, but this
“one-size fits all’ places the burden on entities to obtain exclusions. From an entity’s
viewpoint, move the “bright-line threshold” to non-radial facilities operating at or greater
than 230 kV, and adopt an inclusion process and criteria for including facilities that are
necessary to operate an interconnected electric transmission network.

Page 13 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Paul Cummings, City of Redding
Telephone: 530-245-7016
Email: pcummings@ci.redding.ca.us
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: The WECC Bulk Electric System Definition Task Force has done extensive
work on this topic. Please consider their current work when drafting the BES definition and
exception process.

Page 14 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Patrick Farrell, Southern California Edison Company
Telephone: 626-302-1321
Email: Patrick.Farrell@sce.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: In addition to defining functional characteristics that can be used for an
exemption process, the use of engineering studies that demonstrate the effect of an element
on system performance should be allowed, with clearly defined and technically justified
assumptions, metrics, and thresholds. To the extent that there are physical differences
between regions or interconnections, variations between those regions and interconnections
should be allowed. However, all the assumption, metrics, and thresholds will need to be
thoroughly vetted and approved by NERC as part of the NERC Exemption Process.

Page 15 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Dan Rochester, Independent Electricity System Operator
Telephone: 905-855-6363
Email: dan.rochester@ieso.ca
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: We have difficulties understanding the intent of this Comment Form and the
content in Q1 and Q2, above, which appear to be templates for information to be included in
an exclusion/inclusion request rather than asking for comments on each of the listed items.
1. Is the intent of this Comment Form to obtain:
a.

Recommendations of the criteria to be considered in developing deviations from the
default criteria for classifying Elements and Facilities as part of the BES?

b.

Assessment of the templates proposed in Q1 and Q2?

2. The concept paper that is posted alongside the SAR and proposed definition is not
referenced in this Comment Form. Is it the drafting team’s intent to solicit comments on
the concept paper?
3. In the concept paper, three exemption criteria are presented. We do not have any issue
with the first and third criteria but are concerned that Criterion #2 is not a criterion. It
states that:
“Elements and Facilities identified through application of the exemption process,
consistent with the criteria, where the exemption process deems that the Element or
Facility should be excluded from the BES (with concurrence from the ERO).”
This criterion appears to reference yet another set of criteria not already included in the
set or the concept paper. In fact, this “referenced” set needs to be clearly stipulated to
ensure that applicants are fully aware of the conditions under which an Element or
Facility operated at 100 kV or above can be deemed not necessary to support bulk power
system reliability and, conversely, the conditions for an Element or Facility operated at
below 100 kV to be included. The “templates” presented in Q1 and Q2 of this Comment
Form also do not convey the needed conditions.
We believe it is the clear conditions for exclusion (Elements/Facilities of 100 kV and
above) and inclusion (below 100 kV) that need to be developed and fully vetted. We urge
the drafting team to proceed to developing these criteria expeditiously so as to support the
assessment and approval of the revised definition of BES.
4. We strongly advocate that the exemption process allows for a registered entity to submit
the results of an objective, impact-based assessment process in support of its application
for exemption of facilities that would otherwise be classified as part of the BES. This
Page 16 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

assessment process, when consistently applied in a non-arbitrary manner, would yield
results that demonstrate concretely, that the facilities for which the exemption is being
sought, do not impact the BES.
5. Finally, given that the exemption process will be used to included and exclude
transmission facilities we suggest either of the following as a more appropriate name:
“BES Classification Exception Process” or “BES Classification Review Process”.

Page 17 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Lorissa Jones, Transmission Reliability Program Manager
Telephone: 360-418-8978
Email: ljjones@bpa.gov
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: In addition to defining functional characteristics that can be used for an
exemption process, the use of engineering studies that demonstrate the effect of an element
on system performance must also be allowed, with clearly defined and technically justified
assumptions, metrics and thresholds. Furthermore, to the extent that there are physical
differences between regions or interconnections, variations between those regions and
interconnections must be allowed. However all assumptions, metrics and thresholds must be
thoroughly vetted and approved by NERC as part of the NERC Exemption Process.

Page 18 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

David Burke, Orange and Rockland Utilities
Telephone: 845-577-3076
Email: burkeda@oru.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
[1] Seven Factor Test – NPCC participating members believe that the BES Exclusion process
should place substantial weight upon Factor 3 from the FERC Seven Factor test. Factor 3
states, “Power flows into local distribution systems, and rarely, if ever flows out.” 9 We also
believe that Factor 7 has been broadly interpreted by FERC, State Commissions and the
Courts to include facilities serving a distribution function and operated at 100 kV and above.
10,11,12,13,14,15

[2] NPCC A-10 Methodology for Determine BPS Elements – NPCC participating member
believe the A-10 Criteria methodology that NPCC uses to determine its BPS elements can be
further utilized to identify critical system components that may be below the 100 kV
threshold. The Criteria may also be used be used in lieu of the use of “higher” thresholds
that appear or are contemplated in some of the ERO standards such as FAC-003 cites 200kV
and above, the TPL-001 currently under development may specify a 200 kV threshold for
some “more stringent” planning criteria. These higher thresholds may lend themselves to the
use of an “impact based” methodology that could be used to determine where more stringent
requirements may need to be applied.
[3] New York State Public Service Commission (NYSPSC) - In Opinion No. 97-12, Case
97-E-0251, the NYPSC provided utilities under its jurisdiction explicit guidance for
determining the point-of-demarcation between transmission facilities under FERC
9

We view the term “rarely” as used in Factor 3 to be bounded on the upside by a reverse power flow rate of no
more than 10% of all hours and a peak reverse power flow (MW) amount of no more than 50% of peak inflows.
10
STATE OF IOWA DEPARTMENT OF COMMERCE UTILITIES BOARD, DOCKET NO. SPU-98-12, IN RE: MIDAMERICAN
ENERGY COMPANY, ORDER RECOMMENDING DELINEATION OF TRANSMISSION AND LOCAL DISTRIBUTION
FACILITIES, Issued April 30, 1999. See http://www.state.ia.us/iub/docs/orders/1999/0430_spu9812.pdf
11
Pacific Gas and Electric Company, et al., 77 FERC ¶ 61,077 at 61,325 (1996).
12
Puget Sound Energy, Inc., 110 FERC ¶ 61,229 at 61,856 (2005).
13
Case No. U-l3862, August 26, 2003 meeting of the Michigan Public Service Commission in Lansing, Michigan.
14
“With regard to the deference it would provide to recommendations by state regulatory authorities concerning
where to draw the jurisdictional line between FERC jurisdictional transmission facilities and state-jurisdictional
local distribution facilities, FERC provided the following guidelines:… (e) If the utility's classifications and/or cost
allocations are supported by the state regulatory authorities and are consistent with the principles established in
Order No. 888, FERC will defer to such classifications and/or cost allocations.” FERC comments filing by Central
Illinois Light Company, Docket EL03-39-000, filed Dec. 20, 2002.
15
Mansfield Municipal Electric Department v. New England Power Co., 97 FERC ¶ 61,134 (2001). “…the
Municipals' facilities have all of these [Seven Factor Test] indicators except the last one. The voltage of the lines is
115 kV, the same voltage as the transmission grid. As discussed supra, the voltage alone is not dispositive of the
issue as to whether a line is distribution or transmission. We must also look at the function.”

Page 19 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

jurisdiction and distribution facilities under NYSPSC jurisdiction. 16 Appendix C to this
Order established three (3) measures that utilities were instructed to use in determining the
classification of transmission and distribution assets. See APPENDIX C
NEW YORK INDICATORS (FINAL REVISED VERSION)
[NY-1] A transmission system delivers power from generation plants to local distribution
systems. Where a generator directly supplies a local distribution system, the need for a
transmission system to deliver its output to load depends on the size of the generator in
relation to the minimum load of that system.
[NY-2] Transmission systems end at the high-voltage terminals or at the disconnect switch of
a substation transformer; if no transformer is present, the transmission system ends at the bus
tap of the local distribution feeder.

16

STATE OF NEW YORK PUBLIC SERVICE COMMISSION, OPINION NO. 97-12 in CASE 97-E-0251 - Proceeding on
Motion of the Commission to Distinguish Bulk Electric Transmission System from Local Distribution Facilities.

Page 20 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Alice Ireland, Xcel Energy
Telephone: 303-571-7868
Email: alice.murdock@xcelenergy.com

3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: Xcel Energy agrees that the FERC Order 743 directs NERC to modify the
Rules of Procedure to include the process for how an entity or region may initiate an
exclusion or inclusion. However, we do not agree that FERC also directed that the actual
criteria and technical specifics for inclusion or exclusion be developed as part of the Rules
of Procedure. Furthermore, since the inclusion/exclusion criteria is a key component to the
definition of BES, we feel the criteria should be treated as part of the definition development
and developed in the same manner as the definition itself. (Preferably by the same drafting
team.)
It is also not clear as to why the Reliability Assurer is included as an applicable entity in the
SAR.

Page 21 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Allen Mosher, American Public Power Association
Telephone: 202-467-2944
Email: amosher@publicpower.org
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
The Concept Paper states at page 1 that in Order 743, FERC directed NERC to do the
following:
A. Utilize the NERC Standard Development Process to revise the definition of Bulk
Electric System (BES) contained in the NERC Glossary of Terms.
B. Develop a single Implementation Plan to address the application of the revised
definition of the BES and the implementation of the exemption process.
C. Utilize the NERC Rules of Procedure to develop and implement an ’exemption
process’ used to identify Elements and Facilities which will be included in or
excluded from the BES.
The Concept Paper continues to state that:
This project will address items ‘A’ and ‘B’ and will coordinate efforts between the
Standard Drafting Team (SDT) and the group working to develop the exemption process
for inclusion in the NERC Rules of Procedure to ensure that the revised BES definition
and exemption process result in an accurate, repeatable, and transparent method for the
identification of BES and non-BES Elements and Facilities.
APPA agrees that the standards process must be used to develop the revised BES
definition and that NERC has been directed to use its Rules of Procedure process to
develop an ROP-based procedure to implement an exemption/exclusion/inclusion
process. However, the FERC directives do not speak to how and by whom the technical
methodology, study criteria and data requirements for requesting and receiving approval
for an exemption should be developed.
To the maximum extent possible, subject to time constraints imposed by FERC, this
inherently technical methodology needs to be developed through the NERC standards
development process, in conjunction with development of the revised definition of BES.
Separate development will significantly hamper development of industry consensus in
support of the revised BES definition and the yet to be developed ROP modifications for
the exemption process.
The most critical question is how do we arrive at a commonly agreed upon, widely
accessible, transparent, and replicable continent-wide methodology to determine whether
Page 22 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

each specific facility is or is not “necessary to operate an interconnected electric
transmission network” to quote from paragraph 16 of Order 743. While each region may
have a separate model reflecting its topology and system performance characteristics, a
continent-wide approach is required to address FERC concerns about inconsistency
across regions that are not the result of physical differences.
The statutory definition of the term bulk-power system defines the outer extent of
facilities that can be included (at least within the United States) within the NERC
definition of BES. FPA section 215(a)(1) states that the bulk-power system includes “(A)
facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof); and (B) electric energy from generation
facilities needed to maintain transmission system reliability.” Further, the term BPS
“does not include facilities used in the local distribution of electric energy.” [emphasis
added].
Similarly, “reliable operation” is defined at 215(a)(4) to mean “operating the elements of
the bulk-power system within equipment and electric system thermal, voltage, and
stability limits so that instability, uncontrolled separation, or cascading failures of such
system will not occur as a result of a sudden disturbance, including a cybersecurity
incident, or unanticipated failure of system elements.”
These definitions appear to point to two basic questions for the classification of each facility
or element as BES or non-BES:
1. Is the facility or element necessary for reliable operation because it contributes
significant capability to the interconnected transmission network?
2. Will the misoperation or unanticipated failure of the facility or element adversely
affect the reliable operation of the interconnected transmission network?
APPA suggests that the BES SDT or separate study teams should be directed to establish the
outline for this study methodology. APPA further suggests that BES sub-teams be
established to address the Proposed BES Criteria in the Concept Paper. Separate sub-teams
should be established to address detailed system configuration and study methodology issues
affecting:
1. Radials serving load (with and without distribution voltage generation not subject to
registration)
2. Other transmission elements that entities seek to include in or exclude from the BES.
3. Generating plant equipment that entities seek to include in or exclude from the BES.
4. Technical issues raised by the FERC Seven Factor Test for Local Distribution
Facilities.
Separate sub-teams are appropriate because the study issues are likely to be quite distinct.
For example, radials serving only load do not provide alternative pathways for reliable BES
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

operations, as might some sub-100 kV facilities. Mixing the two teams together might slow
progress on identification of various commonly used radial to load center configurations that
with proper protection schemes do not have the potential to adversely affect the BES. A
focused effort on permissible exclusions of radials serving load is essential to prevent
distribution providers from adopting less reliable system configurations to serve their loads
because they are concerned that the preferred configuration will make them subject to
registration as TOs and/or TOPs.
Note that the proposed sub-teams do not necessarily have to be populated by members of the
SDT. The new standards process allows SDTs to gather informal input from a variety of
sources. However, development and posting for industry comment of the minimum
acceptable characteristics of the study methodology to be used in the Exceptions Process
should be the responsibility of the BES SDT.
The Comment Form on the Exclusion Process poses reasonable questions and it is my hope
that registered entities and regional entities identify numerous candidate facilities and
elements for inclusion or exclusion from the BES, accompanied by one-line diagrams that lay
out each of the permutations for such facilities that are candidates for exclusion/inclusion.
These facilities range from simple radial transmission lines and distribution step-down
transformers to 100 kV class distribution networks that operate radially from the BES. I also
hope that entities submit extensive technical documentation to explain why such facilities
should be excluded from or included in the BES.

Page 24 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Jim Case, Entergy SERC OC Standards Review Group
SERC OC Standards Review Group participants in developing the above comments:
Jim Case, Entergy
Gerald Beckerle, Ameren
Andy Burch, EEI
Randy Castello, Miss Power
Dan Roethemeyer, Dynegy
Melinda Montgomery, Entergy
Sam Holeman, Duke
Joel Wise, TVA
Alvis Lanton, SIPC
Hamid Zakery, Dynegy
John Neagle, AECI
Mike Hirst, Cogentrix
Tim Hattaway, PowerSouth
Robert Thomasson, BREC
Shardra Scott, Gulf Power
Patrick Woods, EKPC
Alisha Ankar, Prairie Power
Bill Hutchison, SIPC
J.T. Wood, Southern
Telephone: 601-985-2345
Email: jcase@entergy.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: Each inclusion and exclusion should be based solely on its technical
justification.
“The comments expressed herein represent a consensus of the views of the above named
members of the SERC OC Standards Review group only and should not be construed as the
position of SERC Reliability Corporation, its board or its officers.”

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

John P. Hughes, Electricity Consumers Resource Council (ELCON)
Telephone: 202-682-1390
Email: jhughes@elcon.org
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: ELCON members have always supported fair and effective reliability efforts at
NERC. However, the expansion of the standards compliance responsibility implied by the
NERC Concept Document goes too far. As written, this proposal could have the effect of
devaluing a large number of industrial owned electrical power assets by forcing industrials to
meet new and unnecessary compliance obligations. Many will be forced to choose to either
accept a significant new cost or fire sale their assets to local providers increasing the
purchaser’s market power in the process. ELCON feels the addition of new compliance
obligations should not be done in such a wholesale manner but instead done on an exception
and as needed basis that factors in both a realistic appraisal of the underlying risk and the
economic burden imposed on the registered entity relative to the expected benefits.
Specific recommendations and concerns are:
1. An Overarching “Principle” for the Identification of BES Elements and Facilities Must be
the Guidance Provided by FERC That Significant Expansion of the Compliance Registry
is Not Contemplated.
In FERC’s March 18, 2010 Notice of Proposed Rulemaking (NOPR) on the Revision to
Electric Reliability Organization Definition of Bulk Electric System, the Commission
stated regarding the revision to the BES definition:
This proposal would eliminate the discretion provided in the current definition for
a Regional Entity to define “bulk electric system” within a region. Importantly,
however, we emphasize that we are not proposing to eliminate all regional
variations and we do not anticipate that the proposed change would affect most
entities. ¶ 16. … the Commission does not believe that the proposal would have
an immediate effect on entities in any Regional Entity other than NPCC. ¶ 27.
Similarly, in Order No. 743, the Commission stated:
We expect that our decision to direct NERC to develop a uniform modified
definition of “bulk-electric system” will eliminate regional discretion and
ambiguity. The change will not significantly increase the scope of the present
definition, which applies to transmission, generation and interconnection
facilities. The proposed exemption process will provide sufficient means for
entities that do not believe particular facilities are necessary for operating the
interconnected transmission system to apply for an exemption. ¶ 144.

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Proposed Definition of Bulk Electric System – Project 2010-17
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One area where the proposed BES definition and exception process will significantly
expand the Compliance Registry is the criteria applicable to behind-the-meter generation
(primarily cogeneration facilities). We urge that the BES definition should not change
the currently applicable 20 MVA / 75 MVA generation size threshold applicable to
generation facilities or the manner in which that threshold is currently applied, with
behind‐ the‐ meter cogeneration facilities evaluated based on the net capacity actually
provided to the grid.
2. A Second Overarching “Principle” for the Identification of BES Elements and Facillities
Is the Need to Clarify Which Facilities Perform a True Transmission Function and
Excluding Facilities That Perform a Local Distribution Function, As Required by Law.
Congress stated in Federal Power Act section 215:
SEC. 215. ELECTRIC RELIABILITY.
‘‘(a) DEFINITIONS.—For purposes of this section:
‘‘(1) The term ‘bulk-power system’ means—
‘‘(A) facilities and control systems necessary for operating an interconnected
electric energy transmission network (or any portion thereof); and
‘‘(B) electric energy from generation facilities needed to maintain transmission
system reliability.
The term does not include facilities used in the local distribution of electric
energy.
There has been little attempt by NERC to clarify what in fact are “facilities used in the
local distribution of electric energy” even though any plain English application of the
term makes such a determination self-evident. The proposed BES definition should
expressly exclude facilities used in the local distribution of electric energy, and the
identification of such facilities is independent of the identification of BES transmission.
Facilities used for local distribution are NOT the residual of any determination of what
are BES transmission facilities.
3. A Third Overarching “Principle” for the Identification of BES Elements and Facilities
Must be Recognition of the Risk Imposed by the Element or Facility, and the Economic
Burden of the Owner/Operator of the Element of Facility.
The efforts of the BES Standards Drafting Team follow the release of two important
policy documents.
First, on January 18, 2011, the White House issued an Executive Order (“Improving
Regulation and Regulatory Review”) by President Obama regarding improvements to
federal regulations and the review of existing regulations to ensure, among other things,
that a regulation be proposed or adopted “only upon reasoned determination that its
benefits justify its costs,” and that regulations be tailored “to impose the least burden on
society.”
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Proposed Definition of Bulk Electric System – Project 2010-17
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Second, the NERC Planning Committee issued on January 10, 2011, “Risk-Based
Reliability Compliance – White Paper Concept Discussion,” which attempts to advance
“processes and procedures to prioritize [NERC’s] efforts and ‘tiering’ elements of its
programs to maximize their value and optimize the benefit/cost of effort from
stakeholders.” This white paper complements the President’s Executive Order.
ELCON believes that BES exclusion criteria and process should recognize and exclude
elements and facilities in which the risk to bulk electric system reliability is at most
theoretical or speculative, and where the compliance burden clearly outweighs the
benefits. Such a determination should recognize the historical record of the element or
facility in terms of the owner or operator’s coordination with the BA or control area, and
transmission operators. This principle should be applied to the development of
exclusion/inclusion criteria for private lines that connect loads and behind-the-meter
generation to true BES Elements and Facilities.
4. An Additional Principle for the Identification of BES Elements and Facilities Should Be
the Explicit Recognition on How the Element or Facility is Actually Operated or Used,
Not Its Physical or Nominal Rating That May be Irrelevant to Reliability Considerations.
In Order No. 743, FERC clarified that it did not intend to require NERC to utilize the
term “rated at” rather than the term “operated at” for the voltage threshold in the revised
BES definition. A principle for the identification of BES Elements and Facilities should
be such recognition and not exclusively on the rated value of an Element or Facility.
This principle should be used to retain the exclusion in the Statement of Compliance
Registry Criteria (Revision 5.0) for “net capacity provided to the bulk power system” in
the context of the 20 MVA generating unit and 75 MVA generating plant thresholds. The
“net capacity” applies to capacity “put” of a behind-the-meter generator whose
predominant function is to serve load at the same site.
5. An Additional Principle for the Identification of BES Elements and Facilities Should be
the Exclusion of PSEs That Do Not Own or Operate Physical Assets and Whose Power
Transactions Are Exclusively Financial in Nature.
Many PSEs that operate in FERC jurisdictional organized wholesale markets (i.e., ISOs
and RTOs) do not own, operate or lease physical assets and are currently bombarded with
data requests that assume that they own or control such assets. An example of a
superfluous data request is to prove that adequate reactive power has been procured to
support the load. This is a question that should not have been asked and displays a
profound ignorance of the operation of ISO/RTO markets. One potential solution to this
problem is to create two subsets of PSEs: one that owns and operates physical assets that
are used to serve their loads, and a second that does not.
Some Regional Entities have also begun to ask questions that require PSEs to reveal the
details of specific commercial transactions. This raises a broader question on what
NERC and regional compliance staffs and auditors “need to know” and whether such
questions are an abuse of their enforcement authority.
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Proposed Definition of Bulk Electric System – Project 2010-17
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6. Any Attempt to Make Demand Side Management (DSM) Measures an Element or
Facility of BES Will Be Shortsighted and Counterproductive.
Proposals that unilaterally and arbitrarily remove exclusions for generation and
transmission, including the application of new compliance obligations to DSM programs,
go far beyond what FERC intended in its guidance for revisions. Any new requirement
concerning voluntary DSM adds cost to a process that so far has only acted to support
reliability with performance equal to and sometimes superior to traditional providers.
How is it that a potential resource that can contribute to maintaining reliability is now so
quickly identified as a risk? We warn against the overzealous pursuit of control over
every asset and resource on the electric system. This mindset will only breed cynicism
and end the willingness of potentially dispatchable loads to cooperate with the real
operators and owners of the BES.
A recently issued FERC study highlights the potential value to reliability of DSM (in the
form of dispatchable demand response) (See Joseph H. Eto et al., Use of Frequency
Response Metrics to Assess the Planning and Operating Requirements for Reliable
Integration of Variable Renewable Generation, LBNL-4142E, December 2010). To
reliably integrate greater amounts of wind energy resources to the bulk electric system,
the study recommended the:
Expanded use of demand response that is technically capable of providing
frequency control (potentially including smart grid applications), starting with
broader industry appreciation of the role of demand response in augmenting
primary and secondary frequency control reserves.
7. Revising the Definition of BES Does Not Justify Shifting the Plenary Burden for BPS
Reliability from Utilities to Utility Customers. A BES Principle Should Recognize That
the Obligation to Serve Applies in One Direction.
The only reason the bulk power system exists is to deliver electric power to residential
households, commercial businesses, government facilities and industrial facilities of all
sizes. The value of a reliable BPS is dependent on the needs of end use customers.
Nothing in the legislative history of section 215 of the Federal Power Act suggests that
Congress wittingly intended to change that relationship.
The burden of complying with NERC Reliability Standards is a cost of doing business for
utility providers of generation, transmission and distribution services. Generation and
interconnection facilities of industrial customers are almost never intended for or used to
“operate the interconnected transmission network.” Those facilities are integral to a
manufacturing process, including purchasing power from the grid. They were built in
expectation that the BPS was prudently planned and operated by utilities. The rare
exceptions are administered under applicable tariffs or contracts, and are already
Registered Entities.

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Proposed Definition of Bulk Electric System – Project 2010-17
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Part of NERC’s effort should include defining the line between a BES asset that is used
to deliver power and an End User asset that's sole purpose is to serve the End User's load.
The NERC Functional Model includes a vague definition of End-use Customer. The
problem is determining the scope of an end-use device. If an industrial company owns a
138 kV to 13.8 kV transformer that feeds its plant, is that an end-use device or a
transmission asset that is used to transmit power to the low voltage distribution network
within the manufacturing facility? Any work to revise the definition of the BES should
also include a clarification of its boundaries. We believe that NERC should not expand
the scope of the BES to include assets within end-use customer's private use networks.
8. An Additional BES Principle Should be that BES Elements and Facilities be Limited to
Only Functions Currently Specified in the NERC Functional Model (Version 5).
NERC’s development of the revised BES definition and exclusion/inclusion criteria and
processes should be limited to functions specified in the NERC Functional Model
(Version 5).
9. NERC is Encouraged to Propose a “Different Solution” That is as Effective as, or
Superior to, the Commission’s Proposed Approach. The Proposed Principles for the
Exclusion of Elements and Facilities from the BES Should Include a Process for
Categorical Exclusion Based on Common Physical Characteristics.
The Commission stated in Order No. 743 regarding its proposed revision of the BES
definition (and presumably the exclusion/inclusion criteria and processes):
… NERC may propose a different solution that is as effective as, or superior to,
the Commission’s proposed approach in addressing the Commission’s technical
and other concerns so as to ensure that all necessary facilities are included within
the scope of the definition. ¶ 16.
In addition, specific to the exclusion of Elements and Facilities from the BES, the Final
Rule did not adopt the exclusion process proposed in the NOPR (i.e., facility-by-facility
review). In the Final Order, FERC directed NERC to develop an exclusion process “with
practical application that is less burdensome than the NOPR proposal.”
FERC has also allowed NERC to consider concerns (mainly industrials’) regarding
“exclusion categories” in developing the exclusion process and criteria. ¶ 120.
ELCON interprets the Commission’s statements to mean that the agency is open to
developing a more efficient compliance process, including processes that minimize
unnecessary regulatory burdens on potential Registered Entities and the administrative
costs of NERC and RE compliance operations. In the spirit of “streamlining” NERC and
the REs’ review of smaller entities, ELCON recommends the addition of a principle on
the exclusion of Elements and Facilities from the BES that encourages a process for
categorical exclusion of entities based on common physical characteristics.

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Proposed Definition of Bulk Electric System – Project 2010-17
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January 27, 2011

Thad Ness, American Electric Power
Telephone: 614-716-2053
Email: tkness@aep.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: We appreciate the opportunity to provide advance comments on the BES
definition exemption process. The comments provided above are initial thoughts, and are by
no means an exhaustive itemized list of exemptions. AEP looks forward to contributing
additional input through the standards development process when the SDT provides drafts or
revisions.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Amir Hammad, Constellation Power Source Generation, Inc. (CPSG), Et All
CPSG is filing the comments below on behalf of:
Constellation Energy Group, Inc.
Baltimore Gas & Electric Company
Constellation Energy Commodities Group, Inc.
Constellation Energy Control and Dispatch, LLC
Constellation NewEnergy, Inc. and its affiliates
Constellation Energy Nuclear Group, LLC, 17
Telephone: 410-787-5226
Email: amir.hammad@constellation.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: While the Regional Bulk Electric System Coordination Group has done an
admirable job at drafting an initially proposed list of inclusion and exclusion criteria,
Constellation strongly suggests that the continued work on criteria be orchestrated through
the FERC-approved standard development process and not as part of a Rules of Procedure
revision. We view development of the technical criteria for both the BES definition and
exemption process as a single exercise.
The compliance implications and technical nature of such criteria make it imperative that
industry input be considered in a transparent stakeholder process. It is appropriate for NERC
to develop aspects such as the administrative management, the role and interaction of the
regions, an appeal process, etc. However, due to the technical aspects of BES operation, the
drafting team members are best suited to devise criteria for inclusion or exclusion of facilities
to the BES.
To clarify the distinction between the exception process and the exception criteria, the
purpose statement in the concept document should add a fourth bullet to read:
A. Utilize the NERC Standard Development Process to revise the definition of
Bulk Electric System (BES) contained in the NERC Glossary of Terms.
B. Utilize the NERC Standard Development Process to develop exception criteria
to be utilized in the exception process.Develop a single Implementation Plan to
address the application of the revised definition of the BES and the
implementation of the exemption process.
17

On November 6, 2009, EDF, Inc. (“EDF”) and Constellation Energy Group, Inc. completed a transaction
pursuant to which EDF acquired a 49.99 percent ownership interest in CENG. CENG was previously a wholly
owned subsidiary of Constellation Energy Group, Inc.

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C. Utilize the NERC Rules of Procedure to develop and implement an ’exemption
process’ used to identify Elements and Facilities which will be included in or
excluded from the BES.
The revised definition should expressly incorporate exclusions for facilities below 100 kV.
Entities should not have to seek an exemption for facilities below 100 kV or for radial lines.
They should be clearly excluded in the BES definition itself. We encourage the drafting
team to embrace a design concept that seeks to maximize the “brightness” of bright line
criteria. The BES exemption process should contemplate very few exemptions. The TFE
process is an example of a process not to be repeated here.
In addition, Constellation is not convinced that creation of a definition and an exception
process is the best course to respond to the FERC directives. We are concerned that the
current approach of a simple, all inclusive definition coupled with an exception criteria and
process will not draw on the fundamentals underpinning the existing definition and create a
cumbersome and unnecessary exception process.
As an alternative, we propose that the standard drafting team utilize the Compliance Registry
Criteria – Section III (Rules of Procedure Appendix 5B) along with definition threshold
language to develop a more comprehensive definition. Further, we propose that the BES
drafting team incorporate the criteria directly into the revised BES definition, replacing the
term “bulk power system” in each criterion with “greater than 100 kV.” It will make for a
longer definition, but by aligning the facilities requiring registration as those defined as BES,
the definition will more clearly determine the line between BES and non-BES. It is
preferable that non-BES facilities be excluded by the definition language rather than to
define BES broadly and require non-BES facilities go through an exception process. Ideally,
this approach can eliminate the need for an onerous exemption process as well as eliminate
the need for Section III of the Registry Criteria in the Rules of Procedure.
For special case facilities deemed non-BES by the revised definition that may warrant
consideration for inclusion, an “opt-in” evaluation could be conducted.
The rules of procedure process may be used to develop the “opt-in” process that would
replace the proposed exception concept; however, the drafting team, perhaps in collaboration
with regional entities, should develop any opt-in criteria needed for the process. Again, it is
appropriate for NERC to develop aspects such as the administrative management, the role
and interaction of the regions, an appeal process, etc. However, due to the technical aspects
of BES operation, the drafting team members are best suited to devise criteria for non-BES
facilities to warrant inclusion in the BES.
We find that this approach to revising the BES definition would satisfy the FERC directives
in Order 743 by encompassing all facilities necessary for operating an interconnected electric
transmission network into a national level, bright-line definition. This approach will improve
the clarity and consistency of the BES definition for application by Industry and NERC as
well as avoiding creation of a potentially cumbersome exception process.

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Proposed Definition of Bulk Electric System – Project 2010-17
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January 27, 2011

Shaun Anders, City Water Light and Power
Telephone: 217-321-1323
Email: shaun.anders@cwlp.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: CWLP has chosen to comment on the inclusion/exclusion process as a whole.
The current lack of detailed, firm administrative guidelines as well as an unambiguous
process for resolving disputes between parties involved in the process of adjudicating
inclusions/exclusions is problematic. It is CWLP’s belief that developing the proposed
administrative framework for the process is needed first. Focusing on the data to be
submitted as shown in (1) and (2) above does not address the scope, nature, and criteria
applicable to the review of requests for inclusions/exclusions. Regardless, CWLP feels
strongly that the sole basis for approval or rejection of a request should be technical
justification.
Speaking to the process in general, any inclusion or exclusion should be a specific request for
a specific facility; continent-wide, interconnect-wide, and region-wide applicability for
inclusions/exclusions departs from the intent of FERC Order 743 to establish a definition
without regional variances.

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Proposed Definition of Bulk Electric System – Project 2010-17
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January 27, 2011

Marc M. Butts, Southern Company
Telephone: 205-257-4839
Email: mmbutts@southernco.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
The evaluation method should be clear, understandable, and technically
based. Sometimes the “process” is called an Exemption Process and other times it is
called “Exception Process”,

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Proposed Definition of Bulk Electric System – Project 2010-17
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January 27, 2011

Andrew Z. Pusztai, American Transmission Company
Telephone: 262-506-6913
Email: apusztai@atcllc.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
a. ATC feels strongly that the exemption criteria need to be developed by the SDT.
NERC Staff should focus on the process (identification, notification, appeal and
rights) but the SDT is in the better position to develop the technical basis of the
exemption criteria.
b. The NERC process for exclusion or inclusion must clearly address who is responsible
for submitting an Element or Facility Exception Process. Is it limited to the asset
owner of the Element or Facilities, or is it open to neighboring entities that may want
to initiate a request for exemption or inclusion to the BES?
c. Also, ATC believes the process should allow for multi-year distinctions for
exceptions. In other words, if a Registered Entity gets an Element or Facility
excluded, then that exclusion or inclusion should be allowed for 3 or more years.
Annual certifications and approval are too restrictive.
d. ATC also supports the comments as submitted by EEI REAC on the Draft Concept
Paper on the Definition of BES Project 2010-17

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Proposed Definition of Bulk Electric System – Project 2010-17
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January 27, 2011

Al DiCaprio, PJM
Telephone: 610-666-8854
Email: dicrapm@pjm.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: We have difficulties understanding the intent of this Comment Form and the
content in Q1 and Q2, above, which appear to be templates for information to be included in
an exclusion/inclusion request rather than asking for comments on each of the listed items.
1. Is the intent of this Comment Form to obtain:
a. Recommendations of the criteria to be considered in developing deviations from the
default criteria for classifying Elements and Facilities as part of the BES?
b. Assessment of the templates proposed in Q1 and Q2?
2. The concept paper that is posted alongside the SAR and proposed definition is not
referenced in this Comment Form. Is it the drafting team’s intent to solicit comments on
the concept paper?
3. In the concept paper, three exemption criteria are presented. We do not have any issue
with the first and third criteria but are concerned that Criterion #2 is not a criterion. It
states that:
“Elements and Facilities identified through application of the exemption process, consistent
with the criteria, where the exemption process deems that the Element or Facility should be
excluded from the BES (with concurrence from the ERO).”
This criterion appears to reference yet another set of criteria not already included in the set or
the concept paper. In fact, this “referenced” set needs to be clearly stipulated to ensure that
applicants are fully aware of the conditions under which an Element or Facility operated at
100 kV or above can be deemed not necessary to support bulk power system reliability and,
conversely, the conditions for an Element or Facility operated at below 100 kV to be
included. The “templates” presented in Q1 and Q2 of this Comment Form also do not convey
the needed conditions.
We believe it is the clear conditions for exclusion (Elements/Facilities of 100 kV and above)
and inclusion (below 100 kV) that need to be developed and fully vetted. We urge the
drafting team to proceed to developing these criteria expeditiously so as to support the
assessment and approval of the revised definition of BES.

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Proposed Definition of Bulk Electric System – Project 2010-17
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January 27, 2011

Bud Tracy, Blachly-Lane Electric Cooperative
Telephone: 541.688.8711
Email: tracyb@blachlylane.coop
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
1. We have a number of concerns related to the initial SAR proposal:
a) The primary concern expressed by FERC in Order No. 743 was the discretion the
current definition accords to the RROs to develop their own definition of the BES
without approval by NERC or FERC. See Order No. 743, 133 FERC ¶ 61,150 at P
16 (2010) (FERC believes the “best way to address these concerns is to eliminate the
Regional Entities’ discretion to define ‘bulk electric system’ without ERO or
Commission review“); at 30 (same). Hence, we believe FERC’s concern can be
addressed by simply removing the phrase “As defined by the Regional Reliability
Organization” from the existing definition. The result would be that the RROs could
then develop regionally-appropriate rules based on the uniform definition, which
NERC and FERC could then approve, giving deference to the technical findings of
the RROs and NERC, as the FPA requires. FPA Section 215(d), 16 U.S.C.
§ 825o(d). We urge the standards drafting team to consider the virtues of such a
minimalist approach and then focus on alternative approaches that will achieve
FERC’s aim more effectively and/or at lower cost, and on the exemption process,
which will, unless FERC abandons its insistence on a 100-kV bright-line threshold,
be the most important aspect of the standards development process.
b) The definition proposed in the SAR would incorporate “All Transmission and
Generation Elements and Facilities” that are “necessary to support bulk power
system reliability.” We applaud the effort to properly restrict the definition of BES
using the NERC-defined terms “Transmission,” “Generation,” “Elements” and
“Facilities.” By using these terms, the drafting team recognizes that Congress
excluded from the statutory “Bulk-Power System” definition “facilities used in the
local distribution of electric energy,” FPA Section 215(a)(1), 16 U.S.C. § 825o(a)(1),
and has thereby excluded such facilities from the reach of the mandatory reliability
system. Similarly, by focusing the definition on “Transmission” and “Generation,”
the standards drafting team recognizes that Congress limited the reach of reliability
standards to: (1) “facilities and control systems necessary for operating an
interconnected electric energy transmission network,” and, (2) “electric energy from
generation facilities needed to maintain transmission system reliability.” Id.

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When viewed in the context of the proposed BES definition, however, we are
concerned that incorporating the terms as defined in the NERC Glossary may create
unnecessary confusion and ambiguity. For example, the NERC Glossary defines
“Facility” as “[a] set of electrical equipment that operates as a single Bulk Electric
System Element.” But attempting to define BES by using a term that itself
incorporates “Bulk Electric System” is circular and is likely to create confusion in
applying the revised definition. Similarly, “Generation” is not specifically defined
in the NERC Glossary of Terms, creating potential confusion.
Finally, the NERC Glossary defines “Transmission” in part as “the movement or
transfer of electric energy between points of supply and points at which it is
transformed for delivery to customers.” This creates the potential for an overinclusive definition since “Transmission” could, by this definition, be understood to
encompass only the last transformation of voltage to end-user level voltage in a
system, whereas distribution systems generally include several downward
transformations of voltage between the point of bulk delivery and the end-use
consumer. One could argue that each of the segments between delivery of bulk
power to the local distribution utility and that utility’s step-down transformers is, by
the terms of the definition, merely moving power “between points of supply” and
only the last segment includes the “point at which [power] is transformed for
delivery to customers.” This, of course, would improperly classify a large portion of
most distribution system as “Transmission.”
For these reasons, it may be necessary to define “Generation” and to more precisely
define “Facility” and “Transmission” as part of the standards drafting process.
We note, on the other hand, that “reliable operation” was a term specifically defined
by Congress in FPA Section 215 to include the operation of BES elements “within
equipment and electric system thermal, voltage, and stability limits so that
instability, uncontrolled separation, or cascading failures of such system will not
occur as a result of a sudden disturbance. . . or unanticipated failure of system
elements.” 16 U.S.C. § 825o(a)(4). Congress specifically precluded the mandatory
reliability system from enforcing standards for adequacy of service, which were left
to state and local authorities. 16 U.S.C. § 825o(i)(2). Accordingly, we applaud the
standards drafting team for including in the BES only facilities “necessary to support
bulk power system reliability,” because the use of the italicized term at least
implicitly excludes from the definition facilities that affect only the levels of service
that were explicitly excluded from the mandatory reliability regime by Congress and
do not affect “reliable operation” of the BES as Congress defined it.
c) The proposed SAR definition unnecessarily restricts the exclusion in the existing
definition for radial facilities. The existing definition provides that radial facilities
are “generally not included” in the BES. The proposed new definition would
significantly restrict this exclusion, excluding radial systems from the BES only if
they are excluded through the “BES definition exemption process.” We believe
there is no reason to make radial systems and other elements of the electric system
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January 27, 2011

that, because of their limited interaction with the bulk system, have no meaningful
impact on bulk system reliability go through a potentially onerous exemption
process. Rather, such systems should be presumptively excluded from the
definition, as they are now. Further, for the reasons set forth in detail by the WECC
BESDTF, local distribution networks in the West should be subject to a similar
categorical exclusion, subject to inclusion in the BES only upon a demonstration that
the network creates substantial reliability risks for the bulk system. This approach
is consistent with FERC’s direction that “radial facilities, as well as facilities used in
the local distribution of electric energy as provided in Section 215, will continue to
be excluded.” Order No. 743 at P 120.

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Proposed Definition of Bulk Electric System – Project 2010-17
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January 27, 2011

Jerome Murray, Oregon Public Utility Commission
Telephone: 503-378-6626
Email: Jerry.murray@state.or.us
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
1. The work that has been completed by the WECC Bulk Electric System Definition
Task Force is based on sound engineering principles and appears to be a
comprehensive solution to defining the BES and providing a means for exceptions to
the 100 kV “bright line” criteria. The NERC BES Drafting Team is urged accept the
proposal in whole or include contained principles to guide NERC’s process for
exception.
2. There is serious concern in the Western Interconnection that if a strict 100 kV bright
line is mandated that billions of dollars will be needed to be upgrade 100kV to 200
kV distribution elements to comply with NERC reliability/security standards. There
is a significant potential for unintended consequences. A serious one is that there
could be substantially less monetary resources available for new transmission
investment for high impact BES elements and for relieving congestion. Another is
FERC would arguably be negating the 7 factor test for distribution facilities,
extending FERC jurisdiction over distribution facilities, bringing costs for such
facilities into the FERC tariffs, and reducing PUC state review of such investments.
These could result in substantial cost increases and/or reliability issues for electric
consumers.

Page 41 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

John D. Martinsen , Public Utility District No. 1 of Snohomish County
Telephone: 425-783-8080
Email: jdmartinsen@snopud.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
1. We have a number of concerns related to the initial SAR proposal:
a) The primary concern expressed by FERC in Order No. 743 was the discretion the
current definition accords to the RROs to develop their own definition of the BES
without approval by NERC or FERC. See Order No. 743, 133 FERC ¶ 61,150 at
P 16 (2010) (FERC believes the “best way to address these concerns is to
eliminate the Regional Entities’ discretion to define ‘bulk electric system’ without
ERO or Commission review“); at 30 (same). Hence, we believe FERC’s concern
can be addressed by simply removing the phrase “As defined by the Regional
Reliability Organization” from the existing definition. The result would be that
the RROs could then develop regionally-appropriate rules based on the uniform
definition, which NERC and FERC could then approve, giving deference to the
technical findings of the RROs and NERC, as the FPA requires. FPA Section
215(d), 16 U.S.C. § 824o(d). We urge the standards drafting team to consider the
virtues of such a minimalist approach and then focus on alternative approaches
that will achieve FERC’s aim more effectively and/or at lower cost, and on the
exemption process, which will, unless FERC abandons its insistence on a 100-kV
bright-line threshold, be the most important aspect of the standards development
process.
b) The definition proposed in the SAR would incorporate “All Transmission and
Generation Elements and Facilities” that are “necessary to support bulk power
system reliability.” We applaud the effort to properly restrict the definition of
BES using the NERC-defined terms “Transmission,” “Generation,” “Elements”
and “Facilities.” By using these terms, the drafting team recognizes that Congress
excluded from the statutory “Bulk-Power System” definition “facilities used in
the local distribution of electric energy,” FPA Section 215(a)(1), 16 U.S.C.
§ 824o(a)(1), and has thereby excluded such facilities from the reach of the
mandatory reliability system. Similarly, by focusing the definition on
“Transmission” and “Generation,” the standards drafting team recognizes that
Congress limited the reach of reliability standards to: (1) “facilities and control
systems necessary for operating an interconnected electric energy transmission
network,” and, (2) “electric energy from generation facilities needed to maintain
transmission system reliability.” Id.

Page 42 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

When viewed in the context of the proposed BES definition, however, we are
concerned that incorporating the terms as defined in the NERC Glossary may
create unnecessary confusion and ambiguity. For example, the NERC Glossary
defines “Facility” as “[a] set of electrical equipment that operates as a single Bulk
Electric System Element.” But attempting to define BES by using a term that
itself incorporates “Bulk Electric System” is circular and is likely to create
confusion in applying the revised definition. Similarly, “Generation” is not
specifically defined in the NERC Glossary of Terms, creating potential confusion.
Finally, the NERC Glossary defines “Transmission” in part as “the movement
or transfer of electric energy between points of supply and points at which it is
transformed for delivery to customers.” This creates the potential for an overinclusive definition since “Transmission” could, by this definition, be understood
to encompass only the last transformation of voltage to end-user level voltage in a
system, whereas distribution systems generally include several downward
transformations of voltage between the point of bulk delivery and the end-use
consumer. One could argue that each of the segments between delivery of bulk
power to the local distribution utility and that utility’s step-down transformers is,
by the terms of the definition, merely moving power “between points of supply”
and only the last segment includes the “point at which [power] is transformed for
delivery to customers.” This, of course, would improperly classify a large portion
of most distribution system as “Transmission.”
For these reasons, it may be necessary to define “Generation” and to more
precisely define “Facility” and “Transmission” as part of the standards drafting
process.
We note, on the other hand, that “reliable operation” was a term specifically
defined by Congress in FPA Section 215 to include the operation of BES
elements “within equipment and electric system thermal, voltage, and stability
limits so that instability, uncontrolled separation, or cascading failures of such
system will not occur as a result of a sudden disturbance. . . or unanticipated
failure of system elements.” 16 U.S.C. § 824o(a)(4). Congress specifically
precluded the mandatory reliability system from enforcing standards for adequacy
of service, which were left to state and local authorities. 16 U.S.C. § 824o(i)(2).
Accordingly, we applaud the standards drafting team for including in the BES
only facilities “necessary to support bulk power system reliability,” because the
use of the italicized term at least implicitly excludes from the definition facilities
that affect only the levels of service that were explicitly excluded from the
mandatory reliability regime by Congress and do not affect “reliable operation” of
the BES as Congress defined it.
c) The proposed SAR definition unnecessarily restricts the exclusion in the existing
definition for radial facilities. The existing definition provides that radial
facilities are “generally not included” in the BES. The proposed new definition
would significantly restrict this exclusion, excluding radial systems from the BES
Page 43 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

only if they are excluded through the “BES definition exemption process.” We
believe there is no reason to make radial systems and other elements of the
electric system that, because of their limited interaction with the bulk system,
have no meaningful impact on bulk system reliability, go through a potentially
onerous exemption process. Rather, such systems should be presumptively
excluded from the definition, as they are now. Further, for the reasons set forth in
detail by the WECC BESDTF, local distribution networks in the West should be
subject to a similar categorical exclusion, subject to inclusion in the BES only
upon a demonstration that the network creates substantial reliability risks for the
bulk system. This approach is consistent with FERC’s direction that “radial
facilities, as well as facilities used in the local distribution of electric energy as
provided in Section 215, will continue to be excluded.” Order No. 743 at P 120.

Page 44 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Steve Alexanderson P.E., Central Lincoln
Telephone: 541-574-2064
Email: salexanderson@cencoast.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: Our understanding of the FERC Order was that the threshold would be 100 kV
“except for defined radial facilities” and that they also ordered NERC to adopt an “exemption
process”. The question confuses the two distinct parts by speaking of an “exception process”
never ordered by FERC. We urge the SDT to clearly define “radial” in such a way that no
external “process” is needed, and that radial facilities can easily be determined by each registered
entity by inspection. And if they have facilities that don’t meet the radial definition, they may
still be put through a formal exemption process and be exempted if they are found not to
contribute to reliable operation of the BPS.
The WECC Bulk Electric System Definition Task Force has done extensive work on this topic.
Please consider their current work when drafting the BES definition and exemption process.

Page 45 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

Brian J. Murphy, NextEra Energy, Inc.
Telephone: (305) 442‐5132
Email: Brian.J.Murphy@fpl.com
3. Please provide any other information that you feel would be helpful to the group working
to develop a BES Definition Exception Process.
Comments: Based on the information posted by the North American Electric Reliability
Corporation (NERC) on its plans to address Order No. 743 of the Federal Energy Regulatory
Commission (FERC), NextEra Energy, Inc.1 (NextEra) believes that NERC (and associated
drafting teams) should slightly modify its direction to more closely align with FERC’s
proposed framework. In Order No. 743, at paragraph 30, FERC stated that:
The Commission believes the best way to address these concerns is to eliminate the
regional discretion in the ERO’s current definition, maintain the bright‐line threshold
that includes all facilities operated at or above 100 kV except defined radial facilities,
and establish an exemption process and criteria for excluding facilities the ERO
determines are not necessary for operating the interconnected transmission network.
It is important to note that Commission is not proposing to change the threshold value
already contained in the definition, but rather seeks to eliminate the ambiguity created
by the current characterization of that threshold as a general guideline.
1 NextEra registered entities, which include NextEra Energy Resources, Inc. and
Florida Power & Light Company, operate in the eight NERC regions. Official
Comment form for BES Definition Exception Process FERC also provided NERC
with the opportunity to propose an alternative approach. NextEra believes, however,
that FERC’s proposed framework is appropriately designed to enhance the definition
of the Bulk Electric System (BES) in the NERC glossary, and to separately develop a
process to apply for and receive, as appropriate, an exemption from the BES
definition. Although it appears that NERC and the drafting teams may also be
inclined to proceed as suggested by FERC, there are indications in the questionnaire
and BES concept paper that there may be some thought to deviating from FERC’s
proposal.
A review of the information posted by NERC seems to indicate NERC’s intention to have a
drafting team develop a revised BES definition via the standards development process (i.e.,
Appendix 3A of the NERC Rules of Procedure). It also seems that NERC is interested in
assigning a “working group” to separately develop an exemption process that would be
implemented as a new process in the NERC Rules of Procedure. NextEra agrees with this
approach.
NextEra’s concerns stem from some of the words in the proposed BES definition, the BES
concept paper and the questions asked, which seem to suggest an unnecessarily overlapping
definition and exemption process, and a movement toward an exemption process based on
categories rather than criteria. Thus, to address these concerns NextEra proposes the
Page 46 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

following enhancements to more clearly separate the BES definition and exemption process,
and align each more closely with Order No. 743.
As for the BES definition, NextEra encourages the drafting team to solely focus its efforts on
the definition. The currently posed revised BES definition reads as follows:
Bulk Electric System: All Transmission and Generation Elements and Facilities
operated at voltages of 100 kV or higher necessary to support bulk power system
reliability. Elements and Facilities operated at voltages of 100kV or higher, including
Radial Transmission systems, may be excluded and Elements and Facilities operated
at voltages less than 100kV may be included if approved through the BES definition
exemption process.
NextEra maintains that this is not the correct starting point, nor consistent with Order No.
743 or the other material posted by NERC, that suggests a more definitive separation of the
BES definition from the exemption process. Thus, NextEra proposes that the definition be
revised to read as follows:
Bulk Electric System: All Transmission and Generation Elements and Facilities
operated at voltages of 100 kV or higher, unless a Transmission or Generation
Element or Facility has been exempted pursuant to the exemption process set forth in
the NERC Rules of Procedure. Official Comment form for BES Definition
Exception Process This proposed BES definition more clearly and cleanly separates
the BES definition from the exemption process. It also does not add unnecessary
qualifiers or verbiage that may result in confusion.
NextEra is also concerned that the working group assigned to the exemption process may
initially be more focused on developing categories, instead of an exemption process and
associated criteria. Given the unique circumstances of the interconnected BES, including
system topology, NextEra does not believe that it would be a productive exercise for the
exemption working group to focus on types, groups or categories of equipment; instead, its
efforts should focus on developing specific objective criteria to judge the reasonableness of a
request or application for an exemption. This approach also seems more in line with FERC’s
statement in Order No. 743 at paragraph 115:
NERC should develop an exemption process that includes clear, objective,
transparent, and uniformly applicable criteria for exemption of facilities that are not
necessary for operating the grid. The ERO also should determine any related changes
to its Rules of Procedures that may be required to implement the exemption process,
and file the proposed exemption process and rule changes with the Commission.
The challenges of developing an exemption process also include ensuring than any applicant
is afforded due process and balanced decision‐making, as required by section 215 of the
Federal Power Act. Thus, the exemption process must address legal, regulatory and technical
issues.
Accordingly, NextEra requests that NERC assemble a working group (perhaps via the
Standards Committee) to develop the exemption process that is comprised of stakeholders
Page 47 of 48

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
January 27, 2011

with legal, regulatory and technical experience. Without this balance of disciplines, NextEra
is concerned that a technical‐heavy working group will attempt to develop a “fix,” instead of
a process whereby applicants may request an exemption, and have that exemption judged by
specific criteria and pursuant to a process that affords due process and balanced
decision‐making.
It is not clear whether an exemption working group has already been assembled. If it has,
NextEra requests that NERC consider restructuring of the group consistent with NextEra’s
proposal.
In summary, NextEra requests that the BES definition drafting team adopt NextEra’s
proposed definition of BES. NextEra also requests that NERC assemble a cross‐functional
working group to develop an exemption process based on specific criteria (rather than
categories), and a process that affords applicants due process and balanced decision‐making.

Page 48 of 48

Attachment 1b.1 - Manny Robledo, City of Anaheim

Attachment 1b.2 - Manny Robledo, City of Anaheim

Attachment 1b.2 - Manny Robledo, City of Anaheim

Attachment 1b.4 - David Angell, Idaho Power
Official Comment form for BES Definition Exception Process

LEGEND

BOIBRO11
1.06 pu

230 kV Line

ONTARIO
1.02 pu

138 kV Line

BOIBRO21
1.06 pu
A

230/138 kV Transformer

BOIBRO31
1.07 pu

A

Amps

Amps

CALDWELL
1.01 pu

BOIHOR41
1.07 pu
A

A

GARNET
1.01 pu
A

LOCUST
1.01 pu

NAMPA TP
1.01 pu

96.3 Mvar

BOISEBCH
1.01 pu

A

BOIMID31
1.04 pu

Amps
A

HUBBARD
1.02 pu

A

Amps
Amps

Amps

A

A

Amps

Amps

DRAM
1.01 pu

Amps
A

Amps

A

A

Amps

Amps
A

Amps

BOISEBCH
1.03 pu
A

0.0 Mvar
LOCUST
1.03 pu

MVA

A

H.P.
1.02 pu
A

A

JOPLIN
1.02 pu

EAGLE TP
1.02 pu

GARY
1.02 pu

A

Amps

Amps

Amps

DRY CRK
1.02 pu

Amps

A

TENMILE
1.03 pu

A

50.4 MW
1.0 Mvar
STAR
1.02 pu

A

EAGLE
1.02 pu

Amps

50.4 MW
1.2 Mvar

63.2 MW
4.2 Mvar

CLOVRDAL
1.03 pu

Amps

1.0 Mvar
41.0 MW

A

USTICK
49.3 MW 1.02 pu
9.5 Mvar

Amps
A

Amps

44.8 MW
2.3 Mvar

20.0 MW
A
0.8 Mvar

Amps

66.8 MW
7.8 Mvar

BCRT
1.03 pu

64.2 MW
-3.1 Mvar

GARY TAP
1.02 pu

Amps

A

Amps

MVA

A

BOISE
1.02 pu

A

WYE
1.02 pu

Amps

19.3 MW
2.5 Mvar

0.0 Mvar

MVA

Amps

A

0.0 Mvar

A

4.6 MW
1.7 Mvar

Amps

A

A

A

Amps

Amps
Amps

33.3 MW Amps BLACKCAT MERIDIAN
2.2 Mvar
1.02 pu A 1.02 pu

A

MVA

A

A
Amps

MVA

CART
63.5 Mvar
1.03 pu

A

Amps

A

14.3 MW
7.3 Mvar

A

0.0 Mvar

A

MVA

Amps

A

62.9 MW
3.3 Mvar

Amps

A

Amps

Amps

73.3 MW
-0.8 Mvar

GROVE
1.03 pu
A

67.7 MW
-4.0 Mvar

65.5 MW
2.2 Mvar

Amps

BUTLER
1.03 pu
50.3 MW
3.1 Mvar

c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: Large load-serving substations require non-radial service to ensure acceptable reliability
performance. Such transmission systems do not carry bulk power transfers as there are substantial
higher voltage transmission lines that surround the metro area which carry the bulk transfers. Idaho
Power has evaluated serving the area from systems that are sourced from only a single bulk substation.
Such a configuration would result in requiring an additional 100 miles of transmission to compared to
the existing network configuration.

RTLSNAKE
1.03 pu

Attachment 1b.5 - Paul Cummings, City of Redding

Official Comment form for BES Definition Exception Process

Attachment 1
DRAFT Bulk Electric System Facilities
Excerpts from Proposal 6 – 1/5/11
Date: not yet approved
I.

CLASSIFICATION

The following Table provides the framework for classification of Elements as BES or non-BES.
In addition, the Table identifies the Elements which are subject to inclusion or exclusion based
on the process set forth in Appendix A
Description of Element

A
B

C

D
E

F

Elements that provide Nuclear Off-Site Power
Supply
Elements that interconnects aBackstart Resource,
or are part of a black-start Cranking Path 1 as
included in the system restoration plan 2 of a
Transmission Operator or Balancing Authority.
Elements that are part of a WECC Transfer Path
identified in the list of Major WECC Transmission
Paths in Attachment 2, TOP-007-WECC-1.
Elements operated above 100 kV (except G and H
below)
Generating Units and the associated Generator
Interconnection Elements operated at or above
100 kV that meet the registration criteria in
Section III (c) of NERC’s Statement of
Compliance Registry Criteria.
Elements operated below 100 kV.

Included in
BES and
cannot be
excluded
through an
exception
process
regardless of
voltage level

Included in
BES but
could be
excluded
through an
exception
process

Not included
in BES. Could
be included
through an
exception
process

Yes
Yes
Yes
Yes
Yes
Yes

1

Cranking Path is defined in the NERC Glossary.

2

NERC Standard EOP-005, Attachment 1 sets forth the elements for consideration in a system restoration plan.

Attachment 1b.5 - Paul Cummings, City of Redding

Official Comment form for BES Definition Exception Process

Description of Element

Included in
BES and
cannot be
excluded
through an
exception
process
regardless of
voltage level

Included in
BES but
could be
excluded
through an
exception
process

Not included
in BES. Could
be included
through an
exception
process

G

Qualifying Radial Elements operated below 200
kV.

Yes

H

Local Distribution Networks operated below 200
kV.

Yes

Table 1 – BES Classification
II.

DEFINITIONS

Automatic Fault
Interrupting
Device (AFID)
Demarcation Point
Local Distribution
Network

A device that operates automatically (i.e., without operator intervention) to
interrupt fault current. Such devices include circuit breakers, vacuum interrupters,
and fuses.
A physical location that indicates a change from BES Elements to non-BES
Elements.
Local Distribution Networks are groups of Elements that function to distribute
power to load rather than to transfer bulk power from location to location. Local
Distribution Networks are connected to the BES at more than one location to
improve the level of service to retail customer load. Local Distribution Networks
must meet the following requirements:
a. Must be connected through automatic fault-interrupting
devices. All Local Distribution Network connections to BES
Elements must be through Automatic Fault-Interrupting
Devices.
b. Limits on connected generation. If the network includes
generation, it qualifies as a Local Distribution Network only if:
(1) no single generator or line contingency could cause the loss of
generation larger than the threshold for Generator
Operator/Generator Owner registration set forth in the NERC
Statement of Compliance Registry Criteria, and (2) the generation
has not been designated, or is under contract, as a “must-run”
generator or otherwise required to operate under some
circumstances for BES transmission reliability.
c. Power flows into the Local Distribution Network. Net power
flows into, not out of, the Local Distribution Network under
non-contingency conditions. “Net” power means the algebraic

Attachment 1b.5 - Paul Cummings, City of Redding
Official Comment form for BES Definition Exception Process

sum of flows at all points at which the Local Distribution
Network connects to the BES. This requirement may be
demonstrated by providing (1) any continuous 8760-hour meter
data within the last two years from all boundary points of the
Local Distribution Network or (2) if continuous 8760-hour data
is not available, the entity and WECC Staff may mutually agree
upon a data period.
d. Not used to transfer bulk power


The Local Distribution Network does not have, or
contribute to, an established Path rating, WECC Operating
Transfer Capability, nor a published TTC for flow through
the Local Distribution Network.

•

Opening one or more connections from the Local
Distribution Network to the BES does not decrease (but
may improve), the established WECC Transfer Capability
of (a) parallel transfer path(s) or Elements.
The Local Distribution Network is not used to schedule
energy originating outside of the Local Distribution
Network for delivery across and outside the Local
Distribution Network to other entity systems that are
otherwise physically interconnected through to the BES by
interconnections with third party systems.



A Local Distribution Network that does not meet the criteria for
exemption in this definition may be excluded from the BES by
demonstrating that it is not necessary for the operation of an
interconnected transmission system through the process set forth in
Appendix A to this Policy.
Element
Generator
Interconnection
Elements

Qualifying Radial
Element

Element means any electrical device with terminals that may be connected to other
electrical devices such as a generator, transformer, circuit breaker, bus section, or
transmission line. An element may be comprised of one or more components.
Generator Interconnection Elements (GIEs) are sole-use facilities for the
purpose of connecting the generating unit(s) to the transmission grid. In this
regard, the sole-use facility only transmits power associated with the
interconnecting generator, whether delivered to the grid or delivered to the
generator for station service or auxiliary load, or delivered to meet cogeneration
load requirements.
These GIEs are BES Elements to the extent that their connected generating units
are considered part of the BES. The point of interconnection with the transmission
system is the location at which operating responsibility for the Generator
Interconnection Facility changes between the Transmission Operator and the
Generator Operator. The principles expressed in this definition cannot and will not
take effect until the relevant standards are modified to apply to these GIEs as
Generator Owners and Generator Operators.
Qualifying Radial Elements are radial Elements that meet the following criteria:

Attachment 1b.5 - Paul Cummings, City of Redding
Official Comment form for BES Definition Exception Process

a. Normally not operated in parallel. Transmission Elements that
are normally operated as radial Elements are not deemed part of
the BES, even if the radial Elements can be connected to the BES
at more than one location through one or more normally open
switches. To qualify, normally open switches, if any, which can
be used to parallel the otherwise radial Elements, must be shown
in operating diagrams and/or operating procedures as normally
open. A normally open switch may be closed for a short period
of time only to avoid interruption of service when load is
transferred from one radial source to another radial source.
b. Limitations on connected generation. The radial Element does
not connect generating a unit or units which either (1) for any
single unit, is greater than 20 MVA and interconnected at or
above 100 kV or, for multiple units, are greater than 75 MVA in
total or (2) has been designated and is under contract as a “mustrun” generator or otherwise required to operate under some
circumstances for BES transmission reliability.
c. Must be connected through an automatic fault-interrupting
device. Qualifying Radial Elements must be connected to the
BES through an Automatic Fault-Interrupting Device.
Elements connected to other Elements via a “hard tap” (not
through an Automatic Fault-Interrupting Device) carry the
same BES status as the Element to which they are connected.
However, a hard-tapped Element may still be excluded from the
BES through the material impact assessment set forth in
Appendix A.
If an Element meets all the requirements of a Qualifying Radial Element, all
Elements downstream from the Qualifying Radial Element are also excluded
from the BES. The upper extent of a set of Qualifying Radial Elements is
identified by its Demarcation Point.

III.

OTHER PROVISIONS

1. Demarcation Points. Please see Appendix C for a discussion regarding Demarcation Points.
2. Separate ownership. An Element that meets the qualifications for exclusion from the BES shall
be deemed non-BES. In the case in which two or more parties own separate (parts of a)
connected Element(s) that meet the qualifications for exclusion from the BES, nothing in this
policy is intended to preclude the owners of any non-BES Element(s) from voluntarily
complying with mandatory reliability standards related to that non-BES Element(s).

Attachment 1b.5 - Paul Cummings, City of Redding
Official Comment form for BES Definition Exception Process

Attachment 2

Appendix C – Draft 1/15/2011)
Demarcation Principles
The following points serve to explain the rationale for the demarcation points between BES and Non-BES
elements. Note that the diagrams in this Appendix C are only intended to provide examples of the
demarcation between BES and non-BES, and not as a substitute for the narrative definition.

Summary of Principles

The demarcation principles are listed here along with a statement explaining the rationale for each, and
are depicted in the various single-line diagrams that follow.

Attachment 1b.5 - Paul Cummings, City of Redding
Official Comment form for BES Definition Exception Process

Principle 1:
A line connecting a BES bus to a bus that has been found to have no impact to the BES through the
application of an MIA, shall be designated BES.

Rationale:
As the MIA process is applied to individual power system buses, line elements that connect BES buses to
MIA-excluded non-BES buses represent a transition between BES and non-BES. The line connecting the
bus excluded from the BES by MIA to a BES bus shall be designated BES by default, because it is
indeterminate where along the line length the impact changes from material to immaterial to the
reliability of the BES. The demarcation point is the physical connection of the line to the non-BES bus.

Attachment 1b.5 - Paul Cummings, City of Redding

Official Comment form for BES Definition Exception Process

Principle 2:
A radial line having an operating voltage greater than 200kV is designated as BES from its point of
connection with its source up to the point where the line is terminated at a physical disconnect switch
within a receiving substation, or, if no switch exists in the receiving substation, the high side bushings of
the receiving substation transformer(s).

Rationale:
A radial line operated at above 200kV is brought into the BES through footnote 4 of the NERC Statement
of Compliance Registry Criteria, provided, however, this line may be excluded through the MIA process.

Attachment 1b.5 - Paul Cummings, City of Redding
Official Comment form for BES Definition Exception Process

Principle 3:
Except for Generator Step-up Transformers (GSU), provided that the high voltage side of a transformer is
primarily protected by an Automatic Fault Interrupting Device (AFID), the transformer always takes the
status of the low voltage side. For GSU’s, the transformer’s classification is that of the associated
Generator Interconnection Element(s).

Rationale:
The presence of an AFID (or in the instance of ring bus or breaker-and-a-half scheme, AFIDs) allows the
transformer to be considered as a separable unit serving the function of providing connection and
transformation of the high side to the low side. Where the electric facilities on the low side are nonBES, the transformer is simply an extension of these non-BES facilities, providing delivery and
connectivity from the BES source. For a GSU, the transformer is clearly an extension of the functionality
provided by the Generator Interconnection Element(s), namely, to move bulk power from the BES
generator to the BES network, and hence, the classification of the GSU must be matched to the GIE.

Attachment 1b.5 - Paul Cummings, City of Redding
Official Comment form for BES Definition Exception Process

Principle 4:
The connection of a 200 kV or higher voltage bus to a non-BES transformer is also designated non-BES
provided that the connection in its entirety is located within the confines of a substation/switching
station perimeter.

Rationale:
Within a substation, the connection from the BES to the non-BES transformer is considered to be an
extension of the transformer itself. Had the lead line to this transformer extended outside the confines
of the substation, it would be considered to be a line, rather than a bus extension, and would be
addressed in a fashion similar to Principle 2 above.

Attachment 1b.5 - Paul Cummings, City of Redding

Official Comment form for BES Definition Exception Process

Principle 5:
A line directly connecting one BES bus to another BES bus shall also be designated as BES.

Rationale:
As both BES buses in question are directly connected to one another via a line element, that line
element becomes an integral part of the BES. Note that this only affects direct connections between
BES buses. If transformations or other intermediary network facilities are electrically connected
between the bounds of two BES buses, they may qualify for Local Distribution Network exclusion from
the BES.

Attachment 1b.5 - Paul Cummings, City of Redding
Official Comment form for BES Definition Exception Process

Principle 6:
Where power flows through an AFID and connecting elements from a 200kV or lower BES bus solely to a
non-BES element, that AFID and connecting elements shall be deemed non-BES. If the flow serves a BES
element or a combination of BES and non-BES elements, the AFID and connecting elements carrying such
dual purpose flow shall be considered to be BES.

Rationale:
Where the sole use of an element is to provide connectivity from the BES to a non-BES element, the
element itself is serving an entirely non-BES function. This applies only to 200kV and below, as above
200kV, footnote 4 of the NERC Statement of Compliance Registry Criteria becomes applicable. (See
Principle 2 above.) If any of the flow on the subject element also serves (flows through?) a BES element,
the element is serving a BES function, and it should therefore be classified as BES. [The concept of “BES
flow” makes me wonder if we won’t have to define what “BES flow” is.]
Principle 7:

Attachment 1b.5 - Paul Cummings, City of Redding

Official Comment form for BES Definition Exception Process

The continuous path at a common voltage within a substation between two BES buses shall also be
designated as BES.

Rationale:
This is similar to Principle 5. The direct connection between BES buses is carrying BES flow, and hence, is
serving a BES function.

Attachment 1b.5 - Paul Cummings, City of Redding
Official Comment form for BES Definition Exception Process

Principle 8:
While Transmission Protection Systems are not elements of the BES, owing to the fact that they are
secondary voltage sensing/control systems, some Transmission Protection Systems affect the reliability
of the Bulk Electric System. Particularly, the Protection Systems associated with BES equipment (those
that initiate opening of BES interrupting devices) shall be deemed to “affect the reliability of the BES” as
in the context of NERC Standard PRC-005-1.

BDT - This diagram does not go with principle 8 and will be deleted from principle 8, but a principle 9
should probably be added to elaborate on the demarcation point between a non-BES generator and the
BES.
Rationale:
Per the text in NERC Standard PRC-005-1, Transmission Protection Systems may “affect the reliability of
the Bulk Electric System”, and these are the ones that are subject to the requirements of this Standard.
Therefore, it is recognized that Transmission Protection Systems themselves, are not BES components,
but certainly may affect the reliability of the BES. Transmission Protection Systems that detect faults on
non-BES elements and initiate opening of only non-BES elements do not have any impact on the
reliability of the BES. However, certain backup protection systems for non-BES elements (for example,
breaker failure protection schemes) can initiate the opening of BES breakers. [All Transmission
Protection Systems whose purpose is to detect faults on the BES clearly have an effect on the reliability
of the BES.

Attachment 1b.6 - John W. Delucca, Lee County Electric Cooperative

FRCC Bulk Electric System
Purpose:
The Bulk Electric System, as defined by the NERC Reliability Standards Glossary, provides the ability to define
and specify detail on a regional basis. The NERC definition is:
“As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment, generally
operated at voltages of 100 kV or higher. Radial transmission facilities serving only load with one
transmission source are generally not included in this definition.”
The FRCC Regional Entity is further defining the definition to clarify and reduce ambiguity.

The Bulk Electric System within the FRCC footprint is defined as all:
1. Electrical generation resources greater than 20 MVA (gross nameplate rating) or a generation plant
with aggregate capacity greater than 75 MVA ((gross aggregate nameplate rating) including
generator step-up (GSU) transformers and associated equipment from the generator terminals to
the high side of the GSU)) connected at voltages of 100 kV or higher (high side of GSU).
2. Transmission Elements and associated equipment, operated at voltages of 100 kV or higher.
3. Transformers (other than generator step-up (GSU) transformers) with both primary and secondary
windings of 100 kV or higher.
The FRCC Bulk Electric System excludes:
Any radial Transmission Element or System connected from one transmission source to load serving
Elements and/or generation resources not included in item 1 above, where a loss of the radial
Elements or System will not result in an Adverse Reliability Impact.
Generating plant control and operation functions which include relays and systems that control and
protect the unit for boiler, turbine, environmental, and/or other plant restrictions.
All other Elements operated at voltages below 100 kV.

Final Version 9/1/2010

Approved by the FRCC Board of Directors ________
Effective Dates:
FRCC BES Definition, Appendix A: Clarification to the FRCC Bulk Electric System (BES) Definition
for Radial Transmission Elements or Systems Exclusion, and Appendix C: Adverse Reliability
st
rd
Impact Study Requirements: 1 day of the 3 calendar quarter following regulatory approval.
st
Appendix B: FRCC regional application of the term “transmission Protection Systems”: 1 day of
th
the 7 calendar quarter following regulatory approval.

Attachment 1b.6 - John W. Delucca, Lee County Electric Cooperative
Supporting Documentation
a) See Appendix A for further clarification of radial Transmission Elements or Systems.
b) See Appendix B for further clarification of transmission Protection Systems.
c) See Appendix C for further clarification of Adverse Reliability Impact Study requirements.

Final Version 9/1/2010

Attachment 1b.7 - John W. Delucca, Lee County Electric Cooperative

Appendix A
Clarification to the FRCC Bulk Electric System (BES) Definition for Radial Transmission Elements or
Systems Exclusion
This is a clarification to the FRCC BES definition exclusion list regarding the exclusion of radial
Transmission Elements / System. Since it is impractical to document every situation for exclusion of
radial Transmission Elements / System, examples are provided for general clarification.
The exclusion states: “Radial Transmission Element or System connected from one transmission source
to load serving Elements and/or generation resources not included in 1) above …”, in general,
unregistered generation1, “… where a loss of the radial Elements or System will not result in an Adverse
Reliability Impact”.
There are a few principles that are applied in determining if radial Elements / Systems are excluded:
o Radial System can be a collection of parallel Elements as long as the radial System originates at
one transmission source and that the System does not connect to a second transmission source
under normal operations.
o

FRCC considers normal operations (i.e. normal system configuration) in determining
whether Elements / Systems are radial and does not consider alternate configurations.
For instance, entities may install normally open switches between radial Elements/
Systems and operate the switches in a ‘make-before-break’ fashion to allow for system
reconfiguration to maintain continuity of electrical service to customers.

o One transmission source is a contiguous bus configuration (e.g. ring bus, breaker-and-a-half
scheme, etc.) comprised of one or more BES Elements operated at one voltage level 100kV or higher.
o Adverse Reliability Impact is as defined in the NERC Glossary of Terms. Studies are necessary to
determine if an Adverse Reliability Impact can result from the loss of a radial Element / System if
the peak loads or generation resources within the radial Element / System exceed one-half of the
largest single loss of source contingency in the FRCC region. Studies will be performed by the
responsible entity and approved by the FRCC Planning Committee.

1

Unregistered generation means that generation that does not meet the registration criteria described in NERC’s Statement
of Compliance Registry Criteria.
Final Version 9/1/2010

Approved by the FRCC Board of Directors ________
Effective Dates:
FRCC BES Definition, Appendix A: Clarification to the FRCC Bulk Electric System (BES) Definition for
Radial Transmission Elements or Systems Exclusion, and Appendix C: Adverse Reliability Impact
st
rd
Study Requirements: 1 day of the 3 calendar quarter following regulatory approval.
st
Appendix B: FRCC regional application of the term “transmission Protection Systems”: 1 day of the
th
7 calendar quarter following regulatory approval.

Attachment 1b.7 - John W. Delucca, Lee County Electric Cooperative

Appendix A: Radial Transmission Elements / Systems Exclusions

The following examples are provided for clarification of where the boundary between BES and radial
exclusions are located.

Final Version 9/1/2010

Page 2 of 8

Attachment 1b.7 - John W. Delucca, Lee County Electric Cooperative

Appendix A: Radial Transmission Elements / Systems Exclusions
Example One:

Line 1

A

Line 2

BES
Non-BES
> 100kV
< 100kV

In this example:
Lines 1 & 2, breaker ‘A’ and the associated buses (> 100kV) are part of the BES.
o

The > 100 kV bus is the single transmission source.

Radial Exclusion:
o

Both transformers and the illustrated switches are radial and excluded from the definition of the
BES as long as the loss of the < 100 kV bus does not result in an Adverse Reliability Impact.

The border between BES and non-BES is at the bus (source) side of the > 100 kV transformer switches.

Final Version 9/1/2010

Page 3 of 8

Attachment 1b.7 - John W. Delucca, Lee County Electric Cooperative

Appendix A: Radial Transmission Elements / Systems Exclusions
Example Two:

Line 3

Line 2
B

A

C
Line 4

E

D

F

BES
Non-BES

Switch A

Line 1

Switch B
> 100kV
< 100kV
LOAD

In this example:
Lines 2, 3 and 4 are networked lines and part of the BES.
Radial Exclusion:
o

Line 1 and associated switch are radial and are not part of the BES, as long as the loss of the radial
system or portions thereof does not cause an Adverse Reliability Impact.

o

The transformer and associated switch are not part of the BES.

The border between BES and the radial exclusion would be at bus (source) side of the Line 1 switch.
If Switch A at the top of Line 1 does not exist then the BES/non-BES dashed line moves down to the source
side of Switch B connected to Line 1.

Final Version 9/1/2010

Page 4 of 8

Attachment 1b.7 - John W. Delucca, Lee County Electric Cooperative

Appendix A: Radial Transmission Elements / Systems Exclusions
Example Three:
A

Line 1

Line 2

C

B

Substation 1

D
BES
Excluded Radial System
(Non-BES)
Line 3

Line 4

E

F

G

Substation 2

> 100kV
< 100kV

LOAD

Unregistered Generation

In this example:
Lines 1 and 2 and substation 1 are part of the BES.
Radial Exclusion:
o

Lines 3 and 4, substation 2, and the transformers comprise the radial system since it serves only
load and unregistered generation and is excluded from the BES as long as the loss of the radial
system, or portions thereof (e.g., loss of all generation without loss of load, visa versa, or loss of
the entire radial system) does not cause an Adverse Reliability Impact.

The border between BES and the radial exclusion would be at bus (source) side of the Line 3 & 4 line
switches at substation 1.
Final Version 9/1/2010

Page 5 of 8

Attachment 1b.7 - John W. Delucca, Lee County Electric Cooperative

Appendix A: Radial Transmission Elements / Systems Exclusions
Example Four:

Line 1

Line 2

A

C

B

D

Substation Boundary

BES
Excluded Radial System
(Non-BES)

> 100kV
> 100kV

E

G

F

H
E
LOAD

LOAD

Line 1, Line 2 and the ring bus comprised of breakers A, B, C and D are part of the BES.
Radial Exclusion:
o

The transformers, the ring bus comprised of breakers E, F, G and H and the radial Elements
serving only load emanating from that ring bus comprise the radial system as long as the loss of
the radial system does not cause an Adverse Reliability Impact.

The border between BES and the radial exclusion would be at bus (source) side of the transformer
switches on the high side of the transformers.

Final Version 9/1/2010

Page 6 of 8

Attachment 1b.7 - John W. Delucca, Lee County Electric Cooperative

Appendix A: Radial Transmission Elements / Systems Exclusions
Example Five:

A

Line 1

B

BES
Excluded Radial System
(Non-BES)

*
> 100kV
< 100kV

* Motor-Operated
Disconnect Switch or
Circuit Switcher

LOAD

In this example:
Line 1 is a network line supplying a tapped substation, and the line, including the tapped segment to the
radial substation, is part of the BES since the entire line is operated as a single BES Element.
Radial Exclusion:
o

The tap substation is radial and not part of the BES as long as the loss of the radial system or
portions thereof does not cause an Adverse Reliability Impact.

The boundary between the BES and the radial exclusion is at the line (source) side of the switch at the
tapped substation.

Final Version 9/1/2010

Page 7 of 8

Attachment 1b.7 - John W. Delucca, Lee County Electric Cooperative

Appendix A: Radial Transmission Elements / Systems Exclusions
Example Six:

Line 1

Line 2

A

C

B

Substation 1

D

Line 3

Line 4

E

Line 5
G

F

Normally
Closed Switch

Line 6

Substation 2

H

Normally
Open Switch

BES
Excluded Radial System
(Non-BES)
> 100kV
< 100kV
LOAD

In this example:
Lines 1, 2, 3 & 4 and Substations 1 and 2 are part of the BES.
Radial Exclusion:
o

Line 5 & 6 and the associated switches are radial and are not part of the BES as long as the loss of
the radial systems or portions thereof does not cause an Adverse Reliability Impact.

o

The transformer and associated switch are not part of the BES.

Note: ‘Make-before-break’ switching to change the source from Substation 1 to Substation 2 does not void the
radial exclusion.
The border between BES and the radial exclusion would be at bus (source) side of the Line 5 & 6 line
switches at Substations 1 & 2 respectively.
Final Version 9/1/2010

Page 8 of 8

Attachment 1b.8 - John W. Delucca, Lee County Electric Cooperative

Appendix B
FRCC regional application of the term “transmission Protection Systems”
This is a clarification of the FRCC regional application of the term “transmission Protection
Systems” as used in the PRC -series Reliability Standards Since it is impractical to document
every situation for Protection Systems, examples are provided for general clarification.
Protection Systems, as defined by this Appendix B, are included in the definition of
“transmission Protection Systems” for application of NERC PRC-series Reliability Standards.
Protection Systems included in the application of the term “transmission
Protection Systems”:
o Protection Systems that detect faults on transmission elements (lines,
buses, transformers, etc.) identified as being included in the Bulk
Electric System (BES) and trips an interrupting device that interrupts
current supplied directly from a BES Element.

The following examples are provided for clarification of the definition of “transmission
Protection Systems”.
In general, a two step process is followed:
1. Identify which Elements are considered BES
2. Determine which Protection Systems detect faults on transmission elements (lines, buses,
transformers, etc.) identified as being included in the Bulk Electric System (BES) and trip an
interrupting device that interrupts current supplied directly from a BES Element.
Note: Isolation/disconnect switches are omitted in these examples (i.e., breaker disconnects, transformer
isolation, etc.) except where such switches are relevant to operation of transmission Protection Systems.

Final Version 9/1/2010

Approved by the FRCC Board of Directors ________
Effective Dates:
FRCC BES Definition, Appendix A: Clarification to the FRCC Bulk Electric System (BES)
Definition for Radial Transmission Elements or Systems Exclusion, and Appendix C:
st
rd
Adverse Reliability Impact Study Requirements: 1 day of the 3 calendar quarter
following regulatory approval.
Appendix B: FRCC regional application of the term “transmission Protection Systems”:
st
th
1 day of the 7 calendar quarter following regulatory approval.

Attachment 1b.8 - John W. Delucca, Lee County Electric Cooperative

Appendix B – Clarification of “transmission Protection Systems”
Example One:

A

Line 1

B

BES
Excluded Radial System
(Non-BES)

*
> 100kV
< 100kV

* Motor-Operated
Disconnect Switch or
Circuit Switcher or
Breaker

LOAD
In this example:
Circuit breakers ‘A’ and ‘B’ and Transmission Line 1 are part of the BES.
Protection Systems for Transmission Line 1 including the radial tap are “transmission Protection
Systems.”
The transformer and associated switches are not part of the BES.
Protection Systems for the transformer are not “transmission Protection Systems” because the
transformer is not a BES Element.

Final Version 9/1/2010

Page 2 of 5

Attachment 1b.8 - John W. Delucca, Lee County Electric Cooperative

Appendix B – Clarification of “transmission Protection Systems”
Example Two:

A

Line 1

Line 2

BES
Non-BES

*

*

> 100kV
< 100kV

B

C

D

E

F

G

* Motor-Operated
Disconnect Switch or
Circuit Switcher or
Breaker

In this example:
Circuit breaker ‘A’ and Transmission Lines 1 & 2 are part of the BES.
The transformers and associated switches are not part of the BES.
Protection Systems for Transmission Lines 1 & 2 are “transmission Protection Systems”.
Protection Systems for the transformer are not “transmission Protection Systems” because the
transformer is not a BES Element.

Final Version 9/1/2010

Page 3 of 5

Attachment 1b.8 - John W. Delucca, Lee County Electric Cooperative

Appendix B – Clarification of “transmission Protection Systems”
Example Three:
Line 3

Line 2
B

A

C

West Bus

East Bus

Line 4
E

D

F

BES
Non-BES

Line 1

> 100kV
< 100kV
LOAD
In this example:
Lines 2, 3 and 4 and the substation, including the East and West bus, are part of the BES.
Line 1, including the transformer and the associated switches, is radial and not part of the BES.
The Protection System for the bus/line between breakers D and E and the associated tap is a
“transmission Protection System.”
Protection Systems for the transformer are not “transmission Protection Systems” because the
transformer is not a BES Element.

Final Version 9/1/2010

Page 4 of 5

Attachment 1b.8 - John W. Delucca, Lee County Electric Cooperative

Appendix B – Clarification of “transmission Protection Systems”
Example Four:
A

Line 1

Line 2

C

B

Substation 1

D
BES
Excluded Radial System
(Non-BES)

Switch A

Switch B

Line 3

Line 4

E

F

G

Substation 2

> 100kV
< 100kV

LOAD

Unregistered Generation

In this example:

Transmission Lines 1 & 2 and circuit breakers A, B, C and D are part of the BES.
Circuit breakers ‘E’, ‘F’ and ‘G’, Transmission Lines 3 & 4 and the transformers are not part of the
BES.
The Protection Systems for the bus sections between breakers B and D and breakers C and D
including the bus sections connecting to the source side of Switch A and Switch B are
“transmission Protection Systems.”

Final Version 9/1/2010

Page 5 of 5

Attachment 1b.9 - John W. Delucca, Lee County Electric Cooperative

Appendix C
Adverse Reliability Impact Study Requirements
Purpose
Adverse Reliability Impact Study is the analysis (steady-state screening and if required dynamic
stability analysis) performed by a functional entity that wishes to apply for exclusion of a radial system
which exceeds the triggering parameter defined by the “Study Triggers” from the Regional Bulk Electric
System (BES).
Study Triggers
Studies are necessary to determine if an Adverse Reliability Impact1 can result from the loss of a
radial Element / System if the peak loads or generation resources within the radial Element / System
exceed one-half of the largest single loss of source contingency in the FRCC region.
If the entity’s proposed radial system is above the established triggering parameter the entity
will be required to perform an Adverse Reliability Impact Study and submit for approval in accordance
with the ‘Approval Process’ defined in this document. This impact study should evaluate the loss of the
proposed radial system applying the following study parameters.
Study Parameters
Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
Study FRCC Region transmission facilities to ensure that they remain within applicable
ratings and voltage limits.
Include loss of entire radial system as a contingency event.
At a minimum, studies should cover a five (5) year period.
Additional studies as requested by the FRCC Regional Entity Planning Committee.
Study Frequency
Adverse Reliability Impact Studies will be conducted every five (5) years or when system
configuration changes dictate a need for re-evaluation or as requested by the FRCC Regional Entity (RE)

1

The NERC Glossary of Terms (dated: April 20, 2009) defines Adverse Reliability Impact as: The impact of
an event that results in frequency-related instability; unplanned tripping of load or generation; or
uncontrolled separation or cascading outages that affects a widespread area of the Interconnection.
Final Version 9/7/2010

Approved by the FRCC Board of Directors ________
Effective Dates:
FRCC BES Definition, Appendix A: Clarification to the FRCC Bulk Electric System (BES)
Definition for Radial Transmission Elements or Systems Exclusion, and Appendix C:
st
rd
Adverse Reliability Impact Study Requirements: 1 day of the 3 calendar quarter
following regulatory approval.
Appendix B: FRCC regional application of the term “transmission Protection Systems”:
st
th
1 day of the 7 calendar quarter following regulatory approval.

Attachment 1b.9 - John W. Delucca, Lee County Electric Cooperative

Appendix C – Adverse Reliability Impact Study Requirements
Planning Committee (PC). FRCC Standing Committees may also make a request to the FRCC RE PC for
studies to be performed.
FRCC Regional Entity Planning Committee Approval Process
All requests for Radial Element/System Exclusions should be submitted to the FRCC RE PC for
review and approval. The FRCC RE PC will review the Adverse Reliability Impact Study (steady-state
screening and if required dynamic stability analysis) and will determine if the identified Radial
Element/System meets all criteria for exclusion.
Requests for radial exclusions (below triggering parameters) should include the
following:
o
o

Executive Summary/Outcome Justification
Assumptions and Methodologies

Requests for radial exclusions (at or above triggering parameters) should include the
following:
o
o
o

Executive Summary/Outcome Justification
Assumptions and Methodologies
Study Results

Final Version 9/7/2010

Page 2 of 2

Attachment 1b.10 - Steve Alexanderson P.E., Central Lincoln

Attachment 1b.11 - Steve Alexanderson P.E., Central Lincoln

Consideration of Comments on Definition of Bulk Electric System— Project
2010-17

Following the development of this report, the leadership of the BES Definition SDT and Rules
of Procedure teams met with the leadership of the Standards Program and the Standards
Committee and determined that the BES Definition SDT will assume responsibility for
working with stakeholders to identify what evidence is needed to support a request for an
exception to the BES definition.
The BES Definition team will solicit stakeholder input to identify the evidence an entity will
need to provide when submitting a request for an exception to the definition of BES. While
the determination of what evidence will be needed to support a request for a BES Definition
Exception will be developed using NERC’s standard development process, a decision on
where the final product will reside - in the definition of BES, or as an attachment (e.g., a
procedure identifying what evidence to produce when applying for a BES exception) to the
Rules of Procedure will be made jointly by the leadership of the Standards Program and the
Standards Committee at a later stage. Given the time constraints of this project, having all
the technical clarity associated with this project developed by a single team seemed the
most efficient decision.

The Definition of Bulk Electric System Drafting Team thanks all commenters who submitted
comments on the SAR and proposed modification to the definition of Bulk Electric System.
These standards were posted for a 30-day public comment period from December 17, 2010
through January 21, 2011. The stakeholders were asked to provide feedback on the
standards through a special Electronic Comment Form. There were 82 sets of comments,
including comments from more than 175 different people from approximately 129
companies representing 10 of the 10 Industry Segments as shown in the table on the
following pages.

http://www.nerc.com/filez/standards/Project2010-17_BES.html
Prior to the issuance of Order 743a, the SDT carefully weighed the many suggestions
received in these comments as well as reviewing numerous documents from Regional
Entities and other sources in coming up with a revised definition shown here:
Bulk Electric System (BES): All Transmission Elements operated at 100 kV or higher,
Real Power resources as described below, and Reactive Power resources connected at 100
kV or higher unless such designation is modified by the list shown below.
Inclusions:
•

I1 - Transformers, other than generator step-up (GSU) transformers, including phase
angle regulators, with two windings of 100 kV or higher unless excluded under
Exclusions E1 and E3.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Consideration of Comments on Definition of Bulk Electric System— Project 2010-17
•

•

•
•

I2 - Individual generating units greater than 20 MVA (gross nameplate rating)
including the generator terminals through the GSU which has a high side voltage of
100 kV or above.
I3 - Multiple generating units located at a single site with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) including the generator terminals
through the GSUs, connected through a common bus operated at a voltage of 100
kV or above.
I4 - Blackstart Resources and the designated blackstart Cranking Paths identified in
the Transmission Operator’s restoration plan regardless of voltage.
I5 - Dispersed power producing resources with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing a collector system through a
common point of interconnection to a system Element at a voltage of 100 kV or
above.

Exclusions:
•

•

•

E1 - Any radial system which is described as connected from a single Transmission
source originating with an automatic interruption device and:
a) Only serving Load. A normally open switching device between radial systems
may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5.
Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and
includes generation resources not identified in Inclusions I2, I3, I4 and I5.
E2 - A generating unit or multiple generating units that serve all or part of retail Load
with electric energy on the customer’s side of the retail meter if: (i) the net capacity
provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and
(ii) standby, back-up, and maintenance power services are provided to the
generating unit or multiple generating units or to the retail Load pursuant to a
binding obligation with a Balancing Authority or another Generator Owner/Generator
Operator, or under terms approved by the applicable regulatory authority.
E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV
that distribute power to Load rather than transfer bulk power across the
interconnected System. LDN’s are connected to the Bulk Electric System (BES) at
more than one location solely to improve the level of service to retail customer Load.
The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the
BES, the LDN must be connected through automatic fault-interrupting devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in
aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed
the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy
originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored
Facility of a permanent Flowgate in the Eastern Interconnection, a major transfer
path within the Western Interconnection as defined by the Regional Entity, or a

March 30, 2011

2

Consideration of Comments on Definition of Bulk Electric System— Project 2010-17
comparable monitored Facility in the Quebec Interconnection, and is not a
monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).
Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.
The SDT has made corresponding changes to the appropriate wording of the SAR and is now
asking the Standards Committee for approval to move this project to the definition
development phase.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at herb.schrayshuen@nerc.net. In addition, there is
a NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.

March 30, 2011

3

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Index to Questions:
1. Should the following be classified as part of the BES? ........................................................ 16
•
2.

Should the following be classified as part of the BES? ........................................................ 30
•

3.

Generation plants with aggregate capacity greater than 75 MVA (gross nameplate
rating) directly connected via a step-up transformer(s) to Facilities operated at voltages
below 100kV where the exemption process deems the generation plants to be included
in the BES ..................................................................................................................... 94

Should the following be excluded from the Elements and Facilities classified as part of the
BES? ................................................................................................................................... 106
•

9.

Individual generation resources greater than 20 MVA (gross nameplate rating) directly
connected via a step-up transformer(s) to Facilities operated at voltages below 100kV
where the exemption process deems the generation resources to be included in the BES
....................................................................................................................................... 81

Should the following be classified as part of the BES? ........................................................ 94
•

8.

Transmission Elements or Facilities operated at voltages below 100kV where the
exemption process deems the Element or Facility to be included in the BES .............. 71

Should the following be classified as part of the BES? ........................................................ 81
•

7.

Blackstart Resources and the designated blackstart Cranking Paths identified in the
Transmission Operator’s (TOP’s) restoration plan ....................................................... 59

Should the following be classified as part of the BES? ........................................................ 71
•

6.

Generation plants (including GSU transformers and the associated generator
interconnecting line lead(s))with aggregate capacity greater than 75 MVA (gross
nameplate rating) directly connected via a step-up transformer(s) to Transmission
Facilities operated at voltages of 100 kV or above ....................................................... 46

Should the following be classified as part of the BES? ........................................................ 59
•

5.

Individual generation resources (including GSU transformers and the associated
generator interconnecting line lead(s)) greater than 20 MVA (gross nameplate rating)
directly connected via a step-up transformer(s) to Transmission Facilities operated at
voltages of 100 kV or above ......................................................................................... 30

Should the following be classified as part of the BES? ........................................................ 46
•

4.

Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle
Regulators, with both primary and secondary windings of 100 kV or higher .............. 16

Any radial Transmission Element or System, connected from one Transmission source
to a Load-serving Element and/or generation resources not included in items 2, 3, 4, 6,
and 7 above are excluded from the BES ..................................................................... 106

Should the following be excluded from the Elements and Facilities classified as part of the
BES? ................................................................................................................................... 119
•

Elements and Facilities identified through application of the exemption process,
consistent with the criteria, where the exemption process deems that the Element or
Facility should be excluded from the BES (with concurrence from the ERO) .......... 119

March 30, 3011

4

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

10. Should the following be excluded from the Elements and Facilities classified as part of the
BES? ................................................................................................................................... 129
•

Generating plant control and operation functions which include relays and systems that
control and protect the unit for boiler, turbine, environmental, and/or other plant
restrictions ................................................................................................................... 129

11. Do you believe that the proposed definition of BES, accompanied by a separate BES
Definition Exception Process meets the reliability-related intent of the directives in Order
743? ..................................................................................................................................... 138
12. If you have a proposal for an equally efficient and effective method of achieving the
reliability- related intent of the directives in Order 743, please provide your proposal here.
157
13. Please provide any other information that you feel would be helpful to the drafting team
working on the definition of BES. ...................................................................................... 171

March 30, 3011

5

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Group

1.

Guy Zito

Northeast Power Coordinating Council

Additional Member Additional Organization

Region

3

4

5

6

7

8

9

10

X

Segment
Selection

1.

Alan Adamson

New York State Reliability Council, LLC

NPCC

10

2.

Gregory Campoli

New York Independent System Operator

NPCC

2

3.

Kurtis Chong

Independent Electricity System Operator

NPCC

2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC

1

5.

Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC

3

6.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC

10

7.

Dean Ellis

Dynegy Generation

NPCC

5

8.

Brian Evans-Mongeon

Utility Services

NPCC

8

9.

Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC

5

10.

Brian L. Gooder

Ontario Power Generation Incorporated

NPCC

5

11.

Kathleen Goodman

ISO - New England

NPCC

2

12.

Chantel Haswell

FPL Group, Inc.

NPCC

5

13.

David Kiguel

Hydro One Networks Inc.

NPCC

1

14.

Michael R. Lombardi

Northeast Utilities

NPCC

1

March 30, 3011

2

6

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

15.

Randy MacDonald

New Brunswick System Operator

NPCC

2

16.

Bruce Metruck

New York Power Authority

NPCC

6

17.

Lee Pedowicz

Northeast Power Coordinating Council

NPCC

10

18.

Robert Pellegrini

The United Illuminating Company

NPCC

1

19.

Si Truc Phan

Hydro-Quebec TransEnergie

NPCC

1

20.

Saurabh Saksena

National Grid

NPCC

1

21.

Michael Schiavone

National Grid

NPCC

1

22.

Bohdan Dackow

US Power Generating Company (USPG)

NPCC

NA

2.

Group

Charles W. Long

SERC EC Planning Standards Subcommittee

Additional Member Additional Organization

Region

Pat Huntley

SERC Reliability Corporation

SERC

10

2.

Bob Jones

Southern Company Services

SERC

1

3.

Darrin Church

Tennessee Valley Authority

SERC

1

4.

Jim Kelley

PowerSouth Energy Cooperative SERC

1

5.

John Sullivan

Ameren Services Co.

SERC

1

6.

Phil Kleckley

South Carolina Electric & Gas Co. SERC

1

Group

Patricia Hervochon

Additional Member

Public Service Enterprise Group Company

Additional Organization
PSE&G

RFC

1, 3

2. Scott Slickers

PSEG Fossil

RFC

5

3. Jim Hebson

PSEG ER&T

RFC

6

4. Dominic Grasso

PSEG Power CT

NPCC

5

5. Peter Dolan

PSEG ER&T

NPCC

6

6. Dominic DiBari

PSEG Fossil Odessa Ector Power Partners ERCOT 5

7. Eric Schmidt

PSEG ER&T

Group

March 30, 3011

Carol Gerou

4

5

6

X

7

8

9

10

X

X

X

X

X

Region Segment Selection

1. Jim Hubertus

4.

3

Segment
Selection

1.

3.

2

ERCOT 6

MRO's NERC Standards Review
Subcommittee

X

7

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Additional Member

Additional Organization
Omaha Public Utility District

MRO

1, 3, 5, 6

2. Chuck Lawrence

American Transmission Company

MRO

1

3. Tom Webb

Wisconsin Public Service Corporation MRO

3, 4, 5, 6

4. Jason Marshall

Midwest ISO Inc.

MRO

2

5. Jodi Jenson

Western Area Power Administration

MRO

1, 6

6. Ken Goldsmith

Alliant Energy

MRO

4

7. Alice Ireland

Xcel Energy

MRO

1, 3, 5, 6

8. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

9. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

10. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

11. Scott Nickels

Rochester Public Utilties

MRO

4

12. Terry Harbour

MidAmerican Energy Company

MRO

6, 1, 3, 5

13. Richard Burt

Minnkota Power Cooperative, Inc.

MRO

1, 3, 5, 6

Group

Al DiCaprio

IRC Standards Review Committee

Additional Member Additional Organization Region
Bill Phillips

MISO

2.

James Castle

NYISO NPCC

2

3.

Matt Goldberg

ISO-NE NPCC

2

4.

Greg Van Pelt

CAISO WECC

2

5.

Charles Yeung

SPP

SPP

2

6.

Dan Rochester

IESO

NPCC

2

7.

Mark Thompson

AESO

WECC

2

8.

Steve Myers

ERCT

ERCOT

2

Group

Frank Gaffney

4

5

6

7

8

9

10

X

Segment
Selection

1.

6.

3

Region Segment Selection

1. Mahmood Safi

5.

2

MRO

2

Florida Municipal Power Agency

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Tim Beyrle

City of New Smyrna Beach FRCC

4

2. Greg Woessner

KUA

3

March 30, 3011

FRCC

8

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

3. Jim Howard

Lakeland Electric

FRCC

3

4. Lynne Mila

City of Clewiston

FRCC

3

5. Joe Stonecipher

Beaches Energy Services FRCC

1

6. Cairo Vanegas

FPUA

FRCC

4

7. Randy Hahn

Ocala Electric Utility

FRCC

3

Group

7.

Denise Koehn

Bonneville Power Administration

Additional Member Additional Organization

Region

X

Sara Sundborg

BPA, Transmission, Technical Operations WECC

1

2.

John Anasis

BPA, Transmission, Technical Operations WECC

1

3.

Jim Gronquist

BPA, Transmission, Technical Operations WECC

1

4.

James O'Brien

BPA, Transmission, Technical Operations WECC

1

5.

Siraji Hirsi

BPA, Transmission, Technical Operations WECC

1

6.

Daniel Goodrich

BPA, Transmission, Technical Operations WECC

1

7.

Lorissa Jones

BPA, Transmission Reliability Program

1

Group

Doug Hohlbaugh

3

4

X

5

6

X

X

X

X

X

X

7

8

9

10

Segment
Selection

1.

8.

2

WECC

FirstEnergy Corp

X

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Rob Martinko

FirstEnergy Corp

Group

9.

Mike Garton

Additional Member Additional Organization

RFC

1, 3, 4, 5, 6

Electric Market Policy
Region

Segment
Selection

1.

Michael Gildea

Dominion Resources Services, Inc. NPCC

5

2.

Louis Slade

Dominion Resources Services, Inc. SERC

3

3.

Connie Lowe

Dominion Resources Services, Inc. RFC

5

4.

John Loftis

Dominion Virginia Power

1

10.

Group

March 30, 3011

Jim Case

SERC

SERC OC Standards Review Group

9

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Additional Member Additional Organization

Region

Gerald Beckerle

Ameren

SERC

1, 3

2.

Andy Burch

EEI

SERC

1, 5

3.

Randy Castello

Mississippi Power SERC

1, 3, 5

4.

Dan Roethemeyer

Dynegy

SERC

5

5.

Melinda Montgomery

Entergy

SERC

1, 3

6.

Sam Holeman

Duke Energy

SERC

1, 3, 5

7.

Joel Wise

TVA

SERC

1, 3, 5, 9

8.

Alvis Lanton

SIPC

SERC

1, 3, 5

9.

Hamid Zakery

Dynegy

SERC

5

10.

John Neagle

AECI

SERC

1, 3

11.

Mike Hirst

Cogentrix

RFC

5, 6

12.

Tim Hattaway

PowerSouth

SERC

1, 3, 5, 9

13.

Robert Thomasson

BREC

SERC

1, 3, 5, 9

14.

Shardra Scott

Gulf Power

SERC

1, 3, 5

15.

Patrick Woods

EKPC

SERC

1, 3, 5, 9

16.

Alisha Ankar

Prairie Power

SERC

1, 3, 5

17.

Bill Hutchison

SIPC

SERC

1, 3, 5

18.

J. T. Wood

Southern

SERC

1, 3, 5

19.

John Troha

SERC

SERC

10

Individual

Sandra Shaffer

PacifiCorp

X

Individual

Sylvain Clermont /
Alain Pageau

Hydro-Québec

X

13.

Individual

William J. Gallagher

Transmission Access Policy Study Group

X

14.

Individual

John Cummings

PPL Energy Plus

12.

March 30, 3011

3

4

5

6

7

8

9

10

Segment
Selection

1.

11.

2

X

X

X

X

X

X

X

X

X

10

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

X

5

X

6

15.

Individual

Jack Cashin

Competitive Suppliers

16.

Individual

Marty Kaufman

ExxonMobil Research and Engineering

17.

Individual

John Seelke

NERC Staff

18.

Individual

Janet Smith

Arizona Public Service Company

X

X

X

X

19.

Individual

Brian J. Murphy

NextEra Energy Inc.

X

X

X

X

20.

Group

David Dworzak

Edison Electric Institute

X

X

X

X

X

X

X

7

8

9

10

X

X

X

http://www.eei.org/whoweare/ourmembers/USElectricCompanies/Pages/USMemberCoLinks.aspx
21.

Individual

Brent Ingebrigtson

LG&E and KU Energy LLC

22.

Individual

Steve Alexanderson

Central Lincoln

23.

Individual

David Thorne

Pepco Holdings Inc.

X

24.

Individual

Martyn Turner

LCRA Transmission Services Corporation

X

25.

Individual

David W Proebstel

PUD No.1 of Clallam County

26.

Individual

Joe Petaski

Manitoba Hydro

27.

Individual

Kevin Koloini

American Municipal Power

28.

Individual

Robert Beadle

North Carolina EMC

29.

Individual

Jim Uhrin

ReliabilityFirst

March 30, 3011

X

X

X

X

X
X

X
X
X

X

X
X

11

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

6

7

8

30.

Individual

Elroy Switlishoff

on behalf of Teck Metals Ltd.

31.

Individual

Rex A Roehl

Indeck Energy Services

32.

Individual

Samuel Stonerock

Southern California Edison

X

X

X

33.

Individual

Patrick Farrell

Southern California Edison Company

X

X

X

34.

Individual

E Switlishoff

on behalf of Catalyst Paper Corporation

X

X

35.

Individual

Jeff Mead

City of Grand Island

X

36.

Individual

Michelle D'Antuono

Occidental Energy Ventures Corp

X

37.

Individual

Manny Robledo

City of Anaheim

38.

Individual

Josh Dellinger

Glacier Electric Cooperative

39.

Individual

Kathleen Goodman

ISO New England Inc.

40.

Individual

Ed Davis

Entergy Services

X

X

41.

Individual

John D. Martinsen

Snohomish County PUD

X

X

42.

Individual

Rick Paschall

PNGC Power

X

43.

Individual

Bud Tracy

Blachly-Lane Electric Co-op

X

X

44.

Individual

Dave Hagen

Clearwater Power Co.

X

X

45.

Individual

Dave Sabala

Douglas Electric Cooperative

X

March 30, 3011

X

5

9

10

X
X

X
X

X

X

X
X
X
X

X
X

12

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

Individual

Dave Markham

Central Electric Cooperative, Inc. (Redmond
Oregon)

X

47.

Individual

Heber Carpenter

Raft River Rural Electric Cooperative

X

48.

Individual

Jon Shelby

Northern Lights Inc.

X

49.

Individual

Ken Dizes

Salmon River Electric Cooperative

50.

Individual

Ray Ellis

Okanogan Country Electric Cooperative

X

51.

Individual

Richard Reynolds

Lost River Electric

X

52.

Individual

Rick Crinklaw

Lane Electric Cooperative

X

53.

Individual

Roger Meader

Coos-Curry Electric Cooperative

X

54.

Individual

Roman Gillen

Consumer's Power Inc.

X

X

55.

Individual

Steve Eldrige

Umatilla Electric Co-op

X

X

56.

Individual

Marc Farmer

West Oregon Electric Cooperative

X

57.

Individual

Michael Henry

Lincoln Electric Cooperative

X

58.

Individual

Bryan Case

Fall River Electric Cooperative

X

59.

Individual

Jonathan Appelbaum

United Illuminating Company

X

60.

Individual

David Burke

Orang and Rockland Utilities, Inc.

X

46.

March 30, 3011

X

4

5

6

7

8

9

10

X

X

13

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

61.

Individual

Andrew Z. Pusztai

american Transmission company

62.

Individual

John A. Gray

The Dow Chemical Company

63.

Individual

Brian Evans-Mongeon

Utility Services

Individual

Barry Lawson

National Rural Electric Cooperative
Association (NRECA)

65.

Individual

Andrew Gallo

City of Austin dba Austin Energy

66.

Individual

Laura Lee

67.

Individual

68.
69.

64.

3

4

X

X

X

X

X

X

Duke Energy

X

Hertzel Shamash

The Dayton Power and Light Company

X

Individual

Michael Moltane

ITC Holdings Corp

X

Individual

Bill Keagle

BGE

X

Amir Hammad

Constellation Power Source Generation, Inc.
(“CPSG”) filing on behalf of Constellation
Energy Group, Inc. (“CEG”), Constellation
Energy Commodities Group, Inc. (“CCG”),
Constellation Energy Control and Dispatch,
LLC (“CDD”), Constellation NewEnergy, Inc.,
(“CNE”) and Constellation Energy Nuclear
Group, LLC, (“CENG”)

Shaun Anders

City Water Light and Power (CWLP) Springfield, IL

Individual
Individual

March 30, 3011

5

6

7

8

9

10

X

X

70.

71.

2

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

14

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

72.

Individual

Steven Grega

Lewis County PUD

73.

Individual

Thad Ness

American Electric Power (AEP)

X

X

X

X

74.

Individual

Marc M. Butts

Southern Company

X

X

X

X

75.

Individual

David Angell

Idaho Power

X

X

X

Individual

John P. Hughes

Electricity Consumers Resource Council
(ELCON)

77.

Individual

Dan Rochester

Independent Electricity System Operator

78.

Individual

Jeff Nelson

Springfield Utility Board

79.

Individual

Jack Stamper

Clark Public Utilities

80.

Individual

Allen Mosher

APPA

81.

Individual

Alice Ireland

Xcel Energy

82.

Individual

Paul Cummings

City of Redding

X

X

83.

Individual

Manny Robledo

City of Anaheim

X

X

76.

March 30, 3011

7

8

9

10

X

X
X
X
X
X
X

X

X

X

X

X

X

15

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

1. Should the following be classified as part of the BES?
•

Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with both primary and
secondary windings of 100 kV or higher

Summary Consideration: Stakeholders who responded to this question were evenly divided with about half the respondents indicating support
for the proposal, and the other half disagreeing with at least some part of the proposal.
The SDT has clarified the definition based on industry comments regarding the classification of transformers.
Included in the BES: I1 - Transformers, other than generator step-up (GSU) transformers, including phase angle regulators, with two
windings of 100 kV or higher unless excluded under Exclusions E1 and E3.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an
automatic interruption device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’
fashion to allow for reliable system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not
identified in Inclusions I2, I3, I4 and I5.
Excluded from the BES: E3 - Local distribution networks (LDN): Groups of Elements operated above 100 kV that distribute power to Load
rather than transfer bulk power across the interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than
one location solely to improve the level of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through
automatic fault-interrupting devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA
generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through
the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent flowgate in the
Eastern Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a
comparable monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).

March 30, 3011

16

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
Northeast Power Coordinating
Council

Yes or No
No

Question 1 Comment
1. Exclusions should be applied to radial non-transmission facilities serving a distribution function.
Step-down transformers with the low-side terminals serving non-BES facilities, which are serving a
distribution function, should not be part of the definition of BES.
2. Transformers, other than GSUs, with both primary and secondary winding above 100kV, and performing a
transmission function, should be classified as BES.
3. Transformers other than GSUs, with both primary and secondary windings above 100kV, and only
providing a distribution function should be classified as non-BES.
4. Transformers other than GSUs, with their secondary windings or both primary and secondary windings
operated below 100kV should not be included in the definition of BES.

Response:
1. The SDT has excluded local distribution networks as shown:
• Excluded from the BES: E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV that distribute power to Load rather than
transfer bulk power across the interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to improve
the level of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting
devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the Quebec Interconnection,
and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
The SDT agrees with your suggestion and has incorporated it in its latest proposal.
2. The SDT agrees with your suggestion and has incorporated it in its latest proposal:
Included in the BES: I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two windings of 100 kV
or higher unless excluded under items E1 and E3.
Excluded from the BES: Any radial system which is described as connected from a single Transmission source originating with an automatic interruption

March 30, 3011

17

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment

device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.
3. The SDT feels that your comment does not illustrate a readily identifiable bright-line designation as there is no definition for distribution. However, the SDT
has determined that such transformers on a radial system will be non-BES.
4. The SDT agrees with your suggestion and has incorporated it in its latest proposal.
Electric Market Policy

No

Dominion could respond yes if the sentence read “All transformers, including Generator Step-up (GSU)
transformers and Phase Angle Regulators, with both primary and secondary windings of 100 kV or higher.

ExxonMobil Research and
Engineering

No

Transformers like all elements should be included based on their function; however, the use of an element's
rating or operating voltage may provide a good guideline for selecting elements to review for inclusion in the
BES.

Response: The SDT does not share your view on the inclusion of all transformers and feels that transformers used in Transmission and generation should be
included. The SDT agrees that operating voltage is a good guideline for applying the definition of BES.
PacifiCorp

March 30, 3011

No

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology. Significant
efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF) over the
course of the past year to identify some initial criteria and methodologies. These efforts are ongoing and
should be supported by the NERC drafting team. For example: Transformers should not be included or
excluded solely based on their voltage classifications (high side and low side). Transformers which are
necessary to operate the interconnected network should be included as part of the regulated BES.
Transformers which are not “necessary for the operation of the interconnected network” should be excluded.
A methodology needs to be developed to determine which transformers may be excluded as part of the

18

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
regulated BES.

Response: The SDT is aware of the WECC Bulk Electric System Definition Task Force’s efforts and has considered that work. The SDT has revised the
definition and included specific inclusion and exclusion designations. Bright-line designations will be developed as part of this project and the process will handle
any exceptions and those will be addressed through the revision of the Rules of Procedure which is a separate parallel effort to the development of the BES
definition by another team. Your comments will be forwarded to the Rules of Procedure Team.
Hydro-Québec

No

For questions 1 to 10, refer to questions 11 to 13.

Response: Please see responses to questions 11 to 13.
National Rural Electric
Cooperative Association
(NRECA)

No

This should not be dependent only on the voltage, but also on where the transformer, etc., is located on the
system. For example, if such a transformer is on a radial line of any transmission voltage that is serving only
load, then it should not be considered part of the BES.

Orange and Rockland Utilities,
Inc.

No

Exclusions should be applied to radial non-transmission facilities serving a distribution function. Step-down
transformers with the low-side terminals serving non-BES facilities, which are serving a distribution function,
should not be part of the definition of BES. Transformers, other than GSUs, with both primary and secondary
winding above 100kV should be classified as BES. However, it is our belief that transformers with either a
primary or secondary winding below 100kV should not be included directly or through the separate BES
Definition Exception Process.

City of Anaheim

No

Transformers with secondary windings of 100kV or less should not be part of the BES if they feed radial load
or radial distribution systems; provided, however, to eliminate any reliability gaps, such transformers should
be classified as "Distribution" equipment subject to DP standards, and the PRC and vegetation management
standards should be made applicable to Distribution Providers and including this equipment. This is
consistent with the NERC Reliability Functional Model and is more efficient than requiring TO/TOP
registration for radial transmission facilities that function as Distribution and are not required for the reliable
operation of the BES.

Southern California Edison
Company

No

The presence of an Automatic Fault Interrupting Device (or in the instance of a ring bus or breaker-and-a-half
configuration) allows the transformer to be considered as a separate unit serving the function of providing
connection and transformation of the high-side to the low-side. Where the electric facilities on the low-side are
below 100kV, the transformer is simply an extension of non-BES facilities, providing delivery and connectivity
from the BES sources.

March 30, 3011

19

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment

PPL Energy Plus

No

Certain transformers with primary and secondary windings greater than 100 kV may serve transmission lines
with only radial load and should therefore be excluded from the BES definition (without requiring application
for an exemption on a case-by-case basis). The BES definition should be modified to incorporate this
exclusion.

LG&E and KU Energy LLC

No

Certain transformers connected with both primary and secondary windings of 100 kV or higher serving only
radial load should be excluded from the BES definition (without requiring application for an exemption on a
case-by-case basis). The BES definition should be modified to incorporate this exclusion.

Central Lincoln

No

PUD No.1 of Clallam County

No

Lewis County PUD

No

While we believe the SAR is on the right track here, we note that many transformers with both windings above
100 kV may be installed on radial systems. We also note that the FERC order excepted “defined radial
facilities,” and expect NERC to provide a definition for “radial” so that facilities that meet this criteria may be
excluded by inspection rather than by going through an exemption process. It should also be clarified that
transformer protection systems are part of the BES only if installed to protect BES transformers.

Response: The SDT agrees with your suggestion and has incorporated it in its latest proposal.
•

Included in the BES: I1 - Transformers, other than generator step-up (GSU) transformers, including phase angle regulators, with two windings of 100 kV or
higher unless excluded under Exclusions E1 and E3.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5.

American Municipal Power

No

Occidental Energy Ventures Corp

No

This would require further study in order to answer in the affirmative.

Response: Thank you for your comment.

March 30, 3011

20

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
Indeck Energy Services

Yes or No

Question 1 Comment

No

The threshold issue is whether the equipment affects the reliability of the Bulk Power System, as defined in
the FPA. By requesting a BES definition that greatly expands the jurisdiction of the NERC Standards beyond
the scope of the BPS, FERC and NERC are outside of their legal jurisdiction. NERC is responsible to the
FPA through the FERC, but not to the FERC instead of the FPA. NPCC had the correct approach until FERC
required it to register every entity down to 20 MW. Reliability is the issue, and in a 30,000+ MW system like
NYISO, a 20, 50 or 150 MW piece of equipment cannot cause a Reportable Disturbance (under NERC's
definition), so how can it have a significant impact on reliability? Deferring the development of the exemption
process to a separate, and possibly much delayed, process of modifying the Rules of Procedure is
disingenuous.

Response: The SDT has been tasked with coming up with a revised definition of the Bulk Electric System. The SDT is following through on this charge. Brightline designations will be developed as part of this project and the ROP process will handle any exemptions or inclusions and those will be addressed through the
revision of the Rules of Procedure which is a separate parallel effort to the development of the BES definition utilizing a different team.
Glacier Electric Cooperative

No

I think it depends on the transformer. If the loss of the transformer would significantly affect the reliability of
the grid, then, yes, it should be included. However, if the loss of the transformer would not significantly affect
the reliability of the grid, then, no, it should not be included no matter what voltage it is connected at.

ReliabilityFirst

Yes

In some cases, facilities that need included do not have both windings operated at 100 kV or higher. This
needs further detail and definition to be helpful in determining if the facility is included or excluded. An
example of this is a distribution transformer (e.g. 138/34 kV) tapped from a BES line with a high side
protective device (such as a circuit switcher or ground switch), in which case the BES line to which it is
connected will trip (and may or not lockout) for a fault in the transformer. Should the distribution transformer
lockout the BES line to which it is connected, and then it should be included in the BES. If the distribution
transformer only trips the BES line to which it is connected (and successfully recloses), it could be argued
whether it should be included in the BES or not. But this issue needs to be addressed in the revised BES
definition.

Response: The SDT feels that your comment does not illustrate a readily identifiable bright-line designation. Bright-line designations will be developed as part of
this project and the ROP process will handle any exemptions or inclusions and those will be addressed through the revision of the Rules of Procedure; which is a
separate parallel effort to the development of the BES definition. Your comments will be forwarded to the Rules of Procedure Team.
Snohomish County PUD

No

PNGC Power

No

March 30, 3011

We note that many transformers with both windings above 100 kV may be installed on radial systems or local
networks used to provide local distribution service. Transformers installed on such systems should not be
part of the BES regardless of operating voltage. We also note that in Order No. 743, FERC made clear that it

21

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric
Cooperative

No

Lincoln Electric Cooperative

No

March 30, 3011

Question 1 Comment
does not intend the Standards Drafting Team to change the exception for radial facilities, and expects the
standards development process to provide a definition for “radial” so that facilities that meet this criteria may
be excluded by inspection rather than by going through an exemption process.
The Standards Drafting Team should also clarify that transformer protection systems are part of the BES only
if installed to protect “BES transformers” (transformer with both windings above 200kV).

22

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
Fall River Electric Cooperative

Yes or No

Question 1 Comment

No

Response: The SDT agrees with your suggestion and has incorporated it in its latest proposal.
•

Included in the BES: I1 - Transformers, other than generator step-up (GSU) transformers, including phase angle regulators, with two windings of 100 kV or
higher unless excluded under Exclusions E1 and E3.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.

The SDT has discussed this issue and will be seeking guidance from FERC staff in regards to the directives in FERC Order No. 743 and how they potentially
apply to Protection Systems. Protection Systems are not currently within the scope of the SAR for this project and any significant expansion could potentially
jeopardize the ability of the SDT to complete this project and file in accordance with the Commission directed time requirements in FERC Order No. 743.
Utility Services

No

Initially, yes; however, such a classification could be exempted upon a NERC review of the technical
justification for exemption.
We suggest that the BES definition be changed to: All Transmission and Generation Elements operated at
voltages of 100 kV or higher; unless modified by the BES Exemption Process.
We note that the term Facility, as defined in the NERC Glossary, implies that it is part of the BES. We
suggest that the BES definition just use the term Element since Facility is already defined as being a part of
the BES.
We envision the BES Exemption Process containing 3 sub-processes; one for Exclusion, one for Exemption,
and one for Inclusion. Each sub-process will establish provisions and guidelines for the three different tasks.
In order to ensure consistency across the continent, it is our view that NERC will be the facilitator of these
processes. We believe that NERC may choose to provide that some of these tasks may be performed at the
regional levels through the existing delegation agreements.
For “Exclusion”, we envision NERC establishing a first set of Exclusions, with FERC’s acceptance, that
Registered Entities can utilize as a means to justify not registering within the ERO or as a means to not have

March 30, 3011

23

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
to meet the compliance obligations of specific reliability standards and or requirements. NERC would also be
in a position to add or remove Exclusions provided such was performed through notification to the industry
and industry’s acceptance. If a Registered Entity uses a listed accepted Exclusion, it would be our
expectation that the RE would be treated in a manner similar to an unregistered organization, in that penalties
or sanctions could not be assessed during the exclusionary period. NERC would have the ability to revoke an
RE’s use of an Exclusion prospectively only. However, If NERC or the Regional Entity determined that a
Registered Entity intentionally claimed an accepted Exclusion; and it turned out to be knowingly false, the
Registered Entity would be subject to penalties and or sanctions appropriate to the period of the falsehood. In
order for Elements to be “Included” or “Exempted”, we envision that NERC will establish a set of criteria
including outlining the types of permissible technical studies or documentation necessary to seek inclusion or
an exemption.
We feel that any inclusion or exemption should be handled on an Element by Element basis, not by broad
application of a set of Elements. Each should be judged based upon its technical merits of the Element(s)
involved.
While an inclusion or exemption is pending, the Registered Entity shall not be subject to the performance
obligations under the any reliability standard(s) associated with the Element(s) being considered.
For Inclusion, any Registered Entity may submit Element(s) with the appropriate materials meeting the criteria
for Inclusion.
For there to be consistency within the ERO, NERC must be the evaluator of the requests. We believe there
must be a measurable, not subjective, improvement in the reliability of the transmission system for the
Element(s) to be included.
All Registered Entities, including applicable RCs, BAs, TOPs, and Regional Entities, who would be impacted
by the proposed Inclusion must be provided sufficient notice and time to participate in the consideration
process. NERC shall render a decision following the timely submission from the potentially impacted
Registered Entities.
For an Exemption to be granted, any Registered Entity may submit Element(s) with the appropriate materials
meeting the criteria for Exemption.
For there to be consistency within the ERO, NERC must be the evaluator of the requests. We believe there
must be no measurable, not subjective, decrease in the reliability of the transmission system for the
Element(s) to be included.
All Registered Entities, including applicable RCs, BAs, TOPs, and Regional Entities, who would be impacted
by the proposed exemption must be provided sufficient notice and time to participate in the consideration
process. NERC shall render a decision following the timely submission from the potentially impacted

March 30, 3011

24

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
Registered Entities.
We note that BES Exemption Process must be an active and ongoing aspect of the ERO program. With the
addition of new or deletion of existing Transmission and Generation Elements, Facilities, or systems; it needs
to be recognized that Exclusions, Inclusions, and Exemptions could possibly need alteration over time. By
establishing appropriate guidelines and processes, the ERO will be able to monitor and maintain information
of what is the bulk electric system or BES.

Response: The SDT thanks you for your comments on the inclusion of transformers.
The SDT agrees with your view that a briefer, more concise definition is beneficial and has incorporated it in the latest proposal.
The SDT agrees with the use of the term, “Elements” rather than “Facilities” and has corrected its use throughout the proposal.
The SDT does not share your view of the BES exception process. Bright-line designations will be developed as part of this project and the ROP process will
handle any exceptions and those will be addressed through the revision of the Rules of Procedure which is a separate parallel effort to the development of the
BES definition utilizing a different team. Your comments will be forwarded to the Rules of Procedure Team.
The Dow Chemical Company

The Dow Chemical Company (“Dow”) recommends that NERC finalize a basic framework for identifying BES
facilities before evaluating individual facilities or types of facilities. Such a framework is recommended by
Dow in response to questions #11 and #12 below.

Response: See response to Q11 & 12.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Yes

Constellation firmly believes that the classifications found in the Compliance Registry Criteria - Section III
(Rules of Procedure Appendix 5B), such as that cited in this question, provide a useful basis to create a
comprehensive, revised BES definition.
Further, we propose that the BES drafting team incorporate the criteria directly into the revised BES definition,
replacing the term “bulk power system” in each criterion with “greater than 100 kV.” This would then include
assets that are currently registered as BES elements as well as those that may have been previously
excluded due to Regional exemption variances. Structuring the revised BES definition to clarify both the
inclusions and exclusions, can, ideally, eliminate the need for an onerous exemption process as well as
eliminate the need for Section III of the Registry Criteria.
Please see our response to question 12 for more detail on a proposed alternative approach to structuring the
BES definition revision.

Response: The SDT agrees and has incorporated as one of its goals that it will not drive a change in the registry criteria if at all possible. .

March 30, 3011

25

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment

The SDT agrees with your suggestion and has incorporated it in its latest proposal.
Please see response to Question 12.
Florida Municipal Power Agency

Yes

In general, yes, unless it is part of a radial Element that is excluded from the BES.

Transmission Access Policy
Study Group

Yes

See FMPA response to Question 12 below. Throughout these comments, FMPA refers to “Elements” and not
to “facilities.”
This is because “Facility” is defined in the NERC Glossary as “[a] set of electrical equipment that operates as
a single Bulk Electric System Element....” Because these comments (and the BES definition) address
whether Elements are or are not part of the BES, it is incorrect to refer to the Elements in question as
“Facilities,” because a Facility is defined as a BES Element.

Response: The SDT agrees with your suggestion and has incorporated it in its latest proposal.
•

Included in the BES: I1 - Transformers, other than generator step-up (GSU) transformers, including phase angle regulators, with two windings of 100 kV or
higher unless excluded under Exclusions E1 and E3.
Excluded from the BES: Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.

See response to Q12.
The SDT agrees with the use of the term, “Elements” rather than “Facilities” and has corrected its use throughout the proposal.
NERC Staff

Yes

Please see additional comments in Attachment 3 at the end of this report.

Response: Please see response to Q13.
Public Service Enterprise Group
Company

March 30, 3011

Yes

The PSEG Companies consider transformers with primary and secondary windings of greater than 100 kV,
and which are not GSU transformers to be part of the BES.

26

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment

Competitive Suppliers

Yes

SERC EC Planning Standards
Subcommittee

Yes

MRO's NERC Standards Review
Subcommittee

Yes

IRC Standards Review
Committee

Yes

Bonneville Power Administration

Yes

FirstEnergy Corp

Yes

SERC OC Standards Review
Group

Yes

Arizona Public Service Company

Yes

AZPS agrees that Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle
Regulators, with both primary and secondary windings of 100 kV or higher should be classified as part of the
BES.

Pepco Holdings Inc.

Yes

Transformers with primary greater than 100kv (connected to a BES facility) but a secondary less than 100kv
are not specially addressed. They should be specially “excluded” and not part of an exemption process.

LCRA Transmission Services
Corporation

Yes

ERCOT, this would include the 138:345-kV autotransformers.

Manitoba Hydro

Yes

North Carolina EMC

Yes

March 30, 3011

EPSA believes that it is appropriate that transformers other than generator step-up transformers, including
Phase Angle Regulators, with primary and secondary windings of 100 kV or higher should be classified as
part of the BES under the proposed definition for Project 2010-17.

Yes, since FERC has directed the bright-line criteria is 100kV or above.

27

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

on behalf of Teck Metals Ltd.

Yes

Southern California Edison

Yes

on behalf of Catalyst Paper
Corporation

Yes

City of Grand Island

Yes

ISO New England Inc.

Yes

Entergy Services

Yes

United Illuminating Company

Yes

American Transmission
company

Yes

City of Austin dba Austin Energy

Yes

Duke Energy

Yes

The Dayton Power and Light
Company

Yes

ITC Holdings Corp

Yes

BGE

Yes

City Water Light and Power
(CWLP) - Springfield, IL

Yes

American Electric Power (AEP)

Yes

March 30, 3011

Question 1 Comment

SCE currently reports on many of its transformers with both primary and secondary windings of 100kV or
higher.

Only those transformers that are not a radial Transmission Element should be included.

No comment.

28

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment

Southern Company

Yes

Only non-radial networked transformers with both primary and secondary voltages >_100kV should be
included in the BES definition.

Idaho Power

Yes

Independent Electricity System
Operator

Yes

Conditional on having an exemption criteria/process which must still be developed.

Springfield Utility Board

Yes

If BOTH primary AND secondary windings are 100kV or higher

Clark Public Utilities

Yes

Xcel Energy

Yes

City of Redding

Yes

Only if the elements or facilities are shown through engineering studies to be necessary to reliably operate an
interconnected transmission system.

Response: Thank you for your response. Please see the summary consideration immediately under the question. Several stakeholders made suggestions that
were adopted by the drafting team.

March 30, 3011

29

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

2. Should the following be classified as part of the BES?
•

Individual generation resources (including GSU transformers and the associated generator interconnecting line lead(s))
greater than 20 MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Transmission Facilities
operated at voltages of 100 kV or above

Summary Consideration: Most Stakeholders who responded to this question disagreed with at least some part of the
proposal.
The SDT has discussed the history and determination of the 20 MVA threshold for inclusion of generating units in the Statement
of Compliance Registry Criteria and subsequently into a draft definition of the BES. Two Regional Entities (FRCC and RFC)
specifically use this criterion in each of their current BES definitions. The 20 MVA unit is a low enough level to capture most
generating units that have an effect on the reliability of the BES and that may be dispatched by Balancing Authorities, but
allows for the exclusion of smaller units, such as 10 MVA units, connected to the BES that may not be dispatched by Balancing
Authorities. The SDT believes that the 20 MVA threshold for inclusion of generating units connected at 100 kV and above is
proper for inclusion in the BES since there is no technical basis to change the values contained in the Statement of Compliance
Registry Criteria. The SDT also has carefully discussed the inclusion of generator step-up (GSU) transformers and associated
interconnection line leads and believes the BES must be contiguous at this level in order to be reliable. The SDT believes it
does not make sense to include generation in the BES without including the Facilities to transfer power from a generating unit
to the BES. The GSUs and line leads must be a part of the BES the same as other Facilities are part of the BES.
Commenters have suggested other thresholds (anywhere from 0 to 100 MVA) for generation plants to be included into the BES
definition. However, as of this date commenters have not submitted technical justification upon which to base a significant
departure from the generation MVA thresholds included in the NERC Statement of Compliance Registry Criteria.
Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the
generator terminals through the GSU which has a high side voltage of 100 kV or above.
Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) including the generator terminals through the GSUs, connected through a common
bus operated at a voltage of 100 kV or above.
Included in the BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a collector system through a common point of interconnection to a system Element
at a voltage of 100 kV or above.
Excluded from the BES: E2 - A generating unit or multiple generating units that serve all or part of retail Load with
electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does not exceed the
criteria identified in Inclusions I2 or I3, and (ii) standby, back-up, and maintenance power services are provided to the
generating unit or multiple generating units or to the retail Load pursuant to a binding obligation with a Balancing

March 30, 3011

30

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable regulatory
authority.

Organization

Yes or No

Question 2 Comment

Northeast Power Coordinating
Council

No

Some generators act as a local load modifier, regardless of connected voltage. The power generated is
consumed locally and does not flow up onto the BES, nor does its operation materially impact any BES
transmission facilities. If a generator functions as a local load modifier and does not materially impact the
BES, meaning that it is not necessary to maintain BES reliability, then it should be excluded from the
definition of BES under the BES Exemption Process.

Orange and Rockland Utilities,
Inc.

No

Some generators act as a local load modifier, regardless of connected voltage. The power generated is
consumed locally and does not flow up onto the BES, nor does its operation materially impact any BES
transmission facilities. If a generator functions as a local load modifier and does not materially impact the
BES, meaning that it is not necessary to maintain BES reliability, then it should be excluded from the
definition of BES under the BES Exemption process.

Response: The SDT has discussed the behind-the-meter customer generation issues and has addressed it in the revised BES definition.
Excluded from the BES: E2 - A generating unit or multiple generating units that serve all or part of retail Load with electric energy on the customer’s side of
the retail meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in items I2 or I3, and (ii) standby, back-up, and maintenance
power services are provided to the generating unit or multiple generating units or to the retail Load pursuant to a binding obligation with a Balancing
Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable regulatory authority.
Public Service Enterprise Group
Company

No

The concept of a stand-alone generator connected through a single GSU transformer to the grid at greater
than 100kV should be included as part of the BES. However, the term “generation resources” is too vague
leading to possible misinterpretation as to what associated generator resource elements are to be included
within the BES. All those “resources” and any connected element would be part of the BES? The definition
should clearly describe (with examples) of the intent of what should be included within the BES scope.. (e.g.
Would a station service transformer connected at 26kV which is part of the generation “resource” be included
as a BES element)?

Response: The SDT has discussed what constitutes a “generation resource” including balance of generation plant controls and auxiliary equipment and believes
that balance of plant equipment is not within the scope of this project. The term “generation resource” is no longer used in the revised definition. Certain
equipment, such as protection systems and under-frequency Load shed controls, may not be part of the BES, but may be subject to specific NERC standards
requirements. Generation plant controls should be treated in a similar fashion.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
Electric Market Policy

Yes or No

Question 2 Comment

No

Dominion does not agree that a generation resource should be classified as part of the BES.Dominion
supports the criteria for registering owners, operators, and users of the bulk power system, as indicated in the
current Statement of Compliance Registry Criteria .

Response: The SDT has carefully considered this matter, and believes that generating units and plants are an integral part of the BES, without which it could not
function, and therefore, should be included in the BES.
SERC OC Standards Review
Group

No

We do not agree with the inclusion of GSU transformers and associated interconnecting line leads. Lines and
transformers should be included based upon the voltage and not the function they serve.
We support the inclusion of all non-radial lines operated at a voltage of 100 kV or higher as well as all
transformers with both primary and secondary windings operated at 100 kV or higher.
We do not support generic inclusions of any radial lines or transformers with primary or secondary windings
operated below 100kV. Our response in question 13 amplifies this statement.

Response: The SDT has carefully discussed the inclusion of GSU transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable. The SDT believes it does not make sense to include generation in the BES without including the Facilities to
transfer power from a generating unit to the BES. The GSUs and line leads must be a part of the BES the same as other Facilities are part of the BES.
Please also see the response to Q13.
PacifiCorp

March 30, 3011

No

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology. Significant
efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF) over the
course of the past year to identify some initial criteria and methodologies. These efforts are ongoing and
should be supported by the NERC drafting team. For example: Generation units should not be included or
excluded solely based on a their gross nameplate rating and the operating voltage at which they are
connected to transmission facilities. Generation resources which are necessary to operate the interconnected
network should be included as part of the regulated BES. Generating units which are not “necessary for the
operation of the interconnected network” should be excluded. A methodology needs to be developed to

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment
determine which generating units may be excluded as part of the regulated BES.

Central Lincoln

No

The generation resources so described should be presumed to be part of the BES unless or until they have
been through the exemption process and as a result have been classified as non-BES.

PUD No.1 of Clallam County

No

The generation resources so described should be presumed to be part of the BES unless or until they have
been through the exemption process and as a result have been classified as non-BES. The 20 MVA threshold
is too low for many parts of the system. The interconnecting source impedance and adjacent facilities may
have a more significant impact on the BES than the MVA of a machine. A 100 MVA plant connected to a high
fault duty/low source impedance system may create little to thermal or transient stability concerns even under
delayed clearing. However a 25 MVA plant connected to a low fault duty/high source impedance system may
create concerns on a weak system. or above.

Snohomish County PUD

No

The generation resources described should not be presumed to be part of the BES. The criteria above are
intended to identify GO/GOP registration as a user/owner/operator rather than to identify BES elements. On
this score, we note there has been considerable confusion between the NERC Statement of Registry Criteria,
which is merely intended to establish a list of entities that may presumptively be required to comply with
Reliability Standards, and the BES definition, which defines which facilities are ultimately protected by
Reliability Standards. In defining the BES, those concepts should be kept separate.

Response: The SDT believes the revised definition contains enough criteria (both for exceptions and inclusions) to determine most, if not all, of the Elements that
will be part of the BES. The SDT also believes that the criteria for including generating units 20 MVA and greater that are connected to the BES at 100 kV and
above provides the “bright-line” criteria that will eliminate the ambiguity the Commission cited in Order 743.
The separate exception process will be drafted by the Rules of Procedure Drafting Team with the DBES SDT developing the bright-line criteria. There will be
coordination between the two groups in this effort.
Hydro-Québec

For questions 1 to 10, refer to questions 11 to 13.

Response: Please see response to Q11 to Q13.
City of Redding

No

The NERC Registration Criteria thresholds were a good start at the time of implementation of the compliance
program, however there is no engineering evidence that all of the facilities are necessary to reliably operate
an interconnected transmission system.

Independent Electricity System

No

To be totally consistent with the 100 kV bright line approach, any Elements and Facilities that are not
operated at voltages of 100 kV or higher should be excluded unless otherwise determined to be included

March 30, 3011

33

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Operator

Question 2 Comment
through the exemption/inclusion process being developed.

Lewis County PUD

No

20MVA generation resources should not be part of the BES. This size generating resource is too small to
affect the BES. Suggest the minimum size BES resource be changed to 100MVA for a single generator. If a
smaller threshold is used then the RE or BA should demonstrate to the GO than this resource is critical to the
BES

ITC Holdings Corp

No

20 MVA is too small a unit to be included in the BES definition. The definition should include units or plants
with 75 MVA or more

Glacier Electric Cooperative

No

Once again, I believe it depends on the facility and whether or not it has a significant impact on the grid.

American Municipal Power

No

Suggest 50 MVA

Arizona Public Service Company

No

The minimum size should be 50 MVA connected to 200 kV or higher. Small generators or plants do not
materially impact the reliability of the BES and do not need to be included.

PPL Energy Plus

No

LG&E and KU Energy LLC

No

The 20 MVA threshold appears to be arbitrary and will include many small generation facilities that have
minimal impact on BES reliability, A 200 MVA aggregate threshold for generating units at the same site
would be more appropriate. Generators that are smaller than 200 MVA are not likely to have a significant
impact on the BES and should be excluded from the definition (without requiring application for an exemption
on a case-by-case basis). The BES definition should be modified to incorporate this exclusion.(See also
response to Question 8.)

Response: The SDT has carefully considered this threshold, and believes that the 20 MVA unit is a low enough level to capture most generating units that have
an effect on the reliability of the BES and may be dispatched by Balancing Authorities, but allows the exclusion of smaller units, such as 10 MVA units, connected
to the BES that may not be dispatched by Balancing Authorities. The SDT believes the 20 MVA threshold for inclusion of generating units connected to the BES is
proper.
ExxonMobil Research and
Engineering

March 30, 3011

No

I have reservations about the removal of the ability to use the net rating of a generation asset as the
generator rating (i.e. the use of gross rating of a machine instead of net rating of the energy provided to the
BES). Many industrial companies have back up power agreements with utilities to cover the loss of internal
generation assets. The requirement to ensure that this back up power can be provided should be part of the
NERC requirements for Transmission Operators and Balancing Authorities (e.g. the VAR-001 requirement for
TOPs to obtain the necessary reactive resources to cover normal and contingency operations). The reliability
goals and strategy of some large electricity consumers that this change is targeting differ from the bulk

34

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment
electric system. For instance, a petrochemical facility that utilizes generation to offset the load seen by the
BES may desire to disconnect from the bulk electric system during an event in order to preserve the stability
of the private use network that supplies electricity to the equipment that control its chemical processes. As
history has demonstrated, the most dangerous activities that petrochemical facilities undertake are the
shutdown and startup of their processes.
As a side note, the term 'directly connected' should be added to the NERC glossary. The concept of 'directly
connected' is the key to understanding which generators are included in the BES and which generators are
exempted.

Response: The SDT has carefully considered “behind-the-meter” generation, and considers it to be an exclusion to the BES. The SDT agrees with the language
currently contained in the Statement of Compliance Registry Criteria regarding the exemption of net capacity associated with a retail meter.
Excluded from the BES: A generating unit or multiple generating units that serve all or part of retail Load with electric energy on the customer’s side of the
retail meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load pursuant to a binding obligation with a
Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable regulatory authority.
With the revised definition and designations, the SDT does not believe that the term ‘directly connected’ needs to be utilized or defined.
on behalf of Teck Metals Ltd.

No

Indeck Energy Services

No

on behalf of Catalyst Paper
Corporation

No

Clark Public Utilities

No

Same response as Question 1

Response: Please see response to Question 1.
City of Grand Island

No

This is a registration criteria issue. Can this project directly cause changes in the registration criteria?
20 MVA is too low. That size of generator can not affect the Adequate Level of Reliability of the BES. 100
MVA is appropriate for this region.

Response: The goal of the SDT is not to change registration criteria if at all possible. In this case, the SDT has adopted the registration criteria and no changes
are necessary.

March 30, 3011

35

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment

The SDT has carefully considered this threshold, and believes that the 20 MVA unit is a low enough level to capture most generating units that have an effect on
the reliability of the BES and may be dispatched by Balancing Authorities, but allows the exclusion of smaller units, such as 10 MVA units, directly connected to
the BES that may not be dispatched by Balancing Authorities. The SDT believes the 20 MVA threshold for inclusion of generating units directly connected to the
BES is proper.
City of Anaheim

No

Unless the generator is required to maintain BES reliability, i.e. black start, etc., the GSU and gen tie should
be excluded from the BES; provided, however, to eliminate any reliability gaps, such generation-tie equipment
should be classified as "Generator" equipment subject to GO/GOP standards, and the PRC and vegetation
management standards should be made applicable to GO/GOPs and this equipment. This is consistent with
the NERC Reliability Functional Model and is more efficient than requiring TO/TOP registration for non-critical
generation-tie transmission elements that are not required for the reliable operation of the BES.

Response: The SDT has carefully discussed the inclusion of GSU transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable. The SDT believes it does not make sense to include generation in the BES without including the Facilities to
transfer power from a generating unit to the BES. The GSUs and line leads must be a part of the BES the same as other Facilities are part of the BES. The SDT
has carefully considered additional Facilities that may be included in the BES due to this project and the ramifications on registration of GO/GOPs and TO/TOPs.
However, the SDT must satisfy the Commission Order and do what is best for reliability of the BES. The development of the BES definition is not meant to result
in registration of GO/GOPs as TO/TOPs. That issue will be addressed as needed in Project 2010-07: Generator Requirements at the Transmission Interface.
PNGC Power

No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.
Douglas Electric Cooperative
Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

March 30, 3011

The generation resources described should not be presumed to be part of the BES. The criteria above are
intended to identify GO/GOP registration as a user/owner/operator rather than to identify BES elements. On
this score, we note there has been considerable confusion between the NERC Statement of Registry Criteria,
which is merely intended to establish a list of entities that may presumptively be required to comply with
Reliability Standards, and the BES definition, that defines which facilities are ultimately protected by Reliability
Standards. In defining the BES, those concepts should be kept separate. In general, we do not believe that
every generator rated at, or greater than, 20MVA should automatically be ‘assumed’ to be part of the BES.
We do believe that some of the Mandatory Reliability Standards should apply however. This leads to an
issue which might be somewhat philosophical, but, in this case, has real-world implications. We do not
believe that the BES is contiguous. That is, say every generator which is greater than 20MVA is assumed to
be part of the BES, does that mean that all the lines and equipment associated with this generator are also
part of the BES? We do not think so, hence the possibility that the BES is non-contiguous. We also believe
that some of the Mandatory Reliability Standards can apply to non-BES facilities, and equipment. A good
example is the UFLS standards. As you might realize some UFLS relays are on lines rated well below 100kV.
So in this case, a generator rated at 20MVA might not be part of the BES, but still the standards that apply to

36

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric
Cooperative

No

Lincoln Electric Cooperative

No

Fall River Electric Cooperative

No

Question 2 Comment
a generator could still apply.

Response: The SDT has carefully considered this threshold, and believes that the 20 MVA unit is a low enough level to capture most generating units that have
an effect on the reliability and adequacy of the BES and may be dispatched by Balancing Authorities, but allows the exclusion of smaller units, such as 10 MVA
units, directly connected to the BES that are not dispatched by Balancing Authorities. The SDT believes the 20 MVA threshold for inclusion of generating units
directly connected to the BES is proper. The SDT also believes that the criteria of including generating units 20 MVA and greater that are connected to the BES at
100 kV and above provides the “bright-line” criteria that will eliminate the ambiguity the Commission cited in Order 743. The SDT has carefully discussed the
inclusion of GSU transformers and associated interconnection line leads and believes the BES must be contiguous at this level in order to be reliable. The SDT
believes it does not make sense to include generation in the BES without including the Facilities to transfer power from a generating unit to the BES. The GSUs
and line leads must be a part of the BES the same as other Facilities are part of the BES.
United Illuminating Company

No

Any Generator connected at 100 kV or above should be part of BES. There should not be a MVA threshold

Response: The SDT has carefully considered this threshold, and believes that the 20 MVA unit is a low enough level to capture most generating units that have

March 30, 3011

37

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment

an effect on the reliability of the BES and may be dispatched by Balancing Authorities, but allows the exclusion of smaller units, such as 10 MVA units, directly
connected to the BES that may not be dispatched by Balancing Authorities. The SDT believes the 20 MVA threshold for inclusion of generating units directly
connected to the BES is proper. The SDT also believes that the criteria of including generating units 20 MVA and greater that are connected to the BES at 100 kV
and above provides the “bright-line” criteria that will eliminate the ambiguity the Commission cited in Order 743.
Southern Company

No

Lines and transformers should be included based upon the voltage and not the function they serve. We
support the inclusion of all non-radial lines operated at a voltage of 100 kV or higher as well as all
transformers with both primary and secondary windings operated at 100 kV or higher. We do not support
generic inclusions of any radial lines or transformers with primary or secondary windings operated below
100kV. Our response in question 13 amplifies this statement.
Individual, non-blackstart, generator
resources of 20MVA are too small to impact the reliability of the BES. We recommend single resource (unit)
inclusion threshold be increased to 75MVA to match the threshold indicated in Q3 below for the aggregated
case. Units smaller than 75MVA could be included using the “exemption process" or the NERC Compliance
Registry Criteria could be changed.

Response: Lines and transformers are discussed as part of Questions 1 and 5.
The SDT has carefully considered this threshold, and believes that the 20 MVA unit is a low enough level to capture most generating units that have an effect on
the reliability of the BES and may be dispatched by Balancing Authorities, but allows the exclusion of smaller units, such as 10 MVA units, directly connected to
the BES that may not be dispatched by Balancing Authorities. The SDT believes the 20 MVA threshold for inclusion of generating units connected to the BES is
proper.
The Dow Chemical Company

As discussed in response to question #12 below, issues relating to the registry criteria applicable to
generation resources should not be revisited at this time.

Response: See response to Q12.
Bonneville Power Administration

Yes

Generation resources should also define how wind generation is included in this clarification (by turbine, by
string, etc)

Response: Wind generating units would be included or excluded based upon the criteria for dispersed generation, generating units, and multiple generating units.
Included in the BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a
collector system through a common point of interconnection to a system Element at a voltage of 100 kV or above.
Florida Municipal Power Agency

March 30, 3011

Yes

1. For the sake of clarity and consistency, the BES should track the Statement of Compliance Registry Criteria

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
Transmission Access Policy
Study Group

March 30, 3011

Yes or No
Yes

Question 2 Comment
wherever possible. In this case, for example, generation resources with respect to which an entity is
registered as a Generator Owner or Generator Operator should be included in the BES, while nonregistered generation resources should not be included in the BES.
2. FMPA’ proposal, as further explained in response to the questions below, is introduced here in the interests
of clarity. FMPA proposes that the BES definition should establish the universe of Elements that are,
absent other factors, considered part of the BES. FMPA supports continuing to use a general 100 kV
threshold, and basing the inclusion of generators in the BES on whether the generation is registered
pursuant to the Statement of Compliance Registry Criteria. There is one “exclusion” in the definition
proposed by FMPA, i.e., the existing exclusion for radial transmission serving only load with one
transmission source (with a proposed clarification). Unlike the definition proposed in the draft SAR,
therefore, but like the current definition, FMPA’ proposal treats radial transmission Elements serving only
load with one transmission source like sub-100 kV Elements, in that they are presumed to be non-BES
unless a showing has been made, on a case-by-case basis, that a particular radial Element is necessary
for operating the interconnected electric transmission network. The current definition of the BES excludes
“radial transmission facilities serving only load with one transmission source,” and FERC stated in Order
743 that it did not intend to require a change to that exclusion. It is very important that radial transmission
serving only load with one transmission source remain excluded from the BES; if such radials instead had
to go through an exemption process, as the SDT’s proposed definition suggests, the burden on small
entities and on NERC and the Regional Entities would be staggering since it would be presumed that the
radial would be part of the BES until exempted (opt-out), where it should be that the radial should be
excluded from the BES unless there is a determination that it should be part of the BES (opt-in).
3. As explained in more detail in response to Question 8 below, FMPA supports adding the clarification that
radials serving generation that is not registered pursuant to the Statement of Compliance Registry Criteria
are covered by the exclusion of radials serving only load with one transmission source. Of course, the
application of the definition of the BES is dynamic. For example, in considering whether new generation
connected by what had previously been a radial to load should be registered, NERC may also reevaluate
the exclusion of the radial.
4. FMPA’ proposed definition of the BES is: In general, the Bulk Electric System includes all Transmission
Elements operated at voltages of 100 kV or higher, and all generation resources registered pursuant to the
Statement of Compliance Registry Criteria. Radial Transmission Elements serving only load with one
Transmission source are generally not included in this definition. A radial Transmission Element may be
considered as “serving only load” for purposes of the foregoing general exclusion even if it connects
generation, so long as that generation is not registered pursuant to the Statement of Compliance Registry
Criteria. An Element that nominally meets the general BES criteria, but which an entity demonstrates, on a
case-by-case basis, is not necessary for operating the interconnected electric transmission network, shall
be exempted from the BES pursuant to the NERC exemption process. An Element that does not nominally
meet the general BES criteria, but which NERC demonstrates, on a case-by-case basis, is necessary for

39

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment
operating the interconnected electric transmission network, shall be included in the BES pursuant to the
NERC inclusion process.
5. As FMPA’ proposed definition suggests, FMPA proposes that entities be able to seek “exemptions” for
Elements nominally included in the BES; obtaining an exemption would require a demonstration that the
Element to be exempted is not necessary for operating the interconnected electric transmission network.
Elements for which NERC has approved exemptions would not be part of the BES.
Conversely, FMPA proposes that NERC have the authority, upon a case-by-case demonstration that a
particular Element that is not nominally included in the BES is necessary for operating the interconnected
electric transmission network, to add such an Element to the BES.
6. Please see also FMPA’ Official Comment Form for BES Definition Exception Process, submitted today.

Response:
1. The SDT agrees that the definition should track the registry criteria. One of the basic tenets of the SDT scope is to not expand the registry criteria if at all
possible.
2. The SDT has revised the definition and included specific inclusion and exclusion criteria that address these issues. The SDT also believes that the revised
definition provides the “bright-line” criteria that will eliminate the ambiguity the Commission cited in Order 743. The separate exception process will be drafted
by the Rules of Procedure Team with the DBESSDT developing the criteria. There will be coordination between the two groups in this effort.
3. See response to Q8.
4. See response to #2 above.
5. The separate exception process will be drafted by the Rules of Procedure Team with the DBESSDT developing the criteria. There will be coordination
between the two groups in this effort.
6. See response to definition exception process.
ReliabilityFirst

Yes

It is recommended that the term “directly connected” be defined and examples of this term are included in the
ERO definition.
Also, most wind farms have multiple transformations when connected to the BES and the intent should be to
capture these wind farms in the BES, so more specific language is most likely needed in the definition to
capture them.

Response: The SDT has revised the definition and “directly connected” is no longer utilized in the revised draft definition.
The SDT has addressed the issue of wind generation in the revised draft definition.
Included in the BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a
collector system through a common point of interconnection to a system Element at a voltage of 100 kV or above.

March 30, 3011

40

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization
NERC Staff

Yes or No
Yes

Question 2 Comment
Please see additional comments at the end of this report.

Response: Please see response to Q13.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Yes

Constellation firmly believes that the classifications found in the Compliance Registry Criteria - Section III
(Rules of Procedure Appendix 5B), such as that cited in this question, provide a useful basis to create a
comprehensive, revised BES definition.
Further, we propose that the BES drafting team incorporate the criteria directly into the revised BES definition,
replacing the term “bulk power system” in each criterion with “greater than 100 kV.” This would then include
assets that are currently registered as BES elements as well as those that may have been previously
excluded due to Regional exemption variances. Structuring the revised BES definition to clarify both the
inclusions and exclusions, can, ideally, eliminate the need for an onerous exemption process as well as
eliminate the need for Section III of the Registry Criteria.
Please see our response to question 11 for more detail on a proposed alternative approach to structuring the
BES definition revision.

Response: The SDT agrees that the definition should track the registry criteria. One of the basic tenets of the SDT scope is to not expand the registry criteria if at
all possible
The SDT agrees and has made the suggested change.
See response to Q11.
Occidental Energy Ventures Corp

March 30, 3011

Yes

Many generator interconnection lines are operated at voltages greater than 100KV, but have traditionally not
been considered part of the the transmission system. Rather these lines have been considered part of the
generation system and, for quite some time, have been constructed and operated according to
interconnection agreements which specify design and protection criteria. The BES definition should not be
constructed in either a direct or implied manner that would alter the interconnection line status as being part of
the Generation Facilities. Otherwise, it could result in registration of GO/GOPs as TO/TOPs. The issue of
what additional standards, if any, should apply to these generation interconnection lines is the subject of
Project 2010-07 and should be resolved by that standards development effort, not by a definition change.
The proposed definition appears not to violate the inclusion of the interconnection line as part of the
Generation Facility while still providing for these lines to be part of the BES, however, some clarification might
be advisable (e.g., a statement that interconnection lines are part of the Generation Facility or are Generation
Elements).

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment

Response: The SDT has carefully considered additional Facilities that may be included in the BES due to this project and the ramifications on registration of
GO/GOPs and TO/TOPs. However, the SDT must satisfy the Commission Order and do what is best for reliability of the BES. The development of the BES
definition is not meant to result in registration of GO/GOPs as TO/TOPs. That issue will be addressed as needed in Project 2010-07: Generator Requirements at
the Transmission Interface.
American Transmission company

Yes

For clarity, ATC suggests that the (gross nameplate rating) be changed to read “(gross generator nameplate
rating)” and further classified as part of the BES given that a fault or outage of the individual generator
resource greater than 20 MVA would not maintain an Adequate Level of Reliability of the BES.

Response: The SDT discussed this and does not agree with the suggested wording change.
LCRA Transmission Services
Corporation

Yes

The 20 MVA threshold is too low.
Should consider the region’s or area’s reserve margin to determine the appropriate level of individual
generator loss. Leave this to the region to determine.

Response: The SDT has carefully considered this threshold, and believes that the 20 MVA unit is a low enough level to capture most generating units that have
an effect on the reliability of the BES and may be dispatched by Balancing Authorities, but allows the exclusion of smaller units, such as 10 MVA units, connected
to the BES that may not be dispatched by Balancing Authorities. The SDT believes the 20 MVA threshold for inclusion of generating units connected to the BES is
proper.
The SDT’s goal is to “eliminate the regional discretion in the ERO’s current definition”, which is specifically stated in the Commission’s Order.
Utility Services

Yes

Initially, yes; however, such a classification could be exempted upon a NERC review of the technical
justification for exemption.

Response: The SDT believes the revised definition will contain enough criteria to determine most, if not all, of the Facilities that will be part of the BES. The
exception process will be handled through the revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
Your comments will be forwarded to the Rules of Procedure Team.
Xcel Energy

March 30, 3011

Yes

Xcel Energy believes that clarity should be added as to what constitutes an individual generation resource
and a generating plant, especially as it pertains to multiple owner facilities and aggregating facilities such as
wind or solar farms (which may also have multiple owners for discreet facilities that tie into a common bus).
Discussion and controversy in other NERC and regional forums and standard development teams indicates
that this is not well defined. It may be that the Statement of Compliance Registry needs to be enhanced if it
forms the foundation for which these items are to be understood.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment

Response: The new wording for generating units in the revised definition has addressed this issue. The Statement of Compliance Registry Criteria should agree
with the BES definition, as they are intended not to be in conflict with each other.
Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the generator terminals through the GSU which
has a high side voltage of 100 kV or above.
Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
Included in the BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a
collector system through a common point of interconnection to a system Element at a voltage of 100 kV or above.
MRO's NERC Standards Review
Subcommittee

Yes

The SAR DT should use caution if the above statement is to be used within a guideline or rational box. The
use of the word “interconnecting line leads may be somewhat ambiguous and lead to other confusion.
GSU should be spelled out as a “generator step up transformer” and properly used within the statement:
Individual generation resources (including Generator Step Up transformers and the associated generator
interconnecting line lead(s)) greater than 20 MVA (gross nameplate rating) directly connected via a
Generator Step-Up transformer(s) to Transmission Facilities operated at voltages of 100 kV or above.
For clarity, the NSRS suggests that the (gross nameplate rating) be changed to read “(gross generator
nameplate rating)” and further classified as part of the BES given that a fault or outage of the individual
generator resource greater than 20 MVA would not maintain an Adequate Level of Reliability of the BES.

Response: The term “interconnecting lines leads” has been deleted in the revised definition.
Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the generator terminals through the GSU which
has a high side voltage of 100 kV or above.
Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
All acronyms used in the definition and supporting materials will be spelled out.
The SDT discussed the wording change to the term “gross generator nameplate rating” and does not agree with the suggested wording change.
SERC EC Planning Standards
Subcommittee

Yes

IRC Standards Review

Yes

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 2 Comment

Committee
FirstEnergy Corp

Yes

Competitive Suppliers

Yes

Pepco Holdings Inc.

Yes

Manitoba Hydro

Yes

North Carolina EMC

Yes

Southern California Edison

Yes

SCE currently reports on individual generation resources (including GSU transformers and the associated
generator interconnecting line lead(s)) greater than 20 MVA (gross nameplate rating) directly connected via a
step-up transformer(s) to Transmission Facilities operated at voltages of 100 kV or above. SCE does not feel
a blanket inclusion of all the listed equipment is needed.

Southern California Edison
Company

Yes

A GSU transformer is clearly an extension of the functionality provided by the Generator Interconnection
Elements, namely, to move bulk power from the BES generator to the BES network, and hence, the
classification of the GSU transformer should match that of the Generator Interconnection Elements.

Entergy Services

Yes

City of Austin dba Austin Energy

Yes

Duke Energy

Yes

The Dayton Power and Light
Company

Yes

BGE

Yes

City Water Light and Power
(CWLP) - Springfield, IL

Yes

March 30, 3011

Increasing numbers of small generators could create reliability issues if excluded.

No comment.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

American Electric Power (AEP)

Yes

Idaho Power

Yes

Springfield Utility Board

Yes

Question 2 Comment

"directly connected" is important.

Response: Thank you for your response. Please see the summary consideration immediately under the question. Several stakeholders made suggestions that
were adopted by the drafting team.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

3. Should the following be classified as part of the BES?
•

Generation plants (including GSU transformers and the associated generator interconnecting line lead(s))with aggregate
capacity greater than 75 MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Transmission
Facilities operated at voltages of 100 kV or above

Summary Consideration: While many commenters did agree with the proposal, most commenters who responded to this question disagreed
with some aspect of the proposal.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. This
threshold is based on the generation threshold values found in the NERC Statement of Compliance Registry Criteria. Also, two Regional Entities
(FRCC and RFC) specifically use this criterion in each of their current BES definitions. The 75 MVA plant is a low enough level to capture most
generating plants that would have an effect on the reliability of the interconnected Transmission network.
Commenters have suggested other thresholds (anywhere from 0 to 300 MVA) for generation plants to be included into the BES definition.
However, as of this date commenters have not submitted technical justification upon which to base a significant departure from the generation
MVA thresholds included in the NERC Statement of Compliance Registry Criteria.
Included in BES: I3 – Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating) including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
Included in BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
utilizing a collector system through a common point of interconnection to a system Element at a voltage of 100 kV or above.
Excluded from BES: E2 - A generating unit or multiple generating units that serve all or part of retail Load with electric energy on the customer’s
side of the retail meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and (ii) standby,
back-up, and maintenance power services are provided to the generating unit or multiple generating units or to the retail Load pursuant to a
binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.

Organization

Yes or No

Question 3 Comment

Northeast Power Coordinating
Council

No

Refer to the response Question 2 above. The answer depends on whether the generator output is consumed
locally or is necessary to maintain the reliability of the BES.

PUD No.1 of Clallam County

No

See comments to question2.

Orange and Rockland Utilities,
Inc.

No

Refer to the response Question 2 above. The answer depends on whether the generator output is consumed
locally or is necessary to maintain the reliability of the BES.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment

No

As in question 2, there is no engineering evidence that all of the facilities are necessary to reliably operate an
interconnected transmission system.

No

Dominion does not agree that generation plants should be classified as part of the BES.Dominion supports
the criteria for registering owners, operators, and users of the bulk power system, as indicated in the current
Statement of Compliance Registry Criteria .

City of Redding

Response: Please see response to Q2.
Electric Market Policy

Response: Dominion makes the suggestion that all generators be excluded from the BES, however, Dominion does not provide a technical justification for this
significant departure.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
SERC OC Standards Review
Group

No

We do not agree with the inclusion of GSU transformers and associated interconnecting line leads. Lines and
transformers should be included based upon the voltage and not the function they serve.
We support the inclusion of all non-radial lines operated at a voltage of 100 kV or higher as well as all
transformers with both primary and secondary windings operated at 100 kV or higher. We do not support
generic inclusions of any radial lines or transformers with primary or secondary windings operated below
100kV. Our response in question 13 amplifies this statement.

Response: SERC has not provided justification for excluding all GSU transformers and associated interconnecting lines leads from the BES.
The SDT believes that generation plants larger than 75 MVA connected above 100kV including GSU transformers and interconnecting line leads need to be
included within the BES.
The SDT has revised the definition and included specific inclusion and exclusion criteria that address these issues.
Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
PacifiCorp

March 30, 3011

No

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology. Significant
efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF) over the
course of the past year to identify some initial criteria and methodologies. These efforts are ongoing and
should be supported by the NERC drafting team. For example: Generation plants should not be included or
excluded solely based on a their gross nameplate rating and the operating voltage at which they are
connected to transmission facilities. Generation plants which are necessary to operate the interconnected
network should be included as part of the regulated BES. Generating plants which are not “necessary for the
operation of the interconnected network” should be excluded. A methodology needs to be developed to
determine which generating plants may be excluded as part of the regulated BES.

Response: The SDT acknowledges that commenters will need to reserve judgment on the exception process, which is being developed as a modification to the
NERC Rules of Procedure (ROP). This exception process will be a parallel effort to this BES definition development. The SDT further acknowledges the work of
WECC and other regional entities (e.g., RFC, FRCC, and NPCC) in proposing the BES definition, bright lines, and exclusion/inclusion criteria and processes. The
work of these regional entities has greatly helped the SDT.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
PPL Energy Plus

No

See response to Questions 2 and 8.

LG&E and KU Energy LLC

No

See response to Questions 2 and 8.

No

I have reservations about the removal of the ability to use the net rating of a generation asset as the
generator rating (i.e. the use of gross rating of a machine instead of net rating of the energy provided to the
BES). Many industrial companies have back up power agreements with utilities to cover the loss of internal
generation assets. The requirement to ensure that this back up power can be provided should be part of the
NERC requirements for Transmission Operators and Balancing Authorities (e.g. the VAR-001 requirement for

Response: See response to Q2 & Q8.
ExxonMobil Research and
Engineering

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment
TOPs to obtain the necessary reactive resources to cover normal and contingency operations). The reliability
goals and strategy of some large electricity consumers that this change is targeting differ from the bulk
electric system. For instance, a petrochemical facility that utilizes generation to offset the load seen by the
BES may desire to disconnect from the bulk electric system during an event in order to preserve the stability
of the private use network that supplies electricity to the equipment that control its chemical processes. As
history has demonstrated, the most dangerous activities that petrochemical facilities undertake are the
shutdown and startup of their processes. As a side note, the term 'directly connected' should be added to the
NERC glossary. The concept of 'directly connected' is the key to understanding which generators are
included in the BES and which generators are exempted.

Response: The SDT’s proposed BES definition has exclusion criteria that address these issues.
Excluded from BES: E2 - A generating unit or multiple generating units that serve all or part of retail Load with electric energy on the customer’s side of the
retail meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load pursuant to a binding obligation with a
Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable regulatory authority.
Arizona Public Service Company

No

The minimum plant size should be 300 MVA. Smaller plants do not materially impact the reliability of thle
BES.

Response: The SDT appreciates the suggestion of a 300 MVA generation threshold for materiality of impact, however, as of this date sufficient technical
justification has not been submitted upon which to base a significant departure from the generation MVA thresholds included in the NERC Statement of
Compliance Registry Criteria.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
Central Lincoln

No

The generation resources so described should be presumed to be part of the BES unless or until they have
been through the exemption process and as a result have been classified as non-BES.

Response: Thank you for your response. The SDT agrees.
American Municipal Power

March 30, 3011

No

Suggest 125 MVA

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment

Response: The SDT appreciates the suggestion of a 125 MVA generation threshold, however, as of this date sufficient technical justification has not submitted
upon which to base a significant departure from the generation MVA thresholds included in the NERC Statement of Compliance Registry Criteria.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure, in a parallel effort to the development of this BES definition.
Indeck Energy Services

No

Same Response as Question 1

No

75 MVA aggregate is too low. 200 MVA aggregate is appropriate for this region.

Response: See response to Q1.
City of Grand Island

Response: The SDT appreciates the suggestion of a 200 MVA generation threshold however, as of this date sufficient technical justification has not been
submitted upon which to base a significant departure from the generation MVA thresholds included in the NERC Statement of Compliance Registry Criteria.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
City of Anaheim

No

Unless the generator is required to maintain BES reliability, i.e. black start, etc., the GSU and gen tie should
be excluded from the BES; provided, however, to eliminate any reliability gaps, such generation-tie equipment
should be classified as "Generator" equipment subject to GO/GOP standards, and the PRC and vegetation
management standards should be made applicable to GO/GOPs and this equipment. This is consistent with
the NERC Reliability Functional Model and is more efficient than requiring TO/TOP registration for non-critical
generation-tie transmission elements that are not required for the reliable operation of the BES.

Response: The SDT appreciates the City’s suggestions, however; the City’s recommendations go beyond the SAR scope of work given to the SDT. The SDT has
not been charged with determining the applicability of various standards.
Also, as of this date sufficient justification has not been submitted demonstrating that GSU transformers and interconnecting generation ties should be excluded
from the BES.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment

should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
Snohomish County PUD

No

The generation resources described should not be presumed to be part of the BES. The criteria above are
intended to identify those entities that are required to register as user, owner or operator of the bulk system,
and not to define a BES device. As noted in our response to question 2, Snohomish is concerned that the
enforcement process to date has frequently conflated registry criteria and definitions of the BES.

Response: Snohomish has not provided justification for varying from a 75 MVA bright line for determining BES generation plants. Further, as of this date, the
SDT has not received sufficient technical justification upon which to base a significant departure from the generation MVA thresholds included in the NERC
Statement of Compliance Registry Criteria.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
PNGC Power

No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Please see our response to Question 2

.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric
Cooperative

No

Lincoln Electric Cooperative

No

Fall River Electric Cooperative

No

Question 3 Comment

Response: See response to Q2.
Glacier Electric Cooperative

No

Once again, I believe it depends on the facility and its importance to the grid. Some 75 MVA plants will have
a greater impact than others. The ones that are truly important to the grid should be include, but the ones that
are not should not be. I believe more of an analytical approach would be much more accurate in determing
which facilities truly should be part of the BES than the bright-line approach that is being attempted.

United Illuminating Company

No

Any goupr of Generators connected at 100 kV or above should be part of BES. There should not be a MVA
threshold

Response: The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception
process – for exclusions/inclusions – should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such

March 30, 3011

52

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment

plants are not necessary for operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES
definition should include exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of
the revision to the NERC Rules of Procedure, in a parallel effort to the development of this BES definition.
Lewis County PUD

No

75MVA generation resources should not be part of the BES. This size generating resource is too small to
affect the BES. Suggest the minimum size BES resource be changed to 150MVA. If a smaller threshold is
used then the RE or BA should demonstrate to the GO than this resource is critical to the BES.

Response: The SDT appreciates the suggestion of a 150 MVA threshold for materiality of impact, however, sufficient technical justification has not been submitted
upon which to base a significant departure from the generation MVA thresholds included in the NERC Statement of Compliance Registry Criteria.
The SDT believes that generation plants larger than 75 MVA connected above 100kV need to be included within the BES definition. The exception process
should allow for the possibility that certain generating plants larger than 75 MVA can be excluded if it can be proven that such plants are not necessary for
operating the interconnected Transmission network. Additionally, the Commission in its Order 743 suggests that the revised BES definition should include
exception processes for exclusion/inclusion of various Elements. The process for such exclusions/inclusions will be developed as part of the revision to the NERC
Rules of Procedure by a different team in a parallel effort to the development of this BES definition.
Independent Electricity System
Operator

No

Same comment as in Q3, above.

Response: It is assumed that the commenter is referring to Q2. See SDT response to Q2.
The Dow Chemical Company

As discussed in response to question #12 below, issues relating to the registry criteria applicable to
generation resources should not be revisited at this time.

Response: See response to Q12.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation

March 30, 3011

Yes

Constellation firmly believes that the classifications found in the Compliance Registry Criteria - Section III
(Rules of Procedure Appendix 5B), such as that cited in this question, provide a useful basis to create a
comprehensive, revised BES definition.
Further, we propose that the BES drafting team incorporate the criteria directly into the revised BES definition,
replacing the term “bulk power system” in each criterion with “greater than 100 kV.” This would then include
assets that are currently registered as BES elements as well as those that may have been previously
excluded due to Regional exemption variances. Structuring the revised BES definition to clarify both the
inclusions and exclusions, can, ideally, eliminate the need for an onerous exemption process as well as

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Question 3 Comment
eliminate the need for Section III of the Registry Criteria.
Please see our response to question 11 for more detail on a proposed alternative approach to structuring the
BES definition revision.

Response: the SDT agrees that the Registry Criteria is a valuable resource for deliberations on a BES definition and has utilized it whenever possible.
The SDT agrees and has made the suggested change.
See response to Question 11.
Occidental Energy Ventures Corp

Yes

Many generator interconnection lines are operated at voltages greater than 100KV, but have traditionally not
been considered part of the the transmission system. Rather these lines have been considered part of the
generation system and, for quite some time, have been constructed and operated according to
interconnection agreements which specify design and protection criteria. The BES definition should not be
constructed in either a direct or implied manner that would alter the interconnection line status as being part of
the Generation Facilities. Otherwise, it could result in registration of GO/GOPs as TO/TOPs. The issue of
what additional standards, if any, should apply to these generation interconnection lines is the subject of
Project 2010-07 and should be resolved by that standards development effort, not by a definition change.
The proposed definition appears not to violate the inclusion of the interconnection line as part of the
Generation Facility while still providing for these lines to be part of the BES, however, some clarification might
be advisable (e.g., a statement that interconnection lines are part of the Generation Facility or are Generation
Elements).

Response: The SDT appreciates the Occidental’s suggestions, however; the recommendations go beyond the SAR scope of work given to the SDT. The SDT
has not been charged with determining the applicability of various standards.
American Transmission company

Yes

For clarity, ATC suggests that the “. . . aggregate capacity greater than 75 MVA . . . “ wording be changed to
read, “. . . aggregate generator capacity greater than 75 MVA. . . and further classified as part of the BES
given that a fault or outage of the aggregate generator capacity greater than 75 MVA would not maintain an
Adequate Level of Reliability of the BES.

Response: The SDT appreciates the ATC’s concern; however, ATC has not provided rationale for the change.
Xcel Energy

March 30, 3011

Yes

Xcel Energy believes that clarity should be added as to what constitutes an individual generation resource
and a generating plant, especially as it pertains to multiple owner facilities and aggregating facilities such as
wind or solar farms (which may also have multiple owners for discreet facilities that tie into a common bus).
Discussion and controversy in other NERC and regional forums and standard development teams indicates

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment
that this is not well defined. It may be that the Statement of Compliance Registry needs to be enhanced if it
forms the foundation for which these items are to be understood.

Response: The SDT has revised the BES definition and has included specific inclusion and exclusion criteria that addresses dispersed generation plants
(including wind and solar farms, which may contain multiple owners).
Included in BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a
collector system through a common point of interconnection to a system Element at a voltage of 100 kV or above.
The SDT has not been charged with making changes to NERC’s Statement of Compliance Registry Criteria and has adopted a goal of not changing that criteria if
at all possible.
Bonneville Power Administration

Yes

There needs to be additional clarity on the definition of generation plant. Wind generation needs to be
incorporated.

Response: The SDT has revised the BES definition and has included specific inclusion and exclusion criteria that addresses dispersed generation plants
(including wind and solar farms).
Included in BES: I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a
collector system through a common point of interconnection to a system Element at a voltage of 100 kV or above.
NERC Staff

Yes

Please see additional comments at the end of this document.

Response: These comments were submitted in response to the concepts paper and were considered
MRO's NERC Standards Review
Subcommittee

Yes

See question 2 for similar comments and it is apparent that the SDT is trying to model the BES definition on
the Statement of Compliance Registry Criteria (v5). Recommend that this question be struck. Question 2
above addresses connection requirements of Generators. For clarity, NSRS suggests that the “. . . aggregate
capacity greater than 75 MVA . . . “ wording be changed to read, “. . . aggregate generator capacity greater
than 75 MVA. . . and further classified as part of the BES given that a fault or outage of the aggregate
generator capacity greater than 75 MVA would not maintain an Adequate Level of Reliability of the BES.

Response: The SDT appreciates the comments; however, the SDT has not received sufficient technical justification upon which to base a significant departure
from the generation MVA thresholds included in the NERC’s Statement of Compliance Registry Criteria. MRO has not provided a rationale for making the
language change.
ReliabilityFirst

March 30, 3011

Yes

It is recommended that the term “directly connected” be defined and examples of this term are included in the

55

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment
ERO definition.

Response: The SDT has revised the definition and the term “directly connected” is no longer utilized.
SERC EC Planning Standards
Subcommittee

Yes

Public Service Enterprise Group
Company

Yes

IRC Standards Review
Committee

Yes

Florida Municipal Power Agency

Yes

FirstEnergy Corp

Yes

Transmission Access Policy
Study Group

Yes

Competitive Suppliers

Yes

Pepco Holdings Inc.

Yes

LCRA Transmission Services
Corporation

Yes

Manitoba Hydro

Yes

North Carolina EMC

Yes

on behalf of Teck Metals Ltd.

Yes

Southern California Edison

Yes

March 30, 3011

Yes, but see comments in section 2 above.

See FMPA response to Question 2 above.

See TAPS response to Question 2 above.

See comment to item 2 above.

SCE currently reports on generation plants (including GSU transformers and the associated generator
interconnecting line lead(s))with aggregate capacity greater than 75 MVA (gross nameplate rating) directly

56

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment
connected via a step-up transformer(s) to Transmission Facilities operated at voltages of 100 kV or above.
SCE does not feel a blanket inclusion of all the listed equipment is needed.

Southern California Edison
Company

Yes

on behalf of Catalyst Paper
Corporation

Yes

Entergy Services

Yes

Utility Services

Yes

City of Austin dba Austin Energy

Yes

Duke Energy

Yes

The Dayton Power and Light
Company

Yes

ITC Holdings Corp

Yes

BGE

Yes

City Water Light and Power
(CWLP) - Springfield, IL

Yes

American Electric Power (AEP)

Yes

Southern Company

Yes

March 30, 3011

A GSU transformer is clearly an extension of the functionality provided by the Generator Interconnection
Elements, namely, to move bulk power from the BES generator to the BES network, and hence, the
classification of the GSU transformer should match that of the Generator Interconnection Elements.

Initially, yes; however, such a classification could be exempted upon a NERC review of the technical
justification for exemption.

No comment.

However, considering today’s transmission network and typical plant size, the plant size that can impact the
reliability should be reevaluated. Particularly Wind Farms with dozens of small generators could have an
impact on the BES if enough exist. Therefore, the 75 MVA threshold should work in this instance.

57

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Idaho Power

Yes

Springfield Utility Board

Yes

Clark Public Utilities

Yes

Question 3 Comment

"directly connected" is important.

Response: Thank you for your response. Please see the summary consideration immediately under the question. Several stakeholders made suggestions that
were adopted by the drafting team.

March 30, 3011

58

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

4. Should the following be classified as part of the BES?
•

Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s (TOP’s)
restoration plan

Summary Consideration: There was no consensus amongst commenters who responded to this question. The Commission directed NERC to
revise its BES definition to ensure that the definition encompasses all Facilities necessary for operating an interconnected electric Transmission
network. The SDT interprets this to include operation under both normal and Emergency conditions, which includes situations related to black
starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be energized without
connection to the remainder of the System, to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from
a Blackstart Resource is essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system
restoration plan. For these reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths
indentified in the Transmission Operator’s restoration plan as BES Elements.

Organization

Yes or No

SERC EC Planning Standards
Subcommittee

No

Southern Company

No

Question 4 Comment
A blackstart designation should not necessarily make it part of the BES.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
Public Service Enterprise Group
Company

March 30, 3011

No

Including these in the definition of BES would impose compliance obligations for these assets even if below
100kV at the same level as assets at or above the 100kV level. Blackstart Resources and Cranking Paths
below 100kV do not impact the reliability of the BES and thus should not be required to comply with all
standards as if they did. For example, 26kV cranking path protection systems typically only trip the 26kV, not
100kV or higher BES transmission facilities, thus do not impact the BES, and should not be required to meet

59

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment
BES compliance standards for system protection. That assets can have different impacts and thus different
levels of required compliance is expressly recognized in the recently stakeholder approved CIP-002-4 draft
standard where blackstart cranking paths must be included as critical assets subject to CIP protections only to
the point where two or more path options exist. Rather than include all Blackstart Resources and the
designated Blackstart Cranking Paths indentified in the Transmission Operator’s (TOP’s) restoration plan in
the blanket definition of BES, the drafting team should be directed to develop a definition that states that
these assets are not part of the BES except where specifically identified in a requirement of a standard as
needing to be compliant. For example, a standard requiring testing of Blackstart units would result in a
Blackstart unit being deemed BES for purposes of that standard only.

FirstEnergy Corp

No

Blackstart generation and cranking paths do not need to be defined as being part of the BES. Rather, they
are more appropriately reflected as supporting and restoring operation of the BES. Not all aspects of the BES
reliability standards pertain to BES facilities. For example, UFLS and UVLS installed on a distribution system
are important to arrest BES reliability concerns but they are not needed in what defines the BES. Similarly,
blackstart generation and Cranking Paths do not need to be inclusive of what defines the BES but are
important aspects of a restoration plan to re-establish a functioning BES.

American Transmission company

No

Blackstart Resources and designated blackstart Cranking Paths should not be classified as part of the BES,
except those Elements and/or Facilities that are rated 100 kV or more and with a gross generator nameplate
rating of 20 MVA or more.

City of Austin dba Austin Energy

No

Just because a unit can be used for black start should not - by definition - mean it is part of the BES. For
example, there may be a very small unit which can be used for black start and the operating utility should not
have to comply with all the NERC Standards all the time when that asset becomes “important” only during a
black start event. Additionally, protective systems associated with small black start units would have to fulfill
the same reliability requirements as any other BES generator even though those protective systems would
have little purpose during a black start event.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

Again, Facilities identified as necessary for blackstart capability (both Blackstart Resources and the blackstart Cranking Path) in a Transmission Operator’s
restoration plan should be designated as part of the BES, and be subject to the corresponding NERC Standards referencing the BES.
A review of the NERC Reliability Standards will be undertaken once the BES Definition is finalized to clearly delineate responsibilities for owners and operators of
BES designated Facilities.
MRO's NERC Standards Review
Subcommittee

No

This question is irrelevant to the scope of this project. A Blackstart Resource may be a 10 MVA unit
connected at the distribution level of voltage and within the TOP’s Restoration Plan. Just because the unit is
within the TOP’s Restoration Plan does not make it a BES connected asset. CIP-002-4 is already industry
approved and may “push” both large and small entities to remove these units from the TOP’s Restoration
Plan due to the Critical Asset label. If the Blackstart Resource is connected via GSU at 100 kV then it would
be part of the BES. If the SDT is worried that a Blackstart Resource will not be maintained or tested, those
requirements are within EOP-005-1 (and yet to be approved EOP-005-2). Blackstart Resources and
designated blackstart Cranking Paths should not be classified as part of the BES, except those Elements
and/or Facilities that are rated 100 kV or more and with a gross nameplate rating of 20 MVA or more.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
For example, BES generation may require external Interconnections and Facilities in order to provide power to auxiliary equipment within the plant during times of
system restoration.
IRC Standards Review
Committee

No

NERC Standards EOP-00-2 stipulates the requirements for testing Blackstart Resource and Cranking Paths.
This testing requirement ensures that the facilities critical to system restoration are functional when needed.
Inclusion of any resources or transmission paths as BES Elements/Facilities intended for use for system
restoration should be determined using the criteria 1-3, above.

Response: The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for operating an
interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which includes situations
related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be energized without

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power capability,
frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart Resources are
essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT
has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s restoration plan as BES
Elements.
A review of the NERC Reliability Standards will be conducted once the BES Definition is finalized in order to clearly delineate responsibilities for owners and
operators of BES designated Facilities.
PacifiCorp

No

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology. Significant
efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF) over the
course of the past year to identify some initial criteria and methodologies. These efforts are ongoing and
should be supported by the NERC drafting team. For example: Blackstart Resources and designated
blackstart Cranking Paths should be included only if they are deemed necessary to restore the interconnected
electric transmission network.

ISO New England Inc.

No

1. Revise the statement, “Blackstart Resources and the designated blackstart Cranking identified in the
Transmission Operator’s (TOP’s) restoration plan.” to “Blackstart Resources “material to” and designated as
part of a Transmission Operator’s (TOPs) restoration plan.” Reason - Some regions have many blackstart
units that are not material to a TOPs restoration plan. These units need not register and be subjected to the
NERC Standards. Only those deemed material (i.e., “key facilities”) should be classified as part of the BES.
See NERC Registry Criteria for reference to “material” in describing, and qualifying, what constitutes
Blackstart Resources.”
2. NERC Standard EOP-00-2 stipulates the requirements for testing Blackstart Resources and Cranking
Paths. This testing requirement suffices to ensure that the facilities critical to system restoration are functional
when needed. Designating these facilities as BES Elements or Facilities beyond the 100 kV bright line
criterion will impose unnecessary requirements for these facilities which may not contribute to the BES
reliability for everyday operations. If indeed any of these facilities are deemed necessary to support BES
reliability for everyday operation, they will be identified through either the 100 kV bright line criterion or the

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment
exemption/inclusion process.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
The SDT assumes that the Blackstart Resources and designated blackstart Cranking Paths included in the Transmission Operator’s restoration plans are those
deemed necessary or required to reliably restore the system, or they wouldn’t be included in the plan, subjecting them to the NERC Standard testing requirements.
Arizona Public Service Company

No

With all of the new NERC Standards in place, a blackout should be an extremely rare event; therefore,
classifying Blackstart units or Cranking Paths is not needed.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
Again, the Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for operating an interconnected
electric Transmission network. This determination is based on the reliable restoration of the system, independent of likelihood of the assumed occurrence of the
need for restoration.
Independent Electricity System
Operator

March 30, 3011

No

NERC Standards EOP-00-2 stipulates the requirements for testing Blackstart Resource and Cranking Paths.
This testing requirement suffices to ensure that the facilities critical to system restoration are functional when
needed. Designating these facilities as BES Elements or Facilities beyond the 100 kV bright line criterion will
impose unnecessary requirements for these facilities which may not contribute to the BES reliability at times
other than during system restoration. If indeed any of these facilities are deemed necessary to support bulk
power system reliability at times other than during system restoration, they will be identified through either the
100 bright line criterion or the exemption/inclusion process.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

American Electric Power (AEP)

No

Should be re-written to state that only those Blackstart Resources in the Transmission Operator’s (TOP’s)
restoration plan be classified as part of the BES.

City Water Light and Power
(CWLP) - Springfield, IL

No

CWLP feels that blackstart resources and cranking paths not otherwise qualified as a part of the BES based
on other criteria should not be included in the definition of BES solely based on their status as blackstartcapable units. Requirements for blackstart resources and cranking paths are already addressed by existing
and proposed EOP standards and we feel that arbitrarily classifying these elements as part of the BES may
create undue burden on Transmission Owners when the same reliability result can be achieved through more
directed effort in the EOP standards. Further, while such blackstart resources and cranking paths may
support operation of the BES, they need not be strictly included in the definition of BES to achieve the desired
reliability result.

City of Grand Island

No

Not across the board. Generator criteria from questions 2 and 3 can apply to blackstart generators as well.
Otherwise the exception process can be used.

Southern California Edison

No

SCE does not feel a blanket inclusion of all the listed equipment is needed.

Pepco Holdings Inc.

No

To remain consistent with the proposed definition of facilities 100kv and above, this should not be included.
Inclusion would not result in a more reliable system or reduce risk.

Electric Market Policy

No

Dominion does not agree that Blackstart Resources should be classified as part of the BES.Dominion
supports the criteria for registering owners, operators, and users of the bulk power system, as indicated in the
current Statement of Compliance Registry Criteria .

Central Lincoln

No

The generation resources so described should be presumed to be part of the BES unless or until they have
been through the exemption process and as a result have been classified as non-BES.

Lewis County PUD

No

Entergy Services

No

The Dayton Power and Light
Company

No

Snohomish County PUD

No

March 30, 3011

The generation resources so described should be presumed to be part of the BES unless they have been

64

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

PNGC Power

No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric
Cooperative

No

March 30, 3011

Question 4 Comment
demonstrated through performance-based studies to present no substantial threat of separation events,
cascading outages, or voltage instability on the bulk system.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Lincoln Electric Cooperative

No

Fall River Electric Cooperative

No

Question 4 Comment

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
Again, Facilities critically identified as necessary for blackstart capability (both Blackstart Resources and the blackstart Cranking Path) in a Transmission Operator’s
restoration plan should be designated as part of the BES, and be subject to the corresponding NERC Standards referencing the BES.
BGE

No

This proposal as written could lead to a reduction in the number of blackstart units which rely on cranking
paths of less than 100 kV and not currently classified as BES, thereby reducing BES reliability.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary for
operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
The Transmission Operator will remain responsible for maintaining a viable restoration plan, regardless of the BES definition.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC

March 30, 3011

No

This proposal as written could lead to a reduction in the number of blackstart units which rely on cranking
paths of less than 100 kV and not currently classified as BES, thereby reducing BES reliability. To account for
this potential gap, Constellation firmly believes that the classifications found in the Compliance Registry
Criteria - Section III (Rules of Procedure Appendix 5B), such as that cited in this question, provide a useful
basis to create a comprehensive, revised BES definition.
Further, we propose that the BES drafting team incorporate the criteria directly into the revised BES definition,
replacing the term “bulk power system” in each criterion with “greater than 100 kV.” This would then include

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Question 4 Comment
assets that are currently registered as BES elements as well as those that may have been previously
excluded due to Regional exemption variances. As an example, the Compliance Registry Criteria includes
any generator, regardless of size, that is a blackstart unit material to and designated as part of a transmission
operator entity’s restoration plan. The Compliance Registry also includes transmission as elements above
100kV or that is critical as defined by the Regional Entity (excluding radial facilities as described in the current
BES definition). Structuring the revised BES definition to clarify both the inclusions and exclusions, can,
ideally, eliminate the need for an onerous exemption process.
Please see our response to question 12 for more detail on a proposed alternative approach to structuring the
BES definition revision.

Response: The SDT disagrees. The Commission directed NERC to revise its BES definition to ensure that the definition encompasses all Facilities necessary
for operating an interconnected electric Transmission network. The SDT interprets this to include operation under both normal and Emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be
energized without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for real and reactive power
capability, frequency, and voltage control. The portion of the electric system that can be isolated and then energized to deliver electric power from Blackstart
Resources are essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s system restoration plan. For these
reasons, the SDT has included Blackstart Resources and the corresponding designated blackstart Cranking Paths indentified in the Transmission Operator’s
restoration plan as BES Elements.
The SDT agrees and has made the suggested change and replaced the term “bulk power system” in each criterion with “greater than 100 kV.”
Please see response to Q12.
The Dow Chemical Company

As discussed in response to question #12 below, issues relating to the registry criteria applicable to
generation resources should not be revisited at this time.

Response: Please see response to Q12.
ReliabilityFirst

Yes

It is recommended that the term “cranking path” be defined and examples of this term be provided.
Also, does the term "cranking paths” include all paths or just the primary path if there are multiple paths
available?

Response: The NERC Glossary of Terms defines ‘Cranking Path’ as “A portion of the electric system that can be isolated and then energized to deliver electric
power from a generation source to enable the startup of one or more other generating units”.
NERC Staff

March 30, 3011

Yes

Please see additional comments at the end of this document.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

Response: See response to Q13.
Springfield Utility Board

Yes

Clark Public Utilities

Yes

Xcel Energy

Yes

City of Redding

Yes

City of Anaheim

Yes

Northeast Power Coordinating
Council

Yes

Florida Municipal Power Agency

Yes

See FMPA response to Question 2 above.

Bonneville Power Administration

Yes

Blackstart resources should never be allowed to be excluded through any technical studies.

SERC OC Standards Review
Group

Yes

Transmission Access Policy
Study Group

Yes

See TAPS response to Question 2 above.

PPL Energy Plus

Yes

LG&E and KU Energy LLC

Yes

Blackstart Resources and the designated blackstart Cranking Paths identified in the TOP’s restoration plan
are a special case and warrant inclusion in the BES definition regardless of voltage because of their
importance to BES reliability. However, this would not be the case for other facilities operated below 100 kV.

Competitive Suppliers

Yes

ExxonMobil Research and
Engineering

Yes

March 30, 3011

68

Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

LCRA Transmission Services
Corporation

Yes

This is critical for system restoration.

PUD No.1 of Clallam County

Yes

Based on the current Reliability Standards practices it may be advantageous to reduce the number of
blackstart generation and cranking paths to limit exposure to BES applicable standards. At this time if a
registered entity has multiple blackstart units, it may be advantageous to reduce or decommission the number
to avoid compliance risks. The current requirements may ultimately reduce the number of blackstart units and
reduce BES electric reliability. It may make more sense to identify subset of critical blackstart projects and
associated cranking paths as BES elements. The generation resources so described should be presumed to
be part of the BES unless or until they have been through the exemption process and as a result have been
classified as non-BES.

Manitoba Hydro

Yes

American Municipal Power

Yes

North Carolina EMC

Yes

on behalf of Teck Metals Ltd.

Yes

Indeck Energy Services

Yes

Southern California Edison
Company

Yes

on behalf of Catalyst Paper
Corporation

Yes

Occidental Energy Ventures Corp

Yes

City of Anaheim

Yes

Glacier Electric Cooperative

Yes

March 30, 3011

These resources are significant to the BES and should be included.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

United Illuminating Company

Yes

Orange and Rockland Utilities,
Inc.

Yes

Utility Services

Yes

Duke Energy

Yes

ITC Holdings Corp

Yes

Idaho Power

Yes

Question 4 Comment

Yes, but the Blackstart Resources identified as the PRIMARY resources in the System Restoration Plan
should be the focus.

Response: Thank you for your response.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

5. Should the following be classified as part of the BES?
•

Transmission Elements or Facilities operated at voltages below 100kV where the exemption process deems the Element or
Facility to be included in the BES

Summary Consideration: Most commenters who responded to this question indicated disagreement with the proposal however there was no
consensus amongst the alternate proposals offered, and the proposals suggesting other thresholds were not supported with any technical
justification. The SDT has reviewed the industry comments on this issue, debated the topic, and has come to an agreement that the bright-line
designation for Transmission Elements is 100kV and above. Any deviations from the bright-line designation (beyond those identified in the revised
definition of BES), including Transmission Elements operated below 100kV, will be handled through the Rules of Procedure process that is being
developed by a separate team.

Organization

Yes or No

Question 5 Comment

SERC EC Planning Standards
Subcommittee

No

We prefer a bright-line rule of 100 kV. The exception process should not be used to include facilities operated
at voltages below 100 kV.

Arizona Public Service Company

No

There are no practical cases where the facilities below 100 kV impact the major load centers or BES.

North Carolina EMC

No

Transmission elements or facilities operated at voltages below 100kV should only be included in the BES if
identified by the RRO as critical to the BES.

Southern California Edison
Company

No

The Exemption Process should apply to transmission elements or facilities greater than 100kV only. Facilities
operated below 100kV are generally used for distribution purposes.

BGE

No

This proposal as written could lead to the inclusion of elements or facilities which have no material reliability
impact on the interconnected transmission system.

Southern Company

No

We prefer a bright-line rule of 100 kV. The exception process should not be used to include facilities operated
at voltages below 100 kV.

ExxonMobil Research and
Engineering

Yes

It is conceivable that, in some areas, the Bulk Electric System may include transmission assets that are rated
and operated at 69kV or below.

Response: The SDT appreciates the preference of several entities to utilize strict bright-line criteria of Facilities at 100kV and above that would be considered for
inclusion in the BES. The SDT has carefully considered this matter, and believes that the exception process must allow for the possibility that certain Facilities

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment

operated at voltages below 100kV could have appreciable influence over the reliable operation of the interconnected network Transmission grid, thereby
warranting examination through an exception process for inclusion in the BES. The SDT expects that these exceptions for Facilities operated at voltages below
100kV will be relatively rare. The criteria for such inclusion will be developed as part of this project and the ROP process will be handled by a separate team
through the revision to the Rules of Procedure, in an effort parallel to the development of the BES definition.
ITC Holdings Corp

No

PRC023 has developed a process for specification of critical lines below 100 kV. This same process should
be used to include below 100 kV lines in the BES

Florida Municipal Power Agency

No

Transmission Access Policy
Study Group

No

This Question refers to including an Element in the BES through the exemption process, suggesting that the
SDT is contemplating a single process for including nominally non-BES Elements in the BES and for
exempting nominally BES Elements from the BES. While it would make sense for the two processes to be
similar, they cannot be identical: The burden should be on the entity requesting an exemption to show that an
Element that is nominally part of the BES is nevertheless not necessary for operating the interconnected
electric transmission network and thus should be exempted from the BES. In contrast, with respect to
transmission operated at voltages below 100 kV, it is NERC that must show, on a case-by-case basis, that
transmission that is not nominally part of the BES is nevertheless necessary for operating the interconnected
electric transmission network and thus should be included in the BES.Transmission operated at voltages
below 100 kV should only be classified as part of the BES if the inclusion process, assessing each Element on
a case-by-case basis, based on a uniform set of criteria, results in a finding that the particular Element should
be included in the BES.

Response: The process for inclusions and exclusions will be developed by a separate team as part of the revision to the Rules of Procedure, in an effort parallel to
the development of the BES definition. Your comments will be forwarded to the Rules of Procedure Team.
FirstEnergy Corp

No

We do not agree with an "exemption process" being associated with "including facilities". We suggest keeping
the exemption process separate from the identification of critical sub 100kV facilities that will be included in the
BES. We do agree that a consistent continent-wide approach for identifying these facilities is a worthwhile
goal but should be a secondary priority to establishing the BES definition and BES exemption process.

Response: The SDT envisions an “exception process”, and regrets the use of “exemption” in the original SAR. The processes for inclusions and exclusions will be
developed by a separate team as part of the revision to the Rules of Procedure, in an effort parallel to the development of the BES definition. Your comments will
be forwarded to the Rules of Procedure Team.
American Electric Power (AEP)

March 30, 3011

No

Exemption processes are distinctly different than inclusion processes, and clarification is needed to address
their differences. There should be two distinct processes. Until details of such processes and their related
criteria are better defined, it is difficult to provide substantive comments.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment

MRO's NERC Standards Review
Subcommittee

No

FERC has directed (in section 30 of FERC Order 743) that NERC have an established “exemption” process to
remove this judgment from the Regions in defining what the BES is. However, the applicable process should
be called an “exception” process, not an “exemption” process that infers the concept of “exclusion” and further
classified as part of the BES given that a fault or an outage on the Transmission Element or Facility at
voltages below 100kV would not maintain an Adequate Level of Reliability of the BES.

PacifiCorp

No

In paragraph 121 of Order No. 743, the Commission states that it agrees that the ERO should develop a
parallel process for including as part of the bulk electric system “critical” facilities, operated at less than 100
kV, that the Regional Entities determine are necessary for operating the interconnected transmission network.
(emphasis added) Further, the Commission stated that “[w]e believe that it would be worthwhile for NERC to
consider formalizing the criteria for inclusion of critical facilities operated below 100 kV in developing the
exemption process.” (emphasis added) PacifiCorp believes that it is appropriate to use the same criteria to
determine what elements or facilities should be included in the definition of Bulk Electric System as those used
to determine what elements or facilities should be excluded from the definition. However, the formal process
used for exclusion (i.e. the exemption process) of facilities above 100 kV should not be the same process as
the process for inclusion of sub-100 kV facilities. As PacifiCorp understands it, per the Commission, the
exemption process will require a facility-by-facility approval by NERC for exemption whereas inclusion of sub100 kV facilities will involve a Regional Entity determination that such facilities must be included. These
should therefore be separate processes.

Central Lincoln

No

PUD No.1 of Clallam County

No

Including elements through an exemption process is bound to create confusion and misunderstandings
between the registrants and REs. Please include such elements through an inclusion process. It should also
be clarified that registrants are not required to put all sub-100 kV elements through this process; the burden
should be on the RE to include elements of particular concern.

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743. The process for such inclusions will be developed by a separate team through the revision to
the Rules of Procedure, in an effort parallel to the development of the BES definition.
Pepco Holdings Inc.

No

Some details on the exemption process must be known before accepting this. Who can submit an exemption
(DP, GO, GOP, TO, TOP, RC, etc)? How do interested parties get informed? Can others intervene?

Occidental Energy Ventures Corp

No

Until the expemtion process is finalized, it is not prudent to answer in the affirmative.

Entergy Services

No

Our response to this question depends on the details of the “exemption process”, including what entity has the

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment
final decision and how it is implemented. Please see our response to Q13 below.

City Water Light and Power
(CWLP) - Springfield, IL

No

While CWLP agrees with the general concept of inclusion by exception (as opposed to exemption), we have
concerns regarding the lack of detailed definition of this process, especially the administrative process for
disputes regarding inclusion of elements in the BES. Without firm administrative rules for resolving disputes
based on technical justification, we cannot support this measure currently.

Manitoba Hydro

It is confusing to use the term “exemption process” to determine what is included. Abstain until exemption
process has been defined.

Duke Energy

There is not enough information available at this time to adequately evaluate this question. It would be
necessary to have a list of exemption criteria or more detail on the exemption process to address this
question. This is one of the reasons that the exemption criteria should be developed through the standards
development process along with the definition.

Xcel Energy

Xcel Energy does not disagree that there may be situations where elements below 100KV may need to be
included, but we have concerns about the exemption process. This undeveloped process presents itself as a
wild card to entities, and will most likely present inconsistencies between regions based upon each Region’s
preference. Additionally, does the Regional Methodology require any approval (e.g. ERO) other than the
Region’s own process? The “exclusions” process indicates that the ERO has the final approval authority to
exclude an item from the BES. Why would the same not apply for including something into the BES based on
the Region’s Methodology?

IRC Standards Review
Committee

Yes

We generally support the concept but we need to assess the criteria for the exception, which have not been
developed. Further, the wording seems to present a circular argument. We suggest the following revised
wording to more clearly convey this criterion:Transmission Elements or Facilities operated at voltages below
100kV that are deemed to be included in the BES as determined by the exception/inclusion process.

Response: The SDT acknowledges that commenters will need to reserve judgment on the exception process, which is being developed by a separate team as a
modification to the Rules of Procedure in an effort parallel with the development of the BES definition.
American Municipal Power

No

on behalf of Teck Metals Ltd.

No

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

on behalf of Teck Metals Ltd.

No

on behalf of Catalyst Paper
Corporation

No

Idaho Power

No

Question 5 Comment

Response: Thank you for your response.
Indeck Energy Services

No

Same Response as Question 1

Utility Services

Yes

See the answer to Question 1.

Response: See Response to Question 1.
Snohomish County PUD

No

Snohomish agrees that certain Elements or Facilities operated at voltages below 100 kV may need to be
classified as part of the BES if engineering studies demonstrate those Elements or Facilities to be necessary
to the reliable operation of the bulk transmission system. We disagree, however, that inclusion of such
facilities should be part of the exemption process. The exemption process should be focused on facilities
operating at voltages above 100 kV that nonetheless are exempt because they are local distribution facilities
or are demonstrated by engineering analysis to be unnecessary for the reliable operation of the
interconnected bulk transmission grid. The inclusion of facilities below 100 kV should be a separate process
in which the RRO is required to demonstrate that the facility has a material impact on the interconnected bulk
transmission system despite its low operating voltage

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of proposed “inclusions” and “exclusions”, and subsequent drafts will
refer to the “exception” process suggested by the Commission in its Order 743. The process for such inclusions and exclusions will be developed as part of the
revision to the Rules of Procedure by a separate team, in an effort parallel to the development of the BES definition. The SDT appreciates the preference of
several entities to utilize strict bright-line criteria of facilities greater than 100kV that would be considered for inclusion in the BES. The SDT has carefully
considered this matter, and believes that the exception process must allow for the possibility that certain Facilities operated at voltages below 100kV could have
appreciable influence over the reliable operation of the interconnected network Transmission grid, thereby warranting examination through an exception process
for inclusion in the BES. The SDT expects that these exceptions for Facilities operated at voltages below 100kV will be relatively rare.
Lewis County PUD

March 30, 3011

No

Including elements through an exemption process is bound to create confusion and misunderstandings
between the registrants and REs. Please include such elements through an inclusion process. It should also
be clarified that registrants are not required to put all sub-100 kV elements through this process; the burden of

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment
proof should be on the RE to include elements less than 100kV.

PNGC Power

No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric

No

March 30, 3011

Including elements through an exemption process is bound to create confusion and misunderstandings
between the registrants and REs. Please include such elements through an inclusion process. It should also
be clarified that registrants are not required to put all sub-100kV elements through this process; the burden
should be on the RE to include elements of particular concern.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment

Cooperative
Lincoln Electric Cooperative

No

Fall River Electric Cooperative

No

Central Lincoln

No

PUD No.1 of Clallam County

No

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743. The process for such inclusions will be developed by a separate team through the revision to
the Rules of Procedure, in an effort parallel to the development of the BES definition.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

No

Although Constellation believes that it may be appropriate to include some of the elements above in the BES,
this proposal will lead to the inclusion of elements or facilities which have no material impact on the
interconnected transmission system. Furthermore, the use of an exemption process to include assets is
confusing. Constellation proposes that the BES drafting team structure the revised BES definition to clarify
both the inclusions and exclusions as completely as possible. If a separate “opt-in” process is deemed
necessary (in anticipation of a few exceptions to the definition) then the drafting team should develop criteria
for such a process.Using this approach the sentence above would then read “Transmission Elements or
Facilities operated at voltages below 100kV where a Regional Entity deems the Element or Facility to be
included in the BES.”

Response: The SDT appreciates the preference of several entities to utilize strict bright-line criteria of Facilities at 100kV or above that would be considered for
inclusion in the BES. The SDT has carefully considered this matter, and believes that the exception process must allow for the possibility that certain Facilities
operated at voltages below 100kV could have appreciable influence over the reliable operation of the interconnected network Transmission grid, thereby
warranting examination through an exception process for inclusion in the BES. The SDT expects that these exceptions for Facilities operated at voltages below
100kV will be relatively rare. The criteria for such inclusion will be developed as part of this project and the ROP process will be handled by a separate team
through the revision to the Rules of Procedure, in an effort parallel to the development of the BES definition.
The SDT acknowledges that the term “exemption” is inappropriate in the context of proposed “inclusions” and “exclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment

No

Why would an entity want to include an element in the definition of the BES? If an entity has a 69kV line that
the ERO believes should be part of the BES but the entity does not want it part of the BES who initiates and
pays for the exemption process? Does the ERO have the ability to initiate the process? If the owner of the
Transmission Element or Facility is the only one that can initiate and exemption process and they do not want
to what is the remedy if the line is necessary for bulk electric system reliability?

Springfield Utility Board

Response: The bright-line designation will be developed as part of this project and the ROP process will be handled through the revision to the Rules of
Procedure by a separate team in an effort parallel to the development of the BES definition. Your comments will be forwarded to the Rules of Procedure Team.
National Rural Electric
Cooperative Association
(NRECA)

Without exemption criteria to review, it is too early to explicitly answer this question. However, the concept
appears to be logical as long as it is also paired with the ability of an entity that owns facilities above 100kV to
appeal the inclusion of its facilities as part of the BES. Such an appeal would need to be supported by a
technical justification demonstrating why certain facilities should not be classified as part of the BES.In
addition, it is critical for exemption criteria to be based on operating voltage, not design voltage. Using design
voltage in the criteria would provide a disincentive to build for future expansion. This could have significant
negative impacts on BES reliability.

Response: The process for such inclusions and exclusions will be developed by a separate team as part of the revision to the Rules of Procedure, in an effort
parallel to the development of the BES definition. Your comments will be forwarded to the Rules of Procedure Team.
The Dow Chemical Company

Dow recommends that NERC finalize a basic framework for identifying BES facilities before evaluating
individual facilities or types of facilities. Such a framework is recommended by Dow in response to questions
#11 and #12 below.

Response: See responses to Q11 & 12.
Orange and Rockland Utilities,
Inc.

Refer to the response to Question 13.

Northeast Power Coordinating
Council

Refer to the response to Question 13.

NERC Staff

Yes

Please see additional comments at the end of this document.

Response: See response to Q13.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment

SERC OC Standards Review
Group

Yes

We think the process should be an “exception” rather than an “exemption”.

City of Grand Island

Yes

Exemption process should be termed “exception” process. Exception means not conforming to general rule,
whereas exemption primarily means exclusion. This process will be difficult to develop and administer and is
counter productive to “bright line” philosophy. Thus the bright lines should be at a high level resulting in fewer
challenges. The exception process must consider the impact of a fault or outage of that facilities on the
Adequate Level of Reliability (NERC defined term) of the BES.

American Transmission company

Yes

However, the applicable process should be called an “exception” process, not an “exemption” process that
infers the concept of “exclusion” and further classified as part of the BES given that a fault or an outage on the
Transmission Element or Facility at voltages below 100kV would not maintain an Adequate Level of Reliability
of the BES.

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743. The process for such inclusions will be developed by a separate team through the revision to
the Rules of Procedure, in an effort parallel to the development of the BES definition.
City of Redding

Yes

City of Anaheim

Yes

Public Service Enterprise Group
Company

Yes

Bonneville Power Administration

Yes

Electric Market Policy

Yes

LCRA Transmission Services
Corporation

Yes

March 30, 3011

If the exemption process is based on reliable engineering studies.

No Comment

Dominion conceptually supports an exemption process whereby NERC or the RRO could apply to have an
element included or excluded from the BES definition. Such process recognizes that it may be necessary to
include elements that do not meet the bright line criteria but are necessary for operating an interconnected
transmission network. Such process should be developed through the existing NERC standards development
process and include a robust appeals process for the owner/operator of any element so included or excluded.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 5 Comment

PPL Energy Plus

Yes

LG&E and KU Energy LLC

Yes

Yes, PPL Energy Plus supports an exemption process provided the Exemption process follows FERCs Order
743 paragraph 115: “NERC should develop an exemption process that includes clear, objective, transparent,
and uniformly applicable criteria for exemption of facilities that are not necessary for operating the grid.”

ReliabilityFirst

Yes

It is recommended that the exemption process be defined and criteria setup so that a common approach
across the ERO can be used to include these facilities.

Southern California Edison

Yes

SCE currently reports on transmission elements or facilities operated at voltages below 100kV that are
interconnected with other utilities.

Glacier Electric Cooperative

Yes

Yes - this is assuming that the exemption process is an accurate way to truly determine whether or not a
facility is significant to the grid.

ISO New England Inc.

Yes

United Illuminating Company

Yes

City of Austin dba Austin Energy

Yes

The Dayton Power and Light
Company

Yes

Independent Electricity System
Operator

Yes

Clark Public Utilities

Yes

This answer assumes that an appropriate engineering study is performed to determine that the asset is
necessary for the reliability of the BES.

We generally support the concept but we need to assess the criteria for the exception, which have not been
developed. Further, the wording seems to present a circular argument. We suggest the following revised
wording to more clearly convey this criterion:Transmission Elements or Facilities operated at voltages below
100kV that are deemed to be included in the BES as determined by the exception/inclusion process

Response: The SDT thanks you for your comments.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

6. Should the following be classified as part of the BES?
•

Individual generation resources greater than 20 MVA (gross nameplate rating) directly connected via a step-up
transformer(s) to Facilities operated at voltages below 100kV where the exemption process deems the generation
resources to be included in the BES

Summary Consideration: Most commenters who responded to this question indicated disagreement with the proposal, however there was no
consensus amongst the alternate proposals offered, and the proposals suggesting other thresholds were not supported with any technical
justification. The SDT has reviewed the industry comments on this issue, debated the topic, and come to an agreement that the bright-line
designation for individual generating units is 20 MVA and 100 kV. Any deviations from the bright-line designation would be handled through the
pending Rules of Procedure process. Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including
the generator terminals through the GSU which has a high side voltage of 100 kV or above.

Organization

Yes or No

Question 6 Comment

SERC EC Planning Standards
Subcommittee

No

We prefer a bright-line rule of 100 kV. The exception process should not be used to include facilities operated
at voltages below 100 kV.

Public Service Enterprise Group
Company

No

The intent of the BES definition is to address the reliability of the bulk electric system and associated
elements. The generation connected at less than 100kV should not be classified as BES - it should be
considered to be within the same category as radial connected facilities serving load (which is not included as
part of the BES).

Response: In Order No. 743, the Commission directed NERC to adopt an inclusion process for including in the BES definition Facilities operated at voltages
below 100 kV. The Commission believes that NERC should “consider formalizing the criteria for inclusion of critical facilities operated below 100 kV in developing
the exemption process.” The DBES SDT and NERC Rules of Procedure team are responding to FERC’s directive.
Florida Municipal Power Agency

No

Transmission Access Policy
Study Group

No

See FMPA response to Question 5 above. Generation resources of any size directly connected via a step-up
transformer(s) to transmission operated at voltages below 100 kV should only be classified as part of the BES
if the generation resource is registered pursuant to the Statement of Compliance Registry Criteria or if the
inclusion process, assessing each generation resource on a case-by-case basis based on a uniform set of
criteria, results in a finding that the particular generation resource should be included in the BES. The
standards for registering a generator should be the same as those for including it in the BES.

Response: The SDT agrees with the comment that designation of these generators as BES would occur only if the pending Rules of Procedure process deems
them to be BES, and such a designation would necessarily warrant registration per the terms of the NERC Statement of Compliance Registry Criteria (SCRC).

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 6 Comment

The scope of the SDT does not extend to revisions of the SCRC; however, recommendations for revision of the SCRC may result from the definition development.
PacifiCorp

No

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology. Significant
efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF) over the
course of the past year to identify some initial criteria and methodologies. These efforts are ongoing and
should be supported by the NERC drafting team. For example: Generation units should not be included or
excluded solely based on a their gross nameplate rating and the operating voltage at which they are
connected to transmission facilities. Generation units which are necessary to operate the interconnected
network should be included as part of the regulated BES. Generating units which are not “necessary for the
operation of the interconnected network” should be excluded. A methodology needs to be developed to
determine which generating units may be excluded as part of the regulated BES.

Response: The SDT believes that the criteria enumerated in the current Statement of Compliance Registry Criteria should be the template (or “methodology” as
used in the comment) for defining the bright-line exception criteria in Project 2010-17. The SDT plans to review past efforts of Regional Entities to develop their
own BES definition.
ExxonMobil Research and
Engineering

No

See comments on questions 2 and 3.

No

Individual generation resources less than 50 MVA (gross nameplate rating) directly connected via a step-up
transformer(s) to Facilities operated at voltages below 100 kV do not materially impact the reliability of the
BES and therefore, should not be classified as part of the BES.

Response: See response to Q2 & Q3.
Arizona Public Service Company

Response: The SDT believes that the criteria enumerated in the current Statement of Compliance Registry Criteria should be the template for defining the brightline exception criteria in Project 2010-17. The comment provides no technical justification for departing from existing practices defined by the Statement of
Compliance Registry Criteria.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 6 Comment

No

Some details on the exemption process must be known before accepting this. Who can submit an exemption
(DP, GO, GOP, TO, TOP, RC, etc)? How do interested parties get informed? Can others intervene? Would
the other facilities completing the connection to a BES facility be automatically included?

Pepco Holdings Inc.

Response: The SDT acknowledges that commenters will need to reserve judgment on the pending Rules of Procedure process, which is to be developed in an effort
parallel with this BES definition development. The SDT believes that the criteria enumerated in the current Statement of Compliance Registry Criteria should be the
template for defining the bright-line criteria in Project 2010-17. The SDT will coordinate its efforts with the NERC ROP team developing the Rules of Procedure
process to develop a single coordinated implementation plan that will define the responsibilities of various parties.
American Municipal Power

No

on behalf of Teck Metals Ltd.

No

on behalf of Catalyst Paper
Corporation

No

Idaho Power

No

Clark Public Utilities

No

Response: Thank you for your response.
Indeck Energy Services

No

Same Response as Question 1

No

SCE currently reports on generation resources greater than 20 MVA (gross nameplate rating) directly
connected via a step-up transformer(s) to Facilities operated at voltages above 100kV. SCE does not feel it is
necessary to report on generation below 100kV.

Response: See response to Q1.
Southern California Edison

Response: In Order No. 743, the Commission directed NERC to adopt an inclusion process for including in the BES definition Facilities operated at voltages
below 100 kV. The Commission believes that NERC should “consider formalizing the criteria for inclusion of critical facilities operated below 100 kV in developing
the exemption process.”
Southern California Edison
Company

March 30, 3011

No

In SCE's system, generation resources are used to offset load being served by distribution facilities. This
means that generation does not flow through step-up transformers into the 100kV and above system.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 6 Comment
Therefore, those generation resources which are used to provide power to local load within a distribution
system should not be included as part of the BES. The Exemption Process should not be applied to such
resources.

Response: The SDT believes that such generation resources will be excluded as part of the BES unless the Facilities are otherwise deemed material to the
reliability of the BES by a ROP to the pending Rules of Procedure exception process. In a section in the revised BES definition on Local Distribution Networks, the
SDT is considering the issue of generation resources used to offset Load being served by distribution Facilities.
ISO New England Inc.

No

1. Yes - There are situations as envisioned in the Registry Criteria clause, i.e., “Any generator, regardless of
size, that is material to the reliability of the bulk power system” where reliability would be threatened without
such inclusion. Similarly, cases can be made for materiality to the reliability of the bulk power system for units
< 20 MVA directly connected at 100 kV or greater and for units < 20 MVA connected at any voltage level. The
exemption process developed should account for any and all situations where a generator, or group of
generators, may be deemed material to support a BES function such as riding through an UFLS event. Just
as UFLS Relays have been stated to be material to the reliability of the bulk power system, despite their
location on the lower voltage distribution systems, any size generator at any voltage level may be found,
through an analysis, to have a supporting role in protecting the BES during a postulated system disturbance.
2. No - In general small generators connected at voltages of 100 kV and greater and those larger generators
connected at voltages less than 100 kV do not impact the reliability of the BES and to classify them as BES
and require them to register with NERC and abide by all NERC Reliability Standards would place an undue
burden on the Generator Owners/Operators with little or no perceived reliability benefit. A more reasonable
process would allow a systematic analysis to define the material need of such otherwise exempted generators
and allow these generators to be registered on a “requirement basis”, a process which FERC has
encouraged, and is an approach recognized in NERC’s “Statement of Registry Criteria” (See “Notes to Above
Criteria” #4, page 10).

Electric Market Policy

No

Dominion does not agree that a generation resource should be classified as part of the BES. Dominion
supports the criteria for registering owners, operators, and users of the bulk power system, as indicated in the
current Statement of Compliance Registry Criteria.

Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.

No

Although Constellation believes that it may be appropriate to include some of the elements above in the BES,
this proposal will lead to the inclusion of elements or facilities which have no material impact on the
interconnected transmission system. Furthermore, the use of an exemption process to include assets is
confusing. Constellation proposes that the BES drafting team structure the revised BES definition to clarify
both the inclusions and exclusions as completely as possible. If a separate “opt-in” process is deemed
necessary (in anticipation of a few exceptions to the definition) then the drafting team should develop criteria

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Organization

Yes or No

(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Question 6 Comment
for such a process. Using this approach the sentence above would then read “Individual generation resources
greater than 20 MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Facilities
operated at voltages below 100kV where a Regional Entity deems the generation resources to be included in
the BES.”

Response: The SDT agrees that criteria enumerated in the current Statement of Compliance Registry Criteria should be the template for defining the bright-line
exception criteria in Project 2010-17. FERC Order No. 743 states that changes to the BES definition “will not significantly increase the scope of the present
definition, which applies to transmission, generation and interconnection facilities.”
Snohomish County PUD

No

The NERC GOTO Task Force considered the issue of whether dedicated interconnection facilities connecting
BES generation to the BES transmission system should also be classified as BES. The Task Force
concluded that it is unnecessary to classify such facilities as part of the BES and that reliability would not be
compromised as long as those interconnection facilities are required to comply with few reliability standards,
primarily those related to vegetation management. The standards drafting group should follow the
recommendation of the GOTO Task Force when considering the status of interconnection facilities and should
consider those recommendations when considering related questions such as the status of radial lines that
both interconnect a generator and serve distribution functions.

Response: The SDT acknowledges the work of Project 2010-07 Generator Requirements at the Transmission Interface regarding the classification rationale for
generation interconnection Facilities and has considered it in the development process of the BES definition. The subject of this question was focused upon the
generating elements themselves, rather than the associated interconnection Facilities. The SDT has carefully considered this matter, and believes that the
pending Rules of Procedure exception process must allow for the possibility that certain generating units larger than 20 MVA yet connected below 100kV could
have appreciable influence over the reliable operation of the interconnected network Transmission grid, thereby warranting a submittal through the ROP process
for inclusion in the BES. The SDT expects that these exceptions for generating units larger than 20 MVA, yet connected to the grid at below 100kV, will be
relatively rare. Additionally, the Commission in its Order No. 743 suggests that the revised BES definition should include exception processes for inclusion of
these sorts of Elements. The process for such inclusions will be developed as part of the revision to the Rules of Procedure, in an effort parallel to the
development of this BES definition.
Central Lincoln

No

PUD No.1 of Clallam County

No

PNGC Power

No

March 30, 3011

Including elements through an exemption process is bound to create confusion and misunderstandings
between the registrants and REs. Please include such elements through an inclusion process. It should also
be clarified that registrants are not required to put all sub-100 kV elements through this process; the burden
should be on the RE to include elements of particular concern.

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Organization

Yes or No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric
Cooperative

No

Lincoln Electric Cooperative

No

March 30, 3011

Question 6 Comment

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Organization
Fall River Electric Cooperative

Yes or No

Question 6 Comment

No

Response: The SDT agrees. In Order No. 743, the Commission directed NERC to adopt an inclusion process for including in the BES definition Facilities
operated at voltages below 100 kV. The Commission believes that NERC should “consider formalizing the criteria for inclusion of critical facilities operated below
100 kV in developing the exemption process.”
ITC Holdings Corp

No

The lower limit for BES generators should be 75 MVA. As long as this Plant is connected to the 100 kV or
greater, it should be included. Below 100 kV, only if it meets the critical test.

Response: The SDT believes that criteria enumerated in the current Statement of Compliance Registry Criteria should be the template for defining the bright-line
exception criteria in Project 2010-17. FERC Order No. 743 states that changes to the BES definition “will not significantly increase the scope of the present
definition, which applies to transmission, generation and interconnection facilities.” As envisioned, Regional Entities will be able to request the inclusion of
Elements below 100 kV in the pending Rules of Procedure exception process and will bear the burden of proof that such Elements are critical Facilities.
BGE

No

This proposal as written could lead to the inclusion of elements or facilities which have no material reliability
impact on the interconnected transmission system.

Response: The SDT believes that criteria enumerated in the current Statement of Compliance Registry Criteria should be the template for defining the bright-line
exception criteria in Project 2010-17. In addition, potential registrants may use the pending Rules of Procedure exception process to demonstrate the lack of
materiality.
City Water Light and Power
(CWLP) - Springfield, IL

No

While CWLP agrees with the general concept of inclusion by exception (as opposed to exemption), we have
concerns regarding the lack of detailed definition of this process, especially the administrative process for
disputes regarding inclusion of elements in the BES. Without firm administrative rules for resolving disputes
based on technical justification, we cannot support this measure currently.

Response: NERC is obligated under Order No. 743 to develop an exception process (including revisions to the NERC ROP) and implementation plan to
administer a revised BES definition and associated exception criteria, and a dispute resolution process. The SDT acknowledges that commenters will need to
reserve judgment on the pending Rules of Procedure exception process, which is to be developed in an effort parallel with this BES definition development.
Lewis County PUD

No

I find it hard to believe that elements connected at less than 100kV are part of the BES. The burden of proof
to include elements in the BES should be on the RE not the owner of such facilities.

Response: In Order No. 743, the Commission directed NERC to adopt an inclusion process for including in the BES definition Facilities operated at voltages
below 100 kV. The Commission believes that NERC should “consider formalizing the criteria for inclusion of critical facilities operated below 100 kV in developing
the exemption process.” Thus, as envisioned, Regional Entities will be able to request the inclusion of Elements below 100 kV in the pending Rules of Procedure

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Organization

Yes or No

Question 6 Comment

exception process and will bear the burden of proof that such Elements are critical Facilities.
American Electric Power (AEP)

No

Please see response provided to question 5.

No

We prefer a bright-line rule of 100 kV. The exception process should not be used to include facilities operated
at voltages below 100 kV.

Response: See response to Q5.
Southern Company

Response: The SDT believes that the criteria enumerated in the current Statement of Compliance Registry Criteria should be the template for defining the “brightline” exception criteria in Project 2010-17. In Order No. 743, the Commission also directed NERC to adopt an inclusion process for including in the BES definition
Facilities operated at voltages below 100 kV. The Commission believes that NERC should “consider formalizing the criteria for inclusion of critical facilities
operated below 100 kV in developing the exemption process.” As envisioned, Regional Entities will be able to request the inclusion of Elements below 100 kV in
the pending Rules of Procedure exception process and will bear the burden of proof that such Elements are critical Facilities.
Independent Electricity System
Operator

No

Again, we need to assess the criteria for the exception, which have not been developed.
Also, the proposed wording seems to present a circular argument. We suggest to change the wording as
follows: Individual generation resources greater than 20 MVA (gross nameplate rating) directly connected via
a step-up transformer(s) to Facilities operated at voltages below 100kV that are deemed to be included in the
BES as determined by the exception/inclusion process.

Response: The SDT acknowledges that commenters will need to reserve judgment on the exception process, which is to be developed as a modification to the
Rules of Procedure in an effort parallel with this BES definition development.
The SDT notes the suggested language in this comment, and has considered it in the development of the revised definition of BES.
Springfield Utility Board

No

"directly connected" is important.

Response: The SDT has revised the definition and that term is no longer utilized.
Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the generator terminals through the GSU which
has a high side voltage of 100 kV or above.
Manitoba Hydro
Occidental Energy Ventures Corp

March 30, 3011

Abstain until exemption process has been defined.
No

Until the exemption process is finalized, it is not prudent to answer in the affirmative.

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Organization
Duke Energy

Yes or No

Question 6 Comment
There is not enough information available at this time to adequately evaluate this question. It would be
necessary to have a list of exemption criteria or more detail on the exemption process to address this
question. This is one of the reasons that the exemption criteria should be developed through the standards
development process along with the definition.

Response: The SDT acknowledges that commenters will need to reserve judgment on the pending Rules of Procedure exception process, which is to be
developed in a parallel effort with this BES definition development. Nonetheless, the SDT believes that criteria enumerated in the current Statement of
Compliance Registry Criteria should be the template for defining the bright-line exception criteria in Project 2010-17. The exception criteria (now included in the
revised definition of BES) provides for both inclusions and exclusions. FERC Order No. 743 states that changes to the BES definition “will not significantly
increase the scope of the present definition, which applies to transmission, generation and interconnection facilities.”
Northeast Power Coordinating
Council

Refer to the response to Question 13.

Response: See response to Q13.
Entergy Services

Our response to this question depends on the details of the “exemption process”, including what entity has
the final decision and how it is implemented. Please see our response to Q13 below.

Orange and Rockland Utilities,
Inc.

The purpose of this question is hard to ascertain. The BES exemption process has not yet been finalized or
approved. So, it is somewhat difficult to know a priori whether any individual generation resources greater
than 20 MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Facilities operated at
voltages below 100kV should or should not be classified as part of the BES definition.
This document uses both “exemption process” and “exception process”. Recommend that the phraseology
be standardized on “exception process” as the exception (not the exemption) can be to include or exclude
elements and facilities.
Refer to the response to Question 13.

Response: The SDT acknowledges that commenters will need to reserve judgment on the pending Rules of Procedure exception process, which is to be
developed in an effort parallel with this BES definition development. Nonetheless, the SDT believes that criteria enumerated in the current Statement of
Compliance Registry Criteria should be the template for defining the bright-line exception criteria in Project 2010-17. The exception criteria will provide for both
inclusions and exclusions. FERC Order No. 743 states that changes to the BES definition “will not significantly increase the scope of the present definition, which
applies to transmission, generation and interconnection facilities.”
See response to Q13.

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Organization

Yes or No

Xcel Energy

Question 6 Comment
Xcel Energy does not disagree that there may be situations where generators greater than 20 MVA
individually or 75 MVA in aggregate are connected via step up Transformers below 100 KV that may need to
be included, but we have concerns about the exemption process. This undeveloped process presents itself
as a wild card to entities, and will most likely present inconsistencies between regions based upon each
Region’s preference. Additionally, does the Regional Methodology require any approval (e.g. ERO) other
than the Region’s own process? The “exclusions” process indicates that the ERO has the final approval
authority to exclude an item from the BES. Why would the same not apply for including something into the
BES based on the Region’s Methodology?

Response: The SDT acknowledges that commenters will need to reserve judgment on the pending Rules of Procedure exception process, which is to be
developed in an effort parallel with this BES definition development. Nonetheless, the SDT believes that criteria enumerated in the current Statement of
Compliance Registry Criteria should be the template for defining the bright-line exception criteria in Project 2010-17. The exception criteria will provide for both
inclusions and exclusions. The SDT notes that a stated purpose of Order No. 743 was to eliminate the regional discretion allowed in the existing definition of BES
and remove any ambiguity regarding who is required to comply and accomplish the goal of reducing inconsistencies across regions. As per FERC Order No. 672,
any regional variations must be approved by FERC, and generally must be more “stringent” than NERC criteria. As envisioned, Regional Entities will be able to
question the outcome of bright-line criteria in the BES definition in the pending Rules of Procedure exception process and will bear the burden of proof that such
Elements are critical Facilities or not. FERC Order No. 743 states that changes to the BES definition “will not significantly increase the scope of the present
definition, which applies to transmission, generation and interconnection facilities.”
The Dow Chemical Company

As discussed in response to question #12 below, issues relating to the registry criteria applicable to
generation resources should not be revisited at this time.

Response: See response to Q12.
City of Grand Island

Yes

See comments for items 2 and 5.

Yes

Please see additional comments at the end of this document.

PPL Energy Plus

Yes

LG&E and KU Energy LLC

Yes

Yes, PPL Energy Plus supports an exemption process provided the Exemption process follows FERCs Order
743 paragraph 115: “NERC should develop an exemption process that includes clear, objective, transparent,
and uniformly applicable criteria for exemption of facilities that are not necessary for operating the grid.” As
written, however, the 20 MVA threshold does not appear to have been developed per FERC’s requirements

Response: See response to Q2 & Q5.
NERC Staff
Response: See response to Q13.

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Organization

Yes or No

Question 6 Comment
for the reasons discussed in the response to Questions 2 and 8.

Response: The SDT is committed to drafting a BES definition and exception criteria that will enable the pending Rules of Procedure exception process “that
includes clear, objective, transparent, and uniformly applicable criteria for exemption of facilities that are not necessary for operating the grid.” The SDT believes
that the criteria enumerated in the current Statement of Compliance Registry Criteria should be the template for defining the bright-line exception criteria in Project
2010-17.
Utility Services

Yes

See the answer to Question 1.

Yes

However, the applicable process should be called an “exception” process, not an “exemption” process that
infers the concept of “exclusion” and further classified as part of the BES given that a fault or an outage on
individual generation resources greater than 20MVA would not maintain an Adequate Level of Reliability of
the BES.

Response: See response to Q1.
American Transmission company

Response: The SDT has adopted the use of the terms “exception criteria” and “exception process.”
SERC OC Standards Review
Group

Yes

We think the process should be an “exception” rather than an “exemption”. This question seems illogical
since the last part of the question assumes the generator is already part of the BES through the determination
of the exemption process. If the question was actually generators less than 20 MVA, we don’t agree.

Response: The SDT has adopted the use of the terms “exception criteria” and “exception process.” The SDT believes that the criteria enumerated in the current
Statement of Compliance Registry Criteria should be the template for defining the bright-line exception criteria in Project 2010-17.
IRC Standards Review
Committee

Yes

Again, we need to assess the criteria for the exception, which have not been developed.
Also, the proposed wording seems to present a circular argument. We suggest to change the wording as
follows: Individual generation resources greater than 20 MVA (gross nameplate rating) directly connected via
a step-up transformer(s) to Facilities operated at voltages below 100kV that are deemed to be included in the
BES as determined by the exception/inclusion process.

Response: The SDT acknowledges that commenters will need to reserve judgment on the pending Rules of Procedure exception process, which is to be
developed in an effort parallel with this BES definition development.
The SDT notes the suggested language in this comment, and has considered it in the development of the revised definition of BES., Included in the BES: I2
- Individual generating units greater than 20 MVA (gross nameplate rating) including the generator terminals through the GSU which has a high side voltage

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Organization

Yes or No

Question 6 Comment

Yes

FERC has directed (in section 30 of FERC Order 743) that NERC have an established “exemption” process to
remove this judgment from the Regions in defining what the BES is. However, the applicable process should
be called an “exception” process, not an “exemption” process that infers the concept of “exclusion” and further
classified as part of the BES given that a fault or an outage on individual generation resources greater than
20MVA would not maintain an Adequate Level of Reliability of the BES.

of 100 kV or above.
MRO's NERC Standards Review
Subcommittee

Response: The SDT has adopted the use of the terms “exception criteria” and “exception process” in its work. Note, however, that neither term is used in the
proposed definition of BES.
City of Redding

Yes

City of Anaheim

Yes

Bonneville Power Administration

Yes

LCRA Transmission Services
Corporation

Yes

North Carolina EMC

Yes

ReliabilityFirst

Yes

It is recommended that the exemption process be defined and criteria setup so that a common approach
across the ERO can be used to include these facilities.

Glacier Electric Cooperative

Yes

Yes - Once again, this is assuming that the exemption process is an accurate way to truly determine whether
or not a facility is significant to the grid.

United Illuminating Company

Yes

Any Generator directly connected via a step-up transformer(s) to Facilities operated at voltages below 100kV
where the exemption process deems the generation resources to be included in the BES should be part of
BES . There should not be a MVA threshold

City of Austin dba Austin Energy

Yes

This answer assumes that an appropriate engineering study is performed to determine that the asset is
necessary for the reliability of the BES.

March 30, 3011

If the exemption process is based on engineering studies targeted to identify those facilities necessary to
reliably operate the interconnected transmission system.

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Organization
The Dayton Power and Light
Company

Yes or No

Question 6 Comment

Yes

Response: Thank you for your response. This criterion was not changed, but is now embedded in the revised definition of BES.

March 30, 3011

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7. Should the following be classified as part of the BES?
•

Generation plants with aggregate capacity greater than 75 MVA (gross nameplate rating) directly connected via a step-up
transformer(s) to Facilities operated at voltages below 100kV where the exemption process deems the generation plants
to be included in the BES

Summary Consideration: Most commenters who responded to this question indicated disagreement with the proposal however there was no
consensus amongst the alternate proposals offered, and the proposals suggesting other thresholds were not supported with any technical
justification. The SDT has reviewed the industry comments on this issue, debated the topic, and come to an agreement that the bright-line
designation for multiple generating units is 75 MVA and 100 kV as shown below. Any deviations from the bright-line designation would be handled
through the Rules of Procedure process.
Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating) including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
Several comments indicated that local distribution networks should be excluded, and the drafting team adopted this suggestion and added the
following to the list of “Exclusions” from the 100 kV threshold that are included in the revised definition of BES.
Excluded from the BES: E3 - Local distribution networks (LDN): Groups of Elements operated above 100 kV that distribute power to Load rather
than transfer bulk power across the Interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one location
solely to improve the level of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;
b) Limits on connected generation: The LDN, nor its underlying Elements, includes no more than a total of 75 MVA generation;
c) Power flows only into the Local Distribution Network: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or Transfer Path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored
Facility in the Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

Organization
SERC EC Planning Standards
Subcommittee

March 30, 3011

Yes or No

Question 7 Comment

No

We prefer a bright-line rule of 100 kV. The exception process should not be used to include facilities operated
at voltages below 100 kV.

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Organization

Yes or No

BGE

No

Question 7 Comment
This proposal as written could lead to the inclusion of elements or facilities which have no material reliability
impact on the interconnected transmission system.

Response: The SDT has reviewed the industry comments on this issue, debated the topic, and come to an agreement that the bright-line designation for multiple
generating units is 75 MVA and 100 kV. Any deviations from the bright-line designation will be handled through the Rules of Procedure process. The process
for such inclusions will be developed as part of the revision to the Rules of Procedure by another team, in an effort parallel to the development of this BES
definition.
IRC Standards Review
Committee

No

Same comment as in Q6, above.

Public Service Enterprise Group
Company

No

See the response to item 6 above.

Snohomish County PUD

No

See response to question 6

Independent Electricity System
Operator

No

Same comment as in Q6, above.

Florida Municipal Power Agency

No

See FMPA responses to Questions 5 and 6 above.

Transmission Access Policy
Study Group

No

Response: See response to Q6.

Response: See responses to Q5 & Q6.
Electric Market Policy

No

Dominion does not agree that generation plants should be classified as part of the BES.

Response: The SDT finds no basis for the exclusion of generation plants from the BES, and continues to believe that generation is an integral part of the BES
which any core BES definition must necessarily include.
PacifiCorp

March 30, 3011

No

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.

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Organization

Yes or No

Question 7 Comment
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology.
Significant efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF)
over the course of the past year to identify some initial criteria and methodologies. These efforts are ongoing
and should be supported by the NERC drafting team. For example: Generation plants should not be included
or excluded solely based on a their gross nameplate rating and the operating voltage at which they are
connected to transmission facilities. Generation plants which are necessary to operate the interconnected
network should be included as part of the regulated BES. Generating plants which are not “necessary for the
operation of the interconnected network” should be excluded. A methodology needs to be developed to
determine which generating plants may be excluded as part of the regulated BES.

Response: The SDT acknowledges that commenters will need to reserve judgment on the process, which is to be developed as a modification to the Rules of
Procedure by another team in an effort parallel with this BES definition development.
The SDT acknowledges the work of the WECC BESDTF, and in keeping with the concepts of that work, envisions that the process will identify for inclusion in the
BES only those generators that are necessary to operate the interconnected network.
ExxonMobil Research and
Engineering

No

See comments on questions 2 and 3.

No

Generation plants with aggregate capacity of less than 300 MVA (gross nameplate rating) directly connected
via a step-up transformer(s) to Facilities operated at voltages below 100 kV do not materially impact the
reliability of the BES and therfore, should not be classified as part of the BES.

Response: See responses to Q2 & Q3.
Arizona Public Service Company

Response: The SDT appreciates the suggestion of a 300 MVA threshold for materiality of impact; however, it sees no technical justification upon which to base a
significant departure from the generation MVA thresholds included in the NERC Statement of Compliance Registry Criteria. The SDT has reviewed the industry
comments on this issue, debated the topic, and come to an agreement that the bright-line designation for multiple generating units is 75 MVA and 100 kV. Any
deviations from the bright-line designation will be handled through the Rules of Procedure process. The process for such inclusions will be developed as part of
the revision to the Rules of Procedure by another team, in an effort parallel to the development of this BES definition.

March 30, 3011

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Organization

Yes or No

Question 7 Comment

Pepco Holdings Inc.

No

Some details on the exemption process must be known before accepting this. Who can submit an exemption
(DP, GO, GOP, TO, TOP, RC, etc)? How do interested parties get informed? Can others intervene? Would
the other facilities completing the connection to a BES facility be automatically included?

American Municipal Power

No

on behalf of Teck Metals Ltd.

No

on behalf of Catalyst Paper
Corporation

No

Occidental Energy Ventures
Corp

No

Idaho Power

No

Springfield Utility Board

No

Clark Public Utilities

No

Until the exemption process is finalized, it is not prudent to answer in the affirmative.

Response: The SDT acknowledges that commenters may need to reserve judgment on the exception process, which is to be developed as a modification to the
Rules of Procedure in an effort parallel with this BES definition development.
North Carolina EMC

No

Generation facilities operated at voltages below 100kV should only be included in the BES if identified by the
RRO as critical to the BES.

Response: The SDT envisions that the exception process that would be used to possibly include such Facilities will identify for inclusion in the BES only those
generating plants that are essential to the reliable operation of the interconnected system. This process is being developed as a revision to the NERC Rules of
Procedure by another team in an effort parallel to the development of this BES definition.
Indeck Energy Services

No

Same Response as Question 1

Utility Services

Yes

See the answer to Question 1.

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Organization

Yes or No

Question 7 Comment

Response: See response to Q1.
Southern California Edison

No

SCE currently reports on generation plants with aggregate capacity greater than 75 MVA (gross nameplate
rating) directly connected via a step-up transformer(s) to Facilities operated at voltages above 100kV. SCE
does not feel it is necessary to report on generation below 100kV.

Response: While the definition of the BES is a different matter than data reporting for generation plants, the SDT has incorporated a BES designation it believes
will address your concerns.

Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
Southern California Edison
Company

No

In SCE's system, generation resources are used to offset load being served by distribution facilities. This
means that generation does not flow through step-up transformers into the 100kV and above system.
Therefore, those generation resources which are used to provide power to local load within a distribution
system should not be included as part of the BES. The Exemption Process should not be applied to such
resources.

Response: In its latest revision of the BES definition, the SDT has incorporated a designation for local distribution networks (LDN) for exclusion from the BES.
•

Excluded from the BES: E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV that distribute power to Load rather than
transfer bulk power across the interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to improve
the level of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting
devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the Quebec Interconnection, and
is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

ISO New England Inc.

March 30, 3011

No

See the comments provided in response to question 7.

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Organization

Yes or No

Question 7 Comment

Response: This is Q7. The SDT assumes that this is a typo and should have referred to a different question.
PUD No.1 of Clallam County

No

Central Lincoln

No

PNGC Power

No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

March 30, 3011

Including elements through an exemption process is bound to create confusion and misunderstandings
between the registrants and REs. Please include such elements through an inclusion process. It should also
be clarified that registrants are not required to put all sub-100 kV elements through this process; the burden
should be on the RE to include elements of particular concern.

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Organization

Yes or No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

West Oregon Electric
Cooperative

No

Lincoln Electric Cooperative

No

Fall River Electric Cooperative

No

Question 7 Comment

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743. The process for such inclusions will be developed as part of the revision to the Rules of
Procedure by another team in an effort parallel to the development of this BES definition.
ITC Holdings Corp

No

Only included if the plant is deemed Critical by the PRC023 test.

Response: The SDT is aware of the test proposed under PRC-023, however, in this definition, the SDT is striving to develop “bright-line” characteristic criteria
that will be used to make definitional inclusions and exclusions, and this will be paired with an “exception process” which will be developed as part of the revision
to the Rules of Procedure by another team in an effort parallel to the development of this BES definition. The SDT will forward the suggestion of a “PRC-023 test”
to the team tasked with development of the revision to the Rules of Procedure.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

No

Although Constellation believes that it may be appropriate to include some of the elements above in the BES,
this proposal will lead to the inclusion of elements or facilities which have no material impact on the
interconnected transmission system.
Furthermore, the use of an exemption process to include assets is confusing. Constellation proposes that the
BES drafting team structure the revised BES definition to clarify both the inclusions and exclusions as
completely as possible. If a separate “opt-in” process is deemed necessary (in anticipation of a few
exceptions to the definition) then the drafting team should develop criteria for such a process. Using this
approach the sentence above would then read “Generation plants with aggregate capacity greater than 75
MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Facilities operated at
voltages below 100kV where a Regional Entity deems the generation plants to be included in the BES.”

Response: The SDT has reviewed the industry comments on this issue, debated the topic, and come to an agreement that the bright line designation for multiple

March 30, 3011

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Organization

Yes or No

Question 7 Comment

generating units is 75 MVA and 100 kV. Any deviations from the bright line designation will be handled through the Rules of Procedure process. The SDT is
striving to develop “bright-line” characteristic criteria that will be used to make definitional inclusions and exclusions, and this will be paired with the “exception
process” which will be developed as part of the revision to the Rules of Procedure by another team in an effort parallel to the development of this BES definition.
The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the “exception”
process suggested by the Commission in its Order 743. The process for such inclusions will be developed as part of the revision to the Rules of Procedure by
another team in an effort parallel to the development of this BES definition.
City Water Light and Power
(CWLP) - Springfield, IL

No

While CWLP agrees with the general concept of inclusion by exception (as opposed to exemption), we have
concerns regarding the lack of detailed definition of this process, especially the administrative process for
disputes regarding inclusion of elements in the BES.
Without firm administrative rules for resolving disputes based on technical justification, we cannot support this
measure currently.

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743. The SDT is striving to develop “bright-line” characteristic criteria that will be used to make
definitional inclusions and exclusions as part of the revised definition of BES. The SDT acknowledges that commenters may need to reserve judgment on the
process until more clarity is provided via the development of the revision to the Rules of Procedure.
Lewis County PUD

No

I find it hard to believe that elements connected at less than 100kV are part of the BES.
The burden of proof to include elements in the BES should be on the RE not the owner of such facilities.

Southern Company

No

We prefer a bright-line rule of 100 kV.
The exception process should not be used to include facilities operated at voltages below 100 kV.

Response: The SDT agrees that the bright-line designation for multiple generating units is 75 MVA and 100 kV. Any deviations from the bright-line designations
identified in the final BES definition will be handled through the Rules of Procedure process. (The SDT is striving to develop “bright-line” characteristic criteria that
will be used to make definitional inclusions and exclusions as part of the revised definition of BES. ) The process for approving such inclusions will be developed
as part of the revision to the Rules of Procedure by another team in an effort parallel to the development of this BES definition.
American Electric Power (AEP)

No

Please see response provided to question 5.

Response: See response to Q5.
Orange and Rockland Utilities,

March 30, 3011

The purpose of this question is hard to ascertain. The BES exemption process has not yet been finalized or
approved. So, it is somewhat difficult to know a priori whether any generation plants with aggregate capacity

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Organization
Inc.

Yes or No

Question 7 Comment
greater than 75MVA (gross nameplate rating) directly connected via a step-up transformer(s) to Facilities
operated at voltages below 100kV should or should not be classified as part of the BES definition. This
document uses both “exemption process” and “exception process”. Recommend that the phraseology be
standardized on “exception process” as the exception (not the exemption) can be to include or exclude
elements and facilities. Refer to the response to Question 13.

Response: The SDT acknowledges that commenters may need to reserve judgment on the exception process until more clarity is provided via the development of
the revision to the Rules of Procedure.
The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the “exception”
process suggested by the Commission in its Order 743. Any deviations from the bright-line designations identified in the final BES definition will be handled
through the Rules of Procedure process. (The SDT is striving to develop “bright-line” characteristic criteria that will be used to make definitional inclusions and
exclusions as part of the revised definition of BES.)
Also, see response to Q13.
The Dow Chemical Company

As discussed in response to question #12 below, issues relating to the registry criteria applicable to
generation resources should not be revisited at this time.

Response: See response to Q12.
Manitoba Hydro

Abstain until exemption process has been defined.

Duke Energy

There is not enough information available at this time to adequately evaluate this question. It would be
necessary to have a list of exemption criteria or more detail on the exemption process to address this
question. This is one of the reasons that the exemption criteria should be developed through the standards
development process along with the definition.

Response: Thank you for your response. The revised definition of BES includes both a “bright-line” characteristic and a list of criteria that will be used to make
definitional inclusions and exclusions to that bright line,
Entergy Services

Our response to this question depends on the details of the “exemption process”, including what entity has
the final decision and how it is implemented. Please see our response to Q13 below.

Northeast Power Coordinating
Council

Refer to the response to Question 13.

March 30, 3011

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Organization

Yes or No

NERC Staff

Yes

Question 7 Comment
Please see additional comments at the end of this document.

Response: See response to Q13.
Xcel Energy

Xcel Energy does not disagree that there may be situations where generators greater than 20 MVA
individually or 75 MVA in aggregate are connected via step up Transformers below 100 KV that may need to
be included, but we have concerns about the exemption process. This undeveloped process presents itself
as a wild card to entities, and will most likely present inconsistencies between regions based upon each
Region’s preference. Additionally, does the Regional Methodology require any approval (e.g. ERO) other
than the Region’s own process? The “exclusions” process indicates that the ERO has the final approval
authority to exclude an item from the BES. Why would the same not apply for including something into the
BES based on the Region’s Methodology?

Response: A separate Rules of Procedure (ROP) team is undertaking to develop a process for Facilities that do not fit within the bright-line definition. The details
of the process are still under discussion and development. However, the SDT expects that ERO will have an oversight role on the Regional Process.
ReliabilityFirst

Yes

It is recommended that the exemption process and the term “directly connected” be defined and criteria setup
so that a common approach for including plants of this size be used across the ERO for reviewing these
facilities and making this determination.

Response: The SDT believes that the phrase “directly connected” has been addressed in the latest revision. The SDT replaced this term with more descriptive
language.

Included in BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
City of Grand Island

Yes

See comments for items 3 and 5.

PPL Energy Plus

Yes

LG&E and KU Energy LLC

Yes

Yes, PPL Energy Plus supports an exemption process provided the Exemption process follows FERCs Order
743 paragraph 115: “NERC should develop an exemption process that includes clear, objective, transparent,
and uniformly applicable criteria for exemption of facilities that are not necessary for operating the grid.” As
written, however, the 75 MVA does not appear to have been developed per FERC’s requirements for the
reasons discussed in the response to Questions 2 and 8.

Response: See responses to Q3 & Q5.

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Organization

Yes or No

Question 7 Comment

Response: The exception process will be developed as part of the revision to the Rules of Procedure by another team in an effort parallel to the development of
this BES definition.
Also, see response to Questions 2 and 8.
SERC OC Standards Review
Group

Yes

We think the process should be an “exception” rather than an “exemption”. This question seems illogical
since the last part of the question assumes the generation plant is already part of the BES through the
determination of the exemption process If the question was actually generation plants less than75 MVA, we
don’t agree.

American Transmission
company

Yes

The applicable process should be called an “exception” process, not an “exemption” process that infers the
concept of “exclusion” and further classified as part of the BES given that a fault or an outage on the
generation resource with aggregate capacity greater than 75 MVA would not maintain an Adequate Level of
Reliability of the BES.

MRO's NERC Standards Review
Subcommittee

Yes

However, the applicable process should be called an “exception” process, not an “exemption” process that
infers the concept of “exclusion” and further classified as part of the BES given that a fault or an outage on the
generation resource with aggregate capacity greater than 75 MVA would not maintain an Adequate Level of
Reliability of the BES.

Response: The SDT acknowledges that the term “exemption” is inappropriate in the context of these proposed “inclusions”, and subsequent drafts will refer to the
“exception” process suggested by the Commission in its Order 743. The process for such inclusions will be developed as part of the revision to the Rules of
Procedure by another team in an effort parallel to the development of this BES definition.
City of Redding

Yes

See question 6 comments

Response: See response to Q6.
City of Anaheim

Yes

Bonneville Power Administration

Yes

LCRA Transmission Services
Corporation

Yes

March 30, 3011

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Organization

Yes or No

Question 7 Comment

Glacier Electric Cooperative

Yes

Yes - Once again, this is assuming that the exemption process is an accurate way to truly determine whether
or not a facility is significant to the grid.

United Illuminating Company

Yes

Generation Plants directly connected via a step-up transformer(s) to Facilities operated at voltages below
100kV where the exemption process deems the generation resources to be included in the BES should be
part of BES . There should not be a MVA threshold

City of Austin dba Austin Energy

Yes

This answer assumes that an appropriate engineering study is performed to determine that the asset is
necessary for the reliability of the BES.

The Dayton Power and Light
Company

Yes

Response: Thank you for your response.

March 30, 3011

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8. Should the following be excluded from the Elements and Facilities classified as part of the BES?
•

Any radial Transmission Element or System, connected from one Transmission source to a Load-serving Element and/or
generation resources not included in items 2, 3, 4, 6, and 7 above are excluded from the BES

Summary Consideration: Most commenters who responded to this question indicated agreement with the proposal. The SDT agrees with the
majority of industry comments and has developed “bright-line” exclusions for designated radial systems (only serving Load and designated
generation resources) as part of the revised BES definition in the NERC Glossary without going through the exception process being developed
separately as part of the revision to the Rules of Procedure by another team in an effort parallel to the development of this BES definition.
The revised definition includes a list of “Inclusions” and “Exclusions” from the 100 kV threshold and no longer references any ‘exemption process’.
Based on stakeholder comments, the following “Exclusions,” relative to radial systems, has been added to the revised definition of BES:
•

Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an
automatic interruption device and:
d) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow
for reliable system reconfiguration to maintain continuity of electrical service. Or,
e) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
f) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in
Inclusions I2, I3, I4 and I5.

Based on stakeholder comments, the following “Exclusions,” relative to local distribution networks, has been added to the revised definition of
BES:
•

Excluded from the BES: E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV that distribute power to Load
rather than transfer bulk power across the interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than
one location solely to improve the level of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic
fault-interrupting devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable
monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating
Limit (IROL).

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Organization

Yes or No

Question 8 Comment

Electric Market Policy

No

Dominion supports bright line exclusions of radial lines regardless of their kV rating. Radial lines to/from
solely generation facilities and radial lines to/from load are comparable in terms of their impact on an
interconnected transmission network. There are situations where these radials make a meaningful and
required contribution to the operation of an interconnected transmission network and there are other
locations/situations where these radials do not. Therefore, radial lines should only be specifically included in
the definition of BES after the RRO has demonstrated that inclusion of the radial is necessary to operate an
interconnected transmission network and the owner/operator of the radial line has had the opportunity to
exercise its aforementioned appeal rights.

Independent Electricity System
Operator

Yes

Classification of all radial facilities operated at voltages of 100 kV and above as part of the BES by default
would be unnecessary and administratively inefficient, and could potentially lead to delays in the review and
approval of other exemption requests. As such, the proposed definitions should be revised to clearly define
what radial Transmission Elements will not be included as part of the BES. This would be consistent with
FERC’s intention expressed in Paragraph 55 of Order 743 to not alter the part of the approved definition that
deals with “radial transmission facilities serving only load”. Additionally, to ensure a common understanding
of the meaning of “radial” and to promote consistency in its application, we believe “radial” should be defined
after seeking stakeholder input and added to the NERC Glossary.

MRO's NERC Standards Review
Subcommittee

Yes

However, the NSRS agrees that a radial transmission element or system directly connected from one
Transmission source to a Load-serving Element and/or generation resources are excluded as part of the BES
given that a fault or an outage of the radial transmission element or system would not impact the Adequate
Level of Reliability of the BES.

SERC EC Planning Standards
Subcommittee

Yes

The definition should clearly state that these elements are excluded. It currently implies that the exception
process would have to be applied to exclude radial elements.

Florida Municipal Power Agency

Yes

Transmission Access Policy
Study Group

Yes

Radial Transmission Elements connected from one Transmission source to a Load-serving Element and/or
generation resources not included in items 2, 3, 4, 6, and 7 above should be excluded from the BES. It is
very important that the exclusion of radial transmission serving only load with one transmission source be
recognized as a categorical exclusion from the BES definition, not merely as grounds for requesting an
exemption. In that way, such radials do not have to go through an exemption process, but are treated the
same as sub-100 kV Transmission, as they are today. In other words, such Elements could be included in
the BES only if a case-by-case assessment pursuant to the inclusion process demonstrates that a particular
radial Element is necessary for operating the interconnected electric transmission network. If every such
Element instead had to go through a case-by-case exemption process in order to be exempted from the BES,
there would be a staggering burden on small entities and on NERC to process exemption requests for all of

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Organization

Yes or No

Question 8 Comment
the radials serving only load with one transmission source that are excluded from the BES under the current
definition. Order 743 does not require NERC to impose any new burdens on entities who own radials serving
only load that are currently excluded from the BES.FMPA supports adding to the current exclusion a
specification that “A radial Transmission Element may be considered as ‘serving only load’ for purposes of the
foregoing general exclusion even if it connects generation, so long as that generation is not registered
pursuant to the Statement of Compliance Registry Criteria.” We believe that this formulation captures the
generation intended in this Question’s reference to “generation resources not included in items 2, 3, 4, 6, and
7 above.” The FERC-approved Compliance Registry Criteria recognize that a small generator, so long as it is
not a “blackstart unit material to and designated as part of a transmission operator entity’s restoration plan,” is
not material to the reliability of the BES. It follows, therefore, that if a radial line would not be included in the
BES but for the presence of this inconsequential generation, the presence of such non-registered generation
does not cause the line to become necessary for operating an interconnected electric transmission system.
For example, rooftop photovoltaic cells are now common enough that allowing their presence to prevent a
radial from being excluded would render the exclusion of radials to load meaningless. Of course, the
application of the definition of the BES is dynamic. For example, in considering whether new generation
connected by what had previously been a radial to load should be registered, NERC may also reevaluate the
exclusion of the radial.There is no basis for differentiating between radials serving only load, and radials
serving load with insignificant generation. Neither is necessary for operating an interconnected electric
transmission network, and so both should be excluded from the BES absent a specific demonstration as to
the materiality of a particular radial.Finally, it may be appropriate for Registered Entities to have the option of
submitting to NERC an informational filing listing their excluded radials. Whether or not a Registered Entity
submits such an informational filing to NERC, a Registered Entity’s claimed exclusion of a radial serving only
load and/or unregistered generation should apply unless and until the radial is added to the BES through the
inclusion process (see FMPA comments on BES exemption process submitted today).

SERC OC Standards Review
Group

Yes

Southern Company

Yes

We assume the question was meant to read: Any radial Transmission Element or System, connected from
one Transmission source to a Load-serving Element and/or generation resources not included in items 2, 3,
4, 6 and 7 above. Any ac transmission Facility composed of Transmission Line(s), substation Facilities, and
transformers that is connected to BES ac Transmission Facilities at only one point by automatic interruption
devices (e.g., circuit breaker or fuse), and is not capable of being switched so as to be simultaneously
connected to BES ac transmission Facilities at a second point, should be considered an “excluded radial
transmission Facility.”

Response: The SDT agrees and has developed “bright-line” exclusions for designated radial systems (only serving Load and designated generation resources) as
part of the revised BES definition in the NERC Glossary without going through the exemption process being developed separately as part of the revision to the
Rules of Procedure by another team in an effort parallel to the development of this BES definition.

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Organization

Yes or No

Question 8 Comment

Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic
interruption device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.
Any deviations from the bright-line designation would be handled through the Rules of Procedure process.
PPL Energy Plus

No

LG&E and KU Energy LLC

No

a) By not allowing exclusion of the generators listed under Items 2,3,4,6,&7, this exclusion is really a blanket
inclusion of all generators over 20MVA. This blanket inclusion is discriminatory because it does not take into
consideration FERC’s orders in Order 743 paragraph 38 that states it is the parallel nature of the lines (and
generator lead lines are not parallel to the Interconnected Network) that justify their inclusion in the BES, NOT
the radial nature of their service. The blanket inclusion of items 2,3,4,6&7 also does not appear to account for
FERC Order 743 in paragraph 120 that encourages exclusion of radial facilities.
b)Further, for the reasons provided in brackets beside the quoted text below, the stated exemption (which is
really a blanket inclusion of items 2,3,4,6&7) appears to ignore FERC Order 743 paragraph 73 which
recognizes that Network Transmission Facilities with specific characteristics should be included in the BES
and most generator lead lines fail to meet the criteria laid out by FERC:
i.most 100 kV lines are parallel to other HV/EHV lines and are significantly loaded by failure of the HV/EHV
lines. [this is not the case with 20 MVA generators]
ii.connect “significant” generation. [less than 200 MVA is generally not significant to the BES]
iii.may be part of a defined transfer path or flowgate. [rarely if ever for a generator]
iv.are capable of causing or contributing to major disturbances. [rarely if ever will this apply to a generator
since an N-1 will take out most generators and the reliability of the Interconnected Network is rarely affected
by an N-1.]

PacifiCorp

March 30, 3011

No

In Order No. 743, the Commission stated that it believes that the best way to address their concerns is to
eliminate the Regional Entities’ discretion to define “bulk electric system” without ERO or Commission review,
maintain a bright-line threshold that includes all facilities operated at or above 100 kV except defined radial
facilities, and adopt an exemption process and criteria for excluding facilities that are not necessary to operate
an interconnected electric transmission network. PacifiCorp believes that the correct interpretation of this

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Organization

Yes or No

Question 8 Comment
sentence is that certain defined radial facilities may be excluded from the definition of BES without going
through the exemption process. The Commission, in paragraph 119 of Order No. 743, does state that the
ERO “could track exemptions for radial facilities,” however, PacifiCorp believes that this step is unnecessary
and would be unduly burdensome for both NERC and registered entities. Therefore a clear definition of
excluded radial transmission elements must be developed and should be defined in the NERC Glossary or in
the BES definition itself.

Springfield Utility Board

No

This question is unclear. There is no NERC definition of "radial" or "Radial". Does this mean transmission
systems normally operated radially but that could be operated in such a way that the system was not radial
that are owned by an LSE/DP and not a TOP/TO (for example) or transmission system?
If radial includes systems "normally operated radial" then "Yes".

Lewis County PUD

No

We note that “radial” and “one Transmission source” are not presently defined. Any radial Transmission
Element or System, connected from one Transmission source to a Load-serving Element and/or generation
resources less than 150MVA should be excluded from the BES.We object to requiring such elements to go
through an exemption process to become excluded.

Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Yes

Constellation believes that the BES definition should incorporate exclusions where possible to eliminate the
need for going through an exclusion process for common facilities that should not be classified as BES.

FirstEnergy Corp

Yes

Needs to be directly identified in the BES definition and not subject to the exemption process.

Response: The SDT agrees and has developed “bright-line” exclusions for designated radial systems (only serving Load and designated generation resources) as
part of the revised BES definition in the NERC Glossary without going through the exception process being developed separately as part of the revision to the
Rules of Procedure by another team in an effort parallel to the development of this BES definition.

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Organization

Yes or No

Question 8 Comment

Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5.
United Illuminating Company

No

Generator Resources should not be excluded.
Load connected by a single radial line can be excluded.

Response: The current Compliance Registry Criteria already excludes certain generator resources from registration. The SDT agrees with this concept and is
continuing that line of thought in the revised definition.
The SDT agrees.
ITC Holdings Corp
National Rural Electric
Cooperative Association
(NRECA)

No
Without explicit exemption criteria to review, it is too early to answer this question. Final exemption criteria
must provide for consistency across all Regional Entities when determining the inclusion or exclusion of radial
facilities as part of the BES. All exemption criteria must be explicit and unambiguous in order to provide as
much certainty as possible. Work done by the Regional Entities on exemption criteria should be reviewed to
determine is usefulness to the SDT.The SDT should consider that load-serving radial transmission lines of
any voltage should be excluded from the BES, especially since these lines are localized and do not affect the
integrity of the BES, i.e., load flow, power flow and short circuit studies.The SDT must also pay particular
attention to the PRC standards and it applicability to radial facilities.

Response: Thank you for your response.
The Dow Chemical Company

Dow recommends that NERC finalize a basic framework for identifying BES facilities before evaluating
individual facilities or types of facilities. Such a framework is recommended by Dow in response to questions
#11 and #12 below.

Response: See responses to Q11 & 12.

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Organization

Yes or No

Question 8 Comment

Central Lincoln

Yes

PUD No.1 of Clallam County

Yes

PNGC Power

Yes

We note, however, that “radial” and “one Transmission source” are not presently defined and are not treated
the same way by the various REs. Please define “radial” in terms of a normal operating mode and clarify that
“one Transmission source” may branch out to have multiple paths to generation upstream of the radial tap.As
noted elsewhere, we object to requiring such elements to go through an exemption process to become
excluded.

Blachly-Lane Electric Co-op

Yes

Clearwater Power Co.

Yes

Douglas Electric Cooperative

Yes

Central Electric Cooperative, Inc.
(Redmond Oregon)

Yes

Raft River Rural Electric
Cooperative

Yes

Northern Lights Inc.

Yes

Salmon River Electric
Cooperative

Yes

Okanogan Country Electric
Cooperative

Yes

Lost River Electric

Yes

Lane Electric Cooperative

Yes

Coos-Curry Electric Cooperative

Yes

Consumer's Power Inc.

Yes

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Organization

Yes or No

Umatilla Electric Co-op

Yes

West Oregon Electric
Cooperative

Yes

Lincoln Electric Cooperative

Yes

Fall River Electric Cooperative

Yes

Question 8 Comment

Response: The SDT agrees and has developed “bright-line” exclusions for designated radial systems (only serving Load and designated generation resources)
as part of the revised BES definition in the NERC Glossary without going through the exception process being developed separately as part of the revision to the
Rules of Procedure by another team in an effort parallel to the development of this BES definition.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5.
Radial systems will be clearly described in the exclusion designations.
Xcel Energy

Xcel Energy has provided a diagram to Ed Dobrowolski on 1/21/11 that lays out a scenario that should be
considered and worked through as part of the development of the definition and exemptions. As stated in
questions 2 & 3 it is unclear as to how treatment of facilities would occur, especially if there are
multiple/separate owners of each wind farm, even thought they aggregate to a common bus that connects to
the transmission system. Treatment of the bus and breakers between each wind farm and the transformer
also needs to be contemplated and addressed in the definition or exclusion process.

Response: See responses to Q2 & Q3.
Indeck Energy Services

March 30, 3011

Yes

Same Response as Question 1

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Organization

Yes or No

Question 8 Comment

Response: See response to Q1.
NERC Staff

Please see additional comments at the end of this document.

Response: See response to Q13.
ExxonMobil Research and
Engineering

Yes

NERC should follow the model of RFC and provide an appendix that provides examples of what type of radial
feeds are exempted. NERC should also utilize IEEE C37.95: Guide for the Protective Relaying of UtilityConsumer Interconnections Section 4, which details typical interconnection facilities, as a reference when
developing their concept of the BES. Addressing typical interconnection facility configurations will assist the
NERC SDT in developing a clear and concise definition that provides a precise line of demarcation between
elements of the BES and end use customer facilities.

Response: The SDT believes that a bright-line definition such as provided in the latest revision is more useful than examples in appendices.
Pepco Holdings Inc.

Yes

Radial transmission element or system and load-serving elements need to be defined.

Manitoba Hydro

Yes

Radial tranmission elements and systems should be excluded, but a clear NERC definition of radial is
required.

Duke Energy

Yes

Radial Transmission Element or System needs to be more clearly defined.

Response: The SDT believes that with the revisions made to the proposed definition that no other definitions will be required.
Idaho Power

Yes

This should be expanded to transmission elements or systems that source load servering stations.Two
examples are: 1.) The non-radial transmission system serving a metro area load at 138 kV where 230 kV and
higher voltage systems surround the area and provide the bulk electric system transfer, and 2.) The nonradial transmission loops that serve rural area load at 138 kV that are essentially tangential to the bulk electric
transfer path.

Response: The SDT has discussed this at length and has drafted exclusions for local distribution networks that should address these concerns and that will be
available for review and comments.
Excluded from the BES: E1 - Local Distribution Networks (LDN): Groups of Elements operated above 100 kV that distribute power to Load rather than transfer
bulk power across the Interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to improve the level

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Organization

Yes or No

Question 8 Comment

of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored
Facility in the Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

Public Service Enterprise Group
Company

Yes

See the response to item 6 above.

Response: See response to Q6.
Northeast Power Coordinating
Council

Yes

City of Redding

Yes

City of Anaheim

Yes

IRC Standards Review
Committee

Yes

Bonneville Power Administration

Yes

March 30, 3011

However, the NERC GO/TO work should incorporated.
Transmission elements serving radial load, radial distribution systems, or non-GO/GOP generation connected to
such radial lines and excluded from BES; provided, however, to eliminate any reliability gaps, such radial
transmission elements should be classified as "Distribution" equipment subject to DP standards, and the PRC
and vegetation management standards should be made applicable to Distribution Providers and this equipment.
This is consistent with the NERC Reliability Functional Model and is more efficient than requiring TO/TOP
registration for radial transmission facilities that function as Distribution and are not required for the reliable
operation of the BES.

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Organization

Yes or No

Question 8 Comment

Competitive Suppliers

Yes

The consideration and criteria about whether radials should be included as elements of the BES or not, needs
to ensure consistency across the Regional Entities, based upon the future revised BES definition and the
exemption criteria. Much of the consideration from the prior questions is based on generators and their size
as measured by their capacity and connection voltage. While EPSA believes that there are some facilities
that should be included (but not all) the “Yes” response to this question is really dependent on the exemption
criteria developed by the Standard Drafting Team for radial lines. The “bright-line” criteria from earlier
questions are not sufficient to make an assertion about what is necessary for reliability with respect to radial
lines. Criteria about generators and their connections is one piece for ensuring reliability. Further bright-line
criteria need to be determined for load-serving elements on par with the generator criteria relevant for
reliability. The BES definition additionally needs to recognize that load and generation can have similar
affects on the BES because both can affect BES voltage and frequency. As written, the BES definition
appears to apply to generation but not load when in fact the BES sees the difference between load and
generation mainly as the direction of power flow.

Arizona Public Service Company

Yes

LCRA Transmission Services
Corporation

Yes

American Municipal Power

Yes

North Carolina EMC

Yes

Radial facilities meeting the above criteria should be automatically exempted from classification as a part of
the BES and should not be required to go through a separate exemption process.

ReliabilityFirst

Yes

As long the facility is purely radial and could under no circumstance or system topology (i.e. via switching or
re-configuration) trip/lockout a BES facility.

on behalf of Teck Metals Ltd.

Yes

Parallel transmission lines from a single source (substation) to a singe load should be excluded from the BES,
with the consent/request of the owner of the connected load (and/or all customers that constitute the
connected load).

Southern California Edison

Yes

SCE currently does not report on any radial Transmission Element or System, connected from one
Transmission source to a Load-serving Element and/or generation resources not included in items 2, 3, 4, 6,
and 7 and believes the above should be excluded.

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Organization

Yes or No

Question 8 Comment

Southern California Edison
Company

Yes

on behalf of Catalyst Paper
Corporation

Yes

City of Grand Island

Yes

Occidental Energy Ventures Corp

Yes

The existing exclusion for radial lines serving load should be maintained. If clarification of the existing
language concerning radials is required, the exclusion and definition of “radial systems,” including the
explanation of “normal operations,” contained in the BES Concept Document seems to accurately reflect
radials serving load or small generators that should be excluded from the BES. FERC orders directing
change in the BES definition support maintaining this exclusion.

City of Anaheim

Yes

Transmission elements serving radial load, radial distribution systems, or non-GO/GOP generation connected
to such radial lines and excluded from BES; provided, however, to eliminate any reliability gaps, such radial
transmission elements should be classified as "Distribution" equipment subject to DP standards, and the PRC
and vegetation management standards should be made applicable to Distribution Providers and this
equipment. This is consistent with the NERC Reliability Functional Model and is more efficient than requiring
TO/TOP registration for radial transmission facilities that function as Distribution and are not required for the
reliable operation of the BES.

Glacier Electric Cooperative

Yes

I don't think a radial transmission system would ever have a significant impact on the BES, so they should be
excluded.

ISO New England Inc.

Yes

Per FERC Order 743, paragraph 55, the Commission declared, "As we stated in the NOPR, we do not seek to
modify the second part of the definition through this Final Rule, which states that "radial transmission facilities"
serving only load with one transmission source are generally not included in this definition.” ISO-NE maintains
that this definition of radial should be the default position and only in cases where other radial configurations
are to be considered should they be examined as part of any exemption or exclusion methodology that is
developed by NERC in accordance with Order 743.

Entergy Services

Yes

March 30, 3011

Parallel transmission lines from a single source (substation) to a singe load should be excluded from the BES,
with the consent/request of the owner of the connected load (and/or all customers that constitute the
connected load).

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Organization

Yes or No

Snohomish County PUD

Yes

Orange and Rockland Utilities,
Inc.

Yes

American Transmission company

Yes

Utility Services

Yes

City of Austin dba Austin Energy

Yes

The Dayton Power and Light
Company

Yes

BGE

Yes

City Water Light and Power
(CWLP) - Springfield, IL

Yes

American Electric Power (AEP)

Yes

Clark Public Utilities

Yes

Question 8 Comment
FERC Order No. 743 is clear that FERC did not intend to disturb the existing exemption for radial facilities.
Accordingly, radial systems should be excluded from the BES. This should not change if the radial system is
used to interconnect a BES generator for reasons set forth in the GOTO Task Force report.

ATC agrees that a radial transmission element or system directly connected from one Transmission source to
a Load-serving Element and/or generation resources are excluded as part of the BES given that a fault or an
outage of the radial transmission element or system would not maintain an Adequate Level of Reliability of the
BES.

BGE believes that the BES definition should incorporate exclusions where possible to eliminate the need for
going through an exclusion process for common facilities which should not be classified as BES.

Yes, and we believe that this exclusion should be applied to both Transmission and Generation.

Response: Thank you for your comments. The revised definition includes a list of “Inclusions” and “Exclusions” from the 100 kV threshold and no longer
references any ‘exemption process’. Based on stakeholder comments, the drafting team added “Exclusions,” to the BES definition relative to radial systems and
local distribution networks.

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9.

Should the following be excluded from the Elements and Facilities classified as part of the BES?
•

Elements and Facilities identified through application of the exemption process, consistent with the criteria, where the
exemption process deems that the Element or Facility should be excluded from the BES (with concurrence from the ERO)

Summary Consideration: The majority of the industry responded positively to this question. However, the SDT understands that the process is
still in development and that may affect actual responses. The SDT is striving to develop a revised “bright-line” definition that contains certain
inclusions/exclusions and that should remove any confusion. A separate Rules of Procedure (ROP) team is undertaking to develop a separate
process for Facilities that entities may choose to follow for their unique/special circumstances that do not fit within the definition and its
designation.

Organization

Yes or No

Question 9 Comment

IRC Standards Review
Committee

No

We find this exclusion criteria to be redundant. We believe that the proposed definition together with the basic
inclusion criteria suffice to provide a bright line framework for determining Elements/Facilities that should be
included as BES. Having this exclusion criteria confuses the bright line approach and does not add any value
to the basic definition and inclusion criteria.

Independent Electricity System
Operator

No

We find this exclusion criteria to be redundant. We believe that the proposed definition together with the basic
inclusion criteria suffice to provide a bright line framework for determining Elements/Facilities that should be
included as BES. Having this exclusion criteria confuses the bright line approach and does not add any value
to the basic definition and inclusion criteria.

Electric Market Policy

Yes

Dominion conceptually supports an exemption process whereby NERC or the RRO could apply to have an
element included or excluded from the BES definition. Such process recognizes that it may be necessary to
include elements that do not meet the bright line criteria but are necessary for operating an interconnected
transmission network. Such process should be developed through the existing NERC standards development
process and include a robust appeals process for the owner/operator of any element so included or excluded.

Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC

Yes

Constellation recognizes the value in clarifying the Definition of Bulk Electric System into a bright line
threshold consistently applied across the regions. However, we are concerned that the current approach of a
simple, all inclusive definition coupled with an exception criteria and process will not draw on the
fundamentals underpinning the existing definition and create a cumbersome and unnecessary exception
process. As an alternative, we propose that the standard drafting team utilize the -Section III (Rules of
Procedure Appendix 5B) along with definition threshold language to develop a more comprehensive
definition. Regardless of approach, any elements and facilities found to meet the criteria for exemption
should be exempted. The development of such criteria should be part of the BES drafting team’s

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Organization

Yes or No

(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Question 9 Comment
responsibility.

Response: Your comments are noted. The SDT is striving to develop a “bright-line” definition that will contain certain inclusions/exclusions and that should
remove any confusion. A separate Rules of Procedure (ROP) team is undertaking to develop a separate process for Facilities that entities may choose to follow for
their unique/special circumstances that do not fit within the definition and its designation.
Occidental Energy Ventures Corp

No

Manitoba Hydro

Until the exemption process is finalized, it is not prudent to answer in the affirmative.
Abstain until exemption process has been defined.

Response: The SDT understands that the process is still in development and how that may affect your response.
National Rural Electric
Cooperative Association
(NRECA)

Without specific exemption criteria to review, it is too early to explicitly answer this question. However, the
concept appears to be logical. All exemption criteria must be explicit and unambiguous in order to provide as
much certainty as possible.
Work done by the Regional Entities on exemption criteria should be reviewed to determine is usefulness to
the SDT.

PacifiCorp

Yes

In Order No. 743, the Commission directed NERC to adopt an exemption process for excluding facilities from
the definition of the BES that are not necessary to operate an interconnected electric transmission network.
In order to determine which facilities may be excluded, there must be criteria and a methodology that may be
applied to identify which facilities are “necessary” to operate an interconnected electric transmission network
and which “transmission and generation” facilities are not. In other words, there must be a clear way to
determine what makes a particular facility is “necessary” for bulk system operation. Application of the criteria
and methodology will result in the identification of the facilities that may be excluded. The comment questions
asked in this questionnaire cannot be answered in a meaningful way absent this methodology.
Significant efforts have been undertaken by the WECC Bulk Electric System Definition Task Force (BESDTF)
over the course of the past year to identify some initial criteria and methodologies. These efforts are ongoing
and should be supported by the NERC drafting team.

Response: The SDT is striving to develop a “bright-line” definition that will contain certain inclusions/exclusions and that should remove any confusion. A separate
Rules of Procedure (ROP) team is undertaking to develop a separate process for Facilities that entities may choose to follow for their unique/special

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Organization

Yes or No

Question 9 Comment

circumstances that do not fit within the definition and its designation.
Work done by Regional Entities is one of many inputs to the SDT deliberations.
Xcel Energy

MRO's NERC Standards Review
Subcommittee

This undeveloped process presents itself as a wild card to entities, and will most likely present inconsistencies
between regions based upon each Region’s preference. Additionally, does the Regional Methodology require
any approval (e.g. ERO) other than the Region’s own process? The “exclusions” process indicates that the
ERO has the final approval authority to exclude an item from the BES. Why would the same not apply for
including something into the BES based on the Region’s Methodology?
Yes

This will give the industry a clear set of criteria to follow which is FERC approved. If a Regional Entity has a
need to alter this process there are processes in place for them to pursue a variance. However, the
applicable process should be called an “exception” process to avoid the connotation that “exemption” process
has for the “inclusion” aspect of the process. NSRS believes the exemption process, review and approval,
would be best handled by the Regional Entity (RE) since they have more knowledge on the transmission
system in their region. The “who” and “what” will have to be spelled out clearly in the criteria for the exception
process.

Response: A separate Rules of Procedure (ROP) team is undertaking to develop a process for Facilities that do not fit within the bright-line definition. The details
of the process are still under discussion and development. However, the SDT expects that ERO will have an oversight role on the Regional Process.
The Dow Chemical Company

Dow recommends that NERC finalize a basic framework for identifying BES facilities before evaluating
individual facilities or types of facilities. Such a framework is recommended by Dow in response to questions
#11 and #12 below.

Response: See responses to Q11 & 12.
Entergy Services

Our response to this question depends on the details of the “exemption process”, including what entity has
the final decision and how it is implemented. Please see our response to Q13 below.

Northeast Power Coordinating
Council

Yes

Refer to the response to Question 13.

FirstEnergy Corp

Yes

Yes, but the process should be simple, rarely used with a high threshold for removing any 100kV and above
facility from the normally defined BES. Please see our Question 13 response for further views.

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Organization

Yes or No

Question 9 Comment

NERC Staff

Yes

Please see additional comments at the end of this document.

Orange and Rockland Utilities,
Inc.

Yes

Refer to the response to Question 13.

Florida Municipal Power Agency

Yes

Transmission Access Policy
Study Group

Yes

It is important to maintain the distinction between “exclusions” and “exemptions.” The SDT seems at times to
use the words interchangeably. An exclusion is a categorical carve-out from the BES definition, such that
excluded Elements are treated the same as sub-100 kV Transmission. FMPA proposes the following
exclusion, which would retain the existing exclusion of radials serving only load with one Transmission
source, clarified to add radials serving inconsequential generation to the exclusion:Radial Transmission
Elements serving only load with one Transmission source are generally not included in this definition. A radial
Transmission Element may be considered as “serving only load” for purposes of the foregoing general
exclusion even if it connects generation, so long as that generation is not registered pursuant to the
Statement of Compliance Registry Criteria. To obtain an exemption, on the other hand, an entity must go
through the NERC exemption process. If the owner or operator of an Element that is nominally part of the
BES can demonstrate to NERC that the particular Element meets the criteria for demonstrating that it is not
necessary for operating the interconnected electric transmission network, that Element should be granted an
exemption and thus considered non-BES. (See also FMPA comments on BES exemption process submitted
today.)Requests for exemptions should be decided by NERC, not the Regional Entities, in order to foster
continent-wide uniformity.

Response: See response to Q13.

Response: Your comments are noted. The SDT is striving to develop a “bright-line” definition that will contain certain inclusions/exclusions and that should
remove any confusion. A separate Rules of Procedure (ROP) team is undertaking to develop a separate process for Facilities that entities may choose to follow for
their unique/special circumstances that do not fit within the definition and its designation.
Pepco Holdings Inc.

Yes

1. The proposed BES definition should be expanded to contain more specific criteria for what is excluded
(and included) to minimize the need for exemptions. The exemption process should only be needed for a few
special situations that are not covered in the criteria.
2. The exemption process should rest with the regional entity.

Response: 1. Your comments are noted. The SDT is striving to develop a “bright-line” definition that will contain certain inclusions/exclusions and that should
remove any confusion.
2. A separate Rules of Procedure (ROP) team is undertaking to develop a process. Regional entities are expected to have an important role in the exception

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Organization

Yes or No

Question 9 Comment

process. However, as directed by FERC, it is expected that the ERO would have an oversight and/or approval role. The details of the process are still under
discussion and development.
Indeck Energy Services

Yes

Same Response as Question 1

Utility Services

Yes

See the answer to Question 1.

PUD No.1 of Clallam County

Yes

Central Lincoln

Yes

We agree with this except for the parenthetical. If the exemption process itself is approved by the ERO, there
should be no reason to get ERO concurrence on every exempted element. Such a process will bog down the
system so that the process will take years. Concurrence with the RE should be sufficient. The ERO should
only become involved in the event of disagreement between the registrant and the RE.

PNGC Power

Yes

Blachly-Lane Electric Co-op

Yes

Clearwater Power Co.

Yes

Douglas Electric Cooperative

Yes

Central Electric Cooperative, Inc.
(Redmond Oregon)

Yes

Raft River Rural Electric
Cooperative

Yes

Northern Lights Inc.

Yes

Salmon River Electric
Cooperative

Yes

Okanogan Country Electric
Cooperative

Yes

Response: see response to Q1.

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Organization

Yes or No

Lost River Electric

Yes

Lane Electric Cooperative

Yes

Coos-Curry Electric Cooperative

Yes

Consumer's Power Inc.

Yes

Umatilla Electric Co-op

Yes

West Oregon Electric
Cooperative

Yes

Lincoln Electric Cooperative

Yes

Fall River Electric Cooperative

Yes

Lewis County PUD

Yes

Question 9 Comment

Response: A separate Rules of Procedure (ROP) team is undertaking to develop an exception process. Regional entities are expected to have an important role
in the exception process. However, as directed by FERC, it is expected that the ERO would have an oversight and/or approval role. The details of the process are
still under discussion and development.
United Illuminating Company

Yes

NERC should specify the technical criteria to determine the exemption of a facility. NERC could either directly
or delegate to the The Regional Entity to oversee the exemption process and verify consistency and maintain
lists.

Response: A separate Rules of Procedure (ROP) team is undertaking to develop an exception process. Regional entities are expected to have an important role
in the exception process. However, as directed by FERC, it is expected that the ERO would have an oversight and/or approval role. The details of the process are
still under discussion and development.
American Transmission company

March 30, 3011

Yes

However, the applicable process should be called an “exception” process to avoid the connotation that
“exemption” process has for the “inclusion” aspect of the process. ATC believes the exemption process,
review and approval, would be best handled by the Regional Entity (RE) since they have more knowledge on
the transmission system in their region. The “who” and “what” will have to be spelled out clearly in the criteria

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Organization

Yes or No

Question 9 Comment
for the exception process. For consistency, it is appropriate for the ERO to monitor and concur with the
exceptions.

Response: A separate Rules of Procedure (ROP) team is undertaking to develop an exception (inclusion/exclusion) process. Regional entities are expected to
have an important role in the exception process. However, as directed by FERC, it is expected that the ERO would have an oversight and/or approval role. The
details of the process are still under discussion and development.
City Water Light and Power
(CWLP) - Springfield, IL

Yes

CWLP generally agrees with this point, but would like to see a firm, detailed administrative process for
resolving disputes for exemptions with technical justification as the guiding principle.

Response: A separate Rules of Procedure (ROP) team is undertaking to develop an exception process for Facilities that do not fit within the bright-line definition.
The details of the process are still under discussion and development.
American Electric Power (AEP)

Yes

As noted in our response to question 5, we believe that an exemption process is needed, though substantive
comments cannot be made until details of such a process and its related criteria are provided.

Yes

Who can apply? Who pays for the process? Is there a time frame for approval? Is the registered entity
required to meet reliability requirements for the Element or Facility while it is in the exemption process? Part
of the concern is that there are Elements and Facilities that are not necessary for the reliability for the BES
but if they were included as part of the BES definition would significantly harm the entity financially to meet
compliance with no measurable impact to reliability.

Response: See response to Q5.
Springfield Utility Board

Response: A separate Rules of Procedure (ROP) team is undertaking to develop an exception process for Facilities that do not fit within the bright-line definition.
The details of the process are still under discussion and development. The SDT will forward your comments to the ROP team for consideration as part of their
process.
City of Redding

Yes

City of Anaheim

Yes

SERC EC Planning Standards
Subcommittee

Yes

March 30, 3011

The key element is a good exemption process based on sound engineering principles.

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Organization

Yes or No

Question 9 Comment

Public Service Enterprise Group
Company

Yes

Bonneville Power Administration

Yes

PPL Energy Plus

Yes

LG&E and KU Energy LLC

Yes

ExxonMobil Research and
Engineering

Yes

Arizona Public Service Company

Yes

LCRA Transmission Services
Corporation

Yes

American Municipal Power

Yes

North Carolina EMC

Yes

If elements or facilities meet one of the BES definition classifications identified in Questions 1-7 above, the
owner of the facility or element should be able to apply for an exemption through the exemption process. In
other words, the criteria outlined in Questions 1-7 should be considered a "bright-line" criteria for inclusion in
the BES. If a facility meets one or more of these criteria, it can only be excluded from the BES by applying for
an exemption through the exemption process.

ReliabilityFirst

Yes

However, the exemption process and criteria needs to be clearly defined so that a common approach across
the ERO is used when this determination is made.

on behalf of Teck Metals Ltd.

Yes

Southern California Edison

Yes

March 30, 3011

No Comment

Yes, PPL Energy Plus support an exemption process for facilities (such as radial generation service and 100
kV looped load service) provided the Exemption process follows FERCs Order 743 paragraph 115: “NERC
should develop an exemption process that includes clear, objective, transparent, and uniformly applicable
criteria for exemption of facilities that are not necessary for operating the grid.”
There should be an exemption process. There should also be a documented process for appealing the
determination of whether or not a facility is part of the BES.

SCE agrees Elements and Facilities identified through application of the exemption process, consistent with
the criteria, where the exemption process deems that the Element or Facility should be excluded from the
BES (with concurrence from the ERO).

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Organization

Yes or No

Question 9 Comment

Southern California Edison
Company

Yes

on behalf of Catalyst Paper
Corporation

Yes

City of Grand Island

Yes

Glacier Electric Cooperative

Yes

Yes - This is assuming that the exemption process is an accurate way to truly determine whether or not a
facility is significant to the grid. I think such an analytical method will be much more effective and accurate
than a bright-line approach.

ISO New England Inc.

Yes

We generally support this approach, subject to the assessment of the detailed exemption/inclusion criteria
and process.

Snohomish County PUD

Yes

If the Element or Facility is demonstrated through engineering studies performed as part of the exemption
process to be unnecessary for the reliable operation of the interconnected bulk transmission system, the
Element or Facility should not be classified as part of the BES regardless of its operating voltage.

City of Austin dba Austin Energy

Yes

Duke Energy

Yes

The Dayton Power and Light
Company

Yes

ITC Holdings Corp

Yes

BGE

Yes

No comment.

Southern Company

Yes

Yes, provided the evaluation method is clear, understandable, and technically based.

Idaho Power

Yes

March 30, 3011

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Organization
Clark Public Utilities

Yes or No

Question 9 Comment

Yes

Response: Thank you for your response.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

10. Should the following be excluded from the Elements and Facilities classified as part of the BES?
•

Generating plant control and operation functions which include relays and systems that control and protect the unit for
boiler, turbine, environmental, and/or other plant restrictions

Summary Consideration: Most commenters who responded to this question indicated agreement with the proposal. The SDT has discussed
generator plant controls and operation functions and feels that they should not be included in the BES definition. It was determined that balance of
plant equipment, including control and operation functions, fall within the scope of existing reliability standards. However, the SDT believes the
inclusion of generator leads and the GSU for some configurations have been established by the SDT through discussions of the elements and
resources material integral to the reliable operation of the BES. The bright-line designation will be developed as part of this project and the ROP
process will be handled through the revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES
definition.
The revised BES definition includes the following “Inclusions” as elements of the BES:
Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the generator terminals through the
GSU which has a high side voltage of 100 kV or above.
Included in the BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or
above.

Organization

Yes or No

Question 10 Comment

Bonneville Power Administration

No

However, if the generator is not part of BES, then the plant control and operation functions should not be
included in the BES as well.

Glacier Electric Cooperative

No

Once again, it depends on the facility's significant impact to the grid.

Manitoba Hydro

If there is an impact to frequency or voltage response or facility ratings it should be included.

City of Austin dba Austin Energy

Yes

This response assumes the question refers to devices within the plant itself. In other words, the relays, etc.
within the plant and used to protect the generation assets should not be included in the definition of BES.
Additionally, many generation units have a design basis allowing some equipment to trip without impact to the
generation output.

City of Redding

Yes

Only the relays and protection schemes that protect BES equipment (example is a BES substation bus), not
power plant equipment. Exception could be a RMR unit.

March 30, 3011

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Organization

Yes or No

Question 10 Comment

Response: The SDT has discussed generator plant controls and operation functions and feels that they should not be included in the BES definition. It was
determined that balance of plant equipment, including control and operation functions, fall within the scope of existing reliability standards.
Duke Energy

No

ReliabilityFirst

Boiler, turbine, environmental or other control systems that are designed to automatically trip a BES facility in
the normal system configuration, when operating correctly for their intended function, should be included in
the BES definition.
Several of these examples listed could in fact force a unit or units out of service, thereby causing a negative
impact (such as lowering frequency, etc.) to the BES. However, there should be some additional thought for
exclusion of balance of plant facilities, such as the boiler, turbine, and environmental and auxiliary equipment
(i.e. scrubber, baghouse, precipitator, fuel/ash coal handling, cooling water, etc.), if they cannot trip the unit
off-line.

Response: The SDT has discussed generator plant controls and operation functions including those associated with balance of plant equipment such as boiler,
turbine, environmental and other control systems and feels that they should not be included in the BES definition. It was determined that balance of plant
equipment, including control and operation functions, fall within the scope of existing reliability standards.
LCRA Transmission Services
Corporation

No

American Municipal Power

No

Response: Thank you for your response.
NERC Staff

No

Please see additional comments at the end of this document.

Response: See response to Q13.
The Dow Chemical Company

As discussed in response to question #12 below, issues relating to the registry criteria applicable to
generation resources should not be revisited at this time.

Response: See response to Q12.
Competitive Suppliers

March 30, 3011

Plant controls and other systems on the generation side from the point of interconnection should not be
included in the BES definition because they do not significantly affect the reliability of the interconnected

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 10 Comment
electric network. EPSA recommends that the standards drafting team develop a BES exemption criteria that
considers the impact of all equipment (including lead lines and GSUs) on the generator side from the point of
interconnection on the reliability of the BES.

Response: The SDT has discussed generator plant controls and operation functions and feels that they should not be included in the BES definition. It was
determined that balance of plant equipment, including control and operation functions, fall within the scope of existing reliability standards. The bright-line
designation will be developed as part of this project and the process will be handled through the revision to the Rules of Procedure by a separate team in an effort
parallel to the development of this BES definition. Your comments will be forwarded to the Rules of Procedure Team.
Arizona Public Service Company

Yes

The above description for defining the exclusion is vague and too difficult to determine where the exclusion
applies for a Generator. AZPS recommends identifying exclusions for all systems which are not
electrically/magnetically connected to generation elements including the GSU, line leads and the generator or
its protection systems.

City of Anaheim

Yes

Unless the generator is required to maintain BES reliability, i.e. black start, etc., the GSU and gen tie should
be excluded from the BES; provided, however, to eliminate any reliability gaps, such generation-tie equipment
should be classified as "Generator" equipment subject to GO/GOP standards, and the PRC and vegetation
management standards should be made applicable to GO/GOPs and this equipment. This is consistent with
the NERC Reliability Functional Model and is more efficient than requiring TO/TOP registration for non-critical
generation-tie transmission elements that are not required for the reliable operation of the BES.

Response: The inclusion of generator leads and the GSU for some configurations have been established by the SDT through discussions of the elements and
resources material integral to the reliable operation of the BES.

Included in the BES: I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the generator terminals through the GSU
which has a high side voltage of 100 kV or above.
Included in the BES: I3 - Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus operated at a voltage of 100 kV or above.
Indeck Energy Services

Yes

Same Response as Question 1

Yes

Individual loads equal to or below 25 MW (one customer on a line) served by Transmission Facilities greater
than 100kV and the Transmission Facilities themselves should be excluded for the same reason. Entity
registration is based on aggregate loads. But a 10 MW load may served by an LSE that has a 200 MW peak

Response: See response to Q1.
Springfield Utility Board

March 30, 3011

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Organization

Yes or No

Question 10 Comment
is part of the BES while the same 10 MW load served by a 20 MW LSE would not be part of the BES. From a
reliability perspective this is inconsistent. Either a facility is or isn't necessary for the reliability of the BES. If a
facility isn't necessary because an entity does not meet registration thresholds then the same facility should
be excluded from the BES for an entity that is registered.

Response: The SDT has decided to stay with the limits in the NERC Statement of Compliance Registry Criteria with regard to the size of generators that will be
included in the BES.
Unless the generator is required to maintain BES reliability, i.e. black start, etc., the GSU and gen tie should be
excluded from the BES; provided, however, to eliminate any reliability gaps, such generation-tie equipment
should be classified as "Generator" equipment subject to GO/GOP standards, and the PRC and vegetation
management standards should be made applicable to GO/GOPs and this equipment. This is consistent with the
NERC Reliability Functional Model and is more efficient than requiring TO/TOP registration for non-critical
generation-tie transmission elements that are not required for the reliable operation of the BES.

City of Anaheim

Yes

Northeast Power Coordinating
Council

Yes

SERC EC Planning Standards
Subcommittee

Yes

Public Service Enterprise Group
Company

Yes

The relays and systems described above should not be classified as part of the BES. The intent of the BES
definition and applicable standards should not include these items as this would further confuse the BES
boundary scope rather than clarify what should be included. The described functions and controls by
themselves do not add to BES reliability.

MRO's NERC Standards Review
Subcommittee

Yes

This will give our industry a clear defining line of what is a BES Facility and what it is comprised of.

IRC Standards Review
Committee

Yes

Florida Municipal Power Agency

Yes

Transmission Access Policy
Study Group

Yes

March 30, 3011

These systems are internal protection systems and will not impact the reliability of the BES.

Excluding such generating plant control and operation functions, which have to do with mechanical energy,
rather than electric energy, would be consistent with Section 215 of the Federal Power Act, which states that
the Bulk Power System includes “electric energy from generation facilities needed to maintain transmission
system reliability.” There are standards, such as PRC-024, FAC-008, and FAC-009, regulating total unit
performance and ratings, which necessarily covers component performance as well. Therefore, no purpose

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Organization

Yes or No

Question 10 Comment
would be served by including these types of items in a granular way in the BES definition.

FirstEnergy Corp

Yes

Electric Market Policy

Yes

SERc OC Standards Review
Group

Yes

PacifiCorp

Yes

PPL Energy Plus

Yes

LG&E and KU Energy LLC

Yes

Central Lincoln

Yes

Pepco Holdings Inc.

Yes

PUD No.1 of Clallam County

Yes

North Carolina EMC

Yes

on behalf of Teck Metals Ltd.

Yes

Southern California Edison

Yes

Southern California Edison
Company

Yes

March 30, 3011

Yes these should be excluded from the BES definition. If there is a reliability need related to these devices a
standard could be written even though they are not included within the BES definition. Our position is similar
to our prior stated view on the blackstart and cranking path.

Excluding these generator components is correct.

Only relay elements and systems for generating units that meet or exceed the 20 MVA nameplate BES
criteria should be included in this classification.

SCE believes generating plant control and operation functions which include relays and systems that control
and protect the unit for boiler, turbine, environmental, and/or other plant restrictions should not be included in
the BES definition.

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Organization

Yes or No

on behalf of Catalyst Paper
Corporation

Yes

City of Grand Island

Yes

Occidental Energy Ventures Corp

Yes

ISO New England Inc.

Yes

Entergy Services

Yes

Snohomish County PUD

Yes

PNGC Power

Yes

Blachly-Lane Electric Co-op

Yes

Clearwater Power Co.

Yes

Douglas Electric Cooperative

Yes

Central Electric Cooperative, Inc.
(Redmond Oregon)

Yes

Raft River Rural Electric
Cooperative

Yes

Northern Lights Inc.

Yes

March 30, 3011

Question 10 Comment

The BES by statutory definition can include only those Facilities and Elements that are necessary for the
reliable operation of the interconnected bulk transmission system. While the facilities identified in question 10
may be necessary for the protection of plant equipment or to meet regulatory obligations related to
environmental protection, they cannot be classified as BES facilities in the absence of a clear demonstration
that the facilities are material to the reliable operation of the bulk system because the failure of those facilities
could threaten cascading failures, separation events, or instability on the interconnected bulk transmission
system.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 10 Comment

Salmon River Electric
Cooperative

Yes

Okanogan Country Electric
Cooperative

Yes

Lost River Electric

Yes

Lane Electric Cooperative

Yes

Coos-Curry Electric Cooperative

Yes

Consumer's Power Inc.

Yes

Umatilla Electric Co-op

Yes

West Oregon Electric
Cooperative

Yes

Lincoln Electric Cooperative

Yes

Fall River Electric Cooperative

Yes

United Illuminating Company

Yes

The Generator Protection systems for the Electrical Interconnection should not be excluded from the BES.

Orange and Rockland Utilities,
Inc.

Yes

These systems are internal protection systems and will not impact the reliability of the BES.

American Transmission company

Yes

Utility Services

Yes

The Dayton Power and Light

Yes

March 30, 3011

Utility Services believes that these systems are internal protection systems and will not impact the reliability
the BES. .

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 10 Comment

Company
ITC Holdings Corp

Yes

BGE

Yes

Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

Yes

City Water Light and Power
(CWLP) - Springfield, IL

Yes

Lewis County PUD

Yes

These elements have little to do with the BES and should be excluded.

American Electric Power (AEP)

Yes

Given the vast diversity of plant auxiliary systems, together with their built-in redundancies, component
failures in these systems would have negligible impact on BES reliability. In support of this, RFC’s definition of
BES does well by seeking to maintain electric system reliability without over-reaching, by allowing the
exemption of the devices mentioned in question 10.

Southern Company

Yes

Generator protection systems and operational control systems for generating plants are not critical to the BES
operation. Generator protection systems should be included. However, we do not believe that other plant
control systems such as boiler controls and operational control systems, etc should be included for generating
plants as they are not critical to the BES operation.

Idaho Power

Yes

March 30, 3011

No comment.

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Independent Electricity System
Operator

Yes

Clark Public Utilities

Yes

Xcel Energy

Yes

Question 10 Comment

Response: Thank you for your response.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

11. Do you believe that the proposed definition of BES, accompanied by a separate BES Definition Exception Process
meets the reliability-related intent of the directives in Order 743?

Summary Consideration: Most commenters who responded to this question indicated disagreement with the proposal, indicating a
preference to have more details in the definition. The SDT will develop the BES definition and associated criteria. The SDT intends to develop
criteria that will be explicit enough so that the owners/operators of the vast majority of Facilities will not have to seek a case-by-case exception on
whether their Facilities are part of the BES. This includes addressing radial Transmission serving only Load.
A separate ROP team will develop the procedures for seeking an exception that is not clearly addressed by the definition and criteria. The SDT
understands the importance of the exception process being developed in parallel with the BES definition and associated criteria and will closely
coordinate with the ROP team that is responsible for developing that process. As the SDT develops the modified BES definition and associated
criteria, it will carefully consider Canadian-specific issues and the current NERC Statement of Compliance Registry Criteria.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an
automatic interruption device and:
a)
b)
c)

Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow
for reliable system reconfiguration to maintain continuity of electrical service. Or,
Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in
Inclusions I2, I3, I4 and I5.

Excluded from the BES: E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV that distribute power to Load
rather than transfer bulk power across the interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one
location solely to improve the level of service to retail customer Load. The LDN is characterized by all of the following:
a)
b)
c)
d)
e)

Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic
fault-interrupting devices;
Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;
Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable
monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating
Limit (IROL).

March 30, 3011

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Organization
Public Service Enterprise Group
Company

Yes or No
No

Question 11 Comment
There is still room for misinterpretation. The definition of the BES should be as explicit as possible since it
affects the majority of the standards.

Response: The SDT is developing a bright-line BES definition and associated criteria that will address as many Facilities as possible.
Florida Municipal Power Agency

No

Transmission Access Policy
Study Group

No

The proposed definition abandons the current exclusion of radials serving only load with one transmission
source that Order 743 specifically left in place, and instead conflates “excluded” Elements with Elements for
which an “exemption” can be sought. The proposed definition would thus require entities to seek an
exemption, presumably on a case-by-case basis, for every > 100 kV radial serving only load with one
transmission source. FERC did not intend to direct such a result in Order 743, but rather intended to allow
the current exclusion of such radials to load to continue.Furthermore, to comply with Order 743, the new BES
definition and exemption/inclusion processes must ensure uniformity throughout the United States. Thus
there must be a uniform process; clear criteria for exemption and inclusion; and a right to appeal decisions to
a higher body within NERC and/or to FERC.

Response: The SDT has proposed the following radial exclusion from the BES as part of its revised definition. The SDT believes that this will address your
concern.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.
Electric Market Policy

No

See comments at bottom of questionnaire (Q13).

PPL Energy Plus

No

For the reasons discussed above, the proposed BES definition does not take into account FERC’s desire to
only include Facilities in the BES that have an impact on the reliability of the Interconnected Electric Network.

LG&E and KU Energy LLC

No

Response: See response to Q13.

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 11 Comment

Response: The SDT assumes that you are referring to responses that you provided to earlier questions. See above responses.
Competitive Suppliers

No

The intent of the directives in Order 743 is to, “direct NERC to develop a uniform modified definition of Bulkelectric system [that] will eliminate regional discretion and ambiguity”. In Order 743 the Commission also
finds that the exemption process needs to work with the definition. Paragraph 115 from the BES final rule
states “NERC should develop an exemption process that includes clear, objective, transparent, and uniformly
applicable criteria for exemption of facilities that are not necessary for operating the grid. The ERO also
should determine any related changes to its Rules of Procedures (ROP) that may be required to implement
the exemption process, and file the proposed exemption process and rule changes with the Commission.”
This section does not direct NERC to use the ROP modification process to develop “separate” exemption
criteria. It only recommends that NERC modify its ROP for any related changes to implement the exemption
process, not for developing the exemption criteria. BES exemption criteria need to be developed through the
NERC standards development procedure by the Standard Drafting Team (SDT) that is modifying the BES
definition. The exemption criteria need to be done by the same group that forms the definition so that the
exemptions are crafted to fit with the new BES definition. The definition and the exemption criteria need to be
meshed and work together.

Response: The SDT will develop the BES definition and associated criteria. A separate Rules of Procedure (ROP) team will develop the procedures for seeking
an exception that is not clearly addressed by the definition and criteria. The SDT will closely coordinate with the ROP team.
PacifiCorp

No

The proposed definition does not meet the reliability-related intent of the directives in Order 743 in two
respects. First, the second clause of the first sentence of the proposed definition re-introduces the ambiguity
that the Commission believes a bright-line threshold will eliminate. The first sentence states that the BES is
“all Transmission and Generation Elements and Facilities operated voltages of 100 kV or higher necessary to
support bulk power system reliability.” (emphasis added). PacifiCorp understands that the intent of this
language is to indicate that only some subset of 100 kV facilities (those necessary for reliability) are included
in the definition of the BES. However, this language is ambiguous in that it does not make it clear that the
only way to exempt 100 kV and above facilities (other than certain defined radial facilities) from the definition
is to utilize the exemption process. Second, the proposed definition does not make it clear that certain
defined radial facilities may be excluded from the definition without utilizing the exemption process.
PacifiCorp proposes the following:Bulk Electric System: All Transmission and Generation Elements and
Facilities operated at voltages of 100 kV or higher except [defined radial facilities]. Transmission and
Generation Elements and Facilities operated at voltages of 100 kV or higher may be excluded if they are not
necessary to operate an interconnected electric transmission network. Transmission and Generation
Elements and Facilities operated at voltages of 100 kV or lower must be included if they are necessary to
operate an interconnected electric transmission network. The criteria for determining whether Elements and

March 30, 3011

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Organization

Yes or No

Question 11 Comment
Facilities are necessary to operate an interconnected electric transmission network are defined in the BES
definition exemption process.

Response: The SDT is developing criteria that will be explicit enough so that the owners/operators of the vast majority of Facilities will not have to seek a case-bycase decision on whether their Facilities are part of the BES. This includes addressing radial Transmission serving only Load.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.

ExxonMobil Research and
Engineering

No

The proposed definition is over reaching and can potentially expand the scope of the BES beyond the point to
which NERC was intended to have the authority to govern. The proposed definition does not directly address
the line of demarcation between customer owned facilities and elements of BES.

Response: The SDT is developing a BES definition and associated criteria that it believes will address your concerns and those of others in this regard.
NERC Staff

No

Please see additional comments at the end of this document.

Entergy Services

No

Please see our response to Q13 below.

No

Radial transmission systems operated below 100 kV should not be included as part of the BES and should
not have to go through the exception process.

Response: See response to Q13.
Arizona Public Service Company

Response: The SDT is developing a BES definition and associated criteria that it believes will address your concerns and minimize the need for owners/operators
to have to have to go through an exception process.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:

March 30, 3011

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Consideration of Comments on Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 11 Comment

a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5.

Xcel Energy

No

Manitoba Hydro

No

No. The proposed definition includes the wording ‘...necessary to support bulk power system reliability’ which
increases ambiguity and reduces the 100kV and above bright line distinction. This wording should be
removed. Manitoba Hydro suggests the following: Bulk Electric System: All Transmission and Generation
Elements and Facilities operated at voltages of 100 kV or higher except defined radial facilities. Elements and
Facilities operated at voltages of 100kV or higher, including Radial Transmission systems, may be excluded
and Elements and Facilities operated at voltages less than 100kV may be included if approved through the
BES definition exemption process.

Response: The SDT has revised the definition and the wording is no longer utilized.
Indeck Energy Services

No

Same Response as Question 1

No

SCE believes that the 100kV brightline threshold is sufficient.

Response: See response to Q1.
Southern California Edison

Response: Thank you for your comment. Please see the revised definition – it includes a detailed list if inclusions/exclusions to minimize the need to use the BES
Exception Process.
City of Grand Island

No

This question is premature given that the BES Exception Process has not been developed.

Occidental Energy Ventures Corp

No

Until the expemtion process is finalized, it is not prudent to answer in the affirmative.

Response: The SDT understands the importance of this process being developed in parallel with the BES definition and associated criteria.
Central Lincoln

March 30, 3011

No

The order was to provide a definition that excepted radial facilities and to create an exemption process for

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Organization

Yes or No

PUD No.1 of Clallam County

No

PNGC Power

No

Blachly-Lane Electric Co-op

No

Clearwater Power Co.

No

Douglas Electric Cooperative

No

Central Electric Cooperative, Inc.
(Redmond Oregon)

No

Raft River Rural Electric
Cooperative

No

Northern Lights Inc.

No

Salmon River Electric
Cooperative

No

Okanogan Country Electric
Cooperative

No

Lost River Electric

No

Lane Electric Cooperative

No

Coos-Curry Electric Cooperative

No

Consumer's Power Inc.

No

Umatilla Electric Co-op

No

March 30, 3011

Question 11 Comment
other facilities not necessary for operating the interconnected network. The SAR proposes to treat the two the
same. This will cause unneeded expense, delay, and uncertainty for those radial facilities that could simply be
eliminated by inspection. This would work against reliability by misdirecting resources toward the elements
tied up in the process, and possibly away from the elements that should be included.The SAR also fails to
meet the order by failing to apply it to all entity types. We fail to see how a bright line is achieved if DPs,
PSEs, and IAs work from a definition different from all the other types of registered entities. Please edit the
SAR to include all entity types.

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Organization

Yes or No

West Oregon Electric
Cooperative

No

Lincoln Electric Cooperative

No

Fall River Electric Cooperative

No

Lewis County PUD

No

Question 11 Comment

Response: The SDT is developing criteria that will be explicit enough so that the owners/operators of the vast majority of Facilities will not have to seek a case-bycase decision on whether their Facilities are part of the BES. This includes addressing radial Transmission serving only Load.
Excluded from the BES: E1 - Any radial system which is described as connected from a single Transmission source originating with an automatic interruption
device and:
a) Only serving Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation resources not identified in inclusions I2, I3, I4
and I5.

The Dow Chemical Company

March 30, 3011

No

Order No. 743 correctly recognizes that local distribution facilities are expressly excluded from the definition of
“Bulk-Power System” set forth in Section 215 of the Federal Power Act. See Order No. 743 at P 37. As such,
local distribution facilities must also be excluded from the definition of BES adopted by NERC. That is not the
case with respect to the proposed definition, which makes no mention whatsoever of local distribution
facilities. Instead, the proposed definition simply provides that certain facilities, including “Radial
Transmission systems, may be excluded . . . if approved through the BES definition exemption process.”
While this language presumably is an acknowledgement that Radial Transmission lines perform a local
distribution function and should be excluded, numerous other types of facilities also perform a local
distribution function and should also be excluded regardless of their voltage.For example, Dow and certain of
its subsidiaries, including Union Carbide Corporation, own and operate electrical facilities at a number of
industrial sites within the U.S. In all cases, a tie line or lines connect the industrial site to the electric
transmission grid. Power is delivered from the electric transmission grid to the industrial site through the tie
line(s). Lines within the industrial site then deliver power to individual manufacturing plants within the site.
Additionally, cogeneration facilities are located at a number of industrial sites owned by Dow and Union

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Question 11 Comment
Carbide Corporation, principally in Texas and Louisiana. These cogeneration facilities generate power that is
primarily distributed within the industrial site and used for manufacturing plant operations. In some instances,
excess power not required for plant operations is delivered into the electric transmission grid through the tie
line(s) connecting the industrial site to the grid.While the tie lines and internal lines at these industrial sites
can be fairly significant in terms of voltage, they do not perform anything that resembles a transmission
function. Rather than transmit power long distances from generation to load centers, the tie lines and internal
lines perform a local distribution function consisting of the distribution of power brought in from the grid or
generated internally to different manufacturing plants within each industrial site. In some cases, the facilities
also perform an interconnection function to the extent they enable excess power from cogeneration facilities
to be delivered into the grid. The voltage of the tie lines and internal lines at these industrial sites is dictated
by the load and basic configuration of each site. Higher voltage lines (>100 kV) are used to reduce line
losses while meeting applicable load requirements. That does not mean that such lines perform a
transmission function. Indeed, just as a line that delivers power into a home, or from a home to an
accompanying garage, is considered a distribution facility and not a transmission facility, the same is true of
lines that deliver power into industrial sites owned by Dow or its subsidiaries (even though such lines also
may be used to deliver excess power to the transmission grid) or within those sites. The definition of BES
adopted by NERC should explicitly provide for these types of local distribution facilities to be categorically
excluded.

City of Redding

No

The current definition goes to far; local goverments, cities, and citizens have been given the right to decide
the level of reliability of their distribution system. FERC & NERC were not given jurisdiction over local
distribution facilities. Note: many local distribution facilities are operated above 100 kV.

Response: The SDT is developing a BES definition and associated criteria that it believes will address your concerns.
•

Excluded from the BES: E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV that distribute power to Load rather than
transfer bulk power across the interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to improve
the level of service to retail customer Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting
devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent Flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the Quebec Interconnection, and

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Question 11 Comment

is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
National Rural Electric
Cooperative Association
(NRECA)

No

It is too early to determine the effectiveness of the proposed BES definition and BES criteria included in the
draft SAR. However, the concept of a BES definition and BES criteria, along with BES exemption criteria,
appears, at least from a preliminary standpoint, to be a satisfactory direction to begin the process. The
concepts presented in the draft SAR should not preclude any other potential direction for the SDT to explore
at this point in the process.The proposed BES definition in the SAR should be considered only as an
alternative for the SDT to consider in its work, not a final definition or a definition that precludes other
proposed definitions.

Response: The SDT considers the proposed BES definition in the SAR as a starting point for SDT consideration.
Duke Energy

No

The high level direction does, but the details need to be defined before this question can be answered
affirmatively.

Response: The SDT is developing a BES definition and associated criteria that it believes will address your concerns.
American Electric Power (AEP)

No

It’s not clear how the criteria in the concept paper will be related back to the overall definition of BES. We
recommend that the finalized criteria be included verbatim in the definition, or that the definition refer to an
official companion document. The definition cannot automatically include all equipment (both primary-voltage
and the associated auxiliary equipment) by default.

Response: The SDT considers the concept paper one of the starting points for SDT consideration. The finalized criteria will be included in the definition.
Springfield Utility Board

March 30, 3011

No

SUB appreciates the work to provide a clearer definition of the BES, but the proposed language is
ambiguous.The existing definition is:"As defined by the Regional Reliability Organization, the electrical
generation resources, transmission lines, interconnections with neighboring systems, and associated
equipment, generally operated at voltages of 100 kV or higher. Radial transmission facilities serving only load
with one transmission source are generally not included in this definition."The proposed definition is: "Bulk
Electric System: All Transmission and Generation Elements and Facilities operated at voltages of 100 kV or
higher necessary to support bulk power system reliability. Elements and Facilities operated at voltages of
100kV or higher, including Radial Transmission systems, may be excluded and Elements and Facilities
operated at voltages less than 100kV may be included if approved through the BES definition exemption
process."Looking at the first sentence, 100kV or higher facilities are part of the BES ONLY if they are
necessary to support bulk power system reliability. As written, if an registered entity determines that a 100kV
or higher facility is not necessary for BPS system reliability then the facility may be excluded. If the intent is to

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Question 11 Comment
assume that all 100kV and above facilities are necessary for BPS reliability, SUB strongly disagrees.To avoid
confusion, SUB suggests that the first sentence state: "Bulk Electric System: All Transmission and Generation
Elements and Facilities operated at voltages of 100 kV or higher." The language "necessary to support bulk
power system reliability." should be deleted.
Turning to the second sentence:"Elements and Facilities operated at voltages of 100kV or higher, including
Radial Transmission systems, may be excluded and Elements and Facilities operated at voltages less than
100kV may be included if approved through the BES definition exemption process."The approved April 2010
NERC Glossary of Terms includes definitions for "Elements", "Facilities", and "Transmission", but does not
have a definition for "Radial" or "Radial Transmission", "Radial Transmission systems", Transmission
systems", or "systems". SUB does not know what this language is intended to mean.If the language "Radial
Transmission systems" means an Transmission Element or Facility normally operated open then SUB agrees
with this language. If all Elements or Facilities are outright excluded from being excluded from the BES
because they could "potentially" be operated closed, this language has little value as most facilities have the
"potential" to operated closed.SUB has concerns that EROs are making interpretation of language, such as
"radial", without going through a required interpretation public process and are just "announcing" what
language means. Is is not uncommon for an ERO to announce a definition for an undefined term and then tell
registered entities that they need to request a formal interpretation from NERC in order to modify an informal
ERO interpretation. SUB would like to eliminate this confusion - starting with the BES definition which is
confusing and may perpetuate an informal interpretation process. SUB proposes that the second sentence
read:"Elements and Facilities operated at voltages of 100kV or higher, including Radial Transmission
systems, may be excluded and Elements and Facilities operated at voltages less than 100kV may be included
if approved through the BES definition exemption process. Radial Transmission systems include Elements or
Facilities normally operated open."
Lastly, why would an entity want to include an Element or Facility that would otherwise be excluded? If an
ERO determines that an Element or Facility below 100kV is necessary for reliability would the ERO be ability
to initiate an exemption process to include the Element or Facility without the owners knowledge or consent?
What if the owner is not a Registered Entity? This inclusion language for elements below 100kV is unclear in
terms of the application, implementation, or intent.

Response: The proposed BES definition included in the SAR is only a starting point for the SDT. The SDT intends to address the issues you have identified in its
efforts to develop a BES definition and associated criteria. The initial thinking is that for Facilities captured as BES by the definition/criteria, if an owner/operator
believed those Facilities should not be considered BES, that owner/operator would need to technically demonstrate why such Facilities should be excluded. In
addition, for Facilities that are not captured as BES by the definition/criteria, if the ERO or a Regional Entity believed those Facilities should be considered as BES,
then the ERO or the Regional Entity would need to technically demonstrate why such Facilities should be included. It is the intent of the SDT that the BES
definition and associated criteria it develops will address the vast majority of Facilities and minimize the need for technical demonstration by owners/operators or

March 30, 3011

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Yes or No

Question 11 Comment

the ERO and regional Entities.
Electricity Consumers Resource
Council (ELCON)

No

The Electricity Consumers Resource Council (ELCON) appreciates the opportunity to submit the following
comments on the draft concept document prepared by the Regional Bulk Electric System Definition
Coordination Group (RBESCG), a team of representatives of the Regional Entities (REs).ELCON is the
national group representing the interests of large industrial consumers of electricity. Many ELCON member
facilities are Registered Entities. One or more ELCON members are registered as: BA, IA, GO, GOP, TO,
TOP, TSP, PA, RP, LSE, and PSE. However, the most common registered functions of large industrial end
users are GO, GOP and PSE by virtue of the need to supply a complex industrial process with low-cost
thermal energy and/or low-cost electric energy.The stated purpose of the concept document is to provide a
“common approach” for:
o Defining the BES and therefore improve the clarity, reduce ambiguity and establish a universal method (i.e.,
bright line) for distinguishing between BES and non-BES Elements and Facilities.
o Identifying BES Elements and Facilities so as to establish a “repeatable” method for applying NERC
Reliability Standard requirements and facilitate consistent application of compliance efforts across regional
boundaries.CommentsELCON members have always supported fair and effective reliability efforts at NERC.
However, the expansion of the standards compliance responsibility implied by the NERC Concept Document
goes too far. As written, this proposal could have the effect of devaluing a large number of industrial owned
electrical power assets by forcing industrials to meet new and unnecessary compliance obligations. Many will
be forced to choose to either accept a significant new cost or fire sale their assets to local providers
increasing the purchaser’s market power in the process. ELCON feels the addition of new compliance
obligations should not be done in such a wholesale manner but instead done on an exception and as needed
basis that factors in both a realistic appraisal of the underlying risk and the economic burden imposed on the
registered entity relative to the expected benefits.
Specific recommendations and concerns are:
1. An Overarching “Principle” for the Identification of BES Elements and Facilities Must be the Guidance
Provided by FERC That Significant Expansion of the Compliance Registry is Not Contemplated.In FERC’s
March 18, 2010 Notice of Proposed Rulemaking (NOPR) on the Revision to Electric Reliability Organization
Definition of Bulk Electric System, the Commission stated regarding the revision to the BES definition:"This
proposal would eliminate the discretion provided in the current definition for a Regional Entity to define “bulk
electric system” within a region. Importantly, however, we emphasize that we are not proposing to eliminate
all regional variations and we do not anticipate that the proposed change would affect most entities." ¶
16."... the Commission does not believe that the proposal would have an immediate effect on entities in any
Regional Entity other than NPCC." ¶ 27.Similarly, in Order No. 743, the Commission stated:"We expect that
our decision to direct NERC to develop a uniform modified definition of 'bulk-electric system' will eliminate

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Question 11 Comment
regional discretion and ambiguity. The change will not significantly increase the scope of the present
definition, which applies to transmission, generation and interconnection facilities. The proposed exemption
process will provide sufficient means for entities that do not believe particular facilities are necessary for
operating the interconnected transmission system to apply for an exemption." ¶ 144.One area where the
proposed BES definition and exception process will significantly expand the Compliance Registry is the
criteria applicable to behind-the-meter generation (primarily cogeneration facilities). We urge that the BES
definition should not change the currently applicable 20 MVA / 75 MVA generation size threshold applicable to
generation facilities or the manner in which that threshold is currently applied, with behind‐the‐meter
cogeneration facilities evaluated based on the net capacity actually provided to the grid.
2. A Second Overarching “Principle” for the Identification of BES Elements and Facillities Is the Need to
Clarify Which Facilities Perform a True Transmission Function and Excluding Facilities That Perform a Local
Distribution Function, As Required by Law.Congress stated in Federal Power Act section 215:SEC. 215.
ELECTRIC RELIABILITY.’’(a) DEFINITIONS.-For purposes of this section:’’(1) The term ‘bulk-power system’
means-‘‘(A) facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof); and’’(B) electric energy from generation facilities needed to
maintain transmission system reliability.The term does not include facilities used in the local distribution of
electric energy.There has been little attempt by NERC to clarify what in fact are “facilities used in the local
distribution of electric energy” even though any plain English application of the term makes such a
determination self-evident. The proposed BES definition should expressly exclude facilities used in the local
distribution of electric energy, and the identification of such facilities is independent of the identification of BES
transmission. Facilities used for local distribution are NOT the residual of any determination of what are BES
transmission facilities.
3. A Third Overarching “Principle” for the Identification of BES Elements and Facilities Must be Recognition of
the Risk Imposed by the Element or Facility, and the Economic Burden of the Owner/Operator of the Element
of Facility.The efforts of the BES Standards Drafting Team follow the release of two important policy
documents. First, on January 18, 2011, the White House issued an Executive Order (“Improving Regulation
and Regulatory Review”) by President Obama regarding improvements to federal regulations and the review
of existing regulations to ensure, among other things, that a regulation be proposed or adopted “only upon
reasoned determination that its benefits justify its costs,” and that regulations be tailored “to impose the least
burden on society.” Second, the NERC Planning Committee issued on January 10, 2011, “Risk-Based
Reliability Compliance - White Paper Concept Discussion,” which attempts to advance “processes and
procedures to prioritize [NERC’s] efforts and ‘tiering’ elements of its programs to maximize their value and
optimize the benefit/cost of effort from stakeholders.” This white paper complements the President’s
Executive Order.ELCON believes that BES exclusion criteria and process should recognize and exclude
elements and facilities in which the risk to bulk electric system reliability is at most theoretical or speculative,
and where the compliance burden clearly outweighs the benefits. Such a determination should recognize the

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Question 11 Comment
historical record of the element or facility in terms of the owner or operator’s coordination with the BA or
control area, and transmission operators. This principle should be applied to the development of
exclusion/inclusion criteria for private lines that connect loads and behind-the-meter generation to true BES
Elements and Facilities.
4. An Additional Principle for the Identification of BES Elements and Facilities Should Be the Explicit
Recognition on How the Element or Facility is Actually Operated or Used, Not Its Physical or Nominal Rating
That May be Irrelevant to Reliability Considerations.In Order No. 743, FERC clarified that it did not intend to
require NERC to utilize the term “rated at” rather than the term “operated at” for the voltage threshold in the
revised BES definition. A principle for the identification of BES Elements and Facilities should be such
recognition and not exclusively on the rated value of an Element or Facility. This principle should be used to
retain the exclusion in the Statement of Compliance Registry Criteria (Revision 5.0) for “net capacity provided
to the bulk power system” in the context of the 20 MVA generating unit and 75 MVA generating plant
thresholds. The “net capacity” applies to capacity “put” of a behind-the-meter generator whose predominant
function is to serve load at the same site.
5. An Additional Principle for the Identification of BES Elements and Facilities Should be the Exclusion of
PSEs That Do Not Own or Operate Physical Assets and Whose Power Transactions Are Exclusively
Financial in Nature.Many PSEs that operate in FERC jurisdictional organized wholesale markets (i.e., ISOs
and RTOs) do not own, operate or lease physical assets and are currently bombarded with data requests that
assume that they own or control such assets. An example of a superfluous data request is to prove that
adequate reactive power has been procured to support the load. This is a question that should not have been
asked and displays a profound ignorance of the operation of ISO/RTO markets. One potential solution to this
problem is to create two subsets of PSEs: one that owns and operates physical assets that are used to serve
their loads, and a second that does not.Some Regional Entities have also begun to ask questions that require
PSEs to reveal the details of specific commercial transactions. This raises a broader question on what NERC
and regional compliance staffs and auditors “need to know” and whether such questions are an abuse of their
enforcement authority.
6. Any Attempt to Make Demand Side Management (DSM) Measures an Element or Facility of BES Will Be
Shortsighted and Counterproductive.Proposals that unilaterally and arbitrarily remove exclusions for
generation and transmission, including the application of new compliance obligations to DSM programs, go
far beyond what FERC intended in its guidance for revisions. Any new requirement concerning voluntary
DSM adds cost to a process that so far has only acted to support reliability with performance equal to and
sometimes superior to traditional providers. How is it that a potential resource that can contribute to
maintaining reliability is now so quickly identified as a risk? We warn against the overzealous pursuit of
control over every asset and resource on the electric system. This mindset will only breed cynicism and end
the willingness of potentially dispatchable loads to cooperate with the real operators and owners of the BES.A
recently issued FERC study highlights the potential value to reliability of DSM (in the form of dispatchable

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Question 11 Comment
demand response) (See Joseph H. Eto et al., Use of Frequency Response Metrics to Assess the Planning
and Operating Requirements for Reliable Integration of Variable Renewable Generation, LBNL-4142E,
December 2010). To reliably integrate greater amounts of wind energy resources to the bulk electric system,
the study recommended the:"Expanded use of demand response that is technically capable of providing
frequency control (potentially including smart grid applications), starting with broader industry appreciation of
the role of demand response in augmenting primary and secondary frequency control reserves."
7. Revising the Definition of BES Does Not Justify Shifting the Plenary Burden for BPS Reliability from Utilities
to Utility Customers. A BES Principle Should Recognize That the Obligation to Serve Applies in One
Direction.The only reason the bulk power system exists is to deliver electric power to residential households,
commercial businesses, government facilities and industrial facilities of all sizes. The value of a reliable BPS
is dependent on the needs of end use customers. Nothing in the legislative history of section 215 of the
Federal Power Act suggests that Congress wittingly intended to change that relationship. The burden of
complying with NERC Reliability Standards is a cost of doing business for utility providers of generation,
transmission and distribution services. Generation and interconnection facilities of industrial customers are
almost never intended for or used to “operate the interconnected transmission network.” Those facilities are
integral to a manufacturing process, including purchasing power from the grid. They were built in expectation
that the BPS was prudently planned and operated by utilities. The rare exceptions are administered under
applicable tariffs or contracts, and are already Registered Entities. Part of NERC’s effort should include
defining the line between a BES asset that is used to deliver power and an End User asset that's sole
purpose is to serve the End User's load. The NERC Functional Model includes a vague definition of End-use
Customer. The problem is determining the scope of an end-use device. If an industrial company owns a 138
kV to 13.8 kV transformer that feeds its plant, is that an end-use device or a transmission asset that is used to
transmit power to the low voltage distribution network within the manufacturing facility? Any work to revise
the definition of the BES should also include a clarification of its boundaries. We believe that NERC should
not expand the scope of the BES to include assets within end-use customer's private use networks. (See our
recommendation #2 above)
8. An Additional BES Principle Should be that BES Elements and Facilities be Limited to Only Functions
Currently Specified in the NERC Functional Model (Version 5).NERC’s development of the revised BES
definition and exclusion/inclusion criteria and processes should be limited to functions specified in the NERC
Functional Model (Version 5).
9. NERC is Encouraged to Propose a “Different Solution” That is as Effective as, or Superior to, the
Commission’s Proposed Approach. The Proposed Principles for the Exclusion of Elements and Facilities
from the BES Should Include a Process for Categorical Exclusion Based on Common Physical
Characteristics.The Commission stated in Order No. 743 regarding its proposed revision of the BES definition
(and presumably the exclusion/inclusion criteria and processes):"... NERC may propose a different solution
that is as effective as, or superior to, the Commission’s proposed approach in addressing the Commission’s

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Question 11 Comment
technical and other concerns so as to ensure that all necessary facilities are included within the scope of the
definition." ¶ 16.In addition, specific to the exclusion of Elements and Facilities from the BES, the Final Rule
did not adopt the exclusion process proposed in the NOPR (i.e., facility-by-facility review). In the Final Order,
FERC directed NERC to develop an exclusion process “with practical application that is less burdensome
than the NOPR proposal.” FERC has also allowed NERC to consider concerns (mainly industrials’) regarding
“exclusion categories” in developing the exclusion process and criteria. ¶ 120.ELCON interprets the
Commission’s statements to mean that the agency is open to developing a more efficient compliance
process, including processes that minimize unnecessary regulatory burdens on potential Registered Entities
and the administrative costs of NERC and RE compliance operations. In the spirit of “streamlining” NERC
and the REs’ review of smaller entities, ELCON recommends the addition of a principle on the exclusion of
Elements and Facilities from the BES that encourages a process for categorical exclusion of entities based on
common physical characteristics.

Response: The SDT considers the proposed BES definition in the SAR as a starting point for SDT consideration. As it develops a modified BES definition and
associated criteria, it is carefully reviewing and considering the NERC Statement of Compliance Registry Criteria. The SDT has considered your comments in
developing a modified BES definition and associated criteria. The SDT appreciates these observations and believes that our new definition with the exclusion and
inclusion designations will provide a bright-line definition, clarity, and consistency across the regions while addressing most, if not all, of the provided suggestions.
This definition will eliminate regional discretion and any questions on this bright-line definition will be handled through a revision to the Rules of Procedure by a
separate team in an effort parallel to the development of this BES definition. NERC will follow the due process established for changes to the Glossary of terms.
This new definition addresses radial Loads, generation, and local distribution networks.
Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear
Group, LLC, (“CENG”)

March 30, 3011

Yes

Paragraph 115 from the BES final rule states “NERC should develop an exemption process that includes
clear, objective, transparent, and uniformly applicable criteria for exemption of facilities that are not necessary
for operating the grid. The ERO also should determine any related changes to its Rules of Procedures (ROP)
that may be required to implement the exemption process, and file the proposed exemption process and rule
changes with the Commission.” This section does not direct NERC to use the ROP modification process to
develop “separate” exemption criteria. It only recommends that NERC modify its ROP for any related changes
to implement the exemption process, not the exemption criteria itself. The compliance implications and
technical nature of such criteria make it imperative that industry input be considered in a transparent
stakeholder process. It is appropriate for NERC to develop aspects such as the administrative management,
the role and interaction of the regions, an appeal process, etc. However, due to the technical aspects of BES
operation, the drafting team members are best suited to devise criteria for non-BES facilities to warrant
inclusion in the BES.As currently proposed, the definition language and the exception criteria are not being
developed in the properly coordinated fashion. This should change. Further, Constellation is not convinced
that creation of a definition and an exception process is the best course to respond to the FERC directives. In
question 12, an alternative approach is proposed.

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City Water Light and Power
(CWLP) - Springfield, IL

Yes

CWLP feels, again, that the lack of a firm, detailed administrative process for exemptions hampers the
proposed BES definition in meeting the intent of Order 743

American Transmission company

Yes

However, ATC does not want to appear to endorse any separate BES Definition Exception and Inclusion
Processes until one has been clearly proposed and meets the reliability-related intent of the Order 743
directives. Furthermore, ATC believes the separate Exception and Inclusion Processes should be subject to
the same Standards Development review and approval process as the associated BES definition.

MRO's NERC Standards Review
Subcommittee

Yes

However, NSRS does not want to appear to endorse any separate BES Definition Exception Process until
one has been clearly proposed and meets the reliability-related intent of the Order 743 directives.
Furthermore, NSRS believes the separate Exception Process should be subject to the Standards
(“Definition”) Development Process as the associated BES definition.

Response: The SDT is developing the BES definition and associated criteria. A separate Rules of Procedure (ROP) team will develop the procedures for seeking
an exception that is not clearly addressed by the definition and criteria. The SDT will closely coordinate with the ROP team.
APPA

Yes

I agree that the proposed definition meets the intent of Order 743. However, the separate development of
exception criteria ouside of the standards development process does raise concerns. See response to
Question 12.

Response: See response to Q12.
Pepco Holdings Inc.

See comments above and below.

Response: See responses above and below.
Hydro-Québec

For the Canadian entities, it is important to consider that the definition of the Bulk Electric System must also
be approved by the Canadian regulators.

Response: The SDT is aware of the issues related to Canadian utilities and regulators and will consider those as it develops a modified BES definition and
associated criteria.
Utility Services

March 30, 3011

Yes

However, Utility Services would like to suggest alternative definitions for Bulk Electric System and BES
Exemption Process. We have presented our proposed definitions in the answer to Question 1. While the
proposed definition may meet the Order, Utility Services believes that the definition can be made cleaner and

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easier to read

Response: See response to Q1.
United Illuminating Company

Yes

Order 743 focused on the definition of BES and the exemption process. Although not part of the SAR or
ORDER 743, UI suggests NERC provide an explanation in the implementation plan of the impact on the
registry criteria. Will the Registry Criteria serve as another filter for identifying which entities willbe part of
Compliance Monitoring

Response: As the SDT develops a modified BES definition and associated criteria, it will be carefully reviewing and considering the NERC Statement of
Compliance Registry Criteria.
Northeast Power Coordinating
Council

Yes

Orange and Rockland Utilities,
Inc.

Yes

A qualified “Yes”. The BES exemption process has not yet been written. So, it is somewhat difficult to know
in advance that this approach meets the reliability-related intent of the directives in Order 743. While in
general agreement with this conclusion, there is concern that the BES definition and BES exception process
do not yet adequately address a “point-of-demarcation” between the BES Facilities and Elements and nonBES facilities and elements (lower case). Propose to add two new terms for the NERC Glossary of Terms in
our reply to Question 13, in order to identify a point-of-demarcation and more fully respond to this question.

Response: The SDT will consider your concerns in its deliberations as it moves forward in revising the definition. .
City of Anaheim

Yes

IRC Standards Review
Committee

Yes

Bonneville Power Administration

Yes

FirstEnergy Corp

Yes

SERc OC Standards Review
Group

Yes

LCRA Transmission Services
Corporation

Yes

March 30, 3011

The definition is critically dependent on the detailed exemption/inclusion criteria and process, which has not
been developed.

However, BES definition changes are needed to establish a bright-line for the BES.

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Yes or No

American Municipal Power

Yes

North Carolina EMC

Yes

ReliabilityFirst

Yes

on behalf of Teck Metals Ltd.

Yes

Southern California Edison
Company

Yes

on behalf of Catalyst Paper
Corporation

Yes

City of Anaheim

Yes

Glacier Electric Cooperative

Yes

ISO New England Inc.

Yes

Snohomish County PUD

Yes

City of Austin dba Austin Energy

Yes

The Dayton Power and Light

Yes

March 30, 3011

Question 11 Comment

A single and uniform definition that includes exemption criteria and an exemption process must be the result
of this effort. Then this material must be consistently used by all of the Regional Entities across the ERO in
order to achieve the directives set forth in Order 743.

I have not seen the BES Definition Exception Process, but I trust it will be an accurate method.

While Snohomish believes FERC substantially overstepped its statutory authority in Order No. 743 for the
reasons set forth in its comments and petition for rehearing filed with FERC in that docket, we nonetheless
support FERC's underlying goal to assure reliable operation of the interconnected bulk transmission system.
Within the constraints imposed by FERC, we believe the approach of defining the BES and then establishing
an exemption process to exclude Facilities and Elements that are not necessary for the reliable operation of
the interconnected bulk transmission system should meet FERC's reliability goals while mitigating the
excessive compliance costs that will arise from blunt application of a 100-kV brightline threshold. Nothing
stated in these comments, however, should be interpreted as withdrawing or waiving any objection
Snohomish has made to Order No. 743.

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Yes or No

Question 11 Comment

Company
ITC Holdings Corp

Yes

As long as the PRC023 Critical criteria is used for below 100 kV is used for inclusion.

BGE

Yes

No comment.

Southern Company

Yes

The framework appears to be in place to respond to the directive; however, the details of the “exemption
process” remain to be fully developed.

Idaho Power

Yes

Independent Electricity System
Operator

Yes

Clark Public Utilities

Yes

The definition is critically dependent on the detailed exemption/inclusion criteria and process, which has not
been developed. We advocate that the revised BES definition and the exemption/inclusion process and
criteria be developed at the same time and preferably by the same drafting team to ensure consistency in
approach, since these issues are very closely interrelated.

Response: Thank you for your response. Please see the revised definition –it includes a detailed list if inclusions/exclusions to minimize the need to use the BES
Exception Process.

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12. If you have a proposal for an equally efficient and effective method of achieving the reliability- related intent of the directives
in Order 743, please provide your proposal here.
Summary Consideration: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion
designations (included within the body of the definition), will provide a bright-line definition, clarity, and consistency across the regions while
addressing most, if not all, of the provided suggestions. This definition will eliminate regional discretion and any questions on this bright-line
definition will be handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES
definition. NERC will follow the due process established for changes to the Glossary of terms. This new definition addresses radial Loads,
generation, and local distribution networks. Furthermore, the SDT has utilized many resources to provide this clarity including the Compliance
Registry Criteria and the WECC BESDTF recommendations.

Organization

Question 12 Comment

Public Service Enterprise Group
Company

The BES definition impacts many standards and has been the source of misunderstanding with subsequent requests for
interpretations. In this one case, a stand alone interpretive descriptive document with clear lines of demarcation using
example one lines and associated notes in lieu of a three sentence description that attempts to describe all elements of the
BES could be considered.

Manitoba Hydro

Manitoba Hydro supports a true bright-line threshold that includes all facilities operated at or above 100kV except defined
radial facilities. There should be no regional differences in the definition or exemption process and the regional discretion
should be removed from the BES definition.

ReliabilityFirst

The ERO and the Regional Entities should develop and propose the common BES definition and exemption process, submit
it to FERC, and allow for the FERC process, whereby the industry provides its comments, etc., to be used to finalize this
definition, exemption process and criteria.

United Illuminating Company

The BES definition should be very clear and simple.

ITC Holdings Corp

Exclusion criteria should be determined at the NERC level and implemented continent wide by the Regions, rather than
allowing each Region to come up with their own policy and criteria on exclusions.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
MRO's NERC Standards Review

March 30, 3011

Proposed Bulk Electric System definition: Facilities operated at voltages of 100 kV or higher necessary to support the

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Organization
Subcommittee

Question 12 Comment
interconnected transmission network reliability (Note see the NERC approved exemption process for Facilities that are and
are not considered part of the BES).
Rational:1. NERC defines Facilities as “a set of electrical equipment that operates as a single BES Element. Since Element
is part of the Facilities NERC definition it is not needed to be repeated.
2. Section 30 of FERC Order 743 “all facilities operated at or above 100kV” should be included in the bright-line criteria.
3. This new language eliminates the ambiguity as directed in FERC Order 743 whereby the Region cannot establish other
bright-line criteria for what the BES is.
4. This reinforces foot note 41 by stating exactly what “reliability” of the BES needs to be reinforced. The “interconnected
transmission reliability should also be used in any “exemption criteria” that the SDT formulates in the future.
5. The removal of bulk power system reliability is still a somewhat ambiguous term and FERC has stated that the BPS
definition is not within the scope of this FERC Order.
6. Note that the NERC defined term of Facility contains the word BES. So, as written, a Facility is energized at 100kV or
above. The capitalized word of Facility cannot be used in the inclusion process since those facilities would be below the
100kV level.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
Section 30 of FERC Order 743 directs the ERO to include exclusions as deemed appropriate, such as radials.
The SDT agrees that the term BPS is not in scope and also stipulates that this work is focused on defining the BES.
The SDT recognized the problem with Facility and has corrected that in the revised work.
City of Anaheim

Transmission elements serving radial load, radial distribution systems, or non-GO/GOP generation connected to such radial
lines and excluded from BES; provided, however, to eliminate any reliability gaps, such radial transmission elements should
be classified as "Distribution" equipment subject to DP standards, and the PRC and vegetation management standards
should be made applicable to Distribution Providers and this equipment. This is consistent with the NERC Reliability
Functional Model and is more efficient than requiring TO/TOP registration for radial transmission facilities that function as
Distribution and are not required for the reliable operation of the BES.
Transformers with secondary windings of 100kV or less should not be part of the BES if they feed radial load or radial
distribution systems; provided, however, to eliminate any reliability gaps, such transformers should be classified as
"Distribution" equipment subject to DP standards, and the PRC and vegetation management standards should be made
applicable to Distribution Providers and including this equipment. This is consistent with the NERC Reliability Functional

March 30, 3011

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Question 12 Comment
Model and is more efficient than requiring TO/TOP registration for radial transmission facilities that function as Distribution
and are not required for the reliable operation of the BES.
Unless the generator is required to maintain BES reliability, i.e. black start, etc., the GSU and gen tie should be excluded
from the BES; provided, however, to eliminate any reliability gaps, such generation-tie equipment should be classified as
"Generator" equipment subject to GO/GOP standards, and the PRC and vegetation management standards should be made
applicable to GO/GOPs and this equipment. This is consistent with the NERC Reliability Functional Model and is more
efficient than requiring TO/TOP registration for non-critical generation-tie transmission elements that are not required for the
reliable operation of the BES.

Florida Municipal Power Agency
Transmission Access Policy
Study Group

FMPA proposes that the BES be defined as:In general, the Bulk Electric System includes all Transmission Elements
operated at voltages of 100 kV or higher, and all generation resources registered pursuant to the Statement of Compliance
Registry Criteria. Radial Transmission Elements serving only load with one Transmission source are generally not included
in this definition. A radial Transmission Element may be considered as “serving only load” for purposes of the foregoing
general exclusion even if it connects generation, so long as that generation is not registered pursuant to the Statement of
Compliance Registry Criteria. An Element that nominally meets the general BES criteria, but which an entity demonstrates,
on a case-by-case basis, is not necessary for operating the interconnected electric transmission network, shall be exempted
from the BES pursuant to the NERC exemption process. An Element that does not nominally meet the general BES criteria,
but which NERC demonstrates, on a case-by-case basis, is necessary for operating the interconnected electric transmission
network, shall be included in the BES pursuant to the NERC inclusion process.
There should be an exemption process with clear criteria pursuant to which an entity can attempt to demonstrate that
although a particular Element is nominally part of the BES, it is not necessary for operating the interconnected electric
transmission network. Elements for which an exemption is granted would be considered non-BES. FMPA’s proposed
criteria and exemption process are discussed in FMPA’ comments on BES exemption process submitted today.
There should be an inclusion process with clear criteria pursuant to which NERC may show, on a case-by-case basis, that
although a particular non-BES Element is nominally not part of the BES, it is necessary for operating the interconnected
electric transmission network and should therefore be considered part of the BES. FMPA’ proposed criteria and inclusion
process are discussed in FMPA’ comments on BES exemption process submitted today.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
This new definition addresses radial Loads.
PacifiCorp

March 30, 3011

See respons #11.

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Question 12 Comment

Response: See response to Q11.
PPL Energy Plus
LG&E and KU Energy LLC

The determination of whether or not a facility is part of the BES should consider FERC’s Order 743 paragraph 73 which
clearly states the network nature of the BES. FERC states that the ability to overload parallel facilities (Order 743 paragraph
73) is a key feature of an element in the BES.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition. Elements such as
Transmission lines are included and excluded in the BES based on this bright-line definition. Furthermore, entities will need to continue to meet all the
performance of Facilities per the applicable NERC standards.
Competitive Suppliers

Initial EPSA suggestions for meeting the directives for Order 743 are included in the answer to question 11. Additionally,
EPSA recommends that the drafting team can benefit from utilizing the Compliance Registry Criteria in the BES definition.
By using the classifications found in the Compliance Registry Criteria - Section III (Rules of Procedure Appendix 5B), of
which much is alluded to in the questions included on this comment form, can provide a useful basis to create a
comprehensive, revised BES definition. Further, competitive suppliers recommend that the BES drafting team incorporate the
criteria directly into the revised BES definition, replacing the term "bulk power system" in each criteria with "100 kV."
Structuring the revised BES definition to clarifying that aligns with the Compliance Registration criteria will ensure against
complex exemption process as well as eliminate the need for Section III of the Registry Criteria.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition. Furthermore, the SDT has
utilized many resources during the development of this definition including the Compliance Registry Criteria.
NERC Staff

Please see additional comments at the end of this document. .

Entergy Services

Please see our response to Q13 below.

Response: See response to Q13.
NextEra Energy Inc.

March 30, 3011

Based on the information posted by the North American Electric Reliability Corporation (NERC) on its plans to address
Order No. 743 of the Federal Energy Regulatory Commission (FERC), NextEra Energy, Inc. (NextEra) believes that NERC
(and associated drafting teams) should slightly modify its direction to more closely align with FERC’s proposed framework.
In Order No. 743, at paragraph 30, FERC stated that:The Commission believes the best way to address these concerns is to

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Question 12 Comment
eliminate the regional discretion in the ERO’s current definition, maintain the bright-line threshold that includes all facilities
operated at or above 100 kV except defined radial facilities, and establish an exemption process and criteria for excluding
facilities the ERO determines are not necessary for operating the interconnected transmission network. It is important to
note that Commission is not proposing to change the threshold value already contained in the definition, but rather seeks to
eliminate the ambiguity created by the current characterization of that threshold as a general guideline.FERC also provided
NERC with the opportunity to propose an alternative approach. NextEra believes, however, that FERC’s proposed
framework is appropriately designed to enhance the definition of the Bulk Electric System (BES) in the NERC glossary, and
to separately develop a process to apply for and receive, as appropriate, an exemption from the BES definition. Although it
appears that NERC and the drafting teams may also be inclined to proceed as suggested by FERC, there are indications in
the questionnaire and BES concept paper that there may be some thought to deviating from FERC’s proposal. A review of
the information posted by NERC seems to indicate NERC’s intention to have a drafting team develop a revised BES
definition via the standards development process (i.e., Appendix 3A of the NERC Rules of Procedure).
It also seems that NERC is interested in assigning a “working group” to separately develop an exemption process that would
be implemented as a new process in the NERC Rules of Procedure. NextEra agrees with this approach. NextEra’s
concerns stem from some of the words in the proposed BES definition, the BES concept paper and the questions asked,
which seem to suggest an unnecessarily overlapping definition and exemption process, and a movement toward an
exemption process based on categories rather than criteria.
Thus, to address these concerns NextEra proposes the following enhancements to more clearly separate the BES definition
and exemption process, and align each more closely with Order No. 743. As for the BES definition, NextEra encourages the
drafting team to solely focus its efforts on the definition. The currently posed revised BES definition reads as follows:Bulk
Electric System: All Transmission and Generation Elements and Facilities operated at voltages of 100 kV or higher
necessary to support bulk power system reliability. Elements and Facilities operated at voltages of 100kV or higher, including
Radial Transmission systems, may be excluded and Elements and Facilities operated at voltages less than 100kV may be
included if approved through the BES definition exemption process.NextEra maintains that this is not the correct starting
point, nor consistent with Order No. 743 or the other material posted by NERC, that suggests a more definitive separation of
the BES definition from the exemption process. Thus, NextEra proposes that the definition be revised to read as follows:Bulk
Electric System: All Transmission and Generation Elements and Facilities operated at voltages of 100 kV or higher, unless a
Transmission or Generation Element or Facility has been exempted pursuant to the exemption process set forth in the NERC
Rules of Procedure. This proposed BES definition more clearly and cleanly separates the BES definition from the
exemption process. It also does not add unnecessary qualifiers or verbiage that may result in confusion.
NextEra is also concerned that the working group assigned to the exemption process may initially be more focused on
developing categories, instead of an exemption process and associated criteria. Given the unique circumstances of the
interconnected BES, including system topology, NextEra does not believe that it would be a productive exercise for the
exemption working group to focus on types, groups or categories of equipment; instead, its efforts should focus on
developing specific objective criteria to judge the reasonableness of a request or application for an exemption. This
approach also seems more in line with FERC’s statement in Order No. 743 at paragraph 115: NERC should develop an

March 30, 3011

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Question 12 Comment
exemption process that includes clear, objective, transparent, and uniformly applicable criteria for exemption of facilities that
are not necessary for operating the grid. The ERO also should determine any related changes to its Rules of Procedures
that may be required to implement the exemption process, and file the proposed exemption process and rule changes with
the Commission. The challenges of developing an exemption process also include ensuring than any applicant is afforded
due process and balanced decision-making, as required by section 215 of the Federal Power Act. Thus, the exemption
process must address legal, regulatory and technical issues. Accordingly, NextEra requests that NERC assemble a working
group (perhaps via the Standards Committee) to develop the exemption process that is comprised of stakeholders with legal,
regulatory and technical experience. Without this balance of disciplines, NextEra is concerned that a technical-heavy
working group will attempt to develop a “fix,” instead of a process whereby applicants may request an exemption, and have
that exemption judged by specific criteria and pursuant to a process that affords due process and balanced decision-making.
It is not clear whether an exemption working group has already been assembled. If it has, NextEra requests that NERC
consider restructuring of the group consistent with NextEra’s proposal.In summary, NextEra requests that the BES definition
drafting team adopt NextEra’s proposed definition of BES. NextEra also requests that NERC assemble a cross-functional
working group to develop an exemption process based on specific criteria (rather than categories), and a process that affords
applicants due process and balanced decision-making.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
The new definition removes the term “general” and provides more specific wording.
NERC will follow the due process established for changes to the Glossary of Terms.
Pepco Holdings Inc.

The RFC BES Definition and Clarifications could be used as a model for definition. It specifically incorporates additional
detail of what is included and what is excluded.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. The SDT has utilized many resources during the development of this definition including the work done by
RFC.
Indeck Energy Services

March 30, 3011

The BES definition should be the same as the FPA Bulk Power System definition! It will not be a bright line, like >100 kV. It
will focus NERC's efforts on the real reliability issues rather than chasing many small entities through paper exercises that
make someone feel that they are punishing unreliable behavior. Such exercises over the last 3 years have not measurably
improved reliability, in fact, NERC doesn't seem to know how to measure reliability in its purest form. It can monitor
operating and planning parameters of the BPS, but none of them truly measure reliability. The July, 2010 FERC Technical
Conference showed how far off NERC is when a FERC Commissioner had to state that preventing "loss of load" does not
define reliability. As referred to in the FPA, preventing cascading outages defines reliability. How does having a Sabotage

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Question 12 Comment
and Bomb Threat procedure at a 100 MW wind farm prevent cascading outages?

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions.
Snohomish County PUD

Snohomish has worked extensively with the WECC Bulk Electric System Task Force ("BESDTF") over the last two years
and, while we disagree with certain details of the BESDTF approach (in particular, we believe a 200-kV threshold rather than
a 100-kV threshold more appropriately reflects conditions in the Western Interconnection), we believe the approach
developed by the BESDTF will achieve the reliability goals laid down by FERC in Order No. 743 while at the same time
excluding facilities from the BES that have no meaningful impact on the reliable operation of the bulk transmission system,
which thereby minimizes unnecessary compliance costs. Accordingly, we commend the work of the BESDTF to the
standards drafting team. Given the relatively short deadline imposed by FERC for completion of work on the revised
definition, we believe it will be necessary for the standards drafting team to rely on existing work of groups like the BESDTF
rather than re-inventing the wheel.

Central Lincoln

The WECC Bulk Electric System Definition Task Force has made significant progress in defining the BES. We encourage
the SAR to look at the work they’ve done.

PUD No.1 of Clallam County
PNGC Power
Blachly-Lane Electric Co-op
Clearwater Power Co.
Douglas Electric Cooperative
Central Electric Cooperative, Inc.
(Redmond Oregon)
Raft River Rural Electric
Cooperative
Northern Lights Inc.
Salmon River Electric

March 30, 3011

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Question 12 Comment

Cooperative
Okanogan Country Electric
Cooperative
Lost River Electric
Lane Electric Cooperative
Coos-Curry Electric Cooperative
Consumer's Power Inc.
Umatilla Electric Co-op
West Oregon Electric
Cooperative
Lincoln Electric Cooperative
Fall River Electric Cooperative
Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. The SDT has utilized many resources during the development of this definition including the work done by
the WECC BESDTF.
The Dow Chemical Company

March 30, 3011

As discussed above, the proposed definition of BES is flawed because it fails to expressly exclude local distribution facilities.
It is also confusing, particularly with respect to its use and application of the 100 kV standard. As the definition is written, the
100 kV standard would apply to both transmission and generation facilities - i.e., “All Transmission and Generation Elements
and Facilities” - even though voltage is primarily a measure of transmission capability with little applicability to generation.
Such a standard would, depending on how it is applied, be inconsistent with the generation criteria already set forth in the
NERC Statement of Compliance Registry Criteria. In the case of Dow and Union Carbide Corporation, these criteria
establish a generally-applicable 20 MVA threshold applicable to exports of electricity to the transmission grid from individual
generating units and a 75 MVA threshold applicable to exports of electricity to the transmission grid from generating
plants/facilities.

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The BES definition should not change the currently applicable 20 MVA / 75 MVA generation size threshold applicable to
generation facilities or the manner in which that threshold is currently applied, with behind-the-meter cogeneration facilities
evaluated based on the net capacity actually provided to the grid. The best approach might be to define BES as simply
consisting of three types of facilities: (1) BES Generation; (2) BES Transmission; and (3) BES Protection and Controls.
Those terms would then be defined by reference to criteria set forth in NERC’s Statement of Compliance Registry Criteria.
For example, the term BES Generation would be defined as individual generating units or generating plants or facilities that
meet the criteria set forth in the Statement of Compliance Registry Criteria.
This approach would provide greater clarity. It would also generally preserve the status quo, which is particularly important in
the context of generation. NERC and the Regional Entities have already made significant progress in deciding what
generators should be subject to compliance with mandatory reliability standards and what generators should be exempted.
Nothing in Order No. 743 requires that those determinations be revisited.
The issues raised in Order No. 743 will, however, likely require revisions to the transmission-related criteria set forth in
NERC’s Statement of Compliance Registry Criteria. Dow is not in principle opposed to the retention of the 100 kV standard
that is already set forth in the registry criteria, but it must be clarified to apply to facilities that perform a transmission function
while excluding facilities that perform a local distribution function. The criteria should also preserve the “material to reliability”
standard that is set forth in the proposed definition, i.e., that facilities must be “necessary to support bulk power system
reliability” in order to be considered part of the BES. This standard is particularly important in the context of interconnection
facilities that connect generation resources to the transmission grid. FERC has recognized that such facilities do not neatly
qualify as either transmission facilities or distribution facilities, but that such facilities should nevertheless be considered part
of the BES and subject to mandatory reliability standards only if they are determined to be “material to the reliability of the
bulk power system.” See New Harquahala Generating Company, LLC, 123 FERC ¶ 61,173 at P 44 (2008), clarified, 123
FERC ¶ 61,311 (2008).Based on these considerations, the criteria set forth in the NERC Statement of Compliance Registry
Criteria should be structured so as to define “BES Transmission” as including: (1) facilities that perform a transmission
function, that are operated at voltages of 100 kV or higher, and that are materially necessary to support bulk power system
reliability; and (2) any other facility that performs a transmission function that is found to be materially necessary to support
bulk power system reliability. To the extent an interconnection line from a BES Generation facility is materially necessary to
support bulk power reliability, that interconnection line should be treated as part of the BES Generation facility, rather than a
BES Transmission facility. Such a structure would preserve the bright-line 100 kV standard preferred by FERC, while
defining and applying the standard in a manner that appropriately preserves the distinctions that are recognized for local
distribution and interconnection facilities, and that ensures that all facilities that materially affect reliability are covered by the
standards.
Of course, once a definition for BES Transmission is adopted, the next step is to develop a process for applying that
definition so as to identify specific facilities that qualify as BES Transmission facilities, and that are subject to mandatory
reliability standards. Owners and operators should be afforded an opportunity in the process to demonstrate that their
facilities should be excluded because they either: (1) perform a distribution function; (2) are not materially necessary to
support bulk power system reliability; or (3) are included as part of BES Generation facilities. Such an opportunity must be

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Question 12 Comment
provided before facilities become subject to mandatory BES Transmission reliability standards.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
This new definition addresses radial Loads and generation.
Furthermore, the SDT has utilized many resources to provide this clarity including the Compliance Registry Criteria.
Utility Services

We believe our answers to the questions above provide for sufficient means to meet the intent of Order 743.

Response: Please see responses to questions above.
BGE

It is preferable that non-BES facilities be excluded by the definition language rather than to define BES broadly and require
non-BES facilities go through an exception process. For those special case facilities that may exist, an “opt-in” evaluation
could be conducted. We find that this approach to revising the BES definition would satisfy the FERC directives in Order
743 by encompassing all facilities necessary for operating an interconnected electric transmission network into a national
level, bright-line definition. This approach will improve the clarity and consistency of the BES definition for application by
Industry and NERC as well as avoiding creation of a potentially cumbersome exception process. The rules of procedure
process may be used to develop the “opt-in” process that would replace the proposed exception concept; however, the
drafting team, perhaps in collaboration with regional entities, should develop any opt-in criteria needed for the process. It is
appropriate for NERC to develop aspects such as the administrative management, the role and interaction of the regions, an
appeal process, etc. However, due to the technical aspects of BES operation, the drafting team members are best suited to
devise criteria for non-BES facilities to warrant inclusion in the BES.

Constellation Power Source
Generation, Inc. (“CPSG”) filing
on behalf of Constellation
Energy Group, Inc. (“CEG”),
Constellation Energy
Commodities Group, Inc.
(“CCG”), Constellation Energy
Control and Dispatch, LLC
(“CDD”), Constellation
NewEnergy, Inc., (“CNE”) and
Constellation Energy Nuclear

Constellation recognizes the value in clarifying the Definition of Bulk Electric System into a bright line threshold consistently
applied across the regions. However, we are concerned that the current approach of a simple, all inclusive definition coupled
with an exception criteria and process will not draw on the fundamentals underpinning the existing definition and create a
cumbersome and unnecessary exception process. As an alternative, we propose that the standard drafting team utilize the
Compliance Registry Criteria-Section III (Rules of Procedure Appendix 5B) along with definition threshold language (such as
100 kV) to develop a more comprehensive definition. Further, we propose that the BES drafting team incorporate the criteria
directly into the revised BES definition, replacing the term “bulk power system” in each criterion with “greater than 100 kV.”
This will make for a longer definition, but by aligning the facilities requiring registration as those defined as BES, the definition
will more clearly determine the line between BES and non-BES. It is preferable that non-BES facilities be excluded by the
definition language rather than to define BES broadly and require non-BES facilities go through an exception process.
Ideally, this approach can eliminate the need for an onerous exemption process as well as eliminate the need for Section III
of the Registry Criteria in the Rules of Procedure. For special case facilities deemed non-BES by the revised definition that

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Organization
Group, LLC, (“CENG”)

Question 12 Comment
may warrant consideration for inclusion, an “opt-in” evaluation could be conducted. The rules of procedure process may be
used to develop the “opt-in” process that would replace the proposed exception concept; however, the drafting team,
perhaps in collaboration with regional entities, should develop any opt-in criteria needed for the process. Again, it is
appropriate for NERC to develop aspects such as the administrative management, the role and interaction of the regions, an
appeal process, etc. However, due to the technical aspects of BES operation, the drafting team members are best suited to
devise criteria for non-BES facilities to warrant inclusion in the BES.We find that this approach to revising the BES definition
would satisfy the FERC directives in Order 743 by encompassing all facilities necessary for operating an interconnected
electric transmission network into a national level, bright-line definition. This approach will improve the clarity and
consistency of the BES definition for application by Industry and NERC as well as avoiding creation of a potentially
cumbersome exception process.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition. Furthermore, the SDT has
utilized many resources to provide this clarity including the Compliance Registry Criteria.
Springfield Utility Board

See suggested language in the comment to Question 11. (This e-survey process is confusing as one does not know what
will be asked to know the right context to provide a response. Can you please post all questions in advance of an entity
walking through the survey. Also - seeing the responses at the conclusion of the survey is great, but it would be convenient
to be able to edit responses at the conclusion as well)

Response: See response to Q11.
The SDT has no control over the logistics of the system for providing comments. However, a Word version was posted on the project web page for review.
APPA

The Concept Paper states at page 1 that in Order 743, FERC directed NERC to do the following:
A. Utilize the NERC Standard Development Process to revise the definition of Bulk Electric System (BES) contained in the
NERC Glossary of Terms.
B. Develop a single Implementation Plan to address the application of the revised definition of the BES and the
implementation of the exemption process.
C. Utilize the NERC Rules of Procedure to develop and implement an ‘exemption process’ used to identify Elements and
Facilities which will be included in or excluded from the BES.
The Concept Paper continues to state that: This project will address items ‘A’ and ‘B’ and will coordinate efforts between the
Standard Drafting Team (SDT) and the group working to develop the exemption process for inclusion in the NERC Rules of
Procedure to ensure that the revised BES definition and exemption process result in an accurate, repeatable, and

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Question 12 Comment
transparent method for the identification of BES and non-BES Elements and Facilities.
APPA agrees that the standards process must be used to develop the revised BES definition and that NERC has been
directed to use its Rules of Procedure process to develop an ROP-based procedure to implement an
exemption/exclusion/inclusion process. However, the FERC directives do not speak to how and by whom the technical
methodology, study criteria and data requirements for requesting and receiving approval for an exemption should be
developed.
To the maximum extent possible, subject to time constraints imposed by FERC, this inherently technical methodology needs
to be developed through the NERC standards development process, in conjunction with development of the revised definition
of BES. Separate development will significantly hamper development of industry consensus in support of the revised BES
definition and the yet to be developed ROP modifications for the exemption process.
The most critical question is how do we arrive at a commonly agreed upon, widely accessible, transparent, and replicable
continent-wide methodology to determine whether each specific facility is or is not “necessary to operate an interconnected
electric transmission network” to quote from paragraph 16 of Order 743. While each region may have a separate model
reflecting its topology and system performance characteristics, a continent-wide approach is required to address FERC
concerns about inconsistency across regions that are not the result of physical differences.
The statutory definition of the term bulk-power system defines the outer extent of facilities that can be included (at least
within the United States) within the NERC definition of BES. FPA section 215(a)(1) states that the bulk-power system
includes “(A) facilities and control systems necessary for operating an interconnected electric energy transmission network
(or any portion thereof); and (B) electric energy from generation facilities needed to maintain transmission system reliability.”
Further, the term BPS “does not include facilities used in the local distribution of electric energy.” [emphasis added].Similarly,
“reliable operation” is defined at 215(a)(4) to mean “operating the elements of the bulk-power system within equipment and
electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such
system will not occur as a result of a sudden disturbance, including a cybersecurity incident, or unanticipated failure of
system elements.” These definitions appear to point to two basic questions for the classification of each facility or element as
BES or non-BES:
1. Is the facility or element necessary for reliable operation because it contributes significant capability to the interconnected
transmission network?
2. Will the misoperation or unanticipated failure of the facility or element adversely affect the reliable operation of the
interconnected transmission network? APPA suggests that the BES SDT or separate study teams should be directed to
establish the outline for this study methodology.
APPA further suggests that BES sub-teams be established to address the Proposed BES Criteria in the Concept Paper.
Separate sub-teams should be established to address detailed system configuration and study methodology issues affecting:

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Question 12 Comment
1. Radials serving load (with and without distribution voltage generation not subject to registration)
2. Other transmission elements that entities seek to include in or exclude from the BES.
3. Generating plant equipment that entities seek to include in or exclude from the BES.
4. Technical issues raised by the FERC Seven Factor Test for Local Distribution Facilities.
Separate sub-teams are appropriate because the study issues are likely to be quite distinct. For example, radials serving
only load do not provide alternative pathways for reliable BES operations, as might some sub-100 kV facilities. Mixing the
two teams together might slow progress on identification of various commonly used radial to load center configurations that
with proper protection schemes do not have the potential to adversely affect the BES. A focused effort on permissible
exclusions of radials serving load is essential to prevent distribution providers from adopting less reliable system
configurations to serve their loads because they are concerned that the preferred configuration will make them subject to
registration as TOs and/or TOPs.
Note that the proposed sub-teams do not necessarily have to be populated by members of the SDT. The new standards
process allows SDTs to gather informal input from a variety of sources. However, development and posting for industry
comment of the minimum acceptable characteristics of the study methodology to be used in the Exceptions Process should
be the responsibility of the BES SDT.
The Comment Form on the Exclusion Process poses reasonable questions and it is my hope that registered entities and
regional entities identify numerous candidate facilities and elements for inclusion or exclusion from the BES, accompanied by
one-line diagrams that lay out each of the permutations for such facilities that are candidates for exclusion/inclusion. These
facilities range from simple radial transmission lines and distribution step-down transformers to 100 kV class distribution
networks that operate radially from the BES. I also hope that entities submit extensive technical documentation to explain
why such facilities should be excluded from or included in the BES.
Good luck!

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
NERC will follow the due process established for changes to the Glossary of Terms.
This new definition addresses radial Loads, generation, and local distribution networks.
Xcel Energy

March 30, 3011

Xcel Energy agrees that the FERC Order 743 directs NERC to modify the Rules of Procedure to include the process for how
an entity or region may initiate an exclusion or inclusion. However, we do not agree that FERC also directed that the actual
criteria and technical specifics for inclusion or exclusion be developed as part of the Rules of Procedure. Furthermore, since

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Question 12 Comment
the inclusion/exclusion criteria is a key component to the definition of BES, we feel the criteria should be treated as part of
the definition development and developed in the same manner as the definition itself. (Preferably by the same drafting
team.)

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions. This definition will eliminate regional discretion and any questions on this bright-line definition will be
handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the development of this BES definition.
NERC will follow the due process established for changes to the Glossary of Terms.
City of Redding

Please consider the WECC Bulk Electric Defination Task Force work to date.
See Attachment 1 at the end of this document.
See Attachment 2 at the end of this document.

Response: The SDT appreciates these observations and believes that our new definition with the exclusion and inclusion designations will provide a bright-line
definition, clarity, and consistency across the regions that will address many, if not all, of the issues in the provided examples. This definition will eliminate regional
discretion and any questions on this bright-line definition will be handled through a revision to the Rules of Procedure by a separate team in an effort parallel to the
development of this BES definition.
Furthermore, the SDT has utilized many resources to provide this clarity including the Compliance Registry Criteria and the work in the WECC BESDTF
recommendations.

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13. Please provide any other information that you feel would be helpful to the drafting team working on the definition of BES.
Summary Consideration: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which
consists of a core definition that establishes the overall starting point for assessing BES and non-BES Elements. The exception criteria use
the same bright-line criteria to provide further guidance as to whether an Element is considered BES or non-BES. The SDT believes that this
is the best method to address the Commission’s concerns of establishing a bright-line definition of the BES that is clear, unambiguous, and
provides for consistent application across the continent.
The SDT acknowledges the comments and concerns related to the Exception Process and recognizes that the forum for providing these
comments to the NERC Rules of Procedure Team was not established prior to this posting. The revision process for the NERC ROP to
develop the Exception Process will be coordinated by NERC staff and governed by current practice for administering such revisions. All
comments pertaining to the Exception Process, the NERC ROP Team, and the ROP revision process will be forwarded to the appropriate
parties for consideration.
The SDT acknowledges the industry’s concerns surrounding the separation of work to different teams in response to the directives in FERC
Order No. 743. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the
directives in Order No. 743 the decision was made to establish two teams working in close coordination to address the issues related to the
project. The SDT is committed to that close coordination between the development of the core definition of the BES and the exception
criteria by the SDT and the development of the Exception Process by the NERC ROP Team. The goal is to have parallel postings from each
aspect of the project, which will enable the industry to review the entire project ‘package’ at one time and effectively provide comments
simultaneously on the core definition exception criteria with its associated lists of “inclusions” and “exclusions” and the Exception Process.

Organization
Northeast Power Coordinating
Council

Yes or No

Question 13 Comment

a.) Proposed definitions to be added to the NERC Glossary of Terms: BES Exemption Process: The review processes for
(a) excluding or exempting facilities and Elements from the BES that are determined not to be necessary to support bulk
power system reliability (e.g., radial elements), and (b) including Elements operated at voltages below 100 kV that are
determined to be necessary to support bulk power system reliability. By identifying all such BES and non-BES facilities
and elements, the BES Exemption Process will establish the Points-of-Demarcation between Facilities and BES Elements
and non-BES facilities and Elements. Point-of-Demarcation: A physical point and/or electrical connection between
facilities and BES Elements and non-BES facilities and elements, e.g., the upstream terminals of a disconnect switch (or
a buss connection) representing the boundary between a BES supply bus and a non-BES radial feeder. The BES
exemption process has not yet been written. So, it is somewhat difficult to know a priori whether any element, elements or
a group of elements or facilities should or should not be classified as part of the BES definition.
b.) This document uses both “exemption process” and “exception process”. Recommend that the phraseology be
standardized on “exception process” as the exception (not the exemption) can be to include or exclude elements and

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Yes or No

Question 13 Comment

facilities.
c.) It is envisioned that the BES Exception Process will contain 3 sub-processes; one for Exclusion, one for Exemption, and
one for Inclusion. Each sub-process will establish provisions and guidelines for the three different tasks. In order to
ensure consistency across the continent, it is our view that NERC should be the facilitator of these processes. NERC
may choose to have some of these tasks performed at the regional levels through the existing delegation agreements.
d.) The BES Exception Process must be an active and ongoing aspect of the ERO program. With the addition of new or
deletion of existing Transmission and Generation Elements, Facilities, or systems. It needs to be recognized that
Exclusions, Inclusions, and Exemptions might need alteration over time. By establishing appropriate guidelines and
processes, the ERO will be able to monitor and maintain information on what is the Bulk Electric System, or BES.
e.) The exception (exemption) process should clearly address the process and requirements for FERC non-jurisdictional
entities (such as the Canadian entities) with the exception of the interconnections between them and those entities under
FERC jurisdiction, and/or those entities having a direct impact on those interconnections.
f.) Classification of all radial facilities operated at voltages of 100 kV and above as part of the BES by default would be
unnecessary and administratively inefficient, because the operation of all radial facilities do not have a significant
operational impact on the BES. Those radial facilities not having a significant impact should be excluded from the BES. If
they aren’t, it could lead to delays in the review and approval of other exemption requests. As such, the proposed BES
definition should be revised to clearly define what radial Transmission Elements will not be included as part of the BES.
This would be consistent with FERC’s intention expressed in Paragraph 55 of Order 743 to not alter the part of the
approved definition that deals with “radial transmission facilities serving only load”.
g.) Additionally, to ensure a common understanding of the meaning of “radial” and to promote consistency in its application,
“radial” should be defined and added to the NERC Glossary.
Response:
a.) With the proposed revisions to the definition of BES, at this time, the SDT does not contemplate adding any additional definitions beyond BES. In regards
to the term “BES Exception Process’; it has been determined that the process will reside in the NERC Rules of Procedure (ROP) and therefore it seems
logical that the purpose of the process would be defined within the boundaries of the NERC ROP.
b.) The inconsistency of the use of ‘exemption’ vs. ‘exception’ in several documents has been identified by the SDT and the team has determined that
‘exception’ is the proper term to be used in reference to the Bulk Electric System definition and supporting processes.
c.) The ‘Exception Process’ will be developed by the NERC Rules of Procedure Drafting Team while coordinating with the DBES SDT. The ‘Exception
Process’ and the responsibilities associated with the implementation and oversight will be defined by the NERC Rules of Procedure Team. Based on the

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Yes or No

Question 13 Comment

language contained in FERC Order No. 743, there are Commission expectations associated with the process oversight by the ERO and allowances for the
delegation of responsibilities to Regional Entities as appropriate, while ensuring the process is clear and capable of being applied consistently, objectively,
and uniformly across all regions.
d.) The SDT agrees that the Bulk Electric System is dynamic and that the implementation and continued application of the BES Definition and supporting
processes will require active oversight and management to ensure that changing conditions (i.e., operational & new construction) surrounding the Bulk
Electric System will be addressed and result in proper evaluation and identification of BES & non-BES Elements. The current scope of the Standard
Authorization Request (SAR) for Project 2010-17 Definition of Bulk Electric System does not include the development of the ‘Exception Process’. The
‘Exception Process’, including the implementation and continued application of the process will be developed by the NERC ROP Team.
e.) The SDT has established non-jurisdictional representation to address the concerns of the applicable entities (i.e., Canadian entities) in regards to the
application of a continent-wide ‘bright-line’ definition of the Bulk Electric System and the exception criteria listed in the definition. NERC Staff has
determined the needs of the NERC Rules of Procedure Team in regards to the diversity of the membership and the technical expertise required to
appropriately modify the ROP in response to the directives identified in FERC Order No. 743.
f.) The SDT has further developed the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall
starting point for assessing BES and non-BES Elements. The ‘exception criteria’ utilizes the same ‘bright-line’ approach to provide further guidance as to
whether an Element is considered BES or non-BES (i.e., bright-line for identifying Generation Facilities, Radials, etc.). The exception criteria has been
listed in the revised definition of BES.
g.) With the proposed revisions to the definition of BES, at this time, the SDT does not contemplate adding any additional definitions beyond BES.
MRO's NERC Standards Review
Subcommittee

A. What time frame is the SDT considering for the implementation of this definition and process once approved, allowing
enough time for the entities to provide justification, and then make the necessary changes to their internal programs?
B. Recommend the BES SDT be consistent with the generation registration criteria and the Protection System definition and
other documents. For example, what is a “common bus” as stated in the generation registration criteria.
C. Please review and update the concept paper. The concept paper does not specifically call out Transmission Lines above
100 kV as in the BES definition (the proposed definition does, however) and there is a circular exemption criteria in the
concept paper. In criterion #2, it refers to the exemption process "consistent with the criteria". The criteria exempt generating
plant controls and Transmission Elements or Systems that are radial to a load or generator not included in the BES List.
However, the BES list is defined prior to the criteria in the concept paper. Exemption criterion #1 points to BES list elements
#6 and #7, which in turn, refer to the exemption process. But, the exemption criteria never define how to exempt the
elements referred to in #6 and #7.
D. How often would a Registered Entity revisit this Exception Process? NSRS can envision a scenario where they are doing
that every year or two because of the changes in load, generation, and transmission. The process should also allow for

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Yes or No

Question 13 Comment

multi-year distinctions for exceptions. In other words, if a Registered Entity gets a facility excluded, then that exclusion
should be allowed for 3 or more years. Annual certifications and approval are too restrictive.
E. NSRS believes the exception criteria needs to be developed by the SDT. NERC Staff should focus on the process
(identification, notification, appeal and rights) but the SDT is in the better position to develop the technical piece of the
exception criterion.
Response:
A. The SDT has established basic goals and assumptions that will be used to guide the development of the BES definition and supporting documents. The
assumptions include: ‘The revised definition will not significantly expand or contract what are currently considered BES Elements, nor will the revised
definition drive entity registration or de-registration”. Based on these goals and assumptions the overall impact of the revised definition is expected to be
minimized for the majority of the Regions and Registered Entities. However, once the definition and supporting documents are nearing completion, the
impact of the revised definition will be assessed and the Implementation Plan and Transition Plans will be developed to provide an appropriate time-period
for entities to establish compliance with the applicable Reliability Standards.
B. The SDT has established basic goals and assumptions that will be used to guide the development of the BES definition and supporting documents. The
assumptions include: ‘The revised definition will not significantly expand or contract what is currently considered to be BES Elements, nor will the revised
definition drive entity registration or de-registration”. Based on these goals and assumptions and in the absence of technical justification, the current
generator registration criteria appears to be the logical starting point for assessing BES Elements. The goal of the SDT is to establish a component-based
‘bright-line’ definition which enables the proper assessment of BES and non-BES Elements. The ‘bright-line’ associated with the identification of Protection
Systems which are applicable to the PRC series of Reliability Standards is not necessarily at the same point. The SDT has discussed this issue and will
be seeking guidance from FERC staff in regards to the directives in FERC Order No. 743 and how they potentially apply to Protection Systems. Protection
Systems are not currently within the scope of the SAR for this project and any significant expansion could potentially jeopardize the ability of the SDT to
complete this project and file in accordance with the Commission directed time requirements in FERC Order No. 743.
C.

The SDT is not considering updating the concept paper as future work will be in crafting the actual definition and designations.

D. The SDT agrees that the Bulk Electric System is dynamic and that the implementation and continued application of the BES Definition and supporting
processes will require active oversight and management to ensure that changing conditions (i.e., operational & new construction) surrounding the Bulk
Electric System will be addressed and result in proper periodic evaluation and identification of BES & non-BES Elements. The current scope of the
Standard Authorization Request (SAR) for Project 2010-17 Definition of Bulk Electric System does not include the development of the ‘Exception Process’.
The specific review/re-assessment ‘time periods’ associated with the identified exceptions (inclusions & exclusions) will be drafted by the NERC ROP
Team and vetted through the ROP Revision Process.
E. The current scope of Project 2010-17 includes the development of the exception criteria. Additionally, the SDT will have representation on the NERC ROP
Team to ensure that consistency is maintained throughout the development of the revised definition and the Exception Process.

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Organization
IRC Standards Review
Committee

Yes or No

Question 13 Comment
a. On the SAR, it indicates an SC approval date of December 8. It is misleading since the SC did not approve
the SAR; it only approved posting of the SAR for industry comment.
b. We have a concern with the concept paper on the exemption/inclusion criteria/process. Please see other
comments on that paper submitted separately.
c. We suggest use of consistent term between “exception” and “exemption”.
d. We suggest the exception/inclusion criteria to be included in the definition and developed/approved by the
balloting body. Determining these criteria via any other processes will not provide the industry the opportunity
to fully vet the criteria.
e. The SAR indicates that “...the definition drafting team will work closely with the team developing the BES
definition exemption process to develop a single coordinated implementation plan. It is also envisioned, that
the team working to develop the BES definition exemption process will solicit input from drafting teams,
stakeholders....” We find this confusing and have a concern that having two teams working on this
definition/criteria package leads to misalignment and confusion. Further, while the definition drafting team is
formed by a nomination process and appointed by the NERC Standards Committee, there is no transparency
and/or public announcement to solicit nominations for the team working to develop the exemption process.
We urge the NERC Standards Committee to direct the definition drafting team to also be responsible for
developing the exemption process, and include the exemption criteria as part of the definition hence
subjecting them to industry comment and balloting.

Response:
a. The default language in the form is misleading and implies that the NERC Standards Committee’s approval is required. Per the NERC Standard Process
Manual the Standards Committee authorizes posting of the SAR for industry comment. The DBES SDT will provide a recommendation to NERC
Standards Staff to revise the SAR form to read, "Date SC Authorized Posting the SAR”.
b. Please see comment responses to other questions.
c.

The inconsistency of the use of ‘exemption’ vs. ‘exception’ in several documents has been identified by the SDT and the SDT has determined that
‘exception’ is the proper term to be used in reference to the Bulk Electric System definition and supporting processes.

d. The current scope of Project 2010-17 includes the development of the exception criteria and the revised definition of BES includes a proposed list of
criteria for “Inclusions” and a proposed list for “Exclusions”. Additionally, the SDT will have representation on the NERC ROP Team to ensure that
consistency is maintained throughout the development of the revised definition and the Exception Process.
e. The passage from the SAR that is referenced in the comment is addressing the need for a single Implementation Plan that takes into consideration all

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Yes or No

Question 13 Comment

aspects of this project. The Implementation Plan will need to address the impact of the revised BES definition and exception criteria, the Exception
Process (ROP) and the Regional Transition Plans. The current scope of Project 2010-17 includes the development of the exception criteria. Additionally,
the SDT will have representation on the NERC ROP Team to ensure that consistency is maintained throughout the development of the revised definition
and the Exception Process. The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC
staff and governed by current practice for administering such revisions. The NERC ROP Team will be established by NERC staff and include
representation from the DBES SDT along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be
determined and administered by NERC staff.
Bonneville Power Administration

1. Define the definition of generation resources and plants, specifically wind.
2. Ensure that the exemption process incorporates all lines in service, outage conditions, etc.
3. Ensure that BA’s have the ability to recommend inclusion in the BES, if the BA determines the facility has
an impact on the BES.

Response:
1. The term is no longer used in the definition.
2. The SDT has developed the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall starting
point for assessing BES and non-BES Elements. The ‘exception criteria’ utilizes the same type of ‘bright-line’ criteria approach to provide further guidance
as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation Facilities, radials, etc.). The idea of injecting the
‘current operational conditions’ (lines in service, outage conditions, etc.) of Elements poses difficulties with the universal application of the definition to
achieve consistent results across the continent. Additionally, the idea of ‘current operational conditions’ (lines in service, outage conditions, etc.) suggests
that these conditions are subject to change and therefore could result in different assessments when identifying BES and non-BES Elements.
3. The responsibilities associated with the Exception Process will be determined and established by the NERC ROP Team as part of the Exception Process.
FirstEnergy Corp

March 30, 3011

a.) FirstEnergy supports a new BES definition that will provide a clear bright-line of electric facilities
deemed inclusive to the BES. The exclusion process should be a simple, continent wide, rarely used
with high-thresholds for removing any 100kV and above facility from the BES. The exclusion process
and BES definition change should also include a practical means for transition for any affected
companies.
b.) The BES definition should explicitly contain language to exclude radial to load transmission operated
at 100kV and above voltage levels. Presently, it seems that radial transmission to load “may” be
excluded, subject to the exemption process. The excluded radial facilities described by the BES
definition should be simply defined and avoid overly complicated scenarios for qualify a facility as
radial transmission.

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Yes or No

Question 13 Comment
c.) BES definition clarity can be accomplished by incorporating aspects of the concept paper’s proposed
“BES Criteria” as being part and parcel of the overall BES definition. Doing so will establish the
desired BES bright-line by further describing facilities as “in” or “out” by definition and avoid an overly
complicated exclusion process.
d.) The exclusion process should be rarely used, having a narrow expectation for removing facilities from
the BES and thus avoid an overly burdensome administrative process. From an exclusion view, the
BES definition should directly exclude radial 100kV and higher transmission, facilities operated below
100kV unless deemed critical to the BES by the Regional Entity and any 100kV and higher facility
qualified by the BES exemption process.
e.) Further, we support EEI’s views that the BES Definition and the technical aspects of the exemption
criteria (outside of the definition) should be treated as a single standards development project and
performed by this drafting team.
f.) We also support a parallel effort by NERC staff, subject to industry review/comment, of revising the
Rules of Procedure to account for the process oriented information that would point to the technical
exemption criteria/guidance developed by the standard drafting team.
g.) Finally, the concept paper awkwardly describes an “exclusion process” that would identify any sub
100kV facilities that would be “included” in the BES. The criterion developed for potentially including
sub 100kV facilities should be separately developed or at least not referenced within an “exclusion
process”. Additionally care should be taken to not cast the net too wide in this regard. While we
propose a high threshold for excluding 100kV facilities from the BES, we similarly propose a high
threshold for inclusion of sub 100kV facilities. The primary focus of this drafting team should be the
drafting of the new BES definition and the technical BES exemption criteria. The development of
continent-wide criteria for including other sub 100kV facilities in the BES should be treated as a
secondary priority for meeting the milestone expectations of the FERC compliance filing.

Response:
a.) The SDT agrees with the comments. The Implementation Plan will need to address the impact of the revised BES definition and exception criteria, the
Exception Process (ROP) and the Regional Transition Plans on affected entities and provide sufficient time to ensure a smooth transition into the realm of
mandatory and enforceable Reliability Standards.
b.) The SDT has further developed the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall
starting point for assessing BES and non-BES Elements with a list of exceptions. The ‘exception criteria’ utilizes the same ‘bright-line’ criteria approach to
provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation Facilities, radials, etc.).
c.) The SDT agrees with the comments and has established the tight linkage between the core definition of the BES with the component-based ‘bright-line’
exception criteria.

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d.) The Exception Process will be employed when the bright-line core definition and its associated exception criteria cannot be applied to a specific Element.
It is anticipated by the SDT that the ‘bright-line’ will be the definitive approach to identifying BES and non-BES Elements for the vast majority of the system
configurations across the continent and utilization of the Exception Process will be limited to the remaining Elements.
e.) The current scope of Project 2010-17 includes the development of the exception criteria and these have been included in the revised definition of BES.
Additionally, the SDT will have representation on the NERC ROP Team to ensure that consistency is maintained throughout the development of the
revised definition and the Exception Process.
f.) The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC
staff.
g.) It is the vision of the SDT that the process to include Elements within the BES and the ability to exclude Elements from the BES should parallel each other
and require the same level of technical justification to achieve consistent results.
Electric Market Policy

Dominion supports, in large part, EEI’s response to the draft concept paper. Dominion provides the following
comments on the proposed exemption process. NERC should use the FERC-approved standards
development process to develop the Bulk Electric System (BES) definition and the exemption process in a
single, integrated and stakeholder approved process. To this end, Dominion conceptually supports an
exemption process whereby NERC or the RRO could apply to have an element included or excluded from the
BES definition. Such process recognizes that it may be necessary to include elements that do not meet the
bright line criteria but are necessary for operating an interconnected transmission network. Such process
should be developed through the existing NERC standards development process and include a robust
appeals process for the owner/operator of any element so included or excluded.
Dominion supports bright line exclusions of all elements rated at less than 100 kV, any transformer that has a
primary or secondary winding of less than 100 kV, and all radial lines regardless of their kV rating. Radial
lines to/from solely generation facilities and radial lines to/from load are comparable in terms of their impact
on an interconnected transmission network. There are situations where these radials make a meaningful and
required contribution to the operation of an interconnected transmission network and there are other
locations/situations where these radials do not. Therefore, radial lines should only be specifically included in
the definition of BES after the RRO has demonstrated that inclusion of the radial is necessary to operate an
interconnected transmission network and the owner/operator of the radial line has had the opportunity to
exercise its aforementioned appeal rights. Adopting this paradigm would prevent a gap in the application of
reliability standards. Specifically, all radial lines would either be included in the definition of BES or would be
captured via the NERC registry under distribution or generation.

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Dominion supports the criteria for registering owners, operators, and users of the bulk power system, as
indicated in the current Statement of Compliance Registry Criteria . Adoption of the foregoing process would
insure confidence in entities that the compliance registration process is equitable and fair.

Response: The NERC Standard Processes Manual is the governing document for the development of the revised BES definition and exception criteria. The SDT
is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall starting
point for assessing BES and non-BES Elements. The ‘exception criteria’ use the same ‘bright-line’ criteria to provide further guidance as to whether an Element is
considered BES or non-BES (i.e. bright-line criteria for identifying Generation Facilities, Radials, etc.).
The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current practice
for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT along with industry
experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC staff.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception Process
by the NERC ROP Team. The goal (identified key to the project’s success) is to have parallel postings from each aspect of the project, which will enable the
industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception criteria, and the
Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the directives in Order
No. 743, the decision was made to establish two teams working in close coordination to address the issues related to the project.
See responses to EEI comments.
SERC OC Standards Review
Group

We agree that Transmission and Generation Elements and Facilities operated at voltages of 100 kV or higher
that are necessary to support bulk power system reliability should be included. Elements and Facilities
operated at voltages of 100kV or higher, including radial elements, may be excluded and Elements and
Facilities operated at voltages less than 100kV may be included if approved through the BES definition
exemption process.”The comments expressed herein represent a consensus of the views of the above
named members of the SERC OC Standards Review group only and should not be construed as the position
of SERC Reliability Corporation, its board or its officers.”

Competitive Suppliers

EPSA recognizes the value in revising the BES definition so that a bright-line proxy can be consistently
applied by the NERC Regional Entities. It is important that this definition be completed so that the drafting
team work sequentially by determining the new BES definition and then move on to developing a exemption
process that can work efficiently with that new definition

Response: The DBESSDT acknowledges your comments and thanks you for the support of the presented concepts.
Hydro-Quebec

March 30, 3011

For Canadian entities, inclusion or exclusion of equipment and facilities in the BES must be also approved by
Canadian regulators. Common interconnection between two jurisdictions must be included in BES when at

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least one Facilities is necessary for the reliability of BES.
The transmission lines dedicated to serve the native load in Quebec Interconnection should be excluded,
considering that the Quebec Interconnection is one of the four recognized interconnection.
Finally, we believe that it is very difficult to propose first a definition for the BES and only after an Exemption
process. Both aspects influence each other and both should be conducted together.

Response: The SDT has established non-jurisdictional representation to address the concerns of the applicable entities (e.g., Canadian entities) in regards to the
application of a continent-wide ‘bright-line’ definition of the Bulk Electric System and exception criteria. NERC Staff has determined the needs of the NERC Rules
of Procedure Team in regards to the diversity of the membership and the technical expertise required to appropriately modify the ROP in response to the
directives identified in FERC Order No. 743.
Transmission Lines dedicated to serving native Load are an identified concern in several Regions and Interconnections. The issues surrounding this concern and
the development of potential bright-line criteria are currently being considered by the SDT.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception Process
by the NERC ROP Team.
PPL Energy Plus
LG&E and KU Energy LLC

Please consider that it is the magnitude of MVA flow on a facility and the subsequent impact on the remaining
facilities that defines when a facility is in the BES rather than just the direction of the real power flowing on the
facility.

Response: The SDT has developed the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall
starting point for assessing BES and non-BES Elements. The ‘exception criteria’ (now proposed as part of the definition of BES) utilizes the same ‘bright-line’
criteria approach to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation Facilities,
radials, etc.). The idea of injecting the ‘current operational conditions’ (i.e., MVA flow) of Elements poses difficulties with the universal application of the definition
to achieve consistent results across the continent. Additionally, the idea of ‘current operational conditions’ (i.e., MVA flow) suggests that these conditions are
subject to change and therefore could result in different assessments when identifying BES and non-BES Elements.
ExxonMobil Research and
Engineering

Industrial facilities must retain the ability to control their electric facilities in order to ensure that the system is
designed to provide for the safest and most reliable source of electric power for the control of their processes.
The definition of the bulk electric system and the exemption process should address this fact and exclude or
provide a process to exclude industrial facilities from all or a select number of NERC requirements when there
is a conflict between the requirements designed to ensure the reliability of BES and the safe operation of
chemical processes.

Response: The SDT has established basic goals and assumptions that will be used to guide the development of the BES definition and supporting documents.

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The assumptions include: ‘The revised definition will not significantly expand or contract what are currently considered BES Elements, nor will the revised
definition drive entity registration or de-registration”. Based on these goals and assumptions the overall impact of the revised definition is expected to be minimized
for the majority of the Regions and Registered Entities. The SDT is currently working toward an equitable solution concerning industrial customers based on
language currently contained in the Registry Criteria which establishes guidance for addressing ‘behind the meter generation’.
NERC Staff

See Attached.

Response: The SDT will consider your comments in the further development of the core definition and the exception criteria.
Edison Electric Institute

Order 743 / NERC BES Project Edison Electric Institute Responses to Draft Concept Paper General Issues:
On behalf of its member companies, Edison Electric Institute (EEI) appreciates the opportunity to offer the
following brief comments on NERC Project 2010-17 for developing response to FERC Order No. 743,
definition of Bulk Electric System and an exemptions process for certain facilities. EEI is the association of
the nation’s shareholder-owned electric companies, international affiliates, and industry associates worldwide.
EEI’s U.S. members serve approximately 95 percent of the ultimate consumers served by the shareholderowned segment of the electric utility industry and approximately 70 percent of all electric utility ultimate
consumers in the nation. Virtually all EEI members are required to comply with the mandatory electric
reliability standards established by the ERO and approved by the Commission, pursuant to section 215 of the
Federal Power Act. As a process matter, EEI develops comments such as these through a disciplined and
well-practiced process that includes broad distribution of draft documents to member companies, conference
calls, and email exchanges, all conducted to ensure that EEI speaks with broad member company support
and with as much specificity as possible. For additional information about the roster of membership, NERC
staff should contact EEI directly.
The concept paper envisions two parts of the project - (1) development of the technical criteria for the BES
definition through the NERC Standards Development Process and (2) development of the Rules of Procedure
for the exemption process.
a.) NERC should use the FERC-approved standards development process for developing the technical
criteria for both the BES definition and exemptions. EEI views this as a single exercise, that is, the BES
definition and technical aspects relating to exemptions as a single project.
b.) EEI members believe that this is a critical project and understands various concerns about timeliness
and process efficiency, and therefore recommends that stakeholders make strong commitments now to
a project plan that will ensure a timely compliance filing at FERC. The drafting team should also
expedite development of a project plan that shows tasks, deliverables, and milestone dates for the entire
one-year timeline.

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c.) EEI reads Order No. 743 as suggesting that NERC should develop appropriate changes to the Rules of
Procedure (ROP) to accommodate the process and due process features of the BES exemptions
process, including matters such as administrative procedure, decision authority, appeals and other due
process matters, and requests for changes. EEI strongly believes that the technical matters are best
resolved in the FERC-approved standards development process, which for this project includes the BES
definition and the various technical criteria to be used to define exemptions. NERC should manage the
development of ROP changes through an open process that considers stakeholder comments and
recommendations.
d.) Alternatively, if NERC decides to develop various technical criteria for the granting of exemptions
through the Rules of Procedure, EEI strongly encourages NERC to plainly describe the process plan,
which will help communicate to companies how the process will be open, inclusive, transparent, and
ensure due process.
e.) Issues recommended for drafting team consideration: Order No. 743 provides that the best way to
address its concerns about the definition of BES is to eliminate the regional discretion in the current
definition, maintain the bright-line threshold that includes all facilities operated at or above 100 kV except
defined radial facilities and establish an exemption process and criteria for excluding facilities that the
ERO determines are not necessary for operating the interconnected transmission network. (P 30)
Because transmission lines below 100 kV and radial lines are not included in the definition of BES, the
standards drafting project should ensure that the definition expressly incorporates these exclusions.
Entities should not have to seek an exemption for facilities below 100 kV or for radial lines. They should
be clearly excluded in the BES definition itself.
f.) Removing regional discretion does not imply that regions have no role. EEI also encourages NERC in
the ROP to delegate the authority to grant exemptions in the first instance to the Regional Entities.
NERC should maintain oversight authority, including review of decisions for consistent application of the
criteria.
g.) Applicants for exemptions should be able to appeal adverse Regional Entity decisions to NERC. The
NERC Compliance Registry process should serve as a general model.
h.) The BES definition must also address the statutory exclusion for facilities used in “local distribution.”
Section 215 plainly excludes facilities used in local distribution from jurisdiction and EEI notes that the
definition is applied under other provisions of the Federal Power Act. The exemptions process should
provide that previous or future regulatory decisions regarding local distribution facilities can serve as an

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exemption criterion. While Order 743 does not provide explicit guidance on this issue, EEI urges the
drafting team to expand the concept paper to include how this issue will be addressed. If the concept
paper is not expanded to include this issue, NERC needs to plainly say where the issue will be
addressed.
i.) Order 743 made references to facilities below 100 kv that might be defined as necessary for operating
an interconnected transmission network, and asked that whatever processes are used to make
jurisdictional decisions are rolled into the NERC process. In addition, the order referred to several
“technical concerns” that might inform jurisdictional decisions on specific facilities greater than 100 kv,
which are scattered references throughout the order. For example: operate in parallel with other high
voltage and extra-high voltage facilities (P. 73), interconnect significant amounts of generation and
(possibly) operate as a defined flowgate (P. 73), will experience similar loadings as high voltage or extrahigh voltage facilities at any given time (P. 73), can cause or contribute to significant bulk power system
disturbances and cascading outages (P. 73), will be relied upon during contingency operations (P. 73),
are not primarily radial in character (P. 39), multiple interconnections of facilities (to other higher voltage
facilities) do not constrain an otherwise limited geographical area (P. 39), overall, (implementation of) the
proposed definition may not result in a reduction in reliability (P. 74), facilities that, when they fail, cause
or influence significant loss of load (PP. 87, 89). Order No. 743 does not explicitly connect these criteria
to the process to be developed; however, the drafting team in its plan should explain how it will address
them, as required by the order (P 74). EEI encourages the drafting team to seek informal agreement
with FERC staff on these various “technical concerns” prior to significantly advancing the project.
j.) As a design matter, EEI encourages the drafting team to endorse a principle to seek to maximize the
“brightness” of bright line criteria. While this may produce a longer or more detailed definition, EEI
believes that greater demarcation at the outset will help reduce companies’ uncertainty, and help avoid
the need to maintain a costly and bureaucratic exemptions process. EEI has previously offered
comments on many occasions to both FERC and NERC in support of a ‘simple and clean’ TFE process.
k.) EEI urges the drafting team to resist the temptation to create a complicated ‘Rube Goldberg’ device for
BES exemptions. Order No. 743 (PP 77-78, 84-85) criticizes the NPCC impact-based study as failing to
identify many facilities that are necessary for operating an interconnected transmission network.
However, the order does not reject such studies generically, and plainly states that the Commission is
not dictating the substance or content of the exemptions process. (P 114) The concept paper needs to
clarify whether requests for exemptions may use impact-based studies to support their requests.
l.) The concept paper reflects an awkwardly-worded reference (Item #6, proposed BES criteria) to the
effect that certain facilities will be deemed included in the BES “...where the exemptions process

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deems...” In the paragraph at the top of p. 2, the concept paper refers to the exemption process as
seeking to determine “...whether a facility should be included or excluded....” EEI requests clarification
that an exemptions process will be used to determine facilities for exclusions and not inclusions, and
based on a 100 kv bright-line criterion for inclusion. Alternatively, the concept paper should clarify the
general intention of this particular criterion.
m.) As previously stated, the proposed ROP to be developed should codify the process - and due process aspects of the exemptions process. The exemptions process should strike the right balance in
establishing the criteria for exemptions to ensure that the process does not become mired in attenuated
processes such as those developed for the TFE process.

Response:
a.) The NERC Standard Processes Manual is the governing document for the development of the revised BES definition and exception criteria. The SDT is
continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall
starting point for assessing BES and non-BES Elements. The ‘exception criteria’ (now proposed as part of the definition of BES) utilizes the same ‘brightline’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation
Facilities, radials, etc.).
b.) The SDT agrees with the critical nature of the project and the need to provide deliverables within the Commission directed time frame. The SDT has
developed and posted a project schedule which identifies the tasks, deliverables, and milestone dates for the entire project. The schedule is publically
posted and available on the project page (Project 2010-17 Definition of the Bulk Electric System) of the NERC website.
c.) The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC
staff.
d.) The SDT has determined that one of the keys to success for this team and the NERC ROP Team is effective communication that provides the industry
with an understanding of the project plan and concepts, which will emphasize the development process attributes of openness, inclusiveness,
transparency, and due process.
e.) The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ utilizes the same ‘bright-line’ criteria to provide
further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying Generation Facilities, Radials, etc.). The
tight linkage between the core definition and the exception criteria provides the framework for identifying BES and non-BES for the vast majority of the
Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or non-BES utilizing the core definition and
exception criteria would be candidates for application of the Exception Process where the technical justification would be required to identify Elements as

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BES (inclusions) or non-BES (exclusions).
f.) The ‘Exception Process’ and the responsibilities associated with the implementation and oversight will be defined by the NERC Rules of Procedure Team.
Based on the language contained in FERC Order No. 743, there are Commission expectations associated with the process oversight by the ERO and
allowances for the delegation of responsibilities to Regional Entities as appropriate, while ensuring the process is clear and capable of being applied
consistently, objectively and uniformly across all regions.
g.) The SDT agrees that within the NERC ROP Exception Process, entities should have the opportunity to appeal decisions made by the Regional Entities
and the ERO concerning the inclusion or exclusion of Elements in relation to the BES.
h.) The SDT agrees that the issues surrounding ‘local distribution networks’ deserve consideration when developing the BES Designations. See the revised
definition as it proposes exclusions for local distribution networks that meet certain criteria.
i.)

The SDT will consider your comments in the further development of the core definition and the exception criteria and will seek clarity on the issues
identified in future discussions with FERC staff.

j.) The SDT has developed the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall starting
point for assessing BES and non-BES Elements. The ‘exception criteria’ utilizes the same ‘bright-line’ criteria approach to provide further guidance as to
whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation Facilities, radials, etc.).
k.) The specific methodology associated with establishing the technical justification of inclusions to or exclusions from the BES will be determined and vetted
by the NERC ROP Team utilizing the revision process for the NERC ROP and will be coordinated by NERC staff and governed by current practice for
administering such revisions.
l.) The SDT disagrees with the commenter in that any Exception Process should establish a process for exceptions from and inclusions to the BES. As
stated in FERC Order No. 743, P83 “The Commission’s proposed approach to addressing these concerns will enable affected entities to pursue
exemptions for facilities they believe should not be included in the bulk electric system, and also will allow Regional Entities to add facilities below 100 kV
they believe should be included”. The Regional Entities currently have the authority to include Elements operated at voltages below 100 kV that are
deemed necessary for the reliable operation of the BES. The Order does not eliminate this authority, but rather emphasizes the need to maintain the
Regional Entity’s ability of establishing inclusions to the BES through the Exception Process.
m.) The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. With that in mind, the SDT agrees with the commenter in that the Exception Process should carry the same
characteristics as the core definition and exception criteria: clear, unambiguous, repeatable, and establish consistency on a continent-wide basis.
Pepco Holdings Inc.

March 30, 3011

1. The definition should be expanded to contain what is excluded to minimize the need for exemptions. For
example radial facilities should by definition be excluded and not have to go through a formal exemption

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process. Other “generic” criteria identified should also be excluded.
2. The exemption process needs to be well designed to minimize the effort. The exemption process
development should incorporate lessons learned and experience from the TFE process, so that this new
process is more manageable.
3. Instead of two separate groups, one working on the definition and one on the exemption process, one
group should handle both activities to assure continuity and consistency.
4. Any data required for the exemption process needs to be kept secure and not posted on an open source.
5. PHI is supportive the EEI comments offered on the BES Project.

Response:
1. The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed as part of the definition of BES)
utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying Generation Facilities, Radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for
identifying BES and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as
BES or non-BES utilizing the core definition and exception criteria would be candidates for application of the Exception Process where the technical
justification would be required to identify Elements as BES (inclusions) or non-BES (exclusions).
2. The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP team will be determined and administered by NERC
staff. With that in mind, the SDT agrees with the commenter in that the Exception Process should be a manageable process that is clear, unambiguous,
repeatable, and establishes consistency on a continent-wide basis.
3. The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception
Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which will enable
the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception criteria
and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the
directives in Order No. 743, the decision was made to establish two teams working in close coordination to address the issues related to the project.
4. The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The current process includes public postings of proposed changes which will allow the industry provide
comments. We will forward your comment to the team working on the ROP modifications.

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5. See responses to EEI comments.
PUD No.1 of Clallam County

Due to the lack of clarity around the current definition of the Bulk Electric System ("BES") the NERC
Statement of Compliance Registry Criteria is often used/misused to define elements of the BES. The
registration criterion uses many undefined terms as well as “bright line” thresholds that that in many cases
have little to no technical basis. One example is using “gross nameplate rating” when the machine size may
be significantly limited by boiler capacity on a cogeneration steam plant or water on a hydro plant. In addition
there is no technical or reliability bases used to identify the low MVA/MW thresholds used in the load and
generation thresholds for the DP, GO, GOp registrations.
The Standards Authorization Requests (SARs) should also address how, or if the registration criteria is used
in identifying BES elements. We believe the Registration Criteria should not be used to identify BES
elements; it should be used as indented, to address functional registration.

Response: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes
the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed as part of the definition of BES)
utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying
Generation Facilities, Radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying BES and nonBES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or non-BES utilizing the core
definition and exception criteria would be candidates for application of the Exception Process where the technical justification would be required to identify
Elements as BES (inclusions) or non-BES (exclusions).
Any impact of the revised core definition, the exception criteria, or Exception Process on the current Registry Criteria will be addressed in the Implementation Plan.
Manitoba Hydro

a.) A NERC definition of ‘radial’ is required to prevent misapplication of the BES definition and exemption
process.
b.) There should be no regional differences in the BES definition or in the BES definition exemption process.
c.) There should be equal representation from the regions to draft this standard and exemption process

Response:
a.) With the proposed revisions to the definition of BES, at this time, the SDT does not contemplate adding any additional definitions beyond BES.
b.) FERC Order No. 743 provides specific direction on the elimination of the regional discretion which is allowed under the current definition of the Bulk
Electric System. The SDT fully intends to be responsive to the Commission directives.
c.) In forming the SDT, NERC staff has utilized the criteria established in the NERC Standard Drafting Team Scope Document, which states: ‘Representation

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from as many NERC Regions as possible’.
North Carolina EMC

The BES definition for radial facilities serving only load with one source should be clarified to include radial
facilities with the potential ability to be served from more than one source, but always operated with an
"opening point" that makes it radial. If the entity can demonstrate that it always operates in this fashion, either
by producing switching orders indicating such operation or other evidence such as documentation of open
and tagged switches, etc., then it should be considered to be in full compliance with the radial BES definition
exemption.

Response: The DBES SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that
establishes the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed as part of the definition
of BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The SDT has revised the definition but is retaining the single source designation.
ReliabilityFirst

March 30, 3011

•

ReliabilityFirst would like to see this as a simple easy-to-follow definition. The exclusion process needs to
be clear without room for discussion or interpretation.

•

There must be a common framework developed to apply the entire process that begins with a single
NERC-wide BES definition.

•

The definition should serve as a common approach for the identification of BES Elements and Facilities
that are subject to compliance that is married to the Registration Criteria.

•

The definition and approach for the determination must be repeatable

•

The method must clearly identify the BES elements for use by the industry.

•

In order to obtain consistency, the definition, application and criteria must be used across Regional Entity
boundaries.

•

The revised BES definition should be consistent with the Statement of Compliance Registry Criteria so as
not to create a conflict between the two, and could possibly simply reference the Criteria for issues such
as size of generating units (e.g., 20 MVA units and 75 MVA plants) included in the BES.

•

As stated in the FERC Order No. 743, the criteria for exemption should be included within the BES
definition, and the exemption process should contain only the procedure for submitting and determination

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of such. The exemption process should not contain a third set of criteria (in addition to the BES definition
and the Statement of Compliance Registry Criteria) in which to make a determination of facilities to be
monitored for compliance to standards.
•

With the revised BES definition containing specific requirements for inclusion in the BES, will the
separate Statement of Compliance Registry Criteria be needed?

Response: The SDT agrees and has considered your comments in the further development of the core definition and the exception criteria.
The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed as part of the definition of BES)
utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying
generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying BES and nonBES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or non-BES utilizing the
core definition and exception criteria would be candidates for application of the Exception Process where the technical justification would be required to
identify Elements as BES (inclusions) or non-BES (exclusions).
A revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBES SDT along
with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC staff. With
that in mind, the SDT agrees with the commenter in that the Exception Process should be a manageable process that is clear, unambiguous, repeatable, and
establishes consistency on a continent-wide basis.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception
Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which will enable the
industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception criteria, and
the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the directives in
Order No. 743 the decision was made to establish two teams working in close coordination to address the issues related to the project.
Any impact of the revised core definition, the exception criteria, or Exception Process on the current Registry Criteria will be addressed in the Implementation
Plan.
on behalf of Teck Metals Ltd.
on behalf of Catalyst Paper
Corporation

Parallel transmission lines from a single source (substation) to a single load should be excluded from the
BES, with the consent/request of the owner of the connected load (and/or all customers that constitute the
connected load).

Response: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes

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the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation facilities, radials, etc.). In the development of the exception criteria, the SDT has considered your comments.
City of Grand Island

a.) The NERC defined Adequate Level of Reliability is the governing factor on whether or not a facility really
has an impact on the BES. Currently the standards are applied far too broadly and numerous small
entities are needlessly involved. This project should pull the standards/compliance environment back to
entities that have a real impact.
b.) Exemption process should be termed “exception” process. Exception means not conforming to general
rule, whereas exemption primarily means exclusion. This process will be difficult to develop and
administer and is counterproductive to “bright line” philosophy. Thus the bright lines should be at a high
level resulting in fewer exceptions. The exception process must consider the impact of a fault or outage of
that facility on the Adequate Level of Reliability of the BES.
c.) The exception process development should be simultaneous to the BES definition project. It’s all one, not
two pieces. In addition if this is a direct impact on registration criteria, then that should be part of the
project as well.

Response:
a.) The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The SDT believes that this method of identification will provide the desired clarity requested by the industry
and directed by the Commission while ensuring that consistent results will be produced universally across the continent. In the development of the core
definition and the exception criteria, the SDT has considered your comments.
b.) The inconsistency of the use of ‘exemption’ vs. ‘exception’ in several documents has been identified by the SDT and the team has determined that
‘exception’ is the proper term to be used in reference to the Bulk Electric System definition and supporting processes.
The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ utilizes the same ‘bright-line’ criteria to provide
further guidance as to whether an Element is considered BES or non-BES (i.e. bright-line criteria for identifying generation Facilities, radials, etc.). The
tight linkage between the core definition and the exception criteria provides the framework for identifying BES and non-BES for the vast majority of the
Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or non-BES utilizing the core definition and
exception criteria would be candidates for application of the Exception Process where the technical justification would be required to identify Elements as

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BES (inclusions) or non-BES (exclusions).
c.) The development of the core definition of the BES and the exception criteria by the DBES SDT will be closely coordinated with the development of the
Exception Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which
will enable the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the
exception criteria and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be
responsive to the directives in Order No. 743, the decision was made to establish two teams working in close coordination to address the issues related to
the project.
Any impact of the revised core definition, the exception criteria or Exception Process on the current Registry Criteria will be addressed in the
Implementation Plan.
Occidental Energy Ventures Corp

Demand Side Management. One commenter has apparently suggested that “Demand Side Management”
relied on to provide Contingency Reserves be included in the BES definition. On the surface, this seems
reasonable. However, this would possibly subject aggregators of DSM resources to registration as a yet
unknown resource type. The DSM resources could be located on lower voltage distribution systems that
should not be part of the BES. Once again, the issue of DSM registration is being pursued under a separate
NERC initiative and should be resolved by that process rather than a broadening of the definition of BES
which forces registration of entities not currently registered. This also could provide a disincentive for potential
DSM development, which the Federal Energy Regulatory Commission (FERC) is on record as trying to foster
as a peak shaving resource. When the issues surrounding DSM as a resource are resolved by due process,
any recommendations could include a change to the definition of BES, if actually required. Finally, this issue
is not part of the FERC directives for changing the BES definition.
Self-Generation and Cogeneration. One commenter has apparently suggested that self-generation as
currently defined and excluded in the Statement of Compliance Registry should not be excluded from the
definition of BES based on the “immediate-term impact on reliability.” This same commenter notes that, in
order to be excluded under the current BES definition, the self-generation is required to purchase back-up
(stand-by) power for the generation in case of an outage. Paying for this standby power (which is essentially
“extra” reserve power) is one reason for allowing the self-generation to be excluded from the BES. Once
again, subjecting self-generation/cogeneration to NERC regulatory requirements is not one of the directives
from the FERC concerning the BES definition and could provide a disincentive for cogeneration, which has
been historically supported by FERC and the federal government. Hence, suggestions such as this are out of
the scope of this process.

Response: The SDT has established basic goals and assumptions that will be used to guide the development of the BES definition and supporting documents.
The assumptions include: ‘The revised definition will not significantly expand or contract what are currently considered BES Elements, nor will the revised

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definition drive entity registration or de-registration. Based on these goals and assumptions the overall impact of the revised definition is expected to be minimized
for the majority of the Regions and Registered Entities. The SDT will consider your comments in the further development of the core definition, the exception
criteria and the Exception Process.
Glacier Electric Cooperative

I highly encourage the development of a method that utilizes engineering analyses to more accurately define
which elements are truly significant to the BES and which are not. Thanks for taking on the challenge to
improve the BES definition.

Response: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes
the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The SDT believes that this method of identification will provide the desired clarity requested by the industry and
directed by the Commission while ensuring that consistent results will be produced universally across the continent. exception criteria
Entergy Services

a.) The following are Entergy’s comments concerning the scope and implementation of the requested work,
the draft SAR, draft standard, draft criteria, draft exemption criteria, exemption process, and
implementation process. We suggest the SAR ad the standard development be revised to reflect the
comments below. In particular, we believe there are several parts to the scope of this project.
First, the development of the revised definition of the BES including all inclusion / exemption criteria and
the development of the implementation plan for that revised definition should be developed through the
Standards Development Process. All future inclusion / exemption criteria would also be developed
through the Standards Development Process. The process for changing the Rules of Procedure should
be used for the development, approval and application of the process for obtaining an exemption of
specific facilities. It would be helpful, but not required, that the development of the standard and the
changes to the ROP proceed together.
b.) We suggest there be one continent-wide definition of BES with no exemption criteria specific to a
particular region...
DEFINITION OF BES, INCLUSION CRITERIA and EXEMPTION CRITERIA We suggest the definition of
BES be the following: Bulk Electric System: All Transmission and Generation Elements and Facilities
conforming to the Inclusion Criteria and Exemption Criteria identified below. Elements and Facilities
operated at voltages of 100kV or higher may be excluded and Elements and Facilities operated at
voltages less than 100kV may be included if approved through the BES definition exemption process
included in the NERC Rules of Procedure.
INCLUSION CRITERIA1. All transmission and generation elements and facilities operated at voltages of

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100 kV or higher,
2... Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators,
with both primary and secondary windings of 100 kV or higher;
3. Individual generation resources (including GSU transformers and the associated generator
interconnecting line lead(s)) greater than 20 MVA (gross nameplate rating) directly connected via a stepup transformer(s) to Transmission Facilities operated at voltages of 100 kV or above;
4. Generation plants (including GSU transformers and the associated generator interconnecting line
lead(s)) with aggregate capacity greater than 75 MVA (gross nameplate rating) directly connected via a
step-up transformer(s) to Transmission Facilities operated at voltages of 100 kV or above;
5. Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission
Operator’s (TOP’s) restoration plan;
6. Transmission Elements or Facilities operated at voltages below 100kV where the exemption process
deems the Element or Facility to be included in the BES;
7. Individual generation resources greater than 20 MVA (gross nameplate rating) directly connected via a
step-up transformer(s) to Facilities operated at voltages below 100kV where the exemption process
deems the generation resources to be included in the BES; and
8. Generation plants with aggregate capacity greater than 75 MVA (gross nameplate rating) directly
connected via a step-up transformer(s) to Facilities operated at voltages below 100kV where the
exemption process deems the generation plants to be included in the BES.
EXEMPTION CRITERIA1. Any radial Transmission Element or System, connected from one
Transmission source to a Load-serving Element and/or generation resources not included in items 2, 3, 4,
6, and 7 above are excluded from the BES;
2. Elements and Facilities identified through application of the exemption process, consistent with the
criteria, where the exemption process deems that the Element or Facility should be excluded from the
BES (with concurrence from the ERO); and
3. Generating plant control and operation functions which include relays and systems that control and
protect the unit for boiler, turbine, environmental, and/or other plant restrictions.
IMPLEMENTATION PLAN FOR REVISED DEFINITION OF BES The Standard Drafting Team will
develop for industry comment an Implementation Plan for the revised definition of BES.

Response:

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a.) The NERC Standard Processes Manual is the governing document for the development of the revised BES definition and exception criteria. The SDT is
continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall
starting point for assessing BES and non-BES Elements. The ‘exception criteria’ (now proposed for inclusion in the definition of BES) utilizes the same
‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e. bright-line criteria for identifying generation
Facilities, radials, etc.).
The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBES SDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC
staff.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the
Exception Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which
will enable the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the
exception criteria and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be
responsive to the directives in Order No. 743, the decision was made to establish two teams working in close coordination to address the issues related
to the project.
b) FERC Order No. 743 provides specific direction on the elimination of the regional discretion which is allowed under the current definition of the Bulk
Electric System. The SDT fully intends to be responsive to the Commission directives.
The SDT has considered your comments in the further development of the core definition and the exception criteria. See the proposed revised definition of
BES with its lists of “Inclusions” and “Exclusions.”
Snohomish County PUD

March 30, 3011

While we recognize that the Standards Drafting Team is a technical body and is not charged with interpreting
legal doctrine, we nonetheless urge the Drafting Team to bear in mind the statutory limitations on the
definition of the BES. If the BES definition is drafted with these limits in mind, the process will more easily
meet with industry acceptance. If the BES definition adopted by the drafting team fails to meet these limits,
by contrast, its efforts are likely to result in extended litigation that will be counterproductive to the goal of
improving the reliability of the bulk delivery system. The definition of “bulk-power system” adopted by
Congress in Section 215 of the Federal Power Act is the ultimate source of the Standards Drafting Team’s
authority and the Team should therefore pay particular attention to that statutory definition:The term ‘bulkpower system’ means-(A) Facilities and control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof); and(B) Electric energy from generation facilities needed
to maintain transmission system reliability. The term does not include facilities used in the local distribution of
electric energy. This definition, and in particular the language italicized above, imposes clear restrictions on
the definition to be developed by the Drafting Team.

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These restrictions are:
a. Only facilities “necessary for” the operation of the interconnected bulk transmission network can be
included in the BES. Snohomish believes the most logical way to determine whether facilities are “necessary
for” operation of the bulk system is through engineering-based studies demonstrating that particular Facilities
or Elements play a material role in the operation of the bulk grid.
b. Generation facilities can be included in the BES only if they are “needed to maintain” the reliability of the
bulk system. Accordingly, as noted above, the thresholds used in the NERC Statement of Registry
Compliance are not determinative of whether a generator is necessary to maintain bulk system reliability.
That determination is an engineering-based assessment and the fact that a generator may exceed the 20 MW
capacity threshold in the Registry Statement does not mean that the generator is “needed to maintain” bulk
system reliability. It may well not be.
c. “Reliability” was also given a specific meaning by Congress when it drafted Section 215. Specifically, the
statute defines “reliable operation” to mean “operating the elements of the bulk-power system within
equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation,
or cascading failures of such system will not occur as a result of sudden disturbances, including . . .
unanticipated failure of system elements.” Accordingly, the BES definition should focus on facilities that are
necessary to ensure that the bulk transmission system does not suffer instability, uncontrolled separation, or
cascading failures. Facilities that do not threaten these kinds of severe consequences should not be included
in the BES.
d. The definition explicitly excludes “facilities used in the local distribution of electric energy.” The definition
adopted by the Standards Drafting Team must therefore unequivocally exclude all local distribution facilities.
In light of these statutory constraints, Snohomish supports as part of the Standards Drafting Team’s process
the creation of a categorical exclusion from the BES for systems that meet NERC’s historical definition of
Local Network. As explained in more detail below, Local Networks are operated to provide service to specific,
geographically-limited service areas and do not affect the reliable operation of the bulk transmission system.
Accordingly, there is no good reason to include Local Networks in the BES and to do so would be contrary to
the language in the statute discussed above. Historically, NERC employed a definition of “Local Networks”
and NERC’s “Bulk Electric System” definition distinguished between the “Bulk Transmission System” and
“Sub-transmission.” More recently, those distinctions have been lost, diverting attention away from critical
elements of the transmission system that, if they fail, threaten cascading outages or other large-scale events,
and increasing attention to facilities that, if they fail, threaten only to disrupt service in a localized areas. The
Standards Drafting Team can remedy this over breadth problem by categorically excluding facilities meeting
the definition of “Local Networks” from the BES definition. Until a few years ago, NERC used the following
definition of “Local Network”: Local Network- a non-radial portion of a bulk electric system whose customers
may be interrupted for the loss of a single transmission element (100 kV or more). This loss of load is only

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allowed in those rare circumstances when it is impractical (e.g., long transmission distances, extremely high
costs with low benefits) to avoid interruption of service to a portion or all of the customers in the network due
to the network being directly connected to or supplied by the faulted transmission system element (e.g.,
generator, transmission circuit, transformer). The resulting customer interruption should be of relatively low
probability of occurrence and limited in magnitude (less than 100 MW). The interruption of such local network
customers shall not impact the overall security of the interconnected transmission systems. The term Local
Network is currently used in the NERC TPL Reliability Standard. However the definition is no longer defined
in the NERC Standard Glossary of Terms. The important distinctions between Local Networks and the Bulk
Electric System have been further obscured by changes in NERC’s BES definition. The “Bulk Electric
System” definition that appeared in the Glossary of Terms reference document approved by both the NERC
EC and OC at a joint meeting of those committees on July 16, 1996, distinguished between “Transmission”
and “Sub-transmission”: Bulk Electric System - A term commonly applied to the portion of an electric utility
system that encompasses the electrical generation resources and bulk transmission system. Where
Transmission - An interconnected group of lines and associated equipment for the movement or transfer of
electric energy between points of supply and points at which it is transformed for delivery to customers or is
delivered to other electric systems. Bulk Transmission - A functional or voltage classification relating to the
higher voltage portion of the transmission system. Sub-transmission - A functional or voltage classification
relating to the lower voltage portion of the transmission system. The current version of the BES definition
does not, by contrast, make such a distinction: Bulk Electric System - As defined by the Regional Reliability
Organization, the electrical generation resources, transmission lines, interconnections with neighboring
systems, and associated equipment, generally operated at voltages of 100 kV or higher. Radial transmission
facilities serving only load with one transmission source are generally not included in this definition. The
definitional changes have diverted attention away from the systems that pose the greatest risks of cascading
outages and toward systems that do not threaten such widespread reliability impacts. Protecting the electric
system from wide-spread cascading outages and focusing on protecting equipment and isolating cascading
outages has historically been the primary goal of NERC reliability efforts and, as FPA Section 215 requires,
should remain so now and in the future. It is clear, however, that there are real distinctions between “Bulk
Transmission,” “Sub-transmission,” and “Local Networks” in terms of their impacts on bulk system reliability.
We propose that, in order to restore these important distinctions, WECC categorically exclude systems
meeting the definition of Local Network from its BES definition. Doing so will refocus the NERC-WECC
reliability mission on those systems that most effect bulk system reliability, while excluding from the BES
ambit those systems whose impacts are purely local.
As noted above, Snohomish has participated in and supports the work of the WECC BESDTF. The
BESDTF’s current proposal contains a categorical exclusion for Local Networks along the lines of the one we
advocate here and the BESDTF has developed an extensive factual and technical record supporting its
approach. We urge the Standards Drafting Team to follow that approach.

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Response: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes
the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The SDT believes that this method of identification will provide the desired clarity requested by the industry and
directed by the Commission while ensuring that consistent results will be produced universally across the continent. In the development of the core definition and
the exception criteria, the SDT has considered your comments.
United Illuminating Company

Any technical definition should provide the means to differentiate facilities used in local distribution since
these facilities are excluded from the statutory definition of bulk-power system. The definition of BES should
be very broad or bright.

Response: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes
the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The SDT believes that this method of identification will provide the desired clarity requested by the industry and
directed by the Commission while ensuring that consistent results will be produced universally across the continent. In the development of the core definition and
the exception criteria, the SDT has considered your comments.
Orange and Rockland Utilities,
Inc.

a.) Proposed definitions to be added to the NERC Glossary of Terms: BES Exemption Process: The review
processes for (a) excluding facilities and elements from the BES that are determined not to be necessary
to support bulk power system reliability (e.g., radial elements), and (b) including Elements operated at
voltages below 100 kV that are determined to be necessary to support bulk power system reliability. By
identifying all such BES and non-BES facilities and elements, the BES Exemption Process will establish
the Points-of-Demarcation between Facilities and BES Elements and non-BES facilities and elements.
Point-of-Demarcation: A physical point and/or electrical connection between facilities and BES Elements
and non-BES facilities and elements, e.g., the upstream terminals of a disconnect switch (or a buss
connection) representing the boundary between a BES supply bus and a non-BES radial feeder.
b.) The BES exemption process has not yet been finalized or approved. So, it is somewhat difficult to know a
priori whether any element, elements or a group of elements or facilities should or should not be
classified as part of the BES definition.
c.) This document uses both “exemption process” and “exception process”. Recommend that the
phraseology be standardized on “exception process” as the exception (not the exemption) can be to
include or exclude elements and facilities.

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d.) It is envisioned that the BES Exemption Process will contain 3 sub-processes; one for Exclusion, one for
Exemption, and one for Inclusion. Each sub-process will establish provisions and guidelines for the
three different tasks. In order to ensure consistency across the continent, it is our view that NERC should
be the facilitator of these processes. NERC may choose to have some of these tasks performed at the
regional levels through the existing delegation agreements.
e.) The BES Exemption Process must be an active and ongoing aspect of the ERO program. With the
addition of new or deletion of existing Transmission and Generation Elements, facilities, or systems. It
needs to be recognized that Exclusions, Inclusions, and Exemptions might need alteration over time. By
establishing appropriate guidelines and processes, the ERO will be able to monitor and maintain
information of what is the Bulk Electric System, or BES.

Response:
a.) The SDT is not currently contemplating any additional definitions beyond BES. In regards to the term “BES Exemption Process’; it has been determined
that the process will reside in the NERC Rules of Procedure (ROP) and therefore it seems logical that the purpose of the process would be defined within
the boundaries of the NERC ROP.
b.) Exception criteria Agree. The Exemption Process is being developed by a separate team and will be posted for stakeholder comment.
c.) The inconsistency of the use of ‘exemption’ vs. ‘exception’ in several documents has been identified by the SDT and the team has determined that
‘exception’ is the proper term to be used in reference to the Bulk Electric System definition and supporting processes.
d.) The ‘Exception Process’ will be developed by the NERC Rules of Procedure Team while coordinating with the DBESSDT. The ‘Exception Process’ and
the responsibilities associated with the implementation and oversight will be defined by the NERC Rules of Procedure Team. Based on the language
contained in FERC Order No. 743, there are Commission expectations associated with the process oversight by the ERO and allowances for the
delegation of responsibilities to Regional Entities as appropriate, while ensuring the process is clear and capable of being applied consistently, objectively,
and uniformly across all regions. Note, however, that the drafting team has revised the definition of BES so that it now includes the exceptions (both
inclusions and exclusions) stakeholders have already proposed be applied to the 100 kV bright line threshold.
e.) The SDT agrees that the Bulk Electric System is dynamic and that the implementation and continued application of the BES Definition and supporting
processes will require active oversight and management to ensure that changing conditions (i.e., operational & new construction) surrounding the Bulk
Electric System will be addressed and result in proper evaluation and identification of BES & non-BES Elements.
American Transmission company

March 30, 3011

1. ATC suggests that once the term “exemption” is replaced with the term “exception”, then consider
modifying the BES definition wording to, “All Transmission and Generation Elements and Facilities operated
at voltages of 100 kV or higher, necessary to support bulk power system reliability. Elements and Facilities

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operated at voltages of 100kV or higher, including Radial Transmission systems, may be excluded through
the BES definition exception process and Elements and Facilities operated at voltages less than 100kV may
be included through the BES definition exception process”.
2. The “Concept Paper” does not specifically call out Transmission Lines above 100 kV as in the BES
definition (the proposed definition does, however) and there is a circular exemption criteria in the concept
paper. In criterion #2, it refers to the exemption process "consistent with the criteria". The criteria exempt
generating plant controls and Transmission Elements or Systems that are radial to a load or generator not
included in the BES List. However, the BES list is defined prior to the criteria in the concept paper. Exception
criterion #1 points to BES list elements #6 and #7, which in turn, refer to the exception process. But, the
exemption criteria never define how to exempt the elements referred to in #6 and #7.
3. The revised definition of the BES and exception process does not address a timeframe for the
implementation of this standard once approved, allowing enough time for the entities to provide justification,
and then make the necessary changes to their internal programs?
4. How often would a Registered Entity revisit this Exception Process? ATC can envision a scenario where
they are doing that every year or two because the loads, generation and transmission changes. The process
should also allow for multi-year distinctions for exceptions. In other words, if a Registered Entity gets a facility
excluded, then that exclusion should be allowed for 3 or more years. Annual certifications and approval are
two restrictive.
5. ATC believes the exception criteria needs to be developed by the SDT. NERC Staff should focus on the
process (identification, notification, appeal and rights) but the SDT is in the better position to develop the
technical piece of the exception criterion.
6. ATC also supports the comments as submitted by EEI REAC on the Draft Concept Paper on the Definition
of BES Project 2010-17.

Response:
1. The SDT has considered your comments in the further development of the core definition and the exception criteria. The drafting team has revised the
definition of BES so that it now includes the exceptions stakeholders have already proposed be applied to the 100 kV bright line threshold. The word,
“exemption” is not used in the proposed definition of BES.
2. The SDT has considered your comments in the further development of the core definition and the exception criteria. Please see the revised definition of
BES.
3. The Implementation Plan will need to address the impact of the revised BES definition and exception criteria, the Exception Process (ROP), and the

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regional Transition Plans on affected entities and provide sufficient time to ensure a smooth transition into the realm of mandatory and enforceable
Reliability Standards.
4. The ‘Exception Process’ will be developed by the NERC Rules of Procedure Team while coordinating with the DBESSDT. The DBESSDT recognizes that
the Bulk Electric System is dynamic and that the implementation and continued application of the BES Definition and supporting processes will require
active oversight and management to ensure that changing conditions (i.e., operational & new construction) surrounding the Bulk Electric System will be
addressed and result in proper evaluation and identification of BES & non-BES Elements. The time frames associated with the ‘review’ processes will be
determined by the NERC ROP Team. The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by
NERC staff and governed by current practice for administering such revisions.
5. The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying
BES and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or nonBES utilizing the core definition and exception criteria would be candidates for application of the Exception Process where the technical justification would
be required to identify Elements as BES (inclusions) or non-BES (exclusions).
The ‘Exception Process’ will be developed by the NERC Rules of Procedure Team while coordinating with the DBES SDT.
6. See responses to EEI comments.
The Dow Chemical Company

Dow has reviewed and generally supports the comments prepared by The Electricity Consumers Resource
Council (ELCON).

Response: See response to ELCON comments.
National Rural Electric
Cooperative Association
(NRECA)

March 30, 3011

a.) BES definition exemption criteria must be developed by the same SDT that is modifying the BES
definition and through the standards development procedure. The BES exemption criteria must not be
developed by a separate group outside of the standard development procedure, e.g., through a NERC
Rules of Procedure (ROP) modification process as is currently proposed in the SAR. The BES exemption
process, not criteria, can be included in the ROP by utilizing the process for making such modifications to
the ROP. The BES definition exemption process should refer to the procedure for applying for such an
exemption, not the criteria that such an exemption application would be based upon. It is critical for the
final SAR to provide clarity as it relates to what is considered exemption criteria and exemption process.

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b.) We appreciate the work of the Regional BES Definition Coordination Group, however, this group must
conclude its work now that a SAR has been proposed and is posted for comment. This group can provide
comment on this SAR and future products from the SDT in same way as any other stakeholder can
provide comment. Having a parallel effort led by Regional Entity staff, outside the formal Project 2010-17
SDT process, will create confusion and potentially cause inefficient use of industry resources. All efforts
should be focused on the formal standard development activities including related future comment and
ballot periods. Compliance registry criteria should only be reviewed and potentially modified if specifically
needed to implement a modified BES definition and associated exemption criteria.
c.) The SDT is tasked with addressing definition modifications to ensure consistent and uniform application
of the BES definition across the Regional Entities. The focus of the SDT's work should first be on the
BES definition and exemption criteria. Any Compliance Registry Criteria modifications would have to be
approached very carefully as it was developed through a lengthy stakeholder consensus process.

Response:
a.) The NERC Standard Processes Manual is the governing document for the development of the revised BES definition and exception criteria. The SDT is
continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the overall
starting point for assessing BES and non-BES Elements. The ‘exception criteria’ (now proposed for inclusion in the definition of BES) utilizes the same
‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation
Facilities, radials, etc.).
The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC
staff.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the
Exception Process by the NERC ROP team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which
will enable the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the
exception criteria, and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be
responsive to the directives in Order No. 743 the decision was made to establish two teams working in close coordination to address the issues related to
the project.
b.) When the NERC Standards Committee accepted the SAR and established the SDT, the RBESDCG acknowledged that the primary development of
definition and supporting documents had shifted from the RBESDCG to the SDT. The RBESDCG agrees that parallel efforts will result in inconsistencies
and disruption of the SDTs efforts. Therefore, the RBESDCG forwarded all applicable work products to the SDT and to the NERC ROP Team for
consideration. Going forward, the RBESDCG will support the development of the definition, supporting documents, and the revisions to the ROP by
collectively participating in the respective development processes (i.e., providing consensus comments to posting and participating in the associated

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Question 13 Comment

balloting process).
c.) Any impact of the revised core definition, the exception criteria, or Exception Process on the current Registry Criteria will be addressed in the
Implementation Plan.
City of Austin dba Austin Energy

The word “exemption” in the last line is confusing. Lines above 100kV would be “exempted” from inclusion as
part of the BES. Lines below 100kV would be “added” to the BES (under certain circumstances) which,
technically, is not an “exemption.” (In fact, the Word document on the NERC web page refers to the process
as an “Exception Process”) AE recommends the following language: Bulk Electric System: All Transmission
and Generation Elements and Facilities operated at voltages of 100 kV or higher necessary to support bulk
power system reliability. Elements and Facilities operated at voltages of 100kV or higher, including Radial
Transmission systems, and Elements and Facilities operated at voltages less than 100kV may be included if
approved through the process described in the BES Definition Exception Process.

Response: The inconsistency of the use of ‘exemption’ vs. ‘exception’ in several documents has been identified by the SDT and the team has determined that
‘exception’ is the proper term to be used in reference to the Bulk Electric System definition and supporting processes. In the development of the core definition and
the exception criteria, the SDT has considered your comments. Please see the revised definition of BES – it now includes a list of both “Inclusions” and
“Exclusions” as part of the definition and no longer references an exemption (or exception) process).
Duke Energy

There should be a provision for the Planning Coordinator or Transmission Planner to include individual
generators and generation plants that are not included in these criteria through a technical evaluation, either
in the definition or in the inclusion of facilities below 100 kV portion of the exemption process. For example,
generating facilities connected to generator step up transformers below 100 kV that have a demonstrated
ability to have a significantly adverse affect on the reliability on the bulk power grid or a major urban load
center should be included.

Response: The SDT agrees with the commenter, in that any Exception Process should establish a process for exceptions from and inclusions to the BES. As
stated in FERC Order No. 743, P83 “The Commission’s proposed approach to addressing these concerns will enable affected entities to pursue exemptions for
facilities they believe should not be included in the bulk electric system, and also will allow Regional Entities to add facilities below 100 kV they believe should be
included”. The Regional Entities currently have the authority to include Elements operated at voltages below 100 kV that are deemed necessary for the reliable
operation of the BES. The Order does not eliminate this authority, but rather emphasizes the need to maintain the Regional Entity’s ability of establishing
inclusions to the BES through the Exception Process. Under these circumstances, the SDT feels that a Planning Coordinator or Transmission Planner could
pursue inclusion of selected Elements into the BES by lobbying with their Regional Entity. exception criteria
BGE

a.) NERC should use the FERC-approved standards development process for developing the technical
criteria for both the BES definition and exemptions process. We view this as a single exercise. BGE

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Question 13 Comment
feels joint development of the BES Definition & Exception Process under a single SDT would be
preferable. The standards drafting project should ensure that the definition expressly incorporates these
exclusions for facilities below 100 kV. Entities should not have to seek an exemption for facilities below
100 kV or for radial lines. They should be clearly excluded in the BES definition itself.
b.) We encourage the drafting team to embrace a design concept that seeks to maximize the “brightness” of
bright line criteria. The BES exemptions process should contemplate very few exemptions. The TFE
process is an example of a process not to be repeated here.

Response:
a.) The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception
Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which will enable
the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception criteria
and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the
directives in Order No. 743 the decision was made to establish two teams working in close coordination to address the issues related to the project.
b.) The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying
BES and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or
non-BES utilizing the core definition and exception criteria would be candidates for application of the Exception Process where the technical justification
would be required to identify Elements as BES (inclusions) or non-BES (exclusions).
City Water Light and Power
(CWLP) - Springfield, IL

Relative to the BES Definition Exclusion Process, CWLP has chosen to comment on the inclusion/exclusion
process as a whole. The current lack of detailed, firm administrative guidelines as well as an unambiguous
process for resolving disputes between parties involved in the process of adjudicating inclusions/exclusions is
problematic. It is CWLP’s belief that developing the proposed administrative framework for the process is
needed first. Focusing on the data to be submitted as shown in (1) and (2) above does not address the
scope, nature, and criteria applicable to the review of requests for inclusions/exclusions. Regardless, CWLP
feels strongly that the sole basis for approval or rejection of a request should be technical justification.
Speaking to the process in general, any inclusion or exclusion should be a specific request for a specific
facility; continent-wide, interconnect-wide, and region-wide applicability for inclusions/exclusions departs from
the intent of FERC Order 743 to establish a definition without regional variances.

Response: The SDT has considered your comments in the further development of the core definition and the exception criteria .

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Question 13 Comment

The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying
BES and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or nonBES utilizing the core definition and exception criteria would be candidates for application of the Exception Process where the technical justification would be
required to identify Elements as BES (inclusions) or non-BES (exclusions).
A revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT along
with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC staff. With
that in mind, the SDT agrees with the commenter in that the Exception Process should be a manageable process that is clear, unambiguous, and repeatable
and establishes consistency on a continent-wide basis.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception
Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which will enable the
industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception criteria, and
the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the directives in
Order No. 743 the decision was made to establish two teams working in close coordination to address the issues related to the project.
Lewis County PUD

The ever increasing regulatory environment does little to improve electric reliability. Suggest that the BES
definition only include the most critical elements of the electric system and leave the smaller elements out of
the definition, e.g. less than 100kV and less than 150MVA.

Response: The SDT has established basic goals and assumptions that will be used to guide the development of the BES definition and supporting documents.
The assumptions include: ‘The revised definition will not significantly expand or contract what are currently considered BES Elements, nor will the revised
definition drive entity registration or de-registration. Based on these goals and assumptions the overall impact of the revised definition is expected to be minimized
for the majority of the Regions and Registered Entities. exception criteria
American Electric Power (AEP)

There needs to be more comprehensive BES nomenclature established that distinguishes among the
applicable primary-voltage equipment, the associated auxiliary equipment having an impact to the BES, and
the associated ancillary equipment having no electrical impact to the BES.
The draft versions of PRC-005-2, Protection System Maintenance, look to bring into scope “systemconnected station service transformers for generators that that are part of the BES”. These transformers are
not clearly included within the proposed BES criteria, and consistency must be obtained between the two

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Question 13 Comment
documents.

Response: The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes
the overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying BES
and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or non-BES utilizing
the core definition and exception criteria would be candidates for application of the Exception Process where the technical justification would be required to identify
Elements as BES (inclusions) or non-BES (exclusions).
The SDT will be reviewing all NERC and Regional Reliability Standards to ensure that no conflicts have been established between the core definition, the
supporting documents and procedures, and the applicability or requirements in the standards.
Southern Company

a. The proposed definition includes the phrase "... necessary to support bulk power system reliability". The
exemption process should resolve the question related to precisely which transmission and generation
elements and facilities are necessary to support reliability of the bulk power system.
b. A clear definition of what is included in “Generation Elements and Facilities” is needed. Does it include
components other than the GSU transformer? As written, does the BES extend beyond the low voltage
side of a GSU transformer?

Response: The SDT has considered your comments in the further development of the core definition and the exception criteria.
a. The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying
BES and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or
non-BES utilizing the core definition and exception criteria would be candidates for application of the Exception Process where the technical justification
would be required to identify Elements as BES (inclusions) or non-BES (exclusions).
A revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC
staff. With that in mind, the SDT agrees with the commenter in that the Exception Process should be a manageable process that is clear, unambiguous,
repeatable, and establishes consistency on a continent-wide basis. We will forward your comment to the NERC ROP Team.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception

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Yes or No

Question 13 Comment

Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which will enable
the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception
criteria, and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to
the directives in Order No. 743 the decision was made to establish two teams working in close coordination to address the issues related to the project.
b. The SDT is not contemplating any further definitions beyond BES based on the latest revision to the definition. Please see the revised definition of BES as
this incorporates more details about including specific generation elements.
Independent Electricity System
Operator

a. On the SAR, it indicates an SC approval date of December 8. It is misleading since the SC did not approve
the SAR; it only approved posting of the SAR for industry comment.
b. We have a concern with the concept paper on the exemption/inclusion criteria/process. Please see other
comments on that paper submitted separately.
c. We suggest use of consistent term between “exception” and “exemption”.
d. We suggest the exception/inclusion criteria to be included in the definition and developed/approved by the
balloting body. Determining these criteria via any other processes will not provide the industry the opportunity
to fully vet the criteria.
e. The SAR indicates that “...the definition drafting team will work closely with the team developing the BES
definition exemption process to develop a single coordinated implementation plan. It is also envisioned, that
the team working to develop the BES definition exemption process will solicit input from drafting teams,
stakeholders....” We find this confusing and have a concern that having two teams working on this
definition/criteria package leads to misalignment and confusion. Further, while the definition drafting team is
formed by a nomination process and appointed by the NERC Standards Committee, there is no transparency
and/or public announcement to solicit nominations for the team working to develop the exemption process.
We urge the NERC Standards Committee to direct the definition drafting team to also be responsible for
developing the exemption process, and include the exemption criteria as part of the definition hence
subjecting them to industry comment and balloting.

Response:
a. The default language in the form is misleading and implies that the NERC Standards Committee’s approval is required. Per the NERC Standard Process
Manual the Standards Committee authorizes posting of the SAR for industry comment. The DBES SDT will provide a recommendation to NERC
Standards Staff to revise the SAR form to read, "Date SC Authorized Posting the SAR”.
b. The SDT has considered your comments in the further development of the core definition and the exception criteria. Note that the revised definition of BES
now includes lists of criteria for both “inclusion” and “exclusion”.

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Question 13 Comment

c. The inconsistency of the use of ‘exemption’ vs. ‘exception’ in several documents has been identified by the SDT and the team has determined that
‘exception’ is the proper term to be used in reference to the Bulk Electric System definition and supporting processes.
d. The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ (now proposed for inclusion in the definition of
BES) utilizes the same ‘bright-line’ criteria to provide further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for
identifying generation Facilities, radials, etc.). The tight linkage between the core definition and the exception criteria provides the framework for identifying
BES and non-BES for the vast majority of the Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or
non-BES utilizing the core definition and exception criteria would be candidates for application of the Exception Process where the technical justification
would be required to identify Elements as BES (inclusions) or non-BES (exclusions).
e. The SDT is continuing the development of the concept of a component-based ‘bright-line’ definition which consists of a core definition that establishes the
overall starting point for assessing BES and non-BES Elements (100 kV threshold). The ‘exception criteria’ utilizes the same ‘bright-line’ criteria to provide
further guidance as to whether an Element is considered BES or non-BES (i.e., bright-line criteria for identifying generation Facilities, radials, etc.). The
tight linkage between the core definition and the exception criteria provides the framework for identifying BES and non-BES for the vast majority of the
Elements under consideration. The remaining Elements that cannot be definitively indentified as BES or non-BES utilizing the core definition and
exception criteria would be candidates for application of the Exception Process where the technical justification would be required to identify Elements as
BES (inclusions) or non-BES (exclusions).
The revision process for the NERC ROP will be utilized to develop the Exception Process and will be coordinated by NERC staff and governed by current
practice for administering such revisions. The NERC ROP Team will be established by NERC staff and will include representation from the DBESSDT
along with industry experts and NERC staff personnel. The process for establishing the NERC ROP Team will be determined and administered by NERC
staff.
The development of the core definition of the BES and the exception criteria by the SDT will be closely coordinated with the development of the Exception
Process by the NERC ROP Team. The goal (identified key to the project’s success) is to have postings from each aspect of the project, which will enable
the industry to review the entire project ‘package’ at one time and effectively provide comments simultaneously on the core definition, the exception criteria
and the Exception Process. Based on the Commission imposed time requirements for filing and the amount of work required to be responsive to the
directives in Order No. 743, the decision was made to establish two teams working in close coordination to address the issues related to the project.
APPA

See text submitted under Question 12.

Response: See response to Q12.
Xcel Energy

March 30, 3011

It is not clear as to why the Reliability Assurer is included as an applicable entity in the SAR.

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Response: The NERC Functional Model Version 5 defines the role of the Reliability Assurer as: “The functional entity that monitors and evaluates the activities
related to planning and operations, and coordinates activities of functional entities to secure the reliability of the Bulk Electric System within a Reliability Assurer
area and adjacent areas”. Any revision to the definition of the Bulk Electric System could potentially expand or contract the ‘Reliability Assurer area’ which would
have a direct effect on the responsibilities indentified in the Functional Model.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Summary Consideration: Prior to the issuance of Order 743a, the SDT reviewed all of the
provided material and used this material and the examples supplied in its consideration of the
revised definition of the Bulk Electric System (BES). The goal of the SDT is to provide a brightline definition of BES which adheres to the guidelines and directives in Order 743. This brightline definition contains certain inclusions and exclusions for specific equipment and
configurations. The SDT believes that this definition now answers many of the questions raised
by industry and encompasses most of the examples provided. However, no bright-line definition
will be able to capture all of the concerns or situations. Accordingly, and consistent with Order
743, another aspect of this project is to establish an exception process with criteria based on
reliability principles for the Interconnected BES that will be incorporated in NERC’s Rules of
Procedure (ROP) that will allow a process for the inclusion or exclusion of a particular BES
Element from the definition. This ROP work effort will be done by a separate team but the
DBESSDT will be in close coordination with that team.
Question 1:
If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
b. Provide a generic one‐line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
d. Identify if this exclusion should apply on a continent‐wide basis,
interconnection‐wide basis, region‐wide basis, or less than a region‐wide basis. If you
don’t know how widely this exclusion should apply, please select, “unknown.”
Commenters:
John A. Gray, The Dow Chemical Company ................................................................................. 3
Michael Moltane & John Zipp, ITC Holdings ................................................................................ 5
Frank Gaffney, Florida Municipal Power Agency, Et all ............................................................... 6
Josh Dellinger, Glacier Electric Cooperative................................................................................ 13
Michelle Mizumori, Western Electricity Coordinating Council................................................... 14
Brandy A. Dunn, Western Area Power Administration ............................................................... 16
Alain Pageau, Hydro-Québec TransÉnergie ................................................................................. 17
Guy Zito, Northeast Power Coordinating Council ....................................................................... 18
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Jim Uhrin, ReliabilityFirst Corporation ........................................................................................ 20
Joe Petaski, Manitoba Hydro ........................................................................................................ 21
John W. Delucca, Lee County Electric Cooperative .................................................................... 22
Paul Cummings, City of Redding ................................................................................................. 24
Patrick Farrell, Southern California Edison Company ................................................................. 25
Ed Davis, Entergy Services, Inc ................................................................................................... 27
Manny Robledo, City of Anaheim ................................................................................................ 28
Lorissa Jones, Bonneville Power Administration ......................................................................... 30
David Burke, Orange and Rockland Utilities ............................................................................... 31
Jim Case (Entergy), SERC OC Standards Review Group ........................................................... 33
Thad Ness, American Electric Power ........................................................................................... 34
Amir Hammad, Constellation Power Source Generation, Inc., Et all .......................................... 36
William J. Gallagher, Vermont Public Power Supply Authority ................................................. 38
David Angell, Idaho Power........................................................................................................... 44
Marc M. Butts, Southern Company .............................................................................................. 45
Andrew Z. Pusztai, American Transmission Company ................................................................ 46
Ronald Sporseen, PNGC Power, Et all ......................................................................................... 48
Jerome Murray, Oregon Public Utility Commission .................................................................... 50
John D. Martinsen , Public Utility District No. 1 of Snohomish County ..................................... 51
Steve Alexanderson P.E., Central Lincoln.................................................................................... 53

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

John A. Gray, The Dow Chemical Company
Phone: 281‐966‐2390
Email: JAGray3@dow.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
As discussed in the comments of The Dow Chemical Company (“Dow”) on the
recommended definition of BES, the 100 kV standard is inapplicable to generation
and should not be used to identify generation facilities that are included in the BES,
or that are eligible for an exception or exclusion. Instead, the NERC Statement of
Compliance
Registry Criteria already sets forth criteria for determining when individual
generating units and generating plants/facilities are not part of the bulk electrical
system. Those existing standards and the generator‐specific registration
determinations that have been made using those standards should be preserved.
Dow does not object to retaining a 100 kV standard for identifying transmission
facilities that should be considered part of the BES, but exclusions must be made for
distribution facilities and interconnection facilities. If owners and/or operators of such
facilities are required to secure an “exception” or “exclusion” from the 100 kV
standard, then such process must ensure that exceptions or exclusions are available
before mandatory reliability standards become applicable.
b. Provide a generic one‐line diagram depicting the Element or Facility in question (if
available).
For a manufacturing site, distribution facilities deliver electricity from the generating
plants and or the transmission grid to the manufacturing plants. Interconnection
facilities are generally identified by reference to the point of interconnection with the
transmission grid. Facilities located on the generator’s side of this interconnection up
to the site transformers are generally considered interconnection facilities while
facilities located at or beyond the point of interconnection are generally considered
transmission facilities.
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: The NERC Statement of Compliance Registry Criteria excludes
certain generating facilities, because these generating facilities are not material to the
reliability of the BES. Distribution facilities are expressly excluded from the
definition of BES pursuant to Section 215 of the Federal Power Act. Distribution
facilities are typically operated differently from transmission facilities. As such,
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

distribution facilities should not be subject to the same reliability standards as
transmission facilities. FERC has recognized that interconnection facilities may or
may not be material to the reliability of the BES. As such, FERC has held that a
facts‐and‐circumstances analysis should be used to determine whether and to what
extent such facilities should be considered part of the BES and, therefore, subject to
mandatory reliability standards. See New Harquahala Generating Company, LLC,
123 FERC ¶ 61,173 at P 44 (2008), clarified, 123 FERC ¶ 61,311 (2008).
d. Identify if this exclusion should apply on a continent‐wide basis,
interconnection‐wide basis, region‐wide basis, or less than a region‐wide basis. If you
don’t know how widely this exclusion should apply, please select, “unknown.”
Continent-wide
Comments relative to the proposed exclusion(s):
At minimum, the exclusions applicable to distribution facilities and interconnection
facilities should apply to all facilities that are subject to FERC’s reliability
jurisdiction under Section 215 of the Federal Power Act.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Michael Moltane & John Zipp, ITC Holdings
Telephone: 248-946-3093
Email:
mmoltane@itctransco.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
Comments relative to the proposed exclusion(s): It is unclear how we would identify
an individual element then in part d. declare it Region-wide. This needs to be made
more clear

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Frank Gaffney, Florida Municipal Power Agency, Et all
Florida Municipal Power Agency is filing the comments below on behalf of its’ project
participants:
City of New Smyrna Beach
KUA
Lakeland Electric
City of Clewiston
Beaches Energy Services
Ocala Electric Utility
Telephone: 407-355-7767
Email: frank.Gaffney@fmpa.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a . Identify the Element or Facility recommended for exclusion:
This question refers to “exclusions”; we believe, however, that the intent of this
comment form is to elicit feedback on the process for “exemptions.” It is important
to distinguish between the two concepts, as FERC did in Order 743. See, e.g.,
Paragraph 1, which refers to “maintain[ing] a bright-line threshold that includes all
facilities operated at or above 100 kV except defined radial facilities,” as well as to
“establish[ing] an exemption process and criteria.” (emphasis added). In other
words, in brief, an “exclusion” is outside of the BES by definition, whereas exempt
Elements are removed on a case-by-case basis by going through a process.
FMPA draws the distinction as follows:
An exclusion is the removal of a category of Elements from the BES definition. The
current BES definition explicitly carves out radials serving only load with one
transmission source. This is a clear example of an exclusion. There is no “exclusion
process” now, nor should there be one in the future; the point of an exclusion is that
the class of excluded Elements can—without any process—be treated like sub100 kV transmission, in that they are presumed to be non-BES unless a particular
Element is demonstrated, on a case-by-case basis, to be properly included in the BES
(see responses to Questions 5 and 11 in FMPA’ comments on BES definition,
submitted today, and FMPA response to Question 2 below).
An exemption, on the other hand, is a finding that a particular Element, although
nominally part of the BES, does not need to be included in the BES because it is not
necessary for operating an interconnected transmission network.
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Because exemptions are less clear-cut than exclusions, each exemption of an Element
needs to be approved by NERC so that the Registered Entity and compliance
authorities have certainty about the Elements with respect to which compliance is
required. In many, perhaps all, cases, this process will likely require a case-by-case
examination of each Element for which an exemption is requested.
FMPA responds to this question with respect to the one “exclusion” from the BES
definition that we advocate, that of radial Transmission Elements serving only load
and/or generation not registered pursuant to the Statement of Compliance Registry
Criteria. We also propose uniform criteria for deciding, on a case-by-case basis,
whether to grant requested exemptions from the BES, or to include nominally nonBES Elements in the BES. The process that we propose for exemption requests and
proposed inclusions is discussed below in response to the invitation of “[c]omments
relative to the proposed exclusion(s).”
Exclusion:
FMPA proposes only one exclusion from the BES definition, namely, “Radial
Transmission Elements serving only load with one Transmission source are generally
not included in this definition. A radial Transmission Element may be considered as
‘serving only load’ for purposes of the foregoing general exclusion even if it connects
generation, so long as that generation is not registered pursuant to the Statement of
Compliance Registry Criteria.” This formulation, which is discussed in FMPA’
comments submitted today on the BES definition, is intended to preserve the current
exclusion of radials serving only load with one transmission source, and to clarify that
the presence of a generator that is not registered under the Compliance Registry
Criteria does not convert a radial into a BES Element. The end result is that radial
transmission is excluded unless it connects generation that is registered pursuant to
the Statement of Compliance Registry Criteria. Consistent with the Compliance
Registry Criteria, a single generator under 20 MVA, or a plant under 75 MVA, if not
designated as a Blackstart Resource needed for system restoration, is unlikely to
affect the grid. Therefore, the presence of such generation should not require that an
otherwise non-BES radial be included in the BES. Rooftop photovoltaic cells, for
example, are increasingly common. If FMPA’ proposed clarification is not accepted,
the presence of such insignificant generation could nullify the exclusion of radials to
load with one transmission source, with no benefit to reliability.
Exemption criteria
FMPA has not yet developed a list of criteria that we believe to be exhaustive, though
we emphasize that such a list must be an ultimate goal of this process. We propose
the following criteria as a start:
FMPA proposes that at least two classes of elements be eligible to request an
exemption:

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

i. Elements that are part of a radial “system” originating from a single BES source
serving only load, as in the Florida Keys. Clarifications: a) radial system means any
number of series and/or parallel Elements as long as they all originate from a single
BES source and do not have another BES source; b) “single BES source” means one
BES bus / substation / switching substation at one voltage level, and c) consistent
with FMPA’ proposed exclusion of radials serving only load and unregistered
generation, “serving only load” includes serving generation that is not registered
through the Statement of Compliance Registry Criteria.
ii. Elements that are part of a “looped” system that has two transmission sources
primarily for local quality of service to the retail customers supplied by the looped
system in question and is not used for bulk electric system flow (e.g., the transfer
distribution factor of flows across the looped system is low, representing a high
impedance path across the looped system). Specific criteria might be: a) a looped
system that participate in less than a 5% of transfer (e.g., 5% or less transfer
distribution factor); and b) that the looped system in question does not limit transfers.
A radial or looped system to be exempted must meet the following criteria:
1. The radial or looped system may not contribute to any Category D or C
contingency resulting in: 1) a supply / demand mismatch greater than the largest loss
of source contingency in the Reliability Coordinator area; or 2) an Adverse Reliability
Impact where, if the Element were not involved in those Category D or C
contingencies, those thresholds would not be exceeded.
Studies to determine whether this criterion is met would be conducted in accordance
with TPL-004-0 and TPL 003-0 standards (or corresponding contingencies in revision
to the TPL standards) in the Short Term Planning Horizon. Although the above
criteria are acceptable responses to a Category D contingency, the concept of the test
is to see if a radial or looped system would cause a significantly worse response to
Category C or D contingencies by testing the contingency with and without the radial
or looped system. FMPA believes that such criteria are good indicators that a radial
or looped system should be included in the BES as it highlights whether the
protection systems are important for critical clearing times, and whether the radial or
looped systems can contribute to an Adverse Reliability Impact in combination with
other contingencies;
2. No portion of the radial or looped system may meet any of the conditions of
Attachment 1 to CIP-002-4;
3. No portion of the radial or looped system may meet any of the conditions listed in
items B1 to B5 of Attachment B to PRC-023-2;
4. No portion of the radial or looped system may be a part of, or be a limiting
element of, any Path, Interchange, or Flowgate used in the calculation of ATC in
accordance with standards MOD-028, MOD 029 or MOD 030; and
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

5. No portion of the radial or looped system may include a blackstart resource or
cranking path deemed significant to the TOP or RC restoration plans of EOP-005,
EOP-006 or EOP-007.
If a Registered Entity demonstrates to NERC that an Element that is nominally in the
BES meets all of these criteria, the exemption would be granted.
Conversely, if NERC demonstrates that a nominally non-BES Element meets the
negative of any of these criteria (e.g., if any portion of the radial or looped system
meets any of the conditions of Attachment 1 to CIP-002-4 or of Attachment B to
PRC-023-2), the Element would be included in the BES.
Throughout these comments, FMPA refers to “Elements” and not to “facilities.” This
is because “Facility” is defined in the NERC Glossary as “[a] set of electrical
equipment that operates as a single Bulk Electric System Element….” Because these
comments (and the BES definition) address whether Elements are or are not part of
the BES, it is incorrect to refer to the Elements in question as “Facilities,” because a
Facility is defined as a BES Element.
In developing the exemption/inclusion criteria and process, NERC and the SDT
should bear in mind the requirement of Order 743: “NERC should develop an
exemption process that includes clear, objective, transparent, and uniformly
applicable criteria for exemption of facilities that are not necessary for operating the
grid.” Paragraph 115 (emphasis added). NERC and the SDT should also bear in
mind that FERC anticipates that between the BES definition and the exemption
process, there will be only “minimal[]” effect on “small entities.” Order 743,
Paragraph 169. Order 743 is referring to the Small Business Act definition of a
“small electric utility” as one that has a total electric output of less than four million
MWh in the preceding year. See BES NOPR, 133 FERC ¶ 61,150, Paragraph 35 &
footnote 50.

b . Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c . Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Radial Transmission Elements serving only load have been
recognized for years as non-BES because such Elements are very unlikely to affect
the BES. FERC stated in Order 743 that NERC may retain that exclusion.
Similarly, generators under 20 MVA and generating plants under 75 MVA are not
subject to registration pursuant to the Statement of Compliance Registry Criteria,
which has been accepted by FERC, because of the recognition that such generators
are very unlikely to affect the BES. It is thus consistent with the Compliance
Registry Criteria to exclude from the BES definition radials serving load with one
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

transmission source even if there is some generation on the radial, so long as none of
the generation is registered. If the generation is not significant enough to be
registered, it is not significant enough to transform an otherwise non-BES radial to
load into a BES Element.

d . Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide
The exclusion of radials to load and unregistered generation, as part of the BES
definition, should apply on a continent-wide basis.
Each Element proposed for exemption or inclusion should be considered individually,
under the same criteria (proposed above), applied uniformly continent-wide.

Comments relative to the proposed exclusion(s):
Exemption and Inclusion Processes:
The exemption and inclusion processes should be designed to ensure continent-wide
uniformity to the maximum extent possible. To that end, NERC must use a uniform
process; the criteria for approving or denying an exemption, or for including an
Element in the BES, must be clear; and entities must be able to appeal decisions to
another body within NERC or to FERC.
In order to obtain an exemption, a Registered Entity should be required to
demonstrate that the Element for which it is requesting an exemption is not
“necessary for operating an interconnected electric transmission network.” This is the
standard set out in Order 743; it is also part of the definition of the “bulk-power
system” in Section 215 of the Federal Power Act, 16 U.S.C. § 824o(a)(1)(A) (the
other part of the statutory definition is “electric energy from generation facilities
needed to maintain transmission system reliability,” 16 U.S.C. § 824o(a)(1)(B)).
Application of this standard should be informed by the statutory definitions of
“reliability standard” (“a requirement, approved by the Commission under this
section, to provide for reliable operation of the bulk-power system”) and “reliable
operation” (“operating the elements of the bulk-power system within equipment and
electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden
disturbance, including a cybersecurity incident, or unanticipated failure of system
elements”).

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Conversely, to include a nominally non-BES Element in the BES, NERC should be
required to demonstrate that the Element is necessary for operating an interconnected
electric transmission network.
Criteria for determining whether an Element is or is not “necessary for operating an
interconnected electric transmission network” are proposed in response to Question
1(a) above. The criteria should be uniform continent-wide, though they will be
applied to each Element on a case-by-case basis.
Exemption requests and proposed inclusions should be decided by NERC staff in the
first instance. FMPA does not believe that the exemption and inclusion processes
should be delegated to the Regional Entities. In Order 743, FERC emphasized the
need for continent-wide uniformity; in fact, it was inconsistency among regions that
prompted Order 743. FMPA members’ experience with Regional registration
processes suggests that Regional implementation of the BES exemption and inclusion
processes is unlikely to yield the uniformity that FERC directed. Furthermore,
implementing this FERC directive will unavoidably require significant personnel
resources, either at NERC or at the Regions. Delegating the process to the Regions
would impose additional costs due to the need for NERC to exercise strong oversight
to attempt to maintain uniformity. It may be that after the exemption and inclusion
processes have been in place for a few years and a body of precedent has been
accumulated, delegation will be appropriate. At this time, however, NERC staff
should make the initial decision on all exemption requests and proposed inclusions.
FMPA proposes, for the sake of consistency with the registration appeal process, that
appeals of decisions on exemptions and inclusions be to the Board of Trustees
Compliance Committee (BOTCC), with further appeals to FERC if necessary.
Appeals to the BOTCC would consist of the record compiled by NERC Staff, and
additional paper submissions by NERC Staff and the Registered Entity demonstrating
why the Element(s) in question is or is not “necessary for operating an interconnected
electric transmission network.” See NERC Rules of Procedure, Appendix 5A,
“Organization Registration and Certification Manual,” at 14-16. Registered Entities
should have the option of requesting a hearing. Hearing procedures could be modeled
on the Compliance and Certification Committee’s “Hearing Procedures for Use in
Appeals of Certification Matters,” in Appendix 4E of the NERC Rules of Procedure.
FMPA also suggests that decisions on exemptions and inclusions be made available
to others, either subject to CEII protection or in a form suitable for public release. As
precedent develops, Registered Entities will increasingly be able to judge for
themselves the likelihood that a particular exemption will be granted, or that an
appeal of an inclusion will succeed. We expect that giving Registered Entities more
information on which to base their decisions will significantly reduce the burden on
NERC of processing exemptions and inclusions.
We propose that BES Elements for which an exemption request is pending should
continue to be included in the BES until the exemption and any appeals are decided,
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

and that non-BES Elements for which an inclusion is pending should continue to be
non-BES until the inclusion and any appeals are decided.
The transition process should include an important exception to the general rule
proposed for BES status during the pendency of an exemption request: to allow for a
smooth transition, to the extent that Elements that are currently considered non-BES
become BES under the new definition, those Elements should be permitted to request
exemptions and to continue to be considered non-BES until their exemption requests
and any appeals are decided.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Josh Dellinger, Glacier Electric Cooperative
Telephone: 406-873-5566
Email:

joshd@glacierelectric.com

1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Our delivery point,
which is a loop-fed 115kV switching station.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: This station’s main purpose is to be a delivery point for our system.
We are a distribution cooperative that serves mainly residential and small commercial
loads. Each year we peak around 35 MW and average around 22 MW. This station
is loop fed by two 115 kV lines to give our members more reliability. No
transmission planner, balancing authority, transmission operator, reliability
coordinator, etc. has included this station in any critical path lists or system
restoration plans. This station is not designated as critical asset by its balancing
authority or transmission operator. The available short-circuit MVA at this station is
677 MVA. If a fault were to occur at this station, outages would be limited to the
local area and the BES as a whole would not be adversely affected at all. It is our
belief that facilities such as this are insignificant to the BES and do not need to be
considered part of the BES.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Michelle Mizumori, Western Electricity Coordinating Council
Telephone: 801-819-7624
Email: mmizumori@wecc.biz
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Those elements or
facilities above 100 kV that are shown through engineering studies to not be necessary
to reliably operate an interconnected transmission system.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: An element or facility that is not necessary to reliably operate an
interconnected transmission system need not be included in the Bulk Electric System
(BES). This can be assessed using engineering studies that show the effect of worstcase disturbances on multiple indicators such as frequency, voltage, system flows,
operating limits, generator tripping, cascading outages, and/or islanding with the
element or facility removed from service. An element or facility is not necessary to
reliably operate if the system can maintain acceptable steady-state and dynamic
performance during and after a worst-case disturbance with the element removed from
service.
d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Comments relative to the proposed exclusion(s):
The BES functions to generate bulk power and transfer that bulk power to locations
from which it is then distributed to end-use load. Elements that generate bulk power,
transfer bulk power, or support the transfer of bulk power are part of the BES.
An element is necessary to reliably operate an interconnected transmission system if it
significantly affects the ability of the BES to generate bulk power or carry bulk power
to locations from which is it distributed to end-use load. While operating voltage (i.e.,
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Proposed Definition of Bulk Electric System – Project 2010-17
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March 25, 2011

the proposed 100 kV bright-line) may be a clear and repeatable proxy for identifying
those elements that are necessary to reliably operate an interconnected transmission
system, it is a broad approach that may not adequately address specific examples.
Moreover, engineering studies can be used to more granularly and accurately identify
elements that are not needed to reliably operate an interconnected transmission system.
The thresholds on the indicators listed above may vary between interconnections and
regions. For example, voltage deviation may be more relevant in the Western
Interconnection (which is primarily stability limited) than in the Eastern Interconnection
(which is primarily thermally limited).

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Brandy A. Dunn, Western Area Power Administration
Telephone: 720-962-7431
Email: dunn@wapa.gov
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Any Element above
100-kV that is shown (through system studies) to NOT be necessary to reliably
operate the interconnected transmission system.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: An Element that is not required to reliably operate the interconnected
transmission system does not need to be included in the BES (or specifically calledout in the definition). This can be assessed through engineering system studies that
show the worst-case results based on indicators such as voltage, frequency, OTC
limits, angular instability and/or cascading outages based on that Element being
removed from service.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Comments relative to the proposed exclusion(s): An Element is necessary to
reliably operate the interconnected transmission system if it significantly affects the
ability of the BES to carry bulk power to end-use load. While a brightline test
voltage (such as the proposed >100-kV) may be a clear and repeatable proxy for
identifying Elements that are necessary to reliably operate the interconnected
transmission system, this broad approach may not adequately address specific
examples. Engineering system studies can accurately identify Elements which are not
needed to reliably operate the interconnected transmission system.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Alain Pageau, Hydro-Québec TransÉnergie
Telephone: 514 879-4100 #5414
Email: pageau.alain@hydro.qc.ca
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: The transmission lines
dedicated to serve the native load in the Quebec Interconnection.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Guy Zito, Northeast Power Coordinating Council
Telephone: 212-840-1070
Email: gzito@npcc.org
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a . Identify the Element or Facility recommended for exclusion:
All step-down transformers with their low-side terminals operated at below 100 kV.
Radial taps from a BES feeder or bus connection to loads. All elements or facilities
in series with excluded or exempt elements or facilities -- upstream to a designated
point-of-demarcation with the BES and downstream to the customer meter or
interconnection. (Refer to the response to Question 3, New York Indicator [NY-2]
below, and the response to Question 13, proposed definition ‘Point-of-Demarcation’
in the BES Definition Comments provided separately). For example, upstream from
an exempt or excluded feeder to the upstream-side of the disconnect switch
connecting the excluded or exempted feeder to the BES, or if no disconnect switch is
present, to the upstream BES supply-bus connection. This exclusion or exemption
would extend to and also apply to related equipment, such as circuit switchers, circuit
breakers, ground switches, disconnect switches, busses, etc. that are down-stream of
the point-of-demarcation and in the same circuit with the exempted or excepted
feeders and transformers.
Local generation and any facility associated with local generation serving as a load
modifier to local load only. The power generated is demonstrated to be consumed
locally and does not flow back into the BES. The operation (or loss) of the local
generation and/or associated facilities does not materially impact any BES
transmission facilities. If a local generator functions as a load modifier, and does not
materially impact the BES, meaning that it is not necessary to maintain BES
reliability, then it should be excluded from the definition of BES under the BES
Exclusion process.
The transmission lines dedicated to serve the native load in the Quebec
Interconnection.
b . Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Not Applicable
c . Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: The FERC Seven Factor test has been shown to be a reliable,
repeatable method for identifying facilities that are local distribution and separating
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Proposed Definition of Bulk Electric System – Project 2010-17
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March 25, 2011

them from those facilities which perform a transmission function. The indicators of
local distribution in the Commission’s seven-factor test 1 are:
1) Local distribution facilities are normally in close proximity to retail
customers;
2) Local distribution facilities are primarily radial in character;
3) Power flows into local distribution systems, and rarely, if ever flows out;
4) When power enters a local distribution system, it is not reconsigned or
transported on to some other market;
5) Power entering a local distribution system is consumed in a comparatively
restricted geographic area;
6) Meters are based at the transmission / local distribution interface to measure
flow into the local distribution system; and
7) Local distribution systems will be of reduced voltage.
1

Ref. FERC Order No. 888 at 31,771 and 31,981, e.g., Promoting Wholesale
Competition Through Open Access Non-Discriminatory Transmission Services
by Public Utilities

d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide
Less than Region-wide
Unknown

Page 19 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Jim Uhrin

, ReliabilityFirst Corporation

Telephone: 330.247.3058
Email: jim.urhin@rfirst.org
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Those that have no
impact to the reliability of the BES for any reason or could at anytime. Those that
may or could through reconfiguration and or operating procedures must be
included.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).

In the diagram above, any equipment downstream of the “A” breaker that does not or
could not trip and lockout a BES facility (e.g. line, transformer, etc.) may be excluded,
however if equipment below the “A” breaker could or does trip and lockout a BES
facility for any reason, then it should be included.
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: If the facility could never trip and lockout a BES facility, there is no
reason to include it. However, caution and careful consideration must be used when
exclusions are considered. There maybe times during toplogy changes or system reconfigurations that certain facilities could trip and lockout a BES facility and
therefore must be included.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide

Page 20 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Joe Petaski, Manitoba Hydro
Telephone: 204-487-5332
Email: jpetaski@hydro.mb.ca
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Radial Transmission
Elements and Systems - See comment below
Comments relative to the proposed exclusion(s): Radial Transmission Elements and
Systems should be excluded from the Elements and Facilities classified as part of the
BES but a clear NERC definition of radial is required to prevent misunderstandings and
misapplications of the BES definition and exemption process. Also, there should be no
regional differences in the BES definition or in the BES definition exemption process.

Page 21 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

John W. Delucca, Lee County Electric Cooperative
Telephone: 239-656-2190
Email: john.delucca@lcec.net
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Radial load serving elements
that do not have an adverse effect upon the BES should be excluded. Also Transmission
systems that have no adverse impact on the BES as evidenced by engineering design and
criteria and load modeling should be excluded such as Non-FERC Jurisdictional Facilities;
Radial Non-Transmission Load Serving Elements; Looped Non-Transmission Load
Serving Elements; Looped Non-Transmission Load Serving Elements Designed &
Installed with No Intent to Provide Transmission Load Service.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Please refer to Attachment 1b.6 – 1b.9 the draft BES Definition currently
under review in the FRCC region. There are multiple single-lines included that represent
a fair cross section of elements that should be excluded.
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: The purpose of including facilities in the definition of BES is make them
subject to federal regulations that are designed to serve the reliability needs of the BES
and to prevent cascading of outages to a broad section of the BES. Certain elements
operated at voltages of 100kV or higher have zero measurable impact to the reliable
operation of the Interconnected BES. No practical purpose is served by including those
elements, and if they are, it unnecessarily increases the cost of delivered power. The
following list also should be considered, a). No FERC Jurisdiction; b) Facilities were/are
designed, installed, and operated to serve local non-transmission loads; c) Rates are
designed to provide revenue to meet local non-transmission service; d) Facilities were
never designed or intended to provide capability of entity-to-entity, region-to-region load
flows other than that required to meet local non-transmission service loads; e) Reactance
resources whose purpose is neutralizing non-transmission inductive loads and/or to
compensate for “within entity” losses.

d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how widely
this exclusion should apply, please select, “unknown.”
Continent-wide

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Comments relative to the proposed exclusion(s): The submitted diagrams are not intended
to represent every possible element that should be excluded Continent-wide. The complete
list should be determined by the proposed task force in order that regional differences in
system characteristics is taken into account. In addition, to insure continuity, but the final
decision as to what meets the exclusion criteria should reside in the Region with appeal
process to NERC and possibly FERC.

Page 23 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Paul Cummings, City of Redding
Telephone: 530-245-7016
Email: pcummings@ci.redding.ca.us
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Those elements or
facilities operated at or above 100kV that are shown through engineering studies
not to be necessary to reliably operate an interconnected transmission system.
Radial elements unless they are shown to be necessary to reliably operate an
interconnected transmission system. See Attachment 1. (Refer to Attachment 1b.5)
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Refer to Attachment 1b.5
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: “The impact an Element has on the BES shall be determined by
assessing the performance of key measures of BES reliability through power flow,
post-transient, and transient stability analysis with (1) the system, and the Subject
Element, operating at reasonably stressed conditions that replicate expected system
conditions under which the loss of the Subject Element would have the greatest
impact on the key measures of reliability, and (2) the Subject Element removed
from service, but without allowing for system readjustment.”
d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how widely
this exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide

Page 24 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Patrick Farrell, Southern California Edison Company
Telephone: 626-302-1321
Email: Patrick.Farrell@sce.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: The elements and
facilities above 100kV that are shown through engineering studies to not be necessary
to reliably operate an interconnected transmission system should be excluded.
Additionally, the transmission facilities at 100kV and above that are radial in nature,
used for load serving purposes, and which are not parallel to interconnected
transmission systems should be excluded. As an example, in SCE’s system, the
Valley 115kV system is radial in nature and the power flow is generally from 500kV
to 115kV to serve load.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: An element or facility that is not necessary to reliably operate an
interconnected transmission system need not be included in the BES. This can be
assessed using engineering studies that show the effect of worst-case disturbances on
multiple indicators such as frequency, voltage, system flows, operating limits,
generator tripping, and cascading outages and/or islanding with the element or facility
removed from service. If a system can maintain acceptable steady-state and dynamic
performance during and after a worst-case disturbance with the element removed
from service, that element or facility is not necessary to reliably operate the system.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
X Continent-wide
X Interconnection-wide
X Region-wide
Comments relative to the proposed exclusion(s): The Bulk Electric System (BES)
functions to generate bulk power and transfer that bulk power to locations from which
it is then distributed to end-use load. Elements that generate bulk power, transfer bulk
power, or support the transfer of bulk power are part of the BES.
Page 25 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

An element is necessary to reliably operate an interconnected transmission system if
it significantly affects the ability of the BES to generate bulk power or carry bulk
power to locations from which it is distributed to end-use load. While operating
voltage (i.e. the proposed 100kV bright-line) may be a clear and repeatable proxy for
identifying those elements that are necessary to reliably operate an interconnected
transmission system, it is a broad approach that may not adequately address specific
examples. Engineering studies can be used to more granularly and accurately identify
elements which are not needed to reliably operate an interconnected transmission
system.
The thresholds on the indicators listed above may vary between interconnections and
regions. For example, SCE’s system has facilities rated at the 115kV level that are
radial in nature for load serving purposes. Therefore, applying a 100kV bright-line
may unnecessarily bring facilities that could be excluded through an engineering
study.

Page 26 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Ed Davis, Entergy Services, Inc
Telephone: 504-576-3029
Email: edavis@entergy.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
These questions and possible responses by entities are appropriate as the questions
relate to specific facilities and configurations to be considered for exemption. The
questions do not reflect principles (criteria) for the determination of if facilities or
configurations to be included / excluded in the definition of BES. We agree the
questions and responses may be appropriate here if the responses are to be used as
examples to develop exemption principles (criteria). However, we suggest the authors
should have also asked the industry for principles (criteria) they believe should be
included as exemption criteria.
These questions and responses also do not address a possible process for determining
if facilities or configurations should be included / excluded in the definition of BES.
We suggest the authors should have also asked the industry for process suggestions
they would like included in the final process.

Page 27 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Manny Robledo, City of Anaheim
Telephone: 714-765-5107
Email: mrobledo@anaheim.net
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: City of Anaheim LewisVermont 230kV radial transmission line and seven 230kV to 69kV transformer banks and
associated substation equipment, which are also radial transmission elements serving
load.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Refer to attachments:
1b.1 Anaheim System One-Line,
1b.2 Anaheim 220kV System,
1b.3 Anaheim 69kV Bus Impedance Diagram
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: The 220kV facilities owned and operated by Anaheim are radial
transmission elements fed from one transmission source, i.e. Lewis Substation. Southern
California Edison Company (SCE) and the California Independent System Operator
(CAISO) are the TO/TOPs for the interconnection of Lewis Substation to the BES,
including the protection system that de-energizes both Anaheim buses using SCE owned
breakers without interrupting any BES transmission lines. The 220kV system owned and
operated by the City of Anaheim is radial to the BES at Lewis Substation and feeds a
69kV sub-transmission system through three 220kV/69kV transformer banks. Anaheim is
able to reliably serve 100% of its load using only three of the four banks at Lewis;
however, to improve reliability within Anaheim, in 2008 Anaheim built a redundant
substation (Vermont Substation) 1.5 miles from Lewis, which is connected via a 220kV
transmission line. This line is not needed to maintain BES or Anaheim system reliability
because it is in parallel with four (4) 69kV lines, which also connect Lewis to Vermont.
Its only purpose is to provide backup transformation should there be a catastrophic failure
of the Lewis transformer banks. Pursuant to an SCE-Anaheim operating order only three
transformer banks may be in service at any time to limit short circuit duty, so the banks at
Vermont are truly redundant.
Transmission elements serving radial load, radial distribution systems, or non-GO/GOP
generation connected to such radial lines and excluded from BES. To eliminate reliability
gaps, such radial transmission elements should be classified as "Distribution" equipment
subject to DP standards, and the PRC and vegetation management standards should be
made applicable to Distribution Providers and this equipment. This is consistent with the
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

NERC Reliability Functional Model and is more efficient than requiring TO/TOP
registration for radial transmission facilities that function as Distribution and are not
required for the reliable operation of the BES.
d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how widely
this exclusion should apply, please select, “unknown.”
Continent-wide
Comments relative to the proposed exclusion(s): Transmission elements serving radial
load, radial distribution systems, or non-GO/GOP generation connected to such radial
lines and excluded from BES. To eliminate reliability gaps, such radial transmission
elements should be classified as "Distribution" equipment subject to DP standards, and
the PRC and vegetation management standards should be made applicable to Distribution
Providers and this equipment. This is consistent with the NERC Reliability Functional
Model and is more efficient than requiring TO/TOP registration for radial transmission
facilities that function as Distribution and are not required for the reliable operation of the
BES.

Page 29 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Lorissa Jones, Bonneville Power Administration
Telephone: 360-418-8978
Email: ljjones@bpa.gov
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Those elements or
facilities above 100kV that are shown through engineering studies not to be necessary to
reliably operate an interconnected transmission system.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: An element or facility that is not necessary to reliably operate an
interconnected transmission system need not be included in the BES. This can be
assessed using engineering studies that show the effect of worst-case disturbances on
multiple indicators such as frequency, voltage, system flows, operating limits,
generator tripping, cascading outages and/or islanding with the element or facility
removed from service. If a system can maintain acceptable steady-state and dynamic
performance during and after a worst-case disturbance with the element removed from
service, that element or facility is not necessary to reliably operate the system.
d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how widely
this exclusion should apply, please select, “unknown.”
Interconnection-wide
Region-wide

Page 30 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

David Burke, Orange and Rockland Utilities
Telephone: 845-577-3076
Email: burkeda@oru.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
All step-down transformers with their low-side terminals operated at below 100 kV.
Radial taps from a BES feeder or bus connection to loads. All elements or facilities
in-series with excluded or exempt elements or facilities -- upstream to a designated
point-of-demarcation with the BES and downstream to the customer meter or
interconnection. For example, upstream from an exempt or excluded feeder to the
upstream-side of the disconnect switch connecting the excluded or exempted feeder
to the BES, or if no disconnect switch is present, to the upstream BES supply-bus
connection. This exclusion or exemption would extend to and also apply to related
equipment, such as circuit switchers, circuit breakers, ground switches, disconnect
switches, busses, etc. that are down-stream of the point-of-demarcation and in the
same circuit with the exempted or excepted feeders and transformers.
Local generation and any facility associated with local generation serving as a load
modifier to local load only. The power generated is demonstrated to be consumed
locally and does not flow back into the BES. The operation (or loss) of the local
generation and/or associated facilities does not materially impact any BES
transmission facilities. If a local generator functions as a load modifier, and does not
materially impact the BES, meaning that it is not necessary to maintain BES
reliability, then it should be excluded from the definition of BES under the BES
Exclusion process.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
Not Applicable
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: The FERC Seven Factor test has been shown to be a reliable,
repeatable method for identifying facilities that are local distribution and separating
them from those facilities which perform a transmission function. The indicators of
local distribution in the Commission’s seven-factor test 2 are:

Page 31 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

1)
2)
3)
4)

Local distribution facilities are normally in close proximity to retail customers;
Local distribution facilities are primarily radial in character;
Power flows into local distribution systems, and rarely, if ever flows out;
When power enters a local distribution system, it is not reconsigned or transported
on to some other market;
5) Power entering a local distribution system is consumed in a comparatively
restricted geographic area;
6) Meters are based at the transmission / local distribution interface to measure flow
into the local distribution system; and
7) Local distribution systems will be of reduced voltage.
1

Ref. FERC Order No. 888 at 31,771 and 31,981, e.g., Promoting Wholesale
Competition Through Open Access Non-Discriminatory Transmission Services
by Public Utilities

d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
X

Continent-wide

X

Unknown

Page 32 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Jim Case (Entergy), SERC OC Standards Review Group
Telephone: 601-985-2345
Email: jcase@entergy.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
Comments relative to the proposed exclusion(s): We agree

Page 33 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Thad Ness, American Electric Power
Telephone: 614-716-2053
Email: tkness@aep.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Radial facilities and
elements operating at or above 100 kV, that are connected to only load serving
facilities operated at distribution voltage levels and that include a high side circuit
breaker or circuit switcher should be excluded from the BES classification. While
protective systems themselves are not by default part of the BES, nor should they be
classified as a BES element, the breaker failure schemes associated with the high side
circuit breaker or circuit switcher are part of a Protection System and should comply
with the appropriate standards.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).

Bus 1 (≥ 100 kV)

A

Load (< 100 kV)

c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Facilities such as that described in 1.a. are designed to support only
one way power flow; from the BES to the load. Operation of the high side circuit
breaker or circuit switcher, Device A, removes the transformer from service
interrupting power flow to the load but will not interrupt power flow on the BES nor
effect reliability of the BES. While protective systems themselves are not by default
Page 34 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

part of the BES, nor should they be classified as a BES element, the breaker failure
scheme associated with Device A has the potential of interrupting BES power flow by
clearing Bus 1. For this reason, the breaker failure scheme is part of a Protection
System and should comply with the appropriate standards.

d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide

Page 35 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Amir Hammad, Constellation Power Source Generation, Inc., Et all
CPSG is filing the comments below on behalf of:
Constellation Energy Group, Inc.
Baltimore Gas & Electric Company
Constellation Energy Commodities Group, Inc.
Constellation Energy Control and Dispatch, LLC
Constellation NewEnergy, Inc. and its affiliates
Constellation Energy Nuclear Group, LLC, 3
Telephone: 410-787-5226
Email:
amir.hammad@constellation.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Constellation believes that
the exclusions mapped out in RFC’s BES definition, as well as the diagrams in
Appendix A of the RFC BES definition would be a good starting point for the standard
drafting team in developing exclusions.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Constellation believes that the exclusions mapped out in RFC’s BES
definition, as well as the diagrams in Appendix A of the RFC BES definition would be a
good starting point for the standard drafting team in developing exclusions.
c. Provide a technical justification for the exclusion (provide justification here or attach a
supplemental document or URL link to publicly posted document if available).
Justification: The BES definition in RFC has been vetted through its members and
incorporates the essence of NERC’s BES definition but includes bright lines for its
members to abide by.
RFC Definition of BES:
https://www.rfirst.org/Documents/RFC%20BES%20Definition.pdf
d. Identify if this exclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how widely
this exclusion should apply, please select, “unknown.”
Continent-wide

3

On November 6, 2009, EDF, Inc. (“EDF”) and Constellation Energy Group, Inc. completed a transaction
pursuant to which EDF acquired a 49.99 percent ownership interest in CENG. CENG was previously a wholly
owned subsidiary of Constellation Energy Group, Inc.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Comments relative to the proposed exclusion(s):
As described in RFC’s BES definition, the following elements should be excluded:
(1) radial facilities connected to load serving facilities or individual generation resources
smaller than 20 MVA or a generation plant with aggregate capacity less than 75 MVA
where the failure of the radial facilities will not adversely affect the reliable steady-state
operation of other facilities operated at voltages of 100 kV or higher and
(2) balance of generating plant control and operation functions (other than protection systems
that directly control the unit itself and step-up transformer); these facilities would
include relays and systems that automatically trip a unit for boiler, turbine,
environmental, and/or other plant restrictions, and
(3) all other facilities operated at voltages below 100 kV.

Page 37 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

William J. Gallagher, Vermont Public Power Supply Authority
Telephone: (802) 839-0562
Email: bgallagher@vppsa.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
This question refers to “exclusions”; we believe, however, that the intent of this
comment form is to elicit feedback on the process for “exemptions.” It is important
to distinguish between the two concepts, as FERC did in Order 743. See, e.g.,
Paragraph 1, which refers to “maintain[ing] a bright-line threshold that includes all
facilities operated at or above 100 kV except defined radial facilities,” as well as to
“establish[ing] an exemption process and criteria” (emphasis added). In other
words, in brief, an “exclusion” is outside of the BES by definition, whereas exempt
Elements are removed on a case-by-case basis by going through a process.
TAPS draws the distinction as follows:
An exclusion is the removal of a category of Elements from the BES definition.
The current BES definition explicitly carves out radials serving only load with one
transmission source. This is a clear example of an exclusion. There is no “exclusion
process” now, nor should there be one in the future; the point of an exclusion is that
the class of excluded Elements can—without any process—be treated like sub-100
kV transmission, in that they are presumed to be non-BES unless a particular
Element is demonstrated, on a case-by-case basis, to be properly included in the BES
(see responses to Questions 5 and 11 in TAPS’ comments on BES definition,
submitted today, and TAPS response to Question 2 below).
An exemption, on the other hand, is a finding that a particular Element, although
nominally part of the BES, does not need to be included in the BES because it is not
necessary for operating an interconnected transmission network.
Because exemptions are less clear-cut than exclusions, each exemption of an
Element needs to be approved by NERC so that the Registered Entity and
compliance authorities have certainty about the Elements with respect to which
compliance is required. In many, perhaps all, cases, this process will likely require a
case-by-case examination of each Element for which an exemption is requested.
TAPS responds to this question with respect to the one “exclusion” from the
BES definition that we advocate, that of radial Transmission Elements serving only
load and/or generation not registered pursuant to the Statement of Compliance
Registry Criteria. We also propose uniform criteria for deciding, on a case-by-case
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

basis, whether to grant requested exemptions from the BES, or to include nominally
non-BES Elements in the BES. The process that we propose for exemption requests
and proposed inclusions is discussed below in response to the invitation of
“[c]omments relative to the proposed exclusion(s).”
Exclusion:
TAPS proposes only one exclusion from the BES definition, namely, “Radial
Transmission Elements serving only load with one Transmission source are
generally not included in this definition. A radial Transmission Element may be
considered as ‘serving only load’ for purposes of the foregoing general exclusion
even if it connects generation, so long as that generation is not registered pursuant to
the Statement of Compliance Registry Criteria.” This formulation, which is
discussed in TAPS’ comments submitted today on the BES definition, is intended to
preserve the current exclusion of radials serving only load with one transmission
source, and to clarify that the presence of a generator that is not registered under the
Compliance Registry Criteria does not convert a radial into a BES Element. The end
result is that radial transmission is excluded unless it connects generation that is
registered pursuant to the Statement of Compliance Registry Criteria. Consistent
with the Compliance Registry Criteria, a single generator under 20 MVA, or a plant
under 75 MVA, if not designated as a Blackstart Resource needed for system
restoration, is unlikely to affect the grid. Therefore, the presence of such generation
should not require that an otherwise non-BES radial be included in the BES.
Rooftop photovoltaic cells, for example, are increasingly common. If TAPS’
proposed clarification is not accepted, the presence of such insignificant generation
could nullify the exclusion of radials to load with one transmission source, with no
benefit to reliability.
Exemption criteria
TAPS has not yet developed a list of criteria that we believe to be exhaustive,
though we emphasize that such a list must be an ultimate goal of this process. We
propose the following criteria as a start:
TAPS proposes that at least two classes of facilities be eligible to request an
exemption:
i.
Elements that are part of a radial “system” originating from a single BES
source serving only load, as in the Florida Keys. Clarifications: a) radial system
means any number of series and/or parallel Elements as long as they all originate
from a single BES source and do not have another BES source; b) “single BES
source” means one BES bus / substation / switching substation at one voltage level,
and c) consistent with TAPS’ proposed exclusion of radials serving only load and
unregistered generation, “serving only load” includes serving generation that is not
registered through the Statement of Compliance Registry Criteria.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

ii.
Elements that are part of a “looped” system that has two transmission
sources primarily for local quality of service to the retail customers supplied by the
looped system in question and is not used for bulk power system flow (e.g., the
transfer distribution factor of flows across the looped system is low, representing a
high impedance path across the looped system). Specific criteria might be: a) a
looped system that participates in less than a 5% of transfer (e.g., 5% or less transfer
distribution factor); and b) that the looped system in question does not limit
transfers.
A radial or looped system to be exempted must meet the following criteria:
1.
The radial or looped system may not contribute to any Category D or C
contingency resulting in: 1) a supply / demand mismatch greater than the largest loss
of source contingency in the Reliability Coordinator area; or 2) an Adverse
Reliability Impact where, if the Element were not involved in those Category D or C
contingencies, those thresholds would not be exceeded.
Studies to determine whether this criterion is met would be conducted in
accordance with TPL-004-0 and TPL-003-0 standards (or corresponding
contingencies in revision to the TPL standards) in the Short Term Planning Horizon.
Although the above criteria are acceptable responses to a Category D contingency,
the concept of the test is to see if a radial or looped system would cause a
significantly worse response to Category C or D contingencies by testing the
contingency with and without the radial or looped system. TAPS believes that such
criteria are good indicators that a radial or looped system should be included in the
BES as it highlights whether the protection systems are important for critical
clearing times, and whether the radial or looped systems can contribute to an
Adverse Reliability Impact in combination with other contingencies;
2.
No portion of the radial or looped system may meet any of the conditions
of Attachment 1 to CIP-002-4;
3.
No portion of the radial or looped system may meet any of the conditions
listed in items B1 to B5 of Attachment B to PRC-023-2;
4.
No portion of the radial or looped system may be a part of, or be a limiting
element of, any Path, Interchange, or Flowgate used in the calculation of ATC in
accordance with standards MOD-028, MOD-029 or MOD-030; and
5.
No portion of the radial or looped system may include a Blackstart
Resource or cranking path deemed significant to the TOP or RC restoration plans of
EOP-005, EOP-006 or EOP-007.
If a Registered Entity demonstrates to NERC that an Element that is nominally in
the BES meets all of these criteria, the exemption would be granted.

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Summary Comment Report – Question 1 a-d
March 25, 2011

Conversely, if NERC demonstrates that a nominally non-BES Element meets the
negative of any of these criteria (e.g., if any portion of the radial or looped system
meets any of the conditions of Attachment 1 to CIP-002-4 or of Attachment B to
PRC-023-2), the Element would be included in the BES.
Throughout these comments, TAPS refers to “Elements” and not to “facilities.”
This is because “Facility” is defined in the NERC Glossary as “[a] set of electrical
equipment that operates as a single Bulk Electric System Element…” Because these
comments (and the BES definition) address whether Elements are or are not part of
the BES, it is incorrect to refer to the Elements in question as “Facilities,” because a
Facility is defined as a BES Element.
In developing the exemption/inclusion criteria and process, NERC and the SDT
should bear in mind the requirement of Order 743: “NERC should develop an
exemption process that includes clear, objective, transparent, and uniformly
applicable criteria for exemption of facilities that are not necessary for operating the
grid.” Paragraph 115 (emphasis added). NERC and the SDT should also bear in
mind that FERC anticipates that between the BES definition and the exemption
process, there will be only “minimal[]” effect on “small entities.” Order 743,
Paragraph 169. Order 743 is referring to the Small Business Act definition of a
“small electric utility” as one that has a total electric output of less than four million
MWh in the preceding year. See March 18, 2010 BES Notice of Proposed
Rulemaking, Paragraph 35 & footnote 50.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Radial Transmission Elements serving only load have been
recognized for years as non-BES because such Elements are very unlikely to affect
the BES. FERC stated in Order 743 that NERC may retain that exclusion.
Similarly, generators under 20 MVA and generating plants under 75 MVA are not
subject to registration pursuant to the Statement of Compliance Registry Criteria,
which has been accepted by FERC, because of the recognition that such generators
are very unlikely to affect the BES. It is thus consistent with the Compliance
Registry Criteria to exclude from the BES definition radials serving load with one
transmission source even if there is some generation on the radial, so long as none of
the generation is registered. If the generation is not significant enough to be
registered, it is not significant enough to transform an otherwise non-BES radial to
load into a BES Element.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Continent-wide
The exclusion of radials to load and unregistered generation, as part of the BES
definition, should apply on a continent-wide basis.
Each Element proposed for exemption or inclusion should be considered
individually, under the same criteria (proposed above), applied uniformly continentwide.
Comments relative to the proposed exclusion(s):
Exemption and Inclusion Processes:
The exemption and inclusion processes should be designed to ensure continentwide uniformity to the maximum extent possible. To that end, NERC must use a
uniform process; the criteria for approving or denying an exemption, or for including
an Element in the BES, must be clear; and entities must be able to appeal decisions
to another body within NERC or to FERC.
In order to obtain an exemption, a Registered Entity should be required to
demonstrate that the Element for which it is requesting an exemption is not
“necessary for operating an interconnected electric transmission network.” This is
the standard set out in Order 743 (e.g., Paragraph 1); it is also part of the definition
of the “bulk-power system” in Section 215 of the Federal Power Act, 16 U.S.C.
§ 824o(a)(1)(A). Application of this standard should be informed by the statutory
definitions of “reliability standard” (“a requirement, approved by the Commission
under this section, to provide for reliable operation of the bulk-power system,”
16 U.S.C. § 824o(a)(3)) and “reliable operation” (“operating the elements of the
bulk-power system within equipment and electric system thermal, voltage, and
stability limits so that instability, uncontrolled separation, or cascading failures of
such system will not occur as a result of a sudden disturbance, including a
cybersecurity incident, or unanticipated failure of system elements,” 16 U.S.C.
§ 824o(a)(4)).
Conversely, to include a nominally non-BES Element in the BES, NERC should
be required to demonstrate that the Element is necessary for operating an
interconnected electric transmission network.
Criteria for determining whether an Element is or is not “necessary for operating
an interconnected electric transmission network” are proposed in response to
Question 1(a) above. The criteria should be uniform continent-wide, though they
will be applied to each Element on a case-by-case basis.
Exemption requests and proposed inclusions should be decided by NERC staff in
the first instance. TAPS does not believe that the exemption and inclusion processes
should be delegated to the Regional Entities. In Order 743, FERC emphasized the
need for continent-wide uniformity; in fact, it was inconsistency among regions that
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Summary Comment Report – Question 1 a-d
March 25, 2011

prompted Order 743. TAPS members’ experience with Regional registration
processes suggests that Regional implementation of the BES exemption and
inclusion processes is unlikely to yield the uniformity that FERC directed.
Furthermore, implementing this FERC directive will unavoidably require significant
personnel resources, either at NERC or at the Regions. Delegating the process to the
Regions would impose additional costs due to the need for NERC to exercise strong
oversight to attempt to maintain uniformity. It may be that after the exemption and
inclusion processes have been in place for a few years and a body of precedent has
been accumulated, delegation will be appropriate. At this time, however, NERC
staff should make the initial decision on all exemption requests and proposed
inclusions.
TAPS proposes, for the sake of consistency with the registration appeal process,
that appeals of decisions on exemptions and inclusions be to the Board of Trustees
Compliance Committee (BOTCC), with further appeals to FERC if necessary.
Appeals to the BOTCC would consist of the record compiled by NERC Staff, and
additional paper submissions by NERC Staff and the Registered Entity
demonstrating why the Element(s) in question is or is not “necessary for operating
an interconnected electric transmission network.” See NERC Rules of Procedure,
Appendix 5A, Organization Registration and Certification Manual at 14-16.
Registered Entities should have the option of requesting a hearing. Hearing
procedures could be modeled on the Compliance and Certification Committee’s
“Hearing Procedures for Use in Appeals of Certification Matters,” in Appendix 4E
of the NERC Rules of Procedure.
TAPS also suggests that decisions on exemptions and inclusions be made
available to others, either subject to CEII protection or in a form suitable for public
release. As precedent develops, Registered Entities will increasingly be able to
judge for themselves the likelihood that a particular exemption will be granted, or
that an appeal of an inclusion will succeed. We expect that giving Registered
Entities more information on which to base their decisions will significantly reduce
the burden on NERC of processing exemptions and inclusions.
We propose that BES Elements for which an exemption request is pending
should continue to be included in the BES until the exemption and any appeals are
decided, and that non-BES Elements for which an inclusion is pending should
continue to be non-BES until the inclusion and any appeals are decided.
The transition process should include an important exception to the general rule
proposed for BES status during the pendency of an exemption request: to allow for a
smooth transition, to the extent that Elements that are currently considered non-BES
become BES under the new definition, those Elements should be permitted to
request exemptions and to continue to be considered non-BES until their exemption
requests and any appeals are decided.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

David Angell, Idaho Power
Telephone: 208-388-2701
Email: daveangell@idahopower.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Non-radial transmission
systems which provide reliable service to load-service substations. There are two
examples where this applies: 1.) The non-radial transmission system serving a metro
area load at 138 kV where 230 kV and higher voltage systems surround the area and
provide the bulk electric system transfer, and 2.) The non-radial transmission loops
that serve rural area load at 138 kV that are essentially tangential to the bulk electric
transfer path.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Refer to Attachment 1b.4
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Large load-serving substations require non-radial service to ensure
acceptable reliability performance. Such transmission systems do not carry bulk
power transfers as there are substantial higher voltage transmission lines that
surround the metro area which carry the bulk transfers. Idaho Power has evaluated
serving the area from systems that are sourced from only a single bulk substation.
Such a configuration would result in requiring an additional 100 miles of transmission
to compared to the existing network configuration.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Marc M. Butts, Southern Company
Telephone: 205-257-4839
Email: mmbutts@southernco.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
Individual
Generators < 75 MVA; this threshold also needs to be included in the NERC
Compliance Registry Criteria.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification:
Generators less than 75 MVA are not large enough to have a
significant impact on the bulk electric system.. However, aggregate generation that
exceeds 75 MVA should be considered for applications such as wind farms.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Unknown

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Andrew Z. Pusztai, American Transmission Company
Telephone: 262-506-6913
Email: apusztai@atcllc.com
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion: Exclude transmission
lines that are operated at 100 kV and above that are operationally radial transmission
elements because of a operating restriction that prevents the line from being operated
as a network transmission element.
b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
The transmission line between Source Line #1 and Sources Line #2 would be a
Network element if the bus-tie circuit breaker was closed, However, Operating
Procedures require the bus-tie circuit breaker to be normally open (N.O.) So, the load
on Bus 1 is served by the radial line segment from Source Line #1 and the load on
Bus 2 is served by the radial line segment from Source Line #2.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011
To Distribution Load
13.2-kV

13.2-kV

60 MVA

60 MVA

T2

T1

Distribution
Substation

138-kV
Bus 2

138-kV Source Line #2

N.O.

Bus 1

138-kV Source Line #1

c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Although the transmission element (line) between network Source #1
and network Source #2 could be a network element if the bus-tie breaker is closed,
the two line sections are normally operated as two different radial elements. So, the
radial Transmission Element exclusion should apply.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Ronald Sporseen, PNGC Power, Et all
Email: RSporseen@pngcpower.com
Supporters of the following comments are as follows:
Bud Tracy, Blachly-Lane Electric Cooperative
Dave Hagen, Clearwater Power Cooperative
Dave Sabala, Douglas Electric Cooperative
Heber Carpenter, Raft River Rural Electric Cooperative
Dave Markham, Central Electric Cooperative
Jon Shelby, Northern Lights, Inc.
Ken Dizes, Salmon River Electric Cooperative
Ray Ellis, Okanogan County Electric Cooperative
Richard Reynolds, Lost River Electric Cooperative
Rick Crinklaw, Lane Electric Cooperative
Roger Meader, Coos-Curry Electric Cooperative
Roman Gillen, Consumer’s Power Inc.
Steve Eldrige, Umatilla Electric Cooperative
Marc Farmer, West Oregon Electric Cooperative
Michael Henry, Lincoln Electric Cooperative
Bryan Case, Fall River Electric Cooperative
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for exclusion:
•

Radial lines

•

Local distribution networks, generators, generation plants, loads, transformers,
reactive devices, and protection and control system found to not cause adverse
reliability impacts on neighboring bulk system Elements and Facilities using a
performance-based exclusion process.

b. Provide a generic one-line diagram depicting the Element or Facility in question (if
available).
Assuming FERC continues to insist upon a 100kV “bright line” definition, we
support a process to exclude systems operating at 100kV and above that do not cause
adverse reliability impacts on the neighboring bulk transmission system. For
facilities operating at 100kV or above, the exclusion process should allow exclusion
of those elements that, using a performance-based assessment, are demonstrated to
operate without causing adverse reliability impacts on neighboring bulk system.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: The ultimate goal of the Reliability Standards process should be to
achieve reliable operation of the bulk transmission system, as defined by Congress.
The term “reliable operation” was a term specifically defined in FPA Section 215 to
include standards assuring the operation of bulk transmission system elements
“within equipment and electric system thermal, voltage, and stability limits so that
instability, uncontrolled separation, or cascading failures of such system will not
occur as a result of a sudden disturbance. . . or unanticipated failure of system
elements.” 16 U.S.C. § 825o(a)(4). Congress specifically precluded the mandatory
reliability system from enforcing standards for adequacy of service, which were left
to state and local authorities. 16 U.S.C. § 825o(i)(2).
Recognizing that Congress intended the mandatory reliability regime to focus on
thermal, voltage, and stability limits on the bulk system rather than more generally on
levels of service to retail customers, the Standards Development Team should define
the Bulk Electric System to include only those facilities whose failure or misoperation meaningfully threatens to produce instability, uncontrolled separation, or
cascading failures on the bulk system. As a legal matter, expanding the definition to
include local distribution facilities and facilities that do not threaten thermal, voltage
or stability impacts on the bulk system exceeds the permissible scope of NERC
Reliability Standards and FERC authority under FPA Section 215. As a practical
matter, mandating adherence to Reliability Standards for facilities, or equipment, that
do not cause adverse reliability impacts on the neighboring bulk system is a
significant diversion of funds and resources that will produce little or no benefits in
terms of improved reliability of the bulk system.
d. Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Comments relative to the proposed exclusion(s): The WECC Bulk Electric System
Definition Task Force (“BESDTF”) has carefully considered and provided an extensive
record of technical support for excluding Radial Facilities and Local Distribution
Networks from the BES. While we recognize that physical differences between the
electric system in WECC and other reliability regions may justify different approaches in
those regions, we commend the work of the BESDTF to the standard drafting team.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Jerome Murray, Oregon Public Utility Commission
Telephone: 503-378-6626
Email: Jerry.murray@state.or.us
1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements
and Facilities classified as part of the BES:
a . Identify the Element or Facility recommended for exclusion: An element or facility
that is not necessary to reliably operate an interconnected transmission system need
not be included in the BES
b.
c.

Provide a generic one-line diagram depicting the Element or Facility in question (if available).
Provide a technical justification for the exclus ion (provide justification here or attach a supplemental document or URL lin k to p ublicly pos ted document if available).

Justification:

d . Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Comments relative to the proposed exclusion(s): This should be assessed first using
engineering-based inspection (or screening) methodologies for 100 kV to 200 kV subtransmission elements to determine obvious exclusions from the BES. For questionable
sub-transmission elements, engineering-based studies evaluating worst-case scenarios need
to be performed to establish exclusion from the BES.
The thresholds associated with screening methodologies and worst-case studies may vary
between interconnections and regions. For example, voltage deviation may be more
relevant in the Western Interconnection (which is primarily stability limited) than in the
Eastern Interconnection (which is primarily thermally limited).

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

John D. Martinsen , Public Utility District No. 1 of Snohomish County
Telephone: 425-783-8080
Email: jdmartinsen@snopud.com

1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a . Identify the Element or Facility recommended for exclusion:

•

Radial lines

•

Local distribution networks, generators, generation plants, loads,
transformers, reactive devices, and protection and control system found to
not cause adverse reliability impacts on neighboring bulk system Elements
and Facilities using a performance-based exclusion process.

b . Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Assuming FERC continues to insist upon a 100-kV “bright line”
definition, SNPD supports a process to exclude systems operating at 100 kV and
above that do not cause adverse reliability impacts on the neighboring bulk
transmission system. For facilities operating at 100 kV or above, the exclusion
process should allow exclusion of those elements that, using a performance-based
assessment, are demonstrated to operate without causing adverse reliability impacts
on neighboring bulk system.
Provide a technical justification for the exclusion (provide justification here or
attach a supplemental document or URL link to publicly posted document if
available).
Justification: The ultimate goal of the Reliability Standards process should be to achieve

reliable operation of the bulk transmission system, as defined by Congress. The term
“reliable operation” was a term specifically defined in FPA Section 215 to include
standards assuring the operation of bulk transmission system elements “within equipment
and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden
disturbance. . . or unanticipated failure of system elements.” 16 U.S.C. § 824o(a)(4).
Congress specifically precluded the mandatory reliability system from enforcing
standards for adequacy of service, which were left to state and local authorities. 16
U.S.C. § 824o(i)(2).
Recognizing that Congress intended the mandatory reliability regime to focus on thermal,
voltage and stability limits on the bulk system rather than more generally on levels of
service to retail customers, the Standards Development Team should define the Bulk
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Electric System to include only those facilities whose failure or mis-operation
meaningfully threatens to produce instability, uncontrolled separation, or cascading
failures on the bulk system. As a legal matter, expanding the definition to include local
distribution facilities and facilities that do not threaten thermal, voltage or stability
impacts on the bulk system exceeds the permissible scope of NERC Reliability Standards
and FERC authority under FPA Section 215. As a practical matter, mandating adherence
to Reliability Standards for facilities that do not cause adverse reliability impacts on the
neighboring bulk system is a significant diversion of funds and resources that will
produce little or no benefits in terms of improved reliability of the bulk system.

c . Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide

Comments relative to the proposed exclusion(s): The WECC Bulk Electric System
Definition Task Force (“BESDTF”) has carefully considered and provided an extensive
record of technical support for excluding Radial Facilities and Local Distribution Networks
from the BES. While we recognize that physical differences between the electric system in
WECC and other reliability regions may justify different approaches in those regions, we
commend the work of the BESDTF to the standard drafting team.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

Steve Alexanderson P.E., Central Lincoln
Telephone: 541-574-2064
Email: salexanderson@cencoast.com

1. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages 100kV and above which should be considered for exclusion from the Elements and
Facilities classified as part of the BES:
a . Identify the Element or Facility recommended for exclusion: All the SS_ 115 kV
buses in the attached one-lines as well as the connecting lines should be excluded
from consideration since they are radial serving load. Additional facilities may be put
through the exclusion process, and excluded if shown not to be needed for “reliable
operation” as defined in 16 U.S.C. § 824o(a)(4).
b . Provide a generic one-line diagram depicting the Element or Facility in question (if
available). Refer to Attachment 1b.10 & 1b.11
c . Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: These SS_ facilities in the diagram are operated radially and are used to
distribute energy locally. The FPA specifically excludes “facilities used in the local
distribution of electric energy” (16 U.S.C. § 824o(a)(1)) and prohibits FERC from
enforcing standards for adequacy of service (16 U.S.C. § 824o(i)(2)). In addition, any
faults or failures in these facilities will only affect the local area, and not cause instability,
uncontrolled separation, or cascading outages (16 U.S.C. § 824o(a)(4)). These facilities
should be excluded by inspection, and should not be required to go through an exemption
process.
d . Identify if this exclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this exclusion should apply, please select, “unknown.”
X Continent-wide
Comments relative to the proposed exclusion(s): The two diagrams illustrate the
overreaching approach that WECC is presently using. Documents on the RFC web site
prove that the WECC approach is not at all universal.
The SS2 bus is presently considered by WECC to be BES because it has two
transmission sources, NON-RADIAL SUB 1 and NON-RADIAL SUB 3, even though
the K9-5 at SS3 is normally open. WECC considers any possible second source
regardless of the system is operated. Any faults at SS3 or in the supplying lines will result
only in a local outage. We hope the SDT will consider actual operating conditions when
it defines “radial” and “one transmission source.”
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 1 a-d
March 25, 2011

The 115 kV bus at SS6 is considered by WECC to be BES because it has two
transmission sources, one by way of NON-RADIAL SUB 4 and the other by way of
NON-RADIAL SUB 5 (off the one-line to the right). We don’t think that is what NERC
meant by “transmission source.” A fault on the SS6 bus would result in a local outage
affecting only the four substations tapped off the NON-RADIAL SUB 4/SUB 5 line. We
assume that if the risk of such an outage was unacceptable, the serving transmission
company would have required protection at the tap points. We hope the SDT will
properly clarify what is meant by a transmission source.
All the SS 115 kV buses shown also have multiple transmission sources by way of
normally open tie switches on the 12.47 kV system. Again we hope the SDT will
consider operating philosophies when defining “radial” and “one transmission source.”
All the substation transformers in the diagrams are considered by WECC to be BES
because one winding exceeds 100 kV. We understand the SDT properly intends to look at
the lowest voltage winding rather than the highest.
Except for the fuses at SS8, all the SS transformer protection systems are considered by
WECC to be BES subject to PRC-005. This is not because the transformers are
considered to BES, but because relay operation results in tripping a circuit switcher that
exceeds 100 kV. We expect the SDT will properly consider the zone of protection rather
than the voltage of the interrupting device.
Please also consider the 115 kV lines joining the NON-RADIAL SUBs in the two
diagrams. While most of them cannot be considered to be radial with one transmission
source, they are not used to transport bulk power. Their purpose is the local distribution
of power. Parallel 230 kV lines (not shown in the diagrams) are responsible for the bulk
power transport. The WECC Bulk Electric System Definition Task Force has been
working on a definition of “local distribution networks” that would properly classify the
115 kV lines as non-BES. We hope the SDT will look at the work the BESDTF has done.

Page 54 of 54

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Question 2: Summary Consideration: Prior to the issuance of Order 743a, the SDT reviewed
all of the provided material and used this material and the examples supplied in its consideration
of the revised definition of the Bulk Electric System (BES). The goal of the SDT is to provide a
bright-line definition of BES which adheres to the guidelines and directives in Order 743. This
bright-line definition contains certain inclusions and exclusions for specific equipment and
configurations. The SDT believes that this definition now answers many of the questions raised
by industry and encompasses most of the examples provided. However, no bright-line definition
will be able to capture all of the concerns or situations. Accordingly, and consistent with Order
743, another aspect of this project is to establish an exception process with criteria based on
reliability principles for the Interconnected BES that will be incorporated in NERC’s Rules of
Procedure (ROP) that will allow a process for the inclusion or exclusion of a particular BES
Element from the definition. This ROP work effort will be done by a separate team but the
DBESSDT will be in close coordination with that team.
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion:
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or
attach a supplemental document or URL link to publicly posted document if
available).
d. Identify if this inclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this inclusion should apply, please select, “unknown.”
Commenters:
Michael Moltane and John Zipp, ITC Holdings ............................................................................ 3
Frank Gaffney, Florida Municipal Power Agency, Et all .............................................................. 4
Brandy A. Dunn, Western Area Power Administration ................................................................. 7
Alain Pageau, Hydro-Québec TransÉnergie .................................................................................. 8
Guy Zito, Northeast Power Coordinating Council ......................................................................... 9
Jim UhrinReliabilityFirst Corporation ......................................................................................... 11
Joe Petaski, Manitoba Hydro ....................................................................................................... 12
John W.Delucca, Lee County Electric Cooperative ..................................................................... 13
Page 1 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Paul Cummings, City of Redding ................................................................................................ 14
Patrick Farrell, Southern California Edison Company................................................................. 15
Manny Robledo, City of Anaheim ............................................................................................... 17
Lorissa Jones, Transmission Reliability Program Manager ......................................................... 18
David Burke, Orange and Rockland Utilities............................................................................... 19
Alice Ireland, Xcel Energy ........................................................................................................... 20
Amir Hammad, Constellation Power Source Generation, Inc., Et all .......................................... 21
William J. Gallagher, Transmission Access Policy Study Group ................................................ 22
Marc M. Butts, Southern Company ............................................................................................. 23
Ronald Sporseen, PNGC Power, Et all ........................................................................................ 24

Page 2 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Michael Moltane and John Zipp, ITC Holdings
Telephone: 248-946-3093
Email: mmoltane@itctransco.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
Comments relative to the proposed inclusion(s): Again it is unclear what is meant by
Region wide when talking about an element inclusion. It is important that this be tied to the
PRC023 “Critical Element” definition/test. Why would I apply for an element inclusion
when there is no definition of what is required for the element to be included?

Page 3 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Frank Gaffney, Florida Municipal Power Agency, Et all
Florida Municipal Power Agency is filing the comments below on behalf of its’ project
participants:
City of New Smyrna Beach
KUA
Lakeland Electric
City of Clewiston
Beaches Energy Services
Ocala Electric Utility
Telephone: 407-355-7767
Email: frank.Gaffney@fmpa.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion:
FMPA’ proposed criteria for inclusion are listed above in response to Question 1(a).
As stated above, there should be no “generic” or “categorical” inclusions. Inclusions,
like exemptions, should be considered on a case-by-case basis. The criteria by which
proposed inclusions or requested exemptions are judged, however, should be uniform
across the continent.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Comments relative to the proposed inclusion(s): This question appears to assume that
all inclusions in the BES will be categorical, rather than case-by-case. This is
inappropriate. Inclusions, like exclusions, should involve case-specific consideration of
the uniform, continent-wide criteria.
The inclusion process should be the mirror image of the exemption process: it is NERC,
rather than the Registered Entity, who initiates the process, and the burden is on NERC to
demonstrate that the Element to be included is “necessary for operating an interconnected
electric transmission network.” The processes should otherwise be identical: the initial
determination should be made by NERC staff, with appeals to the Board of Trustees
Compliance Committee, and to FERC if necessary. The proposed process is discussed in
more detail in response to Question 1 above.

Page 4 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Michelle Mizumori, Western Electricity Coordinating Council
Telephone: 801-819-7624
Email: mmizumori@wecc.biz
3. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Elements or
Facilities that are shown through engineering studies to be necessary to reliably
operate an interconnected bulk electric system.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or
attach a supplemental document or URL link to publicly posted document if
available).
Justification: An element or facility that is necessary to reliably operate an
interconnected transmission system should be included in the BES. This can be
measured using engineering studies that show the effect of worst-case
disturbances on multiple indicators such as frequency, voltage, system flows,
operating limits, generator tripping, cascading outages, and/or islanding. If the
system cannot maintain acceptable steady-state and dynamic performance with a
disturbance at the element, it is necessary to reliably operate the system.
d. Identify if this inclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Comments relative to the proposed inclusion(s): While operating voltage (i.e., the
proposed 100 kV bright-line) may be a clear and repeatable proxy for identifying
those elements that are necessary to reliably operate an interconnected transmission
system, it is a broad approach that may not adequately address specific examples.
Moreover, engineering studies can be used to more granularly and accurately identify
such elements that are needed to reliably operate an interconnected transmission
system.
The thresholds on the indicators listed above may vary between interconnections and
regions. For example, voltage deviation may be more relevant in the Western
Page 5 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Interconnection (which is primarily stability limited) than in the Eastern
Interconnection (which is primarily thermally limited).

Page 6 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Brandy A. Dunn, Western Area Power Administration
Telephone: 720-962-7431
Email: dunn@wapa.gov
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Any Element above
100-kV that is shown (through system studies) to be necessary to reliably operate the
interconnected transmission system.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: An Element that is required to reliably operate the interconnected
transmission system should be included in the BES. This can be assessed through
engineering system studies that show the worst-case results based on indicators such
as voltage, frequency, OTC limits, angular instability and/or cascading outages based
on that Element being removed from service. If the system cannot maintain
acceptable performance without that Element, it is necessary to reliably operate the
interconnected transmission system.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Comments relative to the proposed inclusion(s): While a brightline test voltage (such
as the proposed >100-kV) may be a clear and repeatable proxy for identifying Elements
that are necessary to reliably operate the interconnected transmission system, this broad
approach may not adequately address specific examples. Engineering system studies can
accurately identify Elements which are not needed to reliably operate the interconnected
transmission system.

Page 7 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Alain Pageau, Hydro-Québec TransÉnergie
Telephone: 514 879-4100 #5414
Email: pageau.alain@hydro.qc.ca
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Common
interconnection between the two jurisdictions.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Common rules should applied to the common elements.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide

Page 8 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Guy Zito, Northeast Power Coordinating Council
Telephone: 212-840-1070
Email: gzito@npcc.org
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Transmission facilities
as determined to be necessary for reliability to the bulk electric system. Common
interconnections between two or more areas.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: The exemption process should allow for a registered entity to submit the
results of an objective, impact based assessment evaluation in support of its application
for exemption of facilities that would otherwise be classified as part of the BES. This
assessment process, when consistently applied in a non-arbitrary manner, would yield
results that demonstrate that the facilities for which the exemption is being sought do
not impact the BES whenever they are removed from service.
Any regional or registered entity can present technical studies to NERC for
consideration of the expansion of the Bulk Electric System. The primary consideration
by NERC Staff for inclusion must be that the addition of these recommended facilities
bring a measurable (not subjective) incremental reliability benefit to real-time grid
operations. Common rules should apply to elements common to the interconnections
between two or more areas.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide
Less than Region-wide
Comments relative to the proposed inclusion(s): Registered Entities must retain the
right to appeal any decisions with direct implications to their facilities. Broad
applications of “included facilities” could result in the designation of facilities, the
Page 9 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

inclusion of which is not warranted. Registered Entities need the right to seek exemption
when broad new inclusions are applied.

Page 10 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Jim Uhrin

ReliabilityFirst Corporation

Telephone: 330.247.3058
Email: jim.uhrin@rfirst.org
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Those facilities that
trip and lockout a BES facility at anytime must be included.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).

In the diagram above, the distribution transformer operated below 100 kV without a
high-side interrupting device and connected to the BES that does or could trip and
lockout a BES facility should be included since there is no way to isolate the transformer
without tripping/locking out another BES facility. However, if radial equipment has
sectionalizing (such as a high-side ground switch or circuit switcher) that prohibits its
operation from or does not trip and lockout a BES facility for any reason and therefore
could not affect operation of the BES, those facilities could also be excluded.
c. Provide a technical justification for the exclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: If the facility trips and lockouts a BES facility, then it should be
included as a part of the BES.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide

Page 11 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Joe Petaski, Manitoba Hydro
Telephone: 204-487-5332
Email: jpetaski@hydro.mb.ca
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
Comments relative to the proposed inclusion(s): No comment but there should be no
regional differences in the BES definition or in the BES definition exemption process.

Page 12 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

John W.Delucca, Lee County Electric Cooperative
Telephone: 239-656-2190
Email: john.delucca@lcec.net
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: No specific element
proposed.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: The only reason a lower voltage should be considered for inclusion is
if, under normal operating conditions, loss of these elements has a significant
reliability impact upon the BES
Comments relative to the proposed inclusion(s): Only where and if a rare case of BES
impact exists.

Page 13 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Paul Cummings, City of Redding
Telephone: 530-245-7016
Email: pcummings@ci.redding.ca.us
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Those elements or
facilities operated b elow 100kV that are shown through engineering studies to be
necessary to reliably operate an interconnected transmission system. See Attachment
1below.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
Refer to Attachment 1b.5
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: “The impact an Element has on the BES shall be determined by
assessing the performance of key measures of BES reliability through power flow,
post-transient, and transient stability analysis with (1) the system, and the Subject
Element, operating at reasonably stressed conditions that replicate expected system
conditions under which the loss of the Subject Element would have the greatest
impact on the key measures of reliability, and (2) the Subject Element removed from
service, but without allowing for system readjustment.”
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Region-wide

Page 14 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Patrick Farrell, Southern California Edison Company
Telephone: 626-302-1321
Email: Patrick.Farrell@sce.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Elements or Facilities
that are shown through engineering studies to be necessary to reliably operate an
interconnected bulk electric system may need to be included even if operated at
voltages below 100kV. Additionally, there are transmission facilities at 100kV and
above that are radial in nature and used for load serving purposes that are not parallel
to interconnected transmission systems. As an example, in SCE’s system the Valley
115kV system is radial in nature and the power flow is generally from 500kV to
115kV to serve load.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: An element or facility that is necessary to reliably operate an
interconnected transmission system should be included in the BES. This can be
measured using engineering studies that show the effect of worst-case disturbances on
multiple indicators such as frequency, voltage, system flows, operating limits,
generator tripping, and cascading outages and/or islanding. If the system cannot
maintain acceptable steady-state and dynamic performance without the subject
element in service, that element is necessary to reliably operate the system.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
X Continent-wide
X Interconnection-wide
X Region-wide
Comments relative to the proposed inclusion(s): While operating voltage (i.e. the
proposed 100kV bright-line) may be a clear and repeatable proxy for identifying
those elements that are necessary to reliably operate an interconnected transmission
system, it is a broad approach that may not adequately address specific examples.
Engineering studies can be used to more granularly and accurately identify elements
which are not needed to reliably operate an interconnected transmission system.
Page 15 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

The thresholds on the indicators listed above may vary between interconnections and
regions. For example, SCE’s system has facilities rated at the 115kV level that are
radial in nature for load serving purposes. Therefore, applying a 100kV bright-line
may unnecessarily bring facilities that could be excluded through an engineering
study.

Page 16 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Manny Robledo, City of Anaheim
Telephone: 714-765-5107
Email: mrobledo@anaheim.net
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
Comments relative to the proposed inclusion(s): Anaheim’s sub-transmission system is
operated at 69kV and is radial to the BES with one transmission source. There is no
transmission through Anaheim, and there are no generators connected to Anaheim’s
distribution system that are required for the reliable operation of the BES.

Page 17 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Lorissa Jones, Transmission Reliability Program Manager
Telephone: 360-418-8978
Email: ljjones@bpa.gov
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Elements or Facilities
that are shown through engineering studies to be necessary to reliably operate an
interconnected bulk electric system. Balancing Authorities need to have the authority
to recommend inclusion on a facility by facility basis based on impact to the larger
BES considerations for registration.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: An element or facility that is necessary to reliably operate an
interconnected transmission system should be included in the BES. This can be
measured using engineering studies that show the effect of worst-case disturbances on
multiple indicators such as frequency, voltage, system flows, operating limits,
generator tripping, cascading outages and/or islanding. If the system cannot maintain
acceptable steady-state and dynamic performance without the subject element in
service, it is necessary to reliably operate the system.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Interconnection-wide
Region-wide
Comments relative to the proposed inclusion(s): While operating voltage (i.e. the
proposed 100 kV brightline) may be a clear and, repeatable proxy for identifying those
elements that are necessary to reliably operate an interconnected transmission system, it
is a broad approach that may not adequately address specific examples. Moreover
engineering studies can be used to more granularly and accurately identify such
elements which are needed to reliably operate an interconnected transmission system.

Page 18 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

David Burke, Orange and Rockland Utilities
Telephone: 845-577-3076
Email: burkeda@oru.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Transmission facilities
as determined to be necessary for reliability to the bulk electric system.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: Any regional or registered entity can present technical studies to
NERC for consideration of the expansion of the Bulk Electric System. The primary
consideration by NERC Staff for inclusion must be that the addition of these
recommended facilities bring a measurable (not subjective) incremental reliability
benefit to real-time grid operations.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
X

Continent-wide

X

Interconnection-wide

X

Region-wide

X

Less than Region-wide

Comments relative to the proposed inclusion(s): Registered Entities must retain the
right to appeal any decisions with direct implications to their facilities. Broad
applications of “included facilities” could result in the designation of facilities, the
inclusion of which is not warranted. Registered Entities need the right to seek exemption
when broad new inclusions are applied.

Page 19 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Alice Ireland, Xcel Energy
Telephone: 303-571-7868
Email: alice.murdock@xcelenergy.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
d. Identify if this inclusion should apply on a continent-wide basis, interconnectionwide basis, region-wide basis, or less than a region-wide basis. If you don’t know
how widely this inclusion should apply, please select, “unknown.”
Unknown
Comments relative to the proposed inclusion(s): The scenario below should be
considered and worked through as part of the development of the definition and
exemptions. As stated in questions 2, 3, 8 of the BES definition comment questionnaire
it is unclear as to how treatment of facilities would occur, especially if there are
multiple/separate owners of each wind farm, even thought they aggregate to a common
bus that connects to the transmission system. Treatment of the bus and breakers between
each wind farm and the transformer also needs to be contemplated and addressed in the
definition or exclusion process.

Page 20 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Amir Hammad, Constellation Power Source Generation, Inc., Et all
CPSG is filing the comments below on behalf of:
Constellation Energy Group, Inc.
Baltimore Gas & Electric Company
Constellation Energy Commodities Group, Inc.
Constellation Energy Control and Dispatch, LLC
Constellation NewEnergy, Inc. and its affiliates
Constellation Energy Nuclear Group, LLC, 1
Telephone: 410-787-5226
Email: amir.hammad@constellation.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: Constellation believes
that the drafting team should incorporate the inclusions found in the Compliance
Registration criteria that have been excluded by the proposed BES definition. RFC
has adopted this approach in their BES definition.
d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Comments relative to the proposed inclusion(s): Constellation does not believe that there
are any Transmission or Generation Elements or Facilities operated at voltages below 100kV
that should be considered for inclusion in the Elements and Facilities classified as part of the
BES other than those provided for in the Compliance Registration Criteria and echoed in the
RFC BES Definition sited above.

1

On November 6, 2009, EDF, Inc. (“EDF”) and Constellation Energy Group, Inc. completed a transaction
pursuant to which EDF acquired a 49.99 percent ownership interest in CENG. CENG was previously a wholly
owned subsidiary of Constellation Energy Group, Inc.

Page 21 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

William J. Gallagher, Transmission Access Policy Study Group
Telephone: (802) 839-0562
Email: bgallagher@vppsa.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: TAPS’ proposed criteria for
inclusion are listed above in response to Question 1(a). As stated above, there should be
no “generic” or “categorical” inclusions. Inclusions, like exemptions, should be
considered on a case-by-case basis. The criteria by which proposed inclusions or
requested exemptions are judged, however, should be uniform across the continent.
Comments relative to the proposed inclusion(s): This question appears to assume that all
inclusions in the BES will be categorical, rather than case-by-case. This is inappropriate.
Inclusions, like exclusions, should involve case-specific consideration of the uniform,
continent-wide criteria.
The inclusion process should be the mirror image of the exemption process: it is NERC,
rather than the Registered Entity, who initiates the process, and the burden is on NERC to
demonstrate that the Element to be included is “necessary for operating an interconnected
electric transmission network.” The processes should otherwise be identical: the initial
determination should be made by NERC staff, with appeals to the Board of Trustees
Compliance Committee, and to FERC if necessary. The proposed process is discussed in
more detail in response to Question 1 above.

Page 22 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Marc M. Butts, Southern Company
Telephone: 205-257-4839
Email: mmbutts@southernco.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
Comments relative to the proposed inclusion(s): Subpart D should be deleted – any
inclusion should be a specific request for a specific facility, not on a generic Continent-wide,
Interconnection-wide or Region wide-basis.

Page 23 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Ronald Sporseen, PNGC Power, Et all
Email: RSporseen@pngcpower.com
Supporters of the following comments are as follows:
Bud Tracy, Blachly-Lane Electric Cooperative
Dave Hagen, Clearwater Power Cooperative
Dave Sabala, Douglas Electric Cooperative
Heber Carpenter, Raft River Rural Electric Cooperative
Dave Markham, Central Electric Cooperative
Jon Shelby, Northern Lights, Inc.
Ken Dizes, Salmon River Electric Cooperative
Ray Ellis, Okanogan County Electric Cooperative
Richard Reynolds, Lost River Electric Cooperative
Rick Crinklaw, Lane Electric Cooperative
Roger Meader, Coos-Curry Electric Cooperative
Roman Gillen, Consumer’s Power Inc.
Steve Eldrige, Umatilla Electric Cooperative
Marc Farmer, West Oregon Electric Cooperative
Michael Henry, Lincoln Electric Cooperative
Bryan Case, Fall River Electric Cooperative
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: In rare cases, facilities
operating below 100kV should be considered for inclusion in the BES, but only if the
RRO provides clear evidence that such facilities threaten to cause instability,
uncontrolled separation, or cascading outages on the bulk transmission system if
those facilities are not included as part of the BES.
b. Attach a generic one-line diagram depicting the Element or Facility (if available).
c. Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: As discussed above, the ultimate goal of the standards drafting process
must be to ensure the reliable operation of the bulk transmission system, so that the
risks of instability, uncontrolled separation, and cascading outages on the bulk system
are reduced. In rare cases, it is possible that facilities operating at voltages below
100kV may create risks of this kind to the bulk system. However, caution should be
used when identifying parallel lower voltage systems that reduce transfers on higher
voltage systems as reliability concerns. In many cases these concerns are commercial
in nature and the burden to resolve these capacity issues should be placed on the TSP.

Page 24 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide
Comments relative to the proposed inclusion(s): The BESDTF has developed an approach in
which certain facilities operating at voltages below 100kV would be included in the BES, but
facilities not falling within these specific, defined categories would not be included in the
BES unless the RRO could demonstrate that the facility creates a material impact threatening
the reliable operation of the bulk interconnected system. We believe this is a sensible
approach to this question.

Page 25 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

John D. Martinsen, Public Utility District No. 1 of Snohomish County
Telephone: 425-783-8080
Email: jdmartinsen@snopud.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a . Identify the Element or Facility recommended for inclusion:
In rare cases, facilities operating below 100 kV should be considered for inclusion in
the BES, but only if the RRO provides clear evidence that such facilities threaten to
cause instability, uncontrolled separation, or cascading outages on the bulk
transmission system if those facilities are not included as part of the BES.
b . Attach a generic one-line diagram depicting the Element or Facility (if available).
c . Provide a technical justification for the inclusion (provide justification here or attach
a supplemental document or URL link to publicly posted document if available).
Justification: As discussed above, the ultimate goal of the standards drafting process must

be to ensure the reliable operation of the bulk transmission system, so that the risks of
instability, uncontrolled separation, and cascading outages on the bulk system are
reduced. In rare cases, it is possible that facilities operating at voltages below 100 kV
may create risks of this kind to the bulk system. However, caution should be used
when identifying parallel lower voltage systems that reduce transfers on higher
voltage systems as reliability concerns. In many cases these concerns are commercial
in nature and the burden to resolve these capacity issues should be placed on the TSP.
d . Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
Continent-wide
Interconnection-wide

Comments relative to the proposed inclusion(s): The BESDTF has developed an approach
in which certain facilities operating at voltages below 100-kV would be included in the BES,
but facilities not falling within these specific, defined categories would not be included in the
BES unless the RRO could demonstrate that the facility creates a material impact threatening
the reliable operation of the bulk interconnected system. We believe this is a sensible
approach to this question.

Page 26 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 2 a-d
March 25, 2011

Steve Alexanderson P.E., Central Lincoln
Telephone: 541-574-2064
Email: salexanderson@cencoast.com
2. If you believe there are Transmission or Generation Elements or Facilities operated at
voltages below 100kV which should be considered for inclusion in the Elements and
Facilities classified as part of the BES:
a. Identify the Element or Facility recommended for inclusion: This burden would be
on the Regional Entity rather than the Registered Entity. Facilities that are not radial
serving only load may be put through an inclusion process (similar to, but with the
opposite effect of the exclusion process) to determine if they are needed for “reliable
operation” as defined in 16 U.S.C. § 824o(a)(4).
b.
c.

Attach a generic one-line diagram depicting the Element or Facility (if available). None.
Provide a technical justification for the exclus ion (provide justification here or attach a supplemental document or URL lin k to p ublicly pos ted document if available).

d. Identify if this inclusion should apply on a continent-wide basis, interconnection-wide
basis, region-wide basis, or less than a region-wide basis. If you don’t know how
widely this inclusion should apply, please select, “unknown.”
X Continent-wide

Page 27 of 27

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Question 3: Summary Consideration: Prior to the issuance of Order 743a, the SDT reviewed
all of the provided material and used this material and the examples supplied in its consideration
of the revised definition of the Bulk Electric System (BES). The goal of the SDT is to provide a
bright-line definition of BES which adheres to the guidelines and directives in Order 743. This
bright-line definition contains certain inclusions and exclusions for specific equipment and
configurations. The SDT believes that this definition now answers many of the questions raised
by industry and encompasses most of the examples provided. However, no bright-line definition
will be able to capture all of the concerns or situations. Accordingly, and consistent with Order
743, another aspect of this project is to establish an exception process with criteria based on
reliability principles for the Interconnected BES that will be incorporated in NERC’s Rules of
Procedure (ROP) that will allow a process for the inclusion or exclusion of a particular BES
Element from the definition. This ROP work effort will be done by a separate team but the
DBESSDT will be in close coordination with that team.
Please provide any other information that you feel would be helpful to the group
working to develop a BES Definition Exception Process.
Commenters:
John A. Gray, The Dow Chemical Company ................................................................................. 3
Michael Moltane/John Zipp, ITC Holdings .................................................................................... 4
Laura Lee, Duke Energy ................................................................................................................. 5
Michelle Mizumori, Western Electricity Coordinating Council..................................................... 6
Brandy A. Dunn, Western Area Power Administration ................................................................. 7
Alain Pageau, Hydro-Québec TransÉnergie ................................................................................... 8
Guy Zito, Northeast Power Coordinating Council ......................................................................... 9
Jim UhrinReliabilityFirst Corporation .......................................................................................... 11
Joe Petaski, Manitoba Hydro ........................................................................................................ 12
John W. Delucca, Lee County Electric Cooperative .................................................................... 13
Paul Cummings, City of Redding ................................................................................................. 14
Patrick Farrell, Southern California Edison Company ................................................................. 15
Dan Rochester, Independent Electricity System Operator ........................................................... 16
Lorissa Jones, Transmission Reliability Program Manager ......................................................... 18
David Burke, Orange and Rockland Utilities ............................................................................... 19
Page 1 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Alice Ireland, Xcel Energy ........................................................................................................... 21
Allen Mosher, American Public Power Association .................................................................... 22
Jim Case, Entergy SERC OC Standards Review Group............................................................... 25
John P. Hughes, Electricity Consumers Resource Council (ELCON) ......................................... 26
Thad Ness, American Electric Power ........................................................................................... 31
Amir Hammad, Constellation Power Source Generation, Inc. (CPSG), Et All............................ 32
Marc M. Butts, Southern Company .............................................................................................. 35
Andrew Z. Pusztai, American Transmission Company ................................................................ 36
Al DiCaprio, PJM ......................................................................................................................... 37
Bud Tracy, Blachly-Lane Electric Cooperative ............................................................................ 38
Jerome Murray, Oregon Public Utility Commission .................................................................... 41
John D. Martinsen , Public Utility District No. 1 of Snohomish County ..................................... 42
Steve Alexanderson P.E., Central Lincoln.................................................................................... 45
Brian J. Murphy, NextEra Energy, Inc. ........................................................................................ 46
Phil Tatro, NERC Staff ................................................................................................................. 49

Page 2 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

John A. Gray, The Dow Chemical Company
281‐966‐2390
JAGray3@dow.com
3. Please provide any other information that you feel would be helpful to the group working
to develop a BES Definition Exception Process.
Comments: Dow has reviewed and generally supports the comments prepared by The
Electricity Consumers Resource Council (ELCON).

Page 3 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Michael Moltane/John Zipp, ITC Holdings
Telephone: 248-946-3093
Email: mmoltane@itctransco.com
3. Please provide any other information that you feel would be helpful to the group working
to develop a BES Definition Exception Process.
Comments: I would be motivated to apply for element exclusions and the process looks
good. I don’t see a reason for us to apply for any inclusions

Page 4 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Laura Lee, Duke Energy
Telephone: 704-382-3625
Email: Laura.Lee@duke-energy.com
3. Please provide any other information that you feel would be helpful to the group working
to develop a BES Definition Exception Process.
Comments: There are three parts to the work that need to be accomplished to fulfill the
intent of the Commission’s Order; 1) revision of the definition of Bulk Electric System, 2)
development of exemption criteria and 3) development of a process for applying the
exemption criteria. The first two parts of the work should be accomplished using the
standards development process. This work is technical in nature and therefore should be
developed by technical experts in the industry. The Rules of Procedure change process
should be reserved for the mechanics of administering the exemption process.
The Regions should administer the exemption process with NERC serving an oversight role
to ensure consistency among the Regions. This would fit logically with the Regions’
administration of other processes such as the registration process.
Each registered entity that identifies Transmission or Generation Elements or Facilities that
should be included or excluded from the Bulk Electric System should submit an application
to the Region, including the information sought in parts a, b and c of questions 1 and 2 in this
document (i.e., identification of the Element or Facility, diagram, and technical justification).
The Region should then review the request through a stakeholder technical committee using
the criteria approved through the standards development process. NERC should periodically
review all applications of the exemption process to ensure consistency in the Regions’
application of the criteria.

Page 5 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Michelle Mizumori, Western Electricity Coordinating Council
Telephone: 801-819-7624
Email: mmizumori@wecc.biz
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: In addition to defining functional characteristics that can be used for an
exemption process, the use of engineering studies that demonstrate the effect of an element
on system performance must also be allowed, but must include clearly-defined and
technically-justified assumptions, metrics, and thresholds. To the extent that there are
physical differences between regions or interconnections, variations between those regions
and interconnections must be allowed. However; all assumptions, metrics, and thresholds
must be thoroughly vetted and approved by NERC as part of the NERC Exemption Process.
Furthermore, it would be helpful if NERC could clarify the process that it will use to develop
the Exemption Process and Criteria, including how the team will be populated, how
coordination with the Drafting Team will be assured, and how the vetting process would
occur. It is important that the team developing the exemption criteria includes technical
experts from the stakeholder community.

Page 6 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Brandy A. Dunn, Western Area Power Administration
Telephone: 720-962-7431
Email: dunn@wapa.gov
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: The use of engineering system studies that demonstrate the impact of an
Element on system performance must be allowed to demonstrate inclusion/exclusion to the
BES. To the extent there are physical differences between Regions, variations between those
Regions must be allowed. Also – the Exception Definition Task Force needs to be a
stakeholder-populated/ -driven process.
The exemption process should be part and parcel of the definition. Exemption language
furthermore must be explicit and unambiguous. The WECC Bulk Electric Definition Task
Force (BESDTF) has expended considerable effort over the last two years exploring
important issues pertaining to exempting elements from the BES including;
a.
b.
c.
d.

Lines of demarcation between BES and non-BES elements
Definition of ‘radial’
High voltage distribution networks.
Impact assessment methodologies.

Page 7 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Alain Pageau, Hydro-Québec TransÉnergie
Telephone: 514 879-4100 #5414
Email: pageau.alain@hydro.qc.ca
3. Please provide any other information that you feel would be helpful to the group working
to develop a BES Definition Exception Process.
Comments: For the Canadian entities, the inclusion or exclusion of equipment and
facilities in the BES must be also approved by the Canadian regulators. (as answer 2c).
We believe that it is very difficult to propose first a definition for the BES and only after
an Exemption process. Both aspects influence each other and both should be carried out
together.

Page 8 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Guy Zito, Northeast Power Coordinating Council
Telephone: 212-840-1070
Email: gzito@npcc.org
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
[1] Seven Factor Test – NPCC participating members believe that the BES Exclusion
process should place substantial weight upon Factor 3 from the FERC Seven Factor test.
Factor 3 states, “Power flows into local distribution systems, and rarely, if ever flows out.” 1
We also believe that Factor 7 has been broadly interpreted by FERC, State Commissions and
the Courts to include facilities serving a distribution function and operated at 100 kV and
above. 2,3,4,5,6,7
[2] NPCC A-10 Methodology for Determine BPS Elements – NPCC participating member
believe the A-10 Criteria methodology that NPCC uses to determine its BPS elements can be
further utilized to identify critical system components that may be operated below the 100 kV
threshold. The Criteria may also be used be used in lieu of the use of “higher” thresholds
that appear or are contemplated in some of the ERO standards such as FAC-003 cites 200kV
and above, the TPL-001 currently under development may specify a 200 kV threshold for
some “more stringent” planning criteria. These higher thresholds may lend themselves to the
use of an “impact based” methodology that could be used to determine where more stringent
requirements may need to be applied.
[3] New York State Public Service Commission (NYSPSC) - In Opinion No. 97-12, Case
97-E-0251, the NYPSC provided utilities under its jurisdiction explicit guidance for
1

We view the term “rarely” as used in Factor 3 to be bounded on the upside by a reverse power flow rate of no
more than 10% of all hours and a peak reverse power flow (MW) amount of no more than 50% of peak inflows.
2
STATE OF IOWA DEPARTMENT OF COMMERCE UTILITIES BOARD, DOCKET NO. SPU-98-12, IN RE: MIDAMERICAN
ENERGY COMPANY, ORDER RECOMMENDING DELINEATION OF TRANSMISSION AND LOCAL DISTRIBUTION
FACILITIES, Issued April 30, 1999. See http://www.state.ia.us/iub/docs/orders/1999/0430_spu9812.pdf
3
Pacific Gas and Electric Company, et al., 77 FERC ¶ 61,077 at 61,325 (1996).
4
Puget Sound Energy, Inc., 110 FERC ¶ 61,229 at 61,856 (2005).
5
Case No. U-l3862, August 26, 2003 meeting of the Michigan Public Service Commission in Lansing, Michigan.
6
“With regard to the deference it would provide to recommendations by state regulatory authorities concerning
where to draw the jurisdictional line between FERC jurisdictional transmission facilities and state-jurisdictional
local distribution facilities, FERC provided the following guidelines:… (e) If the utility's classifications and/or cost
allocations are supported by the state regulatory authorities and are consistent with the principles established in
Order No. 888, FERC will defer to such classifications and/or cost allocations.” FERC comments filing by Central
Illinois Light Company, Docket EL03-39-000, filed Dec. 20, 2002.
7
Mansfield Municipal Electric Department v. New England Power Co., 97 FERC ¶ 61,134 (2001). “…the
Municipals' facilities have all of these [Seven Factor Test] indicators except the last one. The voltage of the lines is
115 kV, the same voltage as the transmission grid. As discussed supra, the voltage alone is not dispositive of the
issue as to whether a line is distribution or transmission. We must also look at the function.”

Page 9 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

determining the point-of-demarcation between transmission facilities under FERC
jurisdiction and distribution
facilities under NYSPSC jurisdiction. 8 Appendix C to this Order established three (3)
measures that utilities were instructed to use in determining the classification of transmission
and distribution assets.
[4] FERC non-jurisdictional entities such as the Canadian Provinces.
The exemption process should clearly address the process and requirements for FERC nonjurisdictional entities (such as the Canadian entities) with the exception of the
interconnections between them and those entities under FERC jurisdiction, and/or those
entities having a direct impact on those interconnections. See APPENDIX C

8

STATE OF NEW YORK PUBLIC SERVICE COMMISSION, OPINION NO. 97-12 in CASE 97-E-0251 - Proceeding on
Motion of the Commission to Distinguish Bulk Electric Transmission System from Local Distribution Facilities.

Page 10 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Jim Uhrin

ReliabilityFirst Corporation

Telephone: 330.247.3058
Email: jim.uhrin@rfirst.org
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: ReliabilityFirst would like to see this as a simple and easy-to-follow definition.
The exclusion process needs to be clear without room for discussion or interpretation.
•

There must be a common framework developed, along with a single NERC-wide
BES definition.

•

The definition should serve as a common approach for the identification of BES
Elements and Facilities that are subject to compliance.

•

The definition and approach for the determination must be repeatable.

•

The method must clearly identify the BES elements for use by the industry.

•

In order to obtain consistency, the definition, application and criteria must be used
across Regional Entity boundaries.

•

The revised BES definition should be consistent with the Statement of Compliance
Registry Criteria so as not to create a conflict between the two, and could possibly
simply reference the Criteria for issues such as size of generating units (e.g., 20 MVA
units and 75 MVA plants) included in the BES.

•

The criteria for exemption should be included within the BES definition, and the
exemption process should contain only the procedure for submitting and
determination of such. The exemption process should not contain a third set of
criteria (in addition to the BES definition itself and the Statement of Compliance
Registry Criteria) in which to make a determination of facilities to be monitored for
compliance to standards.

•

With the revised BES definition containing specific requirements for inclusion in the
BES, will the separate Statement of Compliance Registry Criteria even be needed?

Page 11 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Joe Petaski, Manitoba Hydro
Telephone: 204-487-5332
Email: jpetaski@hydro.mb.ca
3. Please provide any other information that you feel would be helpful to the group working
to develop a BES Definition Exception Process.
Comments:
a. A NERC definition of ‘radial’ is required to prevent misapplication of the BES
definition and exemption process.
b. There should be no regional differences in the BES definition or in the BES definition
exemption process.
c. There should be equal representation from the regions to draft this standard
d. There should be consistent wording to describe the process - exception or exemption.

Page 12 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

John W. Delucca, Lee County Electric Cooperative
Telephone: 239-656-2190
Email: john.delucca@lcec.net
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: The exception process under draft in the FRCC region should serve as a strong
basis that could be applied Continent-wide. Also while the exclusion process should be
administered within the Region there needs to be an appeals process in place that progresses
quickly. In addition, a Region should not be allowed to allege violations of reliability
standards related to a system while in the appeals process. If the appeal is not upheld the
entity should then be allowed time to bring the system into compliance. Also for
consideration Bright-line” methodology seems to be the “easy button” solution, but this
“one-size fits all’ places the burden on entities to obtain exclusions. From an entity’s
viewpoint, move the “bright-line threshold” to non-radial facilities operating at or greater
than 230 kV, and adopt an inclusion process and criteria for including facilities that are
necessary to operate an interconnected electric transmission network.

Page 13 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Paul Cummings, City of Redding
Telephone: 530-245-7016
Email: pcummings@ci.redding.ca.us
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: The WECC Bulk Electric System Definition Task Force has done extensive
work on this topic. Please consider their current work when drafting the BES definition and
exception process.

Page 14 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Patrick Farrell, Southern California Edison Company
Telephone: 626-302-1321
Email: Patrick.Farrell@sce.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: In addition to defining functional characteristics that can be used for an
exemption process, the use of engineering studies that demonstrate the effect of an element
on system performance should be allowed, with clearly defined and technically justified
assumptions, metrics, and thresholds. To the extent that there are physical differences
between regions or interconnections, variations between those regions and interconnections
should be allowed. However, all the assumption, metrics, and thresholds will need to be
thoroughly vetted and approved by NERC as part of the NERC Exemption Process.

Page 15 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Dan Rochester, Independent Electricity System Operator
Telephone: 905-855-6363
Email: dan.rochester@ieso.ca
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: We have difficulties understanding the intent of this Comment Form and the
content in Q1 and Q2, above, which appear to be templates for information to be included in
an exclusion/inclusion request rather than asking for comments on each of the listed items.
1. Is the intent of this Comment Form to obtain:
a.

Recommendations of the criteria to be considered in developing deviations from the
default criteria for classifying Elements and Facilities as part of the BES?

b.

Assessment of the templates proposed in Q1 and Q2?

2. The concept paper that is posted alongside the SAR and proposed definition is not
referenced in this Comment Form. Is it the drafting team’s intent to solicit comments on
the concept paper?
3. In the concept paper, three exemption criteria are presented. We do not have any issue
with the first and third criteria but are concerned that Criterion #2 is not a criterion. It
states that:
“Elements and Facilities identified through application of the exemption process,
consistent with the criteria, where the exemption process deems that the Element or
Facility should be excluded from the BES (with concurrence from the ERO).”
This criterion appears to reference yet another set of criteria not already included in the
set or the concept paper. In fact, this “referenced” set needs to be clearly stipulated to
ensure that applicants are fully aware of the conditions under which an Element or
Facility operated at 100 kV or above can be deemed not necessary to support bulk power
system reliability and, conversely, the conditions for an Element or Facility operated at
below 100 kV to be included. The “templates” presented in Q1 and Q2 of this Comment
Form also do not convey the needed conditions.
We believe it is the clear conditions for exclusion (Elements/Facilities of 100 kV and
above) and inclusion (below 100 kV) that need to be developed and fully vetted. We urge
the drafting team to proceed to developing these criteria expeditiously so as to support the
assessment and approval of the revised definition of BES.
4. We strongly advocate that the exemption process allows for a registered entity to submit
the results of an objective, impact-based assessment process in support of its application
for exemption of facilities that would otherwise be classified as part of the BES. This
Page 16 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

assessment process, when consistently applied in a non-arbitrary manner, would yield
results that demonstrate concretely, that the facilities for which the exemption is being
sought, do not impact the BES.
5. Finally, given that the exemption process will be used to included and exclude
transmission facilities we suggest either of the following as a more appropriate name:
“BES Classification Exception Process” or “BES Classification Review Process”.

Page 17 of 55

Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Lorissa Jones, Transmission Reliability Program Manager
Telephone: 360-418-8978
Email: ljjones@bpa.gov
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: In addition to defining functional characteristics that can be used for an
exemption process, the use of engineering studies that demonstrate the effect of an element
on system performance must also be allowed, with clearly defined and technically justified
assumptions, metrics and thresholds. Furthermore, to the extent that there are physical
differences between regions or interconnections, variations between those regions and
interconnections must be allowed. However all assumptions, metrics and thresholds must be
thoroughly vetted and approved by NERC as part of the NERC Exemption Process.

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David Burke, Orange and Rockland Utilities
Telephone: 845-577-3076
Email: burkeda@oru.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
[1] Seven Factor Test – NPCC participating members believe that the BES Exclusion process
should place substantial weight upon Factor 3 from the FERC Seven Factor test. Factor 3
states, “Power flows into local distribution systems, and rarely, if ever flows out.” 9 We also
believe that Factor 7 has been broadly interpreted by FERC, State Commissions and the
Courts to include facilities serving a distribution function and operated at 100 kV and above.
10,11,12,13,14,15

[2] NPCC A-10 Methodology for Determine BPS Elements – NPCC participating member
believe the A-10 Criteria methodology that NPCC uses to determine its BPS elements can be
further utilized to identify critical system components that may be below the 100 kV
threshold. The Criteria may also be used be used in lieu of the use of “higher” thresholds
that appear or are contemplated in some of the ERO standards such as FAC-003 cites 200kV
and above, the TPL-001 currently under development may specify a 200 kV threshold for
some “more stringent” planning criteria. These higher thresholds may lend themselves to the
use of an “impact based” methodology that could be used to determine where more stringent
requirements may need to be applied.
[3] New York State Public Service Commission (NYSPSC) - In Opinion No. 97-12, Case
97-E-0251, the NYPSC provided utilities under its jurisdiction explicit guidance for
determining the point-of-demarcation between transmission facilities under FERC
9

We view the term “rarely” as used in Factor 3 to be bounded on the upside by a reverse power flow rate of no
more than 10% of all hours and a peak reverse power flow (MW) amount of no more than 50% of peak inflows.
10
STATE OF IOWA DEPARTMENT OF COMMERCE UTILITIES BOARD, DOCKET NO. SPU-98-12, IN RE: MIDAMERICAN
ENERGY COMPANY, ORDER RECOMMENDING DELINEATION OF TRANSMISSION AND LOCAL DISTRIBUTION
FACILITIES, Issued April 30, 1999. See http://www.state.ia.us/iub/docs/orders/1999/0430_spu9812.pdf
11
Pacific Gas and Electric Company, et al., 77 FERC ¶ 61,077 at 61,325 (1996).
12
Puget Sound Energy, Inc., 110 FERC ¶ 61,229 at 61,856 (2005).
13
Case No. U-l3862, August 26, 2003 meeting of the Michigan Public Service Commission in Lansing, Michigan.
14
“With regard to the deference it would provide to recommendations by state regulatory authorities concerning
where to draw the jurisdictional line between FERC jurisdictional transmission facilities and state-jurisdictional
local distribution facilities, FERC provided the following guidelines:… (e) If the utility's classifications and/or cost
allocations are supported by the state regulatory authorities and are consistent with the principles established in
Order No. 888, FERC will defer to such classifications and/or cost allocations.” FERC comments filing by Central
Illinois Light Company, Docket EL03-39-000, filed Dec. 20, 2002.
15
Mansfield Municipal Electric Department v. New England Power Co., 97 FERC ¶ 61,134 (2001). “…the
Municipals' facilities have all of these [Seven Factor Test] indicators except the last one. The voltage of the lines is
115 kV, the same voltage as the transmission grid. As discussed supra, the voltage alone is not dispositive of the
issue as to whether a line is distribution or transmission. We must also look at the function.”

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March 25, 2011

jurisdiction and distribution facilities under NYSPSC jurisdiction. 16 Appendix C to this
Order established three (3) measures that utilities were instructed to use in determining the
classification of transmission and distribution assets. See APPENDIX C
NEW YORK INDICATORS (FINAL REVISED VERSION)
[NY-1] A transmission system delivers power from generation plants to local distribution
systems. Where a generator directly supplies a local distribution system, the need for a
transmission system to deliver its output to load depends on the size of the generator in
relation to the minimum load of that system.
[NY-2] Transmission systems end at the high-voltage terminals or at the disconnect switch of
a substation transformer; if no transformer is present, the transmission system ends at the bus
tap of the local distribution feeder.

16

STATE OF NEW YORK PUBLIC SERVICE COMMISSION, OPINION NO. 97-12 in CASE 97-E-0251 - Proceeding on
Motion of the Commission to Distinguish Bulk Electric Transmission System from Local Distribution Facilities.

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Proposed Definition of Bulk Electric System – Project 2010-17
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March 25, 2011

Alice Ireland, Xcel Energy
Telephone: 303-571-7868
Email: alice.murdock@xcelenergy.com

3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: Xcel Energy agrees that the FERC Order 743 directs NERC to modify the
Rules of Procedure to include the process for how an entity or region may initiate an
exclusion or inclusion. However, we do not agree that FERC also directed that the actual
criteria and technical specifics for inclusion or exclusion be developed as part of the Rules
of Procedure. Furthermore, since the inclusion/exclusion criteria is a key component to the
definition of BES, we feel the criteria should be treated as part of the definition development
and developed in the same manner as the definition itself. (Preferably by the same drafting
team.)
It is also not clear as to why the Reliability Assurer is included as an applicable entity in the
SAR.

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Proposed Definition of Bulk Electric System – Project 2010-17
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March 25, 2011

Allen Mosher, American Public Power Association
Telephone: 202-467-2944
Email: amosher@publicpower.org
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
The Concept Paper states at page 1 that in Order 743, FERC directed NERC to do the
following:
A. Utilize the NERC Standard Development Process to revise the definition of Bulk
Electric System (BES) contained in the NERC Glossary of Terms.
B. Develop a single Implementation Plan to address the application of the revised
definition of the BES and the implementation of the exemption process.
C. Utilize the NERC Rules of Procedure to develop and implement an ’exemption
process’ used to identify Elements and Facilities which will be included in or
excluded from the BES.
The Concept Paper continues to state that:
This project will address items ‘A’ and ‘B’ and will coordinate efforts between the
Standard Drafting Team (SDT) and the group working to develop the exemption process
for inclusion in the NERC Rules of Procedure to ensure that the revised BES definition
and exemption process result in an accurate, repeatable, and transparent method for the
identification of BES and non-BES Elements and Facilities.
APPA agrees that the standards process must be used to develop the revised BES
definition and that NERC has been directed to use its Rules of Procedure process to
develop an ROP-based procedure to implement an exemption/exclusion/inclusion
process. However, the FERC directives do not speak to how and by whom the technical
methodology, study criteria and data requirements for requesting and receiving approval
for an exemption should be developed.
To the maximum extent possible, subject to time constraints imposed by FERC, this
inherently technical methodology needs to be developed through the NERC standards
development process, in conjunction with development of the revised definition of BES.
Separate development will significantly hamper development of industry consensus in
support of the revised BES definition and the yet to be developed ROP modifications for
the exemption process.
The most critical question is how do we arrive at a commonly agreed upon, widely
accessible, transparent, and replicable continent-wide methodology to determine whether
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March 25, 2011

each specific facility is or is not “necessary to operate an interconnected electric
transmission network” to quote from paragraph 16 of Order 743. While each region may
have a separate model reflecting its topology and system performance characteristics, a
continent-wide approach is required to address FERC concerns about inconsistency
across regions that are not the result of physical differences.
The statutory definition of the term bulk-power system defines the outer extent of
facilities that can be included (at least within the United States) within the NERC
definition of BES. FPA section 215(a)(1) states that the bulk-power system includes “(A)
facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof); and (B) electric energy from generation
facilities needed to maintain transmission system reliability.” Further, the term BPS
“does not include facilities used in the local distribution of electric energy.” [emphasis
added].
Similarly, “reliable operation” is defined at 215(a)(4) to mean “operating the elements of
the bulk-power system within equipment and electric system thermal, voltage, and
stability limits so that instability, uncontrolled separation, or cascading failures of such
system will not occur as a result of a sudden disturbance, including a cybersecurity
incident, or unanticipated failure of system elements.”
These definitions appear to point to two basic questions for the classification of each facility
or element as BES or non-BES:
1. Is the facility or element necessary for reliable operation because it contributes
significant capability to the interconnected transmission network?
2. Will the misoperation or unanticipated failure of the facility or element adversely
affect the reliable operation of the interconnected transmission network?
APPA suggests that the BES SDT or separate study teams should be directed to establish the
outline for this study methodology. APPA further suggests that BES sub-teams be
established to address the Proposed BES Criteria in the Concept Paper. Separate sub-teams
should be established to address detailed system configuration and study methodology issues
affecting:
1. Radials serving load (with and without distribution voltage generation not subject to
registration)
2. Other transmission elements that entities seek to include in or exclude from the BES.
3. Generating plant equipment that entities seek to include in or exclude from the BES.
4. Technical issues raised by the FERC Seven Factor Test for Local Distribution
Facilities.
Separate sub-teams are appropriate because the study issues are likely to be quite distinct.
For example, radials serving only load do not provide alternative pathways for reliable BES
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operations, as might some sub-100 kV facilities. Mixing the two teams together might slow
progress on identification of various commonly used radial to load center configurations that
with proper protection schemes do not have the potential to adversely affect the BES. A
focused effort on permissible exclusions of radials serving load is essential to prevent
distribution providers from adopting less reliable system configurations to serve their loads
because they are concerned that the preferred configuration will make them subject to
registration as TOs and/or TOPs.
Note that the proposed sub-teams do not necessarily have to be populated by members of the
SDT. The new standards process allows SDTs to gather informal input from a variety of
sources. However, development and posting for industry comment of the minimum
acceptable characteristics of the study methodology to be used in the Exceptions Process
should be the responsibility of the BES SDT.
The Comment Form on the Exclusion Process poses reasonable questions and it is my hope
that registered entities and regional entities identify numerous candidate facilities and
elements for inclusion or exclusion from the BES, accompanied by one-line diagrams that lay
out each of the permutations for such facilities that are candidates for exclusion/inclusion.
These facilities range from simple radial transmission lines and distribution step-down
transformers to 100 kV class distribution networks that operate radially from the BES. I also
hope that entities submit extensive technical documentation to explain why such facilities
should be excluded from or included in the BES.

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Proposed Definition of Bulk Electric System – Project 2010-17
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March 25, 2011

Jim Case, Entergy SERC OC Standards Review Group
SERC OC Standards Review Group participants in developing the above comments:
Jim Case, Entergy
Gerald Beckerle, Ameren
Andy Burch, EEI
Randy Castello, Miss Power
Dan Roethemeyer, Dynegy
Melinda Montgomery, Entergy
Sam Holeman, Duke
Joel Wise, TVA
Alvis Lanton, SIPC
Hamid Zakery, Dynegy
John Neagle, AECI
Mike Hirst, Cogentrix
Tim Hattaway, PowerSouth
Robert Thomasson, BREC
Shardra Scott, Gulf Power
Patrick Woods, EKPC
Alisha Ankar, Prairie Power
Bill Hutchison, SIPC
J.T. Wood, Southern
Telephone: 601-985-2345
Email: jcase@entergy.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: Each inclusion and exclusion should be based solely on its technical
justification.
“The comments expressed herein represent a consensus of the views of the above named
members of the SERC OC Standards Review group only and should not be construed as the
position of SERC Reliability Corporation, its board or its officers.”

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Proposed Definition of Bulk Electric System – Project 2010-17
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March 25, 2011

John P. Hughes, Electricity Consumers Resource Council (ELCON)
Telephone: 202-682-1390
Email: jhughes@elcon.org
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: ELCON members have always supported fair and effective reliability efforts at
NERC. However, the expansion of the standards compliance responsibility implied by the
NERC Concept Document goes too far. As written, this proposal could have the effect of
devaluing a large number of industrial owned electrical power assets by forcing industrials to
meet new and unnecessary compliance obligations. Many will be forced to choose to either
accept a significant new cost or fire sale their assets to local providers increasing the
purchaser’s market power in the process. ELCON feels the addition of new compliance
obligations should not be done in such a wholesale manner but instead done on an exception
and as needed basis that factors in both a realistic appraisal of the underlying risk and the
economic burden imposed on the registered entity relative to the expected benefits.
Specific recommendations and concerns are:
1. An Overarching “Principle” for the Identification of BES Elements and Facilities Must be
the Guidance Provided by FERC That Significant Expansion of the Compliance Registry
is Not Contemplated.
In FERC’s March 18, 2010 Notice of Proposed Rulemaking (NOPR) on the Revision to
Electric Reliability Organization Definition of Bulk Electric System, the Commission
stated regarding the revision to the BES definition:
This proposal would eliminate the discretion provided in the current definition for
a Regional Entity to define “bulk electric system” within a region. Importantly,
however, we emphasize that we are not proposing to eliminate all regional
variations and we do not anticipate that the proposed change would affect most
entities. ¶ 16. … the Commission does not believe that the proposal would have
an immediate effect on entities in any Regional Entity other than NPCC. ¶ 27.
Similarly, in Order No. 743, the Commission stated:
We expect that our decision to direct NERC to develop a uniform modified
definition of “bulk-electric system” will eliminate regional discretion and
ambiguity. The change will not significantly increase the scope of the present
definition, which applies to transmission, generation and interconnection
facilities. The proposed exemption process will provide sufficient means for
entities that do not believe particular facilities are necessary for operating the
interconnected transmission system to apply for an exemption. ¶ 144.

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One area where the proposed BES definition and exception process will significantly
expand the Compliance Registry is the criteria applicable to behind-the-meter generation
(primarily cogeneration facilities). We urge that the BES definition should not change
the currently applicable 20 MVA / 75 MVA generation size threshold applicable to
generation facilities or the manner in which that threshold is currently applied, with
behind‐ the‐ meter cogeneration facilities evaluated based on the net capacity actually
provided to the grid.
2. A Second Overarching “Principle” for the Identification of BES Elements and Facillities
Is the Need to Clarify Which Facilities Perform a True Transmission Function and
Excluding Facilities That Perform a Local Distribution Function, As Required by Law.
Congress stated in Federal Power Act section 215:
SEC. 215. ELECTRIC RELIABILITY.
‘‘(a) DEFINITIONS.—For purposes of this section:
‘‘(1) The term ‘bulk-power system’ means—
‘‘(A) facilities and control systems necessary for operating an interconnected
electric energy transmission network (or any portion thereof); and
‘‘(B) electric energy from generation facilities needed to maintain transmission
system reliability.
The term does not include facilities used in the local distribution of electric
energy.
There has been little attempt by NERC to clarify what in fact are “facilities used in the
local distribution of electric energy” even though any plain English application of the
term makes such a determination self-evident. The proposed BES definition should
expressly exclude facilities used in the local distribution of electric energy, and the
identification of such facilities is independent of the identification of BES transmission.
Facilities used for local distribution are NOT the residual of any determination of what
are BES transmission facilities.
3. A Third Overarching “Principle” for the Identification of BES Elements and Facilities
Must be Recognition of the Risk Imposed by the Element or Facility, and the Economic
Burden of the Owner/Operator of the Element of Facility.
The efforts of the BES Standards Drafting Team follow the release of two important
policy documents.
First, on January 18, 2011, the White House issued an Executive Order (“Improving
Regulation and Regulatory Review”) by President Obama regarding improvements to
federal regulations and the review of existing regulations to ensure, among other things,
that a regulation be proposed or adopted “only upon reasoned determination that its
benefits justify its costs,” and that regulations be tailored “to impose the least burden on
society.”
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Second, the NERC Planning Committee issued on January 10, 2011, “Risk-Based
Reliability Compliance – White Paper Concept Discussion,” which attempts to advance
“processes and procedures to prioritize [NERC’s] efforts and ‘tiering’ elements of its
programs to maximize their value and optimize the benefit/cost of effort from
stakeholders.” This white paper complements the President’s Executive Order.
ELCON believes that BES exclusion criteria and process should recognize and exclude
elements and facilities in which the risk to bulk electric system reliability is at most
theoretical or speculative, and where the compliance burden clearly outweighs the
benefits. Such a determination should recognize the historical record of the element or
facility in terms of the owner or operator’s coordination with the BA or control area, and
transmission operators. This principle should be applied to the development of
exclusion/inclusion criteria for private lines that connect loads and behind-the-meter
generation to true BES Elements and Facilities.
4. An Additional Principle for the Identification of BES Elements and Facilities Should Be
the Explicit Recognition on How the Element or Facility is Actually Operated or Used,
Not Its Physical or Nominal Rating That May be Irrelevant to Reliability Considerations.
In Order No. 743, FERC clarified that it did not intend to require NERC to utilize the
term “rated at” rather than the term “operated at” for the voltage threshold in the revised
BES definition. A principle for the identification of BES Elements and Facilities should
be such recognition and not exclusively on the rated value of an Element or Facility.
This principle should be used to retain the exclusion in the Statement of Compliance
Registry Criteria (Revision 5.0) for “net capacity provided to the bulk power system” in
the context of the 20 MVA generating unit and 75 MVA generating plant thresholds. The
“net capacity” applies to capacity “put” of a behind-the-meter generator whose
predominant function is to serve load at the same site.
5. An Additional Principle for the Identification of BES Elements and Facilities Should be
the Exclusion of PSEs That Do Not Own or Operate Physical Assets and Whose Power
Transactions Are Exclusively Financial in Nature.
Many PSEs that operate in FERC jurisdictional organized wholesale markets (i.e., ISOs
and RTOs) do not own, operate or lease physical assets and are currently bombarded with
data requests that assume that they own or control such assets. An example of a
superfluous data request is to prove that adequate reactive power has been procured to
support the load. This is a question that should not have been asked and displays a
profound ignorance of the operation of ISO/RTO markets. One potential solution to this
problem is to create two subsets of PSEs: one that owns and operates physical assets that
are used to serve their loads, and a second that does not.
Some Regional Entities have also begun to ask questions that require PSEs to reveal the
details of specific commercial transactions. This raises a broader question on what
NERC and regional compliance staffs and auditors “need to know” and whether such
questions are an abuse of their enforcement authority.
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6. Any Attempt to Make Demand Side Management (DSM) Measures an Element or
Facility of BES Will Be Shortsighted and Counterproductive.
Proposals that unilaterally and arbitrarily remove exclusions for generation and
transmission, including the application of new compliance obligations to DSM programs,
go far beyond what FERC intended in its guidance for revisions. Any new requirement
concerning voluntary DSM adds cost to a process that so far has only acted to support
reliability with performance equal to and sometimes superior to traditional providers.
How is it that a potential resource that can contribute to maintaining reliability is now so
quickly identified as a risk? We warn against the overzealous pursuit of control over
every asset and resource on the electric system. This mindset will only breed cynicism
and end the willingness of potentially dispatchable loads to cooperate with the real
operators and owners of the BES.
A recently issued FERC study highlights the potential value to reliability of DSM (in the
form of dispatchable demand response) (See Joseph H. Eto et al., Use of Frequency
Response Metrics to Assess the Planning and Operating Requirements for Reliable
Integration of Variable Renewable Generation, LBNL-4142E, December 2010). To
reliably integrate greater amounts of wind energy resources to the bulk electric system,
the study recommended the:
Expanded use of demand response that is technically capable of providing
frequency control (potentially including smart grid applications), starting with
broader industry appreciation of the role of demand response in augmenting
primary and secondary frequency control reserves.
7. Revising the Definition of BES Does Not Justify Shifting the Plenary Burden for BPS
Reliability from Utilities to Utility Customers. A BES Principle Should Recognize That
the Obligation to Serve Applies in One Direction.
The only reason the bulk power system exists is to deliver electric power to residential
households, commercial businesses, government facilities and industrial facilities of all
sizes. The value of a reliable BPS is dependent on the needs of end use customers.
Nothing in the legislative history of section 215 of the Federal Power Act suggests that
Congress wittingly intended to change that relationship.
The burden of complying with NERC Reliability Standards is a cost of doing business for
utility providers of generation, transmission and distribution services. Generation and
interconnection facilities of industrial customers are almost never intended for or used to
“operate the interconnected transmission network.” Those facilities are integral to a
manufacturing process, including purchasing power from the grid. They were built in
expectation that the BPS was prudently planned and operated by utilities. The rare
exceptions are administered under applicable tariffs or contracts, and are already
Registered Entities.

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Part of NERC’s effort should include defining the line between a BES asset that is used
to deliver power and an End User asset that's sole purpose is to serve the End User's load.
The NERC Functional Model includes a vague definition of End-use Customer. The
problem is determining the scope of an end-use device. If an industrial company owns a
138 kV to 13.8 kV transformer that feeds its plant, is that an end-use device or a
transmission asset that is used to transmit power to the low voltage distribution network
within the manufacturing facility? Any work to revise the definition of the BES should
also include a clarification of its boundaries. We believe that NERC should not expand
the scope of the BES to include assets within end-use customer's private use networks.
8. An Additional BES Principle Should be that BES Elements and Facilities be Limited to
Only Functions Currently Specified in the NERC Functional Model (Version 5).
NERC’s development of the revised BES definition and exclusion/inclusion criteria and
processes should be limited to functions specified in the NERC Functional Model
(Version 5).
9. NERC is Encouraged to Propose a “Different Solution” That is as Effective as, or
Superior to, the Commission’s Proposed Approach. The Proposed Principles for the
Exclusion of Elements and Facilities from the BES Should Include a Process for
Categorical Exclusion Based on Common Physical Characteristics.
The Commission stated in Order No. 743 regarding its proposed revision of the BES
definition (and presumably the exclusion/inclusion criteria and processes):
… NERC may propose a different solution that is as effective as, or superior to,
the Commission’s proposed approach in addressing the Commission’s technical
and other concerns so as to ensure that all necessary facilities are included within
the scope of the definition. ¶ 16.
In addition, specific to the exclusion of Elements and Facilities from the BES, the Final
Rule did not adopt the exclusion process proposed in the NOPR (i.e., facility-by-facility
review). In the Final Order, FERC directed NERC to develop an exclusion process “with
practical application that is less burdensome than the NOPR proposal.”
FERC has also allowed NERC to consider concerns (mainly industrials’) regarding
“exclusion categories” in developing the exclusion process and criteria. ¶ 120.
ELCON interprets the Commission’s statements to mean that the agency is open to
developing a more efficient compliance process, including processes that minimize
unnecessary regulatory burdens on potential Registered Entities and the administrative
costs of NERC and RE compliance operations. In the spirit of “streamlining” NERC and
the REs’ review of smaller entities, ELCON recommends the addition of a principle on
the exclusion of Elements and Facilities from the BES that encourages a process for
categorical exclusion of entities based on common physical characteristics.

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Thad Ness, American Electric Power
Telephone: 614-716-2053
Email: tkness@aep.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: We appreciate the opportunity to provide advance comments on the BES
definition exemption process. The comments provided above are initial thoughts, and are by
no means an exhaustive itemized list of exemptions. AEP looks forward to contributing
additional input through the standards development process when the SDT provides drafts or
revisions.

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Proposed Definition of Bulk Electric System – Project 2010-17
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March 25, 2011

Amir Hammad, Constellation Power Source Generation, Inc. (CPSG), Et All
CPSG is filing the comments below on behalf of:
Constellation Energy Group, Inc.
Baltimore Gas & Electric Company
Constellation Energy Commodities Group, Inc.
Constellation Energy Control and Dispatch, LLC
Constellation NewEnergy, Inc. and its affiliates
Constellation Energy Nuclear Group, LLC, 17
Telephone: 410-787-5226
Email: amir.hammad@constellation.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: While the Regional Bulk Electric System Coordination Group has done an
admirable job at drafting an initially proposed list of inclusion and exclusion criteria,
Constellation strongly suggests that the continued work on criteria be orchestrated through
the FERC-approved standard development process and not as part of a Rules of Procedure
revision. We view development of the technical criteria for both the BES definition and
exemption process as a single exercise.
The compliance implications and technical nature of such criteria make it imperative that
industry input be considered in a transparent stakeholder process. It is appropriate for NERC
to develop aspects such as the administrative management, the role and interaction of the
regions, an appeal process, etc. However, due to the technical aspects of BES operation, the
drafting team members are best suited to devise criteria for inclusion or exclusion of facilities
to the BES.
To clarify the distinction between the exception process and the exception criteria, the
purpose statement in the concept document should add a fourth bullet to read:
A. Utilize the NERC Standard Development Process to revise the definition of
Bulk Electric System (BES) contained in the NERC Glossary of Terms.
B. Utilize the NERC Standard Development Process to develop exception criteria
to be utilized in the exception process.Develop a single Implementation Plan to
address the application of the revised definition of the BES and the
implementation of the exemption process.
17

On November 6, 2009, EDF, Inc. (“EDF”) and Constellation Energy Group, Inc. completed a transaction
pursuant to which EDF acquired a 49.99 percent ownership interest in CENG. CENG was previously a wholly
owned subsidiary of Constellation Energy Group, Inc.

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C. Utilize the NERC Rules of Procedure to develop and implement an ’exemption
process’ used to identify Elements and Facilities which will be included in or
excluded from the BES.
The revised definition should expressly incorporate exclusions for facilities below 100 kV.
Entities should not have to seek an exemption for facilities below 100 kV or for radial lines.
They should be clearly excluded in the BES definition itself. We encourage the drafting
team to embrace a design concept that seeks to maximize the “brightness” of bright line
criteria. The BES exemption process should contemplate very few exemptions. The TFE
process is an example of a process not to be repeated here.
In addition, Constellation is not convinced that creation of a definition and an exception
process is the best course to respond to the FERC directives. We are concerned that the
current approach of a simple, all inclusive definition coupled with an exception criteria and
process will not draw on the fundamentals underpinning the existing definition and create a
cumbersome and unnecessary exception process.
As an alternative, we propose that the standard drafting team utilize the Compliance Registry
Criteria – Section III (Rules of Procedure Appendix 5B) along with definition threshold
language to develop a more comprehensive definition. Further, we propose that the BES
drafting team incorporate the criteria directly into the revised BES definition, replacing the
term “bulk power system” in each criterion with “greater than 100 kV.” It will make for a
longer definition, but by aligning the facilities requiring registration as those defined as BES,
the definition will more clearly determine the line between BES and non-BES. It is
preferable that non-BES facilities be excluded by the definition language rather than to
define BES broadly and require non-BES facilities go through an exception process. Ideally,
this approach can eliminate the need for an onerous exemption process as well as eliminate
the need for Section III of the Registry Criteria in the Rules of Procedure.
For special case facilities deemed non-BES by the revised definition that may warrant
consideration for inclusion, an “opt-in” evaluation could be conducted.
The rules of procedure process may be used to develop the “opt-in” process that would
replace the proposed exception concept; however, the drafting team, perhaps in collaboration
with regional entities, should develop any opt-in criteria needed for the process. Again, it is
appropriate for NERC to develop aspects such as the administrative management, the role
and interaction of the regions, an appeal process, etc. However, due to the technical aspects
of BES operation, the drafting team members are best suited to devise criteria for non-BES
facilities to warrant inclusion in the BES.
We find that this approach to revising the BES definition would satisfy the FERC directives
in Order 743 by encompassing all facilities necessary for operating an interconnected electric
transmission network into a national level, bright-line definition. This approach will improve
the clarity and consistency of the BES definition for application by Industry and NERC as
well as avoiding creation of a potentially cumbersome exception process.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Shaun Anders, City Water Light and Power
Telephone: 217-321-1323
Email: shaun.anders@cwlp.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: CWLP has chosen to comment on the inclusion/exclusion process as a whole.
The current lack of detailed, firm administrative guidelines as well as an unambiguous
process for resolving disputes between parties involved in the process of adjudicating
inclusions/exclusions is problematic. It is CWLP’s belief that developing the proposed
administrative framework for the process is needed first. Focusing on the data to be
submitted as shown in (1) and (2) above does not address the scope, nature, and criteria
applicable to the review of requests for inclusions/exclusions. Regardless, CWLP feels
strongly that the sole basis for approval or rejection of a request should be technical
justification.
Speaking to the process in general, any inclusion or exclusion should be a specific request for
a specific facility; continent-wide, interconnect-wide, and region-wide applicability for
inclusions/exclusions departs from the intent of FERC Order 743 to establish a definition
without regional variances.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Marc M. Butts, Southern Company
Telephone: 205-257-4839
Email: mmbutts@southernco.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
The evaluation method should be clear, understandable, and technically
based. Sometimes the “process” is called an Exemption Process and other times it is
called “Exception Process”,

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Andrew Z. Pusztai, American Transmission Company
Telephone: 262-506-6913
Email: apusztai@atcllc.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
a. ATC feels strongly that the exemption criteria need to be developed by the SDT.
NERC Staff should focus on the process (identification, notification, appeal and
rights) but the SDT is in the better position to develop the technical basis of the
exemption criteria.
b. The NERC process for exclusion or inclusion must clearly address who is responsible
for submitting an Element or Facility Exception Process. Is it limited to the asset
owner of the Element or Facilities, or is it open to neighboring entities that may want
to initiate a request for exemption or inclusion to the BES?
c. Also, ATC believes the process should allow for multi-year distinctions for
exceptions. In other words, if a Registered Entity gets an Element or Facility
excluded, then that exclusion or inclusion should be allowed for 3 or more years.
Annual certifications and approval are too restrictive.
d. ATC also supports the comments as submitted by EEI REAC on the Draft Concept
Paper on the Definition of BES Project 2010-17

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Al DiCaprio, PJM
Telephone: 610-666-8854
Email: dicrapm@pjm.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: We have difficulties understanding the intent of this Comment Form and the
content in Q1 and Q2, above, which appear to be templates for information to be included in
an exclusion/inclusion request rather than asking for comments on each of the listed items.
1. Is the intent of this Comment Form to obtain:
a. Recommendations of the criteria to be considered in developing deviations from the
default criteria for classifying Elements and Facilities as part of the BES?
b. Assessment of the templates proposed in Q1 and Q2?
2. The concept paper that is posted alongside the SAR and proposed definition is not
referenced in this Comment Form. Is it the drafting team’s intent to solicit comments on
the concept paper?
3. In the concept paper, three exemption criteria are presented. We do not have any issue
with the first and third criteria but are concerned that Criterion #2 is not a criterion. It
states that:
“Elements and Facilities identified through application of the exemption process, consistent
with the criteria, where the exemption process deems that the Element or Facility should be
excluded from the BES (with concurrence from the ERO).”
This criterion appears to reference yet another set of criteria not already included in the set or
the concept paper. In fact, this “referenced” set needs to be clearly stipulated to ensure that
applicants are fully aware of the conditions under which an Element or Facility operated at
100 kV or above can be deemed not necessary to support bulk power system reliability and,
conversely, the conditions for an Element or Facility operated at below 100 kV to be
included. The “templates” presented in Q1 and Q2 of this Comment Form also do not convey
the needed conditions.
We believe it is the clear conditions for exclusion (Elements/Facilities of 100 kV and above)
and inclusion (below 100 kV) that need to be developed and fully vetted. We urge the
drafting team to proceed to developing these criteria expeditiously so as to support the
assessment and approval of the revised definition of BES.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Bud Tracy, Blachly-Lane Electric Cooperative
Telephone: 541.688.8711
Email: tracyb@blachlylane.coop
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
1. We have a number of concerns related to the initial SAR proposal:
a) The primary concern expressed by FERC in Order No. 743 was the discretion the
current definition accords to the RROs to develop their own definition of the BES
without approval by NERC or FERC. See Order No. 743, 133 FERC ¶ 61,150 at P
16 (2010) (FERC believes the “best way to address these concerns is to eliminate the
Regional Entities’ discretion to define ‘bulk electric system’ without ERO or
Commission review“); at 30 (same). Hence, we believe FERC’s concern can be
addressed by simply removing the phrase “As defined by the Regional Reliability
Organization” from the existing definition. The result would be that the RROs could
then develop regionally-appropriate rules based on the uniform definition, which
NERC and FERC could then approve, giving deference to the technical findings of
the RROs and NERC, as the FPA requires. FPA Section 215(d), 16 U.S.C.
§ 825o(d). We urge the standards drafting team to consider the virtues of such a
minimalist approach and then focus on alternative approaches that will achieve
FERC’s aim more effectively and/or at lower cost, and on the exemption process,
which will, unless FERC abandons its insistence on a 100-kV bright-line threshold,
be the most important aspect of the standards development process.
b) The definition proposed in the SAR would incorporate “All Transmission and
Generation Elements and Facilities” that are “necessary to support bulk power
system reliability.” We applaud the effort to properly restrict the definition of BES
using the NERC-defined terms “Transmission,” “Generation,” “Elements” and
“Facilities.” By using these terms, the drafting team recognizes that Congress
excluded from the statutory “Bulk-Power System” definition “facilities used in the
local distribution of electric energy,” FPA Section 215(a)(1), 16 U.S.C. § 825o(a)(1),
and has thereby excluded such facilities from the reach of the mandatory reliability
system. Similarly, by focusing the definition on “Transmission” and “Generation,”
the standards drafting team recognizes that Congress limited the reach of reliability
standards to: (1) “facilities and control systems necessary for operating an
interconnected electric energy transmission network,” and, (2) “electric energy from
generation facilities needed to maintain transmission system reliability.” Id.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

When viewed in the context of the proposed BES definition, however, we are
concerned that incorporating the terms as defined in the NERC Glossary may create
unnecessary confusion and ambiguity. For example, the NERC Glossary defines
“Facility” as “[a] set of electrical equipment that operates as a single Bulk Electric
System Element.” But attempting to define BES by using a term that itself
incorporates “Bulk Electric System” is circular and is likely to create confusion in
applying the revised definition. Similarly, “Generation” is not specifically defined
in the NERC Glossary of Terms, creating potential confusion.
Finally, the NERC Glossary defines “Transmission” in part as “the movement or
transfer of electric energy between points of supply and points at which it is
transformed for delivery to customers.” This creates the potential for an overinclusive definition since “Transmission” could, by this definition, be understood to
encompass only the last transformation of voltage to end-user level voltage in a
system, whereas distribution systems generally include several downward
transformations of voltage between the point of bulk delivery and the end-use
consumer. One could argue that each of the segments between delivery of bulk
power to the local distribution utility and that utility’s step-down transformers is, by
the terms of the definition, merely moving power “between points of supply” and
only the last segment includes the “point at which [power] is transformed for
delivery to customers.” This, of course, would improperly classify a large portion of
most distribution system as “Transmission.”
For these reasons, it may be necessary to define “Generation” and to more precisely
define “Facility” and “Transmission” as part of the standards drafting process.
We note, on the other hand, that “reliable operation” was a term specifically defined
by Congress in FPA Section 215 to include the operation of BES elements “within
equipment and electric system thermal, voltage, and stability limits so that
instability, uncontrolled separation, or cascading failures of such system will not
occur as a result of a sudden disturbance. . . or unanticipated failure of system
elements.” 16 U.S.C. § 825o(a)(4). Congress specifically precluded the mandatory
reliability system from enforcing standards for adequacy of service, which were left
to state and local authorities. 16 U.S.C. § 825o(i)(2). Accordingly, we applaud the
standards drafting team for including in the BES only facilities “necessary to support
bulk power system reliability,” because the use of the italicized term at least
implicitly excludes from the definition facilities that affect only the levels of service
that were explicitly excluded from the mandatory reliability regime by Congress and
do not affect “reliable operation” of the BES as Congress defined it.
c) The proposed SAR definition unnecessarily restricts the exclusion in the existing
definition for radial facilities. The existing definition provides that radial facilities
are “generally not included” in the BES. The proposed new definition would
significantly restrict this exclusion, excluding radial systems from the BES only if
they are excluded through the “BES definition exemption process.” We believe
there is no reason to make radial systems and other elements of the electric system
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

that, because of their limited interaction with the bulk system, have no meaningful
impact on bulk system reliability go through a potentially onerous exemption
process. Rather, such systems should be presumptively excluded from the
definition, as they are now. Further, for the reasons set forth in detail by the WECC
BESDTF, local distribution networks in the West should be subject to a similar
categorical exclusion, subject to inclusion in the BES only upon a demonstration that
the network creates substantial reliability risks for the bulk system. This approach
is consistent with FERC’s direction that “radial facilities, as well as facilities used in
the local distribution of electric energy as provided in Section 215, will continue to
be excluded.” Order No. 743 at P 120.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Jerome Murray, Oregon Public Utility Commission
Telephone: 503-378-6626
Email: Jerry.murray@state.or.us
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
1. The work that has been completed by the WECC Bulk Electric System Definition
Task Force is based on sound engineering principles and appears to be a
comprehensive solution to defining the BES and providing a means for exceptions to
the 100 kV “bright line” criteria. The NERC BES Drafting Team is urged accept the
proposal in whole or include contained principles to guide NERC’s process for
exception.
2. There is serious concern in the Western Interconnection that if a strict 100 kV bright
line is mandated that billions of dollars will be needed to be upgrade 100kV to 200
kV distribution elements to comply with NERC reliability/security standards. There
is a significant potential for unintended consequences. A serious one is that there
could be substantially less monetary resources available for new transmission
investment for high impact BES elements and for relieving congestion. Another is
FERC would arguably be negating the 7 factor test for distribution facilities,
extending FERC jurisdiction over distribution facilities, bringing costs for such
facilities into the FERC tariffs, and reducing PUC state review of such investments.
These could result in substantial cost increases and/or reliability issues for electric
consumers.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

John D. Martinsen , Public Utility District No. 1 of Snohomish County
Telephone: 425-783-8080
Email: jdmartinsen@snopud.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments:
1. We have a number of concerns related to the initial SAR proposal:
a) The primary concern expressed by FERC in Order No. 743 was the discretion the
current definition accords to the RROs to develop their own definition of the BES
without approval by NERC or FERC. See Order No. 743, 133 FERC ¶ 61,150 at
P 16 (2010) (FERC believes the “best way to address these concerns is to
eliminate the Regional Entities’ discretion to define ‘bulk electric system’ without
ERO or Commission review“); at 30 (same). Hence, we believe FERC’s concern
can be addressed by simply removing the phrase “As defined by the Regional
Reliability Organization” from the existing definition. The result would be that
the RROs could then develop regionally-appropriate rules based on the uniform
definition, which NERC and FERC could then approve, giving deference to the
technical findings of the RROs and NERC, as the FPA requires. FPA Section
215(d), 16 U.S.C. § 824o(d). We urge the standards drafting team to consider the
virtues of such a minimalist approach and then focus on alternative approaches
that will achieve FERC’s aim more effectively and/or at lower cost, and on the
exemption process, which will, unless FERC abandons its insistence on a 100-kV
bright-line threshold, be the most important aspect of the standards development
process.
b) The definition proposed in the SAR would incorporate “All Transmission and
Generation Elements and Facilities” that are “necessary to support bulk power
system reliability.” We applaud the effort to properly restrict the definition of
BES using the NERC-defined terms “Transmission,” “Generation,” “Elements”
and “Facilities.” By using these terms, the drafting team recognizes that Congress
excluded from the statutory “Bulk-Power System” definition “facilities used in
the local distribution of electric energy,” FPA Section 215(a)(1), 16 U.S.C.
§ 824o(a)(1), and has thereby excluded such facilities from the reach of the
mandatory reliability system. Similarly, by focusing the definition on
“Transmission” and “Generation,” the standards drafting team recognizes that
Congress limited the reach of reliability standards to: (1) “facilities and control
systems necessary for operating an interconnected electric energy transmission
network,” and, (2) “electric energy from generation facilities needed to maintain
transmission system reliability.” Id.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

When viewed in the context of the proposed BES definition, however, we are
concerned that incorporating the terms as defined in the NERC Glossary may
create unnecessary confusion and ambiguity. For example, the NERC Glossary
defines “Facility” as “[a] set of electrical equipment that operates as a single Bulk
Electric System Element.” But attempting to define BES by using a term that
itself incorporates “Bulk Electric System” is circular and is likely to create
confusion in applying the revised definition. Similarly, “Generation” is not
specifically defined in the NERC Glossary of Terms, creating potential confusion.
Finally, the NERC Glossary defines “Transmission” in part as “the movement
or transfer of electric energy between points of supply and points at which it is
transformed for delivery to customers.” This creates the potential for an overinclusive definition since “Transmission” could, by this definition, be understood
to encompass only the last transformation of voltage to end-user level voltage in a
system, whereas distribution systems generally include several downward
transformations of voltage between the point of bulk delivery and the end-use
consumer. One could argue that each of the segments between delivery of bulk
power to the local distribution utility and that utility’s step-down transformers is,
by the terms of the definition, merely moving power “between points of supply”
and only the last segment includes the “point at which [power] is transformed for
delivery to customers.” This, of course, would improperly classify a large portion
of most distribution system as “Transmission.”
For these reasons, it may be necessary to define “Generation” and to more
precisely define “Facility” and “Transmission” as part of the standards drafting
process.
We note, on the other hand, that “reliable operation” was a term specifically
defined by Congress in FPA Section 215 to include the operation of BES
elements “within equipment and electric system thermal, voltage, and stability
limits so that instability, uncontrolled separation, or cascading failures of such
system will not occur as a result of a sudden disturbance. . . or unanticipated
failure of system elements.” 16 U.S.C. § 824o(a)(4). Congress specifically
precluded the mandatory reliability system from enforcing standards for adequacy
of service, which were left to state and local authorities. 16 U.S.C. § 824o(i)(2).
Accordingly, we applaud the standards drafting team for including in the BES
only facilities “necessary to support bulk power system reliability,” because the
use of the italicized term at least implicitly excludes from the definition facilities
that affect only the levels of service that were explicitly excluded from the
mandatory reliability regime by Congress and do not affect “reliable operation” of
the BES as Congress defined it.
c) The proposed SAR definition unnecessarily restricts the exclusion in the existing
definition for radial facilities. The existing definition provides that radial
facilities are “generally not included” in the BES. The proposed new definition
would significantly restrict this exclusion, excluding radial systems from the BES
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

only if they are excluded through the “BES definition exemption process.” We
believe there is no reason to make radial systems and other elements of the
electric system that, because of their limited interaction with the bulk system,
have no meaningful impact on bulk system reliability, go through a potentially
onerous exemption process. Rather, such systems should be presumptively
excluded from the definition, as they are now. Further, for the reasons set forth in
detail by the WECC BESDTF, local distribution networks in the West should be
subject to a similar categorical exclusion, subject to inclusion in the BES only
upon a demonstration that the network creates substantial reliability risks for the
bulk system. This approach is consistent with FERC’s direction that “radial
facilities, as well as facilities used in the local distribution of electric energy as
provided in Section 215, will continue to be excluded.” Order No. 743 at P 120.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Steve Alexanderson P.E., Central Lincoln
Telephone: 541-574-2064
Email: salexanderson@cencoast.com
3. Please provide any other information that you feel would be helpful to the group working to
develop a BES Definition Exception Process.
Comments: Our understanding of the FERC Order was that the threshold would be 100 kV
“except for defined radial facilities” and that they also ordered NERC to adopt an “exemption
process”. The question confuses the two distinct parts by speaking of an “exception process”
never ordered by FERC. We urge the SDT to clearly define “radial” in such a way that no
external “process” is needed, and that radial facilities can easily be determined by each registered
entity by inspection. And if they have facilities that don’t meet the radial definition, they may
still be put through a formal exemption process and be exempted if they are found not to
contribute to reliable operation of the BPS.
The WECC Bulk Electric System Definition Task Force has done extensive work on this topic.
Please consider their current work when drafting the BES definition and exemption process.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Brian J. Murphy, NextEra Energy, Inc.
Telephone: (305) 442‐5132
Email: Brian.J.Murphy@fpl.com
3. Please provide any other information that you feel would be helpful to the group working
to develop a BES Definition Exception Process.
Comments: Based on the information posted by the North American Electric Reliability
Corporation (NERC) on its plans to address Order No. 743 of the Federal Energy Regulatory
Commission (FERC), NextEra Energy, Inc.1 (NextEra) believes that NERC (and associated
drafting teams) should slightly modify its direction to more closely align with FERC’s
proposed framework. In Order No. 743, at paragraph 30, FERC stated that:
The Commission believes the best way to address these concerns is to eliminate the
regional discretion in the ERO’s current definition, maintain the bright‐line threshold
that includes all facilities operated at or above 100 kV except defined radial facilities,
and establish an exemption process and criteria for excluding facilities the ERO
determines are not necessary for operating the interconnected transmission network.
It is important to note that Commission is not proposing to change the threshold value
already contained in the definition, but rather seeks to eliminate the ambiguity created
by the current characterization of that threshold as a general guideline.
1 NextEra registered entities, which include NextEra Energy Resources, Inc. and
Florida Power & Light Company, operate in the eight NERC regions. Official
Comment form for BES Definition Exception Process FERC also provided NERC
with the opportunity to propose an alternative approach. NextEra believes, however,
that FERC’s proposed framework is appropriately designed to enhance the definition
of the Bulk Electric System (BES) in the NERC glossary, and to separately develop a
process to apply for and receive, as appropriate, an exemption from the BES
definition. Although it appears that NERC and the drafting teams may also be
inclined to proceed as suggested by FERC, there are indications in the questionnaire
and BES concept paper that there may be some thought to deviating from FERC’s
proposal.
A review of the information posted by NERC seems to indicate NERC’s intention to have a
drafting team develop a revised BES definition via the standards development process (i.e.,
Appendix 3A of the NERC Rules of Procedure). It also seems that NERC is interested in
assigning a “working group” to separately develop an exemption process that would be
implemented as a new process in the NERC Rules of Procedure. NextEra agrees with this
approach.
NextEra’s concerns stem from some of the words in the proposed BES definition, the BES
concept paper and the questions asked, which seem to suggest an unnecessarily overlapping
definition and exemption process, and a movement toward an exemption process based on
categories rather than criteria. Thus, to address these concerns NextEra proposes the
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

following enhancements to more clearly separate the BES definition and exemption process,
and align each more closely with Order No. 743.
As for the BES definition, NextEra encourages the drafting team to solely focus its efforts on
the definition. The currently posed revised BES definition reads as follows:
Bulk Electric System: All Transmission and Generation Elements and Facilities
operated at voltages of 100 kV or higher necessary to support bulk power system
reliability. Elements and Facilities operated at voltages of 100kV or higher, including
Radial Transmission systems, may be excluded and Elements and Facilities operated
at voltages less than 100kV may be included if approved through the BES definition
exemption process.
NextEra maintains that this is not the correct starting point, nor consistent with Order No.
743 or the other material posted by NERC, that suggests a more definitive separation of the
BES definition from the exemption process. Thus, NextEra proposes that the definition be
revised to read as follows:
Bulk Electric System: All Transmission and Generation Elements and Facilities
operated at voltages of 100 kV or higher, unless a Transmission or Generation
Element or Facility has been exempted pursuant to the exemption process set forth in
the NERC Rules of Procedure. Official Comment form for BES Definition
Exception Process This proposed BES definition more clearly and cleanly separates
the BES definition from the exemption process. It also does not add unnecessary
qualifiers or verbiage that may result in confusion.
NextEra is also concerned that the working group assigned to the exemption process may
initially be more focused on developing categories, instead of an exemption process and
associated criteria. Given the unique circumstances of the interconnected BES, including
system topology, NextEra does not believe that it would be a productive exercise for the
exemption working group to focus on types, groups or categories of equipment; instead, its
efforts should focus on developing specific objective criteria to judge the reasonableness of a
request or application for an exemption. This approach also seems more in line with FERC’s
statement in Order No. 743 at paragraph 115:
NERC should develop an exemption process that includes clear, objective,
transparent, and uniformly applicable criteria for exemption of facilities that are not
necessary for operating the grid. The ERO also should determine any related changes
to its Rules of Procedures that may be required to implement the exemption process,
and file the proposed exemption process and rule changes with the Commission.
The challenges of developing an exemption process also include ensuring than any applicant
is afforded due process and balanced decision‐making, as required by section 215 of the
Federal Power Act. Thus, the exemption process must address legal, regulatory and technical
issues.
Accordingly, NextEra requests that NERC assemble a working group (perhaps via the
Standards Committee) to develop the exemption process that is comprised of stakeholders
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

with legal, regulatory and technical experience. Without this balance of disciplines, NextEra
is concerned that a technical‐heavy working group will attempt to develop a “fix,” instead of
a process whereby applicants may request an exemption, and have that exemption judged by
specific criteria and pursuant to a process that affords due process and balanced
decision‐making.
It is not clear whether an exemption working group has already been assembled. If it has,
NextEra requests that NERC consider restructuring of the group consistent with NextEra’s
proposal.
In summary, NextEra requests that the BES definition drafting team adopt NextEra’s
proposed definition of BES. NextEra also requests that NERC assemble a cross‐functional
working group to develop an exemption process based on specific criteria (rather than
categories), and a process that affords applicants due process and balanced decision‐making.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

Phil Tatro, NERC Staff
NERC Staff Comments on Bulk Electric System (BES) Concept Document
NERC staff appreciates the opportunity to provide comments on the concept document
drafted by the Regional Bulk Electric System Definition Coordination Group
(Coordination Group). We believe the concept document provides a good starting point
from which discussion of the BES definition (included/excluded Facilities) and
exemption process should begin.
In defining the boundaries of the BES, we believe there are some key principles that must be
in place:
•
•
•

The BES must be contiguous. For example, BES generation’s connections and paths to
Transmission need to be part of the BES.
The BES definition must be continent-wide, with a uniform process for considering regional
inclusions or exclusions.
The BES definition cannot override any criteria already explicitly established in a standard. In
other words, if a standard applies to specifically identified Elements or Facilities, then the BES
definition or a regional exclusion cannot be used to modify the Elements or Facilities to which the
standard is applicable (e.g., FAC-003-1, PRC-023-1).

We started with the Facilities identified in the Statement of Compliance Registry Criteria
(Revision 5.0) 18 since these Facilities have been vetted by the industry. We used this
starting point to develop a framework that we believe can be helpful as the industry
continues to work on defining the BES. Our framework has the BES defined in three
parts:
1. BES Generation
2. BES Transmission (excluding Facilities used for local distribution, such as certain radial
transmission Facilities and certain transformers)
3. BES Protection and Controls

These three BES components are described in Sections 1, 2, and 3. This framework could
serve as a continent-wide “base definition” to which additional inclusion and exclusion
of Elements or Facilities could be applied at the regional level as described in Section 4.
As Section 5 discusses, these comments do not address registration or functional model
impacts resulting from the BES definition.
The details of what we think are appropriate for inclusion or exclusion in each component of
the base definition is contained in each of three sections below. The rationale is
described in italicized font 19, as well any changes from current NERC practice. For
convenience, the definitions from the Glossary of Terms Used in NERC Reliability
Standards used herein are in the table below.
18

http://www.nerc.com/files/Statement_Compliance_Registry_Criteria-V5-0.pdf
If an Element or Facility is included in the Statement of Compliance Registry Criteria (Revision 5.0), we have not
provided a rationale.

19

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011
Term

Glossary Definition

Blackstart Resource

A generating unit(s) and its associated set of equipment which has the ability to
be started without support from the System or is designed to remain energized
without connection to the remainder of the System, with the ability to energize a
bus, meeting the Transmission Operator’s restoration plan needs for real and
reactive power capability, frequency and voltage control, and that has been
included in the Transmission Operator’s restoration plan.

Cranking Path

A portion of the electric system that can be isolated and then energized to
deliver electric power from a generation source to enable the startup of one or
more other generating units.

Demand-Side Management

The term for all activities or programs undertaken by [a] Load-Serving Entity or
its customers to influence the amount or timing of electricity they use.

Element

Any electrical device with terminals that may be connected to other electrical
devices such as a generator, transformer, circuit breaker, bus section, or
transmission line. An element may be comprised of one or more components

Facility

A set of electrical equipment that operates as a single Bulk Electric System
Element (e.g., a line, a generator, a shunt compensator, transformer, etc.)

System

A combination of generation, transmission, and distribution components.

Transmission

An interconnected group of lines and associated equipment for the movement or
transfer of electric energy between points of supply and points at which it is
transformed for delivery to customers or is delivered to other electric systems.

Transmission Line

A system of structures, wires, insulators and associated hardware that carry
electric energy from one point to another in an electric power system. Lines are
operated at relatively high voltages varying from 69 kV up to 765 kV, and are
capable of transmitting large quantities of electricity over long distances.

Protection System

Protective relays, associated communication systems, voltage and current
sensing devices, station batteries and DC control circuitry.

Right-of-Way

A corridor of land on which electric lines may be located. The Transmission
Owner may own the land in fee, own an easement, or have certain franchise,
prescription, or license rights to construct and maintain lines.

Prior to any revised BES definition becoming effective, its impact on existing standards
needs to be examined. In other words, if an existing standard was written based on the
existing definition (which included the phrase “as defined by the Regional Reliability
Organization”), then moving to a continent-wide bright-line definition may significantly
alter the intent or implementation of the standard.
1. BES GENERATION

BES Generation should include:
a. Individual generating units greater than 20 MVA (gross nameplate rating). All units greater
than 20 MVA should be included, regardless of the interconnection voltage, because the impact
on reliability of the BES associated with tripping similarly-sized units that are interconnected at
different voltages is nearly identical. This is a change from current practice. We also believe
that “generating unit” should be defined as “A device, whether spinning or static and whether
connected synchronously, asynchronously, or electronically coupled, that produces electrical
energy from another source of energy, either directly from the other energy source (such as a
combustion turbine from natural gas or light distillate oil, a wind turbine from wind, or a solar

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

b.

c.
d.

e.

f.

array from the sun) or through a storage medium (such as pumped storage hydro, a flywheel,
compressed air, or battery).”
Generating plants with aggregate generation capacity greater than 75 MVA (gross nameplate
rating). All plants greater than 75 MVA should be included, regardless of the interconnection
voltage, because the impact on reliability of the BES associated with tripping similarly-sized
plants that are interconnected at different voltages is nearly identical. We also believe that
“generating plant” should be defined as “one or more generating units that are under the
common local operational control of a Generator Operator.”
Blackstart Resources. Blackstart Resources are essential for the restoration of de-energized
portions of a System.
Any resource (supply-side or Demand-Side Management) relied on to provide Contingency
Reserves to its Balancing Authority. Contingency Reserves are required by BAL-002-0 –
Disturbance Control Performance. Resources that may provide such reserves are essential to
ensure control of the BES.
Any resource relied on in the determination of a System Operating Limit (SOL) or an
Interconnection Reliability Operating Limit (IROL). FAC-011-2 - System Operating Limits
Methodology for the Operation Horizon requires that Reliability Coordinators have a
documented SOL Methodology, including a description of how to identify the subset of SOLs that
qualify as IROLs. Resources included in the calculation of an SOL or an IROL should therefore
be considered part of the BES since they are used to determine key BES limits that ensure reliable
operation.
Any resource that is monitored by Reliability Coordinators (RCs). IRO-003-2 – Reliability
Coordination – Wide-Area View requires RCs to monitor “all Bulk Electric System facilities,
which may include sub-transmission information, within its Reliability Coordinator Area and
adjacent Reliability Coordinator Areas, as necessary to ensure that, at any time, regardless of
prior planned or unplanned events, the Reliability Coordinator is able to determine any potential
System Operating Limit and Interconnection Reliability Operating Limit violations within its
Reliability Coordinator Area.” Any resources monitored by an RC are being monitored to
ensure the reliable operation of the BES.

g. Any resource fully or partially relied on to fulfill a capacity obligation. Although most capacity
resources are likely captured by the other categories above, this additional category ensures that
all resources that have capacity obligations are part of the BES.
h. Elements or Facilities required for the control or operation of resources above, regardless of
voltage, and including, but not limited to, various generator transformers (e.g., step-up, auxiliary,
start-up), generator controls (including exciters and power system stabilizers), prime mover
controls, and generating unit control rooms. A generating unit cannot operate reliably without
properly functioning controls or a power supply to its auxiliary loads.

We note that the current Statement of Compliance Registry Criteria (Revision 5.0) has
language (p. 9) that excludes customer-owned/operated generation from registration if it
is behind the customer’s meter, used to serve the customer’s load, has appropriate backup services to cover service to the load when the customer’s generation is outaged, and
the “net capacity provided to the bulk power system does not exceed the criteria above”
(i.e., 20 MVA for an individual generating unit and 75 MVA for a generating plant.)
This language does address generation adequacy for service to the customer’s load;
however, it does not address the immediate-term impact on reliability (e.g., the stability
of the system immediately following the loss of generation). As this exemption is
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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

currently written, a 300 MW behind-the meter generator serving 285 MW customer
load could be excluded from the BES. Therefore, we believe that behind-the-meter
generation exclusions should not be part of the base BES definition. However, we are
not opposed to a reliability-based exemption process that, on a case-by-case basis,
would consider exemptions of specific behind-the-meter generation that would
otherwise be part of the BES.
2. BES TRANSMISSION

BES Transmission is made up of both alternating current (ac) transmission Facilities and
direct current (dc) transmission Facilities. Although the Statement of Compliance
Registry Criteria (Revision 5.0) does not distinguish between ac and dc, we believe that
this distinction is intended, and our framework uses it for clarity.
2.1 AC Transmission Facilities

Ac transmission Facilities should include:
a. Transmission, Transmission Lines (including their associated Right-of-Way), and substation
Facilities nominally operated at 100 kV or higher as measured phase-to-phase for a three-phase ac
circuit, with the exception that radial facilities meeting the criteria described in section 2.1.1
(“Excluded Radial Transmission Facilities) are not included. Radial transmission facilities that
do not meet the criteria described in section 2.1.1 (e.g., BES interconnection Facilities) are
included. We believe that the attributes of excluded radial Facilities make them Facilities that
are used in the local distribution of energy. Their exclusion conforms to the Section 215
definition of Bulk-Power System which states that it “does not include facilities used in the local
distribution of electric energy.”
b. Transformers, including autotransformers, variable frequency transformers, and phase-shifting
transformers, with a high-side voltage 100 kV or higher, provided that transformers used in the
local distribution of electric energy are excluded. The exclusion of transformers used for the
local distribution of energy conforms to the Section 215 definition of Bulk-Power System which
states that it “does not include facilities used in the local distribution of electric energy.”
c. Transmission, Transmission Lines (including their associated Right-of-Way), substation
Facilities, and transformers, not covered by a. or b. above, that form the principal transmission
path 20 between BES Generation and BES ac transmission Facilities, including the Cranking Path
for Blackstart Resources. Per the “contiguous” principle described above, the principal
transmission path of BES Generation that is not connected to transmission Facilities that are 100
kV or higher is part of the BES.
d. Transmission, Transmission Lines, and substation Facilities included in the determination of an
Interconnection Reliability Operating Limit or a System Operating Limit. See 1.e above.
e. Transmission, Transmission Lines, and substation Facilities monitored by Reliability
Coordinators. See 1.f above.
f. Elements or Facilities used in control or operation of BES ac transmission Facilities listed above,
regardless of voltage and including, but not limited to, circuit breakers, in-line switches, fuses,
shunt and series compensation (capacitors and reactors), power electronic control devices (e.g.,
static var compensators (SVCs), static synchronous compensators (STATCOMs)), wave traps,
and current and potential transformers. Ac transmission Facilities cannot operate reliably
without properly functioning controls.
20

The term “principal transmission path” would need to be defined.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

2.1.1 Excluded Radial Transmission Facilities

We believe that it is important to set some guidelines for the exclusion of radial transmission
facilities from the BES. As such, any ac transmission Facility composed of Transmission
Line(s), substation Facilities, and transformers that is connected to BES ac Transmission
Facilities at only one point by automatic interruption devices (e.g., circuit breaker or fuse), and
that meets the following criteria, should be considered an “excluded radial transmission
Facility.”
a. Is not capable of being switched so as to be simultaneously connected to BES ac transmission
Facilities at a second point. This criterion prevents the excluded Facility from carrying loop flow.
b. Has no connected BES Generation. If the transmission Facility has any BES generation
connected to it, the transmission Facility would be included in the BES per 2.1.c. above.
c. Connected aggregate non-BES generation, unreduced for any load, does not exceed 75 MVA.
The addition of “aggregate non-BES generation, unreduced for load, exceeding 75 MVA”
captures generation that may not be captured by 1.b. above if it is distributed and not at a single
generating plant. Electrically, tripping distributed generation on a radial facility has virtually an
identical impact to the BES as tripping the same amount of generation aggregated at a single
generating plant.
d. Will not cause the interruption of power flow on BES ac transmission Facilities due to a fault
with Normal Clearing on any of the subject transmission Facilities described above. If tripping a
radial Facility impacts BES ac transmission Facilities, there is a direct link between BES
reliability and the reliability of the radial Facility, and hence the radial Facility cannot be
excluded.
The automatic interruption device(s) and (i) Protection Systems and (ii) communications and control
systems associated with the excluded radial transmission Facility should be included as part of the BES,
and its owner and operator should be on the NERC Compliance Registry.
The current registry criteria states “Radial transmission facilities serving only load with one
transmission source are generally not included in this definition [of BES].” The language we have
provided above more clearly defines what radial means, but does not specify that an excluded radial
Transmission Facility only serves load because if a radial Facility met all the criteria above and only
served load, it would be excluded. Our proposal does permit some non-BES generation (up to 75 MVA)
to be considered as part of an excluded radial facility. We believe this is a reasonable upper limit and
would allow some self-generation by end-use customers who are connected to the grid to be excluded
from the BES. The registration criteria also includes radial Facilities that are 200 kV or greater that
are explicitly covered by the vegetation management standard. We believe the 200 kV or greater
inclusion in FAC-003-1 – Transmission Vegetation Management Program is not necessary for the
reliable operation of the BES since “radial” has been narrowly defined above. For example, our radial
criteria would not exclude as “radial” a hard tap 21 serving load that is part of a three-terminal line,
while the present radial exclusion language could include it because the load on the hard tap could be
considered as having “one transmission source.”
2.2 DC Transmission Facilities
Dc transmission Facilities should include:
a. Transmission, Transmission Lines, and substation Facilities operated at 100 kV dc or higher as
measured pole-to-ground for a single dc circuit (i.e., a single pole).
21

A “hard tap” has no automatic interruption devices at the tap.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

b. Equipment that connects ac Transmission Lines and substation Facilities to dc Transmission
Lines and substation Facilities, which are operated at 100 kV (ac or dc) and above (e.g., ac/dc
converter terminals).
c. Equipment, regardless of its ac or dc voltage level, that connects normally asynchronous ac
Transmission, Transmission Lines, or substation Facilities operated at 100 kV or higher (e.g.,
ac/dc back-to-back converters).
d. Transmission, Transmission Lines (including their associated Right-of-Way), and substation
Facilities not covered above, that interconnect BES Generation to BES ac transmission Facilities,
including the Cranking Path for Blackstart Resources. See 2.1.c above.
e. Transmission, Transmission Lines, and substation Facilities included in the determination of an
Interconnection Reliability Operating Limit or a System Operating Limit. See 2.1.d above.
f. Transmission, Transmission Lines, and substation Facilities monitored by Reliability
Coordinators. See 2.1.e above.
g. Elements or Facilities used in the control or operation of the BES dc transmission Facilities listed
above, regardless of voltage. See 2.1.f. above.
3. BES PROTECTION AND CONTROLS

We believe that BES Protection and Controls should not only include all Protection Systems
and control and communication systems that are included in Elements or Facilities for
the control and operation of BES Transmission or BES Generation, but also any
Protection Systems, controls and communication systems which are used to reliably
operate the BES, regardless of voltage. BES Protection and Controls would include, but
are not limited to, energy management systems, supervisory control and data acquisition
systems, Protection Systems, Special Protection Systems (a.k.a., Remedial Action
Schemes), underfrequency load shedding programs, undervoltage load shedding
programs, Demand-Side Management programs using control and/or communication
systems, and Protection Systems and control and communication systems and facilities
operated by or relied on by Balancing Authorities, Transmission Operators, Reliability
Coordinators, or Generation Operators. Protection and control of the BES is paramount
for the reliable operation of the BES. Each of the systems, programs, or facilities
delineated above is used to ensure reliability. To be sure that no protection and control
systems used for reliability were inadvertently excluded, we added language that this
third part of the BES definition “should not only include all Protection Systems and
control and communication systems that are included in Elements or Facilities for the
control and operation of BES Transmission or BES Generation, but also any Protection
Systems, controls and communication systems which are used to reliably operate the
BES.” Any attempts to itemize such systems into an exhaustive list would inevitably
leave a key one out.
4. ADDITIONAL REGIONAL INCLUSIONS AND EXCLUSIONS

Facilities not discussed above could be included or excluded by Regional Entities, depending
on whether they are used for the reliable operation of the BES. Such inclusions and
exclusions would be based on a process included in a future revision to NERC’s Rules
of Procedure. Such revision would be subject to both NERC and FERC approval.

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Proposed Definition of Bulk Electric System – Project 2010-17
Summary Comment Report – Question 3
March 25, 2011

a. Regional exclusions should not exclude Elements or Facilities covered by a standard. Such
exclusions would degrade the level of reliability provided by the standard.
b. FERC Order 672 22 addressed criteria for regional differences in Paragraph 291:

As a general matter, we will accept the following two types of regional differences,
provided they are otherwise just, reasonable, not unduly discriminatory or
preferential, and in the public interest, as required under the statute: (1) a
regional difference that is more stringent than the continent-wide Reliability
Standard, including a regional difference that addresses matters that the
continent-wide Reliability Standard does not; and (2) a regional Reliability
Standard that is necessitated by a physical difference in the Bulk-Power
System.
We agree that these criteria should be the starting point for additional regional
inclusions or exclusions.
c. Facilities that are used for the reliable operation of the BES in a particular region and which are
not captured in the base definition should be included as part of the BES by that region.
d. Facilities should only be considered for exclusion by a region if they are not used for the reliable
operation of the BES, provided that such facilities are incapable of being tapped onto or directly
connected to the BES.
e. If excluded Elements or Facilities are to be connected to the BES, they should have automatic
interruption devices (e.g., circuit breakers or fuses) connecting them to the BES at their point of
connection. Furthermore, this device and (i) Protection Systems and (ii) communications and
control systems associated with the excluded Element or Facility should be included as part of the
BES, and its owner and operator should be on the NERC Compliance Registry.
5. REGISTRATION AND FUNCTIONAL MODEL IMPACTS

This proposed BES framework would bring conforming changes to NERC’s compliance
registry criteria; however, this document has not attempted to define those changes. For
example, a Load-Serving Entity served by a hard radial tap that it owns (as part of a
three-terminal line) would be registered as a Transmission Owner since the hard tap is
not excluded from the BES. Likewise, an owner of a 50 MW generating unit
interconnected at 69 kV would be registered as a Generation Owner. Once the BES
definition is settled, changes in the compliance registry criteria would logically follow.
Functional model changes may also be necessitated by a new BES definition. For example,
in the BES Generation section, we have included Demand-Side Management resources,
and no functional model entity is currently responsible for such resources within the
functional model. Again, functional model changes would need to logically follow a
new BES definition.

22

http://www.nerc.com/files/final_rule_reliability_Order_672.pdf

Page 55 of 55

Standard Authorization Request Form
Title of Proposed Standard: NERC Glossary of Terms: Revision of the Bulk Electric System
definition.
Request Date:

December 6, 2010

SC Posting Authorization Date:

December 8, 2010

Revised: March 18, 2011
Date SC Accepted SAR as Final:

SAR Type (Check a box for each one
that applies.)

SAR Requester Information
Name: Regional Bulk Electric System Definition
Coordination Group

New Standard

Primary Contact: Peter Heidrich (Manager of
Reliability Standards, FRCC)

Revision to existing Standard

Regional Participation: FRCC, NPCC, RFC, WECC
Telephone: (813) 207-7994

Withdrawal of existing Standard

Fax: (813) 289-5646
E-mail: pheidrich@frcc.com

Urgent Action

Purpose (Describe what the standard action will achieve in support of bulk power system
reliability.)

Revise the definition of Bulk Electric System (BES), including specific inclusions and exclusions, to
address the Federal Energy Regulatory Commission’s (FERC) concerns as identified in FERC Order 693
issued on March 16, 2007 and directives in FERC Order 743 issued on November 18, 2010. The
definition encompasses all Elements necessary for the reliable operation and planning of the
interconnected transmission network. Identify what evidence will be needed to support a request for
an exception to the new definition of BES.
Industry Need (Provide a justification for the development or revision of the standard,
including an assessment of the reliability and market interface impacts of implementing or
not implementing the standard action.)

This project supports the ERO’s obligation to respond to the Commission’s directives and
recommendations relative to the definition of Bulk Electric System identified in FERC Order 743.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

Standards Authorization Request Form

Revise the definition of Bulk Electric System (BES) contained in the NERC Glossary of Terms to improve
clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between
BES and non-BES Elements. Develop specific inclusions and exclusions to the core definition. Identify
what evidence will be needed to support a request for an exception to the new definition of BES.
Detailed Description (Provide a description of the proposed project with sufficient details
for the standard drafting team to execute the SAR.)

Revise the definition of Bulk Electric System (BES) to identify specific inclusions and exclusions to the
core definition, to address the Federal Energy Regulatory Commission’s (FERC) concerns as identified in
FERC Order 693 issued on March 16, 2007 and directives in FERC Order 743 issued on November 18,
2010. The definition encompasses all Elements necessary for the reliable operation and planning of the
interconnected transmission network.
Existing NERC Glossary of Terms Definition of Bulk Electric System:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated
equipment, generally operated at voltages of 100 kV or higher. Radial transmission
facilities serving only load with one transmission source are generally not included in this
definition.
The authors are proposing a revised definition of the term BES to provide for improved clarity, to reduce
ambiguity, and to establish a universal “bright-line” for distinguishing between BES and non-BES
Elements.
This proposed definition provides consistency across the nation’s reliability regions by establishing a
definition that clearly describes what constitutes BES and non-BES Elements. The BES definition
references an exception process (which may include regional differences as defined by FERC Order 672)
that can be used to:
•
•
•

Identify radial Transmission that is excluded from the BES,
Identify Elements operated at voltages of 100kV or higher that may be excluded from the BES;
and
Identify Elements operated at voltages less than 100kV that may be included in the BES.
The proposed continent-wide definition of Bulk Electric System that the Project 2010-17
SDT will start with is:
Bulk Electric System: All Transmission and Generation Elements and Facilities operated
at voltages of 100 kV or higher necessary to support bulk power system reliability.
Elements and Facilities operated at voltages of 100kV or higher, including Radial
Transmission systems, may be excluded and Elements and Facilities operated at voltages
less than 100kV may be included if approved through the BES definition exemption
process.

The development, approval, and application of the BES definition exception process (including periodic
review) will be governed by revisions to the NERC Rules of Procedure accomplished by another team in
close coordination with the revision of the BES definition.
The Standard Drafting Team will work closely with the Rules of Procedure team developing the BES
SAR–2

Standards Authorization Request Form

definition exception process to develop a single coordinated implementation plan. The BES Definition
team will solicit stakeholder input in identifying the evidence an entity will need when submitting a
request for an exception to the definition of BES. While the determination of what evidence will be
needed to support a request for a BES Definition Exception will be developed using NERC’s standard
development process, no decision has been made on “where” the final product will reside – in the
definition of BES or as an attachment (e.g., a procedure identifying what evidence to produce when
applying for a BES exception) to the new BES Exception Process in the Rules of Procedure.

SAR–3

Standards Authorization Request Form

Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Assurer

Monitors and evaluates the activities related to planning and
operations, and coordinates activities of Responsible Entities to
secure the reliability of the bulk power system within a Reliability
Assurer Area and adjacent areas.

Reliability
Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing
Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.

Interchange
Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.

Planning
Coordinator

Assesses the longer-term reliability of its Planning Coordinator
Area.

Resource
Planner

Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.

Transmission
Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.

Transmission
Planner

Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.

Transmission
Service
Provider

Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).

Distribution
Provider

Delivers electrical energy to the End-use customer.

Generator
Owner

Owns and maintains generation facilities.

Generator
Operator

Operates generation unit(s) to provide real and reactive power.

PurchasingSelling Entity

Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.

LoadServing
Entity

Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.

SAR–4

Standards Authorization Request Form

Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes

SAR–5

Standards Authorization Request Form

Related Standards
Standard No.

Explanation

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

FRCC
MRO
NPCC
SERC
TRE
RFC
SPP
WECC

SAR–6

Standard Authorization Request Form
Title of Proposed Standard: NERC Glossary of Terms: Revision of the Bulk Electric System
definition.
Request Date:

December 6, 2010

SC Approval Posting Authorization Date:

December 8, 2010

Revised: March 18, 2011
Date SC Accepted SAR as Final:

SAR Type (Check a box for each one
that applies.)

SAR Requester Information
Name: Regional Bulk Electric System Definition
Coordination Group

New Standard

Primary Contact: Peter Heidrich (Manager of
Reliability Standards, FRCC)

Revision to existing Standard

Regional Participation: FRCC, NPCC, RFC, WECC
Telephone: (813) 207-7994

Withdrawal of existing Standard

Fax: (813) 289-5646
E-mail: pheidrich@frcc.com

Urgent Action

Purpose (Describe what the standard action will achieve in support of bulk power system
reliability.)

Revise the definition of Bulk Electric System (BES), including specific inclusions and exclusions, to
address the Federal Energy Regulatory Commission’s (FERC) concerns as identified in FERC Order 693
issued on March 16, 2007 and directives in FERC Order 743 issued on November 18, 2010. (Order 743)
so that tThe definition encompasses all Elements and Facilities necessary for the reliable operation and
planning of the interconnected bulk power s transmissionystem network. Identify what evidence will be
needed to support a request for an exception to the new definition of BES.
Industry Need (Provide a justification for the development or revision of the standard,
including an assessment of the reliability and market interface impacts of implementing or
not implementing the standard action.)

This project supports the ERO’s obligation to respond to the Commission’s directives and
recommendations relative to the definition of Bulk Electric System identified in FERC Order No. 743.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

Standards Authorization Request Form

Revise the definition of Bulk Electric System (BES) contained in the NERC Glossary of Terms to improve
clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between
BES and non-BES Elements and Facilities. Develop specific inclusions and exclusions to the core
definition. Identify what evidence will be needed to support a request for an exception to the new
definition of BES.
Detailed Description (Provide a description of the proposed project with sufficient details
for the standard drafting team to execute the SAR.)

Revise the definition of Bulk Electric System (BES) and to developidentify specific inclusions and
exclusions to the core definition, to address the Federal Energy Regulatory Commission’s (FERC)
concerns as identified in FERC Order 693 issued on March 16, 2007 and directives in FERC Order 743
issued on November 18, 2010. (Order 743) so that tThe definition encompasses all Elements and
Facilities necessary for the reliable operation and planning of the interconnected Bulk Power
Systemtransmission network.
Existing NERC Glossary of Terms Definition of Bulk Electric System:
As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated
equipment, generally operated at voltages of 100 kV or higher. Radial transmission
facilities serving only load with one transmission source are generally not included in this
definition.
The authors are proposing a revised definition of the term BES to provide for improved clarity, to reduce
ambiguity, and to establish a universal “bright-line” for distinguishing between BES and non-BES
Elements and Facilities.
This proposed definition provides consistency across the nation’s reliability regions by establishing a
definition that clearly describes what constitutes BES and non-BES Elements and Facilities. The BES
definition references an exemption exception process (which may include regional differences as
defined by FERC Order 672 or jurisdictional exemptions as appropriate for those entities not subject to
Section 215 of the Federal Power Act) that can be used to:
•
•
•

Identify the Rradial Transmission systems that areis excluded from the BES,
Identify Elements and Facilities operated at voltages of 100kV or higher that may be excluded
from the BES; and
Identify Elements and Facilities operated at voltages less than 100kV that may be included in
the BES.
The proposed continent-wide definition of Bulk Electric System that the Project 2010-17
SDT will start with is:
Bulk Electric System: All Transmission and Generation Elements and Facilities operated
at voltages of 100 kV or higher necessary to support bulk power system reliability.
Elements and Facilities operated at voltages of 100kV or higher, including Radial
Transmission systems, may be excluded and Elements and Facilities operated at voltages
less than 100kV may be included if approved through the BES definition exemption
process.
SAR–2

Formatted: Font:

Standards Authorization Request Form

The development, approval, and application of the BES definition exemption exception process
(including periodic review of exempted facilities) will be governed by revisions to the NERC Rules of
Procedure, accomplished by another team in close coordination with the revision of the BES definition.
However, as envisioned, tThe sStandard dDrafting tTeam will work closely with the Rules of Procedure
team developing the BES definition exemption exception process to develop a single coordinated
implementation plan. It is also envisioned, that the Rules of ProcedureThe BES Definition team working
to develop the BES definition exemption exception process will solicit stakeholder input from drafting
teams, stakeholders, and Regional Reliability Organizations Entities in identifying the evidence an entity
will need when submitting a request for an exception to the definition of BES. physical and operational
characteristics for consideration in developing the BES definition exemption exception process. While
the determination of what evidence will be needed to support a request for a BES Definition Exception
will be developed using NERC’s standard development process, no decision has been made on “where”
the final product will reside – in the definition of BES or as an attachment (e.g., a procedure identifying
what evidence to produce when applying for a BES exception) to the new BES Exception Process in the
Rules of Procedure.

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SAR–3

Standards Authorization Request Form

Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Assurer

Monitors and evaluates the activities related to planning and
operations, and coordinates activities of Responsible Entities to
secure the reliability of the bulk power system within a Reliability
Assurer Area and adjacent areas.

Reliability
Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing
Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.

Interchange
Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.

Planning
Coordinator

Assesses the longer-term reliability of its Planning Coordinator
Area.

Resource
Planner

Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.

Transmission
Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.

Transmission
Planner

Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.

Transmission
Service
Provider

Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).

Distribution
Provider

Delivers electrical energy to the End-use customer.

Generator
Owner

Owns and maintains generation facilities.

Generator
Operator

Operates generation unit(s) to provide real and reactive power.

PurchasingSelling Entity

Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.

LoadServing
Entity

Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.

SAR–4

Standards Authorization Request Form

Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes

SAR–5

Standards Authorization Request Form

Related Standards
Standard No.

Explanation

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

FRCC
MRO
NPCC
SERC
TRE
RFC
SPP
WECC

SAR–6

Proposed Continent-wide Definition of Bulk Electric System:
Bulk Electric System (BES): All Transmission Elements operated at 100 kV or higher,
Real Power resources as described below, and Reactive Power resources connected at 100
kV or higher unless such designation is modified by the list shown below.
Inclusions:
•

•

•

•
•

I1 - Transformers, other than generator step-up (GSU) transformers, including phase
angle regulators, with two windings of 100 kV or higher unless excluded under
Exclusions E1 and E3.
I2 - Individual generating units greater than 20 MVA (gross nameplate rating)
including the generator terminals through the GSU which has a high side voltage of
100 kV or above.
I3 - Multiple generating units located at a single site with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) including the generator terminals
through the GSUs, connected through a common bus operated at a voltage of 100
kV or above.
I4 - Blackstart Resources and the designated blackstart Cranking Paths identified in
the Transmission Operator’s restoration plan regardless of voltage.
I5 - Dispersed power producing resources with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing a collector system through a
common point of interconnection to a system Element at a voltage of 100 kV or
above.

Exclusions:
•

•

•

E1 - Any radial system which is described as connected from a single Transmission
source originating with an automatic interruption device and:
a) Only serving Load. A normally open switching device between radial systems
may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5.
Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and
includes generation resources not identified in Inclusions I2, I3, I4 and I5.
E2 - A generating unit or multiple generating units that serve all or part of retail Load
with electric energy on the customer’s side of the retail meter if: (i) the net capacity
provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and
(ii) standby, back-up, and maintenance power services are provided to the
generating unit or multiple generating units or to the retail Load pursuant to a
binding obligation with a Balancing Authority or another Generator Owner/Generator
Operator, or under terms approved by the applicable regulatory authority.
E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV
that distribute power to Load rather than transfer bulk power across the
interconnected System. LDN’s are connected to the Bulk Electric System (BES) at

more than one location solely to improve the level of service to retail customer Load.
The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the
BES, the LDN must be connected through automatic fault-interrupting devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in
aggregate), includes more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed
the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy
originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or transfer path: The LDN does not contain a monitored
Facility of a permanent flowgate in the Eastern Interconnection, a major transfer
path within the Western Interconnection as defined by the Regional Entity, or a
comparable monitored Facility in the Quebec Interconnection, and is not a
monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).

Proposed Continent-wide Definition of Bulk Electric System:
Bulk Electric System: (BES): All Transmission and Generation Elements and Facilities
operated at voltages100 kV or higher, Real Power resources as described below, and
Reactive Power resources connected at 100 kV or higher unless such designation is modified
by the list shown below.
Inclusions:
•

•

•

•
•

I1 - Transformers, other than generator step-up (GSU) transformers, including phase
angle regulators, with two windings of 100 kV or higher necessaryunless excluded
under Exclusions E1 and E3.
I2 - Individual generating units greater than 20 MVA (gross nameplate rating)
including the generator terminals through the GSU which has a high side voltage of
100 kV or above.
I3 - Multiple generating units located at a single site with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) including the generator terminals
through the GSUs, connected through a common bus operated at a voltage of 100
kV or above.
I4 - Blackstart Resources and the designated blackstart Cranking Paths identified in
the Transmission Operator’s restoration plan regardless of voltage.
I5 - Dispersed power producing resources with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing a collector system through a
common point of interconnection to supporta system Element at a voltage of 100 kV
or above.

Exclusions:
•

•

E1 - Any radial system which is described as connected from a single Transmission
source originating with an automatic interruption device and:
a) Only serving Load. A normally open switching device between radial systems
may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5.
Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and
includes generation resources not identified in Inclusions I2, I3, I4 and I5.
E2 - A generating unit or multiple generating units that serve all or part of retail Load
with electric energy on the customer’s side of the retail meter if: (i) the net capacity
provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and
(ii) standby, back-up, and maintenance power services are provided to the
generating unit or multiple generating units or to the retail Load pursuant to a
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

•

binding obligation with a Balancing Authority or another Generator Owner/Generator
Operator, or under terms approved by the applicable regulatory authority.
E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV
that distribute power to Load rather than transfer bulk power system reliability.

Elements and Facilities operated at voltages of 100kV or higher, including Radial
Transmission systems, may across the interconnected System. LDN’s are connected
to the Bulk Electric System (BES) at more than one location solely to improve the
level of service to retail customer Load. The LDN is characterized by all of the
following:
a) Separable by automatic fault interrupting devices: Wherever connected to the
BES, the LDN must be excluded andconnected through automatic faultinterrupting devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements
and Facilities operated at voltages less than 100kV may be(in aggregate), includes
more than 75 MVA generation;
c) Power flows only into the LDN: The generation within the LDN shall not exceed
the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy
originating outside the LDN for delivery through the LDN; and
a)e)
Not part of a Flowgate or transfer path: The LDN does not contain a
monitored Facility of a permanent flowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the
Regional Entity, or a comparable monitored Facility in the Quebec
Interconnection, and is not a monitored Facility included if approved through the

BES definition exemption process.in an Interconnection Reliability Operating Limit
(IROL).

116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

Implementation Plan for Project 2010-17: Definition of BES
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this project can be implemented. However, this definition
relies heavily on the fact that an approved exception process exists in the NERC Rules of Procedure.
Revision to Sections of Approved Standards and Definitions
There is one new definition associated with this project.
Bulk Electric System (BES): All Transmission Elements operated at 100 kV or higher, Real Power
resources as described below, and Reactive Power resources connected at 100 kV or higher unless such
designation is modified by the list shown below.
Inclusions:
• I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle
Regulators, with two windings of 100 kV or higher unless excluded under Exclusions E1 and E3.
•

I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the
generator terminals through the GSU which has a high side voltage of 100 kV or above.

•

I3 - Multiple generating units located at a single site with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) including the generator terminals through the GSUs,
connected through a common bus operated at a voltage of 100 kV or above.

•

I4 - Blackstart Resources and the designated blackstart Cranking Paths identified in the
Transmission Operator’s restoration plan regardless of voltage.

•

I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a collector system through a common point of
interconnection to a system Element at a voltage of 100 kV or above.

Exclusions:
• E1 - Any radial system which is described as connected from a single Transmission source
originating with an automatic interruption device and:
a) Only serving Load. A normally open switching device between radial systems may
operate in a ‘make-before-break’ fashion to allow for reliable system reconfiguration to
maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes
generation resources not identified in Inclusions I2, I3, I4 and I5.
•

E2 - A generating unit or multiple generating units that serve all or part of retail Load with
electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the
BES does not exceed the criteria identified in Inclusions I2 or I3, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to
the retail Load pursuant to a binding obligation with a Balancing Authority or another Generator
Owner/Generator Operator, or under terms approved by the applicable regulatory authority.

•

E3 - Local Distribution Networks (LDN): Groups of Elements operated above 100 kV that
distribute power to Load rather than transfer bulk power across the Interconnected System.
LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to

April 28, 2011

1

improve the level of service to retail customer Load. The LDN is characterized by all of the
following:
a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the
LDN must be connected through automatic fault-interrupting devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in
aggregate), includes more than 75 MVA generation;
c) Power flows only into the Local Distribution Network: The generation within the LDN
shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy originating
outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or Transfer Path: The LDN does not contain a monitored Facility
of a permanent flowgate in the Eastern Interconnection, a major transfer path within the
Western Interconnection as defined by the Regional Entity, or a comparable monitored
Facility in the Quebec Interconnection, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception
process.
Effective Dates
The effective date is the date entities are expected to meet the performance identified.
This definition shall become effective on the first day of the first calendar quarter, 24 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required, all
requirements go into effect on the first day of the first calendar quarter, 24 months after Board of Trustees
adoption.
The SDT realizes that Order 743 suggested a maximum of 18 months for implementation of a revised
definition of the BES. The 24 month period cited here is based on the various rehearing requests filed by
entities expected to be affected by the revised definition. Thus, the SDT believes that this is a more
realistic timeframe in which to effect any changes.
The SDT believes that the timeframe shown is needed to:
• Effectively produce reasonable transition plans – As shown in Order 743, part of the overall
process of revising the definition of BES is for the ERO and Regional Entities to develop
transition plans on a region by region basis to accommodate any changes needed in those regions
due to the revised definition. The transition plans will include any actions necessary for entities
to achieve compliance on any issues brought about by the revised definition.
• Submit any necessary registration changes – While Order 743 states that a revised definition
should provide clarity and not necessarily require major changes to registration; it is possible that
the revised definition may cause some registration changes. Entities will need time to submit
their changes and for those changes to work their way through the process.
• File for exceptions – The revised definition does not exist in a vacuum. There is a corresponding
process for entities to request exceptions for specific equipment or configurations. This process
will be defined in the NERC Rules of Procedure and will involve individual entities or the
Regional Entities having to make a technical case to justify the exception. This process will take

April 28, 2011

2

some time to complete and it would be expected that there will be an initial backlog of cases to
process.
• Provide training – Entities will need to train their operators and personnel on changes to their
operations brought about by the revised definition.
The existing definition of BES shall be retired upon the effective date of the new definition of BES.

April 28, 2011

3

Comment Form for 1st Draft of Definition of BES (Project 2010-17)

Please DO NOT use this form to submit comments on the 1st draft of the Definition of the
Bulk Electric System (Project 2010-17). This comment form must be completed by May
27, 2011.
If you have questions please contact Ed Dobrowolski at ed.dobrowolski@nerc.net or by
telephone at 609-947-3673.

Background Information
Definition of the BES (Project 2010-17)
The SDT responded to the comments received for the posting of the SAR for this project by
clarifying the core definition and expanding the definition to contain specific inclusions and
exclusions to meet the concerns of the industry. The SDT has also used a variety of other
inputs including work that was done by regional entities such as WECC, NPCC, RFC, and
FRCC in coming up with the present definition. Another input was FERC Order No. 743 (and
Order No. 743a) which provided several specific directives on clarifying the existing
definition. The revised definition does not address functional entity registration or the
applicability of standard requirements. Those are separate issues.
The core definition represents a true bright-line; but, it is clear that by itself, it does not
cover all of the known situations and configurations that are needed for a complete
definition. Therefore, the SDT developed several specific inclusions and exclusions that are
proposed for addition to the core definition. At the present time, the SDT has drafted 5
specific inclusions and 3 specific exclusions.
Inclusions represent those items that are included as part of the Bulk Electric System (BES)
where they would not have been included as part of the simple core definition. The reasons
that the SDT has added these items are as follows:
•

Inclusion I1 – Transformers, other than Generator Step-up (GSU) transformers,
including Phase Angle Regulators, with two windings of 100 kV or higher unless
excluded under Exclusions E1 and E3.
o

•

•

Since transformers have windings operating at different voltages, clarification
was required to explicitly identify which transformers to include in the BES.
The SDT believes that the present draft provides this needed clarification.

Inclusion I2 – Individual generating units greater than 20 MVA (gross nameplate
rating) including the generator terminals through the GSU which has a high side
voltage of 100 kV or above.
o

This item mirrors the NERC Compliance Registry Criteria for individual
generating units. One of the basic tenets that the SDT is following is to avoid
changes to registration due to the revised definition if such changes are not
technically required for the definition to be complete.

o

In the comments received from the posting of the SAR for this project, the
SDT found no technical rationale for changing from the present greater than
20 MVA threshold. To provide clarity on these conditions, the SDT has spelled
out that the BES includes the generator terminal leads through the generator
step-up transformer (GSU).

Inclusion I3 – Multiple generating units located at a single site with aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating) including the
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com

Comment Form for 1st Draft of Definition of BES (Project 2010-17)

generator terminals through the GSUs, connected through a common bus operated
at a voltage of 100 kV or above.

•

•

o

This item mirrors the NERC Compliance Registry Criteria for multiple
generating units at a single site. One of the basic tenets that the SDT is
following is to avoid changes to registration due to the revised definition if
such changes are not technically required for the definition to be complete.

o

In the comments received from the posting of the SAR for this project, the
SDT has found no technical rationale for changing from the present greater
than 75 MVA threshold. To provide clarity on these conditions, the SDT has
spelled out that the BES includes the generator terminal leads through the
generator step-up transformer (GSU).

Inclusion I4 – Blackstart Resources and the designated blackstart Cranking Paths
identified in the Transmission Operator’s restoration plan regardless of voltage.
o

Blackstart units and their respective cranking paths are considered vital to the
overall operation of the BES.

o

Consequently, the SDT has included Blackstart Resources and their respective
Cranking Paths in the BES regardless of voltage level.

Inclusion I5 – Dispersed power producing resources with aggregate capacity
greater than 75 MVA (gross aggregate nameplate rating) utilizing a collector system
through a common point of interconnection to a system Element at a voltage of 100
kV or above.
o

This item was added to accommodate the effects of variable generation on
the BES. The intent of this configuration is to include variable generation
(e.g., wind and solar resources) with an aggregate rating greater than 75
MVA at one location and was considered different enough from what was
proposed in Inclusion I3 to warrant its own inclusion statement for clarity.

In addition to inclusions, to complete the picture, specific exclusions also need to be
considered. The SDT has currently drafted 3 specific exclusions:
•

Exclusion E1 – Any radial system which is described as connected from a single
Transmission source originating with an automatic interruption device and:
a) Only serving Load. A normally open switching device between radial systems
may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5.
Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and
includes generation resources not identified in Inclusions I2, I3, I4 and I5.
o

This item was added to address the basic issue of radial systems. A radial
exclusion is part of the existing definition and was supported moving forward
in all of the regional work as well as Order No. 743 (and Order No. 743a). The
SDT has clarified this exclusion by specifying that protection for the BES is a
required element of the system to be excluded. The SDT believes that faults
on radial lines without protection devices could negatively impact the BES.

Page 2 of 7

Comment Form for 1st Draft of Definition of BES (Project 2010-17)

•

Exclusion E2 – A generating unit or multiple generating units that serve all or part
of retail Load with electric energy on the customer’s side of the retail meter if: (i) the
net capacity provided to the BES does not exceed the criteria identified in Inclusions
I2 or I3, and (ii) standby, back-up, and maintenance power services are provided to
the generating unit or multiple generating units or to the retail Load pursuant to a
binding obligation with a Balancing Authority or another Generator Owner/Generator
Operator, or under terms approved by the applicable regulatory authority.
o

•

This item was added to address the situation of behind-the-meter generation.
The wording is basically extracted from the NERC Compliance Registry
Criteria.

Exclusion E3 – Local Distribution Networks (LDN): Groups of Elements operated
above 100 kV that distribute power to Load rather than transfer bulk power across
the Interconnected System. LDN’s are connected to the Bulk Electric System (BES)
at more than one location solely to improve the level of service to retail customer
Load. The LDN is characterized by all of the following:
a) Separable by automatic fault interrupting devices: Wherever connected to the
BES, the LDN must be connected through automatic fault-interrupting devices;
b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in
aggregate), includes more than 75 MVA generation;
c) Power flows only into the Local Distribution Network: The generation within the
LDN shall not exceed the electric Demand within the LDN;
d) Not used to transfer bulk power: The LDN is not used to transfer energy
originating outside the LDN for delivery through the LDN; and
e) Not part of a Flowgate or Transfer Path: The LDN does not contain a monitored
Facility of a permanent flowgate in the Eastern Interconnection, a major transfer
path within the Western Interconnection as defined by the Regional Entity, or a
comparable monitored Facility in the Quebec Interconnection, and is not a
monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).
o

Local distribution networks were added to the exclusion list after considerable
discussions among the SDT and various registered entities that have
configurations meeting these conditions. The SDT believes that any network
that simply supports distribution and is providing adequate protection should
be excluded from the BES.

In parallel with the definition project, another team has been set up to develop a change to
the NERC Rules of Procedure (ROP) to allow entities to technically justify excluding Elements
from the BES that might otherwise be included according to the proposed definition. This
same process would be used by Registered Entities to justify including Elements in the BES
that might otherwise be excluded according to the proposed definition. Finally, this process
would also be used for those situations where the core definition does not clearly identify
whether an Element is part of the BES or not. This ROP team will develop the process for
seeking an exemption from the definition but the DBES SDT will develop the criteria
necessary for inclusion with a request for an exemption through the standards development
process.

Page 3 of 7

Comment Form for 1st Draft of Definition of BES (Project 2010-17)

You do not have to answer all questions. Enter All Comments in Simple Text
Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
The SDT has asked one specific question for each specific aspect of the definition.
1. The SDT has made clarifying changes to the core definition in response to industry
comments. Do you agree with these changes? If you do not support these changes or
you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments.
Yes:
No:
Comments:
2. The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments.
Yes:
No:
Comments:
3. The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I2? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments.
Yes:
No:
Comments:
4. The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I3? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments.
Yes:
No:

Page 4 of 7

Comment Form for 1st Draft of Definition of BES (Project 2010-17)

Comments:
5. The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I4? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments.
Yes:
No:
Comments:
6. The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I5? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments.
Yes:
No:
Comments:
7. The SDT has added specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E1? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments.
Yes:
No:
Comments:
8. The SDT has added specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E2? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments.
Yes:
No:
Comments:
9. The SDT has added specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E3? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments.
Yes:

Page 5 of 7

Comment Form for 1st Draft of Definition of BES (Project 2010-17)

No:
Comments:
10. The SDT is discussing an exclusion from the Bulk Electric System (BES) for small
utilities based on statements in Order No. 743 that FERC does not believe its suggested
approach to the BES definition and exemption process will have a significant economic
impact on a substantial number of small entities and that small entities will not
adversely impact the reliability of the Bulk Electric System. The SDT has been made
aware that organizations that are not presently required to be registered by the NERC
Statement of Compliance Registry Criteria would meet the requirements to be registered
as Transmission Owners given the current proposed BES definition. These small utilities
could use the Rules of Procedure (ROP) exception process but this may be an issue that
could be handled more appropriately through the BES definition. This would alleviate
the paperwork burden for these small utilities and also avoid a possibly unnecessary and
significant impact on the administration of the ROP exception process during the
transition period to the revised BES definition. The proposed exclusion language is:
Exclusion E4: Transmission Elements, from a single Transmission source connected
at a voltage of 100 kV or greater, owned by a small utility whose connection to the
BES is solely through this single Transmission source, and without interconnected
generation as recognized in the BES Designation Inclusion Items I2, I3, I4, or I5. A
small utility is recognized as an entity that performs a Distribution Provider or Load
Serving Entity function but is not required to register as a Distribution Provider or
Load Serving Entity by the ERO.
Do you agree with this approach and the proposed language? If not, please be specific
in your response with a technical reason for your disagreement and, if appropriate,
suggested language for such an exclusion if you agree in general but feel that
alternative language would be more appropriate.
Yes:
No:
Comments:
11. In Order No. 743, the Commission addressed the need to differentiate between
Transmission and distribution in the revised definition of the Bulk Electric System (BES).
Specifically, the Commission stated that local distribution facilities are to be excluded
from the BES. The SDT believes that it has excluded local distribution facilities through
the revised bright-line core definition and specific inclusions and exclusions. Do you
agree with this position? If not, please provide specific comments and suggestions on
what else needs to be addressed or added.
Yes:
No:
Comments:
12. Are you aware of any conflicts between the proposed definition and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement, or
jurisdictional issue? If so, please identify them here and provide suggested language
changes that may clarify the issue.

Page 6 of 7

Comment Form for 1st Draft of Definition of BES (Project 2010-17)

Yes:
No:
Comments:
13. Are there any other concerns with this definition that haven’t been covered in previous
questions and comments?
Yes:
No:
Comments:

Page 7 of 7

Standards Announcement

Bulk Electric System Definition Revision Status
Background
On November 18, 2010 FERC issued Order 743 and directed NERC to revise the definition of Bulk Electric
System (BES) so that the definition encompasses all Elements and Facilities necessary for the reliable operation
and planning of the interconnected bulk power system. Additional specificity will reduce ambiguity and
establish consistency across all Regions in distinguishing between BES and non-BES Elements and Facilities.
In addition, NERC was directed to develop a process for identifying any Elements or Facilities that should be
excluded from the BES. NERC is working to address these directives with two activities – the definition of
Bulk Electric System (BES) is being revised through the standard development process and a BES Definition
Exception Process is being developed as a proposed modification to the NERC Rules of Procedure.
Teams
Two teams have been formed to develop the products needed to respond to Order 743. The first team is a
drafting team working under the direction of the Standards Committee. This team is called the BES Definition
Team (BES DT) and its work is publicly posted on the following web page with a link to toggle between the
work of this team and the work of the BES Rules of Procedure Team:
http://www.nerc.com/filez/standards/Project2010-17_BES.html
The second team is working under the direction of NERC staff and is called the BES Rule of Procedure Team
(BES ROP). Its work is publicly posted on the following web page with a link to toggle between the work of
this team and the work of the BES Definition Team:
http://www.nerc.com/filez/standards/Rules_of_Procedure-RF.html
Deliverables
The Standards Committee and the Standards staff have received many comments concerning the division of
work between these two teams. The leadership of the BES Definition SDT and Rules of Procedure team met
with the leadership of the Standards Program and the Standards Committee and determined that the BES
Definition SDT will assume responsibility for working with stakeholders to identify what evidence is needed to
support a request for an exception to the BES definition. The BES Definition team will solicit stakeholder input
to identify the evidence an entity will need to provide when submitting a request for an exception to the
definition of BES.
Product
Revised BES Definition
Identification of evidence needed to support a request for an
exception to the BES definition
Addition to Rule of Procedure
Implementation Plan

BES Definition
Team

BES Rule of
Procedure Team

X
X

X

X
X

While the determination of what evidence will be needed to support a request for a BES Definition Exception
will be developed using NERC’s standard development process, a decision on where the final product will
reside - in the definition of BES, or as an attachment (e.g., a procedure identifying what evidence to produce
when applying for a BES exception) to the Rules of Procedure will be made jointly by the leadership of the
Standards Program and the Standards Committee at a later stage. Given the time constraints of this project,
having all the technical content associated with this project developed by a single team seemed the most
efficient decision.
Status
The BES Definition Team has posted its consideration of the comments submitted in response to questions
about the SAR, initial draft definition, and list of criteria for either inclusion or exclusion from the definition of
BES. The team has also posted its next draft of the definition of BES and will be posting a comment form in
mid-April to collect stakeholder feedback on the revised definition.
The BES ROP Team has been meeting and expects to post a draft of its proposed ROP in late April for
stakeholder feedback.
Members of the two teams are sharing information and ideas and working cooperatively to ensure cohesion in
the final products.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement
Project 2010-17 BES Definition
Comment Period Open April 28-May 27, 2011
Now available at: http://www.nerc.com/filez/standards/Project2010-17_BES.html
Formal 30-day Comment Period Open through 8 p.m. on May 27, 2011
A proposed revision to the definition of “Bulk Electric System,” and an associated implementation plan have
been posted for a formal comment period until 8 p.m. Eastern on May 27, 2011.
The BES Definition Drafting Team is also working to identify what evidence is needed to support a request for
an exception to the BES definition. The BES Definition team expects to post its initial Technical Justification
Principles proposal describing the evidence needed to support a request for an exception to the BES definition
in early May and will seek stakeholder comments on its proposal.
A separate team is working to identify the necessary changes to NERC’s Rules of Procedure to incorporate the
process for requesting exceptions. The proposed changes to the Rules of Procedure will also be posted in early
May. Once all three documents have been posted (draft revised BES Definition, proposed Technical
Justification Principles, and proposed Rules of Procedure changes) and prior to the end of the comment periods,
a webinar will be scheduled.
Instructions
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Monica Benson at monica.benson@nerc.net. An off-line, unofficial copy of the comment
form is posted on the project page: http://www.nerc.com/filez/standards/Project2010-17_BES.html
Next Steps
The drafting team will consider all comments and determine whether to make additional changes to the
definition and its implementation plan. The team will post its response to comments and, if changes are made to
the definition and implementation plan, submit the revised documents for quality review prior to the next
posting.
Project Background
On November 18, 2010 FERC issued Order 743 and directed NERC to revise the definition of Bulk Electric
System so that the definition encompasses all Elements and Facilities necessary for the reliable operation and
planning of the interconnected bulk power system. Additional specificity will reduce ambiguity and establish
consistency across all Regions in distinguishing between BES and non-BES Elements and Facilities.
In addition, NERC was directed to develop a process for identifying any Elements or Facilities that should be
excluded from the BES. NERC is working to address these directives with two activities – the definition of
Bulk Electric System (BES) is being revised through the standard development process and a BES Definition

Exception Process is being developed as a proposed modification to the Rules of Procedure. The work of the
BES Definition Exception Process has been publicly posted at:
http://www.nerc.com/filez/standards/Rules_of_Procedure-RF.html
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Individual or group. (154 Responses)
Name (108 Responses)
Organization (108 Responses)
Group Name (46 Responses)
Lead Contact (46 Responses)
Question 1 (131 Responses)
Question 1 Comments (154 Responses)
Question 2 (129 Responses)
Question 2 Comments (154 Responses)
Question 3 (133 Responses)
Question 3 Comments (154 Responses)
Question 4 (125 Responses)
Question 4 Comments (154 Responses)
Question 5 (107 Responses)
Question 5 Comments (154 Responses)
Question 6 (120 Responses)
Question 6 Comments (154 Responses)
Question 7 (138 Responses)
Question 7 Comments (154 Responses)
Question 8 (108 Responses)
Question 8 Comments (154 Responses)
Question 9 (131 Responses)
Question 9 Comments (154 Responses)
Question 10 (120 Responses)
Question 10 Comments (154 Responses)
Question 11 (130 Responses)
Question 11 Comments (154 Responses)
Question 12 (106 Responses)
Question 12 Comments (154 Responses)
Question 13 (0 Responses)
Question 13 Comments (154 Responses)

Individual
Kevin Conway
Intellibind
No
I agree in principle with the changes; however the definition and direct effect on certain small entities
has not been improved. Primarily there are many entities that will be included that are marginal at
best. Such entities will include intermittent generation such as wind, which may, or may not fit into
the designation of aggregation of up to 75 MVA. It is becoming a practice to size a farm, or phase of a
farm, to under 75MVA to get around the rules. A site is not defined and could be defined very
narrowly. I do not agree with the 20MVA threshold for single generators when the generators net
output cannot reach the 20MVA output. Trash burning facilities have heavy station service loads and
by nameplate are included when in reality they operate below the arbitrary cut off. FERC has asked
for technically justified standards, and the proposed BES definition still applies an arbitrary threshold
not supported by technical argument. This issue is further aggravated by location of these resources.
Many of these resources are remotely located specifically so that they have no, or minimize impact on
the BES. Many times they are on long lines that are over 100KV simply because of efficiency in
electrical transmission.
Yes
No
In the discussion the Drafting team stated they found no technical rational to change the 20 MVA rule,
however there is no technical rational to support 20 MVA either. There are arguably cases where it
will be appropriate to include these generators; however there are may instances where these

generators should not be included. This should be driven by the interconnected transmission
operators, not by an arbitrary threshold. In the WECC there are multiple examples of small/medium
hydro, waste-to-energy, and other non-dispatchable generation that not only are located where they
cannot add to the reliability of the BES, are not manned, and are bound by contractual relationships
by a BA. These facilities have a tendency to have multiple forced outages, are affected by weather
events, and are not considered reliable by the interconnected transmission operator for BES reliability
purposes. Many of these facilities generate power as a secondary business, not primary. Wood
burning, trash burning is waste disposal, irrigation projects are primarily focused on water delivery.
Failure of power generation is not addressed as a primary importance during a failure, and none of
these facilities were constructed to benefit the BES. In many cases the contract to construct these
facilities was predicated on proving they do not impact the interconnected transmission operator or
the BES.
No
Though as previously stated I do not think that the 20 MVA threshold has technical merit, I do not
believe that the 75MVA limit has technical merit either. Further the impact should be measured at the
buss bar not at the nameplate. The aggregate rating should be the same as the individual unit rating
on a single plant, unless the plant can prove that there is not a common failure mode to lose more
than 20MVA.
Yes
There continues to be confusion in the industry of blackstart by Generator Owners and Operators
(especially small to medium generation), and the drafting team should clearly define what is meant
by blackstart. Many small generators have the capability to blackstart their resource, but are not part
of the Transmission Operator's blackstart plan on restoring the BES. In most cases they are asked to
blackstart if possible and wait until lines are energized and close in as directed by Transmission
Operator. This is significantly different than owning a blackstart resource designated to provide power
during a blackout.
No
Though the intent is understood through the discussion, the language presented is not clear enough.
The drafting team should be cautioned on how Standards are read through many different entities
and audiences. The team should also understand if the issue is not clearly defined, there will continue
to be ambiguity through the registration and compliance processes. As previously stated on an earlier
question, I do not think that the 20 MVA threshold has technical merit, I do not believe that the
75MVA limit has technical merit either. Further the impact should be measured at the buss bar not at
the nameplate. The aggregate rating should be the same as the individual unit rating on a single
plant, unless the plant can prove that there is not a common failure mode to lose more than 20MVA.
No
Small radial systems that have two interconnection points at the same location or very close to the
same location, but are not used for Transmission flow through should also be excluded. There are
numerous examples of two interconnection points that are paralleled by much higher voltage systems
and do not flow power through the system, but are redundant to increase distribution reliability. This
should be left to the Transmission Operator/Transmission Owner to determine if there is flow through
and impact to the BES before designating these as BES assets based on interconnection points. Radial
should be defined as power flowing one direction only, not based on how it is interconnected to 100KV
or higher lines.
No
This is very confusing. Understanding the Drafting Team's goal, it would better to adjust the I2 and I3
criteria to address NET generation and behind the meter generation. E2 appears to try and address
the net generation versus nameplate issue, but not fully. Station service power is behind the meter
and it is a commitment of the resource. Many small generators have multiple processes outside of
power generation they must provide for, and these should be considered in the exceptions.
Yes
This does address some of my concerns on small radial transmission systems. I think that there will
be confusion when small entities try and apply both E3 and E1 to their particular situations. The
ambiguity will cause more questions than it is trying to answer.
No

This does not address the full concerns of these small entities. In on case I am familiar with the entity
has a switchyard over 100KV and it was convenient for the interconnected utility to utilize the location
of the switchyard to add a line for the Transmission Operators purpose, however now that there are
two lines into the switchyard it has affected the small utility and they will not have exemption as
described in Question 10. The financial burden is very high for these entities when not exempted. In
this particular case noted above, the entity is planning to eventually decommission its system, but is
caught in having to bear the cost of operating a transmission system even though it is only one
substation that is immediatly stepped down to 13.8Kv and feeding a small distributed load. The
proposed exemption will still not allow this entity to be exempt. The ROP process does not serve these
small utilities well as an alternative and the Drafting Team should resolve these issues in the
definition of the BES if possible.
No
Due to the voltage bright line of 100kV there is still a question of what makes up sub-transmission.
Many rural companies with large geographic areas use the 115kV system internally as sub
transmission, but because of the bright line it is considered part of the transmission system. This is
not its purpose, or how it is operated. There are no commercial paths, and no transmission flow
through. On the other hand there are significant generation resources (significantly over 20MVA) that
are interconnected directly through the sub transmission system to the BES, and by definition, since
they are not interconnected at 100kV, they are exempted from BES status. Some of these facilities do
have direct impact on the BES.
No
Generation that is BES significant that is not connected at 100kV or above.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
No
The bright line revised definition could expand significantly what is considered to be BES in the case
of HQT, with no discernible impact on the reliable operation of the interconnected system, because of
the nature of the Québec interconnection. Furthermore, it should be stated that there appears to be a
conflict between the proposed definition and the regulatory framework applicable in Québec or at
least there are some important differences between both. The non-FERC juridiction was acknowledged
by FERC Order 743 in paragraph 95. As an example, the Québec regulatory framework considers that
there are several levels of application for standards, not only one. A single BES definition cannot apply
to all standards. The definition must include more latitude for non-FERC jurisdictions, as long as the
reliability objective is achieved.
No
Since transformers are already part of "all transmission Elements operated at 100 kV and above" in
the definition, and since inclusions I2 to I5 are commonly related to only generation, I1 should be
removed and replace instead by the following Exclusion: Ex "Transformers not used as Generator
Step-Up (GSU) transformers that have primary or secondary winding at less than 100 kV."
No
We believe that it is not necessary to include small generator of 20 MVA into the BES, neither the
transmission path that connect them. However, a provision should be made so that some reliability
standards related to generator shall apply (voltage regulation, etc.).
No
We believe that automatic inclusion of 75 MVA generation and the path to connect them to the BES
should not be automatically included in the BES. However, a provision should be made so that some
reliability standards related to generator shall apply (voltage regulation, etc.).
No
When we have to use Blackstart Resources, there is no more system. Therefore, reliability is not a
system planning issue, the need is no more for reliability since we lost the System or part of it. It
becomes a need for restoration of the system as fast as possible. The restoration plan is necessary,
but the Blackstart Resources and do not contribute to the reliability of the System, which just failed,

but to limit the time of loss of service. There is no obligation to apply the same Reliability Standards
on the paths and it should not be automatically included in the BES.
No
We believe that automatic inclusion of dispersed generation greater than 75 MVA and the path to
connect them to the BES should not be automatically included in the BES. However, a provision
should be made so that some reliability standards related to generator shall apply (voltage regulation,
etc.).
No
It is too much restrictive to refuse exclusion of radial system when they have generator greater than
20 MVA, or multiple generating units of aggregate capacity greater than 75 MVA, especially when a
system is able to function reliably with the loss of generation much higher than this amount. The fact
that no Reliability Standards apply to generators excluded from BES is problematic. Generators should
be allowed to be excluded but reliability standards should apply to them in specific. Also, the
connection through only a single Transmission source is again too restrictive. Other Transmission
source could be used for load continuity of service and the restriction should be limited to radial
transmission paths where the power flow is greater than the first contingency lost.
No
Part b) is again very restrictive. It is not necessary to refuse exclusion when generation is above 75
MVA. However, a provision should be made so that reliability standards related to generator shall
apply.
No
The case of small Utility is covered through other exclusions. However, the Facilities owned by small
utility should have protection requirement applied.
No
See comments on E3 (Q.9)
Yes
There appears to be a conflict between the proposed definition and the regulatory framework
applicable in Québec or at least there are some important differences between both. NERC's proposed
definition of Bulk Electric System (“BES”) is made in response to FERC's Order 743. FERC is looking to
remove regional discretion, and in some cases to make sure BES includes the most important national
load centers. As for HQT's System, the BES definition shall meet the expectations of Quebec's
regulator, the Régie de l'Énergie du Québec, (Quebec Energy Board) which has the responsibility to
ensure that electric power transmission in Québec is carried out according to the reliability standards
it adopts. In a recent order (D-2011-068), the Régie de l'Énergie du Québec has recognized several
level of application for the Reliability Standards in Québec. It stated specifically that most reliability
standards in Québec shall be applied to the Main Transmission System (MTS). One other level of
application recognised by this decision is the NPCC Bulk Power System (BPS) to which the standards
related to the protection system (PRC-004-1 and PRC-005-1) and those related to the design of the
transmission system (TPL 001-0 to TPL-004-0) will be applicable. The Main Transmission System
definition is somewhat different than the Bulk Electric System definition. The Main Transmission
System includes elements that impact the reliability of the grid, supply-demand balance and
interchanges. It can be described as follows : The transmission system comprised of equipments and
lines generally carrying large quantities of energy and of generating facilities of 50 MVA or more
controlling reliability parameters: • Generation/load balancing • Frequency control • Level of
operating reserves • Voltage control of the system and tie lines • Power flows within operating limits •
Coordination and monitoring of interchange transactions • Monitoring of special protection systems •
System restoration Therefore, it will be necessary to accommodate NERC's proposed definition of BES
or the exception process with the Québec situation where Entities are under a different jurisdiction.
These differences include more than one level of application for the reliability standards, the Main
Transmission System definition being the main one to which most reliability standards apply.
Individual
Martin Bauer

US Bureau of Reclamation
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
The term "retail load" is ambiguous and unnecessary. The term should be changed to "load". The
change is justified by the conditions (i) and (ii) placed on the generators.
Yes
No
The small entities can seek exclusion using the BES Exception Process developed under this project.
Yes
No

Individual
Jerome Murray
Oregon Public Utility Commission Staff

No
The inclusion of individual generation units with a nameplate capacity between 20 MVA and 75 MVA is
over-inclusive and unnecessary. Generation in this range generally has no impact to the reliability of
the bulk transmission system. The 20 MVA threshold was pulled from the existing NERC Statement of
Compliance Registry. This Registry value was adopted without the benefit of having been scrutinized
through a NERC Standards Development Process, so the technical record justifying the 20 MVA
threshold is unavailable. The BES Drafting Team will need to have technical justification for adopting
the 20 MVA threshold beyond the fact that it was previously adopted by NERC in a different
framework. Absent any technical justification, Inclusion I2 should be eliminated. This would leave the
75 MVA threshold in Inclusion I3 and Inclusion I5 as the minimum BES thresholds for generation. The
proposed BES Definition does not address the BES “demarcation points” and whether the BES must
be “contiguous.” NERC Staff has submitted written comments to this project stating that the BES
“must be contiguous.” Instituting a contiguous BES with Inclusion I2 would result in a over-inclusive
BES definition. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of distribution elements that have nothing to do with
improving or protecting the reliability of bulk transmission system. There is no compelling reason to
adopt a “contiguous” BES down into local distribution systems. Section 215 of the FPA of 2005 gives
FERC jurisdictional authority over “users” as well as “owners” and “operators” of the bulk power
system. Consequently, FERC has the jurisdictional authority to require generation entities in the

Compliance Registry to comply with applicable NERC requirements. Hence, even where an entity does
not own or operate BES assets, it could still be required, for example, to provide necessary
information to the applicable Reliability Coordinator or Planning Coordinator and to participate in
programs to prevent instability, uncontrolled separation or cascading outages to the bulk transmission
system. This approach would fully achieve the goals of bulk transmission system reliability without
imposing the full BES regulatory compliance burden on local distribution elements.

Yes
Exclusion I as currently proposed adequately defines radial systems; however, Inclusion I2 language
should be removed per the rationale stated in the response to Question 3 above. To retain the
Inclusion I2 language herein would sweep in an abundance of distribution elements that have no
impact on the reliable operation of the interconnected bulk transmission system.
Yes
Exclusion E3 is absolutely necessary for excluding local distribution elements from the interconnected
bulk transmission system as required by Section 215 of the FPA of 2005. This exclusion mirrors the
Seven Factor Test (established in FERC Order 888), which sets sound overarching principles for
differentiating local distribution elements from bulk transmission elements. Also, the conversion of
radial systems to local distribution networks is generally implemented by a distribution provider to
improve the level of service to local retail customers, not to accommodate bulk transfer of wholesale
power. Retaining Exclusion E3 is absolutely crucial for maintaining the 100 kV brightline in the core
BES definition. Without the distribution network E3 exclusion, the voltage threshold in the core BES
definition would need to be changed to the 200 kV level. Otherwise, NERC and Regional Entities will
have to deal with endless exception applications and evaluations associated with the removal of local
distribution elements that have no impact on the reliable operation of the interconnected bulk
transmission system.
No
Without BES "demarcation" and "contiguous" principles being addressed in the proposed BES
definition, this question is difficult to answer. NERC Staff has submitted written comments to this
project stating that the BES “must be contiguous.” Instituting a contiguous BES with Inclusion I2, for
example, would result in a substantially over-inclusive BES definition. The adoption of a “contiguous”
BES is therefore likely to result in imposition of reliability standards on a substantial number of
distribution elements that nothing to do with improving or protecting the reliability of bulk
transmission system. There is no compelling reason to adopt a “contiguous” BES down into local
distribution systems. Section 215 of the FPA of 2005 gives FERC jurisdictional authority over “users”
as well as “owners” and “operators” of the bulk power system. Consequently, FERC has the
jurisdictional authority to require generation and other entities in the Compliance Registry to comply
with applicable NERC requirements. Hence, even where an entity does not own or operate BES assets,
it could still be required, for example, to provide necessary information to the applicable Reliability
Coordinator or Planning Coordinator and to participate in programs to prevent instability, uncontrolled
separation, or cascading outages to the bulk transmission system. This approach would fully achieve
the goals of bulk transmission system reliability without imposing the full BES regulatory compliance
burden on local distribution elements.

Individual
Eric Lee Christensen
Public Utility District No. 1 of Snohomish County, Washington
Yes
As a general matter, Snohomish County PUD supports the approach the Standards Development
Team (“SDT”) has taken to defining the Bulk Electric System (“BES”). In the comments we submit

today, we identify several refinements we believe would improve the definition. We also discuss the
legal framework the SDT must operate under as we understand it. But we support the SDT’s
conceptual approach and, if refined as we suggest, we will support the SDT’s proposal so long as an
acceptable process for defining exceptions accompanies the definition. As to the core definition
addressed in Question 1, Snohomish believes the changes made in the revised definition are helpful
and represent significant progress toward an acceptable definition. Nonetheless, we are concerned
that the core definition is overly-broad and sweeps facilities into the BES that are required by the
statute to be excluded, even considering the list of inclusions and exclusions. We therefore suggest
two different approaches below that may achieve the SDT’s aims more effectively than the proposed
core definition. At a minimum, as we explain below, additional clarifications to the core definition are
necessary and an acceptable exemption process is required to ensure that facilities that by statute
must be excluded are excluded from the BES as defined by the SDT. At the outset, we urge the SDT
to bear in mind the specific restrictions on the definition of “bulk-power system” contained in Section
215 of the Federal Power Act (“FPA”) (Following FERC’s guidance on the question, we treat the
statutory term “bulk-power system” as equivalent to the term ordinarily used in the industry, “Bulk
Electric System”). In Section 215(a)(1), Congress defined “bulk-power system” to mean “facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof)” and “electric energy from generation facilities needed to maintain transmission
system reliability.” 16 U.S.C. § 824o(a)(1). Congress unequivocally excluded from this definition
“facilities used in the local distribution of electric energy.” Id. The “bulk-power system” definition thus
imposes a clear limit on the reach of the mandatory reliability regime. Congress reinforced that limit
in Section 215(i), where it emphasized that the FPA authorizes the imposition of reliability standards
“for only the bulk-power system.” 16 U.S.C. § 824o(i)(1) (emph. added). Further, the SDT must bear
in mind “the cardinal rule that a statute is to be read as a whole since the meaning of statutory
language, plain or not, depends on context.” City of Mesa v. FERC, 993 F.2d 888, 893 (D.C. Cir.
1993) (citation omitted). In considering how Congress used the term “bulk-power system” in the
statute, as well as the limits on the reliability regime imposed in the surrounding statutory language,
it is clear that Congress intended the “bulk-power system” to be defined narrowly so that it would
incorporate only high-voltage, interstate facilities used to transmit power over long distances, whose
failure threatens drastic reliability events such as cascading outages. These limitations are plain from,
for example, the statutory definition of “reliability standard,” which provides that reliability standards
are to encompass only requirements to “provide for reliable operation of the bulk-power system.” 16
U.S.C. § 824o(a)(3) (emph. added). Congress further refined the scope of reliability authority by
specifically defining “reliable operation” to mean “operating the elements of the bulk-power system
within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden
disturbance. . . or unanticipated failure of system elements.” 16 U.S.C. § 824o(a)(4). Congress’s
intent to focus the national reliability regime on broad-scale threats to the interconnected, interstate
high-voltage system like cascading outages is made clear, as well, by Congress’s specific direction
that the mandatory reliability system is prohibited from enforcing standards for adequacy of service,
which were left to state and local authorities. 16 U.S.C. § 824o(i)(2). When read in the context of the
statute as a whole, the definition developed by the SDT should therefore focus on that portion of the
interconnected bulk transmission grid for which thermal, voltage, and stability limits must be
observed in order to prevent instability, separation events, and cascading outages. Further, in order
to honor the specific limits placed on the definition by Congress, the SDT’s definition must exclude
facilities used in the local distribution of electric power and it must exclude facilities whose operation
or mis-operation affects only the level of service and does not threaten cascading outages or other
widespread events on the bulk interconnected system. Snohomish is concerned that the SDT’s
proposed definition is overly-broad, and that it will sweep in many Elements that have little or no
material impact on the reliable operation of the interconnected bulk transmission grid. For example,
the definition would sweep in all generators with 20 MVA capacity even though generators this small
rarely create impacts on the interconnected bulk transmission system that would threaten to violate
the thermal, voltage or stability limits of the bulk transmission system and therefore do not threaten
instability, separation, or cascading outages on the interconnected transmission system. Accordingly,
for the BES definition to conform to the requirements of the statute, the SDT must adopt an effective
mechanism to exempt facilities like these that are improperly swept in by the SDT’s brightline
approach to inclusions and exclusions. For this reason, the Exception process to accompany the SDT’s
definition is of critical concern. It constitutes the last line of defense against a SDT definition that

sweeps in facilities excluded by the statutory definition. Snohomish believes the SDT can achieve the
goals of FERC’s Orders No. 743 and 743-A while honoring these statutory limits by taking one of two
alternative approaches to the core definition. First, perhaps the simplest way the SDT could achieve
the goals of FERC Order No. 743 while avoiding overbreadth that violates statutory limits is to simply
adopt the statutory definition of “bulk-power system” as the core definition. This approach is
commonly used by regulatory agencies in defining key jurisdictional terms to ensure that the agency
does not cross statutory boundaries when carrying out the duties assigned to it by Congress. Under
this approach, the core definition would simply echo the statutory definition, substituting “Bulk
Electric System” for its statutory equivalent, “bulk-power system”: The term ‘Bulk Electric System’
means: (A) Facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof); and, (B) Electric energy from generation facilities
needed to maintain transmission system reliability. The term does not include facilities used in the
local distribution of electric energy. See 16 U.S.C. § 824o(a)(1). The inclusions and exclusions
developed by the SDT, with the refinements we discuss below, would then be added to provide
guidance in the application of this definition to specific classes of electric system facilities and
Elements. A second alternative approach is to make the smallest possible adjustment to the current
BES definition that suffices to address the central concern expressed by FERC in Orders No. 743 and
743-A. Those orders emphasized that FERC’s concerns are with the initial phrase in the current NERC
BES definition, which provides that the “Bulk Electric System” is: As defined by the Regional
Reliability Organization, the electrical generation resources, transmission lines, interconnections with
neighboring systems, and associated equipment, generally operated at voltages of 100 kV or higher.
In Order No. 743, FERC made clear that it views the initial phrase ("As defined by the Regional
Reliability Organization") as creating unreviewable discretion for Regional Entities to define the BES in
their region, and that this unreviewable discretion, rather than lack of uniformity per se, is the
problem Order No. 743 is designed to remedy. See, e.g., Order No. 743, 133 FERC ¶ 61,150 at P 16
(2010) (FERC believes the “best way to address these concerns is to eliminate the Regional Entities’
discretion to define ‘bulk electric system’ without ERO or Commission review“; id. at 30 (same). In
Order No. 743-A, FERC clarified that the primary aim of its rulemaking was to eliminate this
unreviewed regional discretion, and it was not, as FERC had originally proposed, to create a uniform
national definition that does not allow for any regional variation. Order No. 743-A, 134 FERC ¶ 61,210
at P 11 (“We clarify that the specific issue the Commission directed the ERO to rectify is the discretion
the Regional Entities have under the current bulk electric system definition to define the parameters
of the bulk electric system in their regions without any oversight from the Commission or NERC.”); id.
at P 39 (“The Commission’s suggested solution simply would eliminate regional discretion that is not
subject to review by [NERC] or the Commission”). Accordingly, the SDT could achieve the primary
aim of Order No. 743 by simply rewriting the current definition to read: Unless a different definition
has been developed by the Regional Reliability Organization and approved by NERC and FERC, the
Bulk Electric System is defined as the electrical generation resources, transmission lines,
interconnections with neighboring systems, and associated equipment, generally operated at voltages
of 100 kV or higher. If the SDT uses this suggested language as its core definition, it will have
addressed FERC’s primary concern with a minimum of disruption to the current NERC system of
definitions. The definition could then be further elaborated with the list of specific inclusions and
exclusions of Elements and systems (modified as discussed below), to provide more specific guidance
to the industry. In this connection, we note that a 200 kV threshold would be more appropriate for
WECC than a 100-kV threshold. This is because generation in the West is generally located far from
load, and power is generally transmitted from these generation sources to distant load centers on
extremely high-voltage lines, usually operating in the range of 230-kV to 500-kV. Further, because
loads are often dispersed across relatively broad geographic areas, especially in the rural West, 115kV lines are frequently used in local distribution systems. See WECC Bulk Electric System Definition
Task Force, Initial Proposal and Discussion, at pp. 11-16 (posted May 15, 2009) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx) (technical discussion showing that
most transmission in the Western Interconnection operates at voltages greater than 200 kV).
Accordingly, a 200-kV threshold with an “inclusion” mechanism to sweep in the relatively limited
number of 115-kV lines in the West that perform a transmission function would be better suited to the
typical topology of systems in the West than a 100-kV threshold with exceptions for facilities that
operate as local distribution. That being said, we recognize that 200-kV may not be an appropriate
threshold for other parts of the country and we are willing to support the SDT’s approach as long as
discretion is preserved for the WECC to develop a definition better suited to the conditions in the

Western Interconnection. If the STD elects not to adopt one of the above suggestions, the core
definition proposed on April 28 requires clarification. Specifically, as drafted, the proposed definition is
ambiguous in that it is not clear whether the clause “unless such designation is modified by the list
shown below” modifies only the preceding clause (“Reactive Power resources connected at 100 kV or
higher”) or the entire definition. To eliminate this ambiguity, we suggest that the proposed definition
be reordered to read as follows: Bulk Electric System (BES): (A) Unless included or excluded in
subpart B, the Bulk Electric System consists of: (1) all Transmission Elements operated at 100 kV or
higher; (2) Real Power resources identified in subpart B; and, (3) Reactive Power resources connected
at 100 kV or higher. (B) [the list of inclusions and exclusions, modified as discussed in our responses
to questions 2 through 9]. Rearranging the definition in this way should make clear that the list of
inclusions and exclusions that would be inserted as Subpart B modifies each provision of Subpart A.
Thus, for example, even if a Transmission Element is otherwise included by virtue of operating at 100
kV or higher, it is nonetheless excluded if specifically addressed in the list of exclusions that would be
incorporated as subpart B of the definition (if, for example, the Element qualifies as a Local
Distribution Network). The rearrangement of the language eliminates any argument that the phrase
“unless such designation is modified by the list shown below” does not modify “all Transmission
Elements operated at 100 kV or higher” because of its placement at the end of the independent
clause “Reactive Power resources connected at 100 kV or higher.” Snohomish supports the use of the
phrase “Transmission Elements” as the starting point for the base definition because both
“Transmission” and “Elements” are already defined in the NERC Glossary of Terms Used, and the use
of the term “Transmission” makes clear that the Bulk Electric System includes only Elements used in
Transmission and therefore excludes Elements used in local distribution of electric power. As
discussed above, the definition must exclude facilities used in local distribution in order to comply with
the limits placed on NERC authority by Congress in Section 215 of the Federal Power Act (“FPA”), 16
U.S.C. § 824o. For similar reasons, we believe the SDT has improved the proposed definition from its
initial proposal by eliminating the use of terms such as “Generation” that are not specifically defined
in the NERC Glossary of Terms and by eliminating terms such as “Facility” that include “Bulk Electric
System” as part of their definition. Eliminating the use of such terms helps sharpen the core
definition. If a key term is undefined, incorporating it into the definition only begs the question of how
the incorporated term is defined. If a currently-defined term uses the phrase “Bulk Electric System”
as part of its definition, incorporating that term into the BES definition creates a confusing circularity.
We therefore support the SDT’s use of defined terms such as “Element,” “Real Power,” and “Reactive
Power.”
Yes
In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and nonBES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is
stepped down from transmission voltages to distribution voltages. We believe, however, that the SDT
should undertake the effort to more clearly define the point where the BES ends and non-BES
systems begin. In this regard, we note that the WECC Bulk Electric System Definition Task Force
(“BESDTF”) has devoted considerable effort to this question and has developed one-line diagrams
denoting the BES demarcation point for a number of different kinds of Elements that are common in
the Western Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available
at: http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES
Definition Clarification Project has devoted considerable effort to developing one-line diagrams of
transmission and distribution Elements, and identifying the point of demarcation between BES and
non-BES Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B
(available at: https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the
SDT should be able to provide much useful guidance to the industry with relatively little additional
effort. Also, the reference to “two windings of 100 kV or higher” may create some confusion because
many three-phase transformer banks have 6 or 9 windings, depending on whether the transformer
has a tertiary. We suggest clarifying this provision by changing the clause referencing two windings to
read: “the two highest voltage transformer windings of 100 kV per phase that are connected to the
Bulk Electric System.”
No
Snohomish is concerned that the inclusion of individual generation units with a nameplate capacity as
small as 20 MVA is over-inclusive. Under FPA Section 215, generation resources are excluded from
the “bulk-power system” unless they produce “electric energy” that is “needed to maintain

transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators with a capacity of 20
MVA almost never produce electricity that is “needed to maintain transmission system reliability.”
Hence, the inclusion as drafted improperly expands the BES definition to include generators that the
statute requires to be excluded. Further, the 20 MVA threshold appears to have been drawn without
explanation from the existing NERC Statement of Compliance Registry. Given that the purpose of the
Compliance Registry is to sweep in all generators that might be material to the operation of the BES,
and not to definitively determine whether a given generator is, in fact, material to the operation of
the BES, the STD has acted arbitrarily and without adequate technical justification in adopting the 20
MVA threshold. In responding to comments on its initial proposal, the SDT states that it adopted the
20 MVA threshold because “there is no technical basis to change the values contained in the
Statement of Compliance Registry Criteria.” Consideration of Comments on Definition of Bulk Electric
System – Project 2010-17, March 30, 2011, at 30. But this gets the equation backwards. The SDT
must have some technical justification for adopting the 20 MVA threshold beyond the fact that it was
previously adopted by NERC in a different context. Without a technical justification demonstrating that
facilities operating at capacities as low as 20 MVA are “needed to maintain transmission system
reliability,” the proposed definition is overly broad and fails to comply with the restrictions imposed by
Congress in FPA Section 215(a)(1), 16 U.S.C. § 8240(a)(1). Further, the Statement of Compliance
Registry was adopted without the benefit of having been vetted through the NERC Standards
Development Process, so the technical record underlying the choice of that threshold is unavailable
for review by the industry. In the same comments, the SDT also states that it has considered “the
inclusion of generator step-up (GSU) transformers and associated interconnection line leads and
believes the BES must be contiguous at this level in order to be reliable.” Id. The SDT’s reasons for
reaching this conclusion are not well-explained, but apparently the concern is that a “non-contiguous”
BES could create “reliability gaps.” But this conclusion cannot be supported as an abstract
proposition, but can only be demonstrated by a careful examination how application of reliability
standards will change depending on how the BES is defined. In fact, we believe that if the SDT insists
on a “contiguous” BES, an over-inclusive definition will result. We base these conclusions on the
findings of NERC’s Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO
Task Force.” The Project 2010-07 Team was formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. After reviewing these questions in considerable depth, the Team concluded that
dedicated high-voltage interconnection facilities need not be treated as “Transmission” and classified
as part of the BES in order to make reliability standards effective. On the contrary, the team
concluded that by complying with a handful of reliability standards, primarily related to vegetation
management, reliable operation of the bulk interconnected system could be protected without unduly
burdening the owners of such interconnection systems. See Final Report from the NERC Ad Hoc Group
for Generator Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the
predecessor of the Project 2010-07 SDT). Much of the work of the Project 2010-07 SDT is applicable
to the work of the BES Standards Developoment Team. For example, the Project 2010-07 Team
observed that interconnection facilities “are most often not part of the integrated bulk power system,
and as such should not be subject to the same level of standards applicable to Transmission Owners
and Transmission Operators who own and operate transmission Facilities and Elements that are part
of the integrated bulk power system.” White Paper Proposal for Information Comment, NERC Project
2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011). Requiring
Generation Owners and Operators to comply with the same standards as BES Transmission Owners
and Operators “would do little, if anything, to improve the reliability of the Bulk Electric System,”
especially “when compared to the operation of the equipment that actually produces electricity – the
generation equipment itself.” Id. We believe the many of the questions considered by the Project
2010-07 Team are analogous to the questions under consideration by the SDT, and that, if the SDT
insists upon a “contiguous” BES, the resulting definition will be substantially over-inclusive. The
“contiguous” BES concept implies that every Element arguably necessary for the reliable operation of
the interconnected bulk system must be included in the BES definition, even if it is interconnected
with Elements that have no bearing on the operation of the BES. The adoption of a “contiguous” BES
is therefore likely to result in imposition of reliability standards on a substantial number of facilities
that have little or nothing to do with bulk system reliability, resulting in wasted regulatory expense
and additional stress on the limited resources of reliability regulators. For example, a “contiguous”
BES would require dedicated interconnection facilities that connect a BES generator to BES
transmission facilities to be classified as BES. But, as the discussion above demonstrates, the

classification of dedicated interconnection facilities as “BES” facilities would, based on the findings of
the Project 2010-07 SDT, result in substantial overregulation and unnecessary expense with little gain
for bulk system reliability. Similarly, a “contiguous” BES suggests that, because certain system
protection facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the
local distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” Such a result is not only plainly contrary to the local distribution exclusion embedded in
Section 215 of the FPA, but would, by improperly classifying local distribution lines as BES
“Transmission” facilities, result in huge regulatory compliance burdens with little or no improvement
in bulk system reliability. There is no good reason for the SDT to adopt a “contiguous” BES. On the
contrary, because Section 215 allows reliability standards to be applied to “users” of the bulk system
as well as “owners” and “operators,” local distribution systems operating UFLS relays and other bulk
system protection devices could be required to comply with standards governing those devices as a
precondition for their use of transmission on the bulk system. The other alternative is to draft
standards that apply to a specific type of equipment – again UFLS relays is a good example – rather
than to BES facilities categorically. Either approach will fully achieve the goals of bulk system
reliability without imposing an undue regulatory compliance burden on local distribution systems. For
these reasons, we urge the SDT to follow the example of the Project 2010-07 Team and the GO-TO
Task Force by giving careful consideration to the specific and practical results of how its definition will
affect the application of particular reliability standards and whether the results are beneficial to
reliability or simply result in unnecessary regulatory burdens that do not benefit bulk system
reliability. We believe there is considerable danger of error if the SDT bases its conclusions on
metaphysical debates about whether a “contiguous” or “non-contiguous” BES is more desirable rather
than engaging in a careful analysis of whether the proposed definition achieves reliability goals in the
most efficient manner possible.
No
Snohomish is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the
20 MVA threshold discussed in our response to question 3, the 75 MVA threshold appears to have
been drawn from the NERC Statement of Compliance Registry without appreciation for the function of
the threshold in that document and without adequate technical justification demonstrating the
generators with an aggregate capacity of 75 MVA produce electric energy “needed to maintain
transmission system reliability” and are therefore properly included in the BES definition.
Yes
Including “all” blackstart and blackstart cranking paths in the BES may ultimately provide an incentive
to the electric industry to reduce the number of resources with blackstart capability. We therefore
suggest that essential blackstart resources identified by the Regional Entity should be included in the
Bulk Electric System, but non-essential blackstart resources need not be.
No
Snohomish agrees that it is important to address wind generation facilities and similar generation
facilities in which a large number of generating units, each with a relatively small capacity, are
clustered and fed into the grid at a single interconnection point. That being said, Snohomish is
concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained. We believe the exclusion as drafted adequately defines radials.
Yes
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through
reference to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the
generation unit is reliability-must-run or essential blackstart, the function of the unit is irrelevant to
the reliable operation of the interconnected bulk transmission grid, and we therefore believe the
reference to the function of the generation unit (“standby, back-up, and maintenance power…”)
should be eliminated.
Yes
Snohomish strongly supports the categorical exclusion of Local Distribution Networks from the BES. In
fact, for reasons discussed at length in our answer to Question 1, we believe the exclusion is
necessary to ensure that the BES definition complies with the statutory requirement to exclude all

facilities used in the local distribution of electric power. LDNs are, of course, probably the most
common kind of local distribution facility. Further, the conversion of radial systems to local
distribution networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. But providing an
exclusion for radials without providing an equivalent exclusion for LDNs will have the opposite effect,
to the ultimate detriment of electric consumers. Snohomish also supports, with the reservations
discussed below, the LDN exclusion as drafted by the SDT. At least conceptually, we believe the SDT
has identified the key characteristics that separate LDNs from facilities that are part of the bulk
transmission system and therefore should be classified as BES. Hence, LDNs can be excluded from
the BES based on the characteristics identified by the SDT without compromising the reliability of the
interconnected bulk transmission system. Although Snohomish supports the LDN exclusion, we
believe the exclusion should be refined in the following respects: • The SDT’s draft states that: “LDN’s
are connected to the Bulk Electric System (BES) at more than one location SOLELY to improve the
level of service to retail customer Load.” (emphasis added) We are concerned that the use of the term
“solely” implies the need for an examination of the motives of a local distribution utility in connecting
to the BES at more than one location. This result is problematic because it defeats the purpose of the
exclusion, which is to allow LDNs to be excluded from the BES without an in-depth and expensive
inquiry into the exact nature of the LDN. In addition, the local utility may have a number of motives
for connecting to the BES at more than one location, but the local utility’s motives have nothing to do
with how the LDN interacts with the interconnected bulk system, which should be the key determinant
in including or excluding any Element from the BES. With these concerns in mind, we therefore
recommend that the SDT revise the sentence quoted above as follows: “LDNs are connected to the
Bulk Electric System (BES) at more than one location to improve the level of service to retail
customer load and not to accommodate bulk transfers of power across the interconnected bulk
system.” By instituting this suggestion, the SDT would emphasize the key difference between an LDN,
which is designed to reliably serve local, end-use retail customers, and the BES, which is designed to
accommodate bulk transfer of power at wholesale over long distances. • We believe the
characteristics specified by the LDN in subsections (b) and (c) of the exclusion are redundant.
Subsection b specifies that the LDN would not interconnect more than 75 MVA of generation in
aggregate. Subpart c specifies that power flows only into the LDN. We believe the SDT can eliminate
subpart b of the definition and simply rely on subpart c because if power only flows into the LDN even
if it interconnects more than 75 MVA of generation, the interconnected generation interconnected will
have no significant interaction with the interconnected bulk transmission system, only with the LDN.
Further, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LDN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and
dispersed and, under the subpart c criteria, would be wholly absorbed within the LDN rather than
transmitting power onto the interconnected grid, those generators would not have a material impact
on the grid. In addition, the 75 MVA criterion would make an LDN interconnecting more than 75 MVA
part of the BES. For the reasons set forth by the Project 2010-07 SDT, we are concerned the result
will be the local utility being improperly classified as a Transmission Owner and Transmission
Operator, which would subject the local utility to a number of reliability standards that would
significantly increase its compliance burden without substantially improving bulk system reliability. In
fact, in the LDN situation, there is even less reason to impose these burdens on the local utility than
in the situation addressed by the Project 2010-07 team, where generators are interconnected to the
BES by dedicated interconnection facilities. Because the LDN is interconnected at multiple points, the
generators interconnected to the LDN could continue to operate even if one or two interconnection
points are out of service. On the other hand, in the situation addressed by the Project 2010-07 team,
if the dedicated interconnection facility is out of service, the generation is unavailable because there is
no alternative route to deliver it to load. Finally, for the reasons stated in our answers to Questions 3
and 4, we believe the SDT’s wholesale adoption of the 20 MVA and 75 MVA thresholds from the NERC
Statement of Compliance Registry lacks adequate technical justification. The SDT repeats that error
here by incorporating those thresholds into the LDN exception.
Yes
Snohomish County PUD supports the SDT in its efforts to avoid unintended consequences from
changes to the BES definition, especially for small entities that can ill afford the substantial costs that
accompany imposition of mandatory compliance with reliability standards. Further, we agree that the
small utilities covered by the exemption will have no measurable impact on the operation of the

interconnected BES. Our views are borne out by experience in the Pacific Northwest where many
small entities were required to register by virtue of owning a very small portion of the region’s 115-kV
system. These utilities have faced substantial compliance burdens even though their operations are
simply not material to the interconnected bulk grid in our region, and the investment of resources in
compliance therefore will have no measurable effect in improving the reliability of the interconnected
grid.
No
While Snohomish County PUD agrees that the approach adopted by the SDT -- a core definition
coupled with specific inclusions and exclusions – will be effective in removing most local distribution
facilities from the BES, it will not remove all such facilities. For the reasons discussed at greater
length in our answer to Question 1, Snohomish believes that the proposed definition is over-inclusive
and is likely to sweep up certain facilities used in local distribution that should not be classified as
BES. To give a further example, assume that a local distribution utility operates a distribution network
that currently would be excluded from the SDT’s definition, but that a cogeneration facility with a
capacity of 30 MVA and average production of 15 MW is constructed in one of the industrial areas
served by local distribution facility and the output is purchased by one of the industrial customers.
Because of inclusion I2, the local utility would now be classified as owning BES facilities, even though
the output of the generator rarely exceeds 20 MW in practice and the output is, as a matter of
physics, absorbed by the surrounding industrials loads rather than being transmitting onto the
interconnected grid. Further, the fundamental nature of the local distribution facilities has not
changed. They are still used to deliver electric power to the utility’s end-use customers, not to deliver
power on the wholesale market across the interconnected bulk grid. Hence, the result of the SDT’s
definition is to include “facilities used on the local distribution of electric energy” in contravention of
FPA Section 215(a)(1), 16 U.S.C. § 8240(a)(1). The practical result of the improper classification
would be that the local utility would be required to register as a Transmission Owner and
Transmission Operator, and would incur substantial costs to comply with requirements that are
designed to ensure the reliable operation of transmission lines that are part of the interconnected
grid, not local distribution facilities. For the reasons explained in the papers published by the Project
2010-07 Task Force, the result is substantially increased compliance costs that produce little or no
improvement in the reliability of the interconnected bulk system. Accordingly, if viewed in isolation,
the SDT’s core definitions and list of inclusions/exclusions do not comply with the statute or produce
optimum benefits for bulk system reliability. Whether the SDT’s approach complies with the statute
can only be determined by examining the Exception process now under development, in conjunction
with the SDT’s definition. If the Exception process results in the exclusion of facilities that are
improperly swept into the BES by the bright-line thresholds included in the SDT’s definition, and the
Exception can be attained at a reasonable cost to the involved entities, then the SDT will have
achieved a result that complies with the statute. But this conclusion can be reached only upon review
of the entire package, not just the core definition and list of inclusions/exclusions. In this regard, as
discussed in our answer to Question 3, Snohomish notes that exclusion of facilities from the BES does
not mean that owners of those facilities are entirely exempt from reliability standards. On the
contrary, the statute provides that “users” of the BES can be subject to reliability regulation. 16
U.S.C. § 824o(b). Hence, even where an entity does not own BES assets, it could be required to, for
example, provide necessary information to the applicable Reliability Coordinator and to participate in
the regional Under-Frequency Load Shedding program by setting the UFLS relays in its Local
Distribution Network at the appropriate settings. We note that participants in the WECC BES Task
Force generally agreed that appropriate information should be provided by non-BES entities, although
there was considerable concern related to ensuring that the provision of information was not unduly
burdensome.
Yes
As noted in our responses to Question 1 and Question 11, we believe the SDT proposal is potentially
in conflict with the limitations of the Federal Power Act, and in particular the statutory exclusion for
facilities used in the local distribution of electric energy. Unless the SDT adopts some approach other
than a core definition with inclusions and exclusions based on brightline thresholds, the SDT’s
approach can meet the statutory requirements only if the Exception process currently under
development results in facilities that are not properly classified as BES being exempted from
regulation as BES facilities.
Snohomish County PUD has these additional concerns: • We are concerned that the proposed 24-

month delay in the effective date of the new definition will delay the potentially beneficial effects of
the SDT’s efforts, especially for utilities that have been inappropriately registered for BES-related
functions, which is a common situation in WECC. We therefore urge the new BES definition to become
effective immediately upon approval by FERC or other applicable regulatory agencies. Entities that
have been improperly registered for BES functions can then immediately file for deregistration and
obtain the benefits of the new definition as soon as possible. For entities that have not previously
been registered for BES-related functions but that would be required to register under the new
definition, we do not object to the 24-month transition period proposed by the SDT to allow the
newly-registered entity to attain compliance with newly-applicable reliability standards, many of
which require new training for employees, new maintenance procedures, and complex new
operational protocols. However, the transition period for newly-registered entities should be
structured in a way that does not prevent entities seeking deregistration from benefitting from the
new definition at the earliest possible date. • The current definition provides that “Elements may be
included or excluded on a case-by-case basis through the Rules of Procedure exception process.”
Snohomish is concerned that the SDT carefully delineate which entity has the burden of proof in the
exclusion process. The WECC BES Task Force approach, which we commend to the SDT, laid out
these burdens in some detail. Under that approach, essentially, if a facility is excluded from the BES
by virtue of the specific exclusions listed in the definition, the Regional Entity bears the burden of
proving that the facility nonetheless has a material impact on the interconnected bulk transmission
system and therefore should be included in the BES. On the other hand, if a facility is classified as
BES by virtue of the list of inclusions set forth in the BES definition, it can still escape classification as
BES, but bears the burden of demonstrating that its facility has no material impact on the
interconnected transmission system. We urge the SDT to give careful consideration to these burdenof-proof questions and to follow the lead of the WECC BES Task Force. • For the reasons we have
explained in our answer to Question 11, we believe the Exception process is critical both to ensure
that the BES definition is effective in producing measurable gains to bulk system reliability and to
ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the Exception process and related procedures, should be
vetted through the NERC Standards Development Process, including the full comment periods and a
ballot approvals provided for in that process. We are concerned that important elements of the BES
definition have been assigned to the Rules of Procedure Team, and that changes in the Rules of
Procedure are subject to approval in a process that provides considerably less due process and
industry input than the Standards Development Process. Compare NERC Rules of Procedure § 1400
(providing for changes to Rules of Procedure upon approval of the NERC board and FERC) with NERC
Standards Process Manual (Sept. 3, 2010) (providing for, e.g., posting of SDT proposals for comment,
successive balloting, and super-majority approval requirements). Accordingly, we urge that all
elements of the BES definition, including those elements that have been assigned to the Rules of
Procedure Team, be vetted through the Standards Development Process. Further, we believe that the
failure to vet all material elements of the BES definition through the Standards Development Process
would constitute a violation of NERC’s bylaws and the requirements of the Standards Development
Process.
Group
Public Service Enterprise Group LLC
Mikhail Falkovich
No
There is still room for misinterpretation of the BES boundaries. The BES definition has ramifications
affecting many standards. NERC should provide examples of what specifically is in and what is out of
BES boundaries. Example one line diagrams showing “Generation Resources” included or excluded
and types of radial feeds exempted should be shown. Identify what element is in BES / what is out.
Suggest showing typical interconnection facilities. Addressing typical interconnection facility
configurations will assist in developing a clear and concise definition that provides a precise line of
demarcation between elements of the BES.
Yes
No
See comment 1 above.

Yes
No
Black start resources and the cranking path should not be included in the BES definition unless
connected at 100kV and above. There are many other existing standards that impact black start
units. Routine testing and redundancy is part of them. Adding in black start units < 100kV and the
associated cranking path to the BES definition may discourage entities from providing black start
capability due to cost associated with cumulative testing and record keeping criteria. This may result
in withdrawing the offer to provide that service and/or potentially drive up the cost of that service
significantly without any related increase in BES reliability.
Yes
No
Again, in similar comments to item 1 above, where is the BES line of demarcation between BES
elements (the interrupting device itself) connecting the non-BES radial system? The term “Generation
resource” is not defined and open for interpretation.
Yes

Group
National Rural Electric Cooperative Association (NRECA)
Barry Lawson and Patti Metro
Yes
NRECA believes the definition should explicitly state that facilities used in local distribution are
excluded from the BES.
Yes
Yes
Yes
No
This is the only part of the BES definition and inclusions/exclusions that specifically states “regardless
of voltage.” NRECA does not believe it is appropriate for the BES definition to include such a
statement. This issue needs to be addressed in standard applicability language, not in the definition of
BES.
Yes
Yes
NRECA requests that the drafting team state explicitly whether the automatic interruption device is
included or excluded from the BES. Examples of automatic interruption devices should be included in
a reference or FAQ document, and drawings/diagrams on typical configurations would be beneficial.
Consistent language is needed in the Inclusions/Exclusions. E1 states “automatic interruption device”
and E3(a) states “automatic fault interrupting devices.” NRECA recommends adding the word “fault”
as in E3(a) and also stating “device(s)” in E1 and E3(a) and wherever else the phrase may be used in
the BES definition and inclusions/exclusions. Additional clarification is needed in explaining E1(c) to
ensure industry understands the scenario.

Yes
Yes
Yes
NRECA agrees with this approach, but also believes this could be addressed in the Statement of
Compliance Registry Criteria document.
No
NRECA believes the definition should explicitly state that facilities used in local distribution are
excluded from the BES.

Individual
Nicholas Winsemius
Grand Haven Board of Light and Power
No
The Grand Haven Board of Light and Power (GHBLP) does not agree that the core definition for the
BES use a “bright line” definition of 100kV and above. Currently, we have a 138kV/69kV transformer
that connects to the BES and serves a radial, load serving system. This transformer is presently
protected by a “ground switch” relay scheme. We have a project in process that is replacing this
“ground switch” relay scheme with a circuit switcher. The circuit switcher, unlike the ground switch,
would not affect the BES if it were to operate. By this “bright line” definition this single asset would be
defined as a part of the BES. The cost that our organization would incur from being forced to register
as a Transmission Owner and Transmission Operator (TO/TOP) would be extreme, and would
significantly impact our budget and our customer’s rates. We should not have to depend on an
“exclusion” process to remove this asset from being defines as a part of the BES, and this should be
addressed in the core definition.
Yes
Yes
Yes
Yes
Yes
No
Exclusion E1 addresses a radial, load serving system, but it does not address whether the automatic
interrupting device should be defined as a part of the BES or not. In our case, the ONE automatic
interrupting device that we own would force us to register as a TO/TOP, and as a result incur
significant costs. This does not comply with FERC Order No. 743 (and No. 743a) and should be
addressed in this exclusion if not in the core definition.
Yes
Yes
No
We agree with addition of Exclusion E4, except that it should apply to small load serving distribution
utilities even if they are required to register as a Distribution Provider and Load Serving Entity. In our
last fiscal year, July 2009 through June 2010, the Grand Haven Board of Light and Power served

262,847 MWh and peaked at 54 MW. Even though we are required to register as DP/LSE, we are still
a small utility. Please revise the definition of a small entity for the purpose of this exception to use
more reasonable criteria.
No
The exclusions do not properly address the exclusion of single automatic interrupting device that
serves a radial, load serving system and, through its operation, does not affect the BES.
Yes
This current definition does not comply with FERC Order No. 743 (and 743a) by not addressing the
exclusion of a single automatic interrupting device that serves a radial, load serving system.
I can not over emphasize how unreasonable it would be for our utility to have to register as a TO/TOP
because of one asset (138kV circuit switcher) that serves a radial, load serving system. It is equally
unreasonable for us to have to use a long and arduous exception process to qualify for deregistration.
Please take this into consideration as you prepare the final definition.
Individual
Josh Dellinger
Glacier Electric Cooperative
No
I still feel that a bright-line of 200 kV would be more appropriate, with language stating that certian
significant elements operated below 200 kV would be included. However, I believe the exlusion
process is definitely a step in the right direction.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
I agree with the approach, but not the language. I believe the small utility clause should be taken out
and this Exlusion should be applicable to any transmission elements whose connection to the BES is
soley through a single transmission source and without interconnected generation, regardless of the
size of the utility.
Yes
I do believe that the language in its plain sense does exclude local distribution systems, but I do see
the possibility of differeing interpretations of the language across the regions again. Perhaps adding
some example system diagrams showing what would and would not be included in the BES would
help alleviate any possible ambiguity and increase consistency across the regions.
No
No
Individual
Russ Schneider

FHEC
Yes
Generally agree, but think E1 should be changed slightly to: From: E1 - Any radial system which is
described as connected from a single Transmission source originating with an automatic interruption
device and: To: E1 - Any radial system which is described as connected from a Transmission source
originating with a single automatic interruption device and:
Yes
Believe that the NERC Statement of Compliance Registry Criteria should be revised to reflect only
thsese inclusions and exclusions. An entity with no assets that meet this definition should be allowed
to de-register.
Yes
Yes
Yes
Yes
No
Suggest the word single be moved later in the sentence, see below- From: E1 - Any radial system
which is described as connected from a single Transmission source originating with an automatic
interruption device and: To: E1 - Any radial system which is described as connected from a
Transmission source originating with a single automatic interruption device and:
Yes
Yes
We support the current wording of E3.
Yes
this begs the question of the Statement of Compliance Registry Criteria being updated also.
No
Not until the Statement of Compliance Registry Criteria is conformed to this proposed definition.
No

Individual
Kim Moulton
Vermont Transco
Yes
It appears that the SDT has made progress in addressing comments made to date. Concerned that
facilities below 100 kV will fall into the current definition of BES. If changes in the wording better
identified key areas the new definition would be easier to interpret, apply, and it would better align
with the concerns of the members
Yes
This inclusion’s wording allows an entity to easily identify which of its transformers will be included as
BES and also adheres directly to the FERC identified 100kV or higher equipment. Question: if a
transformer does not have two windings of 100 kV or higher but does have protection devices that
could open the BES system, e.g. due to a low-voltage failed breaker scenario, would the protective
devices be part of the BES even though the transformer itself is not?
Yes
How will generating owners currently registered as a GO/GOP and have units tied to the BES system
through a radial transmission line, that they own, and connects them to the grid be affected by the

new definition? Will they need to become TO and TOP registered also? Should a GO/GOP have to
adhere to all TO/TOP standards and requirements or only a sub-set of requirements?
No
What is the definition of “common bus”? Would this only apply to generating facilities with a direct
GSU tie to the 100 kV, and up, system? Or would it apply to those units tied to the low side of a
transformer at a voltage below 100 kV that has a step up high side voltage greater than 100 KV?
Example: units are tied through to a single 46 kV substation (GSU high side connected to this
substation) with a tie from this substation to the BES through a step up transformer.
No
: The phrase “regardless of voltage” is a concern. The goal of the FERC order is to provide a more
reliable “bulk power system”. Many blackstart resources are at voltages well below the 100 kV voltage
and are not material to the restoration of the bulk electric system during a blackout. The wording of
this inclusion would require many units that are used only for local area support to now be listed as a
BES facility. The wording of this inclusion should be something to the order of “Blackstart Resources
and the designated blackstart cranking paths identified in the transmission operators restoration plan
that are necessary to restore the BES system”, this should not include cranking paths on distribution
feeds that are used primarily for local area support. The purpose of this inclusion should be to make
certain all units necessary to energize the BES grid after a blackout are maintained and operated
appropriately
No Comment
No
Does “a single transmission source” mean a single “substation” at 100 kV or above? The wording of
this exclusion appears to allow distribution (<100 kV) level generating units to be excluded from the
definition of BES. If so then this generation exclusion is appropriate to the FERC order. However, the
definition of “automatic interruption device” should be defined fully. Specifically what types of
equipment are considered an AID? If a transformer has a high side voltage of 115 kV and a low side
voltage of 34.5 kV it would not be part of the BES definition, however depending on how one
interprets the exclusion for a radial feed, if the transformers automatic interruption device were on
the low side of this transformer, it appears that this transformer would then need to be “included” as
BES. In addition, would the protection schemes associated with the breaker failure on the low side of
a transformer (voltage <100 kV) designed to send a signal to the high side (which is greater than
100KV) for a breaker failure scenario fall into the “included” facilities even though the transformer
would not be “included”?
No Comment
No Comment
The exclusion wording is difficult to understand and apply. Are their voltage levels where this would
not apply (ex. 230 kV) or load levels that would be seen as too high? Cannot agree or disagree due to
the wording
No
The inclusion of all black start units “regardless of voltage”, the unclear definition of “automatic
interruption device” and “common bus” could lead to local distribution company facilities being
included in the definition of BES.
No
No Comment
No additional comments
Group
Northeast Power Coordinating Council
Guy Zito
No
The core definition should be revised to read: Bulk Electric System (BES): All Transmission Elements
operated at 100 KV or higher, unless such designation is modified by the list shown below. The
resulting modified BES shall comprise all Elements deemed necessary for operating an interconnected
electric energy transmission network, but shall exclude any Elements used in the local distribution of
electric energy. The inclusion and exclusion requirements are restrictive. For example, radial

characteristics should not be limited by the amount of installed generation or single transmission
source and/or require an interrupting device. Instead, one or more transmission sources could feed
the radial load to provide redundancy as long as there is adequate protection and isolation for
improved customer-supply continuity and reliability. This would be considered radial as long as the
loss of any transmission source would not affect, and is not necessary for the operation of the
interconnected transmission network. This retains the incentive to build transmission. The revised
definition will have a direct impact on entities across North America and may conflict with regulatory
requirements, Codes, and Licenses. FERC in its Order 743 and 743A has directed NERC to address
these concerns. Include provisions in both the NERC exception criteria and exception process for
federal, state and provincial jurisdictions. These provisions should provide clear guidance so that, if
and when there are deviations from the exception criteria, they are properly identified with technical
and regulatory justifications ensuring there is no adverse impact on the interconnected transmission
network. This burden of proof should be left to the entity seeking exception because it may be difficult
to define the exception criteria. Further, if such an explicit criteria could be defined, it could become
another bright-line BES.
Yes
No
I2 should pertain to individual generating units, but the entire path should not be labeled as BES.
Oftentimes there are cases when neither the path nor a 20 MVA unit itself will have any impact on the
reliability of the interconnected transmission network, nor is it necessary for its operation. The path to
generating facilities does not need to be BES contiguous. Generating units can be required to be
planned, designed, and operated in accordance with a subset of NERC Standards, but should not
require a contiguous path unless the unit is identified essential for the operation of transmission
network.
No
I3 should pertain to multiple generating units located at a single site, but the entire contiguous path
should not be labeled as BES. Oftentimes there are cases when neither the path of a 75 MVA plant or
aggregated generation will have any impact on the reliability of the interconnected transmission
network nor be necessary for its operation. As stated earlier, under various green energy, smart grid
and dispersed renewable energy plans advocated by both Canadian and US policy makers, the gross
nameplate rating of 75 MVA may undermine and deter the future potential of integrating Distributed
Generations (DG’s) that will be implemented to ensure the reliable operation of the interconnected
transmission network BES, and, at the same time, providing the most effective and economical
solutions for rate payers. Local generation can cost-effectively enhance the reliability of load pocket
by avoiding transmission, but such restrictions would deter the adoption of good planning decisions.
Path to generating facilities need not be BES contiguous. Generating units can be required to be
planned, designed, and operated in accordance with a subset of NERC Standards, but should not
require contiguous BES paths.
No
Blackstart resources and transmission facilities on the cranking path should not be classified as BES
regardless of size and voltage level. From a regulatory perspective, such an inclusion would be in
conflict with the current regulatory requirements in many jurisdictions. More importantly, designating
these facilities as BES Elements or Facilities beyond the 100 kV bright line, the 20 MVA/unit or 75
MVA/plant criteria, without a regard to their impact on the BES (under conditions other than system
restoration) will impose unnecessary requirements for these facilities, which do not contribute to
reliability under interconnected operation conditions. For a restoration condition, this inclusion is
extraneous. There is already a designation specific for system restoration covered by an existing
standard to recognize their reliability impacts and to ensure their expected performance. NERC
Standards EOP-005-2 stipulates the requirements for testing blackstart resource and cranking paths.
This testing requirement suffices to ensure that the facilities critical to system restoration are
functional when needed, which meets the intent of identifying their criticality to reliability. The BES
definition should cover those facilities that are needed for operation under both normal and
emergency conditions, which includes situations related to blackstart and system restoration. The
directives should not specifically ask for inclusion of blackstart resources and facilities on the cranking
path in the BES definition. The requirements in EOP-005-2 suffice to address the SDT’s interpretation

and concern regarding recognition of the reliability impacts and requirements for blackstart resources
and facilities used for system restoration. Generating units of any size and transmission facilities of
any voltage level may be used for black start and restoration. Conceivably, a generator of 10 MW and
transmission or distribution facilities of 44 kV or 69 kV may be a part of the cranking path. A BES
inclusion will then subject these generators and facilities, which are essentially “local” facilities but
called upon to begin restoring its bulk interconnected counterparts, to comply with the reliability
standards intended for maintaining BES reliability. Included in the BES definition will thus discourage
smaller generators from providing black start capability, and the transmission facilities from being a
part of the cranking path. This may also discourage Transmission Owners and Operators from
identifying multiple black start resources and cranking paths to provide restoration flexibility. Such an
inclusion will ultimately undermine reliability. If indeed any of these facilities are deemed necessary to
support bulk power system reliability at times other than system restoration, they would/should have
been identified through the basic BES definition and inclusion list or can be addressed through the
exception procedure. I4 should be removed based upon: • The availability and performance
expectations of blackstart resources and facilities on the cranking path are already specifically
addressed in an existing standard; and • Unless they meet the BES definition and the other inclusion
criteria, they do not have any perceived reliability impact on everyday operation of the BES. • I4 may
include very small generators and distribution facilities as it is written. Is it necessary from a reliability
point of view to include “cranking paths” below 100kV?
No
The entire contiguous path does not have to be BES. The path or aggregate generation will rarely
have any impact on the reliability on the interconnected transmission network, nor is it necessary for
its operation. These are generally referred to as connection facilities.
No
The concept is consistent with the statements in the FERC Order. However, it is imperative to
understand that the limitations of E1 will have a direct impact on many entities (big and small) along
with distribution companies across North America. The exclusion requirements are restrictive and
these restrictions mayhave an adverse affect on future transmission investment, for example the
addition of a second line removing the radial status exclusion. Consideration should be given to
allowing entities to build additional transmission and not automatically compromise the exclusion
status of any given facilities. For example, a redundant double circuit designed to supply the load with
adequate protection and isolation beyond the radial tap could be significantly better for load supplycontinuity and reliability. If more than one transmission source feed radial load to ensure customer
supply continuity and reliability, then this should be either part of the bright-line definition E1
exclusion as long as there is adequate protection and, the loss of any single transmission source does
not affect the interconnected transmission network. The SDT should: • Carefully craft the exception
criteria and procedure that is flexible and technically sound to adequately allow entities to present
their case to the ERO for exclusion • Exception criteria should be at a high-level with items of
assessment that can be followed continent-wide by entities to put forward their exception for
element(s) mentioned in exclusions or inclusions based on technical assessment, evidence and
justification for its unique characteristics, configuration, and utilization • Acknowledge and provide
provisions in both NERC exception criteria and exception process for federal, state and provincial
jurisdictions.
Yes
No
Regarding E3.a.--If the supply to a LDN is tapped off a Bulk Electric System facility, and the step
down transformer is protected on its high side by a fault magnitude supervised automatic interrupting
device (such as a circuit switcher), how does that affect the exclusion? The circuit switcher will only
interrupt faults up to a certain magnitude. Above that threshold, depending on the system
configuration, fault clearing might have to be done at the Bulk Electric System facility. Regarding
E3.d.--The LDN cannot be used to transfer real or reactive power under all operating conditions.
Suggest combining E3.c and E3.d to read as follows: Power is intended to flow only into the LDN. The
generation within the LDN shall not exceed the electric real or reactive power demand within the LDN.
The LDN only delivers real or reactive power to load, and is not to be used to transfer real or reactive
power between different locations in the BES. Under no system condition is BES reliability to be

dependent on LDN flow.
No
Small utility or distribution provider is a relative term. A distribution provider may have an impact on
the transmission network based on its design, configuration, connection point, and protection. Such
an exception should apply regardless of the size of an entity. The concept discussed here is to define
a radial system and not a small utility, as mentioned in the FERC Order. We do not believe that the
SDT had sufficient discussions while crafting the proposed exclusion in regards to small utilities. The
language used in the proposed clause is only appropriate to establish a bright-line definition for a
radial system. Many small utilities (and individual load customers or generation connections) have
more than a single transmission source with a solid tap and, at the same time, be adequately
protected and effectively isolated without any adverse impact on the transmission network. Such a
practice and design is widely used across North America. Hence, we do not agree that this exclusion is
an attempt to address the issue of small utilities. The definition and inclusions will force many small
entities, load customers and generation unit owners to act and register as Transmission Owners. This
may be in conflict with state or provincial regulatory act, Codes and Licenses. Consistent with the
FERC Order, the ERO and the SDT should be aware of these conflicts and should not ignore them. The
ERO and the SDT address this by providing explicit but simple provisions in the exception procedure
by considering sound technical exception criteria that is flexible based on demonstration of evidence
to justify the element’s necessity for operation. Regulatory Acts and Rules will always overrule NERC
requirements and the only evidence that should be required of small utilities/entities is: • Regulatory
evidence • Evidence demonstrating that NO adverse reliability impact is afflicted on the
interconnected BES because of their connection.
No
The current definition drafted by the SDT has not differentiated between Transmission and
Distribution, nor excluded distribution facilities from the BES, nor addressed the issue of local
distribution facilities above 100kV. It is important for the ERO and the SDT to understand and be
consistent with the FERC Order for these important but complex issues. Many parts of the continent
could be in conflict with state or provincial regulatory act, Codes, and Licenses. The ERO and SDT and
RoP teams be aware of these conflicts and not disregard them, as they will pose many
implementation complexities and confusion within the industry. Regulatory Acts and Rules will always
supersede NERC requirements and hence it is important that ERO should neither be caught in
regulatory conflict nor put entities in these situations. As responded to in Question 10, the ERO and
SDT can address this by providing explicit but simple provisions in the exception criteria (to be used
by exception procedure) by putting forward required technical assessments , which are based on a
demonstration of evidence to justify the element’s necessity for operation. For example, suggest that
for local distribution, the evidence that should be required is: • Regulatory evidence • Evidence
demonstrating that NO adverse reliability impact is afflicted on the interconnected BES because of
their connection Some of the other key attributes of such an exception criteria should be: • Elements
are not to be part of interconnection between two balancing authority or contribute to IROLs • Entire
system cannot be classified as contiguous • Entity to justify whether or not the elements are
necessary for the operation of the interconnected transmission network • Distinguish if the element in
question supplies load centers, major cities, serves the national interest and/or possibly impact
national commerce or national security, or is identified by the relevant regulatory authority
Accordingly, the exception criteria should ONLY list a menu of items and a prescribed report template
that should be assessed and presented by an entity as their evidence and justification for exception to
a RE, the ERO and any relevant regulatory authority. This evidence and justification would be used by
the ERO as part of its decision making process.
Yes
The proposed definition will have a direct impact on entities not under FERC jurisdiction, and may be
in conflict with regulatory requirements with which those entities must comply.
Currently, the posted exception criterion is only a concept with many gaps and TBD, as posted details
are later to follow. The exception criteria should be a menu of technical items (load flows, stability
analysis etc) and non technical items (type of loads such as distribution companies versus major city
center, national security, etc). Entities should be required to assess and provide their own justification
under each category with a conclusion that takes into account all of the relevant items for element(s)
under exception, in a consistent template and table of contents. Suggest the SDT to avoid
specification of any parameters as they would differ under different design concepts, system

configurations, system characteristics and regulatory requirements. The comments herein reflect
thoughts on the document posted. An “all encompassing” comment is that the definition is too
lengthy. The importance of the BES definition is recognized throughout the industry for its
importance, and as such it should be simple, clear, and straightforward. The first draft definition
posted was more along this line. I2, I3, and I5, being very similar, can they be combined into an
encompassing generator inclusion criteria?
Individual
Richard McLeon
South Texas Electric Cooperative, Inc.
Yes
There is general confusion as to whether or not the “BES” is synonymous with the “BPS”. If this is so,
then it should be expressly stated as such. If not, clarification should be provided to industry.
Yes

Yes

Yes
Yes
Yes
No
I agree with everything up to “…but is not required to register…by the ERO”. There are many small
utilities that fit into the scope and spirit of the exclusion BUT were required to register as DP and/or
LSE by their ERO. This has generally been on the interpretation of “better safe”. Please remove the
language which gives this discretion to the ERO and insert language allowing already registered small
utilities with have their registrations revoked or surrendered.
Yes
I agree, but believe that those distribution companies that were forced to register as LSEs under FERC
interpretation should be excluded as well.
No

Group
Tri-State Generation and Transmission Association, Inc.
Bill Middaugh
No
The Northeast Power Coordinating Council stated that “Step-down transformers with the low-side
terminals serving non-BES facilities, which are serving a distribution function, should not be part of
the definition of BES.” The drafting team stated that it agrees with the comment, but the
implementation uses the term local distribution network, which is different than a step-down
transformer. Transformers are addressed in the answer to the NPCC comment 2, but uses the
ambiguous “single Transmission source” phrase as a requirement to determine BES status. Other
specific comments are below.
No
We recommend changing I1 to the following: “Only transformers, including phase angle regulators,
with two or more windings of 100 kV or higher that are connected through automatic fault-

interrupting devices, unless excluded under Exclusions E1 and E3.” “Only” is required to prevent a
regional interpretation that includes distribution transformers since they are never specifically
excluded. The phrase regarding GSUs is removed since they are covered in I2 and I3.
Yes
Yes
Yes
Yes
No
A “single Transmission source” is unclear and may be interpreted differently by different Regional
Entities. A circuit switcher-protected transformer serving only distribution load may be tapped to a
single transmission line but the transmission line has two or more sources. Is the system then
connected to a single Transmission source, thus making it radial and being excluded? Or will the
Regional Entity declare that, since the transmission line has two sources that the radial system also
has two sources? We suggest changing the opening sentence of Exclusion E1 to “Any radial system
that is connected to a Transmission source through an automatic interrupting device or devices and:”
No
This Exclusion should also include “wholesale” meters for the instance where an electric distribution
cooperative has some small generation connected to its distribution system that meets the same
criteria.
No
We believe that element c. needs to be changed to : “Power flows only into the Local Distribution
Network, even under all contingency conditions that are considered under any TPL standard
requirement dealing with transmission system performance: The generation within the LDN shall not
exceed the electric Demand within the LDN;"
No
We disagree with adding E4. This issue should be resolved by enhancing the NERC Statement of
Compliance Registry Criteria, not by integrating registration exemptions in NERC definitions.
No
See the comments to Question 7.
No
We believe that this definition is not consistent with the response from the SPCS in Project 2009-17,
“Interpretation of PRC-004-1 and PRC-005-1 for Y-W Electric and Tri-State” and could change its
intent. Existing tapped distribution transformers are clearly not BES Elements at this time. Under the
proposed definition that clarity is lost. There are instances where “automatic interruption device” or
“automatic interrupting device” is used. Each should be changed to include “fault” after “automatic.”
Individual
Angela Gaines
Portland General Electric Company
The bright-line definition of 100kV should specify that this is a three-phase line-to-line voltage.
Yes
The reference to “two windings” will cause confusion. Presumably the Standard Drafting Team means
two three-phase windings, which would mean that both the high sides and the low sides of a typical
transformer bank would have to be operating at 100kV and above in order to be part of the BES. In
other words, a 230kV/57kV transformer would not be included, despite the fact that all three windings
that make up the high side are individually rated at over 100kV. The inclusion needs to make clear
that it’s talking about two or more sets of windings, each set consisting of three phases.
No

The 20 MVA gross nameplate rating threshold for an individual unit is too low and will result in the
inclusion in the BES of generating units that have no potential to impact the reliability of the BES. The
20 MVA threshold was taken from the registration criteria, and no technical justification has been
provided for its use. PGE recommends that this inclusion be removed entirely.
The 75 MVA aggregate capacity rating threshold could result in the inclusion in the BES of generating
units that have no potential to impact the reliability of the BES. The 75 MVA threshold was taken from
the registration criteria, and no technical justification has been provided for its use. In addition, the
meaning of the phrase “located at a single site” is unclear and subject to multiple interpretations. The
phrase “connected through a common bus” accomplishes the same goal, and therefore the phrase
“located at a single site” should be removed.
Yes
It is not clear what the SDT is attempting to capture with this inclusion that is not already captured in
I3. In addition, the term “collector system” needs to be defined.
Yes
Yes
While PGE appreciates the SDT’s efforts to exclude distribution systems, as required by the statute,
PGE believes that this Exclusion needs further clarification to be workable. PGE has specific concerns
with the following aspects of the Exclusion: (b) The phrase “nor its underlying Elements (in
aggregate)” is ambiguous. It does not make it clear how a utility could differentiate between the
multiple Local Distribution Networks within its service territory. (c) The phrase “Power flows only into
the Local Distribution Network” does not make clear that under certain abnormal circumstances power
may flow out of a Local Distribution Network. Wording such as “the predominant direction of flow is
into the Local Distribution Network during normal (non-outage) conditions” could account for such
abnormal circumstances. (d) The phrase “Not used to transfer bulk power” should similarly be
modified to indicate that it is meant to describe normal rather than abnormal conditions. In addition,
this aspect of the Exclusion should account for the fact that two utilities may have multiple
interchange points at the distribution level, but the fact that energy is transferred at these points
does not inherently make them transmission paths. A phrase such as “none of the LDN facilities are
identified as belonging to or having direct rating impact on a regionally-recognized constrained
transmission path used to deliver energy to points outside of the LDN” could address this concern.
As stated above, PGE believes that the Exclusion for Local Distribution Network needs to be more
explicit.

Individual
Richard McLeon
South Texas Electric Cooperative, Inc.
Yes
There is general confusion as to whether or not the “BES” is synonymous with the “BPS”. If this is so,
then it should be expressly stated as such. If not, clarification should be provided to industry.
Yes
Yes
Yes
Yes

Yes
Yes
Yes
Yes
Yes
There are many small utilities that fit into the scope and spirit of the exclusion BUT are currently
registered as a DP and/or LSE. Will this exclusion remove them from registration OR should language
be inserted that automatically revokes the NERC registrations of “already registered” small utilities. I
recommend that any such revocation be handled by NERC and NOT by the various EROs for the sake
of consistency.
Yes
I agree, but believe that those local distribution companies operating below the bright-line that were
forced to register as LSEs under FERC Order on Compliance Filing (October 16, 2008) should be
excluded as well. For example, BAL-005-0.1b, CIP-001-1a, EOP-002-3 and others do not apply to DPs
but affect small local utilities as LSEs. If, according to FERC Order 743 a small local distribution utility
would be rightly excluded from DP standards, then, by the same logic and as a distribution-level LSE,
they should be excluded from LSE standards as well. If an operating system voltage below 100kV is
too low to affect the BES/BPS, then it stands to reason that their connected load is too small as well.
If not – then another bright-line should be established in the spirit of FERC Order 743 to differentiate
between power flow across the BES/BPS and power flow to end-use consumers.
No
no.
Individual
Michael Albosta
Sweeny Cogeneration LP
The specific identification of global inclusions and exclusions is a very good way to approach this
complex issue. We believe there are further items to be added to the list related to generator
interconnections, a task that was passed to this project from Project 2010-07. Just as is the case with
complex distribution systems, there are a variety of generator-transmission interconnection
architectures which are driving the Regions to inappropriately register Generator Owner/Operators as
Transmission Owners.
Yes
Transmission system transformers are not part of our existing or anticipated base of facilities.
No
The threshold for individual generation units is consistent with the NERC functional registry criterion.
We believe that it is important to maintain this uniformity. However, we believe there are further
items to be added to the list related to generator interconnections, a task that was passed to this
project from Project 2010-07. Just as is the case with complex distribution systems, there are a
variety of generator-transmission interconnection architectures which are driving the Regions to
inappropriately register Generator Owner/Operators as Transmission Owners.
No
The threshold for multiple generation units aggregated at a single location is consistent with the NERC
functional registry criterion. We believes that it is important to maintain this uniformity. However, we
believe there are further items to be added to the list related to generator interconnections, a task
that was passed to this project from Project 2010-07. Just as is the case with complex distribution
systems, there are a variety of generator-transmission interconnection architectures which are driving
the Regions to inappropriately register Generator Owner/Operators as Transmission Owners.
We do not operate any Blackstarts

Yes
The threshold for widely distributed and aggregated generation units (wind farms) is consistent with
the NERC functional registry criterion.
Yes
We agree that all radial connections serving a single load, small generator, or combination should be
excluded
No
Generators which serve local retail load (cogeneration) should be excluded if the net capacity
available to the BES does not exceed 20 MW Single Unit/75 MW Multiple Units thresholds. We believe
there are further items to be added to the list related to generator interconnections, a task that was
passed to this project from Project 2010-07. Just as is the case with complex distribution systems,
there are a variety of generator-transmission interconnection architectures which are driving the
Regions to inappropriately register Generator Owner/Operators as Transmission Owners.
Yes

Yes
No

Group
American Municipal Power and Members
Kevin Koloini
Yes
AMP and its members appreciate the opportunity to comment on the draft BES definition. We
generally support the direction taken by the SDT, with some minor changes. We agree with some
other entities' comments and suggest a few clarifying edits to the core definition. First, the definition
should refer to “non-generator Reactive Power resources,” to make clear that although all generators
provide some reactive power, those that do not meet the criteria of I2-I5 are not included in the BES.
There is ambiguity concerning whether a transformer stepping down from >100 kV to <100 kV is
included or not, though we believe that the SDT intends to exclude such transformers. It is clear that
transformers with two windings >100 kV are included and GSUs for registered generators are
included, but it is somewhat unclear in the current draft whether a 138 kV to 69 kV transformer is
included or excluded. We suggests making it clear that the intent of the SDT is to include (a) GSUs
associated with BES generators and (b) transformers with 2 or more windingwindings >100 kV, and
that other transformers are excluded. We also believe the drafting team intended to exclude all
elements that are not included either under the BES definition and designations or through the
exception process. For the sake of clarity, we suggest that a sentence to that effect be added to the
core definition. Finally, we note that the definition does not currently refer to the existence of the
exception process. We suggest that such a reference be added either to the core definition or to the
lists of Inclusions and Exclusions. The following is the core definition incorporating the changes: All
Transmission Elements (except transformers) operated at 100 kV or higher, transformers as
described below, Real Power resources as described below, and non-generator Reactive Power
resources connected at 100 kV or higher unless such designation is modified by the list shown below.
The NERC Rules of Procedure provide an Exception Process through which Elements not included in
the BES under this definition and designations may be included in the BES, and Elements included in
the BES under this definition and designations may be excluded from the BES. Elements not included
in the BES either by application of this definition and designations, or through the BES exception
process, are not BES Elements.
Yes
We support I2, but propose clarifying edits. To minimize possible confusion as to the category of
transformers being addressed in I1, and the sufficiency of a single applicable Exclusion, we suggest
the following rewording: “Transformers, including phase angle regulators, and not including generator

step-up (GSU) transformers, with two windings of 100 kV or higher unless excluded under Exclusion
E1 or E3.”
Yes
We support I2 but propose clarifying edits. We understand that the intent is to define the BES
component of qualifying generators as that equipment from the generator terminals through the GSU.
To convey clearly this point, as well as that only generators that are both over 20 MVA and connected
through a GSU with a high side voltage of at least 100 kV are included in the BES, I2 should be
reworded as follows: “Individual generating units greater than 20 MVA (gross nameplate rating)
including the generator terminals, connected through a GSU that has a high-side voltage of 100 kV or
above. A BES generator includes the equipment from the generator terminals through the GSU.”
Yes
I3 contains language similar to I2, and should be similarly reworded, as follows: “Multiple generating
units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating), connected through a common bus operated at a voltage of 100 kV or above. A
BES generating plant includes the equipment from the generator terminals through the respective
GSUs.”
No
We recommend that the SDT exclude Blackstart Units under 20MW and Blackstart Units that are
connected via their GSU to Non-BES Facilities (under 100kV). We believe this would be a minimal
impact on the existing Restoration Plans while increasing the reliability and viability of these
Restoration Plans since the industry would be forced to use only BES facilities as defined by NERC BES
definition. This would force all Blackstart Units to be compliance with all Reliability Standards if this
change is implemented.
No
There is concern over inadvertently including small distribution that has behind-the-meter generation
on a 69 kV loop. We somewhat agree with the concept of Inclusion I5 but suggest a language change
to clarify what we understand to be the drafting team’s intent, that the inclusion is intended to apply
to dispersed wind and solar generating plants, and not, for example, to a radially-connected city with
an aggregate of 75 MW of small generators behind-the-meter. This distinction is appropriate because
such a city cannot have the same impact on the grid as a 75 MW wind farm; loss of the radial
connecting the city to the grid would result in loss of its load as well as its generation, so that the
supply-demand mismatch would be far less significant. We suggest that I5 be revised.
No
The words “described as” should be deleted from the exclusion to avoid confusion. What matters is
how the system is actually connected, not how someone describes it. In addition, “a single
Transmission source” could be defined, and should be generic enough to encompass the various bus
configurations. It is not the case, for example, that each individual breaker position in a ring bus is a
separate Transmission source; in that case, a bus at one voltage level at one substation should be
considered “a single transmission source.” Some examples of configurations that should be
considered a single transmission source for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples 1-6. The
phrase “automatic interrupting device” should be replaced with the phrase “switching device”.” Many
radials are connected to ring buses or breaker-and-a-half schemes where the breakers (automatic
interrupting devices) are within the bus arrangement where the appropriate division between BES and
non-BES is at the disconnect switch as the radial “takes off” from the bus arrangement.
Yes
We understand that E2 is intended to apply only to retail customers’ generation. The exclusion should
therefore be revised to make that limitation clear. Specifically, the first sentence should read: “A
generating unit or multiple generating units that serve all or part of retail customer Load with electric
energy on the retail customer’s side of the retail meter.” In addition, the first condition of exclusion,
(i), "the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or
I3," as written is vague and could be subjectively applied. I2 limits capacity supplied to the BES to
20MVA while I3 limits that capacity to 75MVA. A better way to state the exclusion would be as
follows: (i), "the net capacity provided to the BES does not exceed the retail customer's total
nameplate generation, or 75MVA, whichever is greater,".

Yes
The exclusion refers to groups of Elements that “distribute power to Load rather than transfer bulk
power across the interconnected system.” The use of the term “bulk power” is vague and could be
read incorrectly as a reference to the “bulk-power system,” which is defined in the Federal Power Act
but is not a NERC defined term. If the LDN is connected to the BES at more than one location, there
will by definition be some loop flow. We recommend below that Exclusion 3(d) be revised to quantify
the amount of loop flow that is permissible in an excluded LDN. In the context of the first sentence of
Exclusion E3, less specificity is needed, and the sentence should only be revised for the sake of
accuracy to state: “Groups of Elements operated above 100 kV that are primarily intended to
distribute power to load rather than to transfer power across the interconnected System.” The
exclusion’s reference to connection “at more than one location” is vague. The sentence should be
revised to read “connected to the Bulk Electric System (BES) from more than one Transmission
source solely to improve the level of service to retail customer Load,” and “Transmission source”
should have the same meaning that it does in E1. E3(a) should require that there be switching
devices between the LDN and the BES, not specifically automatic fault-interrupting devices. The term
“separable by” in “Separable by automatic fault interrupting devices” is unclear and should be
reworded. E3(b) To avoid pulling an LDN into the BES based on very small customer-owned
generation (such as rooftop photovoltaics and hospital backup diesel generators) that the utility does
not consider or rely on, or necessarily even know about, the item should be reworded: “Limits on
connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more
than 75 MVA of generation used to meet the resource adequacy requirements of electric utilities.”
E3(d) states “Not used to transfer bulk power.” As noted above, “bulk power” is a vague term. There
will necessarily be some loop flow on a system that is connected to the BES at more than one
location. The amount of permissible loop flow for this purpose needs to be determined and stated in
this item.
Yes
For the sake of clarity, the final sentence should be revised to read as follows: “For purposes of this
exclusion, a “small utility” is an entity that benefits from the utility of the BES, but does not meet the
registry criteria to perform functions in the BES."
No
No
In Ohio, 50 MW is the threshold for siting. Although 20 MW has recently been the criteria for the BES,
if there is no technical justification (a study of some kind) then we highly recommend raising the
threshold for generators to 50 MVA for a single unit. In our experience, registered generators, even
those that have had severe violations, have been routinely classified as not having an impact on the
BES in the enforcement process. Due to this truth, we can not understand the justification for keeping
such a low threshold. We suggest raising the threshold to 50 MVA for single units, unless a technical
study justifies inclusion.
Individual
Michael Jones
National Grid
No
The core definition should be revised to read: Bulk Electric System (BES): All Transmission Elements
operated at 100 KV or higher, unless such designation is modified by the list shown below. The
resulting modified BES shall comprise all Elements deemed necessary for operating an interconnected
electric energy transmission network, but shall exclude any Elements used in the local distribution of
electric energy.
Yes
We would like some clarification regarding three-winding transformers, for example a 345/115/23 kV
transformer. Was the intention to include the 23kV in the new definition of BES? If so, it seems likely
that other 23 kV components on the buswork could be pulled into the definition of BES if it is in the
zone of protection of the transformer.
Yes

Yes
No
We do not feel that blackstart resources and cranking paths should be classified as BES. In several
instances, cranking paths direct the operator to pick up distribution load before moving on to the next
step for stability purposes. These are non-jurisdictional distribution facilities and should not be
considered BES, since they are not necessary to support the reliability of the bulk power system
during normal conditions. The BES definition should cover those facilities that are within FERC’s
jurisdiction and that are needed for operation under both normal and emergency conditions, which
may include some facilities related to black-start and system restoration, but not all. The directives
should not broadly include blackstart resources and facilities on the cranking path in the BES
definition. This is over inclusive. The requirements in NERC standard EOP-005-2 address the SDT’s
interpretation and concern regarding recognition of the reliability impacts and requirements for
blackstart resources and facilities used for system restoration. For example, there could also be small
generators (less than 20 MVA/unit or 75 MVA/plant) or transmission and distribution facilities of 69 kV
or less, which are considered “local”, that are used for system restoration in the cranking path. A BES
inclusion will then subject these generators and facilities, which are “local”, non-jurisdictional facilities
that may be called upon to begin restoring its bulk interconnected counterparts, to comply with the
reliability standards intended for maintaining BES reliability. Including these facilities in the BES
definition will thus discourage smaller generators from providing blackstart capability, and the
transmission facilities from being a part of the cranking path. This may also discourage Transmission
Owners and Operators from identifying multiple blackstart resources and cranking paths to provide
restoration flexibility. This will ultimately undermine reliability. Also, including these types of facilities
in the BES definitions could lead to jurisdictional challenges that could cause uncertainty and delay
the implementation of the new BES definition and divert important industry and regulatory resources.
Because of these reasons, I4 should be removed from the inclusions list.
Yes
No
We feel that there might be some confusion between I1 and E1 because while I1 only includes
transformers with 2 windings greater than 100kV, E1 specifically says a tap must have an automatic
interruption device to be excluded. So, we are concerned that radial tapped lines with a transformer
whose low-side voltage is less than 100kV, but do not have an automatic interruption device are not
excluded. We would like to see some additional clarity in this exclusion to address this situation Does
automatic interruption device only include breakers/circuit switchers? Would a device such as a
motorized loadbreak be considered an automatic interruption device? If motorized loadbreaks are also
considered as an automatic interruption device, then there would be less confusion between E1 and
I1. We also request that this issue be addressed by adding clarity to the exclusion. Another concern is
that this exclusion requirement is restrictive and may have an adverse affect on future transmission
investment for redundant radial supply to improve local load service, for example the addition of a
second line removing the radial status exclusion. Consideration should be given to allowing entities to
build additional transmission without automatically compromising the exclusion status of any given
facilities.
Yes
No
E3.c and E3.d – These two points can be combined into one: Power is intended to flow only into the
LDN. The generation within the LDN shall not exceed the electric real or reactive power demand
within the LDN. The LDN only delivers real or reactive power to load, and is not to be used to transfer
real or reactive power between different locations in the BES. Under no system condition is BES
reliability to be dependent on LDN flow. E3.e - We would like more clarification on flowgates and what
they are. We are interpreting flowgate as the lines that make up defined operational interface, as
defined by the Operations group not the Planning group. Is this the correct interpretation of flowgate?
No

This exclusion is not necessary. Many small utilities (and individual load customers or generation
connections) have more than a single transmission source with a solid tap and, at the same time, be
adequately protected and effectively isolated without any adverse impact on the transmission
network. Such a practice and design is widely used across North America. Hence, we do not agree
that this exclusion is an attempt to address the issue of small utilities. The definition and inclusions
will force many small entities, load customers and generation unit owners to act and register as
Transmission Owners. This may be in conflict with state or provincial regulatory act, Codes and
Licenses, and may lead to jurisdictional challenges that could cause uncertainty and delay in
implementing the new BES definition. Consistent with the FERC Order, the ERO and the SDT should
be aware of these conflicts and should not ignore them The ERO and the SDT address this by
providing explicit but simple provisions in the exception procedure by considering sound technical
exception criteria that is flexible based on demonstration of evidence to justify the element’s
necessity for operation. The only evidence that should be required of small utilities/entities is: •
Regulatory evidence. • Evidence demonstrating that NO adverse reliability impact is afflicted on the
interconnected BES because of their connection.
No
We don’t believe the bright-line core definition and specific inclusions and exclusions prevent
distribution from being considered as BES. Actually, it seems like a lot of distribution will be
considered BES according to the inclusions and exclusions. (E1 may be interpreted to include step
downs if they don't have automatic interruption devices and possibly the tied through distribution
system to the other step-down transformer that doesn't have an automatic interruption device from
the same Transmission source) If the definition is not revised to exclude more distribution, we are
concerned about how the distribution elements that will be considered BES under the new definition
will be classified. The BES definition should not be used to differentiate between transmission and
distribution. It is important for the ERO and the SDT to understand and be consistent with the FERC
Order for these important but complex issues. There could be conflicts with state or provincial
jurisdictions. The ERO and SDT and RoP teams should be aware of these conflicts and not disregard
them, as they will pose many implementation complexities and confusion within the industry, and
may lead to jurisdictional challenges that could cause uncertainty and delay in implementation of the
new BES definition. It is important for the ERO to not put entities in situations where there is some
confusion or conflict. Removing I4, the inclusion regarding blackstart resources and cranking paths,
will prevent distribution from being considered as BES. Also, clarification that step downs which have
one winding which is less than 100 kV but are tapped off of the BES system without an automatic
interruption device are not BES could also prevent distribution from being considered as BES.
Yes
There could be some conflicts with the ISO-NE Pool Transmission Facility (PTF) definition. If
something is considered non-PTF, but is considered BES with this new definition, it could lead to
confusion about which criteria should be applied to these entities and potentially which tariff (non-PTF
or PTF) is truly the correct tariff. We believe adding more clarity as previously mentioned in the other
questions to the definition and excluding I4 and clarifying E1 will minimize these issues.
We are concerned that the proposed definition of BES and specified inclusions reaches farther into the
electric system than the Bulk Power System (BPS) definition. The statutory framework of the Federal
Power and section 215 specifically must govern the definition of BES. It is clear in FERC’s Order No.
743 that BES should not extend further than BPS, therefore the statutory definition of BPS must be
the guide for the SDT’s efforts, particularly with regard to the treatment of local distribution facilities.
The BPS definition includes (1) facilities and control systems necessary for operating an
interconnected electric energy transmission network; and (2) electric energy from generation facilities
needed to maintain transmission system reliability. It does not include facilities used in the local
distribution of electric energy. The definition of BES must comply with the statutory definition. First,
the facilities and control systems to be included within the BPS/BES must be necessary for operating
an interconnected electric transmission network. Therefore, one question to consider for each of the
proposed inclusions and exclusions is “are they necessary?” A particular facility or element should not
included in the BES definition just because it would be desirable to have the facility considered BES or
covered by a particular standard. Imposing a requirement that all contiguous elements be included is
too broad and may sweep in facilities to the BES definition that are statutorily excluded because they
are not necessary. Second, both the transmission and the generation facilities included within the
BPS/BES must be tied to maintaining the reliable operation of the BPS. Section 215 defines the term

“reliable operation” as “operating the elements of the bulk-power system within equipment and
electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or
cascading failures of such system will not occur as a result of a sudden disturbance, including a
cybersecurity incident, or unanticipated failure”. The statute does not require that there be no loss of
load. The statute is aimed at avoiding uncontrolled separation or cascading failures. Therefore, the
definition of BES should only include elements that are necessary to prevent these occurrences.
Group
Edison Electric Institute
Barbara Hindin

No
EEI believes that the entire designated cranking path should not be included in the BES definition if it
would include facilities that are less than 100 kV on the path. Including such facilities may
inappropriately include some facilities that are local distribution facilities, which are under state
jurisdiction. These facilities might be swept into the definition of BES without an inquiry as to whether
or not the facilities are “facilities used in local distribution of electric energy,” which is an explicit
exclusion under the Federal Power Act definition of “Bulk-Power System.” This issue is more fully
discussed in EEI’s response to Question 13.
Yes
EEI suggests that the following language more clearly expresses the intent of the SDT: Dispersed
power producing resources with aggregate capacity greater than 75 MVA gross aggregate nameplate
rating) utilizing a collector system from the point where the aggregate rating exceeds 75 MVA through
a common point of interconnection to a system Element at a voltage o 100 kV or above.
No
EEI suggests the following change to E1: Any radial system which is described as connected from a
single Transmission source [Delete "originating with an automatic interruption device"] and:

See comments to Question 13.
See comments to Question 13.
Comments: EEI appreciates the efforts of the SDT and offers these comments to help guide its
efforts. EEI believes that the statutory framework of the Federal Power Act and Section 215
specifically must govern the definition of BES. While FERC has declined to further define the term
“Bulk-Power System” (“BPS”) and suggested in Order No. 743 that the BPS “reaches farther than
those facilities that are included” in the BES, it is clear that the BES cannot extend further than the
BPS, and therefore the statutory definition of BPS must be the guide for the SDT’s efforts, particularly
with regard to the treatment of local distribution facilities. The BPS definition in Section 215 includes:
(1) facilities and control systems necessary for operating an interconnected electric energy
transmission network; and (2) electric energy from generation facilities needed to maintain
transmission system reliability. But the term BPS does not include facilities used in the local
distribution of electric energy. The definition of BES must comply with the statutory definition. EEI
points to several issues to which it believes the SDT should pay particular attention. First, the facilities
and control systems to be included within the BPS/BES must be necessary for operating an
interconnected electric transmission network. Therefore, each of the proposed inclusions and
exclusions must be measured against this requirement – are they necessary? It is insufficient to
include a particular facility or element within the BES definition merely because it would be desirable
to have such a facility covered under the BES or a particular standard. In addition, EEI believes that
imposing a requirement that all contiguous elements be included is too broad and may sweep in
facilities to the BES definition that are statutorily excluded because they are not necessary. For
example, while blackstart resources may be “necessary,” including all facilities that are contiguous

between a particular blackstart resource and the transmission system is likely to include elements
that are not “necessary” to the operation of the interstate transmission network and therefore not
within the statutory definition. As a general rule, EEI believes it is appropriate to include contiguous
elements or facilities above 100kV necessary for operating the interconnected transmission network,
but not any below 100 kV unless the element is necessary to operate the interconnected transmission
network. There is no reason to require a “contiguous” BES down to the local distribution facility level.
Section 215 gives NERC and FERC jurisdiction over “users, owners and operators” of the BPS.
Therefore, FERC has authority to require an entity that is not a BES facility to comply with applicable
NERC requirements where necessary for BPS reliability. This approach would achieve the goals of BPS
reliability without extending the full reach of BES applicability to facilities that may be local
distribution facilities that are excluded from Section 215. Second, both the transmission and the
generation facilities included within the BPS/BES must be tied to maintaining the reliable operation of
the BPS. Section 215 defines the term “reliable operation” as “operating the elements of the bulkpower system within equipment and electric system thermal, voltage, and stability limits so that
instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a
sudden disturbance, including a cybersecurity incident, or unanticipated failure. The statute does not
require that there be no loss of load. The statute is aimed at avoiding uncontrolled separation or
cascading failures. Therefore, consistent with the statute, the definition of BES should only include
elements that are necessary to prevent these occurrences. Third, the statute contains a specific
exclusion for facilities used in the local distribution of electric energy (“local distribution facilities”).
FERC has agreed in Orders No. 743 and 743-A that local distribution facilities are not subject to
Section 215. FERC, as the agency implementing Section 215, has the authority to interpret what that
means. In Order 743-A, FERC left it to NERC, and therefore to the SDT, to determine in the first
instance which facilities are local distribution and therefore excluded and whether or not to use tests
such as the Seven Factor Test from Order No. 888. Order No. 888 set out seven indicators, a
combination of functional and technical tests, to assist companies and state commissions with
separating local distribution facilities from FERC jurisdictional transmission facilities on a case by case
basis. The seven factors are: (1) Local distribution facilities are normally in close proximity to retail
customers; (2) Local distribution facilities are primarily radial in character; (3) Power flows into local
distribution systems; it rarely, if ever, flows out; (4) When power enters into a local distribution
system, it is not reconsigned or transported on to some other market; (5) Power entering a local
distribution system is consumer in a comparatively restricted geographical area; (6) Meters are based
at the transmission/local distribution interface to measure flows into the local distribution facilities;
and (7) Local distribution systems will be of reduced voltage. EEI acknowledges that the Seven Factor
test does not draw a bright line between facilities used in local distribution and transmission facilities
and may not be a perfect fit for applying to specific pieces of equipment as the SDT has tried to do.
However, many state commissions have made determination of what are local distribution facilities
and FERC has concurred with these determinations. Therefore, EEI proposes that if NERC or FERC
seek to include facilities (or class of facilities) in the BES that have been previously determined by a
state commission to be local distribution through application of the Seven Factor Test, that there is a
rebuttable presumption that these are facilities used in local distribution for purposes of the BES
definition. In order to overcome this presumption, NERC/FERC must make a showing demonstrating
that these facilities “necessary” for the reliable operation of the BPS. EEI will address this and a
procedure for seeking exclusion of facilities that previously have been determined to be local
distribution in its comments to be submitted on the exceptions process. In applying the statutory
exclusion for local distribution facilities, the SDT should ensure that the inclusions do not include local
distribution facilities and that the exclusions are sufficient to exclude local distribution facilities.
Similarly, it is not sufficient to include an element that would otherwise be a local distribution facility
merely to support a facility clearly within the BES. For example, the SDT should consider the how the
proposed criteria would classify types of equipment such as distribution voltage equipment – some,
such as cap banks in a generation switchyard do support the transmission system versus a regulator
on a distribution feeder – the former may be part of the BES and the latter unlikely or not at all.
Individual
Bud Tracy
Blachly Lane Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of

the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local

distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”

Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
The inclusion of individual generation units with a nameplate capacity as small as 20 MVA is overinclusive. Under FPA Section 215, generation resources are excluded from the “bulk-power system”
unless they produce “electric energy” that is “needed to maintain transmission system reliability.” 16
U.S.C. § 824o(a)(1)(B). Smaller generators with a capacity of 20 MVA almost never produce
electricity that is “needed to maintain transmission system reliability.” Hence, the inclusion as drafted
would improperly expand the BES definition to include generators that the statute requires to be
excluded. Further, the 20 MVA threshold appears to have been drawn without explanation from the
existing NERC Statement of Compliance Registry. Given that the purpose of the Compliance Registry
is to sweep in all generators that might be material to the operation of the BES, and not to definitively
determine whether a given generator is, in fact, material to the operation of the BES, the STD has
acted arbitrarily and without adequate technical justification in adopting the 20 MVA threshold. The
100 MVA threshold seems more in alignment with technical standards such as Power System
Stabilizer requirements. In responding to comments on its initial proposal, the SDT states that it
adopted the 20 MVA threshold because “there is no technical basis to change the values contained in
the Statement of Compliance Registry Criteria.” Consideration of Comments on Definition of Bulk
Electric System – Project 2010-17, March 30, 2011, at 30. But this gets the equation backwards. The
SDT must have some technical justification for adopting the 20 MVA threshold beyond the fact that it
was previously adopted by NERC in a different context. Without a technical justification demonstrating
that facilities operating at capacities as low as 20 MVA are “needed to maintain transmission system
reliability,” the proposed definition is overly broad and fails to comply with the restrictions imposed by
Congress in FPA Section 215(a)(1), 16 U.S.C. § 8240(a)(1). Further, the Statement of Compliance
Registry was adopted without the benefit of having been vetted through the NERC Standards
Development Process, so the technical record underlying the choice of that threshold is unavailable
for review by the industry. In the same comments, the SDT also states that it has considered “the
inclusion of generator step-up (GSU) transformers and associated interconnection line leads and
believes the BES must be contiguous at this level in order to be reliable.” Id. The SDT’s reasons for
reaching this conclusion are not well-explained, but apparently the concern is that a “non-contiguous”
BES could create “reliability gaps.” This conclusion cannot be supported as an abstract proposition,
but can only be demonstrated by a careful examination how application of reliability standards will
change depending on how the BES is defined. We believe that if the SDT insists on a “contiguous”
BES, an over-inclusive definition will result. We base these conclusions on the findings of NERC’s
Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO Task Force.” The
Project 2010-07 Team was formed to address how the dedicated interconnection facilities linking a
BES generator to high-voltage transmission facilities should be treated under the NERC standards.
After reviewing these questions in considerable depth, the Team concluded that dedicated highvoltage interconnection facilities need not be treated as “Transmission” and classified as part of the
BES in order to make reliability standards effective. On the contrary, the team concluded that by
complying with a handful of reliability standards, primarily related to vegetation management, reliable
operation of the bulk interconnected system could be protected without unduly burdening the owners
of such interconnection systems. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the predecessor of the

Project 2010-07 SDT). Much of the work of the Project 2010-07 SDT is applicable to the work of the
BES Standards Development Team. For example, the Project 2010-07 Team observed that
interconnection facilities “are most often not part of the integrated bulk power system, and as such
should not be subject to the same level of standards applicable to Transmission Owners and
Transmission Operators who own and operate transmission Facilities and Elements that are part of
the integrated bulk power system.” White Paper Proposal for Information Comment, NERC Project
2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011). Requiring
Generation Owners and Operators to comply with the same standards as BES Transmission Owners
and Operators “would do little, if anything, to improve the reliability of the Bulk Electric System,”
especially “when compared to the operation of the equipment that actually produces electricity – the
generation equipment itself.” Id. We believe the many of the questions considered by the Project
2010-07 Team are analogous to the questions under consideration by the SDT, and that, if the SDT
insists upon a “contiguous” BES, the resulting definition will be substantially over-inclusive. The
“contiguous” BES concept implies that every Element arguably necessary for the reliable operation of
the interconnected bulk system must be included in the BES definition, even if it is interconnected
with Elements that have no bearing on the operation of the BES. The adoption of a “contiguous” BES
is therefore likely to result in imposition of reliability standards on a substantial number of facilities
that have little or nothing to do with bulk system reliability, resulting in wasted regulatory expense
and additional stress on the limited resources of reliability regulators. For example, a “contiguous”
BES would require dedicated interconnection facilities that connect a BES generator to BES
transmission facilities to be classified as BES. But, as the discussion above demonstrates, the
classification of dedicated interconnection facilities as “BES” facilities would, based on the findings of
the Project 2010-07 SDT, result in substantial overregulation and unnecessary expense with little gain
for bulk system reliability. Similarly, a “contiguous” BES suggests that, because certain system
protection facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the
local distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” Such a result is not only plainly contrary to the local distribution exclusion embedded in
Section 215 of the FPA, but would, by improperly classifying local distribution lines as BES
“Transmission” facilities, result in huge regulatory compliance burdens with little or no improvement
in bulk system reliability. There is no good reason for the SDT to adopt a “contiguous” BES. On the
contrary, because Section 215 allows reliability standards to be applied to “users” of the bulk system
as well as “owners” and “operators,” local distribution systems operating UFLS relays and other bulk
system protection devices could be required to comply with standards governing those devices as a
precondition for their use of transmission on the bulk system. For these reasons, we urge the SDT to
follow the example of the Project 2010-07 Team and the GO-TO Task Force by giving careful
consideration to the specific and practical results of how its definition will affect the application fo
particular reliability standards and whether the results are beneficial to reliability or simply result in
unnecessary regulatory burdens that do not benefit bulk system reliability. We believe there is
considerable danger of error if the SDT bases its conclusions on metaphysical debates about whether
a “contiguous” or “non-contiguous” BES is more desirable rather than engaging in a careful analysis of
whether the proposed definition achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold
seems more in alignment with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.

As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Paul Titus
Northern Wasco County PUD
No
As a general matter, Northern Wasco County PUD supports the approach the Standards Development
Team (“SDT”) has taken to defining the Bulk Electric System (“BES”). The changes made in the
revised core definition are helpful and represent significant progress toward an acceptable definition.
With an effective and efficient exclusion process, the draft will better define the BES as a whole. We
urge the SDT to bear in mind the restrictions contained in Section 215 of the Federal Power Act
(“FPA”) The “bulk-power system” (As per FERC, we treat the statutory term “bulk-power system” as
equivalent to the term ordinarily used in the industry, “Bulk Electric System”) definition imposes a
clear limit on the reach of the mandatory reliability regime. The BES is made up of only those
“facilities and control systems necessary for operating an interconnected electric energy transmission
network (or any portion thereof)” and “electric energy from generation facilities needed to maintain

transmission system reliability.” Congress reinforced that limit in Section 215(i), where it emphasized
that the FPA authorizes the imposition of reliability standards “for only the bulk-power system.”
Northern Wasco County PUD is concerned that the SDT’s proposed definition is overly-broad, and that
it will sweep in many Elements that have little or no material impact on the reliable operation of the
interconnected bulk transmission grid. For example, the definition uses the arbitrary 20 MVA
threshold from the NERC Statement of Registry Criteria for inclusion of generators. Accordingly, for
the BES definition to conform to the requirements of the statute, the SDT must adopt an effective
mechanism to exempt facilities like these that are improperly swept in by the SDT’s brightline
approach to inclusions and exclusions. For this reason, the Exception process to accompany the SDT’s
definition is of critical concern. If the SDT incorporates this statutory language as its core definition, it
will have addressed FERC’s primary concern with a minimum of disruption to the current NERC
system of definitions. The definition could then be further elaborated to show specific points of
demarcation for each inclusion and exclusion similar to that Proposal 6 from the WECC Bulk Electric
System Definition Task Force (“BESDTF”) team to further delineate BES and non-BES facilities.
No
In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and nonBES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is
stepped down from transmission voltages to distribution voltages. We believe, however, that the SDT
should undertake the effort to more clearly define the point where the BES ends and non-BES
systems begin. In this regard, we note that the WECC Bulk Electric System Definition Task Force
(“BESDTF”) has devoted considerable effort to this question and has developed one-line diagrams
noting the BES demarcation point for a number of different kinds of Elements that are common in the
Western Interconnection. Using this work as a starting point, the SDT should be able to provide much
useful guidance to the industry with relatively little additional effort. Also, the reference to “two
windings of 100 kV or higher” may create some confusion because many three-phase transformer
banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We suggest
clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”
We again urge the SDT to consider further delineation of points of demarcation similar to WECC
BESDTF Proposal 6.
No
Northern Wasco County PUD is concerned that I2 inclusion criteria that includes the arbitrary 20 MVA
threshold from the NERC Statement of Registry Criteria for inclusion of generators is over-inclusive.
Under FPA Section 215, generation resources are excluded from the “bulk-power system” unless they
produce “electric energy” that is “needed to maintain transmission system reliability.” Hence, the
inclusion as drafted improperly expands the BES definition to include generators that the statute
requires to be excluded. In the same comments, the SDT also states that it has considered “the
inclusion of generator step-up (GSU) transformers and associated interconnection line leads and
believes the BES must be contiguous at this level in order to be reliable.” Unfortunately, the SDT
appears to have concluded that any interconnection facility operating above 100-kV should be
classified as BES. The result will be to require Generation Owners to register as Transmission
Owners/Operators, as well, producing substantial additional compliance costs for those Generation
Owners but resulting in little or no improvement in the reliability of the BES. We recommend that the
SDT, like the Project 2010-07 SDT (commonly referred to as the GO/TO Team), give careful
consideration to the practical results of its recommendations rather than relying on abstract
conclusions about whether a “contiguous” or “non-contiguous” BES is more desirable. We are
concerned that the SDT’s pursuit of a “contiguous” BES will result in a substantially over-inclusive BES
definition. The “contiguous” BES concept implies that every Element arguably necessary for the
reliable operation of the interconnected bulk system must be included in the BES definition, even if it
is interconnected with Elements that have no bearing on the operation of the BES. NERC’s Standards
Drafting Team for Project 2010-07, has already considered this question and, based on an in-depth
review of potentially applicable reliability standards, has concluded that generation interconnection
facilities, even if operated above 100-kV, need to comply only with a limited set of reliability
standards in order to achieve the reliability goals. Much of the work of the Project 2010-07 SDT is
applicable to the work of the BES Standards Development Team. For example, the Project 2010-07
Team observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to Transmission

Owners and Transmission Operators who own and operate transmission Facilities and Elements that
are part of the integrated bulk power system.” Similarly, a “contiguous” BES suggests that, because
certain system protection facilities, such as UFLS relays, are ordinarily embedded in local distribution
systems, the local distribution system, along with the UFLS relays, must be classified as BES to make
the BES “contiguous.” Such a result is not only plainly contrary to the local distribution exclusion
embedded in Section 215 of the FPA, but would, by improperly classifying local distribution lines as
BES “Transmission” facilities, result in huge regulatory compliance burdens with little or no
improvement in bulk system reliability.
No
Northern Wasco County PUD is concerned that the 75 MVA threshold has been chosen arbitrarily by
the SDT. Like the 20 MVA threshold discussed in our response to question 3, the 75 MVA threshold
appears to have been drawn from the NERC Statement of Compliance Registry without appreciation
for the function of the threshold in that document and without adequate technical justification
demonstrating the generators with an aggregate capacity of 75 MVA produce electric energy “needed
to maintain transmission system reliability” and are therefore properly included in the BES definition.
Yes
Including “all” blackstart and blackstart cranking paths in the BES may ultimately provide an incentive
to the electric industry to reduce the number of resources with blackstart capability. We therefore
suggest that essential blackstart resources identified by the Regional Entity should be included in the
Bulk Electric System, but non-essential blackstart resources need not be.
No
Northern Wasco County PUD agrees that it is important to address wind generation facilities and
similar generation facilities in which a large number of generating units, each with a relatively small
capacity, are clustered and fed into the grid at a single interconnection point. That being said,
Northern Wasco County PUD is concerned that the 75 MVA threshold has been chosen arbitrarily for
the reasons stated in our comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained. We believe the exclusion as drafted adequately defines radials.
No
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through
reference to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the
generation unit is reliability-must-run or essential blackstart, the function of the unit is irrelevant to
the reliable operation of the interconnected bulk transmission grid, and we therefore believe the
reference to the function of the generation unit (“standby, back-up, and maintenance power…”)
should be eliminated.
Yes
Northern Wasco County PUD strongly supports the categorical exclusion of Local Distribution
Networks from the BES. In fact, for reasons discussed at length in our answer to Question 1, we
believe the exclusion is necessary to ensure that the BES definition complies with the statutory
requirement to exclude all facilities used in the local distribution of electric power. LDNs are, of
course, probably the most common kind of local distribution facility. Further, the conversion of radial
systems to local distribution networks should be encouraged because networked systems generally
reduce losses, increase system efficiency, and increase the level of service to retail customers.
Northern Wasco County PUD supports the LDN exclusion, but we believe the exclusion should be
refined in the following respects: • The SDT’s draft states that: “LDN’s are connected to the Bulk
Electric System (BES) at more than one location solely to improve the level of service to retail
customer Load.” (emphasis added) We recommend that the SDT revise the sentence quoted above as
follows: “LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to
improve the level of service to retail customer Load and not to accommodate bulk transfers of power
across the interconnected bulk system.” By instituting this suggestion, the SDT would emphasize the
key difference between an LDN, which is designed to reliably serve local, end-use retail customers,
and the BES, which is designed to accommodate bulk transfer of power at wholesale over long
distances.
Yes

Northern Wasco County PUD supports the SDT in its efforts to avoid unintended consequences from
changes to the BES definition, especially for small entities that can ill afford the substantial costs that
accompany imposition of mandatory compliance with reliability standards. Further, we agree that the
small utilities covered by the exemption will have no measurable impact on the operation of the
interconnected BES. In the Pacific Northwest, many small entities were required to register by virtue
of owning a very small portion of the region’s 115-kV system. These utilities have faced substantial
compliance burdens even though their operations are simply not material to the interconnected bulk
grid in our region, and the investment of resources in compliance therefore will have no measurable
effect in improving the reliability of the interconnected grid.
No
While Northern Wasco County PUD agrees that the approach adopted by the SDT -- a core definition
coupled with specific inclusions and exclusions – will be effective in removing most local distribution
facilities from the BES, it will not remove all such facilities. For the reasons discussed at greater
length in our answer to Question 1, Northern Wasco County PUD believes that the proposed definition
is over-inclusive and is likely to sweep up certain facilities used in local distribution that should not be
classified as BES. As discussed in our answer to Question 3, Northern Wasco County PUD notes that
exclusion of facilities from the BES does not mean that owners of those facilities are entirely exempt
from reliability standards. On the contrary, the statute provides that “users” of the BES can be subject
to reliability regulation. Hence, even where an entity does not own BES assets, it could be required to,
for example, provide necessary information to the applicable Reliability Coordinator and to participate
in the regional Under-Frequency Load Shedding program by setting the UFLS relays in its Local
Distribution Network at the appropriate settings. We note that participants in the WECC BESDTF Task
Force generally agreed that appropriate information should be provided by non-BES entities, although
there was considerable concern related to ensuring that the provision of information was not unduly
burdensome.
Yes
The Exceptions process is a necessary part of making this proposal complaint with the Federal Power
Act. As noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is
potentially in conflict with the limitations of the Federal Power Act, and in particular the statutory
exclusion for facilities used in the local distribution of electric energy. The SDT’s approach can meet
the statutory requirements only if the Exception process currently under development results in
facilities that are not properly classified as BES being exempted from regulation as BES facilities.
Northern Wasco County PUD has these additional concerns: • The current definition provides that
“Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.” Northern Wasco County PUD is concerned that the SDT carefully delineate which
entity has the burden of proof in the exclusion process. The WECC BESDTF approach, which we
commend to the SDT, laid out these burdens in some detail. Under that approach, essentially, if a
facility is excluded from the BES by virtue of the specific exclusions listed in the definition, the
Regional Entity bears the burden of proving that the facility nonetheless has a material impact on the
interconnected bulk transmission system and therefore should be included in the BES. On the other
hand, if a facility is classified as BES by virtue of the list of inclusions set forth in the BES definition, it
can still escape classification as BES, but bears the burden of demonstrating that its facility has no
material impact on the interconnected transmission system. We urge the SDT to give careful
consideration to these burden-of-proof questions and to follow the lead of the WECC BES Task Force.
• For the reasons we have explained in our answer to Question 11, we believe the Exception process
is critical both to ensure that the BES definition is effective in producing measurable gains to bulk
system reliability and to ensuring that the definition will comply with the limitations Congress placed
in Section 215. Hence, we believe the entire BES definition, including the Exception process and
related procedures, should be vetted through the NERC Standards Development Process, including
the full comment periods and a ballot approvals provided for in that process. We are concerned that
important elements of the BES definition have been assigned to the Rules of Procedure Team, and
that changes in the Rules of Procedure are subject to approval in a process that provides considerably
less due process and industry input than the Standards Development Process. Accordingly, we urge
that all elements of the BES definition, including those elements that have been assigned to the Rules
of Procedure Team, be vetted through the Standards Development Process.
Individual
Bill Dearing

PUD No. 2 of Grant County, Washington
Yes
Grant supports the approach the Standards Development Team (“SDT”) has taken to defining the
Bulk Electric System (“BES”). The changes made in the revised core definition are helpful and
represent significant progress toward an acceptable definition. With an effective and efficient
exclusion process, the draft will better define the BES as a whole. The definition could then be further
elaborated to show specific points of demarcation for each inclusion and exclusion similar to that
Proposal 6 from the WECC Bulk Electric System Definition Task Force (“BESDTF”) team to further
delineate BES and non-BES facilities.
Yes
Grant supports the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. In I1 the transformer inclusion specifies “two windings greater than 100 kV or”. This
appears to leave auto transformers out of the definition entirely. If the intent is to include these
transformers, then more clarity might be available if it was revised to “at least two sets of bushings
rated higher than 100 kV unless…” Inclusion I-1 is helpful because it implies that the BES ends where
power is stepped down from transmission voltages to distribution voltages. We believe, however, that
the SDT should undertake the effort to more clearly define the point where the BES ends and nonBES systems begin. In this regard, we note again that the WECC BESDTF has devoted considerable
effort to this question and has developed one-line diagrams noting the BES demarcation point for a
number of different kinds of Elements that are common in the Western Interconnection. Using this
work as a starting point, the SDT should be able to provide much useful guidance to the industry with
relatively little additional effort.
No
In the same comments, the SDT also states that it has considered “the inclusion of generator step-up
(GSU) transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable.” Unfortunately, the SDT appears to have concluded
that any interconnection facility operating above 100-kV should be classified as BES. The result will be
to require Generation Owners to register as Transmission Owners/Operators, as well, producing
substantial additional compliance costs for those Generation Owners but resulting in little or no
improvement in the reliability of the BES. We recommend that the SDT, like the Project 2010-07 SDT
(commonly referred to as the GO/TO Team), give careful consideration to the practical results of its
recommendations rather than relying on abstract conclusions about whether a “contiguous” or “noncontiguous” BES is more desirable. We are concerned that the SDT’s pursuit of a “contiguous” BES
will result in a substantially over-inclusive BES definition. The “contiguous” BES concept implies that
every Element arguably necessary for the reliable operation of the interconnected bulk system must
be included in the BES definition, even if it is interconnected with Elements that have no bearing on
the operation of the BES. A “contiguous” BES suggests that, because certain system protection
facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the local
distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” The improper classification of local distribution lines as BES “Transmission” facilities
results in huge regulatory compliance burdens with little or no improvement in bulk system reliability.
Yes
Grant supports this proposed inclusion.
Yes
Grant supports this proposed inclusion with the caveat that the BES should be allowed to be noncontiguous, especially in this case, if the unit is low voltage.
Yes
Grant agrees that it is important to address wind generation facilities and similar generation facilities
in which a large number of generating units, each with a relatively small capacity, are clustered and
fed into the grid at a single interconnection point.
Yes
E1 specifically states “Any radial system which is described as connected from a single transmission
source originating with an automatic disconnection device and…”. The example of concern is a radial
tap to a single distribution power transformer that is connected to a ring bus or breaker and a half
bus. In this case the transformer would have 2 automatic disconnection devices from what is

essentially a single source. Typically ring bus and breaker and a half bus are used to improve
reliability, limiting the exclusion to a single disconnecting device appears to bring a hypothetical radial
tap fed from a ring bus or breaker and a half bus into the BES definition. Although the LDN exclusion
might apply there is the potential for many situations where it might not. A possible remedy is to
revise the exclusion as follows: “Any radial system which is described as connected from a single
transmission source that originates with automatic disconnection device(s) and…” In addition, a
definition for “a single transmission source” should be provided to clarify the intent. Suggestion: “A
single transmission source would be any transmission source located within a single facility, yard or
fenced area and electrically continuous at a single voltage level”.
Yes
Unless the generation unit is reliability-must-run or essential blackstart, the function of the unit is
irrelevant to the reliable operation of the interconnected bulk transmission grid, and we therefore
believe the reference to the function of the generation unit (“standby, back-up, and maintenance
power…”) should be eliminated.
Yes
Grant supports the categorical exclusion of Local Distribution Networks from the BES. We believe the
exclusion is necessary to ensure that the BES definition complies with the statutory requirement to
exclude all facilities used in the local distribution of electric power. LDNs are, of course, probably the
most common kind of local distribution facility. Further, the conversion of radial systems to local
distribution networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. Grant supports the
LDN exclusion, but we believe the exclusion should be refined in the following respects: • The SDT’s
draft states that: “LDN’s are connected to the Bulk Electric System (BES) at more than one location
solely to improve the level of service to retail customer Load.” (emphasis added) We recommend that
the SDT revise the sentence quoted above as follows: “LDN’s are connected to the Bulk Electric
System (BES) at more than one location solely to improve the level of service to retail customer Load
and not to accommodate bulk transfers of power across the interconnected bulk system.” By
instituting this suggestion, the SDT would emphasize the key difference between an LDN, which is
designed to reliably serve local, end-use retail customers, and the BES, which is designed to
accommodate bulk transfer of power at wholesale over long distances. Two more suggestions: Bullet
d, starts with “bulk power” and ends with generic “energy” transferred through and out of the LDN.
This is inconsistent and will likely lead to confusion. In addition, “paper only” contract path transfers
that result in no physical flow across the LDN should be specifically excluded.
Grant supports the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that can ill afford the substantial costs that accompany
imposition of mandatory compliance with reliability standards. Further, we agree that the small
utilities covered by the exemption will have no measurable impact on the operation of the
interconnected BES. In the Pacific Northwest, many small entities were required to register by virtue
of owning a very small portion of the region’s 115-kV transmission. These utilities have faced
substantial compliance burdens even though their operations are simply not material to the
interconnected bulk grid in our region, and the investment of resources in compliance therefore will
have no measurable effect in improving the reliability of the interconnected grid.
Yes
Grant supports the concepts as presented in the draft. Exclusion of facilities from the BES does not
mean that owners of those facilities are entirely exempt from reliability standards. The statutes
provide that “users” of the BES can be subject to reliability regulation. Hence, even where an entity
does not own BES assets, it could be required to, for example, provide necessary information to the
applicable Reliability Coordinator and to participate in the regional Under-Frequency Load Shedding
program by setting the UFLS relays in its Local Distribution Network at the appropriate settings. We
note that participants in the WECC BESDTF Task Force generally agreed that appropriate information
should be provided by non-BES entities, although there was considerable concern related to ensuring
that the provision of information was not unduly burdensome.
Yes
The Exceptions process is a necessary part of making this proposal complaint with the Federal Power
Act. The SDT’s approach can meet the statutory requirements only if the Exception process currently
under development results in facilities that are not properly classified as BES being exempted from

regulation as BES facilities.
Grant has these additional concerns: • We are concerned that the proposed 24-month delay in the
effective date of the new definition will delay the potentially beneficial effects of the SDT’s efforts,
especially for utilities that have been inappropriately required to meet BES reliability standards, which
is a common situation in WECC. We therefore urge the new BES definition become effective
immediately upon approval by FERC or other applicable regulatory agencies. Entities that have been
improperly required to meet standards can then immediately redirect resources to where they are
truly needed. For entities that have not previously been registered for BES-related functions but that
would be required to register under the new definition, we agree that 24 months is an appropriate
transition period to allow the newly-registered entity to attain compliance with newly-applicable
reliability standards, many of which require new training for employees, new maintenance
procedures, and complex new operational protocols. However, the transition period for newlyregistered entities should be structured in a way that does not prevent entities seeking deregistration
from benefitting from the new definition at the earliest possible date. • The current definition provides
that “Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.” Grant is concerned that the SDT carefully delineate which entity has the burden of
proof in the exclusion process. The WECC BESDTF approach, which we commend to the SDT, laid out
these burdens in some detail. Under that approach, essentially, if a facility is excluded from the BES
by virtue of the specific exclusions listed in the definition, the Regional Entity bears the burden of
proving that the facility nonetheless has a material impact on the interconnected bulk transmission
system and therefore should be included in the BES. On the other hand, if a facility is classified as
BES by virtue of the list of inclusions set forth in the BES definition, it can still escape classification as
BES, but bears the burden of demonstrating that its facility has no material impact on the
interconnected transmission system. We urge the SDT to give careful consideration to these burdenof-proof questions and to follow the lead of the WECC BES Task Force.
Group
Small Entity Working Group (SEWG)
Scott Berry
Yes
The Small Entity Working Group (SEWG) appreciates the opportunity to comment on the draft BES
definition. The group generally supports the direction taken by the SDT, with some minor changes.
The BES definition should refer to “non-generator Reactive Power resources,” to clarify that although
all generators provide some reactive power, the generators that do not meet the criteria of I2 through
I5 are not included in the BES. The BES definition should include a reference to the existence of the
exception process.
No comment.
Yes
Yes, with a minor clarification. Individual generating units greater than 20 MVA (gross nameplate
rating) including the generator terminals through the GSU which has a high side connection voltage of
100 kV or above. This should help state that only generators that are both over 20 MVA and
connected through a GSU with a high side voltage of at least 100kV are included in the BES.
No comment.
No
The SEWG proposes a minor change to Inclusion I4. The SEWG recommends that the SDT exclude
Blackstart Units under 20MW and Blackstart Units that are connected via their GSU to Non-BES
Facilities (under 100kV). We believe this would be a minimal impact on the existing Restoration Plans
while increasing the reliability and viability of these Restoration Plans since the industry would be
forced to use only BES facilities as defined by NERC BES definition. In addition, a clarification is
needed under the first bullet under I4 in the posted word comment form for this BES draft (posted in
the first column under Implementation Plan for Definition). It should be changed to read "Blackstart
units that have been included in the Transmission Operator’s restoration plan and their respective
cranking paths..." We do not believe it was the intent of the SDT to include all blackstart units in the
BES definition regardless if they are not part of a Transmission Operator's restoration plan.
No Comment
Yes

Yes, with some minor changes. Delete the words “described as” in the sentence: Any radial system
which is described as connected from a single Transmission source originating with an automatic
interruption device and. How the radial system is actually connected is important not the description.
The SEWG believes that “a single Transmission source” should be defined in such a way to ensure all
the various bus configurations are captured. The SEWG recommends modifying the language in E1 to
allow for the use of a “switching device” rather than an “automatic reclosing device” for two specifics
situations as follows: 1) When a radial transmission line is feed from a ring bus, but only serve load
and/or non-registered generation: 2) When a radial transmission line is feed from a breaker and half
bus and it only serves load and/or non-registered generation. In both cases, faults on the radial
transmission line will not interrupt network transmission flows and therefore has minimal impact on
the BES. For direct connection of radial transmission lines to a networked transmission line, the SEWG
agrees that an automatic interrupting device is required to protect the BES.
No Comments
Yes
Yes, with some clarifying edits. The first sentence of Exclusion 3 should be revised for accuracy as
follows: “”Local Distribution Networks (LDN): Groups of Elements operated above 100 kV that are
primarily intended to distribute power to Load rather than to transfer bulk power across the
Interconnected System.” The second sentence should be revised for clarity as follows: “LDN’s are
connected to the Bulk Electric System (BES) from more than one Transmission source solely to
improve the level of service to retail customer Load.” Exclusion E3 a) should be revised as we note in
our comments in Question#7 to allow for the use of switching devices in specific situations
Yes
Yes, with some clarifying edits. The final sentence should be revised as follows: “For purposes of this
exclusion, a ‘small utility’ is an entity that performs a distribution provider or load serving entity
function but is not required to register as a Distribution Provider or Load Serving Entity by the ERO.”
No comments
No comments
No comments
Group
Idaho Falls Power
Richard Malloy
No
We believe that inclusions or exclusions tied to brightline registration criteria (such as the 20MVA
single generation source or 75 MVA facility) does not fulfill the effort the NERC BES definition project
was tasked to undertake. The current draft's language will draw in many small municipal and other
like entities with small generation assets, which have no material impact upon the BES. Further,
should these generation assets not be excluded, this draft implies that all assets downstream to the
point of interconnection are BES as well regardless of point of connection. We believe it was the
original intent of this definition project to remove such immaterial assets and the undue burden
placed upon such entities and subsequently their rate payers, who have no impact to the BES.
Yes
It seems reasonable to conclude that such transformers would belong in a classification that
comprises the BES.
No
We feel the bright line criteria 20 MVA for generation is equally as arbitrary as the 100KV threshold
for transmission, which was the impetus for the NERC BES definition effort. There should be more
defining criteria to establish what generation resources should be included in the BES. Possible criteria
to consider would be generation serving load other than local load connected to an LDN or generation
that is dispatchable. Surely, just as not all 100 kV is is material to the BES, niether is all 20MVA or
greater generation. If this draft's language is allowed to stand at the brightline of 20MVA, without
additional defining criteria, will have the likely result of an inordinate number of entities having to
resolve the issue of material impact through the Rules of Procedure exemption process. We urge
NERC to take this opportunity now to more clearly define material generation assets beyond a simple
brightline criteria. In addition to our concern of this draft following bright line registry criteria for

generation assets, it is our concern that there is no distinction made as to where the generation is
connected. Our belief is that generation on an LDN wherein the net flow of power is into the LDN
should be exempt as the liklihood of that generation being material to the larger BES is exceedingly
small.
No
Again, following our statement in question 3, we feel an arbitrary brightline threshold requires
additional defining criteria for inclusion. Adopting the registry's brightline criteria is to us skirting the
purpose of the BES definition effort, and lends no more clarity to what is in fact the BES.
Yes
It is reasonable to conclude that Blackstart generation resources are material to the BES.
No
This inclusion seems redundant to the registry criteria for GO/GOP of a facility generation of 75MVA or
greater. We do not see how this definition adds or removes any assets already defined by the registry
criteria.
No
This exclusion speaks to radial systems with generation resouces not identified in I2, I3, I4, or, I5,
thus seemingly only to apply to generation resouces smaller than 20MVA. We wonder why this
exclusion then exists as these resources are already excluded by not being large enough to fall under
the registry criteria, and thus need not comply with the reliability standards.
No
We do not agree with E2(i). If the generation assets listed in the inclusions of I2 and I3 are not
permitted to be excluded in E2, then what is the point of E2? The generation assets would already be
in or out based upon the registry's MVA nameplate capacity. We would support E2 if provision (i) were
struck. If generation assets are behind the meter on a local distribution network (fitting the criteria E3
for exemption) then too the generation should be exempted regardless of MVA rating. Moreover, we
do not agree that there is a brightline MVA threshold of materiality to the BES. We would hope that
the drafting team could demonstrate how the 20MVA brightline is a valid threshold for generation
while the 100kV for transmission is not. We are concerned that relatively small generation on a local
distribution network wherein generation is always serving local retail load behind the meter will be
labelled a BES asset. As such, then is the LDN to the point of interconnection a BES asset as well, and
therefore subject to the suite of TO/TOP standards? We feel such an outcome is unreasonable. It
seems to us, as is stated under section 215 of the FPA, that the term BES "does not include facilities
used in the local distribution of electric energy." To a logical conclusion, the generation attached to
local distribution was considered and is intended to be one of the "facilities" and should therefore be
exempted form inclusion in the BES. However, should the drafting team deem that all generation
above 20MVA are a BES assets, we would hope that the exclusion for Local Distribution Networks
could still stand and that the generation on the LDN would be divorced and defined separately. Our
opinion is the BES is not one large contiguous system, but is rather comprised of assets across the
region, which due to their size or location are vital to a sound BES but are not necessarily connected
to each other. This principle would allow the generation to be regulated yet remove the burden of
transmission standards from small entities.
No
We support this exclusion, however generation assets on a Local Distribution Network should be
excluded regardless of MVA rating if all other defining critera in E3 are met. Additionally, it is unclear
as written whether a single generation asset greater than 20MVA would be excluded as E3(b) states
75 MVA, but is inconsist with E2(i). Some clarification of intent is needed to resolve the ambiguities
between these two exclusions.
No
Just as 100kv is an arbitrary number, so is 20MVA. We appreciate the NERC efforts made to define
transmission material to the BES, and likewise feel the same efforts should be applied to small
generation resources. There exists a large number of utilities with small generation serving local load
on an LDN that will be possibly drawn into TO/TOP standard's compliance by the language in this
draft. We hope the drafting team will define BES generation beyond a brightline criteria, as 20MVA
lends no more clarity as to what is a BES asset than does 100kV. We believe it should be
demonstrated as to why 20MVA is deemed a generation threshold of materiality to the BES. The

opportunity now exists to address thresholds, not just the 100kV.
No
In the exclusions, we feel there has not been given enough clarification of generation assets on a
LDN, specifically, is a single generation resource >20MVA but <75 MVA excluded? This does not seem
clear because of the seeming inconsistencies of E2(i) and E3(b). Further, we believe generation on an
LDN serving local load wherein the net flow is into the LDN should be excluded.
Yes
It is unclear how the reliability standards will be applied to registered entities should some assets be
deemed not to be a part of the BES. As an example; will a an LSE with >25MW of load connected at
161kv be responsible for relay maintenance under PRC-005-1 if the 161 kv is exempted as a local
distribution network? Clarification of this issue may be beyond the scope of the BES definition effort,
however guidance in this area should accompany this effort.
Individual
Dave Markham
Central Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities

and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is

nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
The inclusion of individual generation units with a nameplate capacity as small as 20 MVA is overinclusive. Under FPA Section 215, generation resources are excluded from the “bulk-power system”
unless they produce “electric energy” that is “needed to maintain transmission system reliability.” 16
U.S.C. § 824o(a)(1)(B). Smaller generators with a capacity of 20 MVA almost never produce
electricity that is “needed to maintain transmission system reliability.” Hence, the inclusion as drafted
would improperly expand the BES definition to include generators that the statute requires to be
excluded. Further, the 20 MVA threshold appears to have been drawn without explanation from the
existing NERC Statement of Compliance Registry. Given that the purpose of the Compliance Registry
is to sweep in all generators that might be material to the operation of the BES, and not to definitively
determine whether a given generator is, in fact, material to the operation of the BES, the STD has
acted arbitrarily and without adequate technical justification in adopting the 20 MVA threshold. The
100 MVA threshold seems more in alignment with technical standards such as Power System
Stabilizer requirements. In responding to comments on its initial proposal, the SDT states that it
adopted the 20 MVA threshold because “there is no technical basis to change the values contained in
the Statement of Compliance Registry Criteria.” Consideration of Comments on Definition of Bulk
Electric System – Project 2010-17, March 30, 2011, at 30. But this gets the equation backwards. The
SDT must have some technical justification for adopting the 20 MVA threshold beyond the fact that it
was previously adopted by NERC in a different context. Without a technical justification demonstrating
that facilities operating at capacities as low as 20 MVA are “needed to maintain transmission system
reliability,” the proposed definition is overly broad and fails to comply with the restrictions imposed by
Congress in FPA Section 215(a)(1), 16 U.S.C. § 8240(a)(1). Further, the Statement of Compliance

Registry was adopted without the benefit of having been vetted through the NERC Standards
Development Process, so the technical record underlying the choice of that threshold is unavailable
for review by the industry. In the same comments, the SDT also states that it has considered “the
inclusion of generator step-up (GSU) transformers and associated interconnection line leads and
believes the BES must be contiguous at this level in order to be reliable.” Id. The SDT’s reasons for
reaching this conclusion are not well-explained, but apparently the concern is that a “non-contiguous”
BES could create “reliability gaps.” This conclusion cannot be supported as an abstract proposition,
but can only be demonstrated by a careful examination how application of reliability standards will
change depending on how the BES is defined. We believe that if the SDT insists on a “contiguous”
BES, an over-inclusive definition will result. We base these conclusions on the findings of NERC’s
Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO Task Force.” The
Project 2010-07 Team was formed to address how the dedicated interconnection facilities linking a
BES generator to high-voltage transmission facilities should be treated under the NERC standards.
After reviewing these questions in considerable depth, the Team concluded that dedicated highvoltage interconnection facilities need not be treated as “Transmission” and classified as part of the
BES in order to make reliability standards effective. On the contrary, the team concluded that by
complying with a handful of reliability standards, primarily related to vegetation management, reliable
operation of the bulk interconnected system could be protected without unduly burdening the owners
of such interconnection systems. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the predecessor of the
Project 2010-07 SDT). Much of the work of the Project 2010-07 SDT is applicable to the work of the
BES Standards Development Team. For example, the Project 2010-07 Team observed that
interconnection facilities “are most often not part of the integrated bulk power system, and as such
should not be subject to the same level of standards applicable to Transmission Owners and
Transmission Operators who own and operate transmission Facilities and Elements that are part of
the integrated bulk power system.” White Paper Proposal for Information Comment, NERC Project
2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011). Requiring
Generation Owners and Operators to comply with the same standards as BES Transmission Owners
and Operators “would do little, if anything, to improve the reliability of the Bulk Electric System,”
especially “when compared to the operation of the equipment that actually produces electricity – the
generation equipment itself.” Id. We believe the many of the questions considered by the Project
2010-07 Team are analogous to the questions under consideration by the SDT, and that, if the SDT
insists upon a “contiguous” BES, the resulting definition will be substantially over-inclusive. The
“contiguous” BES concept implies that every Element arguably necessary for the reliable operation of
the interconnected bulk system must be included in the BES definition, even if it is interconnected
with Elements that have no bearing on the operation of the BES. The adoption of a “contiguous” BES
is therefore likely to result in imposition of reliability standards on a substantial number of facilities
that have little or nothing to do with bulk system reliability, resulting in wasted regulatory expense
and additional stress on the limited resources of reliability regulators. For example, a “contiguous”
BES would require dedicated interconnection facilities that connect a BES generator to BES
transmission facilities to be classified as BES. But, as the discussion above demonstrates, the
classification of dedicated interconnection facilities as “BES” facilities would, based on the findings of
the Project 2010-07 SDT, result in substantial overregulation and unnecessary expense with little gain
for bulk system reliability. Similarly, a “contiguous” BES suggests that, because certain system
protection facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the
local distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” Such a result is not only plainly contrary to the local distribution exclusion embedded in
Section 215 of the FPA, but would, by improperly classifying local distribution lines as BES
“Transmission” facilities, result in huge regulatory compliance burdens with little or no improvement
in bulk system reliability. There is no good reason for the SDT to adopt a “contiguous” BES. On the
contrary, because Section 215 allows reliability standards to be applied to “users” of the bulk system
as well as “owners” and “operators,” local distribution systems operating UFLS relays and other bulk
system protection devices could be required to comply with standards governing those devices as a
precondition for their use of transmission on the bulk system. For these reasons, we urge the SDT to
follow the example of the Project 2010-07 Team and the GO-TO Task Force by giving careful
consideration to the specific and practical results of how its definition will affect the application fo
particular reliability standards and whether the results are beneficial to reliability or simply result in
unnecessary regulatory burdens that do not benefit bulk system reliability. We believe there is

considerable danger of error if the SDT bases its conclusions on metaphysical debates about whether
a “contiguous” or “non-contiguous” BES is more desirable rather than engaging in a careful analysis of
whether the proposed definition achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold
seems more in alignment with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that

should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Dave Hagen
Clearwater Power Company
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue

here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude

facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
The inclusion of individual generation units with a nameplate capacity as small as 20 MVA is overinclusive. Under FPA Section 215, generation resources are excluded from the “bulk-power system”
unless they produce “electric energy” that is “needed to maintain transmission system reliability.” 16
U.S.C. § 824o(a)(1)(B). Smaller generators with a capacity of 20 MVA almost never produce
electricity that is “needed to maintain transmission system reliability.” Hence, the inclusion as drafted
would improperly expand the BES definition to include generators that the statute requires to be
excluded. Further, the 20 MVA threshold appears to have been drawn without explanation from the
existing NERC Statement of Compliance Registry. Given that the purpose of the Compliance Registry
is to sweep in all generators that might be material to the operation of the BES, and not to definitively
determine whether a given generator is, in fact, material to the operation of the BES, the STD has
acted arbitrarily and without adequate technical justification in adopting the 20 MVA threshold. The
100 MVA threshold seems more in alignment with technical standards such as Power System
Stabilizer requirements. In responding to comments on its initial proposal, the SDT states that it
adopted the 20 MVA threshold because “there is no technical basis to change the values contained in
the Statement of Compliance Registry Criteria.” Consideration of Comments on Definition of Bulk
Electric System – Project 2010-17, March 30, 2011, at 30. But this gets the equation backwards. The
SDT must have some technical justification for adopting the 20 MVA threshold beyond the fact that it
was previously adopted by NERC in a different context. Without a technical justification demonstrating
that facilities operating at capacities as low as 20 MVA are “needed to maintain transmission system
reliability,” the proposed definition is overly broad and fails to comply with the restrictions imposed by
Congress in FPA Section 215(a)(1), 16 U.S.C. § 8240(a)(1). Further, the Statement of Compliance
Registry was adopted without the benefit of having been vetted through the NERC Standards
Development Process, so the technical record underlying the choice of that threshold is unavailable
for review by the industry. In the same comments, the SDT also states that it has considered “the
inclusion of generator step-up (GSU) transformers and associated interconnection line leads and
believes the BES must be contiguous at this level in order to be reliable.” Id. The SDT’s reasons for
reaching this conclusion are not well-explained, but apparently the concern is that a “non-contiguous”
BES could create “reliability gaps.” This conclusion cannot be supported as an abstract proposition,
but can only be demonstrated by a careful examination how application of reliability standards will
change depending on how the BES is defined. We believe that if the SDT insists on a “contiguous”
BES, an over-inclusive definition will result. We base these conclusions on the findings of NERC’s

Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO Task Force.” The
Project 2010-07 Team was formed to address how the dedicated interconnection facilities linking a
BES generator to high-voltage transmission facilities should be treated under the NERC standards.
After reviewing these questions in considerable depth, the Team concluded that dedicated highvoltage interconnection facilities need not be treated as “Transmission” and classified as part of the
BES in order to make reliability standards effective. On the contrary, the team concluded that by
complying with a handful of reliability standards, primarily related to vegetation management, reliable
operation of the bulk interconnected system could be protected without unduly burdening the owners
of such interconnection systems. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the predecessor of the
Project 2010-07 SDT). Much of the work of the Project 2010-07 SDT is applicable to the work of the
BES Standards Development Team. For example, the Project 2010-07 Team observed that
interconnection facilities “are most often not part of the integrated bulk power system, and as such
should not be subject to the same level of standards applicable to Transmission Owners and
Transmission Operators who own and operate transmission Facilities and Elements that are part of
the integrated bulk power system.” White Paper Proposal for Information Comment, NERC Project
2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011). Requiring
Generation Owners and Operators to comply with the same standards as BES Transmission Owners
and Operators “would do little, if anything, to improve the reliability of the Bulk Electric System,”
especially “when compared to the operation of the equipment that actually produces electricity – the
generation equipment itself.” Id. We believe the many of the questions considered by the Project
2010-07 Team are analogous to the questions under consideration by the SDT, and that, if the SDT
insists upon a “contiguous” BES, the resulting definition will be substantially over-inclusive. The
“contiguous” BES concept implies that every Element arguably necessary for the reliable operation of
the interconnected bulk system must be included in the BES definition, even if it is interconnected
with Elements that have no bearing on the operation of the BES. The adoption of a “contiguous” BES
is therefore likely to result in imposition of reliability standards on a substantial number of facilities
that have little or nothing to do with bulk system reliability, resulting in wasted regulatory expense
and additional stress on the limited resources of reliability regulators. For example, a “contiguous”
BES would require dedicated interconnection facilities that connect a BES generator to BES
transmission facilities to be classified as BES. But, as the discussion above demonstrates, the
classification of dedicated interconnection facilities as “BES” facilities would, based on the findings of
the Project 2010-07 SDT, result in substantial overregulation and unnecessary expense with little gain
for bulk system reliability. Similarly, a “contiguous” BES suggests that, because certain system
protection facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the
local distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” Such a result is not only plainly contrary to the local distribution exclusion embedded in
Section 215 of the FPA, but would, by improperly classifying local distribution lines as BES
“Transmission” facilities, result in huge regulatory compliance burdens with little or no improvement
in bulk system reliability. There is no good reason for the SDT to adopt a “contiguous” BES. On the
contrary, because Section 215 allows reliability standards to be applied to “users” of the bulk system
as well as “owners” and “operators,” local distribution systems operating UFLS relays and other bulk
system protection devices could be required to comply with standards governing those devices as a
precondition for their use of transmission on the bulk system. For these reasons, we urge the SDT to
follow the example of the Project 2010-07 Team and the GO-TO Task Force by giving careful
consideration to the specific and practical results of how its definition will affect the application fo
particular reliability standards and whether the results are beneficial to reliability or simply result in
unnecessary regulatory burdens that do not benefit bulk system reliability. We believe there is
considerable danger of error if the SDT bases its conclusions on metaphysical debates about whether
a “contiguous” or “non-contiguous” BES is more desirable rather than engaging in a careful analysis of
whether the proposed definition achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold

seems more in alignment with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Roman Gillen
Consumers Power Inc.
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of

the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local

distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”

Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
The inclusion of individual generation units with a nameplate capacity as small as 20 MVA is overinclusive. Under FPA Section 215, generation resources are excluded from the “bulk-power system”
unless they produce “electric energy” that is “needed to maintain transmission system reliability.” 16
U.S.C. § 824o(a)(1)(B). Smaller generators with a capacity of 20 MVA almost never produce
electricity that is “needed to maintain transmission system reliability.” Hence, the inclusion as drafted
would improperly expand the BES definition to include generators that the statute requires to be
excluded. Further, the 20 MVA threshold appears to have been drawn without explanation from the
existing NERC Statement of Compliance Registry. Given that the purpose of the Compliance Registry
is to sweep in all generators that might be material to the operation of the BES, and not to definitively
determine whether a given generator is, in fact, material to the operation of the BES, the STD has
acted arbitrarily and without adequate technical justification in adopting the 20 MVA threshold. The
100 MVA threshold seems more in alignment with technical standards such as Power System
Stabilizer requirements. In responding to comments on its initial proposal, the SDT states that it
adopted the 20 MVA threshold because “there is no technical basis to change the values contained in
the Statement of Compliance Registry Criteria.” Consideration of Comments on Definition of Bulk
Electric System – Project 2010-17, March 30, 2011, at 30. But this gets the equation backwards. The
SDT must have some technical justification for adopting the 20 MVA threshold beyond the fact that it
was previously adopted by NERC in a different context. Without a technical justification demonstrating
that facilities operating at capacities as low as 20 MVA are “needed to maintain transmission system
reliability,” the proposed definition is overly broad and fails to comply with the restrictions imposed by
Congress in FPA Section 215(a)(1), 16 U.S.C. § 8240(a)(1). Further, the Statement of Compliance
Registry was adopted without the benefit of having been vetted through the NERC Standards
Development Process, so the technical record underlying the choice of that threshold is unavailable
for review by the industry. In the same comments, the SDT also states that it has considered “the
inclusion of generator step-up (GSU) transformers and associated interconnection line leads and
believes the BES must be contiguous at this level in order to be reliable.” Id. The SDT’s reasons for
reaching this conclusion are not well-explained, but apparently the concern is that a “non-contiguous”
BES could create “reliability gaps.” This conclusion cannot be supported as an abstract proposition,
but can only be demonstrated by a careful examination how application of reliability standards will
change depending on how the BES is defined. We believe that if the SDT insists on a “contiguous”
BES, an over-inclusive definition will result. We base these conclusions on the findings of NERC’s
Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO Task Force.” The
Project 2010-07 Team was formed to address how the dedicated interconnection facilities linking a
BES generator to high-voltage transmission facilities should be treated under the NERC standards.
After reviewing these questions in considerable depth, the Team concluded that dedicated highvoltage interconnection facilities need not be treated as “Transmission” and classified as part of the
BES in order to make reliability standards effective. On the contrary, the team concluded that by
complying with a handful of reliability standards, primarily related to vegetation management, reliable
operation of the bulk interconnected system could be protected without unduly burdening the owners
of such interconnection systems. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the predecessor of the

Project 2010-07 SDT). Much of the work of the Project 2010-07 SDT is applicable to the work of the
BES Standards Development Team. For example, the Project 2010-07 Team observed that
interconnection facilities “are most often not part of the integrated bulk power system, and as such
should not be subject to the same level of standards applicable to Transmission Owners and
Transmission Operators who own and operate transmission Facilities and Elements that are part of
the integrated bulk power system.” White Paper Proposal for Information Comment, NERC Project
2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011). Requiring
Generation Owners and Operators to comply with the same standards as BES Transmission Owners
and Operators “would do little, if anything, to improve the reliability of the Bulk Electric System,”
especially “when compared to the operation of the equipment that actually produces electricity – the
generation equipment itself.” Id. We believe the many of the questions considered by the Project
2010-07 Team are analogous to the questions under consideration by the SDT, and that, if the SDT
insists upon a “contiguous” BES, the resulting definition will be substantially over-inclusive. The
“contiguous” BES concept implies that every Element arguably necessary for the reliable operation of
the interconnected bulk system must be included in the BES definition, even if it is interconnected
with Elements that have no bearing on the operation of the BES. The adoption of a “contiguous” BES
is therefore likely to result in imposition of reliability standards on a substantial number of facilities
that have little or nothing to do with bulk system reliability, resulting in wasted regulatory expense
and additional stress on the limited resources of reliability regulators. For example, a “contiguous”
BES would require dedicated interconnection facilities that connect a BES generator to BES
transmission facilities to be classified as BES. But, as the discussion above demonstrates, the
classification of dedicated interconnection facilities as “BES” facilities would, based on the findings of
the Project 2010-07 SDT, result in substantial overregulation and unnecessary expense with little gain
for bulk system reliability. Similarly, a “contiguous” BES suggests that, because certain system
protection facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the
local distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” Such a result is not only plainly contrary to the local distribution exclusion embedded in
Section 215 of the FPA, but would, by improperly classifying local distribution lines as BES
“Transmission” facilities, result in huge regulatory compliance burdens with little or no improvement
in bulk system reliability. There is no good reason for the SDT to adopt a “contiguous” BES. On the
contrary, because Section 215 allows reliability standards to be applied to “users” of the bulk system
as well as “owners” and “operators,” local distribution systems operating UFLS relays and other bulk
system protection devices could be required to comply with standards governing those devices as a
precondition for their use of transmission on the bulk system. For these reasons, we urge the SDT to
follow the example of the Project 2010-07 Team and the GO-TO Task Force by giving careful
consideration to the specific and practical results of how its definition will affect the application fo
particular reliability standards and whether the results are beneficial to reliability or simply result in
unnecessary regulatory burdens that do not benefit bulk system reliability. We believe there is
considerable danger of error if the SDT bases its conclusions on metaphysical debates about whether
a “contiguous” or “non-contiguous” BES is more desirable rather than engaging in a careful analysis of
whether the proposed definition achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold
seems more in alignment with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.

As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Roger Meader
Coos-Curry Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from

generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric

energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:

http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units
with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT
also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be
supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the
dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily
related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment

that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the
operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk
system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be
required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and
practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.
No
Specific language change: Change 75 MVA to 100 MVA We are concerned that the 75 MVA threshold
has been chosen arbitrarily by the SDT. Like the 20 MVA threshold discussed in our response to
question 3, the 75 MVA threshold appears to have been drawn from the NERC Statement of
Compliance Registry without appreciation for the function of the threshold in that document and
without adequate technical justification demonstrating the generators with an aggregate capacity of
75 MVA produce electric energy “needed to maintain transmission system reliability” and are
therefore properly included in the BES definition. The 100 MVA threshold seems more in alignment
with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to

ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Dave Sabala
Douglas Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization

(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities

would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units

with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT
also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be
supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the
dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily
related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment
that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the
operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk

system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be
required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and
practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold
seems more in alignment with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.

However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Bryan Case
Fall River Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the

definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion

for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units
with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,

material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT
also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be
supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the
dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily
related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment
that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the
operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk
system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only

plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be
required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and
practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold
seems more in alignment with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the

proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Rick Crinklaw
Lane Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution

that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that

would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units
with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are

“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT
also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be
supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the
dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily
related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment
that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the
operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk
system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be
required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and

practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold
seems more in alignment with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions

and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Ray Ellis
Lincoln Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as

local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already

defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units
with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT
also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be

supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the
dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily
related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment
that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the
operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk
system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be
required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and
practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn

from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold
seems more in alignment with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Richard Reynolds

Lost River Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or

developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase

“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units
with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT
also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be
supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the
dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily

related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment
that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the
operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk
system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be
required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and
practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.
No
Specific language change: Change 75 MVA to 100 MVA We are concerned that the 75 MVA threshold
has been chosen arbitrarily by the SDT. Like the 20 MVA threshold discussed in our response to
question 3, the 75 MVA threshold appears to have been drawn from the NERC Statement of
Compliance Registry without appreciation for the function of the threshold in that document and
without adequate technical justification demonstrating the generators with an aggregate capacity of
75 MVA produce electric energy “needed to maintain transmission system reliability” and are
therefore properly included in the BES definition. The 100 MVA threshold seems more in alignment
with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our

comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Annie Terracciano
Northern Lights Inc.
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to

question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent

indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.

We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units
with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT
also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be
supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the
dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily
related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for

Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment
that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the
operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk
system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be
required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and
practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold
seems more in alignment with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.

Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Doug Adams
Okanogan Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the

limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in

the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.

No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units
with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT
also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be
supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the
dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily
related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment
that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the

operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk
system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be
required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and
practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold
seems more in alignment with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be

classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Rick Paschall
PNGC Power
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional

Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,

and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units
with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.

Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT
also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be
supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the
dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily
related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment
that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the
operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk
system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS

relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be
required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and
practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.
No
Specific language change: Change 75 MVA to 100 MVA We are concerned that the 75 MVA threshold
has been chosen arbitrarily by the SDT. Like the 20 MVA threshold discussed in our response to
question 3, the 75 MVA threshold appears to have been drawn from the NERC Statement of
Compliance Registry without appreciation for the function of the threshold in that document and
without adequate technical justification demonstrating the generators with an aggregate capacity of
75 MVA produce electric energy “needed to maintain transmission system reliability” and are
therefore properly included in the BES definition. The 100 MVA threshold seems more in alignment
with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes

We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Heber Carpenter
Raft River Rural Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent

any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the

clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units
with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this

gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT
also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be
supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the
dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily
related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment
that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the
operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk
system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be

required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and
practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.
No
Specific language change: Change 75 MVA to 100 MVA We are concerned that the 75 MVA threshold
has been chosen arbitrarily by the SDT. Like the 20 MVA threshold discussed in our response to
question 3, the 75 MVA threshold appears to have been drawn from the NERC Statement of
Compliance Registry without appreciation for the function of the threshold in that document and
without adequate technical justification demonstrating the generators with an aggregate capacity of
75 MVA produce electric energy “needed to maintain transmission system reliability” and are
therefore properly included in the BES definition. The 100 MVA threshold seems more in alignment
with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance

therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Ken Dizes
Salmon River Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]

unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation

is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units
with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT

also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be
supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the
dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily
related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment
that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the
operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk
system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be
required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and
practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition

achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold
seems more in alignment with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the

jurisdictional limitations of the FPA.
Individual
Steve Eldrige
Umatilla Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)
has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute

is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it
is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the

proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes
We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units
with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT
also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be
supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the

dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily
related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment
that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the
operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk
system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be
required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and
practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold
seems more in alignment with technical standards such as Power System Stabilizer requirements.

No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an
adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Marc Farmer
West Oregon Electric Cooperative
No
First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of
the Bulk Electric System (BES). We appreciate the work that the Standards Development Team (SDT)

has put into a new definition so far and believe the draft is a step in the right direction. We also
understand the relatively short timeframe that NERC is working under in order to create a new BES
definition to submit to FERC for approval before the imposed deadline. That said, we believe that the
draft definition needs significant revision before NERC files it with FERC for approval. In response to
question #1, we recommend that NERC revise the draft BES definition so that the first paragraph
reads as follows: “Bulk Electric System (BES): Includes anything that meets each of the following
three (3) criteria: (1) (a) Is a facility or control system necessary for operating an interconnected
electric energy transmission network (or any portion thereof), or (b) Is electric energy from
generation facilities needed to maintain transmission system reliability; AND (2) Is not a facility used
in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC
Order 888; AND (3) (a) Unless included or excluded in subpart (b), is i. A Transmission Element
operated at 100kV or higher; or ii. A Real Power Resource identified in subpart (b); or iii. A Reactive
Power resource connected at 100kV or higher; (b) [the list of inclusions of exclusions in the draft, as
modified by our comments below]” Criteria (1) and (2) of these revisions would capture the
limitations on what may be included in the BES due to the jurisdictional limits that Congress placed on
FERC, NERC, and the Regional Entities in developing and enforcing mandatory reliability standards.
Specifically, Section 215(i) of the Federal Power Act provides that the Electric Reliability Organization
(ERO) “shall have authority to develop and enforce compliance with reliability standards for only the
Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. With this language, Congress expressly limited FERC, NERC, and the Regional
Entities’ jurisdiction with regard to local distribution facilities as well as those facilities not necessary
for operating a transmission network. Given that these facilities are statutorily excluded from the
definition of the BPS, reliability standards may not be developed or enforced for facilities used in local
distribution, and therefore the definition of the BES may not include such facilities. In Order No. 672,
FERC adopted the statutory definition of the BPS. See Order No. 672, FERC Stats. & Regs. ¶ 31,204
(2006). In Order No. 743-A, issued earlier this year, the Commission acknowledged that “Congress
has specifically exempted ‘facilities used in the local distribution of electric energy’” from the BPS
definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also held that to the extent
any facility is a facility used in the local distribution of electric energy, it is exempted from the
requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution
that will be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process
is for NERC to propose criteria for approval by FERC to determine which facilities are not BPS facilities
and therefore not BES facilities. Accordingly, it is critical that NERC create a definition of the BES that
first excludes facilities used in local distribution. In Order No. 743-A, the Commission confirmed this,
stating: “once a facility is classified as local distribution, the facility will be excluded from the [BES]
unless changes to the system warrant a review of the determination.” Order No. 743-A, at P 71
(emphasis added). We believe that the Seven Factor is the appropriate means to determine whether a
facility is used in the local distribution of electricity and therefore should be referenced in the
definition of the BES. This is the test that applies elsewhere to determine whether facilities qualify as
local distribution, and therefore there is strong and clear precedent for using it in the BES definition.
See 334 F.3d 48. In fact, the statutory language in Section 201 of the FPA that led to the Seven
Factor Test for other purposes is identical to the statutory language in Section 215 of the FPA at issue
here. Well established rules of statutory construction call for interpreting identical language to
produce similar meanings, therefore applying the Seven Factor Test under both sections of the statute
is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain
facilities are part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor
Test could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes, while also allowing NERC flexibility in applying the test or
developing an alternative approach as it deems necessary.” Id. at P 69. The Seven Factor Test
includes the following factors: 1) Local distribution facilities are normally in close proximity to retail
customers; 2) local distribution facilities are primarily radial in character; 3) power flows into local
distribution systems, it rarely, if ever, flows out; 4) when power enters a local distribution system, it

is not re-consigned or transported on to some other market; 5) power entering a local distribution
system is consumed in a comparatively restricted geographical area; 6) meters are based at the
transmission/local distribution interface to measure flows into the local distribution system; and 7)
local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC precedent
indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and
Denying in Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010). NERC must
also limit the BES to facilities or control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local
distribution exclusion, facilities not falling into either of these categories are not part of the BPS and
therefore must be expressly excluded from the BES. In order to establish a process that is consistent
with the FPA and NERC’s delegated authority from FERC, the proper sequence of steps must be
applied in the correct order to determine which facilities are subject to NERC and FERC jurisdiction in
the first instance, and only then, from among the jurisdictional facilities, to determine which facilities
and control systems must comply with the electric reliability standards. Our revisions to the BES
definition would create such a process within the definition of the BES. It would ensure that entities
would begin any analysis of whether a particular item qualifies as BES by asking, first, whether that
facility is “necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” or is “electric energy from generation facilities needed to maintain transmission
system reliability,” and second, whether that facility is “used in the local distribution of electric
energy.” Only after addressing these questions might further analysis be appropriate. We understand,
but disagree with, the argument that, because the FPA clearly excludes local distribution facilities and
facilities necessary for operating an interconnected electric transmission network from FERC, NERC,
and Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the
definition of the BES. This approach might be legally accurate, but could lead to significant confusion
for entities attempting to implement the new BES definition. There are numerous examples of
Regional Entities, particularly WECC, attempting to include such facilities in the BES under the current
BES definition, and regulated entities are not certain as to which facilities they should consider part of
the BES. Clarifying FERC, NERC, and Regional Entity in the BES definition, even if such clarification is
already provided in the FPA, would avoid such problems under the new definition. Criterion (3) of
these revisions is necessary to resolve the ambiguity in the proposed definition as to whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding
clause (“Reactive Power resources connected at 100 kV or higher”) or the entire definition.
Rearranging the definition in this way should make clear that the list of inclusions and exclusions that
would be inserted as Subpart (b) modifies each provision of Subpart (a). Thus, for example, even if a
Transmission Element is otherwise included by virtue of operating at 100 kV or higher, it is
nonetheless excluded if specifically addressed in the list of exclusions that would be incorporated as
subpart (b) of the definition (if, for example, the Element qualifies as a Local Distribution Network).
The rearrangement of the language eliminates any argument that the phrase “unless such designation
is modified by the list shown below” does not modify “all Transmission Elements operated at 100 kV
or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.” Further, we support the use of the phrase “Transmission Elements”
as the starting point for the base definition because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the use of the term “Transmission” makes clear that
the Bulk Electric System includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power. As discussed above, the definition must exclude
facilities used in local distribution in order to comply with the limits placed on NERC authority by
Congress in Section 215 of the FPA. For similar reasons, we believe the SDT has improved the
proposed definition from its initial proposal by eliminating the use of terms such as “Generation” that
are not specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility”
that include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
Yes

We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin.
We note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams denoting the BES
demarcation point for a number of different kinds of Elements that are common in the Western
Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES Definition
Clarification Project has devoted considerable effort to developing one-line diagrams of transmission
and distribution Elements, and identifying the point of demarcation between BES and non-BES
Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should
be able to provide much useful guidance to the industry with relatively little additional effort.
No
Specific language change: Change 20 MVA to 100 MVA The inclusion of individual generation units
with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators
with a capacity of 20 MVA almost never produce electricity that is “needed to maintain transmission
system reliability.” Hence, the inclusion as drafted would improperly expand the BES definition to
include generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be material
to the operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the operation of the BES, the STD has acted arbitrarily and without adequate technical
justification in adopting the 20 MVA threshold. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements. In responding to comments on its
initial proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical
basis to change the values contained in the Statement of Compliance Registry Criteria.” Consideration
of Comments on Definition of Bulk Electric System – Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context. Without
a technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and fails
to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of having
been vetted through the NERC Standards Development Process, so the technical record underlying
the choice of that threshold is unavailable for review by the industry. In the same comments, the SDT
also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Id. The SDT’s reasons for reaching this conclusion are not well-explained, but apparently
the concern is that a “non-contiguous” BES could create “reliability gaps.” This conclusion cannot be
supported as an abstract proposition, but can only be demonstrated by a careful examination how
application of reliability standards will change depending on how the BES is defined. We believe that if
the SDT insists on a “contiguous” BES, an over-inclusive definition will result. We base these
conclusions on the findings of NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force.” The Project 2010-07 Team was formed to address how the
dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. After reviewing these questions in considerable depth,
the Team concluded that dedicated high-voltage interconnection facilities need not be treated as
“Transmission” and classified as part of the BES in order to make reliability standards effective. On
the contrary, the team concluded that by complying with a handful of reliability standards, primarily
related to vegetation management, reliable operation of the bulk interconnected system could be
protected without unduly burdening the owners of such interconnection systems. See Final Report
from the NERC Ad Hoc Group for Generator Requirements at the Transmission Interface (Nov. 16,
2009) (paper written by the predecessor of the Project 2010-07 SDT). Much of the work of the Project
2010-07 SDT is applicable to the work of the BES Standards Development Team. For example, the

Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate transmission
Facilities and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the same
standards as BES Transmission Owners and Operators “would do little, if anything, to improve the
reliability of the Bulk Electric System,” especially “when compared to the operation of the equipment
that actually produces electricity – the generation equipment itself.” Id. We believe the many of the
questions considered by the Project 2010-07 Team are analogous to the questions under
consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES, the resulting
definition will be substantially over-inclusive. The “contiguous” BES concept implies that every
Element arguably necessary for the reliable operation of the interconnected bulk system must be
included in the BES definition, even if it is interconnected with Elements that have no bearing on the
operation of the BES. The adoption of a “contiguous” BES is therefore likely to result in imposition of
reliability standards on a substantial number of facilities that have little or nothing to do with bulk
system reliability, resulting in wasted regulatory expense and additional stress on the limited
resources of reliability regulators. For example, a “contiguous” BES would require dedicated
interconnection facilities that connect a BES generator to BES transmission facilities to be classified as
BES. But, as the discussion above demonstrates, the classification of dedicated interconnection
facilities as “BES” facilities would, based on the findings of the Project 2010-07 SDT, result in
substantial overregulation and unnecessary expense with little gain for bulk system reliability.
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability. There is no good reason
for the SDT to adopt a “contiguous” BES. On the contrary, because Section 215 allows reliability
standards to be applied to “users” of the bulk system as well as “owners” and “operators,” local
distribution systems operating UFLS relays and other bulk system protection devices could be
required to comply with standards governing those devices as a precondition for their use of
transmission on the bulk system. For these reasons, we urge the SDT to follow the example of the
Project 2010-07 Team and the GO-TO Task Force by giving careful consideration to the specific and
practical results of how its definition will affect the application for particular reliability standards and
whether the results are beneficial to reliability or simply result in unnecessary regulatory burdens that
do not benefit bulk system reliability. We believe there is considerable danger of error if the SDT
bases its conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES
is more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. The 100 MVA threshold
seems more in alignment with technical standards such as Power System Stabilizer requirements.
No
We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained.
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an

adequate technical justification. Further, unless the generation unit is reliability-must-run or essential
blackstart, the function of the unit is irrelevant to the reliable operation of the interconnected bulk
transmission grid, and we therefore believe the reference to the function of the generation unit should
be eliminated.
Yes
We strongly support the categorical exclusion of Local Distribution Networks from the BES. For
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are likely the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the
level of service to retail customers. We also support, with the reservations discussed below, the LDN
exclusion as drafted by the SDT. We believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be
classified as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified
by the SDT without compromising the reliability of the interconnected bulk transmission system.
However, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale
adoption of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry
lacks adequate technical justification. The SDT repeats that error here by incorporating those
thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with technical
standards such as Power System Stabilizer requirements.
Yes
We strongly support the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory reliability standards. We agree that the small utilities covered by the
proposed exemption would have no measurable impact on the operation of the interconnected BES.
Our views are borne out by experience in the Pacific Northwest where many small entities were
required to register by virtue of owning a very small portion of the region’s 115-kV system. These
utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance
therefore will have no measurable effect in improving the reliability of the interconnected grid.
No
We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions
and exclusions – will be effective in removing some local distribution facilities from the BES, it will not
remove all such facilities. For the reasons discussed in our answer to Question 1, the proposed
definition is over-inclusive and is likely to sweep up certain facilities used in local distribution that
should not be classified as BES.
As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.
Individual
Kerry Robinson
Wells Rural Electric Company

Dear NERC Standards Drafting Team: Enclosed are Wells Rural Electric Company’s comments on
NERC’s Proposed Continent-wide Definition of Bulk Electric System. We believe that NERC’s proposed
Continent-wide Definition of Bulk Electric System is proceeding in the right direction on this important
topic but that more work needs to the done. We would like to thank the Standards Drafting Team for
their hard work. We support the detailed comments of the Snohomish County Public Utility District
and Pacific Northwest Generating Cooperative with regard to the questions posed by the Comment
Form for Project 2010-17 Definition of BES. We would like to emphasize these portions of
Snohomish’s and PNGC’s comments: • Question 1, both PNGC and Snohomish suggest that NERC
start by adopting the statutory definition of the bulk power system as the core definition. We support
that approach. That is, “(t) he term ‘Bulk Electric System’ means: (A) Facilities and control systems
necessary for operating an interconnected electric energy transmission network (or any portion
thereof); and, (B) Electric energy from generation facilities needed to maintain transmission system
reliability. The term does not include facilities used in the local distribution of electric energy”. See 16
U.S.C. § 824o(a)(1).” • Question 7, we support the exclusion for radial lines as drafted. • Question 9,
we support the categorical exclusion of Local Distribution Networks from the BES as defined here, but
with Snohomish’s clarifications. • Question 10, we support exclusion E4, for small utilities, but we are
unclear how small utilities are defined in the exclusion language presented here. • Question 11, we
support the approach to exclusion of local distribution facilities discussed in the draft but repeat that
more work should be done on the definition so that facilities used in local distribution are not swept
up into the BES. The primary value of clearly defining the BES is for registration determinations. We
realize that clearly defining the BES also has value in determining which standards apply to registered
entities. If a registered entity does not own any Elements of the BES that that registered entity should
be able to efficiently and effectively demonstrate an exception. We encourage NERC to support the
use of the BES definition for registration-issues and to develop the exception procedure for registered
entities that do not own or operate any Elements of the BES.
Group
City of Santa Clara, California, dba Silicon Valley Power
Jim Lauth

Yes
Yes, Silicon Valley Power agrees with proposed Exclusion E3 that "Local Distribution Networks (LDNs):
Groups of Elements above 100 kV that distribute power to Load rather than transfer bulk power
across the interconnected System," that are (among the other characterizations) "connected to the
Bulk Electric System (BES) at more than one location solely to improve the level of service to retail
customer load" should be specifically excluded from the Bulk Electric System definition. SVP also
agrees with the majority of the characteristics of an LDN set forth in proposed Exclusion E3. However,
SVP believes that alternative language may be more appropriate with respect to characteristic "b" of
proposed Exclusion E3. Part "b" to proposed Exception E3 states "Limits on connected generation:
Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation."
SVP submits that the use of a fixed level of generation to determine whether an entity qualifies as an
LDN is too arbitrary and does not reflect engineering reality. If a fixed level of generation is used, it
will often be too high, if the registered entity has a small system, or too low, when the registered
entity has a large system. SVP submits that NERC should consider modifying part "b" to proposed
Exception E3 to give the Regional Entities discretion to determine whether 75 MVA of generation is
the appropriate benchmark for an individual utility. Therefore, SVP submits that with respect to draft
exception E3 b), "Limited connected generation to the LDN or its underlying Elements (in aggregate),

as determined by the LDN's Regional Entity, using 75 MVA as a benchmark" may be appropriate.
Alternatively, SVP submits that instead of a fixed level of generation, NERC could consider modifying
the language of proposed Exception E3 b) to limit an LDN's connected generation to a high
percentage of local minimum demand, or to a high percentage of generation not already committed to
run to meet local reliability needs. Either option would meet the purpose of the LDN: a registered
entity with connected generation that is, for the most part, only used to serve native or local load.
SVP thanks NERC for the opportunity to comment on its 1st Draft definition of BES, and its proposed
inclusions and exceptions.

Individual
Hertzel Shamash
Dayton Power and Light Company
No
Yes
Yes
Yes
No
Black start resources should not be included in this new proposal, which is being developed in
response to FERC Orders 743 and 743A. These orders do not mention the inclusion of black start
resources or cranking paths. These resources are undeniably important and we believe the existing
CIP and other NERC standards applicable to them provide sufficient and appropriate safeguards. Their
inclusion as BES elements would significantly increase the requirements for both distribution and
69kV cranking paths – which would be classed as BES elements and fall under all those requirements.
Entities currently include multiple cranking paths for their restoration plans to improve the flexibility
of their resources. However, if cranking paths are considered BES and must meet those requirements,
they will default to a single cranking path which would potentially decrease their flexibility. The
purpose of the bulk electric system is to accommodate the bulk movement of electricity through the
interconnected system. In a black start situation, entities would NOT be interconnected and not
moving bulk power. In light of the above, there is no sound basis for inclusion of these elements as
part of the BES.
Yes
Yes
Yes
Yes
Yes
Yes
No

Individual
David Proebstel
Clallam County PUD No.1
No
As a general matter,Clallam County PUD supports the approach the Standards Development Team
(“SDT”) has taken to defining the Bulk Electric System (“BES”). In the comments we submit today,
we identify several refinements we believe would improve the definition. We also discuss the legal
framework the SDT must operate under as we understand it. But we support the SDT’s conceptual
approach and, if refined as we suggest, we will support the SDT’s proposal so long as an acceptable
process for defining exceptions accompanies the definition. As to the core definition addressed in
Question 1, Clallambelieves the changes made in the revised definition are helpful and represent
significant progress toward an acceptable definition. Nonetheless, we are concerned that the core
definition is overly-broad and sweeps facilities into the BES that are required by the statute to be
excluded, even considering the list of inclusions and exclusions. We therefore suggest two different
approaches below that may achieve the SDT’s aims more effectively than the proposed core
definition. At a minimum, as we explain below, additional clarifications to the core definition are
necessary and an acceptable exemption process is necessary to ensure that facilities that are required
by statute to be excluded are excluded from the BES as defined by the SDT. At the outset,we urge
the SDT to bear in mind the specific restrictions on the definition of “bulk-power system” contained in
Section 215 of the Federal Power Act (“FPA”) (Following FERC’s guidance on the question, we treat
the statutory term “bulk-power system” as equivalent to the term ordinarily used in the industry,
“Bulk Electric System”). In Section 215(a)(1), Congress defined “bulk-power system” to mean
“facilities and control systems necessary for operating an interconnected electric energy transmission
network (or any portion thereof)” and “electric energy from generation facilities needed to maintain
transmission system reliability.” 16 U.S.C. § 824o(a)(1). Congress unequivocally excluded from this
definition “facilities used in the local distribution of electric energy.” Id. The “bulk-power system”
definition thus imposes a clear limit on the reach of the mandatory reliability regime. Congress
reinforced that limit in Section 215(i), where it emphasized that the FPA authorizes the imposition of
reliability standards “for only the bulk-power system.” 16 U.S.C. § 824o(i)(1) (emph. added). Further,
the SDT must bear in mind “the cardinal rule that a statute is to be read as a whole since the
meaning of statutory language, plain or not, depends on context.” City of Mesa v. FERC, 993 F.2d
888, 893 (D.C. Cir. 1993) (citation omitted). In considering how Congress used the term “bulk-power
system” in the statute, as well as the limits on the reliability regime imposed in the surrounding
statutory language, it is clear that Congress intended the “bulk-power system” to be defined narrowly
so that it would incorporate only high-voltage, interstate facilities used to transmit power over long
distances, whose failure threatens drastic reliability events such as cascading outages. These
limitations are plain from, for example, the statutory definition of “reliability standard,” which
provides that reliability standards are to encompass only requirements to “provide for reliable
operation of the bulk-power system.” 16 U.S.C. § 824o(a)(3) (emph. added). Congress further
refined the scope of reliability authority by specifically defining “reliable operation” to mean “operating
the elements of the bulk-power systemwithin equipment and electric system thermal, voltage, and
stability limits so that instability, uncontrolled separation, or cascading failures of such system will not
occur as a result of a sudden disturbance. . . or unanticipated failure of system elements.” 16 U.S.C.
§ 824o(a)(4). Congress’s intent to focus the national reliability regime on broad-scale threats to the
interconnected, interstate high-voltage system like cascading outages is made clear, as well, by
Congress’s specific direction that the mandatory reliability system is prohibited from enforcing
standards for adequacy of service, which were left to state and local authorities. 16 U.S.C. §
824o(i)(2). When read in the context of the statute as a whole, the definition developed by the SDT
should therefore focus on that portion of the interconnected bulk transmission grid for which thermal,
voltage, and stability limits must be observed in order to prevent instability, separation events, and
cascading outages. Further, in order to honor the specific limits placed on the definition by Congress,
the SDT’s definition must exclude facilities used in the local distribution of electric power and it must
exclude facilities whose operation or mis-operation affects only the level of service and does not
threaten cascading outages or other widespread events on the bulk interconnected system. Clallam is
concerned that the SDT’s proposed definition is overly-broad, and that it will sweep in many Elements
that have little or no material impact on the reliable operation of the interconnected bulk transmission

grid. For example, the definition would sweep in all generators with 20 MVA capacity even though
generators this small rarely create impacts on the interconnected bulk transmission system that
would threaten to violate the thermal, voltage or stability limits of the bulk transmission system and
therefore do not threaten instability, separation, or cascading outages on the interconnected
transmission system. Accordingly, for the BES definition to conform to the requirements of the
statute, the SDT must adopt an effective mechanism to exempt facilities like these that are
improperly swept in by the SDT’s brightline approach to inclusions and exclusions. For this reason, the
Exception process to accompany the SDT’s definition is of critical concern. It constitutes the last line
of defense against a SDT definition that sweeps in facilities excluded by the statutory definition.
Clallam believes the SDT can achieve the goals of FERC’s Orders No. 743 and 743-A while honoring
these statutory limits by taking one of two alternative approaches to the core definition. First, perhaps
the simplest way the SDT could achieve the goals of FERC Order No. 743 while avoiding overbreadth
that violates statutory limits is to simply adopt the statutory definition of “bulk-power system” as the
core definition. This approach is commonly used by regulatory agencies in defining key jurisdictional
terms to ensure that the agency does not cross statutory boundaries when carrying out the duties
assigned to it by Congress. Under this approach, the core definition would simply echo the statutory
definition, substituting “Bulk Electric System” for its statutory equivalent, “bulk-power system”: The
term ‘Bulk Electric System’ means: (A) Facilities and control systems necessary for operating an
interconnected electric energy transmission network (or any portion thereof); and, (B) Electric energy
from generation facilities needed to maintain transmission system reliability. The term does not
include facilities used in the local distribution of electric energy. See 16 U.S.C. § 824o(a)(1). The
inclusions and exclusions developed by the SDT, with the refinements we discuss below, would then
be added to provide guidance in the application of this definition to specific classes of electric system
facilities and Elements. A second alternative approach is to make the smallest possible adjustment to
the current BES definition that suffices to address the central concern expressed by FERC in Orders
No. 743 and 743-A. Those orders emphasized that FERC’s concerns are with the initial phrase in the
current NERC BES definition, which provides that the “Bulk Electric System” is: As defined by the
Regional Reliability Organization, the electrical generation resources, transmission lines,
interconnections with neighboring systems, and associated equipment, generally operated at voltages
of 100 kV or higher. In Order No. 743, FERC made clear that it views the italicized language as
creating unreviewable discretion for Regional Entities to define the BES in their region, and that this
unreviewable discretion, rather than lack of uniformity per se, is the problem Order No. 743 is
designed to remedy. See, e.g., Order No. 743, 133 FERC ¶ 61,150 at P 16 (2010) (FERC believes the
“best way to address these concerns is to eliminate the Regional Entities’ discretion to define ‘bulk
electric system’ without ERO or Commission review“)(emph. added); id. at 30 (same). In Order No.
743-A, FERC clarified that the primary aim of its rulemaking was to eliminate this unreviewedregional
discretion, and it was not, as FERC had originally proposed, to create a uniform national definition
that does not allow for any regional variation.Order No. 743-A, 134 FERC ¶ 61,210 at P 11 (“We
clarify that the specific issue the Commission directed the ERO to rectify is the discretion the Regional
Entities have under the current bulk electric system definition to define the parameters of the bulk
electric system in their regions without any oversight from the Commission or NERC.”) (emph.
added); id. at P 39 (“The Commission’s suggested solution simply would eliminate regional discretion
that is not subject to review by [NERC] or the Commission”) (emph. added). Accordingly, the SDT
could achieve the primary aim of Order No. 743 by simply rewriting the current definition to read: As
defined by theUnless a different definition has been developed by the Regional Reliability Organization
and approved by NERC and FERC, the Bulk Electric System is defined as the electrical generation
resources, transmission lines, interconnections with neighboring systems, and associated equipment,
generally operated at voltages of 100 kV or higher. If the SDT uses this suggested language as its
core definition, it will have addressed FERC’s primary concern with a minimum of disruption to the
current NERC system of definitions. The definition could then be further elaborated with the list of
specific inclusions and exclusions of Elements and systems (modified as discussed below), to provide
more specific guidance to the industry. If the STD elects not to adopt one of the above suggestions,
the core definition proposed on April 28 requires clarification. Specifically, as drafted, the proposed
definition is ambiguous in that it is not clear whether the clause “unless such designation is modified
by the list shown below” modifies only the preceding clause (“Reactive Power resources connected at
100 kV or higher”) or the entire definition. To eliminate this ambiguity, we suggest that the proposed
definition be reordered to read as follows: Bulk Electric System (BES): (A) Unless included or
excluded in subpart B, the Bulk Electric System consists of: (1) all Transmission Elements operated at

100 kV or higher; (2) Real Power resources identified in subpart B; and, (3) Reactive Power resources
connected at 100 kV or higher. (B) [the list of inclusions and exclusions, modified as discussed in our
responses to questions 2 through 9]. Rearranging the definition in this way should make clear that
the list of inclusions and exclusions that would be inserted as Subpart B modifies each provision of
Subpart A. Thus, for example, even if a Transmission Element is otherwise included by virtue of
operating at 100 kV or higher, it is nonetheless excluded if specifically addressed in the list of
exclusions that would be incorporated as subpart B of the definition (if, for example, the Element
qualifies as a Local Distribution Network). The rearrangement of the language eliminates any
argument that the phrase “unless such designation is modified by the list shown below” does not
modify “all Transmission Elements operated at 100 kV or higher” because of its placement at the end
of the independent clause “Reactive Power resources connected at 100 kV or higher.” Clallam
supports the use of the phrase “Transmission Elements” as the starting point for the base definition
because both “Transmission” and “Elements” are already defined in the NERC Glossary of Terms
Used, and the use of the term “Transmission” makes clear that the Bulk Electric System includes only
Elements used in Transmission and therefore excludes Elements used in local distribution of electric
power. As discussed above, the definition must exclude facilities used in local distribution in order to
comply with the limits placed on NERC authority by Congress in Section 215 of the Federal Power Act
(“FPA”), 16 U.S.C. § 824o. For similar reasons, we believe the SDT has improved the proposed
definition from its initial proposal by eliminating the use of terms such as “Generation” that are not
specifically defined in the NERC Glossary of Terms and by eliminating terms such as “Facility” that
include “Bulk Electric System” as part of their definition. Eliminating the use of such terms helps
sharpen the core definition. If a key term is undefined, incorporating it into the definition only begs
the question of how the incorporated term is defined. If a currently-defined term uses the phrase
“Bulk Electric System” as part of its definition, incorporating that term into the BES definition creates
a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,” “Real
Power,” and “Reactive Power.”
No
In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and nonBES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is
stepped down from transmission voltages to distribution voltages. We believe, however, that the SDT
should undertake the effort to more clearly define the point where the BES ends and non-BES
systems begin. In this regard, we note that the WECC Bulk Electric System Definition Task Force
(“BESDTF”) has devoted considerable effort to this question and has developed one-line diagrams
denoting the BES demarcation point for a number of different kinds of Elements that are common in
the Western Interconnection. See WECC BES Definition Task Force Proposal 6, Appendix C (available
at: http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the FRCC’s BES
Definition Clarification Project has devoted considerable effort to developing one-line diagrams of
transmission and distribution Elements, and identifying the point of demarcation between BES and
non-BES Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A& B
(available at: https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the
SDT should be able to provide much useful guidance to the industry with relatively little additional
effort. Also, the reference to “two windings of 100 kV or higher” may create some confusion because
many three-phase transformer bankshave 6 or 9 windings, depending on whether the transformer
has a tertiary. We suggest clarifying this provision by changing the clause referencing two windings to
read: “the two highest voltage transformer windings of 100 kV per phase that are connected to the
Bulk Electric System.”
No
Clallam is concerned that the inclusion of individual generation units with a nameplate capacity as
small as 20 MVA is over-inclusive. Under FPA Section 215,generation resources are excluded from the
“bulk-power system” unless they produce “electric energy” that is “needed to maintain transmission
system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators with a capacity of 20 MVA almost
never produce electricity that is “needed to maintain transmission system reliability.” Hence, the
inclusion as drafted improperly expands the BES definition to include generators that the statute
requires to be excluded. Further, the 20 MVA threshold appears to have been drawn without
explanation from the existing NERC Statement of Compliance Registry. Given that the purpose of the
Compliance Registry is to sweep in all generators that might be material to the operation of the BES,
and not to definitively determine whether a given generator is, in fact, material to the operation of

the BES, the STD has acted arbitrarily and without adequate technical justification in adopting the 20
MVA threshold. In responding to comments on its initial proposal, the SDT states that it adopted the
20 MVA threshold because “there is no technical basis to change the values contained in the
Statement of Compliance Registry Criteria.” Consideration of Comments on Definition of Bulk Electric
System – Project 2010-17, March 30, 2011, at 30. But this gets the equation backwards. The SDT
must have some technical justification for adopting the 20 MVA threshold beyond the fact that it was
previously adopted by NERC in a different context. Without a technical justification demonstrating that
facilities operating at capacities as low as 20 MVA are “needed to maintain transmission system
reliability,” the proposed definition is overly broad and fails to comply with the restrictions imposed by
Congress in FPA Section 215(a)(1), 16 U.S.C. § 8240(a)(1). Further, the Statement of Compliance
Registry was adopted without the benefit of having been vetted through the NERC Standards
Development Process, so the technical record underlying the choice of that threshold is unavailable
for review by the industry. In the same comments, the SDT also states that it has considered “the
inclusion of generator step-up (GSU) transformers and associated interconnection line leads and
believes the BES must be contiguous at this level in order to be reliable.” Id. The SDT’s reasons for
reaching this conclusion are not well-explained, but apparently the concern is that a “non-contiguous”
BES could create “reliability gaps.” But this conclusion cannot be supported as an abstract
proposition, but can only be demonstrated by a careful examination how application of reliability
standards will change depending on how the BES is defined. In fact, we believe that if the SDT insists
on a “contiguous” BES, an over-inclusive definition will result. We base these conclusions on the
findings of NERC’s Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO
Task Force.”. The Project 2010-07 Team was formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. After reviewing these questions in considerable depth, the Team concluded that
dedicated high-voltage interconnection facilities need not be treated as “Transmission” and classified
as part of the BES in order to make reliability standards effective. On the contrary, the team
concluded that by complying with a handful of reliability standards, primarily related to vegetation
management, reliable operation of the bulk interconnected system could be protected without unduly
burdening the owners of such interconnection systems. See Final Report from the NERC Ad Hoc Group
for Generator Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the
predecessor of the Project 2010-07 SDT). Much of the work of the Project 2010-07 SDT is applicable
to the work of the BES Standards Developoment Team. For example, the Project 2010-07 Team
observed that interconnection facilities “are most often not part of the integrated bulk power system,
and as such should not be subject to the same level of standards applicable to Transmission Owners
and Transmission Operators who own and operate transmission Facilities and Elements that are part
of the integrated bulk power system.” White Paper Proposal for Information Comment, NERC Project
2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011). Requiring
Generation Owners and Operators to comply with the same standards as BES Transmission Owners
and Operators “would do little, if anything, to improve the reliability of the Bulk Electric System,”
especially “when compared to the operation of the equipment that actually produces electricity – the
generation equipment itself.” Id. We believe the many of the questions considered by the Project
2010-07 Team are analogous to the questions under consideration by the SDT, and that, if the SDT
insists upon a “contiguous” BES, the resulting definition will be substantially over-inclusive. The
“contiguous” BES concept implies that every Element arguably necessary for the reliable operation of
the interconnected bulk system must be included in the BES definition, even if it is interconnected
with Elements that have no bearing on the operation of the BES. The adoption of a “contiguous” BES
is therefore likely to result in imposition of reliability standards on a substantial number of facilities
that have little or nothing to do with bulk system reliability, resulting in wasted regulatory expense
and additional stress on the limited resources of reliability regulators. For example, a “contiguous”
BES would require dedicated interconnection facilities that connect a BES generator to BES
transmission facilities to be classified as BES. But, as the discussion above demonstrates, the
classification of dedicated interconnection facilities as “BES” facilities would, based on the findings of
the Project 2010-07 SDT, result in substantial overregulation and unnecessary expense with little gain
for bulk system reliability. Similarly, a “contiguous” BES suggests that, because certain system
protection facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the
local distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” Such a result is not only plainly contrary to the local distribution exclusion embedded in
Section 215 of the FPA, but would, by improperly classifying local distribution lines as BES

“Transmission” facilities, result in huge regulatory compliance burdens with little or no improvement
in bulk system reliability. There is no good reason for the SDT to adopt a “contiguous” BES. On the
contrary, because Section 215 allows reliability standards to be applied to “users” of the bulk system
as well as “owners” and “operators,” local distribution systems operating UFLS relays and other bulk
system protection devices could be required to comply with standards governing those devices as a
precondition for their use of transmission on the bulk system. The other alternative is to draft
standards that apply to a specific type of equipment – again UFLS relays is a good example – rather
than to BES facilities categorically. Either approach will fully achieve the goals of bulk system
reliability without imposing an undue regulatory compliance burden on local distribution systems. For
these reasons, we urge the SDT to follow the example of the Project 2010-07 Team and the GO-TO
Task Force by giving careful consideration to the specific and practical results of how its definition will
affect the application fo particular reliability standards and whether the results are beneficial to
reliability or simply result in unnecessary regulatory burdens that do not benefit bulk system
reliability. We believe there is considerable danger of error if the SDT bases its conclusions on
metaphysical debates about whether a “contiguous” or “non-contiguous” BES is more desirable rather
than engaging in a careful analysis of whether the proposed definition achieves reliability goals in the
most efficient manner possible.
No
Clallam is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20
MVA threshold discussed in our response to question 3, the 75 MVA threshold appears to have been
drawn from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition.
Yes
Including “all” blackstart and blackstart cranking paths in the BES may ultimately provide an incentive
to the electric industry to reduce the number of resources with blackstart capability. We therefore
suggest that essential blackstart resources identified by the Regional Entity should be included in the
Bulk Electric System, but non-essential blackstart resources need not be.
No
Clallam agrees that it is important to address wind generation facilities and similar generation
facilities in which a large number of generating units, each with a relatively small capacity, are
clustered and fed into the grid at a single interconnection point. That being said,Clallam is concerned
that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our comments on
Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained. We believe the exclusion as drafted adequately defines radials.
No
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through
reference to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the
generation unit is reliability-must-run or essential blackstart, the function of the unit is irrelevant to
the reliable operation of the interconnected bulk transmission grid, and we therefore believe the
reference to the function of the generation unit (“standby, back-up, and maintenance power…”)
should be eliminated.
Yes
Clallam strongly supports the categorical exclusion of Local Distribution Networks from the BES. In
fact, for reasons discussed at length in our answer to Question 1, we believe the exclusion is
necessary to ensure that the BES definition complies with the statutory requirement to exclude all
facilities used in the local distribution of electric power. LDNs are, of course, probably the most
common kind of local distribution facility. Further, the conversion of radial systems to local
distribution networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. Clallam also
supports, with the reservations discussed below, the LDN exclusion as drafted by the SDT. At least
conceptually, we believe the SDT has identified the key characteristics that separate LDNs from
facilities that are part of the bulk transmission system and therefore should be classified as BES.

Hence, LDNs can be excluded from the BES based on the characteristics identified by the SDT without
compromising the reliability of the interconnected bulk transmission system. Although Clallam
supports the LDN exclusion, we believe the exclusion should be refined in the following respects: •
The SDT’s draft states that: “LDN’s are connected to the Bulk Electric System (BES) at more than one
location solelyto improve the level of service to retail customer Load.” (emphasis added) We are
concerned that the use of the term “solely” implies the need for an examination of the motives of a
local distribution utility in connecting to the BES at more than one location. This result is problematic
because it defeats the purpose of the exclusion, which is to allow LDNs to be excluded from the BES
without an in-depth and expensive inquiry into the exact nature of the LDN. In addition, the local
utility may have a number of motives for connecting to the BES at more than one location, but the
local utility’s motives have nothing to do with how the LDN interacts with the interconnected bulk
system, which should be the key determinant in including or excluding any Element from the BES.
With these concerns in mind, we therefore recommend that the SDT revise the sentence quoted
above as follows: “LDN’s are connected to the Bulk Electric System (BES) at more than one location
solely to improve the level of service to retail customer Load and not to accommodate bulk transfers
of power across the interconnected bulk system.” By instituting this suggestion, the SDT would
emphasize the key difference between an LDN, which is designed to reliably serve local, end-use retail
customers, and the BES, which is designed to accommodate bulk transfer of power at wholesale over
long distances. • We believe the characteristics specified by the LDN in subsections (b) and (c) of the
exclusion are redundant. Subsection b specifies that the LDN would not interconnect more than 75
MVA of generation in aggregate. Subpart c specifies that power flows only into the LDN. We believe
the SDT can eliminate subpart b of the definition and simply rely on subpart c because if power only
flows into the LDN even if it interconnects more than 75 MVA of generation, the interconnected
generation interconnected will have no significant interaction with the interconnected bulk
transmission system, only with the LDN. Further, with the advent of distributed generation, it is easy
to foresee a situation in which a large number of very small distributed generators are interconnected
into a LDN, so that the aggregate capacity of these generators exceeds 75 MVA. However, because
the generators are small and dispersed and, under the subpart c criteria, would be wholly absorbed
within the LDN rather than transmitting power onto the interconnected grid, those generators would
not have a material impact on the grid. In addition, the 75 MVA criterion would make an LDN
interconnecting more than 75 MVA part of the BES. For the reasons set forth by the Project 2010-07
SDT, we are concerned the result will be the local utility being improperly classified as a Transmission
Owner and Transmission Operator, which would subject the local utility to a number of reliability
standards that would significantly increase its compliance burden without substantially improving bulk
system reliability. In fact, in the LDN situation, there is even less reason to impose these burdens on
the local utility than in the situation addressed by the Project 2010-07 team, where generators are
interconnected to the BES by dedicated interconnection facilities. Because the LDN is interconnected
at multiple points, the generators interconnected to the LDN could continue to operate even if one or
two interconnection points are out of service. On the other hand, in the situation addressed by the
Project 2010-07 team, if the dedicated interconnection facility is out of service, the generation is
unavailable because there is no alternative route to deliver it to load. Finally, for the reasons stated in
our answers to Questions 3 and 4, we believe the SDT’s wholesale adoption of the 20 MVA and 75
MVA thresholds from the NERC Statement of Compliance Registry lacks adequate technical
justification. The SDT repeats that error here by incorporating those thresholds into the LDN
exception.
Yes
Clallam County PUD supports the SDT in its efforts to avoid unintended consequences from changes
to the BES definition, especially for small entities that can ill afford the substantial costs that
accompany imposition of mandatory compliance with reliability standards. Further, we agree that the
small utilities covered by the exemption will have no measurable impact on the operation of the
interconnected BES. Our views are borne out by experience in the Pacific Northwest where many
small entities were required to register by virtue of owning a very small portion of the region’s 115-kV
system. These utilities have faced substantial compliance burdens even though their operations are
simply not material to the interconnected bulk grid in our region, and the investment of resources in
compliance therefore will have no measurable effect in improving the reliability of the interconnected
grid.
No

While Clallam County PUD agrees that the approach adopted by the SDT -- a core definition coupled
with specific inclusions and exclusions – will be effective in removing most local distribution facilities
from the BES, it will not remove all such facilities. For the reasons discussed at greater length in our
answer to Question 1, Clallam believes that the proposed definition is over-inclusive and is likely to
sweep up certain facilities used in local distribution that should not be classified as BES. To give a
further example, assume that a local distribution utility operates a distribution network that currently
would be excluded from the SDT’s definition, but that a cogeneration facility with a capacity of 30
MVA and average production of 15 MVA is constructed in one of the industrial areas served by local
distribution facility and the output is purchased by one of the industrial customers. Because of
inclusion I2, the local utility would now be classified as owning BES facilities, even though the output
of the generator rarely exceeds 20 MVA in practice and the output is, as a matter of physics,
absorbed by the surrounding industrials loads rather than being transmitting onto the interconnected
grid. Further, the fundamental nature of the local distribution facilities has not changed. They are still
used to deliver electric power to the utility’s end-use customers, not to deliver power on the
wholesale market across the interconnected bulk grid. Hence, the result of the SDT’s definition is to
include “facilities used on the local distribution of electric energy” in contravention of FPA Section
215(a)(1), 16 U.S.C. § 8240(a)(1). The practical result of the improper classification would be that
the local utility would be required to register as a Transmission Owner and Transmission Operator,
and would incur substantial costs to comply with requirements that are designed to ensure the
reliable operation of transmission lines that are part of the interconnected grid, not local distribution
facilities. For the reasons explained in the papers published by the Project 2010-07 Task Force, the
result is substantially increased compliance costs that produce little or no improvement in the
reliability of the interconnected bulk system. Accordingly, if viewed in isolation, the SDT’s core
definitions and list of inclusions/exclusions do not comply with the statute or produce optimum
benefits for bulk system reliability. Whether the SDT’s approach complies with the statute can only be
determined by examining the Exception process now under development, in conjunction with the
SDT’s definition. If the Exception process results in the exclusion of facilities that are improperly
swept into the BES by the bright-line thresholds included in the SDT’s definition, and the exclusion
can be accomplished at a reasonable cost to the involved entities, then the SDT will have achieved a
result that complies with the statute. But this conclusion can be reached only upon review of the
entire package, not just the core definition and list of inclusions/exclusions. In this regard, as
discussed in our answer to Question 3, Clallam notes that exclusion of facilities from the BES does not
mean that owners of those facilities are entirely exempt from reliability standards. On the contrary,
the statute provides that “users” of the BES can be subject to reliability regulation. 16 U.S.C. §
824o(b). Hence, even where an entity does not own BES assets, it could be required to, for example,
provide necessary information to the applicable Reliability Coordinator and to participate in the
regional Under-Frequency Load Shedding program by setting the UFLS relays in its Local Distribution
Network at the appropriate settings. We note that participants in the WECC BES Task Force generally
agreed that appropriate information should be provided by non-BES entities, although there was
considerable concern related to ensuring that the provision of information was not unduly
burdensome.
Yes
As noted in our responses to Question 1 and Question 11, we believe the SDT proposal is potentially
in conflict with the limitations of the Federal Power Act, and in particular the statutory exclusion for
facilities used in the local distribution of electric energy. Unless the SDT adopts some approach other
than a core definition with inclusions and exclusions based on brightline thresholds, the SDT’s
approach can meet the statutory requirements only if the Exception process currently under
development results in facilities that are not properly classified as BES being exempted from
regulation as BES facilities.
Clallam County PUD has these additional concerns: • The current definition provides that “Elements
may be included or excluded on a case-by-case basis through the Rules of Procedure exception
process.” Clallam is concerned that the SDT carefully delineate which entity has the burden of proof in
the exclusion process. The WECC BES Task Force approach, which we commend to the SDT, laid out
these burdens in some detail. Under that approach, essentially, if a facility is excluded from the BES
by virtue of the specific exclusions listed in the definition, the Regional Entity bears the burden of
proving that the facility nonetheless has a material impact on the interconnected bulk transmission
system and therefore should be included in the BES. On the other hand, if a facility is classified as

BES by virtue of the list of inclusions set forth in the BES definition, it can still escape classification as
BES, but bears the burden of demonstrating that its facility has no material impact on the
interconnected transmission system. We urge the SDT to give careful consideration to these burdenof-proof questions and to follow the lead of the WECC BES Task Force. • For the reasons we have
explained in our answer to Question 11, we believe the exemption process is critical both to ensure
that the BES definition is effective in producing measurable gains to bulk system reliability and to
ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the exemption process and related procedures, should be
vetted through the NERC Standards Development Process, including the full comment periods and a
ballot approvals provided for in that process. We are concerned that important elements of the BES
definition have been assigned to the Rules of Procedure Team, and that changes in the Rules of
Procedure are subject to approval in a process that provides considerably less due process and
industry input than the Standards Development Process. Compare NERC Rules of Procedure § 1400
(providing for changes to Rules of Procedure upon approval of the NERC board and FERC) with NERC
Standards Process Manual (Sept. 3, 2010) (providing for, e.g., posting of SDT proposals for comment,
successive balloting, and super-majority approval requirements). Accordingly, we urge that all
elements of the BES definition, including those elements that have been assigned to the Rules of
Procedure Team, be vetted through the Standards Development Process. Further, we believe that the
failure to vet all material elements of the BES definition through the Standards Development Process
would constitute a violation of NERC’s bylaws and the requirements of the Standards Development
Process.
Group
Overton Power District No. 5
Randall Ozaki
No
The term does not include facilities used in the local distribution of electric energy.
No
clarification is needed to identify which transformers to include in the BES
Yes
Yes
No
No
Yes
Yes
No
we support Snohomish's clarifications
Yes
We support exclusion E4, for small utilities, but we are unclear how small utilities are defined in the
exclusion language presented here.
No
Facilities used in local distribution should not be swept up into the BES
No

Group
Tennessee Valley Authority

Richard Dearman
Yes
No
We suggest I1 to read, “Transformers, other than generator step-up (GSU) transformers, including
phase angle regulators, having two windings of 100 kV or higher, unless excluded under Exclusions
E1 or E3. Transformers having only one winding of 100 kV or higher are excluded.”
No
Other than the NERC Registry Criteria definition, what is the technical justification for the 20 MVA
threshold? The threshold level for inclusion should be technically based on the BES capacity and
configuration at the location of the generating source’s connection to the BES.
No
Other than the NERC Registry Criteria definition, what is the technical justification for the 75 MVA
threshold? The threshold level for inclusion should be technically based on the BES capacity and
configuration at the location of the generating sources’ connection to the BES.
Yes
No
Other than the NERC Registry Criteria definition, what is the technical justification for the 75 MVA
threshold? The threshold level for inclusion should be technically based on the BES capacity and
configuration at the location of the generating sources’ connection to the BES.
No
We suggest the first statement in E1 to read, “Any radial system connected to a single BES
transmission source, operating with an automatic interruption device, including the facilities between
the connection to the transmission source and the automatic interruption device which are within the
transmission source’s zone of protection, and:”
No
We suggest adding a reference to “I5” in the (i) section as follows: “the net capacity provided to the
BES does not exceed the criteria identified in the inclusions I2, I3, or I5.”
No
The following comments are specific to subsections of E3: Section (c): We suggest the section to
read, “Power flows out of the LDN shall not exceed the limitations imposed in Inclusions I3 and I5.”
Section (d): We suggest the section be read, “Not used to transfer bulk power: The LDN is not used
to transfer energy originating outside the LDN for delivery through the LDN, except for the power
flowing in a normally open switching device between radial systems operating in a make-before-break
fashion as defined in exclusion E1.”
Yes
No
We cannot be certain of the effect of the BES definition on distribution facilities until our comments to
the inclusions and exclusions above are considered.
No
No additional concerns.
Individual
Matt Morais
Electric Reliability Council of Texas, Inc.
No
ERCOT ISO suggests a different approach. In order 743, to remedy its concerns, FERC suggested
eliminating RE discretion in defining the BES, and instead basing it upon a bright-line 100kV
threshold, provided that elements above and below 100kV could be excluded and included,
respectively, based on specific procedures. Consistent with that approach, ERCOT ISO suggests that

the BES definition itself establish a bright line standard, with inclusions and exclusions managed
through the exception process (the exception process allows for both exclusions and inclusions of
relevant facilities/equipment). With respect to exclusions (and inclusions), FERC contemplated a
process involving stages that established “exclusion” criteria in the first instance. If equipment met
such criteria, the process ended there and it was excluded or included, as appropriate. If the
equipment did not meet the bright-line criteria, then it moved to the “exception” analysis, which
contemplated additional critical analysis to determine if exemption was warranted. ERCOT ISO
believes that structuring the revised definition in accordance with this approach is more consistent
with FERC’s intent of having an inclusive definition in the first instance, with modifications occurring
subsequently pursuant to critical analysis in a well defined exception process. Revising the BES
definition consistent with the above principles would counsel in favor of revisions to the current
definition that removed RE discretion and provided for inclusion or exclusion on a case by case basis.
ERCOT ISO also believes that the BES definition should provide for a general exclusion of distribution
facilities. In Orders 743 and 743-A, FERC made clear that, consistent with the terms of EPAct 2005,
distribution systems were excluded from the BES. However, FERC also made clear that it reserved the
right to judge whether something was distribution or transmission, and, therefore, subject to its
jurisdiction. Consistent with FERC’s findings in this regard, ERCOT ISO believes that the definition
should provide the general exclusion, with specific exclusions being performed as part of the
exception process. This will meet the goal of respecting Congress’ exclusion of distribution facilities,
while ensuring the distribution/transmission distinction is subject to clear, objective standards the
application of which can be critically reviewed by FERC to provide the appropriate procedural and
substantive checks FERC envisions to ensure its jurisdiction is applied in all relevant cases to facilitate
enhanced system reliability. In addition, ERCOT ISO supports memorializing the generation
registration criteria in the BES definition. However, consistent with the approach described above, the
BES definition should not be characterized in terms of inclusions or exclusions, but rather as general
thresholds, with modifications occurring solely pursuant to the exemption process. Finally, with
respect to generation, ERCOT ISO questions the 75 MVA threshold applied to collector system type
generation. As indicated by the SDT, this was intended to capture renewable resources (e.g. wind),
and ERCOT ISO agrees with this clarification, but questions whether the 20 MVA threshold should
apply. These systems can include multiple wind turbines on the collector system, but when they are
interconnected at a single point, they are viewed as a single resource and, as such, should be subject
to the same 20 MVA threshold as other single units. Applying the approach described above, the BES
definition would reflect general thresholds. Specific circumstances warranting exception would occur
via a separate process – ERCOT ISO is not disagreeing with any of the SDT’s inclusions or exclusions,
it is merely suggesting that they be addressed in that separate process. Consistent with this
approach, ERCOT ISO offers the following language: The Bulk Electric System shall include: A) all
Transmission Elements operated at voltages100 kV or higher; B) all generation resources that: 1) are
individual units greater than 20 MVA; 2) multiple units at a single facility that are equal to or greater
than 75 MVA in the aggregate, provided that all units have a common point of interconnection; and 3)
multiple units connected to a collector system that are equal to or greater than 20 MVA in the
aggregate; 4) all Blackstart Resources; and C) Reactive Power resources connected at 100 kV or
higher. The BES shall not include distribution facilities, and radial transmission facilities serving only
load with one transmission source are generally not included in this definition. The foregoing
notwithstanding, any relevant element (e.g. transmission, generation, etc.) may be included or
excluded in the BES pursuant to the relevant exception processes criteria and analyses as provided
for in the NERC Rules of Procedure.
No
ERCOT ISO agrees that such equipment should be considered for inclusion, but suggests that these
issues be addressed relative to the criteria for evaluation in the exception process. In other words,
this inclusion doesn’t need to be explicitly identified. It would simply be included under the general
100 kV threshold, and to the extent an owner believed the characteristics of its equipment don’t
warrant inclusion, it would seek an exception.
No
See response to question 1. ERCOT ISO supports redefining generation covered under the BES to
reflect the registration threshold, but, consistent with the comments to question 1, believes it should
be included within the bright line criteria unless otherwise indicated by application of the inclusion and
exclusion criteria of the exception process or analyses.

No
See response to question 3 – ERCOT ISO agrees with substance, but not the approach.
No
See response to question 3 – ERCOT ISO agrees with the substance, but not the approach.
No
See response to question 3 – ERCOT ISO agrees with the substance but not the approach.
No
See response to question 1 – while ERCOT ISO does not necessarily disagree with the substance of
the proposed exclusions, it believes all exceptions should occur pursuant to the separate processes
and criteria being developed that will be established in the NERC ROP. The BES definition should be
more general in nature, focusing on objective thresholds. All exclusions should be addressed in the
separate proceeding being conducted in parallel with this proceeding to develop the exception
process, and ERCOT ISO reserves its right to comment on the substance of such proposals in that
proceeding.
No
See response to question 7.
No
See response to Question 7.
No
These entities should be subject to the exception process. They may warrant “first instance” exclusion
in that process, but any such action should occur there, as opposed to the definition of BES. ERCOT
ISO believes this is more consistent with FERC’s position that BES should reflect an objective
threshold, with exceptions being subject to review by the ERO and FERC, as applicable. Accordingly,
ERCOT ISO suggests that this issue be raised in the concurrent BES exception proceeding and ERCOT
ISO reserves its right to comment on the substance in that proceeding.
No
See response to question 1 – ERCOT ISO agrees that distribution facilities should be excluded, and
such facilities are generally excluded in ERCOT ISO’s proposed alternative definition. However, FERC
stated in 743 and 743-A that it has the right to determine if facilities are distribution or transmission.
Accordingly, to respect the FPA explicit exclusion of distribution facilities and FERC’s authority to
determine if a facility is transmission or distribution, ERCOT ISO position is that the general
exemption should be in the BES definition, but any such exemptions must be subject to the
exemption process to facilitate FERC’s authority to make the relevant determination. With respect to
that process, it may provide for a presumptive exclusion with additional at FERC’s discretion. ERCOT
ISO reserves its rights to comment on the criteria for exclusion/exemption/inclusion in that
proceeding. In addition, the exception process should provide for the ability to include certain
distribution facilities if the inclusion criteria of the exception process indicate such action is
appropriate.
Yes
See response to question 1 – ERCOT ISO believes defining BES in terms of the relevant exclusions
may be contrary to FERC’s suggested approach in 743 and 743-A. While FERC did not mandate a
particular approach, and gave the ERO the opportunity to propose an alternative to its suggested
approach, it stated that any alternative must be equal to or greater than its suggested approach in
terms of remedying the identified flaws associated with the current definition. Part of the remedy
envisioned by FERC included the removal of subjectivity in defining BES and the ability of the ERO and
FERC to review any proposed exemptions from the bright line definition. Although the exclusions
strive to apply objective criteria, it is arguable that any such circumstances may not be that clear and
may require some level of subjective judgment as to whether elements deemed to be distribution
according to the exclusion criteria actually are distribution, as opposed to transmission. In addition,
FERC expressly stated that it reserved the right to make that determination in the first instance. This
approach takes that away from FERC.
Group
Arizona Public Service Company

Janet Smith
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No.
Individual
Martin Kaufman
ExxonMobil Research and Engineering
No
The SDT’s attempt to create a structure that clarifies what types of facilities should be included /
excluded from the bulk electric system is a positive step; however, the utilization of an automatic
fault interrupting device as the end point criteria for bulk electric and start point for local distribution
is inappropriate. The Federal Power Act specifically excludes all “facilities used in the local distribution
of electric energy” from the bulk power system without mention of how these facilities are isolated
from the transmission system.
Yes
Yes
Support is contingent on the continued exclusion of generation based on its net capacity provided to
the BES.
Yes
Support is contingent on the continued exclusion of generation based on its net capacity provided to
the BES.
Yes
Yes
No

The inclusion or exclusion of radial lines serving load should not be contingent on whether the radial
line is isolated by a single automatic fault interrupting device. Many of the radial lines impacted by the
requirement for the presence of an automatic fault interrupting device are industrial companies that
are fed via 138 kV and 230 kV systems that are hard-tapped or fed from breaker and a half or ring
buss transmission substations. The requirement for the installation of an automatic fault interrupting
device on the radial line is predicated on the assumption that an event on a hard-tapped line serving
load will produce a negative impact on the interconnected transmission network. Accepting this
assumption as a true fact, the SDT is following the logic that they should expand the scope of the
interconnected transmission network to include the hard-tapped line (used to locally distribute power)
due to the fact that the transmission owner has neglected to properly protect their facilities from the
impact of an event on the hard-tapped line. In effect, the SDT is allowing the transmission planner to
take credit for protective devices installed on the distribution network when they conduct their
contingency studies as part of NERC Reliability Standards TPL-002 and TPL-003; thus shifting the
responsibility of protecting the interconnected transmission network from the owners of the
transmission network to the customers and their local distribution facilities. The SDT should revisit
their assertion that facilities should be included based on the presence of an automatic fault
interrupting device based on the fact that if a contingency study indicates that an automatic fault
interrupting device should be present in order to preserve system stability or prevent a cascading
outage during an N-1 or N-2 contingency, the transmission planner should be recommending such a
device is installed on the interconnected transmission system and not a customer owned facility or
any facility used to locally distribute electric power. It is inappropriate to let transmission owners take
credit for customer owned and local distribution facilities in their reliability studies and require
customer’s and local distribution facilities to protect the interconnected transmission network when
those facilities are explicitly excluded from the bulk power system in Section 215 of the Federal Power
Act and the interconnected transmission system is owned and operated by entities that the customers
and local distribution facility owners pay to provide them with reliable transmission service.
Yes
No
Similar to the comments provided on Exclusion E1, the inclusion of a requirement for automatic fault
interrupting device to separate the local distribution network from the interconnected transmission
network will in many cases shift the onus of securing a reliable interconnected transmission network
from the owners and operators of that interconnected transmission network to the customers and
owners of local distribution networks that pay the owners and operators of the interconnected
transmission network a fee for providing reliable transmission services. Furthermore, the Federal
Power Act excludes all facilities used in the local distribution of electric energy and does not
distinguish whether such local distribution facilities must be isolated by automatic fault interrupting
devices.
No
While the exclusion for a small utility makes sense, the exclusion should not be limited to a utility
company. The SDT should extended the exclusion to similarly situated facilities or organizations with
other primary business functions, such as industrial companies.
No
The SDT has defined a specific type of local distribution facility in their bright-line definition of the
bulk electric system. The SDT’s definition focuses on a specific type of local distribution system that
has a minimum impact on an interconnected transmission system when that interconnected
transmission system does not include the facilities necessary to properly protect itself from faults
originating on its boundary. Section 215 of the Federal Power Act does not qualify the type of local
distribution facility that should be excluded. It exempts ALL facilities used in the local distribution of
electric energy, regardless of whether the owners and operators of the interconnected transmission
system have installed facilities that are necessary to secure the reliability of the interconnected
transmission system from incidents originating at its boundaries. Additionally, the SDT should
consider making its definition of a local distribution network consistent with exclusion E2. If a
generation facility with a net aggregate rating less than 75 MVA or single unit with a net export
capacity below 20 MVA is not a part of the bulk electric system, what is the technical justification of
including a local distribution network that exports less than 75 MVA in the bulk electric system when it

is not used to transmit electric energy between geographic regions? Many QFs and large industrial
facilities may fall under the description of local distribution network due to the breadth of their private
use network, connection to mulitple 138 kV / 230 kV substations (done to improve reliability in order
to provide safer operation of the industrial process), and possible cyclical generation exports
(sometimes exporting / sometimes importing).
Yes
Section 215 of the Federal Power Act excludes facilities used in the local distribution of electric energy
without any qualifications of the type of local distribution facility.
There are certain transmission network configurations in the south east portion of the country where
the majority of the interconnected transmission network is owned and maintained by a single utility
company, but approximately one hundred substations that are located along the interconnected
transmission network and utilized to transmit power between regions are owned by separate
companies (i.e. many companies own a single transmission substation). The SDT should consider this
configuration and the lack of uniform operation and maintenance practices that may exist due to the
differences in how the companies implement NERC compliance.
Individual
Laura Lee
Duke Energy
Yes
Yes
Yes
Yes
Yes
No
I5 is not defined clearly enough. It appears that distributed generators connected to a 44 kV load
pocket that is fed radially from a 100 kV source would be included, but it’s not clear that this was the
intent. Adding generator before collector system would provide greater precision.
No
This needs further clarification as to what constitutes a “single Transmission source”. Does having a
double/multiple circuit line(s) from a single transmission station constitute a radial system?.
Yes
Yes

Yes
No

Group
Imperial Irrigation District
Sammy Alcaraz
Yes
Yes

Yes
Yes
Yes
No
In reference to I5 If the collector system is in the distribution system and after a series of elements
and (sub transmission system) is connected to a common point of interconnection to a system
element at a voltage of 100 kV and above, is there a criteria of after how many elements before it
connects to a system element at a voltage of 100 kV and above is I5 still applicable? IID prefers the
following language: Dispersed power producing resources with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) after the collector system to the first system Element at a
voltage of 100 kV or above.
Yes
Yes
Yes
Yes
Yes
No
None
Individual
Curtis Klashinsky
FortisBC
Yes
We agree with the concept of a bright-line definition and commend the SDT for developing a concept
of explicit inclusions and exclusions as part of the definition. This will reduce the number of exception
applications for some of the BES elements. However, the inclusion and exclusion requirements are
extremely restrictive. For example, radial characteristics should not be limited by the amount of
installed generation or single transmission source and/or require an interrupting device. Instead we
believe that one or more transmission sources could feed the radial load to provide redundancy as
long as there is adequate protection and isolation for improved customer-supply continuity and
reliability. This should be considered radial as long as the loss of any transmission source does not
affect, and is not necessary for, the operation of the interconnected transmission network. Further, it
is imperative to understand that the NERC’s revised definition will have a direct impact on entities
across North America and will conflict with regulatory requirements, Codes, and Licenses. FERC in its
Order 743 and 743A has directed NERC to address these concerns. We suggest the SDT and RoP
teams should: • Carefully craft the exception criteria and procedure to be flexible and technically
sound, to allow entities to adequately present their case to the ERO for inclusions or exclusions
outside of the definition. • Include provisions in both the NERC exception criteria and exception
process for federal, state and provincial jurisdictions. These provisions should provide clear guidance
so that, if and when there are deviations from the exception criteria, they are properly identified with
technical and regulatory justifications ensuring there is no adverse impact on the interconnected
transmission network. This burden of proof should be left to the entity seeking exception because it
may be difficult if not impossible to define the exception criteria. Further, if such an explicit criteria
could be defined, it will in fact become another bright-line BES.

Yes
We agree with the concept of Inclusion I1. However, we suggest that since transformers are already
covered by the definition, "all transmission Elements operated at 100 kV and above", and since
Inclusions I2 to I5 are commonly related to generation only, Inclusion I1 should be removed and
replaced by the following Exclusion: E(x) "Transformers not used as Generator Step-Up (GSU)
transformers that have primary or secondary winding at less than 100 kV." We also suggest the SDT
to put forward a high-level exception criteria with key menu items of assessment that can be followed
continent-wide by entities to put forward their exception for element(s) mentioned in Inclusion I1, or
any other inclusion(s). These inclusion(s) that are intended for exemption would be based on the
entity’s technical assessment, evidence and justification for its unique characteristics, configuration,
and utilization.
No
We agree with the concept of Inclusion I2 with respect to individual generating units, but do not
support having the entire path labeled as BES. In most cases, neither the path or a 20 MVA unit itself
will have any impact on the reliability of the interconnected transmission network nor is it necessary
for the operation. We also do not support the fact that there should be a blanket application of the
BES definition to all individual generating units greater than 20 MVA. It is also important to mention
that moving into the future, with the Green Energy and Smart Grid plans advocated by both Canadian
and US policy makers, the gross nameplate rating of 20 MVA acquired from NERC registration
restricts the penetration of dispersed generation in many parts of North America. We suggest the
following: • Generation restriction (20 MVA or 75 MVA) should either be revised or the exception
procedure should allow entities, with the support of technical evidence, to exclude element(s) from
being labeled as part of the BES. • Entities should be able to use the exception process, with the help
of technical evidence, to exclude generating units that do not impact the interconnected grid and the
bulk transfer of power. • The path to generating facilities does not need to be BES contiguous.
Generating units can be required to be planned, designed, and operated in accordance with a subset
of NERC Standards, but should not require a contiguous path unless the unit is identified essential for
the operation of transmission network. • Definition and/or exception process should provide clear
acknowledgement and flexibility to avoid any regulatory conflicts. - For example: NERC and SDT
should consider introducing a concept of a new category of registration or BES Support (BESS)
elements. These elements are NOT BES but support the reliable operation of the interconnected
transmission network. A sub-set of relevant NERC Standards should still apply to BESS elements such
as planning, design, and maintenance. However, they may not be subject to mandatory compliance.
No
We agree with the concept of Inclusion I3 with respect to multiple generating units located at a single
site, but do not support that the entire contiguous path has to be BES. The path of a 75 MVA plant or
aggregated generation will rarely have any impact on the reliability of the interconnected transmission
network nor is it necessary for its operation. We also do not support the fact that there should be a
blanket application of this inclusion. As stated earlier, under various green energy, smart grid and
dispersed renewable energy plans advocated by both Canadian and US policy makers, the gross
nameplate rating of 75 MVA may undermine and deter the future potential of integrating Distributed
Generations (DG’s) that will be implemented to ensure the reliable operation of the interconnected
transmission network BES, and, at the same time, providing the most effective and economical
solutions for the rate payers in North America. Local generation can cost-effectively enhance the
reliability of load pocket by avoiding transmission, but such restrictions would deter the adoption of
good planning decisions. Upcoming load displacement projects would result in the installation of new
self-generation facilities at customer sites, with the electricity generated being used on-site by the
customer, with a resultant decrease in the consumption of electricity purchased via large scale
generation. These projects can be large, and displace a substantial portion of the customer’s (or local
distribution company’s) existing load, even to the extent of total self-sufficiency and the availability of
surplus generation. The aggregated surplus generation capacity may very well exceed 75 MVA and
would consequently force the facility owners to register as both Generation Owners (GO) and
Transmission Owners (TO), which may be in conflict with regulatory rules in many jurisdictions. We
suggest the following: • Generation restriction (75 MVA) should either be revised or the exception
procedure should allow entities, with the support of technical evidence, to exclude element(s) being
labeled as part of BES. • Path to generating facilities need not be BES contiguous. Generating units
can be required to be planned, designed, and operated in accordance with a subset of NERC

Standards, but should not require contiguous paths. • Entities should be able to use the exception
process, with the help of technical evidence, to exclude generating units that do not impact the
interconnected grid and the bulk transfer of power. • From a regulatory perspective such an inclusion
could also be in conflict with the current regulatory requirements in one or more Canadian
jurisdictions. Definition and/or exception process should provide clear acknowledgement and flexibility
to avoid any regulatory conflicts. For example, as stated earlier (Q4 response) NERC and SDT should
consider introducing a concept of a new category of registration or BES Support elements. These
elements are NOT necessarily BES but support the reliable operation of the interconnected
transmission network.
No
We do not agree with Inclusion I4. Blackstart resources and transmission facilities on the cranking
path should not be classified as BES regardless of size and voltage level. From a regulatory
perspective, such an inclusion would be in conflict with the current regulatory requirements in many
of the jurisdictions. More importantly, designating these facilities as BES Elements or Facilities beyond
the 100 kV bright line, the 20 MVA/unit or 75 MVA/plant criteria, without a regard to their impact on
the BES (under conditions other than system restoration) will impose unnecessary requirements for
these facilities, which do not contribute to reliability under interconnected operation conditions. For
restoration condition, this inclusion is extraneous given there is already a designation specific for
system restoration covered by an existing standard to recognize their reliability impacts and to ensure
their expected performance. NERC Standards EOP-005-2 stipulates the requirements for testing
blackstart resource and cranking paths. This testing requirement suffices to ensure that the facilities
critical to system restoration are functional when needed, which meets the intent of identifying their
criticality to reliability. While we do not disagree with the SDT’s interpretation of the FERC directives,
the BES definition should cover those facilities that are needed for operation under both normal and
emergency conditions, which includes situations related to black-start and system restoration. We do
not agree that the directives specifically ask for inclusion of blackstart resources and facilities on the
crank path in the BES definition. We believe the requirements in EOP-005-2 suffice to address the
SDT’s interpretation and concern regarding recognition of the reliability impacts and requirements for
blackstart resources and facilities used for system restoration. Generating units of any size and
transmission facilities of any voltage level may be used for blackstart and restoration. Conceivably, a
generator of 10 MW and transmission facilities of 44 kV or 69 kV may be a part of the cranking path.
A BES inclusion will then subject these generators and facilities, which are essentially “local” facilities
but called upon to begin restoring its bulk interconnected counterpart, to comply with the reliability
standards intended for maintaining BES reliability. Included in the BES definition will thus discourage
smaller generators from providing blackstart capability, and the transmission facilities from being a
part of the cranking path. This may also discourage Transmission Owners and Operators from
identifying multiple blackstart resources and cranking paths to provide restoration flexibility. Such an
inclusion will ultimately undermine reliability. If indeed any of these facilities are deemed necessary to
support bulk power system reliability at times other than system restoration, they would/should have
been identified through the basic BES definition and inclusion list or can be addressed through the
exception procedure. We suggest and urge the SDT to drop I4 on the basis that: • The availability and
performance expectations of blackstart resources and facilities on the cranking path are already
specifically addressed in an existing standard; and • Unless they meet the BES definition and the
other inclusion criteria, they do not have any perceived reliability impact on everyday operation of the
BES.
No
We agree with the concept of Inclusion I5 but do not support that the entire contiguous path has to
be BES. The path or aggregate generation will rarely have any impact on the reliability on the
interconnected transmission network nor is it necessary for its operation. These are generally referred
to as connection facilities. As stated earlier, with the Green Energy and Smart Grid plans and
dispersed renewable energy advocated by both Canadian and US policy makers, the gross nameplate
rating of 75 MVA may undermine and deter the future potential of integrating DG’s that will be
implemented to ensure the reliable operation of the interconnected transmission network BES, and, at
the same time, provides the most effective and economical solutions for the rate payers in North
America. Local generation can cost-effectively enhance the reliability of load pocket, by avoiding
transmission, but such restrictions would deter the adoption of good planning decisions. (Refer to Q4
comments).

Yes
We agree with this concept as part of establishing a bright-line definition, as well as clarifying this
exclusion as part of the revised BES definition. Although the concept is consistent with the statements
in the FERC Order, it is imperative to understand that the limitations of E1 will have a direct impact on
many entities (big and small) along with distribution companies across North America. The exclusion
requirements are extremely restrictive with little or no technical basis and are limited to the fact that
these parametric restrictions may not have any reliability impact in terms of location, configuration of
element, and system characteristics. The radial characteristics and/or the reliability of the
interconnected transmission network is determined by the amount of installed generation or a single
transmission source or an interrupting device. For example, a redundant double circuit designed to
supply the load with adequate protection and isolation beyond the radial tap could be significantly
better for load supply-continuity and reliability. We suggest if more than one transmission source feed
radial load to ensure customer supply continuity and reliability then this should be either part of the
bright-line definition as long as there is adequate protection and, the loss of any single transmission
source does not affect the interconnected transmission network. Accordingly, it will be an
understatement to suggest that the SDT: • Carefully craft the exception criteria and procedure that is
flexible and technically sound to adequately allow entities to present their case to the ERO for
exclusion • Exception criteria should be at a high-level with key menu items of assessment that can
be followed continent-wide by entities to put forward their exception for element(s) mentioned in
exclusions or inclusions based on technical assessment, evidence and justification for its unique
characteristics, configuration, and utilization • Acknowledge and provide provisions in both NERC
exception criteria and exception process for federal, state and provincial jurisdictions.
Yes
We agree with most of the changes in Exclusion E2. However, we feel there is a need for evidence or
technical study in regards to the limits described in I2 & I3. The real net aggregated power seen by
the bulk power system at the interconnection, with the outlook of distributed generation systems,
may be different than past experience. Hence it requires to be reassessed based on technical studies
with respect to the future integration of DG’s. (Please refer to comments in questions: 3 & 4). To
establish a bright-line definition, E2 exclusion may be acceptable if the SDT provides adequate
provisions within the exception procedure. See response to Q8 Accordingly, we suggest the SDT
carefully craft the exception criteria that will allow entities to present their case to the ERO for
exclusion from E2 requirements.
Yes
We agree with this concept as part of establishing a bright-line definition along with this clarifying
exclusion in the revised BES definition. However, requirements in Exclusion E3 are restrictive and we
do not agree to the limits on connected generation for Local Distribution Networks (LDN), described in
part (b). The development and implementation of distributed generation will grow considerably in the
future and will operate together with conventional sources of energy. The real net aggregated power
of distributed generation seen by the bulk power system at the interconnection may be larger than
past experience; hence it requires to be reassessed based on technical studies with respect to the
future integration of DG’s. (Please refer to comments in questions: 3 & 4) Also, we suggest combining
exception E3 (c) and (d) as follows: “(c) Power is intended to flows only into the LDN: The generation
within the LDN shall not exceed the electric Demand within the LDN; The LDN is intended to deliver
power to load and not be used to transfer bulk power between different locations in the BES. It is
recognized that under specified system conditions, bulk power transfers may take place between
different points of the BES via the LDN. However, for these conditions BES reliability is not dependent
on the existence of these power flows through the LDN.” Finally, we suggest and urge the SDT to
carefully craft the exception criteria & procedure that is flexible and technically sound to adequately
allow entities to present their case, and/or unique characteristics of the elements under exception to
the ERO for exclusion
No
Small utility or distribution provider is a relative term. A smaller distribution provider may have an
impact on the transmission network while a large one may not; this is based on their design,
configuration and protection. Hence, such an exception should apply regardless of the size of an
entity. Having said that, the concept discussed here is to define a radial system and not a small
utility, as mentioned in the FERC Order. We do not believe that the SDT had sufficient discussions
while crafting the proposed exclusion in regards to small utilities. The language used in the proposed

clause is only appropriate to establish a bright-line definition for a radial system. It is worth noting
that many small utilities (and individual load customers or generation connections) would have more
than a single transmission source with a solid tap and, at the same time, be adequately protected and
effectively isolated without any adverse impact on the transmission network. Such a practice and
design is widely used across North America. Hence, we do not agree that this exclusion is an attempt
to address the issue of small utilities. The definition and inclusions will force many small entities, load
customers and generation unit owners to act and register as Transmission Owners. In some parts of
the continent this would be in conflict with state or provincial regulatory act, Codes and Licenses.
Consistent with the FERC Order, the ERO and the SDT should be aware of these conflicts and should
not ignore them for later. Hence, we suggest the ERO and the SDT address this by providing explicit
but simple provisions in the exception procedure by considering sound technical exception criteria
that is flexible based on demonstration of evidence to justify the element’s necessity for operation.
Regulatory Acts and Rules will always trump NERC requirements and hence we suggest that the only
evidence that should be required of small utilities/entities is: • Regulatory evidence • Evidence
demonstrating that NO adverse reliability impact is afflicted on the interconnected BES because of
their connection.
No
We commend the SDT for their concept in putting forward a 100kV BES bright-line definition.
However, we do not believe that the current definition drafted by the SDT has differentiated between
Transmission and Distribution or excluded distribution facilities from the BES, or addressed the issue
of local distribution facilities above 100kV. It is important for the ERO and the SDT to understand and
be consistent with the FERC Order for these important but complex issues. Otherwise, many parts of
the continent could be in conflict with state or provincial regulatory act, Codes, and Licenses. We urge
the ERO and SDT and RoP teams be aware of these conflicts and not disregard them, as they will pose
many implementation complexities and confusion within the industry. Regulatory Acts and Rules will
always trump NERC requirements and hence it is important that ERO should neither be caught in
regulatory conflict nor put entities in these situations. It is worth noting that different jurisdictions
may use different terminology for “distribution” or non transmission facilities or elements. For
example, some jurisdictions label certain facilities as distribution which connect and are owned and
operated by the distribution utility, customer or a generator customer while other label them as
connection facility or elements. As stated earlier (Q10), we believe that the ERO and SDT can address
this by providing explicit but simple provisions in the exception criteria (to be used by exception
procedure) by putting forward a menu of key technical assessments , which are based on
demonstration of evidence to justify the element’s necessity for operation. For example, we suggest
that for local distribution, the evidence that should be required is: • Regulatory evidence. • Evidence
demonstrating that NO adverse reliability impact is afflicted on the interconnected BES because of
their connection. Some of the other key attributes of such an exception criteria should be: • Elements
are not to be part of interconnection between two balancing authority or contribute to IROLs • Entire
system cannot be classified as contiguous • BESS Elements within exclusion can still be subject to
relevant NERC Standards • Entity to justify whether or not the elements are necessary for the
operation of the interconnected transmission network • Distinguish if the element in question supplies
load centers, major cities, serves the national interest and/or possibly impact national commerce or
national security, or is identified by the relevant regulatory authority. Accordingly, we suggest that
the exception criteria should ONLY list a menu of items and a prescribed report template that should
be assessed and presented by an entity as their evidence and justification for exception to a RE, the
ERO and any relevant regulatory authority. This evidence and justification would be used by the ERO
as part of its decision making process.
Yes
See earlier comments and suggestions. NERC’s revised definition will have a direct impact on many
entities across North America and could also be in conflict with regulatory requirements, Codes, and
Licenses, which non FERC jurisdictional must comply. It would be impossible to identify each of these
conflicts. For example: in one of the energy acts, NERC Standards can only apply to generation over
50 MVA which will cause one or more of the requirements to be in conflict and /or what constitutes
distribution and what is not considered transmission (such as connection facility to a load or
generation and owned by the proponent). However, we agree to establish a 100kV BES bright-line
definition and we believe that the best venue to address avoiding compliance conflicts is through the
exception criteria and the exception process. The benefits of such an approach are: • Establishment of

a continent wide bright line definition • Avoidance of regulatory conflicts and legal complexities •
Assurance of the reliability of the interconnected transmission network
We believe that the concepts of inclusions and exclusions as part of the bright-line definition are
excellent. However, these exclusions do not address several directives in Order No. 743 and 743A,
such as: differentiation between Transmission and Distribution, non-jurisdictional concerns, or
distribution. We believe that the BES definition itself is not a venue to address these concerns but
suggest that these issues should be explicitly addressed by the ERO’s exception criteria and exception
process. Currently, the posted exception criterion is only a concept with many gaps and TBD, as
posted details are later to follow. We suggest that the exception criteria should be a menu of technical
items (load flows, stability analysis etc) and non technical items (type of loads such as distribution
companies vs. major city center, national security etc). Entities should be required to assess and
provide their own justification under each category with a conclusion that takes into account all of the
relevant items for element(s) under exception, in a consistent template and table of contents. We
suggest the SDT to avoid specification of any parameters as they would differ under different design
concepts, system configurations, system characteristics and regulatory requirements.
Group
LG&E and KU Energy LLC
Brent Ingebrigtson

Yes LG&E and KU Energy have a concern that the approval and adoption of the BES definition project
and BES exception procedure project are not linked. This would produce the possibility of the BES
definition project completing and Registered Entities having to comply without having the appropriate
and promised BES exception procedure in place to alleviate unreasonable compliance actions. More
specifically, if the BES definition gets approved and BES exception procedure has not yet been
approved (whether due to project delay or disapproval), then Registered Entities are required to
ensure everything within the new definition is compliant, even if doing so is unreasonable or entirely
unnecessary.
Individual
Mark Thompson
Alberta Electric System Operator
Yes
Yes
Yes
Consider adding the word “transformer” after “GSU”.
Yes
Consider adding the word “transformer” after “GSU”.
Yes
Yes

Yes
Yes
Yes

Yes
Yes
Comments: Alberta’s legislation enables reliability standards, but prevents the AESO from developing
rules related to reliability standards. The AESO therefore would like to see retention of the following
clause from the NERC “Statement of Compliance Registry Criteria (revision 5) included in the list of
inclusions as well as identifying the authority that determines what generators are material to
reliability: III.c.4 Any generator, regardless of size, that is material to the reliability of the bulk power
system. The wording should reflect that, for example, in the case of Alberta, that the AESO has the
authority to make this determination.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
We agree with the first part of E2, but we do not see the rationale for section (ii) and suggest it be
deleted.
No
This seems to be covered by E1.
Yes
No
No
Individual
Reggie Wallace

Fayetteville Public Works Commission
No
The changes made by the SDT with respect to Real Power resources in Inclusion I2 do not ensure a
consistent determination by independent entities of whether a generator should be included within the
BES. The ambiguity in Inclusion I2 has implications on other Inclusions and Exclusions. See the
comments on Question 3 for additional detail.
Yes
No
Inclusion I2 contains wording that is ambiguous and does not support a consistent determination by
independent parties of whether or not a specific generator should be included in the BES. This
definition will be a critical part of the guidance used by registered entities to validate their current
registration status and by new entities to properly determine their initial registration status. It will
also be used by regional reliability entities during compliance activities to verify proper registration.
The ambiguous wording of Inclusion I2 could easily lead to re-interpretation issues between the
owner/operator of the generator and regional entities in a compliance audit or other compliance
setting. To be specific, the phrase "including the generator terminals through the GSU which has a
high side voltage of 100 kV or above" is particularly troublesome. The phrase as written is intended to
establish the boundary of the Real Power resource that will be included in the BES if the conditions of
Inclusion I2 are met. The intent appears to be to include within the BES the generator, the cables
connecting the generator terminals to the GSU, and the GSU, if the GSU has a high side voltage of
100 kV or above. If the GSU, however, does not have a high side voltage of 100 kV or above, then
neither the generator, nor the connecting cables, nor the GSU would included within the BES. The
crux of the problem lies in the interpretation of the term "GSU" and the phrase "through the GSU
which". The term "GSU" or "generator step-up transformer" is commonly applied to a transformer
with a generator directly connected to the low side and a bus directly connected to the high side. This
is not, however, a defined term within the NERC Glossary and no standard for that interpretation is
provided. The very structure of the phrase "through the GSU which" implies that there may be more
than one GSU to be considered, some of which do not but at least one of which does have a high side
voltage of 100 kV or above. This could be interpreted to include multiple transformers (GSUs)
stepping up the generator voltage in series, the first stepping up the generator voltage to a bus, the
second stepping up that bus voltge to another bus, and the third, and so on, and so on, until finally
'THE" transformer (GSU?) is encountered "WHICH" does have a high side voltage of 100 kV or higher.
Thus, if the registering entity were to apply the commonly accepted definition of "GSU" to a
generator, and the GSU directly connected to that generator has a high side of less than 100 kV, that
entity would properly conclude that neither the generator nor the leads nor the GSU should be
included in the BES. If a regional compliance entity applies the interpretation that transformers in
series must be considered until a generator is encountered which does have a high side of 100 kV or
higher, then that compliance entity would properly conclude that the generator, all the transformers
in series, and the buses connecting those transformers should be included in the BES. Clearly this
potential for contradictory conclusions would be better cleared up during this comment period than
repeatedly coming up during compliance processes. I offer two suggestions for eliminating this
ambiguity. The first and preferred method would be to change the wording of Inclusion I2 to read s
follows: "Individual generating units greater than 20 MVA (gross nameplate rating) directly connected
to the low side of a GSU which has a high side voltage of 100 kV or higher. The generator, the leads
directly connecting the generator terminals to the GSU, and the GSU are all included in the BES." The
second method would be to define within the NERC Glossary the term GSU as follows: "A generator
step-up transformer (GSU) is a transformer directly connected to the terminals of a generator on the
low side and to a bus at a higher voltage on the high side."
No
The same comment made in Question 3 and applicable to Inclusion I2 is also applicable to Inclusion
I3.
Yes
No
Because no differentiation has been defined between "power producing resources" in Inclusion I5 and

"generating units" from Inclusions I2 and I3, this Inclusion has the potential to conflict with other
Inclusions. It should be modified to read "Dispersed power producing resources with individual
capacity of 20 MVA or less (gross nameplate rating) but with aggregate capacity greater than 75 MVA.
. ."
No
Exclusion E1 references Inclusions I2 and I3. Therefore the comments provided in Question 3 with
respect to Inclusion I2 are pertinent here as well. The radial system cannot be excluded if it includes
any generation resources that are included in Inclusion I2. The ambiguity that exists in Inclusion I2
could, therefore, also have consequences in determining if a radial system can be excluded. If the
recommended changes are made in Inclusion I2 then Exclusion E1 is acceptable as is.
Yes
Yes
Yes
Yes
No
None
Individual
Gary Kruempel
MidAmerican Energy Company
Yes
Yes
Yes
Yes
Yes
No
It is suggested that the inclusion be modified to include a more definitive description of the portion of
the facility that would be considered to be in the BES. It is suggested that the phrase "from the point
where the aggregated rating exceeds 75 MVA" be added after collector system in I5. The revised
inclusion would then read as follows: Dispersed power producing resources with aggregate capacity
greater than 75 MVA (gross aggregate nameplate rating) utilizing a collector system from the point
where the aggregated rating exceeds 75 MVA through a common point of interconnection to a system
Element at a voltage of 100 kV or above.
No
The statement “originating with an automatic interruption device” seems to go beyond differentiating
what is radial. If that were removed, the rest of the draft exclusion seems to capture what is radial.
Yes
Yes
Arbitrarily excluding small entities could affect reliability depinding on the specific transmission
facilities the entity owns and/or operates.

No
We disagree that the SDT has appropriately excluded local distribution facilities through the revised
bright-line core definition and specific inclusions and exclusions. A similar bright line criterion
excluding facilities below 100 kV would be better. The intent is to clearly define facilities below 100kV
(exclusive of resources added under criterion I4) as local distribution (excluded from FERC jurisdiction
in accordance with the Federal Power Act). Critical facilities below 100 kV would be brought back in
under the provisions of inclusion exception criteria of the Technical Principles for Demonstrating BES
Exceptions procedure.
No
While there were no questions directed to the draft implementation plan in the comment form, if the
intent was to also solicit comments on that plan, the schedule in that plan is likely too agressive if the
result of the revised BES definition is that new facilites are brought into the BES and are thereby
obligated to now comply with standards they had not previously been required to meet. Perhaps a
provision should be added to the implementation plan to address this situation and allow an extended
schedule for new BES facilities to comply with applicable standards.
Individual
Dennis Minton
Florida Keys Electric Cooperative
Yes
Yes
Yes
Yes
Yes
Yes
Yes
FKEC agrees with the comments of FMPA as shown below: FMPA agrees with the intent / concept, but
has suggested wording changes to add clarity. The words “described as” should be deleted from the
exclusion to avoid confusion. What matters is how the system is actually connected, not how
someone describes it. In addition, “a single Transmission source” should be defined, and should be
generic enough to encompass the various bus configurations. It is not the case, for example, that
each individual breaker position in a ring bus is a separate Transmission source; in that case, a bus at
one voltage level at one substation should be considered “a single transmission source.” Some
examples of configurations that should be considered a single transmission source for this purpose
are at https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples
1-6. The phrase “automatic interrupting device” should be replaced with the phrase “switching
device.” Many radials are connected to ring buses or breaker-and-a-half schemes where the breakers
(automatic interrupting devices) are within the bus arrangement where the appropriate division
between BES and non-BES is at the disconnect switch as the radial “takes off” from the bus
arrangement. As written, E1 would eliminate most radials from automatic exclusion and force most of
them into the Exception Procedure. For instance, see examples 2 of the FRCC draft BES definition
Appendix A at https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf).
Switch "A" in example 2 is usually not automatic. Breaker D and E are automatic. Switch A is radial,
Breakers D&E may not be. FMPA recommends replacing "automatic interrupting" with "switching" and
allow manual switching devices to establish the boundary between BES and non-BES, otherwise we
get into splitting up ring-buses or breaker-and-a-half schemes, or flooding the Exception Procedures
with a lot of needless requests. Also, "device" is singular whereas the exclusion is for a "radial
system". I presume that the SDT intends that if there are two lines originating at the same substation

supply a load in a redundant nature, that the "radial system" would be excluded (see examples 1, 3
and 4 of the FRC draft BES Definition Attachment A), which would mean there would be more than
one device. Also, the phrase "A normally open switching device between radial systems may operate
in a ‘make-before-break’ fashion to allow for reliable system reconfiguration to maintain continuity of
electrical service." is misplaced in bullet a) and belongs in the non-bulleted section. FMPA
recommends re-wording E1 to be: "Any radial system which is connected from a single Transmission
source (such as a contiguous bus configuration like a ring bus or breaker-and-a-half scheme)
originating with switching device(s) and meeting the criteria in bullets a, b or c below. A normally
open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow
for reliable system reconfiguration to maintain continuity of electrical service. a) Only serving Load b)
Only including generation resources not identified in Inclusions I2, I3, I4 and I5 c) A combination of
(a) and (b)"
Yes
Yes
FKEC agrees with FMPA's comments shown below: FMPA agrees with the intent / concept, but has
suggested wording changes to add clarity. The exclusion refers to groups of Elements that “distribute
power to Load rather than transfer bulk power across the interconnected system.” The use of the
term “bulk power” is vague and could be read incorrectly as a reference to the “bulk-power system,”
which is defined in the Federal Power Act but is not a NERC defined term. If the LDN is connected to
the BES at more than one location, there will by definition be some loop flow. We recommend below
that Exclusion 3(d) be revised to quantify the amount of loop flow that is permissible in an excluded
LDN. In the context of the first sentence of Exclusion E3, less specificity is needed, and the sentence
should only be revised for the sake of accuracy to state: “Groups of Elements operated above 100 kV
that are primarily intended to distribute power to load rather than to transfer power across the
interconnected System.” The exclusion’s reference to connection “at more than one location” is
vague. The sentence should be revised to read “connected to the Bulk Electric System (BES) from
more than one Transmission source solely to improve the level of service to retail customer Load,”
and “Transmission source” should have the same meaning that it does in E1. E3(a) should require
that there be switching devices between the LDN and the BES, not specifically automatic faultinterrupting devices. The term “separable by” in “Separable by automatic fault interrupting devices” is
unclear and should be reworded. E3(b) To avoid pulling an LDN into the BES based on very small
customer-owned generation (such as rooftop photovoltaics and hospital backup diesel generators)
that the utility does not consider or rely on, or necessarily even know about, the item should be
reworded: “Limits on connected generation: Neither the LDN, nor its underlying Elements (in
aggregate), includes more than 75 MVA of generation used to meet the resource-adequacy
requirements of electric utilities.” E3(d) states “Not used to transfer bulk power.” As noted above,
“bulk power” is a vague term. There will necessarily be some loop flow on a system that is connected
to the BES at more than one location. The amount of permissible loop flow for this purpose needs to
be determined and stated in this item.
Yes
Yes
No

Individual
Thad Ness
American Electric Power
No
Rather than a 75 MVA threshold as designated in I3, we suggest a threshold of 100 MVA which we
believe to be more appropriate. It is difficult to provide comments regarding the BES definition, given
the parallel nature of the other related deliverables currently out for review. For example, there needs
to be a defined relationship between an approved definition of BES, the technical principles for

demonstrating BES exception, and the exception process itself. When closely related projects such as
these are done simultaneously, no individual deliverable can rely on the completed work of another.
As a result, we risk having conflicting decision making across these projects.
Yes
No
The use of the word “including” within I2 seems to imply the inclusion of 20MVA (or greater)
generating units beyond those which have a high side voltage of 100 kV or above. Was this
intentional? If not, the following wording is preferable: "Individual generating units greater than 20
MVA (gross nameplate rating) having a GSU with a high side voltage of 100 kV or above. This
includes equipment installed from the generator terminals through the high side of the GSU."
No
Please see response to question 3.
Yes
While AEP supports the concept of including designated Blackstart Cranking paths as part of the BES,
there is concern that doing so without respect to voltage would unnecessarily include elements which
should not be included as part of the BES. More clarity is needed to explicitly describe the scope of
the inclusion. Is it limited to Transmission facilities or more broad to include Distribution facilities or
even sub-Distribution auxiliary systems? If so, this would unnecessarily bring those sub-systems
under the purview of PRC-005, for example.
Yes
Yes
AEP supports the concept of the exclusion of radial systems, however further clarification is needed
regarding whether or not the source equipment is included as part of the radial system (for example,
ring bus or breaker and a half bus configurations). In addition, “automatic interruption device” should
be defined to alleviate any ambiguity.
Yes
Yes
Yes
AEP agrees with the proposed exclusion to the extent that such excluded small utilities would continue
to provide any needed information the registered entities have requested from the excluded small
utilities to ensure the reliability compliance of those registered entities.
Yes
No
AEP is not aware of any conflicts involving the proposed definition and any regulatory function, rule
order, tariff, rate schedule, legislative requirement or agreement, or jurisdictional issue.
Usage of the NERC term “Element” clearly excludes associated auxiliary equipment such as protective
relay systems and metering systems. If this is not the intent of the SDT, then there needs to be more
comprehensive BES nomenclature established that distinguishes among the applicable primaryvoltage equipment, the associated auxiliary equipment having an impact to the BES, and the
associated ancillary equipment having no electrical impact to the BES. In addition, please see
response to question 1 regarding the request for industry input on concurrent, closely related projects
(approved definition of BES, the technical principles for demonstrating BES exception, and the
exception process itself).
Individual
Rick Drury
East Kentucky Power Cooperative, Inc.
Yes

Yes
Yes
Yes
Yes
Yes
Yes
EKPC has a concern with the wording of the definition for Exclusions: E1 - Any radial system which is
described as connected from a single Transmission source originating with an automatic interruption
device and: a) Only serving Load. A normally open switching device between radial systems may
operate in a ‘make-before-break’ fashion to allow for reliable system reconfiguration to maintain
continuity of electrical service.” This wording leads EKPC to believe that a radial 138 kv line that steps
down into a 69 kv looped system that have no facilities included in the BES would not be excluded as
radial. This line cannot have any more impact on the BES than the 69 kv system it connects to that is
excluded from the BES. Therefore I would add to exclusion E1a, “or only connecting to a transformer
stepping down to a voltage below 100kv”.
Yes
Yes
Yes
Yes
Yes

Individual
Andrew Z. Pusztai
American Transmission Company, LLC
Yes
However, to clarify the core definition, ATC proposes to change the text for Real and Reactive Power
resources from “connected” to “operated or connected”.
Yes
Yes
No
ATC offers the following alternative language: • The wording “connected through a common bus” is
drawn from the NERC Compliance Registry Criteria. ATC agrees with the language if the intent is to let
entities classify the applicable multiple generating units as part of the BES only when it is connected
to one (common) bus. However, if the intent is for entities to also classify multiple generation as part
of the BES when it is connected through two or more GSUs to different bus sections of a set of
(common) buses that are interconnected through bus-tie breakers [which may be done to provide
improved reliability and maintenance flexibility], then wording like “connected through a common bus
or set of interconnected buses” would be more appropriate. • It is also ATC’s understanding that

entities do not have to classify applicable multiple generating units as part of the BES when the
aggregate MVA is connected to different buses at different voltage levels and no more than 75 MVA is
connected to any one bus (or set of interconnected buses) at a single voltage level of 100 kV or more.
Is this a correct interpretation?
Yes
For clarification, ATC understands that only blackstart resources that are part of a Transmission
Operator’s Blackstart Restoration plan are included in I4 (Ref. EOP-005) and should be consistent with
the upcoming CIP-002 version 4 standard. ATC also recommends that the SDT consider adding
Blackstart Resources as a defined term in the NERC Glossary.
Yes
ATC poses the following questions to the SDT for consideration: Which components of the dispersed
power resources would be classified as BES? Are the small wind generator units and terminals
through the GSUs to a higher voltage (e.g. 34.5 kV) collector bus classified as BES Elements? Are the
higher voltage bus, the associated elements (e.g. protection system, cap bank, SVC, etc.), and step
up transformer to a system Element of 100 kV or above to be classified as BES Elements?
Yes
ATC offers the following alternative language: ATC suggests replacing the wording of “connected from
a single Transmission source” with “connected to the Bulk Electric System”. Furthermore, ATC
believes that Exclusion E1 is appropriate and should be part of the definition of the BES. However,
ATC believes that a registered entity should be given the option to not be required to follow the
exclusions in the E1 criteria. Some registered entities for operational and business purposes may wish
to continue to classify their radial system assets, which are operated above 100 kV, as BES
components.
Yes
Yes
No
ATC believes that small utilities have interfacing responsibilities, and should not be exempt if they
own elements (e.g. CTs, batteries, etc.) that are part of a protection scheme that protects the BES
Elements.
Yes
ATC agrees that the revised bright-line core definition and associated inclusion and exclusion criteria
excludes distribution, however, recognizes that there are protection elements that may be owned by
distribution which may trip a BES Element. (Covered by NERC Standard PRC-005)
No

Group
Alabama Public Service Commission
John Free

No

In drafting the inclusions and exclusions that accompany the core BES definition, the SDT needs to be
very careful in considering jurisdictional issues. FERC has recognized in its recent orders regarding the
BES definition that local distribution facilities are not subject to its jurisdiction under Section 215 of
the Federal Power Act. As the SDT considers the scope of the inclusions and exclusions from the BES
Definition, it needs to consider whether the proposed provisions only include: 1) facilities or control
systems that are “necessary” for operating an interconnected electric transmission network and 2)
whether they involve generation facilities that are “needed” to maintain transmission system
reliability. If the proposed inclusions and exclusions result in the BES definition applying to facilities
beyond this “necessary” and “needed” scope (such as local distribution facilities), then the definition
would be inconsistent with Section 215 and could improperly make those facilities subject to
“reliability standards” contrary to the Federal Power Act. The APSC generally supports the BES Core
Definition and all three Exclusions proposed by the SDT. The APSC strongly supports Exclusion E3 for
local distribution networks and Exclusion E1 for radial systems (subject to the concerns below).
Exclusion E3 will ensure State jurisdiction over facilities that are used in the local distribution of
electric energy. The APSC does not support Inclusion I2 for individual generating units greater than
20 MVA. Inclusion I2 should be eliminated entirely because it will result in too many radial subtransmission load serving facilities losing their non-BES status, when those facilities are not
“necessary” for bulk power system reliability. The APSC supports Inclusion I3 (75MVA) as a sufficient
generating unit threshold for purposes of this definition. If Inclusion I2 is eliminated, then the
reference to Inclusion I2 within Exclusion E1 should also be eliminated.
Yes
See comments in response to Question 11 above.
The Alabama Public Service Commission (APSC) appreciates the fact that a member of the Oregon
PUC Staff is participating on this BES Definition drafting team. In reviewing the proposed definition,
the APSC’s focus is to ensure that appropriate definitional lines are drawn so that recognized
jurisdictional boundaries are acknowledged and respected. The concern underlying this focus of the
APSC is the fact that utilities must make significant investments to comply with mandatory reliability
standards and, accordingly, compliance with such standards must be necessary and not duplicative.
Furthermore, there should be a commensurate reliability benefit associated with the cost of the
investments needed for compliance. The proposed definition and NERC’s development of standards
should focus on reliable operation of the interconnected electric transmission network (BES) in order
to prevent local events from affecting other regions, not to ensure reliable operation at the local level.
Individual
Linda Jacobson
Farmington Electric Utility System
Yes
Yes
Yes
Yes
No
The drafting team should consider adopting language similar to CIP-002-4 for Cranking Paths.
Cranking Paths up to the the point on the Cranking Path where two or more path options exist.
Yes
Yes
Yes
Yes

Yes
Yes
No
The Rules of Procedure for Exceptions should define the compliance expectation of the entity while an
exception is being considered; similar to the CIP TFE process.
Individual
Rich Salgo
Sierra Pacific Power Co d/b/a NV Energy
Yes
The revised core definition serves to address the directives of the Commission Order in 743 and 743A,
particularly the elimination of regional discretion, and it also eliminates the ambiguity of the word
“generally”.
No
We agree with the concept; however there are two issues that must be resolved. First, the “two
windings” language should be changed to “two terminals”, as in the case of an auto-transformer,
there is technically only one winding, and it would fail to be included in this inclusion designation as
written. Second, a literal read could have an unintended interpretation that transformers with fewer
than 2 windings at 100kV might still be included through the core definition. The SDT should consider
whether this I1 inclusion item would be better applied in the converse as an exclusion designation.
Yes
While 20MVA has no technical basis for the threshold above which a generator should be considered
to be necessary for the reliable operation of an interconnected transmission network, the industry has
not provided any technical data to support a value other than this which has been established in the
NERC Statement of Compliance Registry Criteria.
Yes
While 75MVA has no technical basis for the threshold above which an aggregate generation plant
should be considered to be necessary for the reliable operation of an interconnected transmission
network, the industry has not provided any technical data to support a value other than this which
has been established in the NERC Statement of Compliance Registry Criteria.
Yes
Yes
Similar to the response to Q4, the 75MVA has no technical basis as being a threshold for determining
necessity in the reliable operation of the interconnected transmission system; however, no technical
data supports an alternate value.
Yes
Agree with this exception and emphasize that the make-before-break language is essential to be
retained in this exclusion.
Yes
Yes
NV Energy strongly supports the definitional exclusion of LDN’s from the BES, and such exclusion is
necessary to ensure that the BES definition meets the statutory requirement to exclude all facilities
used in the local distribution of electric power. In the characteristics of the LDN, item (d) should be
clarified to eliminate the ambiguity that arises from the term “used”. We suggest the following
revision: Not intentionally used to transfer bulk power: The LDN is not used to provide a transaction
scheduling path for, nor intentionally used to accommodate the transfer of, energy originating outside
the LDN for delivery through the LDN;

Yes
Yes
Through the radial exclusion and the LDN exclusion (E1 and E3), the definition has made a delineation
between distribution and bulk transmission. In this exclusion language, the definition as proposed
addresses the quantifiable parameters from the FERC 7-factor transmission test.
No

Group
Western Electricity Coordinating Council
Michelle MIzumori
Yes
Yes
WECC agrees in concept and understands that the intent of the phrase “other than GSU transformers”
was used to prevent duplication or conflict with I2. However, it has the unintended consequence of
creating the appearance that GSU transformers are not included in the definition, which is more of a
conflict. By removing this phrase, such transformers would be clearly included because, if both
terminals are connected at greater than 100 kV, it will also be true that the high side is connected at
greater than 100 kV, per I2. WECC suggests removing this phrase. Also, the final statement more
appropriately should be “…unless excluded under Exclusions E1 or E3.” Finally, the term “two
windings” may be technically incorrect because some transformers may only have one winding. This
wording would exclude single-winding transformers at or above 100 kV. One option may be to change
the language to “two terminals” instead of “two windings.” It may also be useful to clarify that
transformers with one terminal above and one terminal below 100 kV should be excluded.
Yes
WECC agrees in concept, but the language could be clarified on the GSU transformer. Suggested
language “Individual generating units greater than 20 MVA (gross nameplate rating) including the
generator terminals up to and including the GSU transformer, which has a high-side voltage of 100 kV
or above.”
Yes
WECC agrees in concept, but suggests that the phrase “connected through a common bus” may be
unclear. For example, if there is also load connected through that common bus, does that net, does it
negate the inclusion, or does it not matter? Perhaps a phrase such as “regardless of the amount of
load also connected through that common bus” would help. The GSU comment from I2 also applies.
Suggested language “…including the generator terminals up to and including the GSU transformer,
which has a high-side voltage of 100 kV or above.”
Yes
Yes
WECC agrees in concept, but it is unclear why there is the new term “power producing resources.” Is
this meant to include both Real Power Resources and Reactive Power Resources (terms used in the
base definition)? This should be clarified. In addition, it appears from comments of the drafting team
that the intent of this inclusion was primarily for wind and solar farms, but the language would also
pull in traditional generation that happens to be connected at a single point. The language should be
clarified so that it only captures the intended generation.
Yes
WECC generally agrees in concept. However, it is unclear what is required to demonstrate the “makebefore-break” connection. Is this intended to mean that the normally-open switch is mechanically or
electrically interlocked to ensure the “make-before-break” requirement is met? It would be a normal
switching practice to close the normally-open switch to make the parallel before opening the
normally-closed switch, but is the normal switching practice sufficient to make this claim? Also, it is

unclear whether the automatic interruption device itself is a part of the BES.
Yes
WECC agrees in concept, but it is unclear what happens if/when the “binding obligation” ends, as well
as what constitutes a “binding obligation.” E2(ii) should be clarified as to what constitutes “standby,
back-up, and maintenance power services provided…pursuant to a binding obligation.” This may
cause administrative burden to monitor such binding commitments.
Yes
WECC agrees in concept. However, in sub-bullet b), it should be clarified that the 75 MVA is grossaggregate nameplate, as described in the inclusions. In sub-bullet c), it should be clarified whether
this requirement is at any time or is for hourly integrated values. Also, the use of the term “major
transfer paths” should be modified to be “major transfer paths in the Table titled Major WECC
Transfer Paths in the Bulk Electric System.” Finally, the reference to “above 100 kV” should be “at or
above 100 kV” for consistency.
No
As written, it is unclear how this exclusion differs from the Radial exclusion. The term “single
Transmission source” needs to be clarified – it could be read to be a single line or a single entity,
which would change the meaning of this exclusion. It is also improper to include registration criteria in
a definition. Furthermore, “small utility” needs to be defined more clearly. The last sentence appears
circular because ownership of a transmission element would draw the owner into registration.
Yes
No
The definition should also reference the exception process and technical justification allowed for
further inclusion or exclusion from the BES.
Group
Western Montana Electric Generating and Transmission Cooperative
William Drummond
No
As a general matter, Western Montana Electric Generating and Transmission Cooperative (WMG&T)
supports the approach the Standards Development Team (“SDT”) has taken to defining the Bulk
Electric System (“BES”). The changes made in the revised core definition are helpful and represent
significant progress toward an acceptable definition. With an effective and efficient exclusion process,
the draft will better define the BES as a whole. We urge the SDT to bear in mind the restrictions
contained in Section 215 of the Federal Power Act (“FPA”) The “bulk-power system” (As per FERC, we
treat the statutory term “bulk-power system” as equivalent to the term ordinarily used in the
industry, “Bulk Electric System”) definition imposes a clear limit on the reach of the mandatory
reliability regime. The BES is made up of only those “facilities and control systems necessary for
operating an interconnected electric energy transmission network (or any portion thereof)” and
“electric energy from generation facilities needed to maintain transmission system reliability.”
Congress reinforced that limit in Section 215(i), where it emphasized that the FPA authorizes the
imposition of reliability standards “for only the bulk-power system.” WMG&T is concerned that the
SDT’s proposed definition is overly-broad, and that it will sweep in many Elements that have little or
no material impact on the reliable operation of the interconnected bulk transmission grid. For
example, the definition uses the arbitrary 20 MVA threshold from the NERC Statement of Registry
Criteria for inclusion of generators. Accordingly, for the BES definition to conform to the requirements
of the statute, the SDT must adopt an effective mechanism to exempt facilities like these that are
improperly swept in by the SDT’s brightline approach to inclusions and exclusions. For this reason, the
Exception process to accompany the SDT’s definition is of critical concern. If the SDT incorporates this
statutory language as its core definition, it will have addressed FERC’s primary concern with a
minimum of disruption to the current NERC system of definitions. The definition could then be further
elaborated to show specific points of demarcation for each inclusion and exclusion similar to that
Proposal 6 from the WECC Bulk Electric System Definition Task Force (“BESDTF”) team to further
delineate BES and non-BES facilities.

No
In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and nonBES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is
stepped down from transmission voltages to distribution voltages. We believe, however, that the SDT
should undertake the effort to more clearly define the point where the BES ends and non-BES
systems begin. In this regard, we note that the WECC Bulk Electric System Definition Task Force
(“BESDTF”) has devoted considerable effort to this question and has developed one-line diagrams
noting the BES demarcation point for a number of different kinds of Elements that are common in the
Western Interconnection. Using this work as a starting point, the SDT should be able to provide much
useful guidance to the industry with relatively little additional effort. Also, the reference to “two
windings of 100 kV or higher” may create some confusion because many three-phase transformer
banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We suggest
clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”
We again urge the SDT to consider further delineation of points of demarcation similar to WECC
BESDTF Proposal 6.
No
WMG&T is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20
MVA threshold discussed in our response to question 3, the 75 MVA threshold appears to have been
drawn from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition. In the same comments,
the SDT also states that it has considered “the inclusion of generator step-up (GSU) transformers and
associated interconnection line leads and believes the BES must be contiguous at this level in order to
be reliable.” Unfortunately, the SDT appears to have concluded that any interconnection facility
operating above 100-kV should be classified as BES. The result will be to require Generation Owners
to register as Transmission Owners/Operators, as well, producing substantial additional compliance
costs for those Generation Owners but resulting in little or no improvement in the reliability of the
BES. We recommend that the SDT, like the Project 2010-07 SDT (commonly referred to as the GO/TO
Team), give careful consideration to the practical results of its recommendations rather than relying
on abstract conclusions about whether a “contiguous” or “non-contiguous” BES is more desirable. We
are concerned that the SDT’s pursuit of a “contiguous” BES will result in a substantially over-inclusive
BES definition. The “contiguous” BES concept implies that every Element arguably necessary for the
reliable operation of the interconnected bulk system must be included in the BES definition, even if it
is interconnected with Elements that have no bearing on the operation of the BES. NERC’s Standards
Drafting Team for Project 2010-07, has already considered this question and, based on an in-depth
review of potentially applicable reliability standards, has concluded that generation interconnection
facilities, even if operated above 100-kV, need to comply only with a limited set of reliability
standards in order to achieve the reliability goals. Much of the work of the Project 2010-07 SDT is
applicable to the work of the BES Standards Development Team. For example, the Project 2010-07
Team observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to Transmission
Owners and Transmission Operators who own and operate transmission Facilities and Elements that
are part of the integrated bulk power system.” Similarly, a “contiguous” BES suggests that, because
certain system protection facilities, such as UFLS relays, are ordinarily embedded in local distribution
systems, the local distribution system, along with the UFLS relays, must be classified as BES to make
the BES “contiguous.” Such a result is not only plainly contrary to the local distribution exclusion
embedded in Section 215 of the FPA, but would, by improperly classifying local distribution lines as
BES “Transmission” facilities, result in huge regulatory compliance burdens with little or no
improvement in bulk system reliability.
No
WMG&T is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20
MVA threshold discussed in our response to question 3, the 75 MVA threshold appears to have been
drawn from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission

system reliability” and are therefore properly included in the BES definition.
Yes
Including “all” blackstart and blackstart cranking paths in the BES may ultimately provide an incentive
to the electric industry to reduce the number of resources with blackstart capability. We therefore
suggest that essential blackstart resources identified by the Regional Entity should be included in the
Bulk Electric System, but non-essential blackstart resources need not be.
No
WMG&T agrees that it is important to address wind generation facilities and similar generation
facilities in which a large number of generating units, each with a relatively small capacity, are
clustered and fed into the grid at a single interconnection point. That being said, WMG&T is concerned
that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our comments on
Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained. We believe the exclusion as drafted adequately defines radials.
No
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through
reference to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the
generation unit is reliability-must-run or essential blackstart, the function of the unit is irrelevant to
the reliable operation of the interconnected bulk transmission grid, and we therefore believe the
reference to the function of the generation unit (“standby, back-up, and maintenance power…”)
should be eliminated.
Yes
WMG&T strongly supports the categorical exclusion of Local Distribution Networks from the BES. In
fact, for reasons discussed at length in our answer to Question 1, we believe the exclusion is
necessary to ensure that the BES definition complies with the statutory requirement to exclude all
facilities used in the local distribution of electric power. LDNs are, of course, probably the most
common kind of local distribution facility. Further, the conversion of radial systems to local
distribution networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. WMG&T supports the
LDN exclusion, but we believe the exclusion should be refined in the following respects: • The SDT’s
draft states that: “LDN’s are connected to the Bulk Electric System (BES) at more than one location
solely to improve the level of service to retail customer Load.” We recommend that the SDT revise the
sentence quoted above as follows: “LDN’s are connected to the Bulk Electric System (BES) at more
than one location to improve the level of service to retail customer Load and not to accommodate
bulk transfers of power across the interconnected bulk system.” By instituting this suggestion, the
SDT would emphasize the key difference between an LDN, which is designed to reliably serve local,
end-use retail customers, and the BES, which is designed to accommodate bulk transfer of power at
wholesale over long distances.
Yes
WMG&T supports the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that can ill afford the substantial costs that accompany
imposition of mandatory compliance with reliability standards. Further, we agree that the small
utilities covered by the exemption will have no measurable impact on the operation of the
interconnected BES. In the Pacific Northwest, many small entities were required to register by virtue
of owning a very small portion of the region’s 115-kV system. These utilities have faced substantial
compliance burdens even though their operations are simply not material to the interconnected bulk
grid in our region, and the investment of resources in compliance therefore will have no measurable
effect in improving the reliability of the interconnected grid.
No
While WMG&T agrees that the approach adopted by the SDT -- a core definition coupled with specific
inclusions and exclusions – will be effective in removing most local distribution facilities from the BES,
it will not remove all such facilities. For the reasons discussed at greater length in our answer to
Question 1, WMG&T believes that the proposed definition is over-inclusive and is likely to sweep up
certain facilities used in local distribution that should not be classified as BES. As discussed in our

answer to Question 3, WMG&T notes that exclusion of facilities from the BES does not mean that
owners of those facilities are entirely exempt from reliability standards. On the contrary, the statute
provides that “users” of the BES can be subject to reliability regulation. Hence, even where an entity
does not own BES assets, it could be required to, for example, provide necessary information to the
applicable Reliability Coordinator and to participate in the regional Under-Frequency Load Shedding
program by setting the UFLS relays in its Local Distribution Network at the appropriate settings. We
note that participants in the WECC BESDTF Task Force generally agreed that appropriate information
should be provided by non-BES entities, although there was considerable concern related to ensuring
that the provision of information was not unduly burdensome.
Yes
The Exceptions process is a necessary part of making this proposal complaint with the Federal Power
Act. As noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is
potentially in conflict with the limitations of the Federal Power Act, and in particular the statutory
exclusion for facilities used in the local distribution of electric energy. The SDT’s approach can meet
the statutory requirements only if the Exception process currently under development results in
facilities that are not properly classified as BES being exempted from regulation as BES facilities.
WMG&T has these additional concerns: • The current definition provides that “Elements may be
included or excluded on a case-by-case basis through the Rules of Procedure exception process.”
WMG&T is concerned that the SDT carefully delineate which entity has the burden of proof in the
exclusion process. The WECC BESDTF approach, which we commend to the SDT, laid out these
burdens in some detail. Under that approach, essentially, if a facility is excluded from the BES by
virtue of the specific exclusions listed in the definition, the Regional Entity bears the burden of proving
that the facility nonetheless has a material impact on the interconnected bulk transmission system
and therefore should be included in the BES. On the other hand, if a facility is classified as BES by
virtue of the list of inclusions set forth in the BES definition, it can still escape classification as BES,
but bears the burden of demonstrating that its facility has no material impact on the interconnected
transmission system. We urge the SDT to give careful consideration to these burden-of-proof
questions and to follow the lead of the WECC BES Task Force. • For the reasons we have explained in
our answer to Question 11, we believe the Exception process is critical both to ensure that the BES
definition is effective in producing measurable gains to bulk system reliability and to ensuring that the
definition will comply with the limitations Congress placed in Section 215. Hence, we believe the
entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES
definition have been assigned to the Rules of Procedure Team, and that changes in the Rules of
Procedure are subject to approval in a process that provides considerably less due process and
industry input than the Standards Development Process. Accordingly, we urge that all elements of the
BES definition, including those elements that have been assigned to the Rules of Procedure Team, be
vetted through the Standards Development Process.
Group
ReliabilityFirst
Jim Uhrin
No
We feel the intent of the FERC Order was to simplify and not complicate the definition and the
inclusion/exclusion process. This definition is now even more complex. we also feel that as a result of
several defined terms such as the LDN teh proposed definition will in most cases exclude portions of
networks in locations such as Washington DC, New York and other Metro Areas, many Munis and
citiies that are currently registered. If the intent is to remove entities from the registry this will in
most likely do it.
Yes
Yes
Yes

Yes
but needs to state if this is ALL paths or just a single path, there may be many.
Yes
but the term "Dispersed Power Producing Resuorces" needs to be defined.
Yes
teh term "Single Transmission Source" needs defined, and as well what elemnents are defined by
"automatic interrupting devices" there is debate out in the industry.
Yes
as long as the resources when removed from service have a load component that accompanies it,
otherwise there could be an impact to the BES.
No
the LDN term must be a NERC defined term and if this is allowed as mentioned in the first comment,
we feel the intent of the FERC Order was to simplify and not complicate the definition and the
inclusion/exclusion process. This definition is now even more complex. we also feel that as a result of
several defined terms such as the LDN teh proposed definition will in most cases exclude portions of
networks in locations such as Washington DC, New York and other Metro Areas, many Munis and
citiies that are currently registered. If the intent is to remove entities from the registry this will in
most likely do it.
No
it needs to be clear that "all" items must be met to be excluded in E4, E4b seems to conflict with I2
that states it needs included, E4a should state a single source unless LDNs are allowed mutilple
sources and then could be considered networked, E4c needs to define who make a the determination
on flow and under all system configurations
No
we feel that BES elements have been included in teh exclusions
No

Individual
Jennifer Eckels
Colorado Springs Utilities
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
Colorado Springs Utilities generally supports Exclusion E3 that provides for the exclusion of Local
Distribution Networks (LDNs) from the BES, with the following modifications: 1) It is not necessary to

articulate the nature of the LDN’s connection to the BES. If the characterizations are met, the number
of connections and the reasons for the connections are immaterial. 2) If the LDN is a normal net
import, there is no need to limit the amount of connected generation since the generation will have no
material effect on the BES. 3) ‘Bulk power transfers’ are acceptable across an LDN if the transfer is to
a nested LDN. Contractual energy, originating outside the LDN and delivered to a nested LDN, for
example, is still load delivery and has the same physical characteristics of a holistic LDN and the
transfer of bulk power is immaterial. We propose changing Exclusion E3 to read, “Local Distribution
Networks (LDN): Groups of Elements operated above 100 kV that distribute power to Load rather
than transfer bulk power across the Interconnected System. The LDN is characterized by all of the
following: a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the
LDN must be connected through automatic fault-interrupting devices; b) Power flows only into the
Local Distribution Network: The generation within the LDN shall not exceed the electric Demand
within the LDN; c) Not used to transfer bulk power, except transfers to nested LDNs: The LDN is not
used to transfer energy originating outside the LDN for delivery through the LDN, except transfers to
nested LDNs; and d) Not part of a Flowgate or Transfer Path: The LDN does not contain a monitored
Facility of a permanent flowgate in the Eastern Interconnection, a major transfer path within the
Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the
Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability
Operating Limit (IROL).”
Yes
Yes
Please refer to comments on question 9 - Exclusion 3
No
Colorado Springs Utilities supports the SDT’s efforts to create an acceptable BES definition directly
linked to an exemption process. Know that WECC has a task force, the Bulk Electric System Definition
Task Force (BESDTF), which has done some notable work on this task. See WECC BESDTF Proposal 6,
Appendix C (http://www.wecc.biz/Standards/Development/BES/default.aspx). The BES definition is
very complex and the BESDTF has already addressed many of the tough issues that have yet to be
addressed in this process, such as: • Local Distribution Network definition for automatic exemption •
Determination of radial facilities • Demarcation of BES and non-BES Elements • Alternate dispute
resolution process • Assignment of the burden of proof for the exemption process • Technical
approach for the inclusion/exclusion determination
Group
Cogeneration Association of California and Energy Producers & Users Coalition
Don Brookhyser

Yes
To respond to WECC's concern, please consider that facilities procure standby service because it is
needed for the facility's operation, not to escape registration or compliance. This is a long-term
commitment, and the sufficiency of the service will be monitored by the state regulatory authority.
"Standby service" is a term well-understood in the industry and generally not further defined in any
utility tariff.

Group
Florida Municipal Power Agency
Frank Gaffney
Yes
FMPA appreciates the opportunity to comment on the draft BES definition. We generally support the
direction taken by the SDT, with some minor changes. FMPA suggests a few clarifying edits to the
core definition. First, the definition should refer to “non-generator Reactive Power resources,” to make
clear that although all generators provide some reactive power, those that do not meet the criteria of
I2-I5 are not included in the BES. There is ambiguity concerning whether a transformer stepping
down from >100 kV to <100 kV is included, though FMPA believes that the SDT intends to exclude
such transformers. It is clear that transformers with two windings >100 kV are included and GSUs for
registered generators are included, but it is somewhat unclear in the current draft whether a 138 kV
to 69 kV transformer is included or excluded, for instance. FMPA suggests making it clear that the
intent of the SDT is to include (a) GSUs associated with BES generators and (b) transformers with 2
or more windings >100 kV, and that other transformers are excluded. We also believe the drafting
team intended to exclude all elements that are not included either under the BES definition and
designations or through the exception process. For the sake of clarity, we suggest that a sentence to
that effect be added to the core definition. Finally, we note that the definition does not currently refer
to the existence of the exception process. We suggest that such a reference be added either to the
core definition (as in the revised text suggested by FMPA in this response) or to the lists of Inclusions
and Exclusions. The following is the core definition incorporating the changes suggested by FMPA: All
Transmission Elements (except transformers) operated at 100 kV or higher, transformers as
described below, Real Power resources as described below, and non-generator Reactive Power
resources connected at 100 kV or higher unless such designation is modified by the list shown below.
The NERC Rules of Procedure [citation] provide an Exception Process through which Elements not
included in the BES under this definition and designations may be included in the BES, and Elements
included in the BES under this definition and designations may be excluded from the BES. Elements
not included in the BES either by application of this definition and designations, or through the BES
exception process, are not BES Elements.
Yes
FMPA supports Inclusion I1 but proposes clarifying edits. To minimize possible confusion as to the
category of transformers being addressed in I1, and the sufficiency of a single applicable Exclusion,
FMPA suggests the following rewording: “Transformers, including phase angle regulators, and not
including generator step-up (GSU) transformers, with two windings of 100 kV or higher unless
excluded under Exclusion E1 or E3.”
Yes
FMPA understands that the intent is to define the BES component of qualifying generators as that
equipment from the generator terminals through the GSU. To convey clearly this point, as well as that
only generators that are both over 20 MVA and connected through a GSU with a high side voltage of
at least 100 kV are included in the BES, I2 should be reworded as follows: “Individual generating
units greater than 20 MVA (gross nameplate rating), connected through a GSU with a high-side
voltage of 100 kV or above. A BES generator includes the equipment from the generator terminals
through the GSU.”
Yes
I3 contains language similar to I2, and should be similarly reworded, as follows: “Multiple generating
units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating), connected through a common bus operated at a voltage of 100 kV or above. A
BES generating plant includes the equipment from the generator terminals through the respective
GSUs.”
Yes
Yes
FMPA agrees with the concept of Inclusion I5 but suggests a language change to clarify what we

understand to be the drafting team’s intent, that the inclusion is intended to apply to dispersed wind
and solar generating plants, and not, for example, to a radially-connected city with an aggregate of
75 MW of small generators behind-the-meter. This distinction is appropriate because such a city
cannot have the same impact on the grid as a 75 MW wind farm; loss of the radial connecting the city
to the grid would result in loss of its load as well as its generation, so that the supply-demand
mismatch would be far less significant. FMPA thus suggests that I5 be revised to read: I5 Wind farm
or solar power installation with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating) utilizing a collector system through a common point of interconnection to a system Element at
a voltage of 100 kV or above.
Yes
FMPA agrees with the intent / concept, but has suggested wording changes to add clarity. The words
“described as” should be deleted from the exclusion to avoid confusion. What matters is how the
system is actually connected, not how someone describes it. In addition, “a single Transmission
source” should be defined, and should be generic enough to encompass the various bus
configurations. It is not the case, for example, that each individual breaker position in a ring bus is a
separate Transmission source; in that case, a bus at one voltage level at one substation should be
considered “a single transmission source.” Some examples of configurations that should be
considered a single transmission source for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples 1-6. The
phrase “automatic interrupting device” should be replaced with the phrase “switching device.” Many
radials are connected to ring buses or breaker-and-a-half schemes where the breakers (automatic
interrupting devices) are within the bus arrangement where the appropriate division between BES and
non-BES is at the disconnect switch as the radial “takes off” from the bus arrangement. As written, E1
would eliminate most radials from automatic exclusion and force most of them into the Exception
Procedure. For instance, see examples 2 of the FRCC draft BES definition Appendix A at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf). Switch "A" in
example 2 is usually not automatic. Breaker D and E are automatic. Switch A is radial, Breakers D&E
may not be. FMPA recommends replacing "automatic interrupting" with "switching" and allow manual
switching devices to establish the boundary between BES and non-BES, otherwise we get into
splitting up ring-buses or breaker-and-a-half schemes, or flooding the Exception Procedures with a lot
of needless requests. Also, "device" is singular whereas the exclusion is for a "radial system". I
presume that the SDT intends that if there are two lines originating at the same substation supply a
load in a redundant nature, that the "radial system" would be excluded (see examples 1, 3 and 4 of
the FRC draft BES Definition Attachment A), which would mean there would be more than one device.
Also, the phrase "A normally open switching device between radial systems may operate in a ‘makebefore-break’ fashion to allow for reliable system reconfiguration to maintain continuity of electrical
service." is misplaced in bullet a) and belongs in the non-bulleted section. FMPA recommends rewording E1 to be: "Any radial system which is connected from a single Transmission source (such as
a contiguous bus configuration like a ring bus or breaker-and-a-half scheme) originating with
switching device(s) and meeting the criteria in bullets a, b or c below. A normally open switching
device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. a) Only serving Load b) Only
including generation resources not identified in Inclusions I2, I3, I4 and I5 c) A combination of (a)
and (b)"
Yes
We understand that E2 is intended to apply only to retail customers’ generation. The exclusion should
therefore be revised to make that limitation clear. Specifically, the first sentence should read: “A
generating unit or multiple generating units that serve all or part of retail customer Load with electric
energy on the retail customer’s side of the retail meter.
Yes
FMPA agrees with the intent / concept, but has suggested wording changes to add clarity. The
exclusion refers to groups of Elements that “distribute power to Load rather than transfer bulk power
across the interconnected system.” The use of the term “bulk power” is vague and could be read
incorrectly as a reference to the “bulk-power system,” which is defined in the Federal Power Act but is
not a NERC defined term. If the LDN is connected to the BES at more than one location, there will by
definition be some loop flow. We recommend below that Exclusion 3(d) be revised to quantify the
amount of loop flow that is permissible in an excluded LDN. In the context of the first sentence of

Exclusion E3, less specificity is needed, and the sentence should only be revised for the sake of
accuracy to state: “Groups of Elements operated above 100 kV that are primarily intended to
distribute power to load rather than to transfer power across the interconnected System.” The
exclusion’s reference to connection “at more than one location” is vague. The sentence should be
revised to read “connected to the Bulk Electric System (BES) from more than one Transmission
source solely to improve the level of service to retail customer Load,” and “Transmission source”
should have the same meaning that it does in E1. E3(a) should require that there be switching
devices between the LDN and the BES, not specifically automatic fault-interrupting devices. The term
“separable by” in “Separable by automatic fault interrupting devices” is unclear and should be
reworded. E3(b) To avoid pulling an LDN into the BES based on very small customer-owned
generation (such as rooftop photovoltaics and hospital backup diesel generators) that the utility does
not consider or rely on, or necessarily even know about, the item should be reworded: “Limits on
connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more
than 75 MVA of generation used to meet the resource-adequacy requirements of electric utilities.”
E3(d) states “Not used to transfer bulk power.” As noted above, “bulk power” is a vague term. There
will necessarily be some loop flow on a system that is connected to the BES at more than one
location. The amount of permissible loop flow for this purpose needs to be determined and stated in
this item.
Yes
FMPA supports this exclusion. For the sake of clarity, the final sentence should be revised to read as
follows: “For purposes of this exclusion, a “small utility” is an entity that performs a Distribution
Provider or Load Serving Entity function but is not required to register as a Distribution Provider or
Load Serving Entity by the ERO.”
Yes
No

Individual
Jianmei Chai
Consumers Energy Company
No
The generic inclusion within the definition of BES, of the NERC-defined term, “Transmission”, has the
potential to cause confusion and controversy. Small entities that own facilities that have been
approved by FERC as being classified as “distribution” according to the FERC Order 888 seven-factor
test, could be viewed as owning “Transmission.” Therefore, Regional Entities might require these
small entities to register as Transmission Owners, Transmission Operators, and/or Transmission
Planners. However, these facilities may not form a contiguous system, as expressed in the defined
term, “Transmission” and being “An interconnected group of lines and associated equipment”.
Alternatively, such facilities, because they do not form such a contiguous system (and thus are not,
and should not be, classified as Transmission) may inappropriately be excluded from the BES.
Therefore, even though “Transmission Facilities” represent a subset of the BES, we urge that NERC
avoid the use of the term, “Transmission” within the definition of BES. NERC should more explicitly
describe, in a functional manner independent of the term, “Transmission”, what is intended to be
included within the core definition. For NERC to fail to do so is to invite challenges to the final
definition as well as establish inappropriate reliability gaps. We agree with GO/TO Interface Project
2010-07 method of resolving reliability gaps by expanding requirements to the Distribution Provider
function as necessary. We propose that “All Transmission Elements …” be replaced with “All network
System Elements …”
No
The facilities currently listed in Inclusion I1 are already arguably included in the core definition.
Inclusion I1 should be reclassified as an Exclusion to cover transformers that do not meet the criteria
in Inclusion I1 such as those transformers with a single winding of 100kV or higher. Following is our
proposed language for the exclusion we are proposing. Transformers, other than Generator Step-up
(GSU) transformers, including Phase Angle Regulators, that have less than two windings of 100 kV or

higher.
Yes
We are supportive of Inclusion I2. Generators 20MVA and greater with terminals through a GSU
connected at 100kV and above are treated as Bulk Electric System at this time along with their radial
connections to the Transmission system. We agree with the SDT that no technical rationale for
changing this condition exists.
Yes
No
We recommend that the word, primary, be added, and that the phrase, “regardless of voltage” be
removed: “Blackstart Resources and the designated primary blackstart Cranking Paths identified in
the Transmission Operator’s restoration plan.” NERC’s May 19, 2011 webinar described this as
applying only to the path directly from the blackstart unit to the Transmission System. Is this correct?
If so, please clarify within the definition.
Yes
Yes
Yes
Yes
LDN needs to be specifically defined. The draft appears to come close with the term “Groups of
Elements operated above 100kV that distribute power to Load rather than transfer bulk power across
the interconnected System.” These Groups of Elements should be contiguous to avoid confusion. We
are also concerned with the limits on connected generation.
No response to be provided to this question.
No
The proposed definition appears to treat “BES” and “Transmission” synonymously, and this is highly
likely to have a significant effect on registration, even if this is not intended. To support consistency
between reliability and tariffs, we recommend that more direct consideration be given to the FERC 7factor test that has been consistently used to delineate transmission facilities for tariff purposes, and
to discriminate between registration requirements for TO and DP based on this delineation. Further,
reliability gaps will not be created (or can be addressed by minor changes to the applicable standards)
if this recommendation is adopted because all aspects of the applicable standards/requirements are
(or will be) captured by the current registration process.
Yes
The proposed definition creates a tension between FERC Order 888 and the resulting 7-factor test as
applied for tariff purposes, and the registry criteria for registration of Transmission Owners and
Transmission Operators. Entities with assets defined by FERC as Distribution might challenge any
rules that treat Distribution assets as Transmission as not being consistent with the Federal Power Act
of 2005.
Yes. We propose an alternative core BES definition to read as follows: “All network System Elements
operated at 100 kV or higher, Real Power resources as described below, and Reactive Power
resources connected at 100 kV or higher unless such designation is modified by the list shown below.”
We support extending the transition period to 24 months.
Individual
Chad Bowman
Chelan PUD - CHPD
No
As a general matter, Chelan County Public Utility District (CHPD) supports the approach the Standards
Development Team (“SDT”) has taken to defining the Bulk Electric System (“BES”). The changes
made in the revised core definition are helpful and represent significant progress toward an
acceptable definition. With an effective and efficient exclusion process, the draft will better define the

BES as a whole. We urge the SDT to bear in mind the restrictions contained in Section 215 of the
Federal Power Act (“FPA”) The “bulk-power system” (As per FERC, we treat the statutory term “bulkpower system” as equivalent to the term ordinarily used in the industry, “Bulk Electric System”)
definition imposes a clear limit on the reach of the mandatory reliability regime. The BES is made up
of only those “facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof)” and “electric energy from generation facilities needed
to maintain transmission system reliability.” Congress reinforced that limit in Section 215(i), where it
emphasized that the FPA authorizes the imposition of reliability standards “for only the bulk-power
system.” CHPD is concerned that the SDT’s proposed definition is overly-broad, and that it will sweep
in many Elements that have little or no material impact on the reliable operation of the interconnected
bulk transmission grid. For example, the definition uses the arbitrary 20 MVA threshold from the
NERC Statement of Registry Criteria for inclusion of generators. Accordingly, for the BES definition to
conform to the requirements of the statute, the SDT must adopt an effective mechanism to exempt
facilities like these that are improperly swept in by the SDT’s brightline approach to inclusions and
exclusions. For this reason, the Exception process to accompany the SDT’s definition is of critical
concern. If the SDT incorporates this statutory language as its core definition, it will have addressed
FERC’s primary concern with a minimum of disruption to the current NERC system of definitions. The
definition could then be further elaborated to show specific points of demarcation for each inclusion
and exclusion similar to that Proposal 6 from the WECC Bulk Electric System Definition Task Force
(“BESDTF”) team to further delineate BES and non-BES facilities.
No
In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and nonBES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is
stepped down from transmission voltages to distribution voltages. We believe, however, that the SDT
should undertake the effort to more clearly define the point where the BES ends and non-BES
systems begin. In this regard, we note that the WECC Bulk Electric System Definition Task Force
(“BESDTF”) has devoted considerable effort to this question and has developed one-line diagrams
noting the BES demarcation point for a number of different kinds of Elements that are common in the
Western Interconnection. Using this work as a starting point, the SDT should be able to provide much
useful guidance to the industry with relatively little additional effort. Also, the reference to “two
windings of 100 kV or higher” may create some confusion because many three-phase transformer
banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We suggest
clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”
We again urge the SDT to consider further delineation of points of demarcation similar to WECC
BESDTF Proposal 6.
No
CHPD is concerned that I2 inclusion criteria that includes the arbitrary 20 MVA threshold from the
NERC Statement of Registry Criteria for inclusion of generators is over-inclusive. Under FPA Section
215, generation resources are excluded from the “bulk-power system” unless they produce “electric
energy” that is “needed to maintain transmission system reliability.” Hence, the inclusion as drafted
improperly expands the BES definition to include generators that the statute requires to be excluded.
In the same comments, the SDT also states that it has considered “the inclusion of generator step-up
(GSU) transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable.” Unfortunately, the SDT appears to have concluded
that any interconnection facility operating above 100-kV should be classified as BES. The result will be
to require Generation Owners to register as Transmission Owners/Operators, as well, producing
substantial additional compliance costs for those Generation Owners but resulting in little or no
improvement in the reliability of the BES. We recommend that the SDT, like the Project 2010-07 SDT
(commonly referred to as the GO/TO Team), give careful consideration to the practical results of its
recommendations rather than relying on abstract conclusions about whether a “contiguous” or “noncontiguous” BES is more desirable. We are concerned that the SDT’s pursuit of a “contiguous” BES
will result in a substantially over-inclusive BES definition. The “contiguous” BES concept implies that
every Element arguably necessary for the reliable operation of the interconnected bulk system must
be included in the BES definition, even if it is interconnected with Elements that have no bearing on
the operation of the BES. NERC’s Standards Drafting Team for Project 2010-07, has already
considered this question and, based on an in-depth review of potentially applicable reliability

standards, has concluded that generation interconnection facilities, even if operated above 100-kV,
need to comply only with a limited set of reliability standards in order to achieve the reliability goals.
Much of the work of the Project 2010-07 SDT is applicable to the work of the BES Standards
Development Team. For example, the Project 2010-07 Team observed that interconnection facilities
“are most often not part of the integrated bulk power system, and as such should not be subject to
the same level of standards applicable to Transmission Owners and Transmission Operators who own
and operate transmission Facilities and Elements that are part of the integrated bulk power system.”
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability.
No
CHPD is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20
MVA threshold discussed in our response to question 3, the 75 MVA threshold appears to have been
drawn from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition.
Yes
Including “all” blackstart and blackstart cranking paths in the BES may ultimately provide an incentive
to the electric industry to reduce the number of resources with blackstart capability. We therefore
suggest that essential blackstart resources identified by the Regional Entity should be included in the
Bulk Electric System, but non-essential blackstart resources need not be.
No
CHPD agrees that it is important to address wind generation facilities and similar generation facilities
in which a large number of generating units, each with a relatively small capacity, are clustered and
fed into the grid at a single interconnection point. That being said, CHPD is concerned that the 75
MVA threshold has been chosen arbitrarily for the reasons stated in our comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials
should be retained. We believe the exclusion as drafted adequately defines radials.
No
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through
reference to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the
generation unit is reliability-must-run or essential blackstart, the function of the unit is irrelevant to
the reliable operation of the interconnected bulk transmission grid, and we therefore believe the
reference to the function of the generation unit (“standby, back-up, and maintenance power…”)
should be eliminated.
Yes
CHPD strongly supports the categorical exclusion of Local Distribution Networks from the BES. In fact,
for reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are, of course, probably the most common kind of local
distribution facility. Further, the conversion of radial systems to local distribution networks should be
encouraged because networked systems generally reduce losses, increase system efficiency, and
increase the level of service to retail customers. CHPD supports the LDN exclusion, but we believe the
exclusion should be refined in the following respects: • The SDT’s draft states that: “LDN’s are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of
service to retail customer Load.” We recommend that the SDT revise the sentence quoted above to
delete the word “solely” and add an additional phrase at the end so that the revised sentence will
read as follows: “LDN's are connected to the Bulk Electric System (BES) at more than one location to
improve the level of service to retail customer Load and not to accommodate bulk transfers of power
across the interconnected bulk system.” By instituting this suggestion, the SDT would emphasize the
key difference between an LDN, which is designed to reliably serve local, end-use retail customers,

and the BES, which is designed to accommodate bulk transfer of power at wholesale over long
distances.
Yes
CHPD supports the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that can ill afford the substantial costs that accompany
imposition of mandatory compliance with reliability standards. Further, we agree that the small
utilities covered by the exemption will have no measurable impact on the operation of the
interconnected BES. In the Pacific Northwest, many small entities were required to register by virtue
of owning a very small portion of the region’s 115-kV system. These utilities have faced substantial
compliance burdens even though their operations are simply not material to the interconnected bulk
grid in our region, and the investment of resources in compliance therefore will have no measurable
effect in improving the reliability of the interconnected grid.
No
While CHPD agrees that the approach adopted by the SDT -- a core definition coupled with specific
inclusions and exclusions – will be effective in removing most local distribution facilities from the BES,
it will not remove all such facilities. For the reasons discussed at greater length in our answer to
Question 1, CHPD believes that the proposed definition is over-inclusive and is likely to sweep up
certain facilities used in local distribution that should not be classified as BES. As discussed in our
answer to Question 3, CHPD notes that exclusion of facilities from the BES does not mean that owners
of those facilities are entirely exempt from reliability standards. On the contrary, the statute provides
that “users” of the BES can be subject to reliability regulation. Hence, even where an entity does not
own BES assets, it could be required to, for example, provide necessary information to the applicable
Reliability Coordinator and to participate in the regional Under-Frequency Load Shedding program by
setting the UFLS relays in its Local Distribution Network at the appropriate settings. We note that
participants in the WECC BESDTF Task Force generally agreed that appropriate information should be
provided by non-BES entities, although there was considerable concern related to ensuring that the
provision of information was not unduly burdensome.
Yes
The Exceptions process is a necessary part of making this proposal compliant with the Federal Power
Act. As noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is
potentially in conflict with the limitations of the Federal Power Act, and in particular the statutory
exclusion for facilities used in the local distribution of electric energy. The SDT’s approach can meet
the statutory requirements only if the Exception process currently under development results in
facilities that are not properly classified as BES being exempted from regulation as BES facilities.
CHPD has these additional concerns: • The current definition provides that “Elements may be included
or excluded on a case-by-case basis through the Rules of Procedure exception process.” CHPD is
concerned that the SDT carefully delineate which entity has the burden of proof in the exclusion
process. The WECC BESDTF approach, which we commend to the SDT, laid out these burdens in some
detail. Under that approach, essentially, if a facility is excluded from the BES by virtue of the specific
exclusions listed in the definition, the Regional Entity bears the burden of proving that the facility
nonetheless has a material impact on the interconnected bulk transmission system and therefore
should be included in the BES. On the other hand, if a facility is classified as BES by virtue of the list
of inclusions set forth in the BES definition, it can still escape classification as BES, but bears the
burden of demonstrating that its facility has no material impact on the interconnected transmission
system. We urge the SDT to give careful consideration to these burden-of-proof questions and to
follow the lead of the WECC BES Task Force. • For the reasons we have explained in our answer to
Question 11, we believe the Exception process is critical both to ensure that the BES definition is
effective in producing measurable gains to bulk system reliability and to ensuring that the definition
will comply with the limitations Congress placed in Section 215. Hence, we believe the entire BES
definition, including the Exception process and related procedures, should be vetted through the
NERC Standards Development Process, including the full comment periods and ballot approvals
provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are
subject to approval in a process that provides considerably less due process and industry input than
the Standards Development Process. Accordingly, we urge that all elements of the BES definition,
including those elements that have been assigned to the Rules of Procedure Team, be vetted through
the Standards Development Process.

Group
Santee Cooper
Terry L. Blackwell
Yes
We agree with the changes of adding the inclusions and exclusions. We recommend that I3 be 100
MVA or higher. Was there a rationale for using 75 MVA?
Yes
Yes
The inclusion for generating units needs to be consistent with regional entities exclusion criteria for
MODO24.
No
We recommend that it say "Single generating units located at a single site with a capacity of greater
than or equal to 100 MVA". The use of aggregate capacity greater than 75 MVA pulls in some very
small units.
Yes
Yes
What is the rationale for 75 MVA.
Yes
Yes
Yes
Yes
Yes
The commission should remain open to future modifications of the bright-line core definition and
specific inclusion and exclusions.
What was the rationale for using aggregate capacity greater than 75 MVA on I2 and I5. I2 and I3
inclusions are not the same as defined by the SERC Regional Entity for MOD-024. The SERC guideline
does not include an aggregate value for generating units.
Individual
Michelle R D'Antuono
Occidental Energy Ventures Corp. (answers include all various Oxy affiliates)
No
Please see discussion in response to Questions 2, 7, 9, 10, 11, 12 and 13.
No
Inclusion I1 would be unlawful to the extent that it would include the transformers of retail customers
that have self-provided “hard-tapped” facilities behind the retail delivery point. (For the purposes of
these Comments, “hard-tapped” means connected without an automatic fault-interrupting device).

No
(Note: Inserted language provided in brackets; deleted language denoted by empty brackets: [ ].)
Exclusion E1 contradicts the plain language of Section 215 of the Federal Power Act (“FPA”), which

denies FERC jurisdiction over facilities used in the local distribution of electric energy (16 U.S.C. §
824o(a)(1) (stating the Bulk Power System “does not include facilities used in the local distribution of
electric energy”)). For example, Exclusion E1 would impermissibly include within the definition of the
Bulk Electric System (“BES”) a retail customer’s self-provided “hard-tapped” radial line that is located
behind the retail delivery point. The Standard Drafting Team (“SDT”) stated in commentary to
Exclusion E1 that it has clarified the existing exclusion for radial systems by specifying that protection
for the BES is a required element, and that it believes that faults on radial lines without protection
devices could negatively impact the BES. Even if faults on radial lines could negatively impact the
BES, however, radial lines that are used in local distribution of electric energy are outside of FERC’s
jurisdiction. Congress did not place any qualifications on the exclusion of facilities used in the
distribution of electric energy, and certainly did not make the exclusion contingent on whether the
facility is “originating with an automatic interruption device.” Exclusion E1 would rewrite Section 215
of the FPA to exclude from the definition of the BES only “facilities [with an automatic interruption
device] used in the local distribution of electric energy.” Such an interpretation, as discussed further
below in response to Questions 11 and 12, is unlawful as it is in direct contravention of Congress’
intent. To make Exclusion E1 consistent with the jurisdictional requirements of Section 215 of the
FPA, Exclusion E1 could be rewritten as follows: Any radial system which is described as connected
from a single Transmission source [ ] and: a) Only serving Load. [ ] Or, b) Only including generation
resources not identified in Inclusions I2, I3, I4 and I5. Or, c) Is a combination of items (a.) and (b.)
where the radial system serves Load and includes generation resources not identified in Inclusions I2,
I3, I4 and I5. Please see further discussion in response to Questions 11, 12 and 13.
Yes
No
(Note: Inserted language provided in brackets; deleted language denoted by empty brackets: [ ].)
Exclusion E3 is also contrary to the plain language of Section 215 of the FPA. The SDT stated in
commentary to E3 that it “believes that any network that simply supports distribution and is providing
adequate protection should be excluded from the BES.” This statement highlights the fundamental
disconnect between the proposal and Section 215 of the FPA, which excludes facilities used in the
local distribution of electric energy from the definition of the BES regardless of whether the facilities
are “providing adequate protection.” That is, Section 215 of the FPA states that the definition of the
BES excludes “facilities used in the local distribution of electric energy,” not “facilities used in the local
distribution of electric energy [providing adequate protection].” With respect to the enumerated
criteria in Exclusion E3, the requirement that Local Distribution Networks (“LDNs”) “must be
connected through automatic fault-interrupting devices” violates the FPA because, as discussed in
response to Question 7, it places a condition on the unqualified exemption granted by Congress to
facilities used in the local distribution of electric energy. Moreover, the other enumerated criteria also
fail under Section 215 of the FPA and case law because they ignore, as discussed further in response
to Question 11, a long line of precedent that requires a fact-specific analysis to be conducted to
determine whether a facility is used in local distribution (see, e.g., Order No. 888 at 31,980). To
make Exclusion E3 consistent with the requirements of Section 215 of the FPA and case law, Exclusion
E3 could be rewritten as follows: E3 – [All facilities used in the distribution of electric energy]
([“]Local [D]istribution [N]etworks,[” or “]LDNs[”]): Groups of Elements operated above 100 kV that
distribute power to Load rather than transfer bulk power across the interconnected System. LDN[]s
are [normally] connected to the Bulk Electric System (BES) at more than one location solely to
improve the level of service to retail customer Load. The LDN is characterized by all of the following:
a) [ ] b) Limits on connected generation: [Generally], neither the LDN, nor its underlying Elements (in
aggregate), includes more than 75 MVA generation; c) Power flows only into the LDN: The generation
within the LDN [normally does] [ ] not exceed the electric Demand within the LDN; d) Not used to
transfer bulk power: The LDN is [generally] not used to transfer energy originating outside the LDN
for delivery through the LDN; and e) Not part of a Flowgate or transfer path: The LDN normally does
not contain a monitored Facility of a permanent flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable
monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL). Please see further discussion in response to
Questions 11 and 12.
No

There is no legal basis to distinguish between “small utilities” and other similarly situated entities.
Thus, to avoid unlawful discrimination, Exclusion E4 should be revised as follows: (Deleted language
denoted by empty brackets: [ ].) Exclusion E4: Transmission Elements, from a single Transmission
source connected at a voltage of 100 kV or greater [ ] whose connection to the BES is solely through
this single Transmission source, and without interconnected generation as recognized in the BES
Designation Inclusion Items I2, I3, I4, or I5. [ ]
No
Local distribution facilities have not been excluded from the proposed definition of the BES. As FERC
recognized in Order No. 743-A in directing NERC to exclude local distribution facilities from the
revised definition of the BES, any definition that does not exclude all “facilities used in the local
distribution of electric energy” is unlawful. FERC, as well as federal courts, have repeatedly stated
that whether a facility is used in local distribution must be determined on a “case-specific” basis (see,
e.g., Order No. 888 at 31,980-81). As a threshold matter, before devoting any additional time and
resources to developing a definition of the BES, there must be a clear understanding of the factors to
consider when determining whether a facility is either a local distribution facility or a transmission
facility. Currently, such a determination is made by considering a “seven-factor test” that FERC has
adopted, and the U.S. Supreme Court has upheld. The “seven-factor test,” of which no one factor is
determinative, evaluates the following indicators: (1) Local distribution facilities are normally in close
proximity to retail customers. (2) Local distribution facilities are primarily radial in character. (3)
Power flows into local distribution systems; it rarely, if ever, flows out. (4) When power enters a local
distribution system, it is not reconsigned or transported on to some other market. (5) Power entering
a local distribution system is consumed in a comparatively restricted geographical area. (6) Meters
are based at the transmission/local distribution interface to measure flows into the local distribution
system. (7) Local distribution systems will be of reduced voltage (Order No. 888 at 31,981). The
seven-factor test, which recognizes that a bright-line between transmission and distribution is a not a
workable approach, is designed to ensure FERC does not impermissibly usurp state and local
regulation of local distribution facilities. There is no evidence that the seven-factor test was
considered in drafting the proposed definition of the BES. Please see further discussion in response to
Question 12.
Yes
The proposed definition conflicts with Section 215 of the FPA and case law because it ignores years of
precedent regarding what constitutes “facilities used in local distribution” and defines the BES in such
a way as to possibly cover local distribution facilities as well as transmission facilities. Specifically,
FERC has jurisdiction over “all users, owners and operators of the bulk-power system” under Section
215 of the FPA (16 U.S.C. § 824o(b)(1)). The bulk-power system is defined as: “(A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy” (Id. at § 824o(a)(1)). By the plain language of Section 215 of the FPA, FERC’s
jurisdiction over the Bulk Power System cannot include any “facilities used in the local distribution of
electric energy.” FERC has recognized that “[s]ince such facilities are exempted from the Bulk-Power
System, they also are excluded from the bulk electric system” (Order No. 743-A at P 25). Congress
specifically recognized that while facilities used in the local distribution of electric energy may be part
of the Bulk-Power System, they are not FERC jurisdictional. Thus, “facilities and control systems
necessary for operating an interconnected electric energy transmission network (or any portion
thereof)” that are used in the local distribution of electric energy are not jurisdictional regardless of
the potential reliability impact of the facilities. The proposed definition of the BES would rewrite
Section 215 of the FPA to exclude only “facilities used in local distribution of electric energy [unless
needed for reliability purposes].” As the DC Court of Appeals stated in Detroit Edison Co. v. FERC:
“[s]uch an interpretation would eviscerate state jurisdiction over numerous local facilities, in direct
contravention of Congress’ intent” (Detroit Edison Co. v. FERC, 334 F.3d 48, 54 (U.S. App. D.C. 2003)
(citation omitted)). In Detroit Edison Co. v. FERC, the DC Court of Appeals rejected FERC’s proposed
definition of a “FERC-jurisdictional distribution facility” as any distribution facility that is not “used
exclusively to provide service to unbundled retail customers” (Id.). The Court stated: “FERC’s position
contradicts the plain language of the FPA,” and further that “FERC would rewrite the statute to
exclude only ‘facilities used exclusively in local distribution’” (Id.). The exclusion of facilities used in
the local distribution of electric energy from the definition of the BES does not mean that NERC lacks

the ability to maintain the reliability of the BES. For example, if NERC determined that a retail
customer’s self-provided “hard-tapped” radial line that is located behind the retail delivery point
created a reliability issue, NERC could require that the transmission facilities be equipped with
automatic fault-interruption devices. NERC could not, however, define the BES to include such local
distribution facilities, which is the result of the proposed bright-line core definition and specific
inclusions and exclusions. While FERC “granted NERC discretion” in developing the revised definition
of the BES because FERC wanted to give NERC “the greatest amount of flexibility to utilize its
technical expertise” (Order No. 743-A at PP 70-71), NERC’s discretion is not unbounded. Moreover,
while FERC stated that it “will evaluate whether the [BES definition] proposal results in any conflicts
with the statutory language” (Id. at P 72), it is imperative that NERC work within the statutory
limitations of Section 215 of the FPA as to prevent submitting a proposal to FERC that is
fundamentally unlawful. It would be a colossal waste of government and industry resources to
develop and advance a definition that cannot withstand basic legal review. As provided above, the
following are suggested language changes that may clarify the issue: Exclusion E1 - Any radial
system which is described as connected from a single Transmission source [ ] and: a) Only serving
Load. [ ] Or, b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes
generation resources not identified in Inclusions I2, I3, I4 and I5. Exclusion E3 – [All facilities used in
the distribution of electric energy] ([“]Local [D]istribution [N]etworks,[” or “]LDNs[”]): Groups of
Elements operated above 100 kV that distribute power to Load rather than transfer bulk power across
the interconnected System. LDN[]s are [normally] connected to the Bulk Electric System (BES) at
more than one location solely to improve the level of service to retail customer Load. The LDN is
characterized by all of the following: a) [ ] b) Limits on connected generation: [Generally], neither the
LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation; c) Power
flows only into the LDN: The generation within the LDN [normally does] [ ] not exceed the electric
Demand within the LDN; d) Not used to transfer bulk power: The LDN is [generally] not used to
transfer energy originating outside the LDN for delivery through the LDN; and e) Not part of a
Flowgate or transfer path: The LDN normally does not contain a monitored Facility of a permanent
flowgate in the Eastern Interconnection, a major transfer path within the Western Interconnection as
defined by the Regional Entity, or a comparable monitored Facility in the Quebec Interconnection, and
is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL). Exclusion
E4 – Transmission Elements, from a single Transmission source connected at a voltage of 100 kV or
greater [ ] whose connection to the BES is solely through this single Transmission source, and without
interconnected generation as recognized in the BES Designation Inclusion Items I2, I3, I4, or I5. [ ]
Occidental Energy Ventures Corp (“OEVC”) would like to emphasize that the proposed definition of the
BES does not only impact OEVC and its affiliates. The proposed BES definition would include
numerous facilities that are used for the local distribution of electric energy, not transmission, in
direct contravention of Section 215 of the FPA. For example, there are likely hundreds, if not
thousands, of retail customers that have self-provided “hard-tapped” facilities behind the retail
delivery point. Those retail customers, many of who are likely unaware of the proposed BES
definition, much less its impact, will have their facilities under the proposed BES definition suddenly
become transmission facilities simply because their facilities are not separated from the BES by an
automatic fault-interruption device.
Individual
Kenneth A. Goldsmith
Alliant Energy

No
We believe the first sentence should be revised to read “Any radial system which is described as
connected from a single Transmission source at 100 kV or above originating with . . .” In this way it is
clear that E1 covers radial transmission, not radial distribution systems.

Yes
In general we believe that the bright line has been created. There should however be one additional
exclusion – Distribution Protection Systems designed specifically to protect Distribution System assets
should not be considered part of the BES, even if they open an element of the BES (ie; Distribution
Breaker Failure Relaying), as long as the action is to protect the Distribution System and not the BES.

Individual
Deborah J Chance
Chevron Global Power, a division of Chevron U.S.A. Inc.

See response to question 13

Yes

Chevron U.S.A. Inc. has reviewed the proposed Bulk Electric System definition and is concerned that
the proposed changes designed to enhance reliability and accountability of Transmission and
Generation are inadvertently catching parties whose prime operations are distribution in nature.
Chevron is proposing minor changes that will not affect the necessary regulation of the bulk power
industry, but will exempt parties that are not crucial to reliability and provide mostly, if not entirely,
distribution or self use service. In remote areas of west Texas, Chevron has hundreds of non
contiguous producing properties and facilities located over hundreds of square miles. In some cases
where the utility was close and had the capability to serve, Chevron took utility service. Where service
was not available or the utility did not have the capability, Chevron built its own private power
distribution system to service its own facilities. Chevron has no generation and takes all of its power
from transmission providers. In at least one instance Chevron takes power at over 100 kV from a
transmission provider. Chevron has an automated interruption device between its facilities and the
transmission facilities. Currently this field takes power from an ERCOT transmission owner at above
100 kV and then distributes the power over a Chevron owned and operated power distribution system
to Chevron facilities. This Chevron system includes a substation, transformers and other facilities
necessary to take power at above 100 kV and distribute and step down the power as necessary.
Chevron uses the power for offices, repair facilities, oil wells, separation facilities, gas plants, drilling
new wells and other related oil and gas activities. Located within the area of the Chevron power
distribution system are ranchers, pump stations, third party oil wells and other small users. These
parties are not located near any utility or coop facilities. For decades Chevron has worked to
accommodate these parties by working with the local utility, transmission owners and the Texas
Public Utility Commission to allow electrical service to these remote users. Many of these ranchers
and other users are not located near any utility lines. Costs could run to the hundreds of thousands of
dollars (or more) to provide an interconnect from the utility. Instead of leaving these parties with no
electrical service, a procedure was developed that allowed parties such as Chevron to accommodate
the small end user. For example if a utility/coop was unable or unwilling to serve a rancher at a
reasonable cost, the rancher could approach Chevron. The goal would be to execute a three party

agreement between the rancher, Chevron and the service provider. Under the terms of the
agreement, the Rancher would interconnect with the Chevron system. A utility quality meter capable
of remote reading would be installed and the rancher would be responsible for all costs beginning at
the meter. The rancher contracts with a power provider for his power. Every month the meter
between the Transmission owner and Chevron would be read. This smart meter located at the
interconnect with the transmission system and its soft ware would show all deduct metering (such as
our rancher) so that any non Chevron parties on the Chevron distribution system’s usage would
clearly be listed. The transmission owner then provides the billing information to the rancher’s power
provider. Chevron receives no compensation from the rancher, power provider or transmission owner.
Chevron provides the service strictly on an accommodation basis. The Texas Public Utility Commission
recognizes the needs of parties in remote areas of Texas and has blessed this type of service.
Chevron is not considered a utility for providing this type of service. Chevron is concerned that the
above described private power distribution system may inadvertently be forced to register as a bulk
electric system provider. This private distribution system is clearly at the terminus of a radial line and
provides service to Chevron owned and operated facilities. The system is large in area and has been
built over a period longer than any current employee’s memory. Through what can be called
“accidents of history” and a good neighbor policy, Chevron has accommodated parties that otherwise
could not connect to utility quality power. This arrangement is blessed and encouraged by the State
PUC. Chevron charges nothing for the service. The system is entirely distribution in nature and does
not contribute to the reliability of the grid in any manner. The intent of the current rule making is not
to encompass such a system. NERC needs to encourage parties such as Chevron to help bring power
to remote areas and not discourage, or worse yet greatly increase the cost to provide such service.
Chevron requests that the NERC include in its definition a statement making it clear that systems
such as those described above should not be required to register. Chevron supports the technical
changes suggested by ELCON in its filing. A party’s facility should not be considered an essential
facility where the facility would otherwise be considered exempt except that it is providing distribution
services as an accommodation to third parties. This is especially true when 1. The incumbent utility or
coop is unable or unwilling to serve the third parties at a reasonable cost 2. The service to the third
party is provided as an accommodation 3. The facility is not generating and/or selling power to the
third party 4. The third party is purchasing power from a power provider
Individual
Scott Bos
Muscatine Power and Water
Yes
Would like to ask the SDT to please affirm that Reactive Resources within the BES definition are
intended to be generator resources and not static resources.
Yes
Yes
No
The phrase “connected through a common bus” is taken from the NERC Compliance Registry Criteria.
MP&W would agree with this language if the intent is to let entities categorize the applicable multiple
generating units as part of the BES only when it is connected to one (common) bus. However, if the
intent is for entities to also classify multiple generation as part of the BES when it is connected
through two or more GSUs to different bus sections of a set of (common) buses that are
interconnected through bus-tie breakers (which may be done to provide improved reliability and
maintenance flexibility), then using language like “connected through a common bus or set of
interconnected buses” would be more appropriate.
Yes
This Inclusion I4 provides a defense in depth with CIP-002-4.
No
MP&W recommends to have Inclusion 5 be revised as follows “Dispersed power producing resources
with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a collector
system from the point where the aggregated rating exceeds 75 MVA through a common point of

interconnection to a system Element at a voltage of 100 kV or above.“
Yes
MP&W recommends to clarify the phrase “originating with an automatic interruption device” regarding
the location of the interruption device. An entity may not have interruption devices at both ends of a
radial fed line. If the interruption device is at the load end of the radial line, then the “up-stream”
portion of the radial line is unprotected. Furthermore, please make it unambiguous that all facilities
operated at less than a 100kV are excluded unless those facilities meet the criteria of an Inclusion.
Yes
No
The SDT is defining what a Local Distribution Network is but the expression “transfer bulk power” is
ambiguous. Please clarify the purpose of this exclusion.
Yes
Yes
Yes
Within FERC’s definition of Bulk Power System, it is plainly stated that BPS does not include facilities
used in the local distribution of electrical energy. Does this support or contradict the SDT's concept of
Local Distribution Network?
In order to provide a unambiguous and concise definition of the BES, we ask the SDT to please
include in the bright-line criteria that “all facilities less than a 100kV are excluded unless those
facilities meet the criteria of an Inclusion.”
Group
NERC Staff
David Taylor
No
The core definition lacks a clear bright-line designation for generating resources. For such resources,
the core definition only references “Real Power resources as described below” which in and of itself is
not a bright-line designation. A bright-line designation for generating resources needs to be included
in the core definition. A bright-line can be established in the core definition by including generating
units based on the MVA ratings as found in current Inclusions I2, I3, and I5. Additional generating
unit specifications could be included in the core definition or as Inclusions such as the existing
Inclusion I4 for black start generating units. >>>>>>>>>> The core definition also lacks clarity with
respect to the facilities included under “Reactive Power resources” and may unintentionally omit
Reactive Power resources necessary for reliable operation of the BES. The definition as proposed
excludes devices such as shunt reactors connected to the tertiary terminals of a BES transformer and
synchronous condensers connected through a transformer, and is unclear whether a static var
compensator (SVC) with thyristor switched capacitors and thyristor switched or controlled reactors
operated below 100 kV, but connected to the BES through a transformer (similar to a generator
connected to the BES through a generator step-up transformer) is included in the BES definition. The
qualifications on Reactive Power resources recommended below will include the necessary
transmission resources noted above, without unintentionally including distribution capacitors
connected on the low voltage side of a distribution transformer. >>>>>>>>>> These concerns can
be addressed by revising the core definition as follows: >>>>>>>>>> “Bulk Electric System (BES):
All Transmission Elements operated at 100 kV or higher; Real Power resources including, * Individual
Generating Units greater than 20 MVA (gross nameplate rating), * Multiple generating units located at
a single site with aggregate capacity greater than 75 MVA (gross nameplate rating) connected
through a common point of interconnection, * Dispersed power producing resources with aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a collector system through
a common point of interconnection, and * Blackstart Resources and the designated blackstart
Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage; and
Reactive Power devices (capacitive or inductive, static or actively controlled) greater than 20 Mvar
that are directly connected at 100 kV or higher, or connected through a transformer at 100 kV or

higher at the site of transformation; unless such designations are modified by the list of Inclusions
and Exclusions shown below.” >>>>>>>>>> (Note that the rationale for excluding the 100 kV
interconnection threshold on the first three bullets is provided in our responses to Questions 3, 4, and
6.) >>>>>>>>>> In conjunction with the alternative language for the core definition proposed
above, NERC staff proposes the following definition of Generating Unit be added to the NERC Glossary
of Terms used in Reliability Standards: >>>>>>>>>> Generating Unit - A device, whether spinning
or static and whether connected synchronously, asynchronously, or electronically coupled, that
produces electrical energy from another source of energy, either directly from the other energy
source (such as a combustion turbine from natural gas or light distillate oil, a wind turbine from wind,
or a solar array from the sun) or through a storage medium (such as pumped storage hydro, a
flywheel, compressed air, or battery).
No
Inclusion I1 is acceptable in general; however, there are two items that should be modified.
>>>>>>>>>> The reference to “two windings” is technically incorrect because it would exclude
autotransformers with two terminals at 100 kV or higher since the primary and secondary terminals
are connected to the same winding. It would be better to replace the phrase “with two windings of
100 kV or higher” with the phrase “with two or more terminals connected at 100 kV or higher.”
>>>>>>>>>> The phrase “other than Generator Step-up (GSU) transformer” is unnecessary. The
qualifier “with two or more terminals connected at 100 kV or higher” already will exclude GSU
transformers. In unusual cases in which a generator is connected to the system through a
transformer that does have two terminals connected at 100 kV or higher the transformer should be
included by Inclusion I1.
No
The interconnection voltage threshold should be removed. The contribution of a generator to system
reliability is a function of its MVA rating rather than its interconnection voltage. All generating units
greater than 20 MVA should be included in the BES definition because all such units provide similar
contributions to system reliability. >>>>>>>>>> Also, the specific inclusion of the GSU transformer
implies that all other components of a generating unit, such as its unit auxiliary transformer, start-up
transformer, governor, exciter, power system stabilizer, etc., are excluded. The SDT should define
“generating unit” or otherwise clarify which components of a generating unit are included in the BES
definition.
No
The interconnection voltage threshold should be removed. The contribution of a multiple generating
units at a single site to system reliability is a function of the aggregate MVA rating rather than the
interconnection voltage. All locations with multiple generating units with aggregate capacity greater
than 75 MVA should be included in the BES definition because all such units provide similar
contributions to system reliability. >>>>>>>>>> As noted in the comment on Question 3 of this
comment request, the specific inclusion of the GSU transformer implies that all other components of a
generating unit, such as its unit auxiliary transformer, start-up transformer, governor, exciter, power
system stabilizer, etc., are excluded. The SDT should define “generating unit” or otherwise clarify
which components of a generating unit are included in the BES definition. >>>>>>>>>> The use of
the term “common bus” introduces ambiguity into the definition. It would be better to replace the
phrase “connected through a common bus” with the phrase “connected through a common point of
interconnection” which also provides consistency with the description of Inclusion I5.
Yes
No
We agree that Inclusion I5 is an effective method for including dispersed resources; however, the
interconnection voltage threshold should be removed. The contribution of dispersed power producing
resources to system reliability is a function of the aggregate MVA rating rather than the
interconnection voltage. All dispersed resources with aggregate capacity greater than 75 MVA should
be included in the BES definition because all such units provide similar contributions to system
reliability.
No
Exclusion E1 would be acceptable if (i) switching the radial system to connect it to the BES at a
second point of interconnection is modified to require that when a make-before-break connection is

used, it occurs at a voltage below 100 kV and (ii) the automatic interrupting device is not excluded as
part of the radial system. >>>>>>>>>> The allowance for make-before-break connections of radial
facilities at voltages 100 kV or higher will result in operating conditions with the potential to degrade
system reliability if the subject Elements are not planned, designed, maintained, and operated in
accordance with NERC Reliability Standards. The risk is most pronounced when the make-beforebreak connection is automated, increasing the likelihood of adverse reliability impacts occurring as a
result of placing the system into an unplanned operating condition. If the make-before-break
connection is made at a voltage below 100 kV the impedance in the parallel connection will mitigate
the reliability impact. When the radial system is connected to the BES at a second point of
interconnection 100 kV or higher, the radial system should not be excluded unless a break-beforemake connection is used because system protection during the momentary parallel network operation
is critical to overall BES reliability. >>>>>>>>>> The reason for requiring an automatic interrupting
device between the BES and the excluded radial system is to prevent faults and other abnormal
conditions on the radial system from negatively impacting reliability of the BES. Given the reliance on
the interrupting device to support BES reliability, it is appropriate to include the interrupting device in
the BES so that it is planned, designed, maintained, and operated in accordance with NERC Reliability
Standards the same as other BES Elements. Thus, when excluding a radial system operated at 100 kV
or higher, the BES line of demarcation should be on the load side of the automatic interrupting device.
>>>>>>>>>> The main clause and part (a) of the exclusion should be changed to read;
>>>>>>>>>> Exclusion E1 – Any radial system which is described as connected from a single
Transmission source originating on the load side of an automatic interruption device and: a) Only
serving Load. A normally open switching device between radial systems may operate in a ‘breakbefore-make’ fashion at 100 kV or higher or a ‘make-before-break’ fashion below 100 kV to allow for
reliable system reconfiguration to maintain continuity of electrical service. Or, etc. …
No
The second condition (ii) in E2 is confusing. While the condition is appropriate and has specific
meaning, the meaning will not be readily understood by most users of the definition. This condition
should be clarified.
No
Exclusion E3 is acceptable in general; however, (i) including the word “distribution” in the exclusion
could be interpreted to imply that certain distribution facilities are included in the BES unless
specifically excluded, (ii) item d) is unclear as to whether it applies to any parallel flow or only to
parallel flow for which the group of Element(s) are part of the contract path, and (iii) interrupting
devices should be included in the BES for the same reasons as stated above for Exclusion E1.
>>>>>>>>>> The concern with the word distribution in the term “Local Distribution Network” can
be avoided by eliminating use of this phrase. The proposed definition already defines the Elements
covered by Exclusion E2 and does not require defining a term for use in this standard. An alternate
solution would be to establish a different term to describe the groups of Elements that does not
include the word distribution. >>>>>>>>>> The phrase “is used to” in item d) lacks clarity. Clarity
should be provided by stating that the group of Elements does not transfer energy originating outside
the group of Elements; this is consistent with item c) that requires that power flows only into the
group of Elements. >>>>>>>>>> The reason for requiring automatic interrupting devices between
the BES and the excluded LDN is to prevent faults and other abnormal conditions in the LDN from
negatively impacting reliability of the BES. Given the reliance on the interrupting devices to support
BES reliability, it is appropriate to include the interrupting devices in the BES so that they are
planned, designed, maintained, and operated in accordance with NERC Reliability Standards the same
as other BES Elements. Thus, when excluding groups of Elements at 100 kV or higher, the BES line of
demarcation should be on the load side of the automatic interrupting devices. >>>>>>>>>> To
address our concerns, Exclusion E3 should be changed to read: >>>>>>>>>> E3 - Groups of
Elements operated above 100 kV that distribute power to Load rather than transfer bulk power across
the interconnected System. Such groups of Elements are connected to the Bulk Electric System (BES)
at more than one location solely to improve the level of service to retail customer Load. These groups
of Elements are characterized by all of the following: a) Separable by automatic fault interrupting
devices: Wherever connected to the BES, the group of Elements must be connected through
automatic fault-interrupting devices (the automatic interrupting device is part of the BES); b) Limits
on connected generation: Neither the group of Elements, nor any underlying Elements operated at
100 kV or below, includes more than 75 MVA generation (in aggregate); c) Power flows only into the

group of Elements: The generation within the group of Elements shall not exceed the electric Demand
within the group of Elements; d) Not used to transfer bulk power: The group of Elements does not
transfer energy originating outside the group of Elements for delivery through the group of Elements;
and e) Not part of a Flowgate or transfer path: The group of Elements does not contain a monitored
Facility of a permanent flowgate in the Eastern Interconnection, a major transfer path within the
Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the
Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability
Operating Limit (IROL).
No
The basis for exclusion must be based on system reliability. The need for an interrupting device
between the BES and excluded radial Elements is necessary for system reliability independent of
ownership of the excluded radial Elements.
Yes
No
The definition should include variable frequency transformers and back-to-back HVdc converters that
connect portions of the system operated at 100 kV or higher, regardless of the dc voltage rating of
the converter equipment, which often is less than 100 kV. >>>>>>>>>> Assuring reliable operation
of nuclear plants requires that Elements subject to Nuclear Plant Interconnection Requirements are
planned, designed, maintained, and operated in accordance with NERC Reliability Standards. An
additional Inclusion I6 should be added to the definition to include “All transmission Elements subject
to Nuclear Plant Interface Requirements (NPIRs) as agreed to by a Nuclear Plant Generator Operator
and a Transmission Entity defined in NUC-001.” >>>>>>>>>> Assuring reliable operation of the
interconnected transmission network also is dependent on reliable operation of generating units that
system operators rely on for capacity and Contingency Reserves. Additional Inclusions I7 and I8
should be added to include: * Real Power resources fully or partially relied on to fulfill a capacity
obligation, and * Real Power resources (supply-side or Demand-Side Management) relied on to
provide Contingency Reserves to its Balancing Authority.
Individual
Bill Keagle
BGE and on behalf of Constellation NewEnergy, Constellation Commodities Group and Constellation
Control and Dispatch
Yes
No comment.
Yes
No comment.
Yes
No comment.
Yes
No comment.
Yes
No comment.
Yes
No comment.
No
BGE generally agrees with the “radial” exclusion, but votes “NO” due to a lack of clarity. The definition
does not make it clear if radial facilities operating above 100 kV with automatic interrupting devices
(which would otherwise be classified as non-BES under exclusion E1, part a) and serving networks
operating below 100 kV are classified as non-BES. We believe E1 should make it clear that such radial
facilities are non-BES. BGE would like to note that under the current RFC BES definition, such facilities
are not designated as BES. To illustrate and clarify the BGE questions, please see the BGE Diagram
attached. The BES designations included on the diagram are BGE’s interpretation of BES facilities

under the proposed definition. Questions regarding the BGE Diagram: 1. If the 13.8 kV device TB is
operated “normally closed” as shown, is it the SDT’s understanding that the two 115 kV lines
classified as Non-BES in the diagram are no longer considered “radial”? 2. If the SDT does not
consider the two 115 kV lines described above as “radial” with device TB closed, would this
configuration be excluded as BES under exclusion E3? Or would the Exception Process be required to
classify such a configuration as non-BES?
Yes
No comment.
Yes
No comment.
No
An automatic interruption device should be required as in exclusion E1.
No
BGE votes “NO” due to the lack of clarity in exclusion E1.
No
We are not currently aware of any conflict, but have not had a chance to thoroughly consider the
potential conflicts.
BGE agrees with the SDT’s position that support equipment such as UVLS and UFLS not be classified
as BES. BGE strongly believes that including control centers and other BES support equipment in the
BES definition is not necessary and will cause confusion. BGE commends the BES Definition Standards
Drafting Team for the informative webinar on 5/19/2011. We were encouraged that the SDT’s
developed a transition plan for the implementation of the new BES definition. BGE urges the SDT to
also address the issue of the addition of new BES elements (i.e., such as new designated blackstart
resources which may include a cranking path that is reclassified as BES). A transition period would
also be required for these situations. BGE appreciates the work of the drafting team and supports the
goal to produce clear definition language so that upwards of 95% of the assets are clearly
distinguished as either included or excluded from the BES. We are particularly sensitive to the
potential for burdensome processes (e.g. TFEs) to be added to reliability compliance, so we appeal to
the team for continued, vigilant consideration of the arduousness of the BES determination process.
Also important to consider is that the subject of this comment form, the proposed BES definition, is
only one part of the BES definition project. The accompanying technical principles for BES Exceptions
and the Rule of Procedure Process must be evaluated together with the BES Definition to sufficiently
understand the revisions. In the end, the Technical Principles and the BES Definition must coalesce
and be clearly coordinated and understood. The BES Definition language must include reference to
the role of the associated defining documents. One unambiguous document must not be made
ambiguous by an associated document or process.
Individual
John Bee
Exelon
Yes
Yes
Yes
Yes
No
Exelon believes that the entire designated cranking path should not be included in the BES definition
if there are facilities less than 100kV on the path. Doing so may inappropriately include a number of
facilities that are local distribution facilities under jurisdiction of the states, i.e, the inclusion of the
entire cranking path occurs without an inquiry as to whether or not the facilities are “facilities used in
local distribution of electric energy” even though such facilities are by explicit language in the Federal

Power Act not included in the definition of Bulk Power System. In Orders 743 and 743-A, FERC
reiterated several times that “facilities that are determined to be local distribution will be excluded
from the bulk electric system.” (Order No. 743-A, P.22). Furthermore, by including these facilities the
Drafting Team has gone beyond the boundaries of Section 215 of the Federal Power Act and Orders
743 and 743-A. It should be noted that there is no reference to black start Cranking Paths in either
Order. Practically, it is unclear that including lower voltage facilities on a Cranking Path will have any
positive impact on reliability without potential entity registration changes or NERC Reliability
Standards changes. For example, NERC Reliability Standards FAC-008 and FAC-009 do not currently
apply to Distribution Providers.
Yes
Exelon agrees with this inclusion as long as it’s clear that distribution voltage collector systems are
not to be included in the BES. Exelon suggests that a clarifying statement be added to the inclusion
item, such as “Collector system facilities that are <100kV are excluded from the BES.”
No
Exelon points out that this is another case where facilities used in local distribution of electric energy
that are presently under state jurisdiction might be included in the BES. Depending on the location of
the automatic interrupting device, the radial facilities in between the tap point at the transmission
sources and the interrupting device would be included in the BES.
Yes
Exelon agrees with this Exclusion since this language is quoted from the Statement of Compliance
Registry Criteria.
No
Exelon has issues with the ambiguity of this Exclusion item. It seems that Local Distribution Networks
will all need to be approved via the Rules of Procedure Exception Process because the characteristics
of each LDN as described are not bright line. For example, does (b) refer to any generation, including
behind-the-meter generation? Does (c) mean always, i.e., generation can never exceed the load
under any condition? In theory or in actuality? How does (d) deal with parallel flows under abnormal
conditions when some energy may go in and out? Exelon understands the concept that an LDN
primarily serves load, but how will the owners prove that there is no impact to the BES under
contingency configurations?
Exelon is abstaining from voting on this item. How would this exclusion be different from E1?
Furthermore, Exelon suggests that a definition of “Small Utility” would need to be developed.
No
As highlighted in the answers to Questions 5 and 7, Exelon does not believe that facilities used in local
distribution of electric energy have been fully excluded in the draft BES definition. For example, there
are many examples of black start cranking path facilities that are <100kV and that are currently
defined as facilities used in the “local distribution of electric energy”.
Yes
To the extent facilities used in local distribution of electric energy may be included in the definition of
BES, the proposed definition is in conflict with the Federal Power Act.
The definition assumes some inclusions or exclusions based on levels of generation used in the NERC
Compliance Registry Criteria. Exelon does not view Orders 743 and 743-A as requiring a view or
justification of these thresholds. See Order No. 743-A at P 47 (“it was not our intent to disrupt the
NERC Rules of Procedure or the Statement of Compliance Registry Criteria”).
Individual
David C. Kahly
Kootenai Electric Cooperative
No
As a general matter, Kootenai supports the approach the Standards Development Team (“SDT”) has
taken to defining the Bulk Electric System (“BES”). The changes made in the revised core definition
are helpful and represent significant progress toward an acceptable definition. With an effective and
efficient exclusion process, the draft will better define the BES as a whole. We urge the SDT to bear in
mind the restrictions contained in Section 215 of the Federal Power Act (“FPA”) The “bulk-power
system” (As per FERC, we treat the statutory term “bulk-power system” as equivalent to the term

ordinarily used in the industry, “Bulk Electric System”) definition imposes a clear limit on the reach of
the mandatory reliability regime. The BES is made up of only those “facilities and control systems
necessary for operating an interconnected electric energy transmission network (or any portion
thereof)” and “electric energy from generation facilities needed to maintain transmission system
reliability.” Congress reinforced that limit in Section 215(i), where it emphasized that the FPA
authorizes the imposition of reliability standards “for only the bulk-power system.” Kootenai is
concerned that the SDT’s proposed definition is overly-broad, and that it will sweep in many Elements
that have little or no material impact on the reliable operation of the interconnected bulk transmission
grid. For example, the definition uses the 20 MVA threshold from the NERC Statement of Registry
Criteria for inclusion of generators. Accordingly, for the BES definition to conform to the requirements
of the statute, the SDT must adopt an effective mechanism to exempt facilities like these that are
improperly swept in by the SDT’s brightline approach to inclusions and exclusions. For this reason, the
Exception process to accompany the SDT’s definition is of critical concern. If the SDT incorporates this
statutory language as its core definition, it will have addressed FERC’s primary concern with a
minimum of disruption to the current NERC system of definitions. The definition could then be further
elaborated to show specific points of demarcation for each inclusion and exclusion similar to that
Proposal 6 from the WECC Bulk Electric System Definition Task Force (“BESDTF”) team to further
delineate BES and non-BES facilities.
No
In concept, Kootenai supports the SDT’s attempt to provide a clear demarcation between the BES and
non-BES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power
is stepped down from transmission voltages to distribution voltages. We believe, however, that the
SDT should undertake the effort to more clearly define the point where the BES ends and non-BES
systems begin. In this regard, we note that the WECC Bulk Electric System Definition Task Force
(“BESDTF”) has devoted considerable effort to this question and has developed one-line diagrams
noting the BES demarcation point for a number of different kinds of Elements that are common in the
Western Interconnection. Using this work as a starting point, the SDT should be able to provide much
useful guidance to the industry with relatively little additional effort. We again urge the SDT to
consider further delineation of points of demarcation similar to WECC BESDTF Proposal 6.
No
Kootenai is concerned that I2 inclusion criteria that includes the 20 MVA threshold from the NERC
Statement of Registry Criteria for inclusion of generators is over-inclusive. Under FPA Section 215,
generation resources are excluded from the “bulk-power system” unless they produce “electric
energy” that is “needed to maintain transmission system reliability.” Hence, the inclusion as drafted
improperly expands the BES definition to include generators that the statute requires to be excluded.
In the same comments, the SDT also states that it has considered “the inclusion of generator step-up
(GSU) transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable.” Unfortunately, the SDT appears to have concluded
that any interconnection facility operating above 100-kV should be classified as BES. The result will be
to require Generation Owners to register as Transmission Owners/Operators, as well, producing
substantial additional compliance costs for those Generation Owners but resulting in little or no
improvement in the reliability of the BES. We recommend that the SDT, like the Project 2010-07 SDT
(commonly referred to as the GO/TO Team), give careful consideration to the practical results of its
recommendations rather than relying on abstract conclusions about whether a “contiguous” or “noncontiguous” BES is more desirable. We are concerned that the SDT’s pursuit of a “contiguous” BES
will result in a substantially over-inclusive BES definition. The “contiguous” BES concept implies that
every Element arguably necessary for the reliable operation of the interconnected bulk system must
be included in the BES definition, even if it is interconnected with Elements that have no bearing on
the operation of the BES. NERC’s Standards Drafting Team for Project 2010-07, has already
considered this question and, based on an in-depth review of potentially applicable reliability
standards, has concluded that generation interconnection facilities, even if operated above 100-kV,
need to comply only with a limited set of reliability standards in order to achieve the reliability goals.
Much of the work of the Project 2010-07 SDT is applicable to the work of the BES Standards
Development Team. For example, the Project 2010-07 Team observed that interconnection facilities
“are most often not part of the integrated bulk power system, and as such should not be subject to
the same level of standards applicable to Transmission Owners and Transmission Operators who own
and operate transmission Facilities and Elements that are part of the integrated bulk power system.”

Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability.

Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained. We believe the exclusion as drafted adequately defines radials.
Yes
Kootenai strongly supports the categorical exclusion of Local Distribution Networks from the BES. In
fact, for reasons discussed at length in our answer to Question 1, we believe the exclusion is
necessary to ensure that the BES definition complies with the statutory requirement to exclude all
facilities used in the local distribution of electric power. LDNs are, of course, probably the most
common kind of local distribution facility. Further, the conversion of radial systems to local
distribution networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. Kootenai supports the
LDN exclusion, but we believe the exclusion should be refined in the following respects: • The SDT’s
draft states that: “LDN’s are connected to the Bulk Electric System (BES) at more than one location
solely to improve the level of service to retail customer Load.” (emphasis added) We recommend that
the SDT revise the sentence quoted above as follows: “LDN’s are connected to the Bulk Electric
System (BES) at more than one location solely to improve the level of service to retail customer Load
and not to accommodate bulk transfers of power across the interconnected bulk system.” By
instituting this suggestion, the SDT would emphasize the key difference between an LDN, which is
designed to reliably serve local, end-use retail customers, and the BES, which is designed to
accommodate bulk transfer of power at wholesale over long distances.
Yes
Kootenai supports the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that can ill afford the substantial costs that accompany
imposition of mandatory compliance with reliability standards. Further, we agree that the small
utilities covered by the exemption will have no measurable impact on the operation of the
interconnected BES. In the Pacific Northwest, many small entities were required to register by virtue
of owning a very small portion of the region’s 115-kV system. These utilities have faced substantial
compliance burdens even though their operations are simply not material to the interconnected bulk
grid in our region, and the investment of resources in compliance therefore will have no measurable
effect in improving the reliability of the interconnected grid.
No
While Kootenai agrees that the approach adopted by the SDT -- a core definition coupled with specific
inclusions and exclusions – will be effective in removing most local distribution facilities from the BES,
it will not remove all such facilities. For the reasons discussed at greater length in our answer to
Question 1, Kootenai believes that the proposed definition is over-inclusive and is likely to sweep up
certain facilities used in local distribution that should not be classified as BES. Kootenai notes that
exclusion of facilities from the BES does not mean that owners of those facilities are entirely exempt
from reliability standards. On the contrary, the statute provides that “users” of the BES can be subject
to reliability regulation. Hence, even where an entity does not own BES assets, it could be required to,
for example, provide necessary information to the applicable Reliability Coordinator and to participate
in the regional Under-Frequency Load Shedding program by setting the UFLS relays in its Local
Distribution Network at the appropriate settings. We note that participants in the WECC BESDTF Task
Force generally agreed that appropriate information should be provided by non-BES entities, although
there was considerable concern related to ensuring that the provision of information was not unduly
burdensome.

Yes
The Exceptions process is a necessary part of making this proposal compliant with the Federal Power
Act. As noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is
potentially in conflict with the limitations of the Federal Power Act, and in particular the statutory
exclusion for facilities used in the local distribution of electric energy. The SDT’s approach can meet
the statutory requirements only if the Exception process currently under development results in
facilities that are not properly classified as BES being exempted from regulation as BES facilities.
Kootenai has these additional concerns: • We are concerned that the proposed 24-month delay in the
effective date of the new definition will delay the potentially beneficial effects of the SDT’s efforts,
especially for utilities that have been inappropriately registered for BES-related functions, which is a
common situation in WECC. We therefore urge the new BES definition to become effective
immediately upon approval by FERC or other applicable regulatory agencies. Entities that have been
improperly registered for BES functions can then immediately file for deregistration and obtain the
benefits of the new definition as soon as possible. For entities that have not previously been
registered for BES-related functions but that would be required to register under the new definition,
we agree that 24 months is an appropriate transition period to allow the newly-registered entity to
attain compliance with newly-applicable reliability standards, many of which require new training for
employees, new maintenance procedures, and complex new operational protocols. However, the
transition period for newly-registered entities should be structured in a way that does not prevent
entities seeking deregistration from benefitting from the new definition at the earliest possible date. •
The current definition provides that “Elements may be included or excluded on a case-by-case basis
through the Rules of Procedure exception process.” Kootenai is concerned that the SDT carefully
delineate which entity has the burden of proof in the exclusion process. The WECC BESDTF approach,
which we commend to the SDT, laid out these burdens in some detail. Under that approach,
essentially, if a facility is excluded from the BES by virtue of the specific exclusions listed in the
definition, the Regional Entity bears the burden of proving that the facility nonetheless has a material
impact on the interconnected bulk transmission system and therefore should be included in the BES.
On the other hand, if a facility is classified as BES by virtue of the list of inclusions set forth in the
BES definition, it can still escape classification as BES, but bears the burden of demonstrating that its
facility has no material impact on the interconnected transmission system. We urge the SDT to give
careful consideration to these burden-of-proof questions and to follow the lead of the WECC BES Task
Force. • For the reasons we have explained in our answer to Question 11, we believe the Exception
process is critical both to ensure that the BES definition is effective in producing measurable gains to
bulk system reliability and to ensuring that the definition will comply with the limitations Congress
placed in Section 215. Hence, we believe the entire BES definition, including the Exception process
and related procedures, should be vetted through the NERC Standards Development Process,
including the full comment periods and a ballot approvals provided for in that process. We are
concerned that important elements of the BES definition have been assigned to the Rules of
Procedure Team, and that changes in the Rules of Procedure are subject to approval in a process that
provides considerably less due process and industry input than the Standards Development Process.
Accordingly, we urge that all elements of the BES definition, including those elements that have been
assigned to the Rules of Procedure Team, be vetted through the Standards Development Process.
Individual
Tracy Richardson
Springfield Utility Board
No
SUB appreciates the effort put forward in this process and is indicating “no” primarily because
Springfield Utility Board (SUB) has observed that the statutory term “Bulk Power System” is being
applied in some cases as being equivalent and interchangeable with “Bulk Electric System”. SUB is
concerned that the SDT’s proposed BES definition is broad and that it will sweep in many elements
that have little or no material impact on the reliable operation of the interconnected bulk transmission
grid. Springfield Utility Board requests that NERC create a distinction between the terms BPS and
BES. Are the two to be used interchangeably, or will BPS no longer be used? SUB suggests NERC
consider adopting the statutory definition of the Bulk Power System as the core definition of the Bulk
Electric System.
Yes

In concept, SUB supports an attempt to provide a clear demarcation between BES and non-BES
elements. The WECC Bulk Electric System Definition Task Force (BESDTF) has devoted considerable
effort to this question and has developed one-line diagrams which note the BES demarcation point for
a number of different kinds of elements that are common in the Western Interconnection.
No
SUB raises the questions “Are multiple individual units considered one unit if they have a shared
bus?” SUB is concerned that in the instance where individual units have a shared bus that some
interpretations would be that these are individual and therefore not part of the BES while other
interpretations would result in the units being considered part of the BES because of a shared bus.
Given I3, SUB suggests that units connected to a shared bus be considered as if they were not
connected to a shared bus if they are individually separable by automatic fault-interrupting devices
(e.g. two 15aMW units that have a shared bus would not be included as part of I2 if they each have
automatic fault-interrupting devices). Continuing the example of the two 15aMW units, if a shared bus
somehow combined the two individual units into one unit for purposes of I2, where does this
distinction end? What if they share the same transmission line? Is this transmission line considered
being a “bus” for purposes of combining the two units into one individual unit? Because this
discussion could go on with multiple examples, SUB suggests that the distinction be the automatic
fault-interrupting device. If the devices can be separated from each other and the local network then
they should be considered individual. While Springfield Utility Board does not own any generating
units, we do recognize the importance of the stability and restoration of the Grid, and the generation
necessary for the Grid.
No
While Springfield Utility Board does not own any generating units, we do recognize the importance of
the restoration of the Grid, and the generation necessary for the Grid. SUB would recommend that
NERC clearly define “location” and “single site”. Does single site mean interstate service area location
(adding up generation over multiple geographically separate areas), same City?, same common bus?,
etc… SUB suggests that for purposes of I3 (and other inclusions and exclusions that reference “same
site”, “same location”, or similar language) that the term “collectively share a common bus” be used.
Yes
While Springfield Utility Board does not own any Blackstart Resources, we do recognize the
importance of the restoration of the Grid, and the generation necessary for the Grid should have
identified paths that are critical, regardless of voltage level.
No
What is a collector system? Does this include a Local Distribution Network? A Local Distribution
Network (E3) may have multiple generating units within its service area that serve all or part of retail
load (E2). Would the aggregate nameplate rating of these units be included even though they would
otherwise be excluded by application of E2? For example, there may be multiple end users with 500
kW photovoltaic systems whose total nameplate capacity is 100 MVA. All or most of the power used is
consumed by the retail consumers. SUB suggests that the language be restated to say “Dispersed
power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating) that are not excluded under E2 utilizing a collector system through a common point of
interconnection to a system Element at a voltage of 100 kV or above” Or “Dispersed power producing
resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a
cCollector sSystem through a common point of interconnection to a system Element at a voltage of
100 kV or above. For purposes of this inclusion, a Collector System is any infrastructure not
connected to load – where parasitic load associated with a generation unit or units is not considered
load.” While Springfield Utility Board does not own any power producing resources, we do recognize
the importance of the restoration of the Grid, and the generation necessary for the Grid, regardless of
voltage level.
No
SUB agrees with the exclusion for radial systems, but would like clarification regarding the definition
of “radial”. SUB appreciates NERC developing a more clear and consistent definition of “radial”. For
clarity, SUB suggests the following language: “• Exclusion E1 – Any radial system which is described
as connected from a single Transmission source originating with an automatic interruption device and
that is characterized by any of the following: a)Only serving Load. A normally open switching device
between radial systems with the same or different transmission sources may operate in a ‘make-

before-break’ fashion to allow for reliable system reconfiguration to maintain continuity of electrical
service. Systems with a normally open switching device(s) that would otherwise result in a system
with more than one transmission source if the switching device(s) is closed are considered radial
systems. Or, b)Only including generation resources not identified in Inclusions I2, I3, I4 and I5. Or,
c)Is a combination of items (a.) and (b.) where the radial system serves Load and includes generation
resources not identified in Inclusions I2, I3, I4 and I5?” As a side note, some in the industry appear
to place a demarcation based on whether there is a fuse separating two systems. SUB is concerned
with interpretations that indicate that if there is a fuse, they are separate. This could result in “closed”
systems being considered “open” because there are fuses installed within the network. For example,
consider a 115 kV interconnection point stepped down to distribution level service with a fuse
continues along the distribution network to another fuse that is interconnected to a 115kV system
with another transmission source. Is this fused system closed or open? Is this an intended outcome?
SUB is hopeful that E1 will provide clarity to this issue.
No
The proposed language for Exclusion E2 refers to the “customer’s side of the retail meter”. There may
be multiple customers with different resources within the geographic area served by a Registered
Entity. Because E2 also refers to “net capacity provided to the BES”, SUB assumes that E2 is intended
to address resources within the Registered Entity that are served to a single customer or multiple
customers. A Registered Entity may have Elements that are separate and independent but that are
connected to the BES. Individually, these elements may not have resources that serve customer load
that meet I2 or I3, but collectively the sum or resources and elements served do meet I2 or I3. SUB
believes that the issue of reliability comes down to both resources, load served, and what paths are
shared (or not) between resources and loads. SUB suggests that isolated loads and resources that are
functionally independent from a Registered Entities overall system do not need to be added together.
SUB suggests the following language: “A generating unit or multiple generating units that serve all or
part of retail Load with electric energy on the customer’s side of the retail meter if: (i) the net
capacity along shared Elements provided to the BES does not exceed the criteria identified in
Inclusions I2 or I3, and (ii) standby, back-up, and maintenance power services are provided to the
generating unit or multiple generating units or to the retail Load pursuant to a binding obligation with
a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by
the applicable regulatory authority. For purposes of this exclusion, if a Registered Entity is responsible
for elements that serve loads and resources that are separate from other elements that the
Registered Entity is responsible for, then each set of loads and resources that are connected to
Elements the Registered Entity is responsible for shall be evaluated separately and resources will not
be added together. While Springfield Utility Board does not own any generating units, we do
recognize the importance of the restoration of the Grid, and the generation necessary for the Grid.
No
SUB agrees with items, a), b), and e) of the characteristics of an LDN. SUB believes that the language
regarding c) and d) needs clarification. c) states: “Power flows only into the Local Distribution
Network: The generation within the LDN shall not exceed the electric Demand within the LDN.” There
may be times where a closed system creates a situation where power flows through the system on an
unscheduled basis (electron’s will follow the path of least resistance). Left as is, there may be a
situation where on a planning basis there is no power flowing out of the LDN, but on a real time basis
power does flow in and out. “Power flows only into the Local Distribution Network: The sum of all
power being delivered into the LDN at the points of measurement is greater than the sum of all the
power measured as being delivered out of the LDN at the points of measurement” The generation
within the LDN shall not exceed the electric Demand within the LDN.” SUB suggests that the
generation language should be deleted, but if the language “The generation within the LDN shall not
exceed the electric Demand within the LDN.” is retained, what does “Demand” mean? The lowest
demand? The highest demand? Instantaneous demand? SUB suggests that if some generation
language is added that the exclusion read: “Power flows only into the Local Distribution Network: The
sum of all power being delivered into the LDN at the points of measurement is greater than the sum
of all the power measured as being delivered out of the LDN at the points of measurement The
generation within the LDN shall not exceed the maximum electric Demand within the LDN, where the
maximum electric Demand is the maximum electric Demand within the LDN as measured for over the
prior sixty (60) months.” d) states: “Not used to transfer bulk power: The LDN is not used to transfer
energy originating outside the LDN for delivery through the LDN”. Again, this language needs

clarification. How would an LSE/DP/TO (or other similar entity) know that their system is not being
used to transfer bulk power when other parties are scheduling transmission paths via a Balancing
Authority or other overarching entity? SUB suggests that the language be clarified to read “Not used
to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for
delivery through the LDN. This would be evaluated using scheduled transmission paths and not
measured amounts at the point of measurement. It is the responsibility of the Balancing Authority to
notify the Registered Entity with an LDN twelve (12) months in advance of when an LDN would be
used to schedule the transfer of energy outside the LDN for delivery through the LDN.” Collectively,
E3 would read: The LDN is characterized by all of the following: a)Separable by automatic fault
interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic
fault-interrupting devices; and b)Limits on connected generation: Neither the LDN, nor its underlying
Elements (in aggregate), includes more than 75 MVA generation; and c)Power flows only into the
Local Distribution Network: The sum of all power being delivered into the LDN at the points of
measurement is greater than the sum of all the power measured as being delivered out of the LDN at
the points of measurement; and d)Not used to transfer bulk power: The LDN is not used to transfer
energy originating outside the LDN for delivery through the LDN. This would be evaluated using
scheduled transmission paths and not measured amounts at the point of measurement. It is the
responsibility of the Balancing Authority to notify the Registered Entity with an LDN twelve (12)
months in advance of when an LDN would be used to schedule the transfer of energy outside the LDN
for delivery through the LDN.;and e)Not part of a Flowgate or Transfer Path: The LDN does not
contain a monitored Facility of a permanent flowgate in the Eastern Interconnection, a major transfer
path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored
Facility in the Quebec Interconnection, and is not a monitored Facility included in an Interconnection
Reliability Operating Limit (IROL). o Local distribution networks were added to the exclusion list after
considerable discussions among the SDT and various registered entities that have configurations
meeting these conditions. The SDT believes that any network that simply supports distribution and is
providing adequate protection should be excluded from the BES.
Yes
Springfield Utility Board supports the SDT in its efforts to avoid unintended consequences from
changes to the BES definition, especially for small entities that cannot afford the substantial costs that
accompany imposition of mandatory compliance with Reliability Standards. Further, we agree that the
small utilities covered by the exemption will have no measureable impact on the operation of the
interconnected BES. In the Pacific Northwest, many small entities were required to register by virtue
of owning a very small portion of the region’s 115 kV system. These utilities have faced substantial
compliance burdens even though their operations are simply not material to the interconnected bulk
grid in our region, and the investment of resources in compliance, therefore, will have no measurable
effect in improving the reliability of the interconnected Grid.
No
While SUB agrees that the approach adopted by the SDT, a core definition, couple with specific
inclusions and exclusions, will be effective in removing most local distribution facilities from the BES,
it will not remove all such facilities. SUB believes that the proposed definition is over-inclusive and is
likely to sweep up certain facilities used in local distribution that should not be classified as BES. SUB
notes that exclusion of facilities from the BES does not mean that owners of those facilities are
entirely exempt.
Yes
The exceptions process is a necessary part of making this proposal compliant with the Federal Power
Act. As noted in responses to Questions 1 and 11, SUB believes the basic SDT proposal is potentially
in conflict with the limitations of the Federal Power Act, and in particular the statutory exclusion for
facilities used in the local distribution of electric energy. The SDT’s approach can meet the statutory
requirements only if the Exception process currently under development results in facilities that are
not properly classified as BES being exempted from regulation as BES facilities.
Springfield Utility Board requests that NERC create a distinction between the terms BPS and BES. Are
the two to be used interchangeably, or will BPS no longer be used? SUB suggests NERC consider
adopting the statutory definition of the Bulk Power System as the core definition of the Bulk Electric
System. _______________________________________________________________ May 26,
2011 Dear NERC Standards Drafting Team: Thank you for the opportunity to comment on NERC’s
proposed Continent-wide Definition of Bulk Electric System. We believe that NERC ‘s proposed Bulk

Electric System definition is proceeding in the right direction, but that more work needs to be done.
SUB’s specific concerns are as follows: • Bulk Power System (BPS) and Bulk Electric System (BES) Springfield Utility Board requests that NERC create a distinction between the terms BPS and BES. Are
the two to be used interchangeably, or will BPS no longer be used? SUB suggests NERC consider
adopting the statutory definition of the Bulk Power System as the core definition of the Bulk Electric
System. • Clear definition of Radial – Because there still appears to be inconsistencies in both
definition and application, SUB encourages NERC to develop a concise definition of a radial system.
For example, if a system is normally operated as radial, but could be operated closed (by manually
closing a breaker), would it be considered a radial or close-looped system? If the answer is “that a
closed system”, is this in all cases, or are there exceptions? • Registration Status – SUB understands
that one of the primary values of clearly defining the BES is for registration determinations, as well as
determining which of the Standards apply to registered entities. SUB encourages NERC to support the
use of the BES definition for entity registration, and to develop the exception procedure for registered
entities that do not own or operate any BES Elements. Springfield Utility Board appreciates FERC and
NERC’s efforts to create a continent-wide definition of Bulk Electric System, and appreciates the
opportunity to provide comment. Tracy Richardson Springfield Utility Board SUB requests NERC to
consider the situation where an entity has multiple, but separate systems. The entity is required to
become a Registered Entity because the sum of their individual systems meets the thresholds, but
portions of their physically separated systems taken individually would otherwise not reach the
threshold for registration. For example, an entity may be responsible for service over a third party’s
transmission for distribution service to a single end user with a load less than =<25MW that has a
hard tap into the third parties’ transmission. Because the load has a hard tap, it is technically served
from more than one transmission source. If there are no other loads served along the tap or along the
third party’s transmission segment, SUB believes that this type of situation warrants exclusion from
the BES as it would otherwise be excluded – except for the fact that the combination of that service
and other separate systems that the entity is responsible for triggers registration. SUB is concerned
that devices such as shunt capacitor banks may be overlooked. For example, is a radial system
serving only load with a shunt capacitor bank included or excluded from BES? It does raise the issue
“what does “serving only load mean, exactly?” If a capacitor bank is used for purposes of managing
reliability within an local network and the local network would otherwise be classified as an LDN, is
the local network still classified as an LDN?
Individual
Joe Tarantino
Sacramento Municipal Utility District (SMUD)
Yes
Yes
Sacramento Municipal Utility District (SMUD) agrees with the concept of Inclusion 1. However, to
ensure a clarity of the “Bright-Line” criteria, two items for the Drafting Team (DT) to consider are: 1)
removal of the phrase other than GSU as it may lead to confusion. The GSUs typically have one
winding below 100 kV that disqualify their inclusion. 2) Reference to the transformer terminals each
above 100 kV would reduce confusion for single winding transformers and multiple winding
transformers.
Yes
SMUD agrees with the concept of Inclusion 2. To ensure the clarity of the “Bright-Line” criteria the
GSU when connected to a voltage 100 kV and above as indicated in the proposal should clearly state
that the GSU is included as BES.
Yes
SMUD also agrees with the Inclusion 3 concept.
Yes
SMUD agrees with the inclusion of blackstart resources and their cranking paths.
Yes
SMUD agrees with the Inclusion 5 concept. However, there are a few terms that require clarification
to support the “Bright-Line” application. It is unclear what is meant to be captured by the term
“Dispersed power producing resources”. As reflected in the intent statement it would be preferred to

indicate the applicability of the wind and solar resources or the term intermittent in the Inclusion 5
language. The term “collector system through a common point” is rather vague that lends to varied
interpretations that perhaps a defined level of MW through a single element bottleneck would help
quantify BES impacts. In addition, the BES delineation should be the single “bottleneck” element for
aggregate connection of 75 MVA as it is that element's interruption is what would impact the BES.
Additional concerns of I-5 suggests that the wind and solar resources would be BES components
where their singular contribution has no appreciable impact to the BES. Including the bottleneck
option seems to identify an aggregate BES impact for a loss of a 75 MW block that could have an
impact on the BES.
Yes
SMUD support with the Exclusion 1 concept. However to maintain the clarity for a “Bright-line” the
term “single Transmission source” needs to be expanded as it could be read to be a single line,
common bus or a single entity, that will change the meaning of this exclusion.
Yes
Yes
SMUD agrees with the concept for Exclusion 3. However, sub-bullet “C” should address potential for
integral values for variations of the load to the connected resource.
Yes
As written, it is unclear how this exclusion differs from the Radial exclusion. Furthermore, “small
utility” needs to be defined more clearly. The last sentence appears circular because ownership of a
transmission element would draw the owner into registration. Small entities have no measurable
impact to the BES and should not be burdened with the exemption process.
Yes
SMUD does agree that the differentiation is established between the transmission & distribution
systems. Although there is concern that the general “Bright-line” is not definitive and could afford
additional value through incorporating clarifying language.
No
SMUD supports the SDT’s efforts to create an acceptable BES definition directly linked to an
exemption process. SMUD would also like to bring to the BES SDT’s attention that the WECC the Bulk
Electric System Definition Task Force has constructed the framework on this task that we encourage
the SDT to review their work. SMUD would like to thank the BES SDT for consideration of these
comments.
Group
NERC Transmission Issues Subcommittee (TIS)
Mark Byrd
No
Although the wording can work as it is, the TIS believes clearer wording would be: “All Transmission
Elements operated at 100 kV or higher, Real Power and Reactive Power resources as described below,
connected at 100 kV or higher unless such designation is modified by the list shown below.”
No
It is not necessary to exclude generator step-up transformers because a GSU should be considered to
be part of the generating Unit. >>>>>>>>>>The reference to two windings is technically incorrect
because it would exclude autotransformers which technically only have one winding. It would be
better to say that both the high-side and the low side of the transformer connected at 100 kV or
higher. >>>>>>>>>>“I1 - Transformers, other than generator step-up (GSU) transformers,
including phase angle regulators, with two windings both the high-side and the low side of the
transformer connected at 100 kV or higher unless excluded under Exclusions E1 and E3.”
No
It is commonly understood that a generating unit includes the generator itself, and all of the
components that connect it to the grid, including the GSU. The specific inclusion of the GSU implies
that other components of a generating unit, such as its auxiliary transformers and loads, the

governors, exciters, etc., are not included. >>>>>>>>>>The TIS suggests the following wording:
>>>>>>>>>>“I2 - Individual generating units greater than 20 MVA (gross nameplate rating)
generator terminals through the GSU which has a high side connected at a voltage of 100 kV or
above.”
No
The use of the term “common bus” technically has a very specific meaning and would openly exclude
most modes of connection. There is no “common bus” in a ring-bus or a breaker-and-one-half
configuration. Also, it is not necessary to include the GSU (s), as commented in 3 above.
>>>>>>>>>>The TIS suggests using wording similar to that contained in I5: >>>>>>>>>>“I3 Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) connected through a common bus operated at a common point of
interconnection to a system Element at a voltage of 100 kV or above.”

The last sub-bullet in E2 is terribly confusing. The TIS does not offer alternate wording because we
are unsure of the meaning of the phrase: >>>>>>>>>> “…pursuant to a binding obligation with a
Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the
applicable regulatory authority.”

The definition should include variable frequency transformers and back-to-back HVdc converters that
connect portions of the system operated at 100 kV or higher, regardless of the dc voltage rating of
the converter equipment.
Group
Rayburn Country Electric Cooperative, Inc.
Eddy Reece
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

No

Individual
Rick Hansen
City of St. George
Yes
The definition is okay as long as proper inclusions and exclusions are included in the definition.
Yes
No
It is understood that this mirrors the Registry Criteria and this is a simple way to address the issue.
The justification states there is no technical rationale to change the 20 MVA threshold, however the
technical rationale for the 20 MVA criteria has not been provided to the industry either. Having a 20
MVA unit treated the same and subject to all of the same standard requirements as a unit with
several hundred MVA of capacity doesn’t make sense either. The requirements for an entity or facility
should match the impact of that facility to the system.
No
It is understood that this mirrors the Registry Criteria and this is a simple way to address the issue.
The justification states there is no technical rationale to change the 75 MVA threshold, however the
technical rationale for the 75 MVA criteria has not been provided either. Having a 75 MVA plant
treated the same as a plant with a rating of several hundred or several thousand MVA doesn’t make
sense either. The requirements for an entity or facility should match the impact of that facility to the
system.
Yes
No
See comments to questions 3 & 4 above. The requirements for an entity or facility should match the
impact of that facility to the system.
No
Radial systems should be excluded as outlined in E1a; however the generation level requirements of
20 MVA and 75 MVA (I2, I3, & I5) should be revisited. As long as the normal power flow is into the
radial system, the amount of generation on a radial segment should not automatically trigger an
inclusion to the BES.
Yes
The limits on generation levels need to be revisited, with similar concerns as noted to questions 7 & 9
for exclusions E1 & E3.
No
Local distribution networks should have an exclusion provision. However, the local generation limit of
75 MVA is too restrictive. As long as power flows into a LDN the amount of generation should not
trigger a LDN to be included in the BES. E3b should be removed from these exclusion criteria or
maybe a reasonable ratio of load level to allowed generation on the LDN.
No
Is the transmission source a single line, a single substation? This needs to be defined. What is a small
utility? This needs to be defined. Generation limits should also be revisited, see previous comments.
No
The way the definition is currently written it will include many entities with lines, generation and other
facilities whose only purpose is for the local generation and distribution of energy to local customers.
The generation restrictions and other language in the proposed definition will add additional
registrations (i.e. TO/TOP) to many smaller entities which will have a significant economic impact to
those utilities with little or no benefit to the main bulk system. The problems may stem more from the
“one size fits all” approach to the standards requirements, with the TO/TOP requirements being the
most onerous and difficult to comply with especially for smaller entities. Allowed generation levels and
the actual use of the transmission and generation facilities should be considered in what is and is not

included in the BES. As the proposed definition stands now along with the current reliability standards
a small utility with a few segments of 115 kV or 138 kV lines and with some generation to serve local
load must comply with the same requirements as a very large utility with hundreds of miles of 345 kV
or 500 kV lines and 1,000’s of MVA of generation. The use of applying small, medium and large
criteria to many of the standard requirements, similar to what is being considered for the CIP
standards with low, medium and high requirements should be considered.
No
What are proposed transition implementation plans for facilities that will now be included in the
definition? The implementation plan indicates 24 months which may or may not be enough depending
on the response time to exception process. How will a pending exception action affect compliance
requirements and effective dates? It should be at least 24 months after it has been determined that a
facility must be included.
Individual
John Brockhan
CenterPoint Energy

No
CenterPoint Energy believes that some radial systems described in Exclusion E1 are similar to the
local distribution networks (LDNs) described in Exclusion E3. A radial system may be connected to
more than one automatic interrupting device in certain substation designs, such as a ring bus
configuration. CenterPoint Energy believes similar wording should be used for Exclusion E1 and
Exclusion E3. Utilizing wording from Exclusion E3, CenterPoint Energy recommends changing the
beginning of Exclusion E1 to “Any radial system which is described as separable by automatic fault
interrupting devices: Wherever connected to the BES, the radial system must be connected through
automatic fault-interrupting devices; and:”.

CenterPoint Energy appreciates the opportunity to provide comments. In reviewing the draft
definition, CenterPoint Energy believes the SDT may have unintentionally expanded the definition of
the BES beyond the statutory definition in Section 215. Facilities included in the BES should be those
facilities that are necessary for the reliable operation of the BES. Many interconnected facilities
operated at 100kV and above, particularly those that are operated between 100kV and 200kV, are
interconnected primarily to enhance the service provided to customers, rather than to maintain
reliable operation of the BES. In addition; CenterPoint Energy is concerned with the addition of
another exception process to the Rules of Procedure (ROP). In orders 743 and 743-A, the Commission
allowed the ERO latitude to develop a definition that varied from the Commission’s recommendation.
CenterPoint Energy supports the inclusion/exclusion approach of the SDT and believes it should be
possible to define what constitutes the BES without an exception process. Historically, exception
processes within the ROP have been cumbersome, labor intensive, confusing, and require on-going
maintenance and quarterly or annual updates. Indeed, in question 10 of this comment form the SDT
recognizes the burden of administrating an exception process. While CenterPoint Energy understands
the SDT may feel pressure to produce a product quickly, the Company does not believe the expedited
nature justifies an inferior product. CenterPoint Energy recommends the SDT continue developing
criteria that clearly defines BES facilities based on the Section 215 language. Once that is
accomplished, an exception process will not be needed.

Individual
Sunitha Kothapalli
Puget Sound Energy
Yes
E3. Local distribution networks (LDNs): In this exclsion criteria, it was unclear about the size of the
LDN that could be excluded from BES. There was a limit on connected generation but not connected
load. If there is any mention of total aggregate load served by this LDN then that would clarify the
definition better. We would like to suggest using a limit say lesser than or equal to 300 MW of total
aggregate load served by LDN could be excluded from BES definition in addition to all the 5 (a-e)
characteristics mentioned.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
As suggested in Q1. If a limit on total aggregate load served by LDN is included, that would improve
the clarity of this exclustion.
Yes
No
The language on total aggregate load served by LDN should be added for the exclusion list.
No

Individual
Linda Esparza
Public Utility District No. 1 of Franklin County
No
As a general matter, Franklin PUD supports the approach the Standards Development Team (“SDT”)
has taken to defining the Bulk Electric System (“BES”). The changes made in the revised core
definition are helpful and represent significant progress toward an acceptable definition. With an
effective and efficient exclusion process, the draft will better define the BES as a whole. We urge the
SDT to bear in mind the restrictions contained in Section 215 of the Federal Power Act (“FPA”) The
“bulk-power system” (As per FERC, we treat the statutory term “bulk-power system” as equivalent to
the term ordinarily used in the industry, “Bulk Electric System”) definition imposes a clear limit on the
reach of the mandatory reliability regime. The BES is made up of only those “facilities and control
systems necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” and “electric energy from generation facilities needed to maintain transmission
system reliability.” Congress reinforced that limit in Section 215(i), where it emphasized that the FPA
authorizes the imposition of reliability standards “for only the bulk-power system.” Franklin PUD is
concerned that the SDT’s proposed definition is overly-broad, and that it will sweep in many Elements

that have little or no material impact on the reliable operation of the interconnected bulk transmission
grid. For example, the definition uses the arbitrary 20 MVA threshold from the NERC Statement of
Registry Criteria for inclusion of generators. Accordingly, for the BES definition to conform to the
requirements of the statute, the SDT must adopt an effective mechanism to exempt facilities like
these that are improperly swept in by the SDT’s brightline approach to inclusions and exclusions. For
this reason, the Exception process to accompany the SDT’s definition is of critical concern. If the SDT
incorporates this statutory language as its core definition, it will have addressed FERC’s primary
concern with a minimum of disruption to the current NERC system of definitions. The definition could
then be further elaborated to show specific points of demarcation for each inclusion and exclusion
similar to that Proposal 6 from the WECC Bulk Electric System Definition Task Force (“BESDTF”) team
to further delineate BES and non-BES facilities.
No
In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and nonBES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is
stepped down from transmission voltages to distribution voltages. We believe, however, that the SDT
should undertake the effort to more clearly define the point where the BES ends and non-BES
systems begin. In this regard, we note that the WECC Bulk Electric System Definition Task Force
(“BESDTF”) has devoted considerable effort to this question and has developed one-line diagrams
noting the BES demarcation point for a number of different kinds of Elements that are common in the
Western Interconnection. Using this work as a starting point, the SDT should be able to provide much
useful guidance to the industry with relatively little additional effort. Also, the reference to “two
windings of 100 kV or higher” may create some confusion because many three-phase transformer
banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We suggest
clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”
We again urge the SDT to consider further delineation of points of demarcation similar to WECC
BESDTF Proposal 6.
No
Franklin PUD is concerned that I2 inclusion criteria that includes the arbitrary 20 MVA threshold from
the NERC Statement of Registry Criteria for inclusion of generators is over-inclusive. Under FPA
Section 215, generation resources are excluded from the “bulk-power system” unless they produce
“electric energy” that is “needed to maintain transmission system reliability.” Hence, the inclusion as
drafted improperly expands the BES definition to include generators that the statute requires to be
excluded. In the same comments, the SDT also states that it has considered “the inclusion of
generator step-up (GSU) transformers and associated interconnection line leads and believes the BES
must be contiguous at this level in order to be reliable.” Unfortunately, the SDT appears to have
concluded that any interconnection facility operating above 100-kV should be classified as BES. The
result will be to require Generation Owners to register as Transmission Owners/Operators, as well,
producing substantial additional compliance costs for those Generation Owners but resulting in little or
no improvement in the reliability of the BES. We recommend that the SDT, like the Project 2010-07
SDT (commonly referred to as the GO/TO Team), give careful consideration to the practical results of
its recommendations rather than relying on abstract conclusions about whether a “contiguous” or
“non-contiguous” BES is more desirable. We are concerned that the SDT’s pursuit of a “contiguous”
BES will result in a substantially over-inclusive BES definition. The “contiguous” BES concept implies
that every Element arguably necessary for the reliable operation of the interconnected bulk system
must be included in the BES definition, even if it is interconnected with Elements that have no bearing
on the operation of the BES. NERC’s Standards Drafting Team for Project 2010-07, has already
considered this question and, based on an in-depth review of potentially applicable reliability
standards, has concluded that generation interconnection facilities, even if operated above 100-kV,
need to comply only with a limited set of reliability standards in order to achieve the reliability goals.
Much of the work of the Project 2010-07 SDT is applicable to the work of the BES Standards
Development Team. For example, the Project 2010-07 Team observed that interconnection facilities
“are most often not part of the integrated bulk power system, and as such should not be subject to
the same level of standards applicable to Transmission Owners and Transmission Operators who own
and operate transmission Facilities and Elements that are part of the integrated bulk power system.”
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with

the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability.
No
Franklin PUD is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the
20 MVA threshold discussed in our response to question 3, the 75 MVA threshold appears to have
been drawn from the NERC Statement of Compliance Registry without appreciation for the function of
the threshold in that document and without adequate technical justification demonstrating the
generators with an aggregate capacity of 75 MVA produce electric energy “needed to maintain
transmission system reliability” and are therefore properly included in the BES definition.
Yes
Including “all” blackstart and blackstart cranking paths in the BES may ultimately provide an incentive
to the electric industry to reduce the number of resources with blackstart capability. We therefore
suggest that essential blackstart resources identified by the Regional Entity should be included in the
Bulk Electric System, but non-essential blackstart resources need not be.
No
Franklin PUD agrees that it is important to address wind generation facilities and similar generation
facilities in which a large number of generating units, each with a relatively small capacity, are
clustered and fed into the grid at a single interconnection point. That being said, Franklin PUD is
concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained. We believe the exclusion as drafted adequately defines radials.
No
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through
reference to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the
generation unit is reliability-must-run or essential blackstart, the function of the unit is irrelevant to
the reliable operation of the interconnected bulk transmission grid, and we therefore believe the
reference to the function of the generation unit (“standby, back-up, and maintenance power…”)
should be eliminated.
Yes
Franklin PUD strongly supports the categorical exclusion of Local Distribution Networks from the BES.
In fact, for reasons discussed at length in our answer to Question 1, we believe the exclusion is
necessary to ensure that the BES definition complies with the statutory requirement to exclude all
facilities used in the local distribution of electric power. LDNs are, of course, probably the most
common kind of local distribution facility. Further, the conversion of radial systems to local
distribution networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. Franklin PUD
supports the LDN exclusion, but we believe the exclusion should be refined in the following respects:
The SDT’s draft states that: “LDN’s are connected to the Bulk Electric System (BES) at more than one
location solely to improve the level of service to retail customer Load." We recommend that the SDT
revise the sentence quoted above as follows: “LDNs are connected to the Bulk Electric System (BES)
at more than one location to improve the level of service to retail customer Load and not to
accommodate bulk transfers of power across the interconnected bulk system.” By instituting this
suggestion, the SDT would emphasize the key difference between an LDN, which is designed to
reliably serve local, end-use retail customers, and the BES, which is designed to accommodate bulk
transfer of power at wholesale over long distances.
Yes
Franklin PUD supports the SDT in its efforts to avoid unintended consequences from changes to the
BES definition, especially for small entities that can ill afford the substantial costs that accompany
imposition of mandatory compliance with reliability standards. Further, we agree that the small
utilities covered by the exemption will have no measurable impact on the operation of the
interconnected BES. In the Pacific Northwest, many small entities were required to register by virtue

of owning a very small portion of the region’s 115-kV system. These utilities have faced substantial
compliance burdens even though their operations are simply not material to the interconnected bulk
grid in our region, and the investment of resources in compliance therefore will have no measurable
effect in improving the reliability of the interconnected grid.
No
While Franklin PUD agrees that the approach adopted by the SDT -- a core definition coupled with
specific inclusions and exclusions – will be effective in removing most local distribution facilities from
the BES, it will not remove all such facilities. For the reasons discussed at greater length in our
answer to Question 1, Franklin PUD believes that the proposed definition is over-inclusive and is likely
to sweep up certain facilities used in local distribution that should not be classified as BES. As
discussed in our answer to Question 3, Franklin PUD notes that exclusion of facilities from the BES
does not mean that owners of those facilities are entirely exempt from reliability standards. On the
contrary, the statute provides that “users” of the BES can be subject to reliability regulation. Hence,
even where an entity does not own BES assets, it could be required to, for example, provide
necessary information to the applicable Reliability Coordinator and to participate in the regional
Under-Frequency Load Shedding program by setting the UFLS relays in its Local Distribution Network
at the appropriate settings. We note that participants in the WECC BESDTF Task Force generally
agreed that appropriate information should be provided by non-BES entities, although there was
considerable concern related to ensuring that the provision of information was not unduly
burdensome.
Yes
The Exceptions process is a necessary part of making this proposal complaint with the Federal Power
Act. As noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is
potentially in conflict with the limitations of the Federal Power Act, and in particular the statutory
exclusion for facilities used in the local distribution of electric energy. The SDT’s approach can meet
the statutory requirements only if the Exception process currently under development results in
facilities that are not properly classified as BES being exempted from regulation as BES facilities.
Franklin PUD has these additional concerns: • The current definition provides that “Elements may be
included or excluded on a case-by-case basis through the Rules of Procedure exception process.”
Franklin PUD is concerned that the SDT carefully delineate which entity has the burden of proof in the
exclusion process. The WECC BESDTF approach, which we commend to the SDT, laid out these
burdens in some detail. Under that approach, essentially, if a facility is excluded from the BES by
virtue of the specific exclusions listed in the definition, the Regional Entity bears the burden of proving
that the facility nonetheless has a material impact on the interconnected bulk transmission system
and therefore should be included in the BES. On the other hand, if a facility is classified as BES by
virtue of the list of inclusions set forth in the BES definition, it can still escape classification as BES,
but bears the burden of demonstrating that its facility has no material impact on the interconnected
transmission system. We urge the SDT to give careful consideration to these burden-of-proof
questions and to follow the lead of the WECC BES Task Force. • For the reasons we have explained in
our answer to Question 11, we believe the Exception process is critical both to ensure that the BES
definition is effective in producing measurable gains to bulk system reliability and to ensuring that the
definition will comply with the limitations Congress placed in Section 215. Hence, we believe the
entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES
definition have been assigned to the Rules of Procedure Team, and that changes in the Rules of
Procedure are subject to approval in a process that provides considerably less due process and
industry input than the Standards Development Process. Accordingly, we urge that all elements of the
BES definition, including those elements that have been assigned to the Rules of Procedure Team, be
vetted through the Standards Development Process.
Individual
Patrick Farrell
Southern California Edison Company
No
The current approach seems to be based on the assumption that the presence of particular equipment
is more important than the manner in which the equipment is used. Before SCE can support the BES

Definition, the definition should be revised to include “All Transmission and Generation Elements and
Facilities operated at voltages 100 kV or higher, Real Power resources as described below, and
Reactive Power resources connected at 100 kV or higher that operate in parallel with the integrated
networked transmission system and are necessary for operating the interconnected transmission
network, unless such designation is modified by the list shown below.” This modification will provide
the clarification needed to better ascertain what facilities should be identified as part of the BES and
lessen the need to trigger the Rules Of Procedure exceptions process. If “Inclusions” and “Exclusions”
continue to be a part of the BES definition, they will need additional clarification to ensure the
exclusion of radial and distribution facilities which (1) do not have interconnected operations risk and
(2) are not used for inter-utility transfers on the BES and, therefore, are not necessary for operating
the interconnected transmission network. They also need to be modified to work in tandem with the
“Technical Principles for Demonstrating BES Exceptions”, so that these types of facilities don’t
continually have to be validated by the ROP exceptions process. Example: The exclusion of facilities
which are radial or distribution in nature and that have connecting generation of 20MVA or higher for
the purpose of serving local load and that are not used to transfer power between “systems” to the
BES should be automatic under the BES Definition.
No
Identifying specific equipment within the “Inclusions” or “Exclusions” component is too prescriptive,
and itemizing them in this fashion misses the intent of this endeavor which should be to ultimately
ensure the risks to region wide reliability are captured. Therefore, it is SCE’s position that the
proposed BES Definition should not single out specific pieces of equipment, and that they should be
included or excluded based on the criteria of the definition. To do otherwise could: (i) generate
confusion due the many types and variations of equipment, and what should/should not be included
In the BES; and (ii) include radial or distribution systems into scope that might not otherwise have
been considered, and which pose no regional reliability risk. If the BES Definition continues to
reference transformer types, it should clarify what specific attributes qualify for inclusion. This might
best reside in companion documentation that would accompany the definition to ensure consistency in
application.
No
Inclusions I2, I3, and I5 should either be modified or removed, because as currently written, these
three Inclusion criteria force the definition to be arbitrarily demarcated by the size of generators
connecting to the system, or the aggregate thereof, rather than focusing on the risk characteristics
that should define the BES, as SCE identified in its response to Question No. 1. In the WECC, it can
safely be said that the vast majority of 20MVA generators are located in local distribution systems and
are used to off-set local load, rather than transfer power to the BES. In SCE’s case, our distribution
system has a number of components which are marginally above the 100kV BES threshold, are radial
in nature, and were previously exempted from the BES by the WECC. These radial systems have
interconnecting generation units larger than 20 MVA and/ or aggregate generation exceeding 75 MVA.
In many cases, the generation levels on those radial systems exceed the limits proposed in I2, I3,
and I5, but the loading on those same systems is such that generation will rarely exceed the local
load. Therefore, there is little to no power flow back to the BES from these radial systems. If the BES
definition continues to heavily focus its inclusion criteria on generator/ generation size, SCE feels that
the SDT also consider incorporating the concept of “potential exports to the BES” from these
generating sources. An example being: “I2 – Individual generating units greater than 20 MVA (gross
nameplate rating) including the generator terminals through the GSU which has a high side voltage of
100 kV or above and have no more than 5% net flows into the BES based on the past XXX calendar
years.” This “Net Flow” concept would negate the need for Section 1C of the “Technical Principles for
Demonstrating BES Exceptions”, or conversely, provide the framework for a more quantifiable criteria
in Section 1C.
No
Please refer to SCE’s answer for Question No. 3 above.
Yes
No
Please refer to SCE’s answer for Question No. 3 above. If the SDT goes forward and includes I5 into
either the proposed BES definition or the Technical Principles for Demonstrating BES Exceptions, the

following additional clarification should be made: (i) Clarify the terms “Dispersed power producing
resources” and “collector system”; (ii) When referencing “collector system,” does it include the lines
connecting the generation?; (iii) Why the 75 MVA threshold? This seems to be a somewhat arbitrary
number which does not correlate with specific operational risks, operational limits, or network
capability. This is highlighted when taking SCE’s system into consideration, as we carry operational
spinning reserves that are 10 to 20 times greater than the 75 MVA threshold identified in the
proposed BES Definition. If SCE were to lose 75 MVA in an event, there would be no reliability risk or
perceptible frequency deviation that would attend the event. The proportionality of risk and benefit
does not seem to fit within the application and philosophy behind the mandatory limit. Setting the
BES Definition in this manner in order to bring in the smallest utilities is not appropriate for
application to the larger utilities.; and (iv) As written, I5 could unintentionally bring into scope subtrans/distribution systems with enough generation as these radial systems could be categorized as
“collector systems”. Specifically, there are radially-connected distribution systems in the Desert
Southwest designed to enable the interconnection of multiple renewable resources which could be
viewed as grouping this collective generation at the point of interconnection with the transmission
system. In many cases, the sum total of this generation could be greater than 75 MVA.
No
SCE cannot support this exclusion as it will only apply if generation on the radial system does not
exceed the criteria identified in I2, I3 and I5. SCE has identified its concerns regarding these
aforementioned items in its previous responses. If the SDT goes forward with E1 criteria, the criteria
should be modified as follows: (i) Delete “originating with an automatic interrupting device.” This
statement does not change or describe the flow to or from a radial system; (ii) E1 should be modified
to identify that generation interconnected to a radial system should not exceed a measureable
threshold of electrical demand on the radial system – an example being “5% occurrence in the past
XXX years”. This would negate some of the concerns identified regarding I2, I3 and I5; and (iii) SCE
also feels that if the core BES definition is to reference protection devices, it should not identify the
particular type of protection device as it did in E1, by specifically calling out “make before break”
switching, as there are other types of protection with similar functionality.
No
SCE does not believe that the size of generator should dictate what system facilities, regardless of
voltage, will or will not be included in the BES definition. More important, is the issue of whether or
not the generation has net flow(s) out to the greater integrated networked transmission system. It is
the “generation” and not the “generator” which has impacts on the BES. In addition, it would seem
that if these are truly “behind-the-meter”, non-export interconnected generation, then there is no
scenario that would result in flow back onto the BES, no matter what the interconnection level. The
focus should not be restricted to only “behind-the-meter” generation, but rather on the flow
generation from the radial system.
No
SCE is in support of the general LDN premise, but believes that this definition should more closely
track the FERC seven-factor test from Order 888. As written, the five factors identified could lead to
the reclassification of radial sub-transmission system facilities above 100kV from “distribution
facilities” to “network facilities”. For example, interconnection amounts within an LDN may exceed an
aggregate level of 75MVA, but will not exceed the load in the LDN. SCE suggests striking
characteristics “B” and “D” from Exclusion E3, and allowing characteristic “C” to stand alone as the
generation characteristic which would define an LDN. The SDT may want to incorporate the following
revision: “LDN’s are connected to the Bulk Electric System (BES) at one or more location solely to
improve the level of service to retail customer load.”
No
Small utilities should not be automatically excluded from the BES if the BES Definition continues to
focus on the size of interconnecting generators to determine what facilities are included in the BES.
Instead, small utilities should be required to justify their exclusion using the exemption procedure and
the Technical Principles for Demonstrating BES Exceptions. This would provide the necessary
oversight to ensure these smaller systems continued to stay under the thresholds stipulated in the
BES definition. In many areas, it is both faster and less expensive for renewable generators to
interconnect with these systems, thus potentially allowing for the addition of large amounts of
generation totaling more than the draft BES allowances within a relatively short period of time.

No
SCE believes that the BES Definition, as currently proposed, relies too heavily on the characterization
of interconnected generation in its “Inclusion” criteria.
Yes
For participants in an ISO/RTO, such as the CAISO, the final BES Definition may change the party
who will control system facilities, even if they are distribution or radial in nature, based on the
amount or size of interconnected generation. Generally, within the CAISO, facilities that are included
in the BES Definition are under CAISO’s direct control, while radial and distribution facilities are not.
As discussed during the May 19, 2011 NERC Webinar, SCE supports having one-line diagrams
illustrating examples of the line and bus arrangements as they pertain to the BES Definition included
as part of a set of support documents. A good start for these diagrams would be the ones developed
by the WECC Bulk Electric System Definition Task Force (WECC BESDTF). These diagrams were
developed by WECC to better illustrate the demarcation between BES and non-BES facilities and
provide important information and insight into the WECC system.
Individual
Thomas Weller
Midstate Electric Cooperative
No
As a general matter, MSEC supports the approach the Standards Development Team (“SDT”) has
taken to defining the Bulk Electric System (“BES”). The changes made in the revised core definition
are helpful and represent significant progress toward an acceptable definition. With an effective and
efficient exclusion process, the draft will better define the BES as a whole. We urge the SDT to bear in
mind the restrictions contained in Section 215 of the Federal Power Act (“FPA”) The “bulk-power
system” (As per FERC, we treat the statutory term “bulk-power system” as equivalent to the term
ordinarily used in the industry, “Bulk Electric System”) definition imposes a clear limit on the reach of
the mandatory reliability regime. The BES is made up of only those “facilities and control systems
necessary for operating an interconnected electric energy transmission network (or any portion
thereof)” and “electric energy from generation facilities needed to maintain transmission system
reliability.” Congress reinforced that limit in Section 215(i), where it emphasized that the FPA
authorizes the imposition of reliability standards “for only the bulk-power system.” MSEC is concerned
that the SDT’s proposed definition is overly-broad, and that it will sweep in many Elements that have
little or no material impact on the reliable operation of the interconnected bulk transmission grid. For
example, the definition uses the arbitrary 20 MVA threshold from the NERC Statement of Registry
Criteria for inclusion of generators. Accordingly, for the BES definition to conform to the requirements
of the statute, the SDT must adopt an effective mechanism to exempt facilities like these that are
improperly swept in by the SDT’s brightline approach to inclusions and exclusions. For this reason, the
Exception process to accompany the SDT’s definition is of critical concern. If the SDT incorporates this
statutory language as its core definition, it will have addressed FERC’s primary concern with a
minimum of disruption to the current NERC system of definitions. The definition could then be further
elaborated to show specific points of demarcation for each inclusion and exclusion similar to that
Proposal 6 from the WECC Bulk Electric System Definition Task Force (“BESDTF”) team to further
delineate BES and non-BES facilities.
No
In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and nonBES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is
stepped down from transmission voltages to distribution voltages. We believe, however, that the SDT
should undertake the effort to more clearly define the point where the BES ends and non-BES
systems begin. In this regard, we note that the WECC Bulk Electric System Definition Task Force
(“BESDTF”) has devoted considerable effort to this question and has developed one-line diagrams
noting the BES demarcation point for a number of different kinds of Elements that are common in the
Western Interconnection. Using this work as a starting point, the SDT should be able to provide much
useful guidance to the industry with relatively little additional effort. Also, the reference to “two
windings of 100 kV or higher” may create some confusion because many three-phase transformer
banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We suggest
clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”

We again urge the SDT to consider further delineation of points of demarcation similar to WECC
BESDTF Proposal 6.
No
MSEC is concerned that I2 inclusion criteria that includes the arbitrary 20 MVA threshold from the
NERC Statement of Registry Criteria for inclusion of generators is over-inclusive. Under FPA Section
215, generation resources are excluded from the “bulk-power system” unless they produce “electric
energy” that is “needed to maintain transmission system reliability.” Hence, the inclusion as drafted
improperly expands the BES definition to include generators that the statute requires to be excluded.
In the same comments, the SDT also states that it has considered “the inclusion of generator step-up
(GSU) transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable.” Unfortunately, the SDT appears to have concluded
that any interconnection facility operating above 100-kV should be classified as BES. The result will be
to require Generation Owners to register as Transmission Owners/Operators, as well, producing
substantial additional compliance costs for those Generation Owners but resulting in little or no
improvement in the reliability of the BES. We recommend that the SDT, like the Project 2010-07 SDT
(commonly referred to as the GO/TO Team), give careful consideration to the practical results of its
recommendations rather than relying on abstract conclusions about whether a “contiguous” or “noncontiguous” BES is more desirable. We are concerned that the SDT’s pursuit of a “contiguous” BES
will result in a substantially over-inclusive BES definition. The “contiguous” BES concept implies that
every Element arguably necessary for the reliable operation of the interconnected bulk system must
be included in the BES definition, even if it is interconnected with Elements that have no bearing on
the operation of the BES. NERC’s Standards Drafting Team for Project 2010-07, has already
considered this question and, based on an in-depth review of potentially applicable reliability
standards, has concluded that generation interconnection facilities, even if operated above 100-kV,
need to comply only with a limited set of reliability standards in order to achieve the reliability goals.
Much of the work of the Project 2010-07 SDT is applicable to the work of the BES Standards
Development Team. For example, the Project 2010-07 Team observed that interconnection facilities
“are most often not part of the integrated bulk power system, and as such should not be subject to
the same level of standards applicable to Transmission Owners and Transmission Operators who own
and operate transmission Facilities and Elements that are part of the integrated bulk power system.”
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability.
No
MSEC is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20
MVA threshold discussed in our response to question 3, the 75 MVA threshold appears to have been
drawn from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition.
Yes
Including “all” blackstart and blackstart cranking paths in the BES may ultimately provide an incentive
to the electric industry to reduce the number of resources with blackstart capability. We therefore
suggest that essential blackstart resources identified by the Regional Entity should be included in the
Bulk Electric System, but non-essential blackstart resources need not be.
MSEC agrees that it is important to address wind generation facilities and similar generation facilities
in which a large number of generating units, each with a relatively small capacity, are clustered and
fed into the grid at a single interconnection point. That being said, MSEC is concerned that the 75
MVA threshold has been chosen arbitrarily for the reasons stated in our comments on Question 4. This
would lump together many IPP's that are spread out over a large distribution network that happen to
be tied into a single point of interconnection.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be

retained. We believe the exclusion as drafted adequately defines radials.
No
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through
reference to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the
generation unit is reliability-must-run or essential blackstart, the function of the unit is irrelevant to
the reliable operation of the interconnected bulk transmission grid, and we therefore believe the
reference to the function of the generation unit (“standby, back-up, and maintenance power…”)
should be eliminated.
Yes
MSEC strongly supports the categorical exclusion of Local Distribution Networks from the BES. In fact,
for reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are, of course, probably the most common kind of local
distribution facility. Further, the conversion of radial systems to local distribution networks should be
encouraged because networked systems generally reduce losses, increase system efficiency, and
increase the level of service to retail customers. MSEC supports the LDN exclusion, but we believe the
exclusion should be refined in the following respects: • The SDT’s draft states that: “LDN’s are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of
service to retail customer Load.” (emphasis added) We recommend that the SDT revise the sentence
quoted above as follows: “LDN’s are connected to the Bulk Electric System (BES) at more than one
location solely to improve the level of service to retail customer Load and not to accommodate bulk
transfers of power across the interconnected bulk system.” By instituting this suggestion, the SDT
would emphasize the key difference between an LDN, which is designed to reliably serve local, enduse retail customers, and the BES, which is designed to accommodate bulk transfer of power at
wholesale over long distances.
Yes
MSEC supports the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that can ill afford the substantial costs that accompany
imposition of mandatory compliance with reliability standards. Further, we agree that the small
utilities covered by the exemption will have no measurable impact on the operation of the
interconnected BES. In the Pacific Northwest, many small entities were required to register by virtue
of owning a very small portion of the region’s 115-kV system. These utilities have faced substantial
compliance burdens even though their operations are simply not material to the interconnected bulk
grid in our region, and the investment of resources in compliance therefore will have no measurable
effect in improving the reliability of the interconnected grid.
No
While MSEC agrees that the approach adopted by the SDT -- a core definition coupled with specific
inclusions and exclusions – will be effective in removing most local distribution facilities from the BES,
it will not remove all such facilities. For the reasons discussed at greater length in our answer to
Question 1,MSEC believes that the proposed definition is over-inclusive and is likely to sweep up
certain facilities used in local distribution that should not be classified as BES. As discussed in our
answer to Question 3, MSEC notes that exclusion of facilities from the BES does not mean that owners
of those facilities are entirely exempt from reliability standards. On the contrary, the statute provides
that “users” of the BES can be subject to reliability regulation. Hence, even where an entity does not
own BES assets, it could be required to, for example, provide necessary information to the applicable
Reliability Coordinator and to participate in the regional Under-Frequency Load Shedding program by
setting the UFLS relays in its Local Distribution Network at the appropriate settings. We note that
participants in the WECC BESDTF Task Force generally agreed that appropriate information should be
provided by non-BES entities, although there was considerable concern related to ensuring that the
provision of information was not unduly burdensome.
Yes
The Exceptions process is a necessary part of making this proposal complaint with the Federal Power
Act. As noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is
potentially in conflict with the limitations of the Federal Power Act, and in particular the statutory
exclusion for facilities used in the local distribution of electric energy. The SDT’s approach can meet
the statutory requirements only if the Exception process currently under development results in

facilities that are not properly classified as BES being exempted from regulation as BES facilities.
Yes MSEC has these additional concerns: • The current definition provides that “Elements may be
included or excluded on a case-by-case basis through the Rules of Procedure exception process.”
MSEC is concerned that the SDT carefully delineate which entity has the burden of proof in the
exclusion process. The WECC BESDTF approach, which we commend to the SDT, laid out these
burdens in some detail. Under that approach, essentially, if a facility is excluded from the BES by
virtue of the specific exclusions listed in the definition, the Regional Entity bears the burden of proving
that the facility nonetheless has a material impact on the interconnected bulk transmission system
and therefore should be included in the BES. On the other hand, if a facility is classified as BES by
virtue of the list of inclusions set forth in the BES definition, it can still escape classification as BES,
but bears the burden of demonstrating that its facility has no material impact on the interconnected
transmission system. We urge the SDT to give careful consideration to these burden-of-proof
questions and to follow the lead of the WECC BES Task Force. • For the reasons we have explained in
our answer to Question 11, we believe the Exception process is critical both to ensure that the BES
definition is effective in producing measurable gains to bulk system reliability and to ensuring that the
definition will comply with the limitations Congress placed in Section 215. Hence, we believe the
entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES
definition have been assigned to the Rules of Procedure Team, and that changes in the Rules of
Procedure are subject to approval in a process that provides considerably less due process and
industry input than the Standards Development Process. Accordingly, we urge that all elements of the
BES definition, including those elements that have been assigned to the Rules of Procedure Team, be
vetted through the Standards Development Process. Dear NERC Standards Drafting Team: Enclosed
are MSEC’s comments on NERC’s Proposed Continent-wide Definition of Bulk Electric System. We
believe that NERC’s proposed Continent-wide Definition of Bulk Electric System is proceeding in the
right direction on this important topic but that more work needs to the done. We would like to thank
the Standards Drafting Team for their hard work. We support the detailed comments of the
Snohomish County Public Utility District and Pacific Northwest Generating Cooperative with regard to
the questions posed by the Comment Form for Project 2010-17 Definition of BES. We would like to
emphasize these portions of Snohomish’s and PNGC’s comments: • Question 1, both PNGC and
Snohomish suggest that NERC start by adopting the statutory definition of the bulk power system as
the core definition. We support that approach. That is, “(t) he term ‘Bulk Electric System’ means: (A)
Facilities and control systems necessary for operating an interconnected electric energy transmission
network (or any portion thereof); and, (B) Electric energy from generation facilities needed to
maintain transmission system reliability. The term does not include facilities used in the local
distribution of electric energy”. See 16 U.S.C. § 824o(a)(1).” • Question 7, we support the exclusion
for radial lines as drafted. • Question 9, we support the categorical exclusion of Local Distribution
Networks from the BES as defined here, but with Snohomish’s clarifications. • Question 10, we
support exclusion E4, for small utilities, but we are unclear how small utilities are defined in the
exclusion language presented here. • Question 11, we support the approach to exclusion of local
distribution facilities discussed in the draft but repeat that more work should be done on the definition
so that facilities used in local distribution are not swept up into the BES. The primary value of clearly
defining the BES is for registration determinations. We realize that clearly defining the BES also has
value in determining which standards apply to registered entities. If a registered entity does not own
any Elements of the BES that that registered entity should be able to efficiently and effectively
demonstrate an exception. We encourage NERC to support the use of the BES definition for
registration-issues and to develop the exception procedure for registered entities that do not own or
operate any Elements of the BES.
Individual
Jason Snodgrass
GTC
Yes
Yes

Yes
Yes
Yes
Yes
Yes
Agree, but further clarification requested. E1 reads as if the originating automatic interrupting device
is to be excluded with the radial system. Can the drafting team clarify this intent with respect to
breakers protecting radial lines versus for example a breaker or circuit switcher protecting an
excluded transformer which is not part of the BES? Drawings would be very beneficial here.
Yes
Yes
Yes
No
Since distribution facilities are to be excluded can the drafting team clarify if the automatic
interrupting protective device (breaker or circuit switcher) operating at 100kV or above and protecting
an excluded transformer (non-BES) should be excluded with the excluded transformer? Perhaps an
additional separate exclusion could eliminate any uncertainty.
No
see comments above.
Individual
Diane Barney
New York State Dept of Public Service
No
1) We do not agree with the core definition. The core definition starts with the premise that the
definition must be drafted based on a 100 kV brightline designation. FERC’s Order 743 and 743-A
clearly state that is just one approach and would entertain other approaches that demonstrate the
same level of reliable operation and is responsive to FERC’s reliable operation concerns. As the EPAct
2005 recognizes, the industry technical expertise is preserved in the NERC and does not reside at
FERC. Therefore, FERC’s jurisdiction is expressly limited by Section 215 of the Federal Power Act.
Moreover, FERC cannot, under the guise of “policy” concerns, exceed the limits of its statutory
authority. FERC’s orders recognize this, and repeatedly acknowledge that FERC must exclude facilities
used in local distribution from the definition of BES. FERC’s orders, at most, assert that “some”
115/138 kV facilities are needed to reliably operate the bulk system. FERC has made no showing that
all facilities of 100kV or greater are necessary for reliable operation of the grid. Without a record
based finding that all such facilities are necessary for reliable operation of the grid, FERC cannot
include all such facilities within its definition of BES. FERC has even explicitly acknowledged within a
New York transmission tariff rate case that a 115 kV loop around a significant size city should not be
included in the transmission account as it existed solely to serve load in that city. Given the technical
expertise to devise a definition more refined lies with the industry, FERC wisely deferred to NERC
processes the ability to employ a different approach other than a brightline. Therefore, NERC should
apply its expertise to fashion a definition of “bulk electric system” that comports with the statutory
jurisdictional limitations Congress imposed upon FERC in FPA Section 215. NERC’s efforts should be
checked at every step that they are not exceeding the originating authority contained in FPA Section
215. Overall, the definition must be guided by, and limited to, the FPA definition of reliable operation
which is explicitly defined as limited to protection of the bulk system by “operating the elements of

the bulk-power system … so that instability limits, uncontrolled separation, or cascading failures of
such systems will not occur….”, and expressly excludes facilities used in local distribution. 2) NERC
fails to make any technical demonstration that using the existing definition as a starting point is valid.
Moreover, NERC has resisted pursuing alternative avenues. The NPCC study submitted to FERC in the
combined NERC-NPCC compliance filing in September 2009, clearly demonstrated the movement from
the NPCC regional criteria to a 100 kV brightline provided little, if any, increased levels of reliable
operation. Through extrapolation, a study of other areas is likely to indicate that reliable operation
levels throughout the rest of the country could be assured by a more refined selection of which
facilities under 200 kV should be included as part of the bulk system. Note that FERC did not reject
use of material impact assessmensts; they only objected to the fact that the NPCC test did not include
some regional interconnection facilities, some nuclear interconnections and a particular load area.
NERC’s failure to evaluate other approaches than a brightline 100 kV standard is a failure to ensure
adequate levels of reliable operation at a sustainable level consistent with provisions of the FPA. All
remaining comments on the definition, as presented by NERC, are based on our belief that the
proposed definition is overreaching in its basic premise of starting with a brightline 100 kV as its core
definition of the bulk system. 3) It is not clear why the core definition has dropped “generation”
interconnected at the specified voltage level. The following inclusions/exclusions included generation
facilities and it appears inconsistent to not include generation in the core definition.
No
The inclusion of 20 MVA generation seems inconsistent with I3 that sets the aggregate threshold at
75 MVA. It is not rational that a 20 MVA facility could be the cause of instability, uncontrolled
separation of the system or cascading events. This inclusion should be dropped.
I3 should be revised to read all generation – individually or aggregate – 75 MVA and above.
No
This inclusion is problematic at a couple levels. First, blackstart resources can be facilities smaller
than the previous thresholds located deep within the local distribution system. Second, given you do
not know ahead of time how the system might come apart, often there are multiple cranking paths
specified. To avoid incurring the costs of upgrading facilities all along multiple paths, there will be an
inclination to designate only one path involving the fewest impacted facilities. The result could be
reduced reliable operation – not more.
Yes
We agree with exclusion E1. As described, the facilities are clearly local distribution. Requiring a
“make-before-break” switching device, between the BES and the excluded radial system, as a
condition-precedent for such exclusion is proper. Such switches are necessary to promote reliable
operation by enabling removal of radial systems principally serving load for maintenance and other
reliable system operations. If the “make-before-break” switching capability is not included as part of
the exclusion, the specification would undermine reliable system operation.
Yes
This exclusion is appropriately specified. Behind the meter generation is mainly on the local
distribution system and most likely modeled in power flow cases used to study the bulk system as
netted against load. For the few sizable behind the meter generation that are: 1) connected at the
100 kV level and above; and, 2) exceed the 75 MVA threshold, if it is believed that these facilities will
impact the bulk system they can be petitioned for inclusion under the rules of procedure.
Yes
This exclusion properly recognizes that local distribution facilities can be at any voltage level. It also
properly recognizes that reliable service to load often requires parallel circuits. As written, the
exclusion respects FERC’s concern that major generation facilities should not be part of the LDN, by
limiting the exclusion to generation of75 MVA or less, and to only facilities that move energy down to
the LDN.
Yes
This exclusion is consistent with E1 and E2. There should not be discrimination against similarly
situated loads.
No

See comments under question 1.
Yes
As expressed in comments under question 1, we believe that use of a 100 kV brightline definition is
an overreach of authority and that any definition must respect the limitations itemized in FPA 215.
The FPA recognizes that only a subset of the electric system facilities have the capacity to impact
multi-state portions of the electric system and rise to the level of federal attention. As a practical
matter, however, the electric system is a continuous machine and efforts to maintain reliability on
both the transmission and local distribution portions of the electric system must be compatible. That
is the key role that the regional entities play and that role should be maintained and respected by
NERC efforts. The time and effort it takes to draft standards to address issues on the bulk system is
directly attributable to the many different options to design and operate transmission facilities, and
options to ensure reliability are different for each design and mode of operation. Multiply that a
hundred fold to the different approaches there are to design, operate and to ensure reliability on the
local distribution system. Attempts at the federal level to design uniform standards to apply at lower
and lower levels of the system are doomed to failure given the nuances of each local system. These
attempts will only lead to needless complications and the actual undermining of the reliability on the
local distribution system. NERC staff comments seeking to sweep into NERC standards behind the
meter generation, meters and relays located deep within the distribution system, etc. and then insist
that the bulk system be contiguous is a phenomenal overreach and an intrusion on the design and
functioning of the distribution system which will a) complicate efforts to maintain a reliable
distribution system; and 2) will needlessly incur costs on ratepayers. NERC needs to stay focused on
the authorities extended to it in the FPA. Leave it to the regions to interface locally with utilities, state
authorities and other stakeholders to shape seamless reliability protocols that will benefit us all. The
question asks if there are orders that relate to this effort. In 1997, the New York Public Service
Commission held a proceeding Case No. 97-E-0251 that supplemented the FERC Seven Factor Test
with three additional factors to be used in New York to distinguish between transmission and local
distribution. This order can be found at the following link:
http://documents.dps.state.ny.us/public/Common/ViewDoc.aspx?DocRefId={3C7602E0-62E0-483182B6-8C34A72934F4}
Group
New York State Reliability Council
Roger Clayton
No
HVDC and VFT technologies are not addressed specifically. Consideration should be given to
expanding the core BES definition to clarify that it includes all AC and DC system Element(s).
Yes
No
The use of a 20 MVA threshold based on NERC's Registry Criteria may be administratively convenient
but is arbitrary when based upon BES reliability considerations. Suggest use of a 300 MW or other
regionally and technically acceptable threshold such as NPCC's A-10 criterion.
No
The use of a 75 MVA threshold based on NERC's Registry Criteria may be administratively convenient
but is arbitrary when based upon BES reliability considerations. Suggest use of a 300 MW or other
regionally and technically acceptable threshold such as NPCC's A-10 criterion.
Yes
BS facilities and their cranking paths are critical to the maintenance of system reliability under system
restoration conditions. However, they are a special case and should not be construed as a precedent
for inclusion of all BES contiguous elements.
No
Distributed resources are comprised of multiple small units that cycle on and off depending upon local
ambient conditions. They have multiple feeders collecting at the point of interconnection. It is not
credible that simultaneous loss of multiple units and/or collector system feeders could occur and they

should be excluded from the BES based upon reliability considerations. It is noted that system
Element(s) beyond the point of interconnection are subject to BES inclusion per the core definition.
No
E1 too prescriptive. Suggest developing a general, flexible definition of radial system in NERC
Glossary such as "A system connected from a single Transmission source originating with an
automatic interruption device".
Yes

Individual
Bob Thomas
Illinois Municipal Electric Agency
Yes
With the following clarifying edits. The BES definition should refer to “non-generator Reactive Power
resources,” to clarify that although all generators provide some reactive power, the generators that
do not meet the criteria of I2 through I5 are not included in the BES.
Yes
With the following clarifying edits. “Transformers, including phase angle regulators, and not including
generator step-up (GSU) transformers, with two windings of 100 kV or higher unless excluded under
Exclusion E1 or E3.”
Yes
Please see comments under Question 13.
Yes
Please see comments under Question 13.
Yes
Please see comments under Question 13.
Yes
Please see comments under Question 13.
Yes
With the following clarifying edits. Delete the words “described as” in the first sentence. Also, “a
single Transmission source” should be defined to encompass various bus configurations. For example,
an individual breaker position in a ring bus is not a single Transmission source, but a bus at one
voltage level at one substation should be considered a single Transmission source. Also, the phrase
“automatic interrupting device” should be replaced with the phrase “switching device”. The current
wording does not take into account that a radial system is often connected to a ring bus or a breakerand-a-half scheme where the breaker/automatic interrupting device is within the bus arrangement.
The appropriate division between BES and non-BES is at the disconnect switch where the radial line
attaches to the bus arrangement.
Yes
Please see comments under Question 13.
Yes
With the following clarfying edits. “Local Distribution Networks (LDN): Groups of Elements operated
above 100 kV that are primarily intended to distribute power to Load rather than to transfer bulk
power across the Interconnected System.” The second sentence should be revised as follows: “LDN’s
are connected to the Bulk Electric System (BES) from more than one Transmission source solely to
improve the level of service to retail customer Load.”
Yes

With the following clarifying edits. The final sentence should be revised as follows: “For purposes of
this exclusion, a ‘small utility’ is an entity that performs a distribution provider or load serving entity
function but is not required to register as a Distribution Provider or Load Serving Entity by the ERO.”
Yes
Please see comments under Question 13.
No
Being a Joint Action Agency and Joint Registration Organization representing small municipal utility
interests, IMEA appreciates this initiative to better define electric systems that should and should not
be considered part of the Bulk Electric System. In addition to those comments provided above, IMEA
supports comments addressing other concerns as submitted by the Transmission Access Policy Study
Group and the Small Entity Working Group.
Individual
Kim Wissman
Public Utilities Commission of Ohio
No
FERC jurisdiction is limited by the Federal Power Act, Section 215. To make a bright line designation
as the starting point, without a demonstration that ALL facilities at 100 kV and greater affect the
reliability of the bulk power system is a step beyond FERC jurisdictional boundaries. The Federal
Power Act explicitly excludes facilities used in local distribution from the bulk power system. NERC
should give serious consideration to other (non bright-line) approaches to ensure bulk system
reliability.
No
FERC jurisdiction is limited by the Federal Power Act, Section 215. To make a bright line designation
as the starting point, without a demonstration that ALL facilities at 100 kV and greater affect the
reliability of the bulk power system is a step beyond FERC jurisdictional boundaries. The Federal
Power Act explicitly excludes facilities used in local distribution from the bulk power system. NERC
should give serious consideration to other (non bright-line) approaches to ensure bulk system
reliability.
No
The inclusion of individual generating units between 20 MVA and 75 MVA nameplate capacity is
inappropriate and over-reaching. Inclusion I3 sets the aggregate threshold at 75 MVA for multiple
generating units. Technical justification for assuming a 20 MVA generating facility could cause
instability, uncontrolled separation, or cascading events on the bulk system appears to be lacking.
This appears to simply be based on that fact the NERC used it in a separate framework, which has no
basis. Inclusion I2 should be removed. Regarding the contiguous standard - simply because an
element is connected to the BES does not make it a part of the BES. By the very nature, a radial or
distribution element should pose limited or no impact on the BES. They are easily isolated from the
rest of the system. This contiguous measurement could impose standards unnecessarily on systems
with no ultimate impact on the bulk system, thereby enabling far-reaching authority into the
distribution system.
No
This should be expanded to also refer to individual generation capacity, as well as aggregate, at 75
MVA and above.
No
this should be determined by an impact analysis, not inclusive of all Blackstart Resources, regardless
of location on the system.
None
Yes
Exclusion E1 is appropriate. However, any inclusion that are inconsistent with this exclusion should be
eliminated. Any facility that has an impact on the bulk system could be considered for inclusion under
a case by case basis.
Yes

Exclusion E2 is appropriate. Same as 7.
Yes
Exclusion 3 is appropriate. This reflects the reality that local distribution can be at any level. As a
reminder the Commission proposed seven indicators of local distribution to be evaluated on a caseby-case basis: (1) Local distribution facilities are normally in close proximity to retail customers. (2)
Local distribution facilities are primarily radial in character. (3) Power flows into local distribution
systems; it rarely, if ever, flows out. (4) When power enters a local distribution system, it is not
reconsigned or transported on to some other market. (5) Power entering a local distribution system is
consumed in a comparatively restricted geographical area. (6) Meters are based at the
transmission/local distribution interface to measure flows into the local distribution system. (7) Local
distribution systems will be of reduced voltage. This test clearly indicates that not all radial circuit
lines are the same. This exclusion would not only appropriately apply the seven factor test, but also
comply with the Federal Power Act regarding appropriate authority.
Yes
It appears this could be applied consistently with other exclusions.
No
While it appears there was an attempt to draft the standard to comply with the Federal Power Act, the
issues outlined throughout the questions above raise concerns that local distribution could easily get
captured in NERC and FERC reliability standards needlessly and inappropriately.
Yes
See concerns above with exceeding authority under the Federal Power Act Section 215. State Utility
Commissions are charged with assuring safe, reliable service to their customers. We are in a much
better situated position than FERC or NERC to provide any necessary regulation and oversight of the
local distribution system.
No
Group
Dominion
Louis Slade
No
Dominion believes the core BES definition should include any non-radial Element or Facility operated
at 100 Kv or higher and should exclude any radial Element or Facility (regardless of operating
voltage) as well as non-radial Element or Facility operated below 100 kV. The core definition should
also include defined criteria that are applied to an Element or Facility to determine whether or not it
meets the intent of the Section 215 of Federal Power which defines the bulk power system as (1)
facilities and control systems necessary for operating an interconnected electric energy transmission
network; and (2) electric energy from generation facilities needed to maintain transmission system
reliability. (3) However, Section 215 excludes facilities used in the local distribution of electric energy
From the definition of the bulk power system . An Element or Facility should be included where the
Element or Facility is necessary for operating an interconnected electric energy transmission network
or is needed to maintain transmission system reliability. Likewise an Element or Facility should be
excluded where the Element or Facility is not necessary for operating an interconnected electric
energy transmission network or is needed to maintain transmission system reliability. Dominion
agrees that the BES definition should exclude local distribution facilities under state jurisdiction. In
specific instances (including UFLS programs and transmission protection systems that are
implemented on distribution elements or radial transmission) local distribution facilities can be
included in approved NERC reliability standards following under explicit standards dedicated to their
explicit mission without their automatic inclusion in a definition of BES that could infringe on state
jurisdiction. Dominion is also concerned at how complicated these lists of inclusions and exclusions
has become! Dominion had implemented the 100 kV threshold, as displayed in prior drafts of this
bright line test (without all these distractions provided in this BES definition version). With the
complexity of inclusion and exclusion criteria now provided in this draft, Dominion is not sure it can
replicate the list of facilities that are now qualified for inclusion in the BES as seen through the eyes of
different auditors and this will expose Dominion to undesirable disputes down the road on what
should have been included or excluded.
No

While Dominion appreciates the SDT’s attempt to respond to initial comments, unfortunately the
response does not squarely address Dominion’s concerns. Rather, the SDT proposes that all
transformers, whether for transmission or generation should be included. The SDT’s response to SERC
also seems to indicate that the facility associated with generators should be included in the BES. In
order to provide clarity Dominion restates its comment. Dominion’s position is that all transformers
with two windings at 100 kV or higher should be included in the BES. Dominion does not agree that a
transformer with two windings at 100 kV or higher should be excluded merely because it is a
generator step up (GSU). And, while Dominion does not agree that a generation resource, Element or
Facility should automatically be classified as part of the BES, if the SDT decides to do so, then it is
Dominion’s position that the GSU should also be included in the BES. It doesn’t seem to make sense
to include the generator itself, but exclude an associated element that is operated at 100 kV or above.
If the SDT’s intent was to ‘carve out’ GSUs in Inclusion -I1, but to include GSUs in Inclusion I2 and 3,
then Dominion suggests revising the phrase “….including the generator terminals through the GSU….”
to read “….including the generator terminals and the GSU.”
No
As stated in its response to Question 2 above, Dominion disagrees that a generation resource,
Element or Facility should automatically be included in the BES. Dominion agrees that the Generator
Owner and Generator Operator, as users of the bulk power system, should have to abide by
applicable reliability standards, but do not agree that this should automatically require the inclusion of
a generation resource, Element or Facility in the BES. Further, Dominion prefers that the SDT use the
term “generation resources” as stated in the current BES definition contained in the Glossary of Terms
instead of the proposed term “generating unit”.
No
As stated in its response to Question 2 above, Dominion disagrees that a generation resource,
Element or Facility should automatically be included in the BES. Dominion agrees that the Generator
Owner and Generator Operator, as users of the bulk power system, should have to abide by
applicable reliability standards, but do not agree that this should automatically require the inclusion of
a generation resource, Element or Facility in the BES. Further, Dominion prefers that the SDT use the
term “generation resources” as stated in the current BES definition contained in the Glossary of
Terms, instead of the proposed term “generation unit”
No
Dominion continues to disagree that a generation resource, Element or Facility should automatically
be included in the BES. Dominion agrees that the Generator Owner and Generator Operator, as users
of the bulk power system, should have to abide by applicable reliability standards, but do not agree
that this should automatically require the inclusion of a generation resource, Element or Facility in the
BES.
No
Dominion disagrees that an Element or Facility operated below 100 kV should be included
automatically in the BES. Dominion agrees that users of the bulk power system should be required to
abide by applicable reliability standards. Dominion questions why the SDT chose to use the phrase
‘Dispersed power producing resources’ As opposed to the phrase ‘Dispersed generating resources’.
Dominion asks that the SDT provide an explanation for its choice of phrases.
No
Dominion can agree with Exclusion E1 only if the exclusion is applied to any radial Facility, regardless
of whether it is used to connect load or generation to the bulk power system.
Yes
Dominion agrees with Exclusion E2 because we agree that specific criteria can be applied and will
indicate the Element or Facility is not necessary for operating an interconnected electric energy
transmission network or is needed to maintain transmission system reliability. . However Dominion
suggests that the SDT add a defined interval of time for measurement of net capacity so that planners
can be assured that the exclusion should really be applied at the location. Dominion suggests use of
an hour as the time increment.
No
An Element or Facility should only be excluded where the Element or Facility is not necessary for
operating an interconnected electric energy transmission network or is needed to maintain

transmission system reliability.
No
It is Dominion’s position that, all things being equal a generator or a load have similar, but typically
inverse impacts of the bulk power system. The burden for small entities is similar, whether that entity
is a LSE, DP, GO or GOP.
No
Dominion believes the core BES definition should include any non-radial Element or Facility operated
at 100 Kv or higher and should exclude any radial Element or Facility (regardless of operating
voltage) as well as non-radial Element or Facility operated below 100 kV. The core definition should
also include defined criteria that are applied to an Element or Facility to determine whether or not it
meets the intent of the Section 215 of Federal Power Act Section 215 defines the bulk power system
as (1) facilities and control systems necessary for operating an interconnected electric energy
transmission network; and (2) electric energy from generation facilities needed to maintain
transmission system reliability. (3) However, Section 215 excludes facilities used in the local
distribution of electric energy From the definition of the bulk power system. An Element or Facility
should be included where the Element or Facility is necessary for operating an interconnected electric
energy transmission network or is needed to maintain transmission system reliability. Likewise an
Element or Facility should be excluded where the Element or Facility is not necessary for operating an
interconnected electric energy transmission network or is needed to maintain transmission system
reliability. Dominion agrees that the BES definition should exclude local distribution facilities under
state jurisdiction. In specific instances (including UFLS programs and transmission protection systems
that are implemented on distribution elements or radial transmission) local distribution facilities can
be included in approved NERC reliability standards following under explicit standards dedicated to
their explicit mission without their automatic inclusion in a definition of BES that could infringe on
state jurisdiction.
Yes
The inclusion of an element or facility that is not integral to the reliable operation of the integrated
bulk power system is in conflict with the intent of Section 215 of the FPA . This is especially true for
radial facilities, whether used to connect generators or load to the bulk power system.
Does the SDT assert that there is no reliability gap because the impact of load on the BES is covered
because the DP and LSE are registered and therefore must comply with applicable reliability
standards? If so, why shouldn’t the same apply to generation elements? GO and GOPs, just like DPs
and LSEs are registered users of the bulk power system and must adhere to applicable reliability
standards. Other comments Dominion also has the following comments which are based, to a large
degree upon the webinar of May 19th. Dominion is concerned that while the BES definition is going
through the standards development process, where stakeholders have the ability to ballot, the
exception process is being treated as a change to the Rules of Procedure, with no associated
stakeholder ballot. For this reason, Dominion prefers that the exception criteria itself be part of the
BES definition standards development process. As Dominion reviews the Inclusions and Exclusions
included by the SDT in the BES definition, we believe that the SDT could just have easily developed
criteria to determine whether impact on the BES is material. We believe this would negate the need
for the exception process proposed for the Rules of Procedure. However, if this course is not chosen,
then Dominion requests the NERC BOT apply these changes in an ‘all or none’ fashion. That is, the
BES definition and the exception process should both require NERC BOT approval or neither should be
moved to FERC for its approval. We are confused as to how the definition, in particular the Inclusions
and Exclusions, and the exception process are meant to be applied to, or by, the registered entity. We
thought we heard differing views from the panel; one stating that, if the Element or Facility met the
Inclusion or Exclusion in the BES definition, then an exception request submittal is not required. On
the other hand, we thought we heard that, unless an exception request submittal had been approved
then ‘status quo’ applies. What is ‘status quo’ based on, the current BES definition or the BES
definition being proposed? Would an entity need to track the effective date of the BES definition
change in order to determine ‘status quo’? How will submittal or non-submittal of an exception
request by the registered entity be applied for compliance purposes? Dominion believes the correct
answer is that and Element or Facility that meets the BES definition is included and if it doesn’t meet
the BES definition, isn’t included. Only when an exception request has been submitted by an entity,
approved and any appeal resolved, is inclusion or exclusion based on the impact to the bulk power
system as determined by the criteria used in the exception process.

Group
SPP Standards Review Group
Robert Rhodes
No
A reference needs to be made to the ROP changes which also provide a mechanism whereby Elements
may be excluded/included in the BES. Without that reference the proposed definition does not
completely include all means for exceptions/inclusions. We would suggest the definition be expanded
to say ‘…modified by the list shown below or as provided by Appendix 5C of the NERC Rules of
Procedure.’
Yes
No
With the inclusion of a voltage criteria in the definition an inconsistency is created between Elements
that are not a part of the BES but are still required to be part of the NERC Compliance Registry. Does
this create an issue? Did the SDT intend to create this inconsistency? A large generating unit or group
of units that are connected to the interconnection via 69kV does not qualify as a part of the BES.
Although the generation level could be substantial, it is still not a part of the BES. If said generation is
20 MVA or 75 MVA, respectively, it would have to be registered in the Compliance Registry. While an
entity may be able to petition to include such a facility in the BES, what is the incentive to do so? This
seems to detract from the ‘bright line’ definition.
No
The comment provided for Question 3 above applies here also.
No
While we understand the necessity of including the Cranking Path in the BES, we are equally
concerned about the broad usage of the term BES throughout the NERC Reliability Standards and the
ramifications of extending the requirements associated with those standards to parts of the
distribution system that do not have a logical association with the BES. For example, some of the TPL
standards require studies of the BES. Does this then mean those studies would apply to those
Cranking Paths on the distribution system? We think Cranking Paths that include portions of the
distribution system should be excluded from the BES definition. Could the SDT please provide us with
an explanation of why these Elements would be included in the BES and what would be gained if they
were included? We’d also like to ask the SDT to identify the standards and requirements that would
be applied to the distribution system Cranking Paths. Is there any way that the significance of the
distribution Cranking Paths could be maintained without going as far as including them in the BES?
Also, if a Distribution Provider has a portion of his distribution system designated an Element of the
BES, as in the Cranking Path scenario, does that then require the DP to register as a TO or TOP?
No
Limiting this to 75 MVA does allow the opportunity for a significant amount of generation to ‘slip
under the fence’ regarding inclusion in the BES. Was this the intent of the SDT? For example, in order
to circumvent the BES issue a developer may decide to build 2-74 MVA sites rather than a single 148
MVA site. Regarding the similarity of the I3 and I5, what is the difference between a ‘single site’ and a
‘common point of interconnection’? Shouldn’t they be the same in the two inclusions?
No
We could concur with this exception providing the ‘automatic interruption device’ is not considered a
part of the BES. Additionally, what are the implications for a radial element connected in a ring bus
via two breakers or a radial element connected via a breaker and a half scheme?
No
We think we may concur with E2, but we are uncertain as to what is included in (ii). Could you please
clarify?
No
While the principle contained in (c) is valid, the explanation following it is too restrictive. This does not
allow the LDN to maintain any excess generation for contingencies and normal load fluctuations. In
(b) the implication is that the LDN is being treated like a single site in I3 whereby the total generation
capability is restricted to 75 MVA. Is this a valid assumption for municipals? In (e) permanent

flowgates may change from month to month, therefore an LDN could bounce into and back out of the
BES depending upon what happens regarding a specific facility which may be included as part of a
flowgate. This creates a very fluid situation which can lead to confusion.
No
What’s the difference between the proposed E4 and E1(a)? Wouldn’t they be the same? Would it be
more appropriate to use single point of Transmission interconnection rather than single Transmission
source in E1 and E4?
No
The inclusion of Cranking Paths into the BES without regard to voltage level has the potential to pull
distribution facilities into the BES. (See Question 5)
Yes
See our responses to Questions 5 and 11 regarding the issue of distribution facilities and Cranking
Paths.
No
Group
MRO's NERC Standards Review Forum
Carol Gerou
Yes
Please quantify that Reactive Resources within the BES definition are meant to be generator resources
and not static resources.
Yes
Please clarify that an exclusion would be a tertiary winding for example an auto transformer.
Yes
No
The wording “connected through a common bus” is drawn from the NERC Compliance Registry
Criteria. NSRF agrees with the language if the intent is to let entities classify the applicable multiple
generating units as part of the BES only when it is connected to one (common) bus. However, if the
intent is for entities to also classify multiple generation as part of the BES when it is connected
through two or more GSUs to different bus sections of a set of (common) buses that are
interconnected through bus-tie breakers [which may be done to provide improved reliability and
maintenance flexibility], then wording like “connected through a common bus or set of interconnected
buses” would be more appropriate. It is the NSRF’s understanding that entities do not have to classify
applicable multiple generating units as part of the BES when the aggregate MVA is connected to
different buses at different voltage levels and no more than 75 MVA is connected to any one bus (or
set of interconnected buses) at a single voltage level of 100 kV or more. Is this a correct
interpretation?
Yes
It does provide a defense in depth with CIP-002-4.
No
We propose the following questions for your consideration: Which components of the dispersed power
resources would be classified as BES? Are the individual small wind generator units and terminals
through the GSUs to a higher voltage (e.g. 34.5 kV) collector bus classified as BES Elements? Are the
higher voltage bus, the associated elements (e.g. protection system, cap bank, SVC, etc.), and step
up transformer to a system Element of 100 kV or above to be classified as BES Elements? With these
questions, the NSRF is confused on what the SDT is trying to formulate as an Inclusion. If a dispersed
power systems meets the threshold of 75MVA and connected at 100kV or higher, does this make the
entire dispersed system considered to be part of the BES? We recommended that one solution is that
I5 to be revised as follows “Dispersed power producing resources with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) utilizing a collector system from the point where the
aggregated rating exceeds 75 MVA through a common point of interconnection to a system Element
at a voltage of 100 kV or above. “
Yes

We recommend the phrase “originating with an automatic interruption device” be clarified as to the
location of the interruption device. An entity may not have interruption devices at both ends of a
radial fed line. If the interruption device is at the load end of the radial line, then the “up-stream”
portion of the radial line is unprotected. Please clarify. Please add the Brightline Criteria that all
facilities less than a 100kV are excluded unless those facilities meet the criteria of an Inclusion.
Yes
No
The SDT is defining what a Local Distribution Network is but the term transfer bulk power is
ambiguous. Please clarify what the intent of this exclusion is.
Yes
Yes
Yes
Within the Commission’s definition of BPS, it is clearly stated that BPS does not include facilities used
in the local distribution of electrical energy.
In order to provide a clear and concise definition, please add the Brightline Criteria that all facilities
less than a 100kV are excluded unless those facilities meet the criteria of an Inclusion.
Group
Transmission Access Policy Study Group
Cynthia S. Bogorad
Yes
TAPS appreciates the opportunity to comment on the draft BES definition. We generally support the
direction taken by the SDT, with some minor changes. TAPS suggests a few clarifying edits to the
core definition. First, the definition should refer to “non-generator Reactive Power resources,” to make
clear that although all generators provide some reactive power, those that do not meet the criteria of
I2-I5 are not included in the BES. There is ambiguity concerning whether a transformer stepping
down from >100 kV to <100 kV is included, though TAPS believes that the SDT intends to exclude
such transformers. It is clear that transformers with two windings >100 kV are included and GSUs for
registered generators are included, but it is somewhat unclear in the current draft whether a 138 kV
to 69 kV transformer is included or excluded. TAPS suggests making it clear that the intent of the SDT
is to include (a) GSUs associated with BES generators and (b) transformers with 2 or more windings
>100 kV, and that other transformers are excluded. We also believe the drafting team intended to
exclude all elements that are not included either under the BES definition and designations or through
the exception process. For the sake of clarity, we suggest that a sentence to that effect be added to
the core definition. Finally, we note that the definition does not currently refer to the existence of the
exception process. We suggest that such a reference be added either to the core definition (as in the
revised text suggested by TAPS in this response) or to the lists of Inclusions and Exclusions. The
following is the core definition incorporating the changes suggested by TAPS: All Transmission
Elements (except transformers) operated at 100 kV or higher, transformers as described below, Real
Power resources as described below, and non-generator Reactive Power resources connected at 100
kV or higher, unless such designation is modified by the list shown below. The NERC Rules of
Procedure [citation] provide an Exception Process through which Elements not included in the BES
under this definition and designations may be included in the BES, and Elements included in the BES
under this definition and designations may be excluded from the BES. Elements not included in the
BES either by application of this definition and designations, or through the BES exception process,
are not BES Elements.
Yes
To minimize possible confusion as to the category of transformers being addressed in I1, and the
sufficiency of a single applicable Exclusion, TAPS suggests the following rewording: “Transformers,
including phase angle regulators, and not including generator step-up (GSU) transformers, with two
windings of 100 kV or higher unless excluded under Exclusion E1 or E3.”
Yes

TAPS understands that the intent is to define the BES component of qualifying generators as that
equipment from the generator terminals through the GSU. To convey clearly this point, as well as that
only generators that are both over 20 MVA and connected through a GSU with a high side voltage of
at least 100 kV are included in the BES, I2 should be reworded as follows: “Individual generating
units greater than 20 MVA (gross nameplate rating), connected through a GSU with a high-side
voltage of 100 kV or above. A BES generator includes the equipment from the generator terminals
through the GSU.”
Yes
I3 contains language similar to I2, and should be similarly reworded, as follows: “Multiple generating
units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating), connected through a common bus operated at a voltage of 100 kV or above. A
BES generating plant includes the equipment from the generator terminals through the respective
GSUs.”
Yes
TAPS agrees with the concept of Inclusion I5 but suggests a language change to clarify what we
understand to be the drafting team’s intent, that the inclusion is intended to apply to dispersed wind
and solar generating plants, and not, for example, to a radially-connected city with an aggregate of
75 MW of small generators behind-the-meter. This distinction is appropriate because such a city
cannot have the same impact on the grid as a 75 MW wind farm; loss of the radial connecting the city
to the grid would result in loss of its load as well as its generation, so that the supply-demand
mismatch would be far less significant. TAPS thus suggests that I5 be revised to read: I5 Wind farm
or solar power installation with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating) utilizing a collector system through a common point of interconnection to a system Element at
a voltage of 100 kV or above.
Yes
TAPS suggests some clarifying changes: The words “described as” should be deleted from the
exclusion to avoid confusion. What matters is how the system is actually connected, not how
someone describes it. In addition, “a single Transmission source” should be defined, and should be
generic enough to encompass the various bus configurations. It is not the case, for example, that
each individual breaker position in a ring bus is a separate Transmission source; in that case, a bus at
one voltage level at one substation should be considered “a single transmission source.” Some
examples of configurations that should be considered a single transmission source for this purpose
are at https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples
1-6. The phrase “automatic interrupting device” should be replaced with the phrase “switching
device.” Many radials are connected to ring buses or breaker-and-a-half schemes where the breakers
(automatic interrupting devices) are within the bus arrangement where the appropriate division
between BES and non-BES is at the disconnect switch as the radial “takes off” from the bus
arrangement.
Yes
We understand that E2 is intended to apply only to retail customers’ generation. The exclusion should
therefore be revised to make that limitation clear. Specifically, the first sentence should read: “A
generating unit or multiple generating units that serve all or part of retail customer Load with electric
energy on the retail customer’s side of the retail meter.”
Yes
The exclusion refers to groups of Elements that “distribute power to Load rather than transfer bulk
power across the interconnected system.” The use of the term “bulk power” is vague and could be
read incorrectly as a reference to the “bulk-power system,” which is defined in the Federal Power Act
but is not a NERC defined term. If the LDN is connected to the BES at more than one location, there
will by definition be some loop flow. We recommend below that Exclusion 3(d) be revised to quantify
the amount of loop flow that is permissible in an excluded LDN. In the context of the first sentence of
Exclusion E3, less specificity is needed, and the sentence should only be revised for the sake of
accuracy to state: “Groups of Elements operated above 100 kV that are primarily intended to
distribute power to load rather than to transfer power across the interconnected System.” The
exclusion’s reference to connection “at more than one location” is vague. The sentence should be
revised to read “connected to the Bulk Electric System (BES) from more than one Transmission

source solely to improve the level of service to retail customer Load,” and “Transmission source”
should have the same meaning that it does in E1. E3(a) should require that there be switching
devices between the LDN and the BES, not specifically automatic fault-interrupting devices. The term
“separable by” in “Separable by automatic fault interrupting devices” is unclear and should be
reworded. E3(b) To avoid pulling an LDN into the BES based on very small customer-owned
generation (such as rooftop photovoltaics and hospital backup diesel generators) that the utility does
not consider or rely on, or necessarily even know about, the item should be reworded: “Limits on
connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more
than 75 MVA of generation used to meet the resource-adequacy requirements of electric utilities.”
E3(d) states “Not used to transfer bulk power.” As noted above, “bulk power” is a vague term. There
will necessarily be some loop flow on a system that is connected to the BES at more than one
location. The amount of permissible loop flow for this purpose needs to be determined and stated in
this item.
Yes
TAPS supports this exclusion. For the sake of clarity, the final sentence should be revised to read as
follows: “For purposes of this exclusion, a “small utility” is an entity that performs a Distribution
Provider or Load Serving Entity function but is not required to register as a Distribution Provider or
Load Serving Entity by the ERO.”
Yes

Individual
Jeff Nelson
Springfield Utility Board
No
These comments are supplemental to Springfield Utility Board's comments provided to NERC on May
26, 2011 by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals
with the concept of "serving only load" and the classification of what types of generation are
incorporated into the definition of generation for purposes of BES inclusion or exclusion. SUB's
comment is that generation normally operated as backup generation for retail load is not counted as
generation for purposes of determining generation thresholds for inclusion or exclusion from the BES.
For purposes of BES inclusion or exclusion, a system with load and generation normally operated as
backup generation for retail load is considered "serving only load" when using generation normally
operated as backup generation for retail load (See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).
The rationalle is that backup generation for retail load is normally used during a localized outage and
for testing for reliability during a localized outage event. Including backup generation for retail load in
generation thresholds (e.g. 75MVA) would not reflect generation used for restoration or reliability of
the BES. Including backup generation for retail load in generation threshold calculations would cause
a inappropriate inclusion of elements and devices, accelerate the triggering of inclusion (and may
make exclusion provisions meaningless), and push more activity of excluding smaller systems from
the BES into the exception process.
Yes
These comments are supplemental to Springfield Utility Board's comments provided to NERC on May
26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment
deals with the concept of "serving only load" and the classification of what types of generation are
incorporated into the definition of generation for purposes of BES inclusion or exclusion. SUB's
comment is that generation normally operated as backup generation for retail load is not counted as
generation for purposes of determining generation thresholds for inclusion or exclusion from the BES.
For purposes of BES inclusion or exclusion, a system with load and generation normally operated as
backup generation for retail load is considered "serving only load" when using generation normally
operated as backup generation for retail load (See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).
The rationalle is that backup generation for retail load is normally used during a localized outage and
for testing for reliability during a localized outage event. Including backup generation for retail load in
generation thresholds (e.g. 75MVA) would not reflect generation used for restoration or reliability of

the BES. Including backup generation for retail load in generation threshold calculations would cause
a inappropriate inclusion of elements and devices, accelerate the triggering of inclusion (and may
make exclusion provisions meaningless), and push more activity of excluding smaller systems from
the BES into the exception process.
No
These comments are supplemental to Springfield Utility Board's comments provided to NERC on May
26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment
deals with the concept of "serving only load" and the classification of what types of generation are
incorporated into the definition of generation for purposes of BES inclusion or exclusion. SUB's
comment is that generation normally operated as backup generation for retail load is not counted as
generation for purposes of determining generation thresholds for inclusion or exclusion from the BES.
For purposes of BES inclusion or exclusion, a system with load and generation normally operated as
backup generation for retail load is considered "serving only load" when using generation normally
operated as backup generation for retail load (See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).
The rationalle is that backup generation for retail load is normally used during a localized outage and
for testing for reliability during a localized outage event. Including backup generation for retail load in
generation thresholds (e.g. 75MVA) would not reflect generation used for restoration or reliability of
the BES. Including backup generation for retail load in generation threshold calculations would cause
a inappropriate inclusion of elements and devices, accelerate the triggering of inclusion (and may
make exclusion provisions meaningless), and push more activity of excluding smaller systems from
the BES into the exception process.
No
These comments are supplemental to Springfield Utility Board's comments provided to NERC on May
26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment
deals with the concept of "serving only load" and the classification of what types of generation are
incorporated into the definition of generation for purposes of BES inclusion or exclusion. SUB's
comment is that generation normally operated as backup generation for retail load is not counted as
generation for purposes of determining generation thresholds for inclusion or exclusion from the BES.
For purposes of BES inclusion or exclusion, a system with load and generation normally operated as
backup generation for retail load is considered "serving only load" when using generation normally
operated as backup generation for retail load (See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).
The rationalle is that backup generation for retail load is normally used during a localized outage and
for testing for reliability during a localized outage event. Including backup generation for retail load in
generation thresholds (e.g. 75MVA) would not reflect generation used for restoration or reliability of
the BES. Including backup generation for retail load in generation threshold calculations would cause
a inappropriate inclusion of elements and devices, accelerate the triggering of inclusion (and may
make exclusion provisions meaningless), and push more activity of excluding smaller systems from
the BES into the exception process.
Yes
These comments are supplemental to Springfield Utility Board's comments provided to NERC on May
26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment
deals with the concept of "serving only load" and the classification of what types of generation are
incorporated into the definition of generation for purposes of BES inclusion or exclusion. SUB's
comment is that generation normally operated as backup generation for retail load is not counted as
generation for purposes of determining generation thresholds for inclusion or exclusion from the BES.
For purposes of BES inclusion or exclusion, a system with load and generation normally operated as
backup generation for retail load is considered "serving only load" when using generation normally
operated as backup generation for retail load (See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).
The rationalle is that backup generation for retail load is normally used during a localized outage and
for testing for reliability during a localized outage event. Including backup generation for retail load in
generation thresholds (e.g. 75MVA) would not reflect generation used for restoration or reliability of
the BES. Including backup generation for retail load in generation threshold calculations would cause
a inappropriate inclusion of elements and devices, accelerate the triggering of inclusion (and may
make exclusion provisions meaningless), and push more activity of excluding smaller systems from
the BES into the exception process.
No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May
26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment
deals with the concept of "serving only load" and the classification of what types of generation are
incorporated into the definition of generation for purposes of BES inclusion or exclusion. SUB's
comment is that generation normally operated as backup generation for retail load is not counted as
generation for purposes of determining generation thresholds for inclusion or exclusion from the BES.
For purposes of BES inclusion or exclusion, a system with load and generation normally operated as
backup generation for retail load is considered "serving only load" when using generation normally
operated as backup generation for retail load (See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).
The rationalle is that backup generation for retail load is normally used during a localized outage and
for testing for reliability during a localized outage event. Including backup generation for retail load in
generation thresholds (e.g. 75MVA) would not reflect generation used for restoration or reliability of
the BES. Including backup generation for retail load in generation threshold calculations would cause
a inappropriate inclusion of elements and devices, accelerate the triggering of inclusion (and may
make exclusion provisions meaningless), and push more activity of excluding smaller systems from
the BES into the exception process.
No
These comments are supplemental to Springfield Utility Board's comments provided to NERC on May
26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment
deals with the concept of "serving only load" and the classification of what types of generation are
incorporated into the definition of generation for purposes of BES inclusion or exclusion. SUB's
comment is that generation normally operated as backup generation for retail load is not counted as
generation for purposes of determining generation thresholds for inclusion or exclusion from the BES.
For purposes of BES inclusion or exclusion, a system with load and generation normally operated as
backup generation for retail load is considered "serving only load" when using generation normally
operated as backup generation for retail load (See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).
The rationalle is that backup generation for retail load is normally used during a localized outage and
for testing for reliability during a localized outage event. Including backup generation for retail load in
generation thresholds (e.g. 75MVA) would not reflect generation used for restoration or reliability of
the BES. Including backup generation for retail load in generation threshold calculations would cause
a inappropriate inclusion of elements and devices, accelerate the triggering of inclusion (and may
make exclusion provisions meaningless), and push more activity of excluding smaller systems from
the BES into the exception process.
No
These comments are supplemental to Springfield Utility Board's comments provided to NERC on May
26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment
deals with the concept of "serving only load" and the classification of what types of generation are
incorporated into the definition of generation for purposes of BES inclusion or exclusion. SUB's
comment is that generation normally operated as backup generation for retail load is not counted as
generation for purposes of determining generation thresholds for inclusion or exclusion from the BES.
For purposes of BES inclusion or exclusion, a system with load and generation normally operated as
backup generation for retail load is considered "serving only load" when using generation normally
operated as backup generation for retail load (See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).
The rationalle is that backup generation for retail load is normally used during a localized outage and
for testing for reliability during a localized outage event. Including backup generation for retail load in
generation thresholds (e.g. 75MVA) would not reflect generation used for restoration or reliability of
the BES. Including backup generation for retail load in generation threshold calculations would cause
a inappropriate inclusion of elements and devices, accelerate the triggering of inclusion (and may
make exclusion provisions meaningless), and push more activity of excluding smaller systems from
the BES into the exception process.
No
These comments are supplemental to Springfield Utility Board's comments provided to NERC on May
26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment
deals with the concept of "serving only load" and the classification of what types of generation are
incorporated into the definition of generation for purposes of BES inclusion or exclusion. SUB's
comment is that generation normally operated as backup generation for retail load is not counted as
generation for purposes of determining generation thresholds for inclusion or exclusion from the BES.

For purposes of BES inclusion or exclusion, a system with load and generation normally operated as
backup generation for retail load is considered "serving only load" when using generation normally
operated as backup generation for retail load (See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).
The rationalle is that backup generation for retail load is normally used during a localized outage and
for testing for reliability during a localized outage event. Including backup generation for retail load in
generation thresholds (e.g. 75MVA) would not reflect generation used for restoration or reliability of
the BES. Including backup generation for retail load in generation threshold calculations would cause
a inappropriate inclusion of elements and devices, accelerate the triggering of inclusion (and may
make exclusion provisions meaningless), and push more activity of excluding smaller systems from
the BES into the exception process.
Yes
These comments are supplemental to Springfield Utility Board's comments provided to NERC on May
26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment
deals with the concept of "serving only load" and the classification of what types of generation are
incorporated into the definition of generation for purposes of BES inclusion or exclusion. SUB's
comment is that generation normally operated as backup generation for retail load is not counted as
generation for purposes of determining generation thresholds for inclusion or exclusion from the BES.
For purposes of BES inclusion or exclusion, a system with load and generation normally operated as
backup generation for retail load is considered "serving only load" when using generation normally
operated as backup generation for retail load (See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).
The rationalle is that backup generation for retail load is normally used during a localized outage and
for testing for reliability during a localized outage event. Including backup generation for retail load in
generation thresholds (e.g. 75MVA) would not reflect generation used for restoration or reliability of
the BES. Including backup generation for retail load in generation threshold calculations would cause
a inappropriate inclusion of elements and devices, accelerate the triggering of inclusion (and may
make exclusion provisions meaningless), and push more activity of excluding smaller systems from
the BES into the exception process.
No
These comments are supplemental to Springfield Utility Board's comments provided to NERC on May
26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment
deals with the concept of "serving only load" and the classification of what types of generation are
incorporated into the definition of generation for purposes of BES inclusion or exclusion. SUB's
comment is that generation normally operated as backup generation for retail load is not counted as
generation for purposes of determining generation thresholds for inclusion or exclusion from the BES.
For purposes of BES inclusion or exclusion, a system with load and generation normally operated as
backup generation for retail load is considered "serving only load" when using generation normally
operated as backup generation for retail load (See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).
The rationalle is that backup generation for retail load is normally used during a localized outage and
for testing for reliability during a localized outage event. Including backup generation for retail load in
generation thresholds (e.g. 75MVA) would not reflect generation used for restoration or reliability of
the BES. Including backup generation for retail load in generation threshold calculations would cause
a inappropriate inclusion of elements and devices, accelerate the triggering of inclusion (and may
make exclusion provisions meaningless), and push more activity of excluding smaller systems from
the BES into the exception process.
Yes
See SUB's May 26 Comments filed by Tracy Richardson
These comments are supplemental to Springfield Utility Board's comments provided to NERC on May
26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment
deals with the concept of "serving only load" and the classification of what types of generation are
incorporated into the definition of generation for purposes of BES inclusion or exclusion. SUB's
comment is that generation normally operated as backup generation for retail load is not counted as
generation for purposes of determining generation thresholds for inclusion or exclusion from the BES.
For purposes of BES inclusion or exclusion, a system with load and generation normally operated as
backup generation for retail load is considered "serving only load" when using generation normally
operated as backup generation for retail load (See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).
The rationalle is that backup generation for retail load is normally used during a localized outage and
for testing for reliability during a localized outage event. Including backup generation for retail load in

generation thresholds (e.g. 75MVA) would not reflect generation used for restoration or reliability of
the BES. Including backup generation for retail load in generation threshold calculations would cause
a inappropriate inclusion of elements and devices, accelerate the triggering of inclusion (and may
make exclusion provisions meaningless), and push more activity of excluding smaller systems from
the BES into the exception process.
Individual
David Angell
Idaho Power
Yes
Yes
I generally agree but the definition accidently excludes autotransformers. It should be restated as
transformers with two terminal at or above 100 kV. Also, there should be clarification about any
tertiary windings that a transformer might have. I would assume that the tertiary winding and any
real or reactive load or generation connected to it to be excluded as the tertiary winding are typically
of distribution class voltage. Finally, there is no need to exclude GSUs in this definition because they
will be excluded unless the two terminals are at 100 kV or above. Additionally, the GSUs will be
covered by other inclusion statements related to generators.
No
Generators at 20 MVA are not material to the BES. I would recommend combining I2, I3, and I5 with
the limit at 75 MVA for plant nameplate capability regardless of the number of generators and type of
generators.
Yes
Generally agreed but please revise to inlcude I2, I3 and I5 at 75 MVA, see Question 3 and 6
comments.
Yes
Yes
Generally agreed but please revise to one Inclusion for I2, I3 and I5 at 75 MVA, see Question 3 and 4
comments.
Yes
Generally agreed assuming that the make-before-break may be performed manually.
Yes
Yes
No
As written, it is unclear how this exclusion differs from the Radial exclusion. The term “single
Transmission source” needs to be clarified – it could be read to be a single line or a single entity,
which would change the meaning of this exclusion. It is also improper to include registration criteria in
a definition. Furthermore, “small utility” needs to be defined more clearly. The last sentence appears
circular because ownership of a transmission element would draw the owner into registration.
Yes
No

Group
New York Power Authority
Randy D. Crissman
Yes

The New York Power Authority (NYPA) supports the Standards Drafting Team’s development of a
revised Bulk Electric System (BES) definition in response to FERC Order 743 that is directly linked to
an exception process for inclusions and exclusions. The definition must be closely coupled to the
exception process and the two must be integrated in the standard that is ultimately adopted. This will
ensure that the regulatory requirements apply to only those facilities that materially affect the
reliability of the BES. In general, NYPA agrees with the proposed definition and the objectives the
Standards Drafting Team has established. NYPA recommends that the team make additional
clarifications to provide industry with a better understanding of the inclusions and exclusions, as well
as the impact of the inclusions/exclusions on the BES. The definition should exclude generator leads
for generating units that do not materially affect the reliability of the BES regardless of the BES
designation of the generating unit. In addition, the definition should not require the inclusion of
contiguous elements. Generating units that are designated BES are currently required to comply with
a subset of NERC Reliability Standards, but may not be material to the reliable operation of the
interconnected BES. This portion of the definition should not require that both BES and non-BES
generating units have their generator leads defined as BES transmission elements. A length-based
criterion for generator leads ought to be considered. For example, the definition should exclude
generator leads that are one mile or less between BES elements. The Standards Drafting Team should
engage and coordinate with the Standards Drafting Team for Project 2010-07 (the GO/TO task force).
This coordination is needed to determine the impacts of the new BES definition on Transmission
Owner (TO) and Transmission Operator (TOP) registration. In addition, NYPA recommends that the
Standards Drafting Team and the GO/TO Task Force consider, if they have not already done so, the
impacts of ownership and operating agreements on registration. For example, clarification of
registration impacts for BES elements that are jointly owned by two utilities (e. g. where one utility
owns 5 of 20 towers and the other utility owns the remaining towers and the conductor of a
transmission line) is required. The definition does not provide clarity on the state of the system
conditions (normal or emergency) that should be applied. The definition should apply to only normal
operating conditions.
Yes
Yes
The definition should exclude generator leads for generating units that do not materially affect the
reliability of the BES regardless of the BES designation of the generating unit. In addition, the
definition should not require the inclusion of contiguous elements. Generating units that are
designated BES are currently required to comply with a subset of NERC Reliability Standards, but may
not be material to the reliable operation of the interconnected BES. This portion of the definition
should not require that both BES and non-BES generating units have their generator leads defined as
BES transmission elements. A length-based criterion for generator leads ought to be considered. For
example, the definition should exclude generator leads that are one mile or less between BES
elements. This comment has been raised in Question number 1 as well.
Yes
No
The Standards Drafting Team needs to clarify whether this inclusion is intended to apply to local
transmission operator restoration plans or only to the Balancing Authority’s restoration plans. This
inclusion should be stated as follows: Blackstart Resources and the designated cranking paths
identified in the Balancing Authority’s Restoration Plan regardless of voltage.” Local restoration plans
may not be material to the restoration and operation of the BES, but black start resources for the
Balancing Authority’s restoration plan are material to the reliable restoration of the BES.
Yes
This inclusion should be specific to the type of generation that the team envisioned it to capture (e.g.
wind and solar). Since the term “dispersed power producing resources” can be interpreted to include
generation resources from a few KW up to 50 MW, this inclusion can be misinterpreted to include
“peaker GT’s”, fuel cells and microturbines, etc.
No
The definition of Exclusion E1 does not cover radial systems that are connected to a single
transmission source by more than one automatic interruption device, such as occurs with a ”breaker-

and-a-half” arrangement. The definition should be modified as follows: “Any radial system which is
described as connected from a single Transmission source originating with one or more automatic
interruption devices and: ….” This exclusion uses many terms that are not defined under NERC’s
standard definitions: “radial load”, “automatic interruption device” and “make–before-break”. If these
terms are used to define an exclusion and can be understood or interpreted differently by different
people, then the terms should be formally defined.
Yes
Yes
Yes
Yes
No
General comments are listed under Question 1.
Group
SERC Planning Standards Subcommittee
Charles W. Long
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
While we agree with the first part of E2, but we do not see the rationale for section (ii) and suggest it
be deleted.
No
This seems to be covered by E1.
Yes
No
The comments expressed herein represent a consensus of the views of the above-named members of
the SERC EC Planning Standards Subcommittee only and should not be construed as the position of
SERC Reliability Corporation, its board, or its officers.
Individual
Robert Ganley
Long Island Power Authority

Yes
Yes
For clarification it is recommended that “windings” be replaced with “connection points”.
Yes
Yes
We recommend clarifying that I3 only covers units under 20 MVA and that the aggregation similarly
just applies to those units that are under 20MVA. Example: a 100 MVA generating unit and a 15 MVA
generating unit at a single site only the 100 MVA generating unit would be BES per Inclusion I2 but
Inclusion I3 would not apply.
Yes
Need to define Cranking Paths.
Yes
Yes
For clarification purposes, we understand “Transmission source” to be a substation and not a line. A
substation connected to only one other substation “source” by two lines would still be considered
radial and thus excluded.
Yes
No
Revise last two sentences in the introductory paragraph to read as follows: “LDN’s are connected to
the bulk electric system (BES) at several points and are characterized by all of the following:”; This
removes ambiguity that exists in the deleted portion of the text. See also response to question 11
regarding Exclusion E3-b.
Yes
No
We don’t believe the bright-line definition and specific inclusions and exclusions prevents distribution
from being considered as BES. It seems like the intent to exclude non bulk distribution systems would
still be included because of E3b. We don’t believe that the SDT has fully excluded local distribution
facilities as required by the FERC Order. Specifically E3b should be eliminated. The other remaining
items a,c,d,e adequately define the LDN.
No
The SDT should clarify that Local Distribution Networks, including any facilities that are within the
LDN, are not subject to Reliability Standard Requirements pursuant to Section 215 of the Federal
Power Act.
Group
Michigan Public Service Commission(MPSC)
Don Mazuchowski
No
MPSC Staff Comments: The BES definition proposed by the SDT should not use the term
“transmission”, if that term is defined as facilities that are at 100 kV or above. Not all facilities at 100
kV or above are properly considered transmission facilities. Use of “transmission” is causing
unnecessary uncertainty and much debate among NERC stakeholders in the standards development
and outreach processes over potential effects on jurisdiction, ownership, and possible new NERC
registration requirements. This is especially true in states such as Michigan where Michigan Public
Service Commission-regulated utilities sold their transmission facilities to independent transmission
companies. Using FERC’s Order 888 seven-factor technical-functional test as the basis for technical
studies presented and evaluated in individual state dockets, the Michigan Public Service Commission

approved, and subsequently FERC deferred to, those transmission and distribution classifications.
Using “transmission” in the BES definition could cause unintended consequences. Entities already
registered with NERC as Distribution Providers, Load Serving Entities, or Generation Owners, etc.
which own facilities previously classified as distribution by state regulatory agencies, may also now be
required to register with NERC as Transmission Planners, Owners, or Operators. A system element
defined as BES should not determine jurisdiction, ownership, or require duplicative or additional NERC
registration. Much compliance with reliability standards is already being done by RTOs and entities
already registered with NERC. Unnecessary and costly duplication of standards work should be
avoided. We support that “All Transmission Elements …” be replaced with “All network System
Elements …” in the BES definition.
No
MPSC Staff Comments: This inclusion should be eliminated entirely for the reasons provided in E1
above. If the BES is required to be contiguous, this I2 threshold will result in many radial
subtransmission lines losing their non-BES status and having to comply with NERC security and
reliability requirements. Two different generation thresholds, one for I2 and one for I3, should not be
used. The I3 inclusion (75MVA) threshold should be sufficient.

MPSC Staff Comments: The MPSC supports this exclusion with the exception that Inclusion I2 should
be removed from the E1(c) provision. Keeping the I2 here will result in too many subtransmission
load-serving elements losing their non-BES status.
Yes
Yes
MPSC Staff Comments: The MPSC strongly supports this exclusion because it should exclude a large
number of subtransmission facilities that are used for the distribution of local load. Also, this exclusion
together with E1 parallels the seven-factor technical-functional test for classifying transmission and
distribution. The problem with the seven-factor test is that it does not provide an on-going clear
bright line for BES determination. For example, an engineer cannot apply the seven-factor test using
a one-line diagram of an electric power network and determine - without supplemental evidence that an element is classified as distribution or not.
No
MPSC Staff Comments: The BES definition proposed by the SDT should not use the term
“transmission”. BES should not equal transmission. A system element defined as BES should not
determine jurisdiction, ownership, or require duplicative NERC registration.
No
MPSC Staff Comments: The intent of the updated BES definition should be to classify facilities
required to meet mandatory NERC reliability standards. Unnecessary and costly duplication of
standards work should be avoided.
Yes
MPSC Staff Comments: The proposed BES definition creates friction with Order 888’s seven-factor
technical-functional test as implemented by state regulatory agencies. The resulting inconsistent
treatment is likely to result in challenges by entities with FERC-defined distribution assets being now
considered as transmission assets as inconsistent with the FPA. FERC’s Order 888 discusses the two
components of an unbundled transaction in interstate commerce has “for jurisdictional purposes -- a
transmission component and a local distribution component.” p 439 The Order also states that the
Commission “will defer to recommendations by state regulatory authorities concerning where to draw
the jurisdictional line under FERC’s technical test for local distribution facilities” p 437, also known as
the seven-factor technical-functional test. This test was applied by Michigan utilities, filed with the
Michigan Public Service Commission in contested case-specific dockets, and after deliberation
approved. These state-approved jurisdictional bright-line determinations were subsequently filed with
and approved by FERC.

Group
Southern Company
Antonio Grayson
No
Inclusion of individual units less than 75MVA was established when these smaller units were
significant to the reliability of the BES and is outdated.
Yes
No
The inclusion criterion I3 and I5 establish the level of generation that has been deemed to be the
important threshold for the amount of generation at a facility. The individual generating unit size
criteria should match that same aggregate size given in I3 and I5. It doesn't make sense to specify a
20 MVA level for a single unit compared to multiple smaller unit plants whose aggregate totals 75
MVA. To provide equivalent weight to each configuration of plant structure, the individual generating
unit size should be 75 MVA rather than 20 MVA. The NERC Registry Criteria should also be changed
from 20 MVA to 75 MVA for a single generator size. Further, a significant number of respondents to
the first BES definition posting stated that the 20 MVA generator threshold is too low. Many Generator
Owners and Operators do not understand the technical basis for including individual generators rated
75 MVA or less. The NERC Registry Criteria alone does not clearly define the technical basis for the 20
MVA threshold, and appears to use this as a conservative generator rating to cover some areas where
units this size may have a material impact on the local area reliability. We do not believe this
translates to material impact on BES reliability in terms of wide area blackouts and cascading
outages. We believe that the technical basis for including any single generator of 75 MVA or less
needs to be more clearly concisely established and documented to support Inclusion Criterion I2.
Yes
No
Inclusion I4 should be removed from this definition. There is an existing standard, EOP-005-2
(System Restoration from Blackstart Resources), which specifically addresses Blackstart Resources
and the designated Blackstart Cranking Paths "regardless of voltage". Also, use of "regardless of
voltage" in Inclusion I4 as part of the BES definition will expand the applicability of some NERC
Reliability Standards, which pertains to the BES, to connected facilities at voltage levels below 100Kv.
Yes
Yes
No
Section (i) is confusing because it mixes MW with MVA. The net capacity in section (i) would be in MW
while the values referenced in I2 and I3 would be in MVA. This will create confusion. Also, we do not
see any need for section (ii). Section (i) is sufficient without section (ii). We recommend Exclusion E2
to be re-written as follows: Exclusion E2 - A generating unit or multiple generating units that serve all
or part of retail Load with electric energy on the customer’s side of the retail meter if the net capacity
provided to the BES does not exceed 20 MW for a single generating unit or 75 MW for multiple
generating units located at a single site.
Yes
No
This seems to be covered by Exclusions E1 and E3.
Yes
No

Group
Luminant Energy
Dennis Hogan
Yes
Yes
Yes
Yes
Yes
Yes
No
E1 a) Omit or clarify-Sentence beginning “A normally open switch…” Does not say what to do with it.
Is it included or excluded. Suggested wording would be “An example would be a line with a normally
open switching device between radial systems that may operate in a ‘make –before-break’ fashion to
allow for reliable system reconfiguration to maintain continuity of electrical service.” E1 b)-ClarifySentence beginning “Only including…”Are those resources that are included in the exclusions that are
not included in the inclusions? Or are they resources that are included in the inclusions that are not
included in the inclusions? This meaning of this sentence is not clear. It should not be necessary to
say that resources are excluded that are not included. Suggested wording would be “Generation
resources that are not specifically described in the Inclusions I2, I3, I4 and I5.”
Yes
Yes
Yes
Yes
No

Individual
Mike Hirst
Cogentrix Energy, LLC
No
I would like to see a definition for clarity of an "Individual Generating Unit" Example: Solar farm with
300 photovoltaic units. Each is a stand-alone unit with its own inverter, but all come together at a
common tie breaker to connect to the BES. Questions: 1. Would each one be considered directly tied
to the BES through one common tie breaker? 2. Would each photovoltaic unit be considered an
individual generating unit? 3. Would the combined total of 300 units be considered an individual
generating unit or would they be considered a facility?
Yes

No
We also strongly suggest the term GSU be defined in the NERC Glossary of Terms to prevent potential
compliance re-interpretation of this requirement. A suggested definition is: “Generator Stepup
Transformer (GSU) should be defined as a transformer directly connected to a generator on the low
side and to a bus on the high side.”
No
GSUs need to be defined – see response to question 3 above
No
The SERC SRG is concerned that this provision may have the effect of incenting transmission
operators to limit the available generator options to the minimum necessary for a reliable option as
opposed to every possible option that might be utilized in a pinch. We recommend the following
adjusted language: “Essential Blackstart Resources and the designated essential blackstart Cranking
Paths identified in the Transmission Operator’s restoration plan regardless of voltage”
Yes
No
This exclusion is acceptable if the suggestions in Questions 3 and 4 are incorporated.
No
This exclusion is acceptable if the suggestions in Questions 3 and 4 are incorporated.
No
B)The SERC SDT believes you intended to grant exception E2 in this case; however, it is not explicitly
identified. C)Is this intended for each hour of the year or is it possible for some hours that generation
may exceed load? This needs to be clarified.
No
We suggest that our comments to Question 3 and Question 4 be incorporated. We also question
whether this is going to have an unintended consequence of requiring Distribution Providers to
register that otherwise wouldn’t have to register because some technical aspect has not been included
in this exception.
Yes
No
No
Individual
Jack Stamper
Clark Public Utilities
No
Clark is concerned that the core definition is overly-broad and sweeps facilities into the BES that are
required by the statute to be excluded, even considering the list of inclusions and exclusions. Clark
urges the SDT to bear in mind the specific restrictions on the definition of “bulk-power system”
contained in Section 215 of the Federal Power Act (“FPA”). In Section 215(a)(1), Congress defined
“bulk-power system” to mean “facilities and control systems necessary for operating an
interconnected electric energy transmission network (or any portion thereof)” and “electric energy
from generation facilities needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1).
Congress unequivocally excluded from this definition “facilities used in the local distribution of electric
energy.” The “bulk-power system” definition thus imposes a clear limit on the reach of the mandatory
reliability regime. Congress reinforced that limit in Section 215(i), where it emphasized that the FPA
authorizes the imposition of reliability standards “for only the bulk-power system.” 16 U.S.C. §
824o(i)(1). Clark believes it is clear that Congress intended the “bulk-power system” to be defined
narrowly so that it would incorporate only high-voltage, interstate facilities used to transmit power
over long distances, whose failure threatens drastic reliability events such as system instability,
uncontrolled separation, or cascading outages. In addition, the Federal Energy Regulatory
Commission clearly stated that Order No. 743 did not mandate or direct NERC to adopt a 100 kV

bright-line threshold (Order No. 743-A, 134 FERC ¶ 61,210 at P 20. The Commission goes on to state
that the 100 kV bright-line threshold is only one way to address the Commission’s concerns. The
Commission only requires that NERC use the Commission’s recommendation or propose a different
solution that is as effective as, or superior to, the Commission’s proposed approach. The Commission
also acknowledges that Congress has specifically exempted facilities used in the local distribution of
electric energy. The definition developed by the SDT should therefore focus on that portion of the
interconnected bulk transmission grid for which thermal, voltage, and stability limits must be
observed in order to prevent instability, uncontrolled separation, or cascading outages. Further, in
order to honor the specific limits placed on the definition by Congress, the SDT’s definition must
exclude facilities used in the local distribution of electric power and it must exclude facilities whose
operation or mis-operation affects only the level of service and does not threaten cascading outages
or other widespread events on the bulk interconnected system. Clark asserts that the adoption of a
bright-line threshold of 100 kV is arbitrary and not based on any investigation of the potential for
facilities at this voltage level to cause instability, uncontrolled separation, or cascading outages or for
the general need of these facilities for the operation of an interconnected electric energy transmission
network. The threshold excludes transmission facilities below 100 kV without any determination on a
general basis of whether these facilities affect interconnected system operation. It goes without
saying that these low voltage transmission facilities should be subject to an inclusion process in the
event that regional reliability entities believe they do have an impact on reliability but on a case-bycase basis. Clark agrees with this concept and does not believe bringing low voltage transmission
facilities into the BES through an inclusion process causes any BES reliability issues. Similarly, Clark
believes that the majority of facilities between 100 kV and 200 kV can be shown to have no impacts
on interconnected system operation and do not threaten instability, uncontrolled separation, or
cascading outages. Clark also points out that the vegetation outage standard (FAC-003) uses this
approach. The standard applies to facilities operated at 200 kV or above and “lower voltage lines
designated by the RRO as critical to the reliability of the electric system in the region.” Clark believes
the use of 100 kV as the bright-line threshold will result in a large number of facilities being brought
into the definition of the BES that are either 1) part of a Local Distribution Network, 2) are radial
serving only load from one transmission source, or 3) that can be shown to have no affect on
interconnected system operation or cannot cause instability, uncontrolled separation, or cascading
outages. This unnecessary inclusion will cause a large amount of effort on the part of the owners of
these facilities and on the part of the Regional Reliability Organizations that will have to review the
many exclusion filings that will result. Utilizing a 200 kV threshold with a low voltage inclusion process
will eliminate much of the unnecessary paperwork since very few owners of 200 kV or above facilities
will seek exclusions. This will free up regional reliability entities to focus on low voltage transmission
facilities that truly have an impact on interconnected system operations. Clark believes that the SDT
and the NERC should consider adopting a bright-line threshold higher than 100 kV with low voltage
inclusion and develop the arguments necessary to demonstrate to the Commission that this solution is
as effective as, or superior to, the Commission’s proposed approach. These arguments should include
the following: • Eventually, a 200 kV bright-line threshold with a low voltage inclusion process will
incorporate into the BES the same facilities that a 100 kV bright-line threshold with an exclusion
process. This means that these two concepts both have the same effect on the reliability and the
operability of the BES. • Utilizing a 200 kV bright-line will reduce the amount of initial effort by
transmission owners and Regional Reliability Organizations and allow these entities to concentrate on
low voltage facilities that truly have an impact on the BES. Clark is similarly concerned that the SDT’s
proposed definition is overly-broad in including all generating units greater than 20 MVA capacity
connected to transmission at 100 kV or above. Clark believes that there are many small to medium
sized generators that individually have no affect on interconnected system operations and do not
threaten the BES with instability, uncontrolled separation, or cascading outages. Many of these
generators are connected to Local Distribution Networks with minimum loads that exceed maximum
generation. While the generators do support system reliability collectively, it is questionable whether
many of these generators individually represent a facility necessary for interconnected system
operations. The adoption by the SDT of a 200 kV bright-line threshold would eliminate many of these
smaller generating units. Again, the RROs must have an inclusion process for smaller generating units
it believes support interconnected system operations. Clark believes that eventually both thresholds
(with appropriate inclusion and exclusion processes) will result in the same 100 kV to 200 kV
connected generators being included in the BES so there will be no difference in the reliability of the
BES. Adopting the higher of the two thresholds and adopting a generating capacity threshold higher

than 20 MVA will allow generator owners and Regional Reliability Organizations to devote resources to
small generating units that truly have an impact on interconnected system operations.
No
Transformers should only be part of the Bulk Electric System if they are transforming voltage from
one BES element to another BES element. The current inclusion language would apply to all
transformers with two windings operated at greater the 100 kV subject to the E1 and E3 exclusions.
There is no indicated exclusion referring to the exception process. If a facility is excluded from the
BES by the exception process, connected transformers should also be excluded. Clark believes if the
inclusion language was changed slightly, the exclusion references to E1 and E3 would not be
necessary. Without this change, it appears that a transformer with two winding connected to greater
than 100 kV would be a BES asset even if both of the facilities these windings were connected to had
been excluded (E1 or E3) or excepted (BES Exception Process). I1 should be rewritten to state:
Transformers, other than generator step-up (GSU) transformers, including phase angle regulators,
with two windings of 100 kV or higher connected to Transmission Elements determined to be part of
the Bulk Electric System.
No
Generators should only be part of the Bulk Electric System if they are connected through a GSU to a
Transmission Element determined to be part of the BES. The current inclusion language would apply
to all generators connected to facilities greater the 100 kV with no exclusion or exception process.
Without a change, it appears that a generator connected to a facility greater than 100 kV would be a
BES asset even if the transmission assets could be excluded or excepted. I2 should be rewritten to
state: Individual generating units greater than 20 MVA (gross nameplate rating) including the
generator terminals through the GSU which has a high side winding connected to a Transmission
Element determined to be part of the Bulk Electric System. Additionally, as indicated by Clark in its
comments on the core definition of the BES, Clark believes the 20 MVA threshold lacks an adequate
technical justification and is a purely arbitrary quantity. The use of a capacity threshold in the
definition of the BES should have technical reasons.
No
Generators should only be part of the Bulk Electric System if they are connected through a GSU to a
Transmission Element determined to be part of the BES. The current inclusion language would apply
to all generators connected to facilities greater the 100 kV with no exclusion or exception process.
Without a change, it appears that a generator connected to a facility greater than 100 kV would be a
BES asset even if the transmission assets could be excluded or excepted. I3 should be rewritten to
state: Multiple generating units located at a single site with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) including the generator terminals through the GSUs, connected
through a common bus to a Transmission Element determined to be part of the Bulk Electric System.
Additionally, as indicated by Clark in its comments on the core definition of the BES, Clark believes
the 75 MVA threshold lacks an adequate technical justification and is a purely arbitrary quantity. The
use of a capacity threshold in the definition of the BES should have technical reasons.
Yes
No
Generators should only be part of the Bulk Electric System if they are connected through a GSU to a
Transmission Element determined to be part of the BES. The current inclusion language would apply
to all generators connected to facilities greater the 100 kV with no exclusion or exception process.
Without a change, it appears that a generator connected to a facility greater than 100 kV would be a
BES asset even if the transmission assets could be excluded or excepted. I5 should be rewritten to
state: Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a collector system through a common point of interconnection
to a Transmission Element determined to be part of the Bulk Electric System. Additionally, as
indicated by Clark in its comments on the core definition of the BES, Clark believes the 75 MVA
threshold lacks an adequate technical justification and is a purely arbitrary quantity. The use of a
capacity threshold in the definition of the BES should have technical reasons.
Yes

No
As indicated by Clark in its comments on the core definition of the BES, Clark believes the 20 MVA
and the 75 MVA thresholds lack adequate technical justification and are a purely arbitrary quantities.
The use of a capacity thresholds in the definition of the BES should have technical reasons.
Yes
Clark strongly supports the categorical exclusion of Local Distribution Networks from the BES. Clark
also believes that adopting a 200 kV bright-line threshold will result in most, if not all, LDN being
exempted from the BES without any need to analyze or self-certify an LDN. This is another case
where a higher threshold (with an appropriate inclusion process) will have no affect on BES reliability
but will focus resources on investigation low voltage facilities that truly have an impact on
interconnected system operations. Clark does recommend a revision to the LDN exclusion language.
E3 - Local distribution networks (LDNs): Groups of Elements operated above 100 kV that distribute
power to Load rather than transfer bulk power across the interconnected System. LDN’s are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of
service to retail customer Load and not to accommodate bulk transfers of power across the
interconnected bulk system. The LDN is characterized by all of the following:
No
This proposed exclusion has no affect or benefit. If an entity is not required to register as a DP or LSE
why do they then need to be exempted from a standard that does not apply to the entity. The
Commission was obviously focusing on a small utility with facilities greater that 100 kV making that
entity a Transmission Owner. A 100 kV facility owned by a utility with a small amount of load is either
material or immaterial to the reliability of the BES irrespective of the amount of load that entity
serves. Therefore the term ‘small utility” must refer to some other measure of size. This may be size
of load, but also may include circuit miles of transmission greater than 100 kV, capacity of largest line
greater than 100 kV line, and possible other measures of “smallness.”
Yes
Yes
The BES Definition does not have any reference to the exception process being developed. Both the
exclusion and inclusion sections of the BES Definition should have a reference to the process where
“BES Definition included” Transmission Elements may be excluded and “BES Definition excluded”
Transmission Elements may be included.
The process for identifying facilities as part of an LDN needs to be stated. Clark has heard that this
will be through a self-certification process, however, there is no written description how a utility
classifies its transmission facilities as an LDN.
Individual
John A. Gray
The Dow Chemical Company
No
See Dow's specific comments on some of the following questions.
No
An additional exclusion for industrial distribution facilities needs to be added for the reasons
expressed in Dow's comments on Exclusion E3. Dow's manufacturing sites have transformers, other
than generator step up transformers, that have two windings of 100 kV or higher and that are
between on-site generation and individual manufacturing plants at such sites. Such transformers
should be excluded, because they are part of electricity distribution facilities. However, such
transformers do not fall within proposed Exclusion E1 or E3.
No
It should be clarified that if something falls within an Inclusion and an Exclusion, then it is excluded.
See ELCON comments.
No
It should be clarified that Exclusion E2 over-rides this Inclusion. See ELCON comments.
Yes

No
The language is not clear enough to understand what is covered.
No
The existing language in the NERC Statement of Compliance Registry for radial exclusions should be
maintained since the change proposed by the SDT could result in a significant increase in entities
and/or facilities that would have to be registered or included (because of the addition of the automatic
interruption device). See ELCON comments for additional details.
No
Clause (ii) should be revised as follows: "(ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or pursuant to a binding obligation with another Generator Owner/Generator Operator, or
under terms approved by the applicable regulatory authority."
No
The Dow Chemical Company (“Dow) is an international chemical and plastics manufacturing firm and
a leader in science and technology, providing chemical, plastic, and agricultural products and services
to many essential consumer markets throughout the world. Dow and certain of its worldwide affiliates
and subsidiaries, including Union Carbide Corporation, own and operate electrical facilities at a
number of industrial sites within the U.S., principally, in Texas and Louisiana. The electrical facilities
at these various industrial sites are configured similarly and perform similar functions. In most cases,
a tie line or lines connect the industrial site to the electric transmission grid. Power is delivered from
the electric transmission grid to the industrial site through the tie line(s). Lines within the industrial
site then deliver power to individual manufacturing plants within the site. Additionally, cogeneration
facilities are located at a number of industrial sites owned by Dow and its subsidiaries. These
cogeneration facilities generate power that is distributed within the industrial site and used for
manufacturing plant operations. In some instances, excess power not required for plant operations is
delivered back into the electric transmission grid through the tie line(s) connecting the industrial site
to the grid. Under all circumstances, electricity is not flowing into and out of such industrial sites at
the same time. While the tie lines and some of the internal lines at these industrial sites operate at
100kV or higher, they do not perform anything that resembles a transmission function. Rather than
transmit power long distances from generation to load centers, the tie lines and internal lines perform
primarily a local distribution function consisting of the distribution of power brought in from the grid
or generated internally to different plants within each industrial site. In some cases, the facilities also
perform an interconnection function to the extent they enable power from cogeneration facilities to be
delivered into the grid. The voltage of the tie lines and internal lines at these industrial sites is
dictated by the load and basic configuration of each site. Higher voltage lines are used when
necessary to meet applicable load requirements or to reduce line losses. That does not mean that
such lines perform a transmission function. At some sites, Dow is registered as a Generation Owner
and Generation Operator. At other sites, the applicable Regional Entity has found that such
registration is not required because of the relatively small amount of power supplied to the grid from
the applicable cogeneration resources, even though those cogeneration resources have an aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating). Tie lines (to the grid) and internal
lines at an industrial site that operate at 100kV or higher should be excluded from the BES definition
if, due to the relatively small amount of power supplied to the grid from the generation resources at
the site, the owner of those generation resources is not required to be registered as a Generation
Owner and the operator of those generation resources is not required to be registered as a
Generation Operator. At sites where the owner of the generation resources is registered as a
Generation Owner and the operator of those generation resources is registered as a Generation
Operator, the internal lines (between the generation resources and the manufacturing plants) that
operate at 100kV or higher should be excluded from the BES definition, because they are distribution
and not transmission facilities. The lines interconnecting the generation resources at such sites to the
transmission grid should be included in the BES definition, but the owner and operator of such
interconnection lines should not be registered as a Transmission Owner or Transmission Operator. In
no instance has a Regional Entity determined that Dow or any subsidiary should be registered as a
Transmission Owner or Transmission Operator. Instead, such interconnection lines should be
considered as part of the generation resource and Generation Owners and Generation Operators

should be subject to reliability standards specifically developed for such interconnection lines. Dow is
strongly opposed to any BES definition that would result in either the tie lines or the internal lines at
industrial sites being subject to the mandatory reliability standards applicable to Transmission Owners
and Transmission Operators. Complying with reliability standards would cause Dow and its
subsidiaries to incur substantial compliance costs and create potential exposure to penalties in the
future for noncompliance. Perhaps such costs and exposure could be justified if subjecting these
facilities to compliance with reliability standards resulted in a material increase in reliability of the
BES, but there is no reason to believe that will be the case. In fact, the opposite might be true. The
tie lines and internal lines at industrial sites owned by Dow and its subsidiaries have been operated
for decades as distribution and interconnection facilities, and practices and procedures have
developed over the years that have enabled such operations to achieve a high degree of reliability for
such sites. Requiring these facilities to now operate in a different manner as transmission facilities
may well result in a degradation of the reliability of the manufacturing plants located at such sites.
For example, outages would have to be coordinated with the RTO, which may not be interested in
coordinating such outages with scheduled manufacturing plant outages. Dow recommends that a
separate exclusion be added to the BES definition to address industrial distribution facilities. Proposed
exclusion E-3 for local distribution networks is not sufficient to ensure that all industrial distribution
facilities are excluded. For example, criteria b), entitled “Limits on connected generation” states that
“Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA
generation”. This criteria makes no sense for an industrial site with on-site electricity generation and
a number of manufacturing plants that has internal power lines and lines interconnecting with the
transmission grid that operate at 100 kV or higher where the owner and operator of the on-site
electricity generation facilities are not registered as a Generation Owner and a Generation Operator
because only a small amount of electricity is ever exported from the on-site electricity generation
facilities to the transmission grid. This criteria also makes no sense with respect to internal electric
lines (operated at 100 kV or higher) at such industrial sites even where the owner and operator of the
on-site electricity generation facilities are registered as a Generation Owner and a Generation
Operator. Criteria c) also causes proposed exclusion E-3 not to be sufficient to ensure that all
industrial distribution facilities are excluded where the owner and operator of the on-site electricity
generation facilities are not registered as a Generation Owner and a Generation Operator because
only a small amount of electricity is ever exported from the on-site electricity generation facilities to
the transmission grid. Criteria c), entitled “Power flows only into the LDN”, states: “The generation
within the LDN shall not exceed the electric Demand within the LDN.” Criteria c) also makes no sense
with respect to internal lines at such industrial sites even where the owner and operator of the on-site
electricity generation facilities are registered as a Generation Owner and a Generation Operator.
No
If this is adopted, it should apply to industrial sites as well as small utilities.
No
The Dow Chemical Company (“Dow) is an international chemical and plastics manufacturing firm and
a leader in science and technology, providing chemical, plastic, and agricultural products and services
to many essential consumer markets throughout the world. Dow and certain of its worldwide affiliates
and subsidiaries, including Union Carbide Corporation, own and operate electrical facilities at a
number of industrial sites within the U.S., principally, in Texas and Louisiana. The electrical facilities
at these various industrial sites are configured similarly and perform similar functions. In most cases,
a tie line or lines connect the industrial site to the electric transmission grid. Power is delivered from
the electric transmission grid to the industrial site through the tie line(s). Lines within the industrial
site then deliver power to individual manufacturing plants within the site. Additionally, cogeneration
facilities are located at a number of industrial sites owned by Dow and its subsidiaries. These
cogeneration facilities generate power that is distributed within the industrial site and used for
manufacturing plant operations. In some instances, excess power not required for plant operations is
delivered back into the electric transmission grid through the tie line(s) connecting the industrial site
to the grid. Under all circumstances, electricity is not flowing into and out of such industrial sites at
the same time. While the tie lines and some of the internal lines at these industrial sites operate at
100kV or higher, they do not perform anything that resembles a transmission function. Rather than
transmit power long distances from generation to load centers, the tie lines and internal lines perform
primarily a local distribution function consisting of the distribution of power brought in from the grid
or generated internally to different plants within each industrial site. In some cases, the facilities also

perform an interconnection function to the extent they enable power from cogeneration facilities to be
delivered into the grid. The voltage of the tie lines and internal lines at these industrial sites is
dictated by the load and basic configuration of each site. Higher voltage lines are used when
necessary to meet applicable load requirements or to reduce line losses. That does not mean that
such lines perform a transmission function. At some sites, Dow is registered as a Generation Owner
and Generation Operator. At other sites, the applicable Regional Entity has found that such
registration is not required because of the relatively small amount of power supplied to the grid from
the applicable cogeneration resources, even though those cogeneration resources have an aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating). Tie lines (to the grid) and internal
lines at an industrial site that operate at 100kV or higher should be excluded from the BES definition
if, due to the relatively small amount of power supplied to the grid from the generation resources at
the site, the owner of those generation resources is not required to be registered as a Generation
Owner and the operator of those generation resources is not required to be registered as a
Generation Operator. At sites where the owner of the generation resources is registered as a
Generation Owner and the operator of those generation resources is registered as a Generation
Operator, the internal lines (between the generation resources and the manufacturing plants) that
operate at 100kV or higher should be excluded from the BES definition, because they are distribution
and not transmission facilities. The lines interconnecting the generation resources at such sites to the
transmission grid should be included in the BES definition, but the owner and operator of such
interconnection lines should not be registered as a Transmission Owner or Transmission Operator. In
no instance has a Regional Entity determined that Dow or any subsidiary should be registered as a
Transmission Owner or Transmission Operator. Instead, such interconnection lines should be
considered as part of the generation resource and Generation Owners and Generation Operators
should be subject to reliability standards specifically developed for such interconnection lines. Dow is
strongly opposed to any BES definition that would result in either the tie lines or the internal lines at
industrial sites being subject to the mandatory reliability standards applicable to Transmission Owners
and Transmission Operators. Complying with reliability standards would cause Dow and its
subsidiaries to incur substantial compliance costs and create potential exposure to penalties in the
future for noncompliance. Perhaps such costs and exposure could be justified if subjecting these
facilities to compliance with reliability standards resulted in a material increase in reliability of the
BES, but there is no reason to believe that will be the case. In fact, the opposite might be true. The
tie lines and internal lines at industrial sites owned by Dow and its subsidiaries have been operated
for decades as distribution and interconnection facilities, and practices and procedures have
developed over the years that have enabled such operations to achieve a high degree of reliability for
such sites. Requiring these facilities to now operate in a different manner as transmission facilities
may well result in a degradation of the reliability of the manufacturing plants located at such sites.
For example, outages would have to be coordinated with the RTO, which may not be interested in
coordinating such outages with scheduled manufacturing plant outages. Dow recommends that a
separate exclusion be added to the BES definition to address industrial distribution facilities. Proposed
exclusion E-3 for local distribution networks is not sufficient to ensure that all industrial distribution
facilities are excluded. For example, criteria b), entitled “Limits on connected generation” states that
“Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA
generation”. This criteria makes no sense for an industrial site with on-site electricity generation and
a number of manufacturing plants that has internal power lines and lines interconnecting with the
transmission grid that operate at 100 kV or higher where the owner and operator of the on-site
electricity generation facilities are not registered as a Generation Owner and a Generation Operator
because only a small amount of electricity is ever exported from the on-site electricity generation
facilities to the transmission grid. This criteria also makes no sense with respect to internal electric
lines (operated at 100 kV or higher) at such industrial sites even where the owner and operator of the
on-site electricity generation facilities are registered as a Generation Owner and a Generation
Operator. Criteria c) also causes proposed exclusion E-3 not to be sufficient to ensure that all
industrial distribution facilities are excluded where the owner and operator of the on-site electricity
generation facilities are not registered as a Generation Owner and a Generation Operator because
only a small amount of electricity is ever exported from the on-site electricity generation facilities to
the transmission grid. Criteria c), entitled “Power flows only into the LDN”, states: “The generation
within the LDN shall not exceed the electric Demand within the LDN.” Criteria c) also makes no sense
with respect to internal lines at such industrial sites even where the owner and operator of the on-site
electricity generation facilities are registered as a Generation Owner and a Generation Operator.

Yes
Comments: Section 215 of the Federal Power Act denies FERC jurisdiction over facilities used in the
local distribution of electric energy. FERC has recognized that since facilities used in the local
distribution of electric energy “are exempted from the Bulk-Power System, they also are excluded
from the bulk electric system.” Section 215 of the Federal Power Act does not qualify the exclusion
from FERC jurisdiction of “facilities used in the local distribution of electric energy.” For example,
Section 215 does not state that: ♣ The term “bulk power system” “does not include facilities used in
the local distribution of electric energy [unless needed for reliability purposes];” or ♣ The term “bulk
power system” “does not include facilities [with automatic interruption devices] used in the local
distribution of electric energy.” Any definition of the bulk electric system that does not exclude all
“facilities used in the local distribution of electric energy” is unlawful. Further, the definition of the
bulk electric system must recognize that Section 215 of the Federal Power Act does not allow the
potential reliability impact of a facility to determine whether the facility is local distribution or
transmission. By excluding all facilities used in the local distribution of electric energy from the
definition of the Bulk-Power System in Section 215, Congress recognized that while facilities used in
the local distribution of electric energy may be part of the Bulk-Power System, they are, nonetheless,
not FERC jurisdictional. Thus, “facilities and control systems necessary for operating an
interconnected electric energy transmission network (or any portion thereof)” that are used in the
local distribution of electric energy are not FERC jurisdictional regardless of the potential reliability
impact of the facilities.
Not that we are aware of at this time.
Group
Pennsylvania Public Utility Commission
Darren D. GIll

The Pennsylvania Public Utility Commission offers the following comments in response to Standards
Announcement Project 2010-17 BES Definition: As you know, Section 1211 of the Energy Policy Act of
2005, amending Section 215 of the Federal Power Act, provided for the promulgation of standards for
the bulk power system by an Electric Reliability Organization subject to the approval of the U.S.
Federal Energy Commission. Section 215 (a) states: ‘SEC. 215. ELECTRIC RELIABILITY. ‘‘(a)
DEFINITIONS.—For purposes of this section: (1) The term ‘bulk-power system’ means— (A) facilities
and control systems necessary for operating an interconnected electric energy transmission network
(or any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy. EPAct 2005, Section 1211, 16 U.S.C. § 824o [emphasis supplied] While the PaPUC
acknowledges the need for a more explicit definition of the Bulk Electric System (or, as it is stated in
EPAct 2005, the “bulk power system”), we are concerned that the existing draft definition and stated
exclusions is insufficiently clear and may be erroneously extended to distribution facilities that are
currently subject to state jurisdiction expressly reserved by the language of EPAct 2005, Section 1211
(a). Exceptions E1-E4 are plainly drafted to address this issue, but there is a concern that the
definition of “local distribution networks” contained in Exception E3 may not fully comport with the
intent of Congress, particularly Exception E3 (d) which excepts facilities that are [n]ot used to
transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery

through the LDN. The proposed language appears to be contrary to Congressional intent as it implies
that some local distribution facilities which “transfer bulk power” are indeed subject to the ERO
standards process. Additionally, the draft BES, which distinguishes local distribution facilities between
those that “transfer bulk power” and those that do not appears insufficiently precise, as bulk power is
ultimately transferred through every portion of the local distribution network to end users. Our major
concern is that this draft standard definition will collide with state regulation of distribution facilities,
particularly where state commissions are seeking to impose standards and protective arrangements
more stringent than might be required by the Electric Reliability Organization or Regional Reliability
Organization. Accordingly, it is recommended that the Draft BES be modified to specifically define
distribution facilities and exclude them from the ambit of the Bulk Electric System definition, as well
as making it clear that State reliability standards relating to the local distribution network are not
overridden or modified by standards applicable to the Bulk Electric System.
Individual
David Thorne
Pepco Holdings Inc
Yes
Do reactive power resources include reactors?
Yes
Clarification needed: If a generator greater than 20mva connected to a bus less than 100kv, but the
bus is connected through a transformer (high side greater then 100kv) to the BES, are the generator,
GSU or transformer considered BES?
Clarification needed: Same situation as described in #3 above.
No
1)In many cases the cranking path or portions of it may consist of facilities less than 100kv. Many of
these facilities are local distribution facilities and should not be included in the BES. 2) If there is an
identified cranking path that is transmission designated, but the path is not contiguous with the BES,
must the elements in-between be included as BES?
Yes

Yes
Yes
No
see answer to #5
1) It would be very helpful to include examples (with an explanation and diagram) of the various
configurations that meet each of the inclusions and exclusions. Can the next draft include such
examples to provide further clarity to the definitions? Consideration should be given to developing an
attachment for this material and a method to add appropriate examples in the future. 2) The proposal
is silent on whether associated auxiliary and protection and control system equipment that could
automatically trip a BES facility independent of the protection and control equipment’s voltage level
are included as part of the BES. The RFC BES definition specially addresses this issue as an example.
Does IRO-005 cover those elements so it is not necessary to address these in this proposal?
Consideration should be given to referencing the issue in the BES document.
Individual
Gary Ferris
Vigilante Electric Cooperative

Dear NERC Standards Drafting Team: Enclosed are Vigilante Electric Cooperative, Inc's (VIEC)
comments on NERC's Proposed Continent-wide Definition of the Bulk Electric System (BES). We
believe that NERC's proposed definition of the Bulk Electric System is moving in the right direction
and we thank the Standards Drafting Team for their hard work. We support the comments of the
Snohomish County Public Utility Distric and Pacific Northwest Generating Cooperative with regard to
questions posed by the comment form for Project 2010-17. We would like to add the following
additional comments: With regard to exclusion E3, part e) - we do not believe that just because an
element is on a list that it cannot be excluded. If an element meets all of the criteria to be excluded,
then it should be excluded and removed from the list. Otherwise, we strongly agree that LDNs have
no material impact on the BES. We also strongly encourage the continued development of a
reasonable method for determination of inclusion/exclusion. We believe that there should be a clearer
path that would ultimately allow a utility to pursue being included/excluded from registration with
WECC. Many small utilities have an element that may actually have no material impact on the BES yet
is required to comply with all WECC standards. We also would like to comment on the WECC
compliance bulletin of April 15, 2011. While we greatly appreciate the recognition that radial T-Taps
with transformer or distribution protection schemes have no material impact to the BES, we would
encourage you to take this the additional logical step to actually remove these instances from WECC
responibilities. This would help reduce the burden both on WECC and the individual entities and save
everyone involved a tremendous amount of time, effort and money. We again thank the Team for
their efforts and appreciate the opportunity to be allowed to comment on these issues.
Individual
Steve Alexanderson
Central Lincoln
No
We support the PNGC comments suggesting beginning with the statutory definition of BPS that
excludes local distribution. The definition should also be further elaborated to show specific points of
demarcation for each inclusion and exclusion by the use of diagrams similar to those included with
Proposal 6 from the WECC Bulk Electric System Definition Task Force. We also note that per the
flowchart at http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf, any >100 kV
element that does not meet an inclusion or an exclusion ends up being included. We don’t think that
was the SDT’s intent. For example a 5 kW solar project connected at 115 kV does not meet any
inclusions so proceed to the exclusion box. It is not radial load, behind a retail meter, or part of an
LDN so it is BES by application of the definition. We realize this flowchart was drafted by another
team. It therefore becomes imperative that the definition team clearly specifies exactly what becomes
of an element that does not meet an inclusion.
No
We support the SDT’s intent, but it is unclear from the language how single winding transformers
(autotransformers) are handled. We suggest replacing “two windings…” with “two sets of terminals….”
Please also indicate how transformers with only one set of terminals above 100 kV are treated, since
we don’t believe the flowchart at
http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly expresses the
SDT’s intent to classify these transformers as non-BES.
Yes

But please indicate how generators below 20 MVA are treated, since we don’t believe the flowchart at
http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly expresses the
SDT’s intent to classify these small units as non-BES.
Yes
Please indicate how aggregate generation below 75 MVA is to be treated, since we don’t believe the
flowchart at http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly
expresses the SDT’s intent to classify these small plants as non-BES.
Yes
But please indicate how blackstart resources (regardless of voltage) not in the TO’s restoration plan
are treated, since we don’t believe the flowchart at
http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly expresses the
SDT’s intent to classify these resources (when also below the 20 or 75 MVA thresholds) as non-BES.
Yes
But please indicate how dispersed aggregate generation below 75 MVA is to be treated, since we don’t
believe the flowchart at http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf
properly expresses the SDT’s intent to classify these resources as non-BES.
Yes
FERC has made clear throughout the Order No. 743 process that the exclusion for radials be retained.
We believe the exclusion as drafted adequately defines radials.
No
We support excluding behind the meter generation below the limits, but the string of “ands” and “ors”
in this exclusion are far too confusing with numerous ways to parse them. Suggest eliminating bullet
(ii) since the existence of obligations has no bearing on impact.
No
Central Lincoln strongly supports the exclusion of LDNs. These networks are used for improving local
service, not for BES reliability; and their use should not be discouraged. However, we see problems
with the language of part d. Part d uses the term the undefined term “bulk power” as part of the
overall definition of “bulk power system,” leading to a circular definition. Did the SDT mean to indicate
that no power may be transferred though an LDN? If so, suggest striking the word “bulk.” We also
believe the SDT meant to define the LDN in terms of normal operating conditions, since all LDNs
would transfer power under the right contingency (such as a complete loss of load within the LDN).
Please make it clear that part d test applies during normal operating conditions.
Yes
Central Lincoln supports the SDT in its efforts to avoid unintended consequences from changes to the
BES definition, especially for small entities that can ill afford the substantial costs that accompany
imposition of mandatory compliance with reliability standards. Further, we agree that the small
utilities covered by the exemption will have no measurable impact on the operation of the
interconnected BES. In the Pacific Northwest, many small entities were required to register by virtue
of owning a very small portion of the region’s 115-kV system. These utilities have faced substantial
compliance burdens even though their operations are simply not material to the interconnected bulk
grid in our region, and the investment of resources in compliance therefore will have no measurable
effect in improving the reliability of the interconnected grid.
No
We believe the SDT has excluded most distribution facilities, but not all. The remaining distribution
facilities will find it necessary to go through a lengthy exception process. As stated in Q1, we support
the PNGC comments stating that local distribution as determined by the seven factor test should be
excluded by definition. We note that the SDT has also developed a technical principal document that
uses language similar to the seven factor test. To use it, though, an entity must apply for exception
first. We believe the seven factors or technical principles should be part of the definition in order to
avoid numerous exception applications and resulting delays.
Yes
Improper classification of local distribution facilities, even if only for the duration of the exceptions
process; puts these facilities under the regulatory jurisdiction of NERC contrary to the Federal Power
Act when they should be under the exclusive jurisdiction of state utility commissions or local utility

boards.
We believe the Exception process is critical both to ensure that the BES definition is effective in
producing measurable gains to bulk system reliability and to ensuring that the definition will comply
with the limitations Congress placed in Section 215. Hence, we believe the entire BES definition,
including the Exception process and related procedures, should be vetted through the NERC
Standards Development Process, including the full comment periods and a ballot approvals provided
for in that process. We are concerned that important elements of the BES definition have been
assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the
Standards Development Process. Accordingly, we urge that all elements of the BES definition,
including those elements that have been assigned to the Rules of Procedure Team, be vetted through
the Standards Development Process. We note also that the SAR still does not apply the definition to
all registered entity types in violation of the FERC order to provide a continent-wide definition. Please
include PSEs in the SAR also. We are concerned that the proposed 24-month delay in the effective
date of the new definition will delay the potentially beneficial effects of the SDT’s efforts, especially for
utilities that have been inappropriately required to meet BES reliability standards, which is a common
situation in WECC. We therefore urge the new BES definition to become effective immediately upon
approval by FERC or other applicable regulatory agencies. Entities that have been improperly required
to meet standards can then immediately redirect resources to where they are truly needed. For
entities that have not previously been registered for BES-related functions but that would be required
to register under the new definition, we agree that 24 months is an appropriate transition period to
allow the newly-registered entity to attain compliance with newly-applicable reliability standards,
many of which require new training for employees, new maintenance procedures, and complex new
operational protocols. However, the transition period for newly-registered entities should be
structured in a way that does not prevent other entities from benefitting from the new definition at
the earliest possible date.
Individual
Neil Phinney
Georgia System Operations

It is unclear to us what the phrase “including the generator terminals through the GSU...” means. Is
the GSU itself included (it apparently would not be under I-1)? We understand terminals to be in
essence points, and therefore don’t see how they go “through” a GSU. Is the intention perhaps to
mean “including the generator terminals at the GSU” or even ”including the generator terminals at the
GSU and the GSU itself”?

A. The phrase “which is described as” is unclear. If the intention is to mean “which is defined as,” the
term “Radial System” should be capitalized and added to the glossary. Otherwise, consider deleting
the phrase. B. It is not clear whether the automatic interruption device on the excluded system is
itself in or out of the BES. Can the drafting team clarify this intent with respect to breakers protecting
radial lines (perhaps compared to circuit switchers protecting load serving transformers)? Drawings
could be very beneficial here. C. The second part of sub-bullet “a” (the sentence beginning “A
normally open switching device...”) applies not only to “a” but to all the sub-bullets, and therefore
should be moved to either the initial sentence or to be a closing item after the last sub-bullet. For
example, if the sub-bullets are indented, and then this sentence returns to the original margin, that
would show that it applies to any “radial system” and not just to a system falling under a single subbullet.
How is “net capacity provided to the BES” measured (e.g., by nameplate capacity minus peak load,
by actual generated energy – rather than capacity - minus actual load at each moment or over some
period of time, etc.)? It is possible that a larger than currently necessary generator may be installed
in anticipation of future load growth, but that it is never used to generate significantly more than
what is needed for load. Depending on how “net capacity” is calculated, such a generator might
unnecessarily be pulled into the BES.

In item c, What is meant by “generation” and by “electric Demand,” and how is whether “generation
within the LDN...exceed[s] the electric Demand within the LDN” to be calculated? Is this installed
nameplate capacity (rather than energy) minus peak Demand, or minus forecast Demand, or minus
actual Demand – in each case either for some period of time or at every moment (the NERC Glossary
defines Demand as either)? Is it the actual generated energy minus actual or forecast Demand for
some period of time or at every moment? If the definition is based on capacity, this exclusion should
allow for the possibility that a larger than currently necessary generator may be installed in
anticipation of future load growth, so long as it is never used to generate significantly more than what
is needed for load. If actual generated energy is intended, the exclusion should provide for
inadvertent and/or de minimis power flows.

Individual
Bill Harm
PJM
Yes
Yes
Yes
No
As written I3 implies a contiguous system from the unit to a “common bus operated at a voltage
above 100 kV” there is no technical justification for a contiguous system. The requirement should
read “Multiple generating units located at a single site with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) including the generator terminals through the GSU“
No
Black start units are used to start other units to when the BES is compromised. There is no technical
justification to include all elements in the “cranking path” as BES facilities.
No
As written I5 implies a contiguous system from the unit to a “point a system element at a voltage
above 100 kV” there is no technical justification for a contiguous system. The requirement should
read “– Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a collector system through a common point of interconnection."
Yes
Yes
Yes
No
There is no technical justification to include/exclude elements based on the asset size of the owning
company. The exclusion should be based on the technical merits.
No
The bright line exclusion includes facilities that would normally be BES facilities but are excluded
based on the asset size of the owner.
No

Individual
Heather Hunt
New England States Committee on Electricity
Yes
The New England States Committee on Electricity (“NESCOE”) appreciates the work of NERC’s
standard drafting team as well as the opportunity to provide comments on the proposed Bulk Electric
System (“BES”) definition. The proposed revision to the BES definition could have significant impacts
on New England’s transmission grid and ratepayers. As NESCOE noted in prior comments to FERC on
this issue, NESCOE shares the interest in continually assessing means to improve system reliability.
Comments of the New England States Committee on Electricity, Docket Nos. RM 09-18 and RM10-6
(May 10, 2010). However, NESCOE is concerned that the definition, as proposed, may impose
substantial new costs on New England transmission owners. In NESCOE’s view, any new costs a
revised definition imposes – which fall ultimately on consumers - should provide meaningful reliability
benefits. NESCOE’s suggestions are intended to capture in the BES definition only those facilities
having a direct impact on the reliability of the BES and to ensure that costs imposed have attendant
reliability benefits. The concept of clarifying inclusions and exclusions is generally helpful. However,
the language needs to be refined and/or clarified further. One primary concern relates to sub
transmission networks. New England’s electric transmission system is comprised of networks operated
at voltages greater than 100 kV and at voltages less than 100 kV. The networks operated below 100
kV are referred to as “sub transmission” networks. They employ various operating voltages including
13.8 kV, 34.5 kV, 46 kV and 69 kV. NESCOE is concerned that the proposed BES definition and the
proposed Inclusions I1 through I5 may bring many elements (generators, transformers and lines) of
these sub transmission networks into the BES at substantial costs to New England ratepayers, without
providing meaningful reliability benefits. To address this concern, NESCOE suggests that the proposed
Inclusions be clarified to exclude generation connected to New England’s sub transmission networks
from the BES regardless of MVA rating. A second concern relates to the treatment of renewable
generation. NESCOE believes that renewable generation complexes, either multiple or dispersed,
should be granted flexibility regarding the Inclusion 3 rating threshold for inclusion in the BES. Finally,
while NESCOE is still assessing the impacts and necessity of inclusion I4, NESCOE suggests that black
start units and associated cranking paths not be considered BES. Please see further comments below.
Yes
Inclusion I1 now appears to exclude transformers that connect the BES to the sub transmission
networks (the sub transmission elements connected to one of the windings is less than 100 kV). This
suggests that the intent of this language is to exclude such transformers and all sub transmission
elements (unless included by the other Inclusion criteria) from the BES. With that understanding,
NESCOE supports Inclusion I1.
No
Inclusion Criteria I2 through I4 relate to generation connected with GSU High side voltages greater
than 100 kV and refer to generators with MVA limits exceeding either 20 or 75 MVA aggregate
depending on their configuration. It should be made clear that all generation connected to sub
transmission are not BES as these units are adequately covered under other applicable NERC and/or
regional reliability organization criteria. These units have no direct impact on the reliability of the BES.
This includes black start units because they do not directly impact normal or contingency operation of
the BES. These units and their associated cranking paths are used only for restoration and not
operation. Further, they are appropriately covered under regional restoration procedures and NERC
standards (see for example, Emergency Operating Procedure EOP-005-2). Use of varying generator
MVA thresholds as inclusion criteria under I2 and I3 could lead to inconsistent treatment of generation
facilities. For example, a generation facility with a single 30 MVA generator would qualify as BES
under I2. However, if an additional 30 MVA generator was added at the same site, the facility’s status
would change to non-BES under I3 even though the facility’s capacity had doubled. NESCOE is also
concerned that if the BES is required to be contiguous, the I2 threshold will result in many radial sub
transmission lines becoming BES, resulting in substantial costs without significant justifying benefits.
NESCOE suggests deleting Inclusion I2 or adopting a threshold that is consistent with I3, and which in
no event should be lower than 75 MVA. Regarding facilities connected at 100 kV and above, some
generation units in paper mills or other entities operating on the retail side of the meter may exceed
the Inclusion Criteria. The Exception Process, which will be the subject of future comments, should

provide some flexibility in this area. NESCOE further notes that in the case of radially connected
generation, the contiguous connection paths should not be BES even if the operating voltage is
greater than 100 kV. This is due to the fact that loss of a path has no greater impact than loss of the
connected generator. This is simply a first contingency loss that has no significant impact on the BES.
Inclusion I2 should be clarified to include only connections that impact the BES.
No
Please refer to comments under 3 above. Additionally, regardless of the connection voltage, the 75
MVA limit may unintentionally impose unnecessary added costs to renewable generation, thus
inhibiting the development of these resources. This is of particular concern to New England, which has
aggressive renewable energy objectives and is working to develop resources in and around the region
to meet them in the most cost-effective way. Looking forward, the exception process should provide
criteria allowing flexibility as to the aggregate MVA rating as related to the specific connection and
impact on a region. This will be discussed further in comments on the Exception Process as
appropriate.
No
Please refer to comments under 3 above. Black start units should be excluded from BES. These units
and their associated cranking paths are used only for restoration and not operation. Such units are
appropriately covered under regional restoration procedures and applicable NERC standards (see for
example, Emergency Operating Procedure EOP-005-2). NESCOE is still exploring the impact and
necessity of this proposed inclusion.
No
As noted in comment under 4 above, the 75 MVA threshold may unintentionally impose unnecessary
added costs that may ultimately be paid by New England ratepayers. The exception process should
provide flexibility as to total MVA rating. In addition, NESCOE believes this language should be
clarified to exclude collector systems and include only elements that actually impact the BES.
Yes
NESCOE generally supports these exclusions. However, NESCOE also notes that subsections (b) and
(c) could (depending on the final definition of Inclusions I2 through I5) sweep many sub-transmission
load serving elements into the BES, at a cost that is not justified in terms of reliability benefits.
Regarding sub transmission, Exclusion Criteria E1 and E2 are concerned with radial configurations
while E3 relates to Local Distribution Networks (LDN’s). None of these apply to sub transmission
networks that may contain both looped and radial configurations. Also, sub transmission networks
may have power flowing parallel to the BES and may have power flowing into the BES with no
potential for adverse impact on the reliability of the BES. Sub transmission networks operated at
voltages less than 100 kV, connected to the BES via non-GSU transformers, should be excluded from
the BES regardless of their configuration. It should be clear that all generation facilities connected to
sub transmission are not BES as these units are adequately covered under other applicable NERC
and/or regional reliability criteria. These units have no direct impact on the reliability of the BES.
Regarding facilities at operated at 100 kV and above, the switching configuration as defined is not
clear and possibly overly restrictive. The definition should incorporate language related to avoiding
”parallel paths” with diverse electrical nodes in the BES.
Yes
Please refer to comments in number 7 above. Additionally, there appears to be an inconsistency in
how generating units are expressed in E2 (net capacity) and in I2 and I3 (MVA).
Yes
NESCOE believes that this language appropriately excludes facilities that serve local distribution loads
from the BES.
No
This appears overly restrictive in that it only includes networks connected at a single source. Please
see comments under 7 above.
No
As stated in 1 above, NESCOE is concerned that the proposed definition may unintentionally
incorporate facilities into the BES that do not have a direct impact on the reliability of the system,
potentially imposing significant costs without meaningful reliability benefits.

Yes
A possible conflict exists with respect to state renewable resource objectives. Please refer to number
4 above regarding renewable energy objectives, which includes state legislation regarding renewable
portfolio standards.
As a general matter, the definition should reference the Exception Process, which may cause assets
and facilities to be further “included” or “excluded.” In particular, once a facility has qualified for
Exclusion it is not clear how that status is maintained.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
Yes
No
The reference to two windings is technically incorrect because it would exclude autotransformers
which technically only have one winding. Recommend rephrasing this to say that both the high-side
and the low side of the transformer connected at 100 kV or higher. I1 Suggested Language: “I1 Transformers, including phase angle regulators, with both the high-side and the low side of the
transformer connected at 100 kV or higher unless excluded under Exclusions E1 and E3.”
Yes
No
The ERCOT Region already considers load in any combination equal to and over 20 MVA through a
single Point of Interconnect as part of the BES
Yes
No
The ERCOT Region already considers load in any combination equal to and over 20 MVA through a
single Point of Interconnect as part of the BES
Yes
Yes
Yes
Yes
Yes
No

Individual
Charles Yeung
Southwest Power Pool
No
SPP generally agrees with the substance of the SDT’s changes, but suggests a different approach. In
order 743, to remedy its concerns, FERC suggested eliminating RE discretion in defining the BES, and
instead basing it upon a bright-line 100kV threshold, provided that elements above and below 100kV
could be excluded and included, respectively, based on specific procedures. Consistent with that
approach, SPP suggests that the BES definition itself establish a bright line standard, with inclusions
and exclusions managed through the exemption process. With respect to exclusions (and inclusions),

FERC contemplated a process involving stages that established “exclusion” criteria in the first
instance. If equipment met such criteria, the process ended there and it was exempt. If the
equipment did not meet the bright-line criteria, then it moved to the “exemption” analysis, which
contemplated additional critical analysis to determine if exemption was warranted. SPP believes that
structuring the revised definition in accordance with this approach is more consistent with FERC’s
intent of having an inclusive definition in the first instance, with modifications occurring subsequently
pursuant to critical analysis in a well defined exemption process. Revising the BES definition
consistent with the above principles would counsel in favor of revisions to the current definition that
removed RE discretion and provided for inclusion or exclusion on a case by case basis. SPP also
believes that the BES definition should provide for a general exclusion of distribution facilities. In
Orders 743 and 743-A, FERC made clear that, consistent with the terms of EPAct 2005, distribution
systems were excluded from the BES. However, FERC also made clear that it reserved the right to
judge whether something was distribution or transmission, and, therefore, subject to its jurisdiction.
Consistent with FERC’s findings in this regard, the SRC believes that the definition should provide the
general exclusion, with specific exclusions being performed as part of the exception process. This will
meet the goal of respecting Congress’ exclusion of distribution facilities, while ensuring the
distribution/transmission distinction is subject to clear, objective standards the application of which
can be critically reviewed by FERC to provide the appropriate procedural and substantive checks FERC
envisions to ensure its jurisdiction is applied in all relevant cases to facilitate enhanced system
reliability. However, consistent with the approach described above, the BES definition should not be
characterized in terms of inclusions or exclusions, but rather as general thresholds, with modifications
occurring solely pursuant to the exemption process. Applying the approach described above, the BES
definition would reflect general thresholds. Specific circumstances warranting
exclusion/exception/inclusion would occur via a separate process –SPP is not disagreeing with any of
the SDT’s inclusions or exclusions, it is merely suggesting that they be addressed in that separate
process. Consistent with this approach, SPP offers the following language: The Bulk Electric System
shall include: A) all Transmission Elements operated at voltages 100 kV or higher; B) all generation
resources that: 1) are individual units greater than 20 MVA; 2) multiple units at a single facility that
are equal to or greater than 75 MVA in the aggregate, provided that all units have a common point of
interconnection; and 3) multiple units connected to a collector system that are equal to or greater
than 75 MVA in the aggregate; 4) all Blackstart Resources regardless of size; and C) Reactive Power
resources connected at 100 kV or higher. The BES shall not include distribution facilities, and Radial
transmission facilities serving only load with one transmission source are generally not included in this
definition. The foregoing notwithstanding, any relevant element (e.g. transmission, generation, etc.)
may be identified as an exception and excluded or included in the BES pursuant to the process
delineated in the NERC Rules of Procedure and subject to the exclusion or inclusion criteria. All
equipment specific issues that affect exclusions/exceptions/inclusions would then be addressed via
the Rules of Procedure processes and the exclusion and inclusion criteria.
Yes
SPP agrees that such equipment should be included, but suggests that these issues be addressed in
the exception process. In other words, this inclusion doesn’t need to be explicitly identified. It would
simply be included under the general 100 kV threshold, and to the extent an owner believed the
characteristics of its equipment don’t warrant inclusion, it would seek an exception, which can be for
either an exclusion or an inclusion.
Yes
Please refer to SPP's response to question 1. but, consistent with the comments to question 1,
believes it should be reflected as part of the general definition, as opposed to inclusions/exclusions,
which should all be addressed pursuant to the separate processes.
Yes
Please see SPP's response to question 3 – SPP agrees with substance, but not the approach.
No
Please see SPP's response to question 3 – SPP agrees with the substance, but not the approach.
No
Please see SPP's response to question 3 – SPP agrees with the substance but not the approach.
No
Please refer to SPP's response to question 1 – while SPP does not necessarily disagree with the

substance of the proposed exclusions, it believes all exceptions, which may be either exclusions or
inclusions, should occur pursuant to the separate process and criteria being developed that will be
established in the NERC ROP. The BES definition should be more general in nature, focusing on
objective thresholds. All exclusions should be addressed in the separate proceeding being conducted
in parallel with this proceeding to develop the exception process, and SPP reserves its right to
comment on the substance of such proposals in that proceeding.
No
See response to question 7.
No
See response to question 7.
No
These entities should be subject to the exception process within the exclusion criteria. They warrant a
“first instance” exclusion in that process, but any such action should occur there, as opposed to the
definition of BES. SPP believes this is more consistent with FERC’s position that BES should reflect an
objective threshold, with exceptions being subject to review by the ERO and FERC, as applicable. It
may prove through that process that these entities receive the presumption of exclusion, but that
should take part in that process as opposed to being granted a de jure exemption from the definition.
Accordingly, SPP suggests that this issue be raised in the concurrent BES exception proceeding as an
exclusion criterion, and SPP reserves its right to comment on the substance in that proceeding.
No
See response to question 1 – SPP does not necessarily disagree with the characterization of excluded
distribution facilities, but believes that issue should be addressed in the concurrent BES exemption
proceeding for the reasons described in question 1. SPP reserves its rights to comment on the criteria
for exclusion/inclusion in that proceeding.
Yes
See SPP's response to question 1 – SPP believes defining BES in terms of the relevant exclusions may
be contrary to FERC’s suggested approach in 743 and 743-A. While FERC did not mandate a particular
approach, and gave the ERO the opportunity to propose an alternative to its suggested approach, it
stated that any alternative must be equal to or greater than its suggested approach in terms of
remedying the identified flaws associated with the current definition. Part of the remedy envisioned by
FERC included the removal of subjectivity in defining BES and the ability of the ERO and FERC to
review any proposed exemptions from the bright line definition. Although the exclusions strive to
apply objective criteria, it is arguable that any such circumstances may not be that clear and may
require some level of subjective judgment as to whether elements deemed to be distribution
according to the exclusion criteria actually are distribution, as opposed to transmission. In addition,
FERC expressly stated that it reserved the right to make that determination in the first instance. This
approach takes that away from FERC.
Group
Texas Industrial Energy Consumers (TIEC)
Katie Coleman

Yes
TIEC supports excluding radial loads serving only load or generation resources that do not trigger
NERC registration requirements. This is consistent with the FERC’s intent and the existing BES
definition. However, TIEC believes that this exclusion should not be contingent upon a radial system
“originating with an automatic interruption device” as proposed by the SDT. Radial feeds serving a
system that contains only load and generation that does not trigger registration requirements should

be categorically excluded from the BES definition regardless of whether the radial lines originate with
an automatic interruption device. It should be the responsibility of the transmission provider to
ensure that its facilities and interconnection properly protect the grid from facilities that fall under this
exclusion, just as the transmission providers do for other load and unregistered generation. The
absence of automatic interruption device should not trigger inclusion as a part of the BES, but should
trigger a requirement upon the transmission provider to install such a device on its side of the
facilities or take other measures to insulate the grid from the activities of a radial network.
Accordingly, TIEC would proposed to strike the phrase “originating with an automatic interruption
device” from the proposed exclusion language.
Yes
TIEC supports this exclusion with two clarifications. The language currently excludes generation on
the customer’s side of the meter as long at “the net capacity provided to the BES does not exceed the
criteria identified in Inclusions I2 or I3.” There are special circumstances in which an regional
Reliability Coordinator may ask that customer-owned generation export to its maximum capability
(i.e., with its load curtailed to the lowest level) in order to support grid reliability. Circumstances such
as this should not be considered in determining whether the “net” capacity exported to the BES
exceeds the threshold for registration. Additionally, there are often instances when customer-owned
generation and associated load are in start-up or shut-down processes that may cause the net export
to the BES to vary such that it temporarily exceeds the registration thresholds. Outlying situations
such as these should not trigger registration. Rather, the “net” capacity should be interpreted as the
typical amount exported during steady-state operation of the site. This interpretation of “net capacity”
should also apply to exclusions E1 and E3.
Yes
Proposed exclusion E3 should be revised to categorically exclude all facilities that are part of a local
distribution network (LDN), regardless of the specifics of the LDN’s interconnection with the Bulk
Electric System. As currently drafted, Exclusion 3 places a number of inappropriate limits on a
whether a local distribution system is excluded from the Bulk Electric System definition. As recognized
by the Commission in Order No. 743-A, Section 215 of the Federal Power Act categorically excludes
local distribution systems from the Bulk Power System definition without qualification. As a result,
LDNs are outside the FERC’s jurisdiction and are outside the scope of this rulemaking. The SDT should
revise the approach to Exclusion 3 to exclude all facilities that are part of a LDN, regardless of how
the LDN is interconnected to the grid. Specifically, making exclusion of an LDN contingent upon the
LDN being connected through automatic fault-interrupting devices is inappropriate. Similar to the
concerns TIEC expressed in response to Question 7, above, if there are concerns about LDNs
impacting the Bulk Electric System, then it is the responsibility of the transmission provider serving
the LDN to ensure that systems and facilities are in place to protect the grid. The specifics of an LDN’s
interconnection to the grid should not dictate whether it is subject to regulation. TIEC would therefore
recommend removing proposed qualification (a) to the LDN exclusion. Further, the requirement that
generation in the LDN can never exceed demand is inappropriate. As the SDT properly recognized in
Exclusion 2, as long as the generation within an LDN does not trigger registration requirements, the
LDN should be able to export power to the grid without subjecting itself to regulation. Many LDNs
export small amount of power intermittently to balance the flow within the LDN. Subjecting these
networks to regulation as a result of this balancing activity is inconsistent with the existing generation
registration requirements and would exceed the scope of this rulemaking. The existing generation
registration requirements exempt customer-owned generation that serves retail load from generation
registration requirements as long as the net capacity provided to the bulk power system does not
exceed the nameplate requirements for stand-alone generators. Consistent with this approach, an
LDN should not have to be registered as long as its net exports to the grid do not exceed the
generation registration requirements. TIEC accordingly requests that proposed LDN characteristics (c)
and (d) be removed as qualifications to the LDN exclusion, and that the exclusion be revised to allow
generation output to the grid as long the net export to the grid does not exceed the threshold levels
for registration as a generator owner/operator.
No
TIEC appreciates the SDT’s effort to identify situations where facilities rated above 100 kV should still
be categorically excluded from the BES definition This recognition is consistent with the concerns
raised by TIEC and many of its individual members in comments to the FERC in Docket RM09-18-000.

However, TIEC submits that the SDT’s approach to these exclusions should be revised to meet FERC’s
express recognition in Order No. 743-A that “facilities used for local distribution are excluded from the
Bulk-Power System definition under section 215, and thus are excluded from the bulk electric
system.” Order No. 743-A at ¶58. It is crucial that the BES definition is drafted in a way that
recognizes that it is the transmission provider’s responsibility to ensure that equipment is in place to
protect the BES from the operations of excluded facilities, not the responsibility of a person owning
facilities involved in the local distribution of electricity. These issues are addressed in further detail in
response to the specific exclusions.

Individual
Geoff Carr
Northwest Requirements Utilities
No
As a general matter, Northwest Requirements Utilities (NRU) supports the approach the Standards
Development Team (“SDT”) has taken to defining the Bulk Electric System (“BES”). The changes
made in the revised core definition are helpful and represent significant progress toward an
acceptable definition. With an effective and efficient exclusion process, the draft will better define the
BES as a whole. We urge the SDT to bear in mind the restrictions contained in Section 215 of the
Federal Power Act (“FPA”) The “bulk-power system” (As per FERC, we treat the statutory term “bulkpower system” as equivalent to the term ordinarily used in the industry, “Bulk Electric System”)
definition imposes a clear limit on the reach of the mandatory reliability regime. The BES is made up
of only those “facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof)” and “electric energy from generation facilities needed
to maintain transmission system reliability.” Congress reinforced that limit in Section 215(i), where it
emphasized that the FPA authorizes the imposition of reliability standards “for only the bulk-power
system.” NRU is concerned that the SDT’s proposed definition is overly-broad, and that it will sweep
in many Elements that have little or no material impact on the reliable operation of the interconnected
bulk transmission grid. For example, the definition uses the arbitrary 20 MVA threshold from the
NERC Statement of Registry Criteria for inclusion of generators. Accordingly, for the BES definition to
conform to the requirements of the statute, the SDT must adopt an effective mechanism to exempt
facilities like these that are improperly swept in by the SDT’s brightline approach to inclusions and
exclusions. For this reason, the Exception process to accompany the SDT’s definition is of critical
concern. If the SDT incorporates this statutory language as its core definition, it will have addressed
FERC’s primary concern with a minimum of disruption to the current NERC system of definitions. The
definition could then be further elaborated to show specific points of demarcation for each inclusion
and exclusion similar to that Proposal 6 from the WECC Bulk Electric System Definition Task Force
(“BESDTF”) team to further delineate BES and non-BES facilities.
No
In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and nonBES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is
stepped down from transmission voltages to distribution voltages. We believe, however, that the SDT
should undertake the effort to more clearly define the point where the BES ends and non-BES
systems begin. In this regard, we note that the WECC Bulk Electric System Definition Task Force
(“BESDTF”) has devoted considerable effort to this question and has developed one-line diagrams
noting the BES demarcation point for a number of different kinds of Elements that are common in the
Western Interconnection. Using this work as a starting point, the SDT should be able to provide much
useful guidance to the industry with relatively little additional effort. Also, the reference to “two
windings of 100 kV or higher” may create some confusion because many three-phase transformer
banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We suggest
clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”
We again urge the SDT to consider further delineation of points of demarcation similar to WECC
BESDTF Proposal 6.
No
Northwest Requirements Utilities is concerned that I2 inclusion criteria that includes the arbitrary 20

MVA threshold from the NERC Statement of Registry Criteria for inclusion of generators is overinclusive. Under FPA Section 215, generation resources are excluded from the “bulk-power system”
unless they produce “electric energy” that is “needed to maintain transmission system reliability.”
Hence, the inclusion as drafted improperly expands the BES definition to include generators that the
statute requires to be excluded. In the same comments, the SDT also states that it has considered
“the inclusion of generator step-up (GSU) transformers and associated interconnection line leads and
believes the BES must be contiguous at this level in order to be reliable.” Unfortunately, the SDT
appears to have concluded that any interconnection facility operating above 100-kV should be
classified as BES. The result will be to require Generation Owners to register as Transmission
Owners/Operators, as well, producing substantial additional compliance costs for those Generation
Owners but resulting in little or no improvement in the reliability of the BES. We recommend that the
SDT, like the Project 2010-07 SDT (commonly referred to as the GO/TO Team), give careful
consideration to the practical results of its recommendations rather than relying on abstract
conclusions about whether a “contiguous” or “non-contiguous” BES is more desirable. We are
concerned that the SDT’s pursuit of a “contiguous” BES will result in a substantially over-inclusive BES
definition. The “contiguous” BES concept implies that every Element arguably necessary for the
reliable operation of the interconnected bulk system must be included in the BES definition, even if it
is interconnected with Elements that have no bearing on the operation of the BES. NERC’s Standards
Drafting Team for Project 2010-07, has already considered this question and, based on an in-depth
review of potentially applicable reliability standards, has concluded that generation interconnection
facilities, even if operated above 100-kV, need to comply only with a limited set of reliability
standards in order to achieve the reliability goals. Much of the work of the Project 2010-07 SDT is
applicable to the work of the BES Standards Development Team. For example, the Project 2010-07
Team observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to Transmission
Owners and Transmission Operators who own and operate transmission Facilities and Elements that
are part of the integrated bulk power system.” Similarly, a “contiguous” BES suggests that, because
certain system protection facilities, such as UFLS relays, are ordinarily embedded in local distribution
systems, the local distribution system, along with the UFLS relays, must be classified as BES to make
the BES “contiguous.” Such a result is not only plainly contrary to the local distribution exclusion
embedded in Section 215 of the FPA, but would, by improperly classifying local distribution lines as
BES “Transmission” facilities, result in huge regulatory compliance burdens with little or no
improvement in bulk system reliability.
No
Northwest Requirements Utilities is concerned that the 75 MVA threshold has been chosen arbitrarily
by the SDT. Like the 20 MVA threshold discussed in our response to question 3, the 75 MVA threshold
appears to have been drawn from the NERC Statement of Compliance Registry without appreciation
for the function of the threshold in that document and without adequate technical justification
demonstrating the generators with an aggregate capacity of 75 MVA produce electric energy “needed
to maintain transmission system reliability” and are therefore properly included in the BES definition.
Yes
Including “all” blackstart and blackstart cranking paths in the BES may ultimately provide an incentive
to the electric industry to reduce the number of resources with blackstart capability. We therefore
suggest that essential blackstart resources identified by the Regional Entity should be included in the
Bulk Electric System, but non-essential blackstart resources need not be.
No
Northwest Requirements (NRU) agrees that it is important to address wind generation facilities and
similar generation facilities in which a large number of generating units, each with a relatively small
capacity, are clustered and fed into the grid at a single interconnection point. That being said, NRU is
concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained. We believe the exclusion as drafted adequately defines radials.
No
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through

reference to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the
generation unit is reliability-must-run or essential blackstart, the function of the unit is irrelevant to
the reliable operation of the interconnected bulk transmission grid, and we therefore believe the
reference to the function of the generation unit (“standby, back-up, and maintenance power…”)
should be eliminated.
Yes
Northwest Requirements Utilities (NRU) strongly supports the categorical exclusion of Local
Distribution Networks from the BES. In fact, for reasons discussed at length in our answer to Question
1, we believe the exclusion is necessary to ensure that the BES definition complies with the statutory
requirement to exclude all facilities used in the local distribution of electric power. LDNs are, of
course, probably the most common kind of local distribution facility. Further, the conversion of radial
systems to local distribution networks should be encouraged because networked systems generally
reduce losses, increase system efficiency, and increase the level of service to retail customers. NRU
supports the LDN exclusion, but we believe the exclusion should be refined in the following respects:
• The SDT’s draft states that: “LDN’s are connected to the Bulk Electric System (BES) at more than
one location solely to improve the level of service to retail customer Load.” (emphasis added) We
recommend that the SDT revise the sentence quoted above as follows: “LDN’s are connected to the
Bulk Electric System (BES) at more than one location solely to improve the level of service to retail
customer Load and not to accommodate bulk transfers of power across the interconnected bulk
system.” By instituting this suggestion, the SDT would emphasize the key difference between an LDN,
which is designed to reliably serve local, end-use retail customers, and the BES, which is designed to
accommodate bulk transfer of power at wholesale over long distances.
Yes
Northwest Requirements Utilities supports the SDT in its efforts to avoid unintended consequences
from changes to the BES definition, especially for small entities that can ill afford the substantial costs
that accompany imposition of mandatory compliance with reliability standards. Further, we agree that
the small utilities covered by the exemption will have no measurable impact on the operation of the
interconnected BES. In the Pacific Northwest, many small entities were required to register by virtue
of owning a very small portion of the region’s 115-kV system. These utilities have faced substantial
compliance burdens even though their operations are simply not material to the interconnected bulk
grid in our region, and the investment of resources in compliance therefore will have no measurable
effect in improving the reliability of the interconnected grid.
No
While Northwest Requirements Utilities (NRU) agrees that the approach adopted by the SDT -- a core
definition coupled with specific inclusions and exclusions – will be effective in removing most local
distribution facilities from the BES, it will not remove all such facilities. For the reasons discussed at
greater length in our answer to Question 1, NRU believes that the proposed definition is over-inclusive
and is likely to sweep up certain facilities used in local distribution that should not be classified as
BES. As discussed in our answer to Question 3, NRU notes that exclusion of facilities from the BES
does not mean that owners of those facilities are entirely exempt from reliability standards. On the
contrary, the statute provides that “users” of the BES can be subject to reliability regulation. Hence,
even where an entity does not own BES assets, it could be required to, for example, provide
necessary information to the applicable Reliability Coordinator and to participate in the regional
Under-Frequency Load Shedding program by setting the UFLS relays in its Local Distribution Network
at the appropriate settings. We note that participants in the WECC BESDTF Task Force generally
agreed that appropriate information should be provided by non-BES entities, although there was
considerable concern related to ensuring that the provision of information was not unduly
burdensome.
Yes
The Exceptions process is a necessary part of making this proposal complaint with the Federal Power
Act. As noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is
potentially in conflict with the limitations of the Federal Power Act, and in particular the statutory
exclusion for facilities used in the local distribution of electric energy. The SDT’s approach can meet
the statutory requirements only if the Exception process currently under development results in
facilities that are not properly classified as BES being exempted from regulation as BES facilities.
Northwest Requirements Utilities (NRU) has these additional concerns: • The current definition

provides that “Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.” NRU is concerned that the SDT carefully delineate which entity has the
burden of proof in the exclusion process. The WECC BESDTF approach, which we commend to the
SDT, laid out these burdens in some detail. Under that approach, essentially, if a facility is excluded
from the BES by virtue of the specific exclusions listed in the definition, the Regional Entity bears the
burden of proving that the facility nonetheless has a material impact on the interconnected bulk
transmission system and therefore should be included in the BES. On the other hand, if a facility is
classified as BES by virtue of the list of inclusions set forth in the BES definition, it can still escape
classification as BES, but bears the burden of demonstrating that its facility has no material impact on
the interconnected transmission system. We urge the SDT to give careful consideration to these
burden-of-proof questions and to follow the lead of the WECC BES Task Force. • For the reasons we
have explained in our answer to Question 11, we believe the Exception process is critical both to
ensure that the BES definition is effective in producing measurable gains to bulk system reliability and
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence,
we believe the entire BES definition, including the Exception process and related procedures, should
be vetted through the NERC Standards Development Process, including the full comment periods and
a ballot approvals provided for in that process. We are concerned that important elements of the BES
definition have been assigned to the Rules of Procedure Team, and that changes in the Rules of
Procedure are subject to approval in a process that provides considerably less due process and
industry input than the Standards Development Process. Accordingly, we urge that all elements of the
BES definition, including those elements that have been assigned to the Rules of Procedure Team, be
vetted through the Standards Development Process.
Individual
Jonathan Appelbaum
United Illuminating
The definition should incorporate the language in Energy Policy Act of 2005 that defines bulk power
system. UI agrees in general that facilities operated at 100 kV and above are part of bulk power
system. Without the clarification in the definition the possibility of facilities that are not necessary for
the operation of the interconnected transmission will be pulled into scope.
No
Inclusion I1 is an attempt to limit the scope of the core definition to only those transformers with a
high and low side connection at or above 100 kV. However it is not clear that a transformer connected
solely on the high side at 100 kV, that is a distribution transformer, is not included in the BES by the
definition. This is because the core definition includes all transmission elements connected at 100 kV,
this would include the distribution transformer. Then Inclusion I1 does not eliminate the distribution
transformer explicitly. It is only implied that the core definition applies only to those transformers
with a high and low side connection at or above 100 kV. UI would prefer a more explicit description.
Such as: I1- Only those Transformers, including phase angle regulators, with two windings of 100 kV
or higher unless excluded under Exclusions E1 and E3 are included in the definition of BES. Generator
Step Up Transformers are included based on the generator. A similar comment can be made for the
other inclusions. An alternative solution is to change word Inclusions to a sentence that explicitly
states: for the category of element below only include the type of equipment specified. Also The use
of the descriptor two windings implies auto transformers with one winding is excluded. UI
understands that is not the intent of the team.

UI suggests the following change to E1 eliinating the automatic device: Any radial system which is
described as connected from a single Transmission source. These taps are not necessary for the
opeation of the interconnected system.

No

The core definition should state that local distribution facilities are not included.

Group
Electricity Consumers Resource Council (ELCON)
John P. Hughes
Yes
We support the expanded structure of the core definition that provides for inclusions and exclusions.
This clarification establishes a rebuttable presumption that excluded elements are not BES and
appropriately shifts the burden of proof for any subsequent inclusion to Regional Entities or the ERO,
thereby minimizing the regulatory burden on the industry, an outcome consistent with the
Commission’s stated assumption that revising the BES definition should have relatively minor impacts
on registrations in non-NPCC regions.
No
Although the BES Standards Drafting Team has stated that it will not propose changing the 20MVA/75-MVA thresholds, we think the thresholds should be set based on the BA/RC needs in each
area and that a suggested range (perhaps by taking a survey of the operational entities) should be in
the new BES Definition. Having an arbitrary and capricious number in the new BES Definition just
because it is in the current Statement of Compliance Registry Criteria, and requiring significant
technical justification for change, does not seem appropriate when so many expert industry
commenters have indicated the existing thresholds are too low to be operationally significant.
No
Same response as item 3 above.
Yes

No
The existing language in the NERC Statement of Compliance Registry for radial exclusions should be
maintained since the change proposed by the SDT could result in a significant increase in entities
and/or facilities that would have to be registered or included (because of the addition of the automatic
interruption device). The burden for proving the need for such significant changes should be placed on
the ERO and the Regional Entities through the BES Exception Process, not on the users of the BES. In
particular, it could force retail load (customers) to register as transmission owners, or engage in other
maneuvers to avoid registration, when this is clearly a transmission owner/customer issue (as to
whether to install automatic interruption devices). These lines are non-jurisdictional and are obvious
under the purview of the state commissions.
Yes
No
There are two different types of LDN: utility owned and customer owned. They should not be treated
the same. Criteria (a) through (e) in Exclusion E3 may be appropriate for distinguishing between
utility-owned LDN and utility-owned BES transmission often owned and operated by the same
integrated utility. A separate, stand-alone exclusion criteria should be established for customer-owned
elements that serve to distribute electric energy to on-site loads, including all or part of the electric
energy from behind-the-meter generation. Thus, E3 criteria (a) through (e) would apply exclusively to
utility-owned elements. For customer-owned elements, the new criterion (f) might read: "Or the LDN
is also characterized by: "f) The Elements are customer owned and used to distribute electric energy
to on-site loads, including all or part of the electric energy from behind-the-meter generation." See
response to #11 below for further justification for this recommendation.
No
We support the concept and intent of the exclusion but it should apply equally to similarly situated
loads such as manufacturing facilities that have loads comparable to small municipalities or rural

cooperative utilities. Thus the language should be amended as noted below: "Exclusion E4:
Transmission Elements, from a single Transmission source connected at a voltage of 100 kV or
greater, owned by a small utility or similarly situated load whose connection to the BES is solely
through this single Transmission source, and without interconnected generation as recognized in the
BES Designation Inclusion Items I2, I3, I4, or I5. A small utility or similarly situated load is
recognized as an entity that performs a Distribution Provider or Load Serving Entity function but is not
required to register as a Distribution Provider or Load Serving Entity by the ERO."
No
Section 215 of the Federal Power Act denies FERC jurisdiction over facilities used in the local
distribution of electric energy. FERC has recognized that since facilities used in the local distribution of
electric energy “are exempted from the Bulk-Power System, they also are excluded from the bulk
electric system.” Section 215 of the Federal Power Act does not qualify the exclusion from FERC
jurisdiction of “facilities used in the local distribution of electric energy.” For example, Section 215
does not state that: --The term “bulk power system” “does not include facilities used in the local
distribution of electric energy [unless needed for reliability purposes];” or --The term “bulk power
system” “does not include facilities [with automatic interruption devices] used in the local distribution
of electric energy.” Any definition of the bulk electric system that does not exclude all “facilities used
in the local distribution of electric energy” is unlawful. Further, the definition of the bulk electric
system must recognize that Section 215 of the Federal Power Act does not allow the potential
reliability impact of a facility to determine whether the facility is local distribution or transmission. By
excluding all facilities used in the local distribution of electric energy from the definition of the BulkPower System in Section 215, Congress recognized that while facilities used in the local distribution of
electric energy may be part of the Bulk-Power System, they are, nonetheless, not FERC jurisdictional.
Thus, “facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof)” that are used in the local distribution of electric energy
are not FERC jurisdictional regardless of the potential reliability impact of the facilities.
Yes
See response to question 11 above. The definition of “local distribution” should be as defined and
practiced in each state (US only) under state laws and regulations, and similarly by the Canadian
provincial governments.
Group
Central Maine Power Company
Brian Conroy
Yes
No
By definition above, a transformer with a 100 kV winding is already an “element operated at 100 kV
or above.” This inclusion is actually intended to exclude transformers with only one winding operated
at 100 kV or higher voltage. Therefore, Inclusion I1 should be deleted and a new Exclusion should be
made: “Transformers with only one winding of 100 kV or higher, including phase angle regulators,
unless included under Inclusions I2, I3, or I5.”
Yes
lease note that this departs from NERC’s Registry Criteria in that the unit of measurement is MVA
instead of MW.
Yes
Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is MVA
instead of MW.
No
Inclusion I4 should be stricken for several reasons: 1. The SDT states that “One of the basic tenets
that the SDT is following is to avoid changes to registration due to the revised definition if such
changes are not technically required for the definition to be complete.” Adding every black start
generator and the designated cranking path is not technically required. All significant black start
generation is already included in I2 and I3 and I5. 2. The NERC Compliance Registry notes that not

every generator that is a blackstart unit is “material” – it may not be necessary to the restoration
plan or to bulk power system reliability. 3. There is already an existing standard to ensure reliability
of blackstart performance. NERC Reliability Standard EOP-005-2 ensures that the facilities critical to
system restoration are functional when needed. 4. In CMP’s case, there are two generator locations
which are part of the Black Start capability, and they are small hydroelectric stations connected to our
34.5 kV transmission system. Under this inclusion, these small hydroelectric stations and 34.5 kV
paths would inappropriately be classified as BES. Other, critical blackstart facilities are already
included in the BES definition without I4.
Yes
Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is MVA
instead of MW.
No
The definition of radial needs to be clear and comply with Order 743. We do not know what a radial
“system” is. Also, “automatic interruption device” is not defined. This exclusion includes “radial”
“systems” with more than one supply from a single “source” – including normally-open switches, even
those which are intended to be normally closed before further switching takes place (“make-beforebreak”). This seems to be a problem, per Order page 32. We suggest a compliant and straightforward
“radial” exclusion, and recommend that E1 be replaced with, “Those Transmission Elements
interconnected to only one other substation through only one transmission line; except those
elements included in I2, I3, and I5.” It is clear and it can be applied in a “bright-line”, consistent
fashion.
No
E2 refers to “net capacity provided to the BES” (which seems to be a flow on an interconnection, not
generator capacity), yet I2 and I3 refer to generator MVA. These are not the same unit which leads to
inconsistency. This Exclusion appears to add confusion or additional criteria to that of the Compliance
Registry. We recommend that E2 be stricken.
No
This exclusion is vague, but needs to be clear and comply with Order 743. Also, “distribution” is
already excluded from transmission and therefore “BES.” Also, E1 refers to “automatic interruption
device” and E3 refers to “automatic fault interrupting device”, neither of which are defined. We think
that large portions of the network may be inappropriately excluded under this exclusion and exclusion
E3 should be deleted.
No
This exclusion E4 seems to already be covered under the E1 “radial” exclusion.
No
Transmission and distribution facilities are already mutually exclusive and are already classified and
reported in FERC Form 1. The SDT definition may have rolled in considerable portions of the
distribution system for consideration as BES. A small generator that is entered into the black start
program would make the complete cranking path BES. As documented previously this inclusion of
immaterial generators and subsequently their distribution cranking paths is at odds with the
Compliance Registry.
No
No.
Individual
John Cummings
PPL Energy Plus and PPL Generation
No
See the response to Question 13
No
See comments in Question 13.
No

See comments in Question 13

No
See comments in Question 13
No
See comments in Question 13.

Yes
See comments in Question 13.
The BES definition strives to draw a line between transmission customers (load and generation) and
the “network” that makes up the bulk electric system. All transmission customers served by the
network are not necessarily part of the network just like an on-ramp is not part of the Interstate
highway, even though on-ramps deliver cars to the Interstate highway. FERC Order 743 paragraph
115 clearly gives guidance to the NERC BES Definition Team (BESDT) on developing fair exclusion
criteria for facilities not necessary for the operation of the grid. PPL Generation and PPL Energy Plus
(PPL) are concerned that the FERC order is being read overly expansively to include much more
generation in the BES than FERC intended. In the NERC BESDT's latest proposed version of a BES
definition, the definition appears to apply to small radial generators (Inclusions I2 and I3) but not to
large radial loads (Exclusions E1 and E3). The BESDT has chosen to exclude or include LDNs based
solely on the direction of power flow (see for example Exclusion E3-c) when the magnitude of the
power flow is more critical than the direction. An example of the stark contrast between treatment of
looped and radial facilities is exemplified by the exclusion of looped load and generation facilities of
almost any size (Exclusion E3) from the BES, versus the seeming omission of any effort to exclude
radially connected generation facilities over 20 MVA. Clearly, FERC Order 743-A paragraph 55
instructs the BESDT to consider “additional facility characteristics” other than voltage to come up with
a fair inclusion/exclusion process. The exclusion of looped facilities serving load and generation and
the inclusion of radial facilities serving only generation does not appear consistent. Moreover, it
ignores the physical reality that radial generator lead lines cannot be overloaded by outages on
parallel paths because there are no parallel paths. Further, the MW flow on a radial line is well known
and limited to a known maximum (limited to the larger of the generation or load on the end of the
line): clearly reasons for exclusion. The BESDT should look carefully at FERC Order 743 paragraph 73
which describes the characteristics of the electrical network that the BES is trying to define. In that
order, FERC justified its bright-line, 100 kV threshold, explaining that "many facilities operated at 100
kV and above have a significant effect on the overall functioning of the grid" because they share the
following characteristics: 1. "operate in parallel with other high voltage and extra high voltage
facilities" i. The “bright line” at 100 kV recognizes many 100 kV lines parallel other HV/EHV lines and
can be significantly loaded by failure of the HV/EHV lines. This does not apply to radial lines, even at
100 kV and above. 2. "interconnect significant amounts of generation sources" 3. "operate as part of
a defined flow gate" 4. have a "parallel nature" and are capable of “caus[ing] or contribute[ing] to
significant bulk system disturbances”. i. Radial lines cannot cause significant BES disturbances since
the outage of a radial line is studied in all N-1 planning studies and if the TPL standards are followed,
an N-1 should not cause such disturbances. To their credit, the BESDT recognizes part of paragraph
73 in Exclusion E3-d and E3-e (possibly exempting many hundreds of MVA load) but yet fails to
exclude radial lines serving generators from the BES “network”. Generation should be excluded from
the definition of the BES on the same basis as load. PPL requests the BESDT clearly exclude radial
generators up to 200 MVA (1200 amps at 100 kV). This exclusion is clearly justified because it would
recognize many (if not all) loads and generators served radially do NOT possess the Network
Transmission Facilities characteristics described in FERC Order 743 paragraph 73. PPL hopes that the
NERC BESDT will recognize (as FERC Order 743 in paragraph 120 recognizes) that radial facilities and
distribution facilities can both be excluded.
Individual
Joe Petaski

Manitoba Hydro
Yes
We recommend that the definition be prefaced with the statement ‘except where provided otherwise
by applicable law…’
No
Inclusion I1 requires clarification. The intention of I1 is to include transformers that have both their
primary and secondary windings operated at 100kV and the wording in I1 should reflect this.
Requiring that only ‘two windings’ must be connected at 100kV or greater for inclusion is not
sufficient in the case of 3 separate single phase banks connected to form a delta-wye connection for
example. As currently written, even if only the primary windings of this bank were connected at
greater than 100kV, this transformer would be included in the BES regardless of the secondary
voltage. -Suggested wording: “Transformers, other than Generator Step-up (GSU) transformers,
including Phase Angle Regulators, that are connected at 100kV or above on their primary and
secondary windings unless excluded under Exclusions E1 and E3. OR “Transformers, other than
generator step-up (GSU) transformers, including phase angle regulators, with two windings of 100 kV
or higher in the same phase unless excluded under Exclusions E1 and E3.”
Yes
No
It is not clear if this inclusion only applies if the generators at a single site have an aggregate capacity
greater than 75 MVA AND are connected through a common bus operated at 100kV or if the inclusion
applies if the generators at a single site have an aggregate capacity of over 75MVA regardless of
whether or not they are connected through a common bus operated at 100kV or above. For example,
would this inclusion apply if a utility has over 75MVA at single generating site but only a small portion
of the generating capacity is connected through the GSU to a common bus at 100kV or above and the
rest is connected through a common bus operating at less than 100kV? Suggested wording: “Multiple
generating units located at a single site connected to a common bus operated at a voltage of 100kV
or above with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) including
the generator terminals through the GSUs.
No
Inclusion I4 should be modified so that only the Blackstart Resources and designated Cranking Paths
required for compliance with the NERC Emergency Preparedness and Operations Standards are
included in the BES Definition.
Yes
Yes
No
It is not clear what is meant by “retail Load”. This is not a NERC defined term. Additional detail is
required.
No
Exclusion E3 needs to be strengthened to ensure that the LDN will have no impact on the BES. The
protective elements preventing the LDN from impacting the BES should be included in the BES. As
well, the term Local Distribution Network (LDN) should be defined as a separate NERC Glossary term,
instead of being defined in the BES definition.
No
Small utilities should be excluded under the definition of the BES without requiring an additional and
specific exclusion.
Yes
Yes
Canadian Entities are not under FERC jurisdiction, so the revised BES Definition may not apply. A
number of Canadian Entities have the BES defined within their provincial legislation. This may

introduce differences and even contradictions between elements that are included in the BES
according to provincial legislation and the NERC definition.
Manitoba Hydro supports a 100kV bright line definition of the BES (excluding radial systems) that is
consistent across all regions. We do not agree with the proposed impact based exception procedure
and believe that the BES definition should be stand-alone. In addition, the complexity of the proposed
BES definition and associated exception process may not provide the goal of uniform application of
the BES definition and moves the burden of assessment and approval to the ERO.
Individual
Kathleen Goodman
ISO New England, Inc.
Yes
This definition does not indicate that there may be other "inclusions" and "exclusions" for which an
entity has to seek ERO/RRO approval. Therefore our recommendation is that this definition be
modified to resolve this concern. This questionnaire contains information as part of the definition
description that is different from the draft Implementation Plan and definition of Bulk Electric System
document, specifically the entirety of E4 is included in the questionnaire but in neither of the other
two documents; this may lead to confusion by commenters.
Yes
Yes
Yes
No
The SDT states that “One of the basic tenets that the SDT is following is to avoid changes to
registration due to the revised definition if such changes are not technically required for the definition
to be complete.” However, adding every black start generator and the designated cranking path to
the definition of the BES is at odds with the Statement of Compliance Registry Criteria which states:
III.c.3 Any generator, regardless of size, that is a blackstart unit material to and designated as part of
a transmission operator entity’s restoration plan, or; The SDT should use the registry language in
order to not expand the BES to every cranking path on the distribution system from a small generator
entered into the black start program. Furthermore, the SDT cannot simply disregard voltage level,
because: (a) FERC Order 743 expresses preference for a bright line definition, and (b) Section 215 of
the Federal Power Act defines the “bulk-power system” as, in part, “electric energy from generation
facilities needed to maintain transmission reliability”. As the NERC Compliance Registry has long
recognized, not every generator that is a blackstart unit is “material” – i.e., may not be necessary –
to the restoration plan or, therefore, to bulk-power system reliability.
Yes
No
The definition of radial needs clarification; we suggest “fed from a single transmission source, i.e. fed
from a single substation at a single voltage”. It is clear and it can be applied in a “bright-line”,
consistent fashion. As currently drafted, if the interruption device is not automatic, E1 would not
exclude tapped “radial - i.e. single fed” equipment. Does the SDT mean to imply that even
transformers which do not have an automatic interruption device on the high side, but have low
voltage side at lower than 100 kV, will be considered part of the BES? If so, is the BES considered to
extend to where the circuit has an automatic interruption device? Would the bus conductor and leads
to the high side of the transformer be BES? This would not be acceptable if the answer is yes. It is
important to keep in mind that the in the instance of a radial line served via a tap, the system needs
to be designed for loss of the line in any event and requiring an automatic switching device is not
necessary. In short, the term radial should be better defined and the requirement for an automatic
interruption device should be eliminated.
No
E2 refers to net capacity and yet I2 and I3 refer to MVA. These are not the same unit which leads to

inconsistency. This Exclusion appears to add additional criteria than that of the Compliance Registry;
we suggest simply using the language from the Compliance Registry.
No
We think that large portions of the network may be inappropriately excluded under this exclusion and
the exclusion should be deleted. If E-3 is retained, then it is recommended that the SDT change the
sentence “LDN’s are connected to the Bulk Electric System (BES)” to “LDN’s include transmission
connected to the Bulk Electric System (BES)...” An Automatic Interruption device needs to be defined.
For example, Iis a fuse an Automatic Interruption device? The definition needs clarification in the
phrase: Power flows only into the Local Distribution Network: The generation within the LDN shall not
exceed the electric Demand within the LDN; Should this be “Net power …”? One transmission path
could be exporting power but the net sum of all paths would always be importing power.
No
This exclusion would not be required if the automatic disconnect requirement was removed from E1.
If E1 is not modified as proposed herein then a MW threshold might have to be considered for this E4
definition. E4 should have also been included in the draft definition as well as this comment form.
No
The SDT definition will unnecessarily roll in portions of the distribution system for consideration as
BES. A small generator that is entered into the black start program would make the complete
cranking path BES. As documented previously this inclusion of immaterial generators and
subsequently their distribution cranking paths is at odds with the Compliance Registry.
Yes
The proposal to include all Blackstart units’ cranking paths has the potential to roll into the BES
facilities distribution level circuits. Inclusion of those circuits would appear to conflict with statutory
exclusion of set out in Section 215(a)(1) of the Federal Power Act, which states that the term “bulk
power system”: “does not include facilities used in the local distribution of electric energy.” Section
215 sets the limits on what may be included within the bulk electric system, and thus subject to
regulation by the ERO and FERC under the reliability standards regime.
None.
Group
New York State Electric & Gas and Rochester Gas & Electric
John Allen
Yes
No comments
No
By definition above, a transformer with a 100 kV winding is already an “element operated at 100 kV
or above.” This inclusion is actually intended to exclude transformers with only one winding operated
at 100 kV or higher voltage. Therefore, Inclusion I1 should be deleted and a new Exclusion should be
made: “Transformers with only one winding of 100 kV or higher, including phase angle regulators,
unless included under Inclusions I2, I3, or I5.”
Yes
Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is MVA
instead of MW.
Yes
Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is MVA
instead of MW.
No
Inclusion I4 should be stricken for several reasons: 1. The SDT states that “One of the basic tenets
that the SDT is following is to avoid changes to registration due to the revised definition if such
changes are not technically required for the definition to be complete.” Adding every black start
generator and the designated cranking path is not technically required. All significant black start
generation is already included in I2 and I3 and I5. 2. The NERC Compliance Registry notes that not
every generator that is a blackstart unit is “material” – it may not be necessary to the restoration
plan or to bulk power system reliability. 3. There is already an existing standard to ensure reliability

of blackstart performance. NERC Reliability Standard EOP-005-2 ensures that the facilities critical to
system restoration are functional when needed.
Yes
Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is MVA
instead of MW.
No
The definition of radial needs to be clear and comply with Order 743. We do not know what a radial
“system” is. Also, “automatic interruption device” is not defined. This exclusion includes “radial”
“systems” with more than one supply from a single “source” – including normally-open switches, even
those which are intended to be normally closed before further switching takes place (“make-beforebreak”). This seems to be a problem, per Order page 32. We suggest a compliant and straightforward
“radial” exclusion, and recommend that E1 be replaced with, “Those Transmission Elements
interconnected to only one other substation through only one transmission line; except those
elements included in I2, I3, and I5.” It is clear and it can be applied in a “bright-line”, consistent
fashion.
No
E2 refers to “net capacity provided to the BES” (which seems to be a flow on an interconnection, not
generator capacity), yet I2 and I3 refer to generator MVA. These are not the same unit which leads to
inconsistency. This Exclusion appears to add confusion or additional criteria to that of the Compliance
Registry. We recommend that E2 be stricken.
No
This exclusion is vague, but needs to be clear and comply with Order 743. Also, “distribution” is
already excluded from transmission and therefore “BES.” Also, E1 refers to “automatic interruption
device” and E3 refers to “automatic fault interrupting device”, neither of which are defined. We think
that large portions of the network may be inappropriately excluded under this exclusion and exclusion
E3 should be deleted.
No
This exclusion E4 seems to already be covered under the E1 “radial” exclusion.
No
Transmission and distribution facilities are already mutually exclusive and are already classified and
reported in FERC Form 1. The SDT definition may have rolled in considerable portions of the
distribution system for consideration as BES. A small generator that is entered into the black start
program would make the complete cranking path BES. As documented previously this inclusion of
immaterial generators and subsequently their distribution cranking paths is at odds with the
Compliance Registry.
No
No additional comments.
Individual
Manny Robledo
City of Anaheim
Yes
I1: Change the "and" to an "or" at the end of the sentence, i.e. Exclusions E1 or E3. E3 (b): Use the
same language in E1 (b), i.e. Only including generation resources not identified in Inclusions I2, I3,
I4, and I5.
Yes
Change the "and" to an "or" at the end of the sentence, i.e. Exclusions E1 or E3. This appears to be
the intent.
Yes
Yes

Yes
Yes
Yes
Yes
Yes
In E3 (b) use the same language as in E1 (b), i.e. Only including generation resources not identified
in Inclusions I2, I3, I4, and I5. This avoids re-defining all of the generator provisions here. At a
minimum "operated at a voltage of 100 kV or above" should be added at the end of E3 (b).
Yes
No
A functional test, similar to the seven factor test used for FERC Order 888, should be used to identify
transmission network facilities independent of voltage. All other electrical facilities not identified as
transmission network facilities should be deemed local distribution facilities, and should excluded from
the Bulk Electric System pursuant to the statutory Bulk Power System definition provided under
federal law (18 CFR 39.1, Title 18, Chapter I, Subchapter B, Part 39)i.e. “facilities and control
systems necessary for operating an interconnected electric energy transmission network (or any
portion thereof), and electric energy from generating facilities needed to maintain transmission
system reliability. The term does not include facilities used in the local distribution of electric energy.”
Please note that the statute does not reference any voltage level, therefore both transmission
network and local distribution facilities each can operate at voltages higher or lower than 100 kV. The
radial (E1) and local distribution network (E3)exclusions are a good starting point under the
definition, but the exception procedure should have a functional exception for local distribution
facilities independent of voltage level.
No

Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
Guidance Document - The SDT should develop a BES Definition Guidance Document which includes a
fairly comprehensive list of Elements considered to be potentially necessary for operating an
interconnected electric energy transmission network. This list would include references to Real Power
and Reactive Power resources.
No
Recommended changes to the wording used in Inclusion I#1, et al: Formatting - When referring to an
Inclusion (or Exclusion), the SDT should use a number/pound sign (“#”) between the “I” and number
to avoid confusing “I” with the numerical value “1.”
No
The inclusion of generation to the BES should be subject to an impact test.
No
The inclusion of generation to the BES should be subject to an impact test.
No
Please define the terms “collector system” and “common point.”
No
We agree with the concept of a allowing a radial exclusion from the BES. However, we ask that the
term “device” be modified to include the optional plural; “device(s).” Some radial systems may

require isolation by more than one automatic interrupting device.
No
Multiple Connections - The current wording in the second sentence “at more than one location” could
be misinterpreted. Replace this sentence with the following wording: LDN’s use multiple connections
to the Bulk Electric System (BES) solely to improve the level of service to retail customer load.

Yes
As FERC stated in Order 743-A “… the Commission uses the term “exclusion” herein when discussing
facilities expressly excluded by the statute (i.e., local distribution) and the term “exemption” when
referring to the exemption process NERC will develop for use with facilities other than local
distribution that may be exempted from compliance with the mandatory Reliability Standards for
other reasons.” (Footnote 82) Thereby, the Commission clearly established its preferred terminology;
“exclusion” for local distribution and “exemption” for exceptions allowed under the NERC designations
and Exception Process. The BES Definition and Designations do not fully utilize this FERC wording
convention.
The ‘core’ definition is not clear as to whether an Element would be included if it meets any one (or
must meet more than one) of the 5 Inclusion criteria for inclusion?
Group
Western Area Power Administration
Brandy A. Dunn
Yes
As a Transmission Operator (TO) it helps us define and write O & M, and operating agreements for
our Load Serving Entities (LSE/customers) that prefer to contract the responsibilities to the TO. The
definition 'Bright Line Threshold' is a general statement, that needs more definition for the special
circumstances in the southwestern U.S. where pump loads provide necessary irrigation. Based upon
NERC's compliance registry criteria, small entities prefer to contract responsibilities to the TO in order
to forego NERC registration, or the exception process for special circumstances.
Yes
Appreciate the bullet comments that help explain the reasoning for the inclusion.
Yes
the bullet comments that define a specific point for demarcation.
Yes
Yes
Yes
Yes
Yes
Yes
Yes
As discussed in the Applicability of Federal Power Act Section 215 to Qualifying Small Power
Production and Cogeneration Facilities document, the concerns regarding the Regulatory Flexibility Act
Analysis of 1980 stated in section VII does not define the phrase a 'significant economic impact' from
the perspective of a small entity. A small entity may have staffed maintenance personnel, to
accomplish its' own maintenance but now prefers to transfer by written agreement with another entity
based upon NERC's compliance registry criteria, in order to bypass the NERC registration. The

significant economic impact is the cost associated with the reduced work load for the small entity,
maintenance personnel, and the work contracted to another entity.
No
Numerous distribution lines in the western US are 115kV, and some are being upgraded from 115kV
to 230kV.
No

Individual
Scott Miller
MEAG Power
Yes
MEAG Power supports the Standards Drafting Team’s development of a revised Bulk Electric System
(BES) definition in response to FERC Order 743 that is directly linked to an exception process for
inclusions and exclusions. The definition must be closely coupled to the exception process and the two
must be integrated in the standard that is ultimately adopted. This will ensure that the regulatory
requirements apply to only those facilities that materially affect the reliability of the BES. In general,
MEAG agrees with the proposed definition and the objectives the Standards Drafting Team has
established. MEAG recommends that the team make additional clarifications to provide industry with a
better understanding of the inclusions and exclusions, as well as the impact of the
inclusions/exclusions on the BES. The definition should exclude generator leads for generating units
that do not materially affect the reliability of the BES regardless of the BES designation of the
generating unit. In addition, the definition should not require the inclusion of contiguous elements.
Generating units that are designated BES are currently required to comply with a subset of NERC
Reliability Standards, but may not be material to the reliable operation of the interconnected BES.
This portion of the definition should not require that both BES and non-BES generating units have
their generator leads defined as BES transmission elements. A length-based criterion for generator
leads ought to be considered. For example, the definition should exclude generator leads that are one
mile or less between BES elements. The Standards Drafting Team should engage and coordinate with
the Standards Drafting Team for Project 2010-07 (the GO/TO task force). This coordination is needed
to determine the impacts of the new BES definition on Transmission Owner (TO) and Transmission
Operator (TOP) registration. In addition, MEAG recommends that the Standards Drafting Team and
the GO/TO Task Force consider, if they have not already done so, the impacts of ownership and
operating agreements on registration. For example, clarification of registration impacts for BES
elements that are jointly owned by two utilities (e. g. where one utility owns 5 of 20 towers and the
other utility owns the remaining towers and the conductor of a transmission line) is required. The
definition does not provide clarity on the state of the system conditions (normal or emergency) that
should be applied. The definition should apply to only normal operating conditions.
Yes
Yes
The definition should exclude generator leads for generating units that do not materially affect the
reliability of the BES regardless of the BES designation of the generating unit. In addition, the
definition should not require the inclusion of contiguous elements. Generating units that are
designated BES are currently required to comply with a subset of NERC Reliability Standards, but may
not be material to the reliable operation of the interconnected BES. This portion of the definition
should not require that both BES and non-BES generating units have their generator leads defined as
BES transmission elements. A length-based criterion for generator leads ought to be considered. For
example, the definition should exclude generator leads that are one mile or less between BES
elements. This comment has been raised in Question number 1 as well.
Yes
Yes
The Standards Drafting Team needs to clarify whether this inclusion is intended to apply to local

transmission operator restoration plans or only to the Balancing Authority’s restoration plans. This
inclusion should be stated as follows: Blackstart Resources and the designated cranking paths
identified in the Balancing Authority’s Restoration Plan regardless of voltage.” Local restoration plans
may not be material to the restoration and operation of the BES, but black start resources for the
Balancing Authority’s restoration plan are material to the reliable restoration of the BES.
Yes
This inclusion should be specific to the type of generation that the team envisioned it to capture (e.g.
wind and solar). Since the term “dispersed power producing resources” can be interpreted to include
generation resources from a few KW up to 50 MW, this inclusion can be misinterpreted to include
“peaker GT’s”, fuel cells and microturbines, etc.
No
The definition of Exclusion E1 does not cover radial systems that are connected to a single
transmission source by more than one automatic interruption device, such as occurs with a ”breakerand-a-half” arrangement. The definition should be modified as follows: “Any radial system which is
described as connected from a single Transmission source originating with one or more automatic
interruption devices and: ....” This exclusion uses many terms that are not defined under NERC’s
standard definitions: “radial load”, “automatic interruption device” and “make–before-break”. If these
terms are used to define an exclusion and can be understood or interpreted differently by different
people, then the terms should be formally defined.
Yes
Yes
Yes
Yes
No
NO. General comments are listed under Question 1.
Individual
Alice Ireland
Xcel Energy
Yes
Yes
The drafting team should consider how components such as autotransformers would be considered
under this aspect, and if additional language needs to be added to clearly include certain
autotransformers.
Yes
Xcel Energy thanks the SDT for their work and appreciates the clarification that BES extends from the
generator out and does not include the prime mover and balance of plant equipment.
Yes
Yes
No
For dispersed power producing resources, such as wind farms, we do not see the value in making
each individual 1-2 MW wind turbine a BES element. The BES applicability should be focused on the
point when the collective becomes large enough to impact the grid. So, we recommend that I5 apply
from the point of aggregation of 75 MW or more to a system element operated at 100 kV or more.
Specifically, we feel it should be limited to the feeder bus and aggregating transformer.

Yes
Yes
Yes
No
There seems to be an implication that if a facility is determined to be BES, registration is required.
Yet, the registration criteria already includes exclusion of users, owners and operators of the BES
from registration, if they do not meet all the criteria. So, we fail to see why a special exclusion is
necessary.
Yes
No
No.
Individual
Michael Falvo
Independent Electricity System Operator
No
We agree with the BES definition principles in general, the concept of Inclusions and Exclusions, as
well as the proposal for an Exception Process. However, since the Exception Process and the Technical
Principles and Criteria (TPC) for justifying BES Exceptions are being developed and will be approved
independently, albeit concurrently with the BES definition, there is a risk that the revised definition
may be approved while the TPC and Exception Process may not come to fruition in the form
anticipated during development of the BES definition. In short, our support for any revised BES
definition would be conditional to the establishment of the associated TPC. As such we advocate
developing the revised BES definition and TPC as a “single package”. Thus, we do not agree with the
blanket inclusion of generation units and Facilities meeting the thresholds of 20 MVA and 75 MVA
respectively. We also do not agree with using these same thresholds in determining when Exclusions
are applicable. Instead, we believe the impact on BES reliability of all generation units and Facilities
meeting these capacity thresholds, should be assessed against the TPC and if found to be impactive,
these units and Facilities should be included as part of the BES after going through the Exception
Process. We believe this change in the approach to defining the BES will take into account the
evolving reality of distributed generation, particularly in the context of radial systems and local
distribution networks (LDNs), where generation units are installed in lieu of transmission
reinforcements. We offer our further comments on the Definition and its Inclusions and Exclusions
against the backdrop of this general philosophy. The BES definition refers to Reactive Power resources
“connected at” 100 kV or higher as opposed to “operated at” 100 kV or higher. Is the intent of this
wording to include in the BES a reactive resource (capacitor, reactor, etc.) operating at a voltage
below 100 kV and connected to the BES via a step-up transformer? If yes, would the transformer be
excluded from the BES to be consistent with Inclusion I1?
No
We agree with the concept of Inclusion I1. We suggest that since transformers with at least two
windings greater than 100 kV are already part of "all transmission Elements operated at 100 kV and
above" in the definition, and since inclusions I2 to I5 are commonly related to only generation,
Inclusion 1 should be removed and replace by the following Exclusion: E(x) “Transformers that have a
primary or secondary winding at less than 100 kV except for those included by I2 and I3”
No
We agree with the goal of inclusion of I2 but as stated earlier in our response to Q1, we do not
support the blanket application of the BES definition to all individual generating units and Facilities
meeting the respective capacity thresholds. Entities should be able to assess the impact of these units
and Facilities against the TPC and use the Exception Process, with the help of technical evidence, to
include generating units and Facilities that impact the interconnected grid and the bulk transfer of

power.
No
See our responses to Q1 and Q3.
No
This inclusion is extraneous given there is already a designation specific for system restoration
covered by an existing standard to recognize their reliability impacts and to ensure their expected
performance. NERC Standards EOP-005-2 stipulates the requirements for testing blackstart resource
and cranking paths. This testing requirement suffices to ensure that the facilities critical to system
restoration are functional when needed, which meets the intent of identifying their criticality to
reliability. We therefore suggest removing Inclusion I4.
No
We agree with the goal of Inclusion I5 but have the same concerns expressed in our responses to Q1
and Q3. For the dispersed power resources referred to in Inclusion I5, we do not see the benefit of
including the collector system, switchgear, associated medium voltage equipment and step-up
transformer(s) in the BES. As before, these Facilities should be subject to assessment and included if
found to impact BES reliability after going through the Exception Process. To reinforcing what was
stated during the NERC BES webinar, we do not believe that the entire contiguous path has to be
BES.
No
Again, we agree with the goal of E1 but we repeat the same concerns expressed in our responses to
Q1 and Q3 with respect to the generation capacity thresholds. A majority of the transmission
elements excluded by E1 would already be excluded by E3 and, therefore, E1 may be redundant. The
SDT may wish to consider combining Exclusion E1 with Exclusion E3, modified as proposed in our
response to Q9. In Exclusion E1, we suggest changing “automatic interruption device” to “automatic
fault-interrupting device” for consistency with E3(a).
No
Again, we echo the same comments stated in our responses to Q1 and Q3. We do not agree with the
Exclusion E2 for the very same reasons specified in responses to questions 3, 4, and 6. Additionally,
we are not clear of the intent for the restriction stated in Exclusion E2 (ii).
No
Consistent with our earlier comments in response to Q1, we do not agree that an LDN should be
characterized by a 75 MVA limit on the connected generation as described in part (b). It is expected
that under various “green energy” programs that the development and implementation of distributed
generation will grow considerably in the future. The 75 MVA generation limit may discourage this
development of distributed generation (in general, it may discourage the installation of generation in
lieu of transmission to supply load) because installing generation in an LDN would cause the entire
LDN to be classified as BES and, as a result, subject the LDN to NERC planning standards that are
inconsistent with well established jurisdictional planning criteria. To avoid subjecting the LDN to NERC
requirements, the planning authority may elect to build generation outside of the LDN, which is
undesirable because of increased transmission losses and reduced reliability. We suggest that (b) be
deleted or revised in keeping with our earlier suggestions. We also suggest modifying Exception E3
(c) and (d) for consistency with language used in Technical Principles for Demonstrating BES
Exceptions, since Bullet 1 recognizes that the system for which the exemption is being applied, may
not be necessary for BES reliability and may experience power flows out to the BES under specified
conditions. The suggested modified wording for E3 (c) and (d) is shown below: (c) Power is intended
to flow only into the LDN: the total net Generation output within the LDN shall not exceed the total
electric Demand of the LDN. (d) Not intended for use in transferring bulk power: While the LDN is
intended to deliver power to load and not transfer bulk power between different locations in the BES,
it is acceptable that under specified system conditions, bulk power transfers may take place between
different points of the BES via the LDN, when it can be demonstrated that these power flows through
the LDN are not necessary for maintaining BES reliability.
No
Small utilities may be impactive to the bulk power system and as such should not be subject to a
carte-blanche exemption but should be subject to assessment and if necessary exclusions after going
through the exception process. The outcome of the exception process may well be that such small

utilities can be excluded but this cannot be determined a priori. In addition, Exclusion E4 is worded
very similarly to Exclusion E1. It is not clear what additional facilities will be excluded by E4 that are
not already excluded by E1.
No
The existing definition and the associated inclusions and exclusions do not exclude local distribution
facilities because the 75 MVA limit on generation within LDNs in E3 (b) will result in portions of the
power system that are serving a distribution function being classified as BES. As stated before, we
suggest subjecting the LDNs to assessment to determine their impact on the BES and including them
if impactive by using the Exception Process.
No
At this point, we are not aware of conflicts for our own jurisdiction. However, NERC must exercise
caution while developing the exception criteria and the associated processes as these may result in
jurisdictional issues between state/provincial and federal entities. We repeat our earlier point that the
BES definition and TPC must be developed and approved simultaneously to provide assurances that
mechanisms are in place to exclude those Facilities from BES classification that are not impactive on
the BES.
We have no other concerns with the definition but we believe a guide demonstrating the correct
application of the definition under various transmission system configurations would be useful.
Individual
Randy MacDonald
NB Power Transmission

Currently, the posted exception criterion is only a concept with many gaps and TBD, as posted details
are later to follow. The exception criteria should be a menu of technical items (load flows, stability
analysis etc). Entities should be required to assess and provide their own justification under each
category with a conclusion that takes into account all of the relevant items for element(s) under
exception, in a consistent template and table of contents. Suggest the SDT to avoid specification of
any parameters as they would differ under different design concepts, system configurations, system
characteristics and regulatory requirements. An “all encompassing” comment is that the definition is
too lengthy with an overly prescriptive exception process. The importance of the BES definition is
recognized throughout the industry for its importance, and as such it should be simple, clear, and
straightforward.
Group
National Association of Regulatory Utility Commissioners
Robin Lunt

No
The inclusion of individual generating units between 20 MVA and 75 MVA nameplate capacity is
inconsistent with I3 that sets the aggregate threshold at 75 MVA. There is no technical justification for
including a facility as low as 20 MVA and no rational basis for thinking that these generators could be

the cause of instability, uncontrolled separation, or cascading events. We recommend removing this
inclusion or raising the threshold to 75 MVA.

Yes
We agree with Exclusion E1. Radial systems are clearly local distribution and excluded from FERC and
NERC jurisdiction. This is consistent with FERC Order 743 and 743a (see e.g. Order 743A P 1, 76 Fed.
Reg. 16264 (March 23, 2011)). We suggest that I2 be removed from this exclusion (and from the
standard as a whole) as discussed in response to question 3.
Yes
Yes
Exclusion 3 is essential for the standard to conform to Federal Power Act Section 215 that clearly
excludes local distribution from FERC and NERC jurisdiction. The exclusion properly recognizes that
local distribution can operate at above 100 kV. This exclusion seems to reflect the essence of the
Seven Factor test from FERC’s Order 888. Although FERC Order 743A did not bind NERC to the Seven
Factor test, it makes sense to pursue consistency between these tests.
The standard as currently written seems to exempt most local distribution from NERC and FERC
reliability standards. Section 215 of the Federal Power Act requires such exemptions. There remain
some outstanding concerns, however. For example, earlier comments from NERC staff have
suggested that the BES needs to be contiguous. If the definition were to require continuity, it would
likely sweep in many local distribution facilities that should not (and cannot under the statute) be
included in the BES definition.
Congress clearly recognized that State utility commissions are concerned about and committed to
reliability at the distribution level; that's why Congress explicitly limited FERC's reach, and directed
FERC not to attempt to regulate facilities used in local distribution. The NERC standard setting process
for defining the Bulk Electric System must respect the statutory limitations under Federal Power Act
Section 215 that explicitly excluded local distribution from the definition of the Bulk Power System
(BPS). The Bulk Electric System, while not necessarily equivalent to the BPS (See FERC Order 743 A P
102), cannot exceed the limitations of the BPS and cannot include facilities used in the local
distribution of electric energy. State Utility Commissions are concerned about and committed to
reliability. These Commissions are in the best position to provide reliability oversight and standards
for the local distribution system in their State.
Individual
Glen Sutton
ATCO Electric
While we agree generally with the inclusion, we have some questions based on specific examples: 1.
A load substation has two 144/25kV transformers that connects to two separate 144kV transmission
lines (i.e. two separate 144kV buses). However, the two transformers joins on one 25kV bus. Should
these two 144/25kV transformers be part of BES? 2. A protection relay is on 72kV side of a 144/72 tie
transformer and its purpose is to remove 72kV weak source (i.e. trip 72kV breakers) during 144kV
bus fault. Should this protective relay be included in BES? 3. According to Inclusion I1, a 144/25kV
transformer is not a BES element. The transformer's 144kV side has a Motor Operated Disconnecting
Switch (MOD), and this MOD connects to one or two 144kV line breakers. The transformer's
protections trip the 144kV line breakers. Should the transformer protection systems be part of BES?
If a generator connects to 2 back to back transformers (25kV/72kV and 72kV/144kV), which
transformer is GSU? 25/72kV transformer only or both transformers.

Is a load substation categorized as a "radial substation" if its 144kV bus connects to another 144kV
bus at an adjacent substation via two 144kV parallel transmission lines?

Individual
David Burke
Orange and Rockland Utilities, Inc.
In the core definition, “the list shown below” is still not clearly defined and causes some confusion.
Yes
No
: X I2 should pertain to individual generating unit impact to the Bulk system, rather than the size unit
only. Oftentimes there are cases when neither the path nor a 20 MVA unit itself will have any impact
on the reliability of the interconnected transmission network, nor is it necessary for its operation.
No
X I3 should pertain to multiple generating units impact to the Bulk system, rather than the size unit
only. Oftentimes there are cases when neither the path nor a 75 MVA unit itself will have any impact
on the reliability of the interconnected transmission network, nor is it necessary for its operation.
No
See comments from question 4.
Yes

Yes

It was mentioned that Cranking Paths of Blackstart Resources are defined as BES. How about the
path(s) of generation units that will be deemed as BES? Please clarify.
Individual
Shane McMinn
Golden Spread Electric Cooperative, Inc.
Yes
Yes
Yes
Yes
Yes

Yes
No
We recommend modifying "Any radial system which is described as connected from a single
Transmission source originating with an automatic interruption device and..." to read EITHER 1. "Any
radial system which is described as connected from a single Transmission source and... [remove
originating with an automatic interruption device ] OR 2. "Any radial system which is described as
connected from a single Transmission source originating with an automatic interruption device or
manual isolating switch..."
Yes
Yes
No
Suggested revision: Transmission Elements, from a single Transmission source connected at a voltage
of 100 kV or greater, owned by a small utility whose connection(s) to the BES is(are) solely through
this(these) single Transmission source(s), and without interconnected generation as recognized in the
BES Designation Inclusion Items I2, I3, I4, or I5. The intent of the revision is to exlude a small utility
with multiple radial connections to BES elements owned by others.
No
All load serving radials need to be excluded from the BES.
No

Individual
Rick Spyker
AltaLink
Yes
We agree with the concept of a bright-line definition and commend the SDT for developing a concept
of explicit inclusions and exclusions as part of the definition. This will reduce the number of exception
applications for some of the BES elements. However, the inclusion and exclusion requirements are
extremely restrictive. For example, radial characteristics should not be limited by the amount of
installed generation or single transmission source and/or require an interrupting device. Instead we
believe that one or more transmission sources could feed the radial load to provide redundancy as
long as there is adequate protection and isolation for improved customer-supply continuity and
reliability. This should be considered radial as long as the loss of any transmission source does not
affect, and is not necessary for, the operation of the interconnected transmission network. We
suggest the SDT and RoP teams should: • Carefully craft the exception criteria and procedure to be
flexible and technically sound, to allow entities to adequately present their case to the ERO for
inclusions or exclusions outside of the definition. • Include provisions in both the NERC exception
criteria and exception process for federal, state and provincial jurisdictions. These provisions should
provide clear guidance so that, if and when there are deviations from the exception criteria, they are
properly identified with technical and regulatory justifications ensuring there is no adverse impact on
the interconnected transmission network. This burden of proof should be left to the entity seeking
exception because it may be difficult if not impossible to define the exception criteria. Further, if such
an explicit criteria could be defined, it will in fact become another bright-line BES.
Yes
We agree with the concept of Inclusion I1. However, we suggest that since transformers are already
covered by the definition, "all transmission Elements operated at 100 kV and above", and since
Inclusions I2 to I5 are commonly related to generation only, Inclusion I1 should be removed and
replaced by the following Exclusion: E(x) "Transformers not used as Generator Step-Up (GSU)
transformers that have primary or secondary winding at less than 100 kV." We also suggest the SDT
to put forward a high-level exception criteria with key menu items of assessment that can be followed
continent-wide by entities to put forward their exception for element(s) mentioned in Inclusion I1, or

any other inclusion(s). These inclusion(s) that are intended for exemption would be based on the
entity’s technical assessment, evidence and justification for its unique characteristics, configuration,
and utilization.
No
We agree with the concept of Inclusion I2 with respect to individual generating units, but do not
support having the entire path labeled as BES. In most cases, neither the path or a 20 MVA unit itself
will have any impact on the reliability of the interconnected transmission network nor is it necessary
for the operation. Generation restriction (20 MVA or 75 MVA) should either be revised or the
exception procedure should allow entities, with the support of technical evidence, to exclude
element(s) from being labeled as part of the BES. The path to generating facilities does not need to
be BES contiguous. Generating units can be required to be planned, designed, and operated in
accordance with a subset of NERC Standards, but should not require a contiguous path unless the unit
is identified essential for the operation of transmission network. Definition and/or exception process
should provide clear acknowledgement and flexibility to avoid any regulatory conflicts.
No
We agree with the concept of Inclusion I3 with respect to multiple generating units located at a single
site, but do not support that the entire contiguous path has to be BES. The path of a 75 MVA plant or
aggregated generation will rarely have any impact on the reliability of the interconnected transmission
network nor is it necessary for its operation. Generation restriction (75 MVA) should either be revised
or the exception procedure should allow entities, with the support of technical evidence, to exclude
element(s) being labeled as part of BES. Path to generating facilities need not be BES contiguous.
Generating units can be required to be planned, designed, and operated in accordance with a subset
of NERC Standards, but should not require contiguous paths.
No
We do not agree with Inclusion I4. Blackstart resources and transmission facilities on the cranking
path should not be classified as BES regardless of size and voltage level. From a regulatory
perspective, such an inclusion would be in conflict with the current regulatory requirements in many
of the jurisdictions. More importantly, designating these facilities as BES Elements or Facilities beyond
the 100 kV bright line, the 20 MVA/unit or 75 MVA/plant criteria, without a regard to their impact on
the BES (under conditions other than system restoration) will impose unnecessary requirements for
these facilities, which do not contribute to reliability under interconnected operation conditions. For
restoration condition, this inclusion is extraneous given there is already a designation specific for
system restoration covered by an existing standard to recognize their reliability impacts and to ensure
their expected performance. NERC Standards EOP-005-2 stipulates the requirements for testing
blackstart resource and cranking paths. This testing requirement suffices to ensure that the facilities
critical to system restoration are functional when needed, which meets the intent of identifying their
criticality to reliability. While we do not disagree with the SDT’s interpretation of the FERC directives,
the BES definition should cover those facilities that are needed for operation under both normal and
emergency conditions, which includes situations related to black-start and system restoration. We do
not agree that the directives specifically ask for inclusion of blackstart resources and facilities on the
crank path in the BES definition. We believe the requirements in EOP-005-2 suffice to address the
SDT’s interpretation and concern regarding recognition of the reliability impacts and requirements for
blackstart resources and facilities used for system restoration. Generating units of any size and
transmission facilities of any voltage level may be used for blackstart and restoration. Conceivably, a
generator of 10 MW and transmission facilities of 44 kV or 69 kV may be a part of the cranking path.
A BES inclusion will then subject these generators and facilities, which are essentially “local” facilities
but called upon to begin restoring its bulk interconnected counterpart, to comply with the reliability
standards intended for maintaining BES reliability. Included in the BES definition will thus discourage
smaller generators from providing blackstart capability, and the transmission facilities from being a
part of the cranking path. This may also discourage Transmission Owners and Operators from
identifying multiple blackstart resources and cranking paths to provide restoration flexibility. Such an
inclusion will ultimately undermine reliability. If indeed any of these facilities are deemed necessary to
support bulk power system reliability at times other than system restoration, they would/should have
been identified through the basic BES definition and inclusion list or can be addressed through the
exception procedure. We suggest and urge the SDT to drop I4 on the basis that: • The availability and
performance expectations of blackstart resources and facilities on the cranking path are already
specifically addressed in an existing standard; and • Unless they meet the BES definition and the

other inclusion criteria, they do not have any perceived reliability impact on everyday operation of the
BES.
No
We agree with the concept of Inclusion I5 but do not support that the entire contiguous path has to
be BES. The path or aggregate generation will rarely have any impact on the reliability on the
interconnected transmission network nor is it necessary for its operation. These are generally referred
to as connection facilities.
Yes
We agree with this concept as part of establishing a bright-line definition, as well as clarifying this
exclusion as part of the revised BES definition. Although the concept is consistent with the statements
in the FERC Order, it is imperative to understand that the limitations of E1 will have a direct impact on
many entities (big and small) along with distribution companies across North America. The exclusion
requirements are extremely restrictive with little or no technical basis and are limited to the fact that
these parametric restrictions may not have any reliability impact in terms of location, configuration of
element, and system characteristics. The radial characteristics and/or the reliability of the
interconnected transmission network is determined by the amount of installed generation or a single
transmission source or an interrupting device. Accordingly, it will be an understatement to suggest
that the SDT: • Carefully craft the exception criteria and procedure that is flexible and technically
sound to adequately allow entities to present their case to the ERO for exclusion • Exception criteria
should be at a high-level with key menu items of assessment that can be followed continent-wide by
entities to put forward their exception for element(s) mentioned in exclusions or inclusions based on
technical assessment, evidence and justification for its unique characteristics, configuration, and
utilization • Acknowledge and provide provisions in both NERC exception criteria and exception
process for federal, state and provincial jurisdictions.
Yes
We agree with most of the changes in Exclusion E2. However, we feel there is a need for evidence or
technical study in regards to the limits described in I2 & I3. The real net aggregated power seen by
the bulk power system at the interconnection, with the outlook of distributed generation systems,
may be different than past experience. Hence it requires to be reassessed based on technical studies
with respect to the future integration of DG’s. To establish a bright-line definition, E2 exclusion may
be acceptable if the SDT provides adequate provisions within the exception procedure. Accordingly,
we suggest the SDT carefully craft the exception criteria that will allow entities to present their case
to the ERO for exclusion from E2 requirements.
Yes
We agree with this concept as part of establishing a bright-line definition along with this clarifying
exclusion in the revised BES definition. However, requirements in Exclusion E3 are restrictive and we
do not agree to the limits on connected generation for Local Distribution Networks (LDN), described in
part (b). The development and implementation of distributed generation will grow considerably in the
future and will operate together with conventional sources of energy. The real net aggregated power
of distributed generation seen by the bulk power system at the interconnection may be larger than
past experience; hence it requires to be reassessed based on technical studies with respect to the
future integration of DG’s. We suggest and urge the SDT to carefully craft the exception criteria &
procedure that is flexible and technically sound to adequately allow entities to present their case,
and/or unique characteristics of the elements under exception to the ERO for exclusion.
No
Small utility or distribution provider is a relative term. A smaller distribution provider may have an
impact on the transmission network while a large one may not; this is based on their design,
configuration and protection. Hence, such an exception should apply regardless of the size of an
entity. Having said that, the concept discussed here is to define a radial system and not a small
utility, as mentioned in the FERC Order. We do not believe that the SDT had sufficient discussions
while crafting the proposed exclusion in regards to small utilities. The language used in the proposed
clause is only appropriate to establish a bright-line definition for a radial system. It is worth noting
that many small utilities (and individual load customers or generation connections) would have more
than a single transmission source with a solid tap and, at the same time, be adequately protected and
effectively isolated without any adverse impact on the transmission network. Such a practice and
design is widely used across North America. Hence, we do not agree that this exclusion is an attempt

to address the issue of small utilities. The definition and inclusions will force many small entities, load
customers and generation unit owners to act and register as Transmission Owners. In some parts of
the continent this would be in conflict with state or provincial regulatory act, Codes and Licenses.
Consistent with the FERC Order, the ERO and the SDT should be aware of these conflicts and should
not ignore them for later. Hence, we suggest the ERO and the SDT address this by providing explicit
but simple provisions in the exception procedure by considering sound technical exception criteria
that is flexible based on demonstration of evidence to justify the element’s necessity for operation.
Regulatory Acts and Rules will always trump NERC requirements and hence we suggest that the only
evidence that should be required of small utilities/entities is: • Regulatory evidence • Evidence
demonstrating that NO adverse reliability impact is afflicted on the interconnected BES because of
their connection.
No
We commend the SDT for their concept in putting forward a 100kV BES bright-line definition.
However, we do not believe that the current definition drafted by the SDT has differentiated between
Transmission and Distribution or excluded distribution facilities from the BES, or addressed the issue
of local distribution facilities above 100kV. We believe that the ERO and SDT can address this by
providing explicit but simple provisions in the exception criteria (to be used by exception procedure)
by putting forward a menu of key technical assessments , which are based on demonstration of
evidence to justify the element’s necessity for operation. For example, we suggest that for local
distribution, the evidence that should be required is: • Regulatory evidence • Evidence demonstrating
that NO adverse reliability impact is afflicted on the interconnected BES because of their connection
We suggest that the exception criteria should ONLY list a menu of items and a prescribed report
template that should be assessed and presented by an entity as their evidence and justification for
exception to a RE, the ERO and any relevant regulatory authority. This evidence and justification
would be used by the ERO as part of its decision making process.
Yes
We believe that the concepts of inclusions and exclusions as part of the bright-line definition are
excellent. However, these exclusions do not address several directives in Order No. 743 and 743A,
such as: differentiation between Transmission and Distribution, non-jurisdictional concerns, or
distribution. We believe that the BES definition itself is not a venue to address these concerns but
suggest that these issues should be explicitly addressed by the ERO’s exception criteria and exception
process. Currently, the posted exception criterion is only a concept with many gaps and TBD, as
posted details are later to follow. We suggest that the exception criteria should be a menu of technical
items (load flows, stability analysis etc) and non technical items (type of loads such as distribution
companies vs. major city center, national security etc). Entities should be required to assess and
provide their own justification under each category with a conclusion that takes into account all of the
relevant items for element(s) under exception, in a consistent template and table of contents. We
suggest the SDT to avoid specification of any parameters as they would differ under different design
concepts, system configurations, system characteristics and regulatory requirements.
Group
ACES Power Participating Members
Jason Marshall
Yes
Yes
We agree with limiting transformers to bulk power transformers and not including step-down or
distribution transformers. Some regions have been enforcing standards on protection equipment that
is on the low-side of these step-down or distribution transformers. Additional language further
clarifying that this low-side protection equipment is not part of the BES should be added to for
consistency across regions. Additionally, the drafting team might consider using the terms primary
and secondary rather than windings. Otherwise, autotransformers which have a sing
Yes
Yes

No
Blackstart resources are rarely used. For many reasons, restoration almost always starts with
synchronizing to other systems (the Interconnection) that are already intact. Because Blackstart
Resources can actually be on the distribution system, the distribution system can then become
subject to the enforceable standards. This results in significant increased costs in tracking compliance
for these distribution systems without a commensurate increase in reliability. Because a Blackstart
Resource must be included in the Transmission Operator’s restoration plan, this creates a perverse
incentive to un-designate the Blackstart Resource that is on a distribution system to avoid the
distribution system becoming part of the Bulk Electric.
Yes
Yes
Yes
Yes
Yes
Yes
No
It is not clear if E1 covers networked sub-transmission. Consider the situation where a 138 kV line
terminates into a 138/69 kV transformer, the 69 kV is networked and only serves load and possibly
generation that does not meet any of the inclusion criteria. This is a situation that appears to meet
the intent to exclude radial load under E1 and local distribution networks under E3 but does not
appear to explicitly meet either criteria. E1 is not met because the 69 kV network is not radial and E3
is not met because it specifically limits the exclusion to 100 kV and above. This issue could be solved
by making clear that E1 applies to even networked sub-transmission or by removing the voltage limit
on E3 so that sub-transmission could be included within this exclusion criterion.
Group
SERC OC Standards Review Group
Jim Case
Yes
The SERC Standards Review Group (SRG) still believes that 200KV is the correct bright line for the
BES definition
Yes
No
SERC proposes the following as an alternative to the Inclusion I2 wording in the draft BES definition:
“Individual generating units greater than 20 MVA (gross nameplate rating) including the generator
terminals through its GSU which has a high side voltage of 100 kV or above.” The only difference in
proposed text is that the word “the” preceding “GSU” has been changed to “its”. The text in the draft
clearly defines that the inclusion begins with the generator, continues through the terminals, and
ends at a GSU. The wording in the draft text does not, however, explicitly limit the scope of
equipment that should be evaluated for inclusion to the GSU which is directly connected to the
generator terminals. Since GSU is not a defined term there is a strong potential for inconsistent
interpretation of this boundary to include multiple transformers in series until ultimately a transformer
which does operate at a voltage of greater than 100 kV is included in the flow path. To eliminate this
potential for compliance re-interpretation, we also strongly suggest the term GSU be defined in the
NERC Glossary of Terms . A suggested definition is: “Generator Step-up Transformer (GSU) should be

defined as a transformer directly connected to a generator on the low side and to a bus on the high
side.”
No
“Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) including the generator terminals through the GSUs, connected through
a common bus operated at a voltage of 100 kV or above.” GSUs need to be defined – see response to
question 3 above.
No
“Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission
Operator’s restoration plan regardless of voltage.” The SERC SRG is concerned that this provision may
have the effect of incenting transmission operators to limit the available generator options to the
minimum necessary for a reliable option as opposed to every possible option that might be utilized in
a pinch. We recommend the following adjusted language: “Essential Blackstart Resources and the
designated essential blackstart Cranking Paths identified in the Transmission Operator’s restoration
plan regardless of voltage”
Yes
No
This exclusion is acceptable if the suggestions in Questions 3 and 4 are incorporated. We also suggest
modifying Exclusion E1a as follows: a) Only serving Load or only connecting to a transformer stepping
down to a voltage below 100kv. A normally open switching device between radial systems may
operate in a ‘make-before-break’ fashion to allow for reliable system reconfiguration to maintain
continuity of electrical service. Or,
No
This exclusion is acceptable if the suggestions in Questions 3 and 4 are incorporated.
No
“b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate),
includes more than 75 MVA generation;” The SERC SDT believes you intended to grant exception E2
in this case; however, it is not explicitly identified “c)Power flows only into the Local Distribution
Network: The generation within the LDN shall not exceed the electric Demand within the LDN;” Is this
intended for each hour of the year or is it possible for some hours that generation may exceed load?
This needs to be clarified.
No
We suggest that our comments to Question 3 and Question 4 be incorporated. We also question
whether this is going to have an unintended consequence of requiring Distribution Providers to
register that otherwise wouldn’t have to register because some technical aspect has not been included
in this exception.
Yes
Exception E4 potentially does have issues – see our response to Question 10.
No
No other concerns “The comments expressed herein represent a consensus of the views of the above
named members of the SERC OC Standards Review group only and should not be construed as the
position of SERC Reliability Corporation, its board or its officers.”
Individual
Benjamin A Friederichs
Big Bend Electric Cooperative, Inc.
No
As a general matter, BBEC supports the approach the Standards Development Team (“SDT”) has
taken to defining the Bulk Electric System (“BES”). The changes made in the revised core definition
are helpful and represent significant progress toward an acceptable definition. With an effective and
efficient exclusion process, the draft will better define the BES as a whole. We urge the SDT to bear in
mind the restrictions contained in Section 215 of the Federal Power Act (“FPA”) The “bulk-power

system” (As per FERC, we treat the statutory term “bulk-power system” as equivalent to the term
ordinarily used in the industry, “Bulk Electric System”) definition imposes a clear limit on the reach of
the mandatory reliability regime. The BES is made up of only those “facilities and control systems
necessary for operating an interconnected electric energy transmission network (or any portion
thereof)” and “electric energy from generation facilities needed to maintain transmission system
reliability.” Congress reinforced that limit in Section 215(i), where it emphasized that the FPA
authorizes the imposition of reliability standards “for only the bulk-power system.” We're concerned
that the SDT’s proposed definition is overly-broad, and that it will sweep in many Elements that have
little or no material impact on the reliable operation of the interconnected bulk transmission grid. For
example, the definition uses the arbitrary 20 MVA threshold from the NERC Statement of Registry
Criteria for inclusion of generators. Accordingly, for the BES definition to conform to the requirements
of the statute, the SDT must adopt an effective mechanism to exempt facilities like these that are
improperly swept in by the SDT’s brightline approach to inclusions and exclusions. For this reason, the
Exception process to accompany the SDT’s definition is of critical concern. If the SDT incorporates this
statutory language as its core definition, it will have addressed FERC’s primary concern with a
minimum of disruption to the current NERC system of definitions. The definition could then be further
elaborated to show specific points of demarcation for each inclusion and exclusion similar to that
Proposal 6 from the WECC Bulk Electric System Definition Task Force (“BESDTF”) team to further
delineate BES and non-BES facilities.
No
In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and nonBES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is
stepped down from transmission voltages to distribution voltages. We believe, however, that the SDT
should undertake the effort to more clearly define the point where the BES ends and non-BES
systems begin. In this regard, we note that the WECC Bulk Electric System Definition Task Force
(“BESDTF”) has devoted considerable effort to this question and has developed one-line diagrams
noting the BES demarcation point for a number of different kinds of Elements that are common in the
Western Interconnection. Using this work as a starting point, the SDT should be able to provide much
useful guidance to the industry with relatively little additional effort. Also, the reference to “two
windings of 100 kV or higher” may create some confusion because many three-phase transformer
banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We suggest
clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”
We again urge the SDT to consider further delineation of points of demarcation similar to WECC
BESDTF Proposal 6.
No
BBEC is concerned that I2 inclusion criteria that includes the arbitrary 20 MVA threshold from the
NERC Statement of Registry Criteria for inclusion of generators is over-inclusive. Under FPA Section
215, generation resources are excluded from the “bulk-power system” unless they produce “electric
energy” that is “needed to maintain transmission system reliability.” Hence, the inclusion as drafted
improperly expands the BES definition to include generators that the statute requires to be excluded.
In the same comments, the SDT also states that it has considered “the inclusion of generator step-up
(GSU) transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable.” Unfortunately, the SDT appears to have concluded
that any interconnection facility operating above 100-kV should be classified as BES. The result will be
to require Generation Owners to register as Transmission Owners/Operators, as well, producing
substantial additional compliance costs for those Generation Owners but resulting in little or no
improvement in the reliability of the BES. We recommend that the SDT, like the Project 2010-07 SDT
(commonly referred to as the GO/TO Team), give careful consideration to the practical results of its
recommendations rather than relying on abstract conclusions about whether a “contiguous” or “noncontiguous” BES is more desirable. We are concerned that the SDT’s pursuit of a “contiguous” BES
will result in a substantially over-inclusive BES definition. The “contiguous” BES concept implies that
every Element arguably necessary for the reliable operation of the interconnected bulk system must
be included in the BES definition, even if it is interconnected with Elements that have no bearing on
the operation of the BES. NERC’s Standards Drafting Team for Project 2010-07, has already
considered this question and, based on an in-depth review of potentially applicable reliability
standards, has concluded that generation interconnection facilities, even if operated above 100-kV,

need to comply only with a limited set of reliability standards in order to achieve the reliability goals.
Much of the work of the Project 2010-07 SDT is applicable to the work of the BES Standards
Development Team. For example, the Project 2010-07 Team observed that interconnection facilities
“are most often not part of the integrated bulk power system, and as such should not be subject to
the same level of standards applicable to Transmission Owners and Transmission Operators who own
and operate transmission Facilities and Elements that are part of the integrated bulk power system.”
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability.
No
BBEC is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20
MVA threshold discussed in our response to question 3, the 75 MVA threshold appears to have been
drawn from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition.
Yes
Including “all” blackstart and blackstart cranking paths in the BES may ultimately provide an incentive
to the electric industry to reduce the number of resources with blackstart capability. We therefore
suggest that essential blackstart resources identified by the Regional Entity should be included in the
Bulk Electric System, but non-essential blackstart resources need not be.
No
BBEC agrees that it is important to address wind generation facilities and similar generation facilities
in which a large number of generating units, each with a relatively small capacity, are clustered and
fed into the grid at a single interconnection point. That being said, we are concerned that the 75 MVA
threshold has been chosen arbitrarily for the reasons stated in our comments on Question 4.
Yes
Our only concern about this exclusion is the timeframe we'd have to get an appropriate automatic
interruption device installed. Currently, we have a short radial that hasn't yet caused us to be
registered as a TO or TOP. Having time to get a solution in place would be crucial for us, as a small
utility, to avoid additional regulatory fees and requirements.
No
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through
reference to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the
generation unit is reliability-must-run or essential blackstart, the function of the unit is irrelevant to
the reliable operation of the interconnected bulk transmission grid, and we therefore believe the
reference to the function of the generation unit (“standby, back-up, and maintenance power…”)
should be eliminated.
BBEC strongly supports the categorical exclusion of Local Distribution Networks from the BES. In fact,
for reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to
ensure that the BES definition complies with the statutory requirement to exclude all facilities used in
the local distribution of electric power. LDNs are, of course, probably the most common kind of local
distribution facility. Further, the conversion of radial systems to local distribution networks should be
encouraged because networked systems generally reduce losses, increase system efficiency, and
increase the level of service to retail customers. BBEC supports the LDN exclusion, but we believe the
exclusion should be refined in the following respects: • The SDT’s draft states that: “LDN’s are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of
service to retail customer Load.” (emphasis added) We recommend that the SDT revise the sentence
quoted above as follows: “LDN’s are connected to the Bulk Electric System (BES) at more than one
location solely to improve the level of service to retail customer Load and not to accommodate bulk
transfers of power across the interconnected bulk system.” By instituting this suggestion, the SDT
would emphasize the key difference between an LDN, which is designed to reliably serve local, enduse retail customers, and the BES, which is designed to accommodate bulk transfer of power at

wholesale over long distances.
BBEC supports the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that can ill afford the substantial costs that accompany
imposition of mandatory compliance with reliability standards. Further, we agree that the small
utilities covered by the exemption will have no measurable impact on the operation of the
interconnected BES. In the Pacific Northwest, many small entities were required to register by virtue
of owning a very small portion of the region’s 115-kV system. These utilities have faced substantial
compliance burdens even though their operations are simply not material to the interconnected bulk
grid in our region, and the investment of resources in compliance therefore will have no measurable
effect in improving the reliability of the interconnected grid.
No
While BBEC agrees that the approach adopted by the SDT -- a core definition coupled with specific
inclusions and exclusions – will be effective in removing most local distribution facilities from the BES,
it will not remove all such facilities. For the reasons discussed at greater length in our answer to
Question 1, BBEC believes that the proposed definition is over-inclusive and is likely to sweep up
certain facilities used in local distribution that should not be classified as BES. As discussed in our
answer to Question 3, BBEC notes that exclusion of facilities from the BES does not mean that owners
of those facilities are entirely exempt from reliability standards. On the contrary, the statute provides
that “users” of the BES can be subject to reliability regulation. Hence, even where an entity does not
own BES assets, it could be required to, for example, provide necessary information to the applicable
Reliability Coordinator and to participate in the regional Under-Frequency Load Shedding program by
setting the UFLS relays in its Local Distribution Network at the appropriate settings. We note that
participants in the WECC BESDTF Task Force generally agreed that appropriate information should be
provided by non-BES entities, although there was considerable concern related to ensuring that the
provision of information was not unduly burdensome.
Yes
The Exceptions process is a necessary part of making this proposal complaint with the Federal Power
Act. As noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is
potentially in conflict with the limitations of the Federal Power Act, and in particular the statutory
exclusion for facilities used in the local distribution of electric energy. The SDT’s approach can meet
the statutory requirements only if the Exception process currently under development results in
facilities that are not properly classified as BES being exempted from regulation as BES facilities.
BBEC has these additional concerns: The current definition provides that “Elements may be included
or excluded on a case-by-case basis through the Rules of Procedure exception process.” BBEC is
concerned that the SDT carefully delineate which entity has the burden of proof in the exclusion
process. The WECC BESDTF approach, which we commend to the SDT, laid out these burdens in some
detail. Under that approach, essentially, if a facility is excluded from the BES by virtue of the specific
exclusions listed in the definition, the Regional Entity bears the burden of proving that the facility
nonetheless has a material impact on the interconnected bulk transmission system and therefore
should be included in the BES. On the other hand, if a facility is classified as BES by virtue of the list
of inclusions set forth in the BES definition, it can still escape classification as BES, but bears the
burden of demonstrating that its facility has no material impact on the interconnected transmission
system. We urge the SDT to give careful consideration to these burden-of-proof questions and to
follow the lead of the WECC BES Task Force. For the reasons we have explained in our answer to
Question 11, we believe the Exception process is critical both to ensure that the BES definition is
effective in producing measurable gains to bulk system reliability and to ensuring that the definition
will comply with the limitations Congress placed in Section 215. Hence, we believe the entire BES
definition, including the Exception process and related procedures, should be vetted through the
NERC Standards Development Process, including the full comment periods and a ballot approvals
provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are
subject to approval in a process that provides considerably less due process and industry input than
the Standards Development Process. Accordingly, we urge that all elements of the BES definition,
including those elements that have been assigned to the Rules of Procedure Team, be vetted through
the Standards Development Process.
Individual

J. McFeely, PE
Modern Electric Water Company
Yes
Taken by itself, the proposed core definition directly accomplishes the following: i) it re-affirms the
100kV bright-line and ii) it removes Regional discretion to define the BES. However, the language
continues to inject ambiguity in that it introduces the use of the separately-defined capitalized term
“Transmission”. In NERC’s Glossary of Terms (May 24, 2011), “Transmission” is defined in terms of
function rather than voltage. Strictly interpreted, the core definition implies that only Elements used
for the transfer of energy to points where it transformed for delivery to customers as well as certain
resources are considered to be included in the BES. Under this viewpoint, there exists a two-stage
qualifier for non-resource Elements – namely that it must first be used for Transmission and not for
“Distribution”, and secondly, that it be operated above 100kV. Rather, the BES cannot contain
Elements used for “Distribution” (a term not explicitly defined, but extrapolated from other NERC
glossary terms to mean the “wires” between the transmission system and the end-use customer, and
NOT defined by voltage). If this is the case, the SDT has established that an Element’s function is
equally important to its voltage, and has simultaneously excluded all Transmission Elements under
100kV – even if used for bulk transfers. While the Exclusions detail characteristics of specific
distribution-like Elements, we suggest that the core BES definition contain language explicitly
excluding Distribution (there are Elements that are neither qualifying radials as defined in E1 nor local
distribution networks as defined in E3).
Yes
The use of “terminals” rather than “windings” might be more clear.

Yes
Clear exclusionary language for radial systems is absolutely necessary for a usable BES definition,
particularly since radial systems serving load are already excluded from the existing NERC definition,
radial systems serving load can only be used for the local distribution of energy (and are thus
excluded by Congress in Sec. 215 of the FPA), and radial systems serving load have been confirmed
excluded from the BES by previous FERC Orders. However, the proposed language could be improved
to be more explicit and further remove the opportunity for improper/unintended interpretation. The
currently-drafted E1 language has several issues that need to be addressed. For instance: The use of
“automatic interruption device” in E1 is not consistent with “automatic fault interruption device” in E3a, and could lead to different interpretations. Another issue is the use of the un-clarified phrase
“single Transmission source”, and deserves additional attention. Presumably, this language exists to
describe the commonly-used radial tap from a networked (two-station) line, as detailed in NERC
Project 2009-17-Response to Request for an Interpretation of PRC-004-1 and PRC-005-1 for Y-W
Electric and Tri-State G&T. In Project 2009-17, diagrams show a radial tap placed on a line between
Station A and Station B, and could be interpreted to indicate that the tap connects to two sources.
Unless “single Transmission source” is clarified, then a radial line originating from a Double-BusDouble-Breaker or a Breaker-and-a-Half station would also connect to two sources. The drafted
language does not go far enough to consider how networked lines are operated – sometimes radially,
sometimes with multiple protection and isolation schemes and equipment. As drafted, this exclusion
cannot be utilized by many insignificant taps (some of such insignificant length that no automatic fault
interrupting device was deemed necessary). This situation leaves those insignificant elements to apply
the LDN exclusion whose characteristics are dissimilar to a simple, load-serving radial tap. We support
the intent of the language of E1-a, “A normally open switching device between radial systems may
operate in a ‘make-before-break’ fashion to allow for reliable system reconfiguration to maintain
continuity of electrical service….”, but suggest that it be re-written as follows: “The existence and use
of ‘make-before-break’ switching devices, which temporarily connect otherwise radial load-serving
systems to alternate sources for purposes of service continuity, do not affect the BES status of the
system before, during, or after their use.” This clarification is needed to address a position held in the
WECC region (WECC Compliance Bulletin #4, April 15, 2011) that make-before-break switches render
systems part of the BES, and discourage distribution providers from “reliably” serving their

customers. We do not intend to air grievances, but ambiguous radial exclusion language has led to an
extreme misuse of resources in the WECC region. It is imperative that industry and the SDT get this
exclusionary language correct and put into use as soon as possible. In an explanatory bullet below
Exclusion E1-c (herein) the SDT states “The SDT believes that faults on radial lines without protection
devices could negatively impact the BES.” Where this reasoning errs is that it assumes that
everything upstream of a radial element is already determined to be BES. Many radial taps connect to
LDN lines without AFIDs. The language proposed does not allow for a radial exclusion directly, but
forces the insignificant tap to apply the LDN exclusion E3 – E1’s success at being complete depends
on another exclusion. Additionally, this reasoning implies that the mere existence of a AFID is the
cure-all to reliability or that technical analysis hasn’t already established the proper balance of
equipment to adequately serve and protect these elements. We suggest including additional isolation
devices as the demarcation point of small radial systems wishing to apply this exclusion.
Yes
Similar to our Question #7 comments regarding radial exclusions in E1, a usable BES definition
excluding local distribution networks (LDNs) is needed to allow this industry to focus on and conduct
business in a fashion that promotes reliable and efficient system operation. In line with a 1/18/2011
Executive Order directing federal regulatory agencies to base their practices on science and to
consider costs, excluding LDNs from the BES definition would achieve that aim on a national scale.
While differing only in connectivity, LDNs operate and function exactly as radial systems. We suggest
modifying the second and third sentences of E3 as “LDNs are normally operated such that they are
connected to the BES through more than one AFID simultaneously, and exist to promote the level of
service to Loads as commonly defined by states’ utility commissions. For a System to be
characterized as an LDN, it must meet all of the following:” Sub-bullet E3-c should be clarified to
indicate conditions, timeframes and metrics used to demonstrate power flow direction. We support
the intent of the remaining sub-bullets.
No
The BES definition has already had a significant economic (and operational) impact on a substantial
number of small entities and those small entities have not adversely impacted the reliability of the
BES. The Commission (and the SDT) should also consider the other side of the coin - an improved
BES definition could have a positive impact on a significantly greater number of small entities than it
will negatively impact small entities otherwise not currently registered. Crafting exclusions properly
with industry suggestions should limit the small number affected by this proposed definition.
Additionally, we point out that in one instance the SDT states that the BES definition does not address
registration or the applicability of standards, yet in another instance is concerned what impact the
definition will have on an entity’s possible registration status. We don’t believe you can have it both
ways or continue to keep one’s proverbial head in the sand any longer. We understand the SDTs
scope is to provide a USABLE definition of the BES, but also understand that its intent is two-fold: 1)
to correct what the Commission believes is a gap in reliability due to regional discretion, and 2) to
remove ambiguity in what constitutes the BES so that industry can focus on and conduct business in a
fashion that promotes reliable and efficient system operation and so that the RROs can implement
their CMEPs. This second point is absolutely related to registration and the applicability of standards,
and shouldn’t be ignored. As drafted, Exclusion E4 still would not allow for the exclusion of ALL small
utilities that may inadvertently be included in the BES based on the currently-drafted definition, even
though they are, indeed, small utilities that should be excluded from the BES. It appears that the SDT
is struggling with the idea that the BES definition should properly evaluate every single element in
North America by itself. We believe this is why the term “generally” was used in NERC’s Statement of
Compliance Registry Criteria (SCRC), and why the issue of the BES definition presently in front of the
SDT cannot be entirely separated from registration and applicability of standards. If the SCRC will not
be examined and modified similarly as the NERCs Rules of Procedure, then the BES definition must
include some “grey area deference” for small utilities such as is the intent of E4. If it is the intent of
the definition to exclude most small utilities from the BES, then exclusions should be granted based
entirely on the definition. Otherwise, as the SDT correctly states, the RoP-based exclusion process will
be flooded and ineffectual. As stated in the SCRC, the definition will initially identify those necessary,
but still allows for refinements later. The SCRC utilizes NERC’s approved definition of the BES, and will
be “improved” by this BES definition. Therefore, craft E4 with language that does not limit its intent to
exclude small utilities from the BES. Do not use metrics already used in other exclusions. Do not

reference registration requirements in exclusions that comprise the definition of the BES – the BES
should not be defined in terms of registration criteria. In Order 743, FERC defines a small utility in
terms of an entity’s annual MWhs sold. Consider aligning NERC’s and FERC’s definitions similarly.
No
The proposed definition continues to inject ambiguity in that it introduces the use of the separatelydefined capitalized term “Transmission”. In NERC’s Glossary of Terms (May 24, 2011), “Transmission”
is defined in terms of function rather than voltage. As it should, the core definition implies that only
Elements used for the transfer of energy to points where it is transformed for delivery to customers
as well as certain resources are considered to be included in the BES. However, it also uses voltage,
and we do not believe that the proposed definition goes far enough to distinguish between T and D.
Under the language of the core definition, there exists a two-stage qualifier for non-resource
Elements – namely that it must first be used for Transmission and not for “Distribution”, and
secondly, that it be operated above 100kV. Rather, the BES cannot contain Elements used for
“Distribution” (a term not explicitly defined, but extrapolated from other NERC glossary terms to
mean the “wires” between the transmission system and the end-use customer, and NOT defined by
voltage). While the Exclusions detail characteristics of specific distribution-like Elements, we suggest
that the core BES definition contain language explicitly excluding Distribution (there are Elements that
are neither qualifying radials as defined in E1 nor local distribution networks as defined in E3). Section
215(a)(1) contains specific language that could be used in the core definition in this instance.
Yes
Exclusion E1 and WECC Compliance Bulletin #4 (April 15, 2011) conflict. We support the intent of E1
and have provided suggested language modifications to it in Question #7 herein. Link http://compliance.wecc.biz/Documents/2%20-%20WECC%20%20Compliance%20Bulletins/01.04%20-%20Compliance%20Bulletin%20%204%20Interpretation%20PRC-004,%20PRC-005%20-%20April%2015,%202011.pdf
1) The SDT states that “one of the basic tenets that the SDT is following is to avoid changes in
registration due the revised definition”. We stress the implications of a missed opportunity and the
importance of a usable BES definition, because if the revised definition does not allow the industry
(both registered and non-registered entities) as well as the regional reliability organizations to focus
on and conduct business in a fashion that promotes reliable and efficient system operation (not just
ultra-conservative compliance monitoring), then NERC has failed to do its job in this particular
instance. 2) The proposed implementation plan indicates that the effective date of this definition is
not for at least 24 months after regulatory approval. We strongly disagree with this suggested
approach as it does not provide for any benefit from this much-needed improvement. We believe the
SDT intended to imply that entities not currently registered would have at least 24 months to become
compliant with applicable standards if the improved BES definition suddenly swept them into the BES
as it did for many small utilities on June 18, 2007. The definition should become effective immediately
upon regulatory approval, and transition plans for newly-registered entities could specify longer
timeframes. 3) As currently drafted, NERC’s Statement of Compliance Registry Criteria (Revision 5.0)
contains the text of NERC’s approved BES definition. Upon approval of any other language, the SCRC
will become inaccurate without review and modification.
Group
Northern California Power Agency
Scott Tomashefsky
Yes
NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.
Yes
NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.
Yes
NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.
Yes
NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.
Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.
Yes
NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.
Yes
NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.
Yes
NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard. In
addition to this support, NCPA asks for consideration of an alternative approach for determining an
exception in this regard, as opposed to having it based on a somewhat arbitrary fixed level of
generation (75 MVA). NCPA suggests consideration be given for an approach based on a determined
percentage of actual demand for a given LDN. As such, NCPA submits the following with respect to
draft exception E3 (b), Limits on Connected Generation: Neither the LDN, nor its underlying Elements
(in aggregate), include more than a certain percentage of minimum area load, as determined by the
regional entity." Such an approach would require the regional entity to look at the amount of
connected generation on a case-by-case basis.
Yes
NCPA supports the comments of the Transmission Access Policy Study Group in this regard.
Yes
NCPA supports the comments of the Transmission Access Policy Study Group in this regard.

Individual
Gary Carlson
Michgan Public Power Agency
Yes
My concern centers on the intent of FERC Order 743 language “we certify that this Final Rule will not
have a significant economic impact on a substantial number of small entities” still falls short from
being met by this definition change. This is a good start but additional work remains to be done. As
pointed out in FERC Order 743A the 100 KV bright-line was not required but NERC can provide an
alternative which can be supported technically. Also I have concerns for the FERC Order 743A
language “facilities used in the local distribution of energy should be excluded from the revised bulk
electric system definition” also needs additional work remains to be done.
Yes
Yes
Generally I would agree with I2 but question the technical justification for 20 MVA without also
considering its capacity factor.
Yes
See comments to question 3
No
I would agree to this for Blackstart Resources only designated Blackstart Cranking Paths in the
Transmission Operator’s restoration plan regardless of voltage.
Yes
I would suggest I5 be revised to say Wind farm or solar power installation with aggregate capacity
greater than 75 MVA (gross aggregate nameplate rating) utilizing a collector system
Yes
I would suggest the following changes be considered: The words “described as” should be deleted
from the exclusion to avoid confusion. What matters is how the system is actually connected, not how
someone describes it. In addition, “a single Transmission source” should be defined, and should be
generic enough to encompass the various bus configurations. It is not the case, for example, that
each individual breaker position in a ring bus is a separate Transmission source; in that case, a bus at
one voltage level at one substation should be considered “a single transmission source.” Some

examples of configurations that should be considered a single transmission source for this purpose
are at https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples
1-6. The phrase “automatic interrupting device” should be replaced with the phrase “switching
device”.” Many radials are connected to ring buses or breaker-and-a-half schemes where the breakers
(automatic interrupting devices) are within the bus arrangement where the appropriate division
between BES and non-BES is at the disconnect switch as the radial “takes off” from the bus
arrangement.
Yes
I understand that E2 is intended to apply only to retail customers’ generation. If that is the case then
I would suggest the following changes be made to make that limitation clear. Specifically, the first
sentence should read: “A generating unit or multiple generating units that serve all or part of retail
customer Load with electric energy on the retail customer’s side of the retail meter.”
Yes
I question the technical justification for the 75 MVA and the 100 KV as pointed out in my comments
above. But given those points addressed above I would suggest the following clarification be
considered. The exclusion refers to groups of Elements that “distribute power to Load rather than
transfer bulk power across the interconnected system.” The use of the term “bulk power” is vague
and could be read incorrectly as a reference to the “bulk-power system,” which is defined in the
Federal Power Act but is not a NERC defined term. If the LDN is connected to the BES at more than
one location, there will by definition be some loop flow. We recommend below that Exclusion 3(d) be
revised to quantify the amount of loop flow that is permissible in an excluded LDN. In the context of
the first sentence of Exclusion E3, less specificity is needed, and the sentence should only be revised
for the sake of accuracy to state: “Groups of Elements operated above 100 kV that are primarily
intended to distribute power to load rather than to transfer power across the interconnected System.”
The exclusion’s reference to connection “at more than one location” is vague. The sentence should be
revised to read “connected to the Bulk Electric System (BES) from more than one Transmission
source solely to improve the level of service to retail customer Load,” and “Transmission source”
should have the same meaning that it does in E1. E3(a) should require that there be switching
devices between the LDN and the BES, not specifically automatic fault-interrupting devices. The term
“separable by” in “Separable by automatic fault interrupting devices” is unclear and should be
reworded. E3(b) To avoid pulling an LDN into the BES based on very small customer-owned
generation (such as rooftop photovoltaics and hospital backup diesel generators) that the utility does
not consider or rely on, or necessarily even know about, the item should be reworded: “Limits on
connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes more
than 75 MVA of generation used to meet the resource -adequacy requirements of electric utilities.”
E3(d) states “Not used to transfer bulk power.” As noted above, “bulk power” is a vague term. There
will necessarily be some loop flow on a system that is connected to the BES at more than one
location. The amount of permissible loop flow for this purpose needs to be determined and stated in
this item.
Yes
But I question if the "Small Entity definition" as indicated in Order 743 language "we certify that this
Final Rule will not have a significant economic impact on a substantial number of small entities." has
been appropriately addressed.
No
As I have indicated in my comments above the "small entity definition" is not being used when the
100 KV, 20 MVA, and 75 MVA aggregate are being used only. A unit with a long start up time and a
low capacity factor and/or availability factor and connected to a local distribution system is
interconnected to the BES has little opportunity to be counted on to support the BES during a critical
event. With the environmental issues out there it could be expected that owners of these types of
units may well decide on economics of the issue and retire such units. How would the reliability of the
BES be served then?
No
No
Group

Hydro One Networks Inc
David Curtis
Yes
We agree with the concept of a bright-line definition and commend the SDT for developing a concept
of explicit inclusions and exclusions as part of the definition. This will reduce the number of exception
applications for some of the BES elements. However, the inclusion and exclusion requirements are
extremely restrictive. For example, radial characteristics should not be limited by the amount of
installed generation or single transmission source and/or require an interrupting device. Instead we
believe that one or more transmission sources could feed the radial load to provide redundancy as
long as there is adequate protection and isolation for improved customer-supply continuity and
reliability. This should be considered radial as long as the loss of any transmission source does not
affect, and is not necessary for, the operation of the interconnected transmission network. Further, it
is imperative to understand that the NERC’s revised definition will have a direct impact on entities
across North America and will conflict with regulatory requirements, Codes, and Licenses. FERC in its
Order 743 and 743A has directed NERC to address these concerns. We suggest the SDT and RoP
teams should: • Carefully craft the exception criteria and procedure to be flexible and technically
sound, to allow entities to adequately present their case to the ERO for inclusions or exclusions
outside of the definition. This burden of proof should be left to the entity seeking exception because it
may be difficult if not impossible to define the exception criteria. If such a criteria could be defined, it
will in fact become another bright-line BES. • Include provisions in both the NERC exception criteria
and exception procedure for federal, state and provincial jurisdictions. These provisions should
provide clear guidance so that, if and when there are deviations from the exception criteria, they are
properly identified with technical and regulatory justifications ensuring there is no adverse impact on
the interconnected transmission network.
Yes
We agree with the concept of Inclusion I1. However, we suggest that since transformers are already
covered by the definition, "all transmission Elements operated at 100 kV and above", and since
Inclusions I2 to I5 are commonly related to generation only, Inclusion I1 should be removed and
replaced by the following Exclusion: E(x) "Transformers not used as Generator Step-Up (GSU)
transformers that have primary or secondary winding at less than 100 kV." We also suggest the SDT
to put forward a high-level exception criteria with key menu items of assessment that can be followed
continent-wide by entities to put forward their exception for element(s) mentioned in Inclusion I1, or
any other inclusion(s). These inclusion(s) that are intended for exemption would be based on the
entity’s technical assessment, evidence and justification for its unique characteristics, configuration,
and utilization.
No
We agree with the concept of Inclusion I2 with respect to individual generating units, but do not
support having the entire path labeled as BES. In most cases, neither the path nor a 20 MVA unit
itself will have any impact on the reliability of the interconnected transmission network nor is it
necessary for the operation. Hence, we do not support the fact that there should be a blanket
application of the BES definition to all individual generating units greater than 20 MVA and its
connection to the system. It is also important to mention that moving into the future, with the Green
Energy and Smart Grid plans advocated by both Canadian and US policy makers, the gross nameplate
rating of 20 MVA acquired from NERC registration restricts the penetration of dispersed generation in
many parts of North America. We suggest the following: • Generation restriction (20 MVA or 75 MVA)
should either be revised or the exception procedure should allow entities, with the support of
technical evidence, to exclude element(s) from being labeled as part of the BES. • Entities should be
able to use the exception process, with the help of technical evidence, to exclude generating units
that do not impact the interconnected grid and the bulk transfer of power. • The path to generating
facilities does not need to be BES contiguous. Generating units can be required to be planned,
designed, and operated in accordance with a subset of NERC Standards, but should not require a
contiguous path unless the unit is identified essential for the operation of transmission network.
No
We agree with the concept of Inclusion I3 with respect to multiple generating units located at a single
site, but do not support that the entire contiguous path has to be BES. The path of a 75 MVA plant or
aggregated generation will rarely have any impact on the reliability of the interconnected transmission

network nor is it necessary for its operation. We also do not support the fact that there should be a
blanket application of this inclusion. As stated earlier, under various green energy, smart grid and
dispersed renewable energy plans advocated by both Canadian and US policy makers, the gross
nameplate rating of 75 MVA may undermine and deter the future potential of integrating Distributed
Generations (DG’s) that will be implemented to ensure the reliable operation of the interconnected
transmission network BES, and, at the same time, providing the most effective and economical
solutions for the rate payers in North America. Local generation can cost-effectively enhance the
reliability of load pocket by avoiding transmission, but such restrictions would deter the adoption of
good planning decisions. Upcoming load displacement projects would result in the installation of new
self-generation facilities at customer sites, with the electricity generated being used on-site by the
customer, with a resultant decrease in the consumption of electricity purchased via large scale
generation. These projects can be large, and displace a substantial portion of the customer’s (or local
distribution company’s) existing load, even to the extent of total self-sufficiency and the availability of
surplus generation. The aggregated surplus generation capacity may very well exceed 75 MVA and
would consequently force the facility owners to register as both Generation Owners (GO) and
Transmission Owners (TO), which may be in conflict with regulatory rules in many jurisdictions. We
suggest the following: • Generation restriction (75 MVA) should either be revised or the exception
procedure should allow entities, with the support of technical evidence, to exclude element(s) being
labeled as part of BES. • Path to generating facilities need not be BES contiguous unless the unit is
identified essential for the operation of transmission network. Generating units can be required to be
planned, designed, and operated in accordance with a subset of NERC Standards, but should not
require contiguous paths. • Entities should be able to use the exception process, with the help of
technical evidence, to exclude generating units that do not impact the interconnected grid and the
bulk transfer of power. • From a regulatory perspective such an inclusion could also be in conflict with
the current regulatory requirements. Definition and/or exception process should provide
acknowledgement and flexibility to avoid any regulatory conflicts. For example, as stated earlier (Q3
response) NERC and SDT should consider introducing a concept of a new category of registration or
BES Support elements. These elements are NOT necessarily BES but support the reliable operation of
the interconnected transmission network.
No
We do not agree with Inclusion I4. Blackstart resources and transmission facilities on the cranking
path should not be classified as BES regardless of size and voltage level. From a regulatory
perspective, such an inclusion would be in conflict with the current regulatory requirements in many
of the jurisdictions. More importantly, designating these facilities as BES Elements or Facilities beyond
the 100 kV bright line, the 20 MVA/unit or 75 MVA/plant criteria, without a regard to their impact on
the BES (under conditions other than system restoration) will impose unnecessary requirements for
these facilities, which do not contribute to reliability under interconnected operation conditions. For
restoration condition, this inclusion is extraneous given there is already a designation specific for
system restoration covered by an existing standard to recognize their reliability impacts and to ensure
their expected performance. NERC Standards EOP-005-2 stipulates the requirements for testing
blackstart resource and cranking paths. This testing requirement suffices to ensure that the facilities
critical to system restoration are functional when needed, which meets the intent of identifying their
criticality to reliability. While we do not disagree with the SDT’s interpretation of the FERC directives,
the BES definition should cover those facilities that are needed for operation under both normal and
emergency conditions, which includes situations related to black-start and system restoration. We do
not agree that the directives specifically ask for inclusion of blackstart resources and facilities on the
crank path in the BES definition. We believe the requirements in EOP-005-2 suffice to address the
SDT’s interpretation and concern regarding recognition of the reliability impacts and requirements for
blackstart resources and facilities used for system restoration. Generating units of any size and
transmission facilities of any voltage level may be used for blackstart and restoration. Conceivably, a
generator of 10 MW and transmission facilities of 44 kV or 69 kV may be a part of the cranking path.
A BES inclusion will then subject these generators and facilities, which are essentially “local” facilities
but called upon to begin restoring its bulk interconnected counterpart, to comply with the reliability
standards intended for maintaining BES reliability. Included in the BES definition will thus discourage
smaller generators from providing blackstart capability, and the transmission facilities from being a
part of the cranking path. This may also discourage Transmission Owners and Operators from
identifying multiple blackstart resources and cranking paths to provide restoration flexibility. Such an
inclusion will ultimately undermine reliability. If indeed any of these facilities are deemed necessary to

support bulk power system reliability at times other than system restoration, they would/should have
been identified through the basic BES definition and inclusion list or can be addressed through the
exception procedure. We suggest and urge the SDT to remove I4 on the basis that: • The availability
and performance expectations of blackstart resources and facilities on the cranking path are already
specifically addressed in an existing standard; and • Unless they meet the BES definition and the
other inclusion criteria, they do not have any perceived reliability impact on everyday operation of the
BES.
No
We agree with the concept of Inclusion I5 but do not support that the entire contiguous path has to
be BES. The path or aggregate generation will rarely have any impact on the reliability on the
interconnected transmission network nor is it necessary for its operation. These are generally referred
to as connection facilities. In addition, renewable generation units are intermittent and the planning
and operational standards and practices make sure that their unavailability or unexpected (sudden)
loss of generation won’t jeopardize reliability of the network; therefore, they should not be BES. As
stated earlier, with the Green Energy and Smart Grid plans and dispersed renewable energy
advocated by both Canadian and US policy makers, the gross nameplate rating of 75 MVA may
undermine and deter the future potential of integrating DG’s that will be implemented to ensure the
reliable operation of the interconnected transmission network BES, and, at the same time, provides
the most effective and economical solutions for the rate payers in North America. Local generation
can cost-effectively enhance the reliability of load pocket, by avoiding transmission, but such
restrictions would deter the adoption of good planning decisions. (Refer to Q4 comments).
Yes
We agree with this concept as part of establishing a bright-line definition, as well as clarifying this
exclusion as part of the revised BES definition. Although the concept is consistent with the statements
in the FERC Order, it is imperative to understand that the limitations of E1 will have a direct impact on
many entities (big and small) along with distribution companies across North America. The exclusion
requirements are extremely restrictive with little or no technical basis and are limited to the fact that
these parametric restrictions may not have any reliability impact in terms of location, configuration of
element, and system characteristics. The radial characteristics and/or the reliability of the
interconnected transmission network should not be determined by the amount of installed generation
or a single transmission source or an interrupting device. For example, a redundant double circuit
designed to supply the load with adequate protection and isolation beyond the radial tap could be
significantly better for load supply-continuity and reliability. We suggest if more than one
transmission source feed radial load to ensure customer supply continuity and reliability then this
should be either part of the bright-line definition as long as there is adequate protection and, the loss
of any single transmission source does not affect the interconnected transmission network. We
suggest SDT to consider revising E1 as follows: Any radial system which is described as connected
from a single Transmission source originating with an automatic interruption device or can be isolated
with adequate protection without affecting the BES and: a) Serves load, or, b) Includes generation
resources not identified in Inclusions I2, I3, I4 and I5, unless excluded by E2, or, c) Has any
combination of items (a) and (b). The radial system can have a normally open switching device for
connecting it to a second Transmission source in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service.
Yes
We agree with most of the changes in Exclusion E2. However, we feel there is a need for evidence or
technical study in regards to the limits described in I2 & I3. The real net aggregated power seen by
the bulk power system at the interconnection, with the outlook of distributed generation systems,
may be different than past experience. Hence it requires to be reassessed based on technical studies
with respect to the future integration of DG’s. (Please refer to comments in questions: 3 & 4). To
establish a bright-line definition, Exclusion E2 may be acceptable if the SDT provides adequate
provisions within the exception procedure. (See response to Q7)
Yes
We agree with this concept of LDN as part of establishing a bright-line definition along with Exclusion
E3. However, restrictions for LDN such as connected Generation must neither be more restrictive than
radial nor should generation limits be applicable unless they impact the reliability of interconnected
transmission network. Requirements in Exclusion E3 are very restrictive and we do not agree to the

limits on connected generation for Local Distribution Networks (LDN), described in part (b). We
suggest that bullet b) be revised and limits on connected generation must not include generation
resources identified in Inclusions I2, I3, I4 and I5. The development and implementation of
distributed generation will grow considerably in the future and will operate together with conventional
sources of energy. The real net aggregated power of distributed generation seen by the bulk power
system at the interconnection may be larger than past experience; hence it requires to be reassessed
based on technical studies with respect to the future integration of DG’s. (Please refer to comments in
questions: 3 & 4) Also, we suggest combining exception E3 (c) and (d) as follows: “(c) Power is
intended to flow only into the LDN: The generation within the LDN shall not exceed the electric
Demand within the LDN; The LDN is intended to deliver power to load and not be used to transfer
bulk power between different locations in the BES. It is recognized that under specified system
conditions, bulk power transfers may take place between different points of the BES via the LDN.
However, for these conditions BES reliability is not dependent on the existence of these power flows
through the LDN.”
No
Small utility or distribution provider is a relative term. A smaller distribution provider may have an
impact on the transmission network while a large one may not; this is based on their design,
configuration and protection. Hence, such an exception should apply regardless of the size of an
entity. Having said that, the concept discussed here is to define a radial system and not a small
utility, as mentioned in the FERC Order. We do not believe that the SDT has proposed exclusion in
regards to small utilities. The language used in the proposed clause is only appropriate to establish a
bright-line definition for a radial system. It is worth noting that many small utilities (and individual
load customers or generation connections) would have more than a single transmission source with a
solid tap and, at the same time, be adequately protected and can be effectively isolated without any
adverse impact on the transmission network. Such a practice and design is widely used. Hence, we do
not agree that this exclusion is an attempt to address the issue of small utilities. The definition and
inclusions may force many small entities, load customers and generation unit owners to act and
register as Transmission Owners. In some parts of the continent this could be in conflict with state or
provincial regulatory act, Codes and Licenses. Consistent with the FERC Order, the ERO and the SDT
should be aware of these conflicts and should not ignore them for later. Hence, we suggest that SDT
address this by providing explicit but simple provisions in the exception procedure by considering
technical assessment of exception criteria to justify the element’s necessity for operation. We suggest
that the only evidence that should be required of small utilities/entities is: • Regulatory evidence •
Evidence demonstrating that NO adverse reliability impact is afflicted on the interconnected BES
because of their connection and operations.
No
We commend the SDT for their concept in putting forward a 100kV BES bright-line definition.
However, we do not believe that the current definition drafted by the SDT has differentiated between
Transmission and Distribution or excluded distribution facilities from the BES, or addressed the issue
of local distribution facilities above 100kV. It is worth noting that different jurisdictions may use
different terminology for “distribution” or non transmission facilities or elements. For example, some
jurisdictions label certain facilities as distribution which connect and are owned and operated by the
distribution utility, customer or a generator customer while other label them as connection facility or
elements. (See Q10 response)
See earlier comments and suggestions. NERC’s revised definition will have a direct impact on many
entities across North America and could also be in conflict with regulatory requirements, Codes, and
Licenses, which non FERC jurisdictional must comply. It would be hard if not impossible to identify the
conflicts. For example: in one of the the provincial energy acts, NERC Standards maycan only apply to
generation over 50 MVA which will cause one or more of the requirements to be in conflict and /or
what constitutes distribution and what is not considered transmission (such as connection facility to a
load or generation and owned by the proponent). However, we agree to establish a 100kV BES brightline definition and we believe that the best venue to address avoiding compliance conflicts is through
the exception criteria and the exception procedure. The benefits of such an approach are: •
Establishment of a continent wide bright line definition • Avoidance of regulatory conflicts and legal
complexities • Assurance of the reliability of the interconnected transmission network
We believe that the concepts of inclusions and exclusions as part of the bright-line definition are
excellent. However, these exclusions do not address adequately several complex issues along with

directives in Order No. 743 and 743A, such as: differentiation between Transmission and Distribution,
non-jurisdictional concerns, or distribution. BES definition itself is not a venue to address these
complex issues and suggest that these should be addressed by the ERO’s exception procedure. We
suggest that SDT consider • Removing I5 and adding E4 to exclude intermittent renewable generation
(wind and solar). As stated earlier, such units are intermittent and the planning and operational
standards and practices ensure that their unavailability or unexpected (sudden) loss of generation
won’t jeopardize reliability of the network; therefore, they should not be BES. • That the definition
and/or exception process should provide acknowledgement and flexibility to avoid any regulatory
conflicts. • Introducing a concept of a new category of registration or BES Support (BESS) elements.
These elements are NOT BES but support the reliable operation of the interconnected transmission
network. A sub-set of relevant NERC Standards should still apply to BESS elements such as planning,
design, and maintenance. However, they may not be contiguous or subject to mandatory compliance.
We do plan to submit our comments on exception criteria and procedure as part of its process.
However, we do suggest that the SDT: • Carefully craft the exception criteria that is flexible and
technically sound to adequately allow entities to present their case to the ERO for exception • Verify
that the exception criteria should be at a high-level with key menu items of assessment that can be
followed continent-wide by entities to put forward their exception for element(s) mentioned in
exclusions or inclusions based on technical assessment, evidence and justification for its unique
characteristics, configuration, and utilization • Acknowledge and provide provisions in both NERC
exception criteria and exception process for federal, state and provincial jurisdictions.
Group
PacifiCorp
Sandra Shaffer
Yes
In general PacifiCorp agrees with the direction of the proposed BES definition. Specific exceptions are
discussed in questions 2 - 13
No
Transformers with two or more windings greater than 100 kV exclusively serving local distribution
networks should be excluded from the BES.
No
Although certain areas of the country may have a need for generating units of this magnitude to be
included in the BES for reliability, the 20 MVA minimum rating essentially discriminates against the
owners of these generators. In I3 and I5 a 75 MVA limit has been established for different
combinations of generation. This limit should also be used for a single generating unit. Those areas
that require generator units less than 75 MVA for reliability should add them back to the BES via the
inclusion/exclusion process to be proposed in NERC’s Rules of Procedure (“ROP”). • The 20 MVA
threshold was intended to mirror the existing NERC Compliance Registry Criteria. This registry value
was adopted without the benefit of having been scrutinized through a NERC Reliability Standards
Development Process, so the technical record justifying the 20 MVA threshold is non-existent. The
BES Drafting Team will need to have technical justification for adopting the 20 MVA threshold beyond
the fact that it was previously adopted by NERC in a different framework (i.e., for entity registration).
Absent any technical justification, Inclusion I2 should be eliminated. This would leave the 75 MVA
threshold in Inclusion I3 and Inclusion I5 as the minimum BES thresholds for generation.Also, please
refer to additional comments in question 13 regarding a contiguous BES.
Yes
PacifiCorp understands the SDT is looking for technical reasons for something other than 75 MVA.
PacifiCorp believes it is not feasible to determine a value that is consistent across the continent.
Although PacifiCorp believes 75 MVA is too low, it is an acceptable number for any configuration of
generation (see comment on question 3). Those above 75 MVA believed to be exempt from the BES
definition can be processed through the proposed ROP inclusion/exclusion process. PacifiCorp submits
the following suggested wording for I3: “Multiple generating units with an aggregate capacity greater
than 75 MVA or a single generating unit with a generating capacity greater than 75 MVA…..”
No
PacifiCorp supports the concept of unique or singular blackstart paths being included in the BES.
However, once the uniqueness of the path disappears PacifiCorp believes the multiple non-unique

blackstart paths should be excluded by definition from the BES. This approach could be equated to
pending version 4 of the CIP Reliability Standards, in which the Critical Asset Criteria of CIP-002-4 set
forth the facilities comprising the Cranking Paths that are considered Critical Assets, up to the point
on the path where two or more path options exist.
Yes
PacifiCorp understands the SDT is looking for technical reasons for something other than 75 MVA.
PacifiCorp believes it is not feasible to determine a value that is consistent across the continent.
Although PacifiCorp believes 75 MVA is too low, it is an acceptable number for any configuration of
generation. Those above 75 MVA believed to be exempt from the BES definition can be processed
through the proposed ROP inclusion/exclusion process.
Yes
: Please refer to additional comments in question 13 regarding a contiguous BES.
Yes
Yes
PacifiCorp believes this meets FERC’s intent in Order Nos. 743 and 743A, however additional
clarification may be added particularly around items b and c. Regardless of the generation level (item
b), if the power only flows into the Local Distribution Network (“LDN”) (item c) then the the level of
generation is not material and should have no impact on the reliable operation of the BES.
Yes
PacifiCorp believes this concept is appropriate with the following concern: Essentially the only
difference between this proposed exclusion and E1a is this proposed exclusion does not include “an
automatic interruption device”. So if the proposed E4 is left as a stand-alone exclusion it should also
require “an automatic interrupting device” qualifier. Technical justification for requiring an interrupting
device is the same justification used by the SDT in E1.
Yes
PacifiCorp understands that no single bright line can accommodate all the various scenarios of local
distribution. The proposed definition appears to capture a high percentage of LDNs. Additional LDNs
can be addressed through the exemption process. Also, please refer to additional comments in
question 13 regarding a contiguous BES.
Yes
The SDT proposal combined with the ROP may be in conflict with Section 215 of the Federal Power Act
(“FPA”) which excludes “facilities used in the local distribution of electric energy” from the definition of
“bulk-power system.” As identified in other responses, without a technical reason for setting the
generation limit to 20 MVA and even 75 MVA and/or requiring a contiguous BES to include such
generators may be over-inclusive and by default require several elements which are not required for
the reliable operation of the BES to be included in the BES definition.
• Effective dates: While understanding that additional facilities will require up to two years to come
into compliance, several facilities will also be excluded that are currently under the current bright line
definition. Are utilities going to be responsible to maintain all NERC reliability standards during the
two year period for facilities or elements that will be excluded by the new bright line definition?
PacifiCorp proposes that the effective date for facilities being removed from the bright line become
effective on the first day of the first calendar quarter after applicable regulatory approval. It is
reasonable to retain the two year period for facilities that will be added to the BES. • NERC Staff has
submitted written comments to this project stating that the BES “must be contiguous.” Instituting a
contiguous BES with Inclusion I2, for example, would result in a substantially over-inclusive BES
definition. The adoption of a “contiguous” BES is therefore likely to result in imposition of reliability
standards on a substantial number of distribution elements that have nothing to do with improving or
protecting the reliability of bulk transmission system. There is no compelling reason to adopt a
“contiguous” BES that covers local distribution systems. Section 215 of the FPA provides FERC with
jurisdictional authority over “users” as well as “owners” and “operators” of the bulk power system.
Consequently, FERC has the jurisdictional authority to require generation and other entities to comply
with applicable NERC requirements. Hence, even where an entity does not own or operate BES assets,
it could still be required, for example, to provide necessary information to the applicable Reliability
Coordinator or Planning Coordinator and to participate in programs to prevent instability, uncontrolled

separation, or cascading outages to the bulk transmission system. This approach would fully achieve
the goals of bulk transmission system reliability without imposing the full BES regulatory compliance
burden on local distribution elements. • Although not specifically the responsibility of the SDT, it
should closely coordinate its efforts with the team developing the inclusion/exclusion process in the
ROP. For instance, if the ROP team develops an overly onerous process to exclude elements which are
not required to reliably operate the interconnected BES yet are not excluded through the bright-line
definition then PacifiCorp would consider the bright-line definition to be over-inclusive.
Individual
Peter Mackin
Utility System Efficiencies, Inc.
Yes
USE believes the final phrase in I1 more appropriately should be “…unless excluded under Exclusions
E1 or E3.” Also, the term “two windings” may be technically incorrect because some transformers
may only have one winding per phase. This wording would exclude single-winding transformers (e.g.,
autotransformers) at or above 100 kV. One option may be to change the language to “two terminals”
instead of “two windings.” It may also be useful to clarify that transformers with one terminal above
and one terminal below 100 kV should be excluded.
No
The 20 MVA threshold appears to have been drawn without explanation from the existing NERC
Statement of Compliance Registry. Given that the purpose of the Compliance Registry is to sweep in
all generators that might be material to the operation of the BES, and not to definitively determine
whether a given generator is, in fact, material to the operation of the BES, the STD has acted
arbitrarily and without adequate technical justification in adopting the 20 MVA threshold. In
responding to comments on its initial proposal, the SDT states that it adopted the 20 MVA threshold
because “there is no technical basis to change the values contained in the Statement of Compliance
Registry Criteria.” Consideration of Comments on Definition of Bulk Electric System – Project 201017, March 30, 2011, at 30. But this response gets the equation backwards. The SDT must have some
technical justification for adopting the 20 MVA threshold beyond the fact that it was previously
adopted by NERC in a different context. Without a technical justification demonstrating that facilities
operating at capacities as low as 20 MVA are “needed to maintain transmission system reliability,” the
proposed definition is overly broad and fails to comply with the restrictions imposed by Congress in
FPA Section 215(a)(1), 16 U.S.C. § 8240(a)(1). Further, the Statement of Compliance Registry was
adopted without the benefit of having been vetted through the NERC Standards Development Process,
so the technical record underlying the choice of that threshold is unavailable for review by the
industry.
No
USE is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn
from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore properly included in the BES definition.
Yes
No
USE agrees that it is important to address wind generation facilities and similar generation facilities in
which a large number of generating units, each with a relatively small capacity, are clustered and fed
into the grid at a single interconnection point. That being said, Snohomish is concerned that the 75
MVA threshold has been chosen arbitrarily for the reasons stated in our comments on Question 4.
Yes
USE agrees in concept with this Exclusion. However, it is unclear what is required to demonstrate the
“make-before-break” connection. Is this statement intended to mean that the normally-open switch is
mechanically or electrically interlocked to ensure the “make-before-break” requirement is met? It
would be a normal switching practice to close the normally-open switch to make the parallel before

opening the normally-closed switch, but is the normal switching practice sufficient to make this claim?
Also, it is unclear whether the automatic interruption device itself is a part of the BES.
No
As noted in USE's response to Question 3, we believe the inclusion of the 20 MVA threshold (through
reference to Inclusion I2) lacks an adequate technical justification in this context. In addition, whether
or not there is provision of standby, back-up, and maintenance power services to the unit(s) or the
load is irrelevant to the reliable operation of the interconnected bulk transmission grid, and we
therefore believe the item (ii) in this Exclusion should be eliminated.
Yes
USE agrees in concept with this Exclusion. However, in sub-bullet b), as noted in our response to
Question 4, there is no technical justification for the 75 MVA threshold on connected generation. In
sub-bullet c), it should be clarified whether this requirement is at any time or is for hourly integrated
values. Also in sub-bullet e), the use of the term “major transfer paths” should be modified to be
“major transfer paths in the Table titled Major WECC Transfer Paths in the Bulk Electric System.”
Finally, the reference to “above 100 kV” should be “at or above 100 kV” for consistency with the rest
of the definition.
Yes
Yes
No
The definition should also reference the exception process and technical justification allowed for
further inclusion or exclusion from the BES.
Individual
Keith Morisette
Tacoma Power
Tacoma Power generally supports clarifying changes to the BES definition by the SDT and the goal of
including only those facilities that materially impact the reliable operation of the interconnected bulk
transmission system. We propose one change to help guide the industry as the definition is applied.
Currently, the definition includes the clause ‘unless such designation is modified by the list shown
below,’ positioned after the reactive resources clause. Due to the position of the clause, it can be
misinterpreted to apply only to reactive resources. To eliminate this ambiguity, we suggest that the
proposed definition be reordered to read as follows: “Bulk Electric System (BES) definition: (A) Unless
included or excluded in Section B below, the BES consists of: (1) All Transmission Elements operated
at 100 kV or higher; (2) Real Power resources identified in Section B below; and (3) Reactive Power
resources connected at 100 kV or higher. (B) [BES designation criteria, list of inclusions and
exclusions].” Additionally, the BES definition should not require the inclusion of contiguous elements
as the definition is further developed. Lastly, the proposed BES definition for comments is not clear on
the state of the system conditions (normal or emergency) that should be assumed when applying the
definition. The definition should apply to only normal operating conditions.
Tacoma Power agrees with Inclusion I1. However, we believe the reference to ‘two windings’ is
ambiguous and propose changing it to read, “Transformers, other than Generator Step-up (GSU)
transformers, including Phase Angle Regulators, with two or more connections to Elements at 100 kV
or higher, unless excluded under Exclusions E1 and E3.”

Tacoma Power generally supports Inclusion I2. However, the term ‘gross nameplate rating’ is not
defined and should be replaced with a specific definition. Additionally, no justification for the 20 MVA
level has been provided and therefore it appears arbitrary. Since this measurement will define
Elements for absolute inclusion in the BES, the threshold for generation units should be based on a
need to maintain transmission reliability. Generation units located within a Local Distribution Network
(LDN), which do not exit the LDN, should not be included. We propose changing Inclusion I2 to read,
“Individual generating units greater than 20 MVA (ratings based on the Code of Federal Regulation,
CFR 18, Part 11.1 definition “Authorized Installed Capacity”) including the generator terminals
through the GSU which has a high side voltage of 100 kV or above, except generating units that are
within a Local Distribution Network (LDN) and do not have a net export out of the LDN.”
Tacoma Power generally supports Inclusion I3. However, the term ‘gross aggregate nameplate rating’
is not defined and should be replaced with a specific definition. Additionally, no justification for the 75
MVA level has been provided and therefore it appears arbitrary. Since this measurement will define
Elements for absolute inclusion in the BES, the threshold for multiple generation units located at a
single site should be based on a need to maintain transmission reliability. Such single sites located
within a Local Distribution Network (LDN), which do not exit the LDN, should not be included. We
propose changing Inclusion I3 to read, “Multiple generating units located at a single site with an
aggregate capacity greater than 75 MVA (aggregate capacity based on the Code of Federal
Regulation, CFR 18, Part 287.1, “Determination of powerplant design capacity”) including the
generator terminals through the GSUs, connected through a common bus operated at a voltage of
100 kV or above, except multiple generating units located at a single site that are within a Local
Distribution Network (LDN) and do not have a net export out of the LDN.”
Tacoma Power generally supports Inclusion I4. We believe additional consideration should be given to
identifying only the Blackstart Resources that support a regional recovery. Based on that criteria, we
propose changing Inclusion I4 to read, “Blackstart Resources and the designated blackstart Cranking
Paths identified in the Transmission Operator’s restoration plan, regardless of voltage, and included in
a regional restoration plan.”
Tacoma Power generally supports Inclusion I5. However, the term ‘gross aggregate nameplate rating’
is not defined and should be replaced with a specific definition. Additionally, no justification for the 75
MVA level has been provided and therefore it appears arbitrary. Since this measurement will define
Elements for absolute inclusion in the BES, the threshold for dispersed power producing resources
should be based on a need to maintain transmission reliability. Further, there is no traceable
definition for ‘collector system.’ Rather than defining it, it can be replaced with a ‘common
interconnection point.’ Lastly, such dispersed resources located within a Local Distribution Network
(LDN), which do not exit the LDN, should not be included. We propose changing Inclusion I5 to read,
“The common interconnection point for dispersed power producing resources with aggregate capacity
greater than 75 MVA (aggregate capacity based on the Code of Federal Regulation, CFR 18, Part
287.1, “Determination of powerplant design capacity”) connected to an Element that is part of the
BES, except for common interconnection points that are within a Local Distribution Network (LDN)
and do not have a net export out of the LDN.”
Tacoma Power supports Exclusion E1.
Tacoma Power generally supports Exclusion E2. However, no justification for the 20 MVA and 75 MVA
levels in Inclusion I2 and Inclusion I3 have been provided and therefore they appear arbitrary. Since
this measurement will define Elements for absolute inclusion in the BES, the thresholds should be
based on a need to maintain transmission reliability. We strongly urge the SDT to accept our
proposed changes to Inclusion I2 and Inclusion I3, listed above in items 3 and 4.
Tacoma Power generally supports Exclusion E3 that provides for the exclusion of Local Distribution
Networks (LDNs) from the BES, with the following modifications: 1) It is not necessary to articulate
the nature of the LDN’s connection to the BES. If the characterizations are met, the number of
connections and the reasons for the connections are immaterial. 2) If the LDN is a normal net import,
there is no need to limit the amount of connected generation since the generation will have no
material effect on the BES. 3) ‘Bulk power transfers’ are acceptable across an LDN if the transfer is to
a nested LDN. Contractual energy, originating outside the LDN and delivered to a nested LDN, for
example, is still load delivery and has the same physical characteristics of a holistic LDN and the
transfer of bulk power is immaterial. We propose changing Exclusion E3 to read, “Local Distribution
Networks (LDN): Groups of Elements operated above 100 kV that distribute power to Load rather
than transfer bulk power across the Interconnected System. The LDN is characterized by all of the

following: a) Separable by automatic fault interrupting devices: Wherever connected to the BES, the
LDN must be connected through automatic fault-interrupting devices; b) c) Power flows only into the
Local Distribution Network: The generation within the LDN shall not exceed the electric Demand
within the LDN; d) Not used to transfer bulk power, except transfers to nested LDNs: The LDN is not
used to transfer energy originating outside the LDN for delivery through the LDN, except transfers to
nested LDNs; and e) Not part of a Flowgate or Transfer Path: The LDN does not contain a monitored
Facility of a permanent flowgate in the Eastern Interconnection, a major transfer path within the
Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the
Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability
Operating Limit (IROL).”
Tacoma Power supports the SDT’s thoughtful approach to minimizing impacts to small entities. They
have no measureable impact to the BES and should not be burdened with the exemption process.
Tacoma Power supports the work of the SDT towards a revised BES definition directly linked to the
exemption process of inclusions and exclusions. The definition must be closely coupled to the
exemption process and the two must move forward together. This will ensure that only the facilities
that materially impact the reliability of the BES will be burdened with the regulatory requirements.
Tacoma Power is not aware of any conflicts at this time.
Tacoma Power supports the SDT’s efforts to create an acceptable BES definition directly linked to an
exemption process. Please be aware that the WECC has a task force, the Bulk Electric System
Definition Task Force (BESDTF), which has done some notable work on this task. See WECC BESDTF
Proposal 6, Appendix C (http://www.wecc.biz/Standards/Development/BES/default.aspx). The BES
definition is very complex and the BESDTF has already addressed many of the tough issues that have
yet to be addressed in this process, such as: • Local Distribution Network definition for automatic
exemption • Determination of radial facilities • Demarcation of BES and non-BES Elements • Alternate
dispute resolution process • Assignment of the burden of proof for the exemption process • Technical
approach for the inclusion/exclusion determination Thank you for consideration of our comments.
Individual
Russell A. Noble
Cowlitz County PUD
No
Cowlitz supports the approach the Standards Development Team (“SDT”) has taken to defining the
Bulk Electric System (“BES”). The changes made in the revised core definition are helpful and
represent significant progress toward an acceptable definition. With an effective and efficient
exclusion process, the new definition will better define the BES as a whole. However, the SDT should
bear in mind the restrictions contained in Section 215 of the Federal Power Act (“FPA”) regarding the
definition of the term “bulk-power system” and FERC’s past statements in acceptance of NERC’s term
“bulk electric system.” FERC clearly states that the statutory term “bulk-power system” is not clearly
defined, but also cannot be subject to the ANSI standard development process under the ERO.
Further, FERC has “chosen to defer, for the time being, to the ERO as to which entities must comply
with Reliability Standards,” and rely on the NERC definition of “bulk electric system” to facilitate this
end. Therefore, although the SDT may not attempt to define “bulk-power system” or equate it as
equal to the BES, the SDT should make every effort to draw upon the stated restrictions within the
FPA concerning the “bulk-power system” in its revised BES definition. The “bulk-power system”
definition imposes limits on the reach of the mandatory reliability regime as those “facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof)” and “electric energy from generation facilities needed to maintain transmission
system reliability.” Further, “[t]he term does not include facilities used in the local distribution of
electric energy.” Congress reinforced that limit in Section 215(i), where it emphasized that the FPA
authorizes the imposition of reliability standards “for only the bulk-power system.” Cowlitz is
concerned that the SDT’s proposed definition is overly-broad, and that it will sweep in many Elements
that have little or no material impact on the reliable operation of the interconnected bulk transmission
grid. For example, the definition uses the arbitrary 20 MVA threshold from the NERC Statement of
Registry Criteria for inclusion of generators. Accordingly, for the BES definition to conform to the
requirements of the statute, the SDT must adopt an effective mechanism to exempt facilities like
these that are improperly swept in by the SDT’s brightline approach to inclusions and exclusions. For
this reason, the Exception and Inclusion process to accompany the SDT’s core definition is of critical

concern. However, the revised core definition should by default exclude those elements of the electric
system that unquestionably are not necessary for operating an interconnected electric energy
transmission network. Likewise, the revised core definition should by default include only those
elements that unquestionably are necessary. From this, the SDT can further define a subset and
provide adequate technical basis for each inclusion and exclution. Cowlitz believes the core definition
should reflect the statutory limits, while at the same time realizing that the BES is a subset thereof.
Taking from FERC’s past orders, the full set of facilities, control systems, and generation of the “bulkpower system” need not all be subject to enforceable reliability standards; a sub-set is permissible as
long as there is sufficient technical basis for any exclusion. For now, FERC has allowed
unsubstantiated exclusions (e.g. generation below 20 MW) due to the need for expedient
implementation of standards, yet allowing for some relief towards unwarranted over compliance
burden. Cowlitz suggests a core definition as follows: “Interconnected Transmission Elements,
generation resources necessary to maintain the interconnected Transmission Elements reliability
unless such designation is modified by the list shown below. Local distribution facilities are excluded.”
Cowlitz believes the 100 kV demarcation should be removed from the core definition since it is
necessary to allow for certain lower voltage interconnected facilities to be included in the BES for
reliability; this demarcation should be relocated in the Inclusions listing along with provision for
including lower voltage facilities. If the SDT incorporates this statutory language as its core definition,
it will have addressed FERC’s primary concern with a minimum of disruption to the current NERC
system of definitions. The definition could then be further elaborated to show specific points of
demarcation for each inclusion and exclusion similar to that Proposal 6 from the WECC Bulk Electric
System Definition Task Force (“BESDTF”) team to further delineate BES and non-BES facilities.
Finally, Cowlitz proposes the following concept: for the “bulk-power system” to be reliable, not all its
elements need be reliable unto themselves. If the BES as a subset is properly defined, and is
successfully maintained and operated reliably, then the rest of the “bulk-power system” will then
benefit and be reliable as a whole.
No
In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and nonBES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is
stepped down from transmission voltages to distribution voltages. We believe, however, that the SDT
should undertake the effort to more clearly define the point where the BES ends and non-BES
systems begin. In this regard, we note that the WECC Bulk Electric System Definition Task Force
(“BESDTF”) has devoted considerable effort to this question and has developed one-line diagrams
noting the BES demarcation point for a number of different kinds of Elements that are common in the
Western Interconnection. Using this work as a starting point, the SDT should be able to provide much
useful guidance to the industry with relatively little additional effort. Also, the reference to “two
windings of 100 kV or higher” may create some confusion because many three-phase transformer
banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We suggest
clarifying this provision by changing the clause reference two windings to read: “with two voltage
transformer windings of 100 kV or higher per phase that are connected to an interconnected
transmission system unless excluded...” We again urge the SDT to consider further delineation of
points of demarcation similar to WECC BESDTF Proposal 6.
No
Cowlitz is concerned that I2 inclusion criteria that includes the arbitrary 20 MVA threshold from the
NERC Statement of Registry Criteria for inclusion of generators is over-inclusive. We believe that after
thorough engineering review, this value should increase. Under FPA Section 215, generation
resources are excluded from the “bulk-power system” unless they produce “electric energy” that is
“needed to maintain transmission system reliability.” Hence, the inclusion as drafted improperly
expands the BES definition to include generators that the statute requires to be excluded. We
understand that it is not in the scope of the SDT to redefine the Registry Criteria, however we also
believe it is not proper for the SDT to use the Registry Criteria as a measure of what to include in the
BES. Again we reiterate that the BES is a subset of the “bulk-power system” (BPS). As such, other
elements of the BPS can be subject to limited standard compliance to assure reliability of the BES, but
not for reliability unto itself. Development of decentralized generation should not be discouraged by
overregulation as it in aggregate is more difficult to mount an attack to neutralize it. In the same
comments, the SDT also states that it has considered “the inclusion of generator step-up (GSU)
transformers and associated interconnection line leads and believes the BES must be contiguous at

this level in order to be reliable.” Unfortunately, the SDT appears to have concluded that any
interconnection facility operating above 100-kV should be classified as BES. The result will be to
require Generation Owners to register as Transmission Owners/Operators, as well, producing
substantial additional compliance costs for those Generation Owners but resulting in little or no
improvement in the reliability of the BES. We recommend that the SDT, like the Project 2010-07 SDT
(commonly referred to as the GO/TO Team), give careful consideration to the practical results of its
recommendations rather than relying on abstract conclusions about whether a “contiguous” or “noncontiguous” BES is more desirable. We are concerned that the SDT’s pursuit of a “contiguous” BES
will result in a substantially over-inclusive BES definition. The “contiguous” BES concept implies that
every Element arguably necessary for the reliable operation of the interconnected bulk system must
be included in the BES definition, even if it is interconnected with Elements that have no bearing on
the operation of the BES. NERC’s Standards Drafting Team for Project 2010-07, has already
considered this question and, based on an in-depth review of potentially applicable reliability
standards, has concluded that generation interconnection facilities, even if operated above 100-kV,
need to comply only with a limited set of reliability standards in order to achieve the reliability goals.
Much of the work of the Project 2010-07 SDT is applicable to the work of the BES Standards
Development Team. For example, the Project 2010-07 Team observed that interconnection facilities
“are most often not part of the integrated bulk power system, and as such should not be subject to
the same level of standards applicable to Transmission Owners and Transmission Operators who own
and operate transmission Facilities and Elements that are part of the integrated bulk power system.”
Similarly, a “contiguous” BES suggests that, because certain system protection facilities, such as UFLS
relays, are ordinarily embedded in local distribution systems, the local distribution system, along with
the UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would, by
improperly classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability.
No
Cowlitz is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20
MVA threshold discussed in our response to question 3, the 75 MVA threshold appears to have been
drawn from the NERC Statement of Compliance Registry without appreciation for the function of the
threshold in that document and without adequate technical justification demonstrating the generators
with an aggregate capacity of 75 MVA produce electric energy “needed to maintain transmission
system reliability” and are therefore not properly included in the BES definition.
Yes
Including “all” blackstart and blackstart cranking paths in the BES may ultimately provide an incentive
to the electric industry to reduce the number of resources with blackstart capability. We therefore
suggest that essential blackstart resources identified by the Regional Entity or Transmission Operator
should be included in the Bulk Electric System, but non-essential blackstart resources need not be.
No
Cowlitz agrees that it is important to address wind generation facilities and similar generation facilities
in which a large number of generating units, each with a relatively small capacity, are clustered and
fed into the grid at a single interconnection point. That being said, we are concerned that the 75 MVA
threshold has been chosen arbitrarily for the reasons stated in our comments on Question 4.
Yes
FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained. Cowlitz believes the exclusion as drafted adequately defines radials. Further, we would point
out that two transmission systems that are operated radial with a normal open between them can’t be
operated reliably with the normal open indefinitely closed. Such extended closures are not possible
were transmission protection systems are not designed for networked systems.
No
As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through
reference to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the
generation unit is reliability-must-run or essential blackstart, the function of the unit is irrelevant to
the reliable operation of the interconnected bulk transmission grid, and we therefore believe the
reference to the function of the generation unit (“standby, back-up, and maintenance power…”)
should be eliminated.

Yes
Cowlitz strongly supports the categorical exclusion of Local Distribution Networks from the BES. In
fact, for reasons discussed at length in our answer to Question 1, we believe the exclusion is
necessary to ensure that the BES definition complies with the statutory requirement to exclude all
facilities used in the local distribution of electric power. LDNs are, of course, probably the most
common kind of local distribution facility. Further, the conversion of radial systems to local
distribution networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. Cowlitz supports the
LDN exclusion, but we believe the exclusion should be refined in the following respects: • The SDT’s
draft states that: “LDN’s are connected to the Bulk Electric System (BES) at more than one location
solely to improve the level of service to retail customer Load.” (emphasis added) We recommend that
the SDT revise the sentence quoted above as follows: “LDN’s are connected to the Bulk Electric
System (BES) at more than one location solely to improve the level of service to retail customer Load
and not to accommodate bulk transfers of power across the interconnected bulk system.” By
instituting this suggestion, the SDT would emphasize the key difference between an LDN, which is
designed to reliably serve local, end-use retail customers, and the BES, which is designed to
accommodate bulk transfer of power at wholesale over long distances. We propose that a reliable BES
will help insure a reliable LDN. If the LDN is not reliable, it should then be an issue to be resolved by
the local authorities. If the BES is not reliable, the local authorities lack the tools to remedy the
situation.
Yes
Cowlitz supports the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that can ill afford the substantial costs that accompany
imposition of mandatory compliance with reliability standards. Further, we agree that the small
utilities covered by the exemption will have no measurable impact on the operation of the
interconnected BES. In the Pacific Northwest, many small entities were required to register by virtue
of owning a very small portion of the region’s 115-kV system. These utilities have faced substantial
compliance burdens even though their operations are simply not material to the interconnected bulk
grid in our region, and the investment of resources in compliance therefore will have no measurable
effect in improving the reliability of the interconnected grid. Further, the such resources used to
comply with the reliability efforts unjustly take away from necessary resources needed for local
quality of service efforts.
No
While Cowlitz agrees that the approach adopted by the SDT -- a core definition coupled with specific
inclusions and exclusions – will be effective in removing most local distribution facilities from the BES,
it will not remove all such facilities. For the reasons discussed at greater length in our answer to
Question 1, Cowlitz believes that the proposed definition is over-inclusive and is likely to sweep up
certain facilities used in local distribution that should not be classified as BES. As discussed in our
answers to several questions, Cowlitz notes that exclusion of facilities from the BES does not mean
that owners of those facilities are entirely exempt from reliability standards. On the contrary, the
statute provides that “users” of the BPS can be subject to reliability regulation. Hence, even where an
entity does not own BES or BPS assets, it could be required to, for example, provide necessary
information to the applicable Reliability Coordinator and to participate in the regional UnderFrequency Load Shedding program by setting the UFLS relays in its Local Distribution Network at the
appropriate settings. We note that participants in the WECC BESDTF Task Force generally agreed that
appropriate information should be provided by non-BES entities, although there was considerable
concern related to ensuring that the provision of information was not unduly burdensome.
Yes
The Exceptions process is a necessary part of making this proposal complaint with the Federal Power
Act. As noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is
potentially in conflict with the limitations of the Federal Power Act, and in particular the statutory
exclusion for facilities used in the local distribution of electric energy. The SDT’s approach can meet
the statutory requirements only if the Exception process currently under development results in
facilities that are not properly classified as BES being exempted from regulation as BES facilities.
Cowlitz understands the difficulty in demonstrating what is and is not distribution to FERC due to the
vague statute language. Cowlitz will work to help provide technical arguments which will buttress the
BES definition in the future.

Cowlitz has these additional concerns: • The current definition provides that “Elements may be
included or excluded on a case-by-case basis through the Rules of Procedure exception process.”
Cowlitz is concerned that the SDT carefully delineate which entity has the burden of proof in the
exclusion process. The WECC BESDTF approach, which we commend to the SDT, laid out these
burdens in some detail. Under that approach, essentially, if a facility is excluded from the BES by
virtue of the specific exclusions listed in the definition, the Regional Entity bears the burden of proving
that the facility nonetheless has a material impact on the interconnected bulk transmission system
and therefore should be included in the BES. On the other hand, if a facility is classified as BES by
virtue of the list of inclusions set forth in the BES definition, it can still escape classification as BES,
but bears the burden of demonstrating that its facility has no material impact on the interconnected
transmission system. We urge the SDT to give careful consideration to these burden-of-proof
questions and to follow the lead of the WECC BES Task Force. • For the reasons we have explained in
our answer to Question 11, we believe the Exception process is critical both to ensure that the BES
definition is effective in producing measurable gains to bulk system reliability and to ensuring that the
definition will comply with the limitations Congress placed in Section 215. Hence, we believe the
entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES
definition have been assigned to the Rules of Procedure Team, and that changes in the Rules of
Procedure are subject to approval in a process that provides considerably less due process and
industry input than the Standards Development Process. Accordingly, we urge that all elements of the
BES definition, including those elements that have been assigned to the Rules of Procedure Team, be
vetted through the Standards Development Process.
Individual
Mihai Cosman
California Public Utilities Commission
Yes
The CPUC supports the changes, especially the exclusions and the flexibility given to facilities to prove
that they are not part of the BES. However, the CPUC is concerned about the automatic imposition of
deterministic standards that are arbitrary rather than technically-based: (1) the 100kV “bright line”
test for transmission facilities, and the (2) 20 MVA threshold for generating units. In general, the
current BES definition is largely deterministic rather than based on economics or probabilities. An
arbitrary number such as a “bright line” test should not be the singular gauge for inclusion in the BES.
A robust BES definition should consider the actual impact on the system and the cost. The courts
have spoken on the issue, Illinois Commerce Commission v. Federal Energy Regulatory Commission,
576 F.3d 476, and instructed FERC to approve projects, “pricing scheme”, only if the benefits
outweigh the cost. Further, the 20 MVA threshold for generating facilities is coincident with the NERC
threshold for registered entities. While a logical threshold to require generators to register with NERC,
the required reliability assessments, and subsequent reliability upgrades may be prohibitively
expensive for small generating units.
Yes
The CPUC would like a technical justification/rational for the 20 MVA threshold. We understand and
agree with the ability to show no impact through a technical impact assessment, but such an
assessment may be costly for a small 20-50 MW peaker plant that may operate for few hours during
any given month. The cost imposed to small generating plants that operate a few hours a month may
be too excessive given the probability of the generator causing an event and the cost associated with
the event. The BES definition should be more than a deterministic standard and should properly
assess every asset it proposes to include, especially given what the courts have ruled. We believe it
would be preferable to include individual elements at power plants that can impact the BES
(governors, system stabilizers, breakers,…) rather than to extend the definition of the BES to include
all small power plants.

Consideration of Comments on the Revisions Made to the Definition of Bulk
Electric System — Project 2010-17
The Definition of Bulk Electric System Drafting Team thanks all commenters who submitted
comments on the revisions made to the definition of BES. The definition and supporting
documents were posted for a 30-day public comment period from April 28, 2010 through
May 27, 2010. The stakeholders were asked to provide feedback on the standards through
a special Electronic Comment Form. There were 154 sets of comments, including comments
from more than 279 different people from approximately 213 companies representing 10 of
the 10 Industry Segments as shown in the table on the following pages.
http://www.nerc.com/filez/standards/Project2010-17_BES.html
The SDT has made numerous clarifying changes to the definition due to comments received:
•

The bright-line core definition has been revised to clarify that all Transmission
Elements at 100 kV or higher and Real Power and Reactive Power resources
connected at 100 kV or higher are to be included in the BES unless there is a
modification for a particular Element in the Inclusion or Exclusion lists.

•

An additional inclusion (I5) was developed for Reactive Resources and an additional
exclusion (E4) was developed to clarify that Reactive Resources that are owned by
retail customers for their own use are not to be included.

•

In Inclusion I1, deleted the Generator Step-Up and Phase Angle Regulating
transformer language, changed the wording from “windings” to “terminals”, and
added the terms “primary” and “secondary”.

•

Inclusion I2 has been eliminated and Inclusion I3 (now numbered as Inclusion I2)
has been revised to include generating resourceswith gross aggregate nameplate
rating per the ERO Statement of Compliance Registry Criteria for consistency
between the two documents.

•

The SDT agreed that Cranking Paths identified in a Transmission Operator’s
restoration plans are often composed of distribution system elements and has
removed the inclusion for Cranking Paths.

•

Inclusion I4 has been revised to eliminate the term ‘collector system.’

•

Within Exclusion E1, the SDT clarified the point of connection, removed the
automatic interrupting device, moved the concept of the normally open switch to a
note, and clarified the generation allowed within the system.

•

Within Exclusion E2, the SDT clarified the generation allowed within the system

•

Within Exclusion E3, the SDT eliminated the term “Distribution” in the label,
eliminated the provision which referred to automatic fault interrupting devices,
clarified the connection point of the local network, inserted a provision in the local
network exclusion to limit the operating voltage of the local network to 300 kV, and
effectively removed the comparison test between generation and minimum demand
of the local network.

•

Included in the core definition a statement that excludes facilities used in local
distribution of electric energy.

116-390 Village Blvd.
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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System —
Project 2010-17

Several commenters objected to simply carrying through the generation thresholds
from the ERO Statement of Compliance Registry Criteria as part of the revised
definition. However, no respondents provided technical justifications for changing
these values. Furthermore, the scope of this project deals mainly with responding to
FERC Orders 743 and 743a which clearly stated that the intent of the order was to
maintain the status quo and to only address those urgent issues identified in the
Orders. After consulting with the NERC Board of Trustees and the NERC Standards
Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic
justice with the mandated schedule. Therefore, the primary focus of the SDT efforts
will be to address the directives in Orders 743 and 743a. However, this does not
mean that the other issues will be dropped. Both the NERC Board of Trustees and
the NERC Standards Committee have endorsed the idea that the Project 2010-17
SDT take a phased approach to this project with a new Standards Authorization
Request (SAR) to address generation thresholds as well as several other issues that
have arisen from SDT deliberations. Issues such as what is necessary for the reliable
operation of the BES, whether the BES needs to be contiguous, possible
interconnection differences, who are users of the BES, and correlation of the
definition of BES and the ERO Statement of Compliance Registry Criteria will be
addressed with this new SAR. The proposed SAR has been posted for information
purposes only concurrent with the second posting of this project. A formal comment
period will follow.
The following minority opinions did not result in changes to the definition:
•

The SDT retained the inclusion for Blackstart Resources although some commenters
thought it should be deleted. The Commission directed NERC to revise its BES
definition to ensure that the definition encompasses all facilities necessary for
operating an interconnected electric transmission network. The SDT interprets this
to include operation under both normal and Emergency conditions, which include
situations related to blackstarts and system restoration. Blackstart Resources have
the ability to be started without support from the System or can be energized
without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability,
frequency, and voltage control. The associated resources of the electric system that
can be isolated and then energized to deliver electric power during a restoration
event are essential to enable the startup of one or more other generating units as
defined in the Transmission Operator’s system restoration plan. For these reasons,
the SDT continues to include Blackstart Resources indentified in the Transmission
Operator’s restoration plan as BES Elements.

•

The SDT considered commenters’ suggestions regarding allowance of some power
flow out of the local network, and concluded that strict limits precluding out-flow are
appropriate, particularly given that the local network comprises facilities that are
electrically parallel to the BES.

In addition, in response to comments received, the SDT has clarified the effective date in
the Implementation Plan.
The SDT proposes to move this project to the 45-day parallel comment and initial ballot
stage.

August 19, 2011

2

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System —
Project 2010-17

If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at herb.schrayshuen@nerc.net. In addition, there
is a NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
August 19, 2011

3

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System —
Project 2010-17

Index to Questions, Comments, and Responses
1.

The SDT has made clarifying changes to the core definition in response to industry
comments. Do you agree with these changes? If you do not support these changes or
you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. ......................................... 22

2.

The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................... 69

3.

The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I2? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................... 90

4.

The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I3? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................. 135

5.

The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I4? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................. 160

6.

The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I5? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................. 183

7.

The SDT has added specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E1? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................. 206

8.

The SDT has added specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E2? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................. 242

August 19, 2011

4

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System —
Project 2010-17

9.

The SDT has added specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E3? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ................................................. 268

10.

The SDT is discussing an exclusion from the Bulk Electric System (BES) for small
utilities based on statements in Order No. 743 that FERC does not believe its
suggested approach to the BES definition and exemption process will have a
significant economic impact on a substantial number of small entities and that small
entities will not adversely impact the reliability of the Bulk Electric System. The SDT
has been made aware that organizations that are not presently required to be
registered by the NERC Statement of Compliance Registry Criteria would meet the
requirements to be registered as Transmission Owners given the current proposed
BES definition. These small utilities could use the Rules of Procedure (ROP) exception
process but this may be an issue that could be handled more appropriately through
the BES definition. This would alleviate the paperwork burden for these small utilities
and also avoid a possibly unnecessary and significant impact on the administration of
the ROP exception process during the transition period to the revised BES definition.
The proposed exclusion language is: Exclusion E4: Transmission Elements, from a
single Transmission source connected at a voltage of 100 kV or greater, owned by a
small utility whose connection to the BES is solely through this single Transmission
source, and without interconnected generation as recognized in the BES Designation
Inclusion Items I2, I3, I4, or I5. A small utility is recognized as an entity that
performs a Distribution Provider or Load Serving Entity function but is not required to
register as a Distribution Provider or Load Serving Entity by the ERO. Do you agree
with this approach and the proposed language? If not, please be specific in your
response with a technical reason for your disagreement and, if appropriate, suggested
language for such an exclusion if you agree in general but feel that alternative
language would be more appropriate. ............................................................... 340

11.

In Order No. 743, the Commission addressed the need to differentiate between
Transmission and distribution in the revised definition of the Bulk Electric System
(BES). Specifically, the Commission stated that local distribution facilities are to be
excluded from the BES. The SDT believes that it has excluded local distribution
facilities through the revised bright-line core definition and specific inclusions and
exclusions. Do you agree with this position? If not, please provide specific comments
and suggestions on what else needs to be addressed or added. ........................... 357

12.

Are you aware of any conflicts between the proposed definition and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement, or
jurisdictional issue? If so, please identify them here and provide suggested language
changes that may clarify the issue. .................................................................. 390

13.

Are there any other concerns with this definition that haven’t been covered in previous
questions and comments? ............................................................................... 410

August 19, 2011

5

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Mikhail Falkovich

Public Service Enterprise Group LLC

X

2

3

X

4

5

6

X

X

7

8

9

10

Additional Member Additional Organization Region Segment Selection
1. Clint Bogan

NPCC 5, 6

2. Ken Brown

RFC

1

3. Jeffrey Mueller

RFC

3

4. Peter Dolan

RFC

6

2.

Group
Additional Member

Guy Zito

Northeast Power Coordinating Council

Additional Organization

X

Region Segment Selection

1. Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC 3

2. Gregory Campoli

New York Independent System Operator

NPCC 2

3. Kurtis Chong

Independent Electricity System Operator

NPCC 2

4. Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5. Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1
6. Gerry Dunbar

Northeast Power Coordinating Council

NPCC 10

7. Mike Garton

Dominion Resources Services, Inc.

NPCC 5

August 19, 2011

6

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

8. Brian L. Gooder

Ontario Power Generation Incorporated

NPCC 2

10. Chantel Haswell

FPL Group, Inc.

NPCC 5

11. David Kiguel

Hydro One Networks Inc.

NPCC 1

12. Michael Lombardi

Northeast Utilities

NPCC 1

13. Randy MacDonald

New Brunswick Power Transmission

NPCC 1

14. Bruce Metruck

New York Power Authority

NPCC 6

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

16. Robert Pellegrini

The United Illuminating Company

NPCC 1

17. Si Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

18. Saurabh Saksena

National Grid

NPCC 1

19. Michael Schiavone

National Grid

NPCC 1

20. Wayne Sipperly

New York Power Authority

NPCC 5

21. Donald Weaver

New Brunswick System Operator

NPCC 1

Orange and Rockland Utilities

NPCC 1

22. Ben Wu

Group

Bill Middaugh

Additional Member

Tri-State Generation and Transmission
Association, Inc.
Additional Organization

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

2. Rick Ashton

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

3. Mark Graham

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

4. Chris Pink

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

5. Marlene Marquez

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

6. Mark Conner

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

7. Keith Carman

Group

4

5

6

X

X

7

8

9

10

X

X

Region Segment Selection

1. Michael Houglum

4.

3

NPCC 5

9. Kathleen Goodman ISO - New England

3.

2

Tri-State Generation and Transmission Association, Inc. WECC 6, 1, 3, 5

Kevin Koloini

American Municipal Power and Members

X

X

X

Additional Member Additional Organization Region Segment Selection

August 19, 2011

7

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1. Steve Harmath

City of Orrville

5.

Scott Berry

Group
Additional Member

RFC

4

5

X

X

6

7

8

9

10

X

Region Segment Selection

1. Kevin Koloini

American Municipal Power, Inc.

RFC

4

2. Mark Ringhausen

Old Dominion Electric Cooperative RFC

4

3. Gary Wright

Allegheny Electric Cooperative

RFC

4

4. Mike Tracy

Hoosier Energy REC, Inc

RFC

1

5. Bob Thomas

Illinois Municipal Power Agency

RFC

4

6. Tom Connell

Indiana Municipal Power Agency

RFC

4

6.

Sammy Alcaraz

Group

3

4

Small Entity Working Group (SEWG)

Additional Organization

2

Imperial Irrigation District

X

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Jose Landeros

IID BES Working Gp

WECC

2. Epifano Martinez

IID BES Working Gp

WECC

3. David Barajas

IID BES Working Gp

WECC

4. Chris Reyes

IID BES Working Gp

WECC

5. Fernando Gutierrez

IID BES Working Gp

WECC

6. Chris Riven

IID BES Working Gp

WECC

7. Joel Fugett

IID BES Working Gp

WECC

8. Al Minor

IID BES Working Gp

WECC

9. Juan Carlos Sandoval IID BES Working Gp

WECC

7.

Group

Frank Gaffney

Florida Municipal Power Agency

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Timothy Beyrle

City of New Smyrna Beach FRCC

4

2. Greg Woessner

Kissimmee Utility Authority FRCC

3

3. Jim Howard

Lakeland Electric

FRCC

3

4. Lynne Mila

City of Clewiston

FRCC

3

5. Joe Stonecipher

Beaches Energy Services FRCC

1

August 19, 2011

8

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

6. Cairo Vanegas

Fort Pierce Utility Authority FRCC

4

7. Randy Hahn

Ocala Electric Utility

3

8.

Terry L. Blackwell

Group

FRCC

Santee Cooper

2

X

3

X

4

5

6

X

X

7

8

9

10

X

X

Additional Member Additional Organization Region Segment Selection
1. S. T. Abrams

Santee Cooper

SERC

1

2. Rene Free

Santee Cooper

SERC

1

3. Vicky Budreau

Santee Cooper

SERC

1

SERC

1

4. Jim Peterson

Santee Cooper

9.

Group

David Taylor

NERC Staff Technical Review

10.

Group

Mark Byrd

NERC Transmission Issues Subcommittee
(TIS)

X

X

Additional Member Additional Organization Region Segment Selection
1. See TIS Roster

11.

Group

Louis Slade

Dominion

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Michael Gildea

Electric Market Policy

SERC

1, 3, 5, 6

2. Connie Lowe

Electric Market Policy

RFC

5, 6

3. Mike Garton

Electric Market Policy

MRO

5, 6

4. Matt Woodzell

F&H

SERC

5

5. Chip Humphrey

F&H

RFC

5

6. Jeff Bailey

Nuclear

NPCC 5

7. Mike Crowley

Electric Transmission

SERC

12.

Group

Robert Rhodes

1, 3

SPP Standards Review Group

X

Additional Member Additional Organization Region Segment Selection

August 19, 2011

9

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1. John Allen

City Utilities of Springfiled SPP

1, 4

2. Matt Bordelon

CLECO

SPP

1, 3, 5, 6

3. Michelle Corley

CLECO

SPP

1, 3, 5, 6

4. Louis Guidry

CLECO

SPP

1, 3, 5, 6

5. Jonathan Hayes

SPP

SPP

2

6. Tom Hestermann

Sunflower Electric

SPP

1, 5

7. Valerie Pinamonti

AEP

SPP

1, 3, 5

8. Mike Richardson

AEP

SPP

1, 3, 5

13.

Group
Additional Member

Carol Gerou

3

4

5

6

7

8

9

10

MRO's NERC Standards Review Forum

Additional Organization

X

Region Segment Selection

1. Mahmood Safi

Omaha Public Utility District

MRO

1, 3, 5, 6

2. Chuck Lawrence

American Transmission Company

MRO

1

3. Tom Webb

Wisconsin Public Service Corporation MRO

3, 4, 5, 6

4. Jodi Jenson

Western Area Power Administration

MRO

1, 6

5. Ken Goldsmith

Alliant Energy

MRO

4

6. Alice Ireland

Xcel Energy

MRO

1, 3, 5, 6

7. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

8. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

9. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

10. Scott Nickels

Rochester Public Utilties

MRO

4

11. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

12. Marie Knox

Midwest ISO Inc.

MRO

2

13. Lee Kittelson

Otter Tail Power Company

MRO

1, 3, 4, 5

14. Scott Bos

Muscatine Power and Water

MRO

1, 3, 5, 6

15. Tony Eddleman

Nebraska Public Power District

MRO

1, 3, 5

16. Mike Brytowski

Great River Energy

MRO

1, 3, 5, 6

17. Richard Burt

Minnkota Power Cooperative, Inc.

MRO

1, 3, 5, 6

August 19, 2011

2

10

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

14.

Group

Additional Member

Charles W. Long

SERC Planning Standards Subcommittee

Additional Organization

3

4

5

6

7

8

9

10

X

X

Region Segment Selection

1. Pat Huntley

SERC Reliability Corporation

SERC

10

2. John Sullivan

Ameren Services Co.

SERC

1

3. Charles Long

Entergy Services, Inc.

SERC

1

4. Philip Kleckley

South Carolina Electric & Gas Co SERC

1

5. Bob Jones

Southern Company Services

SERC

1

6. Darrin Church

Tennessee Valley Authority

SERC

1

15.

Don Mazuchowski

Group

2

Michigan Public Service Commission(MPSC)

X

Additional Member Additional Organization Region Segment Selection
1. Angie Butcher

MPSC

16.

Jason Marshall

Group

Additional Member

RFC

9

ACES Power Participating Members

Additional Organization

X

X

X

X

X

X

Region Segment Selection

1. Chris Lang

Golden Spread Electric Cooperative ERCOT 3, 4, 6

2. Chris Bradley

Big Rivers Electric Cooperative

3. James Jones

Southwest Transmission Company WECC 1

4. Liz Hayden

Arizona Electric Power Cooperative WECC 3, 5, 6

17.

Jim Case

Group

X

SERC

1, 3, 5, 6

SERC OC Standards Review Group

Additional Member Additional Organization Region Segment Selection
1. Gerald Beckerle

Ameren

1, 3

2. Scott Brame

Ameren

1, 3

3. Mike Hirst

Cogentrix

5, 6

4. Dan Roethemeyer

Dynegy

5, 6

5. Tim Hattaway

PowerSouth

1, 3, 5, 9

6. Randy Castello

Alabama Power

1, 3, 5

7. Danny Dees

MEAG

1, 3, 5, 9

August 19, 2011

11

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

8. Robert Thomasson

BREC

1, 3, 5, 9

9. Bob Dalrymple

TVA

1, 3, 5, 9

10. Andy Burch

EEI

1, 5

11. David Trego

Fayetteville PWC

1, 3, 4, 9

12. Reggie Wallace

Fayetteville PWC

1, 3, 4, 9

13. Patrick Woods

EKPC

1, 3, 5, 9

14. Darrin Adams

EKPC

1, 3, 5, 9

15. George Carruba

EKPC

1, 3, 5, 9

16. Alvis Lanton

SIPC

1, 3, 5

17. Brad Young

LGE/KU

1, 3, 5

18. Melinda Montgomery Entergy

1, 3

19. Steve McElhaney

SMEPA

1, 3, 5, 9

20. Marc Butts

Southern

1, 3, 5

21. John Troha

SERC

10

18.

Group

David Curtis

Hydro One Networks Inc

X

2

3

4

5

X

6

7

8

9

10

X

Additional Member Additional Organization Region Segment Selection
1. Bing Young

Transmission Development NPCC 1

2. David Kiguel

Hydro One Distribution

NPCC 3

3. Oded hubert

Regulatory Affairs

NPCC 9

19.

Barry Lawson

Group

National Rural Electric Cooperative
Association (NRECA)

X

Barbara Hindin

Edison Electric Institute

X

Richard Malloy

Idaho Falls Power

X

X

X

1. Patti Metro

20.
1.

Group

See EEI member
list at www.eei.org

21.

Individual

August 19, 2011

12

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Jim Lauth

City of Santa Clara, California, dba Silicon
Valley Power

2

3

4

5

6

22.

Individual

23.

Individual

Randall Ozaki

Overton Power District No. 5

X

X

24.

Individual

Richard Dearman

Tennessee Valley Authority

X

X

X

X

25.

Individual

Janet Smith

Arizona Public Service Company

X

X

X

X

26.

Individual

Brent Ingebrigtson

LG&E and KU Energy LLC

X

X

X

X

27.

Individual

John Free

Alabama Public Service Commission

28.

Individual

Michelle MIzumori

Western Electricity Coordinating Council

29.

Individual

William Drummond

Western Montana Electric Generating and
Transmission Cooperative

30.

Individual

Jim Uhrin

ReliabilityFirst

31.

Individual

Don Brookhyser

Cogeneration Association of California and
Energy Producers & Users Coalition

32.

Individual

Eddy Reece

Rayburn Country Electric Cooperative, Inc.

33.

Individual

Roger Clayton

New York State Reliability Council

34.

Individual

Cynthia S. Bogorad

Transmission Access Policy Study Group

X

X

35.

Individual

Randy D. Crissman

New York Power Authority

X

X

August 19, 2011

7

X

8

9

10

X

X
X
X

X

X
X
X

X

X

X
X
X

X
X

X

13

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

36.

Individual

Antonio Grayson

Southern Company

37.

Individual

Dennis Hogan

Luminant Energy

38.

Individual

Darren D. GIll

Pennsylvania Public Utility Commission

39.

Individual

Katie Coleman

Texas Industrial Energy Consumers (TIEC)

40.

Individual

John P. Hughes

Electricity Consumers Resource Council
(ELCON)

41.

Individual

Brian Conroy

Central Maine Power Company

X

42.

Individual

John Allen

New York State Electric & Gas and
Rochester Gas & Electric

X

43.

Individual

Brandy A. Dunn

Western Area Power Administration

X

44.

Individual

Robin Lunt

National Association of Regulatory Utility
Commissioners

45.

Individual

Scott Tomashefsky

Northern California Power Agency

46.

Individual

Sandra Shaffer

PacifiCorp

47.

Individual

Kevin Conway

Intellibind

48.

Individual

Si Truc PHAN

Hydro-Quebec TransEnergie

49.

Individual

Martin Bauer

US Bureau of Reclamation

August 19, 2011

X

2

3

4

5

6

7

8

X

9

10

X
X
X
X

X

X

X

X

X
X
X

X

X
X

X
X

X
X

14

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

50.

Individual

Jerome Murray

Oregon Public Utility Commission Staff

51.

Individual

Eric Lee Christensen

52.

Individual

Nicholas Winsemius

Public Utility District No. 1 of Snohomish
County, Washington
Grand Haven Board of Light and Power

53.

Individual

Josh Dellinger

Glacier Electric Cooperative

54.

Individual

Russ Schneider

FHEC

55.

Individual

Kim Moulton

Vermont Transco

X

56.

Individual

Richard McLeon

South Texas Electric Cooperative, Inc.

X

57.

Individual

Angela Gaines

Portland General Electric Company

X

58.

Individual

Richard McLeon

South Texas Electric Cooperative, Inc.

X

59.

Individual

Michael Albosta

Sweeny Cogeneration LP

60.

Individual

Michael Jones

National Grid

61.

Individual

Bud Tracy

Blachly Lane Electric Cooperative

62.

Individual

Paul Titus

Northern Wasco County PUD

X

X

63.

Individual

Bill Dearing

PUD No. 2 of Grant County, Washington

X

X

64.

Individual

Dave Markham

Central Electric Cooperative

X

65.

Individual

Dave Hagen

Clearwater Power Company

X

August 19, 2011

4

5

6

7

8

9

10

X
X

X

X

X

X

X

X

X

X

X
X

X
X

X

X

15

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

3

66.

Individual

Roman Gillen

Consumers Power Inc.

67.

Individual

Roger Meader

Coos-Curry Electric Cooperative

X

68.

Individual

Dave Sabala

Douglas Electric Cooperative

X

69.

Individual

Bryan Case

Fall River Electric Cooperative

X

70.

Individual

Rick Crinklaw

Lane Electric Cooperative

X

71.

Individual

Ray Ellis

Lincoln Electric Cooperative

X

72.

Individual

Richard Reynolds

Lost River Electric Cooperative

X

73.

Individual

Annie Terracciano

Northern Lights Inc.

X

74.

Individual

Doug Adams

Okanogan Electric Cooperative

X

75.

Individual

Rick Paschall

PNGC Power

X

76.

Individual

Heber Carpenter

Raft River Rural Electric Cooperative

X

77.

Individual

Ken Dizes

Salmon River Electric Cooperative

X

X

78.

Individual

Steve Eldrige

Umatilla Electric Cooperative

X

X

79.

Individual

Marc Farmer

West Oregon Electric Cooperative

X

80.

Individual

Kerry Robinson

Wells Rural Electric Company

X

81.

Individual

Hertzel Shamash

Dayton Power and Light Company

August 19, 2011

X

2

X

4

5

6

7

8

9

10

X

X

X

X

X

16

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

82.

Individual

David Proebstel

Clallam County PUD No.1

83.

Individual

Matt Morais

Electric Reliability Council of Texas, Inc.

84.

Individual

Martin Kaufman

ExxonMobil Research and Engineering

X

85.

Individual

Laura Lee

Duke Energy

X

86.

Individual

Curtis Klashinsky

FortisBC

87.

Individual

Mark Thompson

Alberta Electric System Operator

88.

Individual

RoLynda Shumpert

South Carolina Electric and Gas

89.

Individual

Reggie Wallace

90.

Individual

91.

2

3

4

5

6

8

9

10

X
X
X
X

X

X

X

X

X

X

Fayetteville Public Works Commission

X

X

Gary Kruempel

MidAmerican Energy Company

X

X

X

X

Individual

Dennis Minton

Florida Keys Electric Cooperative

X

92.

Individual

Thad Ness

American Electric Power

X

X

X

X

93.

Individual

Rick Drury

East Kentucky Power Cooperative, Inc.

X

X

X

94.

Individual

Andrew Z. Pusztai

American Transmission Company, LLC

X

95.

Individual

Linda Jacobson

Farmington Electric Utility System

96.

Individual

Rich Salgo

Sierra Pacific Power Co d/b/a NV Energy

X

X

X

X

97.

Individual

Jennifer Eckels

Colorado Springs Utilities

X

X

X

X

August 19, 2011

7

X

X

17

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

X

X

X

98.

Individual

Jianmei Chai

Consumers Energy Company

99.

Individual

Chad Bowman

Chelan PUD - CHPD

100. Individual

Michelle R D'Antuono

Occidental Energy Ventures Corp. (answers
include all various Oxy affiliates)

101. Individual

Kenneth A. Goldsmith

Alliant Energy

102. Individual

Deborah J Chance

Chevron Global Power, a division of
Chevron U.S.A. Inc.

103. Individual

Scott Bos

Muscatine Power and Water

X

104. Individual

Bill Keagle

X

105. Individual

John Bee

BGE and on behalf of Constellation
NewEnergy, Constellation Commodities
Group and Constellation Control and
Dispatch
Exelon

106. Individual

David C. Kahly

Kootenai Electric Cooperative

X

107. Individual

Tracy Richardson

Springfield Utility Board

X

108. Individual

Joe Tarantino

Sacramento Municipal Utility District
(SMUD)

109. Individual

Rick Hansen

City of St. George

110. Individual

John Brockhan

CenterPoint Energy

August 19, 2011

X

6

7

8

X

X

X

X

X

X

X

X

X

9

10

X

X

X

X

X

X

X

X

X
X

X

X

X

X
X

X
X

X

18

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

111. Individual

Sunitha Kothapalli

Puget Sound Energy

112. Individual

Linda Esparza

113. Individual

Patrick Farrell

Public Utility District No. 1 of Franklin
County
Southern California Edison Company

114. Individual

Thomas Weller

Midstate Electric Cooperative

115. Individual

Jason Snodgrass

GTC

116. Individual

Diane Barney

New York State Dept of Public Service

117. Individual

Bob Thomas

Illinois Municipal Electric Agency

118. Individual

Kim Wissman

Public Utilities Commission of Ohio

119. Individual

Jeff Nelson

Springfield Utility Board

120. Individual

David Angell

Idaho Power

X

121. Individual

Robert Ganley

Long Island Power Authority

X

122. Individual

Mike Hirst

Cogentrix Energy, LLC

123. Individual

Jack Stamper

Clark Public Utilities

124. Individual

John A. Gray

The Dow Chemical Company

125. Individual

David Thorne

Pepco Holdings Inc

126. Individual

Gary Ferris

Vigilante Electric Cooperative

August 19, 2011

X

2

3

4

X

5

6

7

8

9

10

X

X
X

X

X

X

X
X
X
X
X
X
X

X
X
X
X

X

X
X

19

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

127. Individual

Steve Alexanderson

Central Lincoln

X

X

128. Individual

Neil Phinney

Georgia System Operations

X

X

129. Individual

Bill Harm

PJM

130. Individual

Heather Hunt

New England States Committee on
Electricity

131. Individual

Darryl Curtis

Oncor Electric Delivery Company LLC

132. Individual

Charles Yeung

Southwest Power Pool

133. Individual

Geoff Carr

Northwest Requirements Utilities

134. Individual

Jonathan Appelbaum

United Illuminating

135. Individual

John Cummings

PPL Energy Plus and PPL Generation

136. Individual

Joe Petaski

Manitoba Hydro

137. Individual

Kathleen Goodman

ISO New England, Inc.

138. Individual

Manny Robledo

City of Anaheim

139. Individual

Chris de Graffenried

Consolidated Edison Co. of NY, Inc.

X

140. Individual

Scott Miller

MEAG Power

141. Individual

Alice Ireland

Xcel Energy

August 19, 2011

5

6

7

8

9

10

X

X
X
X
X

X
X

X

X

X

X

X

X

X

X

X

X

X

X

X

X
X
X

X

20

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

142. Individual

Michael Falvo

Independent Electricity System Operator

143. Individual

Randy MacDonald

NB Power Transmission

X

144. Individual

Glen Sutton

ATCO Electric

X

145. Individual

David Burke

Orange and Rockland Utilities, Inc.

X

146. Individual

Shane McMinn

Golden Spread Electric Cooperative, Inc.

147. Individual

Rick Spyker

AltaLink

148. Individual

Benjamin A Friederichs

Big Bend Electric Cooperative, Inc.

149. Individual

J. McFeely, PE

Modern Electric Water Company

150. Individual

Gary Carlson

Michgan Public Power Agency

151. Individual

Peter Mackin

Utility System Efficiencies, Inc.

152. Individual

Keith Morisette

Tacoma Power

153. Individual

Russell A. Noble

Cowlitz County PUD

154. Individual

Mihai Cosman

California Public Utilities Commission

August 19, 2011

2

3

4

5

X

X

6

7

8

9

10

X

X
X

X
X

X

X

X

X

X

X

X

X

X

X

21

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

1. The SDT has made clarifying changes to the core definition in response to industry comments. Do you agree
with these changes? If you do not support these changes or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: Based on stakeholder comments, the SDT has made additional clarifying revisions to the draft BES definition.
The BES Draft Definition includes all three sections – core definition, list of inclusions, and list of exclusions. The SDT has revised the bright-line
core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists. In response to
comments, the SDT added an additional inclusion to clarify the inclusion of Reactive Resources and an additional exclusion to clarify that Reactive
Resources that are owned by retail customers for their own use are not to be included. Finally, the SDT elected to retain the 100 kV bright-line
criteria. This is the bright-line voltage level that is included in the existing approved definition of the Bulk Electric System in the NERC Glossary of
Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification was provided that would lead the SDT to
make a change. One goal of this project is to add clarity to the definition without significantly changing the population of BES Elements.
Changes made to the definition as a result of comments on this question are:
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real
Power and Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is
modified by the list shown below. This does not include facilities used in the local distribution of electric energy.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary
windingsterminals of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that
distribute power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection
at 100 kV or higher are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail
customer Load and not to accommodate bulk power transfer across the interconnected system.
E4 – Reactive Power devices owned and operated by the retail customer solely for its own use.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.

Organization
Public Service Enterprise Group
LLC

August 19, 2011

Yes or No

Question 1 Comment

No

There is still room for misinterpretation of the BES boundaries. The BES definition has ramifications affecting
many standards. NERC should provide examples of what specifically is in and what is out of BES boundaries.

22

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
Example one line diagrams showing “Generation Resources” included or excluded and types of radial feeds
exempted should be shown. Identify what element is in BES / what is out. Suggest showing typical
interconnection facilities. Addressing typical interconnection facility configurations will assist in developing a
clear and concise definition that provides a precise line of demarcation between elements of the BES.

Response: Based on the stakeholder comments, the SDT has made additional revisions to the three parts of the BES Definition (Core Definition, Inclusion List,
and Exclusion List) in order to improve clarity.
Northeast Power Coordinating
Council

No

The core definition should be revised to read: Bulk Electric System (BES): All Transmission Elements
operated at 100 KV or higher, unless such designation is modified by the list shown below. The resulting
modified BES shall comprise all Elements deemed necessary for operating an interconnected electric energy
transmission network, but shall exclude any Elements used in the local distribution of electric energy.
The inclusion and exclusion requirements are restrictive. For example, radial characteristics should not be
limited by the amount of installed generation or single transmission source and/or require an interrupting
device. Instead, one or more transmission sources could feed the radial load to provide redundancy as long
as there is adequate protection and isolation for improved customer-supply continuity and reliability. This
would be considered radial as long as the loss of any transmission source would not affect, and is not
necessary for the operation of the interconnected transmission network. This retains the incentive to build
transmission.
The revised definition will have a direct impact on entities across North America and may conflict with
regulatory requirements, Codes, and Licenses. FERC in its Order 743 and 743A has directed NERC to
address these concerns.
Include provisions in both the NERC exception criteria and exception process for federal, state and provincial
jurisdictions. These provisions should provide clear guidance so that, if and when there are deviations from
the exception criteria, they are properly identified with technical and regulatory justifications ensuring there is
no adverse impact on the interconnected transmission network. This burden of proof should be left to the
entity seeking exception because it may be difficult to define the exception criteria. Further, if such an explicit
criteria could be defined, it could become another bright-line BES.

Hydro-Quebec TransEnergie

No

The bright line revised definition could expand significantly what is considered to be BES in the case of HQT,
with no discernible impact on the reliable operation of the interconnected system, because of the nature of the
Quebec interconnection.
Furthermore, it should be stated that there appears to be a conflict between the proposed definition and the
regulatory framework applicable in Quebec or at least there are some important differences between both.
The non-FERC juridiction was acknowledged by FERC Order 743 in paragraph 95. As an example, the

August 19, 2011

23

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
Quebec regulatory framework considers that there are several levels of application for standards, not only
one. A single BES definition cannot apply to all standards.The definition must include more latitude for nonFERC jurisdictions, as long as the reliability objective is achieved.

Hydro One Networks Inc

Yes

We agree with the concept of a bright-line definition and commend the SDT for developing a concept of
explicit inclusions and exclusions as part of the definition. This will reduce the number of exception
applications for some of the BES elements. However, the inclusion and exclusion requirements are extremely
restrictive. For example, radial characteristics should not be limited by the amount of installed generation or
single transmission source and/or require an interrupting device. Instead we believe that one or more
transmission sources could feed the radial load to provide redundancy as long as there is adequate protection
and isolation for improved customer-supply continuity and reliability. This should be considered radial as long
as the loss of any transmission source does not affect, and is not necessary for, the operation of the
interconnected transmission network.
Further, it is imperative to understand that the NERC’s revised definition will have a direct impact on entities
across North America and will conflict with regulatory requirements, Codes, and Licenses. FERC in its Order
743 and 743A has directed NERC to address these concerns.We suggest the SDT and RoP teams should:
o Carefully craft the exception criteria and procedure to be flexible and technically sound, to allow entities to
adequately present their case to the ERO for inclusions or exclusions outside of the definition. This burden of
proof should be left to the entity seeking exception because it may be difficult if not impossible to define the
exception criteria. If such a criteria could be defined, it will in fact become another bright-line BES.
o Include provisions in both the NERC exception criteria and exception procedure for federal, state and
provincial jurisdictions. These provisions should provide clear guidance so that, if and when there are
deviations from the exception criteria, they are properly identified with technical and regulatory justifications
ensuring there is no adverse impact on the interconnected transmission network.

Response: Based on the stakeholder comments, the SDT has made additional revisions to the three parts of the BES Definition (Core Definition, Inclusion List,
and Exclusion List) in order to improve clarity.
See the responses to comments as well as a discussion of the latest revisions regarding the Radial Exclusion in Question 7 and the responses to comments
regarding the Regulatory Requirements in Question 12 below.
Tri-State Generation and
Transmission Association, Inc.

August 19, 2011

No

The Northeast Power Coordinating Council stated that “Step-down transformers with the low-side terminals
serving non-BES facilities, which are serving a distribution function, should not be part of the definition of
BES.” The drafting team stated that it agrees with the comment, but the implementation uses the term local
distribution network, which is different than a step-down transformer. Transformers are addressed in the

24

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
answer to the NPCC comment 2, but uses the ambiguous “single Transmission source” phrase as a
requirement to determine BES status.Other specific comments are below.

Response: The SDT has made revisions to the draft definition to clarify that only transformers with primary and secondary terminals operated at 100 kV or
higher unless excluded under Exclusions E1 or E3 would be included in the BES under Inclusion I1.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary
windingsterminals of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
NERC Staff Technical Review

No

The core definition lacks a clear bright-line designation for generating resources. For such resources, the core
definition only references “Real Power resources as described below” which in and of itself is not a bright-line
designation. A bright-line designation for generating resources needs to be included in the core definition. A
bright-line can be established in the core definition by including generating units based on the MVA ratings as
found in current Inclusions I2, I3, and I5. Additional generating unit specifications could be included in the
core definition or as Inclusions such as the existing Inclusion I4 for black start generating units. >>>>>>>>>>
The core definition also lacks clarity with respect to the facilities included under “Reactive Power resources”
and may unintentionally omit Reactive Power resources necessary for reliable operation of the BES. The
definition as proposed excludes devices such as shunt reactors connected to the tertiary terminals of a BES
transformer and synchronous condensers connected through a transformer, and is unclear whether a static
var compensator (SVC) with thyristor switched capacitors and thyristor switched or controlled reactors
operated below 100 kV, but connected to the BES through a transformer (similar to a generator connected to
the BES through a generator step-up transformer) is included in the BES definition. The qualifications on
Reactive Power resources recommended below will include the necessary transmission resources noted
above, without unintentionally including distribution capacitors connected on the low voltage side of a
distribution transformer. >>>>>>>>>>
These concerns can be addressed by revising the core definition as follows:>>>>>>>>>> “Bulk Electric
System (BES): All Transmission Elements operated at 100 kV or higher;Real Power resources including,
* Individual Generating Units greater than 20 MVA (gross nameplate rating),
* Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross
nameplate rating) connected through a common point of interconnection,
* Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) utilizing a collector system through a common point of interconnection, and
* Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission
Operator’s restoration plan regardless of voltage; andReactive Power devices (capacitive or inductive, static

August 19, 2011

25

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
or actively controlled) greater than 20 Mvar that are directly connected at 100 kV or higher, or connected
through a transformer at 100 kV or higher at the site of transformation;unless such designations are modified
by the list of Inclusions and Exclusions shown below.” >>>>>>>>>>
(Note that the rationale for excluding the 100 kV interconnection threshold on the first three bullets is provided
in our responses to Questions 3, 4, and 6.) >>>>>>>>>>
In conjunction with the alternative language for the core definition proposed above, NERC staff proposes the
following definition of Generating Unit be added to the NERC Glossary of Terms used in Reliability Standards:
>>>>>>>>>> Generating Unit - A device, whether spinning or static and whether connected synchronously,
asynchronously, or electronically coupled, that produces electrical energy from another source of energy,
either directly from the other energy source (such as a combustion turbine from natural gas or light distillate
oil, a wind turbine from wind, or a solar array from the sun) or through a storage medium (such as pumped
storage hydro, a flywheel, compressed air, or battery).

NERC Transmission Issues
Subcommittee (TIS)

No

Although the wording can work as it is, the TIS believes clearer wording would be: “All Transmission
Elements operated at 100 kV or higher, Real Power and Reactive Power resources as described below,
connected at 100 kV or higher unless such designation is modified by the list shown below.”

Response: The BES draft definition includes all three sections – core definition, list of inclusions, and list of exclusions. The SDT has revised the bright-line core
definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or higher are to be
included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.
In response to comments, the SDT added an additional item to clarify the inclusion of Reactive Resources and an additional exclusion to clarify that Reactive
Resources that are owned by retail customers for their own use are not to be included.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.
E4 – Reactive Power devices owned and operated by the retail customer solely for its own use.
Dominion

No

Dominion believes the core BES definition should include any non-radial Element or Facility operated at 100
Kv or higher and should exclude any radial Element or Facility (regardless of operating voltage) as well as
non-radial Element or Facility operated below 100 kV.
The core definition should also include defined criteria that are applied to an Element or Facility to determine

August 19, 2011

26

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment
whether or not it meets the intent of the Section 215 of Federal Power which defines the bulk power system
as (1) facilities and control systems necessary for operating an interconnected electric energy transmission
network; and (2) electric energy from generation facilities needed to maintain transmission system reliability.
(3) However, Section 215 excludes facilities used in the local distribution of electric energy From the definition
of the bulk power system . An Element or Facility should be included where the Element or Facility is
necessary for operating an interconnected electric energy transmission network or is needed to maintain
transmission system reliability. Likewise an Element or Facility should be excluded where the Element or
Facility is not necessary for operating an interconnected electric energy transmission network or is needed to
maintain transmission system reliability.
Dominion agrees that the BES definition should exclude local distribution facilities under state jurisdiction.
In specific instances (including UFLS programs and transmission protection systems that are implemented on
distribution elements or radial transmission) local distribution facilities can be included in approved NERC
reliability standards following under explicit standards dedicated to their explicit mission without their
automatic inclusion in a definition of BES that could infringe on state jurisdiction.
Dominion is also concerned at how complicated these lists of inclusions and exclusions has become!
Dominion had implemented the 100 kV threshold, as displayed in prior drafts of this bright line test (without all
these distractions provided in this BES definition version). With the complexity of inclusion and exclusion
criteria now provided in this draft, Dominion is not sure it can replicate the list of facilities that are now
qualified for inclusion in the BES as seen through the eyes of different auditors and this will expose Dominion
to undesirable disputes down the road on what should have been included or excluded.

National Grid

No

The core definition should be revised to read: Bulk Electric System (BES): All Transmission Elements
operated at 100 KV or higher, unless such designation is modified by the list shown below. The resulting
modified BES shall comprise all Elements deemed necessary for operating an interconnected electric energy
transmission network, but shall exclude any Elements used in the local distribution of electric energy.

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists.
See the responses to comments regarding Local Distribution Facilities in Question 11 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list

August 19, 2011

27

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 1 Comment

shown below. This does not include facilities used in the local distribution of electric energy.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.
E4 – Reactive Power devices owned and operated by the retail customer solely for its own use.
SPP Standards Review Group

No

A reference needs to be made to the ROP changes which also provide a mechanism whereby Elements may
be excluded/included in the BES. Without that reference the proposed definition does not completely include
all means for exceptions/inclusions. We would suggest the definition be expanded to say ‘...modified by the
list shown below or as provided by Appendix 5C of the NERC Rules of Procedure.’

ISO New England, Inc.

Yes

This definition does not indicate that there may be other "inclusions" and "exclusions" for which an entity has
to seek ERO/RRO approval. Therefore our recommendation is that this definition be modified to resolve this
concern.This questionnaire contains information as part of the definition description that is different from the
draft Implementation Plan and definition of Bulk Electric System document, specifically the entirety of E4 is
included in the questionnaire but in neither of the other two documents; this may lead to confusion by
commenters.

Response: In the first posting, a reference to the Rules of Procedure exception process was inadvertently omitted from the posting. It has been added back in
to this posting.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.
Michigan Public Service
Commission(MPSC)

August 19, 2011

No

MPSC Staff Comments: The BES definition proposed by the SDT should not use the term “transmission”, if
that term is defined as facilities that are at 100 kV or above. Not all facilities at 100 kV or above are properly
considered transmission facilities. Use of “transmission” is causing unnecessary uncertainty and much
debate among NERC stakeholders in the standards development and outreach processes over potential
effects on jurisdiction, ownership, and possible new NERC registration requirements. This is especially true
in states such as Michigan where Michigan Public Service Commission-regulated utilities sold their
transmission facilities to independent transmission companies. Using FERC’s Order 888 seven-factor
technical-functional test as the basis for technical studies presented and evaluated in individual state dockets,
the Michigan Public Service Commission approved, and subsequently FERC deferred to, those transmission
and distribution classifications. Using “transmission” in the BES definition could cause unintended
consequences. Entities already registered with NERC as Distribution Providers, Load Serving Entities, or
Generation Owners, etc. which own facilities previously classified as distribution by state regulatory agencies,
may also now be required to register with NERC as Transmission Planners, Owners, or Operators. A system
element defined as BES should not determine jurisdiction, ownership, or require duplicative or additional

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Organization

Yes or No

Question 1 Comment
NERC registration. Much compliance with reliability standards is already being done by RTOs and entities
already registered with NERC. Unnecessary and costly duplication of standards work should be avoided. We
support that “All Transmission Elements ...” be replaced with “All network System Elements ...” in the BES
definition.

Consumers Energy Company

No

The generic inclusion within the definition of BES, of the NERC-defined term, “Transmission”, has the
potential to cause confusion and controversy. Small entities that own facilities that have been approved by
FERC as being classified as “distribution” according to the FERC Order 888 seven-factor test, could be
viewed as owning “Transmission.” Therefore, Regional Entities might require these small entities to register
as Transmission Owners, Transmission Operators, and/or Transmission Planners. However, these facilities
may not form a contiguous system, as expressed in the defined term, “Transmission” and being “An
interconnected group of lines and associated equipment”. Alternatively, such facilities, because they do not
form such a contiguous system (and thus are not, and should not be, classified as Transmission) may
inappropriately be excluded from the BES. Therefore, even though “Transmission Facilities” represent a
subset of the BES, we urge that NERC avoid the use of the term, “Transmission” within the definition of BES.
NERC should more explicitly describe, in a functional manner independent of the term, “Transmission”, what
is intended to be included within the core definition. For NERC to fail to do so is to invite challenges to the
final definition as well as establish inappropriate reliability gaps. We agree with GO/TO Interface Project
2010-07 method of resolving reliability gaps by expanding requirements to the Distribution Provider function
as necessary.We propose that “All Transmission Elements ...” be replaced with “All network System Elements
...”

Response: The SDT elected to retain the use of the word “Transmission” as it is an approved term in the NERC Glossary of Terms. As defined, Transmission is
“An interconnected group of lines and associated equipment for the movement or transfer of electric energy between points of supply and points at which it is
transformed for delivery to customers or is delivered to other electric systems.” The SDT considers this an appropriate use of the term. No change made.
Idaho Falls Power

No

We believe that inclusions or exclusions tied to brightline registration criteria (such as the 20MVA single
generation source or 75 MVA facility) does not fulfill the effort the NERC BES definition project was tasked to
undertake. The current draft's language will draw in many small municipal and other like entities with small
generation assets, which have no material impact upon the BES.
Further, should these generation assets not be excluded, this draft implies that all assets downstream to the
point of interconnection are BES as well regardless of point of connection. We believe it was the original
intent of this definition project to remove such immaterial assets and the undue burden placed upon such
entities and subsequently their rate payers, who have no impact to the BES.

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Organization

Yes or No

Question 1 Comment

Southern Company

No

Inclusion of individual units less than 75MVA was established when these smaller units were significant to the
reliability of the BES and is outdated.

Intellibind

No

I agree in principle with the changes; however the definition and direct effect on certain small entities has not
been improved. Primarily there are many entities that will be included that are marginal at best. Such entities
will include intermittent generation such as wind, which may, or may not fit into the designation of aggregation
of up to 75 MVA. It is becoming a practice to size a farm, or phase of a farm, to under 75MVA to get around
the rules. A site is not defined and could be defined very narrowly.
I do not agree with the 20MVA threshold for single generators when the generators net output cannot reach
the 20MVA output. Trash burning facilities have heavy station service loads and by nameplate are included
when in reality they operate below the arbitrary cut off.
FERC has asked for technically justified standards, and the proposed BES definition still applies an arbitrary
threshold not supported by technical argument. This issue is further aggravated by location of these
resources. Many of these resources are remotely located specifically so that they have no, or minimize
impact on the BES. Many times they are on long lines that are over 100KV simply because of efficiency in
electrical transmission.

Fayetteville Public Works
Commission

No

The changes made by the SDT with respect to Real Power resources in Inclusion I2 do not ensure a
consistent determination by independent entities of whether a generator should be included within the BES.
The ambiguity in Inclusion I2 has implications on other Inclusions and Exclusions. See the comments on
Question 3 for additional detail.

Response: See the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below.
Overton Power District No. 5

No

The term does not include facilities used in the local distribution of electric energy.

Response: The SDT has made additional clarifying revisions to the draft BES definition to address your concern.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Western Montana Electric
Generating and Transmission
Cooperative

August 19, 2011

No

As a general matter, Western Montana Electric Generating and Transmission Cooperative (WMG&T)
supports the approach the Standards Development Team (“SDT”) has taken to defining the Bulk Electric
System (“BES”). The changes made in the revised core definition are helpful and represent significant

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Organization

Yes or No

Northern Wasco County PUD

Question 1 Comment
progress toward an acceptable definition. With an effective and efficient exclusion process, the draft will
better define the BES as a whole.We urge the SDT to bear in mind the restrictions contained in Section 215 of
the Federal Power Act (“FPA”) The “bulk-power system” (As per FERC, we treat the statutory term “bulkpower system” as equivalent to the term ordinarily used in the industry, “Bulk Electric System”) definition
imposes a clear limit on the reach of the mandatory reliability regime. The BES is made up of only those
“facilities and control systems necessary for operating an interconnected electric energy transmission network
(or any portion thereof)” and “electric energy from generation facilities needed to maintain transmission
system reliability.” Congress reinforced that limit in Section 215(i), where it emphasized that the FPA
authorizes the imposition of reliability standards “for only the bulk-power system.” WMG&T is concerned that
the SDT’s proposed definition is overly-broad, and that it will sweep in many Elements that have little or no
material impact on the reliable operation of the interconnected bulk transmission grid. For example, the
definition uses the arbitrary 20 MVA threshold from the NERC Statement of Registry Criteria for inclusion of
generators. Accordingly, for the BES definition to conform to the requirements of the statute, the SDT must
adopt an effective mechanism to exempt facilities like these that are improperly swept in by the SDT’s
brightline approach to inclusions and exclusions. For this reason, the Exception process to accompany the
SDT’s definition is of critical concern. If the SDT incorporates this statutory language as its core definition, it
will have addressed FERC’s primary concern with a minimum of disruption to the current NERC system of
definitions. The definition could then be further elaborated to show specific points of demarcation for each
inclusion and exclusion similar to that Proposal 6 from the WECC Bulk Electric System Definition Task Force
(“BESDTF”) team to further delineate BES and non-BES facilities.

Chelan PUD – CHPD
Kootenai Electric Cooperative
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Big Bend Electric Cooperative,
Inc
Northwest Requirements Utilities
Cowlitz County PUD

Response: See the responses to comments regarding the Regulatory Requirements in Question 12 below.
See the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below.
The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list of inclusions,
and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and
Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or
Exclusion lists.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
ReliabilityFirst

No

We feel the intent of the FERC Order was to simplify and not complicate the definition and the
inclusion/exclusion process. This definition is now even more complex.
we also feel that as a result of several defined terms such as the LDN teh proposed definition will in most

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Organization

Yes or No

Question 1 Comment
cases exclude portions of networks in locations such as Washington DC, New York and other Metro Areas,
many Munis and citiies that are currently registered. If the intent is to remove entities from the registry this will
in most likely do it.

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists.
See the responses to comments as well as a discussion of the latest revisions regarding local networks in Question 9 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
New York State Reliability
Council

No

HVDC and VFT technologies are not addressed specifically.
Consideration should be given to expanding the core BES definition to clarify that it includes all AC and DC
system Element(s).

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists. The SDT discussed your comment and feels that HVDC and VFT technologies are already included in the draft core definition since
they are Transmission Elements.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Grand Haven Board of Light and
Power

August 19, 2011

No

The Grand Haven Board of Light and Power (GHBLP) does not agree that the core definition for the BES use
a “bright line” definition of 100kV and above. Currently, we have a 138kV/69kV transformer that connects to
the BES and serves a radial, load serving system. This transformer is presently protected by a “ground
switch” relay scheme. We have a project in process that is replacing this “ground switch” relay scheme with a
circuit switcher. The circuit switcher, unlike the ground switch, would not affect the BES if it were to operate.
By this “bright line” definition this single asset would be defined as a part of the BES. The cost that our
organization would incur from being forced to register as a Transmission Owner and Transmission Operator
(TO/TOP) would be extreme, and would significantly impact our budget and our customer’s rates. We should

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Organization

Yes or No

Question 1 Comment
not have to depend on an “exclusion” process to remove this asset from being defines as a part of the BES,
and this should be addressed in the core definition.

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists. The SDT has made revisions to the draft definition to further clarify that radial systems at 100 kV or higher serving only Load would be
excluded under Exclusion E1.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Glacier Electric Cooperative

No

I still feel that a bright-line of 200 kV would be more appropriate, with language stating that certian significant
elements operated below 200 kV would be included.
However, I believe the exlusion process is definitely a step in the right direction.

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists. The SDT elected to retain the 100 kV bright line criteria. This is the bright-line voltage level that is included in the existing approved
definition of the Bulk Electric System in the NERC Glossary of Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification
was provided that would lead the SDT to make a change. One goal of this project is to add clarity to the definition without significantly changing the population
of BES elements.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Blachly Lane Electric
Cooperative
Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc.

August 19, 2011

No

First, thank you for the opportunity to comment on the draft Proposed Continent-wide Definition of the Bulk
Electric System (BES). We appreciate the work that the Standards Development Team (SDT) has put into a
new definition so far and believe the draft is a step in the right direction. We also understand the relatively
short timeframe that NERC is working under in order to create a new BES definition to submit to FERC for
approval before the imposed deadline. That said, we believe that the draft definition needs significant revision
before NERC files it with FERC for approval. In response to question #1, we recommend that NERC revise
the draft BES definition so that the first paragraph reads as follows:”Bulk Electric System (BES): Includes

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Organization
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Salmon River Electric
Cooperative Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative

August 19, 2011

Yes or No

Question 1 Comment
anything that meets each of the following three (3) criteria:(1) (a) Is a facility or control system necessary for
operating an interconnected electric energy transmission network (or any portion thereof), or(b) Is electric
energy from generation facilities needed to maintain transmission system reliability; AND(2) Is not a facility
used in the local distribution of electric energy as determined by the Seven Factor Test set out in FERC Order
888; AND(3) (a) Unless included or excluded in subpart (b), isi. A Transmission Element operated at 100kV or
higher; orii. A Real Power Resource identified in subpart (b); oriii. A Reactive Power resource connected at
100kV or higher;(b) [the list of inclusions of exclusions in the draft, as modified by our comments below]”
Criteria (1) and (2) of these revisions would capture the limitations on what may be included in the BES due to
the jurisdictional limits that Congress placed on FERC, NERC, and the Regional Entities in developing and
enforcing mandatory reliability standards. Specifically, Section 215(i) of the Federal Power Act provides that
the Electric Reliability Organization (ERO) “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” Section 215(b)(1) of the FPA, 16 U.S.C. § 824o(a)(1)
(emphasis added). Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A)
facilities and control systems necessary for operating an interconnected electric energy transmission network
(or any portion thereof); and (B) electric energy from generation facilities needed to maintain transmission
system reliability. The term does not include facilities used in the local distribution of electric energy.” Id.
With this language, Congress expressly limited FERC, NERC, and the Regional Entities’ jurisdiction with
regard to local distribution facilities as well as those facilities not necessary for operating a transmission
network. Given that these facilities are statutorily excluded from the definition of the BPS, reliability standards
may not be developed or enforced for facilities used in local distribution, and therefore the definition of the
BES may not include such facilities. In Order No. 672, FERC adopted the statutory definition of the BPS.
See Order No. 672, FERC Stats. & Regs. ¶ 31,204 (2006). In Order No. 743-A, issued earlier this year, the
Commission acknowledged that “Congress has specifically exempted ‘facilities used in the local distribution of
electric energy’” from the BPS definition. See Order 743-A, 134 FERC ¶ 61,210 at P. 25 (2011). FERC also
held that to the extent any facility is a facility used in the local distribution of electric energy, it is exempted
from the requirements of Section 215. Id. at P.54. In Order No. 743-A, FERC delegated to NERC the task of
proposing for FERC approval criteria and a process to identify the facilities used in local distribution that will
be excluded from NERC and FERC regulation. Id. at P 76. The critical first step in this process is for NERC to
propose criteria for approval by FERC to determine which facilities are not BPS facilities and therefore not
BES facilities. Accordingly, it is critical that NERC create a definition of the BES that first excludes facilities
used in local distribution. In Order No. 743-A, the Commission confirmed this, stating: “once a facility is
classified as local distribution, the facility will be excluded from the [BES] unless changes to the system
warrant a review of the determination.” Order No. 743-A, at P 71 (emphasis added).We believe that the
Seven Factor is the appropriate means to determine whether a facility is used in the local distribution of
electricity and therefore should be referenced in the definition of the BES. This is the test that applies
elsewhere to determine whether facilities qualify as local distribution, and therefore there is strong and clear
precedent for using it in the BES definition. See 334 F.3d 48. In fact, the statutory language in Section 201 of

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Organization

Yes or No

Question 1 Comment
the FPA that led to the Seven Factor Test for other purposes is identical to the statutory language in Section
215 of the FPA at issue here. Well established rules of statutory construction call for interpreting identical
language to produce similar meanings, therefore applying the Seven Factor Test under both sections of the
statute is appropriate. And, without the Seven Factor Test as a means of determining what qualifies as local
distribution facilities, there could be significant uncertainty and confusion as to whether certain facilities are
part of the BES. Further, the Commission stated in Order 743-A that, “the Seven Factor Test could be
relevant and possibly is a logical starting point for determining which facilities are local distribution for
reliability purposes, while also allowing NERC flexibility in applying the test or developing an alternative
approach as it deems necessary.” Id. at P 69. The Seven Factor Test includes the following factors: 1) Local
distribution facilities are normally in close proximity to retail customers; 2) local distribution facilities are
primarily radial in character; 3) power flows into local distribution systems, it rarely, if ever, flows out; 4) when
power enters a local distribution system, it is not re-consigned or transported on to some other market; 5)
power entering a local distribution system is consumed in a comparatively restricted geographical area; 6)
meters are based at the transmission/local distribution interface to measure flows into the local distribution
system; and 7) local distribution systems will be of reduced voltage. Order No. 888 at 31,771. FERC
precedent indicates that a utility does not have to meet every factor of the seven-factor test in order for their
facilities to qualify as local distribution. California Pacific Edison Co., Order Granting in Part and Denying in
Part Petition for Declaratory Order, 133 FERC ¶ 61,018, 61,075 (Oct. 7, 2010).
NERC must also limit the BES to facilities or control systems necessary for operating an interconnected
electric energy transmission network (or any portion thereof) or electric energy from generation facilities
needed to maintain transmission system reliability, as directed by the FPA. Similar to the local distribution
exclusion, facilities not falling into either of these categories are not part of the BPS and therefore must be
expressly excluded from the BES.In order to establish a process that is consistent with the FPA and NERC’s
delegated authority from FERC, the proper sequence of steps must be applied in the correct order to
determine which facilities are subject to NERC and FERC jurisdiction in the first instance, and only then, from
among the jurisdictional facilities, to determine which facilities and control systems must comply with the
electric reliability standards. Our revisions to the BES definition would create such a process within the
definition of the BES. It would ensure that entities would begin any analysis of whether a particular item
qualifies as BES by asking, first, whether that facility is “necessary for operating an interconnected electric
energy transmission network (or any portion thereof)” or is “electric energy from generation facilities needed
to maintain transmission system reliability,” and second, whether that facility is “used in the local distribution
of electric energy.” Only after addressing these questions might further analysis be appropriate. We
understand, but disagree with, the argument that, because the FPA clearly excludes local distribution facilities
and facilities necessary for operating an interconnected electric transmission network from FERC, NERC, and
Regional Entity jurisdiction, it is not necessary to expressly exclude these facilities again in the definition of
the BES. This approach might be legally accurate, but could lead to significant confusion for entities
attempting to implement the new BES definition. There are numerous examples of Regional Entities,

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Organization

Yes or No

Question 1 Comment
particularly WECC, attempting to include such facilities in the BES under the current BES definition, and
regulated entities are not certain as to which facilities they should consider part of the BES. Clarifying FERC,
NERC, and Regional Entity in the BES definition, even if such clarification is already provided in the FPA,
would avoid such problems under the new definition.
Criterion (3) of these revisions is necessary to resolve the ambiguity in the proposed definition as to whether
the clause “unless such designation is modified by the list shown below” modifies only the preceding clause
(“Reactive Power resources connected at 100 kV or higher”) or the entire definition.Rearranging the definition
in this way should make clear that the list of inclusions and exclusionsthat would be inserted as Subpart (b)
modifies each provision ofSubpart (a). Thus, for example, even if a Transmission Element is
otherwiseincluded by virtue of operating at 100 kV or higher, it is nonetheless excluded ifspecifically
addressed in the list of exclusions that would be incorporated assubpart (b) of the definition (if, for example,
the Element qualifies as a LocalDistribution Network). The rearrangement of the language eliminates
anyargument that the phrase “unless such designation is modified by the list shownbelow” does not modify
“all Transmission Elements operated at 100 kV or higher”because of its placement at the end of the
independent clause “Reactive Powerresources connected at 100 kV or higher.”Further, we support the use of
the phrase “Transmission Elements” as the startingpoint for the base definition because both “Transmission”
and “Elements” arealready defined in the NERC Glossary of Terms Used, and the use of the
term”Transmission” makes clear that the Bulk Electric System includes only Elementsused in Transmission
and therefore excludes Elements used in local distribution ofelectric power.
As discussed above, the definition must exclude facilities used inlocal distribution in order to comply with the
limits placed on NERC authority byCongress in Section 215 of the FPA.
For similar reasons, we believe the SDT has improved the proposed definition from its initial proposal by
eliminating the use of terms such as “Generation” that are not specifically defined in the NERC Glossary of
Terms and by eliminating terms such as “Facility” that include “Bulk Electric System” as part of their definition.
Eliminating the use of such terms helps sharpen the core definition. If a key term is undefined, incorporating it
into the definition only begs the question of how the incorporated term is defined. If a currently-defined term
uses the phrase “Bulk Electric System” as part of its definition, incorporating that term into the BES definition
creates a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,”
“Real Power,” and “Reactive Power.”

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists.
See the responses to comments regarding Local Distribution Facilities in Question 11 and the responses to comments regarding the Regulatory Requirements in

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Organization

Yes or No

Question 1 Comment

Question 12 below.
The SDT has made revisions to the draft definition to clarify that the BES does not include Facilities used in the local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Electric Reliability Council of
Texas, Inc.

No

ERCOT ISO suggests a different approach. In order 743, to remedy its concerns, FERC suggested
eliminating RE discretion in defining the BES, and instead basing it upon a bright-line 100kV threshold,
provided that elements above and below 100kV could be excluded and included, respectively, based on
specific procedures. Consistent with that approach, ERCOT ISO suggests that the BES definition itself
establish a bright line standard, with inclusions and exclusions managed through the exception process (the
exception process allows for both exclusions and inclusions of relevant facilities/equipment).With respect to
exclusions (and inclusions), FERC contemplated a process involving stages that established “exclusion”
criteria in the first instance. If equipment met such criteria, the process ended there and it was excluded or
included, as appropriate. If the equipment did not meet the bright-line criteria, then it moved to the
“exception” analysis, which contemplated additional critical analysis to determine if exemption was
warranted.ERCOT ISO believes that structuring the revised definition in accordance with this approach is
more consistent with FERC’s intent of having an inclusive definition in the first instance, with modifications
occurring subsequently pursuant to critical analysis in a well defined exception process.Revising the BES
definition consistent with the above principles would counsel in favor of revisions to the current definition that
removed RE discretion and provided for inclusion or exclusion on a case by case basis.
ERCOT ISO also believes that the BES definition should provide for a general exclusion of distribution
facilities. In Orders 743 and 743-A, FERC made clear that, consistent with the terms of EPAct 2005,
distribution systems were excluded from the BES. However, FERC also made clear that it reserved the right
to judge whether something was distribution or transmission, and, therefore, subject to its jurisdiction.
Consistent with FERC’s findings in this regard, ERCOT ISO believes that the definition should provide the
general exclusion, with specific exclusions being performed as part of the exception process. This will meet
the goal of respecting Congress’ exclusion of distribution facilities, while ensuring the distribution/transmission
distinction is subject to clear, objective standards the application of which can be critically reviewed by FERC
to provide the appropriate procedural and substantive checks FERC envisions to ensure its jurisdiction is
applied in all relevant cases to facilitate enhanced system reliability.
In addition, ERCOT ISO supports memorializing the generation registration criteria in the BES definition.
However, consistent with the approach described above, the BES definition should not be characterized in
terms of inclusions or exclusions, but rather as general thresholds, with modifications occurring solely

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Organization

Yes or No

Question 1 Comment
pursuant to the exemption process.
Finally, with respect to generation, ERCOT ISO questions the 75 MVA threshold applied to collector system
type generation. As indicated by the SDT, this was intended to capture renewable resources (e.g. wind), and
ERCOT ISO agrees with this clarification, but questions whether the 20 MVA threshold should apply. These
systems can include multiple wind turbines on the collector system, but when they are interconnected at a
single point, they are viewed as a single resource and, as such, should be subject to the same 20 MVA
threshold as other single units.Applying the approach described above, the BES definition would reflect
general thresholds. Specific circumstances warranting exception would occur via a separate process ERCOT ISO is not disagreeing with any of the SDT’s inclusions or exclusions, it is merely suggesting that
they be addressed in that separate process.
Consistent with this approach, ERCOT ISO offers the following language:The Bulk Electric System shall
include: A) all Transmission Elements operated at voltages100 kV or higher; B) all generation resources that:
1) are individual units greater than 20 MVA; 2) multiple units at a single facility that are equal to or greater
than 75 MVA in the aggregate, provided that all units have a common point of interconnection; and 3) multiple
units connected to a collector system that are equal to or greater than 20 MVA in the aggregate; 4) all
Blackstart Resources; and C) Reactive Power resources connected at 100 kV or higher. The BES shall not
include distribution facilities, and radial transmission facilities serving only load with one transmission source
are generally not included in this definition. The foregoing notwithstanding, any relevant element (e.g.
transmission, generation, etc.) may be included or excluded in the BES pursuant to the relevant exception
processes criteria and analyses as provided for in the NERC Rules of Procedure.

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists.
In the first posting, a reference to the Rules of Procedure exception process was inadvertently omitted from the posting. It has been added back in to this
posting.
The SDT has also made revisions to the draft definition to clarify that the BES does not include Facilities used in the local distribution of electric energy.
The SDT feels this threshold is consistent with the existing limits in the ERO Statement of Compliance Registry Criteria. No stakeholder provided sufficient
technical analysis to support a change.
Also, see the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list

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Question 1 Comment

shown below. This does not include facilities used in the local distribution of electric energy.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.
ExxonMobil Research and
Engineering

No

The SDT’s attempt to create a structure that clarifies what types of facilities should be included / excluded
from the bulk electric system is a positive step; however, the utilization of an automatic fault interrupting
device as the end point criteria for bulk electric and start point for local distribution is inappropriate. The
Federal Power Act specifically excludes all “facilities used in the local distribution of electric energy” from the
bulk power system without mention of how these facilities are isolated from the transmission system.

Response: See the responses to comments as well as a discussion of the latest revisions regarding the Radial Exclusion in Question 7 and the responses to
comments regarding Local Distribution Facilities in Question 11 below. No change made.
American Electric Power

No

Rather than a 75 MVA threshold as designated in I3, we suggest a threshold of 100 MVA which we believe to
be more appropriate.
It is difficult to provide comments regarding the BES definition, given the parallel nature of the other related
deliverables currently out for review. For example, there needs to be a defined relationship between an
approved definition of BES, the technical principles for demonstrating BES exception, and the exception
process itself. When closely related projects such as these are done simultaneously, no individual deliverable
can rely on the completed work of another. As a result, we risk having conflicting decision making across
these projects.

Response: The SDT discussed and has retained the 75 MVA threshold for generating resource(s) located at a single site. The SDT feels this threshold is
consistent with the existing limits in the Registry Criteria. No stakeholder provided sufficient technical analysis to support a change. Also, see the responses to
comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below. No change made.
The teams working on the various documents needed to address the revision to the definition of BES are coordinating their work and did provide some overlap in
the posting periods to provide stakeholders with an opportunity to see the various draft products at one time. Unfortunately, the schedule for delivery doesn’t allow
the products to be developed serially.
Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

No

Please see discussion in response to Questions 2, 7, 9, 10, 11, 12 and 13.

Response: Please see response to Questions 2, 7, 9, 10, 11, 12, and 13.

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Question 1 Comment

Springfield Utility Board

No

SUB appreciates the effort put forward in this process and is indicating “no” primarily because Springfield
Utility Board (SUB) has observed that the statutory term “Bulk Power System” is being applied in some cases
as being equivalent and interchangeable with “Bulk Electric System”. SUB is concerned that the SDT’s
proposed BES definition is broad and that it will sweep in many elements that have little or no material impact
on the reliable operation of the interconnected bulk transmission grid. Springfield Utility Board requests that
NERC create a distinction between the terms BPS and BES. Are the two to be used interchangeably, or will
BPS no longer be used? SUB suggests NERC consider adopting the statutory definition of the Bulk Power
System as the core definition of the Bulk Electric System.

Springfield Utility Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with the
concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: See the responses to comments as well as a discussion of the latest revisions regarding Generation Exclusions for units serving retail customer load
in Question 8 below.
See the responses to comments regarding the Regulatory Requirements in Question 12 below.
Note that in Reliability Standards, the term “Bulk Electric System” (a formally defined term) is used; however in other NERC corporate documents the term, “bulk
power system” (not capitalized) is used.
Southern California Edison
Company

August 19, 2011

No

The current approach seems to be based on the assumption that the presence of particular equipment is
more important than the manner in which the equipment is used. Before SCE can support the BES Definition,
the definition should be revised to include “All Transmission and Generation Elements and Facilities operated
at voltages 100 kV or higher, Real Power resources as described below, and Reactive Power resources

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Question 1 Comment
connected at 100 kV or higher that operate in parallel with the integrated networked transmission system and
are necessary for operating the interconnected transmission network, unless such designation is modified by
the list shown below.” This modification will provide the clarification needed to better ascertain what facilities
should be identified as part of the BES and lessen the need to trigger the Rules Of Procedure exceptions
process.
If “Inclusions” and “Exclusions” continue to be a part of the BES definition, they will need additional
clarification to ensure the exclusion of radial and distribution facilities which (1) do not have interconnected
operations risk and (2) are not used for inter-utility transfers on the BES and, therefore, are not necessary for
operating the interconnected transmission network.
They also need to be modified to work in tandem with the “Technical Principles for Demonstrating BES
Exceptions”, so that these types of facilities don’t continually have to be validated by the ROP exceptions
process. Example: The exclusion of facilities which are radial or distribution in nature and that have
connecting generation of 20MVA or higher for the purpose of serving local load and that are not used to
transfer power between “systems” to the BES should be automatic under the BES Definition.

Response: Based on the stakeholder comments as shown below, the SDT has made additional clarifying revisions to the draft BES definition. The BES draft
definition includes all three sections – core definition, list of inclusions, and list of exclusions. The SDT has revised the bright line core definition to clarify that all
Transmission Elements at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless
there is a modification for a particular Element in the Inclusion or Exclusion lists.
The Rules of Procedure exception process will only be used for those facilities that entities feel should also be excluded or that regions feel should also be
included.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
New York State Dept of Public
Service

August 19, 2011

No

1) We do not agree with the core definition. The core definition starts with the premise that the definition
must be drafted based on a 100 kV brightline designation. FERC’s Order 743 and 743-A clearly state that is
just one approach and would entertain other approaches that demonstrate the same level of reliable operation
and is responsive to FERC’s reliable operation concerns. As the EPAct 2005 recognizes, the industry
technical expertise is preserved in the NERC and does not reside at FERC. Therefore, FERC’s jurisdiction is
expressly limited by Section 215 of the Federal Power Act. Moreover, FERC cannot, under the guise of
“policy” concerns, exceed the limits of its statutory authority. FERC’s orders recognize this, and repeatedly
acknowledge that FERC must exclude facilities used in local distribution from the definition of BES. FERC’s
orders, at most, assert that “some” 115/138 kV facilities are needed to reliably operate the bulk system.

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FERC has made no showing that all facilities of 100kV or greater are necessary for reliable operation of the
grid. Without a record based finding that all such facilities are necessary for reliable operation of the grid,
FERC cannot include all such facilities within its definition of BES. FERC has even explicitly acknowledged
within a New York transmission tariff rate case that a 115 kV loop around a significant size city should not be
included in the transmission account as it existed solely to serve load in that city. Given the technical
expertise to devise a definition more refined lies with the industry, FERC wisely deferred to NERC processes
the ability to employ a different approach other than a brightline. Therefore, NERC should apply its expertise
to fashion a definition of “bulk electric system” that comports with the statutory jurisdictional limitations
Congress imposed upon FERC in FPA Section 215. NERC’s efforts should be checked at every step that they
are not exceeding the originating authority contained in FPA Section 215. Overall, the definition must be
guided by, and limited to, the FPA definition of reliable operation which is explicitly defined as limited to
protection of the bulk system by “operating the elements of the bulk-power system ... so that instability limits,
uncontrolled separation, or cascading failures of such systems will not occur....”, and expressly excludes
facilities used in local distribution.
2) NERC fails to make any technical demonstration that using the existing definition as a starting point is
valid. Moreover, NERC has resisted pursuing alternative avenues. The NPCC study submitted to FERC in
the combined NERC-NPCC compliance filing in September 2009, clearly demonstrated the movement from
the NPCC regional criteria to a 100 kV brightline provided little, if any, increased levels of reliable operation.
Through extrapolation, a study of other areas is likely to indicate that reliable operation levels throughout the
rest of the country could be assured by a more refined selection of which facilities under 200 kV should be
included as part of the bulk system. Note that FERC did not reject use of material impact assessmensts; they
only objected to the fact that the NPCC test did not include some regional interconnection facilities, some
nuclear interconnections and a particular load area.NERC’s failure to evaluate other approaches than a
brightline 100 kV standard is a failure to ensure adequate levels of reliable operation at a sustainable level
consistent with provisions of the FPA.All remaining comments on the definition, as presented by NERC, are
based on our belief that the proposed definition is overreaching in its basic premise of starting with a brightline
100 kV as its core definition of the bulk system.
3) It is not clear why the core definition has dropped “generation” interconnected at the specified voltage level.
The following inclusions/exclusions included generation facilities and it appears inconsistent to not include
generation in the core definition.

Public Utilities Commission of
Ohio

August 19, 2011

No

FERC jurisdiction is limited by the Federal Power Act, Section 215. To make a bright line designation as the
starting point, without a demonstration that ALL facilities at 100 kV and greater affect the reliability of the bulk
power system is a step beyond FERC jurisdictional boundaries. The Federal Power Act explicitly excludes
facilities used in local distribution from the bulk power system. NERC should give serious consideration to

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Question 1 Comment
other (non bright-line) approaches to ensure bulk system reliability.

City of Redding

Yes

In general Redding supports the work of the SDT team in revising the core definition of the Bulk Power System
as ordered by FERC. The core definition, as written, is a good step at removing the ambiguities of the current
definition and is acceptable as long as it is coupled with a fair and objective Exception Process that, as FERC
directed in Order 743, “excludes facilities the ERO determines are not necessary for operating the
interconnected transmission network”. (P 30). It is Redding’s opinion that using a voltage threshold is a
convenient method to make an initial dividing line however it does not provide adequate proof that elements,
over or under this voltage threshold, are “necessary” for the operation of the Bulk Electric System (BES). It is
also noted that while the 100 kV threshold is intended to capture the majority of the power system elements
that are potentially BES, on a continent wide basis, a 200 kV threshold would serve the Western Interconnect
better as a starting brightline. In the Western Interconnect the majority of 100 kV elements are used as
Distribution facilities. Therefore, this will burden NERC and the Regional Entity in the West with a larger
number of Exception Process applications.
Redding supports the use of exclusion and inclusion lists in the Definition; however Redding believes the SDT
needs to take a more literal approach to FERC’s Orders and define the term “necessary for operating the
interconnected transmission network” and clearly “establish whether a particular facility is local distribution or
transmission”. Without a clear distinction of these two foundational principles it is difficult to have a significant
discussion about the validity of the proposed inclusions and exclusions and the thresholds involved.
As an alternative to the proposed definition, Redding would support using a simple approach to meet FERC’s
orders (as long as is coupled with an “exception process that includes clear, objective, transparent, and
uniformly applicable criteria of facilities that are not necessary for operating the grid”). (Order 743A P73). If the
above criteria is developed to accomplish the above then the existing definition could be modified to read:
“Electrical generation resources, transmission lines, interconnections with neighboring systems, and associated
equipment, operated at voltages of 100 kV or higher.”

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists.
The SDT elected to retain the 100 kV bright line criteria. This is the bright-line voltage level that is included in the existing approved definition of the Bulk Electric
System in the NERC Glossary of Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification was provided that would

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Question 1 Comment

lead the SDT to make a change. One goal of this project is to add clarity to the definition without significantly changing the population of BES elements.
Finally, the SDT has made revisions to the draft definition to clarify that the BES does not include Facilities used in the local distribution of electric energy as
established by applicable regulatory authorities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Cogentrix Energy, LLC

No

I would like to see a definition for clarity of an "Individual Generating Unit"Example:Solar farm with 300
photovoltaic units. Each is a stand-alone unit with its own inverter, but all come together at a common tie
breaker to connect to the BES.
Questions:1. Would each one be considered directly tied to the BES through one common tie breaker?
2. Would each photovoltaic unit be considered an individual generating unit?
3. Would the combined total of 300 units be considered an individual generating unit or would they be
considered a facility?

Response: The SDT is not in position to provide an answer without first making sure that all relevant data is in hand.
The Dow Chemical Company

No

See Dow's specific comments on some of the following questions.

Response: See specific responses in following questions.
Clark Public Utilities

No

Clark is concerned that the core definition is overly-broad and sweeps facilities into the BES that are required
by the statute to be excluded, even considering the list of inclusions and exclusions. Clark urges the SDT to
bear in mind the specific restrictions on the definition of “bulk-power system” contained in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress defined “bulk-power system” to mean “facilities
and control systems necessary for operating an interconnected electric energy transmission network (or any
portion thereof)” and “electric energy from generation facilities needed to maintain transmission system
reliability.” 16 U.S.C. § 824
o(a)(1). Congress unequivocally excluded from this definition “facilities used in the local distribution of electric
energy.” The “bulk-power system” definition thus imposes a clear limit on the reach of the mandatory reliability
regime. Congress reinforced that limit in Section 215(i), where it emphasized that the FPA authorizes the
imposition of reliability standards “for only the bulk-power system.” 16 U.S.C. § 824
o(i)(1). Clark believes it is clear that Congress intended the “bulk-power system” to be defined narrowly so

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Question 1 Comment
that it would incorporate only high-voltage, interstate facilities used to transmit power over long distances,
whose failure threatens drastic reliability events such as system instability, uncontrolled separation, or
cascading outages.In addition, the Federal Energy Regulatory Commission clearly stated that Order No. 743
did not mandate or direct NERC to adopt a 100 kV bright-line threshold (Order No. 743-A, 134 FERC ¶
61,210 at P 20. The Commission goes on to state that the 100 kV bright-line threshold is only one way to
address the Commission’s concerns. The Commission only requires that NERC use the Commission’s
recommendation or propose a different solution that is as effective as, or superior to, the Commission’s
proposed approach. The Commission also acknowledges that Congress has specifically exempted facilities
used in the local distribution of electric energy.The definition developed by the SDT should therefore focus on
that portion of the interconnected bulk transmission grid for which thermal, voltage, and stability limits must be
observed in order to prevent instability, uncontrolled separation, or cascading outages.
Further, in order to honor the specific limits placed on the definition by Congress, the SDT’s definition must
exclude facilities used in the local distribution of electric power and it must exclude facilities whose operation
or mis-operation affects only the level of service and does not threaten cascading outages or other
widespread events on the bulk interconnected system. Clark asserts that the adoption of a bright-line
threshold of 100 kV is arbitrary and not based on any investigation of the potential for facilities at this voltage
level to cause instability, uncontrolled separation, or cascading outages or for the general need of these
facilities for the operation of an interconnected electric energy transmission network. The threshold excludes
transmission facilities below 100 kV without any determination on a general basis of whether these facilities
affect interconnected system operation. It goes without saying that these low voltage transmission facilities
should be subject to an inclusion process in the event that regional reliability entities believe they do have an
impact on reliability but on a case-by-case basis. Clark agrees with this concept and does not believe bringing
low voltage transmission facilities into the BES through an inclusion process causes any BES reliability
issues.
Similarly, Clark believes that the majority of facilities between 100 kV and 200 kV can be shown to have no
impacts on interconnected system operation and do not threaten instability, uncontrolled separation, or
cascading outages. Clark also points out that the vegetation outage standard (FAC-003) uses this approach.
The standard applies to facilities operated at 200 kV or above and “lower voltage lines designated by the
RRO as critical to the reliability of the electric system in the region.”
Clark believes the use of 100 kV as the bright-line threshold will result in a large number of facilities being
brought into the definition of the BES that are either 1) part of a Local Distribution Network, 2) are radial
serving only load from one transmission source, or 3) that can be shown to have no affect on interconnected
system operation or cannot cause instability, uncontrolled separation, or cascading outages. This
unnecessary inclusion will cause a large amount of effort on the part of the owners of these facilities and on
the part of the Regional Reliability Organizations that will have to review the many exclusion filings that will
result. Utilizing a 200 kV threshold with a low voltage inclusion process will eliminate much of the

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Question 1 Comment
unnecessary paperwork since very few owners of 200 kV or above facilities will seek exclusions. This will free
up regional reliability entities to focus on low voltage transmission facilities that truly have an impact on
interconnected system operations.Clark believes that the SDT and the NERC should consider adopting a
bright-line threshold higher than 100 kV with low voltage inclusion and develop the arguments necessary to
demonstrate to the Commission that this solution is as effective as, or superior to, the Commission’s
proposed approach.
These arguments should include the following: o Eventually, a 200 kV bright-line threshold with a low voltage
inclusion process will incorporate into the BES the same facilities that a 100 kV bright-line threshold with an
exclusion process. This means that these two concepts both have the same effect on the reliability and the
operability of the BES. o Utilizing a 200 kV bright-line will reduce the amount of initial effort by transmission
owners and Regional Reliability Organizations and allow these entities to concentrate on low voltage facilities
that truly have an impact on the BES.
Clark is similarly concerned that the SDT’s proposed definition is overly-broad in including all generating units
greater than 20 MVA capacity connected to transmission at 100 kV or above. Clark believes that there are
many small to medium sized generators that individually have no affect on interconnected system operations
and do not threaten the BES with instability, uncontrolled separation, or cascading outages. Many of these
generators are connected to Local Distribution Networks with minimum loads that exceed maximum
generation. While the generators do support system reliability collectively, it is questionable whether many of
these generators individually represent a facility necessary for interconnected system operations. The
adoption by the SDT of a 200 kV bright-line threshold would eliminate many of these smaller generating units.
Again, the RROs must have an inclusion process for smaller generating units it believes support
interconnected system operations. Clark believes that eventually both thresholds (with appropriate inclusion
and exclusion processes) will result in the same 100 kV to 200 kV connected generators being included in the
BES so there will be no difference in the reliability of the BES. Adopting the higher of the two thresholds and
adopting a generating capacity threshold higher than 20 MVA will allow generator owners and Regional
Reliability Organizations to devote resources to small generating units that truly have an impact on
interconnected system operations.

Response: The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power
resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.
The SDT elected to retain the 100 kV bright-line criteria. This is the bright-line voltage level that is included in the existing approved definition of the Bulk Electric
System in the NERC Glossary of Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification was provided that would
lead the SDT to make a change. One goal of this project is to add clarity to the definition without significantly changing the population of BES elements.
See the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below.

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Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Central Lincoln

No

We support the PNGC comments suggesting beginning with the statutory definition of BPS that excludes local
distribution.
The definition should also be further elaborated to show specific points of demarcation for each inclusion and
exclusion by the use of diagrams similar to those included with Proposal 6 from the WECC Bulk Electric
System Definition Task Force.
We also note that per the flowchart at
http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf, any >100 kV element that does not
meet an inclusion or an exclusion ends up being included. We don’t think that was the SDT’s intent. For
example a 5 kW solar project connected at 115 kV does not meet any inclusions so proceed to the exclusion
box. It is not radial load, behind a retail meter, or part of an LDN so it is BES by application of the definition.
We realize this flowchart was drafted by another team. It therefore becomes imperative that the definition
team clearly specifies exactly what becomes of an element that does not meet an inclusion.

Response: See the responses to comments regarding Local Distribution Facilities in Question 11 below.
The SDT has revised the wording of the generation inclusions to reference the ERO Statement of Compliance Registry Criteria for consistency. Therefore, there
should be no change in registration due to the revised definition.
Southwest Power Pool

August 19, 2011

No

SPP generally agrees with the substance of the SDT’s changes, but suggests a different approach. In order
743, to remedy its concerns, FERC suggested eliminating RE discretion in defining the BES, and instead
basing it upon a bright-line 100kV threshold, provided that elements above and below 100kV could be
excluded and included, respectively, based on specific procedures. Consistent with that approach, SPP
suggests that the BES definition itself establish a bright line standard, with inclusions and exclusions
managed through the exemption process.With respect to exclusions (and inclusions), FERC contemplated a
process involving stages that established “exclusion” criteria in the first instance. If equipment met such
criteria, the process ended there and it was exempt. If the equipment did not meet the bright-line criteria, then
it moved to the “exemption” analysis, which contemplated additional critical analysis to determine if exemption
was warranted.SPP believes that structuring the revised definition in accordance with this approach is more
consistent with FERC’s intent of having an inclusive definition in the first instance, with modifications occurring
subsequently pursuant to critical analysis in a well defined exemption process.Revising the BES definition
consistent with the above principles would counsel in favor of revisions to the current definition that removed

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Question 1 Comment
RE discretion and provided for inclusion or exclusion on a case by case basis.
SPP also believes that the BES definition should provide for a general exclusion of distribution facilities. In
Orders 743 and 743-A, FERC made clear that, consistent with the terms of EPAct 2005, distribution systems
were excluded from the BES. However, FERC also made clear that it reserved the right to judge whether
something was distribution or transmission, and, therefore, subject to its jurisdiction. Consistent with FERC’s
findings in this regard, the SRC believes that the definition should provide the general exclusion, with specific
exclusions being performed as part of the exception process. This will meet the goal of respecting Congress’
exclusion of distribution facilities, while ensuring the distribution/transmission distinction is subject to clear,
objective standards the application of which can be critically reviewed by FERC to provide the appropriate
procedural and substantive checks FERC envisions to ensure its jurisdiction is applied in all relevant cases to
facilitate enhanced system reliability.
However, consistent with the approach described above, the BES definition should not be characterized in
terms of inclusions or exclusions, but rather as general thresholds, with modifications occurring solely
pursuant to the exemption process. Applying the approach described above, the BES definition would reflect
general thresholds. Specific circumstances warranting exclusion/exception/inclusion would occur via a
separate process -SPP is not disagreeing with any of the SDT’s inclusions or exclusions, it is merely
suggesting that they be addressed in that separate process.
Consistent with this approach, SPP offers the following language:The Bulk Electric System shall include: A)
all Transmission Elements operated at voltages 100 kV or higher; B) all generation resources that: 1) are
individual units greater than 20 MVA; 2) multiple units at a single facility that are equal to or greater than 75
MVA in the aggregate, provided that all units have a common point of interconnection; and 3) multiple units
connected to a collector system that are equal to or greater than 75 MVA in the aggregate; 4) all Blackstart
Resources regardless of size; and C) Reactive Power resources connected at 100 kV or higher. The BES
shall not include distribution facilities, and Radial transmission facilities serving only load with one
transmission source are generally not included in this definition. The foregoing notwithstanding, any relevant
element (e.g. transmission, generation, etc.) may be identified as an exception and excluded or included in
the BES pursuant to the process delineated in the NERC Rules of Procedure and subject to the exclusion or
inclusion criteria.All equipment specific issues that affect exclusions/exceptions/inclusions would then be
addressed via the Rules of Procedure processes and the exclusion and inclusion criteria.

Response: The SDT has made additional clarifying revisions to the draft BES definition. The BES draft definition includes all three sections – core definition, list
of inclusions, and list of exclusions. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the
Inclusion or Exclusion lists.
In the first posting, a reference to the Rules of Procedure exception process was inadvertently omitted from the posting. It has been added back in to this

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posting.
The SDT has also made revisions to the draft definition to clarify that the BES does not include facilities used in the local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.
PPL Energy Plus and PPL
Generation

No

See the response to Question 13

Response: See response to Question 13.
Independent Electricity System
Operator

No

We agree with the BES definition principles in general, the concept of Inclusions and Exclusions, as well as
the proposal for an Exception Process. However, since the Exception Process and the Technical Principles
and Criteria (TPC) for justifying BES Exceptions are being developed and will be approved independently,
albeit concurrently with the BES definition, there is a risk that the revised definition may be approved while the
TPC and Exception Process may not come to fruition in the form anticipated during development of the BES
definition. In short, our support for any revised BES definition would be conditional to the establishment of the
associated TPC. As such we advocate developing the revised BES definition and TPC as a “single
package”.Thus, we do not agree with the blanket inclusion of generation units and Facilities meeting the
thresholds of 20 MVA and 75 MVA respectively. We also do not agree with using these same thresholds in
determining when Exclusions are applicable. Instead, we believe the impact on BES reliability of all
generation units and Facilities meeting these capacity thresholds, should be assessed against the TPC and if
found to be impactive, these units and Facilities should be included as part of the BES after going through the
Exception Process.We believe this change in the approach to defining the BES will take into account the
evolving reality of distributed generation, particularly in the context of radial systems and local distribution
networks (LDNs), where generation units are installed in lieu of transmission reinforcements. We offer our
further comments on the Definition and its Inclusions and Exclusions against the backdrop of this general
philosophy.
The BES definition refers to Reactive Power resources “connected at” 100 kV or higher as opposed to
“operated at” 100 kV or higher. Is the intent of this wording to include in the BES a reactive resource
(capacitor, reactor, etc.) operating at a voltage below 100 kV and connected to the BES via a step-up
transformer?

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Organization

Yes or No

Question 1 Comment
If yes, would the transformer be excluded from the BES to be consistent with Inclusion I1?

Response: The SDT is tasked with creating a bright-line continent-wide definition for the BES. One of the goals of this effort is to ensure that similarly situated
elements in different regions are included or excluded on a consistent basis. The Rules of Procedure Exception process will only be used for those facilities that
entities feel should also be excluded or that regions feel should also be included.
The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power resources
connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.
In response to comments, the SDT added an additional item to clarify the inclusion of Reactive Resources and an additional exclusion to clarify that Reactive
Resources that are owned by retail customers for their own use are not to be included.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Dayton Power and Light
Company

No

Response: Without any specific comments, the SDT is unable to respond.
BPA

No

Tacoma Power

BES Definition First Paragraph - Change first sentence to “Unless otherwise excluded below, all Transmission
Elements operated at 100 kV or higher and those facilities included in the list below, Real Power resources
included below, and Reactive Power resources connected at 100 kV or higher.”
Tacoma Power generally supports clarifying changes to the BES definition by the SDT and the goal of
including only those facilities that materially impact the reliable operation of the interconnected bulk
transmission system. We propose one change to help guide the industry as the definition is applied.
Currently, the definition includes the clause ‘unless such designation is modified by the list shown below,’
positioned after the reactive resources clause. Due to the position of the clause, it can be misinterpreted to
apply only to reactive resources. To eliminate this ambiguity, we suggest that the proposed definition be
reordered to read as follows:”Bulk Electric System (BES) definition: (A) Unless included or excluded in
Section B below, the BES consists of: (1) All Transmission Elements operated at 100 kV or higher; (2)
Real Power resources identified in Section B below; and (3) Reactive Power resources connected at 100
kV or higher.(B) [BES designation criteria, list of inclusions and exclusions].”
Additionally, the BES definition should not require the inclusion of contiguous elements as the definition is
further developed.Lastly, the proposed BES definition for comments is not clear on the state of the system

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Organization

Yes or No

Question 1 Comment
conditions (normal or emergency) that should be assumed when applying the definition. The definition should
apply to only normal operating conditions.

Orange and Rockland Utilities,
Inc.
American Transmission
Company, LLC

In the core definition, “the list shown below” is still not clearly defined and causes some confusion.

Yes

However, to clarify the core definition, ATC proposes to change the text for Real and Reactive Power
resources from “connected” to “operated or connected”.

Response: The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power
resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Consolidated Edison Co. of NY,
Inc.

PUD No. 2 of Grant County,
Washington

Guidance Document - The SDT should develop a BES Definition Guidance Document which includes a fairly
comprehensive list of Elements considered to be potentially necessary for operating an interconnected
electric energy transmission network. This list would include references to Real Power and Reactive Power
resources.
Yes

Grant supports the approach the Standards Development Team (“SDT”) has taken to defining the Bulk
Electric System (“BES”). The changes made in the revised core definition are helpful and represent
significant progress toward an acceptable definition. With an effective and efficient exclusion process, the
draft will better define the BES as a whole. The definition could then be further elaborated to show specific
points of demarcation for each inclusion and exclusion similar to that Proposal 6 from the WECC Bulk Electric
System Definition Task Force (“BESDTF”) team to further delineate BES and non-BES facilities.

Response: The SDT will consider drafting a Guidance Document as a part of this project in order to provide the specific guidance you suggest.
United Illuminating

The definition should incorporate the language in Energy Policy Act of 2005 that defines bulk power system.
UI agrees in general that facilities operated at 100 kV and above are part of bulk power system. Without the
clarification in the definition the possibility of facilities that are not necessary for the operation of the
interconnected transmission will be pulled into scope.

Response: This suggestion would be outside of the scope of the approved BES Definition project. The SDT is tasked with creating a bright-line continent-wide

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Organization

Yes or No

Question 1 Comment

definition for the BES. The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and
Reactive Power resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or
Exclusion lists.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Portland General Electric
Company

The bright-line definition of 100kV should specify that this is a three-phaseline-to-line voltage.

Response: The currently approved definition of the BES in the Glossary of Terms does not include this clarification. The SDT discussed your comment and
decided that this clarification was not necessary. Furthermore, all ac and dc facilities with a line-ground or line-line voltage greater than 100 kV would be included
in the BES except as modified by the lists of exclusions or inclusions. No change made.
Sweeny Cogeneration LP

The specific identification of global inclusions and exclusions is a very good way to approach this complex
issue.
We believe there are further items to be added to the list related to generator interconnections, a task that
was passed to this project from Project 2010-07.
Just as is the case with complex distribution systems, there are a variety of generator-transmission
interconnection architectures which are driving the Regions to inappropriately register Generator
Owner/Operators as Transmission Owners.

Response: See the responses to comments as well as a discussion of the latest revisions regarding generation inclusions in Questions 3, 4, and 6 below.
For clarification, no tasks were passed from Project 2010-07 to the Project 2010-17.
The BES Definition and the associated Exception Process are separate and distinct from the ERO Statement of Compliance Registry Criteria.
American Municipal Power and
Members
Florida Municipal Power Agency
Transmission Access Policy
Study Group

August 19, 2011

Yes

AMP and its members appreciate the opportunity to comment on the draft BES definition. We generally
support the direction taken by the SDT, with some minor changes.We agree with some other entities'
comments and suggest a few clarifying edits to the core definition. First, the definition should refer to “nongenerator Reactive Power resources,” to make clear that although all generators provide some reactive
power, those that do not meet the criteria of I2-I5 are not included in the BES.
There is ambiguity concerning whether a transformer stepping down from >100 kV to <100 kV is included or
not, though we believe that the SDT intends to exclude such transformers. It is clear that transformers with

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Organization

Yes or No

Question 1 Comment
two windings >100 kV are included and GSUs for registered generators are included, but it is somewhat
unclear in the current draft whether a 138 kV to 69 kV transformer is included or excluded. We suggests
making it clear that the intent of the SDT is to include (a) GSUs associated with BES generators and (b)
transformers with 2 or more windingwindings >100 kV, and that other transformers are excluded.
We also believe the drafting team intended to exclude all elements that are not included either under the BES
definition and designations or through the exception process. For the sake of clarity, we suggest that a
sentence to that effect be added to the core definition.
Finally, we note that the definition does not currently refer to the existence of the exception process. We
suggest that such a reference be added either to the core definition or to the lists of Inclusions and
Exclusions.
The following is the core definition incorporating the changes:All Transmission Elements (except
transformers) operated at 100 kV or higher, transformers as described below, Real Power resources as
described below, and non-generator Reactive Power resources connected at 100 kV or higher unless such
designation is modified by the list shown below. The NERC Rules of Procedure provide an Exception
Process through which Elements not included in the BES under this definition and designations may be
included in the BES, and Elements included in the BES under this definition and designations may be
excluded from the BES. Elements not included in the BES either by application of this definition and
designations, or through the BES exception process, are not BES Elements.

Northern California Power
Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.

Response: The SDT added an additional item to clarify the inclusion of Reactive Resources and an additional exclusion to clarify that Reactive Resources that
are owned by retail customers for their own use are not to be included.
See the responses to comments as well as a discussion of the latest revisions regarding the Transformer Inclusion in Question 2.
In the first posting, a reference to the Rules of Procedure exception process was inadvertently omitted from the posting. It has been added back in to this
posting.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.

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Organization
Small Entity Working Group
(SEWG)

Yes or No

Question 1 Comment

Yes

The Small Entity Working Group (SEWG) appreciates the opportunity to comment on the draft BES definition.
The group generally supports the direction taken by the SDT, with some minor changes.The BES definition
should refer to “non-generator Reactive Power resources,” to clarify that although all generators provide some
reactive power, the generators that do not meet the criteria of I2 through I5 are not included in the BES.
The BES definition should include a reference to the existence of the exception process.

MRO's NERC Standards Review
Forum

Yes

Please quantify that Reactive Resources within the BES definition are meant to be generator resources and
not static resources.

Muscatine Power and Water

Yes

Would like to ask the SDT to please affirm that Reactive Resources within the BES definition are intended to
be generator resources and not static resources.

Illinois Municipal Electric Agency

Yes

With the following clarifying edits. The BES definition should refer to “non-generator Reactive Power
resources,” to clarify that although all generators provide some reactive power, the generators that do not
meet the criteria of I2 through I5 are not included in the BES.

Pepco Holdings Inc

Yes

Do reactive power resources include reactors?

Response: In response to comments, the SDT added an additional item to clarify the inclusion of Reactive Resources and an additional exclusion to clarify that
Reactive Resources that are owned by retail customers for their own use are not to be included.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.
E4 – Reactive Power devices owned and operated by the retail customer solely for its own use.
Santee Cooper

Yes

We agree with the changes of adding the inclusions and exclusions. We recommend that I3 be 100 MVA or
higher. Was there a rationale for using 75 MVA?

Response: See the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below.
SERC OC Standards Review
Group

Yes

The SERC Standards Review Group (SRG) still believes that 200KV is the correct bright line for the BES
definition

Response: The SDT elected to retain the 100 kV bright-line criteria. This is the bright-line voltage level that is included in the existing approved definition of the
Bulk Electric System in the NERC Glossary of Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification was provided

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Organization

Yes or No

Question 1 Comment

that would lead the SDT to make a change. One goal of this project is to add clarity to the definition without significantly changing the population of BES
elements.
National Rural Electric
Cooperative Association
(NRECA)

Yes

NRECA believes the definition should explicitly state that facilities used in local distribution are excluded from
the BES.

Response: See the responses to comments regarding Local Distribution Facilities in Question 11 below.
New York Power Authority
MEAG Power

Yes

The New York Power Authority (NYPA) supports the Standards Drafting Team’s development of a revised
Bulk Electric System (BES) definition in response to FERC Order 743 that is directly linked to an exception
process for inclusions and exclusions. The definition must be closely coupled to the exception process and
the two must be integrated in the standard that is ultimately adopted. This will ensure that the regulatory
requirements apply to only those facilities that materially affect the reliability of the BES.In general, NYPA
agrees with the proposed definition and the objectives the Standards Drafting Team has established. NYPA
recommends that the team make additional clarifications to provide industry with a better understanding of the
inclusions and exclusions, as well as the impact of the inclusions/exclusions on the BES.
The definition should exclude generator leads for generating units that do not materially affect the reliability of
the BES regardless of the BES designation of the generating unit.
In addition, the definition should not require the inclusion of contiguous elements. Generating units that are
designated BES are currently required to comply with a subset of NERC Reliability Standards, but may not be
material to the reliable operation of the interconnected BES. This portion of the definition should not require
that both BES and non-BES generating units have their generator leads defined as BES transmission
elements.
A length-based criterion for generator leads ought to be considered. For example, the definition should
exclude generator leads that are one mile or less between BES elements.
The Standards Drafting Team should engage and coordinate with the Standards Drafting Team for Project
2010-07 (the GO/TO task force). This coordination is needed to determine the impacts of the new BES
definition on Transmission Owner (TO) and Transmission Operator (TOP) registration.
In addition, NYPA recommends that the Standards Drafting Team and the GO/TO Task Force consider, if
they have not already done so, the impacts of ownership and operating agreements on registration. For
example, clarification of registration impacts for BES elements that are jointly owned by two utilities (e. g.
where one utility owns 5 of 20 towers and the other utility owns the remaining towers and the conductor of a
transmission line) is required.

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Organization

Yes or No

Question 1 Comment
The definition does not provide clarity on the state of the system conditions (normal or emergency) that
should be applied. The definition should apply to only normal operating conditions.

Response: See the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3, 4, and 6 below.
One goal of this project is to add clarity to the definition without significantly changing the population of BES elements. The Registry Criteria is not being revised
by this project.
The leadership of the two SDTs, Project 2010-17 Definition of BES and Project 2010-07 GO/TO TF, have met and coordinated as necessary.
Electricity Consumers Resource
Council (ELCON)

Yes

We support the expanded structure of the core definition that provides for inclusions and exclusions. This
clarification establishes a rebuttable presumption that excluded elements are not BES and appropriately shifts
the burden of proof for any subsequent inclusion to Regional Entities or the ERO, thereby minimizing the
regulatory burden on the industry, an outcome consistent with the Commission’s stated assumption that
revising the BES definition should have relatively minor impacts on registrations in non-NPCC regions.

Response: Thank you for your comments.
Western Area Power
Administration

Yes

As a Transmission Operator (TO) it helps us define and write O & M, and operating agreements for our Load
Serving Entities (LSE/customers) that prefer to contract the responsibilities to the TO. The definition 'Bright
Line Threshold' is a general statement, that needs more definition for the special circumstances in the
southwestern U.S. where pump loads provide necessary irrigation. Based upon NERC's compliance registry
criteria, small entities prefer to contract responsibilities to the TO in order to forego NERC registration, or the
exception process for special circumstances.

Response: The ERO Statement of Compliance Registry Criteria is not being revised by this project.
PacifiCorp

Yes

In general PacifiCorp agrees with the direction of the proposed BES definition. Specific exceptions are
discussed in questions 2 - 13

Response: Thank you for your support. See specific responses to Questions 2 – 13.
Public Utility District No. 1 of
Snohomish County, Washington
Clallam County PUD No.1

August 19, 2011

Yes

As a general matter, Snohomish County PUD supports the approach the Standards Development Team
(“SDT”) has taken to defining the Bulk Electric System (“BES”). In the comments we submit today, we identify
several refinements we believe would improve the definition. We also discuss the legal framework the SDT
must operate under as we understand it. But we support the SDT’s conceptual approach and, if refined as we
suggest, we will support the SDT’s proposal so long as an acceptable process for defining exceptions

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Organization

Yes or No

Question 1 Comment
accompanies the definition.
As to the core definition addressed in Question 1, Snohomish believes the changes made in the revised
definition are helpful and represent significant progress toward an acceptable definition. Nonetheless, we are
concerned that the core definition is overly-broad and sweeps facilities into the BES that are required by the
statute to be excluded, even considering the list of inclusions and exclusions. We therefore suggest two
different approaches below that may achieve the SDT’s aims more effectively than the proposed core
definition. At a minimum, as we explain below, additional clarifications to the core definition are necessary
and an acceptable exemption process is required to ensure that facilities that by statute must be excluded are
excluded from the BES as defined by the SDT.At the outset, we urge the SDT to bear in mind the specific
restrictions on the definition of “bulk-power system” contained in Section 215 of the Federal Power Act
(“FPA”) (Following FERC’s guidance on the question, we treat the statutory term “bulk-power system” as
equivalent to the term ordinarily used in the industry, “Bulk Electric System”). In Section 215(a)(1), Congress
defined “bulk-power system” to mean “facilities and control systems necessary for operating an
interconnected electric energy transmission network (or any portion thereof)” and “electric energy from
generation facilities needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1). Congress
unequivocally excluded from this definition “facilities used in the local distribution of electric energy.” Id. The
“bulk-power system” definition thus imposes a clear limit on the reach of the mandatory reliability regime.
Congress reinforced that limit in Section 215(i), where it emphasized that the FPA authorizes the imposition of
reliability standards “for only the bulk-power system.” 16 U.S.C. § 824o(i)(1) (emph. added).Further, the SDT
must bear in mind “the cardinal rule that a statute is to be read as a whole since the meaning of statutory
language, plain or not, depends on context.” City of Mesa v. FERC, 993 F.2d 888, 893 (D.C. Cir. 1993)
(citation omitted). In considering how Congress used the term “bulk-power system” in the statute, as well as
the limits on the reliability regime imposed in the surrounding statutory language, it is clear that Congress
intended the “bulk-power system” to be defined narrowly so that it would incorporate only high-voltage,
interstate facilities used to transmit power over long distances, whose failure threatens drastic reliability
events such as cascading outages. These limitations are plain from, for example, the statutory definition of
“reliability standard,” which provides that reliability standards are to encompass only requirements to “provide
for reliable operation of the bulk-power system.” 16 U.S.C. § 824o(a)(3) (emph. added). Congress further
refined the scope of reliability authority by specifically defining “reliable operation” to mean “operating the
elements of the bulk-power system within equipment and electric system thermal, voltage, and stability limits
so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a
sudden disturbance. . . or unanticipated failure of system elements.” 16 U.S.C. § 824o(a)(4). Congress’s
intent to focus the national reliability regime on broad-scale threats to the interconnected, interstate highvoltage system like cascading outages is made clear, as well, by Congress’s specific direction that the
mandatory reliability system is prohibited from enforcing standards for adequacy of service, which were left to
state and local authorities. 16 U.S.C. § 824o(i)(2).When read in the context of the statute as a whole, the
definition developed by the SDT should therefore focus on that portion of the interconnected bulk

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Organization

Yes or No

Question 1 Comment
transmission grid for which thermal, voltage, and stability limits must be observed in order to prevent
instability, separation events, and cascading outages. Further, in order to honor the specific limits placed on
the definition by Congress, the SDT’s definition must exclude facilities used in the local distribution of electric
power and it must exclude facilities whose operation or mis-operation affects only the level of service and
does not threaten cascading outages or other widespread events on the bulk interconnected system.
Snohomish is concerned that the SDT’s proposed definition is overly-broad, and that it will sweep in many
Elements that have little or no material impact on the reliable operation of the interconnected bulk
transmission grid. For example, the definition would sweep in all generators with 20 MVA capacity even
though generators this small rarely create impacts on the interconnected bulk transmission system that would
threaten to violate the thermal, voltage or stability limits of the bulk transmission system and therefore do not
threaten instability, separation, or cascading outages on the interconnected transmission system.
Accordingly, for the BES definition to conform to the requirements of the statute, the SDT must adopt an
effective mechanism to exempt facilities like these that are improperly swept in by the SDT’s brightline
approach to inclusions and exclusions. For this reason, the Exception process to accompany the SDT’s
definition is of critical concern. It constitutes the last line of defense against a SDT definition that sweeps in
facilities excluded by the statutory definition.Snohomish believes the SDT can achieve the goals of FERC’s
Orders No. 743 and 743-A while honoring these statutory limits by taking one of two alternative approaches to
the core definition. First, perhaps the simplest way the SDT could achieve the goals of FERC Order No. 743
while avoiding overbreadth that violates statutory limits is to simply adopt the statutory definition of “bulkpower system” as the core definition. This approach is commonly used by regulatory agencies in defining
key jurisdictional terms to ensure that the agency does not cross statutory boundaries when carrying out the
duties assigned to it by Congress. Under this approach, the core definition would simply echo the statutory
definition, substituting “Bulk Electric System” for its statutory equivalent, “bulk-power system”:The term ‘Bulk
Electric System’ means: (A) Facilities and control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof); and,(B) Electric energy from generation facilities
needed to maintain transmission system reliability.The term does not include facilities used in the local
distribution of electric energy.See 16 U.S.C. § 824o(a)(1). The inclusions and exclusions developed by the
SDT, with the refinements we discuss below, would then be added to provide guidance in the application of
this definition to specific classes of electric system facilities and Elements.
A second alternative approach is to make the smallest possible adjustment to the current BES definition that
suffices to address the central concern expressed by FERC in Orders No. 743 and 743-A. Those orders
emphasized that FERC’s concerns are with the initial phrase in the current NERC BES definition, which
provides that the “Bulk Electric System” is: As defined by the Regional Reliability Organization, the electrical
generation resources, transmission lines, interconnections with neighboring systems, and associated
equipment, generally operated at voltages of 100 kV or higher.In Order No. 743, FERC made clear that it
views the initial phrase ("As defined by the Regional Reliability Organization") as creating unreviewable
discretion for Regional Entities to define the BES in their region, and that this unreviewable discretion, rather

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Yes or No

Question 1 Comment
than lack of uniformity per se, is the problem Order No. 743 is designed to remedy. See, e.g., Order No. 743,
133 FERC ¶ 61,150 at P 16 (2010) (FERC believes the “best way to address these concerns is to eliminate
the Regional Entities’ discretion to define ‘bulk electric system’ without ERO or Commission review”; id. at 30
(same). In Order No. 743-A, FERC clarified that the primary aim of its rulemaking was to eliminate this
unreviewed regional discretion, and it was not, as FERC had originally proposed, to create a uniform national
definition that does not allow for any regional variation. Order No. 743-A, 134 FERC ¶ 61,210 at P 11 (“We
clarify that the specific issue the Commission directed the ERO to rectify is the discretion the Regional Entities
have under the current bulk electric system definition to define the parameters of the bulk electric system in
their regions without any oversight from the Commission or NERC.”); id. at P 39 (“The Commission’s
suggested solution simply would eliminate regional discretion that is not subject to review by [NERC] or the
Commission”).Accordingly, the SDT could achieve the primary aim of Order No. 743 by simply rewriting the
current definition to read:Unless a different definition has been developed by the Regional Reliability
Organization and approved by NERC and FERC, the Bulk Electric System is defined as the electrical
generation resources, transmission lines, interconnections with neighboring systems, and associated
equipment, generally operated at voltages of 100 kV or higher.If the SDT uses this suggested language as its
core definition, it will have addressed FERC’s primary concern with a minimum of disruption to the current
NERC system of definitions. The definition could then be further elaborated with the list of specific inclusions
and exclusions of Elements and systems (modified as discussed below), to provide more specific guidance to
the industry.
In this connection, we note that a 200 kV threshold would be more appropriate for WECC than a 100-kV
threshold. This is because generation in the West is generally located far from load, and power is generally
transmitted from these generation sources to distant load centers on extremely high-voltage lines, usually
operating in the range of 230-kV to 500-kV. Further, because loads are often dispersed across relatively
broad geographic areas, especially in the rural West, 115-kV lines are frequently used in local distribution
systems. See WECC Bulk Electric System Definition Task Force, Initial Proposal and Discussion, at pp. 1116 (posted May 15, 2009) (available at: http://www.wecc.biz/Standards/Development/BES/default.aspx)
(technical discussion showing that most transmission in the Western Interconnection operates at voltages
greater than 200 kV). Accordingly, a 200-kV threshold with an “inclusion” mechanism to sweep in the
relatively limited number of 115-kV lines in the West that perform a transmission function would be better
suited to the typical topology of systems in the West than a 100-kV threshold with exceptions for facilities that
operate as local distribution. That being said, we recognize that 200-kV may not be an appropriate threshold
for other parts of the country and we are willing to support the SDT’s approach as long as discretion is
preserved for the WECC to develop a definition better suited to the conditions in the Western Interconnection.
If the STD elects not to adopt one of the above suggestions, the core definition proposed on April 28 requires
clarification. Specifically, as drafted, the proposed definition is ambiguous in that it is not clear whether the
clause “unless such designation is modified by the list shown below” modifies only the preceding clause

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Organization

Yes or No

Question 1 Comment
(“Reactive Power resources connected at 100 kV or higher”) or the entire definition. To eliminate this
ambiguity, we suggest that the proposed definition be reordered to read as follows:Bulk Electric System
(BES): (A) Unless included or excluded in subpart B, the Bulk Electric System consists of: (1) all Transmission
Elements operated at 100 kV or higher; (2) Real Power resources identified in subpart B; and, (3) Reactive
Power resources connected at 100 kV or higher.(B) [the list of inclusions and exclusions, modified as
discussed in our responses to questions 2 through 9]. Rearranging the definition in this way should make
clear that the list of inclusions and exclusions that would be inserted as Subpart B modifies each provision of
Subpart A. Thus, for example, even if a Transmission Element is otherwise included by virtue of operating at
100 kV or higher, it is nonetheless excluded if specifically addressed in the list of exclusions that would be
incorporated as subpart B of the definition (if, for example, the Element qualifies as a Local Distribution
Network). The rearrangement of the language eliminates any argument that the phrase “unless such
designation is modified by the list shown below” does not modify “all Transmission Elements operated at 100
kV or higher” because of its placement at the end of the independent clause “Reactive Power resources
connected at 100 kV or higher.”
Snohomish supports the use of the phrase “Transmission Elements” as the starting point for the base
definition because both “Transmission” and “Elements” are already defined in the NERC Glossary of Terms
Used, and the use of the term “Transmission” makes clear that the Bulk Electric System includes only
Elements used in Transmission and therefore excludes Elements used in local distribution of electric power.
As discussed above, the definition must exclude facilities used in local distribution in order to comply with the
limits placed on NERC authority by Congress in Section 215 of the Federal Power Act (“FPA”), 16 U.S.C. §
824o.
For similar reasons, we believe the SDT has improved the proposed definition from its initial proposal by
eliminating the use of terms such as “Generation” that are not specifically defined in the NERC Glossary of
Terms and by eliminating terms such as “Facility” that include “Bulk Electric System” as part of their definition.
Eliminating the use of such terms helps sharpen the core definition. If a key term is undefined, incorporating it
into the definition only begs the question of how the incorporated term is defined. If a currently-defined term
uses the phrase “Bulk Electric System” as part of its definition, incorporating that term into the BES definition
creates a confusing circularity. We therefore support the SDT’s use of defined terms such as “Element,”
“Real Power,” and “Reactive Power.”

Response: The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power
resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.
The SDT elected to retain the 100 kV bright-line criteria. This is the bright line voltage level that is included in the existing approved definition of the Bulk Electric
System in the NERC Glossary of Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification was provided that would
lead the SDT to make a change. One goal of this project is to add clarity to the definition without significantly changing the population of BES elements.

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Organization

Yes or No

Question 1 Comment

See the responses to comments regarding the Regulatory Requirements in Question 12 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
FHEC

Yes

Generally agree, but think E1 should be changed slightly to:From: E1 - Any radial system which is described
as connected from a single Transmission source originating with an automatic interruption device and: To:E1
- Any radial system which is described as connected from a Transmission source originating with a single
automatic interruption device and:

Response: See the responses to comments as well as a discussion of the latest revisions regarding the Radial Exclusion in Question 7 below.
Vermont Transco

Yes

It appears that the SDT has made progress in addressing comments made to date. Concerned that facilities
below 100 kV will fall into the current definition of BES. If changes in the wording better identified key areas
the new definition would be easier to interpret, apply, and it would better align with the concerns of the
members

Response: The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power
resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.
The SDT elected to retain the 100 kV bright-line criteria. One goal of this project is to add clarity to the definition without significantly changing the population of
BES elements.
See the responses to comments regarding Local Distribution Facilities in Question 11 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
South Texas Electric
Cooperative, Inc.

Yes

There is general confusion as to whether or not the “BES” is synonymous with the “BPS”. If this is so, then it
should be expressly stated as such. If not, clarification should be provided to industry.

Response: The BES and BPS are not synonymous. The BES is a subset of the BPS. This has been stated in numerous documents, including Orders No. 693
(P76) and 743 (P36). No change made.
FortisBC

August 19, 2011

Yes

We agree with the concept of a bright-line definition and commend the SDT for developing a concept of
explicit inclusions and exclusions as part of the definition. This will reduce the number of exception

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Organization

Yes or No

Question 1 Comment
applications for some of the BES elements. However, the inclusion and exclusion requirements are extremely
restrictive. For example, radial characteristics should not be limited by the amount of installed generation or
single transmission source and/or require an interrupting device. Instead we believe that one or more
transmission sources could feed the radial load to provide redundancy as long as there is adequate protection
and isolation for improved customer-supply continuity and reliability. This should be considered radial as long
as the loss of any transmission source does not affect, and is not necessary for, the operation of the
interconnected transmission network.
Further, it is imperative to understand that the NERC’s revised definition will have a direct impact on entities
across North America and will conflict with regulatory requirements, Codes, and Licenses. FERC in its Order
743 and 743A has directed NERC to address these concerns.We suggest the SDT and RoP teams should:
o Carefully craft the exception criteria and procedure to be flexible and technically sound, to allow entities to
adequately present their case to the ERO for inclusions or exclusions outside of the definition.
o Include provisions in both the NERC exception criteria and exception process for federal, state and
provincial jurisdictions. These provisions should provide clear guidance so that, if and when there are
deviations from the exception criteria, they are properly identified with technical and regulatory justifications
ensuring there is no adverse impact on the interconnected transmission network. This burden of proof should
be left to the entity seeking exception because it may be difficult if not impossible to define the exception
criteria. Further, if such an explicit criteria could be defined, it will in fact become another bright-line BES.

Response: See the responses to comments as well as a discussion of the latest revisions regarding the Radial Exclusion in Question 7 and the responses to
comments regarding Regulatory Requirements in Question 12 below.
Puget Sound Energy

Yes

E3. Local distribution networks (LDNs): In this exclsion criteria, it was unclear about the size of the LDN that
could be excluded from BES. There was a limit on connected generation but not connected load. If there is
any mention of total aggregate load served by this LDN then that would clarify the definition better. We would
like to suggest using a limit say lesser than or equal to 300 MW of total aggregate load served by LDN could
be excluded from BES definition in addition to all the 5 (a-e) characteristics mentioned.

Response: After extensive communication, the SDT has made changes to the draft Local Network definition to provide additional clarity. The draft definition now
includes an upper voltage limit of 300 kV. The draft definition does not contain a limit on connected Load as no technical basis has yet been provided regarding
this issue that would lead the SDT to make this change.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to

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Organization

Yes or No

Question 1 Comment

accommodate bulk power transfer across the interconnected system.
Manitoba Hydro

Yes

We recommend that the definition be prefaced with the statement ‘except where provided otherwise by
applicable law...’

Response: The SDT has made revisions to the draft definition to clarify that the BES does not include facilities used in the local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
City of Anaheim

Yes

I1: Change the "and" to an "or" at the end of the sentence, i.e. Exclusions E1 or E3.
E3 (b): Use the same language in E1 (b), i.e. Only including generation resources not identified in Inclusions
I2, I3, I4, and I5.

Response: The SDT has accepted your proposed change for Inclusion I1.
The SDT has adopted the suggestion. Note that former Inclusions I2 and I3 have been combined into a new Inclusion I2.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
AltaLink

Yes

We agree with the concept of a bright-line definition and commend the SDT for developing a concept of
explicit inclusions and exclusions as part of the definition. This will reduce the number of exception
applications for some of the BES elements. However, the inclusion and exclusion requirements are extremely
restrictive. For example, radial characteristics should not be limited by the amount of installed generation or
single transmission source and/or require an interrupting device. Instead we believe that one or more
transmission sources could feed the radial load to provide redundancy as long as there is adequate protection
and isolation for improved customer-supply continuity and reliability. This should be considered radial as long
as the loss of any transmission source does not affect, and is not necessary for, the operation of the
interconnected transmission network.
We suggest the SDT and RoP teams should:
o Carefully craft the exception criteria and procedure to be flexible and technically sound, to allow entities to
adequately present their case to the ERO for inclusions or exclusions outside of the definition.
o Include provisions in both the NERC exception criteria and exception process for federal, state and

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Organization

Yes or No

Question 1 Comment
provincial jurisdictions. These provisions should provide clear guidance so that, if and when there are
deviations from the exception criteria, they are properly identified with technical and regulatory justifications
ensuring there is no adverse impact on the interconnected transmission network. This burden of proof should
be left to the entity seeking exception because it may be difficult if not impossible to define the exception
criteria. Further, if such an explicit criteria could be defined, it will in fact become another bright-line BES.

Response: See the responses to comments as well as a discussion of the latest revisions regarding the Radial Exclusion in Question 7.
The SDT appreciates your comments and suggestions for the Rules of Procedure exception process and will consider them in its deliberations.
Modern Electric Water Company

Yes

Taken by itself, the proposed core definition directly accomplishes the following: i) it re-affirms the 100kV
bright-line and ii) it removes Regional discretion to define the BES. However, the language continues to inject
ambiguity in that it introduces the use of the separately-defined capitalized term “Transmission”. In NERC’s
Glossary of Terms (May 24, 2011), “Transmission” is defined in terms of function rather than voltage. Strictly
interpreted, the core definition implies that only Elements used for the transfer of energy to points where it
transformed for delivery to customers as well as certain resources are considered to be included in the BES.
Under this viewpoint, there exists a two-stage qualifier for non-resource Elements - namely that it must first be
used for Transmission and not for “Distribution”, and secondly, that it be operated above 100kV. Rather, the
BES cannot contain Elements used for “Distribution” (a term not explicitly defined, but extrapolated from other
NERC glossary terms to mean the “wires” between the transmission system and the end-use customer, and
NOT defined by voltage). If this is the case, the SDT has established that an Element’s function is equally
important to its voltage, and has simultaneously excluded all Transmission Elements under 100kV - even if
used for bulk transfers. While the Exclusions detail characteristics of specific distribution-like Elements, we
suggest that the core BES definition contain language explicitly excluding Distribution (there are Elements
that are neither qualifying radials as defined in E1 nor local distribution networks as defined in E3).

Michgan Public Power Agency

Yes

My concern centers on the intent of FERC Order 743 language “we certify that this Final Rule will not have a
significant economic impact on a substantial number of small entities” still falls short from being met by this
definition change. This is a good start but additional work remains to be done. As pointed out in FERC Order
743A the 100 KV bright-line was not required but NERC can provide an alternative which can be supported
technically. Also I have concerns for the FERC Order 743A language “facilities used in the local distribution
of energy should be excluded from the revised bulk electric system definition” also needs additional work
remains to be done.

Response: The SDT has revised the bright-line core definition to clarify that all Transmission Elements at 100 kV or higher and Real Power and Reactive Power
resources connected at 100 kV or higher are to be included in the BES unless there is a modification for a particular Element in the Inclusion or Exclusion lists.

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Organization

Yes or No

Question 1 Comment

The SDT elected to retain the 100 kV bright-line criteria. One goal of this project is to add clarity to the definition without significantly changing the population of
BES elements.
See the responses to comments regarding Local Distribution Facilities in Question 11 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
California Public Utilities
Commission

Yes

The CPUC supports the changes, especially the exclusions and the flexibility given to facilities to prove that
they are not part of the BES. However, the CPUC is concerned about the automatic imposition of
deterministic standards that are arbitrary rather than technically-based:
(1) the 100kV “bright line” test for transmission facilities, and the
(2) 20 MVA threshold for generating units.In general, the current BES definition is largely deterministic rather
than based on economics or probabilities.
An arbitrary number such as a “bright line” test should not be the singular gauge for inclusion in the BES. A
robust BES definition should consider the actual impact on the system and the cost. The courts have spoken
on the issue, Illinois Commerce Commission v. Federal Energy Regulatory Commission, 576 F.3d 476, and
instructed FERC to approve projects, “pricing scheme”, only if the benefits outweigh the cost.
Further, the 20 MVA threshold for generating facilities is coincident with the NERC threshold for registered
entities. While a logical threshold to require generators to register with NERC, the required reliability
assessments, and subsequent reliability upgrades may be prohibitively expensive for small generating units.

Response: The SDT elected to retain the 100 kV bright-line criteria. One goal of this project is to add clarity to the definition without significantly changing the
population of BES elements. This is the bright-line voltage level that is included in the existing approved definition of the Bulk Electric System in the NERC
Glossary of Terms. While a number of stakeholders suggested alternate voltage levels, no technical justification was provided that would lead the SDT to make a
change.
See the responses to comments as well as a discussion of the latest revisions regarding Generation Inclusions in Questions 3 and 4 below.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Sierra Pacific Power Co d/b/a

August 19, 2011

Yes

The revised core definition serves to address the directives of the Commission Order in 743 and 743A,

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Organization

Yes or No

NV Energy

particularly the elimination of regional discretion, and it also eliminates the ambiguity of the word “generally”.

City of St. George

Yes

Imperial Irrigation District

Yes

SERC Planning Standards
Subcommittee

Yes

ACES Power Participating
Members

Yes

Utility System Efficiencies, Inc.

Yes

Tennessee Valley Authority

Yes

Arizona Public Service Company

Yes

Western Electricity Coordinating
Council

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

Luminant Energy

Yes

Central Maine Power Company

Yes

New York State Electric & Gas
and Rochester Gas & Electric

Yes

US Bureau of Reclamation

Yes

Duke Energy

Yes

August 19, 2011

Question 1 Comment

The definition is okay as long as proper inclusions and exclusions are included in the definition.

No comments

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Organization

Yes or No

Alberta Electric System Operator

Yes

South Carolina Electric and Gas

Yes

MidAmerican Energy Company

Yes

Florida Keys Electric
Cooperative

Yes

East Kentucky Power
Cooperative, Inc.

Yes

Farmington Electric Utility
System

Yes

Colorado Springs Utilities

Yes

Sacramento Municipal Utility
District (SMUD)

Yes

GTC

Yes

Idaho Power

Yes

Long Island Power Authority

Yes

PJM

Yes

Oncor Electric Delivery
Company LLC

Yes

Xcel Energy

Yes

Golden Spread Electric

Yes

August 19, 2011

Question 1 Comment

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Organization

Yes or No

Question 1 Comment

Cooperative, Inc.
Exelon

Yes

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities
Group and Constellation Control
and Dispatch

Yes

No comment.

Response: Thank you for your support. Many stakeholders suggested revisions to the definition – and the drafting team made modifications that were
responsive to theses suggestions. Please see the revised definition.

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

2. Q2. The SDT has added specific inclusions to the core definition in response to industry comments. Do you
agree with Inclusion I1? If you do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: The SDT has made changes to Inclusion I1 of the BES definition based upon comments received from the
industry. These changes in the revised definition include removing the Generator Step-Up and Phase Angle Regulating transformer language,
changing the wording from “windings” to “terminals”, and adding the terms “primary” and “secondary”.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary
windingsterminals of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.

Organization
Tri-State Generation and
Transmission Association, Inc.

Yes or No

Question 2 Comment

No

We recommend changing I1 to the following: “Only transformers, including phase angle regulators, with two or
more windings of 100 kV or higher that are connected through automatic fault-interrupting devices, unless
excluded under Exclusions E1 and E3.” “Only” is required to prevent a regional interpretation that includes
distribution transformers since they are never specifically excluded.
The phrase regarding GSUs is removed since they are covered in I2 and I3.

Response: The SDT has addressed the issue of transformers serving local networks in the revised Exclusion E3 for the Local Network portion of the revised
version of the definition. A transformer serving a local network could be considered an “Element” that is part of the local network and would be excluded if so
justified by the characteristics of the exclusion. No change made.
The SDT agrees with your comment regarding GSUs and has made the appropriate revision in the revised version of the definition.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
NERC Staff Technical Review

No

Inclusion I1 is acceptable in general; however, there are two items that should be modified.>>>>>>>>>>
The reference to “two windings” is technically incorrect because it would exclude autotransformers with two
terminals at 100 kV or higher since the primary and secondary terminals are connected to the same winding.
It would be better to replace the phrase “with two windings of 100 kV or higher” with the phrase “with two or
more terminals connected at 100 kV or higher.”>>>>>>>>>>
The phrase “other than Generator Step-up (GSU) transformer” is unnecessary. The qualifier “with two or
more terminals connected at 100 kV or higher” already will exclude GSU transformers. In unusual cases in
which a generator is connected to the system through a transformer that does have two terminals connected
at 100 kV or higher the transformer should be included by Inclusion I1.

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Organization

Yes or No

Question 2 Comment

Response: The SDT has made appropriate changes in the revised version of the definition regarding both comments.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
NERC Transmission Issues
Subcommittee (TIS)

No

It is not necessary to exclude generator step-up transformers because a GSU should be considered to be part
of the generating Unit. >>>>>>>>>>
The reference to two windings is technically incorrect because it would exclude autotransformers which
technically only have one winding. It would be better to say that both the high-side and the low side of the
transformer connected at 100 kV or higher. >>>>>>>>>>
“I1 - Transformers, other than generator step-up (GSU) transformers, including phase angle regulators, with
two windings both the high-side and the low side of the transformer connected at 100 kV or higher unless
excluded under Exclusions E1 and E3.”

Response: The SDT has deleted the GSU language in the revised Inclusion I1.
The SDT has changed the wording from “windings” to “terminals” in the revised version of the definition.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Dominion

No

While Dominion appreciates the SDT’s attempt to respond to initial comments, unfortunately the response
does not squarely address Dominion’s concerns. Rather, the SDT proposes that all transformers, whether for
transmission or generation should be included. The SDT’s response to SERC also seems to indicate that the
facility associated with generators should be included in the BES. In order to provide clarity Dominion
restates its comment. Dominion’s position is that all transformers with two windings at 100 kV or higher
should be included in the BES. Dominion does not agree that a transformer with two windings at 100 kV or
higher should be excluded merely because it is a generator step up (GSU). And, while Dominion does not
agree that a generation resource, Element or Facility should automatically be classified as part of the BES, if
the SDT decides to do so, then it is Dominion’s position that the GSU should also be included in the BES. It
doesn’t seem to make sense to include the generator itself, but exclude an associated element that is
operated at 100 kV or above. If the SDT’s intent was to ‘carve out’ GSUs in Inclusion -I1, but to include GSUs
in Inclusion I2 and 3, then Dominion suggests revising the phrase “....including the generator terminals
through the GSU....” to read “....including the generator terminals and the GSU.”

Response: The SDT agrees with the inclusion of all generation and transmission transformers and has attempted to provide clarity in the revised version of the

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Organization

Yes or No

Question 2 Comment

definition.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary
windingsterminals of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Overton Power District No. 5

No

clarification is needed to identify which transformers to include in the BES

Tennessee Valley Authority

No

We suggest I1 to read, “Transformers, other than generator step-up (GSU) transformers, including phase
angle regulators, having two windings of 100 kV or higher, unless excluded under Exclusions E1 or E3.
Transformers having only one winding of 100 kV or higher are excluded.”

Central Maine Power Company

No

By definition above, a transformer with a 100 kV winding is already an “element operated at 100 kV or above.”
This inclusion is actually intended to exclude transformers with only one winding operated at 100 kV or higher
voltage. Therefore, Inclusion I1 should be deleted and a new Exclusion should be made: “Transformers with
only one winding of 100 kV or higher, including phase angle regulators, unless included under Inclusions I2,
I3, or I5.”

Hydro-Quebec TransEnergie

No

Since transformers are already part of "all transmission Elements operated at 100 kV and above" in the
definition, and since inclusions I2 to I5 are commonly related to only generation, I1 should be removed and
replace instead by the following Exclusion: Ex "Transformers not used as Generator Step-Up (GSU)
transformers that have primary or secondary winding at less than 100 kV."

Consumers Energy Company

No

The facilities currently listed in Inclusion I1 are already arguably included in the core definition. Inclusion I1
should be reclassified as an Exclusion to cover transformers that do not meet the criteria in Inclusion I1 such
as those transformers with a single winding of 100kV or higher. Following is our proposed language for the
exclusion we are proposing. Transformers, other than Generator Step-up (GSU) transformers, including
Phase Angle Regulators, that have less than two windings of 100 kV or higher.

Southern California Edison
Company

No

Identifying specific equipment within the “Inclusions” or “Exclusions” component is too prescriptive, and
itemizing them in this fashion misses the intent of this endeavor which should be to ultimately ensure the risks
to region wide reliability are captured.Therefore, it is SCE’s position that the proposed BES Definition should
not single out specific pieces of equipment, and that they should be included or excluded based on the criteria
of the definition. To do otherwise could: (i) generate confusion due the many types and variations of
equipment, and what should/should not be included In the BES; and(ii) include radial or distribution systems
into scope that might not otherwise have been considered, and which pose no regional reliability risk. If the
BES Definition continues to reference transformer types, it should clarify what specific attributes qualify for
inclusion. This might best reside in companion documentation that would accompany the definition to ensure

New York State Electric & Gas
and Rochester Gas & Electric

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Organization

Yes or No

Question 2 Comment
consistency in application.

Clark Public Utilities

No

Transformers should only be part of the Bulk Electric System if they are transforming voltage from one BES
element to another BES element. The current inclusion language would apply to all transformers with two
windings operated at greater the 100 kV subject to the E1 and E3 exclusions. There is no indicated exclusion
referring to the exception process. If a facility is excluded from the BES by the exception process, connected
transformers should also be excluded. Clark believes if the inclusion language was changed slightly, the
exclusion references to E1 and E3 would not be necessary. Without this change, it appears that a transformer
with two winding connected to greater than 100 kV would be a BES asset even if both of the facilities these
windings were connected to had been excluded (E1 or E3) or excepted (BES Exception Process). I1 should
be rewritten to state: Transformers, other than generator step-up (GSU) transformers, including phase angle
regulators, with two windings of 100 kV or higher connected to Transmission Elements determined to be part
of the Bulk Electric System.

Independent Electricity System
Operator

No

We agree with the concept of Inclusion I1. We suggest that since transformers with at least two windings
greater than 100 kV are already part of "all transmission Elements operated at 100 kV and above" in the
definition, and since inclusions I2 to I5 are commonly related to only generation, Inclusion 1 should be
removed and replace by the following Exclusion: E(x)”Transformers that have a primary or secondary winding
at less than 100 kV except for those included by I2 and I3”

BPA

No

Transformers, other than generator step-up (GSU) transformers, including phase angle regulators, with two
windings of 100 kV or higher unless excluded under Exclusions E1 and E3.

American Municipal Power and
Members

Yes

We support I2, but propose clarifying edits. To minimize possible confusion as to the category of
transformers being addressed in I1, and the sufficiency of a single applicable Exclusion, we suggest the
following rewording: “Transformers, including phase angle regulators, and not including generator step-up
(GSU) transformers, with two windings of 100 kV or higher unless excluded under Exclusion E1 or E3.”

Transmission Access Policy
Study Group

Yes

To minimize possible confusion as to the category of transformers being addressed in I1, and the sufficiency
of a single applicable Exclusion, TAPS suggests the following rewording: “Transformers, including phase
angle regulators, and not including generator step-up (GSU) transformers, with two windings of 100 kV or
higher unless excluded under Exclusion E1 or E3.”

Northern California Power
Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.

Florida Municipal Power Agency

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Organization

Yes or No

Question 2 Comment

Illinois Municipal Electric Agency

Yes

With the following clarifying edits. “Transformers, including phase angle regulators, and not including
generator step-up (GSU) transformers, with two windings of 100 kV or higher unless excluded under
Exclusion E1 or E3.”

Idaho Power

Yes

I generally agree but the definition accidently excludes autotransformers. It should be restated as
transformers with two terminal at or above 100 kV. Also, there should be clarification about any tertiary
windings that a transformer might have. I would assume that the tertiary winding and any real or reactive load
or generation connected to it to be excluded as the tertiary winding are typically of distribution class voltage.
Finally, there is no need to exclude GSUs in this definition because they will be excluded unless the two
terminals are at 100 kV or above. Additionally, the GSUs will be covered by other inclusion statements related
to generators.

Xcel Energy

Yes

The drafting team should consider how components such as autotransformers would be considered under
this aspect, and if additional language needs to be added to clearly include certain autotransformers.

Response: The SDT has revised Inclusion I1 to provide more clarity on specifically which transformers are included in the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Western Montana Electric
Generating and Transmission
Cooperative

No

In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped down
from transmission voltages to distribution voltages. We believe, however, that the SDT should undertake the
effort to more clearly define the point where the BES ends and non-BES systems begin. In this regard, we
note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted considerable effort
to this question and has developed one-line diagrams noting the BES demarcation point for a number of
different kinds of Elements that are common in the Western Interconnection. Using this work as a starting
point, the SDT should be able to provide much useful guidance to the industry with relatively little additional
effort.
Also, the reference to “two windings of 100 kV or higher” may create some confusion because many threephase transformer banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We
suggest clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”
We again urge the SDT to consider further delineation of points of demarcation similar to WECC BESDTF

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Organization

Yes or No

Question 2 Comment
Proposal 6.

Sierra Pacific Power Co d/b/a NV
Energy

No

We agree with the concept; however there are two issues that must be resolved. First, the “two windings”
language should be changed to “two terminals”, as in the case of an auto-transformer, there is technically only
one winding, and it would fail to be included in this inclusion designation as written.
Second, a literal read could have an unintended interpretation that transformers with fewer than 2 windings at
100kV might still be included through the core definition. The SDT should consider whether this I1 inclusion
item would be better applied in the converse as an exclusion designation.

Chelan PUD – CHPD

No

Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc.
Cowlitz County PUD

In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped down
from transmission voltages to distribution voltages. We believe, however, that the SDT should undertake the
effort to more clearly define the point where the BES ends and non-BES systems begin. In this regard, we
note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted considerable effort
to this question and has developed one-line diagrams noting the BES demarcation point for a number of
different kinds of Elements that are common in the Western Interconnection. Using this work as a starting
point, the SDT should be able to provide much useful guidance to the industry with relatively little additional
effort.
Also, the reference to “two windings of 100 kV or higher” may create some confusion because many threephase transformer banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We
suggest clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”We again
urge the SDT to consider further delineation of points of demarcation similar to WECC BESDTF Proposal 6.

Public Utility District No. 1 of
Snohomish County, Washington
Clallam County PUD No.1

August 19, 2011

Yes

In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped down
from transmission voltages to distribution voltages. We believe, however, that the SDT should undertake the
effort to more clearly define the point where the BES ends and non-BES systems begin. In this regard, we
note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted considerable effort
to this question and has developed one-line diagrams denoting the BES demarcation point for a number of
different kinds of Elements that are common in the Western Interconnection. See WECC BES Definition Task
Force Proposal 6, Appendix C (available at: http://www.wecc.biz/Standards/Development/BES/default.aspx).
Similarly, the FRCC’s BES Definition Clarification Project has devoted considerable effort to developing oneline diagrams of transmission and distribution Elements, and identifying the point of demarcation between
BES and non-BES Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B
(available at: https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT

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Organization

Yes or No

Question 2 Comment
should be able to provide much useful guidance to the industry with relatively little additional effort.
Also, the reference to “two windings of 100 kV or higher” may create some confusion because many threephase transformer banks have 6 or 9 windings, depending on whether the transformer has a tertiary. We
suggest clarifying this provision by changing the clause referencing two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”

Response: The SDT has changed the wording from “windings” to “terminals” in the revised version of the definition. The SDT has revised Inclusion I1 to
provide more clarity on specifically which transformers are included in the BES. The SDT will consider the suggestions to incorporate the WECC work into its
effort.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
PacifiCorp

No

Transformers with two or more windings greater than 100 kV exclusively serving local distribution networks
should be excluded from the BES.

Response: The SDT has addressed the issue of transformers serving local networks in the revised Exclusion E3 for the local network portion of the revised
version of the definition. A transformer serving a Local Network could be considered an “Element” that is part of the local network and would be excluded if so
justified by the characteristics of the exclusion. No change made.
Electric Reliability Council of
Texas, Inc.

No

ERCOT ISO agrees that such equipment should be considered for inclusion, but suggests that these issues
be addressed relative to the criteria for evaluation in the exception process. In other words, this inclusion
doesn’t need to be explicitly identified. It would simply be included under the general 100 kV threshold, and to
the extent an owner believed the characteristics of its equipment don’t warrant inclusion, it would seek an
exception.

Response: The SDT believes the BES definition should be “bright-line” criteria and be able to include a very high percentage of the facilities by inspection. The
exception criteria and process is meant to handle very few facilities. The BES definition and exemption process have been developed under this guiding concept.
No change made.
Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

No

Inclusion I1 would be unlawful to the extent that it would include the transformers of retail customers that have
self-provided “hard-tapped” facilities behind the retail delivery point. (For the purposes of these Comments,
“hard-tapped” means connected without an automatic fault-interrupting device).

Response: The SDT believes that retail customer transformers could be excluded based upon Exclusions E1 or E3. No change made.

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Organization
Kootenai Electric Cooperative

Yes or No

Question 2 Comment

No

In concept, Kootenai supports the SDT’s attempt to provide a clear demarcation between the BES and nonBES elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped
down from transmission voltages to distribution voltages. We believe, however, that the SDT should
undertake the effort to more clearly define the point where the BES ends and non-BES systems begin. In this
regard, we note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted
considerable effort to this question and has developed one-line diagrams noting the BES demarcation point
for a number of different kinds of Elements that are common in the Western Interconnection. Using this work
as a starting point, the SDT should be able to provide much useful guidance to the industry with relatively little
additional effort. We again urge the SDT to consider further delineation of points of demarcation similar to
WECC BESDTF Proposal 6.

Yes

We support the SDT’s attempt to provide a clear demarcation between the BES and non-BES elements.
Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped down from
transmission voltages to distribution voltages. We believe, however, that the SDT should undertake the effort
to more clearly define the point where the BES ends and non-BES systems begin. We note that the WECC
Bulk Electric System Definition Task Force (“BESDTF”) has devoted considerable effort to this question and
has developed one-line diagrams denoting the BES demarcation point for a number of different kinds of
Elements that are common in the Western Interconnection. See WECC BES Definition Task Force Proposal
6, Appendix C (available at: http://www.wecc.biz/Standards/Development/BES/default.aspx). Similarly, the
FRCC’s BES Definition Clarification Project has devoted considerable effort to developing one-line diagrams
of transmission and distribution Elements, and identifying the point of demarcation between BES and nonBES Elements. See FRCC BES Definition Clarification Project Version 4, Appendices A & B (available at:
https://www.frcc.com/Standards/BESDef.aspx). Using this work as a starting point, the SDT should be able to
provide much useful guidance to the industry with relatively little additional effort.

Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative

Blachly Lane Electric Cooperative
PUD No. 2 of Grant County,
Washington
Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc.
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric

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Organization

Yes or No

Question 2 Comment

No

In concept, we support the SDT’s attempt to provide a clear demarcation between the BES and non-BES
elements. Inclusion I-1 is helpful because it at least implies that the BES ends where power is stepped down
from transmission voltages to distribution voltages. We believe, however, that the SDT should undertake the
effort to more clearly define the point where the BES ends and non-BES systems begin. In this regard, we
note that the WECC Bulk Electric System Definition Task Force (“BESDTF”) has devoted considerable effort
to this question and has developed one-line diagrams noting the BES demarcation point for a number of
different kinds of Elements that are common in the Western Interconnection. Using this work as a starting
point, the SDT should be able to provide much useful guidance to the industry with relatively little additional
effort. Also, the reference to “two windings of 100 kV or higher” may create some confusion because many
three-phase transformer banks have 6 or 9 windings, depending on whether the transformer has a tertiary.
We suggest clarifying this provision by changing the clause reference two windings to read: “the two highest
voltage transformer windings of 100 kV per phase that are connected to the Bulk Electric System.”We again
urge the SDT to consider further delineation of points of demarcation similar to WECC BESDTF Proposal 6.

Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative

Northern Wasco County PUD

Response: The SDT will consider the suggestions to incorporate the WECC work and FRCC work into its effort.
Public Utilities Commission of
Ohio

No

FERC jurisdiction is limited by the Federal Power Act, Section 215. To make a bright line designation as the
starting point, without a demonstration that ALL facilities at 100 kV and greater affect the reliability of the bulk
power system is a step beyond FERC jurisdictional boundaries. The Federal Power Act explicitly excludes
facilities used in local distribution from the bulk power system. NERC should give serious consideration to
other (non bright-line) approaches to ensure bulk system reliability.

Response: The task of the SDT is to put forward a 100 kV bright-line for the BES definition. The SDT has modified the definition and distribution facilities are
now specifically excluded from the BES. However, the SDT acknowledges that there may still be regulatory conflicts as many of the commenters have voiced. The
definition is neither intended to nor can it supersede any regulatory orders and/or rulings by relevant Federal, State, or Provincial Authorities. Although the SDT
can not resolve all regulatory conflicts, it believes that a) proposed revisions to the definition should address many of these concerns; and b) remaining issues
may be effectively addressed by the Rules of Procedure exception procedure currently under development.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and

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Organization

Yes or No

Question 2 Comment

Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
The Dow Chemical Company

No

An additional exclusion for industrial distribution facilities needs to be added for the reasons expressed in
Dow's comments on Exclusion E3. Dow's manufacturing sites have transformers, other than generator step
up transformers, that have two windings of 100 kV or higher and that are between on-site generation and
individual manufacturing plants at such sites. Such transformers should be excluded, because they are part of
electricity distribution facilities. However, such transformers do not fall within proposed Exclusion E1 or E3.

Response: If a manufacturing site’s facilities cannot meet the exclusion criteria, then those facilities must be part of the BES. There may be instances where
customer facilities are part of the BES. See response to Question 9. No change made.
Central Lincoln

No

We support the SDT’s intent, but it is unclear from the language how single winding transformers
(autotransformers) are handled. We suggest replacing “two windings...” with “two sets of terminals....”
Please also indicate how transformers with only one set of terminals above 100 kV are treated, since we don’t
believe the flowchart at http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly
expresses the SDT’s intent to classify these transformers as non-BES.

United Illuminating

No

Inclusion I1 is an attempt to limit the scope of the core definition to only those transformers with a high and
low side connection at or above 100 kV. However it is not clear that a transformer connected solely on the
high side at 100 kV, that is a distribution transformer, is not included in the BES by the definition. This is
because the core definition includes all transmission elements connected at 100 kV, this would include the
distribution transformer. Then Inclusion I1 does not eliminate the distribution transformer explicitly. It is only
implied that the core definition applies only to those transformers with a high and low side connection at or
above 100 kV. UI would prefer a more explicit description. Such as: I1- Only those Transformers, including
phase angle regulators, with two windings of 100 kV or higher unless excluded under Exclusions E1 and E3
are included in the definition of BES. Generator Step Up Transformers are included based on the generator. A
similar comment can be made for the other inclusions. An alternative solution is to change word Inclusions to
a sentence that explicitly states: for the category of element below only include the type of equipment
specified.
Also The use of the descriptor two windings implies auto transformers with one winding is excluded. UI
understands that is not the intent of the team.

Response: The SDT has changed the wording from “windings” to “terminals” in the revised version of the definition. The SDT has revised Inclusion I1 to
provide more clarity on specifically which transformers are included in the BES.

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Organization

Yes or No

Question 2 Comment

Transformers with only one set of terminals operated above 100 kV would not be included in the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Oncor Electric Delivery Company
LLC

No

The reference to two windings is technically incorrect because it would exclude autotransformers which
technically only have one winding. Recommend rephrasing this to say that both the high-side and the low
side of the transformer connected at 100 kV or higher.I1 Suggested Language:”I1 - Transformers, including
phase angle regulators, with both the high-side and the low side of the transformer connected at 100 kV or
higher unless excluded under Exclusions E1 and E3.”

Manitoba Hydro

No

Inclusion I1 requires clarification. The intention of I1 is to include transformers that have both their primary
and secondary windings operated at 100kV and the wording in I1 should reflect this. Requiring that only ‘two
windings’ must be connected at 100kV or greater for inclusion is not sufficient in the case of 3 separate single
phase banks connected to form a delta-wye connection for example. As currently written, even if only the
primary windings of this bank were connected at greater than 100kV, this transformer would be included in
the BES regardless of the secondary voltage.
-Suggested wording: “Transformers, other than Generator Step-up (GSU) transformers, including Phase
Angle Regulators, that are connected at 100kV or above on their primary and secondary windings unless
excluded under Exclusions E1 and E3.OR”Transformers, other than generator step-up (GSU) transformers,
including phase angle regulators, with two windings of 100 kV or higher in the same phase unless excluded
under Exclusions E1 and E3.”

Tacoma Power

Western Electricity Coordinating
Council

Tacoma Power agrees with Inclusion I1. However, we believe the reference to ‘two windings’ is ambiguous
and propose changing it to read,”Transformers, other than Generator Step-up (GSU) transformers, including
Phase Angle Regulators, with two or more connections to Elements at 100 kV or higher, unless excluded
under Exclusions E1 and E3.”
Yes

WECC agrees in concept and understands that the intent of the phrase “other than GSU transformers” was
used to prevent duplication or conflict with I2. However, it has the unintended consequence of creating the
appearance that GSU transformers are not included in the definition, which is more of a conflict. By removing
this phrase, such transformers would be clearly included because, if both terminals are connected at greater
than 100 kV, it will also be true that the high side is connected at greater than 100 kV, per I2. WECC suggests
removing this phrase.
Also, the final statement more appropriately should be “...unless excluded under Exclusions E1 or E3.”

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Organization

Yes or No

Question 2 Comment
Finally, the term “two windings” may be technically incorrect because some transformers may only have one
winding. This wording would exclude single-winding transformers at or above 100 kV. One option may be to
change the language to “two terminals” instead of “two windings.” It may also be useful to clarify that
transformers with one terminal above and one terminal below 100 kV should be excluded.

Portland General Electric
Company

Yes

The reference to “two windings” will cause confusion. Presumably theStandard Drafting Team means two
three-phase windings, which would mean that boththe high sides and the low sides of a typical transformer
bank would have to beoperating at 100kV and above in order to be part of the BES. In other words,
a230kV/57kV transformer would not be included, despite the fact that all three windingsthat make up the high
side are individually rated at over 100kV. The inclusion needs tomake clear that it’s talking about two or more
sets of windings, each set consisting ofthree phases.

Sacramento Municipal Utility
District (SMUD)

Yes

Sacramento Municipal Utility District (SMUD) agrees with the concept of Inclusion 1. However, to ensure a
clarity of the “Bright-Line” criteria, two items for the Drafting Team (DT) to consider are: 1) removal of the
phrase other than GSU as it may lead to confusion. The GSUs typically have one winding below 100 kV that
disqualify their inclusion.
2) Reference to the transformer terminals each above 100 kV would reduce confusion for single winding
transformers and multiple winding transformers.

Long Island Power Authority

Yes

For clarification it is recommended that “windings” be replaced with “connection points”.

Modern Electric Water Company

Yes

The use of “terminals” rather than “windings” might be more clear.

Response: The SDT has changed the wording from “windings” to “terminals” in the revised version of the definition. The SDT has revised Inclusion I1 to
provide more clarity on specifically which transformers are included in the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Consolidated Edison Co. of NY,
Inc.

No

Recommended changes to the wording used in Inclusion I#1, et al:Formatting - When referring to an Inclusion
(or Exclusion), the SDT should use a number/pound sign (“#”) between the “I” and number to avoid confusing
“I” with the numerical value “1.”

Response: The comment isn’t related to the question and will be considered by the technical writers when the final draft is written. No change made.

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Organization

Yes or No

ATCO Electric

Question 2 Comment
While we agree generally with the inclusion, we have some questions based on specific examples:
1. A load substation has two 144/25kV transformers that connects to two separate 144kV transmission lines
(i.e. two separate 144kV buses). However, the two transformers joins on one 25kV bus. Should these two
144/25kV transformers be part of BES?
2. A protection relay is on 72kV side of a 144/72 tie transformer and its purpose is to remove 72kV weak
source (i.e. trip 72kV breakers) during 144kV bus fault. Should this protective relay be included in BES?
3. According to Inclusion I1, a 144/25kV transformer is not a BES element. The transformer's 144kV side has
a Motor Operated Disconnecting Switch (MOD), and this MOD connects to one or two 144kV line breakers.
The transformer's protections trip the 144kV line breakers. Should the transformer protection systems be part
of BES?

Response: 1. The two transformers cited in the comment would not be part of the BES based upon Inclusion I1 of the definition.
2. This relay cited in the comment would not be part of the BES because it trips a less than 100 kV interrupting device.
3. The substation configuration would need to be reviewed before a determination could be made on whether the protection system cited in the comment is part
of the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
MRO's NERC Standards Review
Forum

Yes

Please clarify that an exclusion would be a tertiary winding for example an auto transformer.

Response: The SDT has revised Inclusion I1 to provide more clarity on specifically which transformers are included in the BES. As an example, a 345/138 kV
transformer with a 23 kV tertiary winding would be included in the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
ACES Power Participating
Members

August 19, 2011

Yes

We agree with limiting transformers to bulk power transformers and not including step-down or distribution
transformers. Some regions have been enforcing standards on protection equipment that is on the low-side
of these step-down or distribution transformers. Additional language further clarifying that this low-side
protection equipment is not part of the BES should be added to for consistency across regions.Additionally,
the drafting team might consider using the terms primary and secondary rather than windings. Otherwise,

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Organization

Yes or No

Question 2 Comment
autotransformers which have a sing

Response: The SDT has changed the wording from “windings” to “terminals” in the revised version of the definition. The SDT has revised I1 to provide more
clarity on specifically which transformers are included in the BES. Associated protection system equipment will be handled separately via the PRC standards.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Hydro One Networks Inc

Yes

We agree with the concept of Inclusion I1. However, we suggest that since transformers are already covered
by the definition, "all transmission Elements operated at 100 kV and above", and since Inclusions I2 to I5 are
commonly related to generation only, Inclusion I1 should be removed and replaced by the following Exclusion:
E(x) "Transformers not used as Generator Step-Up (GSU) transformers that have primary or secondary
winding at less than 100 kV."
We also suggest the SDT to put forward a high-level exception criteria with key menu items of assessment
that can be followed continent-wide by entities to put forward their exception for element(s) mentioned in
Inclusion I1, or any other inclusion(s). These inclusion(s) that are intended for exemption would be based on
the entity’s technical assessment, evidence and justification for its unique characteristics, configuration, and
utilization.

Response: The SDT has revised Inclusion I1 to provide more clarity on specifically which transformers are included in the BES.
The SDT believes the BES definition should be “bright line” criteria and be able to include a very high percentage of the facilities by inspection. The exemption
criteria and process is meant to handle very few facilities. The BES definition and exemption process have been developed under this guiding concept.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
FHEC

Yes

Believe that the NERC Statement of Compliance Registry Criteria should be revised to reflect only thsese
inclusions and exclusions. An entity with no assets that meet this definition should be allowed to de-register.

Response: Revision of registry criteria is not part of this project. No change made.
Vermont Transco

August 19, 2011

Yes

This inclusion’s wording allows an entity to easily identify which of its transformers will be included as BES
and also adheres directly to the FERC identified 100kV or higher equipment. Question: if a transformer does
not have two windings of 100 kV or higher but does have protection devices that could open the BES system,
e.g. due to a low-voltage failed breaker scenario, would the protective devices be part of the BES even

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Organization

Yes or No

Question 2 Comment
though the transformer itself is not?

Response: Associated protection system equipment will be handled separately via the PRC standards. No change made.
National Grid

Yes

We would like some clarification regarding three-winding transformers, for example a 345/115/23 kV
transformer. Was the intention to include the 23kV in the new definition of BES? If so, it seems likely that
other 23 kV components on the buswork could be pulled into the definition of BES if it is in the zone of
protection of the transformer.

Response: The cited 345/115/23 kV transformer in the comment would be included in the BES since it has both primary and secondary terminals operated
above 100 kV. The SDT has changed the wording from “windings” to “terminals” in the revised version of the definition. The SDT has revised Inclusion I1 to
provide more clarity on specifically which transformers are included in the BES. The 23 kV facilities would not be included in the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
City of Redding

Yes

Redding supports the concept of additional inclusions to the brightline if the objective is to further hone the
generalness of the proposed definition. As we stated in question #1, we support the definition as long as an
entity has the ability to seek an exception via a fair and objective Exception Process. If the SDT keeps
inclusion 1, we believe it is overly broad and should have additional clarification added to address the various
types of transformers such as auto transformers, three phase “Y” transformers, transformers with tertiary
windings, etc. Additionally, the exclusion “other than generator step-up (GSU) transformers” could easily be
interpreted to mean “all” GSU transformers regardless of voltage. Redding suggests that I1 be changed to read:
“Transformers, including phase angle regulators, with both high side and low side windings connected at 100
kV or higher unless excluded under E1 or E3 and generator step-up (GSU) transformers, serving generators
in I2 and I3, with the high-side winding connected at 100 kV or higher.”

FortisBC

Yes

We agree with the concept of Inclusion I1. However, we suggest that since transformers are already covered
by the definition, "all transmission Elements operated at 100 kV and above", and since Inclusions I2 to I5 are
commonly related to generation only, Inclusion I1 should be removed and replaced by the following Exclusion:
E(x) "Transformers not used as Generator Step-Up (GSU) transformers that have primary or secondary
winding at less than 100 kV."
We also suggest the SDT to put forward a high-level exception criteria with key menu items of assessment
that can be followed continent-wide by entities to put forward their exception for element(s) mentioned in
Inclusion I1, or any other inclusion(s). These inclusion(s) that are intended for exemption would be based on
the entity’s technical assessment, evidence and justification for its unique characteristics, configuration, and

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Organization

Yes or No

Question 2 Comment
utilization.

AltaLink

Yes

We agree with the concept of Inclusion I1. However, we suggest that since transformers are already covered
by the definition, "all transmission Elements operated at 100 kV and above", and since Inclusions I2 to I5 are
commonly related to generation only, Inclusion I1 should be removed and replaced by the following Exclusion:
E(x) "Transformers not used as Generator Step-Up (GSU) transformers that have primary or secondary
winding at less than 100 kV."We also suggest the SDT to put forward a high-level exception criteria with key
menu items of assessment that can be followed continent-wide by entities to put forward their exception for
element(s) mentioned in Inclusion I1, or any other inclusion(s). These inclusion(s) that are intended for
exemption would be based on the entity’s technical assessment, evidence and justification for its unique
characteristics, configuration, and utilization.

Response: The SDT believes the BES definition should be “bright-line” criteria and be able to include a very high percentage of the facilities by inspection. The
exemption criteria and process is meant to handle very few facilities. The BES definition and exception process have been developed under this guiding concept.
The SDT has revised Inclusion I1 to provide more clarity on specifically which transformers are included in the BES.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Springfield Utility Board

Yes

In concept, SUB supports an attempt to provide a clear demarcation between BES and non-BES elements.
The WECC Bulk Electric System Definition Task Force (BESDTF) has devoted considerable effort to this
question and has developed one-line diagrams which note the BES demarcation point for a number of
different kinds of elements that are common in the Western Interconnection.

Springfield Utility Board

Yes

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of

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Organization

Yes or No

Question 2 Comment
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: The SDT will consider the suggestions to incorporate the WECC work into its effort.
See the answers to Questions 7, 8, and 9 related to generation.
New England States Committee
on Electricity

Yes

Inclusion I1 now appears to exclude transformers that connect the BES to the sub transmission networks (the
sub transmission elements connected to one of the windings is less than 100 kV). This suggests that the
intent of this language is to exclude such transformers and all sub transmission elements (unless included by
the other Inclusion criteria) from the BES. With that understanding, NESCOE supports Inclusion I1.

Southwest Power Pool

Yes

SPP agrees that such equipment should be included, but suggests that these issues be addressed in the
exception process. In other words, this inclusion doesn’t need to be explicitly identified. It would simply be
included under the general 100 kV threshold, and to the extent an owner believed the characteristics of its
equipment don’t warrant inclusion, it would seek an exception, which can be for either an exclusion or an
inclusion.

City of Anaheim

Yes

Change the "and" to an "or" at the end of the sentence, i.e. Exclusions E1 or E3.This appears to be the intent.

Response: The SDT has revised Inclusion I1 to provide more clarity on specifically which transformers are included in the BES. Your understanding is correct.
I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle Regulators, with two primary and secondary windingsterminals
of operated at 100 kV or higher unless excluded under Exclusions E1 andor E3.
Michgan Public Power Agency

Yes

Sweeny Cogeneration LP

Yes

Transmission system transformers are not part of our existing or anticipated base of facilities.

Western Area Power
Administration

Yes

Appreciate the bullet comments that help explain the reasoning for the inclusion.

Public Service Enterprise Group
LLC

Yes

Northeast Power Coordinating

Yes

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Organization

Yes or No

Question 2 Comment

Council
Imperial Irrigation District

Yes

Santee Cooper

Yes

SPP Standards Review Group

Yes

SERC Planning Standards
Subcommittee

Yes

SERC OC Standards Review
Group

Yes

National Rural Electric
Cooperative Association
(NRECA)

Yes

Arizona Public Service Company

Yes

ReliabilityFirst

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

New York State Reliability
Council

Yes

New York Power Authority

Yes

Southern Company

Yes

Luminant Energy

Yes

Intellibind

Yes

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Organization

Yes or No

US Bureau of Reclamation

Yes

Grand Haven Board of Light and
Power

Yes

Glacier Electric Cooperative

Yes

South Texas Electric
Cooperative, Inc.

Yes

South Texas Electric
Cooperative, Inc.

Yes

Dayton Power and Light
Company

Yes

ExxonMobil Research and
Engineering

Yes

Duke Energy

Yes

Alberta Electric System Operator

Yes

South Carolina Electric and Gas

Yes

Fayetteville Public Works
Commission

Yes

MidAmerican Energy Company

Yes

Florida Keys Electric Cooperative

Yes

American Electric Power

Yes

August 19, 2011

Question 2 Comment

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Organization

Yes or No

East Kentucky Power
Cooperative, Inc.

Yes

American Transmission
Company, LLC

Yes

Farmington Electric Utility System

Yes

Colorado Springs Utilities

Yes

Muscatine Power and Water

Yes

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

Yes

Exelon

Yes

City of St. George

Yes

Puget Sound Energy

Yes

GTC

Yes

Cogentrix Energy, LLC

Yes

Pepco Holdings Inc

Yes

PJM

Yes

ISO New England, Inc.

Yes

August 19, 2011

Question 2 Comment

No comment.

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Organization

Yes or No

MEAG Power

Yes

Orange and Rockland Utilities,
Inc.

Yes

Golden Spread Electric
Cooperative, Inc.

Yes

Idaho Falls Power

Yes

Question 2 Comment

It seems reasonable to conclude that such transformers would belong in a classification that comprises the
BES.

Response: Thank you for your support. The SDT has made changes to Inclusion I1 of the BES definition based upon other stakeholder comments. These
changes in the revised definition include removing the Generator Step-Up and Phase Angle Regulating transformer language, changing the wording from
“windings” to “terminals”, and adding the terms “primary” and “secondary”. Please see the revised definition.

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3. The SDT has added specific inclusions to the core definition in response to industry comments. Do you agree
with Inclusion I2? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration:
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any
attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice
with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743
and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC
Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from
SDT deliberations.
Changes have been made to Inclusion I2 for clarity.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or
gross aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV
or above.

Organization

Yes or No

Public Service
Enterprise Group
LLC

Question 3 Comment

No

See comment 1 above.

No

I2 should pertain to individual generating units, but the entire path should not be labeled as BES.
Oftentimes there are cases when neither the path nor a 20 MVA unit itself will have any impact on
the reliability of the interconnected transmission network, nor is it necessary for its operation. The
path to generating facilities does not need to be BES contiguous. Generating units can be required
to be planned, designed, and operated in accordance with a subset of NERC Standards, but
should not require a contiguous path unless the unit is identified essential for the operation of
transmission network.

Response: See response to Q1 above.
Northeast Power
Coordinating
Council

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Organization

Yes or No

Question 3 Comment

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the generator step up transformer which is connected on the high
side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to the
BES.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
NERC Staff
Technical Review

No

The interconnection voltage threshold should be removed. The contribution of a generator to
system reliability is a function of its MVA rating rather than its interconnection voltage. All
generating units greater than 20 MVA should be included in the BES definition because all such
units provide similar contributions to system reliability. >>>>>>>>>>
Also, the specific inclusion of the GSU transformer implies that all other components of a
generating unit, such as its unit auxiliary transformer, start-up transformer, governor, exciter,
power system stabilizer, etc., are excluded. The SDT should define “generating unit” or otherwise
clarify which components of a generating unit are included in the BES definition.

Response: The SDT has changed the terminology in the definition to include “generating resources” for clarity. Balance of Plant equipment is not included in the
contiguous path of the generator and therefore does not fall under the definition. The SDT carefully debated the generating threshold for inclusion in the
definition. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
NERC Transmission

August 19, 2011

No

It is commonly understood that a generating unit includes the generator itself, and all of the

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Organization

Yes or No

Issues
Subcommittee (TIS)

Question 3 Comment
components that connect it to the grid, including the GSU. The specific inclusion of the GSU
implies that other components of a generating unit, such as its auxiliary transformers and loads,
the governors, exciters, etc., are not included. >>>>>>>>>>
The TIS suggests the following wording: >>>>>>>>>>“I2 - Individual generating units greater than
20 MVA (gross nameplate rating) generator terminals through the GSU which has a high side
connected at a voltage of 100 kV or above.”

Response: The SDT has changed the terminology in the definition to include “generating resources” for clarity. Balance of Plant equipment is not included in
the contiguous path of the generator and therefore does not fall under the definition.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Dominion

No

As stated in its response to Question 2 above, Dominion disagrees that a generation resource,
Element or Facility should automatically be included in the BES. Dominion agrees that the
Generator Owner and Generator Operator, as users of the bulk power system, should have to
abide by applicable reliability standards, but do not agree that this should automatically require the
inclusion of a generation resource, Element or Facility in the BES.
Further, Dominion prefers that the SDT use the term “generation resources” as stated in the
current BES definition contained in the Glossary of Terms instead of the proposed term
“generating unit”.

Response: The SDT has changed the terminology in the definition to include “generating resources” for clarity. The SDT carefully debated the generating
threshold for inclusion in the definition. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any
attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will
be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach
to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.

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Organization
SPP Standards
Review Group

Yes or No

Question 3 Comment

No

With the inclusion of a voltage criteria in the definition an inconsistency is created between
Elements that are not a part of the BES but are still required to be part of the NERC Compliance
Registry. Does this create an issue? Did the SDT intend to create this inconsistency? A large
generating unit or group of units that are connected to the interconnection via 69kV does not
qualify as a part of the BES. Although the generation level could be substantial, it is still not a part
of the BES. If said generation is 20 MVA or 75 MVA, respectively, it would have to be registered in
the Compliance Registry. While an entity may be able to petition to include such a facility in the
BES, what is the incentive to do so? This seems to detract from the ‘bright line’ definition.

Response: The SDT is drafting a definition for the Bulk Electric System and does not have involvement with the registration criteria. If reliability is a concern
regarding specific generation that has been excluded from the definition, the Reliability Coordinator can always go through the NERC Rules of Procedure exception
process to petition to bring generation into the BES. No change made.
Michigan Public
Service
Commission(MPSC)

No

MPSC Staff Comments: This inclusion should be eliminated entirely for the reasons provided in
E1 above. If the BES is required to be contiguous, this I2 threshold will result in many radial
subtransmission lines losing their non-BES status and having to comply with NERC security and
reliability requirements.
Two different generation thresholds, one for I2 and one for I3, should not be used. The I3
inclusion (75MVA) threshold should be sufficient.

Tennessee Valley
Authority

No

Other than the NERC Registry Criteria definition, what is the technical justification for the 20 MVA
thresholds? The threshold level for inclusion should be technically based on the BES capacity and
configuration at the location of the generating source’s connection to the BES.

New York State
Reliability Council

No

The use of a 20 MVA threshold based on NERC's Registry Criteria may be administratively
convenient but is arbitrary when based upon BES reliability considerations. Suggest use of a 300
MW or other regionally and technically acceptable threshold such as NPCC's A-10 criterion.

Michgan Public
Power Agency

Yes

Generally I would agree with I2 but question the technical justification for 20 MVA without also
considering its capacity factor.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new

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Organization

Yes or No

Question 3 Comment

Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
SERC OC
Standards Review
Group

No

SERC proposes the following as an alternative to the Inclusion I2 wording in the draft BES
definition: “Individual generating units greater than 20 MVA (gross nameplate rating) including the
generator terminals through its GSU which has a high side voltage of 100 kV or above.” The only
difference in proposed text is that the word “the” preceding “GSU” has been changed to “its”. The
text in the draft clearly defines that the inclusion begins with the generator, continues through the
terminals, and ends at a GSU. The wording in the draft text does not, however, explicitly limit the
scope of equipment that should be evaluated for inclusion to the GSU which is directly connected
to the generator terminals. Since GSU is not a defined term there is a strong potential for
inconsistent interpretation of this boundary to include multiple transformers in series until ultimately
a transformer which does operate at a voltage of greater than 100 kV is included in the flow path.
To eliminate this potential for compliance re-interpretation, we also strongly suggest the term GSU
be defined in the NERC Glossary of Terms. A suggested definition is: “Generator Step-up
Transformer (GSU) should be defined as a transformer directly connected to a generator on the
low side and to a bus on the high side.”

Response: The SDT generally agrees with your clarification statement.
Inclusion I2 has been eliminated and Inclusion I3 has been clarified to use the term step-up transformer rather than GSU.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Hydro One
Networks Inc

August 19, 2011

No

We agree with the concept of Inclusion I2 with respect to individual generating units, but do not
support having the entire path labeled as BES. In most cases, neither the path nor a 20 MVA unit
itself will have any impact on the reliability of the interconnected transmission network nor is it
necessary for the operation. Hence, we do not support the fact that there should be a blanket
application of the BES definition to all individual generating units greater than 20 MVA and its
connection to the system. It is also important to mention that moving into the future, with the Green
Energy and Smart Grid plans advocated by both Canadian and US policy makers, the gross
nameplate rating of 20 MVA acquired from NERC registration restricts the penetration of dispersed

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Organization

Yes or No

Question 3 Comment
generation in many parts of North America.
We suggest the following: o Generation restriction (20 MVA or 75 MVA) should either be revised
or the exception procedure should allow entities, with the support of technical evidence, to exclude
element(s) from being labeled as part of the BES.
o Entities should be able to use the exception process, with the help of technical evidence, to
exclude generating units that do not impact the interconnected grid and the bulk transfer of power.
o The path to generating facilities does not need to be BES contiguous. Generating units can be
required to be planned, designed, and operated in accordance with a subset of NERC Standards,
but should not require a contiguous path unless the unit is identified essential for the operation of
transmission network.

Ida ho Falls Power

No

We feel the bright line criteria 20 MVA for generation is equally as arbitrary as the 100KV threshold
for transmission, which was the impetus for the NERC BES definition effort. There should be more
defining criteria to establish what generation resources should be included in the BES. Possible
criteria to consider would be generation serving load other than local load connected to an LDN or
generation that is dispatchable. Surely, just as not all 100 kV is is material to the BES, niether is all
20MVA or greater generation. If this draft's language is allowed to stand at the brightline of
20MVA, without additional defining criteria, will have the likely result of an inordinate number of
entities having to resolve the issue of material impact through the Rules of Procedure exemption
process. We urge NERC to take this opportunity now to more clearly define material generation
assets beyond a simple brightline criteria.
In addition to our concern of this draft following bright line registry criteria for generation assets, it
is our concern that there is no distinction made as to where the generation is connected. Our
belief is that generation on an LDN wherein the net flow of power is into the LDN should be exempt
as the liklihood of that generation being material to the larger BES is exceedingly small.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Entities seeking exception from the core definition can utilize the NERC RoP exception process to present relevant evidence.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross

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Organization

Yes or No

Question 3 Comment

aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Western Montana
Electric Generating
and Transmission
Cooperative

No

WMG&T is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the
20 MVA threshold discussed in our response to question 3, the 75 MVA threshold appears to have
been drawn from the NERC Statement of Compliance Registry without appreciation for the
function of the threshold in that document and without adequate technical justification
demonstrating the generators with an aggregate capacity of 75 MVA produce electric energy
“needed to maintain transmission system reliability” and are therefore properly included in the BES
definition.
In the same comments, the SDT also states that it has considered “the inclusion of generator stepup (GSU) transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable.” Unfortunately, the SDT appears to have concluded
that any interconnection facility operating above 100-kV should be classified as BES. The result
will be to require Generation Owners to register as Transmission Owners/Operators, as well,
producing substantial additional compliance costs for those Generation Owners but resulting in
little or no improvement in the reliability of the BES. We recommend that the SDT, like the Project
2010-07 SDT (commonly referred to as the GO/TO Team), give careful consideration to the
practical results of its recommendations rather than relying on abstract conclusions about whether
a “contiguous” or “non-contiguous” BES is more desirable. We are concerned that the SDT’s
pursuit of a “contiguous” BES will result in a substantially over-inclusive BES definition. The
“contiguous” BES concept implies that every Element arguably necessary for the reliable operation
of the interconnected bulk system must be included in the BES definition, even if it is
interconnected with Elements that have no bearing on the operation of the BES. NERC’s
Standards Drafting Team for Project 2010-07, has already considered this question and, based on
an in-depth review of potentially applicable reliability standards, has concluded that generation
interconnection facilities, even if operated above 100-kV, need to comply only with a limited set of
reliability standards in order to achieve the reliability goals. Much of the work of the Project 201007 SDT is applicable to the work of the BES Standards Development Team. For example, the
Project 2010-07 Team observed that interconnection facilities “are most often not part of the
integrated bulk power system, and as such should not be subject to the same level of standards
applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” Similarly, a
“contiguous” BES suggests that, because certain system protection facilities, such as UFLS relays,
are ordinarily embedded in local distribution systems, the local distribution system, along with the
UFLS relays, must be classified as BES to make the BES “contiguous.” Such a result is not only

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Yes or No

Question 3 Comment
plainly contrary to the local distribution exclusion embedded in Section 215 of the FPA, but would,
by improperly classifying local distribution lines as BES “Transmission” facilities, result in huge
regulatory compliance burdens with little or no improvement in bulk system reliability.

Response: There has been no significant technical justification by which to base a departure from the 75 MVA threshold where connected at 100 kV and
above. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the generator step up transformer which is connected on the high
side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to the
BES.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Southern Company

No

The inclusion criterion I3 and I5 establish the level of generation that has been deemed to be the
important threshold for the amount of generation at a facility. The individual generating unit size
criteria should match that same aggregate size given in I3 and I5. It doesn't make sense to specify
a 20 MVA level for a single unit compared to multiple smaller unit plants whose aggregate totals 75
MVA. To provide equivalent weight to each configuration of plant structure, the individual
generating unit size should be 75 MVA rather than 20 MVA. The NERC Registry Criteria should
also be changed from 20 MVA to 75 MVA for a single generator size. Further, a significant
number of respondents to the first BES definition posting stated that the 20 MVA generator
threshold is too low. Many Generator Owners and Operators do not understand the technical
basis for including individual generators rated 75 MVA or less. The NERC Registry Criteria alone
does not clearly define the technical basis for the 20 MVA threshold, and appears to use this as a
conservative generator rating to cover some areas where units this size may have a material
impact on the local area reliability. We do not believe this translates to material impact on BES
reliability in terms of wide area blackouts and cascading outages. We believe that the technical
basis for including any single generator of 75 MVA or less needs to be more clearly concisely
established and documented to support Inclusion Criterion I2.

Electricity

No

Although the BES Standards Drafting Team has stated that it will not propose changing the 20-

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Consumers
Resource Council
(ELCON)

Question 3 Comment
MVA/75-MVA thresholds, we think the thresholds should be set based on the BA/RC needs in
each area and that a suggested range (perhaps by taking a survey of the operational entities)
should be in the new BES Definition. Having an arbitrary and capricious number in the new BES
Definition just because it is in the current Statement of Compliance Registry Criteria, and requiring
significant technical justification for change, does not seem appropriate when so many expert
industry commenters have indicated the existing thresholds are too low to be operationally
significant.

Response: There has been no significant technical justification by which to base a departure from the 75 MVA threshold where connected at 100 kV and
above. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations. The goal of this project is
to clarify the BES definition and not to address issues related to registration criteria.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
National
Association of
Regulatory Utility
Commissioners

No

The inclusion of individual generating units between 20 MVA and 75 MVA nameplate capacity is
inconsistent with I3 that sets the aggregate threshold at 75 MVA. There is no technical justification
for including a facility as low as 20 MVA and no rational basis for thinking that these generators
could be the cause of instability, uncontrolled separation, or cascading events. We recommend
removing this inclusion or raising the threshold to 75 MVA.

American Electric
Power

No

The use of the word “including” within I2 seems to imply the inclusion of 20MVA (or greater)
generating units beyond those which have a high side voltage of 100 kV or above. Was this
intentional? If not, the following wording is preferable: "Individual generating units greater than 20
MVA (gross nameplate rating) having a GSU with a high side voltage of 100 kV or above. This
includes equipment installed from the generator terminals through the high side of the GSU."

Springfield Utility
Board

No

SUB raises the questions “Are multiple individual units considered one unit if they have a shared
bus?” SUB is concerned that in the instance where individual units have a shared bus that some
interpretations would be that these are individual and therefore not part of the BES while other
interpretations would result in the units being considered part of the BES because of a shared bus.
Given I3, SUB suggests that units connected to a shared bus be considered as if they were not

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Question 3 Comment
connected to a shared bus if they are individually separable by automatic fault-interrupting devices
(e.g. two 15aMW units that have a shared bus would not be included as part of I2 if they each
have automatic fault-interrupting devices). Continuing the example of the two 15aMW units, if a
shared bus somehow combined the two individual units into one unit for purposes of I2, where
does this distinction end? What if they share the same transmission line? Is this transmission line
considered being a “bus” for purposes of combining the two units into one individual unit?
Because this discussion could go on with multiple examples, SUB suggests that the distinction be
the automatic fault-interrupting device. If the devices can be separated from each other and the
local network then they should be considered individual. While Springfield Utility Board does not
own any generating units, we do recognize the importance of the stability and restoration of the
Grid, and the generation necessary for the Grid.

Springfield Utility
Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on
May 26, 2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental
comment deals with the concept of "serving only load" and the classification of what types of
generation are incorporated into the definition of generation for purposes of BES inclusion or
exclusion.SUB's comment is that generation normally operated as backup generation for retail
load is not counted as generation for purposes of determining generation thresholds for inclusion
or exclusion from the BES. For purposes of BES inclusion or exclusion, a system with load and
generation normally operated as backup generation for retail load is considered "serving only load"
when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is
normally used during a localized outage and for testing for reliability during a localized outage
event. Including backup generation for retail load in generation thresholds (e.g. 75MVA) would not
reflect generation used for restoration or reliability of the BES. Including backup generation for
retail load in generation threshold calculations would cause a inappropriate inclusion of elements
and devices, accelerate the triggering of inclusion (and may make exclusion provisions
meaningless), and push more activity of excluding smaller systems from the BES into the
exception process.

New York State
Dept of Public
Service

No

The inclusion of 20 MVA generation seems inconsistent with I3 that sets the aggregate threshold
at 75 MVA. It is not rational that a 20 MVA facility could be the cause of instability, uncontrolled
separation of the system or cascading events. This inclusion should be dropped.

Idaho Power

No

Generators at 20 MVA are not material to the BES. I would recommend combining I2, I3, and I5
with the limit at 75 MVA for plant nameplate capability regardless of the number of generators and

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Question 3 Comment
type of generators.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
PacifiCorp

No

Although certain areas of the country may have a need for generating units of this magnitude to be
included in the BES for reliability, the 20 MVA minimum rating essentially discriminates against the
owners of these generators. In I3 and I5 a 75 MVA limit has been established for different
combinations of generation. This limit should also be used for a single generating unit. Those
areas that require generator units less than 75 MVA for reliability should add them back to the BES
via the inclusion/exclusion process to be proposed in NERC’s Rules of Procedure (“ROP”).
o The 20 MVA threshold was intended to mirror the existing NERC Compliance Registry Criteria.
This registry value was adopted without the benefit of having been scrutinized through a NERC
Reliability Standards Development Process, so the technical record justifying the 20 MVA
threshold is non-existent. The BES Drafting Team will need to have technical justification for
adopting the 20 MVA threshold beyond the fact that it was previously adopted by NERC in a
different framework (i.e., for entity registration). Absent any technical justification, Inclusion I2
should be eliminated. This would leave the 75 MVA threshold in Inclusion I3 and Inclusion I5 as
the minimum BES thresholds for generation.
Also, please refer to additional comments in question 13 regarding a contiguous BES.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Comments regarding contiguous BES submitted under Q13 will be answered under Q13.

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Question 3 Comment

I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Intellibind

No

In the discussion the Drafting team stated they found no technical rational to change the 20 MVA
rule, however there is no technical rational to support 20 MVA either. There are arguably cases
where it will be appropriate to include these generators; however there are may instances where
these generators should not be included. This should be driven by the interconnected
transmission operators, not by an arbitrary threshold. In the WECC there are multiple examples of
small/medium hydro, waste-to-energy, and other non-dispatchable generation that not only are
located where they cannot add to the reliability of the BES, are not manned, and are bound by
contractual relationships by a BA. These facilities have a tendency to have multiple forced
outages, are affected by weather events, and are not considered reliable by the interconnected
transmission operator for BES reliability purposes. Many of these facilities generate power as a
secondary business, not primary. Wood burning, trash burning is waste disposal, irrigation
projects are primarily focused on water delivery. Failure of power generation is not addressed as a
primary importance during a failure, and none of these facilities were constructed to benefit the
BES. In many cases the contract to construct these facilities was predicated on proving they do
not impact the interconnected transmission operator or the BES.

Portland General
Electric Company

No

The 20 MVA gross nameplate rating threshold for an individual unit is toolow and will result in the
inclusion in the BES of generating units that have no potentialto impact the reliability of the BES.
The 20 MVA threshold was taken from theregistration criteria, and no technical justification has
been provided for its use. PGErecommends that this inclusion be removed entirely.

City of St. George

No

It is understood that this mirrors the Registry Criteria and this is a simple way to address the issue.
The justification states there is no technical rationale to change the 20 MVA threshold, however
the technical rationale for the 20 MVA criteria has not been provided to the industry either. Having
a 20 MVA unit treated the same and subject to all of the same standard requirements as a unit
with several hundred MVA of capacity doesn’t make sense either. The requirements for an entity
or facility should match the impact of that facility to the system.

City of Redding

Yes

August 19, 2011

In concept Redding is in agreement that the Brightline should specify generators at a certain level,
however we believe the SDT has no technical basis to choose the 20 MVA threshold. If the SDT
elects to retain I2 in its current form then Redding suggests changing the generation level from 20
MVA to 100 MVA. If the goal of the Brightline Definition is to create a starting point to identify power
system elements that are “necessary” then the SDT should choose a larger generation threshold as

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Question 3 Comment
a starting point. The 100 MVA would serve a better purpose by casting the burden of proof (via the
Exception Process) from the smaller units under 100 MVA to the Regional Entity. This would help
the SDT to achieve an objective of reducing the burden on the “small entity” and “distribution”
facilities due to the fact that most smaller generators of this size are installed to serve local loads.
Additionally, The SDT has not provided justification that the “generator terminals through GSU” on
smaller units are “needed to maintain transmission system reliability.” The inclusion of the low
voltage equipment from the GSU to the Generator on small generators is going beyond what is
necessary to operate an interconnected transmission network. This portion of the inclusion should
be removed or modified because the SDT has not demonstrated why the connection facilities are
“necessary”.
The biggest argument for smaller units to be included as BES elements is that their
operation/maintenance schedules and output visiablity are “necessary to operate an interconnected
transmission network”. If that is the case the Compliance Registry captures units above 20 MVA as
users of the BES system; Standards can be written to address the support aspects of these types of
units. As recommended, selecting a higher generator MVA threshold in the brightline definition does
not exempt the lower MVA generation units from being classified as Users of the BES in the
Compliance Registry. In fact Redding, suggests that the Registry be revised to have a more tiered
approach allowing the Standards to be equably applied to Entities. Redding suggests that SDT
recommend that the Generator Owner and Operator definitions be modified to have Large and
Small generator owners and operators.
In summary, Redding supports the concept that the brightline is an initial dividing line of elements
that are necessary to operate the BES. Therefore, Redding suggests that the SDT change the
language in I2:
From: “Individual generating units greater than 20 MVA (gross nameplate rating) including the
generator terminals through the GSU which has a high side voltage of 100 kV or above”.
To: “Individual generating units greater than 100 MVA (gross nameplate rating) including the
generator terminals through the GSU which has a high side voltage of 100 kV or above”.
OR
To: “Individual generating units which have a contractual obligation to provide operational support
necessary to operate the interconnected transmission system.”

California Public
Utilities Commission

August 19, 2011

Yes

The CPUC would like a technical justification/rational for the 20 MVA threshold. We understand
and agree with the ability to show no impact through a technical impact assessment, but such an

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Question 3 Comment
assessment may be costly for a small 20-50 MW peaker plant that may operate for few hours
during any given month. The cost imposed to small generating plants that operate a few hours a
month may be too excessive given the probability of the generator causing an event and the cost
associated with the event. The BES definition should be more than a deterministic standard and
should properly assess every asset it proposes to include, especially given what the courts have
ruled. We believe it would be preferable to include individual elements at power plants that can
impact the BES (governors, system stabilizers, breakers,...) rather than to extend the definition of
the BES to include all small power plants.

Response: There has been no significant technical justification by which to base a departure from the 75 MVA threshold where connected at 100 kV and above.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Hydro-Quebec
TransEnergie

No

We believe that it is not necessary to include small generator of 20 MVA into the BES, neither the
transmission path that connect them. However, a provision should be made so that some reliability
standards related to generator shall apply (voltage regulation, etc.).

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Oregon Public Utility
Commission Staff

August 19, 2011

No

The inclusion of individual generation units with a nameplate capacity between 20 MVA and 75
MVA is over-inclusive and unnecessary. Generation in this range generally has no impact to the
reliability of the bulk transmission system. The 20 MVA threshold was pulled from the existing

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Question 3 Comment
NERC Statement of Compliance Registry. This Registry value was adopted without the benefit of
having been scrutinized through a NERC Standards Development Process, so the technical record
justifying the 20 MVA threshold is unavailable. The BES Drafting Team will need to have technical
justification for adopting the 20 MVA threshold beyond the fact that it was previously adopted by
NERC in a different framework. Absent any technical justification, Inclusion I2 should be
eliminated. This would leave the 75 MVA threshold in Inclusion I3 and Inclusion I5 as the
minimum BES thresholds for generation.The proposed BES Definition does not address the BES
“demarcation points” and whether the BES must be “contiguous.” NERC Staff has submitted
written comments to this project stating that the BES “must be contiguous.” Instituting a
contiguous BES with Inclusion I2 would result in a over-inclusive BES definition. The adoption of a
“contiguous” BES is therefore likely to result in imposition of reliability standards on a substantial
number of distribution elements that have nothing to do with improving or protecting the reliability
of bulk transmission system.There is no compelling reason to adopt a “contiguous” BES down into
local distribution systems. Section 215 of the FPA of 2005 gives FERC jurisdictional authority over
“users” as well as “owners” and “operators” of the bulk power system. Consequently, FERC has
the jurisdictional authority to require generation entities in the Compliance Registry to comply with
applicable NERC requirements. Hence, even where an entity does not own or operate BES
assets, it could still be required, for example, to provide necessary information to the applicable
Reliability Coordinator or Planning Coordinator and to participate in programs to prevent instability,
uncontrolled separation or cascading outages to the bulk transmission system. This approach
would fully achieve the goals of bulk transmission system reliability without imposing the full BES
regulatory compliance burden on local distribution elements.

Response: There has been no significant technical justification by which to base a departure from the 75 MVA threshold where connected at 100 kV and
above. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The SDT proposal does not address BES contiguity beyond the connection to 100 kV or greater (the high side of the GSU).
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Public Utility District

August 19, 2011

No

Snohomish is concerned that the inclusion of individual generation units with a nameplate capacity

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Organization
No. 1 of Snohomish
County, Washington

August 19, 2011

Yes or No

Question 3 Comment
as small as 20 MVA is over-inclusive. Under FPA Section 215, generation resources are excluded
from the “bulk-power system” unless they produce “electric energy” that is “needed to maintain
transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators with a capacity of
20 MVA almost never produce electricity that is “needed to maintain transmission system
reliability.” Hence, the inclusion as drafted improperly expands the BES definition to include
generators that the statute requires to be excluded. Further, the 20 MVA threshold appears to
have been drawn without explanation from the existing NERC Statement of Compliance Registry.
Given that the purpose of the Compliance Registry is to sweep in all generators that might be
material to the operation of the BES, and not to definitively determine whether a given generator is,
in fact, material to the operation of the BES, the STD has acted arbitrarily and without adequate
technical justification in adopting the 20 MVA threshold. In responding to comments on its initial
proposal, the SDT states that it adopted the 20 MVA threshold because “there is no technical basis
to change the values contained in the Statement of Compliance Registry Criteria.” Consideration of
Comments on Definition of Bulk Electric System - Project 2010-17, March 30, 2011, at 30. But this
gets the equation backwards. The SDT must have some technical justification for adopting the 20
MVA threshold beyond the fact that it was previously adopted by NERC in a different context.
Without a technical justification demonstrating that facilities operating at capacities as low as 20
MVA are “needed to maintain transmission system reliability,” the proposed definition is overly
broad and fails to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16
U.S.C. § 8240(a)(1). Further, the Statement of Compliance Registry was adopted without the
benefit of having been vetted through the NERC Standards Development Process, so the technical
record underlying the choice of that threshold is unavailable for review by the industry.In the same
comments, the SDT also states that it has considered “the inclusion of generator step-up (GSU)
transformers and associated interconnection line leads and believes the BES must be contiguous
at this level in order to be reliable.” Id. The SDT’s reasons for reaching this conclusion are not
well-explained, but apparently the concern is that a “non-contiguous” BES could create “reliability
gaps.” But this conclusion cannot be supported as an abstract proposition, but can only be
demonstrated by a careful examination how application of reliability standards will change
depending on how the BES is defined. In fact, we believe that if the SDT insists on a “contiguous”
BES, an over-inclusive definition will result.We base these conclusions on the findings of NERC’s
Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO Task Force.” The
Project 2010-07 Team was formed to address how the dedicated interconnection facilities linking a
BES generator to high-voltage transmission facilities should be treated under the NERC standards.
After reviewing these questions in considerable depth, the Team concluded that dedicated highvoltage interconnection facilities need not be treated as “Transmission” and classified as part of
the BES in order to make reliability standards effective. On the contrary, the team concluded that
by complying with a handful of reliability standards, primarily related to vegetation management,

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Question 3 Comment
reliable operation of the bulk interconnected system could be protected without unduly burdening
the owners of such interconnection systems. See Final Report from the NERC Ad Hoc Group for
Generator Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the
predecessor of the Project 2010-07 SDT). Much of the work of the Project 2010-07 SDT is
applicable to the work of the BES Standards Developoment Team. For example, the Project 201007 Team observed that interconnection facilities “are most often not part of the integrated bulk
power system, and as such should not be subject to the same level of standards applicable to
Transmission Owners and Transmission Operators who own and operate transmission Facilities
and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the
same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of
the equipment that actually produces electricity - the generation equipment itself.” Id. We believe
the many of the questions considered by the Project 2010-07 Team are analogous to the
questions under consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES,
the resulting definition will be substantially over-inclusive. The “contiguous” BES concept implies
that every Element arguably necessary for the reliable operation of the interconnected bulk system
must be included in the BES definition, even if it is interconnected with Elements that have no
bearing on the operation of the BES. The adoption of a “contiguous” BES is therefore likely to
result in imposition of reliability standards on a substantial number of facilities that have little or
nothing to do with bulk system reliability, resulting in wasted regulatory expense and additional
stress on the limited resources of reliability regulators. For example, a “contiguous” BES would
require dedicated interconnection facilities that connect a BES generator to BES transmission
facilities to be classified as BES. But, as the discussion above demonstrates, the classification of
dedicated interconnection facilities as “BES” facilities would, based on the findings of the Project
2010-07 SDT, result in substantial overregulation and unnecessary expense with little gain for bulk
system reliability. Similarly, a “contiguous” BES suggests that, because certain system protection
facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the local
distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” Such a result is not only plainly contrary to the local distribution exclusion embedded
in Section 215 of the FPA, but would, by improperly classifying local distribution lines as BES
“Transmission” facilities, result in huge regulatory compliance burdens with little or no improvement
in bulk system reliability. There is no good reason for the SDT to adopt a “contiguous” BES. On
the contrary, because Section 215 allows reliability standards to be applied to “users” of the bulk
system as well as “owners” and “operators,” local distribution systems operating UFLS relays and
other bulk system protection devices could be required to comply with standards governing those

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Question 3 Comment
devices as a precondition for their use of transmission on the bulk system. The other alternative is
to draft standards that apply to a specific type of equipment - again UFLS relays is a good example
- rather than to BES facilities categorically. Either approach will fully achieve the goals of bulk
system reliability without imposing an undue regulatory compliance burden on local distribution
systems.For these reasons, we urge the SDT to follow the example of the Project 2010-07 Team
and the GO-TO Task Force by giving careful consideration to the specific and practical results of
how its definition will affect the application of particular reliability standards and whether the results
are beneficial to reliability or simply result in unnecessary regulatory burdens that do not benefit
bulk system reliability. We believe there is considerable danger of error if the SDT bases its
conclusions on metaphysical debates about whether a “contiguous” or “non-contiguous” BES is
more desirable rather than engaging in a careful analysis of whether the proposed definition
achieves reliability goals in the most efficient manner possible.

Blachly Lane
Electric Cooperative
Central Electric
Cooperative
Clearwater Power
Company
Consumers Power
Inc
Clallam County
PUD No.1

No

The inclusion of individual generation units with a nameplate capacity as small as 20 MVA is overinclusive. Under FPA Section 215, generation resources are excluded from the “bulk-power
system” unless they produce “electric energy” that is “needed to maintain transmission system
reliability.” 16 U.S.C. § 824o(a)(1)(B). Smaller generators with a capacity of 20 MVA almost never
produce electricity that is “needed to maintain transmission system reliability.” Hence, the inclusion
as drafted would improperly expand the BES definition to include generators that the statute
requires to be excluded.
Further, the 20 MVA threshold appears to have been drawn without explanation from the existing
NERC Statement of Compliance Registry. Given that the purpose of the Compliance Registry is to
sweep in all generators that might be material to the operation of the BES, and not to definitively
determine whether a given generator is, in fact, material to the operation of the BES, the STD has
acted arbitrarily and without adequate technical justification in adopting the 20 MVA threshold.
The 100 MVA threshold seems more in alignment with technical standards such as Power System
Stabilizer requirements. In responding to comments on its initial proposal, the SDT states that it
adopted the 20 MVA threshold because “there is no technical basis to change the values
contained in the Statement of Compliance Registry Criteria.” Consideration of Comments on
Definition of Bulk Electric System - Project 2010-17, March 30, 2011, at 30. But this gets the
equation backwards. The SDT must have some technical justification for adopting the 20 MVA
threshold beyond the fact that it was previously adopted by NERC in a different context. Without a
technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and
fails to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §

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Organization

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Question 3 Comment
8240(a)(1).
Further, the Statement of Compliance Registry was adopted without the benefit of having been
vetted through the NERC Standards Development Process, so the technical record underlying the
choice of that threshold is unavailable for review by the industry.
In the same comments, the SDT also states that it has considered “the inclusion of generator stepup (GSU) transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable.” Id. The SDT’s reasons for reaching this conclusion
are not well-explained, but apparently the concern is that a “non-contiguous” BES could create
“reliability gaps.” This conclusion cannot be supported as an abstract proposition, but can only be
demonstrated by a careful examination how application of reliability standards will change
depending on how the BES is defined. We believe that if the SDT insists on a “contiguous” BES,
an over-inclusive definition will result.We base these conclusions on the findings of NERC’s
Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO Task Force.” The
Project 2010-07 Team was formed to address how the dedicated interconnection facilities linking a
BES generator to high-voltage transmission facilities should be treated under the NERC standards.
After reviewing these questions in considerable depth, the Team concluded that dedicated highvoltage interconnection facilities need not be treated as “Transmission” and classified as part of
the BES in order to make reliability standards effective. On the contrary, the team concluded that
by complying with a handful of reliability standards, primarily related to vegetation management,
reliable operation of the bulk interconnected system could be protected without unduly burdening
the owners of such interconnection systems. See Final Report from the NERC Ad Hoc Group for
Generator Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the
predecessor of the Project 2010-07 SDT). Much of the work of the Project 2010-07 SDT is
applicable to the work of the BES Standards Development Team. For example, the Project 201007 Team observed that interconnection facilities “are most often not part of the integrated bulk
power system, and as such should not be subject to the same level of standards applicable to
Transmission Owners and Transmission Operators who own and operate transmission Facilities
and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the
same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of
the equipment that actually produces electricity - the generation equipment itself.” Id.
We
believe the many of the questions considered by the Project 2010-07 Team are analogous to the
questions under consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES,
the resulting definition will be substantially over-inclusive. The “contiguous” BES concept implies

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Yes or No

Question 3 Comment
that every Element arguably necessary for the reliable operation of the interconnected bulk system
must be included in the BES definition, even if it is interconnected with Elements that have no
bearing on the operation of the BES. The adoption of a “contiguous” BES is therefore likely to
result in imposition of reliability standards on a substantial number of facilities that have little or
nothing to do with bulk system reliability, resulting in wasted regulatory expense and additional
stress on the limited resources of reliability regulators. For example, a “contiguous” BES would
require dedicated interconnection facilities that connect a BES generator to BES transmission
facilities to be classified as BES. But, as the discussion above demonstrates, the classification of
dedicated interconnection facilities as “BES” facilities would, based on the findings of the Project
2010-07 SDT, result in substantial overregulation and unnecessary expense with little gain for bulk
system reliability. Similarly, a “contiguous” BES suggests that, because certain system protection
facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the local
distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” Such a result is not only plainly contrary to the local distribution exclusion embedded
in Section 215 of the FPA, but would, by improperly classifying local distribution lines as BES
“Transmission” facilities, result in huge regulatory compliance burdens with little or no improvement
in bulk system reliability. There is no good reason for the SDT to adopt a “contiguous” BES. On
the contrary, because Section 215 allows reliability standards to be applied to “users” of the bulk
system as well as “owners” and “operators,” local distribution systems operating UFLS relays and
other bulk system protection devices could be required to comply with standards governing those
devices as a precondition for their use of transmission on the bulk system. For these reasons, we
urge the SDT to follow the example of the Project 2010-07 Team and the GO-TO Task Force by
giving careful consideration to the specific and practical results of how its definition will affect the
application fo particular reliability standards and whether the results are beneficial to reliability or
simply result in unnecessary regulatory burdens that do not benefit bulk system reliability. We
believe there is considerable danger of error if the SDT bases its conclusions on metaphysical
debates about whether a “contiguous” or “non-contiguous” BES is more desirable rather than
engaging in a careful analysis of whether the proposed definition achieves reliability goals in the
most efficient manner possible.

Coos-Curry Electric
Cooperative
Douglas Electric
Cooperative
Fall River Electric

August 19, 2011

No

Specific language change: Change 20 MVA to 100 MVAThe inclusion of individual generation
units with a nameplate capacity as small as 20 MVA is over-inclusive. Under FPA Section 215,
generation resources are excluded from the “bulk-power system” unless they produce “electric
energy” that is “needed to maintain transmission system reliability.” 16 U.S.C. § 824o(a)(1)(B).
Smaller generators with a capacity of 20 MVA almost never produce electricity that is “needed to
maintain transmission system reliability.” Hence, the inclusion as drafted would improperly expand
the BES definition to include generators that the statute requires to be excluded. Further, the 20

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Organization
Cooperative
Lane Electric
Cooperative
Lincoln Electric
Cooperative
Lost River Electric
Cooperative
Northern Lights Inc
Okanogan Electric
Cooperative
PNGC Power
Raft River Rural
Electric Cooperative
Salmon River
Electric Cooperative
Umatilla Electric
Cooperative
West Oregon
Electric Cooperative

August 19, 2011

Yes or No

Question 3 Comment
MVA threshold appears to have been drawn without explanation from the existing NERC
Statement of Compliance Registry. Given that the purpose of the Compliance Registry is to sweep
in all generators that might be material to the operation of the BES, and not to definitively
determine whether a given generator is, in fact, material to the operation of the BES, the STD has
acted arbitrarily and without adequate technical justification in adopting the 20 MVA threshold.
The 100 MVA threshold seems more in alignment with technical standards such as Power System
Stabilizer requirements. In responding to comments on its initial proposal, the SDT states that it
adopted the 20 MVA threshold because “there is no technical basis to change the values
contained in the Statement of Compliance Registry Criteria.” Consideration of Comments on
Definition of Bulk Electric System - Project 2010-17, March 30, 2011, at 30. But this gets the
equation backwards. The SDT must have some technical justification for adopting the 20 MVA
threshold beyond the fact that it was previously adopted by NERC in a different context. Without a
technical justification demonstrating that facilities operating at capacities as low as 20 MVA are
“needed to maintain transmission system reliability,” the proposed definition is overly broad and
fails to comply with the restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). Further, the Statement of Compliance Registry was adopted without the benefit of
having been vetted through the NERC Standards Development Process, so the technical record
underlying the choice of that threshold is unavailable for review by the industry.In the same
comments, the SDT also states that it has considered “the inclusion of generator step-up (GSU)
transformers and associated interconnection line leads and believes the BES must be contiguous
at this level in order to be reliable.” Id. The SDT’s reasons for reaching this conclusion are not
well-explained, but apparently the concern is that a “non-contiguous” BES could create “reliability
gaps.” This conclusion cannot be supported as an abstract proposition, but can only be
demonstrated by a careful examination how application of reliability standards will change
depending on how the BES is defined. We believe that if the SDT insists on a “contiguous” BES,
an over-inclusive definition will result.We base these conclusions on the findings of NERC’s
Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO Task Force.” The
Project 2010-07 Team was formed to address how the dedicated interconnection facilities linking a
BES generator to high-voltage transmission facilities should be treated under the NERC standards.
After reviewing these questions in considerable depth, the Team concluded that dedicated highvoltage interconnection facilities need not be treated as “Transmission” and classified as part of
the BES in order to make reliability standards effective. On the contrary, the team concluded that
by complying with a handful of reliability standards, primarily related to vegetation management,
reliable operation of the bulk interconnected system could be protected without unduly burdening
the owners of such interconnection systems. See Final Report from the NERC Ad Hoc Group for
Generator Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the
predecessor of the Project 2010-07 SDT). Much of the work of the Project 2010-07 SDT is

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Organization

Yes or No

Question 3 Comment
applicable to the work of the BES Standards Development Team. For example, the Project 201007 Team observed that interconnection facilities “are most often not part of the integrated bulk
power system, and as such should not be subject to the same level of standards applicable to
Transmission Owners and Transmission Operators who own and operate transmission Facilities
and Elements that are part of the integrated bulk power system.” White Paper Proposal for
Information Comment, NERC Project 2010-07: Generator Requirements at the Transmission
Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply with the
same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of
the equipment that actually produces electricity - the generation equipment itself.” Id.
We
believe the many of the questions considered by the Project 2010-07 Team are analogous to the
questions under consideration by the SDT, and that, if the SDT insists upon a “contiguous” BES,
the resulting definition will be substantially over-inclusive. The “contiguous” BES concept implies
that every Element arguably necessary for the reliable operation of the interconnected bulk system
must be included in the BES definition, even if it is interconnected with Elements that have no
bearing on the operation of the BES. The adoption of a “contiguous” BES is therefore likely to
result in imposition of reliability standards on a substantial number of facilities that have little or
nothing to do with bulk system reliability, resulting in wasted regulatory expense and additional
stress on the limited resources of reliability regulators. For example, a “contiguous” BES would
require dedicated interconnection facilities that connect a BES generator to BES transmission
facilities to be classified as BES. But, as the discussion above demonstrates, the classification of
dedicated interconnection facilities as “BES” facilities would, based on the findings of the Project
2010-07 SDT, result in substantial overregulation and unnecessary expense with little gain for bulk
system reliability. Similarly, a “contiguous” BES suggests that, because certain system protection
facilities, such as UFLS relays, are ordinarily embedded in local distribution systems, the local
distribution system, along with the UFLS relays, must be classified as BES to make the BES
“contiguous.” Such a result is not only plainly contrary to the local distribution exclusion embedded
in Section 215 of the FPA, but would, by improperly classifying local distribution lines as BES
“Transmission” facilities, result in huge regulatory compliance burdens with little or no improvement
in bulk system reliability. There is no good reason for the SDT to adopt a “contiguous” BES. On
the contrary, because Section 215 allows reliability standards to be applied to “users” of the bulk
system as well as “owners” and “operators,” local distribution systems operating UFLS relays and
other bulk system protection devices could be required to comply with standards governing those
devices as a precondition for their use of transmission on the bulk system. For these reasons, we
urge the SDT to follow the example of the Project 2010-07 Team and the GO-TO Task Force by
giving careful consideration to the specific and practical results of how its definition will affect the
application for particular reliability standards and whether the results are beneficial to reliability or

August 19, 2011

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Organization

Yes or No

Question 3 Comment
simply result in unnecessary regulatory burdens that do not benefit bulk system reliability. We
believe there is considerable danger of error if the SDT bases its conclusions on metaphysical
debates about whether a “contiguous” or “non-contiguous” BES is more desirable rather than
engaging in a careful analysis of whether the proposed definition achieves reliability goals in the
most efficient manner possible.

Northern Wasco
County PUD
Chelan PUD –
CHPD
Kootenai Electric
Cooperative
Public Utility District
No. 1 of Franklin
County
Midstate Electric
Cooperative
Northwest
Requirements
Utilities
Big Bend Electric
Cooperative, Inc.
Cowlitz County PUD

August 19, 2011

No

Northern Wasco County PUD is concerned that I2 inclusion criteria that includes the arbitrary 20
MVA threshold from the NERC Statement of Registry Criteria for inclusion of generators is overinclusive. Under FPA Section 215, generation resources are excluded from the “bulk-power
system” unless they produce “electric energy” that is “needed to maintain transmission system
reliability.” Hence, the inclusion as drafted improperly expands the BES definition to include
generators that the statute requires to be excluded. In the same comments, the SDT also states
that it has considered “the inclusion of generator step-up (GSU) transformers and associated
interconnection line leads and believes the BES must be contiguous at this level in order to be
reliable.” Unfortunately, the SDT appears to have concluded that any interconnection facility
operating above 100-kV should be classified as BES. The result will be to require Generation
Owners to register as Transmission Owners/Operators, as well, producing substantial additional
compliance costs for those Generation Owners but resulting in little or no improvement in the
reliability of the BES. We recommend that the SDT, like the Project 2010-07 SDT (commonly
referred to as the GO/TO Team), give careful consideration to the practical results of its
recommendations rather than relying on abstract conclusions about whether a “contiguous” or
“non-contiguous” BES is more desirable. We are concerned that the SDT’s pursuit of a
“contiguous” BES will result in a substantially over-inclusive BES definition. The “contiguous” BES
concept implies that every Element arguably necessary for the reliable operation of the
interconnected bulk system must be included in the BES definition, even if it is interconnected with
Elements that have no bearing on the operation of the BES. NERC’s Standards Drafting Team for
Project 2010-07, has already considered this question and, based on an in-depth review of
potentially applicable reliability standards, has concluded that generation interconnection facilities,
even if operated above 100-kV, need to comply only with a limited set of reliability standards in
order to achieve the reliability goals. Much of the work of the Project 2010-07 SDT is applicable to
the work of the BES Standards Development Team. For example, the Project 2010-07 Team
observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to
Transmission Owners and Transmission Operators who own and operate transmission Facilities
and Elements that are part of the integrated bulk power system.” Similarly, a “contiguous” BES
suggests that, because certain system protection facilities, such as UFLS relays, are ordinarily
embedded in local distribution systems, the local distribution system, along with the UFLS relays,

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Yes or No

Question 3 Comment
must be classified as BES to make the BES “contiguous.” Such a result is not only plainly contrary
to the local distribution exclusion embedded in Section 215 of the FPA, but would, by improperly
classifying local distribution lines as BES “Transmission” facilities, result in huge regulatory
compliance burdens with little or no improvement in bulk system reliability.

Response: The SDT has carefully debated your comments. The SDT does not base its conclusions on “metaphysical debates” as you imply, but rather the
practical nature of inclusions and exclusions in the definition and the reliability impacts associated with them based on technical debate and justification. There
has been no significant technical justification by which to base a departure from the 75 MVA threshold where connected at 100 kV and above. After consulting
with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time.
There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to
address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the
NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization
Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the generator step up transformer which is connected on the
high side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to
the BES.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Sweeny
Cogeneration LP

No

The threshold for individual generation units is consistent with the NERC functional registry
criterion. We believe that it is important to maintain this uniformity. However, we believe there are
further items to be added to the list related to generator interconnections, a task that was passed
to this project from Project 2010-07. Just as is the case with complex distribution systems, there
are a variety of generator-transmission interconnection architectures which are driving the Regions
to inappropriately register Generator Owner/Operators as Transmission Owners.

Response: The SDT cannot respond to this general comment as it lacks specific action.
PUD No. 2 of Grant
County, Washington

August 19, 2011

No

In the same comments, the SDT also states that it has considered “the inclusion of generator stepup (GSU) transformers and associated interconnection line leads and believes the BES must be
contiguous at this level in order to be reliable.” Unfortunately, the SDT appears to have concluded
that any interconnection facility operating above 100-kV should be classified as BES. The result
will be to require Generation Owners to register as Transmission Owners/Operators, as well,
producing substantial additional compliance costs for those Generation Owners but resulting in

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Yes or No

Question 3 Comment
little or no improvement in the reliability of the BES. We recommend that the SDT, like the Project
2010-07 SDT (commonly referred to as the GO/TO Team), give careful consideration to the
practical results of its recommendations rather than relying on abstract conclusions about whether
a “contiguous” or “non-contiguous” BES is more desirable. We are concerned that the SDT’s
pursuit of a “contiguous” BES will result in a substantially over-inclusive BES definition. The
“contiguous” BES concept implies that every Element arguably necessary for the reliable operation
of the interconnected bulk system must be included in the BES definition, even if it is
interconnected with Elements that have no bearing on the operation of the BES. A “contiguous”
BES suggests that, because certain system protection facilities, such as UFLS relays, are
ordinarily embedded in local distribution systems, the local distribution system, along with the
UFLS relays, must be classified as BES to make the BES “contiguous.” The improper
classification of local distribution lines as BES “Transmission” facilities results in huge regulatory
compliance burdens with little or no improvement in bulk system reliability.

FortisBC

No

We agree with the concept of Inclusion I2 with respect to individual generating units, but do not
support having the entire path labeled as BES. In most cases, neither the path or a 20 MVA unit
itself will have any impact on the reliability of the interconnected transmission network nor is it
necessary for the operation.
We also do not support the fact that there should be a blanket application of the BES definition to
all individual generating units greater than 20 MVA. It is also important to mention that moving into
the future, with the Green Energy and Smart Grid plans advocated by both Canadian and US
policy makers, the gross nameplate rating of 20 MVA acquired from NERC registration restricts the
penetration of dispersed generation in many parts of North America.
We suggest the following:
o Generation restriction (20 MVA or 75 MVA) should either be revised or the exception procedure
should allow entities, with the support of technical evidence, to exclude element(s) from being
labeled as part of the BES.
o Entities should be able to use the exception process, with the help of technical evidence, to
exclude generating units that do not impact the interconnected grid and the bulk transfer of power.
o The path to generating facilities does not need to be BES contiguous. Generating units can be
required to be planned, designed, and operated in accordance with a subset of NERC Standards,
but should not require a contiguous path unless the unit is identified essential for the operation of
transmission network.
o Definition and/or exception process should provide clear acknowledgement and flexibility to

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Question 3 Comment
avoid any regulatory conflicts.
- For example: NERC and SDT should consider introducing a
concept of a new category of registration or BES Support (BESS) elements. These elements are
NOT BES but support the reliable operation of the interconnected transmission network. A sub-set
of relevant NERC Standards should still apply to BESS elements such as planning, design, and
maintenance. However, they may not be subject to mandatory compliance.

Public Utilities
Commission of Ohio

No

The inclusion of individual generating units between 20 MVA and 75 MVA nameplate capacity is
inappropriate and over-reaching. Inclusion I3 sets the aggregate threshold at 75 MVA for multiple
generating units. Technical justification for assuming a 20 MVA generating facility could cause
instability, uncontrolled separation, or cascading events on the bulk system appears to be lacking.
This appears to simply be based on that fact the NERC used it in a separate framework, which has
no basis. Inclusion I2 should be removed.Regarding the contiguous standard - simply because an
element is connected to the BES does not make it a part of the BES. By the very nature, a radial
or distribution element should pose limited or no impact on the BES. They are easily isolated from
the rest of the system. This contiguous measurement could impose standards unnecessarily on
systems with no ultimate impact on the bulk system, thereby enabling far-reaching authority into
the distribution system.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations. The SDT
proposal does not address BES contiguity beyond the connection to 100 kV or greater (the high side of the GSU). The SDT believes that the definition must be
contiguous at this level in order to ensure reliability of the BES. Aside from registration burdens, stakeholders have not provided technical justification or
recommendations by which to base a departure from the contiguous nature of the definition. The goal of the SDT is to provide clarity to the definition of the BES
and not to address registration criteria.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Electric Reliability
Council of Texas,
Inc.

August 19, 2011

No

See response to question 1. ERCOT ISO supports redefining generation covered under the BES
to reflect the registration threshold, but, consistent with the comments to question 1, believes it
should be included within the bright line criteria unless otherwise indicated by application of the
inclusion and exclusion criteria of the exception process or analyses.

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Question 3 Comment

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Fayetteville Public
Works Commission

August 19, 2011

No

Inclusion I2 contains wording that is ambiguous and does not support a consistent determination
by independent parties of whether or not a specific generator should be included in the BES. This
definition will be a critical part of the guidance used by registered entities to validate their current
registration status and by new entities to properly determine their initial registration status. It will
also be used by regional reliability entities during compliance activities to verify proper registration.
The ambiguous wording of Inclusion I2 could easily lead to re-interpretation issues between the
owner/operator of the generator and regional entities in a compliance audit or other compliance
setting. To be specific, the phrase "including the generator terminals through the GSU which has
a high side voltage of 100 kV or above" is particularly troublesome. The phrase as written is
intended to establish the boundary of the Real Power resource that will be included in the BES if
the conditions of Inclusion I2 are met. The intent appears to be to include within the BES the
generator, the cables connecting the generator terminals to the GSU, and the GSU, if the GSU has
a high side voltage of 100 kV or above. If the GSU, however, does not have a high side voltage of
100 kV or above, then neither the generator, nor the connecting cables, nor the GSU would
included within the BES.The crux of the problem lies in the interpretation of the term "GSU" and
the phrase "through the GSU which". The term "GSU" or "generator step-up transformer" is
commonly applied to a transformer with a generator directly connected to the low side and a bus
directly connected to the high side. This is not, however, a defined term within the NERC Glossary
and no standard for that interpretation is provided. The very structure of the phrase "through the
GSU which" implies that there may be more than one GSU to be considered, some of which do not
but at least one of which does have a high side voltage of 100 kV or above. This could be
interpreted to include multiple transformers (GSUs) stepping up the generator voltage in series, the
first stepping up the generator voltage to a bus, the second stepping up that bus voltge to another
bus, and the third, and so on, and so on, until finally 'THE" transformer (GSU?) is encountered
"WHICH" does have a high side voltage of 100 kV or higher.Thus, if the registering entity were to
apply the commonly accepted definition of "GSU" to a generator, and the GSU directly connected
to that generator has a high side of less than 100 kV, that entity would properly conclude that

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Organization

Yes or No

Question 3 Comment
neither the generator nor the leads nor the GSU should be included in the BES. If a regional
compliance entity applies the interpretation that transformers in series must be considered until a
generator is encountered which does have a high side of 100 kV or higher, then that compliance
entity would properly conclude that the generator, all the transformers in series, and the buses
connecting those transformers should be included in the BES. Clearly this potential for
contradictory conclusions would be better cleared up during this comment period than repeatedly
coming up during compliance processes.I offer two suggestions for eliminating this ambiguity. The
first and preferred method would be to change the wording of Inclusion I2 to read s follows:
"Individual generating units greater than 20 MVA (gross nameplate rating) directly connected to
the low side of a GSU which has a high side voltage of 100 kV or higher. The generator, the leads
directly connecting the generator terminals to the GSU, and the GSU are all included in the BES."
The second method would be to define within the NERC Glossary the term GSU as follows: "A
generator step-up transformer (GSU) is a transformer directly connected to the terminals of a
generator on the low side and to a bus at a higher voltage on the high side."

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The SDT does not feel that the wording is confusing but is understood to mean that any generating resources, their generator terminals, connecting cabling up to
and including their generator step up transformers that are connected at 100 kV or greater will be included in the definition of the BES. The SDT believes that the
definition must be contiguous at this level in order to ensure reliability of the BES. Aside from registration burdens, stakeholders have not provided technical
justification or recommendations by which to base a departure from the contiguous nature of the definition. Elements connected at below 100 kV that meet
registration criteria will still be required to meet NERC Reliability Standards that apply to their registration.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Southern California
Edison Company

August 19, 2011

No

Inclusions I2, I3, and I5 should either be modified or removed, because as currently written, these
three Inclusion criteria force the definition to be arbitrarily demarcated by the size of generators
connecting to the system, or the aggregate thereof, rather than focusing on the risk characteristics
that should define the BES, as SCE identified in its response to Question No. 1. In the WECC, it
can safely be said that the vast majority of 20MVA generators are located in local distribution
systems and are used to off-set local load, rather than transfer power to the BES. In SCE’s case,

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Organization

Yes or No

Question 3 Comment
our distribution system has a number of components which are marginally above the 100kV BES
threshold, are radial in nature, and were previously exempted from the BES by the WECC. These
radial systems have interconnecting generation units larger than 20 MVA and/ or aggregate
generation exceeding 75 MVA. In many cases, the generation levels on those radial systems
exceed the limits proposed in I2, I3, and I5, but the loading on those same systems is such that
generation will rarely exceed the local load. Therefore, there is little to no power flow back to the
BES from these radial systems.If the BES definition continues to heavily focus its inclusion criteria
on generator/ generation size, SCE feels that the SDT also consider incorporating the concept of
“potential exports to the BES” from these generating sources. An example being:”I2 - Individual
generating units greater than 20 MVA (gross nameplate rating) including the generator terminals
through the GSU which has a high side voltage of 100 kV or above and have no more than 5% net
flows into the BES based on the past XXX calendar years.”This “Net Flow” concept would negate
the need for Section 1C of the “Technical Principles for Demonstrating BES Exceptions”, or
conversely, provide the framework for a more quantifiable criteria in Section 1C.

Response: The SDT has debated your comments and similar comments from stakeholders. After consulting with the NERC Board of Trustees and the NERC
Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to
do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a.
However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the
idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as
well as several other issues that have arisen from SDT deliberations. Individual situations can be evaluated on a case by case basis and utilities can use the NERC
RoP exception process.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Cogentrix Energy,
LLC

No

We also strongly suggest the term GSU be defined in the NERC Glossary of Terms to prevent
potential compliance re-interpretation of this requirement. A suggested definition is: “Generator
Stepup Transformer (GSU) should be defined as a transformer directly connected to a generator
on the low side and to a bus on the high side.”

Response: The SDT has made clarifying changes to the inclusion to address your concern.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.

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Organization
Clark Public Utilities

Yes or No

Question 3 Comment

No

Generators should only be part of the Bulk Electric System if they are connected through a GSU to
a Transmission Element determined to be part of the BES. The current inclusion language would
apply to all generators connected to facilities greater the 100 kV with no exclusion or exception
process. Without a change, it appears that a generator connected to a facility greater than 100 kV
would be a BES asset even if the transmission assets could be excluded or excepted. I2 should be
rewritten to state: Individual generating units greater than 20 MVA (gross nameplate rating)
including the generator terminals through the GSU which has a high side winding connected to a
Transmission Element determined to be part of the Bulk Electric System.
Additionally, as indicated by Clark in its comments on the core definition of the BES, Clark believes
the 20 MVA threshold lacks an adequate technical justification and is a purely arbitrary quantity.
The use of a capacity threshold in the definition of the BES should have technical reasons.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The SDT feels that the revised definition provides adequate clarifying measures. Individual situations can be addressed through the NERC RoP exception process.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
The Dow Chemical
Company

No

It should be clarified that if something falls within an Inclusion and an Exclusion, then it is
excluded. See ELCON comments.

Response: The SDT has made clarifying changes to the definition to address your concern.
New England
States Committee
on Electricity

No

Inclusion Criteria I2 through I4 relate to generation connected with GSU High side voltages greater
than 100 kV and refer to generators with MVA limits exceeding either 20 or 75 MVA aggregate
depending on their configuration.
It should be made clear that all generation connected to sub transmission are not BES as these
units are adequately covered under other applicable NERC and/or regional reliability organization
criteria. These units have no direct impact on the reliability of the BES. This includes black start
units because they do not directly impact normal or contingency operation of the BES. These units

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Organization

Yes or No

Question 3 Comment
and their associated cranking paths are used only for restoration and not operation. Further, they
are appropriately covered under regional restoration procedures and NERC standards (see for
example, Emergency Operating Procedure EOP-005-2).
Use of varying generator MVA thresholds as inclusion criteria under I2 and I3 could lead to
inconsistent treatment of generation facilities. For example, a generation facility with a single 30
MVA generator would qualify as BES under I2. However, if an additional 30 MVA generator was
added at the same site, the facility’s status would change to non-BES under I3 even though the
facility’s capacity had doubled.
NESCOE is also concerned that if the BES is required to be contiguous, the I2 threshold will result
in many radial sub transmission lines becoming BES, resulting in substantial costs without
significant justifying benefits. NESCOE suggests deleting Inclusion I2 or adopting a threshold that
is consistent with I3, and which in no event should be lower than 75 MVA.
Regarding facilities connected at 100 kV and above, some generation units in paper mills or other
entities operating on the retail side of the meter may exceed the Inclusion Criteria. The Exception
Process, which will be the subject of future comments, should provide some flexibility in this area.
NESCOE further notes that in the case of radially connected generation, the contiguous
connection paths should not be BES even if the operating voltage is greater than 100 kV. This is
due to the fact that loss of a path has no greater impact than loss of the connected generator. This
is simply a first contingency loss that has no significant impact on the BES. Inclusion I2 should be
clarified to include only connections that impact the BES.

Response: The definition states that Real and Reactive Power resources connected at 100 kV or higher are considered BES. Sub-transmission referenced in
your comments would generally be considered below 100 kV. Inclusions within the definition address resources connected at below 100 kV that are considered
BES elements.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the generator step up transformer which is connected on the
high side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to
the BES.
Aside from registration burdens, stakeholders have not provided technical justification or recommendations by which to base a departure from the contiguous

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Organization

Yes or No

Question 3 Comment

nature of the definition.
Individual situations can be addressed through the NERC RoP exception process.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
PPL Energy Plus
and PPL
Generation

No

See comments in Question 13.

Illinois Municipal
Electric Agency

Yes

Please see comments under Question 13.

No

The inclusion of generation to the BES should be subject to an impact test.‬

Response: See response to Q13.
Consolidated
Edison Co. of NY,
Inc.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Independent
Electricity System
Operator

August 19, 2011

No

We agree with the goal of inclusion of I2 but as stated earlier in our response to Q1, we do not
support the blanket application of the BES definition to all individual generating units and Facilities
meeting the respective capacity thresholds. Entities should be able to assess the impact of these
units and Facilities against the TPC and use the Exception Process, with the help of technical
evidence, to include generating units and Facilities that impact the interconnected grid and the bulk
transfer of power.

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Organization
Orange and
Rockland Utilities,
Inc.

Yes or No
No

Question 3 Comment
: XI2 should pertain to individual generating unit impact to the Bulk system, rather than the size
unit only. Oftentimes there are cases when neither the path nor a 20 MVA unit itself will have any
impact on the reliability of the interconnected transmission network, nor is it necessary for its
operation.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Individual situations can be addressed through the NERC RoP exception process.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
AltaLink

No

We agree with the concept of Inclusion I2 with respect to individual generating units, but do not
support having the entire path labeled as BES. In most cases, neither the path or a 20 MVA unit
itself will have any impact on the reliability of the interconnected transmission network nor is it
necessary for the operation. Generation restriction (20 MVA or 75 MVA) should either be revised
or the exception procedure should allow entities, with the support of technical evidence, to exclude
element(s) from being labeled as part of the BES. The path to generating facilities does not need
to be BES contiguous. Generating units can be required to be planned, designed, and operated in
accordance with a subset of NERC Standards, but should not require a contiguous path unless the
unit is identified essential for the operation of transmission network.Definition and/or exception
process should provide clear acknowledgement and flexibility to avoid any regulatory conflicts.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the generator step up transformer which is connected on the
high side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to
the BES. Aside from registration burdens, stakeholders have not provided technical justification or recommendations by which to base a departure from the

August 19, 2011

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Organization

Yes or No

Question 3 Comment

contiguous nature of the definition.
Individual situations can be addressed through the NERC RoP exception process.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Utility System
Efficiencies, Inc.

No

The 20 MVA threshold appears to have been drawn without explanation from the existing NERC
Statement of Compliance Registry. Given that the purpose of the Compliance Registry is to sweep
in all generators that might be material to the operation of the BES, and not to definitively
determine whether a given generator is, in fact, material to the operation of the BES, the STD has
acted arbitrarily and without adequate technical justification in adopting the 20 MVA threshold. In
responding to comments on its initial proposal, the SDT states that it adopted the 20 MVA
threshold because “there is no technical basis to change the values contained in the Statement of
Compliance Registry Criteria.” Consideration of Comments on Definition of Bulk Electric System Project 2010-17, March 30, 2011, at 30. But this response gets the equation backwards. The
SDT must have some technical justification for adopting the 20 MVA threshold beyond the fact that
it was previously adopted by NERC in a different context. Without a technical justification
demonstrating that facilities operating at capacities as low as 20 MVA are “needed to maintain
transmission system reliability,” the proposed definition is overly broad and fails to comply with the
restrictions imposed by Congress in FPA Section 215(a)(1), 16 U.S.C. § 8240(a)(1).
Further, the Statement of Compliance Registry was adopted without the benefit of having been
vetted through the NERC Standards Development Process, so the technical record underlying the
choice of that threshold is unavailable for review by the industry.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The goal of the SDT is to provide clarity to the definition of the BES and not to address registration criteria.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.

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Organization
BPA

Yes or No

Question 3 Comment

No

Change to “Individual generating units greater than 20 MVA (gross nameplate rating), including the
generator terminals through the GSU, where the GSU has a high side voltage of 100 kV or
above.” The 100 kV high side voltage is important for determining whether the generation is
included, not whether the terminals are included.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Clarifying language has been included in the definition which addresses your concern.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
ATCO Electric

If a generator connects to 2 back to back transformers (25kV/72kV and 72kV/144kV), which
transformer is GSU? 25/72kV transformer only or both transformers.

Response: There is not enough information included in your comment to determine inclusions or exclusions.
Tacoma Power

Tacoma Power generally supports Inclusion I2. However, the term ‘gross nameplate rating’ is not
defined and should be replaced with a specific definition. Additionally, no justification for the 20
MVA level has been provided and therefore it appears arbitrary. Since this measurement will
define Elements for absolute inclusion in the BES, the threshold for generation units should be
based on a need to maintain transmission reliability. Generation units located within a Local
Distribution Network (LDN), which do not exit the LDN, should not be included. We propose
changing Inclusion I2 to read,”Individual generating units greater than 20 MVA (ratings based on
the Code of Federal Regulation, CFR 18, Part 11.1 definition “Authorized Installed Capacity”)
including the generator terminals through the GSU which has a high side voltage of 100 kV or
above, except generating units that are within a Local Distribution Network (LDN) and do not have
a net export out of the LDN.”

Response: The SDT feels that the term “gross nameplate rating” is a widely used term within industry and does not require additional definition. No change
made.

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Organization

Yes or No

Question 3 Comment

After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Please refer to stakeholder comments and responses to Question 9 for the local distribution network.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Pepco Holdings Inc

Clarification needed: If a generator greater than 20mva connected to a bus less than 100kv, but
the bus is connected through a transformer (high side greater then 100kv) to the BES, are the
generator, GSU or transformer considered BES?

Response: The generator and its contiguous path including the bus or interconnecting cable through the GSU high side bushing would all fall under the BES
definition.
Georgia System
Operations

It is unclear to us what the phrase “including the generator terminals through the GSU...” means.
Is the GSU itself included (it apparently would not be under I-1)? We understand terminals to be in
essence points, and therefore don’t see how they go “through” a GSU. Is the intention perhaps to
mean “including the generator terminals at the GSU” or even “including the generator terminals at
the GSU and the GSU itself”?

Response: The SDT has included clarifying language to address your concern.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Central Lincoln

Yes

But please indicate how generators below 20 MVA are treated, since we don’t believe the
flowchart at http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly
expresses the SDT’s intent to classify these small units as non-BES.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus

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Organization

Yes or No

Question 3 Comment

of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The RoP flowchart that was originally posted was incorrect and a corrected version is now available.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
American Municipal
Power and
Members

Yes

We support I2 but propose clarifying edits. We understand that the intent is to define the BES
component of qualifying generators as that equipment from the generator terminals through the
GSU. To convey clearly this point, as well as that only generators that are both over 20 MVA and
connected through a GSU with a high side voltage of at least 100 kV are included in the BES, I2
should be reworded as follows: “Individual generating units greater than 20 MVA (gross nameplate
rating) including the generator terminals, connected through a GSU that has a high-side voltage of
100 kV or above. A BES generator includes the equipment from the generator terminals through
the GSU.”

Small Entity
Working Group
(SEWG)

Yes

Yes, with a minor clarification. Individual generating units greater than 20 MVA (gross nameplate
rating) including the generator terminals through the GSU which has a high side connection
voltage of 100 kV or above. This should help state that only generators that are both over 20 MVA
and connected through a GSU with a high side voltage of at least 100kV are included in the BES.

Florida Municipal
Power Agency

Yes

FMPA understands that the intent is to define the BES component of qualifying generators as that
equipment from the generator terminals through the GSU. To convey clearly this point, as well as
that only generators that are both over 20 MVA and connected through a GSU with a high side
voltage of at least 100 kV are included in the BES, I2 should be reworded as follows: “Individual
generating units greater than 20 MVA (gross nameplate rating), connected through a GSU with a
high-side voltage of 100 kV or above. A BES generator includes the equipment from the generator
terminals through the GSU.”

Western Electricity
Coordinating
Council

Yes

WECC agrees in concept, but the language could be clarified on the GSU transformer. Suggested
language “Individual generating units greater than 20 MVA (gross nameplate rating) including the
generator terminals up to and including the GSU transformer, which has a high-side voltage of 100
kV or above.”

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Organization

Yes or No

Question 3 Comment

Transmission
Access Policy Study
Group

Yes

TAPS understands that the intent is to define the BES component of qualifying generators as that
equipment from the generator terminals through the GSU. To convey clearly this point, as well as
that only generators that are both over 20 MVA and connected through a GSU with a high side
voltage of at least 100 kV are included in the BES, I2 should be reworded as follows: “Individual
generating units greater than 20 MVA (gross nameplate rating), connected through a GSU with a
high-side voltage of 100 kV or above. A BES generator includes the equipment from the generator
terminals through the GSU.”

Northern California
Power Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this
regard.

Sacramento
Municipal Utility
District (SMUD)

Yes

SMUD agrees with the concept of Inclusion 2. To ensure the clarity of the “Bright-Line” criteria the
GSU when connected to a voltage 100 kV and above as indicated in the proposal should clearly
state that the GSU is included as BES.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Clarifying edits have been made to the definition to address your comments.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Santee Cooper

Yes

The inclusion for generating units needs to be consistent with regional entities exclusion criteria for
MODO24.

Response: The SDT has been asked to provide a definition that provides clarity and less ambiguity on a continent-wide basis. The SDT does not agree that
there should be regional interpretation and criteria associated with this definition.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards

August 19, 2011

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Organization

Yes or No

Question 3 Comment

Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
New York Power
Authority

Yes

The definition should exclude generator leads for generating units that do not materially affect the
reliability of the BES regardless of the BES designation of the generating unit.
In addition, the definition should not require the inclusion of contiguous elements. Generating units
that are designated BES are currently required to comply with a subset of NERC Reliability
Standards, but may not be material to the reliable operation of the interconnected BES. This
portion of the definition should not require that both BES and non-BES generating units have their
generator leads defined as BES transmission elements. A length-based criterion for generator
leads ought to be considered. For example, the definition should exclude generator leads that are
one mile or less between BES elements.This comment has been raised in Question number 1 as
well.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the generator step up transformer which is connected on the high
side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to the
BES. Aside from registration burdens, stakeholders have not provided technical justification or recommendations by which to base a departure from the
contiguous nature of the definition.
Radial exclusions are discussed under Question 7.
Please see responses to comments under question 1 for further discussion.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Central Maine

August 19, 2011

Yes

Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is

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Organization

Yes or No

Power Company
New York State
Electric & Gas and
Rochester Gas &
Electric

Question 3 Comment
MVA instead of MW.

Yes

Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is
MVA instead of MW.

Response: ERO registration criteria utilize MVA as a measurement unit. No change made.
Vermont Transco

Yes

How will generating owners currently registered as a GO/GOP and have units tied to the BES
system through a radial transmission line, that they own, and connects them to the grid be affected
by the new definition? Will they need to become TO and TOP registered also?
Should a GO/GOP have to adhere to all TO/TOP standards and requirements or only a sub-set of
requirements?

Response: The SDT cannot address individual registration questions. Discussion of radial connections can be found under Question 7.
ExxonMobil
Research and
Engineering

Yes

Support is contingent on the continued exclusion of generation based on its net capacity provided
to the BES.

Response: See response to question 4 in this regard.
Alberta Electric
System Operator

Yes

Consider adding the word “transformer” after “GSU”.

Response: Clarifying edits have been made to the definition to address your comments.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
MEAG Power

August 19, 2011

Yes

The definition should exclude generator leads for generating units that do not materially affect the
reliability of the BES regardless of the BES designation of the generating unit. In addition, the
definition should not require the inclusion of contiguous elements. Generating units that are
designated BES are currently required to comply with a subset of NERC Reliability Standards, but

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Organization

Yes or No

Question 3 Comment
may not be material to the reliable operation of the interconnected BES.This portion of the
definition should not require that both BES and non-BES generating units have their generator
leads defined as BES transmission elements. A length-based criterion for generator leads ought to
be considered. For example, the definition should exclude generator leads that are one mile or
less between BES elements.This comment has been raised in Question number 1 as well.

Response: The SDT proposal does not address BES contiguity beyond the connection to 100 kV or greater (the high side of the GSU).
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Xcel Energy

Yes

Xcel Energy thanks the SDT for their work and appreciates the clarification that BES extends from
the generator out and does not include the prime mover and balance of plant equipment.

Southwest Power
Pool

Yes

Please refer to SPP's response to question 1. but, consistent with the comments to question 1,
believes it should be reflected as part of the general definition, as opposed to
inclusions/exclusions, which should all be addressed pursuant to the separate processes.

Consumers Energy
Company

Yes

We are supportive of Inclusion I2. Generators 20MVA and greater with terminals through a GSU
connected at 100kV and above are treated as Bulk Electric System at this time along with their
radial connections to the Transmission system. We agree with the SDT that no technical rationale
for changing this condition exists.

Sierra Pacific Power
Co d/b/a NV Energy

Yes

While 20MVA has no technical basis for the threshold above which a generator should be
considered to be necessary for the reliable operation of an interconnected transmission network,
the industry has not provided any technical data to support a value other than this which has been
established in the NERC Statement of Compliance Registry Criteria.

Western Area
Power
Administration

Yes

the bullet comments that define a specific point for demarcation.

Tri-State Generation
and Transmission
Association, Inc.

Yes

August 19, 2011

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Organization

Yes or No

Imperial Irrigation
District

Yes

MRO's NERC
Standards Review
Forum

Yes

SERC Planning
Standards
Subcommittee

Yes

ACES Power
Participating
Members

Yes

National Rural
Electric Cooperative
Association
(NRECA)

Yes

Overton Power
District No. 5

Yes

Arizona Public
Service Company

Yes

ReliabilityFirst

Yes

Rayburn Country
Electric
Cooperative, Inc.

Yes

Luminant Energy

Yes

US Bureau of

Yes

August 19, 2011

Question 3 Comment

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment

Reclamation
Grand Haven Board
of Light and Power

Yes

Glacier Electric
Cooperative

Yes

FHEC

Yes

South Texas
Electric
Cooperative, Inc.

Yes

National Grid

Yes

Dayton Power and
Light Company

Yes

Duke Energy

Yes

South Carolina
Electric and Gas

Yes

MidAmerican
Energy Company

Yes

Florida Keys
Electric Cooperative

Yes

East Kentucky
Power Cooperative,
Inc.

Yes

American

Yes

August 19, 2011

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Organization

Yes or No

Question 3 Comment

Transmission
Company, LLC
Farmington Electric
Utility System

Yes

Colorado Springs
Utilities

Yes

Muscatine Power
and Water

Yes

Exelon

Yes

BGE and on behalf
of Constellation
NewEnergy,
Constellation
Commodities Group
and Constellation
Control and
Dispatch

Yes

Puget Sound
Energy

Yes

GTC

Yes

Long Island Power
Authority

Yes

PJM

Yes

Oncor Electric
Delivery Company

Yes

August 19, 2011

No comment.

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 3 Comment

LLC
Manitoba Hydro

Yes

ISO New England,
Inc.

Yes

City of Anaheim

Yes

Golden Spread
Electric
Cooperative, Inc.

Yes

Response: Thank you for your support. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo
any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will
be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach
to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations. Please see the revised definition.

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4.

The SDT has added specific inclusions to the core definition in response to industry comments. Do you agree
with Inclusion I3? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: While many commenters did agree with the proposal, about half of the commenters who responded to this
question disagreed with some aspect of the proposal.
The SDT believes that generation plants larger than 75 MVA connected at 100 kV or higher need to be included within the Bulk Electric System
(BES) definition. This threshold is based on the generation plant threshold values found in the NERC Statement of Compliance Registry Criteria.
Also, two Regional Entities (FRCC and RFC) specifically use this criterion in each of their current BES definitions. The 75 MVA plant is a low
enough level to capture most generating plants that would have an effect on the reliability of the interconnected Transmission network.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that
the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the
Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation
thresholds as well as several other issues that have arisen from SDT deliberations.
Commenters have suggested other thresholds (anywhere from 0 to 300 MVA) for generation plants to be included in the BES definition.
However, as of this date, commenters have not submitted technical justification upon which to base a departure from the generation MVA
thresholds included in the ERO Statement of Compliance Registry Criteria. The SDT recommends that entities use the NERC Rules of
Procedure (RoP) exception process for obtaining exceptions to the BES Definition.
Some other issues raised include the following:
•

Some commenters expressed that “single site” should be defined. “Single site” basically means “generating plant/facility” as used in the
ERO Statement of Compliance Registry Criteria (SCRC). Because this SCRC criteria understanding has not been problematic to date, the
SDT does not believe that “single site” needs to be further clarified.

•

Concerns were raised about the interpretation of the term “through a common bus”. The SDT eliminated this term, which should improve
the clarity of the definition.

•

Some commenters brought up concerns related to the “contiguous” nature of the BES. For purposes of this inclusion, the SDT is proposing
BES contiguity from the generator leads through the step up transformer(s). The SDT proposal for this inclusion does not address BES
contiguity beyond the connection to 100 kV or greater (the high side of the step-up transformer).

•

Two commenters expressed concerns that Exclusion E2 (using net capacity) and the new Inclusion I2 (using gross aggregate nameplate
capacity) are inconsistent. The SDT agrees that Exclusion E2 should over-ride this Inclusion. Exclusion E2 is dedicated to the situations
faced by behind-the-meter (retail customer owned) generation that are PURPA qualifying facilities in the US and similarly situated

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

generators in Canada. While the criteria in Inclusions I2 and I3 were based on gross nameplate ratings in MVA, the first condition (i) in
Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed relevant to the
exclusion, not the nameplate rating. The “net capacity provided to the BES” is the behind-the-meter generation that exceeds the Load
directly served by the generator. The revised language in Exclusion E2 should address these concerns.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was
reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual
or gross aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV
or above.

Organization
Northeast Power Coordinating
Council

Yes or No

Question 4 Comment

No

I3 should pertain to multiple generating units located at a single site, but the entire contiguous path should not
be labeled as BES. Oftentimes there are cases when neither the path of a 75 MVA plant or aggregated
generation will have any impact on the reliability of the interconnected transmission network nor be necessary
for its operation.
As stated earlier, under various green energy, smart grid and dispersed renewable energy plans advocated
by both Canadian and US policy makers, the gross nameplate rating of 75 MVA may undermine and deter the
future potential of integrating Distributed Generations (DG’s) that will be implemented to ensure the reliable
operation of the interconnected transmission network BES, and, at the same time, providing the most
effective and economical solutions for rate payers. Local generation can cost-effectively enhance the
reliability of load pocket by avoiding transmission, but such restrictions would deter the adoption of good
planning decisions.Path to generating facilities need not be BES contiguous. Generating units can be required
to be planned, designed, and operated in accordance with a subset of NERC Standards, but should not
require contiguous BES paths.

Response: The SDT carefully debated the generating threshold for this inclusion in the definition. After consulting with the NERC Board of Trustees and the
NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or
resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and
743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed
the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds
as well as several other issues that have arisen from SDT deliberations.
The definition for this inclusion only addresses BES contiguity from the generator leads through the step up transformer(s) connected on the high side at a
voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to the BES.

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Santee Cooper

No

We recommend that it say "Single generating units located at a single site with a capacity of greater than or
equal to 100 MVA". The use of aggregate capacity greater than 75 MVA pulls in some very small units.

Idaho Falls Power

No

Again, following our statement in question 3, we feel an arbitrary brightline threshold requires additional
defining criteria for inclusion.Adopting the registry's brightline criteria is to us skirting the purpose of the BES
definition effort, and lends no more clarity to what is in fact the BES.

Tennessee Valley Authority

No

Other than the NERC Registry Criteria definition, what is the technical justification for the 75 MVA threshold?
The threshold level for inclusion should be technically based on the BES capacity and configuration at the
location of the generating sources’ connection to the BES.

Western Montana Electric
Generating and Transmission
Cooperative

No

WMG&T is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn from
the NERC Statement of Compliance Registry without appreciation for the function of the threshold in that
document and without adequate technical justification demonstrating the generators with an aggregate
capacity of 75 MVA produce electric energy “needed to maintain transmission system reliability” and are
therefore properly included in the BES definition.

New York State Reliability
Council

No

The use of a 75 MVA threshold based on NERC's Registry Criteria may be administratively convenient but is
arbitrary when based upon BES reliability considerations. Suggest use of a 300 MW or other regionally and
technically acceptable threshold such as NPCC's A-10 criterion.

Intellibind

No

Though as previously stated I do not think that the 20 MVA threshold has technical merit, I do not believe that
the 75MVA limit has technical merit either. Further the impact should be measured at the buss bar not at the
nameplate. The aggregate rating should be the same as the individual unit rating on a single plant, unless the
plant can prove that there is not a common failure mode to lose more than 20MVA.

Public Utility District No. 1 of

No

Snohomish is concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn from

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Snohomish County, Washington

Blachly Lane Electric Cooperative
Northern Wasco County PUD
Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc.

Question 4 Comment
the NERC Statement of Compliance Registry without appreciation for the function of the threshold in that
document and without adequate technical justification demonstrating the generators with an aggregate
capacity of 75 MVA produce electric energy “needed to maintain transmission system reliability” and are
therefore properly included in the BES definition.

No

We are concerned that the 75 MVA threshold has been chosen arbitrarily by the SDT. Like the 20 MVA
threshold discussed in our response to question 3, the 75 MVA threshold appears to have been drawn from
the NERC Statement of Compliance Registry without appreciation for the function of the threshold in that
document and without adequate technical justification demonstrating the generators with an aggregate
capacity of 75 MVA produce electric energy “needed to maintain transmission system reliability” and are
therefore properly included in the BES definition. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements.

Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Northern Lights Inc
Okanogan Electric Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Clallam County PUD No.1
Chelan PUD – CHPD
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Northwest Requirements Utilities

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment

Big Bend Electric Cooperative,
Inc.
Cowlitz County PUD
Utility System Efficiencies, Inc
Coos-Curry Electric Cooperative

No

Specific language change: Change 75 MVA to 100 MVAWe are concerned that the 75 MVA threshold has
been chosen arbitrarily by the SDT. Like the 20 MVA threshold discussed in our response to question 3, the
75 MVA threshold appears to have been drawn from the NERC Statement of Compliance Registry without
appreciation for the function of the threshold in that document and without adequate technical justification
demonstrating the generators with an aggregate capacity of 75 MVA produce electric energy “needed to
maintain transmission system reliability” and are therefore properly included in the BES definition. The 100
MVA threshold seems more in alignment with technical standards such as Power System Stabilizer
requirements.

City of St. George

No

It is understood that this mirrors the Registry Criteria and this is a simple way to address the issue. The
justification states there is no technical rationale to change the 75 MVA threshold, however the technical
rationale for the 75 MVA criteria has not been provided either. Having a 75 MVA plant treated the same as a
plant with a rating of several hundred or several thousand MVA doesn’t make sense either. The requirements
for an entity or facility should match the impact of that facility to the system.

Clark Public Utilities

No

Generators should only be part of the Bulk Electric System if they are connected through a GSU to a
Transmission Element determined to be part of the BES. The current inclusion language would apply to all
generators connected to facilities greater the 100 kV with no exclusion or exception process. Without a
change, it appears that a generator connected to a facility greater than 100 kV would be a BES asset even if
the transmission assets could be excluded or excepted. I3 should be rewritten to state: Multiple generating
units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
including the generator terminals through the GSUs, connected through a common bus to a Transmission
Element determined to be part of the Bulk Electric System.

Lost River Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative

Additionally, as indicated by Clark in its comments on the core definition of the BES, Clark believes the 75
MVA threshold lacks an adequate technical justification and is a purely arbitrary quantity. The use of a
capacity threshold in the definition of the BES should have technical reasons.
New England States Committee
on Electricity

August 19, 2011

No

Please refer to comments under 3 above. Additionally, regardless of the connection voltage, the 75 MVA limit
may unintentionally impose unnecessary added costs to renewable generation, thus inhibiting the
development of these resources. This is of particular concern to New England, which has aggressive

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 4 Comment
renewable energy objectives and is working to develop resources in and around the region to meet them in
the most cost-effective way. Looking forward, the exception process should provide criteria allowing flexibility
as to the aggregate MVA rating as related to the specific connection and impact on a region. This will be
discussed further in comments on the Exception Process as appropriate.

Consolidated Edison Co. of NY,
Inc.

No

The inclusion of generation to the BES should be subject to an impact test.‬

Orange and Rockland Utilities,
Inc.

No

XI3 should pertain to multiple generating units impact to the Bulk system, rather than the size unit only.
Oftentimes there are cases when neither the path nor a 75 MVA unit itself will have any impact on the
reliability of the interconnected transmission network, nor is it necessary for its operation.

City of Redding

Yes

As stated in question #3 above, in concept Redding is in agreement that the Brightline should specify
generation facilities at a certain level, however we believe the SDT has no technical basis to choose the 75
MVA threshold. If the SDT elects to retain I3 in its current form then Redding suggests changing the generation
level from 75 MVA to 200 MVA. If the goal of the Brightline Definition is to create a starting point to identify
power system elements that are “necessary” then the SDT should choose a larger generation threshold as a
starting point. The 200 MVA would serve a better purpose by casting the burden of proof (via the Exception
Process) from the smaller facilities under 200 MVA to the Regional Entity. This would help the SDT to achieve
an objective of reducing the burden on the “small entity” and “distribution” facilities due that fact that most
generator facilities of this size are installed to serve local loads.
In summary, Redding supports the concept that the brightline as an initial dividing line of elements to be
labeled as BES. Therefore, Redding suggests that the SDT change the language in I3:
From: “Multiple generating units located at a single site with aggregated capacity greater than 75 MVA (gross
nameplate rating) including the generator terminals through the GSUs, connected through a common buss
operated at a voltage of 100 kV or above”.
To: Multiple generating units located at a single site with aggregated capacity greater than 200 MVA (gross
nameplate rating) including the generator terminals through the GSUs, connected through a common bus
operated at a voltage of 100 kV or above”.

Response: The SDT has not received sufficient technical justification upon which to base a departure from the generation threshold included in the ERO’s
Statement of Compliance Registry Criteria.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the

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Organization

Yes or No

Question 4 Comment

high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
The SDT recommends that entities use the NERC Rules of Procedure process for obtaining exceptions to the BES Definition as needed. No change made.
NERC Staff Technical Review

No

>>>The interconnection voltage threshold should be removed. The contribution of a multiple generating units
at a single site to system reliability is a function of the aggregate MVA rating rather than the interconnection
voltage. All locations with multiple generating units with aggregate capacity greater than 75 MVA should be
included in the BES definition because all such units provide similar contributions to system reliability.
>>>>>>>>>>
As noted in the comment on Question 3 of this comment request, the specific inclusion of the GSU
transformer implies that all other components of a generating unit, such as its unit auxiliary transformer, startup transformer, governor, exciter, power system stabilizer, etc., are excluded. The SDT should define
“generating unit” or otherwise clarify which components of a generating unit are included in the BES definition.
>>>>>>>>>>
The use of the term “common bus” introduces ambiguity into the definition. It would be better to replace the
phrase “connected through a common bus” with the phrase “connected through a common point of
interconnection” which also provides consistency with the description of Inclusion I5.

Response: NERC Staff has not provided technical justification for requiring the inclusion of all generating resources greater than 75MVA no matter the
interconnecting voltage.
The SDT believes that “generating unit” (now expressed as “generating resources”) does not need further clarification. The SDT believes that specific
requirements for generation support equipment and functions should be addressed by specific NERC standards. The goal of the SDT is to provide clarity to the
BES Definition and not to address reliability standards applicability.
The SDT agrees that using the “common bus” term is problematic. The revised definition should resolve this concern.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
NERC Transmission Issues
Subcommittee (TIS)

No

The use of the term “common bus” technically has a very specific meaning and would openly exclude most
modes of connection. There is no “common bus” in a ring-bus or a breaker-and-one-half configuration. Also,
it is not necessary to include the GSU (s), as commented in 3 above. >>>>>>>>>>
The TIS suggests using wording similar to that contained in I5: >>>>>>>>>>“I3 - Multiple generating units

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Yes or No

Question 4 Comment
located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
connected through a common bus operated at a common point of interconnection to a system Element at a
voltage of 100 kV or above.”

Response: The SDT has eliminated term “common bus”. The SDT believes that the revised proposed definition is an improvement.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Dominion

No

As stated in its response to Question 2 above, Dominion disagrees that a generation resource, Element or
Facility should automatically be included in the BES. Dominion agrees that the Generator Owner and
Generator Operator, as users of the bulk power system, should have to abide by applicable reliability
standards, but do not agree that this should automatically require the inclusion of a generation resource,
Element or Facility in the BES.
Further, Dominion prefers that the SDT use the term “generation resources” as stated in the current BES
definition contained in the Glossary of Terms, instead of the proposed term “generation unit”

Response: The SDT agrees and has proposed the term “generating resources” for clarity.
The SDT scope was determined by the language contained in Order Nos. 743 & 743a in which the Commission provided guidance to the ERO to clarify the
definition for continent-wide application. The Commission did not propose significant changes to the current application of the existing definition over the majority
of the continent. Therefore the SDT has developed a draft core definition, together with BES designations (Inclusions and Exclusions) that provide the specificity
necessary to identify the vast majority of BES Elements by utilizing the existing definition and criteria previously approved for this purpose. After consulting with
the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time.
There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to
address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the
NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization
Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.

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Organization
MRO's NERC Standards Review
Forum

Yes or No

Question 4 Comment

No

The wording “connected through a common bus” is drawn from the NERC Compliance Registry Criteria.
NSRF agrees with the language if the intent is to let entities classify the applicable multiple generating units
as part of the BES only when it is connected to one (common) bus. However, if the intent is for entities to also
classify multiple generation as part of the BES when it is connected through two or more GSUs to different
bus sections of a set of (common) buses that are interconnected through bus-tie breakers [which may be
done to provide improved reliability and maintenance flexibility], then wording like “connected through a
common bus or set of interconnected buses” would be more appropriate.
It is the NSRF’s understanding that entities do not have to classify applicable multiple generating units as part
of the BES when the aggregate MVA is connected to different buses at different voltage levels and no more
than 75 MVA is connected to any one bus (or set of interconnected buses) at a single voltage level of 100 kV
or more. Is this a correct interpretation?

American Transmission
Company, LLC

No

ATC offers the following alternative language: o The wording “connected through a common bus” is drawn
from the NERC Compliance Registry Criteria. ATC agrees with the language if the intent is to let entities
classify the applicable multiple generating units as part of the BES only when it is connected to one (common)
bus. However, if the intent is for entities to also classify multiple generation as part of the BES when it is
connected through two or more GSUs to different bus sections of a set of (common) buses that are
interconnected through bus-tie breakers [which may be done to provide improved reliability and maintenance
flexibility], then wording like “connected through a common bus or set of interconnected buses” would be
more appropriate.
o It is also ATC’s understanding that entities do not have to classify applicable multiple generating units as
part of the BES when the aggregate MVA is connected to different buses at different voltage levels and no
more than 75 MVA is connected to any one bus (or set of interconnected buses) at a single voltage level of
100 kV or more. Is this a correct interpretation?

Response: The SDT has eliminated the term “through a common bus”. The SDT believes that the revised proposal should be an improvement. The SDT also
believes that this inclusion is in conformance with the generation plant 75 MVA threshold in the NERC Statement of Compliance Registry Criteria, which has not
needed clarification to date.
The SDT cannot address each and every unique situation related to the connection of generation resources. More information would be needed before this
question could be answered. For individual situations, entities may seek exception by using the NERC Rules of Procedure (RoP) exception process to present
relevant evidence.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross

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Yes or No

Question 4 Comment

aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
SERC OC Standards Review
Group

No

“Multiple generating units located at a single site with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) including the generator terminals through the GSUs, connected through a
common bus operated at a voltage of 100 kV or above.”
GSUs need to be defined - see response to question 3 above.

Response: This inclusion has been clarified using the term step up transformer(s) rather than GSU.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Hydro One Networks Inc
FortisBC

No

We agree with the concept of Inclusion I3 with respect to multiple generating units located at a single site, but
do not support that the entire contiguous path has to be BES. The path of a 75 MVA plant or aggregated
generation will rarely have any impact on the reliability of the interconnected transmission network nor is it
necessary for its operation. We also do not support the fact that there should be a blanket application of this
inclusion.As stated earlier, under various green energy, smart grid and dispersed renewable energy plans
advocated by both Canadian and US policy makers, the gross nameplate rating of 75 MVA may undermine
and deter the future potential of integrating Distributed Generations (DG’s) that will be implemented to ensure
the reliable operation of the interconnected transmission network BES, and, at the same time, providing the
most effective and economical solutions for the rate payers in North America. Local generation can costeffectively enhance the reliability of load pocket by avoiding transmission, but such restrictions would deter
the adoption of good planning decisions.Upcoming load displacement projects would result in the installation
of new self-generation facilities at customer sites, with the electricity generated being used on-site by the
customer, with a resultant decrease in the consumption of electricity purchased via large scale generation.
These projects can be large, and displace a substantial portion of the customer’s (or local distribution
company’s) existing load, even to the extent of total self-sufficiency and the availability of surplus generation.
The aggregated surplus generation capacity may very well exceed 75 MVA and would consequently force the
facility owners to register as both Generation Owners (GO) and Transmission Owners (TO), which may be in
conflict with regulatory rules in many jurisdictions.
We suggest the following:
o Generation restriction (75 MVA) should either be revised or the exception procedure should allow entities,

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Yes or No

Question 4 Comment
with the support of technical evidence, to exclude element(s) being labeled as part of BES.
o Path to generating facilities need not be BES contiguous unless the unit is identified essential for the
operation of transmission network. Generating units can be required to be planned, designed, and operated in
accordance with a subset of NERC Standards, but should not require contiguous paths.
o Entities should be able to use the exception process, with the help of technical evidence, to exclude
generating units that do not impact the interconnected grid and the bulk transfer of power.
o From a regulatory perspective such an inclusion could also be in conflict with the current regulatory
requirements. Definition and/or exception process should provide acknowledgement and flexibility to avoid
any regulatory conflicts. For example, as stated earlier (Q3 response) NERC and SDT should consider
introducing a concept of a new category of registration or BES Support elements. These elements are NOT
necessarily BES but support the reliable operation of the interconnected transmission network.

Response: The definition for this inclusion only addresses BES contiguity from the generator leads through the step up transformer(s).
The SDT has not received sufficient technical justification upon which to base a departure from the generation plant 75 MVA threshold included in the ERO’s
Statement of Compliance Registry Criteria. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo
any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will
be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach
to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations.
The SDT recommends that entities use the NERC Rules of Procedure exception process for obtaining exceptions to the BES Definition.
With respect to the regulatory issue raised, the revised definition should resolve this concern.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Electricity Consumers Resource
Council (ELCON)

No

Same response as item 3 above.

Response: See response to Q3.

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Yes or No

Question 4 Comment

Electric Reliability Council of
Texas, Inc.

No

See response to question 3 - ERCOT ISO agrees with substance, but not the approach.

Fayetteville Public Works
Commission

No

The same comment made in Question 3 and applicable to Inclusion I2 is also applicable to Inclusion I3.

American Electric Power

No

Please see response to question 3.

Southern California Edison
Company

No

Please refer to SCE’s answer for Question No. 3 above.

SPP Standards Review Group

No

The comment provided for Question 3 above applies here also.

Pepco Holdings Inc

Clarification needed: Same situation as described in #3 above.

Southwest Power Pool

Yes

Please see SPP's response to question 3 - SPP agrees with substance, but not the approach.

Michgan Public Power Agency

Yes

See comments to question 3

No

We believe that automatic inclusion of 75 MVA generation and the path to connect them to the BES should
not be automatically included in the BES.

Response: See response to Q3.
Hydro-Quebec TransEnergie

However, a provision should be made so that some reliability standards related to generator shall apply
(voltage regulation, etc.).
Response: The definition for this inclusion only addresses BES contiguity from the generator leads through the step up transformer(s) which is connected on
the high side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service
(generation) to the BES.
The SDT believes that NERC Reliability Standards may be applied to specific generator support elements (e.g., voltage regulation) that are necessary to operate
the interconnected transmission network. The goal of the SDT is to provide clarity to the BES Definition and not to address Reliability Standards applicability.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross

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Yes or No

Question 4 Comment

aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Vermont Transco

No

What is the definition of “common bus”?
Would this only apply to generating facilities with a direct GSU tie to the 100 kV, and up, system?
Or would it apply to those units tied to the low side of a transformer at a voltage below 100 kV that has a step
up high side voltage greater than 100 KV? Example: units are tied through to a single 46 kV substation (GSU
high side connected to this substation) with a tie from this substation to the BES through a step up
transformer.

Response: The SDT has eliminated the term “common bus”.
The SDT cannot address each and every unique situation related to the connection of generation resources. More information would be needed before this
question could be answered. For individual situations, entities may seek exception by using the NERC Rules of Procedure (RoP) exception process to present
relevant evidence.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Sweeny Cogeneration LP

No

The threshold for multiple generation units aggregated at a single location is consistent with the NERC
functional registry criterion. We believes that it is important to maintain this uniformity. However, we believe
there are further items to be added to the list related to generator interconnections, a task that was passed to
this project from Project 2010-07. Just as is the case with complex distribution systems, there are a variety of
generator-transmission interconnection architectures which are driving the Regions to inappropriately register
Generator Owner/Operators as Transmission Owners.

Response: More information would be needed before the concern can be answered. No change made.
Muscatine Power and Water

August 19, 2011

No

The phrase “connected through a common bus” is taken from the NERC Compliance Registry Criteria.
MP&W would agree with this language if the intent is to let entities categorize the applicable multiple
generating units as part of the BES only when it is connected to one (common) bus. However, if the intent is
for entities to also classify multiple generation as part of the BES when it is connected through two or more
GSUs to different bus sections of a set of (common) buses that are interconnected through bus-tie breakers

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Question 4 Comment
(which may be done to provide improved reliability and maintenance flexibility), then using language like
“connected through a common bus or set of interconnected buses” would be more appropriate.

Response: The SDT believes the term “through a common bus” is problematic and the revised proposal should resolve this concern.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Springfield Utility Board

No

While Springfield Utility Board does not own any generating units, we do recognize the importance of the
restoration of the Grid, and the generation necessary for the Grid. SUB would recommend that NERC clearly
define “location” and “single site”. Does single site mean interstate service area location (adding up
generation over multiple geographically separate areas), same City?, same common bus?, etc... SUB
suggests that for purposes of I3 (and other inclusions and exclusions that reference “same site”, “same
location”, or similar language) that the term “collectively share a common bus” be used.

Springfield Utility Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: The SDT believes that “single site” is in agreement with the ERO Statement of Compliance Registry Criteria (SCRC) threshold for including greater
than 75 MVA generating plants/plants. Because this SCRC criterion has not been problematic to date, the SDT does not believe that “single site” needs to be
further clarified.

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Organization

Yes or No

Question 4 Comment

The SDT has not received sufficient technical justification to exclude load modifying or backup generation plants as described from the BES Definition. No
changes made.
Public Utilities Commission of
Ohio

No

New York State Dept of Public
Service

This should be expanded to also refer to individual generation capacity, as well as aggregate, at 75 MVA and
above.
I3 should be revised to read all generation - individually or aggregate - 75 MVA and above.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Cogentrix Energy, LLC

No

GSUs need to be defined - see response to question 3 above

Response: This inclusion has been clarified to use the term step up transformer(s) rather than GSU.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
The Dow Chemical Company

No

It should be clarified that Exclusion E2 over-rides this Inclusion. See ELCON comments.

ExxonMobil Research and
Engineering

Yes

Support is contingent on the continued exclusion of generation based on its net capacity provided to the BES.

Response: The SDT agrees that Exclusion E2 should over-ride this inclusion. The revised language in Exclusion E2 should address these concerns.

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PJM

Yes or No
No

Question 4 Comment
As written I3 implies a contiguous system from the unit to a “common bus operated at a voltage above 100
kV” there is no technical justification for a contiguous system. The requirement should read “Multiple
generating units located at a single site with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) including the generator terminals through the GSU”

Response: The SDT’s revised proposal should address this concern. The definition for this inclusion only addresses BES contiguity from the generator leads
through the step up transformer(s).
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Oncor Electric Delivery Company
LLC

No

The ERCOT Region already considers load in any combination equal to and over 20 MVA through a single
Point of Interconnect as part of the BES

Response: The definition does not preclude more restrictive local requirements.
PPL Energy Plus and PPL
Generation

No

See comments in Question 13

Illinois Municipal Electric Agency

Yes

Please see comments under Question 13.

No

It is not clear if this inclusion only applies if the generators at a single site have an aggregate capacity greater
than 75 MVA AND are connected through a common bus operated at 100kV or if the inclusion applies if the
generators at a single site have an aggregate capacity of over 75MVA regardless of whether or not they are
connected through a common bus operated at 100kV or above. For example, would this inclusion apply if a
utility has over 75MVA at single generating site but only a small portion of the generating capacity is
connected through the GSU to a common bus at 100kV or above and the rest is connected through a
common bus operating at less than 100kV? Suggested wording: “Multiple generating units located at a single
site connected to a common bus operated at a voltage of 100kV or above with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) including the generator terminals through the GSUs.

Response: See response to Q13.
Manitoba Hydro

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Yes or No

Question 4 Comment

Response: The SDT’s revised proposal should be understood to mean that all applicable generating resources at a single site, their generator terminals,
connecting cabling up to and including their step up transformer(s) that are connected at 100kV or greater will be included in the definition of the BES.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Independent Electricity System
Operator

No

See our responses to Q1 and Q3.

No

We agree with the concept of Inclusion I3 with respect to multiple generating units located at a single site, but
do not support that the entire contiguous path has to be BES. The path of a 75 MVA plant or aggregated
generation will rarely have any impact on the reliability of the interconnected transmission network nor is it
necessary for its operation.

Response: See responses to Q1 & Q3.
AltaLink

Generation restriction (75 MVA) should either be revised or the exception procedure should allow entities,
with the support of technical evidence, to exclude element(s) being labeled as part of BES. Path to generating
facilities need not be BES contiguous. Generating units can be required to be planned, designed, and
operated in accordance with a subset of NERC Standards, but should not require contiguous paths.
Response: The definition for this inclusion only addresses BES contiguity from the generator leads through the step up transformer(s) connected on the high
side at a voltage of 100 kV or above. This establishes contiguity of the generation facility and provides for the highest level of reliable service (generation) to the
BES.
The SDT has not received sufficient technical justification upon which to base a departure from the generation plant threshold included in the ERO’s Statement of
Compliance Registry Criteria. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at
changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the
primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped.
Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this
project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations.
The SDT recommends that entities use the NERC Rules of Procedure exception process for obtaining exceptions to the BES Definition.

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Organization

Yes or No

Question 4 Comment

Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
BPA

No

BPA suggest defining “single site.” BPA is assuming that a “single site is a single substation with aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating) including the generator terminals through
the GSUs, connected through a common bus operated at a voltage of 100 kV or above. BPA would also like
this to be consistent with Inclusion #2 and state: a high side voltage of 100 kV or above.

Response: The SDT believes that “single site” is in agreement with the ERO Statement of Compliance Registry Criteria (SCRC) threshold. Because this SCRC
criterion has not been problematic to date, the SDT does not believe that “single site” needs to be defined. No change made.
Portland General Electric
Company

The 75 MVA aggregate capacity rating threshold could result in the inclusionin the BES of generating units
that have no potential to impact the reliability of the BES.The 75 MVA threshold was taken from the
registration criteria, and no technicaljustification has been provided for its use.
In addition, the meaning of the phrase”located at a single site” is unclear and subject to multiple
interpretations. The phrase”connected through a common bus” accomplishes the same goal, and therefore
thephrase “located at a single site” hould be removed.

Response: The SDT has not received sufficient technical justification upon which to base a departure from the generation plant threshold included in the ERO’s
Statement of Compliance Registry Criteria. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo
any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will
be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach
to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations.
The SDT believes that the term “single site” is agreement with the ERO Statement of Compliance Registry Criteria (SCRC) threshold. Because this SCRC criterion
has not been problematic to date, the SDT does not believe that “single site” needs further clarification. No changes made.
Tacoma Power

Tacoma Power generally supports Inclusion I3. However, the term ‘gross aggregate nameplate rating’ is not
defined and should be replaced with a specific definition.
Additionally, no justification for the 75 MVA level has been provided and therefore it appears arbitrary. Since
this measurement will define Elements for absolute inclusion in the BES, the threshold for multiple generation

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Organization

Yes or No

Question 4 Comment
units located at a single site should be based on a need to maintain transmission reliability. Such single sites
located within a Local Distribution Network (LDN), which do not exit the LDN, should not be included. We
propose changing Inclusion I3 to read, “Multiple generating units located at a single site with an aggregate
capacity greater than 75 MVA (aggregate capacity based on the Code of Federal Regulation, CFR 18, Part
287.1, “Determination of powerplant design capacity”) including the generator terminals through the GSUs,
connected through a common bus operated at a voltage of 100 kV or above, except multiple generating units
located at a single site that are within a Local Distribution Network (LDN) and do not have a net export out of
the LDN.”

Response: The SDT feels that the term “gross nameplate rating” is a widely used term within the industry and does not require additional defining.
The SDT has not received sufficient technical justification upon which to base a departure from the generation plant threshold included in the ERO’s Statement of
Compliance Registry Criteria. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt
at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the
primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped.
Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this
project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations.
American Municipal Power and
Members

Yes

I3 contains language similar to I2, and should be similarly reworded, as follows: “Multiple generating units
located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating),
connected through a common bus operated at a voltage of 100 kV or above. A BES generating plant
includes the equipment from the generator terminals through the respective GSUs.”

Transmission Access Policy
Study Group

Yes

I3 contains language similar to I2, and should be similarly reworded, as follows: “Multiple generating units
located at a single site with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating),
connected through a common bus operated at a voltage of 100 kV or above. A BES generating plant
includes the equipment from the generator terminals through the respective GSUs.”

Northern California Power
Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.

Florida Municipal Power Agency

Response: The SDT agrees that BES contiguity for this inclusion is limited to the generator leads through the step up transformer(s). However, the SDT believes
the last sentence in the comment is not needed for clarification.

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Organization

Yes or No

Question 4 Comment

Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Western Electricity Coordinating
Council

Yes

WECC agrees in concept, but suggests that the phrase “connected through a common bus” may be unclear.
For example, if there is also load connected through that common bus, does that net, does it negate the
inclusion, or does it not matter? Perhaps a phrase such as “regardless of the amount of load also connected
through that common bus” would help. The GSU comment from I2 also applies. Suggested language
“...including the generator terminals up to and including the GSU transformer, which has a high-side voltage
of 100 kV or above.”

Response: The SDT eliminated the term “common bus”.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Central Maine Power Company

Yes

New York State Electric & Gas
and Rochester Gas & Electric

Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is MVA instead of
MW.

Response: The ERO Statement of Compliance Registry Criteria uses MVA units (not MW units) for both generator unit and generation plant capacities. No
change made.
PacifiCorp

Response:

Yes

PacifiCorp understands the SDT is looking for technical reasons for something other than 75 MVA. PacifiCorp
believes it is not feasible to determine a value that is consistent across the continent. Although PacifiCorp
believes 75 MVA is too low, it is an acceptable number for any configuration of generation (see comment on
question 3). Those above 75 MVA believed to be exempt from the BES definition can be processed through
the proposed ROP inclusion/exclusion process.PacifiCorp submits the following suggested wording for I3:
“Multiple generating units with an aggregate capacity greater than 75 MVA or a single generating unit with a
generating capacity greater than 75 MVA.....”

Stakeholder comments have not provided technical justification by which to base a departure from the 75 MVA threshold where connected at 100

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Organization

Yes or No

Question 4 Comment

kV and above. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Alberta Electric System Operator

Yes

Consider adding the word “transformer” after “GSU”.

Response: The SDT agrees and has replaced GSU with the term “step-up transformer(s)”.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Idaho Power

Yes

Generally agreed but please revise to inlcude I2, I3 and I5 at 75 MVA, see Question 3 and 6 comments.

Long Island Power Authority

Yes

We recommend clarifying that I3 only covers units under 20 MVA and that the aggregation similarly just
applies to those units that are under 20MVA. Example: a 100 MVA generating unit and a 15 MVA generating
unit at a single site only the 100 MVA generating unit would be BES per Inclusion I2 but Inclusion I3 would not
apply.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Inclusion I2 was eliminated and rolled into the old Inclusion I3, which will be referenced as Inclusion I2 moving forward. This inclusion was reworded as follows:
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross

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Organization

Yes or No

Question 4 Comment

aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Central Lincoln

Yes

Please indicate how aggregate generation below 75 MVA is to be treated, since we don’t believe the flowchart
at http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly expresses the SDT’s
intent to classify these small plants as non-BES.

Response: The BES Rule of Procedure team has been made aware of this.
Sacramento Municipal Utility
District (SMUD)

Yes

SMUD also agrees with the Inclusion 3 concept.

Sierra Pacific Power Co d/b/a NV
Energy

Yes

While 75MVA has no technical basis for the threshold above which an aggregate generation plant should be
considered to be necessary for the reliable operation of an interconnected transmission network, the industry
has not provided any technical data to support a value other than this which has been established in the
NERC Statement of Compliance Registry Criteria.

PUD No. 2 of Grant County,
Washington

Yes

Grant supports this proposed inclusion.

Public Service Enterprise Group
LLC

Yes

Tri-State Generation and
Transmission Association, Inc.

Yes

Imperial Irrigation District

Yes

SERC Planning Standards
Subcommittee

Yes

ACES Power Participating
Members

Yes

National Rural Electric
Cooperative Association

Yes

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Organization

Yes or No

Question 4 Comment

(NRECA)
Overton Power District No. 5

Yes

Arizona Public Service Company

Yes

ReliabilityFirst

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

New York Power Authority

Yes

Southern Company

Yes

Luminant Energy

Yes

Western Area Power
Administration

Yes

US Bureau of Reclamation

Yes

Grand Haven Board of Light and
Power

Yes

Glacier Electric Cooperative

Yes

FHEC

Yes

South Texas Electric
Cooperative, Inc.

Yes

National Grid

Yes

Dayton Power and Light

Yes

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Organization

Yes or No

Question 4 Comment

Company
Duke Energy

Yes

South Carolina Electric and Gas

Yes

MidAmerican Energy Company

Yes

Florida Keys Electric Cooperative

Yes

East Kentucky Power
Cooperative, Inc.

Yes

Farmington Electric Utility System

Yes

Colorado Springs Utilities

Yes

Consumers Energy Company

Yes

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

Yes

Exelon

Yes

Puget Sound Energy

Yes

GTC

Yes

ISO New England, Inc.

Yes

City of Anaheim

Yes

August 19, 2011

No comment.

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Organization

Yes or No

MEAG Power

Yes

Xcel Energy

Yes

Golden Spread Electric
Cooperative, Inc.

Yes

Question 4 Comment

Response: Thank you for your support. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo
any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will
be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach
to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations. Please see the revised definition.

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5. The SDT has added specific inclusions to the core definition in response to industry comments. Do you agree
with Inclusion I4? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often
composed of distribution system elements. In addition, the Transmission Operator’s actual restoration may make use of paths that were not
identified as Cranking Paths in the restoration plan due to the particular system configuration on the day in question. Therefore, the SDT has
removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise
its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission
network. The SDT interprets this to include operation under both normal and Emergency conditions, which include situations related to
blackstarts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be energized
without connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for Real and
Reactive Power capability, frequency, and voltage control. The associated resources of the electric system that can be isolated and then
energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating units as
defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources
indentified in the Transmission Operator’s restoration plan as BES Elements.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules
of Procedure exception process to request including it in the BES.
Inclusion I4 has been re-numbered as Inclusion I3 and revised as follows:
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of
voltage.

Organization

Yes or No

Question 5 Comment

Public Service Enterprise Group
LLC

No

Black start resources and the cranking path should not be included in the BES definition unless connected at
100kV and above. There are many other existing standards that impact black start units. Routine testing and
redundancy is part of them. Adding in black start units < 100kV and the associated cranking path to the BES
definition may discourage entities from providing black start capability due to cost associated with cumulative
testing and record keeping criteria. This may result in withdrawing the offer to provide that service and/or
potentially drive up the cost of that service significantly without any related increase in BES reliability.

ACES Power Participating

No

Blackstart resources are rarely used. For many reasons, restoration almost always starts with synchronizing

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Organization

Yes or No

Members

Western Montana Electric
Generating and Transmission
Cooperative
Public Utility District No. 1 of
Snohomish County, Washington

Question 5 Comment
to other systems (the Interconnection) that are already intact. Because Blackstart Resources can actually be
on the distribution system, the distribution system can then become subject to the enforceable standards.
This results in significant increased costs in tracking compliance for these distribution systems without a
commensurate increase in reliability. Because a Blackstart Resource must be included in the Transmission
Operator’s restoration plan, this creates a perverse incentive to un-designate the Blackstart Resource that is
on a distribution system to avoid the distribution system becoming part of the Bulk Electric.

Yes

Including “all” blackstart and blackstart cranking paths in the BES may ultimately provide an incentive to the
electric industry to reduce the number of resources with blackstart capability. We therefore suggest that
essential blackstart resources identified by the Regional Entity should be included in the Bulk Electric System,
but non-essential blackstart resources need not be.

Northern Wasco County PUD
Clallam County PUD No.1
Chelan PUD – CHPD
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc.
Cowlitz County PUD
Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system elements. In
addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking Paths in the restoration plan due to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES definition to
ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this to include
operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources have the
ability to be started without support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the electric system

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Organization

Yes or No

Question 5 Comment

that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating
units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the
Transmission Operator’s restoration plan as BES Elements.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
Transmission Operators are responsible for maintaining a viable, reliable restoration plan, regardless of the BES definition; the SDT does not agree that adding
Blackstart Resources to the BES definition alone would “discourage entities from providing Blackstart capability.”
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Northeast Power Coordinating
Council

August 19, 2011

No

Blackstart resources and transmission facilities on the cranking path should not be classified as BES
regardless of size and voltage level. From a regulatory perspective, such an inclusion would be in conflict with
the current regulatory requirements in many jurisdictions. More importantly, designating these facilities as
BES Elements or Facilities beyond the 100 kV bright line, the 20 MVA/unit or 75 MVA/plant criteria, without a
regard to their impact on the BES (under conditions other than system restoration) will impose unnecessary
requirements for these facilities, which do not contribute to reliability under interconnected operation
conditions. For a restoration condition, this inclusion is extraneous. There is already a designation specific for
system restoration covered by an existing standard to recognize their reliability impacts and to ensure their
expected performance. NERC Standards EOP-005-2 stipulates the requirements for testing blackstart
resource and cranking paths. This testing requirement suffices to ensure that the facilities critical to system
restoration are functional when needed, which meets the intent of identifying their criticality to reliability.The
BES definition should cover those facilities that are needed for operation under both normal and emergency
conditions, which includes situations related to blackstart and system restoration. The directives should not
specifically ask for inclusion of blackstart resources and facilities on the cranking path in the BES definition.
The requirements in EOP-005-2 suffice to address the SDT’s interpretation and concern regarding recognition
of the reliability impacts and requirements for blackstart resources and facilities used for system
restoration.Generating units of any size and transmission facilities of any voltage level may be used for black
start and restoration. Conceivably, a generator of 10 MW and transmission or distribution facilities of 44 kV or
69 kV may be a part of the cranking path. A BES inclusion will then subject these generators and facilities,
which are essentially “local” facilities but called upon to begin restoring its bulk interconnected counterparts, to
comply with the reliability standards intended for maintaining BES reliability. Included in the BES definition will
thus discourage smaller generators from providing black start capability, and the transmission facilities from
being a part of the cranking path. This may also discourage Transmission Owners and Operators from
identifying multiple black start resources and cranking paths to provide restoration flexibility. Such an inclusion
will ultimately undermine reliability.If indeed any of these facilities are deemed necessary to support bulk
power system reliability at times other than system restoration, they would/should have been identified

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Organization

Yes or No

Question 5 Comment
through the basic BES definition and inclusion list or can be addressed through the exception procedure.
I4 should be removed based upon: o The availability and performance expectations of blackstart resources
and facilities on the cranking path are already specifically addressed in an existing standard; and o Unless
they meet the BES definition and the other inclusion criteria, they do not have any perceived reliability impact
on everyday operation of the BES.
o I4 may include very small generators and distribution facilities as it is written. Is it necessary from a
reliability point of view to include “cranking paths” below 100kV?

American Municipal Power and
Members

No

We recommend that the SDT exclude Blackstart Units under 20MW and Blackstart Units that are connected
via their GSU to Non-BES Facilities (under 100kV). We believe this would be a minimal impact on the
existing Restoration Plans while increasing the reliability and viability of these Restoration Plans since the
industry would be forced to use only BES facilities as defined by NERC BES definition. This would force all
Blackstart Units to be compliance with all Reliability Standards if this change is implemented.

Hydro One Networks Inc

No

We do not agree with Inclusion I4. Blackstart resources and transmission facilities on the cranking path
should not be classified as BES regardless of size and voltage level. From a regulatory perspective, such an
inclusion would be in conflict with the current regulatory requirements in many of the jurisdictions. More
importantly, designating these facilities as BES Elements or Facilities beyond the 100 kV bright line, the 20
MVA/unit or 75 MVA/plant criteria, without a regard to their impact on the BES (under conditions other than
system restoration) will impose unnecessary requirements for these facilities, which do not contribute to
reliability under interconnected operation conditions. For restoration condition, this inclusion is extraneous
given there is already a designation specific for system restoration covered by an existing standard to
recognize their reliability impacts and to ensure their expected performance. NERC Standards EOP-005-2
stipulates the requirements for testing blackstart resource and cranking paths. This testing requirement
suffices to ensure that the facilities critical to system restoration are functional when needed, which meets the
intent of identifying their criticality to reliability.While we do not disagree with the SDT’s interpretation of the
FERC directives, the BES definition should cover those facilities that are needed for operation under both
normal and emergency conditions, which includes situations related to black-start and system restoration. We
do not agree that the directives specifically ask for inclusion of blackstart resources and facilities on the crank
path in the BES definition. We believe the requirements in EOP-005-2 suffice to address the SDT’s
interpretation and concern regarding recognition of the reliability impacts and requirements for blackstart
resources and facilities used for system restoration.Generating units of any size and transmission facilities of
any voltage level may be used for blackstart and restoration. Conceivably, a generator of 10 MW and
transmission facilities of 44 kV or 69 kV may be a part of the cranking path. A BES inclusion will then subject
these generators and facilities, which are essentially “local” facilities but called upon to begin restoring its bulk
interconnected counterpart, to comply with the reliability standards intended for maintaining BES reliability.

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Organization

Yes or No

Question 5 Comment
Included in the BES definition will thus discourage smaller generators from providing blackstart capability, and
the transmission facilities from being a part of the cranking path. This may also discourage Transmission
Owners and Operators from identifying multiple blackstart resources and cranking paths to provide restoration
flexibility. Such an inclusion will ultimately undermine reliability.If indeed any of these facilities are deemed
necessary to support bulk power system reliability at times other than system restoration, they would/should
have been identified through the basic BES definition and inclusion list or can be addressed through the
exception procedure. We suggest and urge the SDT to remove I4 on the basis that: o The availability and
performance expectations of blackstart resources and facilities on the cranking path are already specifically
addressed in an existing standard; and o Unless they meet the BES definition and the other inclusion criteria,
they do not have any perceived reliability impact on everyday operation of the BES.

Southern Company

No

Inclusion I4 should be removed from this definition. There is an existing standard, EOP-005-2 (System
Restoration from Blackstart Resources), which specifically addresses Blackstart Resources and the
designated Blackstart Cranking Paths "regardless of voltage". Also, use of "regardless of voltage" in Inclusion
I4 as part of the BES definition will expand the applicability of some NERC Reliability Standards, which
pertains to the BES, to connected facilities at voltage levels below 100Kv.

Hydro-Quebec TransEnergie

No

When we have to use Blackstart Resources, there is no more system. Therefore, reliability is not a system
planning issue, the need is no more for reliability since we lost the System or part of it. It becomes a need for
restoration of the system as fast as possible. The restoration plan is necessary, but the Blackstart Resources
and do not contribute to the reliability of the System, which just failed, but to limit the time of loss of service.
There is no obligation to apply the same Reliability Standards on the paths and it should not be automatically
included in the BES.

National Grid

No

We do not feel that blackstart resources and cranking paths should be classified as BES. In several
instances, cranking paths direct the operator to pick up distribution load before moving on to the next step for
stability purposes. These are non-jurisdictional distribution facilities and should not be considered BES, since
they are not necessary to support the reliability of the bulk power system during normal conditions. The BES
definition should cover those facilities that are within FERC’s jurisdiction and that are needed for operation
under both normal and emergency conditions, which may include some facilities related to black-start and
system restoration, but not all. The directives should not broadly include blackstart resources and facilities on
the cranking path in the BES definition. This is over inclusive. The requirements in NERC standard EOP-0052 address the SDT’s interpretation and concern regarding recognition of the reliability impacts and
requirements for blackstart resources and facilities used for system restoration.For example, there could also
be small generators (less than 20 MVA/unit or 75 MVA/plant) or transmission and distribution facilities of 69
kV or less, which are considered “local”, that are used for system restoration in the cranking path. A BES
inclusion will then subject these generators and facilities, which are “local”, non-jurisdictional facilities that

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Organization

Yes or No

Question 5 Comment
may be called upon to begin restoring its bulk interconnected counterparts, to comply with the reliability
standards intended for maintaining BES reliability. Including these facilities in the BES definition will thus
discourage smaller generators from providing blackstart capability, and the transmission facilities from being a
part of the cranking path. This may also discourage Transmission Owners and Operators from identifying
multiple blackstart resources and cranking paths to provide restoration flexibility. This will ultimately
undermine reliability.
Also, including these types of facilities in the BES definitions could lead to jurisdictional challenges that could
cause uncertainty and delay the implementation of the new BES definition and divert important industry and
regulatory resources.
Because of these reasons, I4 should be removed from the inclusions list.

Dayton Power and Light
Company

No

Black start resources should not be included in this new proposal, which is being developed in response to
FERC Orders 743 and 743A. These orders do not mention the inclusion of black start resources or cranking
paths. These resources are undeniably important and we believe the existing CIP and other NERC standards
applicable to them provide sufficient and appropriate safeguards. Their inclusion as BES elements would
significantly increase the requirements for both distribution and 69kV cranking paths - which would be
classed as BES elements and fall under all those requirements. Entities currently include multiple cranking
paths for their restoration plans to improve the flexibility of their resources. However, if cranking paths are
considered BES and must meet those requirements, they will default to a single cranking path which would
potentially decrease their flexibility. The purpose of the bulk electric system is to accommodate the bulk
movement of electricity through the interconnected system. In a black start situation, entities would NOT be
interconnected and not moving bulk power. In light of the above, there is no sound basis for inclusion of
these elements as part of the BES.

Cogentrix Energy, LLC

No

The SERC SRG is concerned that this provision may have the effect of incenting transmission operators to
limit the available generator options to the minimum necessary for a reliable option as opposed to every
possible option that might be utilized in a pinch. We recommend the following adjusted language: “Essential
Blackstart Resources and the designated essential blackstart Cranking Paths identified in the Transmission
Operator’s restoration plan regardless of voltage”

New England States Committee
on Electricity

No

Please refer to comments under 3 above. Black start units should be excluded from BES. These units and
their associated cranking paths are used only for restoration and not operation. Such units are appropriately
covered under regional restoration procedures and applicable NERC standards (see for example, Emergency
Operating Procedure EOP-005-2). NESCOE is still exploring the impact and necessity of this proposed
inclusion.

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Organization

Yes or No

Question 5 Comment

Manitoba Hydro

No

Inclusion I4 should be modified so that only the Blackstart Resources and designated Cranking Paths
required for compliance with the NERC Emergency Preparedness and Operations Standards are included in
the BES Definition.

ISO New England, Inc.

No

The SDT states that “One of the basic tenets that the SDT is following is to avoid changes to registration due
to the revised definition if such changes are not technically required for the definition to be complete.”
However, adding every black start generator and the designated cranking path to the definition of the BES is
at odds with the Statement of Compliance Registry Criteria which states: III.c.3 Any generator, regardless of
size, that is a blackstart unit material to and designated as part of a transmission operator entity’s restoration
plan, or; The SDT should use the registry language in order to not expand the BES to every cranking path on
the distribution system from a small generator entered into the black start program.
Furthermore, the SDT cannot simply disregard voltage level, because: (a) FERC Order 743 expresses
preference for a bright line definition, and (b) Section 215 of the Federal Power Act defines the “bulk-power
system” as, in part, “electric energy from generation facilities needed to maintain transmission reliability”. As
the NERC Compliance Registry has long recognized, not every generator that is a blackstart unit is “material”
- i.e., may not be necessary - to the restoration plan or, therefore, to bulk-power system reliability.

Independent Electricity System
Operator

No

This inclusion is extraneous given there is already a designation specific for system restoration covered by an
existing standard to recognize their reliability impacts and to ensure their expected performance. NERC
Standards EOP-005-2 stipulates the requirements for testing blackstart resource and cranking paths. This
testing requirement suffices to ensure that the facilities critical to system restoration are functional when
needed, which meets the intent of identifying their criticality to reliability. We therefore suggest removing
Inclusion I4.

AltaLink

No

We do not agree with Inclusion I4. Blackstart resources and transmission facilities on the cranking path
should not be classified as BES regardless of size and voltage level. From a regulatory perspective, such an
inclusion would be in conflict with the current regulatory requirements in many of the jurisdictions. More
importantly, designating these facilities as BES Elements or Facilities beyond the 100 kV bright line, the 20
MVA/unit or 75 MVA/plant criteria, without a regard to their impact on the BES (under conditions other than
system restoration) will impose unnecessary requirements for these facilities, which do not contribute to
reliability under interconnected operation conditions. For restoration condition, this inclusion is extraneous
given there is already a designation specific for system restoration covered by an existing standard to
recognize their reliability impacts and to ensure their expected performance. NERC Standards EOP-005-2
stipulates the requirements for testing blackstart resource and cranking paths. This testing requirement
suffices to ensure that the facilities critical to system restoration are functional when needed, which meets the
intent of identifying their criticality to reliability.While we do not disagree with the SDT’s interpretation of the

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Organization

Yes or No

Question 5 Comment
FERC directives, the BES definition should cover those facilities that are needed for operation under both
normal and emergency conditions, which includes situations related to black-start and system restoration. We
do not agree that the directives specifically ask for inclusion of blackstart resources and facilities on the crank
path in the BES definition. We believe the requirements in EOP-005-2 suffice to address the SDT’s
interpretation and concern regarding recognition of the reliability impacts and requirements for blackstart
resources and facilities used for system restoration.Generating units of any size and transmission facilities of
any voltage level may be used for blackstart and restoration. Conceivably, a generator of 10 MW and
transmission facilities of 44 kV or 69 kV may be a part of the cranking path. A BES inclusion will then subject
these generators and facilities, which are essentially “local” facilities but called upon to begin restoring its bulk
interconnected counterpart, to comply with the reliability standards intended for maintaining BES reliability.
Included in the BES definition will thus discourage smaller generators from providing blackstart capability, and
the transmission facilities from being a part of the cranking path. This may also discourage Transmission
Owners and Operators from identifying multiple blackstart resources and cranking paths to provide restoration
flexibility. Such an inclusion will ultimately undermine reliability.If indeed any of these facilities are deemed
necessary to support bulk power system reliability at times other than system restoration, they would/should
have been identified through the basic BES definition and inclusion list or can be addressed through the
exception procedure.
We suggest and urge the SDT to drop I4 on the basis that: o The availability and performance expectations
of blackstart resources and facilities on the cranking path are already specifically addressed in an existing
standard; and
o Unless they meet the BES definition and the other inclusion criteria, they do not have any perceived
reliability impact on everyday operation of the BES.

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system elements. In
addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking Paths in the restoration plan due to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES definition to
ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this to include
operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources have the
ability to be started without support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the electric system
that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating
units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the
Transmission Operator’s restoration plan as BES Elements.

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Organization

Yes or No

Question 5 Comment

If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Small Entity Working Group
(SEWG)

No

The SEWG proposes a minor change to Inclusion I4. The SEWG recommends that the SDT exclude
Blackstart Units under 20MW and Blackstart Units that are connected via their GSU to Non-BES Facilities
(under 100kV). We believe this would be a minimal impact on the existing Restoration Plans while increasing
the reliability and viability of these Restoration Plans since the industry would be forced to use only BES
facilities as defined by NERC BES definition. In addition, a clarification is needed under the first bullet under
I4 in the posted word comment form for this BES draft (posted in the first column under Implementation Plan
for Definition). It should be changed to read "Blackstart units that have been included in the Transmission
Operator’s restoration plan and their respective cranking paths..." We do not believe it was the intent of the
SDT to include all blackstart units in the BES definition regardless if they are not part of a Transmission
Operator's restoration plan.

Dominion

No

Dominion continues to disagree that a generation resource, Element or Facility should automatically be
included in the BES. Dominion agrees that the Generator Owner and Generator Operator, as users of the
bulk power system, should have to abide by applicable reliability standards, but do not agree that this should
automatically require the inclusion of a generation resource, Element or Facility in the BES.

SPP Standards Review Group

No

While we understand the necessity of including the Cranking Path in the BES, we are equally concerned
about the broad usage of the term BES throughout the NERC Reliability Standards and the ramifications of
extending the requirements associated with those standards to parts of the distribution system that do not
have a logical association with the BES. For example, some of the TPL standards require studies of the BES.
Does this then mean those studies would apply to those Cranking Paths on the distribution system? We think
Cranking Paths that include portions of the distribution system should be excluded from the BES definition.
Could the SDT please provide us with an explanation of why these Elements would be included in the BES
and what would be gained if they were included? We’d also like to ask the SDT to identify the standards and
requirements that would be applied to the distribution system Cranking Paths. Is there any way that the
significance of the distribution Cranking Paths could be maintained without going as far as including them in
the BES?
Also, if a Distribution Provider has a portion of his distribution system designated an Element of the BES, as
in the Cranking Path scenario, does that then require the DP to register as a TO or TOP?

Michgan Public Power Agency

August 19, 2011

No

I would agree to this for Blackstart Resources only designated Blackstart Cranking Paths in the Transmission

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Organization

Yes or No

Question 5 Comment
Operator’s restoration plan regardless of voltage.

Tacoma Power

Tacoma Power generally supports Inclusion I4. We believe additional consideration should be given to
identifying only the Blackstart Resource`s that support a regional recovery. Based on that criteria, we
propose changing Inclusion I4 to read,”Blackstart Resources and the designated blackstart Cranking Paths
identified in the Transmission Operator’s restoration plan, regardless of voltage, and included in a regional
restoration plan.”

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system elements. In
addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking Paths in the restoration plan due to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES definition to
ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this to include
operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources have the
ability to be started without support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the electric system
that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating
units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the
Transmission Operator’s restoration plan as BES Elements.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
SERC OC Standards Review
Group

No

“Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s
restoration plan regardless of voltage.” The SERC SRG is concerned that this provision may have the effect
of incenting transmission operators to limit the available generator options to the minimum necessary for a
reliable option as opposed to every possible option that might be utilized in a pinch. We recommend the
following adjusted language: “Essential Blackstart Resources and the designated essential blackstart
Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage”

Vermont Transco

No

: The phrase “regardless of voltage” is a concern. The goal of the FERC order is to provide a more reliable
“bulk power system”. Many blackstart resources are at voltages well below the 100 kV voltage and are not
material to the restoration of the bulk electric system during a blackout. The wording of this inclusion would
require many units that are used only for local area support to now be listed as a BES facility. The wording of

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Organization

Yes or No

Question 5 Comment
this inclusion should be something to the order of “Blackstart Resources and the designated blackstart
cranking paths identified in the transmission operators restoration plan that are necessary to restore the BES
system”, this should not include cranking paths on distribution feeds that are used primarily for local area
support. The purpose of this inclusion should be to make certain all units necessary to energize the BES grid
after a blackout are maintained and operated appropriately

Consumers Energy Company

No

We recommend that the word, primary, be added, and that the phrase, “regardless of voltage” be removed:
“Blackstart Resources and the designated primary blackstart Cranking Paths identified in the Transmission
Operator’s restoration plan.” NERC’s May 19, 2011 webinar described this as applying only to the path
directly from the blackstart unit to the Transmission System. Is this correct? If so, please clarify within the
definition.

Exelon

No

Exelon believes that the entire designated cranking path should not be included in the BES definition if there
are facilities less than 100kV on the path. Doing so may inappropriately include a number of facilities that are
local distribution facilities under jurisdiction of the states, i.e, the inclusion of the entire cranking path occurs
without an inquiry as to whether or not the facilities are “facilities used in local distribution of electric energy”
even though such facilities are by explicit language in the Federal Power Act not included in the definition of
Bulk Power System. In Orders 743 and 743-A, FERC reiterated several times that “facilities that are
determined to be local distribution will be excluded from the bulk electric system.” (Order No. 743-A, P.22).
Furthermore, by including these facilities the Drafting Team has gone beyond the boundaries of Section 215
of the Federal Power Act and Orders 743 and 743-A. It should be noted that there is no reference to black
start Cranking Paths in either Order. Practically, it is unclear that including lower voltage facilities on a
Cranking Path will have any positive impact on reliability without potential entity registration changes or NERC
Reliability Standards changes. For example, NERC Reliability Standards FAC-008 and FAC-009 do not
currently apply to Distribution Providers.

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system Elements.
In addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking paths in the restoration plan die to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths. Accordingly, as suggested, the phrase
“regardless of voltage” has been also removed.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
National Rural Electric

August 19, 2011

No

This is the only part of the BES definition and inclusions/exclusions that specifically states “regardless of

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Organization

Yes or No

Cooperative Association
(NRECA)

Question 5 Comment
voltage.” NRECA does not believe it is appropriate for the BES definition to include such a statement. This
issue needs to be addressed in standard applicability language, not in the definition of BES.

Response: As suggested, the phrase “regardless of voltage” has been also removed.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Edison Electric Institute

No

EEI believes that the entire designated cranking path should not be included in the BES definition if it would
include facilities that are less than 100 kV on the path. Including such facilities may inappropriately include
some facilities that are local distribution facilities, which are under state jurisdiction. These facilities might be
swept into the definition of BES without an inquiry as to whether or not the facilities are “facilities used in local
distribution of electric energy,” which is an explicit exclusion under the Federal Power Act definition of “BulkPower System.”
This issue is more fully discussed in EEI’s response to Question 13.

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system elements. In
addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking Paths in the restoration plan due to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES definition to
ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this to include
operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources have the
ability to be started without support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the electric system
that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating
units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the
Transmission Operator’s restoration plan as BES Elements.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
See response to Q13.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
New York Power Authority

August 19, 2011

No

The Standards Drafting Team needs to clarify whether this inclusion is intended to apply to local transmission
operator restoration plans or only to the Balancing Authority’s restoration plans. This inclusion should be
stated as follows: Blackstart Resources and the designated cranking paths identified in the Balancing

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Organization

Yes or No

Question 5 Comment
Authority’s Restoration Plan regardless of voltage.”Local restoration plans may not be material to the
restoration and operation of the BES, but black start resources for the Balancing Authority’s restoration plan
are material to the reliable restoration of the BES.

Response: The SDT reaffirms that the reference is to the Blackstart Resources identified in the Transmission Operator’s restoration plan.
Central Maine Power Company
New York State Electric & Gas
and Rochester Gas & Electric

No

Inclusion I4 should be stricken for several reasons:
1. The SDT states that “One of the basic tenets that the SDT is following is to avoid changes to registration
due to the revised definition if such changes are not technically required for the definition to be complete.”
Adding every black start generator and the designated cranking path is not technically required. All significant
black start generation is already included in I2 and I3 and I5.
2. The NERC Compliance Registry notes that not every generator that is a blackstart unit is “material” - it may
not be necessary to the restoration plan or to bulk power system reliability.
3. There is already an existing standard to ensure reliability of blackstart performance. NERC Reliability
Standard EOP-005-2 ensures that the facilities critical to system restoration are functional when needed.
4. In CMP’s case, there are two generator locations which are part of the Black Start capability, and they are
small hydroelectric stations connected to our 34.5 kV transmission system. Under this inclusion, these small
hydroelectric stations and 34.5 kV paths would inappropriately be classified as BES. Other, critical blackstart
facilities are already included in the BES definition without I4.

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system elements. In
addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking Paths in the restoration plan due to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES definition to
ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this to include
operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources have the
ability to be started without support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the electric system
that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating
units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the
Transmission Operator’s restoration plan as BES Elements.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure

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Organization

Yes or No

Question 5 Comment

exception process to request including it in the BES.
Accordingly, as suggested, the phrase “regardless of voltage” has been also removed.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
PacifiCorp

No

PacifiCorp supports the concept of unique or singular blackstart paths being included in the BES. However,
once the uniqueness of the path disappears PacifiCorp believes the multiple non-unique blackstart paths
should be excluded by definition from the BES. This approach could be equated to pending version 4 of the
CIP Reliability Standards, in which the Critical Asset Criteria of CIP-002-4 set forth the facilities comprising
the Cranking Paths that are considered Critical Assets, up to the point on the path where two or more path
options exist.

Farmington Electric Utility System

No

The drafting team should consider adopting language similar to CIP-002-4 for Cranking Paths. Cranking
Paths up to the the point on the Cranking Path where two or more path options exist.

New York State Dept of Public
Service

No

This inclusion is problematic at a couple levels. First, blackstart resources can be facilities smaller than the
previous thresholds located deep within the local distribution system. Second, given you do not know ahead
of time how the system might come apart, often there are multiple cranking paths specified. To avoid
incurring the costs of upgrading facilities all along multiple paths, there will be an inclination to designate only
one path involving the fewest impacted facilities. The result could be reduced reliable operation - not more.

Pepco Holdings Inc

No

1)In many cases the cranking path or portions of it may consist of facilities less than 100kv. Many of these
facilities are local distribution facilities and should not be included in the BES.
2) If there is an identified cranking path that is transmission designated, but the path is not contiguous with the
BES, must the elements in-between be included as BES?

PJM

No

Black start units are used to start other units to when the BES is compromised. There is no technical
justification to include all elements in the “cranking path” as BES facilities.

ReliabilityFirst

Yes

but needs to state if this is ALL paths or just a single path, there may be many.

American Electric Power

Yes

While AEP supports the concept of including designated Blackstart Cranking paths as part of the BES, there
is concern that doing so without respect to voltage would unnecessarily include elements which should not be
included as part of the BES. More clarity is needed to explicitly describe the scope of the inclusion. Is it
limited to Transmission facilities or more broad to include Distribution facilities or even sub-Distribution
auxiliary systems? If so, this would unnecessarily bring those sub-systems under the purview of PRC-005, for

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Organization

Yes or No

Question 5 Comment
example.

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system Elements.
In addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking paths in the restoration plan die to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Electric Reliability Council of
Texas, Inc.

No

See response to question 3 - ERCOT ISO agrees with the substance, but not the approach.

Southwest Power Pool

No

Please see SPP's response to question 3 - SPP agrees with the substance, but not the approach.

No

We do not agree with Inclusion I4. Blackstart resources and transmission facilities on the cranking path
should not be classified as BES regardless of size and voltage level. From a regulatory perspective, such an
inclusion would be in conflict with the current regulatory requirements in many of the jurisdictions. More
importantly, designating these facilities as BES Elements or Facilities beyond the 100 kV bright line, the 20
MVA/unit or 75 MVA/plant criteria, without a regard to their impact on the BES (under conditions other than
system restoration) will impose unnecessary requirements for these facilities, which do not contribute to
reliability under interconnected operation conditions. For restoration condition, this inclusion is extraneous
given there is already a designation specific for system restoration covered by an existing standard to
recognize their reliability impacts and to ensure their expected performance. NERC Standards EOP-005-2
stipulates the requirements for testing blackstart resource and cranking paths. This testing requirement
suffices to ensure that the facilities critical to system restoration are functional when needed, which meets the
intent of identifying their criticality to reliability.While we do not disagree with the SDT’s interpretation of the
FERC directives, the BES definition should cover those facilities that are needed for operation under both
normal and emergency conditions, which includes situations related to black-start and system restoration. We
do not agree that the directives specifically ask for inclusion of blackstart resources and facilities on the crank
path in the BES definition. We believe the requirements in EOP-005-2 suffice to address the SDT’s
interpretation and concern regarding recognition of the reliability impacts and requirements for blackstart
resources and facilities used for system restoration.Generating units of any size and transmission facilities of
any voltage level may be used for blackstart and restoration. Conceivably, a generator of 10 MW and

Response: See response to Q3.
FortisBC

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Organization

Yes or No

Question 5 Comment
transmission facilities of 44 kV or 69 kV may be a part of the cranking path. A BES inclusion will then subject
these generators and facilities, which are essentially “local” facilities but called upon to begin restoring its bulk
interconnected counterpart, to comply with the reliability standards intended for maintaining BES reliability.
Included in the BES definition will thus discourage smaller generators from providing blackstart capability, and
the transmission facilities from being a part of the cranking path. This may also discourage Transmission
Owners and Operators from identifying multiple blackstart resources and cranking paths to provide restoration
flexibility. Such an inclusion will ultimately undermine reliability.If indeed any of these facilities are deemed
necessary to support bulk power system reliability at times other than system restoration, they would/should
have been identified through the basic BES definition and inclusion list or can be addressed through the
exception procedure.
We suggest and urge the SDT to drop I4 on the basis that:
o The availability and performance expectations of blackstart resources and facilities on the cranking path are
already specifically addressed in an existing standard; and
o Unless they meet the BES definition and the other inclusion criteria, they do not have any perceived
reliability impact on everyday operation of the BES.

Response: The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system elements. In
addition, the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking Paths in the restoration plan due to the
particular system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
However, the SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES definition to
ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this to include
operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources have the
ability to be started without support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the electric system
that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other generating
units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the
Transmission Operator’s restoration plan as BES Elements.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
The SDT does not agree that adding Blackstart Resources to the BES definition alone would “discourage” entities from providing blackstart capability.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.

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Organization
Public Utilities Commission of
Ohio

Yes or No
No

Question 5 Comment
this should be determined by an impact analysis, not inclusive of all Blackstart Resources, regardless of
location on the system.

Response: The SDT disagrees that Blackstart Resources should not be included in the BES definition. The Commission directed NERC to revise its BES
definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network. The SDT interprets this
to include operation under both normal and Emergency conditions, which include situations related to blackstarts and system restoration. Blackstart Resources
have the ability to be started without support from the system or can be energized without connection to the remainder of the System, in order to meet a
Transmission Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of the
electric system that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of one or more other
generating units as defined in the Transmission Operator’s system restoration plan. For these reasons, the SDT continues to include Blackstart Resources
indentified in the Transmission Operator’s restoration plan as BES Elements. No change made.
Intellibind

Yes

There continues to be confusion in the industry of blackstart by Generator Owners and Operators (especially
small to medium generation), and the drafting team should clearly define what is meant by blackstart. Many
small generators have the capability to blackstart their resource, but are not part of the Transmission
Operator's blackstart plan on restoring the BES. In most cases they are asked to blackstart if possible and
wait until lines are energized and close in as directed by Transmission Operator. This is significantly different
than owning a blackstart resource designated to provide power during a blackout.

American Transmission
Company, LLC

Yes

For clarification, ATC understands that only blackstart resources that are part of a Transmission Operator’s
Blackstart Restoration plan are included in I4 (Ref. EOP-005) and should be consistent with the upcoming
CIP-002 version 4 standard.
ATC also recommends that the SDT consider adding Blackstart Resources as a defined term in the NERC
Glossary.

Response: Only Blackstart Resources indentified in the Transmission Operator’s restoration plan are included in the BES. The term “Blackstart Resource” is a
defined term in the NERC Glossary. No change made.
PUD No. 2 of Grant County,
Washington

Yes

Grant supports this proposed inclusion with the caveat that the BES should be allowed to be non-contiguous,
especially in this case, if the unit is low voltage.

Response: The SDT proposed BES definition allows for non-contiguous elements.
Illinois Municipal Electric Agency

August 19, 2011

Yes

Please see comments under Question 13.

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Organization

Yes or No

Question 5 Comment

Springfield Utility Board

Yes

While Springfield Utility Board does not own any Blackstart Resources, we do recognize the importance of the
restoration of the Grid, and the generation necessary for the Grid should have identified paths that are critical,
regardless of voltage level.

Springfield Utility Board

Yes

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Central Lincoln

Yes

But please indicate how blackstart resources (regardless of voltage) not in the TO’s restoration plan are
treated, since we don’t believe the flowchart at
http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly expresses the SDT’s intent
to classify these resources (when also below the 20 or 75 MVA thresholds) as non-BES.

City of Redding

Yes

Redding suggests that only the primary black start resource in the TO or BA’s black start plan fall under this
inclusion otherwise the secondary and or backup black start units may not be identified in the main plans to
avoid excessive regulation of the equipment.

Response: See response to Q13.

Response: Only Blackstart Resources indentified in the Transmission Operator’s restoration plan are included as BES Elements. The Commission directed
NERC to revise its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network.
The SDT interprets this to include operation under both normal and Emergency conditions, which includes situations related to blackstarts and system restoration.
Blackstart Resources have the ability to be started without support from the System or can be energized without connection to the remainder of the System, in
order to meet a Transmission Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated

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Organization

Yes or No

Question 5 Comment

resources of the electric system that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of
one or more other generating units as defined in the Transmission Operator’s system restoration plan. No change made.
Long Island Power Authority

Yes

Need to define Cranking Paths.

Response: “Cranking Path” is a defined NERC Glossary term but is no longer used in the revised inclusion.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
MEAG Power

Yes

The Standards Drafting Team needs to clarify whether this inclusion is intended to apply to local transmission
operator restoration plans or only to the Balancing Authority’s restoration plans. This inclusion should be
stated as follows: Blackstart Resources and the designated cranking paths identified in the Balancing
Authority’s Restoration Plan regardless of voltage.”Local restoration plans may not be material to the
restoration and operation of the BES, but black start resources for the Balancing Authority’s restoration plan
are material to the reliable restoration of the BES.

Response: Only Blackstart Resources indentified in the Transmission Operator’s restoration plan are included as BES Elements. The Commission directed
NERC to revise its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network.
The SDT interprets this to include operation under both normal and Emergency conditions, which includes situations related to blackstarts and system restoration.
Blackstart Resources have the ability to be started without support from the System or can be energized without connection to the remainder of the System, in
order to meet a Transmission Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated
resources of the electric system that can be isolated and then energized to deliver electric power during a restoration event are essential to enable the startup of
one or more other generating units as defined in the Transmission Operator’s system restoration plan.
The SDT agrees that Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system Elements. In addition,
the Transmission Operator’s actual restoration may make use of paths that were not identified as Cranking paths in the restoration plan die to the particular
system configuration on the day in question. Therefore, the SDT has removed the inclusion for Cranking Paths.
If a situation arises where an entity believes that a specific Cranking Path must be part of the BES, that entity can always make use of the Rules of Procedure
exception process to request including it in the BES.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Muscatine Power and Water

Yes

This Inclusion I4 provides a defense in depth with CIP-002-4.

New York State Reliability
Council

Yes

BS facilities and their cranking paths are critical to the maintenance of system reliability under system
restoration conditions. However, they are a special case and should not be construed as a precedent for
inclusion of all BES contiguous elements.

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Organization

Yes or No

Question 5 Comment

Idaho Falls Power

Yes

It is reasonable to conclude that Blackstart generation resources are material to the BES.

MRO's NERC Standards Review
Forum

Yes

It does provide a defense in depth with CIP-002-4.

BPA

Yes

Duke Energy

Yes

ExxonMobil Research and
Engineering

Yes

Alberta Electric System Operator

Yes

South Carolina Electric and Gas

Yes

Fayetteville Public Works
Commission

Yes

MidAmerican Energy Company

Yes

Florida Keys Electric Cooperative

Yes

Sierra Pacific Power Co d/b/a NV
Energy

Yes

Colorado Springs Utilities

Yes

East Kentucky Power
Cooperative, Inc.

Yes

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and

Yes

August 19, 2011

No comment.

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Organization

Yes or No

Question 5 Comment

Dispatch
Sacramento Municipal Utility
District (SMUD)

Yes

City of St. George

Yes

Puget Sound Energy

Yes

Southern California Edison
Company

Yes

GTC

Yes

Idaho Power

Yes

Clark Public Utilities

Yes

The Dow Chemical Company

Yes

Oncor Electric Delivery Company
LLC

Yes

City of Anaheim

Yes

Xcel Energy

Yes

Golden Spread Electric
Cooperative, Inc.

Yes

Utility System Efficiencies, Inc.

Yes

Tri-State Generation and
Transmission Association, Inc.

Yes

August 19, 2011

SMUD agrees with the inclusion of blackstart resources and their cranking paths.

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Organization

Yes or No

Imperial Irrigation District

Yes

Florida Municipal Power Agency

Yes

Santee Cooper

Yes

NERC Staff Technical Review

Yes

SERC Planning Standards
Subcommittee

Yes

Overton Power District No. 5

No

Tennessee Valley Authority

Yes

Arizona Public Service Company

Yes

Western Electricity Coordinating
Council

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

Luminant Energy

Yes

Electricity Consumers Resource
Council (ELCON)

Yes

Western Area Power
Administration

Yes

US Bureau of Reclamation

Yes

Grand Haven Board of Light and

Yes

August 19, 2011

Question 5 Comment

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Organization

Yes or No

Question 5 Comment

Power
Glacier Electric Cooperative

Yes

FHEC

Yes

South Texas Electric
Cooperative, Inc.

Yes

Portland General Electric
Company

Yes

South Texas Electric
Cooperative, Inc.

Yes

Response: Thank you for your response. Several stakeholders identified that Cranking Paths usually involve distribution elements, and the SDT has removed the
inclusion for Cranking Paths. Please see the revised definition.

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6. The SDT has added specific inclusions to the core definition in response to industry comments. Do you agree
with Inclusion I5? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: Industry comments included the following issues:
•
•
•
•

Concern over the assumed contiguous nature of the BES definition. The SDT did not mandate a contiguous BES and has clarified the
language of the inclusions to make this clear.
Confusion over the term ‘collector system.’ The SDT has deleted this terminology.
Concern that the definition could ensnare distributed generation or small generators in a distribution system. The SDT has clarified the
wording of the inclusion to emphasize that the inclusion is ‘designed primarily for aggregating capacity.’
While several commenters asked about the technical justification of the generation thresholds, the SDT was not presented with any technical
rationale for moving away from this existing limit. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the
SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that
topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and
743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards
Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization
Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.

Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system
designed primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a
voltage of 100 kV or above.

Organization

Yes or No

Question 6 Comment

Northeast Power Coordinating
Council

No

The entire contiguous path does not have to be BES. The path or aggregate generation will rarely have any
impact on the reliability on the interconnected transmission network, nor is it necessary for its operation.
These are generally referred to as connection facilities.

MRO's NERC Standards Review
Forum

No

We propose the following questions for your consideration:Which components of the dispersed power
resources would be classified as BES? Are the individual small wind generator units and terminals through
the GSUs to a higher voltage (e.g. 34.5 kV) collector bus classified as BES Elements? Are the higher voltage
bus, the associated elements (e.g. protection system, cap bank, SVC, etc.), and step up transformer to a
system Element of 100 kV or above to be classified as BES Elements?With these questions, the NSRF is

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Organization

Yes or No

Question 6 Comment
confused on what the SDT is trying to formulate as an Inclusion. If a dispersed power systems meets the
threshold of 75MVA and connected at 100kV or higher, does this make the entire dispersed system
considered to be part of the BES? We recommended that one solution is that I5 to be revised as follows
“Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) utilizing a collector system from the point where the aggregated rating exceeds 75 MVA
through a common point of interconnection to a system Element at a voltage of 100 kV or above. “

Hydro One Networks Inc

No

We agree with the concept of Inclusion I5 but do not support that the entire contiguous path has to be BES.
The path or aggregate generation will rarely have any impact on the reliability on the interconnected
transmission network nor is it necessary for its operation. These are generally referred to as connection
facilities. In addition, renewable generation units are intermittent and the planning and operational standards
and practices make sure that their unavailability or unexpected (sudden) loss of generation won’t jeopardize
reliability of the network; therefore, they should not be BES. As stated earlier, with the Green Energy and
Smart Grid plans and dispersed renewable energy advocated by both Canadian and US policy makers, the
gross nameplate rating of 75 MVA may undermine and deter the future potential of integrating DG’s that will
be implemented to ensure the reliable operation of the interconnected transmission network BES, and, at the
same time, provides the most effective and economical solutions for the rate payers in North America. Local
generation can cost-effectively enhance the reliability of load pocket, by avoiding transmission, but such
restrictions would deter the adoption of good planning decisions.(Refer to Q4 comments).

Hydro-Quebec TransEnergie

No

We believe that automatic inclusion of dispersed generation greater than 75 MVA and the path to connect
them to the BES should not be automatically included in the BES. However, a provision should be made so
that some reliability standards related to generator shall apply (voltage regulation, etc.).

New York State Reliability
Council

No

Distributed resources are comprised of multiple small units that cycle on and off depending upon local
ambient conditions. They have multiple feeders collecting at the point of interconnection. It is not credible
that simultaneous loss of multiple units and/or collector system feeders could occur and they should be
excluded from the BES based upon reliability considerations. It is noted that system Element(s) beyond the
point of interconnection are subject to BES inclusion per the core definition.

FortisBC

No

We agree with the concept of Inclusion I5 but do not support that the entire contiguous path has to be BES.
The path or aggregate generation will rarely have any impact on the reliability on the interconnected
transmission network nor is it necessary for its operation. These are generally referred to as connection
facilities.As stated earlier, with the Green Energy and Smart Grid plans and dispersed renewable energy
advocated by both Canadian and US policy makers, the gross nameplate rating of 75 MVA may undermine
and deter the future potential of integrating DG’s that will be implemented to ensure the reliable operation of
the interconnected transmission network BES, and, at the same time, provides the most effective and

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Organization

Yes or No

Question 6 Comment
economical solutions for the rate payers in North America. Local generation can cost-effectively enhance the
reliability of load pocket, by avoiding transmission, but such restrictions would deter the adoption of good
planning decisions.(Refer to Q4 comments).

PJM

No

As written I5 implies a contiguous system from the unit to a “point a system element at a voltage above 100
kV” there is no technical justification for a contiguous system. The requirement should read “- Dispersed
power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
utilizing a collector system through a common point of interconnection."

Xcel Energy

No

For dispersed power producing resources, such as wind farms, we do not see the value in making each
individual 1-2 MW wind turbine a BES element. The BES applicability should be focused on the point when
the collective becomes large enough to impact the grid. So, we recommend that I5 apply from the point of
aggregation of 75 MW or more to a system element operated at 100 kV or more. Specifically, we feel it should
be limited to the feeder bus and aggregating transformer.

Independent Electricity System
Operator

No

We agree with the goal of Inclusion I5 but have the same concerns expressed in our responses to Q1 and
Q3. For the dispersed power resources referred to in Inclusion I5, we do not see the benefit of including the
collector system, switchgear, associated medium voltage equipment and step-up transformer(s) in the BES.
As before, these Facilities should be subject to assessment and included if found to impact BES reliability
after going through the Exception Process. To reinforcing what was stated during the NERC BES webinar, we
do not believe that the entire contiguous path has to be BES.

AltaLink

No

We agree with the concept of Inclusion I5 but do not support that the entire contiguous path has to be BES.
The path or aggregate generation will rarely have any impact on the reliability on the interconnected
transmission network nor is it necessary for its operation. These are generally referred to as connection
facilities.

American Transmission
Company, LLC

Yes

ATC poses the following questions to the SDT for consideration:Which components of the dispersed power
resources would be classified as BES? Are the small wind generator units and terminals through the GSUs to
a higher voltage (e.g. 34.5 kV) collector bus classified as BES Elements? Are the higher voltage bus, the
associated elements (e.g. protection system, cap bank, SVC, etc.), and step up transformer to a system
Element of 100 kV or above to be classified as BES Elements?

Exelon

Yes

Exelon agrees with this inclusion as long as it’s clear that distribution voltage collector systems are not to be
included in the BES. Exelon suggests that a clarifying statement be added to the inclusion item, such as
“Collector system facilities that are <100kV are excluded from the BES.”

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Organization

Yes or No

Central Lincoln

Yes

Question 6 Comment
But please indicate how dispersed aggregate generation below 75 MVA is to be treated, since we don’t
believe the flowchart at http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf properly
expresses the SDT’s intent to classify these resources as non-BES.

Response: There is no contiguous path requirement and the SDT has revised the wording for clarity.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
American Municipal Power and
Members

No

There is concern over inadvertently including small distribution that has behind-the-meter generation on a 69
kV loop. We somewhat agree with the concept of Inclusion I5 but suggest a language change to clarify what
we understand to be the drafting team’s intent, that the inclusion is intended to apply to dispersed wind and
solar generating plants, and not, for example, to a radially-connected city with an aggregate of 75 MW of
small generators behind-the-meter. This distinction is appropriate because such a city cannot have the same
impact on the grid as a 75 MW wind farm; loss of the radial connecting the city to the grid would result in loss
of its load as well as its generation, so that the supply-demand mismatch would be far less significant. We
suggest that I5 be revised.

Response: The SDT clarified the language to address this point.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Imperial Irrigation District

No

In reference to I5 If the collector system is in the distribution system and after a series of elements and (sub
transmission system) is connected to a common point of interconnection to a system element at a voltage of
100 kV and above, is there a criteria of after how many elements before it connects to a system element at a
voltage of 100 kV and above is I5 still applicable?IID prefers the following language: Dispersed power
producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) after
the collector system to the first system Element at a voltage of 100 kV or above.

Response: The SDT clarified the language to address this point.

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Organization

Yes or No

Question 6 Comment

Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
NERC Staff Technical Review

No

We agree that Inclusion I5 is an effective method for including dispersed resources; however, the
interconnection voltage threshold should be removed. The contribution of dispersed power producing
resources to system reliability is a function of the aggregate MVA rating rather than the interconnection
voltage. All dispersed resources with aggregate capacity greater than 75 MVA should be included in the BES
definition because all such units provide similar contributions to system reliability.

Response: The SDT appreciates the concern regarding the 100 kV threshold and the 75 MVA limit on connected generation; however, the SDT has been
presented with no technical basis upon which to suggest a change from these values. No change made.
Dominion

No

Dominion disagrees that an Element or Facility operated below 100 kV should be included automatically in
the BES. Dominion agrees that users of the bulk power system should be required to abide by applicable
reliability standards. Dominion questions why the SDT chose to use the phrase ‘Dispersed power producing
resources’ As opposed to the phrase ‘Dispersed generating resources’. Dominion asks that the SDT provide
an explanation for its choice of phrases.

Response: The SDT used this term intentionally. Generation resources suggest a “generator”. Using the term power producing resources includes devices now
and in the future that could produce energy (like wind and solar). No change made.
SPP Standards Review Group

No

Limiting this to 75 MVA does allow the opportunity for a significant amount of generation to ‘slip under the
fence’ regarding inclusion in the BES. Was this the intent of the SDT? For example, in order to circumvent the
BES issue a developer may decide to build 2-74 MVA sites rather than a single 148 MVA site. Regarding the
similarity of the I3 and I5, what is the difference between a ‘single site’ and a ‘common point of
interconnection’? Shouldn’t they be the same in the two inclusions?

Response: If a developer wants to build 2- 74 MVA sites solely to not be deemed part of the BES, they can do so, but the Regional Entity could still require them
to register. No change made.
Idaho Falls Power

August 19, 2011

No

This inclusion seems redundant to the registry criteria for GO/GOP of a facility generation of 75MVA or
greater. We do not see how this definition adds or removes any assets already defined by the registry
criteria.

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Organization
City of Redding

Yes or No
No

Question 6 Comment
Redding believes that this could be handled in the Statement of Compliance Registration Registry by
specifically addressing distributed generation. This could be part of a tiered approach where these type of
facilities would be included as a User of the BES instead of an owner and operator of BES elements.

Response: The goal of the SDT is to provide clarity to the definition of the BES and not to address registration criteria. No change made.
Tennessee Valley Authority

No

Other than the NERC Registry Criteria definition, what is the technical justification for the 75 MVA threshold?
The threshold level for inclusion should be technically based on the BES capacity and configuration at the
location of the generating sources’ connection to the BES.

Western Montana Electric
Generating and Transmission
Cooperative

No

WMG&T agrees that it is important to address wind generation facilities and similar generation facilities in
which a large number of generating units, each with a relatively small capacity, are clustered and fed into the
grid at a single interconnection point. That being said, WMG&T is concerned that the 75 MVA threshold has
been chosen arbitrarily for the reasons stated in our comments on Question 4.

Public Utility District No. 1 of
Snohomish County, Washington

No

Snohomish agrees that it is important to address wind generation facilities and similar generation facilities in
which a large number of generating units, each with a relatively small capacity, are clustered and fed into the
grid at a single interconnection point. That being said, Snohomish is concerned that the 75 MVA threshold
has been chosen arbitrarily for the reasons stated in our comments on Question 4.

Blachly Lane Electric Cooperative

No

We are concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our
comments on Question 4.

Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative

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Organization

Yes or No

Question 6 Comment

No

Northern Wasco County PUD agrees that it is important to address wind generation facilities and similar
generation facilities in which a large number of generating units, each with a relatively small capacity, are
clustered and fed into the grid at a single interconnection point. That being said, Northern Wasco County PUD
is concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons stated in our comments
on Question 4.

No

Generators should only be part of the Bulk Electric System if they are connected through a GSU to a
Transmission Element determined to be part of the BES. The current inclusion language would apply to all
generators connected to facilities greater the 100 kV with no exclusion or exception process. Without a
change, it appears that a generator connected to a facility greater than 100 kV would be a BES asset even if
the transmission assets could be excluded or excepted. I5 should be rewritten to state: Dispersed power
producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
utilizing a collector system through a common point of interconnection to a Transmission Element determined
to be part of the Bulk Electric System.Additionally, as indicated by Clark in its comments on the core definition

Northern Lights Inc
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Northern Wasco County PUD
Clallam County PUD No.1
Chelan PUD – CHPD
Public Utility District No. 1 of
Franklin County
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc.
Utility System Efficiencies, Inc
Cowlitz County PUD
Clark Public Utilities

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Organization

Yes or No

Question 6 Comment
of the BES, Clark believes the 75 MVA threshold lacks an adequate technical justification and is a purely
arbitrary quantity. The use of a capacity threshold in the definition of the BES should have technical reasons.

Santee Cooper

Yes

What is the rationale for 75 MVA.

Response: The SDT appreciates the concern regarding the lack of technical justification for a 75 MVA threshold; however, the SDT has not been presented with
a technical basis upon which to suggest a change from this value. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the
SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with
the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean
that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17
SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues
that have arisen from SDT deliberations.
Intellibind

No

Though the intent is understood through the discussion, the language presented is not clear enough. The
drafting team should be cautioned on how Standards are read through many different entities and audiences.
The team should also understand if the issue is not clearly defined, there will continue to be ambiguity through
the registration and compliance processes.As previously stated on an earlier question, I do not think that the
20 MVA threshold has technical merit, I do not believe that the 75MVA limit has technical merit either. Further
the impact should be measured at the buss bar not at the nameplate. The aggregate rating should be the
same as the individual unit rating on a single plant, unless the plant can prove that there is not a common
failure mode to lose more than 20MVA.

Response: The SDT appreciates the concern regarding the lack of technical justification for a 20/75 MVA threshold; however, the SDT has not been presented
with a technical basis upon which to suggest a change from this value. After consulting with the NERC Board of Trustees and the NERC Standards Committee,
the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice
with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not
mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 201017 SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues
that have arisen from SDT deliberations.
Electric Reliability Council of
Texas, Inc.

No

See response to question 3 - ERCOT ISO agrees with the substance but not the approach.

Southwest Power Pool

No

Please see SPP's response to question 3 - SPP agrees with the substance but not the approach.

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Organization

Yes or No

Question 6 Comment

No

I5 is not defined clearly enough. It appears that distributed generators connected to a 44 kV load pocket that
is fed radially from a 100 kV source would be included, but it’s not clear that this was the intent. Adding
generator before collector system would provide greater precision.

Response: See response to Q3.
Duke Energy

Response: The SDT believes the re-wording of Inclusion I5 (now Inclusion I4) should address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Fayetteville Public Works
Commission

No

Because no differentiation has been defined between "power producing resources" in Inclusion I5 and
"generating units" from Inclusions I2 and I3, this Inclusion has the potential to conflict with other Inclusions. It
should be modified to read "Dispersed power producing resources with individual capacity of 20 MVA or less
(gross nameplate rating) but with aggregate capacity greater than 75 MVA. . ."

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
MidAmerican Energy Company

No

It is suggested that the inclusion be modified to include a more definitive description of the portion of the
facility that would be considered to be in the BES. It is suggested that the phrase "from the point where the
aggregated rating exceeds 75 MVA" be added after collector system in I5. The revised inclusion would then
read as follows: Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a collector system from the point where the aggregated rating exceeds
75 MVA through a common point of interconnection to a system Element at a voltage of 100 kV or above.

Muscatine Power and Water

No

MP&W recommends to have Inclusion 5 be revised as follows “Dispersed power producing resources with
aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a collector system from
the point where the aggregated rating exceeds 75 MVA through a common point of interconnection to a
system Element at a voltage of 100 kV or above.”

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Organization

Yes or No

Question 6 Comment

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Springfield Utility Board

No

What is a collector system? Does this include a Local Distribution Network? A Local Distribution Network
(E3) may have multiple generating units within its service area that serve all or part of retail load (E2). Would
the aggregate nameplate rating of these units be included even though they would otherwise be excluded by
application of E2? For example, there may be multiple end users with 500 kW photovoltaic systems whose
total nameplate capacity is 100 MVA. All or most of the power used is consumed by the retail
consumers.SUB suggests that the language be restated to say “Dispersed power producing resources with
aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) that are not excluded under E2
utilizing a collector system through a common point of interconnection to a system Element at a voltage of
100 kV or above” Or”Dispersed power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a cCollector sSystem through a common point of interconnection
to a system Element at a voltage of 100 kV or above. For purposes of this inclusion, a Collector System is
any infrastructure not connected to load - where parasitic load associated with a generation unit or units is not
considered load.” While Springfield Utility Board does not own any power producing resources, we do
recognize the importance of the restoration of the Grid, and the generation necessary for the Grid, regardless
of voltage level.

Springfield Utility Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of

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Organization

Yes or No

Question 6 Comment
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: The SDT believes that the re-wording of the inclusion should address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
City of St. George

No

See comments to questions 3 & 4 above. The requirements for an entity or facility should match the impact of
that facility to the system.

Response: The SDT carefully debated the generating threshold for the inclusion. After consulting with the NERC Board of Trustees and the NERC Standards
Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that
topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this
does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the
Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as
several other issues that have arisen from SDT deliberations.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Southern California Edison
Company

No

Please refer to SCE’s answer for Question No. 3 above.If the SDT goes forward and includes I5 into either
the proposed BES definition or the Technical Principles for Demonstrating BES Exceptions, the following
additional clarification should be made:(i) Clarify the terms “Dispersed power producing resources” and
“collector system”;
(ii) When referencing “collector system,” does it include the lines connecting the generation?;
(iii) Why the 75 MVA threshold? This seems to be a somewhat arbitrary number which does not correlate with
specific operational risks, operational limits, or network capability. This is highlighted when taking SCE’s
system into consideration, as we carry operational spinning reserves that are 10 to 20 times greater than the
75 MVA threshold identified in the proposed BES Definition. If SCE were to lose 75 MVA in an event, there
would be no reliability risk or perceptible frequency deviation that would attend the event. The proportionality

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Organization

Yes or No

Question 6 Comment
of risk and benefit does not seem to fit within the application and philosophy behind the mandatory limit.
Setting the BES Definition in this manner in order to bring in the smallest utilities is not appropriate for
application to the larger utilities.; and
(iv) As written, I5 could unintentionally bring into scope sub-trans/distribution systems with enough generation
as these radial systems could be categorized as “collector systems”. Specifically, there are radiallyconnected distribution systems in the Desert Southwest designed to enable the interconnection of multiple
renewable resources which could be viewed as grouping this collective generation at the point of
interconnection with the transmission system. In many cases, the sum total of this generation could be
greater than 75 MVA.

Response: 1. The SDT re-worded the definition to address these concerns.
2. There is no contiguous path requirement and the SDT has revised the wording for clarity.
3. The SDT appreciates the concern regarding the lack of technical justification for a 75 MVA threshold; however, the SDT has been presented with no technical
basis upon which to suggest a change from this value. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has
decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the
mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that
the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT
take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that
have arisen from SDT deliberations.
4. The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
The Dow Chemical Company

No

The language is not clear enough to understand what is covered.

Response: Please consider the revised language.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or

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Organization

Yes or No

Question 6 Comment

No

As noted in comment under 4 above, the 75 MVA threshold may unintentionally impose unnecessary added
costs that may ultimately be paid by New England ratepayers. The exception process should provide flexibility
as to total MVA rating. In addition, NESCOE believes this language should be clarified to exclude collector
systems and include only elements that actually impact the BES.

above.
New England States Committee
on Electricity

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system
designed primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of
100 kV or above.
Oncor Electric Delivery Company
LLC

No

The ERCOT Region already considers load in any combination equal to and over 20 MVA through a single
Point of Interconnect as part of the BES

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Consolidated Edison Co. of NY,
Inc.

No

Please define the terms “collector system” and “common point.”

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed

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Organization

Yes or No

Question 6 Comment

primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Orange and Rockland Utilities,
Inc.

No

See comments from question 4.

Response: See response to Q4.
BPA

No

Does the interconnection point have to be the only interconnection point for all of the resources?
Additionally BPA would like to see a definition of :dispersed power.”

Response: The SDT has revised Inclusion I5 to clarify the interconnection point as a ‘common point’ where the aggregated capacity of the dispersed power
producing resource is connected to the BES.
The SDT is responsible for the revision of the BES definition. In fulfilling this responsibility the SDT is developing a definition that properly classifies facilities as
BES or non-BES Elements. Defining ‘dispersed power’ is not within the scope of Project 2010-17, however the term is used in the definition to capture resources
such as wind farms, solar arrays, etc. that utilize installations over a larger area than would typically be seen at a conventional generation facility.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Tacoma Power

August 19, 2011

Tacoma Power generally supports Inclusion I5. However, the term ‘gross aggregate nameplate rating’ is not
defined and should be replaced with a specific definition. Additionally, no justification for the 75 MVA level has
been provided and therefore it appears arbitrary. Since this measurement will define Elements for absolute
inclusion in the BES, the threshold for dispersed power producing resources should be based on a need to
maintain transmission reliability. Further, there is no traceable definition for ‘collector system.’ Rather than
defining it, it can be replaced with a ‘common interconnection point.’ Lastly, such dispersed resources located
within a Local Distribution Network (LDN), which do not exit the LDN, should not be included. We propose
changing Inclusion I5 to read,”The common interconnection point for dispersed power producing resources
with aggregate capacity greater than 75 MVA (aggregate capacity based on the Code of Federal Regulation,
CFR 18, Part 287.1, “Determination of powerplant design capacity”) connected to an Element that is part of
the BES, except for common interconnection points that are within a Local Distribution Network (LDN) and do
not have a net export out of the LDN.”

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Organization

Yes or No

Question 6 Comment

Response: The goal of the SDT is to provide clarity to the definition of the BES and not to address registration criteria.
The SDT feels that the term “gross aggregate nameplate rating” is a widely understood term within the industry and does not require additional definition. No
changes made.
I5 (now I4) was revised and no longer uses the term, ‘collector system.’
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Portland General Electric
Company

It is not clear what the SDT is attempting to capture with this inclusion thatis not already captured in I3. In
addition, the term “collector system” needs to bedefined.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Midstate Electric Cooperative

MSEC agrees that it is important to address wind generation facilities and similar generation facilities in which
a large number of generating units, each with a relatively small capacity, are clustered and fed into the grid at
a single interconnection point.
That being said, MSEC is concerned that the 75 MVA threshold has been chosen arbitrarily for the reasons
stated in our comments on Question 4. This would lump together many IPP's that are spread out over a large
distribution network that happen to be tied into a single point of interconnection.

Response: The SDT re-worded the definition to better clarify these concerns.
The SDT appreciates the concern regarding the lack of technical justification for a 75 MVA threshold; however, the SDT has been presented with no technical
basis upon which to suggest a change from this value. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has
decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the
mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that
the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT
take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that

August 19, 2011

197

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Organization

Yes or No

Question 6 Comment

have arisen from SDT deliberations.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Florida Municipal Power Agency

Yes

FMPA agrees with the concept of Inclusion I5 but suggests a language change to clarify what we understand
to be the drafting team’s intent, that the inclusion is intended to apply to dispersed wind and solar generating
plants, and not, for example, to a radially-connected city with an aggregate of 75 MW of small generators
behind-the-meter. This distinction is appropriate because such a city cannot have the same impact on the
grid as a 75 MW wind farm; loss of the radial connecting the city to the grid would result in loss of its load as
well as its generation, so that the supply-demand mismatch would be far less significant. FMPA thus
suggests that I5 be revised to read:I5 Wind farm or solar power installation with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) utilizing a collector system through a common point of
interconnection to a system Element at a voltage of 100 kV or above.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Western Electricity Coordinating
Council

Yes

WECC agrees in concept, but it is unclear why there is the new term “power producing resources.” Is this
meant to include both Real Power Resources and Reactive Power Resources (terms used in the base
definition)? This should be clarified. In addition, it appears from comments of the drafting team that the intent
of this inclusion was primarily for wind and solar farms, but the language would also pull in traditional
generation that happens to be connected at a single point. The language should be clarified so that it only
captures the intended generation.

Response: The SDT used this term intentionally. Generation resources suggest a “generator”. Using the term power producing resources is to include devices
now and in the future that could produce energy (like wind and solar). No change made.
Edison Electric Institute

August 19, 2011

Yes

EEI suggests that the following language more clearly expresses the intent of the SDT:Dispersed power
producing resources with aggregate capacity greater than 75 MVA gross aggregate nameplate rating) utilizing

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Organization

Yes or No

Question 6 Comment
a collector system from the point where the aggregate rating exceeds 75 MVA through a common point of
interconnection to a system Element at a voltage o 100 kV or above.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
ReliabilityFirst

Yes

but the term "Dispersed Power Producing Resuorces" needs to be defined.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Transmission Access Policy
Study Group

Yes

TAPS agrees with the concept of Inclusion I5 but suggests a language change to clarify what we understand
to be the drafting team’s intent, that the inclusion is intended to apply to dispersed wind and solar generating
plants, and not, for example, to a radially-connected city with an aggregate of 75 MW of small generators
behind-the-meter. This distinction is appropriate because such a city cannot have the same impact on the
grid as a 75 MW wind farm; loss of the radial connecting the city to the grid would result in loss of its load as
well as its generation, so that the supply-demand mismatch would be far less significant. TAPS thus
suggests that I5 be revised to read:I5 Wind farm or solar power installation with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) utilizing a collector system through a common point of
interconnection to a system Element at a voltage of 100 kV or above.

Northern California Power
Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed

August 19, 2011

199

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 6 Comment

primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
New York Power Authority

Yes

This inclusion should be specific to the type of generation that the team envisioned it to capture (e.g. wind and
solar). Since the term “dispersed power producing resources” can be interpreted to include generation
resources from a few KW up to 50 MW, this inclusion can be misinterpreted to include “peaker GT’s”, fuel
cells and microturbines, etc.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Central Maine Power Company

Yes

New York State Electric & Gas
and Rochester Gas & Electric

Please note that this departs from NERC’s Registry Criteria in that the unit of measurement is MVA instead of
MW.

Response: The SDT believes that MVA is the correct way to measure this. No change made.
PacifiCorp

Yes

PacifiCorp understands the SDT is looking for technical reasons for something other than 75 MVA. PacifiCorp
believes it is not feasible to determine a value that is consistent across the continent. Although PacifiCorp
believes 75 MVA is too low, it is an acceptable number for any configuration of generation. Those above 75
MVA believed to be exempt from the BES definition can be processed through the proposed ROP
inclusion/exclusion process.

Response: The SDT agrees that the exception process will be the proper venue to sort out differences.
Sacramento Municipal Utility
District (SMUD)

August 19, 2011

Yes

SMUD agrees with the Inclusion 5 concept. However, there are a few terms that require clarification to
support the “Bright-Line” application. It is unclear what is meant to be captured by the term “Dispersed power
producing resources”. As reflected in the intent statement it would be preferred to indicate the applicability of
the wind and solar resources or the term intermittent in the Inclusion 5 language. The term “collector system
through a common point” is rather vague that lends to varied interpretations that perhaps a defined level of
MW through a single element bottleneck would help quantify BES impacts.

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Organization

Yes or No

Question 6 Comment
In addition, the BES delineation should be the single “bottleneck” element for aggregate connection of 75
MVA as it is that element's interruption is what would impact the BES.
Additional concerns of I-5 suggests that the wind and solar resources would be BES components where their
singular contribution has no appreciable impact to the BES. Including the bottleneck option seems to identify
an aggregate BES impact for a loss of a 75 MW block that could have an impact on the BES.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Illinois Municipal Electric Agency

Yes

Please see comments under Question 13.

Yes

Generally agreed but please revise to one Inclusion for I2, I3 and I5 at 75 MVA, see Question 3 and 4
comments.

Response: See response to Q13.
Idaho Power

Response: The SDT believes that Inclusion I4 (formerly Inclusion I5) is sufficiently distinct from Inclusion I2 that it needs to be retained. No change made.
MEAG Power

Yes

This inclusion should be specific to the type of generation that the team envisioned it to capture (e.g. wind and
solar). Since the term “dispersed power producing resources” can be interpreted to include generation
resources from a few KW up to 50 MW, this inclusion can be misinterpreted to include “peaker GT’s”, fuel
cells and microturbines, etc.

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Michgan Public Power Agency

August 19, 2011

Yes

I would suggest I5 be revised to say Wind farm or solar power installation with aggregate capacity greater

201

Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

Organization

Yes or No

Question 6 Comment
than 75 MVA (gross aggregate nameplate rating) utilizing a collector system

Response: The SDT re-worded the definition to address these concerns.
Inclusion I5 has been re-numbered as Inclusion I4.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
Sierra Pacific Power Co d/b/a NV
Energy

Yes

Similar to the response to Q4, the 75MVA has no technical basis as being a threshold for determining
necessity in the reliable operation of the interconnected transmission system; however, no technical data
supports an alternate value.

Sweeny Cogeneration LP

Yes

The threshold for widely distributed and aggregated generation units (wind farms) is consistent with the NERC
functional registry criterion.

Public Service Enterprise Group
LLC

Yes

Tri-State Generation and
Transmission Association, Inc.

Yes

SERC Planning Standards
Subcommittee

Yes

ACES Power Participating
Members

Yes

SERC OC Standards Review
Group

Yes

National Rural Electric
Cooperative Association
(NRECA)

Yes

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Organization

Yes or No

Overton Power District No. 5

No

Arizona Public Service Company

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

Southern Company

Yes

Luminant Energy

Yes

Western Area Power
Administration

Yes

US Bureau of Reclamation

Yes

Grand Haven Board of Light and
Power

Yes

Glacier Electric Cooperative

Yes

FHEC

Yes

South Texas Electric
Cooperative, Inc.

Yes

National Grid

Yes

Dayton Power and Light
Company

Yes

ExxonMobil Research and
Engineering

Yes

August 19, 2011

Question 6 Comment

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Organization

Yes or No

Alberta Electric System Operator

Yes

South Carolina Electric and Gas

Yes

Florida Keys Electric Cooperative

Yes

American Electric Power

Yes

East Kentucky Power
Cooperative, Inc.

Yes

Farmington Electric Utility System

Yes

Colorado Springs Utilities

Yes

Consumers Energy Company

Yes

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

Yes

Puget Sound Energy

Yes

GTC

Yes

Long Island Power Authority

Yes

Cogentrix Energy, LLC

Yes

Manitoba Hydro

Yes

ISO New England, Inc.

Yes

August 19, 2011

Question 6 Comment

No comment.

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Organization

Yes or No

City of Anaheim

Yes

Golden Spread Electric
Cooperative, Inc.

Yes

Question 6 Comment

Response: Thank you for your support. Based on stakeholder comments, the SDT made some modifications to the inclusion. After consulting with the NERC
Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply
isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the
directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC
Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization Request
(SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations. Please see the revised definition.

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7. The SDT has added specific exclusions to the core definition in response to industry comments. Do you agree
with Exclusion E1? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: The SDT believes that the changes made to the wording of the definition based on comments received will
provide clarity and address the concerns provided by the commenters. In particular the SDT clarified the point of connection, removed the
automatic interrupting device, moved the concept of the normally open switch to a note, and clarified the generation allowed within the system.
In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local
networks.
The SDT realizes that a bright-line definition may require entities to seek exceptions through the Rules of Procedure exception process.
This BES definition does not address protection or control systems. Standards and requirements can be written against components that are not
BES Elements.
The SDT does not specify the type of normally open switch that will be used to separate the systems described in Exclusion E1 but understands
that any such switch needs to be operated in such a fashion that insures safety, utilizes the best operating practices, and maintains reliability.
Changes due to industry comments are as follows:
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real
Power and Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is
modified by the list shown below. This does not include facilities used in the local distribution of electric energy.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of
connection of 100 kV or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to
allow for reliable system reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to
c)

75 MVA (gross nameplate rating). Or,
Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in
Inclusions I2, I3, I4 and I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

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Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this
exclusion.

Organization
Public Service Enterprise Group
LLC

Yes or No
No

Question 7 Comment
Again, in similar comments to item 1 above, where is the BES line of demarcation between BES elements
(the interrupting device itself) connecting the non-BES radial system?
The term “Generation resource” is not defined and open for interpretation.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.
The SDT believes that generation resource is a widely used and understood term and therefore, a definition is not required.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Northeast Power Coordinating
Council

August 19, 2011

No

The concept is consistent with the statements in the FERC Order. However, it is imperative to understand
that the limitations of E1 will have a direct impact on many entities (big and small) along with distribution
companies across North America. The exclusion requirements are restrictive and these restrictions mayhave
an adverse affect on future transmission investment, for example the addition of a second line removing the
radial status exclusion. Consideration should be given to allowing entities to build additional transmission and
not automatically compromise the exclusion status of any given facilities. For example, a redundant double
circuit designed to supply the load with adequate protection and isolation beyond the radial tap could be

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Organization

Yes or No

Question 7 Comment
significantly better for load supply-continuity and reliability. If more than one transmission source feed radial
load to ensure customer supply continuity and reliability, then this should be either part of the bright-line
definition E1 exclusion as long as there is adequate protection and, the loss of any single transmission source
does not affect the interconnected transmission network.
The SDT should:
o Carefully craft the exception criteria and procedure that is flexible and technically sound to adequately allow
entities to present their case to the ERO for exclusion
o Exception criteria should be at a high-level with items of assessment that can be followed continent-wide
by entities to put forward their exception for element(s) mentioned in exclusions or inclusions based on
technical assessment, evidence and justification for its unique characteristics, configuration, and utilization
o Acknowledge and provide provisions in both NERC exception criteria and exception process for federal,
state and provincial jurisdictions.

Tri-State Generation and
Transmission Association, Inc.

No

A “single Transmission source” is unclear and may be interpreted differently by different Regional Entities. A
circuit switcher-protected transformer serving only distribution load may be tapped to a single transmission
line but the transmission line has two or more sources. Is the system then connected to a single
Transmission source, thus making it radial and being excluded? Or will the Regional Entity declare that, since
the transmission line has two sources that the radial system also has two sources?
We suggest changing the opening sentence of Exclusion E1 to “Any radial system that is connected to a
Transmission source through an automatic interrupting device or devices and:”

American Municipal Power and
Members

No

The words “described as” should be deleted from the exclusion to avoid confusion. What matters is how the
system is actually connected, not how someone describes it.
In addition, “a single Transmission source” could be defined, and should be generic enough to encompass the
various bus configurations. It is not the case, for example, that each individual breaker position in a ring bus
is a separate Transmission source; in that case, a bus at one voltage level at one substation should be
considered “a single transmission source.” Some examples of configurations that should be considered a
single transmission source for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples 1-6.
The phrase “automatic interrupting device” should be replaced with the phrase “switching device”.” Many
radials are connected to ring buses or breaker-and-a-half schemes where the breakers (automatic interrupting
devices) are within the bus arrangement where the appropriate division between BES and non-BES is at the
disconnect switch as the radial “takes off” from the bus arrangement.

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Organization
Central Maine Power Company

Yes or No
No

New York State Electric & Gas
and Rochester Gas & Electric

Question 7 Comment
The definition of radial needs to be clear and comply with Order 743. We do not know what a radial “system”
is.
Also, “automatic interruption device” is not defined.
This exclusion includes “radial” “systems” with more than one supply from a single “source” - including
normally-open switches, even those which are intended to be normally closed before further switching takes
place (“make-before-break”). This seems to be a problem, per Order page 32. We suggest a compliant and
straightforward “radial” exclusion, and recommend that E1 be replaced with, “Those Transmission Elements
interconnected to only one other substation through only one transmission line; except those elements
included in I2, I3, and I5.” It is clear and it can be applied in a “bright-line”, consistent fashion.

Intellibind

No

Small radial systems that have two interconnection points at the same location or very close to the same
location, but are not used for Transmission flow through should also be excluded. There are numerous
examples of two interconnection points that are paralleled by much higher voltage systems and do not flow
power through the system, but are redundant to increase distribution reliability. This should be left to the
Transmission Operator/Transmission Owner to determine if there is flow through and impact to the BES
before designating these as BES assets based on interconnection points. Radial should be defined as power
flowing one direction only, not based on how it is interconnected to 100KV or higher lines.

Hydro-Quebec TransEnergie

No

It is too much restrictive to refuse exclusion of radial system when they have generator greater than 20 MVA,
or multiple generating units of aggregate capacity greater than 75 MVA, especially when a system is able to
function reliably with the loss of generation much higher than this amount. The fact that no Reliability
Standards apply to generators excluded from BES is problematic. Generators should be allowed to be
excluded but reliability standards should apply to them in specific.
Also, the connection through only a single Transmission source is again too restrictive. Other Transmission
source could be used for load continuity of service and the restriction should be limited to radial transmission
paths where the power flow is greater than the first contingency lost.

National Grid

No

We feel that there might be some confusion between I1 and E1 because while I1 only includes transformers
with 2 windings greater than 100kV, E1 specifically says a tap must have an automatic interruption device to
be excluded.So, we are concerned that radial tapped lines with a transformer whose low-side voltage is less
than 100kV, but do not have an automatic interruption device are not excluded. We would like to see some
additional clarity in this exclusion to address this situation
Does automatic interruption device only include breakers/circuit switchers? Would a device such as a
motorized loadbreak be considered an automatic interruption device? If motorized loadbreaks are also

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Organization

Yes or No

Question 7 Comment
considered as an automatic interruption device, then there would be less confusion between E1 and I1. We
also request that this issue be addressed by adding clarity to the exclusion.
Another concern is that this exclusion requirement is restrictive and may have an adverse affect on future
transmission investment for redundant radial supply to improve local load service, for example the addition of
a second line removing the radial status exclusion. Consideration should be given to allowing entities to build
additional transmission without automatically compromising the exclusion status of any given facilities.

CenterPoint Energy

No

CenterPoint Energy believes that some radial systems described in Exclusion E1 are similar to the local
distribution networks (LDNs) described in Exclusion E3. A radial system may be connected to more than one
automatic interrupting device in certain substation designs, such as a ring bus configuration. CenterPoint
Energy believes similar wording should be used for Exclusion E1 and Exclusion E3. Utilizing wording from
Exclusion E3, CenterPoint Energy recommends changing the beginning of Exclusion E1 to “Any radial system
which is described as separable by automatic fault interrupting devices: Wherever connected to the BES, the
radial system must be connected through automatic fault-interrupting devices; and:”.

ISO New England, Inc.

No

The definition of radial needs clarification; we suggest “fed from a single transmission source, i.e. fed from a
single substation at a single voltage”. It is clear and it can be applied in a “bright-line”, consistent fashion.
As currently drafted, if the interruption device is not automatic, E1 would not exclude tapped “radial - i.e.
single fed” equipment. Does the SDT mean to imply that even transformers which do not have an automatic
interruption device on the high side, but have low voltage side at lower than 100 kV, will be considered part of
the BES? If so, is the BES considered to extend to where the circuit has an automatic interruption device?
Would the bus conductor and leads to the high side of the transformer be BES? This would not be
acceptable if the answer is yes. It is important to keep in mind that the in the instance of a radial line served
via a tap, the system needs to be designed for loss of the line in any event and requiring an automatic
switching device is not necessary.In short, the term radial should be better defined and the requirement for an
automatic interruption device should be eliminated.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the
normally open switch to a note, and clarified the generation allowed within the system.
In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local networks. The SDT
realizes that a bright-line definition may require entities to seek exceptions through the Rules of Procedure exception process.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:

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Organization

Yes or No

Question 7 Comment

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems does not affect this exclusion.
NERC Staff Technical Review

No

Exclusion E1 would be acceptable if (i) switching the radial system to connect it to the BES at a second point
of interconnection is modified to require that when a make-before-break connection is used, it occurs at a
voltage below 100 kV and (ii) the automatic interrupting device is not excluded as part of the radial system.
>>>>>>>>>>
The allowance for make-before-break connections of radial facilities at voltages 100 kV or higher will result in
operating conditions with the potential to degrade system reliability if the subject Elements are not planned,
designed, maintained, and operated in accordance with NERC Reliability Standards. The risk is most
pronounced when the make-before-break connection is automated, increasing the likelihood of adverse
reliability impacts occurring as a result of placing the system into an unplanned operating condition. If the
make-before-break connection is made at a voltage below 100 kV the impedance in the parallel connection
will mitigate the reliability impact. When the radial system is connected to the BES at a second point of
interconnection 100 kV or higher, the radial system should not be excluded unless a break-before-make
connection is used because system protection during the momentary parallel network operation is critical to
overall BES reliability. >>>>>>>>>>
The reason for requiring an automatic interrupting device between the BES and the excluded radial system is
to prevent faults and other abnormal conditions on the radial system from negatively impacting reliability of
the BES. Given the reliance on the interrupting device to support BES reliability, it is appropriate to include
the interrupting device in the BES so that it is planned, designed, maintained, and operated in accordance
with NERC Reliability Standards the same as other BES Elements. Thus, when excluding a radial system
operated at 100 kV or higher, the BES line of demarcation should be on the load side of the automatic
interrupting device. >>>>>>>>>>
The main clause and part (a) of the exclusion should be changed to read; >>>>>>>>>> Exclusion E1 - Any
radial system which is described as connected from a single Transmission source originating on the load side
of an automatic interruption device and:a) Only serving Load. A normally open switching device between

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Organization

Yes or No

Question 7 Comment
radial systems may operate in a ‘break-before-make’ fashion at 100 kV or higher or a ‘make-before-break’
fashion below 100 kV to allow for reliable system reconfiguration to maintain continuity of electrical service.
Or, etc. ...

Small Entity Working Group
(SEWG)

Yes

Yes, with some minor changes. Delete the words “described as” in the sentence: Any radial system which is
described as connected from a single Transmission source originating with an automatic interruption device
and. How the radial system is actually connected is important not the description.
The SEWG believes that “a single Transmission source” should be defined in such a way to ensure all the
various bus configurations are captured.
The SEWG recommends modifying the language in E1 to allow for the use of a “switching device” rather than
an “automatic reclosing device” for two specifics situations as follows: 1) When a radial transmission line is
feed from a ring bus, but only serve load and/or non-registered generation: 2) When a radial transmission line
is feed from a breaker and half bus and it only serves load and/or non-registered generation. In both cases,
faults on the radial transmission line will not interrupt network transmission flows and therefore has minimal
impact on the BES.
For direct connection of radial transmission lines to a networked transmission line, the SEWG agrees that an
automatic interrupting device is required to protect the BES.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by most of the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the
normally open switch to a note, and clarified the generation allowed within the system.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.

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Organization

Yes or No

Question 7 Comment

Dominion

No

Dominion can agree with Exclusion E1 only if the exclusion is applied to any radial Facility, regardless of
whether it is used to connect load or generation to the bulk power system.

SPP Standards Review Group

No

We could concur with this exception providing the ‘automatic interruption device’ is not considered a part of
the BES.
Additionally, what are the implications for a radial element connected in a ring bus via two breakers or a radial
element connected via a breaker and a half scheme?

Edison Electric Institute

No

EEI suggests the following change to E1:Any radial system which is described as connected from a single
Transmission source [Delete "originating with an automatic interruption device"] and:

Idaho Falls Power

No

This exclusion speaks to radial systems with generation resouces not identified in I2, I3, I4, or, I5, thus
seemingly only to apply to generation resouces smaller than 20MVA. We wonder why this exclusion then
exists as these resources are already excluded by not being large enough to fall under the registry criteria,
and thus need not comply with the reliability standards.

Tennessee Valley Authority

No

We suggest the first statement in E1 to read, “Any radial system connected to a single BES transmission
source, operating with an automatic interruption device, including the facilities between the connection to the
transmission source and the automatic interruption device which are within the transmission source’s zone of
protection, and:”

New York State Reliability
Council

No

E1 too prescriptive. Suggest developing a general, flexible definition of radial system in NERC Glossary such
as "A system connected from a single Transmission source originating with an automatic interruption device".

New York Power Authority

No

The definition of Exclusion E1 does not cover radial systems that are connected to a single transmission
source by more than one automatic interruption device, such as occurs with a “breaker-and-a-half”
arrangement. The definition should be modified as follows:”Any radial system which is described as
connected from a single Transmission source originating with one or more automatic interruption devices and:
....”This exclusion uses many terms that are not defined under NERC’s standard definitions: “radial load”,
“automatic interruption device” and “make-before-break”. If these terms are used to define an exclusion and
can be understood or interpreted differently by different people, then the terms should be formally defined.

Electricity Consumers Resource
Council (ELCON)

No

The existing language in the NERC Statement of Compliance Registry for radial exclusions should be
maintained since the change proposed by the SDT could result in a significant increase in entities and/or
facilities that would have to be registered or included (because of the addition of the automatic interruption

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Organization

Yes or No

Question 7 Comment
device). The burden for proving the need for such significant changes should be placed on the ERO and the
Regional Entities through the BES Exception Process, not on the users of the BES. In particular, it could
force retail load (customers) to register as transmission owners, or engage in other maneuvers to avoid
registration, when this is clearly a transmission owner/customer issue (as to whether to install automatic
interruption devices). These lines are non-jurisdictional and are obvious under the purview of the state
commissions.

The Dow Chemical Company

No

The existing language in the NERC Statement of Compliance Registry for radial exclusions should be
maintained since the change proposed by the SDT could result in a significant increase in entities and/or
facilities that would have to be registered or included (because of the addition of the automatic interruption
device). See ELCON comments for additional details.

Grand Haven Board of Light and
Power

No

Exclusion E1 addresses a radial, load serving system, but it does not address whether the automatic
interrupting device should be defined as a part of the BES or not. In our case, the ONE automatic interrupting
device that we own would force us to register as a TO/TOP, and as a result incur significant costs. This does
not comply with FERC Order No. 743 (and No. 743a) and should be addressed in this exclusion if not in the
core definition.

FHEC

No

Suggest the word single be moved later in the sentence, see below-From: E1 - Any radial system which is
described as connected from a single Transmission source originating with an automatic interruption device
and: To:E1 - Any radial system which is described as connected from a Transmission source originating with
a single automatic interruption device and:

ExxonMobil Research and
Engineering

No

The inclusion or exclusion of radial lines serving load should not be contingent on whether the radial line is
isolated by a single automatic fault interrupting device. Many of the radial lines impacted by the requirement
for the presence of an automatic fault interrupting device are industrial companies that are fed via 138 kV and
230 kV systems that are hard-tapped or fed from breaker and a half or ring buss transmission substations.
The requirement for the installation of an automatic fault interrupting device on the radial line is predicated on
the assumption that an event on a hard-tapped line serving load will produce a negative impact on the
interconnected transmission network. Accepting this assumption as a true fact, the SDT is following the logic
that they should expand the scope of the interconnected transmission network to include the hard-tapped line
(used to locally distribute power) due to the fact that the transmission owner has neglected to properly protect
their facilities from the impact of an event on the hard-tapped line. In effect, the SDT is allowing the
transmission planner to take credit for protective devices installed on the distribution network when they
conduct their contingency studies as part of NERC Reliability Standards TPL-002 and TPL-003; thus shifting
the responsibility of protecting the interconnected transmission network from the owners of the transmission
network to the customers and their local distribution facilities. The SDT should revisit their assertion that

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Organization

Yes or No

Question 7 Comment
facilities should be included based on the presence of an automatic fault interrupting device based on the fact
that if a contingency study indicates that an automatic fault interrupting device should be present in order to
preserve system stability or prevent a cascading outage during an N-1 or N-2 contingency, the transmission
planner should be recommending such a device is installed on the interconnected transmission system and
not a customer owned facility or any facility used to locally distribute electric power. It is inappropriate to let
transmission owners take credit for customer owned and local distribution facilities in their reliability studies
and require customer’s and local distribution facilities to protect the interconnected transmission network
when those facilities are explicitly excluded from the bulk power system in Section 215 of the Federal Power
Act and the interconnected transmission system is owned and operated by entities that the customers and
local distribution facility owners pay to provide them with reliable transmission service.

MidAmerican Energy Company

No

The statement “originating with an automatic interruption device” seems to go beyond differentiating what is
radial. If that were removed, the rest of the draft exclusion seems to capture what is radial.

Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

No

(Note: Inserted language provided in brackets; deleted language denoted by empty brackets: [ ].) Exclusion
E1 contradicts the plain language of Section 215 of the Federal Power Act (“FPA”), which denies FERC
jurisdiction over facilities used in the local distribution of electric energy (16 U.S.C. § 824o(a)(1) (stating the
Bulk Power System “does not include facilities used in the local distribution of electric energy”)). For example,
Exclusion E1 would impermissibly include within the definition of the Bulk Electric System (“BES”) a retail
customer’s self-provided “hard-tapped” radial line that is located behind the retail delivery point. The
Standard Drafting Team (“SDT”) stated in commentary to Exclusion E1 that it has clarified the existing
exclusion for radial systems by specifying that protection for the BES is a required element, and that it
believes that faults on radial lines without protection devices could negatively impact the BES. Even if faults
on radial lines could negatively impact the BES, however, radial lines that are used in local distribution of
electric energy are outside of FERC’s jurisdiction. Congress did not place any qualifications on the exclusion
of facilities used in the distribution of electric energy, and certainly did not make the exclusion contingent on
whether the facility is “originating with an automatic interruption device.” Exclusion E1 would rewrite Section
215 of the FPA to exclude from the definition of the BES only “facilities [with an automatic interruption device]
used in the local distribution of electric energy.” Such an interpretation, as discussed further below in
response to Questions 11 and 12, is unlawful as it is in direct contravention of Congress’ intent. To make
Exclusion E1 consistent with the jurisdictional requirements of Section 215 of the FPA, Exclusion E1 could be
rewritten as follows:Any radial system which is described as connected from a single Transmission source [ ]
and: a) Only serving Load. [ ] Or, b) Only including generation resources not identified in Inclusions I2, I3, I4
and I5. Or, c) Is a combination of items (a.) and (b.) where the radial system serves Load and includes
generation resources not identified in Inclusions I2, I3, I4 and I5. Please see further discussion in response to
Questions 11, 12 and 13.

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Organization

Yes or No

Question 7 Comment

Alliant Energy

No

We believe the first sentence should be revised to read “Any radial system which is described as connected
from a single Transmission source at 100 kV or above originating with . . .” In this way it is clear that E1
covers radial transmission, not radial distribution systems.

Exelon

No

Exelon points out that this is another case where facilities used in local distribution of electric energy that are
presently under state jurisdiction might be included in the BES. Depending on the location of the automatic
interrupting device, the radial facilities in between the tap point at the transmission sources and the
interrupting device would be included in the BES.

City of St. George

No

Radial systems should be excluded as outlined in E1a; however the generation level requirements of 20 MVA
and 75 MVA (I2, I3, & I5) should be revisited. As long as the normal power flow is into the radial system, the
amount of generation on a radial segment should not automatically trigger an inclusion to the BES.

Golden Spread Electric
Cooperative, Inc.

No

We recommend modifying "Any radial system which is described as connected from a single Transmission
source originating with an automatic interruption device and..." to read EITHER1. "Any radial system which is
described as connected from a single Transmission source and... [remove originating with an automatic
interruption device ] OR2. "Any radial system which is described as connected from a single Transmission
source originating with an automatic interruption device or manual isolating switch..."

Michigan Public Service
Commission(MPSC)

MPSC Staff Comments: The MPSC supports this exclusion with the exception that Inclusion I2 should be
removed from the E1(c) provision. Keeping the I2 here will result in too many subtransmission load-serving
elements losing their non-BES status.

Georgia System Operations

A. The phrase “which is described as” is unclear. If the intention is to mean “which is defined as,” the term
“Radial System” should be capitalized and added to the glossary. Otherwise, consider deleting the phrase.
B. It is not clear whether the automatic interruption device on the excluded system is itself in or out of the
BES. Can the drafting team clarify this intent with respect to breakers protecting radial lines (perhaps
compared to circuit switchers protecting load serving transformers)? Drawings could be very beneficial here.
C. The second part of sub-bullet “a” (the sentence beginning “A normally open switching device...”) applies
not only to “a” but to all the sub-bullets, and therefore should be moved to either the initial sentence or to be a
closing item after the last sub-bullet. For example, if the sub-bullets are indented, and then this sentence
returns to the original margin, that would show that it applies to any “radial system” and not just to a system
falling under a single sub-bullet.

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Organization

Yes or No

United Illuminating

Florida Municipal Power Agency
Florida Keys Electric Cooperative

Question 7 Comment
UI suggests the following change to E1 eliinating the automatic device:Any radial system which is described
as connected from a single Transmission source.These taps are not necessary for the opeation of the
interconnected system.

Yes

FMPA agrees with the intent / concept, but has suggested wording changes to add clarity.The words
“described as” should be deleted from the exclusion to avoid confusion. What matters is how the system is
actually connected, not how someone describes it.
In addition, “a single Transmission source” should be defined, and should be generic enough to encompass
the various bus configurations. It is not the case, for example, that each individual breaker position in a ring
bus is a separate Transmission source; in that case, a bus at one voltage level at one substation should be
considered “a single transmission source.” Some examples of configurations that should be considered a
single transmission source for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples 1-6.
The phrase “automatic interrupting device” should be replaced with the phrase “switching device.” Many
radials are connected to ring buses or breaker-and-a-half schemes where the breakers (automatic interrupting
devices) are within the bus arrangement where the appropriate division between BES and non-BES is at the
disconnect switch as the radial “takes off” from the bus arrangement.As written, E1 would eliminate most
radials from automatic exclusion and force most of them into the Exception Procedure. For instance, see
examples 2 of the FRCC draft BES definition Appendix A at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf).Switch "A" in example 2 is
usually not automatic. Breaker D and E are automatic. Switch A is radial, Breakers D&E may not be. FMPA
recommends replacing "automatic interrupting" with "switching" and allow manual switching devices to
establish the boundary between BES and non-BES, otherwise we get into splitting up ring-buses or breakerand-a-half schemes, or flooding the Exception Procedures with a lot of needless requests.Also, "device" is
singular whereas the exclusion is for a "radial system". I presume that the SDT intends that if there are two
lines originating at the same substation supply a load in a redundant nature, that the "radial system" would be
excluded (see examples 1, 3 and 4 of the FRC draft BES Definition Attachment A), which would mean there
would be more than one device.Also, the phrase "A normally open switching device between radial systems
may operate in a ‘make-before-break’ fashion to allow for reliable system reconfiguration to maintain
continuity of electrical service." is misplaced in bullet a) and belongs in the non-bulleted section.FMPA
recommends re-wording E1 to be:"Any radial system which is connected from a single Transmission source
(such as a contiguous bus configuration like a ring bus or breaker-and-a-half scheme) originating with
switching device(s) and meeting the criteria in bullets a, b or c below. A normally open switching device
between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service.a) Only serving Loadb) Only including generation

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Organization

Yes or No

Question 7 Comment
resources not identified in Inclusions I2, I3, I4 and I5c) A combination of (a) and (b)"

MRO's NERC Standards Review
Forum

Yes

We recommend the phrase “originating with an automatic interruption device” be clarified as to the location of
the interruption device. An entity may not have interruption devices at both ends of a radial fed line. If the
interruption device is at the load end of the radial line, then the “up-stream” portion of the radial line is
unprotected. Please clarify.Please add the Brightline Criteria that all facilities less than a 100kV are excluded
unless those facilities meet the criteria of an Inclusion.

Hydro One Networks Inc

Yes

We agree with this concept as part of establishing a bright-line definition, as well as clarifying this exclusion as
part of the revised BES definition. Although the concept is consistent with the statements in the FERC Order,
it is imperative to understand that the limitations of E1 will have a direct impact on many entities (big and
small) along with distribution companies across North America. The exclusion requirements are extremely
restrictive with little or no technical basis and are limited to the fact that these parametric restrictions may not
have any reliability impact in terms of location, configuration of element, and system characteristics. The
radial characteristics and/or the reliability of the interconnected transmission network should not be
determined by the amount of installed generation or a single transmission source or an interrupting device.
For example, a redundant double circuit designed to supply the load with adequate protection and isolation
beyond the radial tap could be significantly better for load supply-continuity and reliability. We suggest if more
than one transmission source feed radial load to ensure customer supply continuity and reliability then this
should be either part of the bright-line definition as long as there is adequate protection and, the loss of any
single transmission source does not affect the interconnected transmission network.
We suggest SDT to consider revising E1 as follows:Any radial system which is described as connected from a
single Transmission source originating with an automatic interruption device or can be isolated with adequate
protection without affecting the BES and: a) Serves load, or, b) Includes generation resources not identified
in Inclusions I2, I3, I4 and I5, unless excluded by E2, or, c) Has any combination of items (a) and (b). The
radial system can have a normally open switching device for connecting it to a second Transmission source in
a ‘make-before-break’ fashion to allow for reliable system reconfiguration to maintain continuity of electrical
service.

National Rural Electric
Cooperative Association
(NRECA)

Yes

NRECA requests that the drafting team state explicitly whether the automatic interruption device is included or
excluded from the BES.
Examples of automatic interruption devices should be included in a reference or FAQ document, and
drawings/diagrams on typical configurations would be beneficial.
Consistent language is needed in the Inclusions/Exclusions. E1 states “automatic interruption device” and
E3(a) states “automatic fault interrupting devices.” NRECA recommends adding the word “fault” as in E3(a)

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Organization

Yes or No

Question 7 Comment
and also stating “device(s)” in E1 and E3(a) and wherever else the phrase may be used in the BES definition
and inclusions/exclusions.Additional clarification is needed in explaining E1(c) to ensure industry understands
the scenario.

ReliabilityFirst

Yes

teh term "Single Transmission Source" needs defined, and as well what elemnents are defined by "automatic
interrupting devices" there is debate out in the industry.

Transmission Access Policy
Study Group

Yes

TAPS suggests some clarifying changes:The words “described as” should be deleted from the exclusion to
avoid confusion. What matters is how the system is actually connected, not how someone describes it.

Michgan Public Power Agency

In addition, “a single Transmission source” should be defined, and should be generic enough to encompass
the various bus configurations. It is not the case, for example, that each individual breaker position in a ring
bus is a separate Transmission source; in that case, a bus at one voltage level at one substation should be
considered “a single transmission source.” Some examples of configurations that should be considered a
single transmission source for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples 1-6.
The phrase “automatic interrupting device” should be replaced with the phrase “switching device.” Many
radials are connected to ring buses or breaker-and-a-half schemes where the breakers (automatic interrupting
devices) are within the bus arrangement where the appropriate division between BES and non-BES is at the
disconnect switch as the radial “takes off” from the bus arrangement.

Northern California Power
Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.

Texas Industrial Energy
Consumers (TIEC)

Yes

TIEC supports excluding radial loads serving only load or generation resources that do not trigger NERC
registration requirements. This is consistent with the FERC’s intent and the existing BES definition.
However, TIEC believes that this exclusion should not be contingent upon a radial system “originating with an
automatic interruption device” as proposed by the SDT. Radial feeds serving a system that contains only load
and generation that does not trigger registration requirements should be categorically excluded from the BES
definition regardless of whether the radial lines originate with an automatic interruption device. It should be
the responsibility of the transmission provider to ensure that its facilities and interconnection properly protect
the grid from facilities that fall under this exclusion, just as the transmission providers do for other load and
unregistered generation. The absence of automatic interruption device should not trigger inclusion as a part
of the BES, but should trigger a requirement upon the transmission provider to install such a device on its side
of the facilities or take other measures to insulate the grid from the activities of a radial network. Accordingly,
TIEC would proposed to strike the phrase “originating with an automatic interruption device” from the

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Organization

Yes or No

Question 7 Comment
proposed exclusion language.

National Association of
Regulatory Utility Commissioners

Yes

We agree with Exclusion E1. Radial systems are clearly local distribution and excluded from FERC and
NERC jurisdiction. This is consistent with FERC Order 743 and 743a (see e.g. Order 743A P 1, 76 Fed. Reg.
16264 (March 23, 2011)). We suggest that I2 be removed from this exclusion (and from the standard as a
whole) as discussed in response to question 3.

Oregon Public Utility Commission
Staff

Yes

Exclusion I as currently proposed adequately defines radial systems; however, Inclusion I2 language should
be removed per the rationale stated in the response to Question 3 above. To retain the Inclusion I2 language
herein would sweep in an abundance of distribution elements that have no impact on the reliable operation of
the interconnected bulk transmission system.

PUD No. 2 of Grant County,
Washington

Yes

E1 specifically states “Any radial system which is described as connected from a single transmission source
originating with an automatic disconnection device and...”. The example of concern is a radial tap to a single
distribution power transformer that is connected to a ring bus or breaker and a half bus. In this case the
transformer would have 2 automatic disconnection devices from what is essentially a single source. Typically
ring bus and breaker and a half bus are used to improve reliability, limiting the exclusion to a single
disconnecting device appears to bring a hypothetical radial tap fed from a ring bus or breaker and a half bus
into the BES definition. Although the LDN exclusion might apply there is the potential for many situations
where it might not.A possible remedy is to revise the exclusion as follows:”Any radial system which is
described as connected from a single transmission source that originates with automatic disconnection
device(s) and...”
In addition, a definition for “a single transmission source” should be provided to clarify the intent.
Suggestion:”A single transmission source would be any transmission source located within a single facility,
yard or fenced area and electrically continuous at a single voltage level”.

FortisBC
AltaLink

August 19, 2011

Yes

We agree with this concept as part of establishing a bright-line definition, as well as clarifying this exclusion as
part of the revised BES definition. Although the concept is consistent with the statements in the FERC Order,
it is imperative to understand that the limitations of E1 will have a direct impact on many entities (big and
small) along with distribution companies across North America. The exclusion requirements are extremely
restrictive with little or no technical basis and are limited to the fact that these parametric restrictions may not
have any reliability impact in terms of location, configuration of element, and system characteristics. The
radial characteristics and/or the reliability of the interconnected transmission network is determined by the
amount of installed generation or a single transmission source or an interrupting device. For example, a
redundant double circuit designed to supply the load with adequate protection and isolation beyond the radial
tap could be significantly better for load supply-continuity and reliability. We suggest if more than one

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Organization

Yes or No

Question 7 Comment
transmission source feed radial load to ensure customer supply continuity and reliability then this should be
either part of the bright-line definition as long as there is adequate protection and, the loss of any single
transmission source does not affect the interconnected transmission network.
Accordingly, it will be an understatement to suggest that the SDT:
o Carefully craft the exception criteria and procedure that is flexible and technically sound to adequately allow
entities to present their case to the ERO for exclusion
o Exception criteria should be at a high-level with key menu items of assessment that can be followed
continent-wide by entities to put forward their exception for element(s) mentioned in exclusions or inclusions
based on technical assessment, evidence and justification for its unique characteristics, configuration, and
utilization
o Acknowledge and provide provisions in both NERC exception criteria and exception process for federal,
state and provincial jurisdictions.

American Electric Power

Yes

AEP supports the concept of the exclusion of radial systems, however further clarification is needed regarding
whether or not the source equipment is included as part of the radial system (for example, ring bus or breaker
and a half bus configurations). In addition, “automatic interruption device” should be defined to alleviate any
ambiguity.

East Kentucky Power
Cooperative, Inc.

Yes

EKPC has a concern with the wording of the definition for Exclusions:E1 - Any radial system which is
described as connected from a single Transmission source originating with an automatic interruption device
and:a) Only serving Load. A normally open switching device between radial systems may operate in a ‘makebefore-break’ fashion to allow for reliable system reconfiguration to maintain continuity of electrical
service.”This wording leads EKPC to believe that a radial 138 kv line that steps down into a 69 kv looped
system that have no facilities included in the BES would not be excluded as radial. This line cannot have any
more impact on the BES than the 69 kv system it connects to that is excluded from the BES. Therefore I
would add to exclusion E1a, “or only connecting to a transformer stepping down to a voltage below 100kv”.

American Transmission
Company, LLC

Yes

ATC offers the following alternative language:ATC suggests replacing the wording of “connected from a single
Transmission source” with “connected to the Bulk Electric System”.
Furthermore, ATC believes that Exclusion E1 is appropriate and should be part of the definition of the BES.
However, ATC believes that a registered entity should be given the option to not be required to follow the
exclusions in the E1 criteria. Some registered entities for operational and business purposes may wish to
continue to classify their radial system assets, which are operated above 100 kV, as BES components.

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Organization

Yes or No

Question 7 Comment

Muscatine Power and Water

Yes

MP&W recommends to clarify the phrase “originating with an automatic interruption device” regarding the
location of the interruption device. An entity may not have interruption devices at both ends of a radial fed
line. If the interruption device is at the load end of the radial line, then the “up-stream” portion of the radial line
is unprotected. Furthermore, please make it unambiguous that all facilities operated at less than a 100kV are
excluded unless those facilities meet the criteria of an Inclusion.

Sacramento Municipal Utility
District (SMUD)

Yes

SMUD support with the Exclusion 1 concept. However to maintain the clarity for a “Bright-line” the term
“single Transmission source” needs to be expanded as it could be read to be a single line, common bus or a
single entity, that will change the meaning of this exclusion.

GTC

Yes

Agree, but further clarification requested. E1 reads as if the originating automatic interrupting device is to be
excluded with the radial system. Can the drafting team clarify this intent with respect to breakers protecting
radial lines versus for example a breaker or circuit switcher protecting an excluded transformer which is not
part of the BES? Drawings would be very beneficial here.

Illinois Municipal Electric Agency

Yes

With the following clarifying edits. Delete the words “described as” in the first sentence.
Also, “a single Transmission source” should be defined to encompass various bus configurations. For
example, an individual breaker position in a ring bus is not a single Transmission source, but a bus at one
voltage level at one substation should be considered a single Transmission source.
Also, the phrase “automatic interrupting device” should be replaced with the phrase “switching device”. The
current wording does not take into account that a radial system is often connected to a ring bus or a breakerand-a-half scheme where the breaker/automatic interrupting device is within the bus arrangement. The
appropriate division between BES and non-BES is at the disconnect switch where the radial line attaches to
the bus arrangement.

Public Utilities Commission of
Ohio

Yes

Exclusion E1 is appropriate. However, any inclusion that are inconsistent with this exclusion should be
eliminated. Any facility that has an impact on the bulk system could be considered for inclusion under a case
by case basis.

Long Island Power Authority

Yes

For clarification purposes, we understand “Transmission source” to be a substation and not a line. A
substation connected to only one other substation “source” by two lines would still be considered radial and
thus excluded.

Idaho Power

Yes

Generally agreed assuming that the make-before-break may be performed manually.

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Organization
New England States Committee
on Electricity

Yes or No

Question 7 Comment

Yes

NESCOE generally supports these exclusions. However, NESCOE also notes that subsections (b) and (c)
could (depending on the final definition of Inclusions I2 through I5) sweep many sub-transmission load serving
elements into the BES, at a cost that is not justified in terms of reliability benefits.
Regarding sub transmission, Exclusion Criteria E1 and E2 are concerned with radial configurations while E3
relates to Local Distribution Networks (LDN’s). None of these apply to sub transmission networks that may
contain both looped and radial configurations. Also, sub transmission networks may have power flowing
parallel to the BES and may have power flowing into the BES with no potential for adverse impact on the
reliability of the BES. Sub transmission networks operated at voltages less than 100 kV, connected to the
BES via non-GSU transformers, should be excluded from the BES regardless of their configuration. It should
be clear that all generation facilities connected to sub transmission are not BES as these units are adequately
covered under other applicable NERC and/or regional reliability criteria. These units have no direct impact on
the reliability of the BES.Regarding facilities at operated at 100 kV and above, the switching configuration as
defined is not clear and possibly overly restrictive. The definition should incorporate language related to
avoiding “parallel paths” with diverse electrical nodes in the BES.

Big Bend Electric Cooperative,
Inc.

Yes

Our only concern about this exclusion is the timeframe we'd have to get an appropriate automatic interruption
device installed. Currently, we have a short radial that hasn't yet caused us to be registered as a TO or TOP.
Having time to get a solution in place would be crucial for us, as a small utility, to avoid additional regulatory
fees and requirements.

Modern Electric Water Company

Yes

Clear exclusionary language for radial systems is absolutely necessary for a usable BES definition,
particularly since radial systems serving load are already excluded from the existing NERC definition, radial
systems serving load can only be used for the local distribution of energy (and are thus excluded by Congress
in Sec. 215 of the FPA), and radial systems serving load have been confirmed excluded from the BES by
previous FERC Orders. However, the proposed language could be improved to be more explicit and further
remove the opportunity for improper/unintended interpretation. The currently-drafted E1 language has several
issues that need to be addressed. For instance: The use of “automatic interruption device” in E1 is not
consistent with “automatic fault interruption device” in E3-a, and could lead to different interpretations.
Another issue is the use of the un-clarified phrase “single Transmission source”, and deserves additional
attention. Presumably, this language exists to describe the commonly-used radial tap from a networked (twostation) line, as detailed in NERC Project 2009-17-Response to Request for an Interpretation of PRC-004-1
and PRC-005-1 for Y-W Electric and Tri-State G&T. In Project 2009-17, diagrams show a radial tap placed on
a line between Station A and Station B, and could be interpreted to indicate that the tap connects to two
sources. Unless “single Transmission source” is clarified, then a radial line originating from a Double-BusDouble-Breaker or a Breaker-and-a-Half station would also connect to two sources.

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Organization

Yes or No

Question 7 Comment
The drafted language does not go far enough to consider how networked lines are operated - sometimes
radially, sometimes with multiple protection and isolation schemes and equipment. As drafted, this exclusion
cannot be utilized by many insignificant taps (some of such insignificant length that no automatic fault
interrupting device was deemed necessary). This situation leaves those insignificant elements to apply the
LDN exclusion whose characteristics are dissimilar to a simple, load-serving radial tap. We support the intent
of the language of E1-a, “A normally open switching device between radial systems may operate in a ‘makebefore-break’ fashion to allow for reliable system reconfiguration to maintain continuity of electrical service....”,
but suggest that it be re-written as follows: “The existence and use of ‘make-before-break’ switching devices,
which temporarily connect otherwise radial load-serving systems to alternate sources for purposes of service
continuity, do not affect the BES status of the system before, during, or after their use.” This clarification is
needed to address a position held in the WECC region (WECC Compliance Bulletin #4, April 15, 2011) that
make-before-break switches render systems part of the BES, and discourage distribution providers from
“reliably” serving their customers.We do not intend to air grievances, but ambiguous radial exclusion language
has led to an extreme misuse of resources in the WECC region. It is imperative that industry and the SDT get
this exclusionary language correct and put into use as soon as possible.In an explanatory bullet below
Exclusion E1-c (herein) the SDT states “The SDT believes that faults on radial lines without protection
devices could negatively impact the BES.” Where this reasoning errs is that it assumes that everything
upstream of a radial element is already determined to be BES. Many radial taps connect to LDN lines without
AFIDs. The language proposed does not allow for a radial exclusion directly, but forces the insignificant tap to
apply the LDN exclusion E3 - E1’s success at being complete depends on another exclusion. Additionally, this
reasoning implies that the mere existence of a AFID is the cure-all to reliability or that technical analysis
hasn’t already established the proper balance of equipment to adequately serve and protect these elements.
We suggest including additional isolation devices as the demarcation point of small radial systems wishing to
apply this exclusion.

Utility System Efficiencies, Inc.

Yes

USE agrees in concept with this Exclusion. However, it is unclear what is required to demonstrate the “makebefore-break” connection. Is this statement intended to mean that the normally-open switch is mechanically or
electrically interlocked to ensure the “make-before-break” requirement is met? It would be a normal switching
practice to close the normally-open switch to make the parallel before opening the normally-closed switch, but
is the normal switching practice sufficient to make this claim? Also, it is unclear whether the automatic
interruption device itself is a part of the BES.

Duke Energy

No

This needs further clarification as to what constitutes a “single Transmission source”. Does having a
double/multiple circuit line(s) from a single transmission station constitute a radial system?.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally

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Organization

Yes or No

Question 7 Comment

open switch to a note, and clarified the generation allowed within the system through changes.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems does not affect this exclusion.
SERC OC Standards Review
Group

No

This exclusion is acceptable if the suggestions in Questions 3 and 4 are incorporated.
We also suggest modifying Exclusion E1a as follows: a) Only serving Load or only connecting to a
transformer stepping down to a voltage below 100kv. A normally open switching device between radial
systems may operate in a ‘make-before-break’ fashion to allow for reliable system reconfiguration to maintain
continuity of electrical service. Or,

Response: See responses to Q3 & 4
The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns provided by
the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally open switch
to a note, and clarified the generation allowed within the system.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and

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Organization

Yes or No

Question 7 Comment

I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Luminant Energy

No

E1 a) Omit or clarify-Sentence beginning “A normally open switch...” Does not say what to do with it. Is it
included or excluded. Suggested wording would be “An example would be a line with a normally open
switching device between radial systems that may operate in a ‘make -before-break’ fashion to allow for
reliable system reconfiguration to maintain continuity of electrical service.” E1
b)-Clarify- Sentence beginning “Only including...”Are those resources that are included in the exclusions that
are not included in the inclusions? Or are they resources that are included in the inclusions that are not
included in the inclusions? This meaning of this sentence is not clear. It should not be necessary to say that
resources are excluded that are not included. Suggested wording would be “Generation resources that are
not specifically described in the Inclusions I2, I3, I4 and I5.”

Response: a) The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the
concerns provided by the respondents. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of
the normally open switch to a note, and clarified the generation allowed within the system.
b) The SDT believes these changes provide clarification to how the Exclusions and Inclusions are related. If a generation resource is included in the Inclusions
then it can not be excluded by the Exclusions. In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple
connections serving local networks. The SDT realizes that a bright-line definition may require entities to seek exceptions through the Rules of Procedure exception
process.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

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Organization

Yes or No

Question 7 Comment

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Vermont Transco

No

Does “a single transmission source” mean a single “substation” at 100 kV or above?
The wording of this exclusion appears to allow distribution (<100 kV) level generating units to be excluded
from the definition of BES. If so then this generation exclusion is appropriate to the FERC order. However,
the definition of “automatic interruption device” should be defined fully. Specifically what types of equipment
are considered an AID? If a transformer has a high side voltage of 115 kV and a low side voltage of 34.5 kV
it would not be part of the BES definition, however depending on how one interprets the exclusion for a radial
feed, if the transformers automatic interruption device were on the low side of this transformer, it appears that
this transformer would then need to be “included” as BES.
In addition, would the protection schemes associated with the breaker failure on the low side of a transformer
(voltage <100 kV) designed to send a signal to the high side (which is greater than 100KV) for a breaker
failure scenario fall into the “included” facilities even though the transformer would not be “included”?

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the respondents. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.
In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local networks. The SDT
realizes that a bright-line definition may require entities to seek exceptions through the Rules of Procedure exception process. This BES definition does not
address protection or control systems. Standards and requirements can be written against components that are not BES Elements.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.

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Organization
Electric Reliability Council of
Texas, Inc.

Yes or No

Question 7 Comment

No

See response to question 1 - while ERCOT ISO does not necessarily disagree with the substance of the
proposed exclusions, it believes all exceptions should occur pursuant to the separate processes and criteria
being developed that will be established in the NERC ROP. The BES definition should be more general in
nature, focusing on objective thresholds. All exclusions should be addressed in the separate proceeding
being conducted in parallel with this proceeding to develop the exception process, and ERCOT ISO reserves
its right to comment on the substance of such proposals in that proceeding.

Southwest Power Pool

Response:
Please see response to Q1.
The SDT has developed a draft core definition, together with BES designations (Inclusions and Exclusions) that provide the specificity necessary to identify the
vast majority of BES Elements by utilizing the existing definition and criteria previously approved for this purpose. The remaining facilities will be candidates for
the Exception Process (RoP) where the Technical Principles will be utilized to determine if the facility is necessary for the reliable operation of the interconnected
transmission network.
Fayetteville Public Works
Commission

No

Exclusion E1 references Inclusions I2 and I3. Therefore the comments provided in Question 3 with respect to
Inclusion I2 are pertinent here as well. The radial system cannot be excluded if it includes any generation
resources that are included in Inclusion I2. The ambiguity that exists in Inclusion I2 could, therefore, also
have consequences in determining if a radial system can be excluded. If the recommended changes are
made in Inclusion I2 then Exclusion E1 is acceptable as is.

Response: The SDT believes these changes provide clarification to how the Exclusions and Inclusions are related. If a generation resource is included in the
Inclusions then it can not be excluded by the Exclusions. In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used
for multiple connections serving local networks. The SDT realizes that a bright-line definition may require entities to seek exceptions through the Rules of
Procedure exception process.
BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

No

BGE generally agrees with the “radial” exclusion, but votes “NO” due to a lack of clarity. The definition does
not make it clear if radial facilities operating above 100 kV with automatic interrupting devices (which would
otherwise be classified as non-BES under exclusion E1, part a) and serving networks operating below 100 kV
are classified as non-BES. We believe E1 should make it clear that such radial facilities are non-BES. BGE
would like to note that under the current RFC BES definition, such facilities are not designated as BES.To
illustrate and clarify the BGE questions, please see the BGE Diagram attached. The BES designations
included on the diagram are BGE’s interpretation of BES facilities under the proposed definition.
Questions regarding the BGE Diagram:1. If the 13.8 kV device TB is operated “normally closed” as shown, is
it the SDT’s understanding that the two 115 kV lines classified as Non-BES in the diagram are no longer

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Organization

Yes or No

Question 7 Comment
considered “radial”?
2. If the SDT does not consider the two 115 kV lines described above as “radial” with device TB closed, would
this configuration be excluded as BES under exclusion E3? Or would the Exception Process be required to
classify such a configuration as non-BES?
See diagram at end of report.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.

The SDT is not in a position to provide advice on specific cases.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Springfield Utility Board

August 19, 2011

No

SUB agrees with the exclusion for radial systems, but would like clarification regarding the definition of
“radial”. SUB appreciates NERC developing a more clear and consistent definition of “radial”. For clarity,
SUB suggests the following language:” o Exclusion E1 - Any radial system which is described as connected
from a single Transmission source originating with an automatic interruption device and that is characterized
by any of the following:a)Only serving Load. A normally open switching device between radial systems with
the same or different transmission sources may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Systems with a normally open switching
device(s) that would otherwise result in a system with more than one transmission source if the switching
device(s) is closed are considered radial systems. Or,b)Only including generation resources not identified in

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Organization

Yes or No

Question 7 Comment
Inclusions I2, I3, I4 and I5. Or,c)Is a combination of items (a.) and (b.) where the radial system serves Load
and includes generation resources not identified in Inclusions I2, I3, I4 and I5?”
As a side note, some in the industry appear to place a demarcation based on whether there is a fuse
separating two systems. SUB is concerned with interpretations that indicate that if there is a fuse, they are
separate. This could result in “closed” systems being considered “open” because there are fuses installed
within the network. For example, consider a 115 kV interconnection point stepped down to distribution level
service with a fuse continues along the distribution network to another fuse that is interconnected to a 115kV
system with another transmission source. Is this fused system closed or open? Is this an intended outcome?
SUB is hopeful that E1 will provide clarity to this issue.

Springfield Utility Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.
In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local networks. The SDT
realizes that a bright-line definition may require entities to seek exceptions through the Rules of Procedure exception process. This BES definition does not
address protection or control systems. Standards and requirements can be written against components that are not BES Elements. The SDT does not specify the
type of normally open switch that will be used to separate the systems described in Exclusion E1 but understands that any such switch needs to be operated in
such a fashion that insures safety, utilizes the best operating practices, and maintains reliability. Fuses are not considered normally open switches.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV

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Organization

Yes or No

Question 7 Comment

or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Southern California Edison
Company

No

SCE cannot support this exclusion as it will only apply if generation on the radial system does not exceed the
criteria identified in I2, I3 and I5. SCE has identified its concerns regarding these aforementioned items in its
previous responses.If the SDT goes forward with E1 criteria, the criteria should be modified as follows:
(i) Delete “originating with an automatic interrupting device.” This statement does not change or describe the
flow to or from a radial system;
(ii) E1 should be modified to identify that generation interconnected to a radial system should not exceed a
measureable threshold of electrical demand on the radial system - an example being “5% occurrence in the
past XXX years”. This would negate some of the concerns identified regarding I2, I3 and I5; and
(iii) SCE also feels that if the core BES definition is to reference protection devices, it should not identify the
particular type of protection device as it did in E1, by specifically calling out “make before break” switching, as
there are other types of protection with similar functionality.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular, the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the
normally open switch to a note, and clarified the generation allowed within the system.
In particular, the SDT has changed the inclusions to further specify what generation resources are included in a radial (refer to Exclusion E1 and Inclusion I3).
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

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Organization

Yes or No

Question 7 Comment

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Cogentrix Energy, LLC

No

This exclusion is acceptable if the suggestions in Questions 3 and 4 are incorporated.

Response: Please see responses to Q3 & 4.
PPL Energy Plus and PPL
Generation

No

See comments in Question 13

No

We agree with the concept of a allowing a radial exclusion from the BES. However, we ask that the term
“device” be modified to include the optional plural; “device(s).” Some radial systems may require isolation by
more than one automatic interrupting device.

Response: See response to Q13.
Consolidated Edison Co. of NY,
Inc.

Response: The SDT has eliminated the automatic interrupting device qualification.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

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Organization

Yes or No

Question 7 Comment

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
MEAG Power

No

The definition of Exclusion E1 does not cover radial systems that are connected to a single transmission
source by more than one automatic interruption device, such as occurs with a “breaker-and-a-half”
arrangement. The definition should be modified as follows:”Any radial system which is described as
connected from a single Transmission source originating with one or more automatic interruption devices and:
....
”This exclusion uses many terms that are not defined under NERC’s standard definitions: “radial load”,
“automatic interruption device” and “make-before-break”. If these terms are used to define an exclusion and
can be understood or interpreted differently by different people, then the terms should be formally defined.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.
In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local networks.
The terms in question are no longer used.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Independent Electricity System
Operator

August 19, 2011

No

Again, we agree with the goal of E1 but we repeat the same concerns expressed in our responses to Q1 and
Q3 with respect to the generation capacity thresholds. A majority of the transmission elements excluded by
E1 would already be excluded by E3 and, therefore, E1 may be redundant. The SDT may wish to consider
combining Exclusion E1 with Exclusion E3, modified as proposed in our response to Q9.

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Organization

Yes or No

Question 7 Comment
In Exclusion E1, we suggest changing “automatic interruption device” to “automatic fault-interrupting device”
for consistency with E3(a).

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular, the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the
normally open switch to a note, and clarified the generation allowed within the system.

In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local networks and there
are sufficient differences between radial systems to warrant Exclusions E1 and E3.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
BPA

No

August 19, 2011

Exclusions E1 and E3 use the similar yet different terms “automatic fault interruption device” and “automatic
fault interrupting device” respectively to refer to the specific type of device that must be used to separate the
excluded area from the BES. Neither “automatic interruption device” nor “automatic fault interrupting device”
are specifically defined in the NERC Glossary; leaving them up to auditor interpretation. From a compliance
perspective, the fact that different terms are used seems to lead to a conclusion that different types of devices
are being referred to in each case. However, given the technical characteristics of these exclusions, we are
not able to discern how these devices might differ when used to isolate a “radial system” or a “Local
Distribution Network”, from the BES, as defined in E1 and E3 respectively. BPA would like to see the definition
of “automatic fault interruption device” and “automatic fault interrupting device” If the intention is to refer to the
same set of devices as being acceptable for E1 exclusion of Radial Systems and E3 exclusion of Local
Distribution Networks, then please modify the language to be identical in each case. If the intention is to refer
to a difference in the types of devices acceptable for providing separation from the BES in each case, then

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Organization

Yes or No

Question 7 Comment
please modify the language as necessary to further clarify the specific intention in a manner that enables
consistent interpretation and application by auditors from the full spectrum of backgrounds and perspectives. If
necessary, we further recommend that the drafting team consider creating a specific defined term (or 2) to add
to the NERC Glossary that provides specific clarification to a clear and consistent manner in which these
exclusions are to be applied.
BPA would also like to point out a possible way to make E1 more clear – “Any radial system which is
connected to a single Transmission source which connection originates with an automatic interruption device
and . . .”
BPA seeks clarification on whether, if a normally open breaker is switched in-service, it can still be
considered radial. BPA understands this to mean that if a normally open switch is closed to maintain load
service until the original source is disconnected, the system may still be considered radial.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.
Your assumption is correct. The SDT does not specify the type of normally open switch that will be used to separate the systems described in Exclusion E1 but
understands that any such switch needs to be operated in such a fashion that insures safety, utilizes the best operating practices, and maintains reliability.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4 and
I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Tacoma Power

August 19, 2011

Tacoma Power supports Exclusion E1.

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Organization

Yes or No

Question 7 Comment

Response: Thank you for your support.
Chevron Global Power, a division
of Chevron U.S.A. Inc.
PacifiCorp

See response to question 13

Yes

: Please refer to additional comments in question 13 regarding a contiguous BES.

Response: See response to Q13.
ATCO Electric

Is a load substation categorized as a "radial substation" if its 144kV bus connects to another 144kV bus at an
adjacent substation via two 144kV parallel transmission lines?

Response: The SDT is not in position to respond to this question as more information may be required to make a proper determination.
City of Redding

Yes

Redding supports this high level exclusion of Radial systems as a clarification to the Brightline definition as
long as it is part of the SDT’s overall plan to make a clear distinction between distribution and transmission
facilities. Redding’s support rests on the assumption that the SDT will adequately address the distribution and
transmission facilities issue via the Exception Process. There needs to be a fair and equable method where
radial elements that do not meet this criterion can be identified as distribution acilities. This will hinge on the
ability of the SDT to adequately address the two major issues: clarify the term “necessary for operating the
interconnected transmission network” and to “establish whether a particular facility is local distribution or
transmission”.

Response: The SDT has clarified the core definition in this regard.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Western Electricity Coordinating
Council

Yes

WECC generally agrees in concept. However, it is unclear what is required to demonstrate the “make-beforebreak” connection. Is this intended to mean that the normally-open switch is mechanically or electrically
interlocked to ensure the “make-before-break” requirement is met?
It would be a normal switching practice to close the normally-open switch to make the parallel before opening
the normally-closed switch, but is the normal switching practice sufficient to make this claim?

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Organization

Yes or No

Question 7 Comment
Also, it is unclear whether the automatic interruption device itself is a part of the BES.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenters. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the normally
open switch to a note, and clarified the generation allowed within the system.
The SDT does not specify the type of normally open switch that will be used to separate the systems described in Exclusion E1 but understands that any such
switch needs to be operated in such a fashion that insures safety, utilizes the best operating practices, and maintains reliability.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of 100 kV
or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, or I4
and I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this exclusion.
Cowlitz County PUD

Yes

FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained. Cowlitz believes the exclusion as drafted adequately defines radials. Further, we would point out
that two transmission systems that are operated radial with a normal open between them can’t be operated
reliably with the normal open indefinitely closed. Such extended closures are not possible were transmission
protection systems are not designed for networked systems.

New York State Dept of Public
Service

Yes

We agree with exclusion E1. As described, the facilities are clearly local distribution. Requiring a “makebefore-break” switching device, between the BES and the excluded radial system, as a condition-precedent
for such exclusion is proper. Such switches are necessary to promote reliable operation by enabling removal
of radial systems principally serving load for maintenance and other reliable system operations. If the “makebefore-break” switching capability is not included as part of the exclusion, the specification would undermine
reliable system operation.

Sierra Pacific Power Co d/b/a NV

Yes

Agree with this exception and emphasize that the make-before-break language is essential to be retained in

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Organization

Yes or No

Energy

Question 7 Comment
this exclusion.

Sweeny Cogeneration LP

Yes

We agree that all radial connections serving a single load, small generator, or combination should be
excluded

Western Montana Electric
Generating and Transmission
Cooperative

Yes

FERC has made clear throughout the Order No. 743 process that the existing exclusion for radials be
retained. We believe the exclusion as drafted adequately defines radials.

Public Utility District No. 1 of
Snohomish County, Washington
Blachly Lane Electric Cooperative
Northern Wasco County PUD
Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc.
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc.
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric

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Organization

Yes or No

Question 7 Comment

Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Clallam County PUD No.1
Chelan PUD – CHPD
Kootenai Electric Cooperative
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Central Lincoln
Northwest Requirements Utilities
Imperial Irrigation District

Yes

Santee Cooper

Yes

SERC Planning Standards
Subcommittee

Yes

ACES Power Participating
Members

Yes

Overton Power District No. 5

Yes

Arizona Public Service Company

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

Southern Company

Yes

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Organization

Yes or No

Western Area Power
Administration

Yes

US Bureau of Reclamation

Yes

Glacier Electric Cooperative

Yes

South Texas Electric
Cooperative, Inc.

Yes

Portland General Electric
Company

Yes

South Texas Electric
Cooperative, Inc.

Yes

Dayton Power and Light
Company

Yes

Alberta Electric System Operator

Yes

South Carolina Electric and Gas

Yes

Farmington Electric Utility System

Yes

Colorado Springs Utilities

Yes

Consumers Energy Company

Yes

Puget Sound Energy

Yes

Clark Public Utilities

Yes

Pepco Holdings Inc

Yes

August 19, 2011

Question 7 Comment

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Organization

Yes or No

PJM

Yes

Oncor Electric Delivery Company
LLC

Yes

Manitoba Hydro

Yes

City of Anaheim

Yes

Xcel Energy

Yes

Orange and Rockland Utilities,
Inc.

Yes

Question 7 Comment

Response: Thank you for your support. The SDT believes that the changes made to the wording of the definition based on comments received will provide
clarity and address the concerns provided by the respondents. In particular the SDT clarified the point of connection, removed the automatic interrupting device,
moved the concept of the normally open switch to a note, and clarified the generation allowed within the system.

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8. The SDT has added specific exclusions to the core definition in response to industry comments. Do you agree
with Exclusion E2? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: The SDT believes that Exclusion E2 should be dedicated to the situation faced by behind-the-meter (i.e., retail
customer owned) generation that are PURPA qualifying facilities (in the US) (e.g., see 18 CFR Part 292 for the regulations that are applicable in
the US).and similarly situated generators in Canada. Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to
qualifying facilities. The SDT believes that condition (ii), which requires that the generation serving the retail customer load self provide reserves,
is essential for the integrity of the exclusion. The references to Inclusions I2 and I3 in Exclusion E2 have been deleted. Exclusion E2 now
designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA. The SDT has
also modified Exclusion E3 to make non-retail generation in a local network (LN) subject to a comparable exclusion designation as that for
customer-owned generation in Exclusion E2.
Due to industry comments, some slight changes were made for clarity:
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of
connection of 100 kV or higher from a single Transmission source originating with an automatic interruption device and:
a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow
for reliable system reconfiguration to maintain continuity of electrical service. Or,
b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to
75 MVA (gross nameplate rating). Or,
c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in
Inclusions I2, I3, I4 and I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example does not affect
this exclusion.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the
retail meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, backup, and maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or provided pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under
terms approved by the applicable regulatory authority.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that
distribute power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection
at 100 kV or higher are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail
customer Load and not to accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:

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Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in
Inclusion I3 and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate),
includes more than 75 MVA generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the
LDN The LN does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored
Facility in the ERCOT or Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).

Organization
Tri-State Generation and
Transmission Association, Inc.

Yes or No
No

Question 8 Comment
This Exclusion should also include “wholesale” meters for the instance where an electric distribution
cooperative has some small generation connected to its distribution system that meets the same criteria.

Response: The SDT believes that Exclusion E2 should be dedicated to the situations faced by behind-the-meter (i.e., retail customer owned) generation that are
PURPA qualifying facilities (in the US) and similarly situated generators in Canada. For example, see 18 CFR Part 292 for the regulations that are applicable in the
US. Exclusion E2 has also been clarified by replacing the reference to “retail Load” with “retail customer Load.”
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
NERC Staff Technical Review

No

The second condition (ii) in E2 is confusing. While the condition is appropriate and has specific meaning, the
meaning will not be readily understood by most users of the definition. This condition should be clarified.

SPP Standards Review Group

No

We think we may concur with E2, but we are uncertain as to what is included in (ii). Could you please clarify?

Response: Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying cogeneration and small power production

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Organization

Yes or No

Question 8 Comment

facilities. For example, see 18 CFR §292.101 and §292.305(b) for the requirements specific to the US. The SDT believes that the meaning of the definition will be
understood in Balancing Authority Areas where it is applicable. No change made.
SERC Planning Standards
Subcommittee

No

While we agree with the first part of E2, but we do not see the rationale for section (ii) and suggest it be
deleted.

Response: The SDT believes that condition (ii) in Exclusion E2, which requires that the generation serving the retail customer load self provide reserves, is
essential for the integrity of the exclusion. No change made.
SERC OC Standards Review
Group

No

This exclusion is acceptable if the suggestions in Questions 3 and 4 are incorporated.

Cogentrix Energy, LLC

No

This exclusion is acceptable if the suggestions in Questions 3 and 4 are incorporated.

No

We do not agree with E2(i). If the generation assets listed in the inclusions of I2 and I3 are not permitted to
be excluded in E2, then what is the point of E2? The generation assets would already be in or out based
upon the registry's MVA nameplate capacity. We would support E2 if provision (i) were struck.

Response: See response to Q3 & 4.
Idaho Falls Power

If generation assets are behind the meter on a local distribution network (fitting the criteria E3 for exemption)
then too the generation should be exempted regardless of MVA rating.
Moreover, we do not agree that there is a brightline MVA threshold of materiality to the BES. We would hope
that the drafting team could demonstrate how the 20MVA brightline is a valid threshold for generation while
the 100kV for transmission is not.We are concerned that relatively small generation on a local distribution
network wherein generation is always serving local retail load behind the meter will be labelled a BES asset.
As such, then is the LDN to the point of interconnection a BES asset as well, and therefore subject to the
suite of TO/TOP standards? We feel such an outcome is unreasonable. It seems to us, as is stated under
section 215 of the FPA, that the term BES "does not include facilities used in the local distribution of electric
energy." To a logical conclusion, the generation attached to local distribution was considered and is intended
to be one of the "facilities" and should therefore be exempted form inclusion in the BES. However, should the
drafting team deem that all generation above 20MVA are a BES assets, we would hope that the exclusion for
Local Distribution Networks could still stand and that the generation on the LDN would be divorced and
defined separately. Our opinion is the BES is not one large contiguous system, but is rather comprised of
assets across the region, which due to their size or location are vital to a sound BES but are not necessarily
connected to each other. This principle would allow the generation to be regulated yet remove the burden of

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Organization

Yes or No

Question 8 Comment
transmission standards from small entities.

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
The SDT has also modified Exclusion E3 to make non-retail generation in an LN subject to a comparable exclusion designation as that for customer-owned
generation in Exclusion E2.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3 and do
not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
The SDT has changed Inclusion I2 to simply reference the ERO Statement of Compliance Registry Criteria.
Tennessee Valley Authority

No

We suggest adding a reference to “I5” in the (i) section as follows: “the net capacity provided to the BES does
not exceed the criteria identified in the inclusions I2, I3, or I5.”

Response: The SDT believes that situations where the resources captured in Inclusion I5 directly serve its own Load are extremely rare and therefore may be
demonstrated in the Exception Process. No change made.

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Organization

Yes or No

Question 8 Comment

Western Montana Electric
Generating and Transmission
Cooperative

No

As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through reference
to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the generation unit is
reliability-must-run or essential blackstart, the function of the unit is irrelevant to the reliable operation of the
interconnected bulk transmission grid, and we therefore believe the reference to the function of the generation
unit (“standby, back-up, and maintenance power...”) should be eliminated.

Northern Wasco County PUD

No

As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through reference
to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the generation unit is
reliability-must-run or essential blackstart, the function of the unit is irrelevant to the reliable operation of the
interconnected bulk transmission grid, and we therefore believe the reference to the function of the generation
unit (“standby, back-up, and maintenance power...”) should be eliminated.

Chelan PUD – CHPD
Public Utility District No. 1 of
Franklin County
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc
Midstate Electric Cooperative
Cowlitz County PUD

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
The SDT believes that condition (ii) in Exclusion E2, which requires that the generation serving the retail customer Load self provide reserves, is essential for the
integrity of the exclusion.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Southern Company

No

Section (i) is confusing because it mixes MW with MVA. The net capacity in section (i) would be in MW while
the values referenced in I2 and I3 would be in MVA. This will create confusion.
Also, we do not see any need for section (ii). Section (i) is sufficient without section (ii).
We recommend Exclusion E2 to be re-written as follows:Exclusion E2 - A generating unit or multiple
generating units that serve all or part of retail Load with electric energy on the customer’s side of the retail
meter if the net capacity provided to the BES does not exceed 20 MW for a single generating unit or 75 MW

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Organization

Yes or No

Question 8 Comment
for multiple generating units located at a single site.

Response: The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed
relevant to the exclusion, not the nameplate rating. No change made.
The SDT believes that condition (ii) in Exclusion E2, which requires that the generation serving the retail customer Load self provide reserves, is essential for the
integrity of the exclusion. No change made.
Exclusion E2 has been revised due to industry comments:
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Central Maine Power Company

No

New York State Electric & Gas
and Rochester Gas & Electric

E2 refers to “net capacity provided to the BES” (which seems to be a flow on an interconnection, not
generator capacity), yet I2 and I3 refer to generator MVA. These are not the same unit which leads to
inconsistency.This Exclusion appears to add confusion or additional criteria to that of the Compliance
Registry.We recommend that E2 be stricken.

Response: The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed
relevant to the exclusion, not the nameplate rating. No change made.
Intellibind

No

This is very confusing. Understanding the Drafting Team's goal, it would better to adjust the I2 and I3 criteria
to address NET generation and behind the meter generation.
E2 appears to try and address the net generation versus nameplate issue, but not fully. Station service power
is behind the meter and it is a commitment of the resource. Many small generators have multiple processes
outside of power generation they must provide for, and these should be considered in the exceptions.

Response: The SDT believes that Exclusion E2 should be dedicated to the situations faced by behind-the-meter (retail customer owned) generation that are
PURPA qualifying facilities (in the US) and similarly situated generators in Canada. Exclusion E3 has been modified to accommodate non-retail generation in the
LN. Exclusion E2 has also been clarified by replacing the reference to “retail Load” with “retail customer Load.”
The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed relevant to
the exclusion, not the nameplate rating.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail

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Organization

Yes or No

Question 8 Comment

meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting
devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3 and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
US Bureau of Reclamation

No

The term "retail load" is ambiguous and unnecessary. The term should be changed to "load". The change is
justified by the conditions (i) and (ii) placed on the generators.

Springfield Utility Board

No

The proposed language for Exclusion E2 refers to the “customer’s side of the retail meter”. There may be
multiple customers with different resources within the geographic area served by a Registered Entity.
Because E2 also refers to “net capacity provided to the BES”, SUB assumes that E2 is intended to address
resources within the Registered Entity that are served to a single customer or multiple customers. A
Registered Entity may have Elements that are separate and independent but that are connected to the BES.
Individually, these elements may not have resources that serve customer load that meet I2 or I3, but
collectively the sum or resources and elements served do meet I2 or I3. SUB believes that the issue of
reliability comes down to both resources, load served, and what paths are shared (or not) between resources
and loads. SUB suggests that isolated loads and resources that are functionally independent from a

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Organization

Yes or No

Question 8 Comment
Registered Entities overall system do not need to be added together.
SUB suggests the following language: “A generating unit or multiple generating units that serve all or part of
retail Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity along shared
Elements provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and (ii) standby,
back-up, and maintenance power services are provided to the generating unit or multiple generating units or
to the retail Load pursuant to a binding obligation with a Balancing Authority or another Generator
Owner/Generator Operator, or under terms approved by the applicable regulatory authority. For purposes of
this exclusion, if a Registered Entity is responsible for elements that serve loads and resources that are
separate from other elements that the Registered Entity is responsible for, then each set of loads and
resources that are connected to Elements the Registered Entity is responsible for shall be evaluated
separately and resources will not be added together.While Springfield Utility Board does not own any
generating units, we do recognize the importance of the restoration of the Grid, and the generation necessary
for the Grid.

Springfield Utility Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: The SDT believes that Exclusion E2 should be dedicated to the situations faced by behind-the-meter (retail customer owned) generation that are
PURPA qualifying facilities (in the US) and similarly situated generators in Canada. Exclusion E3 has been modified to accommodate non-retail generation in the
LN. Exclusion E2 has also been clarified by replacing the reference to “retail Load” with “retail customer Load.”
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided

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Organization

Yes or No

Question 8 Comment

pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3 and do
not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Sweeny Cogeneration LP

No

Generators which serve local retail load (cogeneration) should be excluded if the net capacity available to the
BES does not exceed 20 MW Single Unit/75 MW Multiple Units thresholds. We believe there are further items
to be added to the list related to generator interconnections, a task that was passed to this project from
Project 2010-07. Just as is the case with complex distribution systems, there are a variety of generatortransmission interconnection architectures which are driving the Regions to inappropriately register Generator
Owner/Operators as Transmission Owners.

Response: The SDT is aware of Project 2010-07 (“Generator Requirements at the Transmission Interface”) and believes that this SDT should not attempt to
duplicate that effort. A primary objective of Project 2010-17 is to clarify the BES definition, make it more transparent, and eliminate regional discretion with
respect to the definition. No change made.
Electric Reliability Council of
Texas, Inc.

No

See response to question 7.

Southwest Power Pool

No

See response to question 7.

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Organization

Yes or No

Question 8 Comment

Response: See response to Q7.
South Carolina Electric and Gas

No

We agree with the first part of E2, but we do not see the rationale for section (ii) and suggest it be deleted.

Central Lincoln

No

We support excluding behind the meter generation below the limits, but the string of “ands” and “ors” in this
exclusion are far too confusing with numerous ways to parse them. Suggest eliminating bullet (ii) since the
existence of obligations has no bearing on impact.

NERC Transmission Issues
Subcommittee (TIS)

PUD No. 2 of Grant County,
Washington

The last sub-bullet in E2 is terribly confusing. The TIS does not offer alternate wording because we are
unsure of the meaning of the phrase: >>>>>>>>>> “...pursuant to a binding obligation with a Balancing
Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.”
Yes

Unless the generation unit is reliability-must-run or essential blackstart, the function of the unit is irrelevant to
the reliable operation of the interconnected bulk transmission grid, and we therefore believe the reference to
the function of the generation unit (“standby, back-up, and maintenance power...”) should be eliminated.

Response: Condition (ii) in Exclusion E2 is derived from FERC and provincial regulations applicable to qualifying cogeneration and small power production
facilities. For example, see 18 CFR Part 292 for the regulations that are applicable in the US. The SDT believes that condition (ii), which requires that the
generation serving the retail customer Load self provide reserves, is essential for the integrity of the exclusion. No change made.
Southern California Edison
Company

No

City of Redding

Yes

August 19, 2011

SCE does not believe that the size of generator should dictate what system facilities, regardless of voltage,
will or will not be included in the BES definition. More important, is the issue of whether or not the generation
has net flow(s) out to the greater integrated networked transmission system. It is the “generation” and not the
“generator” which has impacts on the BES.In addition, it would seem that if these are truly “behind-the-meter”,
non-export interconnected generation, then there is no scenario that would result in flow back onto the BES,
no matter what the interconnection level. The focus should not be restricted to only “behind-the-meter”
generation, but rather on the flow generation from the radial system.
Redding agrees that generators located in close proximity to the end user should be classified as distribution
load modifier generators. Additionally, Redding believes small utilities that have distinct metered boundaries
with installed generation intended to serve their customers (load displacement generators) should receive the
same exclusion as generators behind retail meters. These generators installed on distribution facilities are
almost identical to the generating units in Exclusion E2: “a generating unit or multiple generating units that
serve all or part of retail Load with electric energy on the customer’s side of the retail meter if: (i) the net
capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I3, and (ii) standby,

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Question 8 Comment
back-up, and maintenance power services are provided to the generating unit or multiple generating units or
to the retail Load pursuant to a binding obligation with a Balancing Authority or another Generator
Owner/Generator Operator, or under terms approved by the applicable regulatory authority.” A local
distribution network that is owned by a utility is directly serving load to the end user (retail customer), it has
meters at the network boundaries where bulk power is transferred from the BES network to the distribution
facilities, it has binding obligations with the BA or Reserve Sharing Group, to provide reserves (back up
power), and meets the net capacity requirement. The distribution facilities are technically retail load to the
BES network if owned by the retail user (example would be a Municipal, Public Utility District, Irrigation
District, etc.).
Redding has three suggestions to address our concerns:
1. The language in Exclusion E2 could be changed:
From: “electric energy on the customer’s side of the retail meter”
To: “electric energy on the customer’s side of the retail, or distribution system, meter(s)”. This change will
provide an equable exclusion for the small utility and for generation directly dedicated to local distribution
load.
OR
2. The LDN characteristic #b in Exclusion E3 could have the limits of generation removed and modified to
read “the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I3”
(identical to the language in E2).
3. The SDT address this issue via the Exception Process by specifically creating an exception that
addresses generation in a LDN used as a load modifier.

Response: The SDT believes that Exclusion E2 should be dedicated to the situations faced by behind-the-meter (i.e., retail customer owned) generation that are
PURPA qualifying facilities in the US and similarly situated generators in Canada. Exclusion E3 has been modified to accommodate non-retail generation in the LN.
The SDT has merged Inclusion I2 and Inclusion I3 and therefore Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides
net capacity to the BES that does not exceed the criteria identified, which is greater than 75 MVA. The SDT has merged Inclusion I2 and Inclusion I3 and
therefore Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed the criteria
identified, which is greater than 75 MVA.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable

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Yes or No

Question 8 Comment

regulatory authority.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3 and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Clark Public Utilities

No

As indicated by Clark in its comments on the core definition of the BES, Clark believes the 20 MVA and the 75
MVA thresholds lack adequate technical justification and are a purely arbitrary quantities. The use of a
capacity thresholds in the definition of the BES should have technical reasons.

Response: The MVA thresholds were adopted from the Statement of Compliance Registry Criteria. Exclusion E2 now designates for exclusion relevant behindthe-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
The Dow Chemical Company

August 19, 2011

No

Clause (ii) should be revised as follows: "(ii) standby, back-up, and maintenance power services are provided
to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or pursuant to
a binding obligation with another Generator Owner/Generator Operator, or under terms approved by the
applicable regulatory authority."

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Question 8 Comment

Manitoba Hydro

No

It is not clear what is meant by “retail Load”. This is not a NERC defined term. Additional detail is required.

Florida Municipal Power Agency

Yes

We understand that E2 is intended to apply only to retail customers’ generation. The exclusion should
therefore be revised to make that limitation clear. Specifically, the first sentence should read: “A generating
unit or multiple generating units that serve all or part of retail customer Load with electric energy on the retail
customer’s side of the retail meter.

Transmission Access Policy
Study Group

Yes

We understand that E2 is intended to apply only to retail customers’ generation. The exclusion should
therefore be revised to make that limitation clear. Specifically, the first sentence should read: “A generating
unit or multiple generating units that serve all or part of retail customer Load with electric energy on the retail
customer’s side of the retail meter.”

Northern California Power
Agency

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.

Michgan Public Power Agency

Yes

I understand that E2 is intended to apply only to retail customers’ generation. If that is the case then I would
suggest the following changes be made to make that limitation clear. Specifically, the first sentence should
read: “A generating unit or multiple generating units that serve all or part of retail customer Load with electric
energy on the retail customer’s side of the retail meter.”

Response: Exclusion E2 was modified to reflect your recommendation.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
ISO New England, Inc.

No

E2 refers to net capacity and yet I2 and I3 refer to MVA. These are not the same unit which leads to
inconsistency.
This Exclusion appears to add additional criteria than that of the Compliance Registry; we suggest simply
using the language from the Compliance Registry.

Response: The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed
relevant to the exclusion, not the nameplate rating. Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to

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Yes or No

Question 8 Comment

the BES that does not exceed 75 MVA.
Clarification of the original language adopted from the Statement of Compliance Registry Criteria (SCRC) was in response to industry comments.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Independent Electricity System
Operator

No

Again, we echo the same comments stated in our responses to Q1 and Q3. We do not agree with the
Exclusion E2 for the very same reasons specified in responses to questions 3, 4, and 6. Additionally, we are
not clear of the intent for the restriction stated in Exclusion E2 (ii).

Response: See responses to Q1, Q3, Q4 and Q6. Condition (ii) in Exclusion E2 is derived from FERC and provincial regulations applicable to qualifying
cogeneration and small power production facilities. For example, see 18 CFR Part 292 for the regulations applicable in the US. The SDT believes that condition
(ii), which requires that the generation serving the retail customer Load self provide reserves, is essential for the integrity of the exclusion. No change made.
Utility System Efficiencies, Inc.

No

As noted in USE's response to Question 3, we believe the inclusion of the 20 MVA threshold (through
reference to Inclusion I2) lacks an adequate technical justification in this context.
In addition, whether or not there is provision of standby, back-up, and maintenance power services to the
unit(s) or the load is irrelevant to the reliable operation of the interconnected bulk transmission grid, and we
therefore believe the item (ii) in this Exclusion should be eliminated.

Blachly Lane Electric Cooperative
Central Electric Cooperative
Clearwater Power Company

As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold lacks an adequate
technical justification. Further, unless the generation unit is reliability-must-run or essential blackstart, the
function of the unit is irrelevant to the reliable operation of the interconnected bulk transmission grid, and we
therefore believe the reference to the function of the generation unit should be eliminated.

Consumers Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative

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Yes or No

Question 8 Comment

Yes

As noted in our response to Question 3, we believe the inclusion of the 20 MVA threshold (through reference
to Inclusion I2) lacks an adequate technical justification in this context. Further, unless the generation unit is
reliability-must-run or essential blackstart, the function of the unit is irrelevant to the reliable operation of the
interconnected bulk transmission grid, and we therefore believe the reference to the function of the generation
unit (“standby, back-up, and maintenance power...”) should be eliminated.

Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Clallam County PUD No.1
Public Utility District No. 1 of
Snohomish County, Washington

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
Condition (ii) in Exclusion E2 is derived from FERC and provincial regulations applicable to qualifying cogeneration and small power production facilities. For
example, see 18 CFR Part 292 for the regulations applicable to the US. The SDT believes that condition (ii), which requires that the generation serving the retail
customer Load self provide reserves, is essential for the integrity of the exclusion.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.

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BPA

Yes or No
No

Question 8 Comment
BPA seeks clarification on exactly what “net capacity provided to the BES” means.
BPA would like to suggest a minor clarification in brackets below:
A generating unit or multiple generating units located on, and that serve all or part of retail Load with electric
energy on, the customer’s side of the retail meter if: (i) the net capacity provided to the BES does not exceed
the criteria identified in Inclusions I2 or I3 or I5 and (ii) standby, back-up, and maintenance power services are
provided to the generating unit or multiple generating units or to the retail Load pursuant to a binding
obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms
approved by the applicable regulatory authority.

Response: Exclusion E2 is dedicated to the situations faced by behind-the-meter (retail customer owned) generation that are PURPA qualifying facilities in the
US and similarly situated generators in Canada. While the criteria in Inclusions I2 and I3 were based on gross nameplate ratings in MVA, the first condition (i) in
Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed relevant to the exclusion, not the
nameplate rating. The “net capacity provided to the BES” is the behind-the-meter generation that exceeds the Load directly served by the generator. The SDT
believes that situations where the resources captured in Inclusion I5 directly serve its own load are extremely rare and should therefore be demonstrate in the
Exception Process. No change made.
Georgia System Operations

How is “net capacity provided to the BES” measured (e.g., by nameplate capacity minus peak load, by actual
generated energy - rather than capacity - minus actual load at each moment or over some period of time,
etc.)? It is possible that a larger than currently necessary generator may be installed in anticipation of future
load growth, but that it is never used to generate significantly more than what is needed for load. Depending
on how “net capacity” is calculated, such a generator might unnecessarily be pulled into the BES.

Response: The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed
relevant to the exclusion, not the nameplate rating. Regardless of the nameplate rating of the generator(s), the “net capacity” is the behind-the-meter generation
that exceeds the Load. No change made.
Tacoma Power

Tacoma Power generally supports Exclusion E2. However, no justification for the 20 MVA and 75 MVA levels
in Inclusion I2 and Inclusion I3 have been provided and therefore they appear arbitrary. Since this
measurement will define Elements for absolute inclusion in the BES, the thresholds should be based on a
need to maintain transmission reliability. We strongly urge the SDT to accept our proposed changes to
Inclusion I2 and Inclusion I3, listed above in items 3 and 4.

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
See responses to Q3 and Q4.

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Yes or No

Question 8 Comment

E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Dominion

Yes

Dominion agrees with Exclusion E2 because we agree that specific criteria can be applied and will indicate
the Element or Facility is not necessary for operating an interconnected electric energy transmission network
or is needed to maintain transmission system reliability. . However Dominion suggests that the SDT add a
defined interval of time for measurement of net capacity so that planners can be assured that the exclusion
should really be applied at the location. Dominion suggests use of an hour as the time increment.

Response: The SDT believes that the context of “net capacity” is understood and no change is necessary.
American Municipal Power and
Members

Yes

We understand that E2 is intended to apply only to retail customers’ generation. The exclusion should
therefore be revised to make that limitation clear. Specifically, the first sentence should read: “A generating
unit or multiple generating units that serve all or part of retail customer Load with electric energy on the retail
customer’s side of the retail meter.”
In addition, the first condition of exclusion, (i), "the net capacity provided to the BES does not exceed the
criteria identified in Inclusions I2 or I3," as written is vague and could be subjectively applied. I2 limits
capacity supplied to the BES to 20MVA while I3 limits that capacity to 75MVA. A better way to state the
exclusion would be as follows: (i), "the net capacity provided to the BES does not exceed the retail
customer's total nameplate generation, or 75MVA, whichever is greater,".

Response: The term “retail Load” had been replaced with “retail customer Load.”
Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Hydro One Networks Inc

August 19, 2011

Yes

We agree with most of the changes in Exclusion E2. However, we feel there is a need for evidence or
technical study in regards to the limits described in I2 & I3. The real net aggregated power seen by the bulk

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Yes or No

Question 8 Comment
power system at the interconnection, with the outlook of distributed generation systems, may be different than
past experience. Hence it requires to be reassessed based on technical studies with respect to the future
integration of DG’s. (Please refer to comments in questions: 3 & 4).
To establish a bright-line definition, Exclusion E2 may be acceptable if the SDT provides adequate provisions
within the exception procedure. (See response to Q7)

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
The I2 Inclusion was adopted from the ERO Statement of Compliance Registry Criteria.
See response to question 7.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Western Electricity Coordinating
Council

Yes

WECC agrees in concept, but it is unclear what happens if/when the “binding obligation” ends, as well as
what constitutes a “binding obligation.” E2(ii) should be clarified as to what constitutes “standby, back-up, and
maintenance power services provided...pursuant to a binding obligation.” This may cause administrative
burden to monitor such binding commitments.

Cogeneration Association of
California and Energy Producers
& Users Coalition

Yes

To respond to WECC's concern, please consider that facilities procure standby service because it is needed
for the facility's operation, not to escape registration or compliance. This is a long-term commitment, and the
sufficiency of the service will be monitored by the state regulatory authority. "Standby service" is a term wellunderstood in the industry and generally not further defined in any utility tariff.

Response: Binding obligations are retail tariffs approved by state PUCs or applicable Canadian provincial authorities, or the FERC-approved market rules of
RTOs/ISOs in cases where FERC has granted a waiver to local utilities from those service obligations because the RTO/ISO market provides comparable services.
In the US, the services are defined in 18 CFR §292.101 and §292.305(b). No change made.
ReliabilityFirst

Yes

as long as the resources when removed from service have a load component that accompanies it, otherwise
there could be an impact to the BES.

Response: That is the purpose of condition (ii) in Exclusion E2. Back-up power, as defined in the US in 18 CFR §292.101, means electric energy or capacity
supplied by an electric utility to replace energy ordinarily generated by a facility’s own generation equipment during an unscheduled outage of the facility.

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Organization

Yes or No

Question 8 Comment

Maintenance power, also as defined in 18 CFR §292.101, means electric energy or capacity supplied by an electric utility during scheduled outages of the
qualifying facility. Provincial regulations do the same in Canada. No change made.
Texas Industrial Energy
Consumers (TIEC)

Yes

TIEC supports this exclusion with two clarifications. The language currently excludes generation on the
customer’s side of the meter as long at “the net capacity provided to the BES does not exceed the criteria
identified in Inclusions I2 or I3.” There are special circumstances in which an regional Reliability Coordinator
may ask that customer-owned generation export to its maximum capability (i.e., with its load curtailed to the
lowest level) in order to support grid reliability. Circumstances such as this should not be considered in
determining whether the “net” capacity exported to the BES exceeds the threshold for registration.
Additionally, there are often instances when customer-owned generation and associated load are in start-up
or shut-down processes that may cause the net export to the BES to vary such that it temporarily exceeds the
registration thresholds. Outlying situations such as these should not trigger registration. Rather, the “net”
capacity should be interpreted as the typical amount exported during steady-state operation of the site. This
interpretation of “net capacity” should also apply to exclusions E1 and E3.

Response: The SDT has discussed your concern and agrees that emergency or other extraordinary situations should not impair the general applicability of the
E2 Exclusion.
The SDT has changed E1 and E3 to clarify the criteria applicable to non-retail generation.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
d) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,
e) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA
(gross nameplate rating). Or,
f)

Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this
exclusion.

E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to

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Yes or No

Question 8 Comment

accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3 and do
not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
FortisBC

Yes

We agree with most of the changes in Exclusion E2. However, we feel there is a need for evidence or
technical study in regards to the limits described in I2 & I3. The real net aggregated power seen by the bulk
power system at the interconnection, with the outlook of distributed generation systems, may be different than
past experience. Hence it requires to be reassessed based on technical studies with respect to the future
integration of DG’s. (Please refer to comments in questions: 3 & 4).
To establish a bright-line definition, E2 exclusion may be acceptable if the SDT provides adequate provisions
within the exception procedure.
See response to Q8
Accordingly, we suggest the SDT carefully craft the exception criteria that will allow entities to present their
case to the ERO for exclusion from E2 requirements.

AltaLink

Yes

We agree with most of the changes in Exclusion E2. However, we feel there is a need for evidence or
technical study in regards to the limits described in I2 & I3. The real net aggregated power seen by the bulk
power system at the interconnection, with the outlook of distributed generation systems, may be different than
past experience. Hence it requires to be reassessed based on technical studies with respect to the future
integration of DG’s.
To establish a bright-line definition, E2 exclusion may be acceptable if the SDT provides adequate provisions
within the exception procedure. Accordingly, we suggest the SDT carefully craft the exception criteria that will
allow entities to present their case to the ERO for exclusion from E2 requirements.

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Organization

Yes or No

Question 8 Comment

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
See response to Q8.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
City of St. George

Yes

The limits on generation levels need to be revisited, with similar concerns as noted to questions 7 & 9 for
exclusions E1 & E3.

Response: Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES that does not exceed 75 MVA.
The SDT adopted the criteria from the ERO Statement of Compliance Registry Criteria.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
Illinois Municipal Electric Agency

Yes

Please see comments under Question 13.

Yes

Please refer to comments in number 7 above. Additionally, there appears to be an inconsistency in how
generating units are expressed in E2 (net capacity) and in I2 and I3 (MVA).

Response: See response to Q13.
New England States Committee
on Electricity
Response: See response to Q7.
The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated that was deemed relevant to
the exclusion, not the nameplate rating. Exclusion E2 now designates for exclusion relevant behind-the-meter generation that provides net capacity to the BES
that does not exceed 75 MVA.
E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy on the customer’s side of the retail
meter if: (i) the net capacity provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA, and (ii) standby, back-up, and

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Organization

Yes or No

Question 8 Comment

maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Balancing Authority or another Generator Owner/Generator Operator, or under terms approved by the applicable
regulatory authority.
New York State Dept of Public
Service

Yes

This exclusion is appropriately specified. Behind the meter generation is mainly on the local distribution
system and most likely modeled in power flow cases used to study the bulk system as netted against load.
For the few sizable behind the meter generation that are: 1) connected at the 100 kV level and above; and, 2)
exceed the 75 MVA threshold, if it is believed that these facilities will impact the bulk system they can be
petitioned for inclusion under the rules of procedure.

Exelon

Yes

Exelon agrees with this Exclusion since this language is quoted from the Statement of Compliance Registry
Criteria.

Public Utilities Commission of
Ohio

Yes

Exclusion E2 is appropriate. Same as 7.

GTC

Yes

Northeast Power Coordinating
Council

Yes

Imperial Irrigation District

Yes

Santee Cooper

Yes

MRO's NERC Standards Review
Forum

Yes

Michigan Public Service
Commission(MPSC)

Yes

ACES Power Participating
Members

Yes

National Rural Electric
Cooperative Association

Yes

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Organization

Yes or No

Question 8 Comment

(NRECA)
Overton Power District No. 5

Yes

Arizona Public Service Company

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

New York State Reliability
Council

Yes

New York Power Authority

Yes

Luminant Energy

Yes

Electricity Consumers Resource
Council (ELCON)

Yes

Western Area Power
Administration

Yes

National Association of
Regulatory Utility Commissioners

Yes

PacifiCorp

Yes

Grand Haven Board of Light and
Power

Yes

Glacier Electric Cooperative

Yes

FHEC

Yes

South Texas Electric

Yes

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Organization

Yes or No

Question 8 Comment

Cooperative, Inc.
Portland General Electric
Company

Yes

South Texas Electric
Cooperative, Inc.

Yes

National Grid

Yes

Dayton Power and Light
Company

Yes

ExxonMobil Research and
Engineering

Yes

Duke Energy

Yes

Alberta Electric System Operator

Yes

Fayetteville Public Works
Commission

Yes

Florida Keys Electric Cooperative

Yes

American Electric Power

Yes

East Kentucky Power
Cooperative, Inc.

Yes

American Transmission
Company, LLC

Yes

Farmington Electric Utility System

Yes

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Organization

Yes or No

Sierra Pacific Power Co d/b/a NV
Energy

Yes

Colorado Springs Utilities

Yes

Consumers Energy Company

Yes

Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

Yes

Muscatine Power and Water

Yes

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

Yes

Sacramento Municipal Utility
District (SMUD)

Yes

Puget Sound Energy

Yes

GTC

Yes

Idaho Power

Yes

Long Island Power Authority

Yes

PJM

Yes

Oncor Electric Delivery Company
LLC

Yes

August 19, 2011

Question 8 Comment

No comment.

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Organization

Yes or No

City of Anaheim

Yes

MEAG Power

Yes

Xcel Energy

Yes

Golden Spread Electric
Cooperative, Inc.

Yes

Question 8 Comment

Response: Thank you for your support. The SDT modified Exclusion E3 to make non-retail generation in a local network subject to a comparable exclusion
designation as that for customer-owned generation in Exclusion E2. Please see the modified definition.

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9. The SDT has added specific exclusions to the core definition in response to industry comments. Do you agree
with Exclusion E3? If you do not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: The SDT has modified the local network definition in the following manner:
•

Elimination of the term “Distribution” in the label of this exclusion, making it a “local network”.

•

Changes were made to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network, including a
statement that the local network does not accommodate bulk power transfer across the interconnected system.
Eliminated the provision in Exclusion E3.a which referred to automatic fault interrupting devices, and changed wording to clarify the
connection point of the local network.

•

While the SDT disagrees with removal of restrictions on the amount of connected generation, it takes note of the concern about growing amounts
of connected generation within the distribution system. As such, the SDT has made changes to those limits from the original posting in a new
item E3.a limiting connected generation within a local network to 75 MVA aggregate non-retail generation similar to the provision in Exclusion
E1.c. Commenters expressed concern about the lack of technical justification for a 75 MVA limit on connected generation; however, the SDT has
been presented with no technical basis upon which to suggest a change from this value. After consulting with the NERC Board of Trustees and
the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t
enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address
the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and
the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
Items E3.c and E3.d were combined into a new item E3.b, incorporating the concepts of power flow into the Local Network and precluding energy
transfers across the Local Network. This provision also effectively removed the comparison test between generation and minimum demand of the
Local Network.
The SDT considered commenters’ suggestions regarding allowance of some power flow out of the LN, and concluded that strict limits precluding
out-flow are appropriate, particularly given that the local network comprises facilities that are electrically parallel to the BES.
Finally, the SDT, in consideration of regulatory concerns, inserted a provision in the local network exclusion to limit the operating voltage of the
local network to 300 kV.
The revised Exclusion E3 reads as follows:
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that
distribute power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection
at 100 kV or higher are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail
customer Load and not to accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:

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Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in
Inclusion I3, and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in
aggregate), includes more than 75 MVA generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the
LDN The LN does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored
Facility in the ERCOT or Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).

Organization
Northeast Power Coordinating
Council

Yes or No

Question 9 Comment

No

Regarding E3.a.--If the supply to a LDN is tapped off a Bulk Electric System facility, and the step down
transformer is protected on its high side by a fault magnitude supervised automatic interrupting device (such
as a circuit switcher), how does that affect the exclusion? The circuit switcher will only interrupt faults up to a
certain magnitude. Above that threshold, depending on the system configuration, fault clearing might have to
be done at the Bulk Electric System facility.
Regarding E3.d.--The LDN cannot be used to transfer real or reactive power under all operating conditions.
Suggest combining E3.c and E3.d to read as follows:Power is intended to flow only into the LDN. The
generation within the LDN shall not exceed the electric real or reactive power demand within the LDN. The
LDN only delivers real or reactive power to load, and is not to be used to transfer real or reactive power
between different locations in the BES. Under no system condition is BES reliability to be dependent on LDN
flow.

Response: The SDT has modified the local network definition, eliminating provision E3.a, which referred to the automatic fault interrupting devices. The point
of demarcation of the local network may be clarified in subsequent guidance documents; however, it begins at the point where the three remaining
characteristics (E3.a, b, and c) can be demonstrated. Additionally, the SDT has combined prior items E3.c and E3.d into a new item E3.b in the revised definition
incorporating the concepts of power flow into the local network and precluding energy transfers across the Local Network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to

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Organization

Yes or No

Question 9 Comment

accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Tri-State Generation and
Transmission Association, Inc.

No

We believe that element c. needs to be changed to : “Power flows only into the Local Distribution Network,
even under all contingency conditions that are considered under any TPL standard requirement dealing with
transmission system performance: The generation within the LDN shall not exceed the electric Demand
within the LDN;"

Response: The SDT has combined prior items E3.c and E3.d into a new item E3.b in the revised definition incorporating the concepts of power flow into the
Local Network and precluding energy transfers across the Local Network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Interconnected System. LDN’s emanate from multiple points of connection at 100 kV or higher are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to accommodate
bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and

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Organization

Yes or No

Question 9 Comment

c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
NERC Staff Technical Review

No

Exclusion E3 is acceptable in general; however, (i) including the word “distribution” in the exclusion could be
interpreted to imply that certain distribution facilities are included in the BES unless specifically excluded,
(ii) item d) is unclear as to whether it applies to any parallel flow or only to parallel flow for which the group of
Element(s) are part of the contract path, and
(iii) interrupting devices should be included in the BES for the same reasons as stated above for Exclusion
E1. >>>>>>>>>>
The concern with the word distribution in the term “Local Distribution Network” can be avoided by eliminating
use of this phrase. The proposed definition already defines the Elements covered by Exclusion E2 and does
not require defining a term for use in this standard. An alternate solution would be to establish a different
term to describe the groups of Elements that does not include the word distribution. >>>>>>>>>>
The phrase “is used to” in item d) lacks clarity. Clarity should be provided by stating that the group of
Elements does not transfer energy originating outside the group of Elements; this is consistent with item c)
that requires that power flows only into the group of Elements. >>>>>>>>>>
The reason for requiring automatic interrupting devices between the BES and the excluded LDN is to prevent
faults and other abnormal conditions in the LDN from negatively impacting reliability of the BES. Given the
reliance on the interrupting devices to support BES reliability, it is appropriate to include the interrupting
devices in the BES so that they are planned, designed, maintained, and operated in accordance with NERC
Reliability Standards the same as other BES Elements. Thus, when excluding groups of Elements at 100 kV
or higher, the BES line of demarcation should be on the load side of the automatic interrupting devices.
>>>>>>>>>>
To address our concerns, Exclusion E3 should be changed to read: >>>>>>>>>> E3 - Groups of Elements
operated above 100 kV that distribute power to Load rather than transfer bulk power across the
interconnected System. Such groups of Elements are connected to the Bulk Electric System (BES) at more
than one location solely to improve the level of service to retail customer Load. These groups of Elements are
characterized by all of the following:a) Separable by automatic fault interrupting devices: Wherever
connected to the BES, the group of Elements must be connected through automatic fault-interrupting devices
(the automatic interrupting device is part of the BES);b) Limits on connected generation: Neither the group of
Elements, nor any underlying Elements operated at 100 kV or below, includes more than 75 MVA generation
(in aggregate);c) Power flows only into the group of Elements: The generation within the group of Elements
shall not exceed the electric Demand within the group of Elements;d) Not used to transfer bulk power: The

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Organization

Yes or No

Question 9 Comment
group of Elements does not transfer energy originating outside the group of Elements for delivery through the
group of Elements; ande) Not part of a Flowgate or transfer path: The group of Elements does not contain a
monitored Facility of a permanent flowgate in the Eastern Interconnection, a major transfer path within the
Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the Quebec
Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).

Response: The term “Distribution” has been removed; these facilities are now referred to as “local networks”.
The SDT has combined prior items E3.c and E3.d into a new item E3.b in the revised definition incorporating the concepts of power flow into the local network
and precluding energy transfers across the local network.
Item E3.a has been removed from the definition, and as such, there is no longer any mention of the interrupting devices within this exclusion.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Interconnected System. LDN’s emanate from multiple points of connection at 100 kV or higher are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to accommodate
bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Dominion

No

An Element or Facility should only be excluded where the Element or Facility is not necessary for operating
an interconnected electric energy transmission network or is needed to maintain transmission system
reliability.

Response: The SDT believes that the revised Exclusion E3 properly identifies facilities that are not necessary for operating an interconnected electric energy

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Organization

Yes or No

Question 9 Comment

transmission network and not needed to maintain transmission system reliability.
SPP Standards Review Group

No

While the principle contained in (c) is valid, the explanation following it is too restrictive. This does not allow
the LDN to maintain any excess generation for contingencies and normal load fluctuations.
In (b) the implication is that the LDN is being treated like a single site in I3 whereby the total generation
capability is restricted to 75 MVA. Is this a valid assumption for municipals?
In (e) permanent flowgates may change from month to month, therefore an LDN could bounce into and back
out of the BES depending upon what happens regarding a specific facility which may be included as part of a
flowgate. This creates a very fluid situation which can lead to confusion.

Response: The SDT has revised the language concerning limits on connected generation in new item E3.a.
A 75 MVA aggregate non-retail generation limit is proposed, and the SDT believes that this is consistent with the similar provision in the radial exclusion, E1.c.
The SDT appropriately uses the word “permanent” in connection with the flowgates in E3.c, as its intent is to prevent facilities that might temporarily be
considered to be a flowgate from qualifying for exclusion as a local network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Interconnected System. LDN’s emanate from multiple points of connection at 100 kV or higher are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to accommodate
bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
MRO's NERC Standards Review

August 19, 2011

No

The SDT is defining what a Local Distribution Network is but the term transfer bulk power is ambiguous.

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Organization

Yes or No

Forum

Question 9 Comment
Please clarify what the intent of this exclusion is.

Response: The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term
“bulk power” was retained in paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
SERC OC Standards Review
Group

No

“b) Limits on connected generation: Neither the LDN, nor its underlying Elements (in aggregate), includes
more than 75 MVA generation;” The SERC SDT believes you intended to grant exception E2 in this case;
however, it is not explicitly identified”
c)Power flows only into the Local Distribution Network: The generation within the LDN shall not exceed the
electric Demand within the LDN;” Is this intended for each hour of the year or is it possible for some hours
that generation may exceed load? This needs to be clarified.

Response: The revised definition includes a revised item E3.a, which clarifies the limits on connected generation within the local network.
It is the intent of the SDT that the power flowing into the local network be demonstrated through integrated hourly measurements over a period of time
consistent with the ROP Exception Process, which is currently contemplated to be a period of two years.
Idaho Falls Power

August 19, 2011

No

We support this exclusion, however generation assets on a Local Distribution Network should be excluded

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Organization

Yes or No

Question 9 Comment
regardless of MVA rating if all other defining critera in E3 are met.
Additionally, it is unclear as written whether a single generation asset greater than 20MVA would be excluded
as E3(b) states 75 MVA, but is inconsist with E2(i). Some clarification of intent is needed to resolve the
ambiguities between these two exclusions.

Response: The SDT disagrees with removing restrictions on the amount of connected generation, but has made changes to those limits to address industry
concerns.
Please refer to the new item E3.a.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Tennessee Valley Authority

No

The following comments are specific to subsections of E3:Section (c): We suggest the section to read,
“Power flows out of the LDN shall not exceed the limitations imposed in Inclusions I3 and I5.
”Section (d): We suggest the section be read, “Not used to transfer bulk power: The LDN is not used to
transfer energy originating outside the LDN for delivery through the LDN, except for the power flowing in a
normally open switching device between radial systems operating in a make-before-break fashion as defined
in exclusion E1.”

Response: The SDT considered this suggestion regarding allowance of some power flow out of the local network, and concluded that strict limits precluding out-

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Organization

Yes or No

Question 9 Comment

flow are appropriate, particularly given that the local network comprises facilities that are electrically parallel to the BES.
The revised definition has included a change to the prior E3.d language, which is now reflected in the revised item E3.b.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
ReliabilityFirst

No

the LDN term must be a NERC defined term and if this is allowed as mentioned in the first comment, we feel
the intent of the FERC Order was to simplify and not complicate the definition and the inclusion/exclusion
process. This definition is now even more complex.
we also feel that as a result of several defined terms such as the LDN teh proposed definition will in most
cases exclude portions of networks in locations such as Washington DC, New York and other Metro Areas,
many Munis and citiies that are currently registered. If the intent is to remove entities from the registry this
will in most likely do it.

Response: The SDT intends to fully explain the characteristics of a “local network” within the BES definition, and as such, the term is not necessary in the
Glossary.
It is not the SDT’s intent to specifically exclude any facilities in major metropolitan areas; it expects that the specific examples mentioned (NYC, Washington DC)
would not qualify for exclusion under the revised Exclusion E3. No change made.
Electricity Consumers Resource

August 19, 2011

No

There are two different types of LDN: utility owned and customer owned. They should not be treated the

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Organization

Yes or No

Council (ELCON)

Question 9 Comment
same. Criteria (a) through (e) in Exclusion E3 may be appropriate for distinguishing between utility-owned
LDN and utility-owned BES transmission often owned and operated by the same integrated utility. A
separate, stand-alone exclusion criteria should be established for customer-owned elements that serve to
distribute electric energy to on-site loads, including all or part of the electric energy from behind-the-meter
generation. Thus, E3 criteria (a) through (e) would apply exclusively to utility-owned elements. For
customer-owned elements, the new criterion (f) might read:"Or the LDN is also characterized by:"f) The
Elements are customer owned and used to distribute electric energy to on-site loads, including all or part of
the electric energy from behind-the-meter generation."See response to #11 below for further justification for
this recommendation.

Response: The SDT has revised item E3.a to clarify that retail generation would not contribute toward the limits of connected generation within the local
network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or
Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Central Maine Power Company
New York State Electric & Gas
and Rochester Gas & Electric

August 19, 2011

No

This exclusion is vague, but needs to be clear and comply with Order 743. Also, “distribution” is already
excluded from transmission and therefore “BES.”
Also, E1 refers to “automatic interruption device” and E3 refers to “automatic fault interrupting device”, neither
of which are defined.We think that large portions of the network may be inappropriately excluded under this
exclusion and exclusion E3 should be deleted.

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Organization

Yes or No

Question 9 Comment

Response: The term “Distribution” has been removed, and now this exclusion refers to “local networks”.
Also, the prior item E3.a, referring to automatic fault interrupting devices, has been removed in this revision of the definition.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Hydro-Quebec TransEnergie

No

Part b) is again very restrictive. It is not necessary to refuse exclusion when generation is above 75 MVA.
However, a provision should be made so that reliability standards related to generator shall apply.

Response: The SDT disagrees with removing restrictions on the amount of connected generation, but has made changes to those limits to address industry
concerns. Please refer to new item E3.a.
The application of the reliability standards to generators will continue to be determined by the Statement of Compliance Registry Criteria.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and

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Organization

Yes or No

Question 9 Comment

do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
National Grid

No

E3.c and E3.d - These two points can be combined into one:Power is intended to flow only into the LDN. The
generation within the LDN shall not exceed the electric real or reactive power demand within the LDN. The
LDN only delivers real or reactive power to load, and is not to be used to transfer real or reactive power
between different locations in the BES. Under no system condition is BES reliability to be dependent on LDN
flow.
E3.e - We would like more clarification on flowgates and what they are. We are interpreting flowgate as the
lines that make up defined operational interface, as defined by the Operations group not the Planning group.
Is this the correct interpretation of flowgate?

Response:
Flowgate is a defined term in the Glossary of Terms used in Reliability Standards as follows:
1.) A portion of the Transmission system through which the Interchange Distribution Calculator calculates the power flow from Interchange Transactions.
2.) A mathematical construct, comprised of one or more monitored transmission Facilities and optionally one or more contingency Facilities, used to analyze
the impact of power flows upon the Bulk Electric System.
Items E3.c and E3.d were indeed combined as suggested, and now have become new item E3.b.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusions I3, and

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Organization

Yes or No

Question 9 Comment

do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or
Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Electric Reliability Council of
Texas, Inc.

No

See response to Question 7.

Southwest Power Pool

No

See response to question 7.

No

Similar to the comments provided on Exclusion E1, the inclusion of a requirement for automatic fault
interrupting device to separate the local distribution network from the interconnected transmission network
will in many cases shift the onus of securing a reliable interconnected transmission network from the owners
and operators of that interconnected transmission network to the customers and owners of local distribution
networks that pay the owners and operators of the interconnected transmission network a fee for providing
reliable transmission services. Furthermore, the Federal Power Act excludes all facilities used in the local
distribution of electric energy and does not distinguish whether such local distribution facilities must be
isolated by automatic fault interrupting devices.

Response: See response to Q7.
ExxonMobil Research and
Engineering

Response: Item E3.a has been removed from the definition, and as such, there is no longer any mention of the interrupting devices within this exclusion.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA

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Organization

Yes or No

Question 9 Comment

generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Colorado Springs Utilities

No

Colorado Springs Utilities generally supports Exclusion E3 that provides for the exclusion of Local Distribution
Networks (LDNs) from the BES, with the following modifications:
1) It is not necessary to articulate the nature of the LDN’s connection to the BES. If the characterizations are
met, the number of connections and the reasons for the connections are immaterial.
2) If the LDN is a normal net import, there is no need to limit the amount of connected generation since the
generation will have no material effect on the BES.
3) ‘Bulk power transfers’ are acceptable across an LDN if the transfer is to a nested LDN. Contractual
energy, originating outside the LDN and delivered to a nested LDN, for example, is still load delivery and has
the same physical characteristics of a holistic LDN and the transfer of bulk power is immaterial.We propose
changing Exclusion E3 to read,”Local Distribution Networks (LDN): Groups of Elements operated above 100
kV that distribute power to Load rather than transfer bulk power across the Interconnected System. The LDN
is characterized by all of the following:a) Separable by automatic fault interrupting devices: Wherever
connected to the BES, the LDN must be connected through automatic fault-interrupting devices;b) Power
flows only into the Local Distribution Network: The generation within the LDN shall not exceed the electric
Demand within the LDN;c) Not used to transfer bulk power, except transfers to nested LDNs: The LDN is not
used to transfer energy originating outside the LDN for delivery through the LDN, except transfers to nested
LDNs; andd) Not part of a Flowgate or Transfer Path: The LDN does not contain a monitored Facility of a
permanent flowgate in the Eastern Interconnection, a major transfer path within the Western Interconnection
as defined by the Regional Entity, or a comparable monitored Facility in the Quebec Interconnection, and is
not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).”

Response: The SDT has revised Exclusion E3 Local network in a way that removes the mention of automatic fault interrupting devices.
This is a continent-wide definition that applies to all cases of a local network. One can not assume that a local network will always be a net importer in all
situations, hence the limit on generation.

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Organization

Yes or No

Question 9 Comment

While the SDT does not fully understand the concept of “nested LDN”, we believe that the revised Exclusion E3 in sum captures the concept of networks that are
providing a distribution function.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

August 19, 2011

No

(Note: Inserted language provided in brackets; deleted language denoted by empty brackets: [ ].) Exclusion
E3 is also contrary to the plain language of Section 215 of the FPA. The SDT stated in commentary to E3
that it “believes that any network that simply supports distribution and is providing adequate protection should
be excluded from the BES.” This statement highlights the fundamental disconnect between the proposal and
Section 215 of the FPA, which excludes facilities used in the local distribution of electric energy from the
definition of the BES regardless of whether the facilities are “providing adequate protection.” That is, Section
215 of the FPA states that the definition of the BES excludes “facilities used in the local distribution of electric
energy,” not “facilities used in the local distribution of electric energy [providing adequate protection].”With
respect to the enumerated criteria in Exclusion E3, the requirement that Local Distribution Networks (“LDNs”)
“must be connected through automatic fault-interrupting devices” violates the FPA because, as discussed in
response to Question 7, it places a condition on the unqualified exemption granted by Congress to facilities
used in the local distribution of electric energy. Moreover, the other enumerated criteria also fail under
Section 215 of the FPA and case law because they ignore, as discussed further in response to Question 11,
a long line of precedent that requires a fact-specific analysis to be conducted to determine whether a facility
is used in local distribution (see, e.g., Order No. 888 at 31,980). To make Exclusion E3 consistent with the
requirements of Section 215 of the FPA and case law, Exclusion E3 could be rewritten as follows:E3 - [All

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Organization

Yes or No

Question 9 Comment
facilities used in the distribution of electric energy] ([“]Local [D]istribution [N]etworks,[“ or “]LDNs[“]): Groups of
Elements operated above 100 kV that distribute power to Load rather than transfer bulk power across the
interconnected System. LDN[]s are [normally] connected to the Bulk Electric System (BES) at more than one
location solely to improve the level of service to retail customer Load. The LDN is characterized by all of the
following:a) [ ]b) Limits on connected generation: [Generally], neither the LDN, nor its underlying Elements (in
aggregate), includes more than 75 MVA generation;c) Power flows only into the LDN: The generation within
the LDN [normally does] [ ] not exceed the electric Demand within the LDN;d) Not used to transfer bulk
power: The LDN is [generally] not used to transfer energy originating outside the LDN for delivery through the
LDN; ande) Not part of a Flowgate or transfer path: The LDN normally does not contain a monitored Facility
of a permanent flowgate in the Eastern Interconnection, a major transfer path within the Western
Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the Quebec
Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).Please see further discussion in response to Questions 11 and 12.

Response: The SDT has revised the Exclusion E3 Local network in a way that removes the mention of automatic fault interrupting devices, which it believes
addresses the concern about the apparent disconnect between Section 215 and the prior proposal.
The SDT disagrees with the use of terms such as “normally” and “generally” as these tend to lack precision and objectivity. Please see the revised exclusion.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

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Organization
Muscatine Power and Water

Yes or No
No

Question 9 Comment
The SDT is defining what a Local Distribution Network is but the expression “transfer bulk power” is
ambiguous. Please clarify the purpose of this exclusion.

Response: The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term
“bulk power” was retained in paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or
Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Exelon

No

Exelon has issues with the ambiguity of this Exclusion item. It seems that Local Distribution Networks will all
need to be approved via the Rules of Procedure Exception Process because the characteristics of each LDN
as described are not bright line. For example, does (b) refer to any generation, including behind-the-meter
generation?
Does (c) mean always, i.e., generation can never exceed the load under any condition? In theory or in
actuality?
How does (d) deal with parallel flows under abnormal conditions when some energy may go in and out?
Exelon understands the concept that an LDN primarily serves load, but how will the owners prove that there
is no impact to the BES under contingency configurations?

Response: The SDT has modified exclusion E3 in a manner that addresses the ambiguity of the proposal, clarifies the amount of connected generation rather

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Organization

Yes or No

Question 9 Comment

than the prior comparison of demand and generation, and clarifies that the power flow must always be into the Local Network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Springfield Utility Board

No

SUB agrees with items, a), b), and e) of the characteristics of an LDN.
SUB believes that the language regarding c) and d) needs clarification.c) states: “Power flows only into the
Local Distribution Network: The generation within the LDN shall not exceed the electric Demand within the
LDN.” There may be times where a closed system creates a situation where power flows through the system
on an unscheduled basis (electron’s will follow the path of least resistance). Left as is, there may be a
situation where on a planning basis there is no power flowing out of the LDN, but on a real time basis power
does flow in and out. “Power flows only into the Local Distribution Network: The sum of all power being
delivered into the LDN at the points of measurement is greater than the sum of all the power measured as
being delivered out of the LDN at the points of measurement”
The generation within the LDN shall not exceed the electric Demand within the LDN.”SUB suggests that the
generation language should be deleted, but if the language “The generation within the LDN shall not exceed
the electric Demand within the LDN.” is retained, what does “Demand” mean? The lowest demand? The
highest demand? Instantaneous demand?SUB suggests that if some generation language is added that the
exclusion read:”Power flows only into the Local Distribution Network: The sum of all power being delivered
into the LDN at the points of measurement is greater than the sum of all the power measured as being
delivered out of the LDN at the points of measurement The generation within the LDN shall not exceed the

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Question 9 Comment
maximum electric Demand within the LDN, where the maximum electric Demand is the maximum electric
Demand within the LDN as measured for over the prior sixty (60) months.”
d) states: “Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the
LDN for delivery through the LDN”. Again, this language needs clarification. How would an LSE/DP/TO (or
other similar entity) know that their system is not being used to transfer bulk power when other parties are
scheduling transmission paths via a Balancing Authority or other overarching entity?SUB suggests that the
language be clarified to read “Not used to transfer bulk power: The LDN is not used to transfer energy
originating outside the LDN for delivery through the LDN. This would be evaluated using scheduled
transmission paths and not measured amounts at the point of measurement. It is the responsibility of the
Balancing Authority to notify the Registered Entity with an LDN twelve (12) months in advance of when an
LDN would be used to schedule the transfer of energy outside the LDN for delivery through the
LDN.”Collectively, E3 would read:The LDN is characterized by all of the following:a)Separable by automatic
fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic
fault-interrupting devices; andb)Limits on connected generation: Neither the LDN, nor its underlying
Elements (in aggregate), includes more than 75 MVA generation; and c)Power flows only into the Local
Distribution Network: The sum of all power being delivered into the LDN at the points of measurement is
greater than the sum of all the power measured as being delivered out of the LDN at the points of
measurement; andd)Not used to transfer bulk power: The LDN is not used to transfer energy originating
outside the LDN for delivery through the LDN. This would be evaluated using scheduled transmission paths
and not measured amounts at the point of measurement. It is the responsibility of the Balancing Authority to
notify the Registered Entity with an LDN twelve (12) months in advance of when an LDN would be used to
schedule the transfer of energy outside the LDN for delivery through the LDN.;ande)Not part of a Flowgate or
Transfer Path: The LDN does not contain a monitored Facility of a permanent flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity,
or a comparable monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in
an Interconnection Reliability Operating Limit (IROL).
o Local distribution networks were added to the exclusion list after considerable discussions among the SDT
and various registered entities that have configurations meeting these conditions. The SDT believes that any
network that simply supports distribution and is providing adequate protection should be excluded from the
BES.

Springfield Utility Board

August 19, 2011

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation
normally operated as backup generation for retail load is not counted as generation for purposes of

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Question 9 Comment
determining generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or
exclusion, a system with load and generation normally operated as backup generation for retail load is
considered "serving only load" when using generation normally operated as backup generation for retail load
(See Inclusions I2, I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is
normally used during a localized outage and for testing for reliability during a localized outage event.
Including backup generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation
used for restoration or reliability of the BES. Including backup generation for retail load in generation
threshold calculations would cause a inappropriate inclusion of elements and devices, accelerate the
triggering of inclusion (and may make exclusion provisions meaningless), and push more activity of excluding
smaller systems from the BES into the exception process.

Response: Items E3.c and E3.d were indeed combined as suggested, and now have become the new item E3.b.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
City of St. George

August 19, 2011

No

Local distribution networks should have an exclusion provision. However, the local generation limit of 75
MVA is too restrictive. As long as power flows into a LDN the amount of generation should not trigger a LDN
to be included in the BES. E3b should be removed from these exclusion criteria or maybe a reasonable ratio
of load level to allowed generation on the LDN.

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Question 9 Comment

Response: The limits on connected generation, now described in item E3.a, have been revised, resulting in a less restrictive exclusion characteristic.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Southern California Edison
Company

No

SCE is in support of the general LDN premise, but believes that this definition should more closely track the
FERC seven-factor test from Order 888.
As written, the five factors identified could lead to the reclassification of radial sub-transmission system
facilities above 100kV from “distribution facilities” to “network facilities”. For example, interconnection
amounts within an LDN may exceed an aggregate level of 75MVA, but will not exceed the load in the LDN.
SCE suggests striking characteristics “B” and “D” from Exclusion E3, and allowing characteristic “C” to stand
alone as the generation characteristic which would define an LDN.The SDT may want to incorporate the
following revision:”LDN’s are connected to the Bulk Electric System (BES) at one or more location solely to
improve the level of service to retail customer load.”

Response: The genesis of the characteristics in the local network exclusion is the FERC seven-factor test; however, the SDT seeks to establish bright-line
characteristics that add specificity and objectivity to these principles through this exclusion. The definition differentiates between radial systems and LNs by
clarifying the connection points to the BES from these systems. Radial systems have a single connection point and LNs have multiple connection points. This
alone establishes a bright-line between radial systems and LNs which does not allow for the re-classification of such systems as alluded to in the comment.
Items E3.c and E3.d have now been combined, and have become the new item E3.b. After much discussion, the SDT believes that there must be a limit on

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Question 9 Comment

connected generation (new item E3.a) as well as a provision ensuring that power flow only into the local network (new item E3.b).
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Long Island Power Authority

No

Revise last two sentences in the introductory paragraph to read as follows: “LDN’s are connected to the bulk
electric system (BES) at several points and are characterized by all of the following:”; This removes ambiguity
that exists in the deleted portion of the text.See also response to question 11 regarding Exclusion E3-b.

Response: The SDT has made changes to the introductory paragraph in E3, which it believes clarifies the intent of the local network; however, the SDT believes
that the descriptive language adds necessary context to the entire exclusion principle and therefore should be retained.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;

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Question 9 Comment

b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
The Dow Chemical Company

August 19, 2011

No

The Dow Chemical Company (“Dow) is an international chemical and plastics manufacturing firm and a
leader in science and technology, providing chemical, plastic, and agricultural products and services to many
essential consumer markets throughout the world. Dow and certain of its worldwide affiliates and
subsidiaries, including Union Carbide Corporation, own and operate electrical facilities at a number of
industrial sites within the U.S., principally, in Texas and Louisiana. The electrical facilities at these various
industrial sites are configured similarly and perform similar functions. In most cases, a tie line or lines
connect the industrial site to the electric transmission grid. Power is delivered from the electric transmission
grid to the industrial site through the tie line(s). Lines within the industrial site then deliver power to individual
manufacturing plants within the site. Additionally, cogeneration facilities are located at a number of industrial
sites owned by Dow and its subsidiaries. These cogeneration facilities generate power that is distributed
within the industrial site and used for manufacturing plant operations. In some instances, excess power not
required for plant operations is delivered back into the electric transmission grid through the tie line(s)
connecting the industrial site to the grid. Under all circumstances, electricity is not flowing into and out of such
industrial sites at the same time. While the tie lines and some of the internal lines at these industrial sites
operate at 100kV or higher, they do not perform anything that resembles a transmission function. Rather than
transmit power long distances from generation to load centers, the tie lines and internal lines perform
primarily a local distribution function consisting of the distribution of power brought in from the grid or
generated internally to different plants within each industrial site. In some cases, the facilities also perform
an interconnection function to the extent they enable power from cogeneration facilities to be delivered into
the grid. The voltage of the tie lines and internal lines at these industrial sites is dictated by the load and basic
configuration of each site. Higher voltage lines are used when necessary to meet applicable load
requirements or to reduce line losses. That does not mean that such lines perform a transmission function.
At some sites, Dow is registered as a Generation Owner and Generation Operator. At other sites, the
applicable Regional Entity has found that such registration is not required because of the relatively small
amount of power supplied to the grid from the applicable cogeneration resources, even though those
cogeneration resources have an aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating). Tie lines (to the grid) and internal lines at an industrial site that operate at 100kV or higher should be
excluded from the BES definition if, due to the relatively small amount of power supplied to the grid from the
generation resources at the site, the owner of those generation resources is not required to be registered as

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Question 9 Comment
a Generation Owner and the operator of those generation resources is not required to be registered as a
Generation Operator.At sites where the owner of the generation resources is registered as a Generation
Owner and the operator of those generation resources is registered as a Generation Operator, the internal
lines (between the generation resources and the manufacturing plants) that operate at 100kV or higher
should be excluded from the BES definition, because they are distribution and not transmission facilities. The
lines interconnecting the generation resources at such sites to the transmission grid should be included in the
BES definition, but the owner and operator of such interconnection lines should not be registered as a
Transmission Owner or Transmission Operator. In no instance has a Regional Entity determined that Dow or
any subsidiary should be registered as a Transmission Owner or Transmission Operator. Instead, such
interconnection lines should be considered as part of the generation resource and Generation Owners and
Generation Operators should be subject to reliability standards specifically developed for such
interconnection lines. Dow is strongly opposed to any BES definition that would result in either the tie lines or
the internal lines at industrial sites being subject to the mandatory reliability standards applicable to
Transmission Owners and Transmission Operators. Complying with reliability standards would cause Dow
and its subsidiaries to incur substantial compliance costs and create potential exposure to penalties in the
future for noncompliance. Perhaps such costs and exposure could be justified if subjecting these facilities to
compliance with reliability standards resulted in a material increase in reliability of the BES, but there is no
reason to believe that will be the case. In fact, the opposite might be true. The tie lines and internal lines at
industrial sites owned by Dow and its subsidiaries have been operated for decades as distribution and
interconnection facilities, and practices and procedures have developed over the years that have enabled
such operations to achieve a high degree of reliability for such sites. Requiring these facilities to now operate
in a different manner as transmission facilities may well result in a degradation of the reliability of the
manufacturing plants located at such sites. For example, outages would have to be coordinated with the
RTO, which may not be interested in coordinating such outages with scheduled manufacturing plant
outages.Dow recommends that a separate exclusion be added to the BES definition to address industrial
distribution facilities. Proposed exclusion E-3 for local distribution networks is not sufficient to ensure that all
industrial distribution facilities are excluded. For example, criteria b), entitled “Limits on connected
generation” states that “Neither the LDN, nor its underlying Elements (in aggregate), includes more than 75
MVA generation”. This criteria makes no sense for an industrial site with on-site electricity generation and a
number of manufacturing plants that has internal power lines and lines interconnecting with the transmission
grid that operate at 100 kV or higher where the owner and operator of the on-site electricity generation
facilities are not registered as a Generation Owner and a Generation Operator because only a small amount
of electricity is ever exported from the on-site electricity generation facilities to the transmission grid. This
criteria also makes no sense with respect to internal electric lines (operated at 100 kV or higher) at such
industrial sites even where the owner and operator of the on-site electricity generation facilities are registered
as a Generation Owner and a Generation Operator.Criteria c) also causes proposed exclusion E-3 not to be
sufficient to ensure that all industrial distribution facilities are excluded where the owner and operator of the

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Question 9 Comment
on-site electricity generation facilities are not registered as a Generation Owner and a Generation Operator
because only a small amount of electricity is ever exported from the on-site electricity generation facilities to
the transmission grid. Criteria c), entitled “Power flows only into the LDN”, states: “The generation within the
LDN shall not exceed the electric Demand within the LDN.” Criteria c) also makes no sense with respect to
internal lines at such industrial sites even where the owner and operator of the on-site electricity generation
facilities are registered as a Generation Owner and a Generation Operator.

Response: Criteria E3.c has been revised to separate the concepts of power flow into the network from the comparison of generation to demand. Additionally,
the new E3.a addresses the limits on connected generation and in so doing, excludes from consideration all retail generation.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Central Lincoln

No

Central Lincoln strongly supports the exclusion of LDNs. These networks are used for improving local
service, not for BES reliability; and their use should not be discouraged. However, we see problems with the
language of part d. Part d uses the term the undefined term “bulk power” as part of the overall definition of
“bulk power system,” leading to a circular definition. Did the SDT mean to indicate that no power may be
transferred though an LDN? If so, suggest striking the word “bulk.”
We also believe the SDT meant to define the LDN in terms of normal operating conditions, since all LDNs
would transfer power under the right contingency (such as a complete loss of load within the LDN). Please
make it clear that part d test applies during normal operating conditions.

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Question 9 Comment

Response: The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term
“bulk power” was retained in the paragraph E3, as we believe it provides conceptual value to the exclusion principle.
The SDT disagrees with the use of the concept “normal operating conditions” as it tends to lack precision and objectivity for use in an effective definition.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
PPL Energy Plus and PPL
Generation

No

See comments in Question 13.

No

Exclusion E3 needs to be strengthened to ensure that the LDN will have no impact on the BES. The
protective elements preventing the LDN from impacting the BES should be included in the BES.

Response: See response to Q13.
Manitoba Hydro

As well, the term Local Distribution Network (LDN) should be defined as a separate NERC Glossary term,
instead of being defined in the BES definition.
Response: The SDT has revised the E3 local network exclusion in a way that removes the mention of automatic fault interrupting devices.
The SDT intends to fully explain the characteristics of a “local network” within the BES definition, and as such, the term is not necessary in the Glossary.

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Yes or No

Question 9 Comment

E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
ISO New England, Inc.

No

We think that large portions of the network may be inappropriately excluded under this exclusion and the
exclusion should be deleted.If E-3 is retained, then it is recommended that the SDT change the sentence
“LDN’s are connected to the Bulk Electric System (BES)” to “LDN’s include transmission connected to the
Bulk Electric System (BES)...”
An Automatic Interruption device needs to be defined. For example, Iis a fuse an Automatic Interruption
device?
The definition needs clarification in the phrase: Power flows only into the Local Distribution Network: The
generation within the LDN shall not exceed the electric Demand within the LDN;Should this be “Net power
...”? One transmission path could be exporting power but the net sum of all paths would always be importing
power.

Response: The SDT has debated Exclusion E3 and has determined that it should be retained.
similar to what your comment suggested.

However, the language has been changed to provide clarification

The SDT has revised the Exclusion E3 local network in a way that removes the mention of automatic fault interrupting devices.
The revised Exclusion E3 now combines the prior items E3.c and E3.d into a revised item E3.b.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute

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Yes or No

Question 9 Comment

power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Consolidated Edison Co. of NY,
Inc.

No

Multiple Connections - The current wording in the second sentence “at more than one location” could be
misinterpreted. Replace this sentence with the following wording:LDN’s use multiple connections to the Bulk
Electric System (BES) solely to improve the level of service to retail customer load.

Response: The SDT considered this suggestion and believes that reference to “more than one location” has sufficient clarity; therefore this language was
retained. The paragraph has been revised to eliminate the term “solely” and to explain that the local network does not accommodate bulk transfer across the
interconnected system.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN

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does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Independent Electricity System
Operator

No

Consistent with our earlier comments in response to Q1, we do not agree that an LDN should be
characterized by a 75 MVA limit on the connected generation as described in part (b). It is expected that
under various “green energy” programs that the development and implementation of distributed generation
will grow considerably in the future. The 75 MVA generation limit may discourage this development of
distributed generation (in general, it may discourage the installation of generation in lieu of transmission to
supply load) because installing generation in an LDN would cause the entire LDN to be classified as BES
and, as a result, subject the LDN to NERC planning standards that are inconsistent with well established
jurisdictional planning criteria. To avoid subjecting the LDN to NERC requirements, the planning authority
may elect to build generation outside of the LDN, which is undesirable because of increased transmission
losses and reduced reliability. We suggest that (b) be deleted or revised in keeping with our earlier
suggestions.
We also suggest modifying Exception E3 (c) and (d) for consistency with language used in Technical
Principles for Demonstrating BES Exceptions, since Bullet 1 recognizes that the system for which the
exemption is being applied, may not be necessary for BES reliability and may experience power flows out to
the BES under specified conditions. The suggested modified wording for E3 (c) and (d) is shown below: (c)
Power is intended to flow only into the LDN: the total net Generation output within the LDN shall not exceed
the total electric Demand of the LDN. (d) Not intended for use in transferring bulk power: While the LDN is
intended to deliver power to load and not transfer bulk power between different locations in the BES, it is
acceptable that under specified system conditions, bulk power transfers may take place between different
points of the BES via the LDN, when it can be demonstrated that these power flows through the LDN are not
necessary for maintaining BES reliability.

Response: The SDT takes note of the concern about growing amounts of connected generation within the distributed generation arena, and has proposed a
revision to the limits on connected generation, now found in item E3.a.
Regarding the suggestion for language changes in sub-items c and d, the SDT has made a modification in the revised definition item E3.b to address both the
power flow into the local network and the prohibition of use of a candidate local network for power flow transactions through the network (commonly referred to
as “wheel-through” transactions). Since the local network is electrically parallel to facilities presumed to be BES, and hence, may have some interactive effect
upon the BES, the SDT believes that in order to qualify for exclusion, the local network must exhibit characteristics that mimic a classic radial system; i.e., flow

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only into the network and no utilization for “through” transactions.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
BPA

No

[As requested above BPA would like “automatic interruption device” and “automatic fault interrupting device” to
be defined terms] Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;
BPA seeks clarification on:
E3 – couldn’t E2 and E3 both apply to the same system? If so, wouldn’t the generation limit in E3(b) (75 MVA
maximum) eliminate the exemption in E2 (can be above 75 MVA if maximum net capacity provided to BES
does not exceed 75 MVA)?
BPA seeks to have “transfer bulk power” defined.
If an LDN had two connections, 200 MW flowed in on one, and 150 MW flowed out on another, how would
that be counted?)
How do you determine if the LDN is being used for bulk power transfer or not?
One interpretation could be: any path that is scheduled across for purposes other than serving load

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contained therein would be determined to be used to “transfer bulk power”. In other words, transactions can
only flow INTO an LDN. If transactions flow out of an area at any point, then from a compliance perspective
that area would not meet this component of the LDN definition. The LDN is not used to transfer energy
originating outside the LDN for delivery through the LDN; and (end of comment)

Response: The SDT has revised the Exclusion E3 local network in a way that removes the mention of automatic fault interrupting devices.
The revised Exclusion E3 now specifically excludes from consideration the “behind the meter” generation in the limits on connected generation.
The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term “bulk power”
was retained in the paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.
In the example of 200 MW in-flow and 150 MW out-flow, this network would not meet the revised item E3.b, as power is flowing out at one or more of the
interfaces; therefore the exclusion would not be satisfied.
The determination of use of the local network for transfer of bulk power would be characterized by the demonstration that power is flowing only in to the
network and that the network is not accommodating power transfers for instance, it is not a contract path for power transactions.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Portland General Electric
Company

August 19, 2011

While PGE appreciates the SDT’s efforts to exclude distribution systems, asrequired by the statute, PGE
believes that this Exclusion needs further clarification to beworkable. PGE has specific concerns with the
following aspects of the Exclusion:(b) The phrase “nor its underlying Elements (in aggregate)” is ambiguous.

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It does notmake it clear how a utility could differentiate between the multiple Local DistributionNetworks
within its service territory.
(c) The phrase “Power flows only into the Local Distribution Network” does not makeclear that under certain
abnormal circumstances power may flow out of a LocalDistribution Network. Wording such as “the
predominant direction of flow is into theLocal Distribution Network during normal (non-outage) conditions”
could account forsuch abnormal circumstances.
(d) The phrase “Not used to transfer bulk power” should similarly be modified toindicate that it is meant to
describe normal rather than abnormal conditions. Inaddition, this aspect of the Exclusion should account for
the fact that two utilities mayhave multiple interchange points at the distribution level, but the fact that energy
istransferred at these points does not inherently make them transmission paths. A phrasesuch as “none of
the LDN facilities are identified as belonging to or having direct ratingimpact on a regionally-recognized
constrained transmission path used to deliver energyto points outside of the LDN” could address this
concern.

Response: The SDT appreciates your concern about the possible ambiguity in “underlying Elements”; however, the SDT believes that this language is
appropriate in order to clarify that the lower than 100 kV facilities contribute to the limits on connected generation.
The SDT has determined that it will refrain from the use of “predominant direction”, “normal circumstances” etc., as the use of this language tends to lack
precision and objectivity and is therefore unsuitable in a definition. No changes made for these comments.
Georgia System Operations

In item c, What is meant by “generation” and by “electric Demand,” and how is whether “generation within the
LDN...exceed[s] the electric Demand within the LDN” to be calculated? Is this installed nameplate capacity
(rather than energy) minus peak Demand, or minus forecast Demand, or minus actual Demand - in each
case either for some period of time or at every moment (the NERC Glossary defines Demand as either)? Is it
the actual generated energy minus actual or forecast Demand for some period of time or at every moment?
If the definition is based on capacity, this exclusion should allow for the possibility that a larger than currently
necessary generator may be installed in anticipation of future load growth, so long as it is never used to
generate significantly more than what is needed for load. If actual generated energy is intended, the
exclusion should provide for inadvertent and/or de minimis power flows.

Response: The SDT has removed the concept of comparison of generation to electric demand, and instead has moved to a simpler limit on connected
generation.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to

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accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Tacoma Power

Tacoma Power generally supports Exclusion E3 that provides for the exclusion of Local Distribution Networks
(LDNs) from the BES, with the following modifications:
1) It is not necessary to articulate the nature of the LDN’s connection to the BES. If the characterizations are
met, the number of connections and the reasons for the connections are immaterial.
2) If the LDN is a normal net import, there is no need to limit the amount of connected generation since the
generation will have no material effect on the BES.
3) ‘Bulk power transfers’ are acceptable across an LDN if the transfer is to a nested LDN. Contractual
energy, originating outside the LDN and delivered to a nested LDN, for example, is still load delivery and has
the same physical characteristics of a holistic LDN and the transfer of bulk power is immaterial.
We propose changing Exclusion E3 to read,”Local Distribution Networks (LDN): Groups of Elements
operated above 100 kV that distribute power to Load rather than transfer bulk power across the
Interconnected System. The LDN is characterized by all of the following:a) Separable by automatic fault
interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;b) c) Power flows only into the Local Distribution Network: The generation within the
LDN shall not exceed the electric Demand within the LDN;d) Not used to transfer bulk power, except
transfers to nested LDNs: The LDN is not used to transfer energy originating outside the LDN for delivery
through the LDN, except transfers to nested LDNs; ande) Not part of a Flowgate or Transfer Path: The LDN
does not contain a monitored Facility of a permanent flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable
monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an

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Interconnection Reliability Operating Limit (IROL).”

Response: The SDT considered this suggestion and believes that reference to “more than one location” has sufficient clarity; therefore this language was
retained. The paragraph has been revised to eliminate the term “solely” and to explain that the Local Network does not accommodate bulk transfer across the
interconnected system.
The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty as possible
in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current application of
the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support consistent
application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation that the
revision to the definition would not significantly expand or contract what is currently considered to be the BES. The SDT disagrees with removal of all limits on
connected generation, as this could significantly change the scope of the definition and potentially limit the amount of generation that would be classified as BES
Elements.
While the SDT does not fully understand the concept of “nested LDN”, it believes that the revised Exclusion E3 in sum captures the concept of networks that are
providing a distribution function.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
City of Redding

August 19, 2011

Yes

Redding will support this high level exclusion of Local Distribution in the light that it is a “sharpening” of the
Brightline and is part of the SDT’s overall plan to make the distinction between distribution and transmission
facilities. As Redding mentioned with the radial exclusion (E1), Redding’s support rests on the fact that the

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Exception Process will adequately address the distribution and transmission facilities issue and there will be a
fair and equable method where LDN’s that do not meet this criteria will be adequately identified as distribution
facilities.
However, Redding does believe (as noted in question #4) that the 75 MVA threshold has very little
justification as “necessary” for the transmission system. Generators connected to LDNs are a classic
example where the generation installed acts only as a load modifier. Redding suggests using the 200 MVA
level for generation connected to a LDN.

Response: The SDT has determined that a generation limit is essential to qualify these local networks as distribution; however, in the revised Exclusion E3, the
limits on connected generation have been made somewhat less restrictive as indicated in item E3.a.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
American Municipal Power and
Members
Florida Municipal Power Agency
Florida Keys Electric Cooperative

Yes

The exclusion refers to groups of Elements that “distribute power to Load rather than transfer bulk power
across the interconnected system.” The use of the term “bulk power” is vague and could be read incorrectly
as a reference to the “bulk-power system,” which is defined in the Federal Power Act but is not a NERC
defined term. If the LDN is connected to the BES at more than one location, there will by definition be some
loop flow. We recommend below that Exclusion 3(d) be revised to quantify the amount of loop flow that is
permissible in an excluded LDN.
In the context of the first sentence of Exclusion E3, less specificity is needed, and the sentence should only

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Question 9 Comment
be revised for the sake of accuracy to state: “Groups of Elements operated above 100 kV that are primarily
intended to distribute power to load rather than to transfer power across the interconnected System.
”The exclusion’s reference to connection “at more than one location” is vague. The sentence should be
revised to read “connected to the Bulk Electric System (BES) from more than one Transmission source solely
to improve the level of service to retail customer Load,” and “Transmission source” should have the same
meaning that it does in E1.
E3(a) should require that there be switching devices between the LDN and the BES, not specifically
automatic fault-interrupting devices. The term “separable by” in “Separable by automatic fault interrupting
devices” is unclear and should be reworded.
E3(b) To avoid pulling an LDN into the BES based on very small customer-owned generation (such as
rooftop photovoltaics and hospital backup diesel generators) that the utility does not consider or rely on, or
necessarily even know about, the item should be reworded: “Limits on connected generation: Neither the
LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA of generation used to meet the
resource adequacy requirements of electric utilities.”
E3(d) states “Not used to transfer bulk power.” As noted above, “bulk power” is a vague term. There will
necessarily be some loop flow on a system that is connected to the BES at more than one location. The
amount of permissible loop flow for this purpose needs to be determined and stated in this item.

Response: The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term
“bulk power” was retained in paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.
The SDT has made changes to the introductory paragraph in Exclusion E3, which it believes clarifies the intent of the local network; however, the SDT believes
that the descriptive language adds necessary context to the entire exclusion principle and therefore should be retained.
The SDT considered this suggestion and believes that reference to “more than one location” has sufficient clarity; therefore this language was retained. The
paragraph has been revised to eliminate the term “solely” and to explain that the Local Network does not accommodate bulk transfer across the interconnected
system.
The SDT has revised the Exclusion E3 local network in a way that removes the mention of automatic fault interrupting devices.
The revised Exclusion E3 now specifically excludes from consideration the “behind the meter” generation in the limits on connected generation.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:

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Question 9 Comment

Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Small Entity Working Group
(SEWG)

Yes

Yes, with some clarifying edits. The first sentence of Exclusion 3 should be revised for accuracy as follows:
““Local Distribution Networks (LDN): Groups of Elements operated above 100 kV that are primarily intended
to distribute power to Load rather than to transfer bulk power across the Interconnected System.
”The second sentence should be revised for clarity as follows: “LDN’s are connected to the Bulk Electric
System (BES) from more than one Transmission source solely to improve the level of service to retail
customer Load.”Exclusion E3 a) should be revised as we note in our comments in Question#7 to allow for the
use of switching devices in specific situations

Response: The SDT has made changes to the introductory paragraph in Exclusion E3, which it believes clarifies the intent of the local network; however, the
SDT believes that the descriptive language adds necessary context to the entire exclusion principle and therefore should be retained.
The SDT considered this suggestion and believes that reference to “more than one location” has sufficient clarity; therefore this language was retained. The
paragraph has been revised to eliminate the term “solely” and to explain that the Local Network does not accommodate bulk transfer across the interconnected
system.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA

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generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Hydro One Networks Inc

Yes

We agree with this concept of LDN as part of establishing a bright-line definition along with Exclusion E3.
However, restrictions for LDN such as connected Generation must neither be more restrictive than radial nor
should generation limits be applicable unless they impact the reliability of interconnected transmission
network.Requirements in Exclusion E3 are very restrictive and we do not agree to the limits on connected
generation for Local Distribution Networks (LDN), described in part (b). We suggest that bullet b) be revised
and limits on connected generation must not include generation resources identified in Inclusions I2, I3, I4
and I5. The development and implementation of distributed generation will grow considerably in the future
and will operate together with conventional sources of energy. The real net aggregated power of distributed
generation seen by the bulk power system at the interconnection may be larger than past experience; hence
it requires to be reassessed based on technical studies with respect to the future integration of DG’s. (Please
refer to comments in questions: 3 & 4)
Also, we suggest combining exception E3 (c) and (d) as follows:”(c) Power is intended to flow only into the
LDN: The generation within the LDN shall not exceed the electric Demand within the LDN; The LDN is
intended to deliver power to load and not be used to transfer bulk power between different locations in the
BES. It is recognized that under specified system conditions, bulk power transfers may take place between
different points of the BES via the LDN. However, for these conditions BES reliability is not dependent on the
existence of these power flows through the LDN.”

Response: The SDT has made changes to Exclusion E3 which promotes improved consistency between the restrictions of Exclusions E1 and E3. As well, the
revised item E3.a now provides specific reference to items of the inclusion list.
The SDT has made revisions to combine items E3.c and E3.d into a new item E3.a.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:

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Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
City of Santa Clara, California,
dba Silicon Valley Power

Yes

Yes, Silicon Valley Power agrees with proposed Exclusion E3 that "Local Distribution Networks (LDNs):
Groups of Elements above 100 kV that distribute power to Load rather than transfer bulk power across the
interconnected System," that are (among the other characterizations) "connected to the Bulk Electric System
(BES) at more than one location solely to improve the level of service to retail customer load" should be
specifically excluded from the Bulk Electric System definition. SVP also agrees with the majority of the
characteristics of an LDN set forth in proposed Exclusion E3. However, SVP believes that alternative
language may be more appropriate with respect to characteristic "b" of proposed Exclusion E3. Part "b" to
proposed Exception E3 states "Limits on connected generation: Neither the LDN, nor its underlying
Elements (in aggregate), includes more than 75 MVA generation." SVP submits that the use of a fixed level
of generation to determine whether an entity qualifies as an LDN is too arbitrary and does not reflect
engineering reality. If a fixed level of generation is used, it will often be too high, if the registered entity has a
small system, or too low, when the registered entity has a large system. SVP submits that NERC should
consider modifying part "b" to proposed Exception E3 to give the Regional Entities discretion to determine
whether 75 MVA of generation is the appropriate benchmark for an individual utility. Therefore, SVP submits
that with respect to draft exception E3 b), "Limited connected generation to the LDN or its underlying
Elements (in aggregate), as determined by the LDN's Regional Entity, using 75 MVA as a benchmark" may
be appropriate.
Alternatively, SVP submits that instead of a fixed level of generation, NERC could consider modifying the
language of proposed Exception E3 b) to limit an LDN's connected generation to a high percentage of local
minimum demand, or to a high percentage of generation not already committed to run to meet local reliability
needs. Either option would meet the purpose of the LDN: a registered entity with connected generation that
is, for the most part, only used to serve native or local load.SVP thanks NERC for the opportunity to comment

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on its 1st Draft definition of BES, and its proposed inclusions and exceptions.

Response: The SDT appreciates the concern regarding the lack of technical justification for a 75 MVA limit on connected generation; however, the SDT has been
presented with no technical basis upon which to suggest a change from this value. After consulting with the NERC Board of Trustees and the NERC Standards
Committee, the SDT has decided to forgo any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that
topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However,
this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the
Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as
several other issues that have arisen from SDT deliberations. The revised Exclusion E3 has resulted in a somewhat less restrictive limit on connected generation
as provided in revised item E3.a.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Public Utility District No. 1 of
Snohomish County, Washington

August 19, 2011

Yes

Snohomish strongly supports the categorical exclusion of Local Distribution Networks from the BES. In fact,
for reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to ensure
that the BES definition complies with the statutory requirement to exclude all facilities used in the local
distribution of electric power. LDNs are, of course, probably the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the level of
service to retail customers. But providing an exclusion for radials without providing an equivalent exclusion
for LDNs will have the opposite effect, to the ultimate detriment of electric consumers.Snohomish also

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supports, with the reservations discussed below, the LDN exclusion as drafted by the SDT. At least
conceptually, we believe the SDT has identified the key characteristics that separate LDNs from facilities that
are part of the bulk transmission system and therefore should be classified as BES. Hence, LDNs can be
excluded from the BES based on the characteristics identified by the SDT without compromising the reliability
of the interconnected bulk transmission system.Although Snohomish supports the LDN exclusion, we believe
the exclusion should be refined in the following respects: o The SDT’s draft states that:”LDN’s are connected
to the Bulk Electric System (BES) at more than one location SOLELY to improve the level of service to retail
customer Load.” (emphasis added) We are concerned that the use of the term “solely” implies the need for
an examination of the motives of a local distribution utility in connecting to the BES at more than one location.
This result is problematic because it defeats the purpose of the exclusion, which is to allow LDNs to be
excluded from the BES without an in-depth and expensive inquiry into the exact nature of the LDN. In
addition, the local utility may have a number of motives for connecting to the BES at more than one location,
but the local utility’s motives have nothing to do with how the LDN interacts with the interconnected bulk
system, which should be the key determinant in including or excluding any Element from the BES. With
these concerns in mind, we therefore recommend that the SDT revise the sentence quoted above as follows:
“LDNs are connected to the Bulk Electric System (BES) at more than one location to improve the level of
service to retail customer load and not to accommodate bulk transfers of power across the interconnected
bulk system.” By instituting this suggestion, the SDT would emphasize the key difference between an LDN,
which is designed to reliably serve local, end-use retail customers, and the BES, which is designed to
accommodate bulk transfer of power at wholesale over long distances.
o We believe the characteristics specified by the LDN in subsections (b) and (c) of the exclusion are
redundant. Subsection b specifies that the LDN would not interconnect more than 75 MVA of generation in
aggregate. Subpart c specifies that power flows only into the LDN. We believe the SDT can eliminate
subpart b of the definition and simply rely on subpart c because if power only flows into the LDN even if it
interconnects more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system, only with the LDN. Further, with the
advent of distributed generation, it is easy to foresee a situation in which a large number of very small
distributed generators are interconnected into a LDN, so that the aggregate capacity of these generators
exceeds 75 MVA. However, because the generators are small and dispersed and, under the subpart c
criteria, would be wholly absorbed within the LDN rather than transmitting power onto the interconnected grid,
those generators would not have a material impact on the grid. In addition, the 75 MVA criterion would make
an LDN interconnecting more than 75 MVA part of the BES. For the reasons set forth by the Project 2010-07
SDT, we are concerned the result will be the local utility being improperly classified as a Transmission Owner
and Transmission Operator, which would subject the local utility to a number of reliability standards that
would significantly increase its compliance burden without substantially improving bulk system reliability. In
fact, in the LDN situation, there is even less reason to impose these burdens on the local utility than in the
situation addressed by the Project 2010-07 team, where generators are interconnected to the BES by

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dedicated interconnection facilities. Because the LDN is interconnected at multiple points, the generators
interconnected to the LDN could continue to operate even if one or two interconnection points are out of
service. On the other hand, in the situation addressed by the Project 2010-07 team, if the dedicated
interconnection facility is out of service, the generation is unavailable because there is no alternative route to
deliver it to load.
Finally, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale adoption
of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry lacks adequate
technical justification. The SDT repeats that error here by incorporating those thresholds into the LDN
exception.

Overton Power District No. 5

No

we support Snohomish's clarifications

Response: The introductory paragraph in Exclusion E3 has been revised to eliminate the term “solely” and to explain that the local network does not
accommodate bulk transfer across the interconnected system.
The Commission provided guidance within Order Nos. 743 & 743a which identified the current application of the existing BES definition was essentially correct for
the majority of the continent and directed clarification of the existing language to support consistent application across all regions. Additional guidance from the
Commission spoke to significant changes in the scope of the definition with an expectation that the revision to the definition would not significantly expand or
contract what is currently considered to be the BES. Based on these expectations, the SDT believes that there must be a limit on connected generation as well as
a provision to ensure that power flows only into the local network. Elimination of the generation limit would potentially limit what generation is currently
considered to be BES Elements. The SDT has proposed revised characteristics E3.a and E3.b to capture these concepts.
The SDT has made revisions to combine the items E3.c and E3.d into a new item E3.a.
The revised definition, Exclusion E3, and item E3.a makes the limit on connected generation somewhat less restrictive than in the prior definition document.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN

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does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Western Electricity Coordinating
Council

Yes

WECC agrees in concept. However, in sub-bullet b), it should be clarified that the 75 MVA is gross-aggregate
nameplate, as described in the inclusions.
In sub-bullet c), it should be clarified whether this requirement is at any time or is for hourly integrated values.
Also, the use of the term “major transfer paths” should be modified to be “major transfer paths in the Table
titled Major WECC Transfer Paths in the Bulk Electric System.”
Finally, the reference to “above 100 kV” should be “at or above 100 kV” for consistency.

Response: The suggestion regarding “gross aggregate nameplate” has been incorporated into this revision of the definition.
The SDT has removed the concept of comparison of connected generation to electric demand.
The SDT has incorporated the suggestion to add the words in the introductory paragraph of Exclusion E3.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec

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Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Western Montana Electric
Generating and Transmission
Cooperative

Yes

WMG&T strongly supports the categorical exclusion of Local Distribution Networks from the BES. In fact, for
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to ensure
that the BES definition complies with the statutory requirement to exclude all facilities used in the local
distribution of electric power. LDNs are, of course, probably the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the level of
service to retail customers.
WMG&T supports the LDN exclusion, but we believe the exclusion should be refined in the following
respects: o The SDT’s draft states that:”LDN’s are connected to the Bulk Electric System (BES) at more than
one location solely to improve the level of service to retail customer Load.” We recommend that the SDT
revise the sentence quoted above as follows: “LDN’s are connected to the Bulk Electric System (BES) at
more than one location to improve the level of service to retail customer Load and not to accommodate bulk
transfers of power across the interconnected bulk system.” By instituting this suggestion, the SDT would
emphasize the key difference between an LDN, which is designed to reliably serve local, end-use retail
customers, and the BES, which is designed to accommodate bulk transfer of power at wholesale over long
distances.

Response: The introductory paragraph in Exclusion E3 has been revised to eliminate the term “solely” and to explain that the local network does not
accommodate bulk transfer across the interconnected system.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a

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Question 9 Comment

major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Transmission Access Policy
Study Group

Yes

The exclusion refers to groups of Elements that “distribute power to Load rather than transfer bulk power
across the interconnected system.” The use of the term “bulk power” is vague and could be read incorrectly
as a reference to the “bulk-power system,” which is defined in the Federal Power Act but is not a NERC
defined term. If the LDN is connected to the BES at more than one location, there will by definition be some
loop flow.
We recommend below that Exclusion 3(d) be revised to quantify the amount of loop flow that is permissible in
an excluded LDN. In the context of the first sentence of Exclusion E3, less specificity is needed, and the
sentence should only be revised for the sake of accuracy to state: “Groups of Elements operated above 100
kV that are primarily intended to distribute power to load rather than to transfer power across the
interconnected System.
”The exclusion’s reference to connection “at more than one location” is vague. The sentence should be
revised to read “connected to the Bulk Electric System (BES) from more than one Transmission source solely
to improve the level of service to retail customer Load,” and “Transmission source” should have the same
meaning that it does in E1.
E3(a) should require that there be switching devices between the LDN and the BES, not specifically
automatic fault-interrupting devices. The term “separable by” in “Separable by automatic fault interrupting
devices” is unclear and should be reworded.
E3(b) To avoid pulling an LDN into the BES based on very small customer-owned generation (such as
rooftop photovoltaics and hospital backup diesel generators) that the utility does not consider or rely on, or
necessarily even know about, the item should be reworded: “Limits on connected generation: Neither the
LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA of generation used to meet the
resource-adequacy requirements of electric utilities.
”E3(d) states “Not used to transfer bulk power.” As noted above, “bulk power” is a vague term. There will
necessarily be some loop flow on a system that is connected to the BES at more than one location. The
amount of permissible loop flow for this purpose needs to be determined and stated in this item.

Response: The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term
“bulk power” was retained in the paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.
The SDT has found no technical basis upon which to establish any limits on the amount of allowable loop flow in a local network; however, the technical
exception process may be an avenue for considering such a metric. The SDT has made changes to the introductory paragraph in Exclusion E3, which the SDT

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believes clarifies the intent of the local network; however, the SDT believes that the descriptive language adds necessary context to the entire exclusion principle
and therefore should be retained.
The SDT considered this suggestion and believes that reference to “more than one location” has sufficient clarity; therefore this language was retained. The
paragraph has been revised to eliminate the term “solely” and to explain that the Local Network does not accommodate bulk transfer across the interconnected
system.
The SDT has revised Exclusion E3 local network in a way that removes the mention of automatic fault interrupting devices.
The revised Exclusion E3 now specifically excludes from consideration the “behind the meter” generation in the limits on connected generation, and the SDT has
made revisions that allow up to 75 MVA of connected generation to exist while still qualifying for this exclusion.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Northern California Power
Agency

August 19, 2011

Yes

NCPA supports the comments of the Transmission Access Policy Study Group (TAPS) in this regard.In
addition to this support, NCPA asks for consideration of an alternative approach for determining an exception
in this regard, as opposed to having it based on a somewhat arbitrary fixed level of generation (75 MVA).
NCPA suggests consideration be given for an approach based on a determined percentage of actual demand
for a given LDN. As such, NCPA submits the following with respect to draft exception E3 (b), Limits on
Connected Generation: Neither the LDN, nor its underlying Elements (in aggregate), include more than a
certain percentage of minimum area load, as determined by the regional entity." Such an approach would
require the regional entity to look at the amount of connected generation on a case-by-case basis.

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Question 9 Comment

Response: The SDT has made modifications to the exclusion criteria under Exclusion E3; however, the SDT continues to believe that a flat, fixed value of
generation is the most suitable approach in order to promote consistency and repeatability in the determination.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Texas Industrial Energy
Consumers (TIEC)

Yes

Proposed exclusion E3 should be revised to categorically exclude all facilities that are part of a local
distribution network (LDN), regardless of the specifics of the LDN’s interconnection with the Bulk Electric
System. As currently drafted, Exclusion 3 places a number of inappropriate limits on a whether a local
distribution system is excluded from the Bulk Electric System definition. As recognized by the Commission in
Order No. 743-A, Section 215 of the Federal Power Act categorically excludes local distribution systems from
the Bulk Power System definition without qualification. As a result, LDNs are outside the FERC’s jurisdiction
and are outside the scope of this rulemaking. The SDT should revise the approach to Exclusion 3 to exclude
all facilities that are part of a LDN, regardless of how the LDN is interconnected to the grid. Specifically,
making exclusion of an LDN contingent upon the LDN being connected through automatic fault-interrupting
devices is inappropriate. Similar to the concerns TIEC expressed in response to Question 7, above, if there
are concerns about LDNs impacting the Bulk Electric System, then it is the responsibility of the transmission
provider serving the LDN to ensure that systems and facilities are in place to protect the grid. The specifics
of an LDN’s interconnection to the grid should not dictate whether it is subject to regulation. TIEC would
therefore recommend removing proposed qualification (a) to the LDN exclusion.
Further, the requirement that generation in the LDN can never exceed demand is inappropriate. As the SDT

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Question 9 Comment
properly recognized in Exclusion 2, as long as the generation within an LDN does not trigger registration
requirements, the LDN should be able to export power to the grid without subjecting itself to regulation. Many
LDNs export small amount of power intermittently to balance the flow within the LDN. Subjecting these
networks to regulation as a result of this balancing activity is inconsistent with the existing generation
registration requirements and would exceed the scope of this rulemaking. The existing generation
registration requirements exempt customer-owned generation that serves retail load from generation
registration requirements as long as the net capacity provided to the bulk power system does not exceed the
nameplate requirements for stand-alone generators. Consistent with this approach, an LDN should not have
to be registered as long as its net exports to the grid do not exceed the generation registration requirements.
TIEC accordingly requests that proposed LDN characteristics (c) and (d) be removed as qualifications to the
LDN exclusion, and that the exclusion be revised to allow generation output to the grid as long the net export
to the grid does not exceed the threshold levels for registration as a generator owner/operator.

Response: One of the objectives of the revised definition of the BES is to provide a deterministic method of identifying and excluding facilities that are used for
distribution, and Exclusion E3 is one of the mechanisms by which the SDT proposes to accomplish this. The SDT has revised the Exclusion E3 local network in a
way that removes the mention of automatic fault interrupting devices which the SDT believes addresses the concern about the apparent disconnect between
Section 215 and the prior proposal.
The SDT believes that generation connected within a network that would otherwise be a distribution system, can change the functionality of that network to one
that serves transmission functions; hence, the SDT believes that some limit on connected generation must continue to exist in this exclusion principle.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec

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Organization

Yes or No

Question 9 Comment

Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
PacifiCorp

Yes

PacifiCorp believes this meets FERC’s intent in Order Nos. 743 and 743A, however additional clarification
may be added particularly around items b and c. Regardless of the generation level (item b), if the power only
flows into the Local Distribution Network (“LDN”) (item c) then the the level of generation is not material and
should have no impact on the reliable operation of the BES.

Response: The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty
as possible in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current
application of the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support
consistent application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation
that the revision to the definition would not significantly expand or contract what is currently considered to be the BES. Therefore the SDT disagrees with removal
of all limits on connected generation, but it has made this provision somewhat less restrictive as shown in the revised item E3.a.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Intellibind

Yes

This does address some of my concerns on small radial transmission systems. I think that there will be
confusion when small entities try and apply both E3 and E1 to their particular situations. The ambiguity will
cause more questions than it is trying to answer.

Response: The revisions to Exclusion E3 are intended to bring more clarity and consistency to the application of this exclusion principle. The SDT believes this

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Organization

Yes or No

Question 9 Comment

revision removes the ambiguity mentioned in your comment.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Blachly Lane Electric Cooperative
Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative

Yes

We strongly support the categorical exclusion of Local Distribution Networks from the BES. For reasons
discussed at length in our answer to Question 1, we believe the exclusion is necessary to ensure that the
BES definition complies with the statutory requirement to exclude all facilities used in the local distribution of
electric power. LDNs are likely the most common kind of local distribution facility. Further, the conversion of
radial systems to local distribution networks should be encouraged because networked systems generally
reduce losses, increase system efficiency, and increase the level of service to retail customers. We also
support, with the reservations discussed below, the LDN exclusion as drafted by the SDT. We believe the
SDT has identified the key characteristics that separate LDNs from facilities that are part of the bulk
transmission system and therefore should be classified as BES. Hence, LDNs can be excluded from the
BES based on the characteristics identified by the SDT without compromising the reliability of the
interconnected bulk transmission system.However, for the reasons stated in our answers to Questions 3 and
4, we believe the SDT’s wholesale adoption of the 20 MVA and 75 MVA thresholds from the NERC
Statement of Compliance Registry lacks adequate technical justification. The SDT repeats that error here by
incorporating those thresholds into the LDN exception. The 100 MVA threshold seems more in alignment with
technical standards such as Power System Stabilizer requirements.

Northern Lights Inc

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Yes or No

Question 9 Comment

Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Response: The SDT has revised the Exclusion E3 Local Network in a way that removes the mention of automatic fault interrupting devices, which the SDT
believes addresses the concern about the apparent disconnect between Section 215 and the prior proposal.
The limits on connected generation, now described in item E3.a, have been revised, resulting in a less restrictive exclusion characteristic. The SDT notes,
however, that the responses to the comments in the first posting of the BES Definition did not yield any technically-based alternatives to the generation
thresholds of the ERO Statement of Compliance Registry Criteria (SCRC), and as such, the SDT has no technical rationale to deviate from the SCRC. After
consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at
this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will
be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and
the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization
Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and

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Yes or No

Question 9 Comment

Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Northern Wasco County PUD
Chelan PUD – CHPD
Kootenai Electric Cooperative
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc

Yes

Northern Wasco County PUD strongly supports the categorical exclusion of Local Distribution Networks from
the BES. In fact, for reasons discussed at length in our answer to Question 1, we believe the exclusion is
necessary to ensure that the BES definition complies with the statutory requirement to exclude all facilities
used in the local distribution of electric power. LDNs are, of course, probably the most common kind of local
distribution facility. Further, the conversion of radial systems to local distribution networks should be
encouraged because networked systems generally reduce losses, increase system efficiency, and increase
the level of service to retail customers. Northern Wasco County PUD supports the LDN exclusion, but we
believe the exclusion should be refined in the following respects: o The SDT’s draft states that:”LDN’s are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service
to retail customer Load.” (emphasis added) We recommend that the SDT revise the sentence quoted above
as follows: “LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to
improve the level of service to retail customer Load and not to accommodate bulk transfers of power across
the interconnected bulk system.” By instituting this suggestion, the SDT would emphasize the key difference
between an LDN, which is designed to reliably serve local, end-use retail customers, and the BES, which is
designed to accommodate bulk transfer of power at wholesale over long distances.

Response: The SDT agrees with your suggestion, and has incorporated this concept into the revised introductory paragraph for Exclusion E3.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and

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Yes or No

Question 9 Comment

c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
PUD No. 2 of Grant County,
Washington

Yes

Grant supports the categorical exclusion of Local Distribution Networks from the BES. We believe the
exclusion is necessary to ensure that the BES definition complies with the statutory requirement to exclude
all facilities used in the local distribution of electric power. LDNs are, of course, probably the most common
kind of local distribution facility. Further, the conversion of radial systems to local distribution networks
should be encouraged because networked systems generally reduce losses, increase system efficiency, and
increase the level of service to retail customers. Grant supports the LDN exclusion, but we believe the
exclusion should be refined in the following respects: o The SDT’s draft states that:”LDN’s are connected to
the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail
customer Load.” (emphasis added) We recommend that the SDT revise the sentence quoted above as
follows: “LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to improve
the level of service to retail customer Load and not to accommodate bulk transfers of power across the
interconnected bulk system.” By instituting this suggestion, the SDT would emphasize the key difference
between an LDN, which is designed to reliably serve local, end-use retail customers, and the BES, which is
designed to accommodate bulk transfer of power at wholesale over long distances.Two more suggestions:
Bullet d, starts with “bulk power” and ends with generic “energy” transferred through and out of the LDN. This
is inconsistent and will likely lead to confusion.
In addition, “paper only” contract path transfers that result in no physical flow across the LDN should be
specifically excluded.

Response: The SDT agrees with your suggestion, and has incorporated this concept into the revised introductory paragraph for Exclusion E3.
The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term “bulk power”
was retained in the paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.
The SDT disagrees with the suggestion that “paper only” contract path transfers that result in no physical flow be specifically excluded, as the use of a local
network for transaction scheduling purposes causes it to be serving a transmission function. Where transactions are scheduled through the facilities of a local
network, some physical flow change will occur in accordance with the transfer distribution factor of the network in relation to the transaction source and sink.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:

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Organization

Yes or No

Question 9 Comment

Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Clallam County PUD No.1

August 19, 2011

Yes

Clallam strongly supports the categorical exclusion of Local Distribution Networks from the BES. In fact, for
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to ensure
that the BES definition complies with the statutory requirement to exclude all facilities used in the local
distribution of electric power. LDNs are, of course, probably the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the level of
service to retail customers. Clallam also supports, with the reservations discussed below, the LDN exclusion
as drafted by the SDT. At least conceptually, we believe the SDT has identified the key characteristics that
separate LDNs from facilities that are part of the bulk transmission system and therefore should be classified
as BES. Hence, LDNs can be excluded from the BES based on the characteristics identified by the SDT
without compromising the reliability of the interconnected bulk transmission system.Although Clallam
supports the LDN exclusion, we believe the exclusion should be refined in the following respects: o The
SDT’s draft states that:”LDN’s are connected to the Bulk Electric System (BES) at more than one location
solelyto improve the level of service to retail customer Load.” (emphasis added)We are concerned that the
use of the term “solely” implies the need for an examination of the motives of a local distribution utility in
connecting to the BES at more than one location. This result is problematic because it defeats the purpose
of the exclusion, which is to allow LDNs to be excluded from the BES without an in-depth and expensive
inquiry into the exact nature of the LDN. In addition, the local utility may have a number of motives for
connecting to the BES at more than one location, but the local utility’s motives have nothing to do with how
the LDN interacts with the interconnected bulk system, which should be the key determinant in including or
excluding any Element from the BES. With these concerns in mind, we therefore recommend that the SDT
revise the sentence quoted above as follows: “LDN’s are connected to the Bulk Electric System (BES) at
more than one location solely to improve the level of service to retail customer Load and not to accommodate

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Yes or No

Question 9 Comment
bulk transfers of power across the interconnected bulk system.” By instituting this suggestion, the SDT would
emphasize the key difference between an LDN, which is designed to reliably serve local, end-use retail
customers, and the BES, which is designed to accommodate bulk transfer of power at wholesale over long
distances.
o We believe the characteristics specified by the LDN in subsections (b) and (c) of the exclusion are
redundant. Subsection b specifies that the LDN would not interconnect more than 75 MVA of generation in
aggregate. Subpart c specifies that power flows only into the LDN. We believe the SDT can eliminate
subpart b of the definition and simply rely on subpart c because if power only flows into the LDN even if it
interconnects more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system, only with the LDN. Further, with the
advent of distributed generation, it is easy to foresee a situation in which a large number of very small
distributed generators are interconnected into a LDN, so that the aggregate capacity of these generators
exceeds 75 MVA. However, because the generators are small and dispersed and, under the subpart c
criteria, would be wholly absorbed within the LDN rather than transmitting power onto the interconnected grid,
those generators would not have a material impact on the grid. In addition, the 75 MVA criterion would make
an LDN interconnecting more than 75 MVA part of the BES. For the reasons set forth by the Project 2010-07
SDT, we are concerned the result will be the local utility being improperly classified as a Transmission Owner
and Transmission Operator, which would subject the local utility to a number of reliability standards that
would significantly increase its compliance burden without substantially improving bulk system reliability. In
fact, in the LDN situation, there is even less reason to impose these burdens on the local utility than in the
situation addressed by the Project 2010-07 team, where generators are interconnected to the BES by
dedicated interconnection facilities. Because the LDN is interconnected at multiple points, the generators
interconnected to the LDN could continue to operate even if one or two interconnection points are out of
service. On the other hand, in the situation addressed by the Project 2010-07 team, if the dedicated
interconnection facility is out of service, the generation is unavailable because there is no alternative route to
deliver it to load.
Finally, for the reasons stated in our answers to Questions 3 and 4, we believe the SDT’s wholesale adoption
of the 20 MVA and 75 MVA thresholds from the NERC Statement of Compliance Registry lacks adequate
technical justification. The SDT repeats that error here by incorporating those thresholds into the LDN
exception.

Response: The SDT has made changes to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network; however,
the SDT believes that the descriptive language adds necessary context to the entire exclusion principle and therefore should be retained.
The SDT has determined that a generation limit is appropriate from a bright-line perspective to qualify these local networks as distribution; however, in the
revised Exclusion E3, the limits on connected generation have been made somewhat less restrictive as indicated in E3.a. Also, the revised Exclusion E3 now

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Yes or No

Question 9 Comment

specifically excludes from consideration the “behind the meter” generation in the limits on connected generation. Entities that own/operate facilities that are not
necessarily captured for exclusion by Exclusion E3 can still pursue exclusion through the RoP Exception Process.
The SDT notes that the responses to the comments in the first posting of the BES Definition did not yield any technically-based alternatives to the generation
thresholds of the ERO Statement of Compliance Registry Criteria (SCRC), and as such, the SDT has no technical rationale to deviate from the SCRC. After
consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation thresholds at
this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT efforts will
be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of Trustees and
the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards Authorization
Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
FortisBC

August 19, 2011

Yes

We agree with this concept as part of establishing a bright-line definition along with this clarifying exclusion in
the revised BES definition. However, requirements in Exclusion E3 are restrictive and we do not agree to the
limits on connected generation for Local Distribution Networks (LDN), described in part (b). The development
and implementation of distributed generation will grow considerably in the future and will operate together
with conventional sources of energy. The real net aggregated power of distributed generation seen by the
bulk power system at the interconnection may be larger than past experience; hence it requires to be
reassessed based on technical studies with respect to the future integration of DG’s. (Please refer to
comments in questions: 3 & 4)

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Question 9 Comment
Also, we suggest combining exception E3 (c) and (d) as follows:”(c) Power is intended to flows only into the
LDN: The generation within the LDN shall not exceed the electric Demand within the LDN; The LDN is
intended to deliver power to load and not be used to transfer bulk power between different locations in the
BES. It is recognized that under specified system conditions, bulk power transfers may take place between
different points of the BES via the LDN. However, for these conditions BES reliability is not dependent on the
existence of these power flows through the LDN.”Finally, we suggest and urge the SDT to carefully craft the
exception criteria & procedure that is flexible and technically sound to adequately allow entities to present
their case, and/or unique characteristics of the elements under exception to the ERO for exclusion

Response: The SDT has determined that a generation limit is essential to qualify these local networks as distribution; however, in the revised Exclusion E3, the
limits on connected generation have been made somewhat less restrictive as indicated in E3.a. Also, the revised Exclusion E3 now specifically excludes from
consideration the “behind the meter” generation in the limits on connected generation.
The revised Exclusion E3 now combines the prior items E3.c and E3.d into a revised item E3.b.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Sierra Pacific Power Co d/b/a NV
Energy

August 19, 2011

Yes

NV Energy strongly supports the definitional exclusion of LDN’s from the BES, and such exclusion is
necessary to ensure that the BES definition meets the statutory requirement to exclude all facilities used in
the local distribution of electric power.In the characteristics of the LDN, item (d) should be clarified to
eliminate the ambiguity that arises from the term “used”. We suggest the following revision:Not intentionally

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Organization

Yes or No

Question 9 Comment
used to transfer bulk power: The LDN is not used to provide a transaction scheduling path for, nor
intentionally used to accommodate the transfer of, energy originating outside the LDN for delivery through the
LDN;

Response: The SDT has incorporated this suggestion into the revised language of Exclusion E3.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Consumers Energy Company

Yes

LDN needs to be specifically defined. The draft appears to come close with the term “Groups of Elements
operated above 100kV that distribute power to Load rather than transfer bulk power across the
interconnected System.” These Groups of Elements should be contiguous to avoid confusion.
We are also concerned with the limits on connected generation.

Response: The SDT agrees with the suggestion regarding the contiguous nature of these local networks and has incorporated that suggestion into the revision
of Exclusion E3.
The SDT received many comments on the limits of connected generation, and it has made this provision somewhat less restrictive as shown in the revised item
E3.a.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher

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Yes or No

Question 9 Comment

are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Sacramento Municipal Utility
District (SMUD)

Yes

SMUD agrees with the concept for Exclusion 3. However, sub-bullet “C” should address potential for integral
values for variations of the load to the connected resource.

Response: The SDT has removed the concept of comparison of generation to electric demand, and instead has moved to a simpler limit on connected
generation.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a

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Yes or No

Question 9 Comment

major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Puget Sound Energy

Yes

As suggested in Q1. If a limit on total aggregate load served by LDN is included, that would improve the
clarity of this exclustion.

Response: To address similar concerns about the size of a local network, the SDT has now introduced a voltage cap for the LN exclusion of 300 kV.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Illinois Municipal Electric Agency

Yes

With the following clarfying edits. “Local Distribution Networks (LDN): Groups of Elements operated above
100 kV that are primarily intended to distribute power to Load rather than to transfer bulk power across the
Interconnected System.” The second sentence should be revised as follows: “LDN’s are connected to the
Bulk Electric System (BES) from more than one Transmission source solely to improve the level of service to
retail customer Load.”

Response: The SDT has made changes to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to

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Yes or No

Question 9 Comment

accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Clark Public Utilities

Yes

Clark strongly supports the categorical exclusion of Local Distribution Networks from the BES. Clark also
believes that adopting a 200 kV bright-line threshold will result in most, if not all, LDN being exempted from
the BES without any need to analyze or self-certify an LDN. This is another case where a higher threshold
(with an appropriate inclusion process) will have no affect on BES reliability but will focus resources on
investigation low voltage facilities that truly have an impact on interconnected system operations. Clark does
recommend a revision to the LDN exclusion language. E3 - Local distribution networks (LDNs): Groups of
Elements operated above 100 kV that distribute power to Load rather than transfer bulk power across the
interconnected System. LDN’s are connected to the Bulk Electric System (BES) at more than one location
solely to improve the level of service to retail customer Load and not to accommodate bulk transfers of power
across the interconnected bulk system. The LDN is characterized by all of the following:

Response: The SDT has not uncovered nor been presented with any technical rationale for deviating from the voltage threshold of 100 kV in the definition of
BES; however, the SDT believes that the revised definition speaks to, and sufficiently identifies, the exclusion of the facilities used for distribution functions.
The SDT has made changes to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;

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Yes or No

Question 9 Comment

a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
City of Anaheim

Yes

In E3 (b) use the same language as in E1 (b), i.e. Only including generation resources not identified in
Inclusions I2, I3, I4, and I5. This avoids re-defining all of the generator provisions here. At a minimum
"operated at a voltage of 100 kV or above" should be added at the end of E3 (b).

Response: The SDT has made modifications to the new item E3a, which addresses this concern.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

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Organization
AltaLink

Yes or No

Question 9 Comment

Yes

We agree with this concept as part of establishing a bright-line definition along with this clarifying exclusion in
the revised BES definition. However, requirements in Exclusion E3 are restrictive and we do not agree to the
limits on connected generation for Local Distribution Networks (LDN), described in part (b). The development
and implementation of distributed generation will grow considerably in the future and will operate together
with conventional sources of energy. The real net aggregated power of distributed generation seen by the
bulk power system at the interconnection may be larger than past experience; hence it requires to be
reassessed based on technical studies with respect to the future integration of DG’s. We suggest and urge
the SDT to carefully craft the exception criteria & procedure that is flexible and technically sound to
adequately allow entities to present their case, and/or unique characteristics of the elements under exception
to the ERO for exclusion.

Response: The SDT has determined that a generation limit is appropriate from a bright-line perspective to qualify these local networks as distribution; however,
in the revised Exclusion E3, the limits on connected generation have been made somewhat less restrictive as indicated in E3.a. Also, the revised Exclusion E3
now specifically excludes from consideration the “behind the meter” generation in the limits on connected generation. Entities that own/operate facilities that are
not necessarily captured for exclusion by Exclusion E3 can still pursue exclusion through the RoP Exception Process.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Modern Electric Water Company

August 19, 2011

Yes

Similar to our Question #7 comments regarding radial exclusions in E1, a usable BES definition excluding
local distribution networks (LDNs) is needed to allow this industry to focus on and conduct business in a

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Question 9 Comment
fashion that promotes reliable and efficient system operation. In line with a 1/18/2011 Executive Order
directing federal regulatory agencies to base their practices on science and to consider costs, excluding
LDNs from the BES definition would achieve that aim on a national scale. While differing only in connectivity,
LDNs operate and function exactly as radial systems. We suggest modifying the second and third sentences
of E3 as “LDNs are normally operated such that they are connected to the BES through more than one AFID
simultaneously, and exist to promote the level of service to Loads as commonly defined by states’ utility
commissions. For a System to be characterized as an LDN, it must meet all of the following:”Sub-bullet E3-c
should be clarified to indicate conditions, timeframes and metrics used to demonstrate power flow
direction.We support the intent of the remaining sub-bullets.

Response: The SDT has made changes to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network.
The SDT has revised the Exclusion E3 local network in a way that removes the mention of automatic fault interrupting devices.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Michgan Public Power Agency

Yes

I question the technical justification for the 75 MVA and the 100 KV as pointed out in my comments above.
But given those points addressed above I would suggest the following clarification be considered.
The exclusion refers to groups of Elements that “distribute power to Load rather than transfer bulk power
across the interconnected system.” The use of the term “bulk power” is vague and could be read incorrectly
as a reference to the “bulk-power system,” which is defined in the Federal Power Act but is not a NERC

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Yes or No

Question 9 Comment
defined term.
If the LDN is connected to the BES at more than one location, there will by definition be some loop flow. We
recommend below that Exclusion 3(d) be revised to quantify the amount of loop flow that is permissible in an
excluded LDN.
In the context of the first sentence of Exclusion E3, less specificity is needed, and the sentence should only
be revised for the sake of accuracy to state: “Groups of Elements operated above 100 kV that are primarily
intended to distribute power to load rather than to transfer power across the interconnected System.”
The exclusion’s reference to connection “at more than one location” is vague. The sentence should be
revised to read “connected to the Bulk Electric System (BES) from more than one Transmission source solely
to improve the level of service to retail customer Load,” and “Transmission source” should have the same
meaning that it does in E1.
E3(a) should require that there be switching devices between the LDN and the BES, not specifically
automatic fault-interrupting devices. The term “separable by” in “Separable by automatic fault interrupting
devices” is unclear and should be reworded.
E3(b) To avoid pulling an LDN into the BES based on very small customer-owned generation (such as
rooftop photovoltaics and hospital backup diesel generators) that the utility does not consider or rely on, or
necessarily even know about, the item should be reworded: “Limits on connected generation: Neither the
LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA of generation used to meet the
resource -adequacy requirements of electric utilities.”
E3(d) states “Not used to transfer bulk power.” As noted above, “bulk power” is a vague term. There will
necessarily be some loop flow on a system that is connected to the BES at more than one location. The
amount of permissible loop flow for this purpose needs to be determined and stated in this item.

Response: The SDT has not uncovered nor been presented with any technical rationale for deviating from the voltage threshold of 100 kV or 75 MVA in the
definition of BES; however, the SDT believes that the revised definition speaks to, and sufficiently identifies, the exclusion of the facilities used for distribution
functions. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary
focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the
NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a
new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
The SDT has modified the definition such that the term “bulk power” is no longer used in the characteristics, specifically new item E3.b. The term “bulk power”
was retained in the paragraph E3, as the SDT believes it provides conceptual value to the exclusion principle.

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Yes or No

Question 9 Comment

The SDT has revised the Exclusion E3 Local Network in a way that removes the mention of automatic fault interrupting devices.
The SDT has made changes to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network.
After consideration of the establishment of limits on flow-through, the SDT has elected to make modifications to the local network characteristics to preclude the
scheduled use of the network for flow-through rather than establishing a MW limit or transfer distribution factor. The SDT has determined that this is appropriate
from a bright-line perspective to qualify these local networks as distribution; Entities that own/operate facilities that are not necessarily captured for exclusion by
Exclusion E3 can still pursue exclusion through the RoP Exception Process.
The revised Exclusion E3 now specifically excludes from consideration the “behind the meter” generation in the limits on connected generation.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Utility System Efficiencies, Inc.

Yes

USE agrees in concept with this Exclusion. However, in sub-bullet b), as noted in our response to Question 4,
there is no technical justification for the 75 MVA threshold on connected generation.
In sub-bullet c), it should be clarified whether this requirement is at any time or is for hourly integrated values.
Also in sub-bullet e), the use of the term “major transfer paths” should be modified to be “major transfer paths
in the Table titled Major WECC Transfer Paths in the Bulk Electric System.” Finally, the reference to “above
100 kV” should be “at or above 100 kV” for consistency with the rest of the definition.

Response: See response to Q4.

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Question 9 Comment

The SDT has determined that a generation limit is appropriate from a bright-line perspective to qualify these local networks as distribution; however, in the
revised Exclusion E3, the limits on connected generation have been made somewhat less restrictive as indicated in E3.a. Also, the revised Exclusion E3 now
specifically excludes from consideration the “behind the meter” generation in the limits on connected generation. Entities that own/operate facilities that are not
necessarily captured for exclusion by Exclusion E3 can still pursue exclusion through the RoP Exception Process.
The revised version of the Exclusion E3 language removes the comparison of connected generation to network demand.
The new item E3.c clarifies the language regarding WECC major paths.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Cowlitz County PUD

August 19, 2011

Yes

Cowlitz strongly supports the categorical exclusion of Local Distribution Networks from the BES. In fact, for
reasons discussed at length in our answer to Question 1, we believe the exclusion is necessary to ensure
that the BES definition complies with the statutory requirement to exclude all facilities used in the local
distribution of electric power. LDNs are, of course, probably the most common kind of local distribution
facility. Further, the conversion of radial systems to local distribution networks should be encouraged
because networked systems generally reduce losses, increase system efficiency, and increase the level of
service to retail customers. Cowlitz supports the LDN exclusion, but we believe the exclusion should be
refined in the following respects: o The SDT’s draft states that:”LDN’s are connected to the Bulk Electric
System (BES) at more than one location solely to improve the level of service to retail customer Load.”
(emphasis added) We recommend that the SDT revise the sentence quoted above as follows: “LDN’s are
connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service

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Question 9 Comment
to retail customer Load and not to accommodate bulk transfers of power across the interconnected bulk
system.” By instituting this suggestion, the SDT would emphasize the key difference between an LDN, which
is designed to reliably serve local, end-use retail customers, and the BES, which is designed to
accommodate bulk transfer of power at wholesale over long distances. We propose that a reliable BES will
help insure a reliable LDN. If the LDN is not reliable, it should then be an issue to be resolved by the local
authorities. If the BES is not reliable, the local authorities lack the tools to remedy the situation.

Response: The introductory paragraph in Exclusion E3 has been revised to eliminate the term “solely” and to explain that the local network does not
accommodate bulk transfer across the interconnected system.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3, and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;
b) Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The LN
does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
New England States Committee
on Electricity

Yes

NESCOE believes that this language appropriately excludes facilities that serve local distribution loads from
the BES.

Public Utilities Commission of
Ohio

Yes

Exclusion 3 is appropriate. This reflects the reality that local distribution can be at any level. As a reminder
the Commission proposed seven indicators of local distribution to be evaluated on a case-by-case basis:(1)
Local distribution facilities are normally in close proximity to retail customers.(2) Local distribution facilities are
primarily radial in character.(3) Power flows into local distribution systems; it rarely, if ever, flows out.(4)
When power enters a local distribution system, it is not reconsigned or transported on to some other
market.(5) Power entering a local distribution system is consumed in a comparatively restricted geographical

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Question 9 Comment
area.(6) Meters are based at the transmission/local distribution interface to measure flows into the local
distribution system.(7) Local distribution systems will be of reduced voltage.This test clearly indicates that not
all radial circuit lines are the same. This exclusion would not only appropriately apply the seven factor test,
but also comply with the Federal Power Act regarding appropriate authority.

New York State Dept of Public
Service

Yes

This exclusion properly recognizes that local distribution facilities can be at any voltage level. It also properly
recognizes that reliable service to load often requires parallel circuits. As written, the exclusion respects
FERC’s concern that major generation facilities should not be part of the LDN, by limiting the exclusion to
generation of75 MVA or less, and to only facilities that move energy down to the LDN.

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

Yes

No comment.

Oregon Public Utility Commission
Staff

Yes

Exclusion E3 is absolutely necessary for excluding local distribution elements from the interconnected bulk
transmission system as required by Section 215 of the FPA of 2005. This exclusion mirrors the Seven Factor
Test (established in FERC Order 888), which sets sound overarching principles for differentiating local
distribution elements from bulk transmission elements. Also, the conversion of radial systems to local
distribution networks is generally implemented by a distribution provider to improve the level of service to
local retail customers, not to accommodate bulk transfer of wholesale power.Retaining Exclusion E3 is
absolutely crucial for maintaining the 100 kV brightline in the core BES definition. Without the distribution
network E3 exclusion, the voltage threshold in the core BES definition would need to be changed to the 200
kV level. Otherwise, NERC and Regional Entities will have to deal with endless exception applications and
evaluations associated with the removal of local distribution elements that have no impact on the reliable
operation of the interconnected bulk transmission system.

National Association of
Regulatory Utility Commissioners

Yes

Exclusion 3 is essential for the standard to conform to Federal Power Act Section 215 that clearly excludes
local distribution from FERC and NERC jurisdiction. The exclusion properly recognizes that local distribution
can operate at above 100 kV. This exclusion seems to reflect the essence of the Seven Factor test from
FERC’s Order 888. Although FERC Order 743A did not bind NERC to the Seven Factor test, it makes sense
to pursue consistency between these tests.

Michigan Public Service
Commission(MPSC)

Yes

MPSC Staff Comments: The MPSC strongly supports this exclusion because it should exclude a large
number of subtransmission facilities that are used for the distribution of local load. Also, this exclusion

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Question 9 Comment
together with E1 parallels the seven-factor technical-functional test for classifying transmission and
distribution. The problem with the seven-factor test is that it does not provide an on-going clear bright line for
BES determination. For example, an engineer cannot apply the seven-factor test using a one-line diagram of
an electric power network and determine - without supplemental evidence - that an element is classified as
distribution or not.

FHEC

Yes

Public Service Enterprise Group
LLC

Yes

Imperial Irrigation District

Yes

Santee Cooper

Yes

ACES Power Participating
Members

Yes

National Rural Electric
Cooperative Association
(NRECA)

Yes

Arizona Public Service Company

Yes

Rayburn Country Electric
Cooperative, Inc.

Yes

New York Power Authority

Yes

Southern Company

Yes

Luminant Energy

Yes

Western Area Power
Administration

Yes

August 19, 2011

We support the current wording of E3.

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US Bureau of Reclamation

Yes

Grand Haven Board of Light and
Power

Yes

Glacier Electric Cooperative

Yes

South Texas Electric
Cooperative, Inc.

Yes

South Texas Electric
Cooperative, Inc.

Yes

Sweeny Cogeneration LP

Yes

Dayton Power and Light
Company

Yes

Duke Energy

Yes

Alberta Electric System Operator

Yes

Fayetteville Public Works
Commission

Yes

MidAmerican Energy Company

Yes

American Electric Power

Yes

East Kentucky Power
Cooperative, Inc.

Yes

American Transmission
Company, LLC

Yes

August 19, 2011

Question 9 Comment

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Farmington Electric Utility System

Yes

GTC

Yes

Idaho Power

Yes

Pepco Holdings Inc

Yes

PJM

Yes

Oncor Electric Delivery Company
LLC

Yes

MEAG Power

Yes

Xcel Energy

Yes

Orange and Rockland Utilities,
Inc.

Yes

Golden Spread Electric
Cooperative, Inc.

Yes

Question 9 Comment

Response: Thank you for your support. Based on stakeholder comments, the SDT modified the local network exclusion in the following manner:
Elimination of the term “Distribution” in the label of this exclusion, making it a “local network”.
Changes were made to the introductory paragraph in Exclusion E3, which the SDT believes clarifies the intent of the local network, including a statement that the
local network does not accommodate bulk transfer across the interconnected system.
Eliminated the provision in Exclusion E3.a which referred to automatic fault interrupting devices, and changed wording to clarify the connection point of the local
network.
Please see the revised definition.

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10.The SDT is discussing an exclusion from the Bulk Electric System (BES) for small utilities based on
statements in Order No. 743 that FERC does not believe its suggested approach to the BES definition and
exemption process will have a significant economic impact on a substantial number of small entities and
that small entities will not adversely impact the reliability of the Bulk Electric System. The SDT has been
made aware that organizations that are not presently required to be registered by the NERC Statement of
Compliance Registry Criteria would meet the requirements to be registered as Transmission Owners given
the current proposed BES definition. These small utilities could use the Rules of Procedure (ROP) exception
process but this may be an issue that could be handled more appropriately through the BES definition. This
would alleviate the paperwork burden for these small utilities and also avoid a possibly unnecessary and
significant impact on the administration of the ROP exception process during the transition period to the
revised BES definition. The proposed exclusion language is:
Exclusion E4: Transmission Elements, from a single Transmission source connected at a voltage of 100 kV or
greater, owned by a small utility whose connection to the BES is solely through this single Transmission
source, and without interconnected generation as recognized in the BES Designation Inclusion Items I2, I3,
I4, or I5. A small utility is recognized as an entity that performs a Distribution Provider or Load Serving
Entity function but is not required to register as a Distribution Provider or Load Serving Entity by the ERO.
Do you agree with this approach and the proposed language? If not, please be specific in your response
with a technical reason for your disagreement and, if appropriate, suggested language for such an exclusion
if you agree in general but feel that alternative language would be more appropriate.

Summary Consideration: The basis for the additional exclusion was predicated by the circumstances of radial systems and
the demarcation of the automatic interrupting device. With the change of the demarcation point back to the point where the
tap line intersects with the transmission line; this proposed exclusion is unnecessary. The SDT will drop consideration for this
proposed exclusion given the change to radial systems. This shall serve as a single response to all comments submitted in
response to this question.

Organization
Northeast Power Coordinating
Council
Hydro One Networks Inc

August 19, 2011

Yes or No

Question 10 Comment

No

Small utility or distribution provider is a relative term. A distribution provider may have an impact on the
transmission network based on its design, configuration, connection point, and protection. Such an exception
should apply regardless of the size of an entity. The concept discussed here is to define a radial system and
not a small utility, as mentioned in the FERC Order. We do not believe that the SDT had sufficient discussions
while crafting the proposed exclusion in regards to small utilities. The language used in the proposed clause

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Question 10 Comment
is only appropriate to establish a bright-line definition for a radial system.Many small utilities (and individual
load customers or generation connections) have more than a single transmission source with a solid tap and,
at the same time, be adequately protected and effectively isolated without any adverse impact on the
transmission network. Such a practice and design is widely used across North America. Hence, we do not
agree that this exclusion is an attempt to address the issue of small utilities. The definition and inclusions will
force many small entities, load customers and generation unit owners to act and register as Transmission
Owners. This may be in conflict with state or provincial regulatory act, Codes and Licenses. Consistent with
the FERC Order, the ERO and the SDT should be aware of these conflicts and should not ignore them. The
ERO and the SDT address this by providing explicit but simple provisions in the exception procedure by
considering sound technical exception criteria that is flexible based on demonstration of evidence to justify the
element’s necessity for operation. Regulatory Acts and Rules will always overrule NERC requirements and
the only evidence that should be required of small utilities/entities is: o Regulatory evidence o Evidence
demonstrating that NO adverse reliability impact is afflicted on the interconnected BES because of their
connection.

Tri-State Generation and
Transmission Association, Inc.

No

We disagree with adding E4. This issue should be resolved by enhancing the NERC Statement of
Compliance Registry Criteria, not by integrating registration exemptions in NERC definitions.

NERC Staff Technical Review

No

The basis for exclusion must be based on system reliability. The need for an interrupting device between the
BES and excluded radial Elements is necessary for system reliability independent of ownership of the
excluded radial Elements.

Dominion

No

It is Dominion’s position that, all things being equal a generator or a load have similar, but typically inverse
impacts of the bulk power system. The burden for small entities is similar, whether that entity is a LSE, DP,
GO or GOP.

SPP Standards Review Group

No

What’s the difference between the proposed E4 and E1(a)? Wouldn’t they be the same?
Would it be more appropriate to use single point of Transmission interconnection rather than single
Transmission source in E1 and E4?

SERC Planning Standards
Subcommittee

No

This seems to be covered by E1.

South Carolina Electric and Gas

No

This seems to be covered by E1.

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Question 10 Comment

Michigan Public Service
Commission(MPSC)

No

MPSC Staff Comments: The BES definition proposed by the SDT should not use the term “transmission”.
BES should not equal transmission. A system element defined as BES should not determine jurisdiction,
ownership, or require duplicative NERC registration.

SERC OC Standards Review
Group

No

We suggest that our comments to Question 3 and Question 4 be incorporated.

Idaho Falls Power

No

Just as 100kv is an arbitrary number, so is 20MVA. We appreciate the NERC efforts made to define
transmission material to the BES, and likewise feel the same efforts should be applied to small generation
resources. There exists a large number of utilities with small generation serving local load on an LDN that will
be possibly drawn into TO/TOP standard's compliance by the language in this draft.We hope the drafting
team will define BES generation beyond a brightline criteria, as 20MVA lends no more clarity as to what is a
BES asset than does 100kV.We believe it should be demonstrated as to why 20MVA is deemed a generation
threshold of materiality to the BES. The opportunity now exists to address thresholds, not just the 100kV.

Western Electricity Coordinating
Council

No

As written, it is unclear how this exclusion differs from the Radial exclusion.

We also question whether this is going to have an unintended consequence of requiring Distribution Providers
to register that otherwise wouldn’t have to register because some technical aspect has not been included in
this exception.

The term “single Transmission source” needs to be clarified - it could be read to be a single line or a single
entity, which would change the meaning of this exclusion.
It is also improper to include registration criteria in a definition.
Furthermore, “small utility” needs to be defined more clearly. The last sentence appears circular because
ownership of a transmission element would draw the owner into registration.

ReliabilityFirst

No

it needs to be clear that "all" items must be met to be excluded in E4,
E4b seems to conflict with I2 that states it needs included,
E4a should state a single source unless LDNs are allowed mutilple sources and then could be considered
networked, E4c needs to define who make a the determination on flow and under all system configurations

Southern Company

No

This seems to be covered by Exclusions E1 and E3.

Electricity Consumers Resource

No

We support the concept and intent of the exclusion but it should apply equally to similarly situated loads such
as manufacturing facilities that have loads comparable to small municipalities or rural cooperative utilities.

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Council (ELCON)

Central Maine Power Company

Question 10 Comment
Thus the language should be amended as noted below:"Exclusion E4: Transmission Elements, from a single
Transmission source connected at a voltage of 100 kV or greater, owned by a small utility or similarly situated
load whose connection to the BES is solely through this single Transmission source, and without
interconnected generation as recognized in the BES Designation Inclusion Items I2, I3, I4, or I5. A small
utility or similarly situated load is recognized as an entity that performs a Distribution Provider or Load Serving
Entity function but is not required to register as a Distribution Provider or Load Serving Entity by the ERO."

No

This exclusion E4 seems to already be covered under the E1 “radial” exclusion.

Intellibind

No

This does not address the full concerns of these small entities. In on case I am familiar with the entity has a
switchyard over 100KV and it was convenient for the interconnected utility to utilize the location of the
switchyard to add a line for the Transmission Operators purpose, however now that there are two lines into
the switchyard it has affected the small utility and they will not have exemption as described in Question 10.
The financial burden is very high for these entities when not exempted. In this particular case noted above,
the entity is planning to eventually decommission its system, but is caught in having to bear the cost of
operating a transmission system even though it is only one substation that is immediatly stepped down to
13.8Kv and feeding a small distributed load. The proposed exemption will still not allow this entity to be
exempt.The ROP process does not serve these small utilities well as an alternative and the Drafting Team
should resolve these issues in the definition of the BES if possible.

Hydro-Quebec TransEnergie

No

The case of small Utility is covered through other exclusions. However, the Facilities owned by small utility
should have protection requirement applied.

US Bureau of Reclamation

No

The small entities can seek exclusion using the BES Exception Process developed under this project.

Grand Haven Board of Light and
Power

No

We agree with addition of Exclusion E4, except that it should apply to small load serving distribution utilities
even if they are required to register as a Distribution Provider and Load Serving Entity. In our last fiscal year,
July 2009 through June 2010, the Grand Haven Board of Light and Power served 262,847 MWh and peaked
at 54 MW. Even though we are required to register as DP/LSE, we are still a small utility. Please revise the
definition of a small entity for the purpose of this exception to use more reasonable criteria.

South Texas Electric
Cooperative, Inc.

No

I agree with everything up to “...but is not required to register...by the ERO”. There are many small utilities
that fit into the scope and spirit of the exclusion BUT were required to register as DP and/or LSE by their
ERO. This has generally been on the interpretation of “better safe”. Please remove the language which gives

New York State Electric & Gas
and Rochester Gas & Electric

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Question 10 Comment
this discretion to the ERO and insert language allowing already registered small utilities with have their
registrations revoked or surrendered.

National Grid

No

This exclusion is not necessary. Many small utilities (and individual load customers or generation
connections) have more than a single transmission source with a solid tap and, at the same time, be
adequately protected and effectively isolated without any adverse impact on the transmission network. Such a
practice and design is widely used across North America. Hence, we do not agree that this exclusion is an
attempt to address the issue of small utilities. The definition and inclusions will force many small entities, load
customers and generation unit owners to act and register as Transmission Owners. This may be in conflict
with state or provincial regulatory act, Codes and Licenses, and may lead to jurisdictional challenges that
could cause uncertainty and delay in implementing the new BES definition. Consistent with the FERC Order,
the ERO and the SDT should be aware of these conflicts and should not ignore themThe ERO and the SDT
address this by providing explicit but simple provisions in the exception procedure by considering sound
technical exception criteria that is flexible based on demonstration of evidence to justify the element’s
necessity for operation. The only evidence that should be required of small utilities/entities is: o Regulatory
evidence. o Evidence demonstrating that NO adverse reliability impact is afflicted on the interconnected BES
because of their connection.

Electric Reliability Council of
Texas, Inc.

No

These entities should be subject to the exception process. They may warrant “first instance” exclusion in that
process, but any such action should occur there, as opposed to the definition of BES. ERCOT ISO believes
this is more consistent with FERC’s position that BES should reflect an objective threshold, with exceptions
being subject to review by the ERO and FERC, as applicable. Accordingly, ERCOT ISO suggests that this
issue be raised in the concurrent BES exception proceeding and ERCOT ISO reserves its right to comment
on the substance in that proceeding.

ExxonMobil Research and
Engineering

No

While the exclusion for a small utility makes sense, the exclusion should not be limited to a utility company.
The SDT should extended the exclusion to similarly situated facilities or organizations with other primary
business functions, such as industrial companies.

FortisBC

No

Small utility or distribution provider is a relative term. A smaller distribution provider may have an impact on
the transmission network while a large one may not; this is based on their design, configuration and
protection. Hence, such an exception should apply regardless of the size of an entity. Having said that, the
concept discussed here is to define a radial system and not a small utility, as mentioned in the FERC Order.
We do not believe that the SDT had sufficient discussions while crafting the proposed exclusion in regards to
small utilities. The language used in the proposed clause is only appropriate to establish a bright-line
definition for a radial system.It is worth noting that many small utilities (and individual load customers or
generation connections) would have more than a single transmission source with a solid tap and, at the same

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Question 10 Comment
time, be adequately protected and effectively isolated without any adverse impact on the transmission
network. Such a practice and design is widely used across North America. Hence, we do not agree that this
exclusion is an attempt to address the issue of small utilities. The definition and inclusions will force many
small entities, load customers and generation unit owners to act and register as Transmission Owners. In
some parts of the continent this would be in conflict with state or provincial regulatory act, Codes and
Licenses. Consistent with the FERC Order, the ERO and the SDT should be aware of these conflicts and
should not ignore them for later. Hence, we suggest the ERO and the SDT address this by providing explicit
but simple provisions in the exception procedure by considering sound technical exception criteria that is
flexible based on demonstration of evidence to justify the element’s necessity for operation. Regulatory Acts
and Rules will always trump NERC requirements and hence we suggest that the only evidence that should be
required of small utilities/entities is:
o Regulatory evidence
o Evidence demonstrating that NO adverse
reliability impact is afflicted on the interconnected BES because of their connection.

American Transmission
Company, LLC

No

ATC believes that small utilities have interfacing responsibilities, and should not be exempt if they own
elements (e.g. CTs, batteries, etc.) that are part of a protection scheme that protects the BES Elements.

Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

No

There is no legal basis to distinguish between “small utilities” and other similarly situated entities. Thus, to
avoid unlawful discrimination, Exclusion E4 should be revised as follows:(Deleted language denoted by empty
brackets: [ ].) Exclusion E4: Transmission Elements, from a single Transmission source connected at a
voltage of 100 kV or greater [ ] whose connection to the BES is solely through this single Transmission
source, and without interconnected generation as recognized in the BES Designation Inclusion Items I2, I3,
I4, or I5. [ ]

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

No

An automatic interruption device should be required as in exclusion E1.

City of St. George

No

Is the transmission source a single line, a single substation? This needs to be defined.
What is a small utility? This needs to be defined.
Generation limits should also be revisited, see previous comments.

Southern California Edison
Company

August 19, 2011

No

Small utilities should not be automatically excluded from the BES if the BES Definition continues to focus on
the size of interconnecting generators to determine what facilities are included in the BES. Instead, small

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Question 10 Comment
utilities should be required to justify their exclusion using the exemption procedure and the Technical
Principles for Demonstrating BES Exceptions. This would provide the necessary oversight to ensure these
smaller systems continued to stay under the thresholds stipulated in the BES definition. In many areas, it is
both faster and less expensive for renewable generators to interconnect with these systems, thus potentially
allowing for the addition of large amounts of generation totaling more than the draft BES allowances within a
relatively short period of time.

Idaho Power

No

As written, it is unclear how this exclusion differs from the Radial exclusion. The term “single Transmission
source” needs to be clarified - it could be read to be a single line or a single entity, which would change the
meaning of this exclusion. It is also improper to include registration criteria in a definition. Furthermore, “small
utility” needs to be defined more clearly. The last sentence appears circular because ownership of a
transmission element would draw the owner into registration.

Cogentrix Energy, LLC

No

We suggest that our comments to Question 3 and Question 4 be incorporated.
We also question whether this is going to have an unintended consequence of requiring Distribution Providers
to register that otherwise wouldn’t have to register because some technical aspect has not been included in
this exception.

Clark Public Utilities

No

This proposed exclusion has no affect or benefit. If an entity is not required to register as a DP or LSE why do
they then need to be exempted from a standard that does not apply to the entity. The Commission was
obviously focusing on a small utility with facilities greater that 100 kV making that entity a Transmission
Owner. A 100 kV facility owned by a utility with a small amount of load is either material or immaterial to the
reliability of the BES irrespective of the amount of load that entity serves. Therefore the term ‘small utility”
must refer to some other measure of size. This may be size of load, but also may include circuit miles of
transmission greater than 100 kV, capacity of largest line greater than 100 kV line, and possible other
measures of “smallness.”

The Dow Chemical Company

No

If this is adopted, it should apply to industrial sites as well as small utilities.

PJM

No

There is no technical justification to include/exclude elements based on the asset size of the owning
company. The exclusion should be based on the technical merits.

New England States Committee
on Electricity

No

This appears overly restrictive in that it only includes networks connected at a single source. Please see
comments under 7 above.

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Question 10 Comment

Southwest Power Pool

No

These entities should be subject to the exception process within the exclusion criteria. They warrant a “first
instance” exclusion in that process, but any such action should occur there, as opposed to the definition of
BES. SPP believes this is more consistent with FERC’s position that BES should reflect an objective
threshold, with exceptions being subject to review by the ERO and FERC, as applicable. It may prove
through that process that these entities receive the presumption of exclusion, but that should take part in that
process as opposed to being granted a de jure exemption from the definition. Accordingly, SPP suggests that
this issue be raised in the concurrent BES exception proceeding as an exclusion criterion, and SPP reserves
its right to comment on the substance in that proceeding.

Manitoba Hydro

No

Small utilities should be excluded under the definition of the BES without requiring an additional and specific
exclusion.

ISO New England, Inc.

No

This exclusion would not be required if the automatic disconnect requirement was removed from E1. If E1 is
not modified as proposed herein then a MW threshold might have to be considered for this E4 definition.
E4 should have also been included in the draft definition as well as this comment form.

Xcel Energy

No

There seems to be an implication that if a facility is determined to be BES, registration is required. Yet, the
registration criteria already includes exclusion of users, owners and operators of the BES from registration, if
they do not meet all the criteria. So, we fail to see why a special exclusion is necessary.

Independent Electricity System
Operator

No

Small utilities may be impactive to the bulk power system and as such should not be subject to a carteblanche exemption but should be subject to assessment and if necessary exclusions after going through the
exception process. The outcome of the exception process may well be that such small utilities can be
excluded but this cannot be determined a priori.
In addition, Exclusion E4 is worded very similarly to Exclusion E1. It is not clear what additional facilities will
be excluded by E4 that are not already excluded by E1.

Golden Spread Electric
Cooperative, Inc.

No

Suggested revision: Transmission Elements, from a single Transmission source connected at a voltage of
100 kV or greater, owned by a small utility whose connection(s) to the BES is(are) solely through this(these)
single Transmission source(s), and without interconnected generation as recognized in the BES Designation
Inclusion Items I2, I3, I4, or I5. The intent of the revision is to exlude a small utility with multiple radial
connections to BES elements owned by others.

AltaLink

No

Small utility or distribution provider is a relative term. A smaller distribution provider may have an impact on
the transmission network while a large one may not; this is based on their design, configuration and

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Question 10 Comment
protection. Hence, such an exception should apply regardless of the size of an entity. Having said that, the
concept discussed here is to define a radial system and not a small utility, as mentioned in the FERC Order.
We do not believe that the SDT had sufficient discussions while crafting the proposed exclusion in regards to
small utilities. The language used in the proposed clause is only appropriate to establish a bright-line
definition for a radial system.It is worth noting that many small utilities (and individual load customers or
generation connections) would have more than a single transmission source with a solid tap and, at the same
time, be adequately protected and effectively isolated without any adverse impact on the transmission
network. Such a practice and design is widely used across North America. Hence, we do not agree that this
exclusion is an attempt to address the issue of small utilities. The definition and inclusions will force many
small entities, load customers and generation unit owners to act and register as Transmission Owners. In
some parts of the continent this would be in conflict with state or provincial regulatory act, Codes and
Licenses. Consistent with the FERC Order, the ERO and the SDT should be aware of these conflicts and
should not ignore them for later. Hence, we suggest the ERO and the SDT address this by providing explicit
but simple provisions in the exception procedure by considering sound technical exception criteria that is
flexible based on demonstration of evidence to justify the element’s necessity for operation. Regulatory Acts
and Rules will always trump NERC requirements and hence we suggest that the only evidence that should be
required of small utilities/entities is: o Regulatory evidence o Evidence demonstrating that NO adverse
reliability impact is afflicted on the interconnected BES because of their connection.

Modern Electric Water Company

No

The BES definition has already had a significant economic (and operational) impact on a substantial number
of small entities and those small entities have not adversely impacted the reliability of the BES. The
Commission (and the SDT) should also consider the other side of the coin - an improved BES definition could
have a positive impact on a significantly greater number of small entities than it will negatively impact small
entities otherwise not currently registered. Crafting exclusions properly with industry suggestions should limit
the small number affected by this proposed definition.
Additionally, we point out that in one instance the SDT states that the BES definition does not address
registration or the applicability of standards, yet in another instance is concerned what impact the definition
will have on an entity’s possible registration status. We don’t believe you can have it both ways or continue to
keep one’s proverbial head in the sand any longer.
We understand the SDTs scope is to provide a USABLE definition of the BES, but also understand that its
intent is two-fold: 1) to correct what the Commission believes is a gap in reliability due to regional discretion,
and 2) to remove ambiguity in what constitutes the BES so that industry can focus on and conduct business in
a fashion that promotes reliable and efficient system operation and so that the RROs can implement their
CMEPs. This second point is absolutely related to registration and the applicability of standards, and shouldn’t
be ignored.

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Organization

Yes or No

Question 10 Comment
As drafted, Exclusion E4 still would not allow for the exclusion of ALL small utilities that may inadvertently be
included in the BES based on the currently-drafted definition, even though they are, indeed, small utilities that
should be excluded from the BES. It appears that the SDT is struggling with the idea that the BES definition
should properly evaluate every single element in North America by itself. We believe this is why the term
“generally” was used in NERC’s Statement of Compliance Registry Criteria (SCRC), and why the issue of the
BES definition presently in front of the SDT cannot be entirely separated from registration and applicability of
standards.
If the SCRC will not be examined and modified similarly as the NERCs Rules of Procedure, then the BES
definition must include some “grey area deference” for small utilities such as is the intent of E4. If it is the
intent of the definition to exclude most small utilities from the BES, then exclusions should be granted based
entirely on the definition. Otherwise, as the SDT correctly states, the RoP-based exclusion process will be
flooded and ineffectual. As stated in the SCRC, the definition will initially identify those necessary, but still
allows for refinements later. The SCRC utilizes NERC’s approved definition of the BES, and will be
“improved” by this BES definition. Therefore, craft E4 with language that does not limit its intent to exclude
small utilities from the BES. Do not use metrics already used in other exclusions. Do not reference registration
requirements in exclusions that comprise the definition of the BES - the BES should not be defined in terms of
registration criteria. In Order 743, FERC defines a small utility in terms of an entity’s annual MWhs sold.
Consider aligning NERC’s and FERC’s definitions similarly.

City of Redding

No

Redding in theory supports this concept however the language proposed does little to improve the current
LDN and Radial exemptions. Redding would like the SDT to continue exploring the issue however we have no
suggestions for the definition level at this time. Redding does suggest that a viable alternative is to target this
issue via the exception process by allowing a exception method to use system or entity “characteristics” as
proof for an exception. This would allow a shorter and less burdensome exception process for small entities.

Tacoma Power

Tacoma Power supports the SDT’s thoughtful approach to minimizing impacts to small entities. They have no
measureable impact to the BES and should not be burdened with the exemption process.

Vermont Transco

The exclusion wording is difficult to understand and apply. Are their voltage levels where this would not apply
(ex. 230 kV) or load levels that would be seen as too high? Cannot agree or disagree due to the wording

Exelon

Exelon is abstaining from voting on this item. How would this exclusion be different from E1? Furthermore,
Exelon suggests that a definition of “Small Utility” would need to be developed.

BPA

Yes

August 19, 2011

Generally agree BPA would like to provide an exclusion for a small utility with multiple connections to a single
Transmission source connected at a voltage of 100 kV or greater. An example would be a single long 115 kV

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Organization

Yes or No

Question 10 Comment
transmission line passing through a rural area where a small utility utilizes multiple taps to the 115 kV line to
serve several radial systems

Cowlitz County PUD Cowlitz
County PUD

Yes

Cowlitz supports the SDT in its efforts to avoid unintended consequences from changes to the BES definition,
especially for small entities that can ill afford the substantial costs that accompany imposition of mandatory
compliance with reliability standards. Further, we agree that the small utilities covered by the exemption will
have no measurable impact on the operation of the interconnected BES. In the Pacific Northwest, many
small entities were required to register by virtue of owning a very small portion of the region’s 115-kV system.
These utilities have faced substantial compliance burdens even though their operations are simply not
material to the interconnected bulk grid in our region, and the investment of resources in compliance therefore
will have no measurable effect in improving the reliability of the interconnected grid. Further, the such
resources used to comply with the reliability efforts unjustly take away from necessary resources needed for
local quality of service efforts.

Small Entity Working Group
(SEWG)

Yes

Yes, with some clarifying edits. The final sentence should be revised as follows: “For purposes of this
exclusion, a ‘small utility’ is an entity that performs a distribution provider or load serving entity function but is
not required to register as a Distribution Provider or Load Serving Entity by the ERO.”

Florida Municipal Power Agency

Yes

FMPA supports this exclusion. For the sake of clarity, the final sentence should be revised to read as follows:
“For purposes of this exclusion, a “small utility” is an entity that performs a Distribution Provider or Load
Serving Entity function but is not required to register as a Distribution Provider or Load Serving Entity by the
ERO.”

American Municipal Power and
Members

Yes

For the sake of clarity, the final sentence should be revised to read as follows: “For purposes of this exclusion,
a “small utility” is an entity that benefits from the utility of the BES, but does not meet the registry criteria to
perform functions in the BES."

National Rural Electric
Cooperative Association
(NRECA)

Yes

NRECA agrees with this approach, but also believes this could be addressed in the Statement of Compliance
Registry Criteria document.

Overton Power District No. 5

Yes

We support exclusion E4, for small utilities, but we are unclear how small utilities are defined in the exclusion
language presented here.

Transmission Access Policy
Study Group
Northern California Power
Agency

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Organization

Yes or No

Question 10 Comment

PacifiCorp

Yes

PacifiCorp believes this concept is appropriate with the following concern: Essentially the only difference
between this proposed exclusion and E1a is this proposed exclusion does not include “an automatic
interruption device”. So if the proposed E4 is left as a stand-alone exclusion it should also require “an
automatic interrupting device” qualifier. Technical justification for requiring an interrupting device is the same
justification used by the SDT in E1.

FHEC

Yes

this begs the question of the Statement of Compliance Registry Criteria being updated also.

South Texas Electric
Cooperative, Inc.

Yes

There are many small utilities that fit into the scope and spirit of the exclusion BUT are currently registered as
a DP and/or LSE. Will this exclusion remove them from registration OR should language be inserted that
automatically revokes the NERC registrations of “already registered” small utilities. I recommend that any
such revocation be handled by NERC and NOT by the various EROs for the sake of consistency.

Sacramento Municipal Utility
District (SMUD)

Yes

As written, it is unclear how this exclusion differs from the Radial exclusion.
Furthermore, “small utility” needs to be defined more clearly.
The last sentence appears circular because ownership of a transmission element would draw the owner into
registration. Small entities have no measurable impact to the BES and should not be burdened with the
exemption process.

Illinois Municipal Electric Agency

Yes

With the following clarifying edits. The final sentence should be revised as follows: “For purposes of this
exclusion, a ‘small utility’ is an entity that performs a distribution provider or load serving entity function but is
not required to register as a Distribution Provider or Load Serving Entity by the ERO.”

Michgan Public Power Agency

Yes

But I question if the "Small Entity definition" as indicated in Order 743 language "we certify that this Final Rule
will not have a significant economic impact on a substantial number of small entities." has been appropriately
addressed.

Public Utilities Commission of
Ohio

Yes

It appears this could be applied consistently with other exclusions.

New York State Dept of Public
Service

Yes

This exclusion is consistent with E1 and E2. There should not be discrimination against similarly situated
loads.

Springfield Utility Board

Yes

Springfield Utility Board supports the SDT in its efforts to avoid unintended consequences from changes to

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Organization

Yes or No

Question 10 Comment
the BES definition, especially for small entities that cannot afford the substantial costs that accompany
imposition of mandatory compliance with Reliability Standards. Further, we agree that the small utilities
covered by the exemption will have no measureable impact on the operation of the interconnected BES. In
the Pacific Northwest, many small entities were required to register by virtue of owning a very small portion of
the region’s 115 kV system. These utilities have faced substantial compliance burdens even though their
operations are simply not material to the interconnected bulk grid in our region, and the investment of
resources in compliance, therefore, will have no measurable effect in improving the reliability of the
interconnected Grid.

Springfield Utility Board

Yes

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

American Electric Power

Yes

AEP agrees with the proposed exclusion to the extent that such excluded small utilities would continue to
provide any needed information the registered entities have requested from the excluded small utilities to
ensure the reliability compliance of those registered entities.

MidAmerican Energy Company

Yes

Arbitrarily excluding small entities could affect reliability depinding on the specific transmission facilities the
entity owns and/or operates.

Western Area Power
Administration

Yes

As discussed in the Applicability of Federal Power Act Section 215 to Qualifying Small Power Production and
Cogeneration Facilities document, the concerns regarding the Regulatory Flexibility Act Analysis of 1980
stated in section VII does not define the phrase a 'significant economic impact' from the perspective of a small
entity. A small entity may have staffed maintenance personnel, to accomplish its' own maintenance but now
prefers to transfer by written agreement with another entity based upon NERC's compliance registry criteria,

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Organization

Yes or No

Question 10 Comment
in order to bypass the NERC registration. The significant economic impact is the cost associated with the
reduced work load for the small entity, maintenance personnel, and the work contracted to another entity.

Western Montana Electric
Generating and Transmission
Cooperative
Public Utility District No. 1 of
Snohomish County, Washington
Blachly Lane Electric Cooperative
Northern Wasco County PUD

Yes

WMG&T supports the SDT in its efforts to avoid unintended consequences from changes to the BES
definition, especially for small entities that can ill afford the substantial costs that accompany imposition of
mandatory compliance with reliability standards. Further, we agree that the small utilities covered by the
exemption will have no measurable impact on the operation of the interconnected BES. In the Pacific
Northwest, many small entities were required to register by virtue of owning a very small portion of the
region’s 115-kV system. These utilities have faced substantial compliance burdens even though their
operations are simply not material to the interconnected bulk grid in our region, and the investment of
resources in compliance therefore will have no measurable effect in improving the reliability of the
interconnected grid.

PUD No. 2 of Grant County,
Washington
Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric

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Organization

Yes or No

Question 10 Comment

Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Clallam County PUD No.1
Chelan PUD – CHPD
Kootenai Electric Cooperative
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Central Lincoln
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc
Imperial Irrigation District

Yes

Santee Cooper

Yes

MRO's NERC Standards Review
Forum

Yes

ACES Power Participating
Members

Yes

Tennessee Valley Authority

Yes

Arizona Public Service Company

Yes

Rayburn Country Electric

Yes

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Organization

Yes or No

Question 10 Comment

Cooperative, Inc.
New York Power Authority

Yes

Luminant Energy

Yes

Dayton Power and Light
Company

Yes

Fayetteville Public Works
Commission

Yes

Florida Keys Electric Cooperative

Yes

East Kentucky Power
Cooperative, Inc.

Yes

Farmington Electric Utility System

Yes

Sierra Pacific Power Co d/b/a NV
Energy

Yes

Colorado Springs Utilities

Yes

Chevron Global Power, a division
of Chevron U.S.A. Inc.

Yes

Muscatine Power and Water

Yes

Puget Sound Energy

Yes

GTC

Yes

Long Island Power Authority

Yes

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Organization

Yes or No

Pepco Holdings Inc

Yes

Oncor Electric Delivery Company
LLC

Yes

City of Anaheim

Yes

MEAG Power

Yes

Utility System Efficiencies, Inc.

Yes

Question 10 Comment

Response: The basis for the additional exclusion was predicated by the circumstances of radial systems and the demarcation of the automatic interrupting
device. With the change of the demarcation point back to the point where the tap line intersects with the transmission line; this proposed exclusion is
unnecessary. The SDT will drop consideration for this proposed exclusion given the change to radial systems.

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Consideration of Comments on Revisions Made to the Definition of Bulk Electric System — Project 2010-17

11. In Order No. 743, the Commission addressed the need to differentiate between Transmission and
distribution in the revised definition of the Bulk Electric System (BES). Specifically, the Commission stated
that local distribution facilities are to be excluded from the BES. The SDT believes that it has excluded local
distribution facilities through the revised bright-line core definition and specific inclusions and exclusions.
Do you agree with this position? If not, please provide specific comments and suggestions on what else
needs to be addressed or added.

Summary Consideration: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater
distinction between transmission and distribution facilities. The SDT has also included in the definition a statement that excludes facilities used in
local distribution of electric energy. The SDT believes that the revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide
appropriate opportunities to exclude distribution facilities above 100 kV. In addition, the “cranking path” and “automatic interrupting devices”
language have been removed from the draft BES definition.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real
Power and Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is
modified by the list shown below. This does not include facilities used in the local distribution of electric energy.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or
gross aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV
or above.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of
voltage.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of
connection of 100 kV or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion
b)
c)

to allow for reliable system reconfiguration to maintain continuity of electrical service. Or,
Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or
equal to 75 MVA (gross nameplate rating). Or,
Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in
Inclusions I2, I3, I4 and I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate
rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect
this exclusion.

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E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that
distribute power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection
at 100 kV or higher are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail
customer Load and not to accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic faultinterrupting devices;
E3a. Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in
Inclusion I3, and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in
aggregate), includes more than 75 MVA generation;
E3b. Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within
the LDN The LN does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
E3c. Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored
Facility in the Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).

Organization
Northeast Power Coordinating
Council

Yes or No

Question 11 Comment

No

The current definition drafted by the SDT has not differentiated between Transmission and Distribution, nor
excluded distribution facilities from the BES, nor addressed the issue of local distribution facilities above
100kV. It is important for the ERO and the SDT to understand and be consistent with the FERC Order for
these important but complex issues. Many parts of the continent could be in conflict with state or provincial
regulatory act, Codes, and Licenses. The ERO and SDT and RoP teams be aware of these conflicts and not
disregard them, as they will pose many implementation complexities and confusion within the industry.
Regulatory Acts and Rules will always supersede NERC requirements and hence it is important that ERO
should neither be caught in regulatory conflict nor put entities in these situations.As responded to in Question
10, the ERO and SDT can address this by providing explicit but simple provisions in the exception criteria (to
be used by exception procedure) by putting forward required technical assessments , which are based on a
demonstration of evidence to justify the element’s necessity for operation.
For example, suggest that for local distribution, the evidence that should be required is:
o Regulatory evidence
o Evidence demonstrating that NO adverse reliability impact is afflicted on the interconnected BES because of

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Organization

Yes or No

Question 11 Comment
their connection
Some of the other key attributes of such an exception criteria should be: o Elements are not to be part of
interconnection between two balancing authority or contribute to IROLs
o Entire system cannot be classified as contiguous o Entity to justify whether or not the elements are
necessary for the operation of the interconnected transmission network
o Distinguish if the element in question supplies load centers, major cities, serves the national interest and/or
possibly impact national commerce or national security, or is identified by the relevant regulatory authority
Accordingly, the exception criteria should ONLY list a menu of items and a prescribed report template that
should be assessed and presented by an entity as their evidence and justification for exception to a RE, the
ERO and any relevant regulatory authority. This evidence and justification would be used by the ERO as part
of its decision making process.

Hydro One Networks Inc

No

We commend the SDT for their concept in putting forward a 100kV BES bright-line definition. However, we do
not believe that the current definition drafted by the SDT has differentiated between Transmission and
Distribution or excluded distribution facilities from the BES, or addressed the issue of local distribution
facilities above 100kV. It is worth noting that different jurisdictions may use different terminology for
“distribution” or non transmission facilities or elements. For example, some jurisdictions label certain facilities
as distribution which connect and are owned and operated by the distribution utility, customer or a generator
customer while other label them as connection facility or elements.(See Q10 response)

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT has also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Pepco Holdings Inc

No

see answer to #5

Response: See response to Q5.
American Municipal Power and
Members

August 19, 2011

No

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Organization

Yes or No

Question 11 Comment

Response: Thank you for your response. In the future please provide more information to let us know more specifically what you disagree with.
Tri-State Generation and
Transmission Association, Inc.

No

See the comments to Question 7.

No

Dominion believes the core BES definition should include any non-radial Element or Facility operated at 100
Kv or higher and should exclude any radial Element or Facility (regardless of operating voltage) as well as
non-radial Element or Facility operated below 100 kV. The core definition should also include defined criteria
that are applied to an Element or Facility to determine whether or not it meets the intent of the Section 215 of
Federal Power Act Section 215 defines the bulk power system as (1) facilities and control systems necessary
for operating an interconnected electric energy transmission network; and (2) electric energy from generation
facilities needed to maintain transmission system reliability. (3) However, Section 215 excludes facilities used
in the local distribution of electric energy From the definition of the bulk power system. An Element or Facility
should be included where the Element or Facility is necessary for operating an interconnected electric energy
transmission network or is needed to maintain transmission system reliability. Likewise an Element or Facility
should be excluded where the Element or Facility is not necessary for operating an interconnected electric
energy transmission network or is needed to maintain transmission system reliability.Dominion agrees that
the BES definition should exclude local distribution facilities under state jurisdiction. In specific instances
(including UFLS programs and transmission protection systems that are implemented on distribution elements
or radial transmission) local distribution facilities can be included in approved NERC reliability standards
following under explicit standards dedicated to their explicit mission without their automatic inclusion in a
definition of BES that could infringe on state jurisdiction.

Response: See the response to Q7.
Dominion

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT has also included in the definition a statement that excludes facilities used in local distribution of electric energy. NERC Reliability
Standards can apply to non-BES Facilities and compliance can be enforced for those entities in the NERC Compliance Registry.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
SPP Standards Review Group

August 19, 2011

No

The inclusion of Cranking Paths into the BES without regard to voltage level has the potential to pull
distribution facilities into the BES. (See Question 5)

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Organization

Yes or No

Question 11 Comment

Response: The SDT removed Cranking Paths from the BES definition.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Michigan Public Service
Commission(MPSC)

No

MPSC Staff Comments: The intent of the updated BES definition should be to classify facilities required to
meet mandatory NERC reliability standards. Unnecessary and costly duplication of standards work should be
avoided.

Response: The SDT is revising the BES definition to meet the FERC directives in Order Nos. 743 and 743-A. The SDT does not believe it is contributing to any
unnecessary and costly duplication of standards work. No change made.
National Rural Electric
Cooperative Association
(NRECA)

No

NRECA believes the definition should explicitly state that facilities used in local distribution are excluded from
the BES.

United Illuminating

No

The core definition should state that local distribution facilities are not included.

Response: The SDT included in the definition a statement that excludes facilities used in local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy as established by applicable regulatory authorities.
Idaho Falls Power

No

In the exclusions, we feel there has not been given enough clarification of generation assets on a LDN,
specifically, is a single generation resource >20MVA but <75 MVA excluded? This does not seem clear
because of the seeming inconsistencies of E2(i) and E3(b).Further, we believe generation on an LDN serving
local load wherein the net flow is into the LDN should be excluded.

Response: The SDT made changes to the LDN, now LN, to address your comment and the comments of others. Specifically, LNs are permitted to have
generating resources that in the aggregate do not exceed 75 MVA, and such generating resources are not already included under I3 of the BES definition. The
SDT believes these changes clarify the amount of generation permitted in the LN.
E3a. Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3 and
do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75 MVA
generation;

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Organization

Yes or No

Question 11 Comment

Overton Power District No. 5

No

Facilities used in local distribution should not be swept up into the BES

Western Montana Electric
Generating and Transmission
Cooperative

No

While WMG&T agrees that the approach adopted by the SDT -- a core definition coupled with specific
inclusions and exclusions - will be effective in removing most local distribution facilities from the BES, it will
not remove all such facilities. For the reasons discussed at greater length in our answer to Question 1,
WMG&T believes that the proposed definition is over-inclusive and is likely to sweep up certain facilities used
in local distribution that should not be classified as BES. As discussed in our answer to Question 3, WMG&T
notes that exclusion of facilities from the BES does not mean that owners of those facilities are entirely
exempt from reliability standards. On the contrary, the statute provides that “users” of the BES can be subject
to reliability regulation. Hence, even where an entity does not own BES assets, it could be required to, for
example, provide necessary information to the applicable Reliability Coordinator and to participate in the
regional Under-Frequency Load Shedding program by setting the UFLS relays in its Local Distribution
Network at the appropriate settings. We note that participants in the WECC BESDTF Task Force generally
agreed that appropriate information should be provided by non-BES entities, although there was considerable
concern related to ensuring that the provision of information was not unduly burdensome.

Texas Industrial Energy
Consumers (TIEC)

No

TIEC appreciates the SDT’s effort to identify situations where facilities rated above 100 kV should still be
categorically excluded from the BES definition This recognition is consistent with the concerns raised by
TIEC and many of its individual members in comments to the FERC in Docket RM09-18-000. However, TIEC
submits that the SDT’s approach to these exclusions should be revised to meet FERC’s express recognition
in Order No. 743-A that “facilities used for local distribution are excluded from the Bulk-Power System
definition under section 215, and thus are excluded from the bulk electric system.” Order No. 743-A at ¶58.
It is crucial that the BES definition is drafted in a way that recognizes that it is the transmission provider’s
responsibility to ensure that equipment is in place to protect the BES from the operations of excluded
facilities, not the responsibility of a person owning facilities involved in the local distribution of electricity.
These issues are addressed in further detail in response to the specific exclusions.

Electricity Consumers Resource
Council (ELCON)

No

Section 215 of the Federal Power Act denies FERC jurisdiction over facilities used in the local distribution of
electric energy. FERC has recognized that since facilities used in the local distribution of electric energy “are
exempted from the Bulk-Power System, they also are excluded from the bulk electric system.” Section 215 of
the Federal Power Act does not qualify the exclusion from FERC jurisdiction of “facilities used in the local
distribution of electric energy.” For example, Section 215 does not state that:--The term “bulk power system”
“does not include facilities used in the local distribution of electric energy [unless needed for reliability
purposes];” or --The term “bulk power system” “does not include facilities [with automatic interruption devices]
used in the local distribution of electric energy.”Any definition of the bulk electric system that does not exclude
all “facilities used in the local distribution of electric energy” is unlawful.

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Yes or No

Question 11 Comment
Further, the definition of the bulk electric system must recognize that Section 215 of the Federal Power Act
does not allow the potential reliability impact of a facility to determine whether the facility is local distribution or
transmission. By excluding all facilities used in the local distribution of electric energy from the definition of
the Bulk-Power System in Section 215, Congress recognized that while facilities used in the local distribution
of electric energy may be part of the Bulk-Power System, they are, nonetheless, not FERC jurisdictional.
Thus, “facilities and control systems necessary for operating an interconnected electric energy transmission
network (or any portion thereof)” that are used in the local distribution of electric energy are not FERC
jurisdictional regardless of the potential reliability impact of the facilities.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Tennessee Valley Authority

No

We cannot be certain of the effect of the BES definition on distribution facilities until our comments to the
inclusions and exclusions above are considered.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
these changes address your concerns.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Alabama Public Service
Commission

August 19, 2011

No

In drafting the inclusions and exclusions that accompany the core BES definition, the SDT needs to be very
careful in considering jurisdictional issues. FERC has recognized in its recent orders regarding the BES
definition that local distribution facilities are not subject to its jurisdiction under Section 215 of the Federal
Power Act. As the SDT considers the scope of the inclusions and exclusions from the BES Definition, it
needs to consider whether the proposed provisions only include: 1) facilities or control systems that are
“necessary” for operating an interconnected electric transmission network and 2) whether they involve
generation facilities that are “needed” to maintain transmission system reliability. If the proposed inclusions
and exclusions result in the BES definition applying to facilities beyond this “necessary” and “needed” scope
(such as local distribution facilities), then the definition would be inconsistent with Section 215 and could
improperly make those facilities subject to “reliability standards” contrary to the Federal Power Act.

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Question 11 Comment
The APSC generally supports the BES Core Definition and all three Exclusions proposed by the SDT.
The APSC strongly supports Exclusion E3 for local distribution networks and Exclusion E1 for radial systems
(subject to the concerns below). Exclusion E3 will ensure State jurisdiction over facilities that are used in the
local distribution of electric energy.
The APSC does not support Inclusion I2 for individual generating units greater than 20 MVA. Inclusion I2
should be eliminated entirely because it will result in too many radial sub-transmission load serving facilities
losing their non-BES status, when those facilities are not “necessary” for bulk power system reliability.
The APSC supports Inclusion I3 (75MVA) as a sufficient generating unit threshold for purposes of this
definition.If Inclusion I2 is eliminated, then the reference to Inclusion I2 within Exclusion E1 should also be
eliminated.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
ReliabilityFirst

No

we feel that BES elements have been included in teh exclusions

PJM

No

The bright line exclusion includes facilities that would normally be BES facilities but are excluded based on
the asset size of the owner.

Response: The SDT does not believe it has excluded BES Elements in the draft BES definition. The SDT made a number of clarifying changes to the draft BES

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Question 11 Comment

definition that it believes provides a greater distinction between transmission and distribution facilities. The SDT also included in the definition a statement that
excludes facilities used in local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Central Maine Power Company

No

Transmission and distribution facilities are already mutually exclusive and are already classified and reported
in FERC Form 1. The SDT definition may have rolled in considerable portions of the distribution system for
consideration as BES. A small generator that is entered into the black start program would make the
complete cranking path BES. As documented previously this inclusion of immaterial generators and
subsequently their distribution cranking paths is at odds with the Compliance Registry.

No

As highlighted in the answers to Questions 5 and 7, Exelon does not believe that facilities used in local
distribution of electric energy have been fully excluded in the draft BES definition. For example, there are
many examples of black start cranking path facilities that are <100kV and that are currently defined as
facilities used in the “local distribution of electric energy”.

New York State Electric & Gas
and Rochester Gas & Electric

Exelon

Response: The SDT removed Cranking Paths from the BES definition. The SDT made a number of clarifying changes to the draft BES definition that it believes
provides a greater distinction between transmission and distribution facilities. The SDT also included in the definition a statement that excludes facilities used in
local distribution of electric energy.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Western Area Power
Administration

No

Numerous distribution lines in the western US are 115kV, and some are being upgraded from 115kV to
230kV.

Intellibind

No

Due to the voltage bright line of 100kV there is still a question of what makes up sub-transmission. Many
rural companies with large geographic areas use the 115kV system internally as sub transmission, but
because of the bright line it is considered part of the transmission system. This is not its purpose, or how it is
operated. There are no commercial paths, and no transmission flow through. On the other hand there are
significant generation resources (significantly over 20MVA) that are interconnected directly through the sub
transmission system to the BES, and by definition, since they are not interconnected at 100kV, they are

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Yes or No

Question 11 Comment
exempted from BES status. Some of these facilities do have direct impact on the BES.

Public Utility District No. 1 of
Snohomish County, Washington

August 19, 2011

No

While Snohomish County PUD agrees that the approach adopted by the SDT -- a core definition coupled with
specific inclusions and exclusions - will be effective in removing most local distribution facilities from the BES,
it will not remove all such facilities. For the reasons discussed at greater length in our answer to Question 1,
Snohomish believes that the proposed definition is over-inclusive and is likely to sweep up certain facilities
used in local distribution that should not be classified as BES. To give a further example, assume that a local
distribution utility operates a distribution network that currently would be excluded from the SDT’s definition,
but that a cogeneration facility with a capacity of 30 MVA and average production of 15 MW is constructed in
one of the industrial areas served by local distribution facility and the output is purchased by one of the
industrial customers. Because of inclusion I2, the local utility would now be classified as owning BES
facilities, even though the output of the generator rarely exceeds 20 MW in practice and the output is, as a
matter of physics, absorbed by the surrounding industrials loads rather than being transmitting onto the
interconnected grid. Further, the fundamental nature of the local distribution facilities has not changed. They
are still used to deliver electric power to the utility’s end-use customers, not to deliver power on the wholesale
market across the interconnected bulk grid. Hence, the result of the SDT’s definition is to include “facilities
used on the local distribution of electric energy” in contravention of FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). The practical result of the improper classification would be that the local utility would be required
to register as a Transmission Owner and Transmission Operator, and would incur substantial costs to comply
with requirements that are designed to ensure the reliable operation of transmission lines that are part of the
interconnected grid, not local distribution facilities. For the reasons explained in the papers published by the
Project 2010-07 Task Force, the result is substantially increased compliance costs that produce little or no
improvement in the reliability of the interconnected bulk system. Accordingly, if viewed in isolation, the SDT’s
core definitions and list of inclusions/exclusions do not comply with the statute or produce optimum benefits
for bulk system reliability. Whether the SDT’s approach complies with the statute can only be determined by
examining the Exception process now under development, in conjunction with the SDT’s definition. If the
Exception process results in the exclusion of facilities that are improperly swept into the BES by the bright-line
thresholds included in the SDT’s definition, and the Exception can be attained at a reasonable cost to the
involved entities, then the SDT will have achieved a result that complies with the statute. But this conclusion
can be reached only upon review of the entire package, not just the core definition and list of
inclusions/exclusions. In this regard, as discussed in our answer to Question 3, Snohomish notes that
exclusion of facilities from the BES does not mean that owners of those facilities are entirely exempt from
reliability standards. On the contrary, the statute provides that “users” of the BES can be subject to reliability
regulation. 16 U.S.C. § 824o(b). Hence, even where an entity does not own BES assets, it could be
required to, for example, provide necessary information to the applicable Reliability Coordinator and to
participate in the regional Under-Frequency Load Shedding program by setting the UFLS relays in its Local
Distribution Network at the appropriate settings. We note that participants in the WECC BES Task Force

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Question 11 Comment
generally agreed that appropriate information should be provided by non-BES entities, although there was
considerable concern related to ensuring that the provision of information was not unduly burdensome.

Blachly Lane Electric Cooperative

No

We agree that the approach adopted by the SDT -- a core definition coupled with specific inclusions and
exclusions - will be effective in removing some local distribution facilities from the BES, it will not remove all
such facilities. For the reasons discussed in our answer to Question 1, the proposed definition is overinclusive and is likely to sweep up certain facilities used in local distribution that should not be classified as
BES.

No

While Northern Wasco County PUD agrees that the approach adopted by the SDT -- a core definition coupled
with specific inclusions and exclusions - will be effective in removing most local distribution facilities from the
BES, it will not remove all such facilities. For the reasons discussed at greater length in our answer to
Question 1, Northern Wasco County PUD believes that the proposed definition is over-inclusive and is likely
to sweep up certain facilities used in local distribution that should not be classified as BES. As discussed in

Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc.
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Northern Wasco County PUD
Chelan PUD – CHPD
Kootenai Electric Cooperative

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Yes or No

Public Utility District No. 1 of
Franklin County

our answer to Question 3, Northern Wasco County PUD notes that exclusion of facilities from the BES does
not mean that owners of those facilities are entirely exempt from reliability standards. On the contrary, the
statute provides that “users” of the BES can be subject to reliability regulation. Hence, even where an entity
does not own BES assets, it could be required to, for example, provide necessary information to the
applicable Reliability Coordinator and to participate in the regional Under-Frequency Load Shedding program
by setting the UFLS relays in its Local Distribution Network at the appropriate settings. We note that
participants in the WECC BESDTF Task Force generally agreed that appropriate information should be
provided by non-BES entities, although there was considerable concern related to ensuring that the provision
of information was not unduly burdensome.

Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc.
Cowlitz County PUD

Clallam County PUD No.1

August 19, 2011

Question 11 Comment

No

While Clallam County PUD agrees that the approach adopted by the SDT -- a core definition coupled with
specific inclusions and exclusions - will be effective in removing most local distribution facilities from the BES,
it will not remove all such facilities. For the reasons discussed at greater length in our answer to Question 1,
Clallam believes that the proposed definition is over-inclusive and is likely to sweep up certain facilities used
in local distribution that should not be classified as BES. To give a further example, assume that a local
distribution utility operates a distribution network that currently would be excluded from the SDT’s definition,
but that a cogeneration facility with a capacity of 30 MVA and average production of 15 MVA is constructed in
one of the industrial areas served by local distribution facility and the output is purchased by one of the
industrial customers. Because of inclusion I2, the local utility would now be classified as owning BES
facilities, even though the output of the generator rarely exceeds 20 MVA in practice and the output is, as a
matter of physics, absorbed by the surrounding industrials loads rather than being transmitting onto the
interconnected grid. Further, the fundamental nature of the local distribution facilities has not changed. They
are still used to deliver electric power to the utility’s end-use customers, not to deliver power on the wholesale
market across the interconnected bulk grid. Hence, the result of the SDT’s definition is to include “facilities
used on the local distribution of electric energy” in contravention of FPA Section 215(a)(1), 16 U.S.C. §
8240(a)(1). The practical result of the improper classification would be that the local utility would be required
to register as a Transmission Owner and Transmission Operator, and would incur substantial costs to comply
with requirements that are designed to ensure the reliable operation of transmission lines that are part of the
interconnected grid, not local distribution facilities. For the reasons explained in the papers published by the
Project 2010-07 Task Force, the result is substantially increased compliance costs that produce little or no
improvement in the reliability of the interconnected bulk system. Accordingly, if viewed in isolation, the SDT’s
core definitions and list of inclusions/exclusions do not comply with the statute or produce optimum benefits
for bulk system reliability. Whether the SDT’s approach complies with the statute can only be determined by
examining the Exception process now under development, in conjunction with the SDT’s definition. If the
Exception process results in the exclusion of facilities that are improperly swept into the BES by the bright-line
thresholds included in the SDT’s definition, and the exclusion can be accomplished at a reasonable cost to
the involved entities, then the SDT will have achieved a result that complies with the statute. But this

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Yes or No

Question 11 Comment
conclusion can be reached only upon review of the entire package, not just the core definition and list of
inclusions/exclusions. In this regard, as discussed in our answer to Question 3, Clallam notes that exclusion
of facilities from the BES does not mean that owners of those facilities are entirely exempt from reliability
standards. On the contrary, the statute provides that “users” of the BES can be subject to reliability
regulation. 16 U.S.C. § 824o(b). Hence, even where an entity does not own BES assets, it could be
required to, for example, provide necessary information to the applicable Reliability Coordinator and to
participate in the regional Under-Frequency Load Shedding program by setting the UFLS relays in its Local
Distribution Network at the appropriate settings. We note that participants in the WECC BES Task Force
generally agreed that appropriate information should be provided by non-BES entities, although there was
considerable concern related to ensuring that the provision of information was not unduly burdensome.

Electric Reliability Council of
Texas, Inc.

No

See response to question 1 - ERCOT ISO agrees that distribution facilities should be excluded, and such
facilities are generally excluded in ERCOT ISO’s proposed alternative definition. However, FERC stated in
743 and 743-A that it has the right to determine if facilities are distribution or transmission. Accordingly, to
respect the FPA explicit exclusion of distribution facilities and FERC’s authority to determine if a facility is
transmission or distribution, ERCOT ISO position is that the general exemption should be in the BES
definition, but any such exemptions must be subject to the exemption process to facilitate FERC’s authority to
make the relevant determination. With respect to that process, it may provide for a presumptive exclusion
with additional at FERC’s discretion. ERCOT ISO reserves its rights to comment on the criteria for
exclusion/exemption/inclusion in that proceeding. In addition, the exception process should provide for the
ability to include certain distribution facilities if the inclusion criteria of the exception process indicate such
action is appropriate.

MidAmerican Energy Company

No

We disagree that the SDT has appropriately excluded local distribution facilities through the revised bright-line
core definition and specific inclusions and exclusions. A similar bright line criterion excluding facilities below
100 kV would be better. The intent is to clearly define facilities below 100kV (exclusive of resources added
under criterion I4) as local distribution (excluded from FERC jurisdiction in accordance with the Federal Power
Act). Critical facilities below 100 kV would be brought back in under the provisions of inclusion exception
criteria of the Technical Principles for Demonstrating BES Exceptions procedure.

Springfield Utility Board

No

While SUB agrees that the approach adopted by the SDT, a core definition, couple with specific inclusions
and exclusions, will be effective in removing most local distribution facilities from the BES, it will not remove
all such facilities. SUB believes that the proposed definition is over-inclusive and is likely to sweep up certain
facilities used in local distribution that should not be classified as BES. SUB notes that exclusion of facilities
from the BES does not mean that owners of those facilities are entirely exempt.

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Organization

Yes or No

Question 11 Comment

Springfield Utility Board

No

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause a inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Midstate Electric Cooperative

No

While MSEC agrees that the approach adopted by the SDT -- a core definition coupled with specific
inclusions and exclusions - will be effective in removing most local distribution facilities from the BES, it will
not remove all such facilities. For the reasons discussed at greater length in our answer to Question 1,MSEC
believes that the proposed definition is over-inclusive and is likely to sweep up certain facilities used in local
distribution that should not be classified as BES.
As discussed in our answer to Question 3, MSEC notes that exclusion of facilities from the BES does not
mean that owners of those facilities are entirely exempt from reliability standards. On the contrary, the statute
provides that “users” of the BES can be subject to reliability regulation. Hence, even where an entity does not
own BES assets, it could be required to, for example, provide necessary information to the applicable
Reliability Coordinator and to participate in the regional Under-Frequency Load Shedding program by setting
the UFLS relays in its Local Distribution Network at the appropriate settings. We note that participants in the
WECC BESDTF Task Force generally agreed that appropriate information should be provided by non-BES
entities, although there was considerable concern related to ensuring that the provision of information was not
unduly burdensome.

Public Utilities Commission of
Ohio

August 19, 2011

No

While it appears there was an attempt to draft the standard to comply with the Federal Power Act, the issues
outlined throughout the questions above raise concerns that local distribution could easily get captured in
NERC and FERC reliability standards needlessly and inappropriately.

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Yes or No

Question 11 Comment

New England States Committee
on Electricity

No

As stated in 1 above, NESCOE is concerned that the proposed definition may unintentionally incorporate
facilities into the BES that do not have a direct impact on the reliability of the system, potentially imposing
significant costs without meaningful reliability benefits.

AltaLink

No

We commend the SDT for their concept in putting forward a 100kV BES bright-line definition. However, we do
not believe that the current definition drafted by the SDT has differentiated between Transmission and
Distribution or excluded distribution facilities from the BES, or addressed the issue of local distribution
facilities above 100kV. We believe that the ERO and SDT can address this by providing explicit but simple
provisions in the exception criteria (to be used by exception procedure) by putting forward a menu of key
technical assessments , which are based on demonstration of evidence to justify the element’s necessity for
operation. For example, we suggest that for local distribution, the evidence that should be required is: o
Regulatory evidence o Evidence demonstrating that NO adverse reliability impact is afflicted on the
interconnected BES because of their connectionWe suggest that the exception criteria should ONLY list a
menu of items and a prescribed report template that should be assessed and presented by an entity as their
evidence and justification for exception to a RE, the ERO and any relevant regulatory authority. This evidence
and justification would be used by the ERO as part of its decision making process.

Modern Electric Water Company

No

The proposed definition continues to inject ambiguity in that it introduces the use of the separately-defined
capitalized term “Transmission”. In NERC’s Glossary of Terms (May 24, 2011), “Transmission” is defined in
terms of function rather than voltage. As it should, the core definition implies that only Elements used for the
transfer of energy to points where it is transformed for delivery to customers as well as certain resources are
considered to be included in the BES. However, it also uses voltage, and we do not believe that the proposed
definition goes far enough to distinguish between T and D. Under the language of the core definition, there
exists a two-stage qualifier for non-resource Elements - namely that it must first be used for Transmission and
not for “Distribution”, and secondly, that it be operated above 100kV. Rather, the BES cannot contain
Elements used for “Distribution” (a term not explicitly defined, but extrapolated from other NERC glossary
terms to mean the “wires” between the transmission system and the end-use customer, and NOT defined by
voltage). While the Exclusions detail characteristics of specific distribution-like Elements, we suggest that the
core BES definition contain language explicitly excluding Distribution (there are Elements that are neither
qualifying radials as defined in E1 nor local distribution networks as defined in E3). Section 215(a)(1) contains
specific language that could be used in the core definition in this instance.

Michgan Public Power Agency

No

As I have indicated in my comments above the "small entity definition" is not being used when the 100 KV, 20
MVA, and 75 MVA aggregate are being used only. A unit with a long start up time and a low capacity factor
and/or availability factor and connected to a local distribution system is interconnected to the BES has little
opportunity to be counted on to support the BES during a critical event. With the environmental issues out

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Question 11 Comment
there it could be expected that owners of these types of units may well decide on economics of the issue and
retire such units. How would the reliability of the BES be served then?

City of Redding

No

Redding agrees that addressing Radial’s and LDN’s in the core definition is a great first step in identifying
distribution facilities, however there will still be a sizeable amount of elements operated over 100 kV that will
not be identified as distribution facilities through the efforts of the brightline. Additionally, as noted in question
#1, in the Western Interconnect the majority of 100 kV elements are used as Distribution facilities. Therefore,
the exclusions E1 & E2 will help ease the burden of NERC and the Regional Entity in the West by reducing the
number of Exception Process applications.
Also, Redding believes the SDT needs to take a more literal approach to FERC’s Orders and define the term
“necessary for operating the interconnected transmission network” and clearly “establish whether a particular
facility is local distribution or transmission”. Without a clear distinction of these two foundational principles it
will be difficult to remove the confusion between the Regulators and Entities as to the term “necessary”.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Hydro-Quebec TransEnergie

No

See comments on E3 (Q.9)

No

Without BES "demarcation" and "contiguous" principles being addressed in the proposed BES definition, this
question is difficult to answer. NERC Staff has submitted written comments to this project stating that the
BES “must be contiguous.” Instituting a contiguous BES with Inclusion I2, for example, would result in a
substantially over-inclusive BES definition. The adoption of a “contiguous” BES is therefore likely to result in
imposition of reliability standards on a substantial number of distribution elements that nothing to do with
improving or protecting the reliability of bulk transmission system.There is no compelling reason to adopt a
“contiguous” BES down into local distribution systems. Section 215 of the FPA of 2005 gives FERC
jurisdictional authority over “users” as well as “owners” and “operators” of the bulk power system.
Consequently, FERC has the jurisdictional authority to require generation and other entities in the Compliance
Registry to comply with applicable NERC requirements. Hence, even where an entity does not own or

Response: See response to Q9.
Oregon Public Utility Commission
Staff

August 19, 2011

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operate BES assets, it could still be required, for example, to provide necessary information to the applicable
Reliability Coordinator or Planning Coordinator and to participate in programs to prevent instability,
uncontrolled separation, or cascading outages to the bulk transmission system. This approach would fully
achieve the goals of bulk transmission system reliability without imposing the full BES regulatory compliance
burden on local distribution elements.

National Association of
Regulatory Utility Commissioners

The standard as currently written seems to exempt most local distribution from NERC and FERC reliability
standards. Section 215 of the Federal Power Act requires such exemptions. There remain some outstanding
concerns, however. For example, earlier comments from NERC staff have suggested that the BES needs to
be contiguous. If the definition were to require continuity, it would likely sweep in many local distribution
facilities that should not (and cannot under the statute) be included in the BES definition.

Response: The SDT did not adopt a “contiguous” BES down into the local distribution systems. The SDT made a number of clarifying changes to the draft BES
definition that it believes provides a greater distinction between transmission and distribution facilities. The SDT also included in the definition a statement that
excludes facilities used in local distribution of electric energy. The SDT believes that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion)
provide appropriate opportunity to exclude distribution facilities above 100 kV.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Grand Haven Board of Light and
Power

No

The exclusions do not properly address the exclusion of single automatic interrupting device that serves a
radial, load serving system and, through its operation, does not affect the BES.

Response: The SDT removed the requirement for an automatic interrupting device for radial exclusions.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
FHEC

No

Not until the Statement of Compliance Registry Criteria is conformed to this proposed definition.

South Texas Electric
Cooperative, Inc.

Yes

I agree, but believe that those distribution companies that were forced to register as LSEs under FERC
interpretation should be excluded as well.

South Texas Electric
Cooperative, Inc.

Yes

I agree, but believe that those local distribution companies operating below the bright-line that were forced to
register as LSEs under FERC Order on Compliance Filing (October 16, 2008) should be excluded as well.
For example, BAL-005-0.1b, CIP-001-1a, EOP-002-3 and others do not apply to DPs but affect small local

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utilities as LSEs. If, according to FERC Order 743 a small local distribution utility would be rightly excluded
from DP standards, then, by the same logic and as a distribution-level LSE, they should be excluded from
LSE standards as well.If an operating system voltage below 100kV is too low to affect the BES/BPS, then it
stands to reason that their connected load is too small as well. If not - then another bright-line should be
established in the spirit of FERC Order 743 to differentiate between power flow across the BES/BPS and
power flow to end-use consumers.

Response: The SDT was assigned the job of revising the BES definition as required by FERC Order Nos. 743 and 743-A. Any changes to the ERO Statement of
Compliance Registry Criteria are outside the scope of the SDT’s assigned work. No change made.
Vermont Transco

No

The inclusion of all black start units “regardless of voltage”, the unclear definition of “automatic interruption
device” and “common bus” could lead to local distribution company facilities being included in the definition of
BES.

ISO New England, Inc.

No

The SDT definition will unnecessarily roll in portions of the distribution system for consideration as BES. A
small generator that is entered into the black start program would make the complete cranking path BES. As
documented previously this inclusion of immaterial generators and subsequently their distribution cranking
paths is at odds with the Compliance Registry.

Response: The SDT removed the requirement for (1) an automatic interrupting device for radial exclusions and (2) all Cranking Paths regardless of voltage from
the draft BES definition. In addition, the “common bus” language has been deleted from the draft BES definition.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
National Grid

August 19, 2011

No

We don’t believe the bright-line core definition and specific inclusions and exclusions prevent distribution from
being considered as BES. Actually, it seems like a lot of distribution will be considered BES according to the
inclusions and exclusions. (E1 may be interpreted to include step downs if they don't have automatic
interruption devices and possibly the tied through distribution system to the other step-down transformer that
doesn't have an automatic interruption device from the same Transmission source) If the definition is not
revised to exclude more distribution, we are concerned about how the distribution elements that will be
considered BES under the new definition will be classified. The BES definition should not be used to
differentiate between transmission and distribution. It is important for the ERO and the SDT to understand and
be consistent with the FERC Order for these important but complex issues. There could be conflicts with state
or provincial jurisdictions. The ERO and SDT and RoP teams should be aware of these conflicts and not

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disregard them, as they will pose many implementation complexities and confusion within the industry, and
may lead to jurisdictional challenges that could cause uncertainty and delay in implementation of the new
BES definition. It is important for the ERO to not put entities in situations where there is some confusion or
conflict.Removing I4, the inclusion regarding blackstart resources and cranking paths, will prevent distribution
from being considered as BES.
Also, clarification that step downs which have one winding which is less than 100 kV but are tapped off of the
BES system without an automatic interruption device are not BES could also prevent distribution from being
considered as BES.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV. In
addition, the Cranking Path and automatic interruption device language has been removed from the draft BES definition.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
ExxonMobil Research and
Engineering

August 19, 2011

No

The SDT has defined a specific type of local distribution facility in their bright-line definition of the bulk electric
system. The SDT’s definition focuses on a specific type of local distribution system that has a minimum
impact on an interconnected transmission system when that interconnected transmission system does not
include the facilities necessary to properly protect itself from faults originating on its boundary. Section 215 of
the Federal Power Act does not qualify the type of local distribution facility that should be excluded. It
exempts ALL facilities used in the local distribution of electric energy, regardless of whether the owners and
operators of the interconnected transmission system have installed facilities that are necessary to secure the
reliability of the interconnected transmission system from incidents originating at its boundaries.Additionally,
the SDT should consider making its definition of a local distribution network consistent with exclusion E2. If a
generation facility with a net aggregate rating less than 75 MVA or single unit with a net export capacity below
20 MVA is not a part of the bulk electric system, what is the technical justification of including a local
distribution network that exports less than 75 MVA in the bulk electric system when it is not used to transmit
electric energy between geographic regions? Many QFs and large industrial facilities may fall under the
description of local distribution network due to the breadth of their private use network, connection to mulitple

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138 kV / 230 kV substations (done to improve reliability in order to provide safer operation of the industrial
process), and possible cyclical generation exports (sometimes exporting / sometimes importing).

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy as established by applicable regulatory authorities.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards
Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
FortisBC

August 19, 2011

No

We commend the SDT for their concept in putting forward a 100kV BES bright-line definition. However, we do
not believe that the current definition drafted by the SDT has differentiated between Transmission and
Distribution or excluded distribution facilities from the BES, or addressed the issue of local distribution
facilities above 100kV. It is important for the ERO and the SDT to understand and be consistent with the
FERC Order for these important but complex issues. Otherwise, many parts of the continent could be in
conflict with state or provincial regulatory act, Codes, and Licenses. We urge the ERO and SDT and RoP
teams be aware of these conflicts and not disregard them, as they will pose many implementation
complexities and confusion within the industry. Regulatory Acts and Rules will always trump NERC
requirements and hence it is important that ERO should neither be caught in regulatory conflict nor put
entities in these situations. It is worth noting that different jurisdictions may use different terminology for
“distribution” or non transmission facilities or elements. For example, some jurisdictions label certain facilities
as distribution which connect and are owned and operated by the distribution utility, customer or a generator
customer while other label them as connection facility or elements.As stated earlier (Q10), we believe that the
ERO and SDT can address this by providing explicit but simple provisions in the exception criteria (to be used
by exception procedure) by putting forward a menu of key technical assessments , which are based on
demonstration of evidence to justify the element’s necessity for operation. For example, we suggest that for
local distribution, the evidence that should be required is:
o Regulatory evidence.
o Evidence
demonstrating that NO adverse reliability impact is afflicted on the interconnected BES because of their
connection.Some of the other key attributes of such an exception criteria should be:
o Elements are not to
be part of interconnection between two balancing authority or contribute to IROLs
o Entire system cannot

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be classified as contiguous
o BESS Elements within exclusion can still be subject to relevant NERC
Standards
o Entity to justify whether or not the elements are necessary for the operation of the
interconnected transmission network
o Distinguish if the element in question supplies load centers, major
cities, serves the national interest and/or possibly impact national commerce or national security, or is
identified by the relevant regulatory authority.Accordingly, we suggest that the exception criteria should ONLY
list a menu of items and a prescribed report template that should be assessed and presented by an entity as
their evidence and justification for exception to a RE, the ERO and any relevant regulatory authority. This
evidence and justification would be used by the ERO as part of its decision making process.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV.
Your comments regarding the exception process criteria will be addressed separately in the response to the exception process comments.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Consumers Energy Company

No

The proposed definition appears to treat “BES” and “Transmission” synonymously, and this is highly likely to
have a significant effect on registration, even if this is not intended. To support consistency between reliability
and tariffs, we recommend that more direct consideration be given to the FERC 7-factor test that has been
consistently used to delineate transmission facilities for tariff purposes, and to discriminate between
registration requirements for TO and DP based on this delineation. Further, reliability gaps will not be created
(or can be addressed by minor changes to the applicable standards) if this recommendation is adopted
because all aspects of the applicable standards/requirements are (or will be) captured by the current
registration process.

Response: The SDT reviewed and considered the FERC 7-factor test and has included some concepts of that test in the LN portion of the draft BES definition.
No change made.
Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

August 19, 2011

No

Local distribution facilities have not been excluded from the proposed definition of the BES. As FERC
recognized in Order No. 743-A in directing NERC to exclude local distribution facilities from the revised
definition of the BES, any definition that does not exclude all “facilities used in the local distribution of electric
energy” is unlawful. FERC, as well as federal courts, have repeatedly stated that whether a facility is used in
local distribution must be determined on a “case-specific” basis (see, e.g., Order No. 888 at 31,980-81). As a
threshold matter, before devoting any additional time and resources to developing a definition of the BES,
there must be a clear understanding of the factors to consider when determining whether a facility is either a

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local distribution facility or a transmission facility. Currently, such a determination is made by considering a
“seven-factor test” that FERC has adopted, and the U.S. Supreme Court has upheld. The “seven-factor test,”
of which no one factor is determinative, evaluates the following indicators: (1) Local distribution facilities are
normally in close proximity to retail customers.(2) Local distribution facilities are primarily radial in
character.(3) Power flows into local distribution systems; it rarely, if ever, flows out.(4) When power enters a
local distribution system, it is not reconsigned or transported on to some other market. (5) Power entering a
local distribution system is consumed in a comparatively restricted geographical area. (6) Meters are based at
the transmission/local distribution interface to measure flows into the local distribution system.(7) Local
distribution systems will be of reduced voltage (Order No. 888 at 31,981). The seven-factor test, which
recognizes that a bright-line between transmission and distribution is a not a workable approach, is designed
to ensure FERC does not impermissibly usurp state and local regulation of local distribution facilities. There
is no evidence that the seven-factor test was considered in drafting the proposed definition of the BES.
Please see further discussion in response to Question 12.

Central Lincoln

No

We believe the SDT has excluded most distribution facilities, but not all. The remaining distribution facilities
will find it necessary to go through a lengthy exception process. As stated in Q1, we support the PNGC
comments stating that local distribution as determined by the seven factor test should be excluded by
definition. We note that the SDT has also developed a technical principal document that uses language
similar to the seven factor test. To use it, though, an entity must apply for exception first. We believe the
seven factors or technical principles should be part of the definition in order to avoid numerous exception
applications and resulting delays.

City of Anaheim

No

A functional test, similar to the seven factor test used for FERC Order 888, should be used to identify
transmission network facilities independent of voltage. All other electrical facilities not identified as
transmission network facilities should be deemed local distribution facilities, and should excluded from the
Bulk Electric System pursuant to the statutory Bulk Power System definition provided under federal law (18
CFR 39.1, Title 18, Chapter I, Subchapter B, Part 39)i.e. “facilities and control systems necessary for
operating an interconnected electric energy transmission network (or any portion thereof), and electric energy
from generating facilities needed to maintain transmission system reliability. The term does not include
facilities used in the local distribution of electric energy.” Please note that the statute does not reference any
voltage level, therefore both transmission network and local distribution facilities each can operate at voltages
higher or lower than 100 kV. The radial (E1) and local distribution network (E3)exclusions are a good starting
point under the definition, but the exception procedure should have a functional exception for local distribution
facilities independent of voltage level.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and

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distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV. In
addition, the SDT reviewed and considered the FERC 7-factor test and has included some concepts of that test in the LN portion of the draft BES definition.
However, the 7-factor test, in and of itself, has been cited by FERC as insufficient to prove a facility is distribution. The SDT has attempted to provide additional
tests that will hopefully pass FERC scrutiny.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

No

BGE votes “NO” due to the lack of clarity in exclusion E1.

Response: The SDT made significant revisions to Exclusion E1 and hopes that addresses the lack of clarity referred to in your comment.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:

a) Only servingserves Load. A normally open switching device between radial systems may operate in a ‘make-before-break’ fashion to allow for reliable
system reconfiguration to maintain continuity of electrical service. Or,

b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA
(gross nameplate rating). Or,

c) Is a combination of items (a.) and (b.) wWhere the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5. with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).

Note – A normally open switching device between radial systems, as depicted on prints or one-line diagrams for example, does not affect this
exclusion.
City of St. George

August 19, 2011

No

The way the definition is currently written it will include many entities with lines, generation and other facilities
whose only purpose is for the local generation and distribution of energy to local customers. The generation
restrictions and other language in the proposed definition will add additional registrations (i.e. TO/TOP) to
many smaller entities which will have a significant economic impact to those utilities with little or no benefit to

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the main bulk system. The problems may stem more from the “one size fits all” approach to the standards
requirements, with the TO/TOP requirements being the most onerous and difficult to comply with especially
for smaller entities. Allowed generation levels and the actual use of the transmission and generation facilities
should be considered in what is and is not included in the BES. As the proposed definition stands now along
with the current reliability standards a small utility with a few segments of 115 kV or 138 kV lines and with
some generation to serve local load must comply with the same requirements as a very large utility with
hundreds of miles of 345 kV or 500 kV lines and 1,000’s of MVA of generation. The use of applying small,
medium and large criteria to many of the standard requirements, similar to what is being considered for the
CIP standards with low, medium and high requirements should be considered.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV. The
SDT is focused solely on revisions to the BES definition, and changes to specific standards are outside the scope of this project.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Puget Sound Energy

No

The language on total aggregate load served by LDN should be added for the exclusion list.

Response: The SDT did not see a need to provide an aggregate Load limitation on any of the draft BES definition exclusions. No change made.
Southern California Edison
Company

No

SCE believes that the BES Definition, as currently proposed, relies too heavily on the characterization of
interconnected generation in its “Inclusion” criteria.

Response: The SDT made significant revisions to the draft BES definition, including changes to the inclusion and exclusion portions to address your concerns and
those of others.
GTC

No

Since distribution facilities are to be excluded can the drafting team clarify if the automatic interrupting
protective device (breaker or circuit switcher) operating at 100kV or above and protecting an excluded
transformer (non-BES) should be excluded with the excluded transformer? Perhaps an additional separate
exclusion could eliminate any uncertainty.

Response: The SDT removed the automatic interrupting device language from the draft BES definition.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of

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100 kV or higher from a single Transmission source originating with an automatic interruption device and:
New York State Dept of Public
Service

No

See comments under question 1.

Long Island Power Authority

No

We don’t believe the bright-line definition and specific inclusions and exclusions prevents distribution from
being considered as BES. It seems like the intent to exclude non bulk distribution systems would still be
included because of E3b. We don’t believe that the SDT has fully excluded local distribution facilities as
required by the FERC Order. Specifically E3b should be eliminated. The other remaining items a,c,d,e
adequately define the LDN.

Independent Electricity System
Operator

No

The existing definition and the associated inclusions and exclusions do not exclude local distribution facilities
because the 75 MVA limit on generation within LDNs in E3 (b) will result in portions of the power system that
are serving a distribution function being classified as BES. As stated before, we suggest subjecting the LDNs
to assessment to determine their impact on the BES and including them if impactive by using the Exception
Process.

Response: See response to Q1.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV. In
addition, item E3b) was revised to provide further clarity.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
E3b) Only includingincludes generation resources not identified in Inclusions I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA
(gross nameplate rating).
The Dow Chemical Company

August 19, 2011

No

The Dow Chemical Company (“Dow) is an international chemical and plastics manufacturing firm and a leader
in science and technology, providing chemical, plastic, and agricultural products and services to many
essential consumer markets throughout the world. Dow and certain of its worldwide affiliates and
subsidiaries, including Union Carbide Corporation, own and operate electrical facilities at a number of
industrial sites within the U.S., principally, in Texas and Louisiana. The electrical facilities at these various
industrial sites are configured similarly and perform similar functions. In most cases, a tie line or lines connect

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the industrial site to the electric transmission grid. Power is delivered from the electric transmission grid to the
industrial site through the tie line(s). Lines within the industrial site then deliver power to individual
manufacturing plants within the site. Additionally, cogeneration facilities are located at a number of industrial
sites owned by Dow and its subsidiaries. These cogeneration facilities generate power that is distributed
within the industrial site and used for manufacturing plant operations. In some instances, excess power not
required for plant operations is delivered back into the electric transmission grid through the tie line(s)
connecting the industrial site to the grid. Under all circumstances, electricity is not flowing into and out of such
industrial sites at the same time. While the tie lines and some of the internal lines at these industrial sites
operate at 100kV or higher, they do not perform anything that resembles a transmission function. Rather than
transmit power long distances from generation to load centers, the tie lines and internal lines perform primarily
a local distribution function consisting of the distribution of power brought in from the grid or generated
internally to different plants within each industrial site. In some cases, the facilities also perform an
interconnection function to the extent they enable power from cogeneration facilities to be delivered into the
grid. The voltage of the tie lines and internal lines at these industrial sites is dictated by the load and basic
configuration of each site. Higher voltage lines are used when necessary to meet applicable load
requirements or to reduce line losses. That does not mean that such lines perform a transmission function.
At some sites, Dow is registered as a Generation Owner and Generation Operator. At other sites, the
applicable Regional Entity has found that such registration is not required because of the relatively small
amount of power supplied to the grid from the applicable cogeneration resources, even though those
cogeneration resources have an aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating). Tie lines (to the grid) and internal lines at an industrial site that operate at 100kV or higher should be
excluded from the BES definition if, due to the relatively small amount of power supplied to the grid from the
generation resources at the site, the owner of those generation resources is not required to be registered as a
Generation Owner and the operator of those generation resources is not required to be registered as a
Generation Operator.At sites where the owner of the generation resources is registered as a Generation
Owner and the operator of those generation resources is registered as a Generation Operator, the internal
lines (between the generation resources and the manufacturing plants) that operate at 100kV or higher should
be excluded from the BES definition, because they are distribution and not transmission facilities. The lines
interconnecting the generation resources at such sites to the transmission grid should be included in the BES
definition, but the owner and operator of such interconnection lines should not be registered as a
Transmission Owner or Transmission Operator. In no instance has a Regional Entity determined that Dow or
any subsidiary should be registered as a Transmission Owner or Transmission Operator. Instead, such
interconnection lines should be considered as part of the generation resource and Generation Owners and
Generation Operators should be subject to reliability standards specifically developed for such interconnection
lines. Dow is strongly opposed to any BES definition that would result in either the tie lines or the internal lines
at industrial sites being subject to the mandatory reliability standards applicable to Transmission Owners and
Transmission Operators. Complying with reliability standards would cause Dow and its subsidiaries to incur

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substantial compliance costs and create potential exposure to penalties in the future for noncompliance.
Perhaps such costs and exposure could be justified if subjecting these facilities to compliance with reliability
standards resulted in a material increase in reliability of the BES, but there is no reason to believe that will be
the case. In fact, the opposite might be true. The tie lines and internal lines at industrial sites owned by Dow
and its subsidiaries have been operated for decades as distribution and interconnection facilities, and
practices and procedures have developed over the years that have enabled such operations to achieve a high
degree of reliability for such sites. Requiring these facilities to now operate in a different manner as
transmission facilities may well result in a degradation of the reliability of the manufacturing plants located at
such sites. For example, outages would have to be coordinated with the RTO, which may not be interested in
coordinating such outages with scheduled manufacturing plant outages.Dow recommends that a separate
exclusion be added to the BES definition to address industrial distribution facilities. Proposed exclusion E-3
for local distribution networks is not sufficient to ensure that all industrial distribution facilities are excluded.
For example, criteria b), entitled “Limits on connected generation” states that “Neither the LDN, nor its
underlying Elements (in aggregate), includes more than 75 MVA generation”. This criteria makes no sense for
an industrial site with on-site electricity generation and a number of manufacturing plants that has internal
power lines and lines interconnecting with the transmission grid that operate at 100 kV or higher where the
owner and operator of the on-site electricity generation facilities are not registered as a Generation Owner
and a Generation Operator because only a small amount of electricity is ever exported from the on-site
electricity generation facilities to the transmission grid. This criteria also makes no sense with respect to
internal electric lines (operated at 100 kV or higher) at such industrial sites even where the owner and
operator of the on-site electricity generation facilities are registered as a Generation Owner and a Generation
Operator.Criteria c) also causes proposed exclusion E-3 not to be sufficient to ensure that all industrial
distribution facilities are excluded where the owner and operator of the on-site electricity generation facilities
are not registered as a Generation Owner and a Generation Operator because only a small amount of
electricity is ever exported from the on-site electricity generation facilities to the transmission grid. Criteria c),
entitled “Power flows only into the LDN”, states: “The generation within the LDN shall not exceed the electric
Demand within the LDN.”
Criteria c) also makes no sense with respect to internal lines at such industrial sites even where the owner
and operator of the on-site electricity generation facilities are registered as a Generation Owner and a
Generation Operator.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV.
In addition, the SDT made extensive changes to Exclusion E3 to address your concerns and those of others.

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Organization

Yes or No

Question 11 Comment

Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting
devices;
E3a. Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3,
and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75
MVA generation;
E3b. Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The
LN does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
E3c. Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the
Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
Southwest Power Pool

No

See response to question 1 - SPP does not necessarily disagree with the characterization of excluded
distribution facilities, but believes that issue should be addressed in the concurrent BES exemption
proceeding for the reasons described in question 1. SPP reserves its rights to comment on the criteria for
exclusion/inclusion in that proceeding.

Response: The SDT believes it is appropriate to exclude Facilities used in the local distribution of electric energy in the BES definition.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Golden Spread Electric
Cooperative, Inc.

August 19, 2011

No

All load serving radials need to be excluded from the BES.

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Organization

Yes or No

Question 11 Comment

Response: The SDT believes that the draft BES definition excludes Load-serving radial systems as your comment recommends. No change made.
Tacoma Power

Tacoma Power supports the work of the SDT towards a revised BES definition directly linked to the
exemption process of inclusions and exclusions. The definition must be closely coupled to the exemption
process and the two must move forward together. This will ensure that only the facilities that materially
impact the reliability of the BES will be burdened with the regulatory requirements.

Response: The SDT is working closely with the Rules of Procedure team to ensure that the respective work products are appropriately linked and proceed
forward in a parallel manner.
Edison Electric Institute

See comments to Question 13.

Response: See response to Q13.
Portland General Electric
Company

As stated above, PGE believes that the Exclusion for Local DistributionNetwork needs to be more explicit.

Response: The SDT made significant clarifying changes to the LDN, now LN, exclusion of the draft BES definition to address your concerns and those of others.
E3 - Local Distribution Networks (LDN): A Ggroups of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute
power to Load rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from multiple points of connection at 100 kV or higher
are connected to the Bulk Electric System (BES) at more than one location solely to improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to the BES, the LDN must be connected through automatic fault-interrupting
devices;
E3a. Limits on connected generation: Neither tThe LDN, norand its underlying Elements do not include generation resources identified in Inclusion I3,
and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating) (in aggregate), includes more than 75
MVA generation;
E3b. Power flows only into the Local Distribution NetworkLN: The generation within the LDN shall not exceed the electric Demand within the LDN The
LN does not transfer energy originating outside the LN for delivery through the LN; and
Not used to transfer bulk power: The LDN is not used to transfer energy originating outside the LDN for delivery through the LDN; and
E3c. Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a monitored Facility of a permanent fFlowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable monitored Facility in the

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Organization

Yes or No

Question 11 Comment

Quebec Interconnection, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
SERC OC Standards Review
Group

Yes

Exception E4 potentially does have issues - see our response to Question 10.

Yes

Please refer to comments on question 9 - Exclusion 3

Yes

In general we believe that the bright line has been created. There should however be one additional
exclusion - Distribution Protection Systems designed specifically to protect Distribution System assets should
not be considered part of the BES, even if they open an element of the BES (ie; Distribution Breaker Failure
Relaying), as long as the action is to protect the Distribution System and not the BES.

Response: See response to Q10.
Colorado Springs Utilities
Response: See response to Q9.
Alliant Energy

Response: The SDT does not see a need to add the exclusion you requested since distribution protection systems that protect distribution systems are not
determined to be BES under the draft BES definition. No change made.
Illinois Municipal Electric Agency

Yes

Please see comments under Question 13.

Sacramento Municipal Utility
District (SMUD)

Yes

SMUD does agree that the differentiation is established between the transmission & distribution systems.
Although there is concern that the general “Bright-line” is not definitive and could afford additional value
through incorporating clarifying language.

Sierra Pacific Power Co d/b/a NV
Energy

Yes

Through the radial exclusion and the LDN exclusion (E1 and E3), the definition has made a delineation
between distribution and bulk transmission. In this exclusion language, the definition as proposed addresses
the quantifiable parameters from the FERC 7-factor transmission test.

American Transmission
Company, LLC

Yes

ATC agrees that the revised bright-line core definition and associated inclusion and exclusion criteria
excludes distribution, however, recognizes that there are protection elements that may be owned by
distribution which may trip a BES Element. (Covered by NERC Standard PRC-005)

Response: See response to Q13.

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Organization

Yes or No

Question 11 Comment

PUD No. 2 of Grant County,
Washington

Yes

Grant supports the concepts as presented in the draft. Exclusion of facilities from the BES does not mean
that owners of those facilities are entirely exempt from reliability standards. The statutes provide that “users”
of the BES can be subject to reliability regulation. Hence, even where an entity does not own BES assets, it
could be required to, for example, provide necessary information to the applicable Reliability Coordinator and
to participate in the regional Under-Frequency Load Shedding program by setting the UFLS relays in its Local
Distribution Network at the appropriate settings. We note that participants in the WECC BESDTF Task Force
generally agreed that appropriate information should be provided by non-BES entities, although there was
considerable concern related to ensuring that the provision of information was not unduly burdensome.

Glacier Electric Cooperative

Yes

I do believe that the language in its plain sense does exclude local distribution systems, but I do see the
possibility of differeing interpretations of the language across the regions again. Perhaps adding some
example system diagrams showing what would and would not be included in the BES would help alleviate
any possible ambiguity and increase consistency across the regions.

PacifiCorp

Yes

PacifiCorp understands that no single bright line can accommodate all the various scenarios of local
distribution. The proposed definition appears to capture a high percentage of LDNs. Additional LDNs can be
addressed through the exemption process. Also, please refer to additional comments in question 13 regarding
a contiguous BES.

Santee Cooper

Yes

The commission should remain open to future modifications of the bright-line core definition and specific
inclusion and exclusions.

BPA

Yes

Utility System Efficiencies, Inc.

Yes

Imperial Irrigation District

Yes

Florida Municipal Power Agency

Yes

NERC Staff Technical Review

Yes

MRO's NERC Standards Review
Forum

Yes

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Organization

Yes or No

SERC Planning Standards
Subcommittee

Yes

ACES Power Participating
Members

Yes

Arizona Public Service Company

Yes

Western Electricity Coordinating
Council

Yes

Transmission Access Policy
Study Group

Yes

Northern California Power
Agency

Yes

New York Power Authority

Yes

Southern Company

Yes

Luminant Energy

Yes

US Bureau of Reclamation

Yes

Sweeny Cogeneration LP

Yes

Dayton Power and Light
Company

Yes

Duke Energy

Yes

Alberta Electric System Operator

Yes

August 19, 2011

Question 11 Comment

NCPA supports the comments of the Transmission Access Policy Study Group in this regard.

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Organization

Yes or No

South Carolina Electric and Gas

Yes

Fayetteville Public Works
Commission

Yes

Florida Keys Electric Cooperative

Yes

American Electric Power

Yes

East Kentucky Power
Cooperative, Inc.

Yes

Farmington Electric Utility System

Yes

Muscatine Power and Water

Yes

Idaho Power

Yes

Cogentrix Energy, LLC

Yes

Clark Public Utilities

Yes

Oncor Electric Delivery Company
LLC

Yes

Manitoba Hydro

Yes

MEAG Power

Yes

Xcel Energy

Yes

Question 11 Comment

Response: Thank you for your support. Several stakeholders made suggestions for clarifying changes to the draft BES definition that were adopted to provide a
greater distinction between transmission and distribution facilities. Please see the revised definition.

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12. Are you aware of any conflicts between the proposed definition and any regulatory function, rule order,
tariff, rate schedule, legislative requirement or agreement, or jurisdictional issue? If so, please identify
them here and provide suggested language changes that may clarify the issue.

Summary Consideration: The task of the SDT is to put forward a 100 kV bright-line for the BES definition. The SDT has
modified the definition and distribution facilities are now specifically excluded from the BES. However, the SDT acknowledges
that there may still be regulatory conflicts as many of the commenters have voiced. The definition is neither intended to nor
can it supersede any regulatory orders and/or rulings by relevant Federal, State, or Provincial Authorities. Although the SDT can
not resolve all regulatory conflicts, it believes that a) proposed revisions to the definition should address many of these
concerns; and b) remaining issues may be effectively addressed by the Rules of Procedure exception procedure currently under
development.
Changes to the definition due to industry comments are as follows:
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real
Power and Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is
modified by the list shown below. This does not include facilities used in the local distribution of electric energy.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or
gross aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV
or above.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of
voltage.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of
connection of 100 kV or higher from a single Transmission source originating with an automatic interruption device and:
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.

Organization

Yes or No

AltaLink

Yes

East Kentucky Power
Cooperative, Inc.

Yes

August 19, 2011

Question 12 Comment

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Organization

Yes or No

Question 12 Comment

Response: Without any details the SDT is unable to respond.
BPA

Yes

The Low Voltage Ride Through standard is a U.S. industry standard via FERC Order 611A and applies to wind
generation without regard to size. The I2 definition appears to be in conflict with the LVRT set by Order 611A.
Request NERC clarification including when it will be issuing a LVRT reliability standard.
DGF supports Rebecca Berdahl Comment 2, as discussed below.

Response: Inclusion I2 has been modified by the SDT in the revised BES definition to address your concerns and those of others.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Northeast Power Coordinating
Council

Yes

The proposed definition will have a direct impact on entities not under FERC jurisdiction, and may be in
conflict with regulatory requirements with which those entities must comply.

Dominion

Yes

The inclusion of an element or facility that is not integral to the reliable operation of the integrated bulk power
system is in conflict with the intent of Section 215 of the FPA . This is especially true for radial facilities,
whether used to connect generators or load to the bulk power system.

Michigan Public Service
Commission(MPSC)

Yes

MPSC Staff Comments: The proposed BES definition creates friction with Order 888’s seven-factor technicalfunctional test as implemented by state regulatory agencies. The resulting inconsistent treatment is likely to
result in challenges by entities with FERC-defined distribution assets being now considered as transmission
assets as inconsistent with the FPA. FERC’s Order 888 discusses the two components of an unbundled
transaction in interstate commerce has “for jurisdictional purposes -- a transmission component and a local
distribution component.” p 439 The Order also states that the Commission “will defer to recommendations by
state regulatory authorities concerning where to draw the jurisdictional line under FERC’s technical test for
local distribution facilities” p 437, also known as the seven-factor technical-functional test. This test was
applied by Michigan utilities, filed with the Michigan Public Service Commission in contested case-specific
dockets, and after deliberation approved. These state-approved jurisdictional bright-line determinations were
subsequently filed with and approved by FERC.

Hydro-Quebec TransEnergie

Yes

There appears to be a conflict between the proposed definition and the regulatory framework applicable in
Quebec or at least there are some important differences between both.NERC's proposed definition of Bulk
Electric System (“BES”) is made in response to FERC's Order 743. FERC is looking to remove regional
discretion, and in some cases to make sure BES includes the most important national load centers.As for

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Organization

Yes or No

Question 12 Comment
HQT's System, the BES definition shall meet the expectations of Quebec's regulator, the Régie de
l'Énergie du Québec, (Quebec Energy Board) which has the responsibility to ensure that electric power
transmission in Québec is carried out according to the reliability standards it adopts. In a recent order (D2011-068), the Régie de l'Énergie du Québec has recognized several level of application for the
Reliability Standards in Québec. It stated specifically that most reliability standards in Québec shall be
applied to the Main Transmission System (MTS). One other level of application recognised by this decision is
the NPCC Bulk Power System (BPS) to which the standards related to the protection system (PRC-004-1 and
PRC-005-1) and those related to the design of the transmission system (TPL 001-0 to TPL-004-0) will be
applicable. The Main Transmission System definition is somewhat different than the Bulk Electric System
definition. The Main Transmission System includes elements that impact the reliability of the grid, supplydemand balance and interchanges. It can be described as follows :The transmission system comprised of
equipments and lines generally carrying large quantities of energy and of generating facilities of 50 MVA or
more controlling reliability parameters: o Generation/load balancing o Frequency control o Level of
operating reserves o Voltage control of the system and tie lines o Power flows within operating limits o
Coordination and monitoring of interchange transactions o Monitoring of special protection systems o
System restorationTherefore, it will be necessary to accommodate NERC's proposed definition of BES or the
exception process with the Québec situation where Entities are under a different jurisdiction. These
differences include more than one level of application for the reliability standards, the Main Transmission
System definition being the main one to which most reliability standards apply.

Hydro One Networks Inc

Public Utility District No. 1 of

August 19, 2011

See earlier comments and suggestions. NERC’s revised definition will have a direct impact on many entities
across North America and could also be in conflict with regulatory requirements, Codes, and Licenses, which
non FERC jurisdictional must comply. It would be hard if not impossible to identify the conflicts. For example:
in one of the the provincial energy acts, NERC Standards maycan only apply to generation over 50 MVA
which will cause one or more of the requirements to be in conflict and /or what constitutes distribution and
what is not considered transmission (such as connection facility to a load or generation and owned by the
proponent). However, we agree to establish a 100kV BES bright-line definition and we believe that the best
venue to address avoiding compliance conflicts is through the exception criteria and the exception procedure.
The benefits of such an approach are: o Establishment of a continent wide bright line definition o
Avoidance of regulatory conflicts and legal complexities o Assurance of the reliability of the interconnected
transmission network

Yes

As noted in our responses to Question 1 and Question 11, we believe the SDT proposal is potentially in
conflict with the limitations of the Federal Power Act, and in particular the statutory exclusion for facilities used

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Organization

Yes or No

Question 12 Comment

Snohomish County, Washington

in the local distribution of electric energy. Unless the SDT adopts some approach other than a core definition
with inclusions and exclusions based on brightline thresholds, the SDT’s approach can meet the statutory
requirements only if the Exception process currently under development results in facilities that are not
properly classified as BES being exempted from regulation as BES facilities.

Blachly Lane Electric Cooperative

As discussed in our answers to Question 1 and Question 11, the SDT proposal does not reflect the
jurisdictional limitations of the FPA.

Central Electric Cooperative
Clearwater Power Company
Consumers Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Inc
Okanogan Electric Cooperative
PNGC Power
Raft River Rural Electric
Cooperative
Salmon River Electric
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Northern Wasco County PUD
Clallam County PUD No.1

August 19, 2011

Yes

The Exceptions process is a necessary part of making this proposal complaint with the Federal Power Act. As
noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is potentially in
conflict with the limitations of the Federal Power Act, and in particular the statutory exclusion for facilities used
in the local distribution of electric energy. The SDT’s approach can meet the statutory requirements only if

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Organization

Yes or No

Chelan PUD – CHPD

Question 12 Comment
the Exception process currently under development results in facilities that are not properly classified as BES
being exempted from regulation as BES facilities.

Kootenai Electric Cooperative
Public Utility District No. 1 of
Franklin County
Midstate Electric Cooperative
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc
PUD No. 2 of Grant County,
Washington

Yes

The Exceptions process is a necessary part of making this proposal complaint with the Federal Power Act.
The SDT’s approach can meet the statutory requirements only if the Exception process currently under
development results in facilities that are not properly classified as BES being exempted from regulation as
BES facilities.

ExxonMobil Research and
Engineering

Yes

Section 215 of the Federal Power Act excludes facilities used in the local distribution of electric energy without
any qualifications of the type of local distribution facility.

FortisBC

Yes

See earlier comments and suggestions. NERC’s revised definition will have a direct impact on many entities
across North America and could also be in conflict with regulatory requirements, Codes, and Licenses, which
non FERC jurisdictional must comply. It would be impossible to identify each of these conflicts. For example:
in one of the energy acts, NERC Standards can only apply to generation over 50 MVA which will cause one or
more of the requirements to be in conflict and /or what constitutes distribution and what is not considered
transmission (such as connection facility to a load or generation and owned by the proponent).However, we
agree to establish a 100kV BES bright-line definition and we believe that the best venue to address avoiding
compliance conflicts is through the exception criteria and the exception process. The benefits of such an
approach are:
o Establishment of a continent wide bright line definition
o Avoidance of regulatory
conflicts and legal complexities
o Assurance of the reliability of the interconnected transmission network

Consumers Energy Company

Yes

The proposed definition creates a tension between FERC Order 888 and the resulting 7-factor test as applied
for tariff purposes, and the registry criteria for registration of Transmission Owners and Transmission
Operators. Entities with assets defined by FERC as Distribution might challenge any rules that treat
Distribution assets as Transmission as not being consistent with the Federal Power Act of 2005.

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Organization

Yes or No

Question 12 Comment

Exelon

Yes

To the extent facilities used in local distribution of electric energy may be included in the definition of BES, the
proposed definition is in conflict with the Federal Power Act.

Springfield Utility Board

Yes

The exceptions process is a necessary part of making this proposal compliant with the Federal Power Act. As
noted in responses to Questions 1 and 11, SUB believes the basic SDT proposal is potentially in conflict with
the limitations of the Federal Power Act, and in particular the statutory exclusion for facilities used in the local
distribution of electric energy. The SDT’s approach can meet the statutory requirements only if the Exception
process currently under development results in facilities that are not properly classified as BES being
exempted from regulation as BES facilities.

New York State Dept of Public
Service

Yes

As expressed in comments under question 1, we believe that use of a 100 kV brightline definition is an
overreach of authority and that any definition must respect the limitations itemized in FPA 215. The FPA
recognizes that only a subset of the electric system facilities have the capacity to impact multi-state portions
of the electric system and rise to the level of federal attention. As a practical matter, however, the electric
system is a continuous machine and efforts to maintain reliability on both the transmission and local
distribution portions of the electric system must be compatible. That is the key role that the regional entities
play and that role should be maintained and respected by NERC efforts. The time and effort it takes to draft
standards to address issues on the bulk system is directly attributable to the many different options to design
and operate transmission facilities, and options to ensure reliability are different for each design and mode of
operation. Multiply that a hundred fold to the different approaches there are to design, operate and to ensure
reliability on the local distribution system. Attempts at the federal level to design uniform standards to apply at
lower and lower levels of the system are doomed to failure given the nuances of each local system. These
attempts will only lead to needless complications and the actual undermining of the reliability on the local
distribution system. NERC staff comments seeking to sweep into NERC standards behind the meter
generation, meters and relays located deep within the distribution system, etc. and then insist that the bulk
system be contiguous is a phenomenal overreach and an intrusion on the design and functioning of the
distribution system which will a) complicate efforts to maintain a reliable distribution system; and 2) will
needlessly incur costs on ratepayers. NERC needs to stay focused on the authorities extended to it in the
FPA. Leave it to the regions to interface locally with utilities, state authorities and other stakeholders to shape
seamless reliability protocols that will benefit us all.The question asks if there are orders that relate to this
effort. In 1997, the New York Public Service Commission held a proceeding Case No. 97-E-0251 that
supplemented the FERC Seven Factor Test with three additional factors to be used in New York to distinguish
between transmission and local distribution. This order can be found at the following
link:http://documents.dps.state.ny.us/public/Common/ViewDoc.aspx?DocRefId={3C7602E0-62E0-4831-82B68C34A72934F4}

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Organization

Yes or No

Question 12 Comment

Midstate Electric
CooperativePublic Utilities
Commission of Ohio

Yes

See concerns above with exceeding authority under the Federal Power Act Section 215. State Utility
Commissions are charged with assuring safe, reliable service to their customers. We are in a much better
situated position than FERC or NERC to provide any necessary regulation and oversight of the local
distribution system.

The Dow Chemical Company

Yes

Comments: Section 215 of the Federal Power Act denies FERC jurisdiction over facilities used in the local
distribution of electric energy. FERC has recognized that since facilities used in the local distribution of
electric energy “are exempted from the Bulk-Power System, they also are excluded from the bulk electric
system.” Section 215 of the Federal Power Act does not qualify the exclusion from FERC jurisdiction of
“facilities used in the local distribution of electric energy.” For example, Section 215 does not state that:
The term “bulk power system” “does not include facilities used in the local distribution of electric energy
[unless needed for reliability purposes];” or  The term “bulk power system” “does not include facilities [with
automatic interruption devices] used in the local distribution of electric energy.”Any definition of the bulk
electric system that does not exclude all “facilities used in the local distribution of electric energy” is
unlawful.Further, the definition of the bulk electric system must recognize that Section 215 of the Federal
Power Act does not allow the potential reliability impact of a facility to determine whether the facility is local
distribution or transmission. By excluding all facilities used in the local distribution of electric energy from the
definition of the Bulk-Power System in Section 215, Congress recognized that while facilities used in the local
distribution of electric energy may be part of the Bulk-Power System, they are, nonetheless, not FERC
jurisdictional. Thus, “facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof)” that are used in the local distribution of electric energy are not
FERC jurisdictional regardless of the potential reliability impact of the facilities.

Central Lincoln

Yes

Improper classification of local distribution facilities, even if only for the duration of the exceptions process;
puts these facilities under the regulatory jurisdiction of NERC contrary to the Federal Power Act when they
should be under the exclusive jurisdiction of state utility commissions or local utility boards.

Cowlitz County PUD

Yes

The Exceptions process is a necessary part of making this proposal complaint with the Federal Power Act. As
noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is potentially in
conflict with the limitations of the Federal Power Act, and in particular the statutory exclusion for facilities used
in the local distribution of electric energy. The SDT’s approach can meet the statutory requirements only if
the Exception process currently under development results in facilities that are not properly classified as BES
being exempted from regulation as BES facilities. Cowlitz understands the difficulty in demonstrating what is
and is not distribution to FERC due to the vague statute language. Cowlitz will work to help provide technical
arguments which will buttress the BES definition in the future.

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Organization

Yes or No

Question 12 Comment

Response: The definition is neither intended to nor can it supersede any regulatory orders and/or rulings by relevant Federal, State, or Provincial Authorities.
Although the SDT can not resolve all regulatory conflicts, it believes that a) proposed revisions to the definition should address many of these concerns; and b)
remaining issues may be effectively addressed by the Rules of Procedure exception procedure currently under development. Specifically, the SDT added a
sentence to the core definition to address concerns about local distribution.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
SPP Standards Review Group

Yes

See our responses to Questions 5 and 11 regarding the issue of distribution facilities and Cranking Paths.

Response: See responses to Q5 and Q11.
Idaho Falls Power

Yes

It is unclear how the reliability standards will be applied to registered entities should some assets be deemed
not to be a part of the BES. As an example; will a an LSE with >25MW of load connected at 161kv be
responsible for relay maintenance under PRC-005-1 if the 161 kv is exempted as a local distribution network?
Clarification of this issue may be beyond the scope of the BES definition effort, however guidance in this area
should accompany this effort.

Response: The application of Reliability Standards is not based solely on registration or an Element being classified as BES or not. There are several standards
that are currently mandatory for Elements that are non-BES and they will continue to apply if those Elements are considered necessary for the operation of BES,
such as UFLS. No change made.
Alabama Public Service
Commission

Yes

See comments in response to Question 11 above.

Yes

The Exceptions process is a necessary part of making this proposal complaint with the Federal Power Act. As
noted in our responses to Question 1 and Question 11, we believe the basic SDT proposal is potentially in
conflict with the limitations of the Federal Power Act, and in particular the statutory exclusion for facilities used
in the local distribution of electric energy. The SDT’s approach can meet the statutory requirements only if
the Exception process currently under development results in facilities that are not properly classified as BES
being exempted from regulation as BES facilities.

Response: See response to Q11.
Western Montana Electric
Generating and Transmission
Cooperative

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Organization

Yes or No

Question 12 Comment

Electricity Consumers Resource
Council (ELCON)

Yes

See response to question 11 above. The definition of “local distribution” should be as defined and practiced
in each state (US only) under state laws and regulations, and similarly by the Canadian provincial
governments.

MRO's NERC Standards Review
Forum

Yes

Within the Commission’s definition of BPS, it is clearly stated that BPS does not include facilities used in the
local distribution of electrical energy.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
PacifiCorp

Yes

The SDT proposal combined with the ROP may be in conflict with Section 215 of the Federal Power Act
(“FPA”) which excludes “facilities used in the local distribution of electric energy” from the definition of “bulkpower system.”
As identified in other responses, without a technical reason for setting the generation limit to 20 MVA and
even 75 MVA and/or requiring a contiguous BES to include such generators may be over-inclusive and by
default require several elements which are not required for the reliable operation of the BES to be included in
the BES definition.

Response: The definition is neither intended to nor can it supersede any regulatory orders and/or rulings by relevant Federal, State, or Provincial Authorities.
Although the SDT can not resolve all regulatory conflicts, it believes that a) proposed revisions to the definition should address many of these concerns; and b)
remaining issues may be effectively addressed by the Rules of Procedure exception procedure currently under development.
The SDT did not adopt a “contiguous” BES. After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo
any attempt at changing generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule.
Therefore, the primary focus of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will
be dropped. Both the NERC Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach
to this project with a new Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT
deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.

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Organization
Grand Haven Board of Light and
Power

Yes or No

Question 12 Comment

Yes

This current definition does not comply with FERC Order No. 743 (and 743a) by not addressing the exclusion
of a single automatic interrupting device that serves a radial, load serving system.

Response: The SDT revised Exclusion E1 to address your concern and those of others.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
National Grid

Yes

There could be some conflicts with the ISO-NE Pool Transmission Facility (PTF) definition. If something is
considered non-PTF, but is considered BES with this new definition, it could lead to confusion about which
criteria should be applied to these entities and potentially which tariff (non-PTF or PTF) is truly the correct
tariff. We believe adding more clarity as previously mentioned in the other questions to the definition and
excluding I4 and clarifying E1 will minimize these issues.

Response: The task of SDT is to put forward a 100 kV bright-line definition for BES. The SDT acknowledges that there may be regulatory conflicts but believes
that many of these concerns may be addressed by the revised BES definition and exception procedure currently under development. SDT has made some changes
to Inclusion I4 (now Inclusion I3) and Exclusion E1 that may address your concerns.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
Electric Reliability Council of
Texas, Inc.

Yes

See response to question 1 - ERCOT ISO believes defining BES in terms of the relevant exclusions may be
contrary to FERC’s suggested approach in 743 and 743-A. While FERC did not mandate a particular
approach, and gave the ERO the opportunity to propose an alternative to its suggested approach, it stated
that any alternative must be equal to or greater than its suggested approach in terms of remedying the
identified flaws associated with the current definition. Part of the remedy envisioned by FERC included the
removal of subjectivity in defining BES and the ability of the ERO and FERC to review any proposed
exemptions from the bright line definition. Although the exclusions strive to apply objective criteria, it is
arguable that any such circumstances may not be that clear and may require some level of subjective
judgment as to whether elements deemed to be distribution according to the exclusion criteria actually are
distribution, as opposed to transmission. In addition, FERC expressly stated that it reserved the right to make
that determination in the first instance. This approach takes that away from FERC.

Southwest Power Pool

Yes

See SPP's response to question 1 - SPP believes defining BES in terms of the relevant exclusions may be
contrary to FERC’s suggested approach in 743 and 743-A. While FERC did not mandate a particular

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Organization

Yes or No

Question 12 Comment
approach, and gave the ERO the opportunity to propose an alternative to its suggested approach, it stated
that any alternative must be equal to or greater than its suggested approach in terms of remedying the
identified flaws associated with the current definition. Part of the remedy envisioned by FERC included the
removal of subjectivity in defining BES and the ability of the ERO and FERC to review any proposed
exemptions from the bright line definition. Although the exclusions strive to apply objective criteria, it is
arguable that any such circumstances may not be that clear and may require some level of subjective
judgment as to whether elements deemed to be distribution according to the exclusion criteria actually are
distribution, as opposed to transmission. In addition, FERC expressly stated that it reserved the right to make
that determination in the first instance. This approach takes that away from FERC.

Alberta Electric System Operator

Yes

Comments: Alberta’s legislation enables reliability standards, but prevents the AESO from developing rules
related to reliability standards. The AESO therefore would like to see retention of the following clause from the
NERC “Statement of Compliance Registry Criteria (revision 5) included in the list of inclusions as well as
identifying the authority that determines what generators are material to reliability:III.c.4 Any generator,
regardless of size, that is material to the reliability of the bulk power system. The wording should reflect that,
for example, in the case of Alberta, that the AESO has the authority to make this determination.

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV. The
definition is neither intended to nor can it supersede any regulatory orders and/or rulings by relevant Federal, State, or Provincial Authorities. Although the SDT
can not resolve all regulatory conflicts, it believes that a) proposed revisions to the definition should address many of these concerns; and b) remaining issues
may be effectively addressed by the Rules of Procedure exception procedure currently under development.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

August 19, 2011

Yes

The proposed definition conflicts with Section 215 of the FPA and case law because it ignores years of
precedent regarding what constitutes “facilities used in local distribution” and defines the BES in such a way
as to possibly cover local distribution facilities as well as transmission facilities. Specifically, FERC has
jurisdiction over “all users, owners and operators of the bulk-power system” under Section 215 of the FPA (16
U.S.C. § 824o(b)(1)). The bulk-power system is defined as:”(A) facilities and control systems necessary for
operating an interconnected electric energy transmission network (or any portion thereof); and (B) electric
energy from generation facilities needed to maintain transmission system reliability. The term does not
include facilities used in the local distribution of electric energy” (Id. at § 824o(a)(1)).By the plain language of
Section 215 of the FPA, FERC’s jurisdiction over the Bulk Power System cannot include any “facilities used in

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Organization

Yes or No

Question 12 Comment
the local distribution of electric energy.” FERC has recognized that “[s]ince such facilities are exempted from
the Bulk-Power System, they also are excluded from the bulk electric system” (Order No. 743-A at P 25).
Congress specifically recognized that while facilities used in the local distribution of electric energy may be
part of the Bulk-Power System, they are not FERC jurisdictional. Thus, “facilities and control systems
necessary for operating an interconnected electric energy transmission network (or any portion thereof)” that
are used in the local distribution of electric energy are not jurisdictional regardless of the potential reliability
impact of the facilities. The proposed definition of the BES would rewrite Section 215 of the FPA to exclude
only “facilities used in local distribution of electric energy [unless needed for reliability purposes].” As the DC
Court of Appeals stated in Detroit Edison Co. v. FERC: “[s]uch an interpretation would eviscerate state
jurisdiction over numerous local facilities, in direct contravention of Congress’ intent” (Detroit Edison Co. v.
FERC, 334 F.3d 48, 54 (U.S. App. D.C. 2003) (citation omitted)). In Detroit Edison Co. v. FERC, the DC
Court of Appeals rejected FERC’s proposed definition of a “FERC-jurisdictional distribution facility” as any
distribution facility that is not “used exclusively to provide service to unbundled retail customers” (Id.). The
Court stated: “FERC’s position contradicts the plain language of the FPA,” and further that “FERC would
rewrite the statute to exclude only ‘facilities used exclusively in local distribution’” (Id.). The exclusion of
facilities used in the local distribution of electric energy from the definition of the BES does not mean that
NERC lacks the ability to maintain the reliability of the BES. For example, if NERC determined that a retail
customer’s self-provided “hard-tapped” radial line that is located behind the retail delivery point created a
reliability issue, NERC could require that the transmission facilities be equipped with automatic faultinterruption devices. NERC could not, however, define the BES to include such local distribution facilities,
which is the result of the proposed bright-line core definition and specific inclusions and exclusions.While
FERC “granted NERC discretion” in developing the revised definition of the BES because FERC wanted to
give NERC “the greatest amount of flexibility to utilize its technical expertise” (Order No. 743-A at PP 0-71),
NERC’s discretion is not unbounded. Moreover, while FERC stated that it “will evaluate whether the [BES
definition] proposal results in any conflicts with the statutory language” (Id. at P 72), it is imperative that NERC
work within the statutory limitations of Section 215 of the FPA as to prevent submitting a proposal to FERC
that is fundamentally unlawful. It would be a colossal waste of government and industry resources to develop
and advance a definition that cannot withstand basic legal review. As provided above, the following are
suggested language changes that may clarify the issue:Exclusion E1 - Any radial system which is described
as connected from a single Transmission source [ ] and: a) Only serving Load. [ ] Or, b) Only including
generation resources not identified in Inclusions I2, I3, I4 and I5. Or, c) Is a combination of items (a.) and (b.)
where the radial system serves Load and includes generation resources not identified in Inclusions I2, I3, I4
and I5. Exclusion E3 - [All facilities used in the distribution of electric energy] ([“]Local [D]istribution
[N]etworks,[“ or “]LDNs[“]): Groups of Elements operated above 100 kV that distribute power to Load rather
than transfer bulk power across the interconnected System. LDN[]s are [normally] connected to the Bulk
Electric System (BES) at more than one location solely to improve the level of service to retail customer Load.
The LDN is characterized by all of the following:a) [ ]b) Limits on connected generation: [Generally], neither

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Organization

Yes or No

Question 12 Comment
the LDN, nor its underlying Elements (in aggregate), includes more than 75 MVA generation;c) Power flows
only into the LDN: The generation within the LDN [normally does] [ ] not exceed the electric Demand within
the LDN;d) Not used to transfer bulk power: The LDN is [generally] not used to transfer energy originating
outside the LDN for delivery through the LDN; ande) Not part of a Flowgate or transfer path: The LDN
normally does not contain a monitored Facility of a permanent flowgate in the Eastern Interconnection, a
major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable
monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).Exclusion E4 - Transmission Elements, from a single
Transmission source connected at a voltage of 100 kV or greater [ ] whose connection to the BES is solely
through this single Transmission source, and without interconnected generation as recognized in the BES
Designation Inclusion Items I2, I3, I4, or I5. [ ]

Response: The SDT made a number of clarifying changes to the draft BES definition that it believes provides a greater distinction between transmission and
distribution facilities. The SDT also included in the definition a statement that excludes facilities used in local distribution of electric energy. The SDT believes
that revised Exclusions E1 (radial exclusion) and E3 (Local Network exclusion) provide appropriate opportunity to exclude distribution facilities above 100 kV.
Muscatine Power and Water

Yes

Within FERC’s definition of Bulk Power System, it is plainly stated that BPS does not include facilities used in
the local distribution of electrical energy. Does this support or contradict the SDT's concept of Local
Distribution Network?

Response: The LDN (now referred to as LN) is a unique case due to the multiple connections to the BES and as such the SDT believes it deserves a specific
exclusion but it supports the SDT’s concept.
Southern California Edison
Company

Yes

For participants in an ISO/RTO, such as the CAISO, the final BES Definition may change the party who will
control system facilities, even if they are distribution or radial in nature, based on the amount or size of
interconnected generation. Generally, within the CAISO, facilities that are included in the BES Definition are
under CAISO’s direct control, while radial and distribution facilities are not.

Response: Control of system facilities is not within the scope of the SDT and must be worked out locally.
Clark Public Utilities

August 19, 2011

Yes

The BES Definition does not have any reference to the exception process being developed. Both the
exclusion and inclusion sections of the BES Definition should have a reference to the process where “BES
Definition included” Transmission Elements may be excluded and “BES Definition excluded” Transmission
Elements may be included.

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Organization

Yes or No

Question 12 Comment

Response: The reference to the exception process was inadvertently left off the posting.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.
New England States Committee
on Electricity

Yes

A possible conflict exists with respect to state renewable resource objectives. Please refer to number 4
above regarding renewable energy objectives, which includes state legislation regarding renewable portfolio
standards.

Response: The task of SDT is to put forward a 100 kV bright-line definition for BES. The definition is neither intended to nor can it supersede any regulatory
orders and/or rulings by relevant Federal, State, or Provincial Authorities. Although the SDT can not resolve all regulatory conflicts, it believes that a) proposed
revisions to the definition should address many of these concerns; and b) remaining issues may be effectively addressed by the Rules of Procedure exception
procedure currently under development.
PPL Energy Plus and PPL
Generation

Yes

Edison Electric Institute

See comments in Question 13.

See comments to Question 13.

Response: See response to Q13.
Manitoba Hydro

Yes

Canadian Entities are not under FERC jurisdiction, so the revised BES Definition may not apply. A number of
Canadian Entities have the BES defined within their provincial legislation. This may introduce differences and
even contradictions between elements that are included in the BES according to provincial legislation and the
NERC definition.

Response: The definition is neither intended to nor can it supersede any regulatory orders and/or rulings by relevant Federal, State, or Provincial Authorities.
Although the SDT can not resolve all regulatory conflicts, it believes that a) proposed revisions to the definition should address many of these concerns; and b)
remaining issues may be effectively addressed by the Rules of Procedure exception procedure currently under development. Regional difference (vs. regional
discretion), under the purview of the ERO, is acceptable methodology that will be consistently applied as a result of the definition and exception process.
ISO New England, Inc.

August 19, 2011

Yes

The proposal to include all Blackstart units’ cranking paths has the potential to roll into the BES facilities
distribution level circuits. Inclusion of those circuits would appear to conflict with statutory exclusion of set out
in Section 215(a)(1) of the Federal Power Act, which states that the term “bulk power system”: “does not
include facilities used in the local distribution of electric energy.” Section 215 sets the limits on what may be
included within the bulk electric system, and thus subject to regulation by the ERO and FERC under the

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Organization

Yes or No

Question 12 Comment
reliability standards regime.

Response: The SDT has eliminated Cranking Path from the definition.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of voltage.
Consolidated Edison Co. of NY,
Inc.

Yes

As FERC stated in Order 743-A “... the Commission uses the term “exclusion” herein when discussing
facilities expressly excluded by the statute (i.e., local distribution) and the term “exemption” when referring to
the exemption process NERC will develop for use with facilities other than local distribution that may be
exempted from compliance with the mandatory Reliability Standards for other reasons.” (Footnote
82)Thereby, the Commission clearly established its preferred terminology; “exclusion” for local distribution
and “exemption” for exceptions allowed under the NERC designations and Exception Process. The BES
Definition and Designations do not fully utilize this FERC wording convention.

Response: The SDT and the corresponding Rules of Procedure team have created a set of terminology that is consistent across the two projects and in line with
what they believe is the intent of FERC. No change made.
Modern Electric Water Company

Yes

Exclusion E1 and WECC Compliance Bulletin #4 (April 15, 2011) conflict. We support the intent of E1 and
have provided suggested language modifications to it in Question #7 herein.Link http://compliance.wecc.biz/Documents/2%20-%20WECC%20-%20Compliance%20Bulletins/01.04%20%20Compliance%20Bulletin%20-%204%20Interpretation%20PRC-004,%20PRC-005%20%20April%2015,%202011.pdf

Response: Exclusion E1 has been modified under the revised BES definition to address your concerns and those of others.
E1 - Any rRadial systems: which is described as connected A group of contiguous transmission Elements emanating from a single point of connection of
100 kV or higher from a single Transmission source originating with an automatic interruption device and:
American Municipal Power and
Members

No

In Ohio, 50 MW is the threshold for siting. Although 20 MW has recently been the criteria for the BES, if there
is no technical justification (a study of some kind) then we highly recommend raising the threshold for
generators to 50 MVA for a single unit. In our experience, registered generators, even those that have had
severe violations, have been routinely classified as not having an impact on the BES in the enforcement
process. Due to this truth, we can not understand the justification for keeping such a low threshold. We
suggest raising the threshold to 50 MVA for single units, unless a technical study justifies inclusion.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus

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Organization

Yes or No

Question 12 Comment

of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Tacoma Power

Tacoma Power is not aware of any conflicts at this time.

Independent Electricity System
Operator

No

At this point, we are not aware of conflicts for our own jurisdiction. However, NERC must exercise caution
while developing the exception criteria and the associated processes as these may result in jurisdictional
issues between state/provincial and federal entities. We repeat our earlier point that the BES definition and
TPC must be developed and approved simultaneously to provide assurances that mechanisms are in place to
exclude those Facilities from BES classification that are not impactive on the BES.

BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

No

We are not currently aware of any conflict, but have not had a chance to thoroughly consider the potential
conflicts.

American Electric Power

No

AEP is not aware of any conflicts involving the proposed definition and any regulatory function, rule order,
tariff, rate schedule, legislative requirement or agreement, or jurisdictional issue.

City of Redding

No

Illinois Municipal Electric Agency

No

Tri-State Generation and
Transmission Association, Inc.

No

Imperial Irrigation District

No

Florida Municipal Power Agency

No

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Organization

Yes or No

NERC Staff Technical Review

No

SERC Planning Standards
Subcommittee

No

ACES Power Participating
Members

No

SERC OC Standards Review
Group

No

Overton Power District No. 5

No

Tennessee Valley Authority

No

Arizona Public Service Company

No

Western Electricity Coordinating
Council

No

ReliabilityFirst

No

Rayburn Country Electric
Cooperative, Inc.

No

New York Power Authority

No

Southern Company

No

Luminant Energy

No

Central Maine Power Company

No

New York State Electric & Gas

No

August 19, 2011

Question 12 Comment

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Organization

Yes or No

Question 12 Comment

and Rochester Gas & Electric
Western Area Power
Administration

No

Intellibind

No

US Bureau of Reclamation

No

Glacier Electric Cooperative

No

FHEC

No

Vermont Transco

No

South Texas Electric
Cooperative, Inc.

No

South Texas Electric
Cooperative, Inc.

No

Sweeny Cogeneration LP

No

Dayton Power and Light
Company

No

Duke Energy

No

South Carolina Electric and Gas

No

Fayetteville Public Works
Commission

No

MidAmerican Energy Company

No

August 19, 2011

No Comment

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Organization

Yes or No

Florida Keys Electric Cooperative

No

American Transmission
Company, LLC

No

Farmington Electric Utility System

No

Sierra Pacific Power Co d/b/a NV
Energy

No

Colorado Springs Utilities

No

Sacramento Municipal Utility
District (SMUD)

No

City of St. George

No

Puget Sound Energy

No

GTC

No

Idaho Power

No

Long Island Power Authority

No

Cogentrix Energy, LLC

No

PJM

No

Oncor Electric Delivery Company
LLC

No

City of Anaheim

No

August 19, 2011

Question 12 Comment

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Organization

Yes or No

MEAG Power

No

Xcel Energy

No

Golden Spread Electric
Cooperative, Inc.

No

Michgan Public Power Agency

No

Utility System Efficiencies, Inc.

No

Question 12 Comment

Response: Thank you for your response.

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13.Are there any other concerns with this definition that haven’t been covered in previous questions and
comments?

Summary Consideration: Comments received for Question 13 were mostly re-statements of comments expressed in the
previous question. No changes were made to the core definition or Inclusions or Exclusions based solely on question 13
comments. However, changes were made to the Implementation Plan to clarify the effective date of the revised definition.

Organization
Northeast Power Coordinating
Council

Yes or No

Question 13 Comment
Currently, the posted exception criterion is only a concept with many gaps and TBD, as posted details are
later to follow. The exception criteria should be a menu of technical items (load flows, stability analysis etc)
and non technical items (type of loads such as distribution companies versus major city center, national
security, etc). Entities should be required to assess and provide their own justification under each category
with a conclusion that takes into account all of the relevant items for element(s) under exception, in a
consistent template and table of contents. Suggest the SDT to avoid specification of any parameters as they
would differ under different design concepts, system configurations, system characteristics and regulatory
requirements.The comments herein reflect thoughts on the document posted. An “all encompassing”
comment is that the definition is too lengthy. The importance of the BES definition is recognized throughout
the industry for its importance, and as such it should be simple, clear, and straightforward. The first draft
definition posted was more along this line. I2, I3, and I5, being very similar, can they be combined into an
encompassing generator inclusion criteria?

Response: Comments concerning the Technical Principles (Exception Criteria) associated with the RoP Exception Process will be addressed through the dedicated
responses developed by the SDT and published in the specific Consideration of Comments document associated with that portion of the overall project.
The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the language and to provide as much certainty as possible in the
identification of Bulk Electric System (BES) and non-BES Elements. Although the clarifications added to the core definition and the inclusions and exclusions have
lengthened the definition as a whole, the SDT feels that the improvements in clarity and the increased ability to apply the definition to achieve consistent results
justify the overall length of the definition.
After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing generation
thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC Board of
Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new Standards

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Yes or No

Question 13 Comment

Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
Tri-State Generation and
Transmission Association, Inc.

We believe that this definition is not consistent with the response from the SPCS in Project 2009-17,
“Interpretation of PRC-004-1 and PRC-005-1 for Y-W Electric and Tri-State” and could change its intent.
Existing tapped distribution transformers are clearly not BES Elements at this time. Under the proposed
definition that clarity is lost.There are instances where “automatic interruption device” or “automatic
interrupting device” is used. Each should be changed to include “fault” after “automatic.”

Response: The Interpretation speaks to which Protection Systems are applicable to the PRC Standards, not which Elements are BES or non-BES. The SDT
believes that the bright-line established by the draft BES definition is not necessarily the same bright-line that should be utilized to identify the Protection Systems
that are applicable to the PRC Reliability Standards and should be addressed by a separate development project. No change made.
Santee Cooper

What was the rationale for using aggregate capacity greater than 75 MVA on I2 and I5. I2 and I3 inclusions
are not the same as defined by the SERC Regional Entity for MOD-024. The SERC guideline does not
include an aggregate value for generating units.

Response: After consulting with the NERC Board of Trustees and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation thresholds at this time. There simply isn’t enough time or resources to do that topic justice with the mandated schedule. Therefore, the primary focus
of the SDT efforts will be to address the directives in Orders 743 and 743a. However, this does not mean that the other issues will be dropped. Both the NERC
Board of Trustees and the NERC Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased approach to this project with a new
Standards Authorization Request (SAR) to address generation thresholds as well as several other issues that have arisen from SDT deliberations.
NERC Staff Technical Review

The definition should include variable frequency transformers and back-to-back HVdc converters that connect
portions of the system operated at 100 kV or higher, regardless of the dc voltage rating of the converter
equipment, which often is less than 100 kV.
Assuring reliable operation of nuclear plants requires that Elements subject to Nuclear Plant Interconnection
Requirements are planned, designed, maintained, and operated in accordance with NERC Reliability
Standards. An additional Inclusion I6 should be added to the definition to include “All transmission Elements
subject to Nuclear Plant Interface Requirements (NPIRs) as agreed to by a Nuclear Plant Generator Operator
and a Transmission Entity defined in NUC-001.”
Assuring reliable operation of the interconnected transmission network also is dependent on reliable operation

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Question 13 Comment
of generating units that system operators rely on for capacity and Contingency Reserves. Additional
Inclusions I7 and I8 should be added to include: * Real Power resources fully or partially relied on to fulfill a
capacity obligation, and * Real Power resources (supply-side or Demand-Side Management) relied on to
provide Contingency Reserves to its Balancing Authority.

Response: The SDT believes that the language contained in the core definition (all Transmission Elements operated at 100 kV or higher) adequately captures
specific components such as variable frequency transformers and back-to-back HVdc converters. No change made.
The SDT does not believe that additional clarification beyond the designations currently established by the core definition and accompanying Inclusions and
Exclusions are necessary to appropriately identify the vast majority of Elements that support the reliable operation of the interconnected transmission network.
Additionally, the RoP Exception Process can be utilized to include facilities that are deemed necessary for the reliable operation of the interconnected transmission
network but not captured by the BES definition. No change made.
NERC Transmission Issues
Subcommittee (TIS)

The definition should include variable frequency transformers and back-to-back HVdc converters that connect
portions of the system operated at 100 kV or higher, regardless of the dc voltage rating of the converter
equipment.

Response: The SDT believes that the language contained in the core definition (all Transmission Elements operated at 100 kV or higher) adequately captures
specific components such as, variable frequency transformers and back-to-back HVdc converters. No change made.
Dominion

Does the SDT assert that there is no reliability gap because the impact of load on the BES is covered
because the DP and LSE are registered and therefore must comply with applicable reliability standards? If so,
why shouldn’t the same apply to generation elements? GO and GOPs, just like DPs and LSEs are registered
users of the bulk power system and must adhere to applicable reliability standards.
Other comments Dominion also has the following comments which are based, to a large degree upon the
webinar of May 19th. Dominion is concerned that while the BES definition is going through the standards
development process, where stakeholders have the ability to ballot, the exception process is being treated as
a change to the Rules of Procedure, with no associated stakeholder ballot. For this reason, Dominion prefers
that the exception criteria itself be part of the BES definition standards development process. As Dominion
reviews the Inclusions and Exclusions included by the SDT in the BES definition, we believe that the SDT
could just have easily developed criteria to determine whether impact on the BES is material. We believe this
would negate the need for the exception process proposed for the Rules of Procedure. However, if this
course is not chosen, then Dominion requests the NERC BOT apply these changes in an ‘all or none’ fashion.
That is, the BES definition and the exception process should both require NERC BOT approval or neither
should be moved to FERC for its approval. We are confused as to how the definition, in particular the
Inclusions and Exclusions, and the exception process are meant to be applied to, or by, the registered entity.

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Question 13 Comment
We thought we heard differing views from the panel; one stating that, if the Element or Facility met the
Inclusion or Exclusion in the BES definition, then an exception request submittal is not required. On the other
hand, we thought we heard that, unless an exception request submittal had been approved then ‘status quo’
applies.
What is ‘status quo’ based on, the current BES definition or the BES definition being proposed? Would an
entity need to track the effective date of the BES definition change in order to determine ‘status quo’? How
will submittal or non-submittal of an exception request by the registered entity be applied for compliance
purposes? Dominion believes the correct answer is that and Element or Facility that meets the BES definition
is included and if it doesn’t meet the BES definition, isn’t included. Only when an exception request has been
submitted by an entity, approved and any appeal resolved, is inclusion or exclusion based on the impact to
the bulk power system as determined by the criteria used in the exception process.

Response: The SDT scope was determined by the language contained in Order Nos. 743 & 743a in which the Commission provided guidance to the ERO to
clarify the definition for continent-wide application. The Commission did not propose significant changes to the current application of the existing definition over
the majority of the continent. Therefore the SDT has developed a draft core definition, together with BES designations (Inclusions and Exclusions) that provide
the specificity necessary to identify the vast majority of BES Elements by utilizing the existing definition and criteria previously approved for this purpose. Although
load is a component that can impact the reliability of the BES, the development of the definition is bound by the limitations documented in Section 215 of the
Federal Power Act. Expanding the definition to include load would exceed the jurisdictional boundaries into the area of local distribution facilities. No change
made.
Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the appropriate
mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles associated with
the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed through the RoP
process for the revision of the Rules of Procedure. The approvals will follow the applicable revision process. No change made.
The BES definition (core definition and Inclusions & Exclusions) will be applied to classify BES vs. non-BES Elements. The SDT believes that this will cover the vast
majority of the facilities in question. The remaining facilities will be candidates for the Exception Process (RoP) where the Technical Principles will be utilized to
determine if the facility is necessary for the reliable operation of the interconnected transmission network. The term ‘status quo’ was referring to the draft BES
definition. Once approved (BES definition, Exception Process and the Technical Principles) the current BES definition will be retired. No change made.
MRO's NERC Standards Review
Forum

In order to provide a clear and concise definition, please add the Brightline Criteria that all facilities less than a
100kV are excluded unless those facilities meet the criteria of an Inclusion.

Response: The SDT believes that the current draft BES definition provides sufficient clarity in establishing the bright-line of 100 kV and the identification of
facilities operated at less than 100 kV for exclusion would be redundant and jeopardize the SDTs efforts of establishing clarity in the language of the definition. In
an effort to provide additional guidance and in support of comments provided in response to Question 11, the SDT has modified the BES core definition with a

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Question 13 Comment

statement that specifically excludes ‘local distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
SERC Planning Standards
Subcommittee

The comments expressed herein represent a consensus of the views of the above-named members of the
SERC EC Planning Standards Subcommittee only and should not be construed as the position of SERC
Reliability Corporation, its board, or its officers.

Response: The SDT appreciates the clarification.
ACES Power Participating
Members

It is not clear if E1 covers networked sub-transmission. Consider the situation where a 138 kV line terminates
into a 138/69 kV transformer, the 69 kV is networked and only serves load and possibly generation that does
not meet any of the inclusion criteria. This is a situation that appears to meet the intent to exclude radial load
under E1 and local distribution networks under E3 but does not appear to explicitly meet either criteria. E1 is
not met because the 69 kV network is not radial and E3 is not met because it specifically limits the exclusion
to 100 kV and above. This issue could be solved by making clear that E1 applies to even networked subtransmission or by removing the voltage limit on E3 so that sub-transmission could be included within this
exclusion criterion.

Response: Exclusions E1 & E3 identify facilities operated at a voltage of 100 kV or higher in an attempt to exclude those types of facilities that do not support
the reliable operation of the interconnected transmission network. Facilities operated at a voltage level less than 100 kV are excluded by the ‘bright-line’
established by the BES core definition unless included through the RoP Exception Process. The SDT is unable to comment on specific system configurations
without detailed information pertaining to the facility in question; however, the SDT believes that the application of the BES definition should start with the
application of the ‘bright-line’ established at the 100 kV threshold.
BPA

As presently written, this BES definition says that “Real Power resources … and Reactive Power resources
connected at 100kV or higher” are to be considered as part of the BES unless one of the specified exclusions
applies. Though exclusion E2 specifically excludes “generating units that serve all or part of a retail Load …
on the customer’s side of the meter”, there is not a similar exclusion for Reactive Power resources that
similarly provide such reactive support solely “on the customer’s side of the meter”. It seems that this results
in such Reactive Power resources (i.e. capacitors, inductors, SVCs, etc.), customer side of the meter being
defined as part of the BES. If this was not the SDT’s intent, BPA requests a new exclusion to specifically
exclude such Reactive Power resources “on the customer’s side of the meter”.

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Question 13 Comment

Response: The SDT agrees with the commenter’s concerns regarding retail customer-owned Reactive Power resources and has drafted an additional Exclusion
E4 to address these concerns.
E4 – Reactive Power devices owned and operated by the retail customer solely for their own use.
Hydro One Networks Inc

We believe that the concepts of inclusions and exclusions as part of the bright-line definition are excellent.
However, these exclusions do not address adequately several complex issues along with directives in Order
No. 743 and 743A, such as: differentiation between Transmission and Distribution, non-jurisdictional
concerns, or distribution. BES definition itself is not a venue to address these complex issues and suggest
that these should be addressed by the ERO’s exception procedure.
We suggest that SDT consider: Removing I5 and adding E4 to exclude intermittent renewable generation
(wind and solar). As stated earlier, such units are intermittent and the planning and operational standards and
practices ensure that their unavailability or unexpected (sudden) loss of generation won’t jeopardize reliability
of the network; therefore, they should not be BES. That the definition and/or exception process should provide
acknowledgement and flexibility to avoid any regulatory conflicts. Introducing a concept of a new category of
registration or BES Support (BESS) elements. These elements are NOT BES but support the reliable
operation of the interconnected transmission network.
A sub-set of relevant NERC Standards should still apply to BESS elements such as planning, design, and
maintenance. However, they may not be contiguous or subject to mandatory compliance.
We do plan to submit our comments on exception criteria and procedure as part of its process. However, we
do suggest that the SDT: Carefully craft the exception criteria that is flexible and technically sound to
adequately allow entities to present their case to the ERO for exception. Verify that the exception criteria
should be at a high-level with key menu items of assessment that can be followed continent-wide by entities
to put forward their exception for element(s) mentioned in exclusions or inclusions based on technical
assessment, evidence and justification for its unique characteristics, configuration, and utilization.
Acknowledge and provide provisions in both NERC exception criteria and exception process for federal, state
and provincial jurisdictions.

Response: The SDT agrees with the commenter that the Exception Process should be the primary mechanism for addressing the concerns surrounding issues
such as: differentiation between Transmission and Distribution, non-jurisdictional concerns, or distribution. However, the SDT has made modifications to the BES
core definition to address the issues associated with the jurisdictional concerns related to local distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.

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Yes or No

Question 13 Comment

Although dispersed power producing resources (wind, solar, etc.) can be intermittent suppliers of electrical generation to the interconnected transmission
network, the SDT has been made aware of geographical areas that depend on these types of generation resources for the reliable operation of the interconnected
transmission network which has prompted the development of Inclusion I4 (previously Inclusion I5). Inclusion I4 has been revised to address industry concerns
identified in responses to Question 6.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacitycollector system , connected throughat a common point of interconnection to a system Element at a voltage of 100 kV or
above.
The development of Reliability Standards is not limited in applicability to BES Elements. Reliability Standards are written against facilities that support the reliable
operation of the interconnected transmission network. Therefore the SDT believes that the clarification of the BES definition does not require identification of
these types of facilities and that the specific facilities in question are better addressed by the applicability of individual Reliability Standards and not through the
BES definition or the Exception Process. No change made.
Comments concerning the Technical Principles (Exception Criteria) associated with the RoP Exception Process will be addressed through the dedicated responses
developed by the SDT and published in the specific Consideration of Comments document associated with that portion of the overall project.
Edison Electric Institute

Comments: EEI appreciates the efforts of the SDT and offers these comments to help guide its efforts. EEI
believes that the statutory framework of the Federal Power Act and Section 215 specifically must govern the
definition of BES. While FERC has declined to further define the term “Bulk-Power System” (“BPS”) and
suggested in Order No. 743 that the BPS “reaches farther than those facilities that are included” in the BES, it
is clear that the BES cannot extend further than the BPS, and therefore the statutory definition of BPS must
be the guide for the SDT’s efforts, particularly with regard to the treatment of local distribution facilities.The
BPS definition in Section 215 includes:(1) facilities and control systems necessary for operating an
interconnected electric energy transmission network; and (2) electric energy from generation facilities needed
to maintain transmission system reliability. But the term BPS does not include facilities used in the local
distribution of electric energy. The definition of BES must comply with the statutory definition.EEI points to
several issues to which it believes the SDT should pay particular attention. First, the facilities and control
systems to be included within the BPS/BES must be necessary for operating an interconnected electric
transmission network. Therefore, each of the proposed inclusions and exclusions must be measured against
this requirement - are they necessary? It is insufficient to include a particular facility or element within the
BES definition merely because it would be desirable to have such a facility covered under the BES or a
particular standard.
In addition, EEI believes that imposing a requirement that all contiguous elements be included is too broad
and may sweep in facilities to the BES definition that are statutorily excluded because they are not necessary.
For example, while blackstart resources may be “necessary,” including all facilities that are contiguous
between a particular blackstart resource and the transmission system is likely to include elements that are not

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Question 13 Comment
“necessary” to the operation of the interstate transmission network and therefore not within the statutory
definition. As a general rule, EEI believes it is appropriate to include contiguous elements or facilities above
100kV necessary for operating the interconnected transmission network, but not any below 100 kV unless the
element is necessary to operate the interconnected transmission network.There is no reason to require a
“contiguous” BES down to the local distribution facility level. Section 215 gives NERC and FERC jurisdiction
over “users, owners and operators” of the BPS. Therefore, FERC has authority to require an entity that is not
a BES facility to comply with applicable NERC requirements where necessary for BPS reliability. This
approach would achieve the goals of BPS reliability without extending the full reach of BES applicability to
facilities that may be local distribution facilities that are excluded from Section 215. Second, both the
transmission and the generation facilities included within the BPS/BES must be tied to maintaining the reliable
operation of the BPS. Section 215 defines the term “reliable operation” as “operating the elements of the
bulk-power system within equipment and electric system thermal, voltage, and stability limits so that
instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden
disturbance, including a cybersecurity incident, or unanticipated failure. The statute does not require that
there be no loss of load. The statute is aimed at avoiding uncontrolled separation or cascading failures.
Therefore, consistent with the statute, the definition of BES should only include elements that are necessary
to prevent these occurrences. Third, the statute contains a specific exclusion for facilities used in the local
distribution of electric energy (“local distribution facilities”). FERC has agreed in Orders No. 743 and 743-A
that local distribution facilities are not subject to Section 215. FERC, as the agency implementing Section
215, has the authority to interpret what that means. In Order 743-A, FERC left it to NERC, and therefore to
the SDT, to determine in the first instance which facilities are local distribution and therefore excluded and
whether or not to use tests such as the Seven Factor Test from Order No. 888. Order No. 888 set out seven
indicators, a combination of functional and technical tests, to assist companies and state commissions with
separating local distribution facilities from FERC jurisdictional transmission facilities on a case by case basis.
The seven factors are: (1) Local distribution facilities are normally in close proximity to retail customers; (2)
Local distribution facilities are primarily radial in character; (3) Power flows into local distribution systems; it
rarely, if ever, flows out; (4) When power enters into a local distribution system, it is not reconsigned or
transported on to some other market; (5) Power entering a local distribution system is consumer in a
comparatively restricted geographical area; (6) Meters are based at the transmission/local distribution
interface to measure flows into the local distribution facilities; and (7) Local distribution systems will be of
reduced voltage. EEI acknowledges that the Seven Factor test does not draw a bright line between facilities
used in local distribution and transmission facilities and may not be a perfect fit for applying to specific pieces
of equipment as the SDT has tried to do. However, many state commissions have made determination of
what are local distribution facilities and FERC has concurred with these determinations. Therefore, EEI
proposes that if NERC or FERC seek to include facilities (or class of facilities) in the BES that have been
previously determined by a state commission to be local distribution through application of the Seven Factor
Test, that there is a rebuttable presumption that these are facilities used in local distribution for purposes of

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Question 13 Comment
the BES definition. In order to overcome this presumption, NERC/FERC must make a showing demonstrating
that these facilities “necessary” for the reliable operation of the BPS. EEI will address this and a procedure
for seeking exclusion of facilities that previously have been determined to be local distribution in its comments
to be submitted on the exceptions process.In applying the statutory exclusion for local distribution facilities,
the SDT should ensure that the inclusions do not include local distribution facilities and that the exclusions are
sufficient to exclude local distribution facilities. Similarly, it is not sufficient to include an element that would
otherwise be a local distribution facility merely to support a facility clearly within the BES. For example, the
SDT should consider the how the proposed criteria would classify types of equipment such as distribution
voltage equipment - some, such as cap banks in a generation switchyard do support the transmission system
versus a regulator on a distribution feeder - the former may be part of the BES and the latter unlikely or not at
all.

Response: The SDT has made modifications to the BES core definition to address the issues associated with the jurisdictional concerns related to local
distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
The SDT agrees that the establishment of a contiguous BES could have the unintended consequences of being overly-inclusive and has made corresponding
changes to the Inclusions to address this concern.
The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty as possible
in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current application of
the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support consistent
application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation that the
revision to the definition would not significantly expand or contract what is currently considered to be the BES. Limiting the draft definition to Elements where a
loss could result in instability, uncontrolled separation, or cascading failures is a significant departure from the current definition and not in alignment with the
expectations documented in the Orders (743 & 743a). No change made.
LG&E and KU Energy LLC

August 19, 2011

YesLG&E and KU Energy have a concern that the approval and adoption of the BES definition project and
BES exception procedure project are not linked. This would produce the possibility of the BES definition
project completing and Registered Entities having to comply without having the appropriate and promised
BES exception procedure in place to alleviate unreasonable compliance actions. More specifically, if the BES
definition gets approved and BES exception procedure has not yet been approved (whether due to project
delay or disapproval), then Registered Entities are required to ensure everything within the new definition is
compliant, even if doing so is unreasonable or entirely unnecessary.

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Question 13 Comment

Response: It is the intention of the SDT and the RoP team to file all portions of the project (BES definition, RoP Exception Process, and the Technical Principles)
as a single response to the directives contained in Order Nos. 743 & 743a with the expectation that all portions would be approved at the same time.
Alabama Public Service
Commission

The Alabama Public Service Commission (APSC) appreciates the fact that a member of the Oregon PUC
Staff is participating on this BES Definition drafting team. In reviewing the proposed definition, the APSC’s
focus is to ensure that appropriate definitional lines are drawn so that recognized jurisdictional boundaries are
acknowledged and respected. The concern underlying this focus of the APSC is the fact that utilities must
make significant investments to comply with mandatory reliability standards and, accordingly, compliance with
such standards must be necessary and not duplicative. Furthermore, there should be a commensurate
reliability benefit associated with the cost of the investments needed for compliance.The proposed definition
and NERC’s development of standards should focus on reliable operation of the interconnected electric
transmission network (BES) in order to prevent local events from affecting other regions, not to ensure
reliable operation at the local level.

Pennsylvania Public Utility
Commission

The Pennsylvania Public Utility Commission offers the following comments in response to Standards
Announcement Project 2010-17 BES Definition: As you know, Section 1211 of the Energy Policy Act of 2005,
amending Section 215 of the Federal Power Act, provided for the promulgation of standards for the bulk
power system by an Electric Reliability Organization subject to the approval of the U.S. Federal Energy
Commission. Section 215 (a) states:’SEC. 215. ELECTRIC RELIABILITY.’’(a) DEFINITIONS.-For purposes of
this section:(1) The term ‘bulk-power system’ means-(A) facilities and control systems necessary for operating
an interconnected electric energy transmission network (or any portion thereof); and (B) electric energy from
generation facilities needed to maintain transmission system reliability.The term does not include facilities
used in the local distribution of electric energy.EPAct 2005, Section 1211, 16 U.S.C. § 824 [emphasis
supplied] While the PaPUC acknowledges the need for a more explicit definition of the Bulk Electric System
(or, as it is stated in EPAct 2005, the “bulk power system”), we are concerned that the existing draft definition
and stated exclusions is insufficiently clear and may be erroneously extended to distribution facilities that are
currently subject to state jurisdiction expressly reserved by the language of EPAct 2005, Section 1211
(a).Exceptions E1-E4 are plainly drafted to address this issue, but there is a concern that the definition of
“local distribution networks” contained in Exception E3 may not fully comport with the intent of Congress,
particularly Exception E3 (d) which excepts facilities that are [n]ot used to transfer bulk power: The LDN is not
used to transfer energy originating outside the LDN for delivery through the LDN. The proposed language
appears to be contrary to Congressional intent as it implies that some local distribution facilities which
“transfer bulk power” are indeed subject to the ERO standards process. Additionally, the draft BES, which
distinguishes local distribution facilities between those that “transfer bulk power” and those that do not
appears insufficiently precise, as bulk power is ultimately transferred through every portion of the local
distribution network to end users.Our major concern is that this draft standard definition will collide with state

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Question 13 Comment
regulation of distribution facilities, particularly where state commissions are seeking to impose standards and
protective arrangements more stringent than might be required by the Electric Reliability Organization or
Regional Reliability Organization. Accordingly, it is recommended that the Draft BES be modified to
specifically define distribution facilities and exclude them from the ambit of the Bulk Electric System definition,
as well as making it clear that State reliability standards relating to the local distribution network are not
overridden or modified by standards applicable to the Bulk Electric System.

National Association of
Regulatory Utility Commissioners

Congress clearly recognized that State utility commissions are concerned about and committed to reliability at
the distribution level; that's why Congress explicitly limited FERC's reach, and directed FERC not to attempt to
regulate facilities used in local distribution.The NERC standard setting process for defining the Bulk Electric
System must respect the statutory limitations under Federal Power Act Section 215 that explicitly excluded
local distribution from the definition of the Bulk Power System (BPS). The Bulk Electric System, while not
necessarily equivalent to the BPS (See FERC Order 743 A P 102), cannot exceed the limitations of the BPS
and cannot include facilities used in the local distribution of electric energy. State Utility Commissions are
concerned about and committed to reliability. These Commissions are in the best position to provide reliability
oversight and standards for the local distribution system in their State.

Response: The SDT is developing a revised definition of the BES to identify the facilities that support the reliable operation of the interconnected transmission
network. The SDT has revised the draft BES definition to address the potential jurisdictional boundaries that currently exist in regards to local distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Western Electricity Coordinating
Council

The definition should also reference the exception process and technical justification allowed for further
inclusion or exclusion from the BES.

Utility System Efficiencies, Inc.

The definition should also reference the exception process and technical justification allowed for further
inclusion or exclusion from the BES.

Response: Such a statement was inadvertently left off of the first posted version of the definition.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.
Western Montana Electric
Generating and Transmission

August 19, 2011

WMG&T has these additional concerns: The current definition provides that “Elements may be included or
excluded on a case-by-case basis through the Rules of Procedure exception process.” WMG&T is concerned
that the SDT carefully delineate which entity has the burden of proof in the exclusion process. The WECC

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Organization
Cooperative

Yes or No

Question 13 Comment
BESDTF approach, which we commend to the SDT, laid out these burdens in some detail. Under that
approach, essentially, if a facility is excluded from the BES by virtue of the specific exclusions listed in the
definition, the Regional Entity bears the burden of proving that the facility nonetheless has a material impact
on the interconnected bulk transmission system and therefore should be included in the BES. On the other
hand, if a facility is classified as BES by virtue of the list of inclusions set forth in the BES definition, it can still
escape classification as BES, but bears the burden of demonstrating that its facility has no material impact on
the interconnected transmission system. We urge the SDT to give careful consideration to these burden-ofproof questions and to follow the lead of the WECC BES Task Force.
For the reasons we have explained in our answer to Question 11, we believe the Exception process is critical
both to ensure that the BES definition is effective in producing measurable gains to bulk system reliability and
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the Standards
Development Process. Accordingly, we urge that all elements of the BES definition, including those elements
that have been assigned to the Rules of Procedure Team, be vetted through the Standards Development
Process.

Response: The SDT believes that the burden of proof issue should be resolved through the development of the RoP Exception Process. Your comments will be
forwarded to the RoP team for consideration.
Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the appropriate
mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles associated with
the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed through the RoP
process for the revision of the Rules of Procedure.
PacifiCorp

Effective dates: While understanding that additional facilities will require up to two years to come into
compliance, several facilities will also be excluded that are currently under the current bright line definition.
Are utilities going to be responsible to maintain all NERC reliability standards during the two year period for
facilities or elements that will be excluded by the new bright line definition? PacifiCorp proposes that the
effective date for facilities being removed from the bright line become effective on the first day of the first
calendar quarter after applicable regulatory approval. It is reasonable to retain the two year period for facilities
that will be added to the BES.
NERC Staff has submitted written comments to this project stating that the BES “must be contiguous.”

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Organization

Yes or No

Question 13 Comment
Instituting a contiguous BES with Inclusion I2, for example, would result in a substantially over-inclusive BES
definition. The adoption of a “contiguous” BES is therefore likely to result in imposition of reliability standards
on a substantial number of distribution elements that have nothing to do with improving or protecting the
reliability of bulk transmission system.There is no compelling reason to adopt a “contiguous” BES that covers
local distribution systems. Section 215 of the FPA provides FERC with jurisdictional authority over “users” as
well as “owners” and “operators” of the bulk power system. Consequently, FERC has the jurisdictional
authority to require generation and other entities to comply with applicable NERC requirements. Hence, even
where an entity does not own or operate BES assets, it could still be required, for example, to provide
necessary information to the applicable Reliability Coordinator or Planning Coordinator and to participate in
programs to prevent instability, uncontrolled separation, or cascading outages to the bulk transmission
system. This approach would fully achieve the goals of bulk transmission system reliability without imposing
the full BES regulatory compliance burden on local distribution elements.
Although not specifically the responsibility of the SDT, it should closely coordinate its efforts with the team
developing the inclusion/exclusion process in the ROP. For instance, if the ROP team develops an overly
onerous process to exclude elements which are not required to reliably operate the interconnected BES yet
are not excluded through the bright-line definition then PacifiCorp would consider the bright-line definition to
be over-inclusive.

Response: The SDT agrees with the commenter and has made revisions to the Implementation Plan to address these concerns surrounding the implementation
dates.
The SDT agrees that the establishment of a contiguous BES could have the unintended consequences of being overly-inclusive. Inclusion I2 has been revised and
merged with Inclusion I3 (now Inclusion I2) and as a result the implication of the continuity of the BES has been removed. Additionally, the SDT recognizes the
limitations associated with FERC’s jurisdiction as defined in the FPA Section 215 and has therefore provided additional clarification in the core BES definition to
address these concerns.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
It is the intention of the SDT and the RoP team to file all portions of the project (BES definition, RoP Exception Process, and the Technical Principles) as a single
response to the directives contained in Order Nos. 743 & 743a with the expectation that all portions would be approved at the same time.

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Organization
Intellibind

Yes or No

Question 13 Comment
Generation that is BES significant that is not connected at 100kV or above.

Response: This ‘significant’ generation should be identified with the appropriate technical justification, established and presented by the Regional Entity, in
accordance with the Rules of Procedure Exception Process for ‘inclusion’ approval by the ERO. No change made.
City of Redding

Additional concerns:
The SDT has avoided directly addressing the predominate issues that plagues the industry. The two main
issues are: a sound definition of the term “necessary for operating the interconnected transmission network”
and “whether a particular facility is local distribution or transmission” as directed by FERC in both Orders 743
and 743A. As an example, in terms of pure operation of an interconnected transmission system there is only a
small amount of the generation connected to the BES system where the energy is actually “necessary for
operating the interconnected transmission network”. As the users of the system increase load and remote
generation responds then the transmission system only needs the VAR support and reserves from a select
set of generators, therefore the Definition goes too far, and creates a generalization that all generators over
20 MVA are “necessary”. This is especially not true if the generation is a load modifier embedded in a
Distribution system and the generator only requires reserves from the BES. These services are a function of
the BES and are paid for by the user.
Redding is concerned that the SDT is intertwining the BES Definition and the Statement of Compliance
Registry out of convenience. It is our view that the the NERC Registry Criteria serves a different function than
the Definition in that it does not clarify what elements are BES elements but identifies the Owners, Operators,
and Users of the BES and therefore the NERC Standards could be applied. The SDT does not have a
technical justification to adopt the current thresholds in the Compliance Registry as part of the BES Definition.
These thresholds have not been presented to the industry for validation or review. Additionally, the Statement
of Compliance Registry was an initial attempt of NERC to begin a new regulation requirement and was not
created through the NERC Standards Development Process.
Redding suggests that the SDT, in the interest of reliability, recommend that the NERC Statement of
Compliance Registry be modified to create a tiered level of responsibilities for entities. A 20 MVA generator
has a different level of responsibility to the BES then an 800 MVA generation unit. A LDN that does not qualify
for an exemption due to an impact on a path or flow gate should not be required to meet the full requirements
of a Transmission Operator. This in fact reduces reliability by diverting the local training focus from the
operation of a Local Control Center (LCC) and a sub-transmission system. Prior to the NERC Standards
WECC had training classes for Sub-transmission Operators that were applicable to the reliable operation of a
local Sub-transmission system. The implementation of the NERC Standards has decreased reliability in this
area because the focus of coordinating with the LCC and sub-transmission level has been lost.

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Organization

Yes or No

Question 13 Comment

Response: The SAR has clearly identified the responsibilities of the SDT in revising the definition of the BES. The scope does not include the additional definitions
noted above. No change made.
The Commission stated in Order Nos. 743 & 743a that they believe the current application of the definition is correct and should be maintained. The current
application of the definition is based on Commission language contained Order 693 which directs the use of the BES definition and NERC Statement of Compliance
Registry to identify the functional entities required to be registered and which Reliability Standards will apply. The linkage between the BES definition and Registry
Criteria was established by the Commission in Order No. 693 and uncontested by the industry at the time of filing. No change made.
The ERO Statement of Compliance Registry is governed by the Rules of Procedure and under the responsibilities of the ERO Certification and Registration
Department and does not fall under the current responsibility of the SDT as defined by the scope in the SAR for Project 2010-17. No change made.
Public Utility District No. 1 of
Snohomish County, Washington

Snohomish County PUD has these additional concerns:
We are concerned that the proposed 24-month delay in the effective date of the new definition will delay the
potentially beneficial effects of the SDT’s efforts, especially for utilities that have been inappropriately
registered for BES-related functions, which is a common situation in WECC. We therefore urge the new BES
definition to become effective immediately upon approval by FERC or other applicable regulatory agencies.
Entities that have been improperly registered for BES functions can then immediately file for deregistration
and obtain the benefits of the new definition as soon as possible. For entities that have not previously been
registered for BES-related functions but that would be required to register under the new definition, we do not
object to the 24-month transition period proposed by the SDT to allow the newly-registered entity to attain
compliance with newly-applicable reliability standards, many of which require new training for employees, new
maintenance procedures, and complex new operational protocols. However, the transition period for newlyregistered entities should be structured in a way that does not prevent entities seeking deregistration from
benefitting from the new definition at the earliest possible date.
The current definition provides that “Elements may be included or excluded on a case-by-case basis through
the Rules of Procedure exception process.” Snohomish is concerned that the SDT carefully delineate which
entity has the burden of proof in the exclusion process. The WECC BES Task Force approach, which we
commend to the SDT, laid out these burdens in some detail. Under that approach, essentially, if a facility is
excluded from the BES by virtue of the specific exclusions listed in the definition, the Regional Entity bears
the burden of proving that the facility nonetheless has a material impact on the interconnected bulk
transmission system and therefore should be included in the BES. On the other hand, if a facility is classified
as BES by virtue of the list of inclusions set forth in the BES definition, it can still escape classification as
BES, but bears the burden of demonstrating that its facility has no material impact on the interconnected
transmission system. We urge the SDT to give careful consideration to these burden-of-proof questions and
to follow the lead of the WECC BES Task Force.
For the reasons we have explained in our answer to Question 11, we believe the Exception process is critical

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Yes or No

Question 13 Comment
both to ensure that the BES definition is effective in producing measurable gains to bulk system reliability and
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the Standards
Development Process. Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of
Procedure upon approval of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3,
2010) (providing for, e.g., posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). Accordingly, we urge that all elements of the BES definition, including those
elements that have been assigned to the Rules of Procedure Team, be vetted through the Standards
Development Process. Further, we believe that the failure to vet all material elements of the BES definition
through the Standards Development Process would constitute a violation of NERC’s bylaws and the
requirements of the Standards Development Process.

Response: The SDT agrees with the commenter and has made revisions to the Implementation Plan to address these concerns surrounding the implementation
dates.
The SDT believes that the burden of proof issue should be resolved through the RoP Exception Process. Your comments will be forwarded to the RoP team for
consideration.
Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the appropriate
mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles associated with
the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed through the RoP
process for the revision of the Rules of Procedure.
Grand Haven Board of Light and
Power

I can not over emphasize how unreasonable it would be for our utility to have to register as a TO/TOP
because of one asset (138kV circuit switcher) that serves a radial, load serving system. It is equally
unreasonable for us to have to use a long and arduous exception process to qualify for deregistration. Please
take this into consideration as you prepare the final definition.

Response: The SDT is responsible for the revision of the BES definition. In fulfilling this responsibility the SDT is developing a definition that properly classifies
facilities as BES or non-BES Elements. Defining registration requirements is not within the scope of Project 2010-17. No change made.
National Grid

August 19, 2011

We are concerned that the proposed definition of BES and specified inclusions reaches farther into the
electric system than the Bulk Power System (BPS) definition. The statutory framework of the Federal Power

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Organization

Yes or No

Question 13 Comment
and section 215 specifically must govern the definition of BES. It is clear in FERC’s Order No. 743 that BES
should not extend further than BPS, therefore the statutory definition of BPS must be the guide for the SDT’s
efforts, particularly with regard to the treatment of local distribution facilities. The BPS definition includes (1)
facilities and control systems necessary for operating an interconnected electric energy transmission network;
and (2) electric energy from generation facilities needed to maintain transmission system reliability. It does
not include facilities used in the local distribution of electric energy. The definition of BES must comply with
the statutory definition.First, the facilities and control systems to be included within the BPS/BES must be
necessary for operating an interconnected electric transmission network. Therefore, one question to consider
for each of the proposed inclusions and exclusions is “are they necessary?” A particular facility or element
should not included in the BES definition just because it would be desirable to have the facility considered
BES or covered by a particular standard.
Imposing a requirement that all contiguous elements be included is too broad and may sweep in facilities to
the BES definition that are statutorily excluded because they are not necessary.
Second, both the transmission and the generation facilities included within the BPS/BES must be tied to
maintaining the reliable operation of the BPS. Section 215 defines the term “reliable operation” as “operating
the elements of the bulk-power system within equipment and electric system thermal, voltage, and stability
limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result
of a sudden disturbance, including a cybersecurity incident, or unanticipated failure”. The statute does not
require that there be no loss of load. The statute is aimed at avoiding uncontrolled separation or cascading
failures. Therefore, the definition of BES should only include elements that are necessary to prevent these
occurrences.

Response: The SDT recognizes the limitations associated with FERC’s jurisdiction as defined in the FPA Section 215 and has therefore provided additional
clarification in the core BES definition to address these concerns.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
The SDT agrees that the establishment of a contiguous BES could have the unintended consequences of being overly-inclusive. Inclusion I2 has been revised and
merged with Inclusion I3 (now Inclusion I2) and as a result the implication of the continuity of the BES has been removed.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater than 75 MVA (with gross individual or gross
aggregate nameplate rating) per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated at a voltage of 100 kV or above.
The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty in the

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Organization

Yes or No

Question 13 Comment

identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current application of the
existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support consistent application
across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation of the revision to the
definition would not significantly expand or contract what is currently considered to be the BES. Limiting the draft definition to Elements where a loss could result
in instability, uncontrolled separation, or cascading failures is a significant departure from the current definition and not in alignment with the expectations
documented in the Orders (743 & 743a). No change made.
Northern Wasco County PUD

Northern Wasco County PUD has these additional concerns: The current definition provides that “Elements
may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.”
Northern Wasco County PUD is concerned that the SDT carefully delineate which entity has the burden of
proof in the exclusion process. The WECC BESDTF approach, which we commend to the SDT, laid out
these burdens in some detail. Under that approach, essentially, if a facility is excluded from the BES by virtue
of the specific exclusions listed in the definition, the Regional Entity bears the burden of proving that the
facility nonetheless has a material impact on the interconnected bulk transmission system and therefore
should be included in the BES. On the other hand, if a facility is classified as BES by virtue of the list of
inclusions set forth in the BES definition, it can still escape classification as BES, but bears the burden of
demonstrating that its facility has no material impact on the interconnected transmission system. We urge the
SDT to give careful consideration to these burden-of-proof questions and to follow the lead of the WECC BES
Task Force.
For the reasons we have explained in our answer to Question 11, we believe the Exception process is critical
both to ensure that the BES definition is effective in producing measurable gains to bulk system reliability and
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the Standards
Development Process. Accordingly, we urge that all elements of the BES definition, including those elements
that have been assigned to the Rules of Procedure Team, be vetted through the Standards Development
Process.

Clallam County PUD No.1
Chelan PUD – CHPD
Public Utility District No. 1 of
Franklin County

August 19, 2011

Clallam County PUD has these additional concerns: The current definition provides that “Elements may be
included or excluded on a case-by-case basis through the Rules of Procedure exception process.” Clallam is
concerned that the SDT carefully delineate which entity has the burden of proof in the exclusion process. The
WECC BES Task Force approach, which we commend to the SDT, laid out these burdens in some detail.
Under that approach, essentially, if a facility is excluded from the BES by virtue of the specific exclusions

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Organization
Northwest Requirements Utilities
Big Bend Electric Cooperative,
Inc.
Cowlitz County PUD

Yes or No

Question 13 Comment
listed in the definition, the Regional Entity bears the burden of proving that the facility nonetheless has a
material impact on the interconnected bulk transmission system and therefore should be included in the BES.
On the other hand, if a facility is classified as BES by virtue of the list of inclusions set forth in the BES
definition, it can still escape classification as BES, but bears the burden of demonstrating that its facility has
no material impact on the interconnected transmission system. We urge the SDT to give careful
consideration to these burden-of-proof questions and to follow the lead of the WECC BES Task Force.
For the reasons we have explained in our answer to Question 11, we believe the exemption process is critical
both to ensure that the BES definition is effective in producing measurable gains to bulk system reliability and
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the exemption process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the Standards
Development Process. Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of
Procedure upon approval of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3,
2010) (providing for, e.g., posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). Accordingly, we urge that all elements of the BES definition, including those
elements that have been assigned to the Rules of Procedure Team, be vetted through the Standards
Development Process. Further, we believe that the failure to vet all material elements of the BES definition
through the Standards Development Process would constitute a violation of NERC’s bylaws and the
requirements of the Standards Development Process.

Response: The SDT believes that the burden of proof issue should be resolved through the development RoP Exception Process. Your comments will be
forwarded to the RoP team for consideration.
Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the appropriate
mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles associated with
the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed through the RoP
process for the revision of the Rules of Procedure.
PUD No. 2 of Grant County,
Washington

August 19, 2011

Grant has these additional concerns: We are concerned that the proposed 24-month delay in the effective
date of the new definition will delay the potentially beneficial effects of the SDT’s efforts, especially for utilities
that have been inappropriately required to meet BES reliability standards, which is a common situation in
WECC. We therefore urge the new BES definition become effective immediately upon approval by FERC or
other applicable regulatory agencies. Entities that have been improperly required to meet standards can then
immediately redirect resources to where they are truly needed. For entities that have not previously been

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Organization

Yes or No

Question 13 Comment
registered for BES-related functions but that would be required to register under the new definition, we agree
that 24 months is an appropriate transition period to allow the newly-registered entity to attain compliance with
newly-applicable reliability standards, many of which require new training for employees, new maintenance
procedures, and complex new operational protocols. However, the transition period for newly-registered
entities should be structured in a way that does not prevent entities seeking deregistration from benefitting
from the new definition at the earliest possible date.
The current definition provides that “Elements may be included or excluded on a case-by-case basis through
the Rules of Procedure exception process.” Grant is concerned that the SDT carefully delineate which entity
has the burden of proof in the exclusion process. The WECC BESDTF approach, which we commend to the
SDT, laid out these burdens in some detail. Under that approach, essentially, if a facility is excluded from the
BES by virtue of the specific exclusions listed in the definition, the Regional Entity bears the burden of proving
that the facility nonetheless has a material impact on the interconnected bulk transmission system and
therefore should be included in the BES. On the other hand, if a facility is classified as BES by virtue of the
list of inclusions set forth in the BES definition, it can still escape classification as BES, but bears the burden
of demonstrating that its facility has no material impact on the interconnected transmission system. We urge
the SDT to give careful consideration to these burden-of-proof questions and to follow the lead of the WECC
BES Task Force.

Response: The SDT agrees with the commenter and has made revisions to the Implementation Plan to address these concerns surrounding the implementation
dates.
The SDT believes that the burden of proof issue should be resolved through the development RoP Exception Process. Your comments will be forwarded to the
RoP DT for consideration.
Wells Rural Electric Company

Dear NERC Standards Drafting Team:Enclosed are Wells Rural Electric Company’s comments on NERC’s
Proposed Continent-wide Definition of Bulk Electric System. We believe that NERC’s proposed Continentwide Definition of Bulk Electric System is proceeding in the right direction on this important topic but that more
work needs to the done. We would like to thank the Standards Drafting Team for their hard work. We support
the detailed comments of the Snohomish County Public Utility District and Pacific Northwest Generating
Cooperative with regard to the questions posed by the Comment Form for Project 2010-17 Definition of
BES.We would like to emphasize these portions of Snohomish’s and PNGC’s comments:
Question 1, both PNGC and Snohomish suggest that NERC start by adopting the statutory definition of the
bulk power system as the core definition. We support that approach. That is, “(t) he term ‘Bulk Electric
System’ means: (A) Facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof); and,(B) Electric energy from generation facilities needed to
maintain transmission system reliability.The term does not include facilities used in the local distribution of

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Question 13 Comment
electric energy”. See 16 U.S.C. § 824o(a)(1).”
Question 7, we support the exclusion for radial lines as drafted.
Question 9, we support the categorical exclusion of Local Distribution Networks from the BES as defined
here, but with Snohomish’s clarifications.
Question 10, we support exclusion E4, for small utilities, but we are unclear how small utilities are defined in
the exclusion language presented here.
Question 11, we support the approach to exclusion of local distribution facilities discussed in the draft but
repeat that more work should be done on the definition so that facilities used in local distribution are not swept
up into the BES.The primary value of clearly defining the BES is for registration determinations. We realize
that clearly defining the BES also has value in determining which standards apply to registered entities. If a
registered entity does not own any Elements of the BES that that registered entity should be able to efficiently
and effectively demonstrate an exception. We encourage NERC to support the use of the BES definition for
registration-issues and to develop the exception procedure for registered entities that do not own or operate
any Elements of the BES.

Response: The SDT appreciates the industry support for this project. Please see the SDT responses in Questions 1, 7, 9, 10, and 11 of this document.
ExxonMobil Research and
Engineering

There are certain transmission network configurations in the south east portion of the country where the
majority of the interconnected transmission network is owned and maintained by a single utility company, but
approximately one hundred substations that are located along the interconnected transmission network and
utilized to transmit power between regions are owned by separate companies (i.e. many companies own a
single transmission substation). The SDT should consider this configuration and the lack of uniform operation
and maintenance practices that may exist due to the differences in how the companies implement NERC
compliance.

Response: The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty
as possible in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current
application of the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support
consistent application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation
of the revision to the definition would not significantly expand or contract what is currently considered to be the BES. The SDT is unable to comment on specific
system configurations without detailed information pertaining to the facility in question.
FortisBC

August 19, 2011

We believe that the concepts of inclusions and exclusions as part of the bright-line definition are excellent.
However, these exclusions do not address several directives in Order No. 743 and 743A, such as:

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Question 13 Comment
differentiation between Transmission and Distribution, non-jurisdictional concerns, or distribution. We believe
that the BES definition itself is not a venue to address these concerns but suggest that these issues should be
explicitly addressed by the ERO’s exception criteria and exception process. Currently, the posted exception
criterion is only a concept with many gaps and TBD, as posted details are later to follow. We suggest that the
exception criteria should be a menu of technical items (load flows, stability analysis etc) and non technical
items (type of loads such as distribution companies vs. major city center, national security etc). Entities should
be required to assess and provide their own justification under each category with a conclusion that takes into
account all of the relevant items for element(s) under exception, in a consistent template and table of
contents. We suggest the SDT to avoid specification of any parameters as they would differ under different
design concepts, system configurations, system characteristics and regulatory requirements.

Response: The SDT agrees with the commenter that the Exception Process should be the primary mechanism for addressing the concerns surrounding issues
such as: differentiation between Transmission and Distribution, non-jurisdictional concerns, or distribution. However the SDT has made modifications to the BES
core definition to address the issues associated with the jurisdictional concerns related to local distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Comments concerning the Technical Principles (Exception Criteria) associated with the RoP Exception Process will be addressed through the dedicated responses
developed by the SDT and published in the specific Consideration of Comments document associated with that portion of the overall project.
MidAmerican Energy Company

While there were no questions directed to the draft implementation plan in the comment form, if the intent was
to also solicit comments on that plan, the schedule in that plan is likely too agressive if the result of the
revised BES definition is that new facilites are brought into the BES and are thereby obligated to now comply
with standards they had not previously been required to meet. Perhaps a provision should be added to the
implementation plan to address this situation and allow an extended schedule for new BES facilities to comply
with applicable standards.

Response: The SDT believes that the 24 month schedule for implementation is a reasonable compromise considering the Commission suggested timeframe of 18
months and the burden of newly registered functional entities in establishing compliance with the applicable Reliability Standards. The SDT did, however, extend
the effective date by an additional quarter of a year based on stakeholder comments.
American Electric Power

August 19, 2011

Usage of the NERC term “Element” clearly excludes associated auxiliary equipment such as protective relay
systems and metering systems. If this is not the intent of the SDT, then there needs to be more
comprehensive BES nomenclature established that distinguishes among the applicable primary-voltage
equipment, the associated auxiliary equipment having an impact to the BES, and the associated ancillary

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equipment having no electrical impact to the BES.In addition, please see response to question 1 regarding
the request for industry input on concurrent, closely related projects (approved definition of BES, the technical
principles for demonstrating BES exception, and the exception process itself).

Response: The SDT has determined that the draft BES definition should identify BES Elements which are operated at a voltage of 100 kV or above. The SDT also
has recognized the existence of facilities (i.e., auxiliary equipment and Protection Systems) that support the reliable operation of the interconnected transmission
network but do not necessarily operate at voltages of 100 kV or above and should not necessarily be classified as BES Elements. Reliability of the interconnected
transmission network is established by the application of Reliability Standards and the development of Reliability Standards is not limited in applicability to BES
Elements. Reliability Standards are written against facilities that support the reliable operation of the interconnected transmission network. Therefore the SDT
believes that the clarification of the BES definition does not require identification of these types of facilities and that the specific facilities in question are better
addressed by the applicability of individual Reliability Standards and not through the BES definition or the Exception Process. No change made.
Farmington Electric Utility System

The Rules of Procedure for Exceptions should define the compliance expectation of the entity while an
exception is being considered; similar to the CIP TFE process.

Response: The SDT believes that compliance expectation issues should be resolved through the RoP Exception Process. Your comments will be forwarded to the
RoP team for consideration.
Colorado Springs Utilities

Colorado Springs Utilities supports the SDT’s efforts to create an acceptable BES definition directly linked to
an exemption process. Know that WECC has a task force, the Bulk Electric System Definition Task Force
(BESDTF), which has done some notable work on this task. See WECC BESDTF Proposal 6, Appendix C
(http://www.wecc.biz/Standards/Development/BES/default.aspx). The BES definition is very complex and the
BESDTF has already addressed many of the tough issues that have yet to be addressed in this process, such
as: o Local Distribution Network definition for automatic exemption o Determination of radial facilities o
Demarcation of BES and non-BES Elements o Alternate dispute resolution process o Assignment of the
burden of proof for the exemption process o Technical approach for the inclusion/exclusion determination

Sacramento Municipal Utility
District (SMUD)

SMUD supports the SDT’s efforts to create an acceptable BES definition directly linked to an exemption
process. SMUD would also like to bring to the BES SDT’s attention that the WECC the Bulk Electric System
Definition Task Force has constructed the framework on this task that we encourage the SDT to review their
work. SMUD would like to thank the BES SDT for consideration of these comments.

Tacoma Power

Tacoma Power supports the SDT’s efforts to create an acceptable BES definition directly linked to an
exemption process. Please be aware that the WECC has a task force, the Bulk Electric System Definition
Task Force (BESDTF), which has done some notable work on this task. See WECC BESDTF Proposal 6,
Appendix C (http://www.wecc.biz/Standards/Development/BES/default.aspx). The BES definition is very

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complex and the BESDTF has already addressed many of the tough issues that have yet to be addressed in
this process, such as: o Local Distribution Network definition for automatic exemption o Determination of
radial facilities o Demarcation of BES and non-BES Elements o Alternate dispute resolution process o
Assignment of the burden of proof for the exemption process o Technical approach for the
inclusion/exclusion determinationThank you for consideration of our comments.

Response: The SDT has taken into account the work product of several regional efforts in the development of the draft BES definition.
Consumers Energy Company

Yes.We propose an alternative core BES definition to read as follows: “All network System Elements
operated at 100 kV or higher, Real Power resources as described below, and Reactive Power resources
connected at 100 kV or higher unless such designation is modified by the list shown below.”
We support extending the transition period to 24 months.

Response: The SDT believes that the revised draft BES definition provides sufficient clarity in establishing the bright-line of 100 kV.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
Thank you for your support.
Occidental Energy Ventures
Corp. (answers include all
various Oxy affiliates)

Occidental Energy Ventures Corp (“OEVC”) would like to emphasize that the proposed definition of the BES
does not only impact OEVC and its affiliates. The proposed BES definition would include numerous facilities
that are used for the local distribution of electric energy, not transmission, in direct contravention of Section
215 of the FPA. For example, there are likely hundreds, if not thousands, of retail customers that have selfprovided “hard-tapped” facilities behind the retail delivery point. Those retail customers, many of who are
likely unaware of the proposed BES definition, much less its impact, will have their facilities under the
proposed BES definition suddenly become transmission facilities simply because their facilities are not
separated from the BES by an automatic fault-interruption device.

Response: The SDT believes that the changes made to the wording of the definition based on comments received will provide clarity and address the concerns
provided by the commenter’s. In particular the SDT clarified the point of connection, removed the automatic interrupting device, moved the concept of the
normally open switch to a note, and clarified the generation allowed within the system.
In addition, the SDT wishes to point out that the definition also includes Exclusion E3 that can be used for multiple connections serving local networks. The SDT
realizes that a bright-line definition may require entities to seek exceptions through the Rules of Procedure exception process.

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Chevron Global Power, a division
of Chevron U.S.A. Inc.

August 19, 2011

Yes or No

Question 13 Comment
Chevron U.S.A. Inc. has reviewed the proposed Bulk Electric System definition and is concerned that the
proposed changes designed to enhance reliability and accountability of Transmission and Generation are
inadvertently catching parties whose prime operations are distribution in nature. Chevron is proposing minor
changes that will not affect the necessary regulation of the bulk power industry, but will exempt parties that
are not crucial to reliability and provide mostly, if not entirely, distribution or self use service.In remote areas of
west Texas, Chevron has hundreds of non contiguous producing properties and facilities located over
hundreds of square miles. In some cases where the utility was close and had the capability to serve, Chevron
took utility service. Where service was not available or the utility did not have the capability, Chevron built its
own private power distribution system to service its own facilities. Chevron has no generation and takes all of
its power from transmission providers. In at least one instance Chevron takes power at over 100 kV from a
transmission provider. Chevron has an automated interruption device between its facilities and the
transmission facilities. Currently this field takes power from an ERCOT transmission owner at above 100 kV
and then distributes the power over a Chevron owned and operated power distribution system to Chevron
facilities. This Chevron system includes a substation, transformers and other facilities necessary to take
power at above 100 kV and distribute and step down the power as necessary. Chevron uses the power for
offices, repair facilities, oil wells, separation facilities, gas plants, drilling new wells and other related oil and
gas activities. Located within the area of the Chevron power distribution system are ranchers, pump stations,
third party oil wells and other small users. These parties are not located near any utility or coop facilities. For
decades Chevron has worked to accommodate these parties by working with the local utility, transmission
owners and the Texas Public Utility Commission to allow electrical service to these remote users. Many of
these ranchers and other users are not located near any utility lines. Costs could run to the hundreds of
thousands of dollars (or more) to provide an interconnect from the utility. Instead of leaving these parties with
no electrical service, a procedure was developed that allowed parties such as Chevron to accommodate the
small end user. For example if a utility/coop was unable or unwilling to serve a rancher at a reasonable cost,
the rancher could approach Chevron. The goal would be to execute a three party agreement between the
rancher, Chevron and the service provider. Under the terms of the agreement, the Rancher would
interconnect with the Chevron system. A utility quality meter capable of remote reading would be installed
and the rancher would be responsible for all costs beginning at the meter. The rancher contracts with a
power provider for his power. Every month the meter between the Transmission owner and Chevron would
be read. This smart meter located at the interconnect with the transmission system and its soft ware would
show all deduct metering (such as our rancher) so that any non Chevron parties on the Chevron distribution
system’s usage would clearly be listed. The transmission owner then provides the billing information to the
rancher’s power provider. Chevron receives no compensation from the rancher, power provider or
transmission owner. Chevron provides the service strictly on an accommodation basis. The Texas Public
Utility Commission recognizes the needs of parties in remote areas of Texas and has blessed this type of
service. Chevron is not considered a utility for providing this type of service.Chevron is concerned that the
above described private power distribution system may inadvertently be forced to register as a bulk electric

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system provider. This private distribution system is clearly at the terminus of a radial line and provides
service to Chevron owned and operated facilities. The system is large in area and has been built over a
period longer than any current employee’s memory. Through what can be called “accidents of history” and a
good neighbor policy, Chevron has accommodated parties that otherwise could not connect to utility quality
power. This arrangement is blessed and encouraged by the State PUC. Chevron charges nothing for the
service. The system is entirely distribution in nature and does not contribute to the reliability of the grid in any
manner. The intent of the current rule making is not to encompass such a system. NERC needs to
encourage parties such as Chevron to help bring power to remote areas and not discourage, or worse yet
greatly increase the cost to provide such service.Chevron requests that the NERC include in its definition a
statement making it clear that systems such as those described above should not be required to register.
Chevron supports the technical changes suggested by ELCON in its filing.A party’s facility should not be
considered an essential facility where the facility would otherwise be considered exempt except that it is
providing distribution services as an accommodation to third parties. This is especially true when1. The
incumbent utility or coop is unable or unwilling to serve the third parties at a reasonable cost2. The service to
the third party is provided as an accommodation3. The facility is not generating and/or selling power to the
third party4. The third party is purchasing power from a power provider

Response: The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty
as possible in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current
application of the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support
consistent application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation
of the revision to the definition would not significantly expand or contract what is currently considered to be the BES.
The SDT believes that establishing a ‘bright-line’ approach to identify BES Elements will inherently incorrectly identify a small number of facilities. The Exception
Process is designed to clear up these discrepancies and render the proper classification of those questionable facilities. The SDT believes that with the draft core
definition and the BES designations (Inclusions and Exclusions) the vast majority of facilities will be correctly identified as BES or non-BES Elements and therefore
will produce the consistent application and results as desired by the Commission’s language in Order Nos. 743 & 743a.
The SDT made several revisions to the definition that should address your concerns.
Muscatine Power and Water

In order to provide a unambiguous and concise definition of the BES, we ask the SDT to please include in the
bright-line criteria that “all facilities less than a 100kV are excluded unless those facilities meet the criteria of
an Inclusion.”

Response: The SDT believes that the current draft BES definition provides sufficient clarity in establishing the bright-line of 100 kV and the identification facilities
operated at less than 100 kV for exclusion would be redundant and jeopardize the SDTs efforts of establishing charity in the language of the definition. If an effort
to provide additional guidance and in support of comments provided in response to Question 11, the SDT has modified the BES core definition with a statement

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that specifically excludes ‘local distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list
shown below. This does not include facilities used in the local distribution of electric energy.
BGE and on behalf of
Constellation NewEnergy,
Constellation Commodities Group
and Constellation Control and
Dispatch

BGE agrees with the SDT’s position that support equipment such as UVLS and UFLS not be classified as
BES. BGE strongly believes that including control centers and other BES support equipment in the BES
definition is not necessary and will cause confusion. BGE commends the BES Definition Standards Drafting
Team for the informative webinar on 5/19/2011. We were encouraged that the SDT’s developed a transition
plan for the implementation of the new BES definition. BGE urges the SDT to also address the issue of the
addition of new BES elements (i.e., such as new designated blackstart resources which may include a
cranking path that is reclassified as BES). A transition period would also be required for these situations.
BGE appreciates the work of the drafting team and supports the goal to produce clear definition language so
that upwards of 95% of the assets are clearly distinguished as either included or excluded from the BES. We
are particularly sensitive to the potential for burdensome processes (e.g. TFEs) to be added to reliability
compliance, so we appeal to the team for continued, vigilant consideration of the arduousness of the BES
determination process.Also important to consider is that the subject of this comment form, the proposed BES
definition, is only one part of the BES definition project. The accompanying technical principles for BES
Exceptions and the Rule of Procedure Process must be evaluated together with the BES Definition to
sufficiently understand the revisions. In the end, the Technical Principles and the BES Definition must
coalesce and be clearly coordinated and understood. The BES Definition language must include reference to
the role of the associated defining documents. One unambiguous document must not be made ambiguous by
an associated document or process.

Response: The SDT appreciates the supportive comments and has taken into consideration the concerns raised by the commenter in its deliberations.
Exelon

The definition assumes some inclusions or exclusions based on levels of generation used in the NERC
Compliance Registry Criteria. Exelon does not view Orders 743 and 743-A as requiring a view or justification
of these thresholds. See Order No. 743-A at P 47 (“it was not our intent to disrupt the NERC Rules of
Procedure or the Statement of Compliance Registry Criteria”).

Response: The SDT agrees with the commenter.
Kootenai Electric Cooperative

August 19, 2011

Kootenai has these additional concerns: We are concerned that the proposed 24-month delay in the effective
date of the new definition will delay the potentially beneficial effects of the SDT’s efforts, especially for utilities
that have been inappropriately registered for BES-related functions, which is a common situation in WECC.

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We therefore urge the new BES definition to become effective immediately upon approval by FERC or other
applicable regulatory agencies. Entities that have been improperly registered for BES functions can then
immediately file for deregistration and obtain the benefits of the new definition as soon as possible. For
entities that have not previously been registered for BES-related functions but that would be required to
register under the new definition, we agree that 24 months is an appropriate transition period to allow the
newly-registered entity to attain compliance with newly-applicable reliability standards, many of which require
new training for employees, new maintenance procedures, and complex new operational protocols. However,
the transition period for newly-registered entities should be structured in a way that does not prevent entities
seeking deregistration from benefitting from the new definition at the earliest possible date. The current
definition provides that “Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.” Kootenai is concerned that the SDT carefully delineate which entity has the
burden of proof in the exclusion process. The WECC BESDTF approach, which we commend to the SDT,
laid out these burdens in some detail. Under that approach, essentially, if a facility is excluded from the BES
by virtue of the specific exclusions listed in the definition, the Regional Entity bears the burden of proving that
the facility nonetheless has a material impact on the interconnected bulk transmission system and therefore
should be included in the BES. On the other hand, if a facility is classified as BES by virtue of the list of
inclusions set forth in the BES definition, it can still escape classification as BES, but bears the burden of
demonstrating that its facility has no material impact on the interconnected transmission system. We urge the
SDT to give careful consideration to these burden-of-proof questions and to follow the lead of the WECC BES
Task Force.
For the reasons we have explained in our answer to Question 11, we believe the Exception process is critical
both to ensure that the BES definition is effective in producing measurable gains to bulk system reliability and
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the Standards
Development Process. Accordingly, we urge that all elements of the BES definition, including those elements
that have been assigned to the Rules of Procedure Team, be vetted through the Standards Development
Process.

Response: The SDT agrees with the commenter and has made revisions to the Implementation Plan to address these concerns surrounding the implementation
dates.
The SDT believes that the burden of proof issue should be resolved through the development RoP Exception Process. Your comments will be forwarded to the

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RoP team for consideration.
Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the appropriate
mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles associated with
the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed through the RoP
process for the revision of the Rules of Procedure.
Springfield Utility Board

Springfield Utility Board requests that NERC create a distinction between the terms BPS and BES. Are the
two to be used interchangeably, or will BPS no longer be used? SUB suggests NERC consider adopting the
statutory definition of the Bulk Power System as the core definition of the Bulk Electric System.
May 26, 2011Dear NERC Standards Drafting Team:Thank you for the opportunity to comment on NERC’s
proposed Continent-wide Definition of Bulk Electric System. We believe that NERC ‘s proposed Bulk Electric
System definition is proceeding in the right direction, but that more work needs to be done. SUB’s specific
concerns are as follows:
Bulk Power System (BPS) and Bulk Electric System (BES) - Springfield Utility Board requests that NERC
create a distinction between the terms BPS and BES. Are the two to be used interchangeably, or will BPS no
longer be used? SUB suggests NERC consider adopting the statutory definition of the Bulk Power System as
the core definition of the Bulk Electric System.
Clear definition of Radial - Because there still appears to be inconsistencies in both definition and application,
SUB encourages NERC to develop a concise definition of a radial system. For example, if a system is
normally operated as radial, but could be operated closed (by manually closing a breaker), would it be
considered a radial or close-looped system? If the answer is “that a closed system”, is this in all cases, or are
there exceptions?
Registration Status - SUB understands that one of the primary values of clearly defining the BES is for
registration determinations, as well as determining which of the Standards apply to registered entities. SUB
encourages NERC to support the use of the BES definition for entity registration, and to develop the
exception procedure for registered entities that do not own or operate any BES Elements.
Springfield Utility Board appreciates FERC and NERC’s efforts to create a continent-wide definition of Bulk
Electric System, and appreciates the opportunity to provide comment. Tracy Richardson Springfield Utility
Board SUB requests NERC to consider the situation where an entity has multiple, but separate systems. The
entity is required to become a Registered Entity because the sum of their individual systems meets the
thresholds, but portions of their physically separated systems taken individually would otherwise not reach the
threshold for registration. For example, an entity may be responsible for service over a third party’s
transmission for distribution service to a single end user with a load less than =<25MW that has a hard tap
into the third parties’ transmission. Because the load has a hard tap, it is technically served from more than

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one transmission source. If there are no other loads served along the tap or along the third party’s
transmission segment, SUB believes that this type of situation warrants exclusion from the BES as it would
otherwise be excluded - except for the fact that the combination of that service and other separate systems
that the entity is responsible for triggers registration.
SUB is concerned that devices such as shunt capacitor banks may be overlooked. For example, is a radial
system serving only load with a shunt capacitor bank included or excluded from BES? It does raise the issue
“what does “serving only load mean, exactly?” If a capacitor bank is used for purposes of managing reliability
within an local network and the local network would otherwise be classified as an LDN, is the local network
still classified as an LDN?

Springfield Utility Board

These comments are supplemental to Springfield Utility Board's comments provided to NERC on May 26,
2011 filed by Tracy Richardson. Please see the May 26 comments. This supplemental comment deals with
the concept of "serving only load" and the classification of what types of generation are incorporated into the
definition of generation for purposes of BES inclusion or exclusion.SUB's comment is that generation normally
operated as backup generation for retail load is not counted as generation for purposes of determining
generation thresholds for inclusion or exclusion from the BES. For purposes of BES inclusion or exclusion, a
system with load and generation normally operated as backup generation for retail load is considered "serving
only load" when using generation normally operated as backup generation for retail load (See Inclusions I2,
I3, I5, and Exclusions E1, E2, E3).The rationalle is that backup generation for retail load is normally used
during a localized outage and for testing for reliability during a localized outage event. Including backup
generation for retail load in generation thresholds (e.g. 75MVA) would not reflect generation used for
restoration or reliability of the BES. Including backup generation for retail load in generation threshold
calculations would cause an inappropriate inclusion of elements and devices, accelerate the triggering of
inclusion (and may make exclusion provisions meaningless), and push more activity of excluding smaller
systems from the BES into the exception process.

Response: The SAR for Project 2010-17 identifies the scope of the SDTs responsibilities. The scope does not include revision or any level of assessment of the
term Bulk Power System. Therefore any recommended revision to the definition of the BPS or recommendation on the usage or application of the term is not
within the responsibilities of the SDT. No change made.
The SDT has crafted language in Exclusion E1 that clearly identifies what constitutes a radial facility.
The SDT is revising the definition of the BES and use or application of this definition for registration purposes solely resides under the responsibilities of the
Certification and Registration department at NERC.
The SDT is revising the definition of the BES to identify BES Elements without regard to the ownership of such facilities. Ownership is an issue better addressed by
the registration process or the applicability of specific Reliability Standards. The SDT is not in a position to comment on specific situations without the opportunity

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to review all available information pertaining to the facility in question.
The SDT agrees with the commenter and has crafted revised Inclusion I5 language that specifically addresses Reactive Power resources.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.
The vast array of functional qualities of generation does not lend itself to a ‘bright-line’ concept of identifying BES Elements. Therefore the SDT has opted for the
size threshold designation of generating facilities and allows for use of the Exception Process for further analysis of the facility and potential exclusion from or
inclusion to the BES. No change made.
City of St. George

What are proposed transition implementation plans for facilities that will now be included in the definition?
The implementation plan indicates 24 months which may or may not be enough depending on the response
time to exception process. How will a pending exception action affect compliance requirements and effective
dates? It should be at least 24 months after it has been determined that a facility must be included.

Response: The SDT believes that the proposed 24 month period is sufficient time for entities to achieve the appropriate level of compliance with the Reliability
Standards. Comments concerning the Exception Process will be directed to the Rules of Procedure team for review. The SDT did, however, extend the effective
date by an additional quarter of a year based on stakeholder comments.
CenterPoint Energy

August 19, 2011

CenterPoint Energy appreciates the opportunity to provide comments. In reviewing the draft definition,
CenterPoint Energy believes the SDT may have unintentionally expanded the definition of the BES beyond
the statutory definition in Section 215. Facilities included in the BES should be those facilities that are
necessary for the reliable operation of the BES. Many interconnected facilities operated at 100kV and above,
particularly those that are operated between 100kV and 200kV, are interconnected primarily to enhance the
service provided to customers, rather than to maintain reliable operation of the BES.In addition; CenterPoint
Energy is concerned with the addition of another exception process to the Rules of Procedure (ROP). In
orders 743 and 743-A, the Commission allowed the ERO latitude to develop a definition that varied from the
Commission’s recommendation. CenterPoint Energy supports the inclusion/exclusion approach of the SDT
and believes it should be possible to define what constitutes the BES without an exception process.
Historically, exception processes within the ROP have been cumbersome, labor intensive, confusing, and
require on-going maintenance and quarterly or annual updates. Indeed, in question 10 of this comment form
the SDT recognizes the burden of administrating an exception process. While CenterPoint Energy
understands the SDT may feel pressure to produce a product quickly, the Company does not believe the
expedited nature justifies an inferior product. CenterPoint Energy recommends the SDT continue developing
criteria that clearly defines BES facilities based on the Section 215 language. Once that is accomplished, an
exception process will not be needed.

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Response: The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty
as possible in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current
application of the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support
consistent application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation
of the revision to the definition would not significantly expand or contract what is currently considered to be the BES. No change made.
The SDT believes that establishing a ‘bright-line’ approach to identify BES Elements will inherently incorrectly identify a small number of facilities. The Exception
Process is designed to clear up these discrepancies and render the proper classification of those questionable facilities. The SDT believes that with the draft core
definition and the BES designations (Inclusions and Exclusions) the vast majority of facilities will be correctly identified as BES or non-BES Elements and therefore
will produce the consistent application and results as desired by the Commission’s language in Order Nos. 743 & 743a.
The SDT made several changes to the definition, based on stakeholder comments that provide additional clarity to the definition. Please see the revised definition.
Southern California Edison
Company

As discussed during the May 19, 2011 NERC Webinar, SCE supports having one-line diagrams illustrating
examples of the line and bus arrangements as they pertain to the BES Definition included as part of a set of
support documents. A good start for these diagrams would be the ones developed by the WECC Bulk Electric
System Definition Task Force (WECC BESDTF). These diagrams were developed by WECC to better
illustrate the demarcation between BES and non-BES facilities and provide important information and insight
into the WECC system.

Response: The SDT has taken into account the work product of several regional efforts in the development of the draft BES definition. The SDT also recognizes
the value of a supporting reference document and will consider future development based on the project timeline and available resources.
Midstate Electric Cooperative

Yes MSEC has these additional concerns: The current definition provides that “Elements may be included or
excluded on a case-by-case basis through the Rules of Procedure exception process.” MSEC is concerned
that the SDT carefully delineate which entity has the burden of proof in the exclusion process. The WECC
BESDTF approach, which we commend to the SDT, laid out these burdens in some detail. Under that
approach, essentially, if a facility is excluded from the BES by virtue of the specific exclusions listed in the
definition, the Regional Entity bears the burden of proving that the facility nonetheless has a material impact
on the interconnected bulk transmission system and therefore should be included in the BES. On the other
hand, if a facility is classified as BES by virtue of the list of inclusions set forth in the BES definition, it can still
escape classification as BES, but bears the burden of demonstrating that its facility has no material impact on
the interconnected transmission system. We urge the SDT to give careful consideration to these burden-ofproof questions and to follow the lead of the WECC BES Task Force.
For the reasons we have explained in our answer to Question 11, we believe the Exception process is critical
both to ensure that the BES definition is effective in producing measurable gains to bulk system reliability and

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Question 13 Comment
to ensuring that the definition will comply with the limitations Congress placed in Section 215. Hence, we
believe the entire BES definition, including the Exception process and related procedures, should be vetted
through the NERC Standards Development Process, including the full comment periods and a ballot
approvals provided for in that process. We are concerned that important elements of the BES definition have
been assigned to the Rules of Procedure Team, and that changes in the Rules of Procedure are subject to
approval in a process that provides considerably less due process and industry input than the Standards
Development Process. Accordingly, we urge that all elements of the BES definition, including those elements
that have been assigned to the Rules of Procedure Team, be vetted through the Standards Development
Process.
Dear NERC Standards Drafting Team:Enclosed are MSEC’s comments on NERC’s Proposed Continent-wide
Definition of Bulk Electric System. We believe that NERC’s proposed Continent-wide Definition of Bulk
Electric System is proceeding in the right direction on this important topic but that more work needs to the
done. We would like to thank the Standards Drafting Team for their hard work. We support the detailed
comments of the Snohomish County Public Utility District and Pacific Northwest Generating Cooperative with
regard to the questions posed by the Comment Form for Project 2010-17 Definition of BES.We would like to
emphasize these portions of Snohomish’s and PNGC’s comments:
Question 1, both PNGC and Snohomish suggest that NERC start by adopting the statutory definition of the
bulk power system as the core definition. We support that approach. That is, “(t) he term ‘Bulk Electric
System’ means: (A) Facilities and control systems necessary for operating an interconnected electric energy
transmission network (or any portion thereof); and,(B) Electric energy from generation facilities needed to
maintain transmission system reliability.The term does not include facilities used in the local distribution of
electric energy”. See 16 U.S.C. § 824o(a)(1).”
Question 7, we support the exclusion for radial lines as drafted.
Question 9, we support the categorical exclusion of Local Distribution Networks from the BES as defined
here, but with Snohomish’s clarifications.
Question 10, we support exclusion E4, for small utilities, but we are unclear how small utilities are defined in
the exclusion language presented here.
Question 11, we support the approach to exclusion of local distribution facilities discussed in the draft but
repeat that more work should be done on the definition so that facilities used in local distribution are not swept
up into the BES.The primary value of clearly defining the BES is for registration determinations. We realize
that clearly defining the BES also has value in determining which standards apply to registered entities. If a
registered entity does not own any Elements of the BES that that registered entity should be able to efficiently
and effectively demonstrate an exception. We encourage NERC to support the use of the BES definition for
registration-issues and to develop the exception procedure for registered entities that do not own or operate

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Yes or No

Question 13 Comment
any Elements of the BES.

Response: The SDT believes that the burden of proof issue should be resolved through the development RoP Exception Process. Your comments will be
forwarded to the RoP DT for consideration.
Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the appropriate
mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles associated with
the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed through the RoP
process for the revision of the Rules of Procedure. No change made.
The SDT appreciates the industry support for this project. Please see the SDT responses in Questions 1, 7, 9, 10, and 11 of this document.
Illinois Municipal Electric Agency

Being a Joint Action Agency and Joint Registration Organization representing small municipal utility interests,
IMEA appreciates this initiative to better define electric systems that should and should not be considered part
of the Bulk Electric System. In addition to those comments provided above, IMEA supports comments
addressing other concerns as submitted by the Transmission Access Policy Study Group and the Small Entity
Working Group.

Response: Please see the SDT responses to the Transmission Access Policy Study Group and the Small Entity Working Group comments.
Long Island Power Authority

The SDT should clarify that Local Distribution Networks, including any facilities that are within the LDN, are
not subject to Reliability Standard Requirements pursuant to Section 215 of the Federal Power Act.

Response: The Local Distribution Network concept was developed to allow facilities operated at 100 kV or higher, that serve a distribution function, to be eligible
for exclusion if specific criteria are met. The use of the term ‘Local Distribution Network’ has resulted in some confusion by the industry in relation to the exclusion
of local distribution facilities indentified in Section 215 of the Federal Power Act. The SDT has elected to revise the Exclusion to be termed ‘Local Networks’ to
eliminate the confusion as to what type of facilities are being addressed by the Exclusion.
Clark Public Utilities

The process for identifying facilities as part of an LDN needs to be stated. Clark has heard that this will be
through a self-certification process, however, there is no written description how a utility classifies its
transmission facilities as an LDN.

Response: The SDT envisions that the current practice of self-identification continues with the revised definition of the BES. No change made.
Pepco Holdings Inc

August 19, 2011

1) It would be very helpful to include examples (with an explanation and diagram) of the various
configurations that meet each of the inclusions and exclusions. Can the next draft include such examples to
provide further clarity to the definitions? Consideration should be given to developing an attachment for this

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Question 13 Comment
material and a method to add appropriate examples in the future.
2) The proposal is silent on whether associated auxiliary and protection and control system equipment that
could automatically trip a BES facility independent of the protection and control equipment’s voltage level are
included as part of the BES. The RFC BES definition specially addresses this issue as an example. Does
IRO-005 cover those elements so it is not necessary to address these in this proposal? Consideration should
be given to referencing the issue in the BES document.

Response: 1) The SDT has taken into account the work product of several regional efforts in the development of the draft BES definition. The SDT also
recognizes the value of a supporting reference document and will consider future development based on the project timeline and available resources.
2) The SDT has determined that the draft BES definition should identify BES Elements which are operated at a voltage of 100 kV or above. The SDT also has
recognized the existence of facilities (i.e., auxiliary equipment and Protection Systems) that support the reliable operation of the interconnected transmission
network but do not necessarily operate at voltages of 100 kV or above and should not necessarily be classified as BES Elements. Reliability of the interconnected
transmission network is established by the application of Reliability Standards and the development of Reliability Standards is not limited in applicability to BES
Elements. Reliability Standards are written against facilities that support the reliable operation of the interconnected transmission network. Therefore the SDT
believes that the clarification of the BES definition does not require identification of these types of facilities and that the specific facilities in question are better
addressed by the applicability of individual Reliability Standards and not through the BES definition or the Exception Process. No change made.
Vigilante Electric Cooperative

Dear NERC Standards Drafting Team:Enclosed are Vigilante Electric Cooperative, Inc's (VIEC) comments on
NERC's Proposed Continent-wide Definition of the Bulk Electric System (BES).We believe that NERC's
proposed definition of the Bulk Electric System is moving in the right direction and we thank the Standards
Drafting Team for their hard work. We support the comments of the Snohomish County Public Utility Distric
and Pacific Northwest Generating Cooperative with regard to questions posed by the comment form for
Project 2010-17.We would like to add the following additional comments:
With regard to exclusion E3, part e) - we do not believe that just because an element is on a list that it cannot
be excluded. If an element meets all of the criteria to be excluded, then it should be excluded and removed
from the list. Otherwise, we strongly agree that LDNs have no material impact on the BES.We also strongly
encourage the continued development of a reasonable method for determination of inclusion/exclusion. We
believe that there should be a clearer path that would ultimately allow a utility to pursue being
included/excluded from registration with WECC. Many small utilities have an element that may actually have
no material impact on the BES yet is required to comply with all WECC standards.
We also would like to comment on the WECC compliance bulletin of April 15, 2011. While we greatly
appreciate the recognition that radial T-Taps with transformer or distribution protection schemes have no
material impact to the BES, we would encourage you to take this the additional logical step to actually remove
these instances from WECC responibilities. This would help reduce the burden both on WECC and the

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Question 13 Comment
individual entities and save everyone involved a tremendous amount of time, effort and money.We again
thank the Team for their efforts and appreciate the opportunity to be allowed to comment on these issues.

Response: The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the current language and to provide as much certainty
as possible in the identification of BES and non-BES Elements. The Commission provided guidance within Order Nos. 743 & 743a which identified the current
application of the existing BES definition was essentially correct for the majority of the continent and directed clarification of the existing language to support
consistent application across all regions. Additional guidance from the Commission spoke to significant changes in the scope of the definition with an expectation
of the revision to the definition would not significantly expand or contract what is currently considered to be the BES. No change made.
The SDT is drafting a definition with the expectation of consistent application across the continent. The introduction or removal of specific language to address
specific circumstances that may reside in the WECC footprint would not support this concept. No change made.
The SDT is not in a position to comment on a WECC Compliance Bulletin.
Central Lincoln

We believe the Exception process is critical both to ensure that the BES definition is effective in producing
measurable gains to bulk system reliability and to ensuring that the definition will comply with the limitations
Congress placed in Section 215. Hence, we believe the entire BES definition, including the Exception
process and related procedures, should be vetted through the NERC Standards Development Process,
including the full comment periods and a ballot approvals provided for in that process. We are concerned that
important elements of the BES definition have been assigned to the Rules of Procedure Team, and that
changes in the Rules of Procedure are subject to approval in a process that provides considerably less due
process and industry input than the Standards Development Process. Accordingly, we urge that all elements
of the BES definition, including those elements that have been assigned to the Rules of Procedure Team, be
vetted through the Standards Development Process.
We note also that the SAR still does not apply the definition to all registered entity types in violation of the
FERC order to provide a continent-wide definition. Please include PSEs in the SAR also.
We are concerned that the proposed 24-month delay in the effective date of the new definition will delay the
potentially beneficial effects of the SDT’s efforts, especially for utilities that have been inappropriately required
to meet BES reliability standards, which is a common situation in WECC. We therefore urge the new BES
definition to become effective immediately upon approval by FERC or other applicable regulatory agencies.
Entities that have been improperly required to meet standards can then immediately redirect resources to
where they are truly needed. For entities that have not previously been registered for BES-related functions
but that would be required to register under the new definition, we agree that 24 months is an appropriate
transition period to allow the newly-registered entity to attain compliance with newly-applicable reliability
standards, many of which require new training for employees, new maintenance procedures, and complex
new operational protocols. However, the transition period for newly-registered entities should be structured in

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Yes or No

Question 13 Comment
a way that does not prevent other entities from benefitting from the new definition at the earliest possible date.

Response: Upon initiation of the development project in response to Order Nos. 743 & 743a, NERC staff and the NERC Standards Committee determined the
appropriate mechanisms for the development of each aspect of the project. The revision of the BES definition and the development of the Technical Principles
associated with the Exception Process are currently being developed through the Standards Development Process. The RoP Exception Process is being developed
through the RoP process for the revision of the Rules of Procedure. No change made.
The draft BES definition identifies assets that meet specific criteria for classification as a BES Element. The NERC Functional Model defines the Purchase Selling
Entity (PSE) as: The functional entity that purchases or sells, and takes title to, energy, capacity, and reliability related services. The ownership or responsibility of
assets should trigger the registration of the functional entity in question in another area of registration. No change made.
The SDT agrees with the commenter and has made revisions to the Implementation Plan to address these concerns surrounding the implementation dates.
New England States Committee
on Electricity

As a general matter, the definition should reference the Exception Process, which may cause assets and
facilities to be further “included” or “excluded.”
In particular, once a facility has qualified for Exclusion it is not clear how that status is maintained.

Response: The phrase requested was inadvertently omitted from the first posting.
Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.
The SDT believes that maintaining an approved Exclusion should be resolved through the RoP Exception Process. Your comments will be forwarded to the RoP DT
for consideration.
PPL Energy Plus and PPL
Generation

August 19, 2011

The BES definition strives to draw a line between transmission customers (load and generation) and the
“network” that makes up the bulk electric system. All transmission customers served by the network are not
necessarily part of the network just like an on-ramp is not part of the Interstate highway, even though onramps deliver cars to the Interstate highway. FERC Order 743 paragraph 115 clearly gives guidance to the
NERC BES Definition Team (BESDT) on developing fair exclusion criteria for facilities not necessary for the
operation of the grid. PPL Generation and PPL Energy Plus (PPL) are concerned that the FERC order is
being read overly expansively to include much more generation in the BES than FERC intended. In the NERC
BESDT's latest proposed version of a BES definition, the definition appears to apply to small radial generators
(Inclusions I2 and I3) but not to large radial loads (Exclusions E1 and E3). The BESDT has chosen to exclude
or include LDNs based solely on the direction of power flow (see for example Exclusion E3-c) when the
magnitude of the power flow is more critical than the direction. An example of the stark contrast between
treatment of looped and radial facilities is exemplified by the exclusion of looped load and generation
facilities of almost any size (Exclusion E3) from the BES, versus the seeming omission of any effort to

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Question 13 Comment
exclude radially connected generation facilities over 20 MVA. Clearly, FERC Order 743-A paragraph 55
instructs the BESDT to consider “additional facility characteristics” other than voltage to come up with a fair
inclusion/exclusion process.The exclusion of looped facilities serving load and generation and the inclusion of
radial facilities serving only generation does not appear consistent. Moreover, it ignores the physical reality
that radial generator lead lines cannot be overloaded by outages on parallel paths because there are no
parallel paths. Further, the MW flow on a radial line is well known and limited to a known maximum (limited to
the larger of the generation or load on the end of the line): clearly reasons for exclusion. The BESDT should
look carefully at FERC Order 743 paragraph 73 which describes the characteristics of the electrical network
that the BES is trying to define. In that order, FERC justified its bright-line, 100 kV threshold, explaining that
"many facilities operated at 100 kV and above have a significant effect on the overall functioning of the grid"
because they share the following characteristics: 1. "operate in parallel with other high voltage and extra high
voltage facilities"i. The “bright line” at 100 kV recognizes many 100 kV lines parallel other HV/EHV lines and
can be significantly loaded by failure of the HV/EHV lines. This does not apply to radial lines, even at 100 kV
and above.2. "interconnect significant amounts of generation sources"3. "operate as part of a defined flow
gate"4. have a "parallel nature" and are capable of “caus[ing] or contribute[ing] to significant bulk system
disturbances”.i. Radial lines cannot cause significant BES disturbances since the outage of a radial line is
studied in all N-1 planning studies and if the TPL standards are followed, an N-1 should not cause such
disturbances.To their credit, the BESDT recognizes part of paragraph 73 in Exclusion E3-d and E3-e
(possibly exempting many hundreds of MVA load) but yet fails to exclude radial lines serving generators from
the BES “network”. Generation should be excluded from the definition of the BES on the same basis as load.
PPL requests the BESDT clearly exclude radial generators up to 200 MVA (1200 amps at 100 kV). This
exclusion is clearly justified because it would recognize many (if not all) loads and generators served radially
do NOT possess the Network Transmission Facilities characteristics described in FERC Order 743 paragraph
73. PPL hopes that the NERC BESDT will recognize (as FERC Order 743 in paragraph 120 recognizes) that
radial facilities and distribution facilities can both be excluded.

Response: The SDT scope was determined by the language contained in Order Nos. 743 & 743a in which the Commission provided guidance to the ERO to
clarify the definition for continent-wide application. The Commission did not propose significant changes to the current application of the existing definition over
the majority of the continent. Therefore the SDT has developed a draft core definition, together with BES designations (Inclusions and Exclusions) that provide
the specificity necessary to identify the vast majority of BES Elements by utilizing the existing definition and criteria previously approved for this purpose. Although
load is a component that can impact the reliability of the BES, the development of the definition is bound by the limitations documented in Section 215 of the
Federal Power Act. Expanding the definition to include load would exceed the jurisdictional boundaries into the area of local distribution facilities. No change
made.
The BES definition (core definition and Inclusions & Exclusions) will be applied to classify BES vs. non-BES Elements. The SDT believes that this will cover the vast
majority of the facilities in question. The remaining facilities will be candidates for the Exception Process (RoP) where the Technical Principles will be utilized to
determine if the facility is necessary for the reliable operation of the interconnected transmission network. Please see the revisions made to the revised definition.

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Manitoba Hydro

Yes or No

Question 13 Comment
Manitoba Hydro supports a 100kV bright line definition of the BES (excluding radial systems) that is
consistent across all regions.
We do not agree with the proposed impact based exception procedure and believe that the BES definition
should be stand-alone.
In addition, the complexity of the proposed BES definition and associated exception process may not provide
the goal of uniform application of the BES definition and moves the burden of assessment and approval to the
ERO.

Response: The SDT believes that establishing a ‘bright-line’ approach to identify BES Elements will inherently incorrectly identify a small number of facilities. The
Exception Process, a Commission identified component of the project, is designed to clear up these discrepancies and render the proper classification of those
questionable facilities. The SDT believes that with the draft core definition and the BES designations (Inclusions and Exclusions) the vast majority of facilities will
be correctly identified as BES or non-BES Elements and therefore will produce the consistent application and results as desired by the Commission’s language in
Order Nos. 743 & 743a.
The primary goal of the SDT in the revision of the definition of the BES is to improve clarity in the language and to provide as much certainty in the identification
of BES and non-BES Elements. Although the clarifications added to the core definition and the inclusions and exclusions have lengthened and increased the
complexity of the definition as a whole, the SDT feels that the improvements in clarity have increased the ability to apply the definition to achieve consistent
results.
Consolidated Edison Co. of NY,
Inc.

The ‘core’ definition is not clear as to whether an Element would be included if it meets any one (or must meet
more than one) of the 5 Inclusion criteria for inclusion?

Response: As inclusions speak to specific facilities and are not necessarily related other than for identification of BES Elements; if a facility meets the criteria of a
single inclusion then the facility is classified as a BES Element. Therefore only one (1) inclusion must be met for a facility to be classified a BES Element.
Independent Electricity System
Operator

We have no other concerns with the definition but we believe a guide demonstrating the correct application of
the definition under various transmission system configurations would be useful.

Response: The SDT also recognizes the value of a supporting reference document and will consider future development based on the project timeline and
available resources.
NB Power Transmission

August 19, 2011

Currently, the posted exception criterion is only a concept with many gaps and TBD, as posted details are
later to follow. The exception criteria should be a menu of technical items (load flows, stability analysis etc).
Entities should be required to assess and provide their own justification under each category with a
conclusion that takes into account all of the relevant items for element(s) under exception, in a consistent

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Question 13 Comment
template and table of contents. Suggest the SDT to avoid specification of any parameters as they would differ
under different design concepts, system configurations, system characteristics and regulatory requirements.
An “all encompassing” comment is that the definition is too lengthy with an overly prescriptive exception
process. The importance of the BES definition is recognized throughout the industry for its importance, and
as such it should be simple, clear, and straightforward.

Response: Comments concerning the Technical Principles (Exception Criteria) associated with the RoP Exception Process will be addressed through the dedicated
responses developed by the SDT and published in the specific Consideration of Comments document associated with that portion of the overall project.
Orange and Rockland Utilities,
Inc.

It was mentioned that Cranking Paths of Blackstart Resources are defined as BES. How about the path(s) of
generation units that will be deemed as BES? Please clarify.

Response: The SDT has revised the Inclusion that identified Blackstart Cranking Paths as BES Elements. A significant number of comments identified that the
Cranking Path could utilize local distribution facilities and could cross jurisdictional boundaries which should not be classified as BES Elements. Additionally the
Inclusions related to generation facilities have been revised to eliminate the language which suggested paths between generation and the transmission are
required to be contiguous Elements of the BES.
AltaLink

We believe that the concepts of inclusions and exclusions as part of the bright-line definition are excellent.
However, these exclusions do not address several directives in Order No. 743 and 743A, such as:
differentiation between Transmission and Distribution, non-jurisdictional concerns, or distribution. We believe
that the BES definition itself is not a venue to address these concerns but suggest that these issues should be
explicitly addressed by the ERO’s exception criteria and exception process. Currently, the posted exception
criterion is only a concept with many gaps and TBD, as posted details are later to follow. We suggest that the
exception criteria should be a menu of technical items (load flows, stability analysis etc) and non technical
items (type of loads such as distribution companies vs. major city center, national security etc). Entities should
be required to assess and provide their own justification under each category with a conclusion that takes into
account all of the relevant items for element(s) under exception, in a consistent template and table of
contents. We suggest the SDT to avoid specification of any parameters as they would differ under different
design concepts, system configurations, system characteristics and regulatory requirements.

Response: The SDT agrees with the commenter that the Exception Process should be the primary mechanism for addressing the concerns surrounding issues
such as: differentiation between Transmission and Distribution, non-jurisdictional concerns, or distribution. However the SDT has made modifications to the BES
core definition to address the issues associated with the jurisdictional concerns related to local distribution facilities.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission Elements operated at 100 kV or higher, and Real Power and
Reactive Power resources as described below, and Reactive Power resources connected at 100 kV or higher unless such designation is modified by the list

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Question 13 Comment

shown below. This does not include facilities used in the local distribution of electric energy.
Comments concerning the Technical Principles (Exception Criteria) associated with the RoP Exception Process will be addressed through the dedicated responses
developed by the SDT and published in the specific Consideration of Comments document associated with that portion of the overall project.
Modern Electric Water Company

1) The SDT states that “one of the basic tenets that the SDT is following is to avoid changes in registration
due the revised definition”. We stress the implications of a missed opportunity and the importance of a usable
BES definition, because if the revised definition does not allow the industry (both registered and nonregistered entities) as well as the regional reliability organizations to focus on and conduct business in a
fashion that promotes reliable and efficient system operation (not just ultra-conservative compliance
monitoring), then NERC has failed to do its job in this particular instance.
2) The proposed implementation plan indicates that the effective date of this definition is not for at least 24
months after regulatory approval. We strongly disagree with this suggested approach as it does not provide
for any benefit from this much-needed improvement. We believe the SDT intended to imply that entities not
currently registered would have at least 24 months to become compliant with applicable standards if the
improved BES definition suddenly swept them into the BES as it did for many small utilities on June 18, 2007.
The definition should become effective immediately upon regulatory approval, and transition plans for newlyregistered entities could specify longer timeframes.
3) As currently drafted, NERC’s Statement of Compliance Registry Criteria (Revision 5.0) contains the text of
NERC’s approved BES definition. Upon approval of any other language, the SCRC will become inaccurate
without review and modification.

Response: 1) The goals and assumptions established by the SDT are based on the documented Commission expectations in Orders Nos. 743 & 743a.
Opportunity does exist to further revise the definition beyond the clarification identified by the Commission in the Orders, however, technical justification is
required to deviate from the current application of the current BES definition. No change made.
2) The SDT agrees with the commenter and has made revisions to the Implementation Plan to address these concerns surrounding the implementation dates.
3) Review and potential revision of the NERC Statement of Compliance Registry is beyond the scope of the current SAR for this project. No change made.

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Diagram below refers to BGE comment for Q7:

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Technical Principles for Demonstrating
BES Exceptions
An entity must request an exception under this Exception Procedure before
any Element(s) that is included in the BES by application of the BES definition and
designations can be excluded from the BES. Likewise, an entity must request an
exception under this Exception Procedure before any Element(s) that is excluded from
the BES by application of the BES definition and designations can be included in the
BES.
Due to the importance of Blackstart Resources and their designated blackstart Cranking
Paths to restoration efforts, no exceptions will be allowed for those items.
Entities that have Element(s) already designated as excluded under the BES definition
and designations do not have to seek exception under the Exception Procedure.
The reasonableness of any such demonstration will be subject to review and remand by
the ERO itself, or by any agency having regulatory or statutory oversight of NERC as the
ERO (e.g., FERC or appropriate Canadian authorities).
Specific content of the application is spelled out elsewhere in this appendix.
Exception Criteria – Exclusions
Entities can submit an application to seek an exception from the BES definition,
including designations, by demonstrating the Element(s) are not necessary to reliably
operate the interconnected transmission network as demonstrated by one or both of the
following:
1. The Element(s) meet all of the following characteristics:
a. System Element(s) are located in close electrical proximity to Load.
i. Electrical proximity is a measurement of system impedance
between the interconnected transmission network and the Load
centers connected to the Element(s) within the system seeking
exception. Loads within the system seeking exception are in close
electrical proximity if they are separated by an impedance of no
greater than TBD.

Draft 1 – May 10, 2011
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Princeton, NJ 08540
609.452.8060 | www.nerc.com

ii. Evidence to support this position could include impedance cutsheets or power flow data.
b. System Elements are treated as radial in character.
i. This can be demonstrated by the way the connections to the BES
are operated, e.g., the Elements(s) are not operated as part of the
BES with disconnection procedures for when a Disturbance
occurs.
ii. This can also be demonstrated by the way the Element(s) are
treated in operations, for example, they are not included in a
regional dispatch.
iii. Evidence to support this position could include a one-line diagram
and pertinent Operating Procedures.
c. Power flows into the system, but rarely flows out.
i. This can be demonstrated through transactional records where it is
shown that flow out occurs only under a very limited set of
conditions and for a limited quantity of energy.
ii. The limited set of conditions must clearly state the conditions
where power flows out, for example, only under specified
Contingency events.
iii. Transactional records provided must be for the same time specified
in the Exception Rules of Procedure for performing periodic
exception self-certifications (presently two years).
iv. The maximum amount of energy flowing out is TBD MWh per
year.
v. Evidence to support this position could include hourly energy data
(MWh) for the most recent 12 month period.
d. Power entering the system is not intentionally transported through the
system to some other system.
i. This can be demonstrated by operational procedures that restrict
use of delivered power to that system.
ii. Evidence to support this position could include pertinent Operating
Procedures.
OR,
2. The Element(s) in question can be demonstrated as not being necessary for
reliable operation of the interconnected transmission network as follows:
a. Based on the model used in the most recent applicable planning
assessment:
i. If required, update the model to reflect your local conditions.
ii. If the model was updated, then run TPL studies for the first two
years of the Near-term Transmission Planning Horizon.
iii. Document all assumptions made in the analysis.
iv. Analyze the subject Element(s) against the following criteria:
1. Having a distribution factor of TBD% for any other
Element.

Draft 1 – May 10, 2011

2

2. Allowable transient voltage dip – criteria TBD
3. Allowable transient frequency excursion – criteria TBD
4. Voltage deviation – criteria TBD
5. Transient Stability – positively damped
6. Steady-state Stability – positively damped
7. No cascading outages
8. Other
v. If within the criteria in all cases, then the Element(s) can be
excluded.
vi. If not within the criteria, then the Element(s) can’t be excluded.
b. The ERO can override this criterion but would need to provide additional
justification to support their finding.
Exception Criteria – Inclusions
Entities can submit an application to seek an exception for an inclusion in the BES based
on the following condition:
1. The Element(s) in question can be demonstrated as being necessary for reliable
operation of the interconnected transmission network as follows:
a. Run TPL studies based on the existing model used in the most recent
applicable planning assessment.
b. Monitor the contribution of the disputed Element(s).
c. Analyze against criteria set by SDT through industry feedback.
1. Having a distribution factor of TBD% for any other
Element.
2. Allowable transient voltage dip – criteria TBD
3. Allowable transient frequency excursion – criteria TBD
4. Voltage deviation – criteria TBD
5. Transient Stability – not positively damped
6. Steady-state Stability – not positively damped
7. Cascading outages
8. Other
d. If within the criteria, then the Element(s) can’t be included.
e. If not within the criteria, then the Element(s) can be included.
f. The ERO can override this criterion but would need to provide additional
justification to support their finding.

Draft 1 – May 10, 2011

3

Comment Form for 1st Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions

Please DO NOT use this form. Please use the electronic comment form to submit
comments on the first draft of the Project 2010-17: Definition of the Bulk Electric System
(BES) Technical Principles for Demonstrating BES Exceptions. Only submit comments on
the first draft Technical Principles for Demonstrating BES Exceptions. The comments must
be submitted by June 10, 2011.
If you have questions please contact Ed Dobrowolski at ed.dobrowolski@nerc.net or by
telephone at 609-947-3673.

Background Information
Definition of the BES (Project 2010-17)
In parallel with the definition project, another stakeholder team outside the standards
development process has been set up to develop a change to the NERC Rules of Procedure
(ROP) to allow for entities to apply for excluding Elements from the BES that might
otherwise be included according to the proposed definition and designations. This same
process would be used by Registered Entities to justify including Elements in the BES that
might otherwise be excluded according to the proposed definition and designations. This
process would also be utilized for those situations where the core definition and
designations do not clearly identify whether an Element is BES or not. The ROP team will
develop the process for seeking an exception from the definition and designations, but the
Definition of the BES Standards Drafting Team (DBESSDT), through the standards
development process, has developed the criteria necessary for applying for an exception.
The exclusion exception process has been set up as a choice between two alternative forms
of evidence. The first choice is seen as less onerous in nature as it does not require
extensive technical analysis. An entity must choose which path it wants to pursue.
The inclusion exception process requires more detailed analysis and only one choice is
provided.
The first draft of the criteria that has been posted contains the evidence that must be
presented by an entity seeking an exception as well as specific criteria for how that
evidence will be evaluated. The SDT is seeking industry feedback not just on the approach
being presented but also on the specific numeric thresholds that will be used. Comments
received from this posting will help to determine the final criteria that the industry will be
required to adhere to. Therefore, industry feedback is vital to the development process.
It should be noted that the actual application process is described in the Rules of Procedure
document that has been posted concurrent with the criteria document.

116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com

Comment Form for 1st Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. The first item involves proximity to Load and
requests industry feedback on how to measure this variable. Do you agree with this
requirement? If you do not support this requirement or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. In addition, in the comment field, please provide your
thoughts on the appropriate impedance value to replace ‘TBD,’ including technical
rationale for your argument.
Yes:
No:
Comments:
2. Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. The second item involves Element(s) treated
as radial. Do you agree with this requirement? If you do not support this requirement
or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments.
Yes:
No:
Comments:
3. Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. The third item involves power flow. Do you
agree with this requirement? If you do not support this requirement or you agree in
general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments. In addition, in the comment field, please
provide your thoughts on the appropriate MWh value to replace ‘TBD,’ including
technical rationale for your argument.
Yes:
No:
Comments:
4. Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. The fourth item involves power transport. Do

Page 2 of 4

Comment Form for 1st Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions
you agree with this requirement? If you do not support this requirement or you agree in
general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.
Yes:
No:
Comments:
5. Exclusions - The SDT has set up one path for evidence that includes technical analysis.
Do you agree with this requirement? If you do not support this requirement or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. In addition, in the comment field,
please provide your thoughts on the proposed metrics for analysis and the appropriate
values to replace ‘TBD,’ including technical rationale for your argument.
Yes:
No:
5a. Comments on approach:
5b.Comments on distribution factor measurement:
5c. Comments on allowable transient voltage dip measurement:
5d. Comments on allowable transient frequency response:
5e. Comments on voltage deviation measurement:
6. Exclusions – Do you have other methods that may be appropriate for proving an
exclusion claim? Or, other variables/measurements that may be added to the
requirements already shown in the posted Technical Principles for Demonstrating BES
Exceptions? If so, please provide your comments here with technical rationale for why
they should be considered.
Yes:
No:
Comments:
7. Inclusions - The SDT has set up only one path for evidence that includes technical
analysis. Do you agree with this requirement? If you do not support this requirement or
you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. In addition, in the comment
field, please provide your thoughts on the proposed metrics for analysis and the
appropriate values to replace ‘TBD,’ including technical rationale for your argument.
Yes:
No:
7a. Comments on approach:

Page 3 of 4

Comment Form for 1st Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions
7b. Comments on distribution factor measurement:
7c. Comments on allowable transient voltage dip measurement:
7d. Comments on allowable transient frequency response:
7e. Comments on voltage deviation measurement:
8. Do you have concerns about an entity’s ability to obtain the data they would need to do
the indicated technical analyses? If so, please be specific with your concerns so that the
SDT can fully understand the problem and address it in future drafts.
Yes:
No:
Comments:
9. Are you aware of any conflicts between the proposed approach and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement, or
jurisdictional issue? If so, please identify them here and provide suggested language
changes that may clarify the issue.
Yes:
No:
Comments:
10. Are there any other concerns with this approach that haven’t been covered in previous
questions and comments? Please be as specific as possible with your comments.
Yes:
No:
Comments:

Page 4 of 4

Standards Announcement
Technical Principles for Demonstrating BES Exceptions
Appendix 5C - BES Component Exception Process
Two Comment Periods Open May 11-June 10, 2011
Webinar Scheduled on Thursday, May 19, 2011
Now available at: http://www.nerc.com/filez/standards/Project2010-17_BES.html and
http://www.nerc.com/filez/standards/Rules_of_Procedure-BES.html
On April 28, the BES Definition Drafting Team (DBES SDT) posted a revised draft BES definition for
comment through May 27, 2011. This announcement identifies two additional documents related to the BES
Definition that are also being posted for comment.
Two 30-day Comment Periods Open through 8 p.m. on June 10, 2011
To allow for comment in concert with the proposed definition of the Bulk Electric System under NERC
Standards Project 2010-17, NERC is requesting comments on a proposed revision to the NERC Rules of
Procedure to add Appendix 5C Bulk Electric System Component Exception Procedure. The proposed Appendix
5C is being posted for a 30-day comment period through 8 p.m. Eastern on Friday, June 10, 2011.
In addition, a proposed approach to developing evidence to support an application for a BES Exception,
Technical Principles for Demonstrating BES Exceptions, has been posted for a 30-day comment period until 8
p.m. Eastern on Friday, June 10, 2011.
A webinar has been scheduled for Thursday, May 19 from 11:00 a.m. to 1:00 p.m. Eastern to review all three
documents associated with the BES Definition project. A separate announcement will be sent with registration
instructions for this webinar.
Instructions for Submitting Comments on the Proposed Technical Principles for
Demonstrating BES Exceptions
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Monica Benson at monica.benson@nerc.net. An off-line, unofficial copy of the comment
form is posted on the project page: http://www.nerc.com/filez/standards/Project2010-17_BES.html
Instructions for Submitting Comments on the Proposed Rules of Procedure Modifications to
Incorporate a Process for Requesting BES Exceptions
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Elizabeth Heenan at Elizabeth.heenan@nerc.net. An off-line, unofficial copy of the
comment form is posted on the project page: http://www.nerc.com/filez/standards/Rules_of_ProcedureBES.html

Next Steps
The DBES SDT will consider all comments received on the Technical Principles for Demonstrating BES
Exceptions and make revisions to the document to incorporate stakeholder input. The team will post its
response to comments prior to the next posting.
The BES ROP team will consider comments on the proposed changes to NERC’s Rules of Procedure and make
revisions if appropriate. An additional 45 day comment period on Appendix 5C is contemplated in August as
Project 2010-17 is prepared for balloting.
Project Background
On November 18, 2010 FERC issued Order 743 and directed NERC to revise the definition of Bulk Electric
System so that the definition encompasses all Elements and Facilities necessary for the reliable operation and
planning of the interconnected bulk power system. Additional specificity will reduce ambiguity and establish
consistency across all Regions in distinguishing between BES and non-BES Elements and Facilities.
In addition, NERC was directed to develop a process for identifying any Elements or Facilities that should be
excluded from the BES. NERC is working to address these directives with two drafting teams – the definition
of Bulk Electric System (BES) is being revised through the standard development process and a BES Definition
Exception Process is being developed as a proposed modification to the Rules of Procedure. The proposed
approach to developing evidence to support an application for a BES Exception, Technical Principles for
Demonstrating BES Exceptions, was drafted by the BES Definition SDT with assistance from the BES Rules of
Procedure team.
The work of the BES Definition team is posted at: http://www.nerc.com/filez/standards/Project201017_BES.html
The work of the BES Rules of Procedure Definition Exception Process has been publicly posted at:
http://www.nerc.com/filez/standards/Rules_of_Procedure-BES.html.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Individual or group. (92 Responses)
Name (67 Responses)
Organization (67 Responses)
Group Name (25 Responses)
Lead Contact (25 Responses)
Question 1 (85 Responses)
Question 1 Comments (92 Responses)
Question 2 (86 Responses)
Question 2 Comments (92 Responses)
Question 3 (83 Responses)
Question 3 Comments (92 Responses)
Question 4 (85 Responses)
Question 4 Comments (92 Responses)
Question 5 (79 Responses)
Question 5a Comments (92 Responses)
Question 5b Comments (92 Responses)
Question 5c Comments (92 Responses)
Question 5d Comments (92 Responses)
Question 5e Comments (92 Responses)
Question 6 (81 Responses)
Question 6 Comments (92 Responses)
Question 7 (79 Responses)
Question 7a Comments (92 Responses)
Question 7b Comments (92 Responses)
Question 7c Comments (92 Responses)
Question 7d Comments (92 Responses)
Question 7e Comments (92 Responses)
Question 8 (77 Responses)
Question 8 Comments (92 Responses)
Question 9 (80 Responses)
Question 9 Comments (92 Responses)
Question 10 (84 Responses)
Question 10 Comments (92 Responses)

Individual
Angela P Gaines
Portland General Electric Company
The proposed Continent-wide Definition of Bulk Electric System has an Exclusion rule (E1) which
describes how radial facilities connected from a single Transmission source will not be considered part
of the BES when the radial system meets subcategory (a), (b), or (c). For the proposed Technical
Principles for Demonstrating BES Exemptions, the Exemption Criteria - Exclusions permits the entity
to submit an application seeking exclusion from the BES definition when the network meets all of the
following characteristics: a. System Elements are located in close electrical proximity to Load b.
System Elements are treated as radial in nature c. Power flows into the system, but rarely flows out
d. Power entering the system is not intentionally transported through the system to some other
system Portland General Electric Company (PGE) asserts that subcategory (b) should be stricken from
the criteria, since radial elements are already addressed in the Continent-wide Definition of Bulk
Electric System. This subcategory specifies that to meet the criteria, System Elements must be
"treated" as radial in nature. To be "treated" as radial, a system will inherently demonstrate
compliance with all of subcategories (a), (c), and (d); and therefore, the inclusion of subcategory (b)
is redundant in nature. In addition, PGE believes that Exception Criteria Exclusion 1.a.i. is ambiguous
because it does not provide a clear definition of where the “interconnected transmission network”
ends and the “Load center” begins. Also, PGE notes that a per unit impedance value will vary
contingent on base voltage, so PGE does not believe this measure should be used in measuring “close
proximity to Load.” Finally, PGE notes that the qualifiers “close,” “treated,” “rarely” and “intentionally”

are used in the current version of the proposed document. In following FERC's most recent Docket
No. RM11-18 regarding the revised TPL standards, there should be an effort to replace all qualifiers
with more quantifiable terms.

Group
Electric Market Policy
Connie Lowe
Yes
Yes
The word rarely should be struck from this item. It is meaningless in the context for which it is used
and offers little to characterize an element or connection since it does not contain a measure.
Yes

Yes

Yes
Generation Owners and Generation Operators are typically not given access to non-public
transmission information, especially that where a NDA or CEII signature is required. It would be
virtually impossible for a GO to refute proposed inclusion of an Element owned by the GO unless they
procure the services of a consulting firm with access to the data. And, even then, the consultant
couldn’t provide specifics of the evaluation only their findings.
Yes

Dominion is concerned that the provision of the proposed technical principles prohibiting the seeking
of an exclusion for a cranking path for blackstart resources will include local distribution facilities
within the definition of the BES. This conflicts with the definition of “Bulk Power System” in Section
215 of the Federal Power Act, which excludes facilities used in local distribution.
Yes
Although Dominion didn’t see a specific form to address comments on Appendix 5B to the NERC ROP,
Dominion would like to point out a particular area of concern with that Appendix. Dominion requests
that NERC include explicit language stating that exclusion or inclusion of an element (for compliance
purposes) begins only after approval/disapproval and any associated appeal has been reviewed and a
final decision reached. Dominion would also like to point out that it assisted in the preparation of the
Edison Electric Institute’s comments and therefore agrees with the comments raised by EEI.
Group
PacifiCorp
Sandra Shaffer
No
All of PacifiCorp’s responses are based on the application of these items to a given interconnection
and not on a continental basis. See comments on question 10. Setting a standard for close electrical
proximity using an impedance measurement does not address a proper measurement in all
interconnections. A better, more accurate measurement would be to utilize fault duty. Low fault duties
provide a good measurement of impact on the BES. Fault Duty at adjacent BES substations should
not exceed 5,000 MVA.
Yes
All of PacifiCorp’s responses are based on the application of these items to a given interconnection
and not on a continental basis. See comments on question 10. If this requirement is added to the four
requirements to capture local distribution networks, which are often operated in a looped
configuration, which may still be included in the BES by the proposed BES bright-line due to generator
inclusions, then this requirement has merit. Otherwise, exclusion E1 in the proposed BES bright-line
definition already covers this item and it becomes redundant.
Yes
All of PacifiCorp’s responses are based on the application of these items to a given interconnection
and not on a continental basis. See comments on question 10. This criterion is very similar to a part
of exclusion 3 of the proposed bright-line, which requires that power flows into the system. If the
intent of this requirement is to capture local distribution networks that may be included under the
proposed bright-line definition, then this requirement has merit. PacifiCorp proposes that instead of
using a measure of energy, that the SDT utilize a measure of time and recommends that flow out of
the system be limited to 15% on an annual basis. PacifiCorp does not have a technical justification for
15%, nor does it believe that a technical justification can be provided for any reasonable percent of
time used, or MWh used to be applied equally to all interconnections.
Yes
All of PacifiCorp’s responses are based on the application of these items to a given interconnection
and not on a continental basis. See comments on question 10. This criterion is very similar to parts of
exclusion 3 of the proposed bright-line, which states “d) Not used to transfer bulk power: The LDN is
not used to transfer energy originating outside the LDN for delivery through the LDN; and e) Not part
of a Flowgate or transfer path: The LDN does not contain a monitored Facility of a permanent
flowgate in the Eastern Interconnection, a major transfer path within the Western Interconnection as
defined by the Regional Entity, or a comparable monitored Facility in the Quebec Interconnection, and
is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).” If the
intent of this requirement is to capture local distribution networks that may be included under the
proposed bright-line definition, then this requirement has merit.
No
5a. Comments on approach: All of PacifiCorp’s responses are based on a given interconnection and
not on a continental basis. See comments on question 10. Using any technical criteria will allow many
elements to be excluded from the BES regardless of the element’s criticality to the interconnected
system. Whatever technical criteria is established should only be applied to elements under 200 kV
and any radial elements above 200 kV

5b.Comments on distribution factor measurement: All of PacifiCorp’s responses are based on a given
interconnection and not on a continental basis. See comments on question 10. Distribution factor has
little to no bearing on entities in the Western Interconnection.

Yes
All of PacifiCorp’s responses are based on a given interconnection and not on a continental basis.
Fault duty may be appropriate for certain interconnections only.
Yes
Please refer to additional comments in question 13 regarding a contiguous BES.

No
Yes
The SDT proposal combined with the ROP proposal may be in conflict with Section 215 of the Federal
Power Act, which requires “facilities used in the local distribution of electric energy” be excluded. The
processes proposed may be over inclusive and by default require several elements which are not
required for the reliable operation of the BES to in fact be included in the definition of “BES.”
Yes
The SDT has proposed several technical criteria to be used to determine if an element has an impact
on the reliability of the BES. PacifiCorp believes that the majority of non-BES elements can be
excluded using a modified proposed bright-line and/or using the non-technical approach. However, in
the event an entity requires additional justification to remove non-BES elements from the BES, then
PacifiCorp feels the technical criteria should be established on an interconnection basis, not on a
continent-wide basis. Because of the number of operating and geographic differences among the
interconnections, to try to establish technical criteria on a continental basis would introduce
confusion. PacifiCorp believes it is impossible to establish technical criteria that will allow unique
interconnections to be treated in a comparable manner.
Group
ReliabilityFirst
Jim Uhrin
No
it is far too complicated for the smaller entities
Yes
yes only true radial without any impact should be excluded otherwise include it
No
All power flow studies can be don eto show a small impact, this is how the system is planned. This will
only cause more confusion and debate between the FERC, NERC the Regions and registered entities
No
no one knows when some event will occur, putting this limitation will only cause debate. Any impact is
an impact and should be included
No
to complicated and will only raise debate between FERC, NERC, the Regions and the Registered
Entities
any impact is an impact, even generation is re-dispatched at 0% in some cases.
any impact is an impact, planning criteria between 3 & 5 % is often used and not allowed, why inject
this into what define the BES. the criteria is applied it should be included
any impact is an impact, planning criteria between 5 & 10 % is often used and restricted to guard

against these changes, why inject this into what define the BES. the criteria is applied it should be
included
any impact is an impact, planning criteria is often used and restricted to guard against these changes,
why inject this into what define the BES. If the criteria is applied to the facility as a BES element it
should be included
No
No
to complicated and will only raise debate between FERC, NERC, the Regions and the Registered
Entities
any impact is an impact, even generation is re-dispatched at 0% in some cases
any impact is an impact, planning criteria between 3 & 5 % is often used and not allowed, why inject
this into what define the BES. the criteria is applied it should be included
any impact is an impact, stability and planning criteria are often used and restricted and guard
against these changes, why inject this into what define the BES. if the criteria is applied it should be
included
any impact is an impact, planning criteria is often used and restricted to guard against these changes,
why inject this into what define the BES. the criteria is applied to the facility as a BES element it
should be included
Yes
many smaller entities would require assistance and or consultants to perform this analysis and some
data many not be available or be shared etc.
Yes
FERC stated that entities registered were not to be taken off the registry without sound reasons and
the definition sole intent was not to restrict or remove entities, but put in place a sound definition that
everyone can use. I do not think this is a help, it is very detailed and allot of entities will be confused
and lost
No
Individual
Michael Moltane
ITC
No
Please explain the rationale to require electrical proximity. Is it to limit fault exposure? Perhaps 2
miles of line could be shown to typically have few faults, thus limiting the number of voltage sags to
nearby buses. At approximately 0.7 ohms per mile 1.5 ohms (for overhead) might be a reasonable
number. Does it make a difference if the load is connected via underground cable?
Yes
ITC is in agreement if we are correct in assuming that any one of the three ways ( i, ii, or iii ) can be
used to satisfy the exclusion. We would also like to request additional clarification as to what
"disconnection procedures" would be valid for consideration in this requirement.

No

Individual
Michael Jones
National Grid
No
We feel that there is no relation between the proximity to load and system reliability. The impedance
is technically irrelevant, and we suggest that this criteria be dropped. If the criteria is not dropped,
there should be clarification on what is meant by “Load”. For instance are you really referring to
“major load centers”? In many areas of the country Load is connected all along a 100kV line and
hence much of a line is in close proximity to Load – but it could be small industrial loads and not
significant load centers. If significant Load Centers is what the drafting team was driving at then, we
believe it should be explicit. We also believe that if the drafting team is defining some technical
criteria, then it should not be in the exception process. It should be included as part of the core
definition. The exception process should be strictly limited to the procedures for application and
approval and should not include substantive elements.
Yes
We agree that elements that are treated as radial should be allowed to request an exception. We
would like more clarification about what is meant by “regional dispatch”. To the extent definitions of
terms such as “regional dispatch” are necessary; they should be addressed in the core definition
development process. The exception process should be strictly limited to the procedures for
application and approval and should not include substantive elements. We would also like clarification
on whether all three criteria under bullet b are required to show if the element is treated as radial, or
if meeting one is enough.
Yes
We agree with this requirement, but feel that assigning a specific value to the energy flowing out of
the system in MWh is unnecessary. The energy flowing out of a system depends on the size of the
area, and thus could vary widely. Another concern is about non-wires alternatives (NWA). One type of
non-wires alternative that is considered during planning studies is to reduce the amount of load on
our system by paying customers to not operate during peak hours. One scenario to consider is a
generator connected on a radial line that qualifies as BES, and will need upgrades if the generator
runs frequently. If this generator produces power close to the MWh threshold in the specified time
frame per NERC criteria, does it mean the utility company will have to consider paying the generator
owner money to shut down in order to keep total MWh generation below the threshold and avoid BES
criteria required radial line upgrades? This is another reason assigning a specific value to the energy
flowing out of the system is unnecessary. We would like clarification on whether all criteria (i,ii,iii,iv,v)
need to be met, or if just meeting one criteria is sufficient. We feel that meeting criteria 1.c.1, 1.c.ii
OR 1.c.iii is sufficient in showing that power rarely flows out of the system. Criteria 1.c.iv and 1.c.v
should be removed. The exception process should be strictly limited to the procedures for application
and approval and should not include substantive elements.
No
We feel that this requirement is not specific enough. “System” is too general. It should be clear what
is intended by “system”. Also, we would like more clarification about what is meant by “intentionally
transport”. Is the intent to mean there is a contract between a generator and load? The exception
process should be strictly limited to the procedures for application and approval and should not
include substantive elements.
We do not agree with all the criteria listed in point 2.a.iv. For example we believe that the term in
2.a.vi.6 “Steady-state Stability – positively damped” does not relate to the concept of steady-state
stability. We believe an acceptable measure of steady-state stability would be an angle difference

across the transmission line. That difference can vary depending on the line; however, a rule of
thumb is typically 45 degrees which provides a 30% steady state stability margin. As mentioned
previously, the exception process should be strictly limited to the procedures for application and
approval and should not include substantive elements.
We don’t think this measurement is necessarily relevant in determining whether an element is
necessary to system reliability. This criterion can be removed from the list. The exception process
should be strictly limited to the procedures for application and approval and should not include
substantive elements.

Yes
The NERC process could potentially by very lengthy and could interfere with the timely completion of
our studies. In the technical paths for exclusions, bullet v states “If within the criteria in all cases,
then the Elements can be excluded.” This could lead to a very high number of studies that need to be
done to prove an element should be excluded. For this reason, National Grid endorses a more
streamlined process. We propose a process where entities would only need to submit a short form
that briefly describes what they would like to exempt and the reason why, along with a one-line
diagram. The entity who is requesting the exception would have to maintain records that show why
the elements can be exempted until NERC performs an audit. At the audit, the entity can show the
proof of why the element should be granted an exception. This process also allows for the application
to remain public and reduces documentation burdens, because the non-public, CEII, or NERC CIP
protected supporting documentation is maintained by the applicant. In this process, the entity first
submits the application to their RE, and if approved by the RE, the application is submitted to NERC.
The entity should be able to appeal if either the RE or NERC denies the application; however, it should
be clear that for the second appeal to NERC, the decision is made by a different group than whoever
decided on the first appeal. The appeal process in this exception procedure could be similar to the
appeal process set by CMEP (compliance, monitoring and enforcement program). For entities that
don’t wish to wait until the next audit, there can be an optional process by which the proposed
exception can be reviewed to provide an immediate ruling. Also, there should be a grace period after
the audit is performed if audit staff concludes that an exception or inclusion granted by the initial
application is not supported by adequate evidence. NERC’s approval of an exception during this initial
application process should stand until an Entity is audited and a final audit report is issued. There
should also be an implementation period included in the audit report for the entity to come into
compliance if the audit report disagrees with the initial exception approval. Absent evidence of fraud
or intentional misrepresentation by the entity, there should be no non-compliance assessed for the
period from initial exception approval to the final audit report. This process would need to allow
participation or comments by Regional Entities, Reliability Coordinators, and/or Balancing Authorities
in the application process, but should not allow participation by other third parties.
There should be a non-technical process for inclusions similar to the exclusions process.

No
No
Insufficient time was provided to fully undertake this inquiry.
Yes
The exception process should be strictly limited to the procedures for application and approval and
should not include substantive elements.
Group
Tennessee Valley Authority
Richard Dearman

Yes
We agree with the requirement of an element being radial in character as being a qualifier for
exclusion thru the non-technical analysis. However, we recommend that the term "radial in character"
needs to be better defined. In addition, the language is confusing and we recommend the following:
i.: suggest replacing “disconnection procedures” with “automatic disconnection devices” ii.: The intent
of this item is not clear, and the term "regional dispatch" is not defined. Recommend the item be
clarified or deleted.
Yes
One possible starting point for selecting a MWh threshold: Generators of 20 MVA or less are typically
exempt from detailed modeling requirements. Suggest that reverse flows of this level or less, for a
period of 24 hours or less would be an acceptable threshold. Therefore, this would provide a basis for
selecting a threshold MWh level for reverse flows into the system under part iv. of 20 MW x 24 hours
= 480 MWh per year.
No
There is not sufficient evidence provided by the SDT to distinguish between this fourth item for
exclusion and the third item for exclusion. They both seem to fall in line with what is excluded per the
bright line exclusion E3 (or Local Distribution Networks), but as written, it would be difficult to
measure what is meant by “is not intentionally transported through” in this fourth item just as it
would be difficult to measure what’s meant by “flows into the system, but rarely flows out” for the
third item. Such an exclusion should be required to include some technical analysis, but not extensive
technical analysis (at least the inclusion of power flow base case as a minimum).
No
As written, most of this approach makes no sense. The words imply that if you have planned the
system properly, you can exclude it from the BES! In TPL studies you make sure that voltage dips,
frequency excursions, voltage deviations are acceptable, oscillations are damped, and no cascading
outages occur. So if you meet the performance requirements of TPL studies, you can exclude the
element from the BES. What good is this?
This is the only part of this technical analysis that may make sense. If the loss of any element of the
BES results in a distribution factor of less than X% on the element being considered for exclusion,
then exclude it. We suggest a value of 3% for this, since 3% is the threshold typically used in transfer
studies.
As stated above, it does not make sense to use this category.
As stated above, it does not make sense to use this category.
As stated above, it does not make sense to use this category.
Yes
Comments: Revise second paragraph to read “Due to the importance of designated Blackstart
Resources and their Cranking Paths to restore efforts, no exceptions will be allowed for those items
that are included in a system restoration plan.” Technical rationale: Multiple Blackstart Resources and
Cranking Paths are frequentlyavailable but are not included in a system restoration plan. System
restoration plans describe the Blackstart resources and cranking paths thar are deemed to be
necessary for system restoration. Section “Exception Criteria – Exclusions”: Add 1.e. “Generation that
is inoperable and not planned to be placed back into service but not yet officially decommissioned.”
Technical rationale: These facilities are not relied on to insure the reliability of the BES.
No
Applications for inclusion of facilities into the BES should include justification for doing so. However,
there should not necessarily be specific criteria that must be met, but the importance of the facility to
the BES should be clearly demonstrated.

No

No
No
Individual
Scott Bos
Muscatine Power and Water
No
The relevance and rationale for this criterion is unknown. If this criterion is intended to exempt
elements, like circuit switchers, that are part of the distribution transformer circuits operated above
100 kV, and located within a mile of the BES interconnection point, then NSRF would expect the
wording to be “in close electric proximity to the BES” rather than in “close electric proximity to Load”.
Requesting the SDT explain the relevance and rationale for this criterion before agreeing on its
inclusion.
No
Radial in Character –propose that this criterion be removed for the reason that it does not illustrate
any materially different characteristics beyond Exclusion E1 of the bright-line BES definition.
No
Proposing that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the bright-line BES definition.
No
This criterion should be eliminated based on the fact that it does not describe any materially different
characteristics beyond Exclusion E3 of the BES definition.
No
Would like to propose that this technical analysis criterion be changed to criteria that are more closely
tied to the Adequate Level of Reliability (ALR) characteristics. Would like to offer the following
alternate criteria as possible examples, “(1) the BES can be controlled to stay within acceptable limits
following a fault on or loss of the Element; (2) the BES performs acceptably subsequent to credible
contingences of the Element; (3) the Element does not limit the impact and scope of instability and
cascading outages once they occur; (4) BES Facilities are protected from undesirable damage by
operating the Element within its ratings; (5) the reliability of the BES can be restored promptly
subsequent to a fault on or loss of the Element; and (6) the BES has the ability to supply the
aggregate electric power and energy requirements of the electricity consumers at all times, taking
into account scheduled or reasonably expected unscheduled outages of the Element. Currently not
aware of any continent-wide appropriate BES performance metrics for voltage dip, frequency
excursion, voltage deviation, stability, etc. and would speculate that different values are likely for the
different regions and system characteristics across the continent. Thus, it is not advisable to try to
adopt unproven values without reasonable industry investigation and development.
Suggest replacing this aspect with those cited above because a distribution factor measurement
indicates how much system changes influence the element, not how much a loss of the element would
compromise the ALR of the BES. Currently unable to establish a clear correlation between this factor
and any of the six characteristics of Adequate Level of Reliability (ALR) of the BES.
Suggest replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable transient voltage dip performance level for evaluating whether a fault or
loss of the element would not compromise the ALR of the BES. In addition, the appropriate
performance level for this factor may be different in other areas and system characteristics across the
continent.
Suggest replacing this factor with those cited above. There are recognized, continent-wide transient
frequency performance levels in the PRC-006-1 standard; however, the elements that are applicable
to this standard are not necessarily BES elements and the transient frequency response requirements
are not intended to be a criterion for BES classification.
Requesting the STD replace this factor with those cited above. At this time there is no established,
continent-wide, acceptable (steady state) voltage deviation performance level for evaluating whether

a fault or loss of the element would not compromise the ALR of the BES. Moreover, the appropriate
performance level for this factor may vary for different areas and system characteristics across the
continent.
Yes
Recommending that this process address the six characteristics of the Definition of Adequate Level of
Reliability (ALR) as listed in the comments above in Question #5. Also recommend that municipalities
and other small entities having transmission systems designed to serve local load only, operated
below 200 kV and not having any IROL’s or SOL’s be excluded from the BES definition. Rationale: this
could affect smaller registered entities within a BA. The standards, especially those for Transmission
Operators, aren’t written for the smaller utilities. A small, municipal utility could have 75 MW of
generation and operate a 115 kV looped system around their service area that is used primarily to
serve their own load. Subsequently, they get forced into significant compliance requirements that
does not enhance the reliability of the BES whatsoever.
No
Would like to propose that the technical analysis criterion be replaced by criteria that are more closely
tied to the Adequate Level of Reliability (ALR) characteristics. The following alternate criteria are
offered as possible examples, “(1) the BES cannot be controlled to stay within acceptable limits
following a fault on or loss of the Element; (2) the BES does not perform acceptably after credible
contingences of the Element; (3) the Element limits the impact and scope of instability and cascading
outages when they occur; (4) BES facilities are not protected from unacceptable damage by operating
the Element within its ratings; (5) the integrity of the BES cannot be restored promptly following a
fault on or loss of the Element; and (6) the BES does not have the ability to supply the aggregate
electric power and energy requirements of the electricity consumers at all times, taking into account
scheduled or reasonably expected unscheduled outages of the Element. Currently not aware of any
continent-wide appropriate BES performance measures for voltage dip, frequency excursion, voltage
deviation, stability, etc. and would speculate that different values are likely for different regions and
system characteristics across the continent. Therefore, would like to state that it is not advisable to
try to adopt unproven values without reasonable industry investigation and development.
Proposing to replace this factor with those cited above because a distribution factor measurement
indicates how much system changes affect the element, not how a fault or loss of the element would
compromise the ALR of the BES. There is no clear correlation between this factor and any of the six
characteristics of Adequate Level of Reliability (ALR) of the BES.
Propose replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable transient voltage dip performance level for evaluating whether a fault or
loss of the element would compromise the ALR of the BES. In addition, the appropriate performance
level for this factor may vary for different areas and system characteristics across the continent.
Propose replacing this factor with those cited above because there are established, continent-wide
transient frequency performance levels in the PRC-006-1 standard, but the elements that are
applicable to the standard do not have to be BES elements and the transient frequency response
requirements are not intended to be a criterion for BES classification.
Propose replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable (steady state) voltage deviation performance level for evaluating whether
a fault or loss of the element would compromise the ALR of the BES. In addition, the appropriate
performance level for this factor may vary for different areas and system characteristics across the
continent.
No
No
Yes
1. Propose replacing the wording in the Exclusion preface, Exclusion 2 preface, and Inclusion 1
preface of “not necessary to reliably operate the interconnected transmission network” with
“necessary to maintain an Adequate Level of Reliability (ALR) of the Bulk Electric System”. 2.
Currently having reservations concerning the following statement made in the introduction of this
document: ” Due to the importance of Blackstart Resources and their designated blackstart Cranking

Paths to restoration efforts, no exceptions will be allowed for those items.” This does not allow for a
provision to exclude any designated Blackstart Cranking Path (at any voltage) even though there may
be technical justification for it. 3. The first page states that “Specific content of this application is
spelled out elsewhere in this appendix.” Request the SDT describe where this appendix will be
published and indicate if this is a compliance document or just technical “guidance”? 4. By having the
following statement included for both exclusions and inclusions will lead to disagreement: “The ERO
can override this criterion but would need to provide additional justification to support their finding.”
Suggesting that any override should include adequate technical justification and not interfere with
other statutory requirements. Also, it does not clarify or identify who would make the determination
whether NERC has made adequate justification to override the criterion. 5. Do not believe that the
“Inclusion” process should be completely removed from BES Definition. Would like to recommend
using bright-line criteria indentifying everything 100 kV and above to be considered BES and then
allow for the “Exception” process to take out Facilities that do not have an impact on the reliability of
the BES. Selecting BES Facilities based on bright-line criteria is what FERC requested in its Order
regarding BES Definition. This would streamline and simplify the process by removing a large quantity
of exceedingly unnecessary paperwork.
Individual
Bud Tracy
Blachly Lane Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should

be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the

Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, , as we discuss above, the Technical Principles for Demonstrating BES Exceptions present
a reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES

definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
No
SCE&G disagrees with the assumption that the proximity of a BES facility to Load is indicative of it's
importance to BES reliability. Some lower voltage facilities can be quite short and thus have lower
impedance but be important to BES reliability. Furthermore, the term "Load centers" is not defined
leaving it subject to interpretation. Assuming a load center has many busses, where would the
measurement be made - From the most distant load bus in the load center or the nearest? Similarly does a single facility get measured from it's terminal to the load center or does the presence or lack
of breakers need to be considered when selecting the measurement point?
Yes
SCE&G agrees with the requirement of an element being radial in character as being a qualifier for
exclusion thru the non-technical analysis. However, we recommend that the term "radial in character"
be better defined. In addition, the language is confusing and we would like to recommend the
following: i.: suggest replacing “disconnection procedures” with “automatic disconnection devices” ii.:
The intent of this item is not clear, and the term "regional dispatch" is not defined. Recommend the
item be clarified or deleted.
Yes
One possible starting point for selecting a MWh threshold: Generators of 20 MVA or less are typically
exempt from detailed modeling requirements. Suggest that reverse flows of this level or less, for a
period of 24 hours or less would be an acceptable threshold. Therefore, this would provide a basis for
selecting a threshold MWh level for reverse flows into the system under part iv. of 20 MW x 24 hours
= 480 MWh per year
No
There is not sufficient evidence provided by the SDT to distinguish between this fourth item for
exclusion and the third item for exclusion. They both seem to fall in line with what is excluded per the
bright line exclusion E3 (or Local Distribution Networks), but as written, it would be difficult to
measure what is meant by “is not intentionally transported through” in this fourth item just as it

would be difficult to measure what’s meant by “flows into the system, but rarely flows out” for the
third item. Such an exclusion should be required to include some technical analysis, but not extensive
technical analysis (at least the inclusion of power flow base case as a minimum).
No
As written, most of this approach makes no sense. The words imply that if you have planned the
system properly, you can exclude it from the BES! In TPL studies you make sure that voltage dips,
frequency excursions, voltage deviations are acceptable, oscillations are damped, and no cascading
outages occur. So if you meet the performance requirements of TPL studies, you can exclude the
element from the BES. This does not seem to be what was intended.
This is the only part of this technical analysis that may make sense. If the loss of any element of the
BES results in a distribution factor of less than X% on the element being considered for exclusion,
then exclude it. We suggest a value of 3% for this, since 3% is the threshold typically used in transfer
studies.
As stated above, it does not make sense to use this category.
As stated above, it does not make sense to use this category.
As stated above, it does not make sense to use this category.
Yes
Revise second paragraph to read “Due to the importance of designated Blackstart Resources and their
Cranking Paths to restore efforts, no exceptions will be allowed for those items that are included in a
system restoration plan.” Technical rationale: Multiple Blackstart Resources and Cranking Paths are
frequently available but are not included in a system restoration plan. System restoration plans
describe the Blackstart resources and cranking paths thar are deemed to be necessary for system
restoration. Section “Exception Criteria – Exclusions”: Add 1.e. “Generation that is inoperable and not
planned to be placed back into service but not yet officially decommissioned.” Technical rationale:
These facilities are not relied on to insure the reliability of the BES.
No
SCE&G recommends that applications for inclusion of facilities into the BES should include justification
for doing so. However, there should not necessarily be specific criteria that must be met, but the
importance of the facility to the BES should be clearly demonstrated.

No
No
No
Group
Northeast Power Coordinating Council
Guy Zito
No
1.a.i. Electrical Proximity - If impedance is to be used as a measure of electrical proximity, which in
turn is a replacement for geographical proximity, then how would the presence of parallel lines,
capacitors, phase-angle regulators (PARs), tap-changing transformers, generation and reactors be
treated in determining electrical proximity? How does this approach effectively differentiate between
transmission and distribution lines of the same voltage and length? When using impedance, how is
“greater than” determined? Sum of the Impedances - Would the filing entity simply add up the inseries impedances for each radial Element to demonstrate its electrical proximity? For example, would
the sum of the impedances from this radial path example be equal to the sum of the two feeder and
transformer impedances, i.e., measured from a 230 kV bus along a 230 kV feeder, through a 230/138
kV step-down transformer, and an in-series 138 kV feeder to a 138/13.8 kV step-down distribution

transformer? What impedance would the SDT apply to a PAR (or tap-changing transformer) and to
the overall path if a PAR (or tap-changing transformer) were located in-series with the measured
Elements? 1.a.ii. Power Flows – What is the meaning of “power flow data” as the term is used here
and how is the meaning different from the term when used under 1.c. Power flows into the system,
but rarely flows out? Should this sentence use the phrase “impedance data extracted from a load flow
study” instead? Entities should be required to identify the significance of the element’s physical
characteristics. Such identification can be done through a simple checklist along with any relevant
comments. The SDT should revise the exception criteria to seek an alternative language and/or revise
exclusion criteria (a), which will require entities to provide the previously stated information for their
element.
No
The term “regional dispatch” is not defined. Provide a definition or reference to a definition to be used
in making this determination. Recommend adoption of the alternate term “operational control.” 1.b.ii,
Operational Control - The SDT should consider using the terms “under the operational control of a
Balancing Authority.” It is instructive that the overarching requirement for a finding of transmission
system integration in Mansfield was that the facilities be under operational control of the Independent
System Operator (ISO).* * Southern Cal. Edison Co., 92 FERC ¶ 61,070 at 61,255 (2000), reh'g
denied 108 FERC ¶ 61,085 (2004). Replace the example in 1.b.i. with a clearer example. Entities
should be allowed to demonstrate the radial characteristics to determine if they are permitted for an
exception, and demonstrate compliance with radial defining criteria.
No
If an entity provides hourly MWh power flow data on a radial for a 12-month period (under v.)
showing no power flow reversals, would transaction data (under i. through iv.) still be required? Could
the entity just say “no transactional records?” If there were power flow reversals, wouldn’t the power
flow data (provided under v.) also show those, e.g., the amount and duration? Isn’t this request
redundant? If reversing power flows on a feeder caused it to fail one of the criteria, could the radial
still be excluded, or is it necessary for the Element to pass all requirements? Alternatively, could the
entity choose to file for Exclusion of that Element under the technical analysis option? What happens
and what are the implications when the two approaches produce different outcomes? Recommend
that “iv. The maximum amount of energy flowing out” limit be set to no more than 24 hours of
reverse power flows within any rolling 12-month period. Consider avoiding prescribing values and
eliminate bullet (iv). The intended performance outcome should be described, but without setting
values. This should not have any impact on the reliability of the transmission network if items 1, 2
and 3 are satisfied.
Yes
No
This method may allow an entity to exclude Elements which perform a transmission function, but that
are not the most limiting Element. “Not being necessary for reliability operation” needs definition. The
SDT should consider developing a Guidance Document to provide examples and insights to guide
prospective filing entities. The TPL Reliability Standards already describe the full set of requirements
for a reliable system. Why are added requirements necessary? Why would any such added criteria not
conflict with the TPL Reliability Standards to the extent that they were either more or less restrictive?
Entities should be given an option to conduct an analysis to demonstrate if an element is necessary
for the operation of a transmission network. NERC should specify all the relevant criteria categories to
be listed as under 2 (a). NERC should avoid prescribing numerical values, but instead establish a
range of values (or reference industry standards) that would be consistent with industry/ regional
standards or practices without compromising the reliability of the transmission network.
2.a. The term “Planning Assessment” is not a defined term in the NERC Glossary of Terms Used and
should not be capitalized, or it should be defined. 2.a.iv.1. Distribution Factor - This is a judgment of
what feeder power flow participation level is material and what is non-material. While TDF and OTDF
analysis is an indication of contributions from the element, the SDT should avoid setting values and
instead describe the intended performance outcome from a distribution factor measurement. Note
that ultimately NERC as an ERO or relevant regulatory authority will approve the application and can
assess the performance outcome in their decision making presented in an entity’s application.
Voltage dip is specified in terms of duration and retained voltage, usually expressed in percentage.

Suggest that either the SDT avoid using voltage dip as a criteria, or clearly specify that the transient
voltage not exceed the X limit of Y cycles (time). References to relevant industry standards such as
IEEE standard 1346-1998 should be made.
Suggest that for assigning a value for transient frequency response, entities conduct and submit to
the SDT their quantitative and qualitative technical assessment based on the conditions of the
element(s) under the application. Do not establish a fixed binary value within the exception criteria
but rather focus on the performance outcome. See 5 (a) above.
Voltage deviation is generally expressed as a percentage, between the voltage at a given instant at a
point in the system. Do not establish a fixed binary value within the exception criteria but rather focus
on the performance outcome. Adequate voltage performance does not guarantee system voltage
stability. Steady state stability is the ability of the grid to remain in synchronism during relatively slow
or normal load or generation changes, and to damp out oscillations caused by such changes. The
requirement should suggest that following checks are carried out to ensure system voltage stability
for both the pre-contingency period and the steady state post-contingency period: • Properly
converged pre- and post-contingency power flows are to be obtained with the critical parameter
increased up to 10% with typical generation as applicable; • All of the properly converged cases
obtained must represent stable operating points. This is to be determined for each case by carrying
out P-V analysis at all critical buses to verify that for each bus the operating point demonstrates
acceptable margin on the power transfer; and • The damping factor must be acceptable (the real part
of the eigen values of the reduced Jacobian matrix are positive).
Yes
An impact-based method should be available for entities seeking Exclusions and Inclusions. The
method should not allow excess regional discretion and unintended continent-wide variation.
Recommend the power Transfer Distribution Factor (power TDF) approach mentioned in the reply to
Question 5 above. If the Transmission Planner (TP) or Planning Authority (PA), were tasked with
performing such analyses using standardized assumptions, then regional discretion could be
minimized. Technical Analysis must fundamentally use NERC – TPL methodology and testing
requirements.
No
Inclusions criteria should mirror the Exclusion criteria, and that consistent values should be employed
for Inclusions here and for Exclusions above. That is, for example, if 0.95 to 1.05 (+/- 5%) p.u. is
adopted as an acceptable voltage deviation range for Exclusions, then Elements resulting in posttransient system voltage deviations outside that range should be candidates for Inclusion. Further, all
assumptions should also be fully documented for any proposed Inclusions. Also refer to comments on
exclusions.
See reply to Questions 5b and 6 above.
Refer to the response to Question 5c
Refer to the response to Question 5d
See reply to Questions 5e and 6 above.
No
Yes
It is imperative to understand that the NERC’s revised definition will have a direct impact on entities
across North America and may conflict with regulatory requirements, Codes, and Licenses. FERC in its
Orders 743 and 743A has directed NERC to address these concerns. For Ontario, the BES exception
criteria shall meet the expectations of Ontario's regulator (Ontario Energy Board) which has the sole
authority and responsibility for the reliability of customer connections and loads within Ontario.
Therefore, it will be necessary to accommodate NERC's proposed definition of BES or the exception
process with the Ontario situation. The SDT and RoP teams should: • Modify the exception criteria
and procedure to provide regulatory flexibility with requirements to conduct basic technical analysis ,
to allow entities to consistently present their case to the ERO and/or the regulator for a step by step
expedited evaluation. • Include provisions in both the NERC exception criteria and exception process
for federal, state and provincial jurisdictions. These provisions should provide clear guidance so that,
if and when there are deviations from the exception criteria, they are identified with technical and
regulatory justifications ensuring there is no adverse impact on the interconnected transmission

network. • Understand that the path to generating facilities need not be always BES contiguous.
Generating units can/should be required to be planned, designed, and operated in accordance with a
subset of NERC Standards, but should not always require contiguous paths.
Yes
Exception criteria should be crafted at a high-level with key menu items of assessment that can be
followed continent-wide by entities to put forward their exception(s) for element(s) that are not
necessary for the interconnected transmission network based on technical assessment, evidence and
justification for unique characteristics, configuration, and utilization. (Also see suggestions/ comments
in Question 6)
Individual
Josh Dellinger
Glacier Electric Cooperative
No
I do not think that the proximity to load should be a factor in determining whether or not an element
should be included in the BES. Rather, the purpose of the element should be the important factor. If
an element only serves load, then that should be the most important factor and the proximity
(electrical or physical) to that load should not matter.
No
I do agree that radial elements should definitely be excluded. However, I believe that non-radial
elements should be able to be excluded by Path 1 as well. If a small local distribution system is
operated non-radially for the purpose of improving reliability for its loads, then that system should be
eligible for exclusion from the BES. I also believe that language needs to be included that makes the
provision for radial elements that can be temporarily and briefly looped together during switching to
prevent an outage (e.g. for transformer maintenance) to also be excluded from the BES.
No
Regarding using power flow into and out of a system as a criterion fro BES exclusion, I do not think
that establishing a hard MWh per year is the proper approach to take. Once again, I believe that the
purpose of the system should be the most important factor. If the purpose of a system is to serve
load or transport non-essential generation (i.e. wind power), then that system should be able to be
exluded.
No
I believe that there should be a provision for systems that intentionally transport variable, nonessential generation (such as systems that transport wind power) to be excluded from the BES. By
nature, these types of systems cannot be essential to the BES due to the variability of the generation,
and, therefore, should be able to be excluded from the BES.
No
I strongly agree that there should be a way for elements to be excluded from the BES based on a
technical analysis. However, the current approach only provides one technical avenue for exclusion
and that is through a transmission planning study. Performing and analyzing such a study could be
very, very difficult for a small entity to do. If this is the approach that NERC continues with, then I
believe there needs to be some extra language outlining who is responsible for performing and
analyzing these transmission planning studies. The question is should the RRO (WECC, etc.) be
responsible for performing the study and determining through the technical criteria what elements are
included and excluded in the BES, or should that resposiblity fall on control area operators within an
RRO, or should that responsibility fall on individual entities? I believe it should fall on either the RROs
or the control area operators within the RROs. Perhaps an alternative approach could be to establish a
few techincal checks that could be evaluated first before a transmission planning study is required.
For example, a max fault MVA value could be established and if the available fault MVA at an element
is less than the established value, then that element and could be excluded without having to go
through a transmission planning study. If the available fault MVA at the element is above the
established value, then the study would have to be done for determination.

Yes
Perhaps using an element's available fault MVA as a "quick screening" method to quickly determine if
an element should be included or excluded. If an element's available fault MVA exceeds a properly
established value, then a more detailed technical analysis can be done to determine whether or not
the element truly should be included in the BES. But if the elemet's available fault MVA is less than
the established value, then that element could quickly be excluded.
Yes
I do strongly agree that there should be an avenue for elements to be included or excluded from the
BES based on technical analysis. I do believe who's responsibility it will be to perform and analyze the
transmission planning studies needs to be clarified.

Yes
It could be very, very difficult and costly for small utilities to perform the necessary transmission
planning studies described in the proposal. I think there needs to be language clarifying how smaller
utilities should be able to obtain this data.
No
No
Individual
Diane Barney
New York State Department of Public Service

The core BES definition based on a 100 kV brightline is an overreach of bulk system designation
under the provisions of the Federal Power Act; a properly specified BES core definition would avoid
the extensive analysis required under the exceptions procedure. That said, the proposed principles for
use in the exceptions process are consistent with previous FERC efforts to distinguish between
transmission and local distribution. The upfront exclusion of applying the proposed principles to
blackstart cranking path facilities is a potential overreach into the local distribution system and can be
counter productive reliability. Mandating compliance of NERC standards to cranking paths will result in
the specification of only one cranking path by host utilities to minimize costs, where designating

multiple paths in restoration paths would provide the flexibility needed to minimize customer outage
duration.
Individual
John Bee
Exelon
No
The term “close proximity” is ambiguous and open ended. Exelon believes that all facilities used in
local distribution of electric energy that are presently under state jurisdiction should be excluded from
the BES regardless of system impedance.
No
The term “rarely” is ambiguous and should be removed or quantified. Furthermore, the requirement
for power flow analysis will be viewed by many entities as extensive technical analysis.

No
This item calls for the use of criteria in order to prove that a facility should be excluded the BES. First
of all, the items 5b – 5e do indeed require extensive technical analysis which will be outside of the
capabilities of many users of the BES. Furthermore, it is not clear who’s criteria will be used? The
user’s? The Transmission Owner’s? The Planning Authority’s? This question of ownership needs to be
resolved and in itself poses a problem for this process. If differing criteria levels are used across the
continent, there remains the possibility that similarly-situated facilities in different Regions will not be
treated consistently.

No
: Exelon points out that most of the Regions don’t have Region-wide criteria for distribution factor
measurement, voltage excursions, or transient frequency response for use in this proposed Inclusion
Process. In addition, most of the Regions do not have region-wide criteria developed for these
attributes. If differing criteria levels are used across the continent, there remains the possibility that
similarly-situated facilities in different Regions will not be treated consistently.

Yes
As mentioned above, this process will require extensive technical analysis from users, owners,
operators and the Regions. In many cases, the Principles anticipate the use of criteria that is not in
existence today. Rather than reinforcing the bright line approach, these Principles have the potential
to create processes that will result in high costs with little to no corresponding benefits to reliability.
Yes
To the extent facilities used in local distribution of electric energy may be included in the BES, the
proposed principles are in conflict with the Federal Power Act.
No
Individual
Bob Casey
Georgia Transmission Corporation
No

GTC disagrees with the assumption that the proximity of a BES facility to Load is indicative of it's
importance to BES reliability. Some lower voltage facilities can be quite short and thus have lower
impedance but be important to BES reliability. Furthermore, the term "Load centers" is not defined
leaving it subject to interpretation. Assuming a load center has many busses, where would the
measurement be made - From the most distant load bus in the load center or the nearest? Similarly does a single facility get measured from it's terminal to the load center or does the presence or lack
of breakers need to be considered when selecting the measurement point?
Yes
GTC agrees with the requirement of an element being radial in character as being a qualifier for
exclusion thru the non-technical analysis. However, GTC recommends that the term "radial in
character" needs to be better defined. In addition, the language is confusing and the PSS would like
to recommend the following: i.: suggest replacing “disconnection procedures” with “automatic
disconnection devices” ii.: The intent of this item is not clear, and the term "regional dispatch" is not
defined. Recommend the item be clarified or deleted.
Yes
One possible starting point for selecting a MWh threshold: Generators of 20 MVA or less are typically
exempt from detailed modeling requirements. Suggest that reverse flows of this level or less, for a
period of 24 hours or less would be an acceptable threshold. Therefore, this would provide a basis for
selecting a threshold MWh level for reverse flows into the system under part iv. of 20 MW x 24 hours
= 480 MWh per year.
No
As written, most of this approach makes no sense. The words imply that if you have planned the
system properly, you can exclude it from the BES! In TPL studies you make sure that voltage dips,
frequency excursions, voltage deviations are acceptable, oscillations are damped, and no cascading
outages occur. So if you meet the performance requirements of TPL studies, you can exclude the
element from the BES. What good is this?
This is the only part of this technical analysis that may make sense. If the loss of any element of the
BES results in a distribution factor of less than X% on the element being considered for exclusion,
then exclude it. We suggest a value of 3% for this, since 3% is the threshold typically used in transfer
studies.
As stated above, it does not make sense to use this category.
As stated above, it does not make sense to use this category.
As stated above, it does not make sense to use this category.
Yes
Revise second paragraph to read “Due to the importance of designated Blackstart Resources and their
Cranking Paths to restore efforts, no exceptions will be allowed for those items that are included in a
system restoration plan.” Technical rationale: Multiple Blackstart Resources and Cranking Paths are
frequently available but are not included in a system restoration plan. System restoration plans
describe the Blackstart resources and cranking paths that are deemed to be necessary for system
restoration. Section “Exception Criteria – Exclusions”: Add 1.e. “Generation that is inoperable and not
planned to be placed back into service but not yet officially decommissioned.” Technical rationale:
These facilities are not relied on to insure the reliability of the BES.
No
GTC recommends that applications for inclusion of facilities into the BES should include justification
for doing so. However, there should not necessarily be specific criteria that must be met, but the
importance of the facility to the BES should be clearly demonstrated.

No

No
No
Group
SERC Planning Standards Subcommittee
Charles W. Long
No
The PSS disagrees with the assumption that the proximity of a BES facility to Load is indicative of it's
importance to BES reliability. Some lower voltage facilities can be quite short and thus have lower
impedance but be important to BES reliability. Furthermore, the term "Load centers" is not defined
leaving it subject to interpretation. Assuming a load center has many busses, where would the
measurement be made - From the most distant load bus in the load center or the nearest? Similarly does a single facility get measured from it's terminal to the load center or does the presence or lack
of breakers need to be considered when selecting the measurement point?
Yes
The PSS agrees with the requirement of an element being radial in character as being a qualifier for
exclusion thru the non-technical analysis. However, the PSS recommends that the term "radial in
character" needs to be better defined. In addition, the language is confusing and the PSS would like
to recommend the following: i.: suggest replacing “disconnection procedures” with “automatic
disconnection devices” ii.: The intent of this item is not clear, and the term "regional dispatch" is not
defined. Recommend the item be clarified or deleted.
Yes
One possible starting point for selecting a MWh threshold: Generators of 20 MVA or less are typically
exempt from detailed modeling requirements. Suggest that reverse flows of this level or less, for a
period of 24 hours or less would be an acceptable threshold. Therefore, this would provide a basis for
selecting a threshold MWh level for reverse flows into the system under part iv. of 20 MW x 24 hours
= 480 MWh per year.
No
There is not sufficient evidence provided by the SDT to distinguish between this fourth item for
exclusion and the third item for exclusion. They both seem to fall in line with what is excluded per the
bright line exclusion E3 (or Local Distribution Networks), but as written, it would be difficult to
measure what is meant by “is not intentionally transported through” in this fourth item just as it
would be difficult to measure what’s meant by “flows into the system, but rarely flows out” for the
third item. Such an exclusion should be required to include some technical analysis, but not extensive
technical analysis (at least the inclusion of power flow base case as a minimum).
No
As written, most of this approach makes no sense. The words imply that if you have planned the
system properly, you can exclude it from the BES! In TPL studies you make sure that voltage dips,
frequency excursions, voltage deviations are acceptable, oscillations are damped, and no cascading
outages occur. So if you meet the performance requirements of TPL studies, you can exclude the
element from the BES. What good is this?
This is the only part of this technical analysis that may make sense. If the loss of any element of the
BES results in a distribution factor of less than X% on the element being considered for exclusion,
then exclude it. We suggest a value of 3% for this, since 3% is the threshold typically used in transfer
studies.
As stated above, it does not make sense to use this category.
As stated above, it does not make sense to use this category.
As stated above, it does not make sense to use this category.
Yes
Revise second paragraph to read “Due to the importance of designated Blackstart Resources and their
Cranking Paths to restore efforts, no exceptions will be allowed for those items that are included in a
system restoration plan.” Technical rationale: Multiple Blackstart Resources and Cranking Paths are

frequently available but are not included in a system restoration plan. System restoration plans
describe the Blackstart resources and cranking paths thar are deemed to be necessary for system
restoration. Section “Exception Criteria – Exclusions”: Add 1.e. “Generation that is inoperable and not
planned to be placed back into service but not yet officially decommissioned.” Technical rationale:
These facilities are not relied on to insure the reliability of the BES.
No
The PSS recommends that applications for inclusion of facilities into the BES should include
justification for doing so. However, there should not necessarily be specific criteria that must be met,
but the importance of the facility to the BES should be clearly demonstrated.

No
No
No
The comments expressed herein represent a consensus of the views of the above-named members of
the SERC EC Planning Standards Subcommittee only and should not be construed as the position of
SERC Reliability Corporation, its board, or its officers.
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
No
We generally support this exclusion option concept, to the extent that it is fashioned after the FERC
Seven Factor test. However, we have a number of questions as to how it might work in practice. 1.a.i.
Electrical Proximity - If impedance is to be used as a measure of electrical proximity, which in turn is
a replacement for geographical proximity, then how would the presence of parallel lines, capacitors,
phase-angle regulators (PARs), tap-changing transformers, generation and reactors be treated in
determining electrical proximity? How does this approach effectively differentiate between
transmission and distribution lines of the same voltage and length? When using impedance, how is
“greater than” determined? Sum of the Impedances - Would the filing entity simply add up the inseries impedances for each radial Element to demonstrate its electrical proximity? For example, would
the sum of the impedances from this example radial path be equal to the sum of the two feeder and
transformer impedances, i.e., measured from a 230 kV bus along a 230 kV feeder, through a 230/138
kV step-down transformer, and an in-series 138 kV feeder to a 138/13.8 kV step-down distribution
transformer? What impedance would the SDT apply to a PAR (or tap-changing transformer) and to
the overall path if a PAR (or tap-changing transformer) were located in-series with the measured
Elements? 1.a.ii. Power Flows – What is the meaning of “power flow data” as the term is used here
and how is the meaning different from the term when used under 1.c. Power flows into the system,
but rarely flows out? Should this sentence use the phrase “impedance data extracted from a load flow
study” instead?
No
We generally support this exclusion option concept, to the extent that it is fashioned after the FERC
Seven Factor test. However, we have a number of questions as to how it might work in practice. For
example, the term “regional dispatch” is not defined. Please provide a definition or reference to a
definition to be used in making this determination. Below we recommend adoption of the alternate
term “operational control.” 1.b.ii, Operational Control - The SDT should consider using the terms
“under the operational control of a Balancing Authority.” It is instructive that the overarching
requirement for a finding of transmission system integration in Mansfield was that the facilities be
under operational control of the Independent System Operator (ISO).* * Southern Cal. Edison Co., 92
FERC ¶ 61,070 at 61,255 (2000), reh'g denied 108 FERC ¶ 61,085 (2004). Replace the example in
1.b.i. with a clearer example.

No
We generally support this exclusion option concept, to the extent that it is fashioned after the FERC
Seven Factor test. However, we have a number of questions as to how it might work in practice. For
example: • If an entity provides hourly MWh power flow data on a radial for a 12-month period
(under v.) showing no power flow reversals, would transaction data (under i. through iv.) still be
required? Couldn’t the entity just say “no operating records?” • If there were power flow reversals,
wouldn’t the power flow data (provided under v.) also show those, e.g., the amount and duration?
Isn’t this request redundant? If not, why not? Please explain. • If reversing power flows on a feeder
caused it to fail one of the criteria, could the radial still be excluded, or is it necessary for the Element
to pass all requirements? Alternatively, could the entity choose to file for Exclusion of that Element
under the technical analysis option? What happens and what are the implications when the two
approaches produce different outcomes? We recommend that “iv. The maximum amount of energy
flowing out” limit be set to no more than 24 hours of reverse power flows within any rolling 12-month
period. Replace “transactional records” with “operating records.”
Yes
No
The technical analysis approach may have merit. However, we have a number of questions about how
it would be implemented in practice. We are concerned that this method may allow an entity to
exclude Elements simply because they are not the most limiting Element in a particular TPL analysis.
What does “not being necessary for reliability operation” mean? Please define. The SDT should
consider developing a Guidance Document to provide examples and insights to guide prospective
filing entities. The TPL Reliability Standards already describe the full set of requirements for a reliable
system. Why are added requirements necessary? Why would any such added criteria not conflict with
the TPL Reliability Standards to the extent that they were either more or less restrictive?
2.a. The term “Planning Assessment” is not a defined term in the NERC Glossary of Terms Used and
should not be capitalized, or alternatively it should be defined. 2.a.iv.1. Distribution Factor - The issue
comes down to a judgment call concerning what feeder power flow participation level is material and
what is non-material. In New York, the NYISO has traditionally used a 1% power transfer distribution
factor (power TDF) cut-off. Feeders showing less than a 1% power transfer in a study are not
materially participating in transmission.

The NYISO uses a 0.95 to 1.05 p.u. as the acceptable range for post-transient system conditions.
Yes
An impact-based method should be available for entities seeking Exclusions and Inclusions. The
method should not allow excess regional discretion and unintended continent-wide variation. We
recommend the power Transfer Distribution Factor (power TDF) approach mentioned in the reply to
Question 6 above. If the Transmission Planner (TP) or Planning Authority (PA), e.g., the NYISO, were
tasked with performing such analyses, using standardized assumptions, then regional discretion could
be minimized.
No
We believe that Inclusions criteria should mirror the Exclusion criteria, and that consistent values
should be employed for Inclusions here and for Exclusions above. That is, for example, if 0.95 to 1.05
(+/- 5%) p.u. is adopted as an acceptable voltage deviation range for Exclusions, then Elements
resulting in post-transient system voltage deviations outside that range should be candidates for
Inclusion. Further, all assumptions should also be fully documented for any proposed Inclusions.
See reply to Question 6.

See reply to Question 6.
Yes
See the EEI reply to BES Definition and Designations Question 11.

No
Group
Idaho Falls Power
Richard Malloy
No
We do not agree that all four criteria under exclusion #1 need be applied in combination to an
element to determine its material impact. Assets satisfying all four defining criteria would seem
exceedingly small and likely already excluded by the BES definition. This exception criteria appears
redundant to, and shadows the NERC BES definition draft’s language excluding radial elements and
local distribution networks, and as such add little value to the exclusions built into the BES definitions.
Further, the language of the exception criteria addresses transmission elements and doesn’t provide
exclusion criteria for generation assets. We would hope that NERC could develop criteria to exempt
certain generation, especially those small resources on local distribution networks wherein the
generation is completely allocated to local load. Language in section 215 of the FPA excludes
distribution “elements.” We assert that generation on a distribution network serving only load on that
network is an “element” of the network and deserves exclusionary defining criteria.
Using these criteria assumes that every asset must be radial in nature in order to receive
consideration that it may not be material to the BES. This then implies that the BES is a contiguous
connected system as only radial off-shoots could receive exemption consideration. We disagree. Our
assertion is that the BES is comprised of assets that due to their size or location are vital to a sound
BES but may or may not necessarily be connected to each other. This defining criteria in the
exception could be a stand-alone criteria or stricken.
No
We agree in general, however believe there is little distinction between the defining criteria in this
exception and the local distribution network exclusion already provided for in the BES definition. We
would like to see added language that provides an exclusion for all elements on such a system, to
include generation regardless of MVA rating, wherein the power flows are generally into the system.
We would agree that a number of MWh of annual outflow needs to be established as a limitation to
the size and amount of generation under consideration. This exclusion should be geared towards
smaller municipal or like sized systems having no material impact upon a BA much less the region.
No
We generally agree with this requirement. If a system has redundant transmission to move power
that is normally wheeled through, the question of materiality could be addressed by technical
analysis.
We generally agree with having two paths towards exclusion.

No
No comments
Yes

No
No comments
No
We believe that the final drafts of the definition and exemptions should comport to the legal

requirements of Section 215.
No
No comments
Individual
Tracy Richardson
Springfield Utility Board
Yes
SUB agrees with providing an exclusion exception for System Elements that are treated as “radial in
character”, but feels this should be part of the core definition in NERC’s Proposed Continent-wide
Definition of Bulk Electric System rather than requiring an exclusion/exemption application process. In
SUB’s May 27, 2011 BES definition comments SUB expressed concern that there still appears to be
inconsistencies in both definition and application of “radial.” SUB encourages NERC to develop a
concise definition. For example, if a system is normally operated as radial, but could be operated
closed (for example, by manually closing a breaker), would it be considered a radial or close-looped
system?
No
NERC’s Proposed Continent-wide Definition of Bulk Electric System contains Exclusion E3 (LDNs) as
part of the BES core definition. Why would this fourth item be necessary in demonstrating BES
Exceptions if LDNs are already excluded as part of NERC’s core BES definition?
Yes
In general, SUB supports a technical analysis approach as a secondary/ alternative option for
qualifying to apply for BES Element exclusions.

No
NERC’s Exception Criteria for Inclusions states that, “Entities can submit an application to see an
exception for an inclusion in the BES...”, but SUB would ask NERC to clarify whether an entity can 1)
seek an inclusion exception for them only, or 2) can an entity seek an inclusion exception for another
entity? SUB would not support another entity having the ability to file for another entity.

Yes
• The four characteristics defined in the “Exception Criteria – Exclusions” portion of Technical
Principles for Demonstrating BES Exceptions appears to be in conflict with, rather than in parallel to,
the exceptions which are part of the proposed “core definition” in the Proposed Continent-wide
Definition of Bulk Electric System. SUB proposes that NERC postpone work related to Technical
Principles for Demonstrating BES Exceptions until a continent-wide BES definition is approved. • FERC
Order No. 743 states, “We believe that it would be worthwhile for NERC to consider formalizing the
criteria for inclusion of critical facilities operated below 100 kV in developing the exemption process”.
However, there is no mention of critical facilities operated below 100 kV in NERC’s Exception Criteria.
SUB would encourage NERC to include critical facilities consideration in their exception criteria.
Yes
SUB has the following concerns regarding NERC’s Technical Principles for Demonstrating BES
Exceptions: • Clear Definition of Radial - As previously addressed in our BES Definition comments,

SUB would encourage a more clear definition of a “radial” versus “closed-loop” system. Because there
still appears to be inconsistencies in both definition and application, SUB encourages NERC to develop
a concise definition of a radial system. For example, if a system is normally operated as radial, but
could be operated as closed (by manually closing a breaker), would it be considered a radial or closelooped system? If the answer is close-looped, then is this in all cases, or are there exceptions? •
Approval of Exceptions – SUB would like for NERC to clarify the process for receiving, reviewing, and
accepting or rejecting exception applications. The Technical Principles for Demonstrating BES
Exceptions states that, “…will be subject to review and remand by the ERO itself, or by any agency
having regulatory or statutory oversight of NERC as the ERO.” During NERC’s presentation at APPA’s
BES Definition webinar, it was explained that the exception process would look like the following: 1.
Entity applies for expemption, 2. Region receives application, verifies received, and forward to NERC
with recommendation(s), and 3. NERC makes final determination (decision is appealable by entity).
For consistent application of the expemption procedure, SUB would encourage NERC to adopt the
process as it was communicated during the APPA webinar, with regions making recommendations, but
NERC making the final decision. • Duration of Approved Exclusions/Inclusions – The Technical
Principles for Demonstrating BES Exceptions does not indicate the duration for approved exclusions or
inclusions. How long are granted exclusions/inclusions? Permanent? Annual? Other? • Publication of
Exceptions – For consistent application, as well as transparency and accountability, SUB would
request that all exceptions be published ; those applied for, as well as whether they were rejected or
accepted, as well as decision rationale.
Individual
John Pearson
ISO New England
No
We disagree with this exception and believe that Section 1.a. should be deleted in it’s entirety and
replaced with a definition that excludes remote areas of a generally lesser overall value to reliability
and includes areas that are heavily networked serving large loads. The premise of the existing section
1.a. seems at odds with overall system reliability and possibly removes large metropolitan areas from
the BES definition. How is close electrical proximity to load defined? A maximum number of Ohms?
Heavily networked areas will have lower impedance and are more likely to serve larger amounts of
demand and are therefore more likely to be impactful on the overall integrity of the BES.
No
This three part definition of radial presented in section 1.b. appears cumbersome and requires more
definition. With regard to b.i - Where is the disturbance? Is sending a person to the field to perform
manual disconnection a requirement of this exception? This item is so vague that we have difficulty
providing replacement language as we do not understand its intent. With regard to b.ii – Elements
(Excluding generators) are not dispatched in operations. If this approach were to be taken, what
would be the criteria for the way the Element is treated in Operations? Again, this item is so vague
that we have difficulty providing replacement language. The existing definition appears to require a
good deal of technical scrutiny and be at odds with the goal of having a path for evidence that does
not include extensive technical analysis. Overall it seems simpler to replace section b with a simpler
definition of radial such as – all load served from a single substation at a single voltage level.
No
Section 1.c again appears to allow the exclusion of large portions of the system in metropolitan areas.
How does this differ from the LDN exclusion already presented in the definition? Section c should
simply be deleted.
No
This appears to be the same as section 1.c and again possibly allows for the exclusion of large
portions of the system in metropolitan areas. Section 1.d. should simply be deleted.
No
The use of distribution factors is a significant concern. The term distribution factor is used a number
of ways in the industry. Is this determined using the percentage pickup on the element in question
following the loss of another element, or is this the percentage of a transfer that is picked up on the
element in question, or a combination of both? Item 2.a.ii states that the TPL studies have to be run if
the model is updated. The distribution factor is not required to be calculated as part of the TPLs and

therefore will require additional analysis in all circumstances, not just when the model is updated.
The use of distribution factors is a significant concern. The term distribution factor is used a number
of ways in the industry. Is this determined using the percentage pickup on the element in question
following the loss of another element, or is this the percentage of a transfer that is picked up on the
element in question, or a combination of both? Item 2.a.ii states that the TPL studies have to be run if
the model is updated. The distribution factor is not required to be calculated as part of the TPLs and
therefore will require additional analysis in all circumstances, not just when the model is updated.
Is the requirement to evaluate the voltage dip on the element or is the test to evaluate the voltage
dip on the BES due to a contingency on the element? Under the draft TPL standards, this will have to
be tested and investigated anyway, so it is unclear as to what is being added or evaluated here.
Is the requirement to evaluate the voltage dip on the element or is the test to evaluate the voltage
dip on the BES due to a contingency on the element? Under the draft TPL standards, this will have to
be tested and investigated anyway, so it is unclear as to what is being added or evaluated here.
No
No
Comments were already included above.

No
No
Yes
Any generator that is studied individually will not be shown as material since the electric system is
designed to allow the outage of any individual generator. Generators must be studied within the
context of the electric system to assess materiality. The generator and its interconnecting
transmission facilities would likely be able to be excluded based on this process although they meet
the Registry Criteria thresholds requiring inclusion.
Group
SPP Standards Review Group
Robert Rhodes
No
Physical characteristics as described in 1.a.i. do not capture the true picture of the functionality of an
Element. Rather than use impedance perhaps the SDT should use ‘radial’ or ‘having one source’ as
the descriptive term.
No
Could the SDT clarify what is meant by ‘disconnection procedures’ in 1.b.ii? It appears that the SDT is
okay with excluding an element that can be switched out of service without removing another
element. How are automatic breaker operations or manual switching factored into disconnection
procedures? We need clarification on this. More and better examples, including the type of
connectivity to the grid, would be helpful.
No
Rather than combining two conflicting criterion – ‘rarely’ and the number of MHh of backflow allowed
annually – we would suggest the following. 1) That the maximum outflow doesn’t create an issue on
the BES. This would be determined by study of the system and conditions. Or 2) when the condition
exists, be able to mitigate the condition within a prescribed time relevant to the prevailing system
conditions.
No

It may be better to focus on the purpose, or need, of a facility, the functionality of the facility, rather
than how electric flows impacted the facility during a given situation. Therefore, we would suggest
moving away from the term ‘intent’.
No
There are situations where setting a minimum TDF will not work due to the nature of the TDF. For
example, a radial line connected to a bus with two networked lines. The radial line serves only load
and would normally be excluded from the BES. However, if we use the TDF as a factor the radial line
would be included in the BES since the TDFs would be high.

Yes
We would suggest that the SDT consider an exclusion for networked municipal systems operating
below 200kV which have more than 75 MVA of generation and whose systems do not include
flowgates or IROLs.
No
Please see our comment in 5b above.

No
Yes
In Question 5 regarding the Transient and Steady State Stability criteria, we would suggest
establishing criteria for the damping such that the time required to return to normal is limited.
Damping in 1-5% range may be sufficient to accomplish this. Also, delete 2.a.iv.8. in the Exclusion
Criteria and 1.c.8. in the Inclusion Criteria.
Individual
Jonathan Appelbaum
The United Illuminating Company
No
No
No
What does rarely mean? How is maintenance conditions considered? This is simply worded but
conceptually extremely complicated.
No
The wording is ambiguous. What is meant by system? Different voltage levels, Owners?
No
This is not very different from trying to demonstrate no adverse impact outide the local area.
Distribution factor requires a definition.
Measured where on the BES?
Measured where on BES?
No
Procees is complicated and fraught with interpretations.

No

No
NERC modeling Standards should be sufficient
Yes
under the technical principles, some facilities that are local distribution facilities may be included the
BES. This is in conflict with the definition of the Bulk Power System in Section 215 which excludes
facilities used in local distribution. In particular, Local distribution facilities can not be included in the
BES even if they are part of a cranking path.
Yes
UI is concerned that the method used to characterize exclusions in Method 1 did not follow the
proposed BES Definition and believe the process developed for Method 2 (and reused for Sub-100kV
Inclusions) is overly complicated, lacks necessary regional standards to support the process and may
prove too difficult for some companies to fully comply with thereby discouraging a consistent and
uniform application of the definition across all regions and affected BES element owners. These
Principles are not technical Principles. Further the use of these Planning criteria and impact
assessments is not very different from the NPCC functional test that drew the ire of FERC. The
Drafting Team is attempting to develop definitions and identifiers for the fringes of the bulk power
system, but they are replacing one set of ambiguities with a set of technical ambiguity. This product is
poor because given the very first term, that is the first principle to be met, is those facilities
necessary for the reliable operation of an interconnected transmission system, is full of undefined
concepts such that anything attempting to define it in a subtle manner is immediately lost in the
ether. Recognizing that these technical principles will be permanent, UI suggests excluding them and
sticking with the bright line exclusions and inclusions in the proposed definition.
Individual
Neil Phinney
Georgia System Operations Corporation
The concept of “Load centers” is vague and needs more specificity for this to be clear.
If the BES Definition itself is clarified to allow for some de minimis amount of power flow out of a
customarily radial line that is excluded by definition, this justification for an exclusion may not be
necessary. We encourage the Drafting Team to pursue that approach because we believe it is
technically justified and could significantly reduce the need for exceptions.
The concept of “intentional” transport of power is vague and needs more specificity for this to be
clear. Also, it would help to have more information about the sort of “operational procedures” that
would be acceptable as evidence.
It would be helpful to specify which TPL Standard(s) the referenced studies are usually prescribed for.

Group
Western Electricity Coordinating Council
Michelle Mizumori
Yes
As long as this remains an “AND” statement, WECC supports this concept. It helps to support the
concept that the element is used as distribution to serve Load, rather than to transfer bulk power.
However, some correlation between the size of the Load and the size of an element may be needed.
For example, a line that can carry 600 MW in close electrical proximity a 20-MW Load may not meet
the intent of this characteristic. Furthermore, the criteria must define where the load is located for the
measure of electrical proximity. In planning models, loads are often aggregated to a higher voltage
substation bus, while in a distribution system model they are typically modeled along a distribution
feeder. The SDT should clarify how it intends for the load to be modeled for this analysis of close
proximity.
No
This characteristic is vague and subjective. It is unclear what “radial in character” means, and the
methods for demonstration do not appropriately clarify the meaning. WECC recommends that the SDT
determine what it is looking for to show “radial in character” and clearly identify that concept in the
methods for demonstration. It is not clear how Operating Procedures can demonstrate that an
element is “radial in character” nor is it clear how a re-evaluation might be processed if such
Operating Procedures, ownership, or operations change. WECC believes that BES inclusion or
exclusion should be based on physical, technical characteristics of the element, and requests a
justification for use of procedural or contractual documentation as evidence of a technical principle.
Yes
WECC agrees in concept with this characteristic, but it needs to be clarified whether the items i-v are
“AND” statements. WECC also suggests that i and ii be switched and re-worded. Suggested language
for ii would be “A limited set of conditions where power flows out must be identified; for example,
only under specified Contingency events.” Then i can become a sub-bullet of ii. It must also be
clarified that the specified conditions must have a technical justification to show that the element is
not “necessary for reliable operation.” Otherwise it is not clear that the “limited conditions” are truly a
justification for exclusion. Any non-zero MWh limit must have a technical justification, otherwise zero
should be used. In addition to the imports/exports from the system, the size of the system (in MW)
should also be defined.
Yes
WECC agrees in concept with this characteristic, but believes that there needs to be more clarity of
what constitutes the evidence. Since flow data is used for characteristic c, it seems that the same sort
of data (but separated into hourly flow in and hourly flow out) could be used to demonstrate this.
Otherwise, a simple procedure that claims “power entering this system is not intentionally transported
through the system to some other system” would meet the letter of the law, but gives no description
of how this is achieved. If Operating Procedures are allowed, more clarity must be provided on what
those procedures must entail.
Yes
WECC agrees in concept that a technical analysis can be used and should be allowed to show that an
element is not necessary for reliable operation. However, the technical analysis must be based on
sound reasoning and a justification must be given as to why the analysis makes a showing that the
element is not necessary for reliable operation. Furthermore, the technical principles must identify
what category(ies) of TPL studies must be run. Finally, the values used for the threshold criteria
and/or disturbances must be more stringent than the applicable TPL criteria/disturbances. Otherwise
the argument becomes circular because all BES elements must meet the TPL criteria, so by meeting
them all elements could be excluded.

Yes
WECC recommends that the SDT consider not only the single-phase faults used in the TPL standards,
but also the effect of more severe events such as two- or three-phase faults, with delayed clearing
and the necessity of the element in those cases.
Yes

Yes
The Owner should have all of the data to perform this analysis for an Exclusion; however, an Inclusion
would likely be sought by an entity other than the Owner (i.e., Regional Entity, RC, BA, TOP) that
may not have sufficient data. It should be clarified in the Rules of Procedure that such an entity has
the right to request such data and that the Owner must provide such data.
Yes
It must be clear that under NERC Standard IRO-010, the Reliability Coordinators are required to
obtain information relating to the operation of the bulk power system within their respective areas. In
light of this requirement, Reliability Coordinators may request the submittal of information for
network facilities that ultimately are not determined to be BES facilities. It would be reasonable to
also include a requirement that Reliability Coordination staff will explain why they require the
requested information from non-BES facilities when seeking such information.
Yes
The biggest concern is that the Technical Principles and the reasoning behind them need to be fully
explained. The SDT has mentioned on calls the possibility of a white paper or resource document, and
WECC fully supports the creation of such a document. This white paper should describe the rationale
for the criteria as well as how that indicates that the element is necessary for reliable operation. Also,
the justification for the ERO to override these criteria should be clarified. It should be clear that the
ERO’s ability to override these criteria is on a case-by-case basis.
Individual
Michelle R DAntuono
Occidental Energy Ventures Corp.
Yes
Yes
Yes
Yes

Yes
Suggested additional method. The Element(s) meet all the following characteristics: 1) generally
radial in nature, and 2) used to supply a retail customer from the point of delivery to the load
regardless of voltage. Evidence to support this position could be an interconnection agreement
indicating the point of delivery, a one-line diagram showing the point of delivery and load, etc. The

technical rationale is that protection of the BES for facilities serving a retail customer is the
responsibility of the service provider (e.g., transmission owner/operator). These facilities are
distribution facilities and are not now part of the BPS. Alternatively, this could be an Exclusion in the
BES Definition as it is in the current definition.

Yes
The proposed technical principles seem to be in contradiction to the exemption in FPA Section 215
against the inclusion in the BES of facilities used in the local distribution of electric energy.
Yes
The Technical Principles and the new BES Definition seem to include a significant number of retail
customers as proposed. Surely this is not the intent of these changes. There should be an exclusion
along the lines of Comment 6.
Individual
Russ Schneider
Flathead Electric Cooperative, Inc.
No
agree in principle that one characteristic of local distribution systems is that they are usually confined
to a relatively limited geographic area, as opposed to transmission systems, which (especially in the
West) tend to cover very large distances. We also believe the proximity test may be a sensible way to
identify local distribution facilities. However, we believe that the proximity test may be unnecessary,
and if an Element or group of Elements meets other tests proposed by the SDT, it should be excluded
from the BES, even if it does not meet the proximity test.
Yes
agree conceptually that systems operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. That is because local
distribution systems typically operate adjacent to, or at the end of transmission lines, and function
operationally to move power from the Transmission Service Provider’s point of delivery of bulk power
that has moved across the integrated bulk transmission system to end-users located within the local
distribution utility’s service territory. To be consistent with the draft BES definition, the term “radial in
character” should be explicitly defined as a system that may include one or more lines into a load
area or referenced as a local distribution network. In addition, we agree that the manner in which a
system is operated during BES disturbances may be an indication of whether that system is radial in
character. That being said, we are concerned that, to the extent the SDT considers regional
disconnect procedures, it should be careful to note that UFLS and UVLS relays are often embedded
within local distribution systems and, while it is necessary for the UFLS and UVLS relays to be
properly armed to protect the BES in the event of a severe system disturbance, the local distribution
system interconnected with those relays should not, and cannot legally, be classified as BES.
Yes
agree conceptually that one critical characteristic distinguishing local distribution facilities that must
be excluded from the BES from transmission facilities that should be included is the manner in which
power flows on those facilities. Power on local distribution systems generally flows only from the
interconnected transmission source and across the distribution system for delivery to end-use
customers. By contrast, power on transmission systems generally flows in two (or multiple, in
networked systems) directions and is delivered in bulk to distribution utilities rather than to endusers. Hence, the SDT has properly identified power flows as one important characteristic that
distinguishes BES transmission systems from local distribution systems. We agree conceptually that
the fact that power may flow out of a local distribution system onto the grid during a few hours in a
year or during extreme contingencies should not change the characterization of the system as local
distribution. Accordingly, we support inclusion of power flow analysis as one element of characteristics

that can be used to exclude local distribution facilities from the BES even if the facilities do not pass
each of the bright-line thresholds laid down in the BES definition. We also agree that transactional
and hourly generation records are an appropriate basis for making the determination since these can
be used to demonstrate that demand within a local distribution system exceeds generation within that
system in most hours and that power therefore does not flow onto the grid, and also to determine the
number of hours where this is not the case and the amount by which generation within the system
exceeds demand. In order to identify systems that are not necessary for the operation of the BES
under this text, we propose that any system where real power flows into the local distribution system
90 percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions
should be held to meet this test. That a system meets this test could be demonstrated using metering
or supervisory control and data acquisition ("SCADA") data records over the course on two years. In
addition, the presence of generation within a local distribution system that only modifies the level of
the load served by the bulk system, but does not result in power being injection into the bulk system,
does not change the reliability effect of the local network and therefore should not require the local
network to be classified as BES.
Yes
agrees that the SDT’s fourth test, which asks whether power is intentionally transported through a
system, identifies a key characteristic of local distribution facilities that distinguishes such facilities
from interconnect bulk transmission facilities that are properly considered part of the BES. In fact, we
believe this may be the most important and readily identifiable distinction. As a matter of operation,
power is scheduled across transmission lines. Further, transmission lines in the Western
Interconnection (either individually or as part of a transmission path) are rated for total transmission
capacity and available transmission capacity, and transmission rights can be purchased on such lines,
if available, on an OASIS. Local distribution systems do not share any of these operational
characteristics. Accordingly, we agree that if power is not intentionally transported through a
particular system, that system is not used for transmission and should not be considered part of the
BES. We also agree that examining the Operating Procedures applicable to a particular system will
provide a ready guide to whether power is intentionally scheduled across that system. We suggest,
however, that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of
Operating Procedure. For example, in the West, transmission paths are almost all listed in the WECC
Path Rating Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the
other factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such
specific operational characteristics as part of this test.
Yes
agree conceptually with the idea that two different paths to exclusion should be adopted, one relying
upon readily identifiable characteristics that are ordinarily associated with local distribution and not
BES transmission facilities, and one relying on technical analysis to determine whether or not an
Element or group of Elements has a measurable impact on the threat of cascading outages,
separation events, or instability on the interconnected bulk system. If technical analysis demonstrates
that Elements create no material threat of such reliability events, they should properly be excluded
from the BES.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of operations. For example, the Western
Interconnection uses a rated paths methodology while the Eastern Interconnection uses transmission
load relief mechanisms. Consistent with FERC order 743-A we support exemption criteria for
individual frequency independent regions, or interconnections.
we propose that, if an Element is to be excluded from the BES, removal of that Element should

produce no more than a 20% voltage drop for no more than 20 cycles in a Category B contingency
and no more than a 20% drop for 40 cycles in a Category C contingency.
we propose that, if an Element is to be excluded from the BES, removal of that Element should not
cause any load bus to drop below 59.6 Hz for 6 cycles or more.
we propose that, if an Element is to be excluded from the BES, removal of that Element should not
cause any load bus to drop below 59.6 Hz for 6 cycles or more.
No
supports the exemption of generation interconnected to local distribution networks if the generation is
less than 300 MW capacity and where the power generated is consumed within the LDN and rarely
flows out of the LDN consistent with the section III.c.4 [Exclusion] of the NERC Statement of
Compliance Registry Criteria as well as the Load modifiers used in the Eastern Interconnection. "Load
Modifiers" (small generators that only affect load at the distribution level).”
Yes
Elements otherwise excluded from the BES should be included only upon a technically valid showing
that the Elements contribute substantially to the potential for cascading outages, separation events,
or instability on the interconnection bulk transmission system.

Yes
Obtaining data creates a cost and should be minimized as possible.
No
the proposed BES Definition could conflict with Section 215 of the Federal Power Act if the Definition,
the Exception Process, and the Technical Criteria do not effectively exclude facilities used in local
distribution from the BES or if the BES definition does not focus on cascading outages, separation
events, and instability on the interconnected bulk system. These statutory limits on the scope of the
BES and reliability standards are a minimum that must be met.
Yes
supports the approach to the exclusion process proposed by the SDT, which provides two different
paths to exclusion, one based on readily-identifiable operational characteristics of a system, and one
based on technical reliability analysis. We believe it is important to provide for the first path, based on
operational characteristics, so that systems that are marginally disqualified under the BES Definition
(because, for example, generation within the system exceeds demand for a few hours a year) can
obtain an exclusion without the large investment of resources that otherwise might be required for a
full-scale technical analysis. we question whether the first subsection of the characteristic test,
relating to system proximity, is necessary, and we are concerned that the requirement that a system
meet all four requirements of the characteristics test may be overly restrictive. For example, it is easy
to imagine a distribution system in a rural area that covers a widely dispersed area, so that load is
many miles from the relevant generation/transmission source, and that the system therefore does not
meet the electrical proximity element, but meets the other three elements of the characteristics test.
Such a system should be excluded because it clearly serves a local distribution function, and not a
transmission function, as demonstrated by the fact that the system meets subsections (c) (power
flows into the system but rarely flows out ) and (d) (power is not intentionally transported over the
system). Accordingly, we recommend that the SDT consider eliminating the first test. In the
alternative, the SDT should consider allowing exempting a system from the BES if it, for example,
meets three of the four criteria rather than all four.
Individual
Ed Davis
Entergy Services
No
Entergy does not agree with the assumption that the proximity of a BES facility to Load is indicative of
it's importance to BES reliability. Some lower voltage facilities can be quite short and thus have lower
impedance but be important to BES reliability. Likewise some facilites remote from load centers may

have virtually no impact on BES reliability. There is also insufficient information as to how the
impedance would be measured (locations of measurements within and outside of the "Load pockets".
This Exemption Criteria should be removed. The term "Load centers" is not defined leaving it subject
to interpretation. "Loads" are not BES Elements and therefore can not be exempted from being
considered BES Elements. Item 1.a.i - "Loads within the system seeking exception are in close
electrical proximity if they are separated by an impedance of no greater than TBD." This sentence
needs to be deleted.
Yes
Entergy agrees that radial facilities should be excluded directly. However, the "radial in character"
language is nebulous. A simpler approach could be to allow exceptions for facilities which become
radial as a consequence of a normal system response to a disturbance (breakers opening during
normal clearing of a fault).
No
Power flows into or out of a portion of the BES may characterize BES facilities less important to BES
reliability but without limits to the size of the area, it would be difficult to show compliance. An entire
state could be excluded from the BES. Additionally, there is no process specified to review the
characteristics as transmission topology and resources change over time.
No
There is not sufficient evidence provided by the SDT to distinguish between this fourth item for
exclusion and the third item for exclusion. They both seem to fall in line with what is excluded per the
bright line exclusion E3 (or Local Distribution Networks), but as written, it would be difficult to
measure what is meant by “is not intentionally transported through” in this fourth item just as it
would be difficult to measure what’s meant by “flows into the system, but rarely flows out” for the
third item. Such an exclusion should be required to include some technical analysis, but not extensive
technical analysis (at least the inclusion of power flow base case as a minimum).
No
The entire approach seems overly complex and difficult to document.

Yes
Revise second paragraph to read “Due to the importance of designated Blackstart Resources and their
Cranking Paths to restore efforts, no exceptions will be allowed for those items that are included in a
system restoration plan.” Technical rationale: Multiple Blackstart Resources and Cranking Paths are
frequently available but are not included in a system restoration plan. System restoration plans
describe the Blackstart resources and cranking paths that are deemed to be necessary for system
restoration. Section “Exception Criteria – Exclusions”: Add 1.e. “Generation that is inoperable and not
planned to be placed back into service but not yet officially decommissioned.” Technical rationale:
These facilities are not relied on to insure the reliability of the BES.
No
It is unclear why an inclusion process should be necessary. Including facilities not otherwise included
in the basic definition should be at the discretion of the TO.

No
No
No

Individual
Jack Stamper
Clark Public Utilities
Yes
Clark believes the proximity test should be considered be a valid factor in determining whether a
facility is part of the BES or not. Just as this factor is used in the consideration on whether a facility is
part of a Local Distribution Network. Clark is not convinced that “proximity” and “impedance” are
interchangeable. While impedance will be lower for shorter distances it will also be affected by other
factors that are not indicative of close proximity. Distance seems more appropriate to use since it
would complement a literal interpretation of the term proximity.
Yes
Clark agrees conceptually that systems operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. That is because local
distribution systems typically operate adjacent to, or at the end of transmission lines, and function
operationally to move power from the Transmission Service Provider’s point of delivery of bulk power
that has moved across the integrated bulk transmission system to end-users located within the local
distribution utility’s service territory. To be consistent with the draft BES definition, the term “radial in
character” should be explicitly defined as a system that may include one or more lines into a load
area or referenced as a local distribution network. In addition, Clark agrees that the manner in which
a system is operated during BES disturbances may be an indication of whether that system is radial in
character. That being said, we are concerned that, to the extent the SDT considers regional
disconnect procedures, it should be careful to note that UFLS and UVLS relays are often embedded
within local distribution systems and, while it is necessary for the UFLS and UVLS relays to be
properly armed to protect the BES in the event of a severe system disturbance, the local distribution
system interconnected with those relays should not.
Yes
Clark agrees conceptually that one critical characteristic distinguishing local distribution facilities that
must be excluded from the BES from transmission facilities that should be included is the manner in
which power flows on those facilities. Power on local distribution systems generally flows only from
the interconnected transmission source and across the distribution system for delivery to end-use
customers. By contrast, power on transmission systems generally flows in two (or multiple, in
networked systems) directions and is delivered in bulk to distribution utilities rather than to endusers. Hence, the SDT has properly identified power flows as one important characteristic that
distinguishes BES transmission systems from local distribution systems. In order to identify systems
that are not necessary for the operation of the BES under this text, we propose that any system
where real power flows into the local distribution system 90 percent of the time or more under normal
operating conditions.
Yes
Clark agrees that the SDT’s fourth test, which asks whether power is intentionally transported through
a system, identifies a key characteristic of local distribution facilities that distinguishes such facilities
from interconnect bulk transmission facilities that are properly considered part of the BES. Clark
believes this may be the most important and readily identifiable distinction. Accordingly, Clark agrees
that if power is not intentionally transported through a particular system, that system is not used for
transmission and should not be considered part of the BES.
Yes
Clark agrees conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with local distribution
and not BES transmission facilities, and one relying on technical analysis to determine whether or not
an Element or group of Elements has a measurable impact on the threat of cascading outages,
separation events, or instability on the interconnected bulk system. If technical analysis demonstrates
that Elements create no material threat of such reliability events, they should properly be excluded
from the BES. Clark supports the technical arguments and the White Paper presented by Snohomish
County PUD in their comments. Clark recommends that the SDT modify its approach to the technical
exclusion process to match the approach advocated in the White Paper, which is based upon the
approach recommended by the WECC BES Task Force.

The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection.
Specific transient voltage dip thresholds are proposed at page 15 of Snohomish’s White Paper. For
example, Clark proposes that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, Clark proposes that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
See Clark’s comments on 5c and 5d.
No
Yes
As a general matter, Clark agrees with the SDT that Elements otherwise excluded from the BES
should be included only upon a technically valid showing that the Elements contribute substantially to
the potential for cascading outages, separation events, or instability on the interconnection bulk
transmission system. Clark also agrees that the SDT has, in general, identified the correct technical
approach, although Clark recommends that the inclusion analysis (which mirrors the technical
exclusion analysis) be modified as discussed in the Snohomish PUD White Paper, in the WECC BES
Task Force Proposal 6, and in Clark’s answer to Question 5.
See comments in 5.
See comments in 5.
See comments in 5.
See comments in 5.
No
As discussed on page 12 of the Snohomish White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis Clark recommends is the current base case operated by the relevant
Regional Entity, and in nearly every case, the base case can be expected to model any Element that
conceivably has a material impact on the reliable operation of the bulk system. In those rare cases
where it does not, we believe the owner or operator of the subject Element should be able to provide
the needed data.
No
No
Individual
Dave Markham
Central Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other

mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.

Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary

because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual

Dave Hagen
Clearwater Power Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We

also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes

As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece

of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Roman Gillen
Consumer's Power Inc.
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were

constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical

justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and

control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Roger Meader
Coos-Curry Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which

generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that

are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes

In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Dave Sabala
Douglas Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those

facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task

Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting

point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Bryan Case
Fall River Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution

network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.

Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)

have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Rick Crinklaw
Lane Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using

impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are

concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,

we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to

comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Michael Henry
Lincoln Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased

on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No

Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would

come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Richard Reynolds
Lost River Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for

new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element

should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with

reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Annie Terracciano
Northern Lights Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system

exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical

exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.Page 15 of
Snohomish’s White Paper also sets forth recommended thresholds for transient frequency response.
For example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical justification for
these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,

although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Doug Adams
Okanogan Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,

while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and

resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Heber Carpenter
Raft River Rural Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.

Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one

relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected

transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Ken Dizes

Salmon River Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a

ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should

be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the

criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Steve Eldrige
Umatilla Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of

the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.

Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

Yes
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or

any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Marc Farmer
West Oregon Electric Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for

the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with

loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes

In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Rick Paschall
Pacific Northwest Generating Cooperative
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those

facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task

Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting

point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Aleka Scott
PNGC Power
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using
impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution

network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are
concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.

Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,
we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)

have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Stuart Sloan
Consumer's Power Inc.
Yes
First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related
efforts to revise the definition of the BES. In response to question #1, we note only that using

impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest
impedance.
Yes
We agree conceptually that facilities operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. However, to be
consistent with the draft BES definition, the term “radial in character” should be explicitly defined as
facilities that may include one or more lines into a load area or referenced as a local distribution
network. In addition, we agree that the manner in which a system is operated during BES
disturbances may be an indication of whether that facility is radial in character. That being said, we
are concerned that, to the extent the SDT considers regional disconnect procedures, it should be
careful to note that UFLS and UVLS relays are often embedded within local distribution facilities and,
while it is necessary for the UFLS and UVLS relays to be properly armed to protect the BES in the
event of a severe system disturbance, the local distribution facilities interconnected with those relays
should not, and cannot legally, be classified as BES.
Yes
We agree conceptually that one critical characteristic distinguishing facilities that must be excluded
from the BES from facilities that should be included is the manner in which power flows on those
facilities. Hence, the SDT has properly identified power flows as one important characteristic that
identifies BES facilities. We also agrees conceptually that the fact that power may flow out of facilities
onto the grid during a few hours in a year or during extreme contingencies should not change the
characterization of the facilities in question as excluded from the BES. Accordingly, we support
inclusion of power flow analysis as one element of characteristics that can be used to exclude facilities
from the BES even if the facilities do not pass each of the bright-line thresholds laid down in the BES
definition. We also agree that transactional and hourly generation records are an appropriate basis for
making the determination since these can be used to demonstrate that demand within a system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify facilities that are not necessary for
the operation of the BES under this text, we propose that any facility where real power flows in 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should
be held to meet this test. That facilities meet this test could be demonstrated using metering or
supervisory control and data acquisition ("SCADA") data records over the course on two years. While
we agree with the SDT’s view that power should flow predominantly in the direction of load for
excluded facilities, we are concerned that this characteristic may no longer be a defining characteristic
as the electric industry evolves in the future. If distributed generation becomes the future norm for
new power generation facilities, it may no longer make sense to look at power flow as a defining
characteristic. That is, even if a sufficient number of small distributed generation facilities were
constructed on certain facilities to cause power to flow out of those facilities more than ten percent of
the time, the fundamental character of those facilities will not have changed. Finally, we believe that
power flow analysis under this item should consider actual power flow, not scheduled power flow.
Yes
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Facilities that do not share any of these operational
characteristics should not be part of the BES. Accordingly, we agree that if power is not intentionally
transported through particular facilities, those facilities should not be considered part of the BES. We
also agree that examining the Operating Procedures applicable to particular facilities will provide a
ready guide to whether power is intentionally scheduled across those facilities. We suggest, however,
that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of Operating
Procedure. For example, in the West, transmission paths are almost all listed in the WECC Path Rating
Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other
factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test. Finally, as noted in our answer to Question 3, we are

concerned that, if distributed generation advances significantly, power transport may cease to be a
meaningful measure for determining whether a facility is part of the BES, and we believe that power
flow analysis should consider actual power flow, not scheduled power flow.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with non-BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based
approach to support the technical determination whether Elements should be excluded from the BES,
which we commend to the SDT for study. We also commend the work of the WECC BES Task Force
and the WECC Technical Studies Subcommittee, both of which have devoted substantial time and
resources to developing a workable and technically defensible process for excluding Elements
classified as BES based upon their electrical characteristics. See WECC BES Task Force Proposal 6,
App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, we suggest that a detailed technical
exemption process be allowed on an interconnections wide basis. The Western Interconnection is a
“hub and spoke system” where loads are very remote from large generation plants, with margins that
are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system with
loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the
Western Interconnection uses a rated-paths methodology while the Eastern Interconnection uses
transmission load relief mechanisms. Consistent with FERC order 743-A, we support exemption
criteria for individual frequency independent regions, or interconnections.
Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided on pages 12-16 of Snohomish’s White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided on pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the
interconnection bulk transmission system. We also agree that the SDT has, in general, identified the
correct technical approach, although we recommend that the inclusion analysis (which mirrors the
technical exclusion analysis) be modified as discussed in Snohomish’s White Paper, in the WECC BES
Task Force Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach,

we believe subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this
criterion” if it provides “additional justification” for doing so is both unnecessary and creates confusion
and uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary
because if the technical process laid out in subsections (a) through (e) fails to provide any evidence
that the contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see our corresponding answers to Question 5 for 7b-7e.

No
As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant RE,
and in nearly every case, the base case can be expected to model any Element that conceivably has a
material impact on the reliable operation of the bulk system. In those rare cases where it does not,
we believe the owner or operator of the subject Element should be able to provide the needed data,
although we propose that the relevant owner or operator be relieved of this burden if it can be
demonstrated that the nearest electrically interconnected Element has no material impact on the bulk
system.
No
Yes
In general, as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES
definition itself does not clearly resolve. However, we caution that these principles for demonstrating
exceptions cannot, and must not, take the place of a consideration of, and criteria under whether, any
specific piece of equipment is subject to FERC, the ERO, and Regional Entity jurisdiction in the first
instance. Section 215 of the Federal power Act (FPA) sets out clear limits of jurisdiction of FERC, the
ERO, and Regional Entities for purposes of developing and enforcing reliability standards. Specifically,
Section 215(i) provides that the ERO “shall have authority to develop and enforce compliance with
reliability standards for only the Bulk-Power System.” 16 U.S.C. § 824o(a)(1) (emphasis added).
Section 215(a)(1) of the statute defines the term “Bulk-Power System” or “BPS” as: (A) facilities and
control systems necessary for operating an interconnected electric energy transmission network (or
any portion thereof); and (B) electric energy from generation facilities needed to maintain
transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition
should expressly account for these jurisdictional limitations up front. This would allow for the
jurisdictional limitation consideration as the very first step in determining whether or not a particular
piece of equipment is part of the BES. The Technical Principles for Demonstrating BES Exceptions, on
the other hand, provides a completely separate set of criteria for exclusion from the BES and would
come into play only after application of the full BES definition to a particular piece of equipment and
determination that the BES definition does not provide a satisfactory answer as to whether that piece
of equipment is or is not part of the BES. This is acceptable insofar as it goes, but, because (1) the
criteria in the Technical Principles are distinct from the jurisdictional limits of Section 215 of the FPA,
and (2) consideration of the Technical Principles would essentially be the last, or one of the last, steps
in the process, the Technical Principles cannot substitute for, in any way, consideration of the
jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how important it is to
have the jurisdictional consideration be the very first step in the process of determining whether a
particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to

comment. We look forward to continuing to work with NERC and stakeholders to develop a BES
definition that is both workable and lawful.
Individual
Bill Keagle
BGE
No
BGE is not clear as to why “close electrical proximity to load” is appropriate to use as a factor in
determining exclusion.
Yes
No comment.
No
BGE is generally opposed to this requirement because the MWh factor is too variable and/or may be
utilized in a way contrary to reliable system operation.
Yes
BGE generally agrees with this requirement, but believes that the term “system” should be clarified.
Yes
BGE believes that there is value in allowing for exclusions through a technical analysis path. Because
multiple entities may perform “planning assessments” using different models, the phrase, “*the*
most recent *applicable* planning assessment” should be clarified to avoid ambiguity as to which
model(s) are acceptable. It may be useful to designate the models used in the Planning Authority
analyses as acceptable.
BGE requests that it be made clear that the 2(a) iv.1 criteria refers to the of the distribution factor for
the loss of any other facility on the subject Element, whereas criteria 2 through 7 refer to the
performance following the loss of the subject Element.
For PJM members, this figure is set at 5%. BGE suggests a lower figure such as 2-3%.
No comment.
BGE believe the loss of the facility in question should cause only a small voltage deviation to the BES
(on the order of 1%).
No
No comment.
Yes
BGE believes that there is a value in allowing for inclusions through a technical analysis path;
however, it is critical that such a path does not allow for unreasonable inclusion of facilities that do
not warrant BES status.
No comment.
No comment.
No comment.
No comment.
No
No comment.
No
No comment.
No
It is important to consider that the Technical Principles for Demonstrating BES Exceptions is only one
part of the BES definition project. The Technical Principles and the Rule of Procedure Process must be
evaluated together with the BES Definition to sufficiently understand the revisions. In the end, the
Technical Principles and the BES Definition must coalesce and be clearly coordinated and understood.
The BES Definition language must include reference to the role of the associated defining documents.
One unambiguous document must not be made ambiguous by an associated document or process.
We appreciate the work of the drafting team and support the goal to produce clear definition language
so that upwards of 95% of the assets are clearly distinguished as either included or excluded from the
BES. We are particularly sensitive to the potential for burdensome processes (e.g. TFEs) to be added

to reliability compliance. We appeal to the team for continued, vigilant consideration of the
arduousness of the BES determination process.
Group
NERC Staff
David Taylor
No
Electrical proximity to load is not an informative measure of whether Element(s) are necessary for
reliable operation or the potential reliability impact of excluding Element(s) from the BES. Establishing
a maximum impedance threshold as proposed would assure only that the excluded Element(s) do not
span a large electrical distance. While minimizing impedance may be beneficial for some aspects of
reliability, other aspects of BES reliability are improved with higher impedance. For example, higher
impedance minimizes through-flow of power and minimizes impacts to BES reliability associated with
faults and switching errors.
No
We believe that restating this measure as “System performance impacts are similar to radial systems”
would be more in-line with the SDT intent and a better measure of whether Element(s) are necessary
for reliable operation. We also believe that the best measure of whether Element(s) affect system
performance in a manner similar to radial systems is through distribution factor analysis. Such
analysis, when limited to this purpose, does not require extensive technical analysis. Analysis for a
limited number of stressed transfer conditions, and contingencies involving the Element(s) under
consideration and in the area of the Element(s) under consideration, is sufficient to demonstrate
whether the system performance impacts are similar to radial systems.
No
Requiring that power flows into, and rarely out of, the Element(s) considered for exclusion is an
appropriate measure, as is requiring an entity to define the conditions under which power will flow
out. In addition to information such as specified contingencies in item (ii), details on the conditions
should include other relevant information such as the system load level, generation dispatch, system
transfer levels, etc., and the number of hours per year these conditions are expected. An exception
request also should include the maximum flow expected. E.g., the following information would be
useful in evaluating a request for exception: “Power will flow out only when line A is out of service,
system load is at or below X percent of peak load, and generator B is on-line; based on the load
duration curve for this area and the number of hours generator B is dispatched at these load levels,
the exposure to power flow out for this contingency is limited to N hours per year and the maximum
flow if the contingency occurred during these hours would be Y MW.” This type of information will be
far more informative than a pass/fail test as to whether a MWh threshold is expected to be exceeded.
While a MWh threshold may be useful for evaluating requests, it is unlikely that a one-size-fits-all
threshold could be established for evaluating exception requests.
No
Limitations on through-flow of power is an appropriate consideration; however, whether the power
flow is intentional should not be a primary consideration. Intent is not measurable and most major
disturbances are the result of unintentionally placing the system in an unreliable operating condition.
The main clause in item (d) should be modified to reflect that transporting power to another system
through the Element(s) to be excluded is prevented (such as by system configuration and/or
impedance) or restricted (such as by Operating Procedures). Sub-items (i) and (ii) already are
consistent with this revision to the main clause.
No
NERC staff is not opposed to development of evidence based on technical analysis; however, the type
of analysis included in this exception criterion requires extensive resources and lacks sufficient detail
to allow for consistent and repeatable application. Concerns with this approach include (1) the ability
to provide sufficient guidance on the system conditions and contingencies necessary to support an
exception request, (2) difficulty with identifying thresholds for items iv-1 through iv-4, and (3) the
ability to address interdependencies among exception requests. These concerns can be addressed by
deleting this second path for evidence and including technical analysis on a limited basis to assess
performance as described in our response to Question 2. If the SDT elects to retain this second path
for evidence, then our three concerns must be addressed. In particular with regard to our third

concern, the ERO must be able to deny requests for exception based on the cumulative impact of all
previously approved exceptions.

No
No
NERC staff is not opposed to development of evidence based on technical analysis; however, we have
the same concerns with the exception criterion for including Element(s) as with exception criterion 1
for excluding Element(s). The type of analysis included in this exception criterion requires extensive
resources and lacks sufficient detail to allow for consistent and repeatable application. Additional
concerns with this approach include (1) the ability to provide sufficient guidance on the system
conditions and contingencies necessary to support an exception request, (2) difficulty with identifying
thresholds for items iv-1 through iv-4, and (3) the ability to address interdependencies among
exception requests.

No
No
Yes
A criterion should be added for supporting a request for inclusion of an Element. If an Element has
been identified as causal or contributory to a Category 2 or higher event as defined in the ERO Event
Analysis Process, that should be sufficient evidence that it is necessary for the Element to be planned,
designed, maintained, and operated in accordance with NERC Reliability Standards. An assessment of
the Element should include consideration of any corrective actions that have been implemented to
prevent a reoccurrence. The Exception criteria also should include a list of characteristics of Elements
that will not be considered for exclusion, on the basis that this list of characteristics already identifies
the importance of such Elements to reliable operation of the interconnected transmission network.
Characteristics should include: (1) Elements that are relied on in the determination of an
Interconnection Reliability Operating Limit (IROL); (2) Blackstart resources and the designated
blackstart Cranking Paths identified in the Transmission Operator’s restoration plan regardless of
voltage, (3) Elements subject to Nuclear Plant Interface Requirements (NPIRs) as agreed to by a
Nuclear Plant Generator Operator and a Transmission Entity defined in NUC-001, and (4) Elements
identified as required to comply with a NERC Reliability Standard by application of criteria defined
within the standard (e.g., the test defined in PRC-023 to identify sub-200 kV Elements to which the
standard is applicable.)
Individual
Rick
Spyker
No
We agree with this concept to allow entities to submit an exception application that does not include
extensive technical analysis. Such an option will make the process efficient for all stakeholders, such
as entities, Regions, NERC and relevant regulatory authority. However, our opinion is that there is no
real relation between reliability and the proximity of load. Consistent with references in the FERC
Order, we feel that it is much more important to identify and ensure if the element(s) are serving load
pockets associated with large metropolitan load centers (e.g. New York City, Washington DC,
Toronto), loads of significance to national security and/or as identified by relevant Federal, State or

Provincial Regulatory Authority. We believe that entities should be required to identify the significance
of the elements’ physical characteristics, such as the proximity of element or, being served or
impacted by the element to a load of significant interest. Such identification can be done through a
simple checklist along with any relevant comments. Therefore, we suggest the SDT to revise the
exception criteria to seek an alternative language and/or re-craft exclusion criteria (a), which will
require entities to provide the previously stated information for their element.
Yes
We agree with this concept. Entities should be allowed to demonstrate the radial characteristics to
determine if they are permitted for an exception.
Yes
We agree with the criteria set out in 1(c), but suggest the SDT to avoid prescribing values and
eliminate bullet (iv). The SDT should describe the intended performance outcome but avoid setting
values. This should have little, if any impact on reliability of the transmission network if the items 1, 2
and 3 are satisfied.
Yes
Yes
We agree that entities should be given an option to conduct an analysis to demonstrate if an element
is necessary or not for the operation of transmission network. We also support that NERC should
specify all the relevant criteria category to be listed as under 2 (a). However, we suggest that NERC
should avoid prescribing numerical values but establish a range of value (or reference industry
standard) that would be consistent with industry/ regional standards or practices without
compromising the reliability of transmission network.
The SDT should avoid setting values and instead describe the intended performance outcomes from
the measurement
We suggest SDT to make references to relevant industry standard such as IEEE standards
The SDT should avoid setting values and instead describe the intended performance outcomes from
the measurement
The SDT should avoid setting values and instead describe the intended performance outcomes from
the measurement
Yes
Technical Analysis must fundamentally use NERC – TPL methodology and testing requirements.
Yes
We agree that entities should be allowed to conduct an analysis to demonstrate if an element is
necessary or not for the operation of transmission network. We also support that NERC should specify
all the relevant criteria category to be listed as under 2 (a). However, we suggest that NERC should
avoid prescribing numerical values but establish a range of value (or reference industry standard)
that would be consistent with industry/ regional standards or practices without compromising the
reliability of transmission network.
See comments in section 5
See comments in section 5
See comments in section 5
See comments in section 5
No
Yes
NERC’s revised definition will have a direct impact on entities across North America and may conflict
with regulatory requirements, Codes, and Licenses. FERC in its Order 743 and 743A has directed
NERC to address these concerns. We suggest the SDT and RoP teams should: • modify the exception
criteria and procedure to provide regulatory flexibility with requirements to conduct basic technical
analysis , to allow entities to consistently present their case to the ERO and/or the regulator for a step
by step expedited evaluation. • Include provisions in both the NERC exception criteria and exception
process for federal, state and provincial jurisdictions. These provisions should provide clear guidance

so that, if and when there are deviations from the exception criteria, they are identified with technical
and regulatory justifications ensuring there is no adverse impact on the interconnected transmission
network. • Understand that the path to generating facilities need not be always BES contiguous.
Generating units can/should be required to be planned, designed, and operated in accordance with a
subset of NERC Standards, but should not always require contiguous paths.
Yes
Exception criteria should be crafted at a high-level with key menu items of assessment that can be
followed continent-wide by entities to put forward their exception for element(s) that are not
necessary for the interconnected transmission network and based on technical assessment, evidence
and justification for its unique characteristics, configuration, and utilization.
Individual
Clint Gerkensmeyer
Benton Rural Electric Association
No
We believe that the proximity test may be unnecessary, and if an Element or group of Elements
meets the other three tests proposed by the SDT, it should be excluded from the BES, even if it does
not meet the proximity test. Secondly, using impedance to benchmark system load proximity would
likely not yield clear demarcations. High voltage relative or per-unit impedances are considered
typically much lower than low voltage impedances. Hence, in the absence of phase shifting
transformers, service compensation, or other mitigation factors, power typically flows over the
highest voltage lines, which offer the lowest impedance.
Yes
Benton REA agrees conceptually that systems operating as radials rather than as integrated portions
of the integrated bulk transmission system should be excluded from the BES definition. That is
because local distribution systems typically operate adjacent to, or at the end of transmission lines,
and function operationally to move power from the Transmission Service Provider’s point of delivery
of bulk power that has moved across the integrated bulk transmission system to end-users located
within the local distribution utility’s service territory. To be consistent with the draft BES definition,
the term “radial in character” should be explicitly defined as a system that may include one or more
lines into a load area or referenced as a local distribution network. In addition, we agree that the
manner in which a system is operated during BES disturbances may be an indication of whether that
system is radial in character. That being said, we are concerned that, to the extent the SDT considers
regional disconnect procedures, it should be careful to note that UFLS and UVLS relays are often
embedded within local distribution systems and, while it is necessary for the UFLS and UVLS relays to
be properly armed to protect the BES in the event of a severe system disturbance, the local
distribution system interconnected with those relays should not.
Yes
Benton REA agrees conceptually that one critical characteristic distinguishing local distribution
facilities that must be excluded from the BES from transmission facilities that should be included is
the manner in which power flows on those facilities. Power on local distribution systems generally
flows only from the interconnected transmission source and across the distribution system for delivery
to end-use customers. By contrast, power on transmission systems generally flows in two (or
multiple, in networked systems) directions and is delivered in bulk to distribution utilities rather than
to end-users. Hence, the SDT has properly identified power flows as one important characteristic that
distinguishes BES transmission systems from local distribution systems. In order to identify systems
that are not necessary for the operation of the BES under this text, we propose that any system
where real power flows into the local distribution system 90 percent of the time or more under normal
operating conditions.
Yes
Benton REA agrees that the SDT’s fourth test, which asks whether power is intentionally transported
through a system, identifies a key characteristic of local distribution facilities that distinguishes such
facilities from interconnect bulk transmission facilities that are properly considered part of the BES. In
fact, we believe this may be the most important and readily identifiable distinction. Accordingly,
Benton REA agrees that if power is not intentionally transported through a particular system, that
system is not used for transmission and should not be considered part of the BES. One exception may

be for a small embedded generation unit owned by a different party that may be “scheduled” out of
an area, but in reality, does not produce any physical flow. These circumstances should not trigger
inclusion.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with local distribution
and not BES transmission facilities, and one relying on technical analysis to determine whether or not
an Element or group of Elements has a measurable impact on the threat of cascading outages,
separation events, or instability on the interconnected bulk system. If technical analysis demonstrates
that Elements create no material threat of such reliability events, they should properly be excluded
from the BES. Benton REA supports the technical arguments and the White Paper presented by
Snohomish County PUD in their comments. We recommend that the SDT modify its approach to the
technical exclusion process to match the approach advocated in the White Paper, which is based upon
the approach recommended by the WECC BES Task Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection.
Specific transient voltage dip thresholds are proposed at page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid showing that the Elements contribute substantially to the
potential for cascading outages, separation events, or instability on the interconnection bulk
transmission system. We also agree that the SDT has, in general, identified the correct technical
approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion
analysis) be modified as discussed in the Snohomish PUD White Paper, in the WECC BES Task Force
Proposal 6, and in our answer to Question 5.
See exclusion comments Question 5
See exclusion comments Question 5
See exclusion comments Question 5
See exclusion comments Question 5
No
As discussed on page 12 of the Snohomish White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant
Regional Entity, and in nearly every case, the base case can be expected to model any Element that
conceivably has a material impact on the reliable operation of the bulk system. In those rare cases
where it does not, we believe the owner or operator of the subject Element should be able to provide
the needed data.
No

As properly constructed Definition and Exceptions process should meet the legal requirements of
Section 215.
Yes
Benton REA generally supports the approach to the exclusion process proposed by the SDT, which
provides two different paths to exclusion, one based on readily-identifiable operational characteristics
of a system, and one based on technical reliability analysis. We believe it is important to provide for
the first path, based on operational characteristics, so that systems that are marginally disqualified
under the BES Definition (because, for example, generation within the system exceeds demand for a
few hours a year) can obtain an exclusion without the large investment of resources that otherwise
might be required for a full-scale technical analysis. That being said, we question whether the first
subsection of the characteristic test, relating to system proximity, is necessary, and we are concerned
that the requirement that a system meet all four requirements of the characteristics test may be
overly restrictive. For example, it is easy to imagine a distribution system in a rural area that covers a
widely dispersed area, so that load is many miles from the relevant generation/transmission source,
and that the system therefore does not meet the electrical proximity element, but meets the other
three elements of the characteristics test. Such a system should be excluded because it clearly serves
a local distribution function, and not a transmission function, as demonstrated by the fact that the
system meets subsections (c) (power flows into the system but rarely flows out ) and (d) (power is
not intentionally transported over the system). Accordingly, we recommend that the SDT consider
eliminating the first test. In the alternative, the SDT should consider allowing exempting a system
from the BES if it, for example, meets three of the four criteria rather than all four.
Individual
Robert Ganley
Long Island Power Authority
Yes
Agree with close proximity to load concept but further direction (define suggested methodology) is
required for how to calculate impedance value. In addition to impedance value suggest consideration
of adding mileage or relative phase angle differences between locations be also an allowable criteria.
Yes
Elements could be included in a regional dispatch such as a large regional ISO, but still serve only
local load and therefore should still be treated as radial.
Yes
Item iv. The maximum amount of energy flowing out is (TBD-1,752,000) MWh per year. Another
measure that may be more appropriate is a percent % of total energy requirements in the area.
Yes
In addition to Operating Procedures, electrical elements that restrict or control flow over the line
should be allowed to be used as evidence.
Exclusion under this criteria would require that the analysis be performed by the registered TP.
Criteria identified is based on interconnection to neighboring utilities.

No
Yes

Yes

The Reliability Coordinator would be required to provide much of the data needed to perform the
technical analyses.

Individual
Thad Ness
American Electric Power
Yes
Using “proximity to load” is a reasonable metric, but would require further consideration given the
impedance value eventually chosen to replace “TBD”.
Yes
Considering whether or not the element is treated as radial is a reasonable approach.
Yes
Requiring that “power flows into the system, but rarely flows out” is a reasonable approach, but would
require further consideration given the MWh value eventually chosen to replace “TBD”.
Yes
Requiring that “power entering the system is not intentionally transported through the system to
some other system” is a reasonable approach.
Yes

No
No

Yes
Each criterion specified would not be able to be provided, or even applicable, for each exclusion
requested. If the criteria provided may be selected from as necessary for each request, then we have
no concerns on our ability to provide the data. Our only concern would be if the intent is that each
and every criterion specified must be provided for each request made.
No
AEP is not aware of any conflicts between the proposed approach and any regulatory function, rule
order, tariff, rate schedule, legislative requirement or agreement, or jurisdictional issue.
Yes
AEP appreciates the work that the drafting teams have done within the various deliverables related to
the BES definition, technical principles for demonstrating BES exceptions, and the BES definition
exception process. AEP acknowledges the benefits of agreeing to a BES definition and exception
process, and appreciates the drafting teams’ requests for industry involvement. Due to the
interrelated nature of the deliverables currently out for review regarding the BES definition and
exception processes, it is difficult if not impossible, to comment “in isolation” on any individual facet
of the project. For example, there needs to be a defined relationship between an approved definition
of BES, the technical principles for demonstrating BES exception, and the exception process itself.
When closely related projects such as these are done simultaneously, no individual deliverable can
rely on the completed work of another. As a result, we risk having conflicting decision making across

these projects. As a result, AEP is not in the position to make further comments at this time beyond
those recently and concurrently made regarding the BES definition and technical principles for
demonstrating BES exceptions. We suggest that further work on these efforts, when appropriate,
become more consolidated and that care be taken to not undertake concurrent efforts before
sufficient progress has been made on important aspects of the project. AEP appreciates the drafting
teams’ requests for industry input, and looks forward to its future involvement after additional
progress has been made on these issues.
Individual
David Burke
Orange and Rockland Utilities, Inc.
No
The approach does not differentiate between transmission and distribution. There is no direct relation
between impedance and load. A study of the particular system should be performed to assess impact
on BES.
Yes
Yes
The “TBD” value should be reasonable and well justified.
Yes
No
This approach is not necessary since NERC TPL Reliability Standards already addressed how to
maintain a reliable electric system.

Yes
FERC Order No. 888 – Seven Factor Test.
No
The Inclusion criteria should mirror Exclusion criteria. See comments 5.

No
No
No
Individual
David Thorne
Pepco Holdings Inc
No
A specific impedance value would not be appropriate for all regions and all configurations.
No
Radial system is already an explicit Exclusion by definition (E1). Does this imply that ALL radial
systems require a request to be submitted for the RE and NERC approval that the elements are in fact
radial? There may not be internal written procedures describing the radial system operation. The

evidence that an entity can provide should include a description or justification of the radial operation
and non impact to the BES.
No
The characteristic statement should be reworded to say: “Power flow is generally load serving.” The
criteria as written have very burdensome MWh record requirements. Yearly totals for flows in and out
and an overall description or justification for this exception should be allowable.
No
This criterion is very similar to the third item. Written operating procedures may not exist. The entity
should be allowed to summit a description and justification.
No
Generally agree that a specific technical analysis approach (power flow studies) showing no impact on
BES is appropriate, but don’t know how to define specific criteria on which to base decision.

No
No
Same comments as question #5

Yes
The entity may not have the tools, model or resources to do a full transmission planning study
Yes
Facilities defined as local distribution facilities should not be forced into BES classification due to this
new bright line definition.
Yes
Concern that as this proposal is written such that each exclusion in the BES definition (E1, E2 and E3)
will require a submittal to approve that is an exclusion.
Individual
Paul Titus
Northern Wasco County PUD
No
We believe that the proximity test may be unnecessary, and if an Element or group of Elements
meets the other three tests proposed by the SDT, it should be excluded from the BES, even if it does
not meet the proximity test. Secondly, using impedance to benchmark system load proximity would
likely not yield clear demarcations. High voltage relative or per-unit impedances are considered
typically much lower than low voltage impedances. Hence, in the absence of phase shifting
transformers, service compensation, or other mitigation factors, power typically flows over the
highest voltage lines, which offer the lowest impedance.
Yes
Northern Wasco County PUD agrees conceptually that systems operating as radials rather than as
integrated portions of the integrated bulk transmission system should be excluded from the BES
definition. That is because local distribution systems typically operate adjacent to, or at the end of
transmission lines, and function operationally to move power from the Transmission Service Provider’s
point of delivery of bulk power that has moved across the integrated bulk transmission system to
end-users located within the local distribution utility’s service territory. To be consistent with the draft
BES definition, the term “radial in character” should be explicitly defined as a system that may include
one or more lines into a load area or referenced as a local distribution network. In addition, we agree

that the manner in which a system is operated during BES disturbances may be an indication of
whether that system is radial in character. That being said, we are concerned that, to the extent the
SDT considers regional disconnect procedures, it should be careful to note that UFLS and UVLS relays
are often embedded within local distribution systems and, while it is necessary for the UFLS and UVLS
relays to be properly armed to protect the BES in the event of a severe system disturbance, the local
distribution system interconnected with those relays should not.
Yes
Northern Wasco County PUD agrees conceptually that one critical characteristic distinguishing local
distribution facilities that must be excluded from the BES from transmission facilities that should be
included is the manner in which power flows on those facilities. Power on local distribution systems
generally flows only from the interconnected transmission source and across the distribution system
for delivery to end-use customers. By contrast, power on transmission systems generally flows in two
(or multiple, in networked systems) directions and is delivered in bulk to distribution utilities rather
than to end-users. Hence, the SDT has properly identified power flows as one important characteristic
that distinguishes BES transmission systems from local distribution systems. In order to identify
systems that are not necessary for the operation of the BES under this text, we propose that any
system where real power flows into the local distribution system 90 percent of the time or more under
normal operating conditions.
Yes
Northern Wasco County PUD agrees that the SDT’s fourth test, which asks whether power is
intentionally transported through a system, identifies a key characteristic of local distribution facilities
that distinguishes such facilities from interconnect bulk transmission facilities that are properly
considered part of the BES. In fact, we believe this may be the most important and readily identifiable
distinction. Accordingly, Northern Wasco County PUD agrees that if power is not intentionally
transported through a particular system, that system is not used for transmission and should not be
considered part of the BES. One exception may be for a small embedded generation unit owned by a
different party that may be “scheduled” out of an area, but in reality, does not produce any physical
flow. These circumstances should not trigger inclusion.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with local distribution
and not BES transmission facilities, and one relying on technical analysis to determine whether or not
an Element or group of Elements has a measurable impact on the threat of cascading outages,
separation events, or instability on the interconnected bulk system. If technical analysis demonstrates
that Elements create no material threat of such reliability events, they should properly be excluded
from the BES. Northern Wasco County PUD supports the technical arguments and the White Paper
presented by Snohomish County PUD in their comments. We recommend that the SDT modify its
approach to the technical exclusion process to match the approach advocated in the White Paper,
which is based upon the approach recommended by the WECC BES Task Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection.
Specific transient voltage dip thresholds are proposed at page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of

that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid showing that the Elements contribute substantially to the
potential for cascading outages, separation events, or instability on the interconnection bulk
transmission system. We also agree that the SDT has, in general, identified the correct technical
approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion
analysis) be modified as discussed in the Snohomish PUD White Paper, in the WECC BES Task Force
Proposal 6, and in our answer to Question 5.

No
As discussed on page 12 of the Snohomish White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant
Regional Entity, and in nearly every case, the base case can be expected to model any Element that
conceivably has a material impact on the reliable operation of the bulk system. In those rare cases
where it does not, we believe the owner or operator of the subject Element should be able to provide
the needed data.
No
As properly constructed Definition and Exceptions process should meet the legal requirements of
Section 215.
Yes
Northern Wasco County PUD generally supports the approach to the exclusion process proposed by
the SDT, which provides two different paths to exclusion, one based on readily-identifiable operational
characteristics of a system, and one based on technical reliability analysis. We believe it is important
to provide for the first path, based on operational characteristics, so that systems that are marginally
disqualified under the BES Definition (because, for example, generation within the system exceeds
demand for a few hours a year) can obtain an exclusion without the large investment of resources
that otherwise might be required for a full-scale technical analysis. That being said, we question
whether the first subsection of the characteristic test, relating to system proximity, is necessary, and
we are concerned that the requirement that a system meet all four requirements of the characteristics
test may be overly restrictive. For example, it is easy to imagine a distribution system in a rural area
that covers a widely dispersed area, so that load is many miles from the relevant
generation/transmission source, and that the system therefore does not meet the electrical proximity
element, but meets the other three elements of the characteristics test. Such a system should be
excluded because it clearly serves a local distribution function, and not a transmission function, as
demonstrated by the fact that the system meets subsections (c) (power flows into the system but
rarely flows out ) and (d) (power is not intentionally transported over the system). Accordingly, we
recommend that the SDT consider eliminating the first test. In the alternative, the SDT should
consider allowing exempting a system from the BES if it, for example, meets three of the four criteria
rather than all four.
Individual
Alice Ireland
Xcel Energy
Yes
Yes

Yes
Regarding the question on MWH, one possible approach is to use 175,000 MWH/ year which would be
just under the annual hourly output from the smallest generator (not at a plant) that must be
registered under the registry criteria.
Yes
It is not clear what ‘some other system’ would be. Is this another point on the BES in general?
Yes

Yes
Xcel Energy would like the SDT to consider a Capacity Factor exclusion for generating resources that
are rarely used. For example, at least two standards that are currently being drafted exempt
generators that have an average Capacity Factor of 5% or less over a three year period.
Yes

No
No
No
Individual
Jianmei Chai
Consumers Energy Company
No
Consumers Energy Company (CECo) proposes that this criterion be eliminated, as it is not a definitive
BES criterion. There is no correlation between the proximity of Elements that are 100kV and above to
load.
Yes
Yes
Yes
No
Generally, this approach seems sound.
This criterion raises concerns. If based on transfer distribution factor it may have some merit,
depending on the TBD value. However, the criteria should not be based on outage transfer
distribution factor, as Draft 1 implies, since loss of certain local distribution facilities can result in local
distribution load being transferred to other local distribution facilities. Distribution facilities should not
be prevented from exclusion from BES.
The criterion related to Transient Voltage Deviations should be removed. This criterion, regardless of

value TBD, would be impossible to achieve, and would render this process meaningless. A fault on
non-BES elements will cause significant transient voltage dips on nearby BES elements until the fault
is cleared. If the non-BES element is at the same voltage level, the dip will result in near-zero
voltages; if at different voltage levels, the dip magnitude will be determined by the ratio of the
system Thévinen impedance at the BES to the intervening transformer impedance - if the system
Thévinen impedance is 2% and the transformer impedance is 18%, the voltage on the BES will dip to
10%.
The criterion relative to frequency response should be removed. Frequency deviations can result from
large changes in distribution load. Distribution facilities should not be prevented from being excluded
from BES.
This criterion may be reasonable, depending on the TBD value. The TBD value may need to vary for
different voltage levels or system configurations. The criteriona needs to recognize that loss of
multiple capacitors at the distribution level could result in significant voltage deviation at the BES and
this must not prevent distribution facilities from being excluded from BES.
No
We believe all of the Inclusion criteria should be replaced by a single criterion, which would include
any element that could cause cascading outages of greater than 1,000 MW.
If our suggestion in 7a is not adopted, we propose the following: If based on transfer distribution
factor this criterion may have some merit, depending on the TBD value. However, the criterion should
not be based on outage transfer distribution factor, as Draft 1 implies since loss of certain distribution
facilities can result in distribution load being transferred to other interconnection points. Distribution
facilities should not be classified as BES.
If our suggestion in 7a is not adopted, we propose the following: The criterion related to Transient
Voltage Deviations should be removed from the Inclusion Process. This criterion, regardless of value
TBD, would cause any element, perhaps even including radial Primary Distribution Facilities (8.2 kV,
etc.) to be sequentially included as BES. A fault on non-BES elements will cause significant transient
voltage dips on nearby BES elements until the fault is cleared. If the non-BES element is at the same
voltage level, the dip will result in near-zero voltages; if at different voltage levels, the dip magnitude
will be determined by the ratio of the system Thévinen impedance at the BES to the intervening
transformer impedance - if the system Thévinen impedance is 2% and the transformer impedance is
18%, the voltage on the BES will dip to 10%.
If our suggestion in 7a is not adopted, we propose the following: The criterion relative to frequency
response should be removed. Frequency deviations can result from large changes in distribution load.
Distribution facilities should not be classified as BES.
If our suggestion in 7a is not adopted, we propose the following: This criterion may be reasonable,
depending on the TBD value. The TBD value may need to vary for different voltage levels or system
configurations. Loss of multiple capacitors at the distribution level could result in significant voltage
deviation at the BES and the criterion should be developed so as not to result in Distribution facilities
being classified as BES.
Yes
CECo is not able to formulate detailed comments at this time, as the criteria have not been finalized.
There are a number of items that are somewhat open ended, i.e. TBD and Other. Once those gray
areas are filled in, we will have a better idea of our ability to obtain the necessary data.
Yes
The Technical Principles for Demonstrating BES Exceptions should not conflict with the seven-factor
test provisions of FERC Order 888. In particular, provisions should not be established by the Standard
Drafting Team that contradict prior Commission rulings associated with seven-factor test provisions.
Yes
In addition to the owner, only those with jurisdictional authority, such as the ERO and RRO, should be
permitted to register Exception Requests. A third party may have a business reason for wishing to
encumber another entity with regulatory compliance risk and responsibility. In addition, this could
create an additional strain on the Exception Request process due to an excessive number of requests
from third parties. We do want to ensure that the term "Other", used in Exclusion Section 2.a.iv.8.,
and Inclusion Section 1.c.8., not remain in the final Technical Principles document.

Group
PPL Supply
John Cummings
No
See comments in
No
See comments in
No
See comments in
No
See comments in
No
See comments in

Questions 9 and 10
Questions 9 and 10
Questions 9 and 10
Questions 9 and 10
Questions 9 and 10

Yes
See comments in Questions 9 and 10
No
See comments in Questions 9 and 10

Yes
See comments in Questions 9 and 10
Yes
Based on FERC Order 743 paragraph 120, radial and local distribution facilities should be excluded
from the definition of the Bulk Electric System (BES). The exclusion of non-networked facilities such
as radial lines is further re-enforced with Order 743 paragraph 73 which describes the characteristics
of a network and does not include most generator interconnection facilities. In that order, FERC
justified its bright-line, 100 kV threshold, explaining that "many facilities operated at 100 kV and
above have a significant effect on the overall functioning of the grid" because they share the following
characteristics: 1. "operate in parallel with other high voltage and extra high voltage facilities" i. The
“bright line” at 100 kV recognizes many 100 kV lines parallel other HV/EHV lines and can be
significantly loaded by failure of the HV/EHV lines. This does not apply to radial lines, even at 100 kV
and above. 2. "interconnect significant amounts of generation sources" (emphasis added) 3. "operate
as part of a defined flow gate" 4. have a "parallel nature" and are capable of “caus[ing] or
contribute[ing] to significant bulk system disturbances”. i. Radial lines cannot cause significant BES
disturbances since the outage of a radial line is studied in all N-1 planning studies and if the TPL
standards are followed, an N-1 should not cause such disturbances. Excluding generator lead lines is
very practical because the physical reality of a radial generator lead line is that it cannot be
overloaded by outages on parallel paths because there are no parallel paths. Further, the MW flow on
a radial line is well known and limited to a known maximum (limited to the larger of the generation or
load on the end of the line); clearly these are reasons for excluding radial lines. When and if a
generator lead line is tapped by another generator or load, it is possible that the line between the tap
point and the original point of interconnection might need to be rolled into the electrical network.
However, at that time, it might also be possible for the transmission owner to purchase the line and
make the tap point the new point of interconnection.
Yes
General PPL Supply concerns with draft Technical Principles for exclusion/inclusion: 1. It may be

premature to work on an exclusion/exemption/inclusion process since the BES definition is not
established yet. A lot of work could be done on the Exclusion/Inclusion that is meaningless because
there is some chance the exclusion/inclusion process will not complement or might duplicate the BES
definition. 2. The proposal will result in inclusion of generation facilities that are not significant to BES
reliability. 3. The exclusion/inclusion drafting team does not appear to have considered the FERC
assessment in Order 743-A (17-Mar-11) that “material impact assessments” cannot be unduly
subjective and must be technically based as stated in paragraph 47. a. For the material impact tests
in the Exclusion/Inclusion Technical Principles to be technically based, it is important that the tests
actually measure what FERC states are the characteristics of the BES (see Order 743 paragraph 73),
namely 1) operate in parallel, 2) carry significant amounts of generation, 3) operate as part of a
defined flowgate, 4) are parallel in nature and 5) are capable of causing or contributing to significant
disturbances. The proposed tests do not make these measurements. b. Further, since all facilities
already meet the technically based NERC planning and operating standards, any additional measure
beyond these standards such as those created by the BES Exclusion/Inclusion drafting team will be
unduly subjective, as these new measures go beyond the technical basis of the NERC standards. 4. It
is unclear how the exclusion/inclusion drafting team considered FERC’s concerns with the use of
“material impact assessments,” as described in Order 743, paragraph 85 (“no grounds on which to
reasonably assume that the results of the material impact assessment are accurate, consistent, and
comprehensive”). Specific comments on Technical Principles paper from NERC DT 20110510 A. Please
add wording to make complete sentences as needed in order to clarify whether facilities meeting
these criteria are included or excluded. For example, the clarifying words are added to the following
Exclusion 1 to help the reader better understand the meaning. 1. “The elements that meet all of the
following characteristics are not necessary for the reliable operation of the grid and are thus
excluded:” a. System elements that are located in close electrical proximity to Load are exempt from
inclusion in the BES. B. Notwithstanding the need for complete sentences to assure proper
interpretation, the following comments should be considered by the drafting team: o Exclusion 1 a)
uses an unduly subjective, non-technically based material impact test. o Exclusion 1 b) i and ii
attempts to introduce disconnect procedures in the classification as “radial” which may hurt reliability
by disconnecting radial equipment that could provide voltage support. The exclusion also introduces
commercial (dispatch) considerations which may not be appropriate in a reliability-based document. o
Exclusion 1 c) assuming “system” is short for “system elements”, this requirement for exclusion is
overly discriminatory to generators which flow power out. o Exclusion 1 d) is too vague to be useful
because “system” seems to have more than one meaning in this requirement. o Exclusion 2 and
Inclusion 1 in their entirety are unduly subjective, non-technically based material impact tests. We
are concerned that the proposed inclusion and exclusion procedures could result in not only significant
generation interconnection facilities being included in the BES – but also less significant generation
interconnection facilities. Such a result would be inconsistent with FERC Order 743. Accordingly, PPL
Supply respectfully requests NERC to: o Exclude radial facilities less than 100 kV and not black start
(these facilities are excluded in the latest definition of the BES). o Exclude radial facilities greater than
100 kV but less than 200 MVA (proposed BES now includes generators over 20 MVA) o Exclude local
distribution networks (LDNs) with flow into network up to 200 MVA o Currently, LDNs are excluded if
they only absorb (not produce) net power (Technical Principles Exclusion 1-c). It is also appropriate to
exclude LDNs with less than net 200 MVA flow into the BES electrical network. o Inclusion efforts
should not consider such issues as proximity to markets, proximity to load or nuclear facilities, or
length of generator lead line.
Individual
Jo Elg
United Electric Co-op Inc.
No
We believe that the proximity test may be unnecessary, and if an Element or group of Elements
meets the other three tests proposed by the SDT, it should be excluded from the BES, even if it does
not meet the proximity test. Secondly, using impedance to benchmark system load proximity would
likely not yield clear demarcations. High voltage relative or per-unit impedances are considered
typically much lower than low voltage impedances. Hence, in the absence of phase shifting
transformers, service compensation, or other mitigation factors, power typically flows over the
highest voltage lines, which offer the lowest impedance.
Yes

United Electric Co-op Inc agrees conceptually that systems operating as radials rather than as
integrated portions of the integrated bulk transmission system should be excluded from the BES
definition. That is because local distribution systems typically operate adjacent to, or at the end of
transmission lines, and function operationally to move power from the Transmission Service Provider’s
point of delivery of bulk power that has moved across the integrated bulk transmission system to
end-users located within the local distribution utility’s service territory. To be consistent with the draft
BES definition, the term “radial in character” should be explicitly defined as a system that may include
one or more lines into a load area or referenced as a local distribution network. In addition, we agree
that the manner in which a system is operated during BES disturbances may be an indication of
whether that system is radial in character. That being said, we are concerned that, to the extent the
SDT considers regional disconnect procedures, it should be careful to note that UFLS and UVLS relays
are often embedded within local distribution systems and, while it is necessary for the UFLS and UVLS
relays to be properly armed to protect the BES in the event of a severe system disturbance, the local
distribution system interconnected with those relays should not.
Yes
United Electric Co-op Inc agrees conceptually that one critical characteristic distinguishing local
distribution facilities that must be excluded from the BES from transmission facilities that should be
included is the manner in which power flows on those facilities. Power on local distribution systems
generally flows only from the interconnected transmission source and across the distribution system
for delivery to end-use customers. By contrast, power on transmission systems generally flows in two
(or multiple, in networked systems) directions and is delivered in bulk to distribution utilities rather
than to end-users. Hence, the SDT has properly identified power flows as one important characteristic
that distinguishes BES transmission systems from local distribution systems. In order to identify
systems that are not necessary for the operation of the BES under this text, we propose that any
system where real power flows into the local distribution system 90 percent of the time or more under
normal operating conditions.
Yes
United Electric Co-op Inc agrees that the SDT’s fourth test, which asks whether power is intentionally
transported through a system, identifies a key characteristic of local distribution facilities that
distinguishes such facilities from interconnect bulk transmission facilities that are properly considered
part of the BES. In fact, we believe this may be the most important and readily identifiable distinction.
Accordingly, United Electric Co-op Inc agrees that if power is not intentionally transported through a
particular system, that system is not used for transmission and should not be considered part of the
BES. One exception may be for a small embedded generation unit owned by a different party that
may be “scheduled” out of an area, but in reality, does not produce any physical flow. These
circumstances should not trigger inclusion.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with local distribution
and not BES transmission facilities, and one relying on technical analysis to determine whether or not
an Element or group of Elements has a measurable impact on the threat of cascading outages,
separation events, or instability on the interconnected bulk system. If technical analysis demonstrates
that Elements create no material threat of such reliability events, they should properly be excluded
from the BES. United Electric Co-op Inc supports the technical arguments and the White Paper
presented by Snohomish County PUD in their comments. We recommend that the SDT modify its
approach to the technical exclusion process to match the approach advocated in the White Paper,
which is based upon the approach recommended by the WECC BES Task Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection.
Specific transient voltage dip thresholds are proposed at page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B

contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid showing that the Elements contribute substantially to the
potential for cascading outages, separation events, or instability on the interconnection bulk
transmission system. We also agree that the SDT has, in general, identified the correct technical
approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion
analysis) be modified as discussed in the Snohomish PUD White Paper, in the WECC BES Task Force
Proposal 6, and in our answer to Question 5.
See exclusion comment.
See exclusion comment.
See exclusion comment.
See exclusionn comment.
No
As discussed on page 12 of the Snohomish White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant
Regional Entity, and in nearly every case, the base case can be expected to model any Element that
conceivably has a material impact on the reliable operation of the bulk system. In those rare cases
where it does not, we believe the owner or operator of the subject Element should be able to provide
the needed data.
No
As properly constructed Definition and Exceptions process should meet the legal requirements of
Section 215.
Yes
United Electric Co-op Inc generally supports the approach to the exclusion process proposed by the
SDT, which provides two different paths to exclusion, one based on readily-identifiable operational
characteristics of a system, and one based on technical reliability analysis. We believe it is important
to provide for the first path, based on operational characteristics, so that systems that are marginally
disqualified under the BES Definition (because, for example, generation within the system exceeds
demand for a few hours a year) can obtain an exclusion without the large investment of resources
that otherwise might be required for a full-scale technical analysis. That being said, we question
whether the first subsection of the characteristic test, relating to system proximity, is necessary, and
we are concerned that the requirement that a system meet all four requirements of the characteristics
test may be overly restrictive. For example, it is easy to imagine a distribution system in a rural area
that covers a widely dispersed area, so that load is many miles from the relevant
generation/transmission source, and that the system therefore does not meet the electrical proximity
element, but meets the other three elements of the characteristics test. Such a system should be
excluded because it clearly serves a local distribution function, and not a transmission function, as
demonstrated by the fact that the system meets subsections (c) (power flows into the system but
rarely flows out ) and (d) (power is not intentionally transported over the system). Accordingly, we
recommend that the SDT consider eliminating the first test. In the alternative, the SDT should
consider allowing exempting a system from the BES if it, for example, meets three of the four criteria
rather than all four.
Individual

Ned Ratterman
Oregon Trail Electric Cooperative, Inc.
No
We believe that the proximity test may be unnecessary, and if an Element or group of Elements
meets the other three tests proposed by the SDT, it should be excluded from the BES, even if it does
not meet the proximity test. Secondly, using impedance to benchmark system load proximity would
likely not yield clear demarcations. High voltage relative or per-unit impedances are considered
typically much lower than low voltage impedances. Hence, in the absence of phase shifting
transformers, service compensation, or other mitigation factors, power typically flows over the
highest voltage lines, which offer the lowest impedance.
Yes
Oregon Trail Electric agrees conceptually that systems operating as radials rather than as integrated
portions of the integrated bulk transmission system should be excluded from the BES definition. That
is because local distribution systems typically operate adjacent to, or at the end of transmission lines,
and function operationally to move power from the Transmission Service Provider’s point of delivery
of bulk power that has moved across the integrated bulk transmission system to end-users located
within the local distribution utility’s service territory. To be consistent with the draft BES definition,
the term “radial in character” should be explicitly defined as a system that may include one or more
lines into a load area or referenced as a local distribution network. In addition, we agree that the
manner in which a system is operated during BES disturbances may be an indication of whether that
system is radial in character. That being said, we are concerned that, to the extent the SDT considers
regional disconnect procedures, it should be careful to note that UFLS and UVLS relays are often
embedded within local distribution systems and, while it is necessary for the UFLS and UVLS relays to
be properly armed to protect the BES in the event of a severe system disturbance, the local
distribution system interconnected with those relays should not.
Yes
Oregon Trail Electric agrees conceptually that one critical characteristic distinguishing local distribution
facilities that must be excluded from the BES from transmission facilities that should be included is
the manner in which power flows on those facilities. Power on local distribution systems generally
flows only from the interconnected transmission source and across the distribution system for delivery
to end-use customers. By contrast, power on transmission systems generally flows in two (or
multiple, in networked systems) directions and is delivered in bulk to distribution utilities rather than
to end-users. Hence, the SDT has properly identified power flows as one important characteristic that
distinguishes BES transmission systems from local distribution systems. In order to identify systems
that are not necessary for the operation of the BES under this text, we propose that any system
where real power flows into the local distribution system 90 percent of the time or more under normal
operating conditions.
Yes
Oregon Trail Electric agrees that the SDT’s fourth test, which asks whether power is intentionally
transported through a system, identifies a key characteristic of local distribution facilities that
distinguishes such facilities from interconnect bulk transmission facilities that are properly considered
part of the BES. In fact, we believe this may be the most important and readily identifiable distinction.
Accordingly, Oregon Trail Electric agrees that if power is not intentionally transported through a
particular system, that system is not used for transmission and should not be considered part of the
BES. One exception may be for a small embedded generation unit owned by a different party that
may be “scheduled” out of an area, but in reality, does not produce any physical flow. These
circumstances should not trigger inclusion.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with local distribution
and not BES transmission facilities, and one relying on technical analysis to determine whether or not
an Element or group of Elements has a measurable impact on the threat of cascading outages,
separation events, or instability on the interconnected bulk system. If technical analysis demonstrates
that Elements create no material threat of such reliability events, they should properly be excluded
from the BES. Oregon Trail Electric supports the technical arguments and the White Paper presented
by Snohomish County PUD in their comments. We recommend that the SDT modify its approach to

the technical exclusion process to match the approach advocated in the White Paper, which is based
upon the approach recommended by the WECC BES Task Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric m. While we understand that
many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection.
Specific transient voltage dip thresholds are proposed at page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid showing that the Elements contribute substantially to the
potential for cascading outages, separation events, or instability on the interconnection bulk
transmission system. We also agree that the SDT has, in general, identified the correct technical
approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion
analysis) be modified as discussed in the Snohomish PUD White Paper, in the WECC BES Task Force
Proposal 6, and in our answer to Question 5.
See exclusion comment
See exclusion comment
See exclusion comment
See exclusion comment
No
As discussed on page 12 of the Snohomish White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant
Regional Entity, and in nearly every case, the base case can be expected to model any Element that
conceivably has a material impact on the reliable operation of the bulk system. In those rare cases
where it does not, we believe the owner or operator of the subject Element should be able to provide
the needed data.
No
As properly constructed Definition and Exceptions process should meet the legal requirements of
Section 215.
Yes
Oregon Trail Electric generally supports the approach to the exclusion process proposed by the SDT,
which provides two different paths to exclusion, one based on readily-identifiable operational
characteristics of a system, and one based on technical reliability analysis. We believe it is important
to provide for the first path, based on operational characteristics, so that systems that are marginally
disqualified under the BES Definition (because, for example, generation within the system exceeds
demand for a few hours a year) can obtain an exclusion without the large investment of resources
that otherwise might be required for a full-scale technical analysis. That being said, we question
whether the first subsection of the characteristic test, relating to system proximity, is necessary, and
we are concerned that the requirement that a system meet all four requirements of the characteristics

test may be overly restrictive. For example, it is easy to imagine a distribution system in a rural area
that covers a widely dispersed area, so that load is many miles from the relevant
generation/transmission source, and that the system therefore does not meet the electrical proximity
element, but meets the other three elements of the characteristics test. Such a system should be
excluded because it clearly serves a local distribution function, and not a transmission function, as
demonstrated by the fact that the system meets subsections (c) (power flows into the system but
rarely flows out ) and (d) (power is not intentionally transported over the system). Accordingly, we
recommend that the SDT consider eliminating the first test. In the alternative, the SDT should
consider allowing exempting a system from the BES if it, for example, meets three of the four criteria
rather than all four.
Individual
Steve Alexanderson
Central Lincoln
No
Central Lincoln agrees in principle that one characteristic of local distribution systems is that they are
usually confined to a relatively limited geographic area, as opposed to transmission systems, which
(especially in the West) tend to cover very large distances. We also believe the proximity test may be
a sensible way to identify local distribution facilities. However, as explained in more detail in our
response to Question 10, we believe that the proximity test may be unnecessary, and if an Element or
group of Elements meets the other three tests proposed by the SDT, it should be excluded from the
BES, even if it does not meet the proximity test. Secondly, using impedance to benchmark system
load proximity would likely not yield consistent demarcations. High voltage relative or per-unit
impedances are typically much lower than low voltage impedances. Hence, in the absence of phase
shifting transformers, service compensation, or other mitigation factors, power typically flows over
the highest voltage lines, which offer the lowest impedance. Central Lincoln proposes that “proximity”
be determined in the dictionary manner with units of distance.
No
Central Lincoln agrees that systems operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. That is because local
distribution systems typically operate adjacent to, or at the end of transmission lines, and function
operationally to move power from the Transmission Service Provider’s point of delivery of bulk power
that has moved across the integrated bulk transmission system to end-users located within the local
distribution utility’s service territory. To be consistent with the draft BES definition, the term “radial in
character” should be explicitly defined as a system that may include one or more lines into a load
area or referenced as a local distribution network. In addition, we agree that the manner in which a
system is operated during BES disturbances may be an indication of whether that system is radial in
character. That being said, we are concerned that, to the extent the SDT considers regional
disconnect procedures, it should be careful to note that UFLS and UVLS relays are often embedded
within local distribution systems and, while it is necessary for the UFLS and UVLS relays to be
properly armed to protect the BES in the event of a severe system disturbance, the local distribution
system interconnected with those relays should not, and cannot legally, be classified as BES.
Yes
Central Lincoln agrees that one critical characteristic distinguishing local distribution facilities that
must be excluded from the BES from transmission facilities that should be included is the manner in
which power flows on those facilities. Power on local distribution systems generally flows only from
the interconnected transmission source and across the distribution system for delivery to end-use
customers. By contrast, power on transmission systems generally flows in two (or multiple, in
networked systems) directions and is delivered in bulk to distribution utilities rather than to endusers. Hence, the SDT has properly identified power flows as one important characteristic that
distinguishes BES transmission systems from local distribution systems. Central Lincoln also agrees
that the fact that power may flow out of a local distribution system onto the grid during a few hours in
a year or during extreme contingencies should not change the characterization of the system as local
distribution. Accordingly, we support inclusion of power flow analysis as one element of characteristics
that can be used to exclude local distribution facilities from the BES even if the facilities do not pass
each of the bright-line thresholds laid down in the BES definition. We also agree that transactional
and hourly generation records are an appropriate basis for making the determination since these can

be used to demonstrate that demand within a local distribution system exceeds generation within that
system in most hours and that power therefore does not flow onto the grid, and also to determine the
number of hours where this is not the case and the amount by which generation within the system
exceeds demand. In order to identify systems that are not necessary for the operation of the BES
under this test, we propose that any system where real power flows into the local distribution system
90 percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions
should be held to meet this test. That a system meets this test could be demonstrated using metering
or supervisory control and data acquisition ("SCADA") data records over the course of two years. In
addition, the presence of generation within a local distribution system that only modifies the level of
the load served by the bulk system, but does not result in power being injection into the bulk system,
does not change the reliability effect of the local network and therefore should not require the local
network to be classified as BES.
No
Central Lincoln agrees that the SDT’s fourth test, which asks whether power is intentionally
transported through a system, identifies a key characteristic of local distribution facilities that
distinguishes such facilities from interconnect bulk transmission facilities that are properly considered
part of the BES. In fact, we believe this may be the most important and readily identifiable distinction.
As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in
the Western Interconnection (either individually or as part of a transmission path) are rated for total
transmission capacity and available transmission capacity, and transmission rights can be purchased
on such lines, if available, on an OASIS. Local distribution systems do not share any of these
operational characteristics. Accordingly, Central Lincoln agrees that if power is not intentionally
transported through a particular system, that system is not used for transmission and should not be
considered part of the BES. We also agree that examining the Operating Procedures applicable to a
particular system will provide a ready guide to whether power is intentionally scheduled across that
system. We suggest, however, that the SDT look beyond those protocols that fall within the NERC
Glossary’s definition of Operating Procedure. For example, in the West, transmission paths are almost
all listed in the WECC Path Rating Catalog. Similarly, it is not clear whether scheduling protocols,
OASIS operations, and the other factors listed above qualify as Operating Procedures. Hence, we urge
the SDT to list such specific operational characteristics as part of this test.
Yes
We agree that two different paths to exclusion should be adopted, one relying upon readily
identifiable characteristics that are ordinarily associated with local distribution and not BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element
or group of Elements has a measurable impact on the threat of cascading outages, separation events,
or instability on the interconnected bulk system. If technical analysis demonstrates that Elements
create no material threat of such reliability events, they should properly be excluded from the BES.
Snohomish PUD has prepared a White Paper proposing a performance-based approach to support the
technical determination whether Elements should be excluded from the BES, which are attached to
their comments and we recommend to the SDT for study. We also commend the work of the WECC
BES Task Force and the WECC Technical Studies Subcommittee, both of which have devoted
substantial time and resources to developing a workable and technically defensible process for
excluding Elements classified as BES based upon their electrical characteristics. See WECC BES Task
Force Proposal 6, App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in
Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES Task
Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection. Based on the significant differences
between the four major interconnections in North America, Central Lincoln suggests that a detailed
technical exemption process be allowed on an interconnections wide basis. The Western
Interconnection is a “hub and spoke system” where loads are very remote from large generation

plants, with margins that are based on stability limits. By contrast, the Eastern Interconnection is a
tightly meshed system with loads and generation in close proximity, often creating margins that are
based on thermal limitations. These differences manifest themselves in a variety of operations. For
example, the Western Interconnection uses a rated paths methodology while the Eastern
Interconnection uses transmission load relief mechanisms. Consistent with FERC order 743-A Central
Lincoln supports exemption criteria for individual frequency independent regions, or interconnections.
Fault induced transient voltage measurements will always be low if taken at a point electrically close
to the fault during the fault. The question should be about voltage recovery following the clearing of
the fault as in the TPL standards. The Technical Principles do not make this distinction, and the
resulting effect would be the exclusion of elements that should be included and the inclusion of
elements that should be excluded.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid showing that the Elements contribute substantially to the
potential for cascading outages, separation events, or instability on the interconnection bulk
transmission system. We also agree that the SDT has, in general, identified the correct technical
approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion
analysis) be modified as discussed in the Snohomish PUD White Paper, in the WECC BES Task Force
Proposal 6, and in our answer to Question 5. While we support the SDT’s overall approach, we believe
subsection (f) of the proposed inclusion criteria, which would allow NERC to “override this criterion” if
it provides “additional justification” for doing so is both unnecessary and creates confusion and
uncertainty in what is otherwise a clear and concise process. Subsection (f) is unnecessary because if
the technical process laid out in subsections (a) through (e) fails to provide any evidence that the
contested Element(s) create a material impact on the reliability of the bulk interconnected
transmission network, there is no reason to classify those Element(s) as BES, and that should be the
end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but
there is no suggestion as to what this additional justification might be. Nor is there any explanation as
to why additional justification might be necessary after the criteria in subsections (a) through (e)
have been exhausted.
Please see 5b.
Please see 5c.
Please see 5d.
Please see 5e.
No
As discussed on page 12 of the Snohomish PUD White Paper, there may be a few isolated cases
where additional data will need to be provided to run a valid technical analysis under the criteria set
forth in the Exception Procedure. These cases should be exceedingly rare, however, because the
starting point for the technical analysis we recommend is the current base case operated by the
relevant RE, and in nearly every case, the base case can be expected to model any Element that
conceivably has a material impact on the reliable operation of the bulk system. In those rare cases
where it does not, we believe the owner or operator of the subject Element should be able to provide
the needed data, although we propose that the relevant owner or operator be relieved of this burden
if it can be demonstrated that the nearest electrically interconnected Element has no material impact
on the bulk system.
No
As we explained in our response to Question 1 of the Comment Form on the 1st Draft of Definition of
BES, filed on May 27, Central Lincoln believes that the proposed BES Definition could conflict with

Section 215 of the Federal Power Act if the Definition, the Exception Process, and the Technical
Criteria do not effectively exclude facilities used in local distribution from the BES or if the BES
definition does not focus on cascading outages, separation events, and instability on the
interconnected bulk system. These statutory limits on the scope of the BES and reliability standards
are a minimum that must be met.
Yes
Central Lincoln generally supports the approach to the exclusion process proposed by the SDT, which
provides two different paths to exclusion, one based on readily-identifiable operational characteristics
of a system, and one based on technical reliability analysis. We believe it is important to provide for
the first path, based on operational characteristics, so that systems that are marginally disqualified
under the BES Definition (because, for example, generation within the system exceeds demand for a
few hours a year) can obtain an exclusion without the large investment of resources that otherwise
might be required for a full-scale technical analysis. That being said, we question whether the first
subsection of the characteristic test, relating to system proximity, is necessary, and we are concerned
that the requirement that a system meet all four requirements of the characteristics test may be
overly restrictive. For example, it is easy to imagine a distribution system in a rural area that covers a
widely dispersed area, so that load is many miles from the relevant generation/transmission source,
and that the system therefore does not meet the electrical proximity element, but meets the other
three elements of the characteristics test. Such a system should be excluded because it clearly serves
a local distribution function, and not a transmission function, as demonstrated by the fact that the
system meets subsections (c) (power flows into the system but rarely flows out ) and (d) (power is
not intentionally transported over the system). Accordingly, we recommend that the SDT consider
eliminating the first test. In the alternative, the SDT should consider allowing exempting a system
from the BES if it, for example, meets three of the four criteria rather than all four.
Group
New York State Reliability Council
Roger Clayton
No
NERC’s Glossary definition of Load is “An end-use device or customer that receives power from the
electric system.” which is not specific enough to permit the definition of an appropriate impedance
value. It is not clear from the proposed wording whether the exception applies to the Loads or the
electrically close System Elements or both. In any case, the concept of a single impedance value as a
metric is flawed because it could be a low impedance breaker or a relatively high impedance
transformer connecting the BES to a “radial” Load center. This exclusion is superfluous given the
radial test in item 2. Suggest dropping this exclusion test. N.B. The proposed criteria in items 1 – 4
must all be met in order for an element to qualify for an exclusion.
Yes
It should be clarified that radial Element(s) include all system elements in load pockets.
Yes
It should be clarified that this exclusion should not apply to inter-regional transfers, which clearly are
candidates for inclusion as BES.
Yes
Yes
A single threshold value for performance based testing does not recognize differences in regional
system characteristics. Therefore, regional approaches for at least generation exclusions should be
used, like NPCC's A-10 criterion.

Yes
See answer to 5a.

Yes
See answer to 5a.

No
NPCC A-10 criteria data is freely available.
No
Group
Electricity Consumers Resource Council (ELCON)
John P. Hughes
Yes
We recommend that this item be added to the BES definition.
Yes
We recommend that that the item be added to the BES definition.
Yes
The thresholds for power flows out of the system should be made consistent with Exclusion E2 in the
definition. We recommend that this item be added to the BES definition.
Yes
This requirement should be further relaxed to allow for intentional flows that are provided as a
courtesy to the local distribution company. In such cases, private, customer-owned facilities may be
used to deliver power from a DP to a small number of the DP's retail customers who are unaffiliated
with the owner/operator of the private network. These flows are generally de minimis. We also
recommend that this item (with our qualification) be added to the BES definition.
Yes

Yes
We recommend an additional method (or alternatively this be added to the BES Definition Exception
E1): System Elements are part of facilities, generally radial in nature, supplying a retail customers
from the point of delivery to the load regardless of voltage. Evidence to support this position could be
an interconnection agreement indicating the point of delivery, a one-line diagram showing the point of
delivery and load etc. The technical rationale is that protection of the BES for facilities serving load is
the responsibility of the service provider (e.g., TO/TOP). These facilities are distribution facilities and
are not now part of the BPS.

Yes
NERC (and the BES SDT) should not assume that data pursuant to Large Generator Interconnection
Agreements (LGIA) or the Large Generator Interconnection Procedures (LGIP) will be forthcoming on
a timely basis for the purpose of demonstrating BES exceptions. While such information is generally
available from ISOs and RTOs, it is not so forthcoming from vertically-integrated utilities in regions of
the country not served by ISOs or RTOs because such utilities are generally hostile to third-party

generation in their service territory. They are capable of delaying or otherwise obstructing requests
for data and information. We recommend that NERC or the SDT identify mechanisms for requesting
and getting the necessary data and information. This process should be included in the NERC Rules of
Procedure.
Yes
The proposed technical principles violate the exemption in FPA section 215 against the inclusion in the
BES of facilities used in the local distribution of electric energy, given that the BES is a subset of the
BPS.
Yes
The bright-line tests used in the revised BES definition and technical principles may capture the
facilities of hundreds of entities that may not know that NERC exists or the enforceability of NERC
Reliability Standards. The technical principles should be supplemented with a technical guide or
appendix that provides examples of the steps that may be necessary to demonstrate BES exceptions.
Individual
Darryl Curtis
Oncor Electric Delivery
Yes
Oncor Electric Delivery agrees with the proposed language as it is stated, related to load proximity.
Yes
Oncor Electric Delivery agrees with the proposed language that describes the exclusion criteria for
system Elements that are radial in character.
Yes
Oncor Electric Delivery agrees with the proposed language that describes the exclusion criteria based
upon power flows.
Yes
Oncor Electric Delivery agrees with the proposed language that describes the exclusion criteria based
upon the non – intentional flow of power through the system to some other system.
Yes
Oncor Electric Delivery agrees with the proposed language that describes the exclusion criteria based
technical analysis.

No
Yes
Oncor Electric Delivery agrees with the proposed language that describes the inclusion criteria based
technical analysis.

No
No
No
Although Oncor Electric Delivery understands the need for the ERO to be in a position to override the
inclusion criterion, Oncor desires more clarity on what factors contribute to an overriding action.
Individual

Jerome Murray
Oregon Public Utility Commission Staff
Yes
Use of the 100 kV brightline and the core BES definition as proposed is an overreach into local
distribution systems and an overreach of FERC’s authority as set out in the FPA 215. A full
engineering technical analysis - required every 2 years - is too onerous and not necessary for
identifying most local distribution elements miss-identified as BES Elements. A simple screening
methodology consistent with the 7-Factor Test (from FERC Order 888) is needed as the first stage
the exception process.
Yes
Use of the 100 kV brightline and the core BES definition as proposed is an overreach into local
distribution systems and an overreach of FERC’s authority as set out in the FPA 215. A full
engineering technical analysis - required every 2 years - is too onerous and not necessary for
identifying most local distribution elements miss-identified as BES Elements. A simple screening
methodology consistent with the 7-Factor Test (from FERC Order 888) is needed as the first stage
the exception process.
Yes
Use of the 100 kV brightline and the core BES definition as proposed is an overreach into local
distribution systems and an overreach of FERC’s authority as set out in the FPA 215. A full
engineering technical analysis - required every 2 years - is too onerous and not necessary for
identifying most local distribution elements miss-identified as BES Elements. A simple screening
methodology consistent with the 7-Factor Test (from FERC Order 888) is needed as the first stage
the exception process.
Yes
Use of the 100 kV brightline and the core BES definition as proposed is an overreach into local
distribution systems and an overreach of FERC’s authority as set out in the FPA 215. A full
engineering technical analysis - required every 2 years - is too onerous and not necessary for
identifying most local distribution elements miss-identified as BES Elements. A simple screening
methodology consistent with the 7-Factor Test (from FERC Order 888) is needed as the first stage
the exception process.

of

of

of

of

Individual
Anthony Schacher
Salem Electric
No
We believe that the proximity test may be unnecessary, and if an Element or group of Elements
meets the other three tests proposed by the SDT, it should be excluded from the BES, even if it does
not meet the proximity test. Secondly, using impedance to benchmark system load proximity would
likely not yield clear demarcations. High voltage relative or per-unit impedances are considered

typically much lower than low voltage impedances. Hence, in the absence of phase shifting
transformers, service compensation, or other mitigation factors, power typically flows over the
highest voltage lines, which offer the lowest impedance.
Yes
Salem Electric agrees conceptually that systems operating as radials rather than as integrated
portions of the integrated bulk transmission system should be excluded from the BES definition. That
is because local distribution systems typically operate adjacent to, or at the end of transmission lines,
and function operationally to move power from the Transmission Service Provider’s point of delivery
of bulk power that has moved across the integrated bulk transmission system to end-users located
within the local distribution utility’s service territory. To be consistent with the draft BES definition,
the term “radial in character” should be explicitly defined as a system that may include one or more
lines into a load area or referenced as a local distribution network. In addition, we agree that the
manner in which a system is operated during BES disturbances may be an indication of whether that
system is radial in character. That being said, we are concerned that, to the extent the SDT considers
regional disconnect procedures, it should be careful to note that UFLS and UVLS relays are often
embedded within local distribution systems and, while it is necessary for the UFLS and UVLS relays to
be properly armed to protect the BES in the event of a severe system disturbance, the local
distribution system interconnected with those relays should not.
Yes
Salem Electric agrees conceptually that one critical characteristic distinguishing local distribution
facilities that must be excluded from the BES from transmission facilities that should be included is
the manner in which power flows on those facilities. Power on local distribution systems generally
flows only from the interconnected transmission source and across the distribution system for delivery
to end-use customers. By contrast, power on transmission systems generally flows in two (or
multiple, in networked systems) directions and is delivered in bulk to distribution utilities rather than
to end-users. Hence, the SDT has properly identified power flows as one important characteristic that
distinguishes BES transmission systems from local distribution systems. In order to identify systems
that are not necessary for the operation of the BES under this text, we propose that any system
where real power flows into the local distribution system 90 percent of the time or more under normal
operating conditions.
Yes
Salem Electric agrees that the SDT’s fourth test, which asks whether power is intentionally
transported through a system, identifies a key characteristic of local distribution facilities that
distinguishes such facilities from interconnect bulk transmission facilities that are properly considered
part of the BES. In fact, we believe this may be the most important and readily identifiable distinction.
Accordingly, Salem Electric agrees that if power is not intentionally transported through a particular
system, that system is not used for transmission and should not be considered part of the BES. One
exception may be for a small embedded generation unit owned by a different party that may be
“scheduled” out of an area, but in reality, does not produce any physical flow. These circumstances
should not trigger inclusion.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with local distribution
and not BES transmission facilities, and one relying on technical analysis to determine whether or not
an Element or group of Elements has a measurable impact on the threat of cascading outages,
separation events, or instability on the interconnected bulk system. If technical analysis demonstrates
that Elements create no material threat of such reliability events, they should properly be excluded
from the BES. Salem Electric supports the technical arguments and the White Paper presented by
Snohomish County PUD in their comments. We recommend that the SDT modify its approach to the
technical exclusion process to match the approach advocated in the White Paper, which is based upon
the approach recommended by the WECC BES Task Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the

approach is unlikely to work in the Western Interconnection.
Specific transient voltage dip thresholds are proposed at page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid showing that the Elements contribute substantially to the
potential for cascading outages, separation events, or instability on the interconnection bulk
transmission system. We also agree that the SDT has, in general, identified the correct technical
approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion
analysis) be modified as discussed in the Snohomish PUD White Paper, in the WECC BES Task Force
Proposal 6, and in our answer to Question 5.
See exclusion comment
See exclusion comment
See exclusion comment
See exclusion comment
No
As discussed on page 12 of the Snohomish White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant
Regional Entity, and in nearly every case, the base case can be expected to model any Element that
conceivably has a material impact on the reliable operation of the bulk system. In those rare cases
where it does not, we believe the owner or operator of the subject Element should be able to provide
the needed data.
No
As properly constructed Definition and Exceptions process should meet the legal requirements of
Section 215.
Yes
Salem Electric generally supports the approach to the exclusion process proposed by the SDT, which
provides two different paths to exclusion, one based on readily-identifiable operational characteristics
of a system, and one based on technical reliability analysis. We believe it is important to provide for
the first path, based on operational characteristics, so that systems that are marginally disqualified
under the BES Definition (because, for example, generation within the system exceeds demand for a
few hours a year) can obtain an exclusion without the large investment of resources that otherwise
might be required for a full-scale technical analysis. That being said, we question whether the first
subsection of the characteristic test, relating to system proximity, is necessary, and we are concerned
that the requirement that a system meet all four requirements of the characteristics test may be
overly restrictive. For example, it is easy to imagine a distribution system in a rural area that covers a
widely dispersed area, so that load is many miles from the relevant generation/transmission source,
and that the system therefore does not meet the electrical proximity element, but meets the other
three elements of the characteristics test. Such a system should be excluded because it clearly serves
a local distribution function, and not a transmission function, as demonstrated by the fact that the
system meets subsections (c) (power flows into the system but rarely flows out ) and (d) (power is
not intentionally transported over the system). Accordingly, we recommend that the SDT consider

eliminating the first test. In the alternative, the SDT should consider allowing exempting a system
from the BES if it, for example, meets three of the four criteria rather than all four.
Group
Edison Electric Institute
Mark Gray
No
We do not believe that a meaningful “not to exceed” impedance value can be proffered which would
be appropriately useful across all regions. EEI recommends that Exclusion benchmarks should directly
correlate to the BES definition exclusions as written. Although the “4 Item” approach was obviously
intended to provide a simple approach, the outcome suggested in the draft was less than satisfactory
and we submit it does not hold true to the exclusions provided by the Drafting Committee in their
proposed BES Definition. (see additional comments provided at the end of the Comment form)
Yes
The verbiage used in the BES Principles document does not closely match the verbiage used in the
NERC Bright-line Exclusion. For that reason, we submit the following alternative language. System
Elements and Facilities treated in total as a radial system shall have the following characteristics: 1.
Shall be separated from the BES with an Automatic Interrupting Device, AND 2. Only load serving and
must be isolated from other radial systems through a normally open switching device, OR 3. Only
include generation resources but cannot include any of the Inclusions (i.e., I2, I3, I4 and I5)
identified in the BES Definition, OR 4. Is a combination of Load and Generation but cannot include any
of the Inclusions (i.e., I2, I3, I4 and I5) identified in the BES Definition Evidences to be supplied shall
include: • One-line Diagram clearly showing all demarcations between BES Facilities and the Radial
System (including the Automatic Interrupting Device, AND • Operating procedures or interconnection
agreements that indicate Generating Units contained within the Radial System are not dispatchable (if
applicable), AND/OR • Operating procedures that show that the Radial System is not operated as part
of the BES
Yes
Although EEI agrees in principle to the exclusion, we feel the current language has some problems
which need to be addresses. Note the following: The word “rarely should be struck. It is meaningless
in the context for which it is used and offers little to characterize an element or connection since it
does not contain a measure. A more appropriate statement to broadly characterize a Non-BES
element or connection would be the following: “Power flows are broadly characterized as Load
Serving.” Items i. and iii. are excessive requirements which do not aide in defining what is “necessary
for operating an interconnected electric transmission network”. What might be more a more useful
measure is a comparison of total MW hours of load consumed vs. MW hours fed back into the BES as
measured on an annual basis. Item v. – Hourly energy data (MWh) for the most recent 12 month
period for every excluded BES element is an excessive requirement. Annual records indicating that
MW hours consumed annually verses MW hours that flow through the non-BES element would be a
better indicator in line with the definition.
Yes
A radial system by definition transports power from the BES System to a Distribution System,
similarly an LDN operates in a like manner. A strict reading of the above criteria would exclude both
from consideration yet the definition allows both. We believe that in an attempt to develop a set of
criteria useful for all situations, the outcome has weakened the original intent as set in the Definition.
Although much of the criteria used is largely appropriate, a stricter adherence to the BES definition
criteria would substantially help to avoid confusion between what was developed as principles and
what was developed as the BES Definition.
Yes
In general, we agree that an alternative path allowing a technical analysis to demonstrate that a
Facility (or Element) should not be considered part of the BES is appropriate. However, we disagree
with the measures offered and suggest an alignment with efforts already being developed within
NERC’s Event Analysis Working Group. EEI proposes that the technical analysis criterion which has
been proposed is too complicated, inconsistent with what is currently being done across the regions
and submits that a better approach would be to align reliability impacts with the Event Analysis
Criteria being developed by NERC’s EAWG. These criteria would be a better benchmark as to whether

a Facility or Element should be excluded from the BES. The proposed alternate criteria are as follows:
(1) The loss of the Facility (or Element) would not interfere or negatively impact the BES from staying
within acceptable limits (i.e., frequency, voltage and System Operating limits) following a fault on or
loss of that Facility (or Element); (2) The loss of the Facility (or Element) would not interfere or
negatively impact the BES from performing acceptably after credible contingences; (3) Facility (or
Element) faults, failures, or trips do not push the system to a point of Instability or otherwise initiate
cascading outages; (4) BES facilities are protected from unacceptable damage by operating the
Facility (or Element) within its ratings; and (5) The unexpected loss of the Facility (or Element) does
not negatively impact the BES from achieving its mission of to supply the aggregate electric power
and energy requirements of its customers.
In general, we do not agree this is a relevant factor for consideration and should be excluded.
Presently no regional standards exist for allowable transient voltage dip beyond WECC. It is also
doubtful a useful standard could be developed for all regions or interconnections.
Presently no regional standards exist for allowable transient frequency response beyond WECC. It is
also doubtful a useful standard could be developed for all regions or interconnections.
Presently no regional standards exist for allowable voltage deviation beyond WECC. It is also doubtful
a useful standard could be developed for all regions or interconnections.
No
None beyond what was offered under question 5
Yes
See comments for Question 5 above
See comments for Question 5 above
See comments for Question 5 above
See comments for Question 5 above
See comments for Question 5 above
Yes
Method 2 is largely based on System Planning Criteria developed by WECC. At the present time, we
do not believe that any of the other regions have similar planning criteria for which they could use or
could easily integrate similar criteria into useable Planning Standards which could be applied in useful
manner across all regions. For this reason, it is recommended that a separate Design Committee be
created which would include representatives from all regions. It is expected that this effort may be
substantial but is necessary before Method 2 or the Inclusion Process as written could be used. We
would further caution the use or imposition of such a process since some transmission owners may
not have the necessary skills or tools required to conduct studies of this type (in-house) and imposing
this level of evidence will likely cause many who cannot meet this requirement to include unnecessary
elements diluting the BES as defined and negating the value of the exclusion process.
Yes
EEI is concerned that under the technical principles, some facilities that are local distribution facilities
may be included the BES. This is in conflict with the definition of the Bulk Power System in Section
215 which excludes facilities used in local distribution. In particular, EEI is concerned that the
provision of the technical principles prohibiting the seeking an Exclusion for a cranking path will
include local distribution within the definition of BES.
Yes
We are concerned that the method used to characterize exclusions in Method 1 did not follow the
proposed BES Definition and believe the process developed for Method 2 (and reused for Sub-100kV
Inclusions) is overly complicated, lacks necessary regional standards to support the process and may
prove too difficult for some companies to fully comply with thereby discouraging a consistent and
uniform application of the definition across all regions and affected BES element owners. In the
proposed (BES) definition and accompanying Inclusions and Exclusions, the Drafting Committee went
to some effort to clearly and methodically define what was included and what was permissible to
exclude. Unfortunately the NERC proposed “Technical Principles for Demonstrating BES Exceptions”
did not follow that same clear and concise manner adding some confusion which could lead to
inconsistent application of the Exclusion (and Inclusion) Criteria. For example, at no point did the
“Principles” ever identify Inclusions I2 through I5 which were liberally used in the exclusion criteria

within the BES definition. Additionally within the body of the Proposed BES definition, there are three
(3) approved Exclusions (E1 – Radial System; E2 – Small Customer Generator/Generation System
and E3 – Local Distribution Networks). Each of the Exclusions have its own set of criteria used to
define and characterize the methodology necessary to meet each exclusion, however, the “Principles”
contained in this document only loosely follow the criteria provided and in some cases miss that
criteria all together. We refer the SDT to the EEI comments previously submitted on the BES
Definition regarding the relationship of the BES definition to the statutory exclusion of local
distribution facilites.
Group
Florida Municipal Power Agency
Frank Gaffney
No
Impedance is a function of a line’s length; it does not measure whether a line serves a BES function.
A very long line can exist only to serve load, and a short line in an urban area (where the load is
physically close to the grid) could be needed for transmission but would have low impedance. This
proposed metric is thus both over- and under-inclusive, and should be discarded. Transfer distribution
factor is a more appropriate metric, as described in FMPA’ response to Question 4. FMPA supports
having two paths for exclusions, one that includes extensive technical analysis and another that does
not. The path with less technical analysis is appropriate for Elements that a relatively high-level
examination shows to be not relevant to the reliability of the grid. This opportunity should be
available in the context of exclusions to reduce the burden on small entities. Reliability will not be
impaired by this option; all exception requests will be reviewed by NERC, and in any case where NERC
is less than certain that an exception is appropriate, NERC can perform any or all of the analyses that
would be required for a more technical exclusion or inclusion, and a positive result on any one of the
analyses would be sufficient justification to deny the exclusion request.
We believe that this criterion is intended, like those in 1(a) and (d), to determine whether an Element
is planned and operated to function as part of the interconnected grid. It is, however, too vague to be
useful and should be discarded.
The third item is “power flows into the system, but rarely flows out.” This criterion is vague. FMPA
suggests instead the following language, which is consistent with FMPA’ comments on Exclusion E3 of
the BES definition: “Neither the Element, nor any Elements that it connects to the grid (in aggregate),
includes more than 75 MVA of generation used to meet the resource-adequacy requirements of
electric utilities.”
Yes
FMPA supports the criterion in concept, but “intention[]” is a vague term and not relevant to an
Element’s impact on the grid. We suggest instead that to obtain an exclusion for such a quasi-radial
Element, the owner be required to demonstrate that the Element has no more than a 5% transfer
distribution factor on any BES Element for transfers that could be curtailed through the NAESB TLR
procedure (e.g., interchange transactions, or generator to load distribution factors (GLDF) for BES
generators). Transfer distribution factor (or GLDF) is a good measure of an Element’s impact on the
grid and is not subject to varying interpretations. In addition, NAESB standards are also approved by
FERC and mandatory to jurisdictional entities. Hence, the 5% TDF “Curtailment Threshold” has
already been approved by FERC as indicating an insufficient impact on the BES to be considered for
TLR. And, it shows consistency between NERC and NEASB standards.
Yes
FMPA supports including specific technical criteria that Elements must meet to obtain an exclusion
through the exception process. This approach will facilitate uniform application of the exception
process. FMPA responds to the first five proposed criteria in response to 5b-5e below. In the sixth
proposed criterion, “steady state stability” is ambiguous, does the SDT mean voltage stability, power
angle curve stability, or small signal stability? The seventh proposed criterion, “No cascading
outages,” is insufficiently granular and should be discarded. The criteria are intended to measure
whether, among other things, a particular Element can cause a cascading outage. They need to set
out how decision-makers will determine whether an Element can cause a cascading outage, not
simply state that an Element that can cause a cascading outage cannot be excluded from the BES.
The first proposed criterion, “Having a distribution factor of 5% for any other Element,” should instead
be “Having a distribution factor of 5% for Interchange Transactions or BES generator to load

curtailable in Transmission Loading Relief stages one through five.”
The second criterion, “Allowable transient voltage dip – criteria TBD,” should specify where the
transient voltage dip is, i.e. “Allowable transient voltage dip on another BES Element for events on
the Element that is a candidate of the Exception Request—criteria TBD.”
The third proposed criterion, “Allowable transient frequency excursion – criteria TBD,” should be
rephrased like the second: “Allowable transient frequency excursion on another BES Element for
events on the Element that is a candidate of the Exception Request – criteria TBD.”
The fourth proposed criterion should be revised in the same way as the second and third: “Voltage
deviation on another BES Element for events on the Element that is a candidate of the Exception
Request – criteria TBD.” The fifth proposed criterion should be similarly revised: “Transient Stability
on another BES Element for events on the Element that is a candidate of the Exception Request –
positively damped.”
Yes
TAPS proposes a simpler set of exclusion exception criteria: 1. Having a distribution factor of 5% for
curtailable Interchange Transactions or BES generator – load identified in Transmission Loading Relief
stages one through five, and 2. Category B and C contingencies on the Element that is the subject of
the Exception Request meet the TPL-002 criteria for other BES Elements. (With the new TPL-001-3
standard recently approved by ballot, Category P0 through P7 contingencies on the Element that is
subject of the Exception Request meets the criteria of P0 through P3 for other BES Elements) 3. The
Element that is the subject of the Exception Request is not: (1) part of an IROL, (ii) part of a
blackstart or cranking path used in a TOP’s restoration plan, and (iii) is not used in NUC-001 to
provide service to a nuclear plant. TAPS believes these three criteria meet the intent of all of the
criteria presented by the SDT.
FMPA supports using a uniform set of technical criteria to decide inclusion exceptions. Such an
approach will facilitate uniform application of the criteria. In addition to having clear and uniform
criteria, the technical analysis for inclusions and exclusions should use the same criteria (though one
should of course be the inverse of the other). We note that the steps laid out for Inclusions do not
quite track those in Exclusions 2(a). For example, Inclusions 1(b) states, confusingly, “Monitor the
contribution of the disputed Element(s),” but there is no corresponding step in Exclusions 2(a). FMPA
suggests that Inclusions 1 be revised to mirror Exclusions 2.
See FMPA comments in response to Question 5.
See FMPA comments in response to Question 5.
See FMPA comments in response to Question 5.
See FMPA comments in response to Question 5.

Yes
The third paragraph of the introduction to the Technical Principles is awkwardly worded and might be
misconstrued. FMPA suggests the following rewording: “Entities are not required to seek exceptions
under the Exception Procedure to exclude from the BES Element(s) that are already excluded under
the BES definition and designations.” For the sake of consistency, Exclusions (1) should contain a
provision analogous to Exclusions (2)(b) and Inclusions (1)(f) addressing the circumstances under
which the ERO can override a demonstration based on these criteria. As noted above, one of those
circumstances would be a demonstration by NERC that the Element in question meets the criteria for
inclusion in the BES.
Individual
Laura Lee
Duke Energy
No
Duke Energy does not agree that this characteristic materially demonstrates that an Element is not
necessary for operating an interconnected electric transmission network. There is no correlation
between the electrical proximity of an element to load and its necessity for operating an
interconnected transmission network. In general, the path that does not include extensive technical
analysis is not adequate to distinguish between the Elements that are and that are not necessary for

said operation.
No
This second characteristic does not add clarity to the E1 Exclusion in the proposed BES definition. And
in general, the path that does not include extensive technical analysis is not adequate to distinguish
between the Elements that are and that are not necessary for operating an interconnected electric
transmission network.
No
This third characteristic does not add clarity to the E3 Exclusion in the proposed BES definition. And in
general, the path that does not include extensive technical analysis is not adequate to distinguish
between the Elements that are and that are not necessary for operating an interconnected electric
transmission network.
No
This fourth characteristic does not add clarity to the E3 Exclusion in the proposed BES definition. And
in general, the path that does not include extensive technical analysis is not adequate to distinguish
between the Elements that are and that are not necessary for operating an interconnected electric
transmission network.
Yes
Duke Energy agrees with the approach of using a technical analysis based on transmission system
modeling but the specific criteria do not need to be specified here – they should be consistent with
the latest revision of the TPL-001. R5 of TPL-001-2, Transmission System Planning Performance
Requirements states that each Transmission Planner and Planning Coordinator shall have criteria for
acceptable System steady state voltage limits, post-Contingency voltage deviations, and the transient
voltage response for its System. The technical analysis required for exclusion of an Element from the
BES should evaluate the loss of the Element against a more conservative set of criteria than that
specified by the Transmission Planner and Planning Coordinator responsible for that Element. There
are currently no continent-wide performance levels defined for these evaluations, and there is no
technical basis for developing performance levels that would be applicable continent wide.
This should be removed – there is no correlation between distribution factor and whether or not an
element is necessary for reliable operation of the interconnected transmission network.
See general comment on approach.
See general comment on approach.
See general comment on approach.
No
Yes
The approach and evaluation values should be consistent with those for the Exclusions.

No
No
No
Individual
Bill Dearing
Grant County PUD No. 2 (Grant)
No
We believe that the proximity test may be unnecessary, and if an Element or group of Elements
meets the other three tests proposed by the SDT, it should be excluded from the BES, even if it does

not meet the proximity test. Secondly, using impedance to benchmark system load proximity would
likely not yield clear demarcations. High voltage relative or per-unit impedances are considered
typically much lower than low voltage impedances. Hence, in the absence of phase shifting
transformers, service compensation, or other mitigation factors, power typically flows over the
highest voltage lines, which offer the lowest impedance.
Yes
Grant agrees conceptually that systems operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. That is because local
distribution systems typically operate adjacent to, or at the end of transmission lines, and function
operationally to move power from the Transmission Service Provider’s point of delivery of bulk power
that has moved across the integrated bulk transmission system to end-users located within the local
distribution utility’s service territory. To be consistent with the draft BES definition, the term “radial in
character” should be explicitly defined as a system that may include one or more lines into a load
area or referenced as a local distribution network. In addition, we agree that the manner in which a
system is operated during BES disturbances may be an indication of whether that system is radial in
character. That being said, we are concerned that, to the extent the SDT considers regional
disconnect procedures, it should be careful to note that UFLS and UVLS relays are often embedded
within local distribution systems and, while it is necessary for the UFLS and UVLS relays to be
properly armed to protect the BES in the event of a severe system disturbance, the local distribution
system interconnected with those relays should not.
Yes
Grant agrees conceptually that one critical characteristic distinguishing local distribution facilities that
must be excluded from the BES from transmission facilities that should be included is the manner in
which power flows on those facilities. Power on local distribution systems generally flows only from
the interconnected transmission source and across the distribution system for delivery to end-use
customers. By contrast, power on transmission systems generally flows in two (or multiple, in
networked systems) directions and is delivered in bulk to distribution utilities rather than to endusers. Hence, the SDT has properly identified power flows as one important characteristic that
distinguishes BES transmission systems from local distribution systems. In order to identify systems
that are not necessary for the operation of the BES under this text, we propose that any system
where real power flows into the local distribution system 90 percent of the time or more under normal
operating conditions.
Yes
Grant agrees that the SDT’s fourth test, which asks whether power is intentionally transported
through a system, identifies a key characteristic of local distribution facilities that distinguishes such
facilities from interconnect bulk transmission facilities that are properly considered part of the BES. In
fact, we believe this may be the most important and readily identifiable distinction. Accordingly, Grant
agrees that if power is not intentionally transported through a particular system, that system is not
used for transmission and should not be considered part of the BES. One exception may be for a small
embedded generation unit owned by a different party that may be “scheduled” out of an area, but in
reality, does not produce any physical flow. These circumstances should not trigger inclusion.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with local distribution
and not BES transmission facilities, and one relying on technical analysis to determine whether or not
an Element or group of Elements has a measurable impact on the threat of cascading outages,
separation events, or instability on the interconnected bulk system. If technical analysis demonstrates
that Elements create no material threat of such reliability events, they should properly be excluded
from the BES. Grant supports the technical arguments and the White Paper presented by Snohomish
County PUD in their comments. We recommend that the SDT modify its approach to the technical
exclusion process to match the approach advocated in the White Paper, which is based upon the
approach recommended by the WECC BES Task Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand

that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection
Specific transient voltage dip thresholds are proposed at page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
See responsde to 5d
No
No comments
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid showing that the Elements contribute substantially to the
potential for cascading outages, separation events, or instability on the interconnection bulk
transmission system. We also agree that the SDT has, in general, identified the correct technical
approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion
analysis) be modified as discussed in the Snohomish PUD White Paper, in the WECC BES Task Force
Proposal 6, and in our answer to Question 5.
See exclusion comment
See exclusion comment
See exclusion comment
See exclusion comment
No
As discussed on page 12 of the Snohomish White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant
Regional Entity, and in nearly every case, the base case can be expected to model any Element that
conceivably has a material impact on the reliable operation of the bulk system. In those rare cases
where it does not, we believe the owner or operator of the subject Element should be able to provide
the needed data.
No
As properly constructed Definition and Exceptions process should meet the legal requirements of
Section 215.
Yes
Grant generally supports the approach to the exclusion process proposed by the SDT, which provides
two different paths to exclusion, one based on readily-identifiable operational characteristics of a
system, and one based on technical reliability analysis. We believe it is important to provide for the
first path, based on operational characteristics, so that systems that are marginally disqualified under
the BES Definition (because, for example, generation within the system exceeds demand for a few
hours a year) can obtain an exclusion without the large investment of resources that otherwise might
be required for a full-scale technical analysis. That being said, we question whether the first
subsection of the characteristic test, relating to system proximity, is necessary, and we are concerned
that the requirement that a system meet all four requirements of the characteristics test may be
overly restrictive. For example, it is easy to imagine a distribution system in a rural area that covers a
widely dispersed area, so that load is many miles from the relevant generation/transmission source,
and that the system therefore does not meet the electrical proximity element, but meets the other
three elements of the characteristics test. Such a system should be excluded because it clearly serves
a local distribution function, and not a transmission function, as demonstrated by the fact that the
system meets subsections (c) (power flows into the system but rarely flows out ) and (d) (power is

not intentionally transported over the system). Accordingly, we recommend that the SDT consider
eliminating the first test. In the alternative, the SDT should consider allowing exempting a system
from the BES if it, for example, meets three of the four criteria rather than all four.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
No
Close electrical proximity to load does not appear to be an appropriate criteria. There is no reason
that this criteria would prevent exclusion of a radial system with long lines feeding far away loads.
Instead of considering proximity to load, it would be better to consider the way the Element is
connected to the BES and the function of the excluded part of the system, mainly to deserve loads or
integrate some generation, but not to transfer power to another Balancing Authority. Those are
covered by criteria b., c. and d., so we believe that criteria a. should not be maintained.
Yes
However, the point B.i. is hard to understand and would need clarification. Here is a proposal: "For an
Element to be excluded from BES, its should be demonstrated that there are a proper disconnection
procedure when facing a disturbance that would prevent this Element to impact the BES" ?. The point
should be to make sure a fault on the Element will be isolated effectively without adverse impact on
the BES, even when we have a second transmission source for the syb system seeking exclusion.
Also, for point B. ii., it should be explained what is meant by the expression "regional dispatch". Is it
an alternate way of transfer of power outside the Balancing Authority ?
Yes
However, this is only part of an exclusion. The point c. iv and v, MWh is not relevant for real-time
operation. It would be more simple to put a time reference, such as a total number of days or a % of
the time. In number iii, do you mean the first self certification ? In fact, the evidence for exclusion will
be done once, but ROP suppose that the self certification will be done many times (every two years).
Yes
Yes
Comments on distribution factor measurement: The choice of the maximum distribution factor could
be difficult to establish. For this point, the comparison of the distribution factor prior and after the
events could be considered.
Comments on allowable transient voltage dip measurement: The TPL-001 to 004 do not specify any
reference measurement for stability (such as Allowable transient voltage, frequency excursion,
voltage deviation, etc.). Instead, it request that the system shall remain stable, without cascading or
uncontrolled islanding. Also, it is requested that the Planning Entities shall define and document the
criteria or methodology used in the analysis to identify System instability for conditions such as
Cascading, voltage instability, or uncontrolled islanding. This is exactly what should be requested in
the analysis and demonstration of Element seeking exclusion from BES. The analysis and burden of
proof should be left to the Entity as is done in the TPL, considering that there are no common values
with the different interconnection.

Yes
Technical demonstration should not be limited to technical principles stated in the "Technical
Principles for Demonstrating BES Exceptions". Entities should be allowed to do their own
demonstration with their own technical arguments. As an example, an Entity could consider a few
level of application for the standards. As an example, the level #1 being the most important level, all
standards would apply to this level, including more stringent criteria than the TPL standards. This
would bring BES level #1 very robust and reliable, ensuring the reliability of the main system. A
second BES level #2 could be define for local transmission to which would be applied most standards
but excluding some of the C section of TPL. Attention would be given to proper reliable operation of
the BES level #2, but with smaller level of investment on the design aspect, those regional

transmission part of the system being able to face higher risk for loss of continuity of service. Finally,
for generation or Load Facility that would be excluded from both level of BES, minimum standards
would still apply such as in protection or for generation. Through its own technical principles, the
Entity could demonstrate that the highest level of BES is more reliable than what is expected by
NERC's standard, but that in regional transmission part of the system, the C TPL standard would not
apply with the only risk of lower continuity of service.
Yes

No
Yes
However, there is a conflict between the proposed approach and the regulatory framework applicable
in the Quebec's Interconnexion or at least there are some important differences between both.
Paragraph 95 of FERC Order 743 acknowledged the situation of non-FERC juridiction. As for the
Quebec's Interconnexion, the BES definition and exclusion approach shall meet the expectations of
Quebec's regulator, the Régie de l'Énergie du Québec, (Quebec Energy Board) which has the
responsibility to ensure that electric power transmission in Quebec is carried out according to the
reliability standards it adopts. In a recent order (D-2011-068), the Régie de l'Énergie du Québec has
recognized several level of application for the Reliability Standards in Québec. It stated specifically
that most reliability standards in Québec shall be applied to the Main Transmission System (MTS).
One other level of application recognised by this decision is the NPCC Bulk Power System (BPS) to
which the standards related to the protection system (PRC-004-1 and PRC-005-1) and those related
to the design of the transmission system (TPL 001-0 to TPL-004-0) will be applicable (including the
rest of the standards). The Main Transmission System definition is somewhat different than the Bulk
Electric System definition. The Main Transmission System includes elements that impact the reliability
of the grid, supply-demand balance and interchanges. It can be described as follows : The
transmission system comprised of equipments and lines generally carrying large quantities of energy
and of generating facilities of 50 MVA or more controlling reliability parameters: • Generation/load
balancing • Frequency control • Level of operating reserves • Voltage control of the system and tie
lines • Power flows within operating limits • Coordination and monitoring of interchange transactions •
Monitoring of special protection systems • System restoration Therefore, it will be necessary to
accommodate NERC's proposed definition of BES or the exception process with the Quebec situation
where Entities are under a different jurisdiction. These differences include more than one level of
application for the reliability standards, the Main Transmission System definition being the main one
to which most reliability standards apply.
No
Individual
Eric Lee Christensen
for Snohomish County PUD
No
Snohomish agrees in principle that one characteristic of local distribution systems is that they are
usually confined to a relatively limited geographic area, as opposed to transmission systems, which
(especially in the West) tend to cover very large distances. We also believe the proximity test may be
a sensible way to identify local distribution facilities. However, as explained in more detail in our
response to Question 10, we believe that the proximity test may be unnecessary, and if an Element or
group of Elements meets the other three tests proposed by the SDT, it should be excluded from the
BES, even if it does not meet the proximity test. Further, using impedance to benchmark system load
proximity would likely not yield clear demarcations. High voltage relative or per-unit impedances are
considered typically much lower than low voltage impedances. Hence, in the absence of phase shifting

transformers, service compensation, or other mitigation factors, power typically flows over the
highest voltage lines, which offer the lowest impedance.
Yes
Snohomish agrees conceptually that systems operating as radials rather than as integrated portions
of the integrated bulk transmission system should be excluded from the BES definition. That is
because local distribution systems typically operate adjacent to, or at the end of transmission lines,
and function operationally to move power from the Transmission Service Provider’s point of delivery
of bulk power that has moved across the integrated bulk transmission system to end-users located
within the local distribution utility’s service territory. To be consistent with the draft BES definition,
the term “radial in character” should be explicitly defined as a system that may include one or more
lines into a load area or referenced as a local distribution network. In addition, we agree that the
manner in which a system is operated during BES disturbances may be an indication of whether that
system is radial in character. That being said, we are concerned that, to the extent the SDT considers
regional disconnect procedures, it should be careful to note that UFLS and UVLS relays are often
embedded within local distribution systems and, while it is necessary for the UFLS and UVLS relays to
be properly armed to protect the BES in the event of a severe system disturbance, the local
distribution system interconnected with those relays should not, and cannot legally, be classified as
BES.
Yes
Snohomish agrees conceptually that one critical characteristic distinguishing local distribution facilities
that must be excluded from the BES from transmission facilities that should be included is the manner
in which power flows on those facilities. Power on local distribution systems generally flows only from
the interconnected transmission source and across the distribution system for delivery to end-use
customers. By contrast, power on transmission systems generally flows in two (or multiple, in
networked systems) directions and is delivered in bulk to distribution utilities rather than to endusers. Hence, the SDT has properly identified power flows as one important characteristic that
distinguishes BES transmission systems from local distribution systems. Snohomish also agrees
conceptually that the fact that power may flow out of a local distribution system onto the grid during
a few hours in a year or during extreme contingencies should not change the characterization of the
system as local distribution. Accordingly, we support inclusion of power flow analysis as one element
of characteristics that can be used to exclude local distribution facilities from the BES even if the
facilities do not pass each of the bright-line thresholds laid down in the BES definition. We also agree
that transactional and hourly generation records are an appropriate basis for making the
determination since these can be used to demonstrate that demand within a local distribution system
exceeds generation within that system in most hours and that power therefore does not flow onto the
grid, and also to determine the number of hours where this is not the case and the amount by which
generation within the system exceeds demand. In order to identify systems that are not necessary for
the operation of the BES under this test, we propose that any system where real power flows into the
local distribution system 90 percent of the time or more under normal (“N-0” or All Lines in Service)
operating conditions should be held to meet this test. That a system meets this test could be
demonstrated using metering or supervisory control and data acquisition ("SCADA") data records over
the course on two years. In addition, the presence of generation within a local distribution system
that only modifies the level of the load served by the bulk system, but does not result in power being
injection into the bulk system, does not change the reliability effect of the local network and therefore
should not require the local network to be classified as BES.
Yes
Snohomish agrees that the SDT’s fourth test, which asks whether power is intentionally transported
through a system, identifies a key characteristic of local distribution facilities that distinguishes such
facilities from interconnect bulk transmission facilities that are properly considered part of the BES. In
fact, we believe this may be the most important and readily identifiable distinction. As a matter of
operation, power is scheduled across transmission lines. Further, transmission lines in the Western
Interconnection (either individually or as part of a transmission path) are rated for total transmission
capacity and available transmission capacity, and transmission rights can be purchased on such lines,
if available, on an OASIS. Local distribution systems do not share any of these operational
characteristics. Accordingly, Snohomish agrees that if power is not intentionally transported through a
particular system, that system is not used for transmission and should not be considered part of the
BES. We also agree that examining the Operating Procedures applicable to a particular system will

provide a ready guide to whether power is intentionally scheduled across that system. We suggest,
however, that the SDT look beyond those protocols that fall within the NERC Glossary’s definition of
Operating Procedure. For example, in the West, transmission paths are almost all listed in the WECC
Path Rating Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and the
other factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such
specific operational characteristics as part of this test.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with local distribution
and not BES transmission facilities, and one relying on technical analysis to determine whether or not
an Element or group of Elements has a measurable impact on the threat of cascading outages,
separation events, or instability on the interconnected bulk system. If technical analysis demonstrates
that Elements create no material threat of such reliability events, they should properly be excluded
from the BES. Snohomish has prepared a White Paper proposing a performance-based approach to
support the technical determination whether Elements should be excluded from the BES, which we
attach to these comments and commend to the SDT for study. We also commend the work of the
WECC BES Task Force and the WECC Technical Studies Subcommittee, both of which have devoted
substantial time and resources to developing a workable and technically defensible process for
excluding Elements classified as BES based upon their electrical characteristics. See WECC BES Task
Force Proposal 6, App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011) (available at:
http://www.wecc.biz/Standards/Development/BES/default.aspx). We recommend that the SDT
modify its approach to the technical exclusion process to match the approach advocated in our White
Paper, which is based upon the approach recommended by the WECC BES Task Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection, such factors have never been a definitive indicator
of whether a system fault with delayed clearing would impact a neighboring electric system. While we
understand that many entities from the Eastern Interconnection support the use of such factors, we
believe the approach is unlikely to work in the Western Interconnection. Based on the significant
differences between the four major interconnections in North America, Snohomish suggests that a
detailed technical exemption process be allowed on an interconnection- wide basis. The Western
Interconnection is a “hub and spoke system” where loads are very remote from large generation
plants, with margins that are based on stability limits. By contrast, the Eastern Interconnection is a
tightly meshed system with loads and generation in close proximity, often creating margins that are
based on thermal limitations. These differences manifest themselves in a variety of operations. For
example, the Western Interconnection uses a rated paths methodology while the Eastern
Interconnection uses transmission load relief mechanisms. Consistent with FERC Order 743-A,
Snohomish supports exemption criteria for individual frequency independent regions, or
interconnections.
Specific transient voltage dip thresholds are proposed at page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
SNPD supports the exemption of generation interconnected to local distribution networks if the
generation is less than 300 MW capacity and where the power generated is consumed within the LDN
and rarely flows out of the LDN, using the proposed criteria described in our response to question 3.
This proposal is consistent with the section III.c.4 [Exclusion] of the NERC Statement of Compliance
Registry Criteria as well as the Load modifiers used in the Eastern Interconnection. "Load Modifiers"
(small generators that only affect load at the distribution level).”

Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid showing that the Elements contribute substantially to the
potential for cascading outages, separation events, or instability on the interconnection bulk
transmission system. We also agree that the SDT has, in general, identified the correct technical
approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion
analysis) be modified as discussed in our White Paper, in the WECC BES Task Force Proposal 6, and in
our answer to Question 5. While we support the SDT’s overall approach, we believe subsection (f) of
the proposed inclusion criteria, which would allow NERC to “override this criterion” if it provides
“additional justification” for doing so is both unnecessary and creates confusion and uncertainty in
what is otherwise a clear and concise process. Subsection (f) is unnecessary because if the technical
process laid out in subsections (a) through (e) fails to provide any evidence that the contested
Element(s) create a material impact on the reliability of the bulk interconnected transmission
network, there is no reason to classify those Element(s) as BES, and that should be the end of the
question. Subsection (f) creates needless uncertainly because it allows NERC to override the technical
criteria laid out in subsections (a) through (e) if “additional justification” is provided, but there is no
suggestion as to what this additional justification might be. Nor is there any explanation as to why
additional justification might be necessary after the criteria in subsections (a) through (e) have been
exhausted.
Please see our response to Question 5b.
Please see our response to Question 5c.
Please see our response to Question 5d.
Please see our response to Question 5d.
No
As discussed on page 12 of our White Paper, there may be a few isolated cases where additional data
will need to be provided to run a valid technical analysis under the criteria set forth in the Exception
Procedure. These cases should be exceedingly rare, however, because the starting point for the
technical analysis we recommend is the current base case operated by the relevant RE, and in nearly
every case, the base case can be expected to model any Element that conceivably has a material
impact on the reliable operation of the bulk system. In those rare cases where it does not, we believe
the owner or operator of the subject Element should be able to provide the needed data, although we
propose that the relevant owner or operator be relieved of this burden if it can be demonstrated that
the nearest electrically interconnected Element has no material impact on the bulk system.
Yes
As we explained in considerable detail in our response to Question 1 of the Comment Form on the 1st
Draft of Definition of BES, filed on May 27, Snohomish believes that the proposed BES Definition could
conflict with Section 215 of the Federal Power Act if the Definition, the Exception Process, and the
Technical Criteria do not effectively exclude facilities used in local distribution from the BES or if the
BES definition does not focus on cascading outages, separation events, and instability on the
interconnected bulk system. These statutory limits on the scope of the BES and reliability standards
are a minimum that must be met.
Yes
Snohomish County PUD generally supports the approach to the exclusion process proposed by the
SDT, which provides two different paths to exclusion, one based on readily-identifiable operational
characteristics of a system, and one based on technical reliability analysis. We believe it is important
to provide for the first path, based on operational characteristics, so that systems that are marginally
disqualified under the BES Definition (because, for example, generation within the system exceeds
demand for a few hours a year) can obtain an exclusion without the large investment of resources
that otherwise might be required for a full-scale technical analysis. That being said, we question
whether the first subsection of the characteristic test, relating to system proximity, is necessary, and
we are concerned that the requirement that a system meet all four requirements of the characteristics
test may be overly restrictive. For example, it is easy to imagine a distribution system in a rural area
that covers a widely dispersed area, so that load is many miles from the relevant
generation/transmission source, and that the system therefore does not meet the electrical proximity
element, but meets the other three elements of the characteristics test. Such a system should be
excluded because it clearly serves a local distribution function, and not a transmission function, as

demonstrated by the fact that the system meets subsections (c) (power flows into the system but
rarely flows out ) and (d) (power is not intentionally transported over the system). Accordingly, we
recommend that the SDT consider eliminating the first test. In the alternative, the SDT should
consider allowing exempting a system from the BES if it, for example, meets three of the four criteria
rather than all four. We have pasted in the text of our White Paper below. Please contact us for a
more readable version of the White Paper. White Paper A Performance-Based Exemption Process to
Exclude Local Distribution Facilities from the Bulk Electric System April 2011 This White Paper
proposes a transmission planning (“TPL”) “performance-based” process to determine the local
distribution facilities the North American Electric Reliability Corporation (“NERC”) must exclude from
the Bulk Electric System (“BES”) pursuant to Section 215(a)(1) of the Federal Power Act (“FPA”). This
process would apply to those local distribution facilities that are not automatically excluded under a
bright-line BES definition. Consistent with Federal Energy Regulatory Commission (“FERC”) Order Nos.
743 and 743-A, a performance-based exemption process would be objective, consistent, and
transparent, and would adequately differentiate between local distribution and transmission, i.e., BES,
facilities. I. What Is Reliability? FPA Section 215 authorizes NERC to promulgate “reliability
standards,” subject to FERC approval. Section 215 defines “reliability standard” to mean a properlyapproved requirement “to provide for the reliable operation of the bulk-power system.” The statute, in
turn, defines “reliable operation” to mean “operating the elements of the bulk-power system within
equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of sudden disturbances,
including . . . unanticipated failure of system elements.” II. What Is “Customer Service” or “Level of
Service” (“LOS”)? Local customer service or LOS relates to service failures on local utility systems that
are wholly internalized rather than spilling onto the interconnected regional grid. These types of
service failures relate to local customer service and LOS standards. The customers of those utilities
will bear the full cost of complying with internal LOS standards and will obtain the full benefit of
compliance to the extent that service levels on those systems improve. Accordingly, state public
utility commissions (for regulated utilities) and independent boards (for non-regulated utilities) can
fully and accurately weigh whether the benefits of compliance with such standards are justified by the
costs they will pay. Intervention by NERC and a Regional Entity is not needed because a utility’s
actions related to level of service on its own system will neither unduly burden the customers of other
systems, threaten the reliable delivery of power to those customers, nor create incidental benefits to
those remote customers. In the absence of the need to protect customers of systems remote from the
consequences of decisions made by an individual utility, there is no warrant for NERC or a Regional
Entity to interfere with a utility’s internal decision-making about the appropriate LOS to its own
customers, and the costs that will be borne by those customers to achieve any particular level of
service. In fact, in the “Savings Provisions” of Section 215, Congress specifically included language
prohibiting NERC and Regional Entities from enforcing “compliance with standards for adequacy” of
electric service. By law, these remain the exclusive province of local decision-makers. III. The Need
for a Material Impact Test In Order No. 743-A, FERC clarified that a material impact test is
appropriate in the reliability context if the test can be shown to identify facilities needed for reliable
operation. The following example of an outage demonstrates the need for an impact test to
distinguish between LOS and Reliability, i.e., local distribution facilities and BES facilities. A. Pre-Event
Facts Local Utility Administration (“LUA”) owns a 115 kV system that moves power from two points of
delivery (“POD”) and serves 1000 MW of load. A DC battery rack had an unexpected failure a few
days after it was routinely inspected and LUA has not implemented Supervisory Control and Data
Acquisition (“SCADA”) so the DC battery voltage is not continuously monitored. The LUA system
interconnects with BES Company’s system which consists of 230 kV and 500 kV lines. B. Event Facts
A fault occurs and the breakers in substation 2 fail to operate due to a battery failure (Figure 1). This
results in an outage for customers served by substations 1, 2, and 3 on the LUA system. Figure 1 C.
Post-Event Facts Immediately after the outage, LUA customer service receives numerous customer
calls followed by a call from its Public Utility Commission/Local Utility Board (“/PUC/LUB”). LUA
dispatches crews immediately after being informed of the outage to identify and resolve the problem.
Within 45 minutes, the fault is sectionalized and the all load is restored. The PUC/LUB receives
complaints from LUA customers who identify economic and other adverse impacts of the outage. The
PUC/LUB demands a report from the LUA that describes the event and restoration, as well as potential
solutions. LUA submits a report which finds that the main solution to this problem involves the
implementation of a SCADA system. The SCADA system scope of work includes battery voltage
telemetry and would have identified the DC system issue and prevented the protection system failure,

resulting in only the loss of substation 3. The SCADA plan cost estimate is $30 million and was
presented three years earlier. The PUC/LUB evaluated the costs and benefits of the new SCADA
system, but did not approve the project in order to reduce the budget and/or provide rate stability for
the struggling local economy. LUA, the PUC/LUB, and customers will re-evaluate the merits of adding
SCADA as well as other solutions such as increasing substation inspection runs, updating the batter
fleet, and further investigating battery manufacture reliability records. Based on the LUA report, the
battery bank failure rate immediately after routine inspections is expected to occur once every 3,500
years. Seventy battery banks are used on the LUA system, so a bank failure should be expected every
50 years. BES Company’s neighboring 230kV and 500kV system does not experience an adverse
system impact. Subsequently, BES Company identifies that one of its breakers operated at the LUA
South POD. BES Company and LUA coordinate a review of the system protection scheme and BES
Company determines that it operated correctly. BES Company verifies that the LUA outage did not
create any thermal, voltage, or transient stability limit violations on the BES Company system. The
Regional Entity, NERC, and FERC treat the outage as a Reliability Standards issue. The LUA System
(highlighted in yellow) is considered part of the BES because it meets the “bright line” 20 MVA and
100 kV thresholds under the current BES definition and the NERC Statement of Compliance Registry
Criteria (“SCRC”). The event would most likely be considered a TPL-003 category C event specifically
C8 SLG Fault, with delayed clearing that may include a stuck breaker or protection system failure. The
LUA Substation Department reviews its inspection records and has adequate documentation for the
battery banks involved in the outage. As a result, LUA avoids substantial fines. However, during the
inspection review, LUA notices that the battery bank in a similar distribution substation inspection
schedule was completed three days late. Upon following further internal procedures, LUA finds that
the battery bank was inspected three days late due to restorations efforts after a major wind storm.
Although there were no LOS impacts, and the inspection schedule was unrelated to the outage, the
Reliability Standards triggered a LUA self report to its Regional Entity which ultimately resulted in a
$50,000 penalty. D. Summary This example identifies that in addition to a “bright line” BES exclusion
process a more refined process such as a “performance based” reliability assessment is needed to
distinguish BES facilities from distribution facilities if the NERC Statement of Compliance Registry
Criteria (“SCRC”) continues to be the benchmark for assessing BES facilities. It is clear from this
example that the current 100 kV and 20 MVA thresholds cannot accurately classify what is and is not
considered part of the BES. Defining BES facilities is important from the “Reliability Standard” and
“LOS” perspectives as well as from a local and regional jurisdictional standpoint. There are multiple
agencies identifying and approving what facilities should and should not be built, what programs
should and should not be implemented, and if a fine should be paid by customers experiencing an
outage without determining if it could have had an adverse impact on neighboring electric systems.
Without a performance-based process, many small and medium electric utilities would be
unnecessarily burdened.
IV. Neighboring System Rule It is important but not always easy to
distinguish the difference between “reliability” and “LOS” impacts. One way to resolve this is to use
the “neighboring system rule.” Simplistically, if events on the host system’s facilities can create an
“adverse” or “material” impact on a neighboring electric (TO, TOP, BA) system, those facilities should
be considered part of the BES as they are creating a reliability impact. If not, these facilities should
not be considered part of the BES. V. “Adverse” or “Material” Impact A key question in applying the
“neighboring system rule” is what is an “adverse” or “material” impact, and what “performance
based” assessment should be used to benchmark adverse or material. Because the electric system
within an interconnection is frequency interdependent, theoretically every system change impacts the
interconnected system to some degree. Turning on a light-switch that is connected to an operational
20 watt CFL (light bulb) theoretically impacts frequency, although to an undetectable degree.
Therefore the term “material” or “adverse” impacts must be defined to distinguish observable impacts
that affect reliability from minutia. A number of performance based exclusion examples have been
proposed that use, Power Transfer Distribution Factors (“PTDF”), Line Outage Distribution Factors
(“LODF”), fault duty or short circuit levels, reactive margin studies (P-V and Q-V), abbreviated or
focused powerflow and transient stability analysis, as well as complete TPL assessment using multiple
seasonal base cases, loading conditions, transfer levels. These methods demonstrate various metrics,
they rank system strength (both real and reactive), the ability of power to flow through system under
normal and outage conditions, and they determine steady state, voltage stability and transient
(angular) stability performance. Although there may be advantages to a multi-step “performance
based” approach that includes the exclusion examples above, this paper proposes a TPL-based
assessment that is consistent with BES performance benchmarks used in assessing transmission

system performance in North America. The Western Electricity Coordinating Council (“WECC”) BES
Exclusion/Inclusion Assessment – 2-16-11 version provides a sound metrics in assessing the
performance of a system as well as determining if a system can materially impact a neighboring
system (Figure 2). It would be envisioned that each interconnection would develop a “Disturbance
Performance Table of Allocable Effects on Other System”. This table is necessary because the NERC
TPL Performance Table does not provide actual performance details on acceptable transient and post
transient voltage perturbations or minimum transient voltage frequencies. Figure 2 show the
approved TPL-001 through TPL-004 performance tables. Figure 3 - Table 1 from the NERC TPL
Reliability Standards
VI. Performance Based Assessment Process The “performance based”
methodology below is based on the “neighboring system rule” and the WECC BES Exclusion/Inclusion
Assessment – 2-16-11 that was developed by the WECC Bulk Electric System Definition Task Force
(“BESDTF”). The process focuses on exclusions rather than inclusion and specific response times,
schedules, and process details have been removed as this will likely need to be determined by each,
Regional Entity Representing the Interconnection (“RERI”) A. Purpose The purpose of this document is
to set forth a “performance based” technical process for assessing whether elements with a nominal
operating voltage greater than 100 kV and outside the NERC SCRC based excursion process should be
excluded from the Bulk Electric System. An element is necessary to reliably operate an interconnected
transmission system if it significantly affects neighboring Transmission Owners, Operators, and
Balancing Authorities as described in Table 1 below. This paper proposes a method for assessing
whether an element is necessary to support the reliability of an interconnected transmission system
or if the element is limited to supporting local customer service levels. B. Terms Exclusion Assessment
(EA) An assessment of whether a Subject Element or System has a material impact on neighboring
Transmission Owners, Operators, and Balancing Authorities as described in Table 1 below and
conducted in accordance with the process set forth in this document. EA Base Case The
interconnection approved, Base Case as modified to include the Subject Element, used to perform the
assessment described in this document. Regional Entity Representing the Interconnection The
regional entity representing the interconnection Registered Entity The entity registered to comply with
mandatory reliability standards for a Registered Function. Responsible Entity The entity responsible
for performing the EA and verifying the results of the EA to the interconnection. Subject System or
Element of a System The System or Element of a System that is being examined by the EA. C.
Applicability a. An EA may be performed: i. By a registered entity, or by a third party on behalf of a
registered entity, to assess whether a Subject Element or system has a material impact on
neighboring Transmission Owners, Operators, and Balancing Authorities as described in Table 1 may
be excluded from the BES as set forth by the RERI. ii. The RERI, or by a third party on behalf of the
RERI, to assess whether a Subject Element or system has a material impact on neighboring
Transmission Owners, Operators, and Balancing Authorities as described in Table 1 should be included
as part of the BES as set by the RERI. b. Frequency of analysis. The confirmed findings of an EA are
valid until reversed by a subsequent EA. A new EA is required if: i. Significant changes are made to
the network topology in the vicinity of the Subject Element; or ii. RERI staff requests a new EA. Such
request shall be provided in writing and shall include reasonable justification for the request. D.
Notifying the RERI of the Responsible Entity’s intent to submit an EA finding or to perform an EA. The
Responsible Entity shall notify the RERI in writing of its intent to submit such a finding. Such notice
shall include: a. A general description of the Subject Element(s); b. One-line diagrams representing
the Subject Element and applicable neighboring Elements; and c. A description of the base case that
will be used in performing the EA and how that case will be stressed for the analysis. E. Performing
the Analysis Base Case The base case(s) used for the studies shall be developed from current
interconnection Operating Cases and shall simulate stressed conditions in the area of the element to
be analyzed which (1) are reasonably expected to be achieved, consistent with the study period
selected (e.g., hydro generation shall reflect seasonal water availability patterns) and (2) are
expected to provide “worst-case” results (i.e., the greatest impact on voltage, flow, or transfer
capability) during the upcoming operating year. The base case(s) shall be “stressed” by committing or
de-committing generating units and adjusting generating unit output to increase the flow on the
candidate element and the electrically nearest rated interconnection transfer path to the greatest
extent possible, but not beyond their continuous ratings, for the initial set of conditions. To help
minimize the possibility of dispute as to whether the base case(s) are suitably stressed, entities are
encouraged to solicit input from subregional planning groups or other planning entities as the
suitability of the base case(s) before undertaking the analyses described below. i. Non-represented
Elements. If the Subject Element is not represented in the EA Base case: 1. The Responsible Entity

shall provide to the RERI a written request to add the Responsible Entities data to the cases: o all
data reasonably necessary to accurately and completely model the Subject Element in the EA Base
case; and o A one-line diagram showing this element and other nearby Elements. If the nearest
connected Element is not found to be necessary for the operation of an interconnected transmission
system, the RERI shall notify the Responsible Entity to take no further action. F. Performance Based
Methodology The impact an System or Element has on neighboring Transmission Owners, Operators,
and Balancing Authorities as described in Table 1 shall be determined by assessing the performance
of key measures of BES reliability through power flow, post-transient, and transient stability analysis
with (1) the system, and the Subject Element, operating at reasonably stressed conditions that
replicate expected system conditions under which the loss of the Subject Element would have the
greatest impact on the key measures of reliability, and (2) the Subject Element removed from
service, but without allowing for system readjustment. For the purposes of this analysis, “Elements”
may be: (1) lines; (2) transformers; (3) buses or bus sections; (4) generating units; (5) shunt
devices . i. Simulation 1: Requirement: Meet applicable NERC Reliability Standard (TPL-002 and TPL003) and the RERI Disturbance Performance Table of Allocable Effects on Other System” Criteria
performance for NERC TPL-002 and TPL-003 disturbances. Step 1: Run appropriate TPL-002 (N-1
contingency) studies of elements in the electrical vicinity of and including the Candidate Element (i.e.,
simulate primary protection operates as intended) Step 2: Run appropriate TPL-003 (N-2
contingency) studies of elements in the electrical vicinity of and including the Candidate Element. This
would include both N-2 contingencies in which the Candidate Element would simultaneously be lost as
part of a common mode failure, as well as contingencies in which the Candidate Element’s primary
protection fails. Automatic Remedial Action Schemes (“RAS”) or Special Protection Schemes (“SPS”)
that are fully redundant (i.e., their failure is not credible) may be triggered during this simulation. If
the failure of the RAS/SPS is a credible event, it should be considered as part of the N-2 analysis. ii.
Simulation 2: Requirement: Remove the Candidate Element. Do not allow for system adjustment, and
re-solve the base case. Then conduct applicable NERC Reliability Standard (TPL-002 and TPL-003)
contingencies. Step 1: Remove Candidate Element (i.e., simulate unplanned opening of facility). Step
2: Assume no system adjustment. At this point, elements may be loaded above their continuous
ratings but may not be loaded above their emergency ratings. Step 3: Perform NERC TPL-002 and
TPL-003 (N-1 and N-2 contingency) studies. Step 4: If the analysis demonstrates performance that
meets or exceeds that called for in the NERC Reliability Standards and RERI System Performance
Criteria, the Candidate Element would be determined to not be necessary for the operation of an
interconnected transmission system. Note: Consequential load tripping is allowed, and consequential
and out-of-step generation tripping is allowed. Criteria Table 1: RERI Disturbance-Performance Table
of Allowable Effects on Other Systems NERC and WECC Categories Outage Frequency Associated with
the Performance Category (outage/year) Transient Voltage Dip Standard Minimum Transient
Frequency Standard Post Transient Voltage Deviation Standard A System normal Not Applicable
Nothing in addition to NERC B One element out-of-service ≥ 0.33 Not to exceed 25% at load busses or
30% at non-load busses. Not to exceed 20% for more than 20 cycles at load busses. Not below
59.6Hz for 6 cycles or more at a load bus. Not to exceed 5% at any bus. C Two or more elements
out-of-service 0.033 – 0.33 Not to exceed 30% at any bus. Not to exceed 20% for more than 40
cycles at load busses. Not below 59.0Hz for 6 cycles or more at a load bus. Not to exceed 10% at any
bus. D Extreme multiple-element outages < 0.033 Nothing in addition to NERC Figure 1. Voltage
Performance Parameters RERI TPL criteria related to reactive power resources: 1. For transfer paths,
voltage stability is required with the pre-contingency path flow modeled at a minimum of 105% of the
path rating for system normal conditions (Category A) and for single contingencies (Category B). For
multiple contingencies (Category C), post-transient voltage stability is required with the precontingency transfer path flow modeled at a minimum of 102.5% of the path rating. 2. For load
areas, voltage stability is required for the area modeled at a minimum of 105% of the reference load
level for system normal conditions (Category A) and for single contingencies (Category B). For
multiple contingencies (Category C), post-transient voltage stability is required with the area modeled
at a minimum of 102.5% of the reference load level. For this criterion, the reference load level is the
maximum established planned load limit for the area under study. 3. Specific requirements that
exceed the minimums specified in 1 and 2 may be established, to be adhered to by others, provided
that technical justification has been approved by the RERI. 4. Item 3 applies to internal
interconnection Systems. Submitting a Proposed Finding of Exclusion to the Regional Entity
Information required. Once the analysis has been performed and the Subject Element/System has
been determined to not have a material impact on neighboring Transmission Owners, Operators, and

Balancing Authorities as described in Table 1, and is unnecessary for the operation of an
interconnected transmission system, the Responsible Entity shall submit the findings to the RERI.
RERI Review of Proposed Findings The RERI operational/planning staff with technical expertise in
powerflow studies shall review Proposed Findings of Exclusion submittals and shall determine if the
assessment is deficient or agrees with the finding of exclusion. The RERI shall exempt the system
elements from the BES, if the elements are approved for exclusion. If the exclusion of the BES
elements change the Responsible Entities NERC functional registrations the Region shall support the
Responsible Entity through the NERC deregistration process. Dispute Resolution A Responsible Entity
or Registered Entity or Owner may appeal a Disputed Finding of Exclusion with the RERI to NERC.
Ongoing Responsibilities a. Logging. The RERI shall create and maintain a comprehensive list,
available for public review, of: i. All Elements with nominal operating voltages at or above 100 KV
that have Confirmed Findings of Exclusion, or, through other aspects of the BES definition, have been
excluded from the BES including an explanation of how the element was excluded through the
definition; ii. All Elements with nominal operating voltages below 100 kV that have Findings of
Inclusion; and iii. The status of all EAs in dispute. iv. The Responsible Entity would continue to provide
system data to the neighboring Balancing Authorities and Transmission Owners and Operators and if
applicable continue to coordinate underfrequency load shed and under voltage load shed scheme
information. VII. Conclusion NERC should adopt the TPL-based assessment as proposed herein. A
bright-line BES test will not exclude all load distribution facilities as required by the FPA. Further, a
performance-based exemption process would be objective, consistent, and transparent, and would
adequately differentiate between local distribution and transmission, i.e., BES, facilities.
Individual
Bill Dearing
Northwest Public Power Association (NWPPA)
No
We believe that the proximity test may be unnecessary, and if an Element or group of Elements
meets the other three tests proposed by the SDT, it should be excluded from the BES, even if it does
not meet the proximity test. Secondly, using impedance to benchmark system load proximity would
likely not yield clear demarcations. High voltage relative or per-unit impedances are considered
typically much lower than low voltage impedances. Hence, in the absence of phase shifting
transformers, service compensation, or other mitigation factors, power typically flows over the
highest voltage lines, which offer the lowest impedance.
Yes
NWPPA agrees conceptually that systems operating as radials rather than as integrated portions of
the integrated bulk transmission system should be excluded from the BES definition. That is because
local distribution systems typically operate adjacent to, or at the end of transmission lines, and
function operationally to move power from the Transmission Service Provider’s point of delivery of
bulk power that has moved across the integrated bulk transmission system to end-users located
within the local distribution utility’s service territory. To be consistent with the draft BES definition,
the term “radial in character” should be explicitly defined as a system that may include one or more
lines into a load area or referenced as a local distribution network. In addition, we agree that the
manner in which a system is operated during BES disturbances may be an indication of whether that
system is radial in character. That being said, we are concerned that, to the extent the SDT considers
regional disconnect procedures, it should be careful to note that UFLS and UVLS relays are often
embedded within local distribution systems and, while it is necessary for the UFLS and UVLS relays to
be properly armed to protect the BES in the event of a severe system disturbance, the local
distribution system interconnected with those relays should not.
Yes
NWPPA agrees conceptually that one critical characteristic distinguishing local distribution facilities
that must be excluded from the BES from transmission facilities that should be included is the manner
in which power flows on those facilities. Power on local distribution systems generally flows only from
the interconnected transmission source and across the distribution system for delivery to end-use
customers. By contrast, power on transmission systems generally flows in two (or multiple, in
networked systems) directions and is delivered in bulk to distribution utilities rather than to endusers. Hence, the SDT has properly identified power flows as one important characteristic that
distinguishes BES transmission systems from local distribution systems. In order to identify systems

that are not necessary for the operation of the BES under this text, we propose that any system
where real power flows into the local distribution system 90 percent of the time or more under normal
operating conditions.
Yes
NWPPA agrees that the SDT’s fourth test, which asks whether power is intentionally transported
through a system, identifies a key characteristic of local distribution facilities that distinguishes such
facilities from interconnect bulk transmission facilities that are properly considered part of the BES. In
fact, we believe this may be the most important and readily identifiable distinction. Accordingly,
NWPPA agrees that if power is not intentionally transported through a particular system, that system
is not used for transmission and should not be considered part of the BES. One exception may be for
a small embedded generation unit owned by a different party that may be “scheduled” out of an area,
but in reality, does not produce any physical flow. These circumstances should not trigger inclusion.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with local distribution
and not BES transmission facilities, and one relying on technical analysis to determine whether or not
an Element or group of Elements has a measurable impact on the threat of cascading outages,
separation events, or instability on the interconnected bulk system. If technical analysis demonstrates
that Elements create no material threat of such reliability events, they should properly be excluded
from the BES. NWPPA supports the technical arguments and the White Paper presented by Snohomish
County PUD in their comments. We recommend that the SDT modify its approach to the technical
exclusion process to match the approach advocated in the White Paper, which is based upon the
approach recommended by the WECC BES Task Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection.
Specific transient voltage dip thresholds are proposed at page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
See response to 5d
No
None
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid showing that the Elements contribute substantially to the
potential for cascading outages, separation events, or instability on the interconnection bulk
transmission system. We also agree that the SDT has, in general, identified the correct technical
approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion
analysis) be modified as discussed in the Snohomish PUD White Paper, in the WECC BES Task Force
Proposal 6, and in our answer to Question 5.
See exclusion comment
See exclusion comment
See exclusion comment
See exclusion comment
No

As discussed on page 12 of the Snohomish White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant
Regional Entity, and in nearly every case, the base case can be expected to model any Element that
conceivably has a material impact on the reliable operation of the bulk system. In those rare cases
where it does not, we believe the owner or operator of the subject Element should be able to provide
the needed data.
No
As properly constructed Definition and Exceptions process should meet the legal requirements of
Section 215.
Yes
NWPPA generally supports the approach to the exclusion process proposed by the SDT, which
provides two different paths to exclusion, one based on readily-identifiable operational characteristics
of a system, and one based on technical reliability analysis. We believe it is important to provide for
the first path, based on operational characteristics, so that systems that are marginally disqualified
under the BES Definition (because, for example, generation within the system exceeds demand for a
few hours a year) can obtain an exclusion without the large investment of resources that otherwise
might be required for a full-scale technical analysis. That being said, we question whether the first
subsection of the characteristic test, relating to system proximity, is necessary, and we are concerned
that the requirement that a system meet all four requirements of the characteristics test may be
overly restrictive. For example, it is easy to imagine a distribution system in a rural area that covers a
widely dispersed area, so that load is many miles from the relevant generation/transmission source,
and that the system therefore does not meet the electrical proximity element, but meets the other
three elements of the characteristics test. Such a system should be excluded because it clearly serves
a local distribution function, and not a transmission function, as demonstrated by the fact that the
system meets subsections (c) (power flows into the system but rarely flows out ) and (d) (power is
not intentionally transported over the system). Accordingly, we recommend that the SDT consider
eliminating the first test. In the alternative, the SDT should consider allowing exempting a system
from the BES if it, for example, meets three of the four criteria rather than all four.
Individual
Ben Friederichs
Big Bend Electric Cooperative, Inc.
No
We believe that the proximity test may be unnecessary, and if an Element or group of Elements
meets the other three tests proposed by the SDT, it should be excluded from the BES, even if it does
not meet the proximity test. Secondly, using impedance to benchmark system load proximity would
likely not yield clear demarcations. High voltage relative or per-unit impedances are considered
typically much lower than low voltage impedances. Hence, in the absence of phase shifting
transformers, service compensation, or other mitigation factors, power typically flows over the
highest voltage lines, which offer the lowest impedance.
Yes
BBEC agrees conceptually that systems operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. That is because local
distribution systems typically operate adjacent to, or at the end of transmission lines, and function
operationally to move power from the Transmission Service Provider’s point of delivery of bulk power
that has moved across the integrated bulk transmission system to end-users located within the local
distribution utility’s service territory. To be consistent with the draft BES definition, the term “radial in
character” should be explicitly defined as a system that may include one or more lines into a load
area or referenced as a local distribution network. In addition, we agree that the manner in which a
system is operated during BES disturbances may be an indication of whether that system is radial in
character. That being said, we are concerned that, to the extent the SDT considers regional
disconnect procedures, it should be careful to note that UFLS and UVLS relays are often embedded
within local distribution systems and, while it is necessary for the UFLS and UVLS relays to be
properly armed to protect the BES in the event of a severe system disturbance, the local distribution
system interconnected with those relays should not.

Yes
BBEC agrees conceptually that one critical characteristic distinguishing local distribution facilities that
must be excluded from the BES from transmission facilities that should be included is the manner in
which power flows on those facilities. Power on local distribution systems generally flows only from
the interconnected transmission source and across the distribution system for delivery to end-use
customers. By contrast, power on transmission systems generally flows in two (or multiple, in
networked systems) directions and is delivered in bulk to distribution utilities rather than to endusers. Hence, the SDT has properly identified power flows as one important characteristic that
distinguishes BES transmission systems from local distribution systems. In order to identify systems
that are not necessary for the operation of the BES under this text, we propose that any system
where real power flows into the local distribution system 90 percent of the time or more under normal
operating conditions.
Yes
BBEC agrees that the SDT’s fourth test, which asks whether power is intentionally transported
through a system, identifies a key characteristic of local distribution facilities that distinguishes such
facilities from interconnect bulk transmission facilities that are properly considered part of the BES. In
fact, we believe this may be the most important and readily identifiable distinction. Accordingly, BBEC
agrees that if power is not intentionally transported through a particular system, that system is not
used for transmission and should not be considered part of the BES. One exception may be for a small
embedded generation unit owned by a different party that may be “scheduled” out of an area, but in
reality, does not produce any physical flow. These circumstances should not trigger inclusion.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with local distribution
and not BES transmission facilities, and one relying on technical analysis to determine whether or not
an Element or group of Elements has a measurable impact on the threat of cascading outages,
separation events, or instability on the interconnected bulk system. If technical analysis demonstrates
that Elements create no material threat of such reliability events, they should properly be excluded
from the BES. BBEC supports the technical arguments and the White Paper presented by Snohomish
County PUD in their comments. We recommend that the SDT modify its approach to the technical
exclusion process to match the approach advocated in the White Paper, which is based upon the
approach recommended by the WECC BES Task Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection.
Specific transient voltage dip thresholds are proposed at page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid showing that the Elements contribute substantially to the
potential for cascading outages, separation events, or instability on the interconnection bulk
transmission system. We also agree that the SDT has, in general, identified the correct technical

approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion
analysis) be modified as discussed in the Snohomish PUD White Paper, in the WECC BES Task Force
Proposal 6, and in our answer to Question 5.
See exclusion comment
See exclusion comment
See exclusion comment
See exclusion comment
No
As discussed on page 12 of the Snohomish White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant
Regional Entity, and in nearly every case, the base case can be expected to model any Element that
conceivably has a material impact on the reliable operation of the bulk system. In those rare cases
where it does not, we believe the owner or operator of the subject Element should be able to provide
the needed data.
No
As properly constructed Definition and Exceptions process should meet the legal requirements of
Section 215
Yes
BBEC generally supports the approach to the exclusion process proposed by the SDT, which provides
two different paths to exclusion, one based on readily-identifiable operational characteristics of a
system, and one based on technical reliability analysis. We believe it is important to provide for the
first path, based on operational characteristics, so that systems that are marginally disqualified under
the BES Definition (because, for example, generation within the system exceeds demand for a few
hours a year) can obtain an exclusion without the large investment of resources that otherwise might
be required for a full-scale technical analysis. That being said, we question whether the first
subsection of the characteristic test, relating to system proximity, is necessary, and we are concerned
that the requirement that a system meet all four requirements of the characteristics test may be
overly restrictive. For example, it is easy to imagine a distribution system in a rural area that covers a
widely dispersed area, so that load is many miles from the relevant generation/transmission source,
and that the system therefore does not meet the electrical proximity element, but meets the other
three elements of the characteristics test. Such a system should be excluded because it clearly serves
a local distribution function, and not a transmission function, as demonstrated by the fact that the
system meets subsections (c) (power flows into the system but rarely flows out ) and (d) (power is
not intentionally transported over the system). Accordingly, we recommend that the SDT consider
eliminating the first test. In the alternative, the SDT should consider allowing exempting a system
from the BES if it, for example, meets three of the four criteria rather than all four.
Group
Transmission Access Policy Study Group
Cynthia S. Bogorad
No
Impedance is a function of a line’s length; it does not measure whether a line serves a BES function.
A very long line can exist only to serve load, and a short line in an urban area (where the load is
physically close to the grid) could be needed for transmission but would have low impedance. This
proposed metric is thus both over- and under-inclusive, and should be discarded. Transfer distribution
factor is a more appropriate metric, as described in TAPS’ response to Question 4. TAPS supports
having two paths for exclusions, one that includes extensive technical analysis and another that does
not. The path with less technical analysis is appropriate for Elements that a relatively high-level
examination shows to be not relevant to the reliability of the grid. This opportunity should be
available in the context of exclusions to reduce the burden on small entities. Reliability will not be
impaired by this option; all exception requests will be reviewed by NERC, and in any case where NERC
is less than certain that an exception is appropriate, NERC can perform any or all of the analyses that
would be required for a more technical exclusion or inclusion, and a positive result would be sufficient
justification to deny the exclusion request.

No
We believe that this criterion is intended, like those in 1(a) and (d), to determine whether an Element
is planned and operated to function as part of the interconnected grid. It is, however, too vague to be
useful and should be discarded.
The third item is “power flows into the system, but rarely flows out.” This criterion is vague. TAPS
suggests instead the following language, which is consistent with TAPS’ comments on Exclusion E3 of
the BES definition: “Neither the Element, nor any Elements that it connects to the grid (in aggregate),
includes more than 75 MVA of generation used to meet the resource-adequacy requirements of
electric utilities.”
Yes
TAPS supports the criterion in concept, but “intention[]” is a vague term and not relevant to an
Element’s impact on the grid. We suggest instead that to obtain an exclusion for such a quasi-radial
Element, the owner be required to demonstrate that energy transfers subject to NAESB TLR
procedures (Interchange Transactions or BES generator to load) have no more than a 5% transfer
distribution factor (TDF) on the Element that is a candidate for exception. Transfer distribution factor
is a good measure of an Element’s impact on the grid and is not subject to varying interpretations.
Yes
TAPS supports including specific technical criteria that Elements must meet to obtain an exclusion
through the exception process. This approach will facilitate uniform application of the exception
process. TAPS responds to the first five proposed criteria in response to 5b-5e below. The seventh
proposed criterion, “No cascading outages,” is insufficiently granular and should be discarded. The
criteria are intended to measure whether, among other things, a particular Element can cause a
cascading outage. They need to set out how decision-makers will determine whether an Element can
cause a cascading outage, not simply state that an Element that can cause a cascading outage cannot
be excluded from the BES.
The first proposed criterion, “Having a distribution factor of 5% for any other Element,” should instead
be “Having a distribution factor of 5% for curtailable Interchange Transactions or BES generator to
load identified in Transmission Loading Relief stages one through five.” An Element with a higher
distribution factor only on a non-BES Element should not be considered part of the BES on that
account.
The second criterion, “Allowable transient voltage dip – criteria TBD,” should specify where the
transient voltage dip is, i.e. “Allowable transient voltage dip on another BES Element for events on
the Element that is the subject of the Exception Request—criteria TBD.”
The third proposed criterion, “Allowable transient frequency excursion – criteria TBD,” should be
rephrased like the second: “Allowable transient frequency excursion on another BES Element for
events on the Element that is the subject of the Exception Request – criteria TBD.”
The fourth proposed criterion should be revised in the same way as the second and third: “Voltage
deviation on another BES Element for events on the Element that is the subject of the Exception
Request – criteria TBD.” The fifth proposed criterion should be similarly revised: “Transient Stability
on another BES Element for events on the Element that is the subject of the Exception Request –
positively damped.”
Yes
TAPS proposes a simpler set of exclusion exception criteria: 1. Having a distribution factor of 5% for
curtailable Interchange Transactions or BES generator to load identified in Transmission Loading
Relief stages one through five; 2. Category B and C contingencies on the Element that is the subject
of the Exception Request meet the TPL-002 criteria for other BES Elements. (With the new TPL-001-3
standard recently approved by ballot, Category P0 through P7 contingencies on the Element that is
subject of the Exception Request meets the criteria of P0 through P3 for other BES Elements); and 3.
The Element that is the subject of the Exception Request is not: (1) part of an IROL, (ii) part of a
blackstart or cranking path used in a TOP’s restoration plan, or (iii) used in NUC-001 to provide
service to a nuclear plant. TAPS believes these three criteria meet the intent of all of the criteria
presented by the SDT.
TAPS supports using a uniform set of technical criteria to decide inclusion exceptions. Such an
approach will facilitate uniform application of the criteria. It is appropriate for there to be only one
path, using technical analysis, for inclusions, because the analysis for inclusions should be performed

by Regional Entities and NERC (see TAPS comments on the BES Exception Process, also submitted
today), which have more resources available than do the small entities that TAPS believes are likely
to request exclusions based on the path for exclusions that does not include extensive technical
analysis. In addition to having clear and uniform criteria, the technical analysis for inclusions and
exclusions should use the same criteria (though one should of course be the inverse of the other). We
note that the steps laid out for Inclusions do not quite track those in Exclusions 2(a). For example,
Inclusions 1(b) states, confusingly, “Monitor the contribution of the disputed Element(s),” but there is
no corresponding step in Exclusions 2(a). TAPS suggests that Inclusions 1 be revised to mirror
Exclusions 2.
See TAPS comments in response to Question 5.
See TAPS comments in response to Question 5.
See TAPS comments in response to Question 5.
See TAPS comments in response to Question 5.

Yes
The third paragraph of the introduction to the Technical Principles is awkwardly worded and might be
misconstrued. TAPS suggests the following rewording: “Entities are not required to seek exceptions
under the Exception Procedure to exclude from the BES Element(s) that are already excluded under
the BES definition and designations.” For the sake of consistency, Exclusions (1) should contain a
provision analogous to Exclusions (2)(b) and Inclusions (1)(f) addressing the circumstances under
which the ERO can override a demonstration based on these criteria. As noted above, one of those
circumstances would be a demonstration by NERC that the Element in question meets the criteria for
inclusion in the BES.
Individual
Andrew Z Pusztai
American Transmission Company, LLC
No
ATC believes the relevance and rationale for this criterion is unknown. If this criterion is intended to
exempt elements, like circuit switchers, that are part of the distribution transformer circuits operated
above 100 kV, and located within a mile of the BES interconnection point, then ATC would expect the
wording to be “in close electric proximity to the BES” rather than in “close electric proximity to Load”.
Otherwise, ATC requests the SDT explain the relevance and rationale for this criterion before agreeing
on its inclusion.
No
Radial in Character – ATC proposes that this criterion be eliminated because it does not describe any
materially different characteristics beyond Exclusion E1 of the bright-line BES definition.
No
ATC proposes that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the bright-line BES definition.
No
ATC proposes that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the BES definition.
No
ATC proposes that this technical analysis criterion be replaced by criteria that are more closely tied to
the Adequate Level of Reliability (ALR) characteristics. The following alternate criteria are offered as
possible examples, “(1) the BES can be controlled to stay within acceptable limits following a fault on
or loss of the Element; (2) the BES performs acceptably after credible contingences of the Element;
(3) the Element does not limit the impact and scope of instability and cascading outages when they
occur; (4) BES facilities are protected from unacceptable damage by operating the Element within its
ratings; and (5) the BES has the ability to supply the aggregate electric power and energy
requirements of the electricity consumers at all times, taking into account scheduled or reasonably
expected unscheduled outages of the Element. In addition, ATC is not aware of any continent-wide
appropriate BES performance measures for voltage dip, frequency excursion, voltage deviation,

stability, etc. and ATC speculates that different values are likely for different regions and system
characteristics across the continent. As a result, ATC believes it is not advisable to try to adopt
unproven values without reasonable industry investigation and development.
ATC proposes replacing this factor with those cited above in 5a because a distribution factor
measurement indicates how much system changes affect the element, not how much a fault or loss of
the element would compromise the ALR of the BES. There is no clear correlation between this factor
and any of the six characteristics of Adequate Level of Reliability (ALR) of the BES.
ATC proposes replacing this factor with those cited above in 5a because there is presently no
established, continent-wide, acceptable transient voltage dip performance level for evaluating
whether a fault or loss of the element would not compromise the ALR of the BES. In addition, the
appropriate performance level for this factor may vary for different areas and system characteristics
across the continent.
ATC proposes replacing this factor with those cited above in 5a because there are established,
continent-wide transient frequency performance levels in the PRC-006-1 standard, but the elements
that are applicable to the standard do not have to be BES elements and the transient frequency
response requirements are not intended to be a criterion for BES classification.
ATC proposes replacing this factor with those cited above in 5a because there is presently no
established, continent-wide, acceptable (steady state) voltage deviation performance level for
evaluating whether a fault or loss of the element would not compromise the ALR of the BES. In
addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.
Yes
ATC recommends this process address the five characteristics of the Definition of Adequate Level of
Reliability (ALR) as listed in the comments above in Question #5a.
No
ATC proposes that the technical analysis criterion be replaced by criteria that are more closely tied to
the Adequate Level of Reliability (ALR) characteristics. The following alternate criteria are offered as
possible examples, “(1) the BES cannot be controlled to stay within acceptable limits following a fault
on or loss of the Element; (2) the BES does not perform acceptably after credible contingences of the
Element; (3) the Element limits the impact and scope of instability and cascading outages when they
occur; (4) BES facilities are not protected from unacceptable damage by operating the Element within
its ratings; and (5) the BES does not have the ability to supply the aggregate electric power and
energy requirements of the electricity consumers at all times, taking into account scheduled or
reasonably expected unscheduled outages of the Element. In addition, ATC is not aware of any
continent-wide appropriate BES performance measures for voltage dip, frequency excursion, voltage
deviation, stability, etc. and ATC speculates that different values are likely for different regions and
system characteristics across the continent. As a result, ATC believes it is not advisable to try to
adopt unproven values without reasonable industry investigation and development.
ATC proposes replacing this factor with those cited above in 7a because a distribution factor
measurement indicates how much system changes affect the element, not how a fault or loss of the
element would compromise the ALR of the BES. There is no clear correlation between this factor and
any of the six characteristics of Adequate Level of Reliability (ALR) of the BES.
ATC proposes replacing this factor with those cited above in 7a because there is presently no
established, continent-wide, acceptable transient voltage dip performance level for evaluating
whether a fault or loss of the element would compromise the ALR of the BES. In addition, the
appropriate performance level for this factor may vary for different areas and system characteristics
across the continent.
ATC proposes replacing this factor with those cited above in 7a because there are established,
continent-wide transient frequency performance levels in the PRC-006-1 standard, but the elements
that are applicable to the standard do not have to be BES elements and the transient frequency
response requirements are not intended to be a criterion for BES classification.
ATC proposes replacing this factor with those cited above in 7a because there is presently no
established, continent-wide, acceptable (steady state) voltage deviation performance level for
evaluating whether a fault or loss of the element would compromise the ALR of the BES. In addition,
the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent

No
No
Yes
1. ATC proposes replacing the wording in the Exclusion preface, Exclusion 2 preface, and Inclusion 1
preface of “not necessary to reliably operate the interconnected transmission network” with
“necessary to maintain an Adequate Level of Reliability (ALR) of the Bulk Electric System”. 2. ATC has
reservations on the following statement made in the introduction of this document: ” Due to the
importance of Blackstart Resources and their designated blackstart Cranking Paths to restoration
efforts, no exceptions will be allowed for those items.” This does not allow for a provision to exclude
any designated Blackstart Cranking Path (at any voltage) even though there may be technical
justification for it. 3. The first page states that “Specific content of this application is spelled out
elsewhere in this appendix.” ATC requests the SDT describe where this appendix will be published.
Furthermore, is it a compliance document or just technical “guidance”? 4. Having the following
statement included for both exclusions and inclusions will create disagreement: “The ERO can
override this criterion but would need to provide additional justification to support their finding.” ATC
believes any override should have adequate technical justification and not interfere with other
statutory requirements. Also, it does not clarify or identify who would make the determination
whether NERC has made adequate justification to override the criterion.
Individual
Joe Petaski
Manitoba Hydro
No
The purpose of this exception is unclear. It would be possible that a large transmission station with
many network connections, which is close to a load (irrespective of size), would be excluded from the
BES definition. Similarly, a reduction of system impedance, by transmission line re-conductoring for
example, could remove assets out of the scope of the BES definition. The listed proposed criteria
suggest values yet to be determined. It is unclear how this exception would support BES reliability.
No
The proposed criteria to substantiate a request for an exception should be removed as it does not
introduce anything different than what is already proposed under the exclusions in the bright line BES
definition. Specifically, radial systems are already excluded in the bright line definition E1.
No
Vague language such as “rarely” or “not intentionally” does not support a “bright line” approach, and
is not measureable or auditable. Also, the sample evidence should not be included as part of the
criteria. In addition, the proposed criteria to substantiate a request for an exception should be
removed as it does not introduce anything different than what is already proposed under the
exclusions in the bright line BES definition. Specifically, this item is already excluded in the bright line
definition E3.
No
Vague language such as “rarely” or “not intentionally” does not support a “bright line” approach, and
is not measureable or auditable. Also, the sample evidence should not be included as part of the
criteria. In addition, the proposed criteria to substantiate a request for an exception should be
removed as it does not introduce anything different than what is already proposed under the
exclusions in the bright line BES definition. Specifically, this item is already excluded in the bright line
definition E3.
No
Manitoba Hydro does not agree with an impact based approach to establishing BES elements as we
believe it will result in regional differences in the application of the BES definition. In addition, the
resources required to verify the assumptions made in the models used to substantiate a BES
exception would be substantial with no benefit to reliability. As well, this section appears to be an
incomplete process. As currently worded, if the model was not updated in step ii, then there is no
requirement to run the TPL studies indicated in the remainder of step ii.

No
No
Manitoba Hydro does not agree with an impact based approach to establishing BES elements as we
believe it will result in regional differences in the application of the BES definition. In addition, the
resources required to verify the assumptions made in the models used to substantiate a BES
exception would be substantial with no benefit to reliability.

No
We are concerned however that assumptions could be made to complete the technical analysis to
support an exclusion that may not be appropriate.
Yes
Canadian Entities are not under FERC jurisdiction, so the revised BES Definition may not apply. A
number of Canadian Entities have the BES defined within their provincial legislation. This may
introduce differences and even contradictions between elements that are included in the BES
according to provincial legislation and the NERC definition.
Yes
The exception procedure is a complicated and resource intensive process. To be most effective, the
BES definition should be a stand-alone 100kV bright line with any exception criteria being specified
within the definition. Additionally: -FERC Order 743 directed the revision of the Bulk Electric System
(BES) definition to improve clarity, to reduce ambiguity, and to establish consistency across all
Regions. The proposed impact based exception procedure undermines all three of these targets. -The
Technical Exceptions eliminate the 100kV ‘bright-line’ definition and introduce regional differences,
both of which are contradictory to the goals of the BES revision project. -The commitment for NERC to
review and continuously monitor BES exceptions made through this process would be extremely
onerous and resource intensive with little benefit to reliability. -To obtain industry consensus on the
precise limits to determine if an element has sufficient impact on the BES to be included in the BES is
not a reasonable or attainable endeavor.
Group
ISO/RTO Standards Review Committee
Albert DiCaprio
No
The SRC fails to see how electrical proximity to load qualifies an element for exclusion from the BES.
Such elements may indeed be involved in serving electricity to those loads. If those loads are critical
loads, then why should the element be excluded from the BES?
No
The SRC generally agrees that radial elements likely may be excluded from the BES. However, there
is insufficient information given as to what it means to be “not operated as part of the BES with
disconnection procedures for when a Disturbance occurs”. Further, is it possible that such radial
elements are serving a remote “critical” load? One would think that, normally, critical loads would
have arrangements for multiple sources, but could those multiple sources be individually considered
to be radial?
No
The SRC believes that, if power EVER flows out, then the area is either not radial or it includes
generation resources. There is insufficient information to determine whether this “limited quantity of
energy” is indeed small. There could be very large amounts of load and generation resources within

that area. Such large quantities could represent a significant potential for sudden increases in load or
unexpected energy injections.
No
Hasn’t the reliability concern associated with “loop flows” been related to the unintentional flow of
power through parts of the system?
Yes
Predictive analysis of an accurate model is useful in determining the importance of various elements
of the system.
Distribution factors by themselves are not sufficient evidence that elements are not important to the
system. Multiple elements may have significant distribution factors related to various portions of the
system, but that doesn’t necessarily mean that loss of those elements will result in a reliability risk to
the system.
These “transient” and “voltage deviation” analyses are highly dependent upon sound and accurate
dynamic system models. Much has been said in recent days about the suspicions that many such
models are not truly accurate enough to predict system response that is close to what actually occurs.
See 5c
See 5c
Very small elements may be candidates for exclusion because such a small loss cannot cause
reliability risk. An exception to this statement may be that, though small, the element is important to
the service of a critical load.
Yes
The SRC generally agrees with the technical analysis approach to determining whether an element
should be included in the BES. However, consideration should also be given to valid and supported
evidence given by RCs and PCs, and, possibly TOPs and BAs to actual historical events that indicate
significant importance of elements which, when lost, have resulted in reliability risk to the system.

Group
New York Power Authority
Randy D. Crissman
No
NYPA does not see a need for this requirement. A radial element that specifically serves a load center
will perform that task regardless of the electrical distance from the source to the load. Similarly, any
loss of load in the load center will result in a corresponding need to reduce generation in the source
system, regardless of the proximity of the load.
Yes
The definition of radial systems needs to be modified to include radials that are connected to a single
transmission source by more than one automatic interruption devices, such as occurs with a ”breaker
and a half” arrangement.
Yes
NYPA generally agrees with this item. However, the term “system” needs to be better defined. It is
not clear how power could flow out of a load only system. If reversing power flows on a feeder caused
it to fail one of the criteria, could the radial still be excluded, or is it necessary for the Element to pass
all requirements? Alternatively, could the entity choose to file for Exclusion of that Element under the
technical analysis option? What happens and what are the implications when the two approaches
produce different outcomes? An example of revised wording for “iv. The maximum amount of energy
flowing out” would be no more than 24 hours of reverse power flows within any rolling 12-month

period. Consider avoiding prescribing values and eliminate bullet (iv). The intended performance
outcome should be described, but without setting values. This should not have any impact on the
reliability of the transmission network if items 1, 2 and 3 are satisfied.
Yes
NYPA agrees that power flow wheeled through a system indicates that the system potentially has
more than one source. Therefore, the element in question is not radial.
Yes
In general, NYPA agrees with this approach except as noted below.
NYPA does not agree with this measurement. Distribution factors are dependent on the number of
radial transmission lines that connect a single source to a load. For example, if two lines connect a
single source to a load, and one line trips, the distribution factor provides a 100% increase in flow on
the remaining line. If three lines connect the source to the load, and one line trips, the distribution
factor for the remaining lines would be 50%. The SDT should avoid setting values and instead
describe the intended performance outcome from a distribution factor measurement. Note that
ultimately NERC as an ERO or relevant regulatory authority will approve the application and can
assess the performance outcome in their decision making presented in an entity’s application.
Suggest that either the SDT avoid using voltage dip as a criteria, or clearly specify that the transient
voltage not exceed the X limit of Y cycles (time). References to relevant industry standards such as
IEEE standard 1346-1998 should be made.
Suggest that for assigning a value for transient frequency response, entities conduct and submit to
the SDT their quantitative and qualitative technical assessment based on the conditions of the
element(s) under the application. Do not establish a fixed binary value within the exception criteria
but rather focus on the performance outcome.
Voltage deviation is generally expressed as a percentage, between the voltage at a given instant at a
point in the system. Do not establish a fixed binary value within the exception criteria but rather focus
on the performance outcome.
No
Yes
In general, NYPA agrees with this approach except as noted below. Inclusions criteria should mirror
the Exclusion criteria, and that consistent values should be employed for Inclusions here and for
Exclusions above.
NYPA does not agree with this measurement. Distribution factors are dependent on the number of
radial transmission lines that connect a single source to a load. For example, if two lines connect a
single source to a load, and one line trips, the distribution factor provides a 100% increase in flow on
the remaining line. If three lines connect the source to the load, and one line trips, the distribution
factor for the remaining lines would be 50%.
Refer to the response to Question 5c.
Refer to the response to Question 5d.
Refer to the response to Question 5e.
No
No
No
Group
Iberdrola USA
John Allen
No
We do not agree with this requirement. These exclusion exception criteria should be deleted in their
entirety and replaced with criteria that are objective, specific, and repeatable, or preferably not

replaced at all. Specific problems with the criteria as stated are: 1. A facility is not BES if all of “a”
through “d” below apply: a. “System elements” are in “close electrical proximity to load” – this is
vague, and a lower impedance between systems is higher likelihood of interaction between systems.
Proximity measured in ohms should be related to the load level itself. A pair of values (ohms, load) is
necessary for this purpose. Transient stability is affected by this value-pair. For a load pocket, an
equivalent impedance (e.g., a sort of Thevenin impedance) between the network source and the load
location could be defined. The impedances within the network source can also affect the assessment.
Re-evaluation over time would be necessary if this path were adopted. This path of evidence (i.e., the
path of engineering judgment) which does not include extensive technical analysis is an attempt to
provide a definitive criteria for exception without going through the other path of evidence (i.e., the
analytical path) which includes extensive technical analysis. Unless the analytical path has been
clearly defined and sufficient data obtained from/on it, the path of engineering judgment could
become difficult to establish. System parameters such as proximity to load, radial (or non-radial)
configuration, power flow direction over time (either unintended or intended) will directly influence
results of technical analysis evaluated for distribution factors, transient voltage dip and frequency
excursions, voltage deviations, transient and steady-state stability, and sequence of events following
a disturbance (i.e., either a cascading outage or a controlled outage). The two paths of evidence
cannot be in conflict with each other.
No
We do not agree with this requirement. These exclusion exception criteria should be deleted in their
entirety and replaced with criteria that are objective, specific, and repeatable, or preferably not
replaced at all. Specific problems with the criteria as stated are: 1. A facility is not BES if all of “a”
through “d” below apply: b. “System elements” are “treated as” radial “in character” – this is also
vague, and based on operating procedures… what does “treated” involve? What is “character” in the
context of system elements?
No
We do not agree with this requirement. These exclusion exception criteria should be deleted in their
entirety and replaced with criteria that are objective, specific, and repeatable, or preferably not
replaced at all. Specific problems with the criteria as stated are: 1. A facility is not BES if all of “a”
through “d” below apply: c. Power flows into “the system” most of the time – this is vague and covers
much of the 115 kV system.
No
We do not agree with this requirement. These exclusion exception criteria should be deleted in their
entirety and replaced with criteria that are objective, specific, and repeatable, or preferably not
replaced at all. Specific problems with the criteria as stated are: 1. A facility is not BES if all of “a”
through “d” below apply: d. Power “entering” “the system” does not “intentionally” flow into another
“system” – what does intentionally versus unintentionally mean?
No
A facility is not BES if it is not necessary for reliable system operation, based on a TPL-type analysis
similar to NPCC Document A-10 “Classification of Bulk Power System Elements” – this type of analysis
was rejected by FERC. Besides, at 115kV, calculated distribution factors for interfaces between areas
(where higher voltage lines, e.g., at 230kV and 345kV, are included as part of the interface definition)
tend to be small and inaccurate. The method used to calculate distribution factors is an approximate
method which must be re-evaluated for small values of distribution factors.
See 5a.
See 5a.
See 5a.
See 5a.
No
No
A facility is BES if it is necessary for reliable system operation, based on a TPL-type analysis similar to
NPCC Document A-10 “Classification of Bulk Power System Elements” – this type of analysis was
rejected by FERC. In addition, applicable threshold values for these parameters could differ from one
system to another, and would require extensive analysis.

See
See
See
See
No

7a.
7a.
7a.
7a.

No
No
Group
Tri-State Generation and Transmission Association
Mark Conner
No
A long radial line with a small transformer could have a relatively high impedance. Proximity to load
has no real bearing on this procedure. Requirement 1.(a) should be deleted.
No
While we generally agree, 1.(b) should be changed to “normally radial.” “Radial” should not be
defined differently in the Rule of Procedure than in the BES Definition.
Yes
It may be more appropriate to use a threshold based on maximum power rather than on an annual
energy threshold.
Yes
While we generally agree, "system" needs to be clarified, and should be changed to "transmission
system." It may also need to be qualified by indicating a change in ownership of transmission
systems. We also wonder if the concept of scheduling should be addressed rather than using the word
"intentionally?"
No
This appears very similar to the “material impact” proposal that FERC has previously disallowed, so
we recommend removing 2. If retained, remove 2.(b) because allowing the ERO to override the
technical justification and analysis devalues such analysis to the point of it being meaningless.
If this approach is used, then there needs to be a clear technical rationale for defining the metric and
for determining the threshold value.
If this approach is used, then there needs to be a clear technical rationale for defining the metric and
for determining the threshold value.
If this approach is used, then there needs to be a clear technical rationale for defining the metric and
for determining the threshold value.
If this approach is used, then there needs to be a clear technical rationale for defining the metric and
for determining the threshold value.
No
No
This appears very similar to the “material impact” proposal that FERC has previously disallowed, so
we recommend removing it, but allowing elements that are included in Regional Entity defined bulk
transfer paths that are not already included in the BES definition. If retained, remove 1.(f) because
allowing the ERO to override the technical justification and analysis devalues such analysis to the
point of it being meaningless.
If this approach is used, then there needs to be a clear technical rationale for defining the metric and
for determining the threshold value.
If this approach is used, then there needs to be a clear technical rationale for defining the metric and
for determining the threshold value.

If this approach is used, then there needs to be a clear technical rationale for defining the metric and
for determining the threshold value.
If this approach is used, then there needs to be a clear technical rationale for defining the metric and
for determining the threshold value.
Yes
No
Yes
The proposed principles seem preliminary and immature. In addition as noted in earlier comments
they are not fully consistent with the proposed BES definition, particularly with respect to radial
elements and local distribution networks. Such consistency should be incorporated before the next
posting. We further feel that it is very unlikely that the technical evidence path can be placed on a
sound technical foundation and matured by the end of this year as directed by the FERC. Key
definitions are lacking and should be added to the document. For instance “distribution factor” is not
carefully defined even though such factors can be calculated in a variety of ways.
Group
Hydro One
David Curtis
No
We agree with this concept to allow entities to submit an exception application that does not include
extensive technical analysis. Such an option will make the process efficient for all stakeholders, such
as entities, Regions, NERC and relevant regulatory authority. However, our opinion is that there is no
real relationship between reliability and the proximity of load. If impedance is to be used as a
measure of electrical proximity, which in turn is a replacement for geographical proximity, then how
would the presence of parallel lines, capacitors, phase-angle regulators (PARs), tap-changing
transformers, generation and reactors be treated in determining electrical proximity? Consistent with
references in the FERC Order, we feel that it is much more important to identify and ensure if the BES
element(s) are serving load pockets associated with large metropolitan load centers, loads of
significance to national security and/or as identified by relevant Federal, State or Provincial
Regulatory Authority. We urge the SDT to clarify the exception criteria for exclusions, based on the
following questions: •How does the proximity impedance approach effectively differentiate between
transmission and distribution lines of the same voltage and length? •When using impedance, how is
“greater than” determined? •What impedance would the SDT apply to a PAR (or tap-changing
transformer) and to the overall path if a PAR (or tap-changing transformer) were located in-series
with the measured Elements? •What is the meaning of “power flow data” used here and how is the
meaning different from the term when used under “1c) Power flows into the system, but rarely flows
out”? Should this sentence use the phrase “impedance data extracted from a load flow study”
instead? Finally we suggest that entities should be required to identify the significance of the
element’s physical characteristics. Such identification can be done through a simple checklist along
with any relevant comments.
No
Entities should be allowed to demonstrate the radial characteristics to determine if they are permitted
for an exception, and demonstrate compliance with radial defining criteria. The term “regional
dispatch” is not defined. Therefore we suggest the SDT to provide a definition or reference to clarify
regional dispatch in 1 b) II. We recommend adoption of the alternate term “operational control” and
suggest that the SDT consider using the terms “under the operational control of a Balancing
Authority” (It is instructive that the overarching requirement for a finding of transmission system
integration in Mansfield was that the facilities be under operational control of the Independent System
Operator.*) * Southern Cal. Edison Co., 92 FERC ¶ 61,070 at 61,255 (2000), reh'g denied 108 FERC
¶ 61,085 (2004).
No
We agree with the criteria set out in 1(c), but suggest the SDT to avoid prescribing values and
eliminate bullet (IV). The SDT should also consider allowing: a) Power flow-out up to 20% of the
minimum forecasted load for the element(s) over a 12 month period; or b) Maximum amount of

energy flowing out be set to no more than 24 hours of reverse power flows within any rolling 12month period. The intended performance outcome should be described, but without setting values.
This should not have any impact on the reliability of the transmission network if items 1, 2 and 3 are
satisfied.
Yes
No
We agree that entities should be given an option to conduct an analysis to demonstrate whether or
not an element is necessary for the operation of the transmission network. We also support that NERC
should specify the entire relevant criteria category to be listed under exclusion criteria 2 (a).
However, we suggest that NERC should avoid prescribing numerical values but establish a range of
value (or reference industry standard) that would be consistent with industry/ regional standards or
practices without compromising the reliability of the transmission network.
Distribution Factor is an estimate of what feeder power flow participation level material is and what
non-material is. While TDF and OTDF analysis is an indication of contributions from the element,
hence the SDT should avoid setting values and instead describe the intended performance outcome
from a distribution factor measurement. Note that ultimately NERC as an ERO or relevant regulatory
authority will approve the application and can assess the performance outcome in their decision
making presented in an entity’s application.
Voltage dip is specified in terms of duration and retained voltage, usually expressed in percentage.
We advise against prescribing limits by the SDT, and instead suggest that either the SDT avoid
relating voltage dip altogether or clearly specify that the transient voltage not exceed the X limit of Y
cycles (time). We suggest SDT to make references to relevant industry standard such as IEEE
standard 1346-1998. For example, a document effective in 2007 titled Ontario Resource and
Transmission Assessment Criteria Issue 5.0 mentions that: “The minimum post-fault positive
sequence voltage sag must remain above 70% of nominal voltage and must not remain below 80% of
nominal voltage for more than 250 milliseconds within 10 seconds following a fault. Specific locations
or grandfathered agreements may stipulate minimum post-fault positive sequence voltage sag criteria
higher than 80%. IEEE standard 1346-1998 supports these limits.”
We suggest that, in terms of assigning a value for transient frequency response, entities conduct and
submit to the SDT their quantitative and qualitative technical assessment based on the conditions of
the element(s) under the application. We suggest not to establish a fixed binary value within the
exception criteria but rather focus on the performance outcome. See 5 (a)
Voltage deviation is generally expressed as a percentage, between the voltage at a given instant at a
point in the system. We suggest not to establish a fixed binary value within the exception criteria but
rather focus on the performance outcome. Adequate voltage performance does not guarantee system
voltage stability. Steady state stability is the ability of the grid to remain in synchronism during
relatively slow or normal load or generation changes and to damp out oscillations caused by such
changes. We suggest that the requirement should suggest that following checks are carried out to
ensure system voltage stability for both the pre-contingency period and the steady state postcontingency period: •Properly converged pre- and post-contingency power flows are to be obtained
with the critical parameter increased up to 10% with typical generation as applicable; •All of the
properly converged cases obtained must represent stable operating points. This is to be determined
for each case by carrying out P-V analysis at all critical buses to verify that for each bus the operating
point demonstrates acceptable margin on the power transfer as shown in the following section; and
•The damping factor must be acceptable (the real part of the eigen values of the reduced Jacobian
matrix are positive).
Yes
Technical Analysis must fundamentally use NERC – TPL methodology and testing requirements. We
believe that an element may “not be necessary for the operation of the interconnected transmission
system” if the remaining system can be operated without the element(s) for over 30 days and during
peak load conditions. This assumption considers that loss of element(s) may result in outage to the
connected load or generation during this period but will not have any adverse impact on the operation
of the interconnected transmission network. Following are technical assessment categories that
entities could be required when filing for exception: 1.Power flow •Primarily unidirectional (less than
20% of min load) 2.TPL Assessment •Load Flows Analysis •Thermal and Voltage Stability •Transient

Stability 3.TDF and OTDF assessment For entities filing an exception: [Step 1] Entities should
undertake relevant and detailed technical assessment/analysis and describe their findings under each
of the technical categories. Finally, the findings and conclusions should be listed in the form of
maximum 6 bullets. [Step 2] Findings and conclusions from each of the technical categories should be
presented in a spreadsheet including the categories that may not be relevant to the element(s). If a
category is not relevant, it should be explained why. [Step 3] The final conclusion should be
presented by taking the overall assessment in Step 2 by assessing contributions of each item and
demonstrating that the element(s) is or is not necessary for the operation of interconnected
transmission network. We suggest the above method and request entities to complete the table
below, as this will allow entities to present their assessment of the element(s) that are under the
consideration of exception. Measured Value ============== Load || Critical Load Affected?
[yes][No] ------------------------------------------- •Radial •Local supply, e.g. distribution in nature
•Large load center, critical load, national security Generation Characteristics || Critical Load Affected?
[yes][No] --------------------------------------------------------------- •Local load modifier, peak shaver
•Behind meter or industrial load displacement •Must Run •Flow contribution outside of the elements
under exception Cascading Outage || Critical Load Affected? [yes][No] ---------------------------------------------------- Measured Value ============== Max Dip [Voltage] Applicable Industry
Practice (IEEE/CSA,Market Rules,etc.) Acceptable Level [in cycles] Assessment Results [in cycles]
Does the assessment confirm successful recovery? [Yes] [No] Transient Voltage Dip [voltage]
Transient Frequency Excursion [Hertz] Voltage deviation [Voltage] Transient Stability Steady State
Stability
No
Inclusions criteria should mirror the Exclusion criteria, and that consistent values should be employed
for Inclusions here and for Exclusions above. [See our comments on exclusions]
[See Comment 5b]
[See Comment 5c]
[See comment 5d]
[See comment 5e]
No
Yes
It is imperative to understand that the NERC’s revised definition will have a direct impact on entities
across North America and may conflict with regulatory requirements, Codes, and Licenses. FERC in its
Order 743 and 743A has directed NERC to address these concerns. As for Ontario System, the BES
exception criteria shall meet the expectations of Ontario's regulator (Ontario Energy Board) which has
the sole authority and responsibility for the reliability of customer connections and loads within
Ontario. Therefore, it will be necessary to accommodate NERC's proposed definition of BES or the
exception process with the Ontario situation. We suggest the SDT and RoP teams should: •Modify the
exception criteria and procedure to provide regulatory flexibility with requirements to conduct basic
technical analysis, to allow entities to consistently present their case to the ERO and/or the regulator
for a step by step expedited evaluation. •Include provisions in both the NERC exception criteria and
exception process for federal, state and provincial jurisdictions. These provisions should provide clear
guidance so that, if and when there are deviations from the exception criteria, they are identified with
technical and regulatory justifications ensuring there is no adverse impact on the interconnected
transmission network. •Understand that the path to generating facilities need not be always BES
contiguous. Generating units can/should be required to be planned, designed, and operated in
accordance with a subset of NERC Standards, but should not always require contiguous paths.
Yes
Exception criteria should be crafted at a high-level with key menu items of assessment that can be
followed continent-wide by entities to put forward their exception for element(s) that are not
necessary for the interconnected transmission network and based on technical assessment, evidence
and justification for its unique characteristics, configuration, and utilization. (Also see suggestions/
comments on Question 6)
Group
Alabama Public Service Commission

John Free

Yes
The second paragraph of the proposed Technical Principles states that “[d]ue to the importance of
Blackstart Resources and their designated blackstart Cranking Paths to restoration efforts, no
exceptions will be allowed for those items.” This sentence should be deleted from the technical
principles. An unintended consequence of subjecting all blackstart cranking pathways to inclusion in
the BES by default would be to cause a Registered Entity, in order to minimize costs, to not declare
every possible cranking path but instead limit to the minimum required cranking paths in order to
comply with the standards, as opposed to designating multiple pathways. This consequence could be
avoided by allowing blackstart cranking pathways to be evaluated for exceptions just like any other
element.
Individual
Heather Hunt
NESCOE
No
The New England States Committee on Electricity (“NESCOE”) appreciates the work of NERC’s
standard drafting team as well as the opportunity to provide comments on this matter. NESCOE is
New England’s Regional State Committee and the comments provided herein reflect the collective
views of the six New England states. NESCOE’s comments below reflect its general perspective that
any new costs imposed as a result of the BES and its implementation, which costs ultimately fall on
consumers, should provide meaningful reliability benefits. NESCOE questions the concept as
presented and seeks further clarification. As a general matter, NESCOE believes the requirement that
a proposed exception must meet all four criteria is overly restrictive and will result in only a narrow
category of elements qualifying for exclusion from the BES. NESCOE suggests that a better approach
would allow exclusions to be based on one or more criteria, depending on the nature of the element
that is the subject of the application. With respect to the proposal, NESCOE does not believe it is
possible to obtain agreement on the “proximity to load” criterion for additional exclusions from the
BES when the underlying impedance value has not been determined and may be the subject of
significant debate. While it is possible that NESCOE could support a single impedance value that
would govern exclusion determinations, it notes that a uniform value may not adequately address
varying system configurations throughout ISO-New England and neighboring control areas. NESCOE
suggests that the standards setting process allow for further deliberation on possible proposed values.
Other terms, such as “load center,” also need definition.
No
As noted in Response 1, NESCOE believes exclusion determinations should not require a finding that
all four proposed criteria are met. In addition, NESCOE believes that the criterion proposed here is

overly complex and that developing the evidence may be overly burdensome to the applicant. Radial
paths should have a simple definition related to how the path is connected from a topological
perspective. NESCOE suggests that a radial path be defined simply as a path having only one
connection point to the BES, thereby presenting no opportunity for power flows parallel to the BES
network. Under fault situations, these excluded paths can be isolated from the BES with suitable
NERC compliant protection systems. Note the radial path may be comprised of parallel lines that
terminate at the BES connection point. In addition, NESCOE believes that a radial path should qualify
for exclusion as long as the power flowing into the BES is less than a threshold MVA. NESCOE does
not at this point have a recommendation as to this specific threshold but believes it should be
developed through the standards-setting process. NESCOE suggests this approach to avoid burdening
the development of generation including renewable generation. As New England is working on
facilitating the development of renewable resources located in and around the region to serve
customers most cost-effectively, this process should take specific care not to impose undue burdens
on renewable resources.
No
As noted in Response 1, NESCOE believes exclusion determinations should not require a finding that
all four proposed criteria are met. Generally, NESCOE is in agreement with an exception criteria for
additional exclusions that takes into account power flows into the system that rarely flows out.
However, additional clarity is necessary for criteria 1(c)(i),(ii) and (iv). Specifically, what is meant by
“very limited set of conditions” under 1(c)(i) and (ii) and “limited quantity of energy” under 1(c)(i)?
Further, is it appropriate to establish a fixed value of X megawatt hours for the maximum amount of
energy flowing out of the system? While it is possible that NESCOE could agree upon a uniform value,
NESCOE is not in a position to provide specific comment or support when the MWh value is
unspecified. In addition, a fixed value may not adequately address varying system configurations
throughout ISO-New England and neighboring control areas.
No
As noted in Response 1, NESCOE believes exclusion determinations should not require a finding that
all four proposed criteria are met. NESCOE further notes that New England’s network has numerous
parallel paths operated at voltages less than 200 kV which may parallel 230 kV and 345 kV BES
network paths. If flows on a given <200 kV path only exceed 200 MVA under contingency conditions
and if these paths are connected to the higher voltage BES elements with suitable NERC compliant
protection systems, these paths may be EXCLUDED from the BES. NESCOE suggests the value of 200
MVA based on typical thermal ratings of 115 kV transmission lines but is open to other values that the
drafting team may suggest. NESCOE also suggests that the phrase “to some other system” be
broadened to include any other higher voltage BES element.
Yes
NESCOE supports the concept of allowing an additional path to justifying an exclusion from the BES.
NESCOE could support development of technical criteria such as those proposed, but does not have
specific recommendations at this time. As stated earlier, any excluded elements must be connected to
the BES using fully NERC compliant protection systems.

Yes
Please refer to comments under item 4., above. If the parallel power flow in a given < 200 kV path
only exceed 200 MVA under contingency conditions and if the applicable BES points have fully NERC
compliant protection systems, disturbances on this lower voltage path will not adversely affect the
reliability of the BES. The exclusion determination process should be flexible enough to recognize that
any requirement that may impose substantial new costs on New England transmission owners, and
ultimately on consumers, should also provide meaningful reliability benefits

Yes
NESCOE believes that exclusion determinations should be based on clear but flexible criteria that do
not result in the unnecessary inclusion of elements into the BES that do not adversely impact the
reliability of the BES. The process described here is too limiting in its requirement that an application
meet all of those four listed criteria not requiring technical analysis. Applicants and reviewers should
have a broader menu of decision criteria available to them. Regarding those criteria related to
exclusions based on technical analysis, NESCOE suggests that ranges of values, in recognition of
regional differences in network characteristics, be suggested by the drafting team for further
consideration. Finally, as discussed above in response to questions 1 through 4, NESCOE believes that
additional exclusion determinations should not require a finding that all four proposed criteria are
met. Rather, the various criteria set forth under 1(a) through 1(d) should be treated as alternative
criteria to qualify for an additional exclusion, and entities seeking additional exclusions to the BES
should be allowed to demonstrate that one or more criteria is met, depending on the nature of the
element that is the subject of the application.
Individual
Michael Falvo
Independent Electricity System Operator
No
We agree with this concept to allow entities to submit an exception application that does not include
extensive technical analysis. Such an option will make the process efficient for all stakeholders, such
as entities, Regions, NERC and relevant regulatory authority. However, we believe that an Element’s
electrical proximity to load is not necessarily a relevant consideration for determining whether the
Element is required for reliable operations.
Yes
We agree with this concept. Entities should be allowed to demonstrate the radial characteristics to
determine if they are permitted for an exception. However, we believe some further clarification of
the meaning of “radial in character” is needed. The example given in (b)I does not clarify the matter.
Would a transmission line operated with a normally open point to form two radial lines be considered
“radial in character”? Please clarify. The location of the Disturbance needs to be clarified. For
example, if the Disturbance (e.g. a fault) occurs at the radial part of the Element, then it is necessary
for the Element to have the capability to disconnect itself from the Disturbance to preserve BES
reliability but the Element can be by itself a legitimate radial facility that is used solely for supplying
load. The phrase “are not included in a regional dispatch” is unclear. We do not understand what this
means.
No
There is an inconsistency between the language used in bullet (c) - “rarely flows out”, and that used
in Exclusion E3(c) of the BES definition – “Power flows only into the LDN”. We have commented
during the BES Definition comment period that Exclusion E3 needs to be modified to match the
Exception Principles. We agree with the criteria set out in 1(c) except for bullets (iv) and (v). We do
not believe it is possible to establish a limit on the energy flow out of a system for which an exception
has been requested. Further, we suggest that the SDT avoid prescribing set values in the exception
criteria since these would only serve to limit the flexibility of the process. As an alternative to the
proposed bullet (iv), we suggest that power flow study results could be used to support the exception
request. We therefore propose the following wording to replace bullets (iv) and (v). iv. Power flow
simulation results to demonstrate that BES reliability is not dependent upon the power flows through
the Element(s) for which an exception has been submitted, for the conditions specified in (ii).
Yes
There is an inconsistency between the language used in bullet (c) - “rarely flows out”, and that used
in Exclusion E3(c) of the BES definition – “Power flows only into the LDN”. We have commented
during the BES Definition comment period that Exclusion E3 needs to be modified to match the
Exception Principles. We agree with the criteria set out in 1(c) except for bullets (iv) and (v). We do
not believe it is possible to establish a limit on the energy flow out of a system for which an exception

has been requested. Further, we suggest that the SDT avoid prescribing set values in the exception
criteria since these would only serve to limit the flexibility of the process. As an alternative to the
proposed bullet (iv), we suggest that power flow study results could be used to support the exception
request. We therefore propose the following wording to replace bullets (iv) and (v). iv. Power flow
simulation results to demonstrate that BES reliability is not dependent upon the power flows through
the Element(s) for which an exception has been submitted, for the conditions specified in (ii).
No
The technical analysis path for exclusions and inclusions allows for override of the listed “criterion”. It
is not clear what will be the basis for overriding, and what process will be followed? Is the “criterion”
meant to be all of (1) to (7) in (a), or is it any one of them? This needs to be clarified. We agree that
entities should be given an option to conduct an analysis to demonstrate if an element is or is not
necessary for the operation of transmission network. However, consistent with our earlier comments,
we suggest that the exception criteria avoid prescribing numerical values. A transmission element is
not necessary for the reliable operation of an interconnected electric transmission system, if it can be
removed without effecting bulk transfer capabilities. In our view, testing in accordance with the TPL
standards should be the basis for establishing this. One way of demonstrating that an element is not
required for the transfer of bulk power is to show that with the element out of service (and with all
elements that received exemptions in the past also out of service) and at the required power
transfers: 1. Pre-contingency and post-contingency loadings on all BES elements are within applicable
ratings. 2. Pre-contingency and post-contingency voltages on the BES are within established ratings.
3. All units on the BES remain synchronized following contingencies. 4. All voltage declines on the BES
are within established limits (if any limits were defined). 5. All steady-state oscillations and
oscillations following a contingency are positively damped. 6. Transient voltage dips do not exceed
established limits anywhere on the BES (if any limits were defined). 7. Frequency excursions do not
exceed established limits anywhere on the BES (if any limits were defined). Our view is that the
exception criteria should NOT specify the voltage decline limits, allowable frequency excursion or the
allowable transient voltage dip because every region will have different limits depending on the
characteristics of their power system. This would be consistent with Requirement R5 of the recently
balloted standard TPL-001-2, which requires each Transmission Planner and Planning Coordinator to
have criteria for acceptable System steady state voltage limits, post-Contingency voltage deviations,
and the transient voltage response for its System. Required power transfers are the transfers required
to meet the “one day in ten year” loss of load expectation criteria. Further, exception criteria for
generators must also be defined. A power system is typically planned to be able to service the load
under multiple dispatch scenarios and, therefore, multiple generators disconnected from the
transmission system will unlikely reduce the ability of the power system to supply the load. In fact,
market forces typically determine whether or not a generator is connected. However, transmission
lines are built to achieve specific transfer capabilities and, therefore, directly affect the power
system’s ability to meet the electricity demand. Since, generators and transmission elements
contribute to reliability in a very different ways, the criteria exempting generators should be different
from the criteria exempting transmission elements.
We do not agree with setting values for this criterion. This should be left to the relevant Transmission
Planner and Planning Coordinator. See our comments in response to Q5a.
We do not agree with setting values for this criterion. This should be left to the relevant Transmission
Planner and Planning Coordinator. See our comments in response to Q5a.
We do not agree with setting values for this criterion. This should be left to the relevant Transmission
Planner and Planning Coordinator. See our comments in response to Q5a.
We do not agree with setting values for this criterion. This should be left to the relevant Transmission
Planner and Planning Coordinator. See our comments in response to Q5a. We suggest that the
exception criteria could include the following checks to be carried out in the course of the TPL analysis
referred to above to ensure system voltage stability for both the pre-contingency period and the
steady state post-contingency period: • Properly converged pre- and post-contingency power flows
are to be obtained with the critical parameter increased up to 10% with typical generation as
applicable; • All of the properly converged cases obtained must represent stable operating points.
This is to be determined for each case by carrying out P-V analysis at all critical buses to verify that
for each bus the operating point demonstrates acceptable margin on the power transfer as shown in
the following section; and • The damping factor must be acceptable (the real part of the eigen values
of the reduced Jacobian matrix are positive).”

No
No
We support the concept of technical analysis in support of Inclusions but disagree with the approach
that involves setting specific values for criteria. Please refer to our comments on exclusions.
[See Comment 7a]
[See Comment 7a]
[See Comment 7a]
[See Comment 7a]
No
We anticipate that entities would be granted access to any required historical operations records and
modeling data after signing of non-disclosure agreements as necessary.
Yes
Similar to the BES Exception Procedure, the document “Technical Principles for Demonstrating BES
Exceptions” must explicitly recognize the authority of Canadian and Mexican Governmental Entities to
adopt the Technical Principles for Demonstrating BES Exceptions in its entirety or in part with their
own deviations, while ensuring there will be no adverse impact on the interconnected transmission
system. Footnote 2 of the “Procedure for Requesting and Receiving an Exception from the Application
of the NERC Definition of Bulk Electric System” should be repeated in the “Technical Principles”
document.
Yes
We hold the view that the path to generating facilities need not be always BES contiguous. Generating
units should be required to meet a subset of NERC Standards, but should not always require
contiguous BES paths. Finally, we reiterate that exception criteria should be crafted at a high-level
with key menu items of assessment that can be followed continent-wide by entities to put forward
their exception for element(s) that are not necessary for the interconnected transmission network and
based on technical assessment, evidence and justification for its unique characteristics, configuration,
and utilization.
Group
MRO's NERC Standards Review Forum
Carol Gerou
No
NSRF believes the relevance and rationale for this criterion is unknown. If this criterion is intended to
exempt elements, like circuit switchers, that are part of the distribution transformer circuits operated
above 100 kV, and located within a mile of the BES interconnection point, then NSRF would expect
the wording to be “in close electric proximity to the BES” rather than in “close electric proximity to
Load”. Otherwise, NSRF requests the SDT explain the relevance and rationale for this criterion before
agreeing on its inclusion.
No
Radial in Character – NSRF proposes that this criterion be eliminated because it does not describe any
materially different characteristics beyond Exclusion E1 of the bright-line BES definition.
No
NSRF proposes that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the bright-line BES definition.
No
NSRF proposes that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the BES definition.
No
NSRF proposes that this technical analysis criterion be replaced by criteria that are more closely tied
to the Adequate Level of Reliability (ALR) characteristics. The following alternate criteria are offered
as possible examples, “(1) the BES can be controlled to stay within acceptable limits following a fault
on or loss of the Element; (2) the BES performs acceptably after credible contingences of the
Element; (3) the Element does not limit the impact and scope of instability and cascading outages

when they occur; (4) BES facilities are protected from unacceptable damage by operating the Element
within its ratings; (5) the integrity of the BES can be restored promptly following a fault on or loss of
the Element; and (6) the BES has the ability to supply the aggregate electric power and energy
requirements of the electricity consumers at all times, taking into account scheduled or reasonably
expected unscheduled outages of the Element. In addition, NSRF is not aware of any continent-wide
appropriate BES performance measures for voltage dip, frequency excursion, voltage deviation,
stability, etc. and NSRF speculates that different values are likely for different regions and system
characteristics across the continent. As a result, NSRF believes it is not advisable to try to adopt
unproven values without reasonable industry investigation and development.
NSRF proposes replacing this factor with those cited above because a distribution factor measurement
indicates how much system changes affect the element, not how much a fault or loss of the element
would compromise the ALR of the BES. There is no clear correlation between this factor and any of
the six characteristics of Adequate Level of Reliability (ALR) of the BES.
NSRF proposes replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable transient voltage dip performance level for evaluating whether a fault or
loss of the element would not compromise the ALR of the BES. In addition, the appropriate
performance level for this factor may vary for different areas and system characteristics across the
continent.
NSRF proposes replacing this factor with those cited above because there are established, continentwide transient frequency performance levels in the PRC-006-1 standard, but the elements that are
applicable to the standard do not have to be BES elements and the transient frequency response
requirements are not intended to be a criterion for BES classification.
NSRF proposes replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable (steady state) voltage deviation performance level for evaluating whether
a fault or loss of the element would not compromise the ALR of the BES. In addition, the appropriate
performance level for this factor may vary for different areas and system characteristics across the
continent.
Yes
A. NSRF recommends this process address the six characteristics of the Definition of Adequate Level
of Reliability (ALR) as listed in the comments above in Question #5. B. Recommend municipalities and
other small entities having transmission systems designed to serve local load, operated below 200 kV
and not having any IROL’s or SOL’s be excluded from the BES definition. Rational: The standards,
especially those for Transmission Operators (TO) aren’t written for the smaller utilities. A utility may
have over 75 MWs of generation and have installed a 115 kV loop around their city that is used
primarily to serve load and get forced into significant compliance requirements that don’t enhance the
reliability of the BES.
No
NSRF proposes that the technical analysis criterion be replaced by criteria that are more closely tied
to the Adequate Level of Reliability (ALR) characteristics. The following alternate criteria are offered
as possible examples, “(1) the BES cannot be controlled to stay within acceptable limits following a
fault on or loss of the Element; (2) the BES does not perform acceptably after credible contingences
of the Element; (3) the Element limits the impact and scope of instability and cascading outages when
they occur; (4) BES facilities are not protected from unacceptable damage by operating the Element
within its ratings; (5) the integrity of the BES cannot be restored promptly following a fault on or loss
of the Element; and (6) the BES does not have the ability to supply the aggregate electric power and
energy requirements of the electricity consumers at all times, taking into account scheduled or
reasonably expected unscheduled outages of the Element. In addition, NSRF is not aware of any
continent-wide appropriate BES performance measures for voltage dip, frequency excursion, voltage
deviation, stability, etc. and NSRF speculates that different values are likely for different regions and
system characteristics across the continent. As a result, NSRF believes it is not advisable to try to
adopt unproven values without reasonable industry investigation and development.
NSRF proposes replacing this factor with those cited above because a distribution factor measurement
indicates how much system changes affect the element, not how a fault or loss of the element would
compromise the ALR of the BES. There is no clear correlation between this factor and any of the six
characteristics of Adequate Level of Reliability (ALR) of the BES.
NSRF proposes replacing this factor with those cited above because there is presently no established,

continent-wide, acceptable transient voltage dip performance level for evaluating whether a fault or
loss of the element would compromise the ALR of the BES. In addition, the appropriate performance
level for this factor may vary for different areas and system characteristics across the continent.
NSRF proposes replacing this factor with those cited above because there are established, continentwide transient frequency performance levels in the PRC-006-1 standard, but the elements that are
applicable to the standard do not have to be BES elements and the transient frequency response
requirements are not intended to be a criterion for BES classification.
NSRF proposes replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable (steady state) voltage deviation performance level for evaluating whether
a fault or loss of the element would compromise the ALR of the BES. In addition, the appropriate
performance level for this factor may vary for different areas and system characteristics across the
continent
No
No
Yes
1. NSRF proposes replacing the wording in the Exclusion preface, Exclusion 2 preface, and Inclusion 1
preface of “not necessary to reliably operate the interconnected transmission network” with
“necessary to maintain an Adequate Level of Reliability (ALR) of the Bulk Electric System”. 2. NSRF
has reservations on the following statement made in the introduction of this document: ” Due to the
importance of Blackstart Resources and their designated blackstart Cranking Paths to restoration
efforts, no exceptions will be allowed for those items.” This does not allow for a provision to exclude
any designated Blackstart Cranking Path (at any voltage) even though there may be technical
justification for it. 3. The first page states that “Specific content of this application is spelled out
elsewhere in this appendix.” NSRF requests the SDT describe where this appendix will be published.
Furthermore, is it a compliance document or just technical “guidance”? 4. Having the following
statement included for both exclusions and inclusions will create disagreement: “The ERO can
override this criterion but would need to provide additional justification to support their finding.” NSRF
believes any override should have adequate technical justification and not interfere with other
statutory requirements. Also, it does not clarify or identify who would make the determination
whether NERC has made adequate justification to override the criterion. 5. NSRF believes that the
“Inclusion” process should be completely removed from BES Definition. We recommend using brightline criteria indentifying everything 100 kV and above to be BES and then allow for the “Exception”
process to take out facilities that do not impact the reliability of the BES. Selecting BES facilities
based on a right-line criteria is what FERC requested in its Order regarding BES Definition. This would
streamline the process and remove some unnecessary paperwork.
Individual
Shane Sweet
Harney Electric Cooperative, Inc.
Yes
I don't have a suggestion for an appropriate impedance.
Yes
Yes
Yes

No

Individual
David Kahly
Kootenai Electric Cooperative
No
We believe that the proximity test may be unnecessary, and if an Element or group of Elements
meets the other three tests proposed by the SDT, it should be excluded from the BES, even if it does
not meet the proximity test. Secondly, using impedance to benchmark system load proximity would
likely not yield clear demarcations. High voltage relative or per-unit impedances are considered
typically much lower than low voltage impedances. Hence, in the absence of phase shifting
transformers, service compensation, or other mitigation factors, power typically flows over the
highest voltage lines, which offer the lowest impedance.
Yes
Kootenai agrees conceptually that systems operating as radials rather than as integrated portions of
the integrated bulk transmission system should be excluded from the BES definition. That is because
local distribution systems typically operate adjacent to, or at the end of transmission lines, and
function operationally to move power from the Transmission Service Provider’s point of delivery of
bulk power that has moved across the integrated bulk transmission system to end-users located
within the local distribution utility’s service territory. To be consistent with the draft BES definition,
the term “radial in character” should be explicitly defined as a system that may include one or more
lines into a load area or referenced as a local distribution network. In addition, we agree that the
manner in which a system is operated during BES disturbances may be an indication of whether that
system is radial in character. That being said, we are concerned that, to the extent the SDT considers
regional disconnect procedures, it should be careful to note that UFLS and UVLS relays are often
embedded within local distribution systems and, while it is necessary for the UFLS and UVLS relays to
be properly armed to protect the BES in the event of a severe system disturbance, the local
distribution system interconnected with those relays should not.
Yes
Kootenai agrees conceptually that one critical characteristic distinguishing local distribution facilities
that must be excluded from the BES from transmission facilities that should be included is the manner
in which power flows on those facilities. Power on local distribution systems generally flows only from
the interconnected transmission source and across the distribution system for delivery to end-use
customers. By contrast, power on transmission systems generally flows in two (or multiple, in
networked systems) directions and is delivered in bulk to distribution utilities rather than to endusers. Hence, the SDT has properly identified power flows as one important characteristic that
distinguishes BES transmission systems from local distribution systems. In order to identify systems
that are not necessary for the operation of the BES under this text, we propose that any system
where real power flows into the local distribution system 90 percent of the time or more under normal
operating conditions.
Yes
Kootenai agrees that the SDT’s fourth test, which asks whether power is intentionally transported
through a system, identifies a key characteristic of local distribution facilities that distinguishes such
facilities from interconnect bulk transmission facilities that are properly considered part of the BES. In
fact, we believe this may be the most important and readily identifiable distinction. Accordingly,
Kootenai agrees that if power is not intentionally transported through a particular system, that

system is not used for transmission and should not be considered part of the BES. One exception may
be for a small embedded generation unit owned by a different party that may be “scheduled” out of
an area, but in reality, does not produce any physical flow. These circumstances should not trigger
inclusion.
Yes
We agree conceptually with the idea that two different paths to exclusion should be adopted, one
relying upon readily identifiable characteristics that are ordinarily associated with local distribution
and not BES transmission facilities, and one relying on technical analysis to determine whether or not
an Element or group of Elements has a measurable impact on the threat of cascading outages,
separation events, or instability on the interconnected bulk system. If technical analysis demonstrates
that Elements create no material threat of such reliability events, they should properly be excluded
from the BES. Kootenai supports the technical arguments and the White Paper presented by
Snohomish County PUD in their comments. We recommend that the SDT modify its approach to the
technical exclusion process to match the approach advocated in the White Paper, which is based upon
the approach recommended by the WECC BES Task Force.
The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage
Transfer Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring
systems. However in the Western Interconnection it has never been a definitive indicator of whether a
system fault with delayed clearing would impact a neighboring electric system. While we understand
that many entities from the Eastern Interconnection support the use of such factors, we believe the
approach is unlikely to work in the Western Interconnection.
Specific transient voltage dip thresholds are proposed at page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element
should produce no more than a 20% voltage drop for no more than 20 cycles in a Category B
contingency and no more than a 20% drop for 40 cycles in a Category C contingency. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of
that Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical
justification for these thresholds is provided at pages 12-16 of the White Paper.
[Please see our response to Question 5d.
No
Yes
As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should
be included only upon a technically valid showing that the Elements contribute substantially to the
potential for cascading outages, separation events, or instability on the interconnection bulk
transmission system. We also agree that the SDT has, in general, identified the correct technical
approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion
analysis) be modified as discussed in the Snohomish PUD White Paper, in the WECC BES Task Force
Proposal 6, and in our answer to Question 5.
See Exclusion comment.
See Exclusion comment.
See Exclusion comment.
See Exclusion comment.
No
As discussed on page 12 of the Snohomish White Paper, there may be a few isolated cases where
additional data will need to be provided to run a valid technical analysis under the criteria set forth in
the Exception Procedure. These cases should be exceedingly rare, however, because the starting
point for the technical analysis we recommend is the current base case operated by the relevant
Regional Entity, and in nearly every case, the base case can be expected to model any Element that
conceivably has a material impact on the reliable operation of the bulk system. In those rare cases
where it does not, we believe the owner or operator of the subject Element should be able to provide
the needed data.

No
As properly constructed Definition and Exceptions process should meet the legal requirements of
Section 215.
Yes
Kootenai generally supports the approach to the exclusion process proposed by the SDT, which
provides two different paths to exclusion, one based on readily-identifiable operational characteristics
of a system, and one based on technical reliability analysis. We believe it is important to provide for
the first path, based on operational characteristics, so that systems that are marginally disqualified
under the BES Definition (because, for example, generation within the system exceeds demand for a
few hours a year) can obtain an exclusion without the large investment of resources that otherwise
might be required for a full-scale technical analysis. That being said, we question whether the first
subsection of the characteristic test, relating to system proximity, is necessary, and we are concerned
that the requirement that a system meet all four requirements of the characteristics test may be
overly restrictive. For example, it is easy to imagine a distribution system in a rural area that covers a
widely dispersed area, so that load is many miles from the relevant generation/transmission source,
and that the system therefore does not meet the electrical proximity element, but meets the other
three elements of the characteristics test. Such a system should be excluded because it clearly serves
a local distribution function, and not a transmission function, as demonstrated by the fact that the
system meets subsections (c) (power flows into the system but rarely flows out ) and (d) (power is
not intentionally transported over the system). Accordingly, we recommend that the SDT consider
eliminating the first test. In the alternative, the SDT should consider allowing exempting a system
from the BES if it, for example, meets three of the four criteria rather than all four.
Group
Southern Company
Antonio Grayson
No
Yes
We agree with the requirement of an element being radial in character as being a qualifier for
exclusion thru the non-technical analysis. However, we recommend tha the term "radial in character"
be better defined. Item ii.: The intent of this item is not clear, and the term "regional dispatch" is not
defined. Recommend the item be clarified.
Yes
No
No
As written, most of this approach makes no sense. The words imply that if you have planned the
system properly, you can exclude it from the BES! In TPL studies you make sure that voltage dips,
frequency excursions, voltage deviations are acceptable, oscillations are damped, and no cascading
outages occur. So if you meet the performance requirements of TPL studies, you can exclude the
element from the BES. What good is this?
This is the only part of this technical analysis that may make sense. If the loss of any element of the
BES results in a distribution factor of less than X% on the element being considered for exclusion,
then exclude it. We suggest a value of 3% for this, since 3% is the threshold typically used in transfer
studies.
As stated above, it does not make sense to use this category.
As stated above, it does not make sense to use this category.
As stated above, it does not make sense to use this category.
Yes
No
Southern Company recommends that applications for inclusion of facilities into the BES should include

justification for doing so. However, there should not necessarily be specific criteria that must be met,
but the importance of the facility to the BES should be clearly demonstrated

No
No
Yes
The Technical Principles document suggests that no exceptions be allowed for Blackstart Resources
and designated Cranking Paths. Southern Company is concerned with the treatment of these facilities
and recommends that certain statements be removed. In Project 2010-17 Definition of the BES,
Southern Company commented that the proposed inclusion, Inclusion I4, be removed from the BES
Definition because an existing NERC Reliability Standard, EOP-005-2 System Restoration from
Blackstart Resources, already addresses these facilities regardless of voltage. Further, the proposed
inclusion will expand the applicability of some NERC Reliability Standards to facilities below 100 kV.
Southern Company believes this position will unnecessarily cause more facilities to become applicable
to reliability standards without any benefit to reliability. Therefore, we recommend the following
statement be deleted: “Due to the importance of Blackstart Resources and their designated blackstart
Cranking Paths to restoration efforts, no exceptions will be allowed for those items.”
Individual
Keith Morisette
Tacoma Power
No
Tacoma Power does not believe that a proximity to Load criteria is useful in BES designation when the
other 3 exclusion criteria of this path are applied. However, if the SDT retains this item, we suggest
an impedance value of < 0.3 ohms on a 100 MVA base.
Yes
Tacoma Power generally agrees that radial elements should be an item in this path and we suggest
that radial element operated at below 300 kV should be excluded from the BES. The 300 kV level is
linked with NERC CIP’s proposed version 4 definition of critical asset and should be applied here with
the BES definition.
Yes
Tacoma Power generally agrees that elements primarily serving load, allowing a limited flow out of
the local distribution network, should be excluded from the BES. We support an annual limitation of
219,000 MWhs, equivalent to 25 aMW, since a system of elements that primarily serve load under
this limit are insignificant to the BES.
Yes
Tacoma Power generally agrees with fourth item (power transport) when not intentionally
transporting power through a system. In development of the supporting evidence for this item, we
suggest a demonstration by operating studies or the option to demonstrate the criteria by the use of
operational procedures.
Yes
Tacoma Power generally agrees with approach used on the technical analysis path for exclusions.
Tacoma Power generally agrees with the distribution factor measurement in the technical analysis
path for exclusions. We suggest adopting a distribution factor not exceeding 30% on an adjacent
system.
Tacoma Power generally agrees with allowable transient voltage dip measurement in the technical
analysis path for exclusions. We suggest adopting an allowable transient voltage dip not exceeding
20% for more than 20 cycles on an adjacent system’s bus.
Tacoma Power generally agrees with the allowable transient frequency response in the technical

analysis path for exclusions. We suggest adopting an allowable transient frequency response of not
below 59.6 Hz for up to 6 cycles on an adjacent system’s bus.
Tacoma Power generally agrees with the voltage deviation measurement in the technical analysis path
for exclusions. We suggest adopting a voltage deviation not exceeding 10% on an adjacent system’s
bus.
No
Tacoma Power is not suggesting any other methods at this time.
Yes
Tacoma Power generally agrees with approach used on the technical analysis path for inclusions.
Tacoma Power generally agrees with the distribution factor measurement in the technical analysis
path for inclusions. We suggest adopting a distribution factor of 30%, or more, on an adjacent
system.
Tacoma Power generally agrees with allowable transient voltage dip measurement in the technical
analysis path for inclusions. We suggest adopting the criteria that includes a transient voltage dip
exceeding 20% for more than 20 cycles on an adjacent system’s bus.
Tacoma Power generally agrees with the allowable transient frequency response in the technical
analysis path for inclusions. We suggest adopting the criteria that includes a transient frequency
response that goes below 59.6 Hz for up to 6 cycles on an adjacent system’s bus.
Tacoma Power generally agrees with the voltage deviation measurement in the technical analysis path
for inclusions. We suggest adopting a voltage deviation that exceeds 10% on an adjacent system’s
bus. We have an additional concern with how the language is constructed on items d. and e. The
inclusion criteria may work for simply inverting the exclusion language but in this initial draft, it does
not appear to work as intended. Our suggestions above are describing criteria for defining elements
that can be included in the BES. If that is the result to be adopted by the SDT, items d. and e. must
be rewritten to state that elements within such criteria can be included in the BES.
No
Tacoma Power has no comment at this time.
No
Tacoma Power is not aware of any conflicts at this time.
Yes
Tacoma Power supports the SDT’s efforts to create an acceptable BES definition directly linked to an
exception process. We do have a concerned about the application of the standards to Elements that
change status due to the Exception process. Any Elements that are determined to be newly included
in the BES should have a 24-month period before the standards will apply as a BES Elements.
Conversely, a determination that removes an Element from the BES should apply as soon as
practicable. Please be aware that the WECC has a task force, the Bulk Electric System Definition Task
Force(BESDTF), which has done some notable work on this task. See WECC BESDTF Proposal 6,
Appendix C (http://www.wecc.biz/Standards/Development /BES/default.aspx). The BES definition is
very complex and the BESDTF has already addressed many of the tough issues that have yet to be
addressed in this process, such as: • Local Distribution Network definition for automatic exemption •
Determination of radial facilities • Demarcation of BES and non-BES Elements • Alternate dispute
resolution process • Assignment of the burden of proof for the exemption process • Technical
approach for the inclusion/exclusion determination Thank you for consideration of our comments.
Individual
Terry Harbour
MidAmerican Energy
No
MidAmerican agrees with the NSRF. The NSRF believes the relevance and rationale for this criterion is
unknown. If this criterion is intended to exempt elements, like circuit switchers, that are part of the
distribution transformer circuits operated above 100 kV, and located within a mile of the BES
interconnection point, then NSRF would expect the wording to be “in close electric proximity to the
BES” rather than in “close electric proximity to Load”. Otherwise, NSRF requests the SDT explain the
relevance and rationale for this criterion before agreeing on its inclusion.
No

MidAmerican supports the NSRF comments. The NSRF proposes that this criterion be eliminated
because it does not describe any materially different characteristics beyond Exclusion E1 of the
bright-line BES definition. If not eliminated, the IEEE definition of a radial system should be used.
No
MidAmerican supports the NSRF comments. The NSRF proposes that this criterion be eliminated
because it does not describe any materially different characteristics beyond Exclusion E3 of the
bright-line BES definition.
No
MidAmerican support the NSRF comments. The NSRF proposes that this criterion be eliminated
because it does not describe any materially different characteristics beyond Exclusion E3 of the BES
definition.
Yes
The concept of using TPL analyses and normalized Transmission Distribution Factors makes basic
sense as a way to determine what elements react to system transfers and what elements react
primarily to distribution load. In general all facilities below 100 kV should be exlcuded by default as
distribution according to the 2005 Federal Power Act. Transmission Distribution Factors tend to show
low bulk power system transfers (less than 2%) based on their inherent high impedance when
normalized. Normalizing the transmission impedance means diving the ohmic value by a base
impedance which is dominated by a (kV^2) term. Per Unit Impedance = (transmission line ohms /
base impedance) where base impedance = (kV^2 / MVA). Using a common MVA base value of 100
MVA, a base impedance at 69kV = 47.6 ohms versus at 161 kV = 259.2 or at 345 kV = 1190.2 ohms.
The rapid increase of the denominator as kV goes higher insures that a 69 kV system is high
impedance compared to any high kV facilities and therefore nearly insure the 69 kV system is local in
nature and reacts primarily to load. Therefore it is distribution. This all supports the conclusion that all
facilites below 100 kV should be classified as distribution according to the 2005 FPA and exempted by
default. Facilities below 100 kV could be brought into scope if TPL analyses show instability,
uncontrolled separation, or cascading as defined in the 2005 FPA.
The Distribution Factor measurement is acceptable and should exclude facilities that show a low
distribution factor for bulk power system transfers. An arbitrary low value could be those facilities that
show less than a 2% distribution factor.
There isn't a nation wide transient voltage dip measurement.
There isn't a nation wide transient frequency response
Determining a nation wide voltage deviation would be difficult.
Yes
In general all facilities below 100 kV should be exlcuded by default as distribution according to the
2005 Federal Power Act. Transmission Distribution Factors tend to show low bulk power system
transfers (less than 2%) based on their inherent high impedance when normalized. Normalizing the
transmission impedance means diving the ohmic value by a base impedance which is dominated by a
(kV^2) term. Per Unit Impedance = (transmission line ohms / base impedance) where base
impedance = (kV^2 / MVA). Using a common MVA base value of 100 MVA, a base impedance at 69kV
= 47.6 ohms versus at 161 kV = 259.2 or at 345 kV = 1190.2 ohms. The rapid increase of the
denominator as kV goes higher insures that a 69 kV system is high impedance compared to any high
kV facilities and therefore nearly insure the 69 kV system is local in nature and reacts primarily to
load. Therefore it is distribution. This all supports the conclusion that all facilites below 100 kV should
be classified as distribution according to the 2005 FPA and exempted by default. Facilities below 100
kV could be brought into scope if TPL analyses show instability, uncontrolled separation, or cascading
as defined in the 2005 FPA.
No

No

No
Yes
MidAmerican supports the NSRF comments.
Group
Bonneville Power Administration
Denise Koehn
Yes
BPA suggests that correlation between the size of the Load and the size of an element is needed. BPA
would like the word “close” in the description “close electric proximity to load” to be better defined.
For example, a line that carries 600 MWs in close electrical proximity to a 20-MW Load may not meet
the intent of this characteristic. In planning models, loads are often aggregated to a higher voltage
while, in a distribution system model, the loads are explicitly represented along the distribution
feeder. Because of this, the criteria should define where the load is located/represented for the
measure of electrical proximity.
No
BPA requests clarification on what the SDT considers radial through additional examples of i “the way
the connections to the BES are operated” and ii “the way the Element(s) are treated in operations.”
BPA emphasizes that this assessment should be conducted using normal system operations.
Yes
BPA generally agrees with the power flow concept, but suggests including language that the
assessment should be “based on normal system operating conditions.” A MWh value to replace ‘TBD’
for maximum energy flowing out per year could be determined based on on an annual average MW
load level of 25 MW average and below with distribution service of 50MVA and below, because 25MW
loads can be served by lines under 100kv. The energy flowing out per year would be limited by the
size of the load and the ability to import power to the load area (i.e. the export would never be larger
than the initial distribution service minus the local area losses and load). BPA requests that the
drafting team perform a cross-walk analysis on each of the 4 items to ensure the consistent
application of an existing industry process, practice, or standard.
Yes
BPA suggests that the SDT provide a method for assessing power transport based on intake to serve
load versus outflow. BPA requests that the SDT clarify that the qualifying statements i-v for the fourth
item are “or” statements.
BPA comments on the technical analysis are as follows: 1. Who is responsible for running these
studies (the BA, individual utilities….?). 2. The analysis and criteria need to be better defined for the
technical analysis. 3. What did SDT mean by “having a distribution factor of TBD% for any other
Element”? This should probably reference a specific PTDF for a path or source/sink group. 4. What
contingencies are studied to show the elements meet the transient voltage dip, frequency excursion,
etc. (i.e. are they 3 phase delayed cleared faults, single phase faults, etc.)? Furthermore, the
exclusion criteria needs to be much more specific about how the study is to be conducted in general –
i.e.: Regional Entities have established study guidelines and procedures to determine voltage and
frequency criteria. Specifically, is it the intent that the element being proposed for exclusion be
opened in the study and then the standard contingency list applied to the rest of the system?
Presumably, if there is no difference in system performance with the element in or out, then it could
be excluded. Alternatively, is it intended that the contingency to be tested is simply the loss of the
element proposed for exclusion? 5. What elements and/or flow gates should be monitored for these
analyses? 6. In “Other”, the SDT should add “The limiting element for a flow-gate cannot be excluded
from the BES”. 7. How will the criteria be set? Will they follow current standards? (i.e. TPL-001)? The
technical principles must identify what category(ies) of TPL studies must be run. BPA requests
clarification on what the values for the threshold criteria and/or disturbances would be?

No
BPA emphasizes that exclusion criteria and analysis should be based on normal operations. An
exclusion should not be unavailable based on temporary system configuration such as load service by
a different transmission segment temporarily used to mitigate system operations due to planned
maintenance outages, i.e. a system that is operated radially over 90% of the time and closed for
maintenance outages for safety and/or reliability purposes, etc. BPA recommends that the SDT
consider not only the single-phase faults, also the effect of more severe events such as two- or threephase faults, with delayed clearing and evaluate the necessity of the element in those cases.
No
Please refer to BPA’s comments on Question #5.

No
The owner of the asset should have all the data necessary to perform the analysis for an Exclusion.
The Exclusion analysis should use the same data request and sharing requirements of other NERC
standards and the owner conducting the Exclusion analysis should consult with other entities as
necessary.
No
Under NERC Standard IRO-010, the Transmission Operators are required to obtain information
relating to the operation of the bulk power system within their respective areas. Transmission
Operators may still need information relating to network facilities that ultimately are determined not
to be BES facilities. BPA is concerned that an exclusion could eliminate a requirement that such
information be provided.
No

Comment Form for 1st Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions – City of Redding Paul Cummings
Please DO NOT use this form. Please use the electronic comment form to submit
comments on the first draft of the Project 2010-17: Definition of the Bulk Electric System
(BES) Technical Principles for Demonstrating BES Exceptions. Only submit comments on
the first draft Technical Principles for Demonstrating BES Exceptions. The comments must
be submitted by June 10, 2011.
If you have questions please contact Ed Dobrowolski at ed.dobrowolski@nerc.net or by
telephone at 609-947-3673.

Background Information
Definition of the BES (Project 2010-17)
In parallel with the definition project, another stakeholder team outside the standards
development process has been set up to develop a change to the NERC Rules of Procedure
(ROP) to allow for entities to apply for excluding Elements from the BES that might
otherwise be included according to the proposed definition and designations. This same
process would be used by Registered Entities to justify including Elements in the BES that
might otherwise be excluded according to the proposed definition and designations. This
process would also be utilized for those situations where the core definition and
designations do not clearly identify whether an Element is BES or not. The ROP team will
develop the process for seeking an exception from the definition and designations, but the
Definition of the BES Standards Drafting Team (DBESSDT), through the standards
development process, has developed the criteria necessary for applying for an exception.
The exclusion exception process has been set up as a choice between two alternative forms
of evidence. The first choice is seen as less onerous in nature as it does not require
extensive technical analysis. An entity must choose which path it wants to pursue.
The inclusion exception process requires more detailed analysis and only one choice is
provided.
The first draft of the criteria that has been posted contains the evidence that must be
presented by an entity seeking an exception as well as specific criteria for how that
evidence will be evaluated. The SDT is seeking industry feedback not just on the approach
being presented but also on the specific numeric thresholds that will be used. Comments
received from this posting will help to determine the final criteria that the industry will be
required to adhere to. Therefore, industry feedback is vital to the development process.
It should be noted that the actual application process is described in the Rules of Procedure
document that has been posted concurrent with the criteria document.

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Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com

Comment Form for 1st Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions
You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. The first item involves proximity to Load and
requests industry feedback on how to measure this variable. Do you agree with this
requirement? If you do not support this requirement or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. In addition, in the comment field, please provide your
thoughts on the appropriate impedance value to replace ‘TBD,’ including technical
rationale for your argument.
Yes:
No: x
Comments: This could serve as one characteristic of a distribution system and is
generally a good indicator that the facilities have been installed and are operating to
serve a distinct geographical area (the end user). The intent should be changed to
indicate it is geographical and not electrical. The electrical reference should be removed
from this section and moved to the engineering section.
2. Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. The second item involves Element(s) treated
as radial. Do you agree with this requirement? If you do not support this requirement
or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments.
Yes: x
No:
Comments: The term Radial could cause confusion. Clarification needs to be added to
indicate that the system can have more than one connection to the BES.
3. Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. The third item involves power flow. Do you
agree with this requirement? If you do not support this requirement or you agree in
general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments. In addition, in the comment field, please
provide your thoughts on the appropriate MWh value to replace ‘TBD,’ including
technical rationale for your argument.
Yes: x
No:

Page 2 of 5

Comment Form for 1st Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions
Comments: To be consistent with E2 of the proposed BES Definition a distribution
system should be allowed to export at least 75 mw. This would be the same as a
commercial retail customer can export into the distribution system.
4. Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. The fourth item involves power transport. Do
you agree with this requirement? If you do not support this requirement or you agree in
general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.
Yes: x
No:
Comments: The SDT needs to address renewable energy and customer owned
generation. If an aggregator adds up one thousand roof top PV units or the power from
plugged in electric cars and sells them to an entity outside of this system it should not
affect the ability of the distribution system to qualify for this exclusion, especially if the
power is consumed inside of the distribution system.
5. Exclusions - The SDT has set up one path for evidence that includes technical analysis.
Do you agree with this requirement? If you do not support this requirement or you
agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. In addition, in the comment field,
please provide your thoughts on the proposed metrics for analysis and the appropriate
values to replace ‘TBD,’ including technical rationale for your argument.
Yes: x
No:
5a. Comments on approach: It appears the industry experts have a very difficult time
identifying any set of measurement factors that can be applied on a consistant basis to
any system and produce similar results, therefore there needs to be geographical
variation where the experts in the local systems can make a determination.
5b.Comments on distribution factor measurement:
5c. Comments on allowable transient voltage dip measurement:
5d. Comments on allowable transient frequency response:
5e. Comments on voltage deviation measurement:
6. Exclusions – Do you have other methods that may be appropriate for proving an
exclusion claim? Or, other variables/measurements that may be added to the
requirements already shown in the posted Technical Principles for Demonstrating BES
Exceptions? If so, please provide your comments here with technical rationale for why
they should be considered.
Yes:
No: x

Page 3 of 5

Comment Form for 1st Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions

Comments:
7. Inclusions - The SDT has set up only one path for evidence that includes technical
analysis. Do you agree with this requirement? If you do not support this requirement or
you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. In addition, in the comment
field, please provide your thoughts on the proposed metrics for analysis and the
appropriate values to replace ‘TBD,’ including technical rationale for your argument.
Yes: x
No:
7a. Comments on approach:
7b. Comments on distribution factor measurement:
7c. Comments on allowable transient voltage dip measurement:
7d. Comments on allowable transient frequency response:
7e. Comments on voltage deviation measurement:
8. Do you have concerns about an entity’s ability to obtain the data they would need to do
the indicated technical analyses? If so, please be specific with your concerns so that the
SDT can fully understand the problem and address it in future drafts.
Yes:
No: x
Comments:
9. Are you aware of any conflicts between the proposed approach and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement, or
jurisdictional issue? If so, please identify them here and provide suggested language
changes that may clarify the issue.
Yes: x
No:
Comments: State and court rulings that have defined Transmission and Distribution.
One possible solution is to state that the determination made via this methodology is for
reliability purposes only and is not intended to redefine established market and rate
determinations.
10. Are there any other concerns with this approach that haven’t been covered in previous
questions and comments? Please be as specific as possible with your comments.
Yes: x
No:

Page 4 of 5

Comment Form for 1st Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions
Comments: The SDT is encouraged to address generators installed as load modifiers to
distribution load.>>>> As additional evidence of distribution line, if there is not an OATT
filed on a line then it is not transmission per FERC rules.

Page 5 of 5

Consideration of Comments on Definition of the Bulk Electric System (BES)
Technical Principles for Demonstrating BES Exceptions — Project 2010-17
The Bulk Electric System (BES) Drafting Team thanks all commenters who submitted
comments on the first draft of the Project 2010-17: Definition of the Bulk Electric System
(BES) Technical Principles for Demonstrating BES Exceptions. These standards were posted
for a 30-day public comment period from May 11, 2011 through June 10, 2011. The
stakeholders were asked to provide feedback on the standards through a special Electronic
Comment Form. There were 91 sets of comments, including comments from approximately
182 different people from approximately 124 companies representing all 10 Industry
Segments as shown in the table on the following pages.

http://www.nerc.com/filez/standards/Project2010-17_BES.html
Based on industry response and further analysis, the SDT has abandoned the initial
exclusion criteria and developed a new methodology is intended to clarify the technical and
operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on
a comparison of an entity’s characteristics to a defined value and/or limit. It has become
apparent that it is not feasible to establish continent-wide values and/or limits due to
differences in operational characteristics. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as
appropriate through submittal of an exception request form along with any other supporting
documentation for the exception being sought. The appropriate Regional Entity will review
the submittal to validate information, make a recommendation of whether or not to support
the exclusion or inclusion, and then file the request and recommendation with the ERO as
established in the Rules of Procedure as presently being drafted.
The SDT is recommending that the project be moved to a parallel 45-day posting and ballot.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 404-443-2560 or at herb.schrayshuen@nerc.net. In addition, there is
a NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical
Principles for Demonstrating BES Exceptions — Project 2010-17

Index to Questions, Comments, and Responses
1.

Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. ............................................................ 14

2.

Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. ............................................................ 31

3.

Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. ............................................................ 44

4.

Exclusions - The SDT has set up one path for evidence that does not include extensive
technical analysis. It consists of 4 items, all of which must be addressed in order to
submit a completed request for exclusion. ............................................................ 58

5.

Exclusions - The SDT has set up one path for evidence that includes technical analysis.
Do you agree with this requirement? .................................................................... 70
5a.

Comments on approach .............................................................................. 76

5b.

Comments on distribution factor measurement .............................................. 90

5c.

Comments on allowable transient voltage dip measurement ............................ 97

5d.

Comments on allowable transient frequency response .................................. 103

5e.

Comments on voltage deviation measurement ............................................. 108

6.

Exclusions – Do you have other methods that may be appropriate for proving an
exclusion claim? Or, other variables/measurements that may be added to the
requirements already shown in the posted Technical Principles for Demonstrating BES
Exceptions? .................................................................................................... 114

7.

Inclusions - The SDT has set up only one path for evidence that includes technical
analysis. Do you agree with this requirement?. ................................................... 126
7a.

Comments on approach ............................................................................ 133

7b.

Comments on distribution factor measurement ............................................ 142

7c.

Comments on allowable transient voltage dip measurement .......................... 147

7d.

Comments on allowable transient frequency response .................................. 151

7e.

Comments on voltage deviation measurement ............................................. 155

8.

Do you have concerns about an entity’s ability to obtain the data they would need to do
the indicated technical analyses?. ...................................................................... 159

9.

Are you aware of any conflicts between the proposed approach and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement, or
jurisdictional issue?.......................................................................................... 167

10. Are there any other concerns with this approach that haven’t been covered in previous
questions and comments? Please be as specific as possible with your comments. .... 177

2

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Connie Lowe

Electric Market Policy

X

2

3

X

4

5

X

6

7

8

9

10

X

Additional Member Additional Organization Region Segment Selection
1. Mike Crowley

SERC

1, 3, 5

2. Mike Garton

MRO

5

3. Louis Slade

RFC

5, 6

4. Michael Gildea

NPCC

5

2.

Group
Additional Member

Guy Zito

Northeast Power Coordinating Council
Additional Organization

Region Segment Selection

1. Alan Adamson

New York State Reliability Council, LLC

NPCC 10

2. Gregory Campoli

New York Independent System Operator

NPCC 2

3. Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC 3

4. Sylvain Clermont

Hydro-Quebec TransEnergie

5. Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC 1

6. Gerry Dunbar

Northeast Power Coordinating Council

7. Brian Evans-Mongeon Utility Services

X

NPCC 1
NPCC 10
NPCC 8

3

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

8. Mike Garton

Dominion Resources Services, Inc.

NPCC 5

9. Kathleen Goodman

ISO - New England

NPCC 2

10. Chantel Haswell

FPL Group, Inc.

NPCC 5

11. Brian Gooder

Ontario Power Generation Incorporated

NPCC 5

12. David Kiguel

Hydro One Networks Inc.

NPCC 1

13. Michael Lombardi

Northeast Utilities

NPCC 1

14. Randy MacDonald

New Brunswick Power Transmission

NPCC 1

15. Bruce Metruck

New York Power Authority

NPCC 6

16. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

17. Robert Pellegrini

The United Illuminating Company

NPCC 1

18. Si Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

19. Saurabh Saksena

National Grid

NPCC 1

20. Michael Schiavone

National Grid

NPCC 1

21. Wayne Sipperly

New York Power Authority

NPCC 5

22. Donald Weaver

New Brunswick System Operator

NPCC 1

23. Ben Wu

Orange and Rockland Utilities

NPCC 1

3.

Group

Charles W. Long

Additional Member

SERC Planning Standards Subcommittee

Additional Organization
Entergy Services, Inc.

SERC

1

2. Darrin Church

Tennesee Valley Authority

SERC

1

3. John Sullivan

Ameren Services Co.

SERC

1

4. James Manning

North Carolina Electric Cooperatives SERC

1

5. Bob Jones

Southern Company Services

SERC

1

6. Phil Kleckley

South Carolina Electric &Gas Co.

SERC

1

7. Pat Huntley

SERC

SERC

NA

Group
Additional Member

1. Clem Cassmeyer

Robert Rhodes

X

3

4

5

6

7

8

9

10

X

Region Segment Selection

1. Charles W. Long

4.

2

SPP Standards Review Group

Additional Organization
Western Farmers Electric Cooperative

X

Region Segment Selection
SPP

1, 3, 5

4

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2. John Mason

Independence Power & Light

SPP

1, 3, 5

3. John Kerr

Southwest Power Pool

SPP

2

4. Matthew Bordelon

CLECO

SPP

1, 3, 5

5. Michelle Corley

CLECO

SPP

1, 3, 5

6. Ron Gunderson

Nebraska Public Power District

MRO

1, 3, 5

7. Jonathan Hayes

SPP

SPP

2

8. Sean Simpson

Board of Publlic Utilities, City of McPherson SPP

1, 3, 5

9. Tom Hestermann

Sunflower Electric

SPP

1, 3, 5

10. Tony Eddleman

Nebraska Public Power District

MRO

1, 3, 5

11. Valerie Pinamonti
12. Doug Callison

American Electric Power
Grand River Dam Authority

SPP
SPP

1, 3, 5
1, 3, 5

13. Sean Simpson
14. Tom Hestermann

Board of Public Utilities, City of McPherson SPP
Sunflower Electric
SPP

1, 3, 5
1, 3, 5

5.

Group

David Taylor

2

3

4

5

6

7

8

9

10

NERC Staff Technical Review

No additional members listed.
6.

Group

Mark Gray

Edison Electric Institute

http://www.eei.org/whoweare/ourmembers/USElectricCompanies/Pages/USMemberCoLinks.aspx
7.

Group

Frank Gaffney

Florida Municipal Power Agency

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Tim Beyrle

City of New Smyrna Beach FRCC

4

2. Jim Howard

Lakeland Electric

FRCC

3

3. Cairo Vanegas

Fort Pierce Utility Authority FRCC

4

4. Lynne Mila

City of Clewiston

FRCC

3

5. Joe Stonecipher

Beaches Energy Services FRCC

1

5

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

6. Randy Hahn

Ocala Electric Utility

FRCC

3

7. Greg Woessner

Kissimmee Utility Authority FRCC

3

Group

8.

Cynthia S. Bogorad

Transmission Access Policy Study Group

2

X

3

X

4

X

5

6

X

X

X

X

7

8

9

10

No additional members listed.
Group

9.

Albert DiCaprio

ISO/RTO Standards Review Committee

X

Additional Member Additional Organization Region Segment Selection
1. Terry Bilke

MISO

RFC

2

2. Patrick Brown

PJM

RFC

2

3. Greg Campoli

NY ISO

NPCC

2

4. Kurtis Chong

IESO

NPCC

2

5. Ben Li

IESO

NPCC

2

6. Steve Myers

ERCOT

ERCOT 2

7. Bill Phillips

MISO

RFC

2

8. Don Weaver

NBSO

NPCC

2

9. Mark Westendorf

MISO

RFC

2

10. Charles Yeung

SPP

SPP

2

10.

Group

Additional Member

John Allen
Additional Organization

Iberdrola USA
Region Segment Selection

1. Raymond Kinney

New York State Electric & Gas NPCC 1

2. Kevin Howes

Central Maine Power

11.

Group

Additional Member
1. Bill Middaugh

Mark Conner

X

NPCC 1

Tri-State Generation and Transmission
Association

Additional Organization

X

X

Region Segment Selection

Tri-State Generation and Transmission Association WECC 1, 3, 5, 6

6

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

12.

Group

David Curtis

Hydro One

X

2

3

4

5

6

X

7

8

9

10

X

Additional Member Additional Organization Region Segment Selection
1. Ajay Garg

Transmission

NPCC

1

2. David Kiguel

Distribution

NPCC

2

3. Oded Hubert

Regulatory Affairs

NPCC

9

13.

Group
Additional Member

Carol Gerou

MRO's NERC Standards Review Forum

Additional Organization

Region Segment Selection

1. Mahmood Safi

Omaha Public Utility District

MRO

1, 3, 5, 6

2. Chuck Lawrence

American Transmission Company

MRO

1

3. Tom Webb

Wisconsin Public Service Corporation MRO

3, 4, 5, 6

4. Jodi Jenson

Western Area Power Administration

MRO

1, 6

5. Ken Goldsmith

Alliant Energy

MRO

4

6. Alice Ireland

Xcel Energy

MRO

1, 3, 5, 6

7. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

8. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

9. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

10. Scott Nickels

Rochester Public Utilties

MRO

4

11. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

12. Marie Knox

Midwest ISO Inc.

MRO

2

13. Lee Kittelson

Otter Tail Power Company

MRO

1, 3, 4, 5

14. Scott Bos

Muscatine Power and Water

MRO

1, 3, 5, 6

15. Tony Eddleman

Nebraska Public Power District

MRO

1, 3, 5

16. Mike Brytowski

Great River Energy

MRO

1, 3, 5, 6

17. Richard Burt

Minnkota Power Cooperative, Inc.

MRO

1, 3, 5, 6

14.

Group
Additional Member

1. Steve Larson

Denise Koehn

Bonneville Power Administration

Additional Organization
BPA, Legal Department

X

X

X

X

X

Region Segment Selection
WECC 1, 3, 5, 6

7

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2. Rebecca Berdahl

BPA, Power Services, Long Term Sales and Purchases WECC 3

3. Erika Doot

BPA, Power Services, Generation Support

WECC 3, 5, 6

4. Sara Sundborg

BPA, Transmission Technical Operations

WECC 1

5. Lorissa Jones

BPA, Transmission Reliability Program

WECC 1

6. Fran Halpin

BPA, Power Services, Duty Scheduling

WECC 5

15.

Individual

Sandra Shaffer

PacifiCorp

16.

Individual

Jim Uhrin

ReliabilityFirst

17.

Individual

Richard Dearman

Tennessee Valley Authority

18.

Individual

Richard Malloy

Idaho Falls Power

19.

Individual

Michelle Mizumori

Western Electricity Coordinating Council

20.

Individual

John Cummings

PPL Supply

21.

Individual

Roger Clayton

New York State Reliability Council

Individual

John P. Hughes

Electricity Consumers Resource Council
(ELCON)

X

23.

Individual

Randy D. Crissman

New York Power Authority

X

24.

Individual

John Free

Alabama Public Service Commission

25.

Individual

Antonio Grayson

Southern Company

X

26.

Individual

Michael Moltane

ITC

X

22.

X

2

3

X

4

5

X

6

7

8

9

10

X
X

X

X

X

X

X
X

X
X

X

X

X

X

X

X
X
X

8

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

27.

Individual

Michael Jones

National Grid

X

X

28.

Individual

Scott Bos

Muscatine Power and Water

X

X

29.

Individual

Bud Tracy

Blachly Lane Electric Cooperative

30.

Individual

RoLynda Shumpert

South Carolina Electric and Gas

31.

Individual

Josh Dellinger

Glacier Electric Cooperative

Individual

Diane Barney

New York State Department of Public
Service

33.

Individual

John Bee

Exelon

X

34.

Individual

Bob Casey

Georgia Transmission Corporation

X

35.

Individual

Chris de Graffenried

Consolidated Edison Co. of NY, Inc.

X

36.

Individual

Tracy Richardson

Springfield Utility Board

37.

Individual

John Pearson

ISO New England

38.

Individual

Jonathan Appelbaum

The United Illuminating Company

39.

Individual

Neil Phinney

Georgia System Operations Corporation

X

40.

Individual

Michelle R DAntuono

Occidental Energy Ventures Corp.

X

41.

Individual

Russ Schneider

Flathead Electric Cooperative, Inc.

X

32.

4

5

6

X

X

X

X

7

8

9

10

X
X

X

X
X

X

X

X

X

X
X
X

X

X

X

X

9

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

42.

Individual

Ed Davis

Entergy Services

X

X

43.

Individual

Jack Stamper

Clark Public Utilities

X

44.

Individual

Dave Markham

Central Electric Cooperative

X

45.

Individual

Dave Hagen

Clearwater Power Electric Cooperative

X

46.

Individual

Roman Gillen

Consumer's Power Inc.

X

47.

Individual

Roger Meader

Coos-Curry Electric Cooperative

X

48.

Individual

Dave Sabala

Douglas Electric Cooperative

X

49.

Individual

Bryan Case

Fall River Electric Cooperative

X

50.

Individual

Rick Crinklaw

Lane Electric Cooperative

X

51.

Individual

Michael Henry

Lincoln Electric Cooperative

X

52.

Individual

Richard Reynolds

Lost River Electric Cooperative

X

53.

Individual

Annie Terracciano

Northern Lights Electric Cooperative

X

54.

Individual

Doug Adams

Okanogan Electric Cooperative

X

55.

Individual

Heber Carpenter

Raft River Rural Electric Cooperative

X

56.

Individual

Ken Dizes

Salmon River Electric Cooperative

X

4

5

X

6

7

8

9

10

X

10

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

57.

Individual

Steve Eldrige

Umatilla Electric Cooperative

X

58.

Individual

Marc Farmer

West Oregon Electric Cooperative

X

59.

Individual

Rick Paschall

Pacific Northwest Generating Cooperative

X

60.

Individual

Aleka Scott

PNGC Power

61.

Individual

Stuart Sloan

Consumer's Power Inc.

X

62.

Individual

Bill Keagle

BGE

X

63.

Individual

Rick

Spyker

X

64.

Individual

Clint Gerkensmeyer

Benton Rural Electric Association

65.

Individual

Robert Ganley

Long Island Power Authority

X

66.

Individual

Thad Ness

American Electric Power

X

X

67.

Individual

David Burke

Orange and Rockland Utilities, Inc.

X

X

68.

Individual

David Thorne

Pepco Holdings Inc

X

X

69.

Individual

Paul Titus

Northern Wasco County PUD

X

X

70.

Individual

Alice Ireland

Xcel Energy

X

X

71.

Individual

Jianmei Chai

Consumers Energy Company

4

5

6

7

8

9

10

X

X

X

X

X

X

X

X

X

11

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

72.

Individual

Jo Elg

United Electric Co-op Inc.

73.

Individual

Ned Ratterman

Oregon Trail Electric Cooperative, Inc.

74.

Individual

Steve Alexanderson

Central Lincoln

75.

Individual

Darryl Curtis

Oncor Electric Delivery

76.

Individual

Jerome Murray

Oregon Public Utility Commission Staff

77.

Individual

Anthony Schacher

Salem Electric

78.

Individual

Laura Lee

Duke Energy

X

X

79.

Individual

Bill Dearing

Grant County PUD No. 2 (Grant)

X

X

X

X

80.

Individual

Si Truc PHAN

Hydro-Quebec TransEnergie

X

81.

Individual

Eric Lee Christensen

for Snohomish County PUD

X

X

X

X

Individual

Bill Dearing

Northwest Public Power Association
(NWPPA)

X

X

X

83.

Individual

Ben Friederichs

Big Bend Electric Cooperative, Inc.

84.

Individual

Andrew Z Pusztai

American Transmission Company, LLC

X

85.

Individual

Joe Petaski

Manitoba Hydro

X

86.

Individual

Heather Hunt

NESCOE

82.

6

7

8

9

10

X
X

X
X

X

X

X
X
X
X

X

X

X

X

X
X

12

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

87.

Individual

Michael Falvo

Independent Electricity System Operator

88.

Individual

Shane Sweet

Harney Electric Cooperative, Inc.

X

89.

Individual

David Kahly

Kootenai Electric Cooperative

X

90.

Individual

Keith Morisette

Tacoma Power

X

91.

Individual

Terry Harbour

MidAmerican Energy

X

4

5

6

7

8

9

10

X

X

X

X

X

13

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

1. Exclusions - The SDT has set up one path for evidence that does not include extensive technical
analysis. It consists of 4 items, all of which must be addressed in order to submit a completed
request for exclusion. The first item involves proximity to Load and requests industry feedback on
how to measure this variable. Do you agree with this requirement? If you do not support this
requirement or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. In addition, in the comment field, please
provide your thoughts on the appropriate impedance value to replace ‘TBD,’ including technical
rationale for your argument.
Summary Consideration: A vast majority of the commenters disagreed with, or had significant questions about the validity
of using electrical proximity as a metric to reflect the importance of an element or group of elements to the operation of an
interconnected transmission network. Commenters pointed out that the proximity, electrical or otherwise, of an element to
Load is not a reliable basis to determine functionality of an element, nor its impact upon the interconnected network.
Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new
methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a
comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to
establish values and/or limits that would be valid across all regions and systems. The new process requires an entity to clarify
the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of
an exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization
Northeast Power Coordinating
Council

Yes or No
No

Question 1 Comment
1.a.i. Electrical Proximity - If impedance is to be used as a measure of electrical proximity, which in turn is a
replacement for geographical proximity, then how would the presence of parallel lines, capacitors, phaseangle regulators (PARs), tap-changing transformers, generation and reactors be treated in determining
electrical proximity?
How does this approach effectively differentiate between transmission and distribution lines of the same
voltage and length?

14

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment
When using impedance, how is “greater than” determined?
Sum of the Impedances - Would the filing entity simply add up the in-series impedances for each radial
Element to demonstrate its electrical proximity? For example, would the sum of the impedances from this
radial path example be equal to the sum of the two feeder and transformer impedances, i.e., measured from a
230 kV bus along a 230 kV feeder, through a 230/138 kV step-down transformer, and an in-series 138 kV
feeder to a 138/13.8 kV step-down distribution transformer? What impedance would the SDT apply to a PAR
(or tap-changing transformer) and to the overall path if a PAR (or tap-changing transformer) were located inseries with the measured Elements?
1.a.ii. Power Flows - What is the meaning of “power flow data” as the term is used here and how is the
meaning different from the term when used under 1.c. Power flows into the system, but rarely flows out?
Should this sentence use the phrase “impedance data extracted from a load flow study” instead?
Entities should be required to identify the significance of the element’s physical characteristics. Such
identification can be done through a simple checklist along with any relevant comments.
The SDT should revise the exception criteria to seek an alternative language and/or revise exclusion criteria
(a), which will require entities to provide the previously stated information for their element.

SERC Planning Standards
Subcommittee

No

The PSS disagrees with the assumption that the proximity of a BES facility to Load is indicative of it's
importance to BES reliability. Some lower voltage facilities can be quite short and thus have lower impedance
but be important to BES reliability. Furthermore, the term "Load centers" is not defined leaving it subject to
interpretation. Assuming a load center has many busses, where would the measurement be made - From the
most distant load bus in the load center or the nearest? Similarly - does a single facility get measured from
it's terminal to the load center or does the presence or lack of breakers need to be considered when selecting
the measurement point?

SPP Standards Review Group

No

Physical characteristics as described in 1.a.i. do not capture the true picture of the functionality of an Element.
Rather than use impedance perhaps the SDT should use ‘radial’ or ‘having one source’ as the descriptive
term.

City of Redding

This could serve as one characteristic of a distribution system and is generally a good indicator that the
facilities have been installed and are operating to serve a distinct geographical area (the end user). The intent
should be changed to indicate it is geographical and not electrical. The electrical reference should be
removed from this section and moved to the engineering section.

15

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

NERC Staff Technical Review

No

Electrical proximity to load is not an informative measure of whether Element(s) are necessary for reliable
operation or the potential reliability impact of excluding Element(s) from the BES. Establishing a maximum
impedance threshold as proposed would assure only that the excluded Element(s) do not span a large
electrical distance. While minimizing impedance may be beneficial for some aspects of reliability, other
aspects of BES reliability are improved with higher impedance. For example, higher impedance minimizes
through-flow of power and minimizes impacts to BES reliability associated with faults and switching errors.

ISO/RTO Standards Review
Committee

No

The SRC fails to see how electrical proximity to load qualifies an element for exclusion from the BES. Such
elements may indeed be involved in serving electricity to those loads. If those loads are critical loads, then
why should the element be excluded from the BES?

Iberdrola USA

No

We do not agree with this requirement. These exclusion exception criteria should be deleted in their entirety
and replaced with criteria that are objective, specific, and repeatable, or preferably not replaced at all.
Specific problems with the criteria as stated are: 1. A facility is not BES if all of “a” through “d” below apply:
a. “System elements” are in “close electrical proximity to load” - this is vague, and a lower impedance
between systems is higher likelihood of interaction between systems. Proximity measured in ohms should be
related to the load level itself. A pair of values (ohms, load) is necessary for this purpose. Transient stability is
affected by this value-pair. For a load pocket, an equivalent impedance (e.g., a sort of Thevenin impedance)
between the network source and the load location could be defined. The impedances within the network
source can also affect the assessment. Re-evaluation over time would be necessary if this path were
adopted.
This path of evidence (i.e., the path of engineering judgment) which does not include extensive technical
analysis is an attempt to provide a definitive criteria for exception without going through the other path of
evidence (i.e., the analytical path) which includes extensive technical analysis. Unless the analytical path has
been clearly defined and sufficient data obtained from/on it, the path of engineering judgment could become
difficult to establish. System parameters such as proximity to load, radial (or non-radial) configuration, power
flow direction over time (either unintended or intended) will directly influence results of technical analysis
evaluated for distribution factors, transient voltage dip and frequency excursions, voltage deviations, transient
and steady-state stability, and sequence of events following a disturbance (i.e., either a cascading outage or
a controlled outage). The two paths of evidence cannot be in conflict with each other.

Tri-State Generation and
Transmission Association

No

A long radial line with a small transformer could have a relatively high impedance. Proximity to load has no
real bearing on this procedure. Requirement 1.(a) should be deleted.

16

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization
Hydro One

Yes or No

Question 1 Comment

No

We agree with this concept to allow entities to submit an exception application that does not include extensive
technical analysis. Such an option will make the process efficient for all stakeholders, such as entities,
Regions, NERC and relevant regulatory authority. However, our opinion is that there is no real relationship
between reliability and the proximity of load. If impedance is to be used as a measure of electrical proximity,
which in turn is a replacement for geographical proximity, then how would the presence of parallel lines,
capacitors, phase-angle regulators (PARs), tap-changing transformers, generation and reactors be treated in
determining electrical proximity?
Consistent with references in the FERC Order, we feel that it is much more important to identify and ensure if
the BES element(s) are serving load pockets associated with large metropolitan load centers, loads of
significance to national security and/or as identified by relevant Federal, State or Provincial Regulatory
Authority.
We urge the SDT to clarify the exception criteria for exclusions, based on the following questions: oHow does
the proximity impedance approach effectively differentiate between transmission and distribution lines of the
same voltage and length?
oWhen using impedance, how is “greater than” determined?
oWhat impedance would the SDT apply to a PAR (or tap-changing transformer) and to the overall path if a
PAR (or tap-changing transformer) were located in-series with the measured Elements?
oWhat is the meaning of “power flow data” used here and how is the meaning different from the term when
used under “1c) Power flows into the system, but rarely flows out”? Should this sentence use the phrase
“impedance data extracted from a load flow study” instead?
Finally we suggest that entities should be required to identify the significance of the element’s physical
characteristics. Such identification can be done through a simple checklist along with any relevant comments.

MRO's NERC Standards Review
Forum

No

NSRF believes the relevance and rationale for this criterion is unknown. If this criterion is intended to exempt
elements, like circuit switchers, that are part of the distribution transformer circuits operated above 100 kV,
and located within a mile of the BES interconnection point, then NSRF would expect the wording to be “in
close electric proximity to the BES” rather than in “close electric proximity to Load”. Otherwise, NSRF
requests the SDT explain the relevance and rationale for this criterion before agreeing on its inclusion.

ReliabilityFirst

No

it is far too complicated for the smaller entities

New York State Reliability

No

NERC’s Glossary definition of Load is “An end-use device or customer that receives power from the electric

MidAmerican Energy
Muscatine Power and Water

17

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Council

Question 1 Comment
system.” which is not specific enough to permit the definition of an appropriate impedance value.
It is not clear from the proposed wording whether the exception applies to the Loads or the electrically close
System Elements or both. In any case, the concept of a single impedance value as a metric is flawed
because it could be a low impedance breaker or a relatively high impedance transformer connecting the BES
to a “radial” Load center. This exclusion is superfluous given the radial test in item 2. Suggest dropping this
exclusion test.
N.B. The proposed criteria in items 1 - 4 must all be met in order for an element to qualify for an exclusion.

New York Power Authority

No

NYPA does not see a need for this requirement. A radial element that specifically serves a load center will
perform that task regardless of the electrical distance from the source to the load. Similarly, any loss of load
in the load center will result in a corresponding need to reduce generation in the source system, regardless of
the proximity of the load.

ITC

No

Please explain the rationale to require electrical proximity. Is it to limit fault exposure? Perhaps 2 miles of
line could be shown to typically have few faults, thus limiting the number of voltage sags to nearby buses. At
approximately 0.7 ohms per mile 1.5 ohms (for overhead) might be a reasonable number. Does it make a
difference if the load is connected via underground cable?

South Carolina Electric and Gas

No

SCE&G disagrees with the assumption that the proximity of a BES facility to Load is indicative of it's
importance to BES reliability. Some lower voltage facilities can be quite short and thus have lower impedance
but be important to BES reliability.

Georgia Transmission
Corporation

Furthermore, the term "Load centers" is not defined leaving it subject to interpretation. Assuming a load center
has many busses, where would the measurement be made - From the most distant load bus in the load
center or the nearest? Similarly - does a single facility get measured from it's terminal to the load center or
does the presence or lack of breakers need to be considered when selecting the measurement point?
Glacier Electric Cooperative

No

I do not think that the proximity to load should be a factor in determining whether or not an element should be
included in the BES. Rather, the purpose of the element should be the important factor. If an element only
serves load, then that should be the most important factor and the proximity (electrical or physical) to that load
should not matter.

Consolidated Edison Co. of NY,
Inc.

No

We generally support this exclusion option concept, to the extent that it is fashioned after the FERC Seven
Factor test. However, we have a number of questions as to how it might work in practice.1.a.i. Electrical
Proximity - If impedance is to be used as a measure of electrical proximity, which in turn is a replacement for

18

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment
geographical proximity, then how would the presence of parallel lines, capacitors, phase-angle regulators
(PARs), tap-changing transformers, generation and reactors be treated in determining electrical proximity?
How does this approach effectively differentiate between transmission and distribution lines of the same
voltage and length? When using impedance, how is “greater than” determined?
Sum of the Impedances - Would the filing entity simply add up the in-series impedances for each radial
Element to demonstrate its electrical proximity? For example, would the sum of the impedances from this
example radial path be equal to the sum of the two feeder and transformer impedances, i.e., measured from a
230 kV bus along a 230 kV feeder, through a 230/138 kV step-down transformer, and an in-series 138 kV
feeder to a 138/13.8 kV step-down distribution transformer? What impedance would the SDT apply to a PAR
(or tap-changing transformer) and to the overall path if a PAR (or tap-changing transformer) were located inseries with the measured Elements?
1.a.ii. Power Flows - What is the meaning of “power flow data” as the term is used here and how is the
meaning different from the term when used under 1.c. Power flows into the system, but rarely flows out?
Should this sentence use the phrase “impedance data extracted from a load flow study” instead?

ISO New England

No

We disagree with this exception and believe that Section 1.a. should be deleted in it’s entirety and replaced
with a definition that excludes remote areas of a generally lesser overall value to reliability and includes areas
that are heavily networked serving large loads.
The premise of the existing section 1.a. seems at odds with overall system reliability and possibly removes
large metropolitan areas from the BES definition. How is close electrical proximity to load defined? A
maximum number of Ohms? Heavily networked areas will have lower impedance and are more likely to
serve larger amounts of demand and are therefore more likely to be impactful on the overall integrity of the
BES.

Flathead Electric Cooperative,
Inc.

No

agree in principle that one characteristic of local distribution systems is that they are usually confined to a
relatively limited geographic area, as opposed to transmission systems, which (especially in the West) tend to
cover very large distances. We also believe the proximity test may be a sensible way to identify local
distribution facilities. However, we believe that the proximity test may be unnecessary, and if an Element or
group of Elements meets other tests proposed by the SDT, it should be excluded from the BES, even if it
does not meet the proximity test.

Entergy Services

No

Entergy does not agree with the assumption that the proximity of a BES facility to Load is indicative of it's
importance to BES reliability. Some lower voltage facilities can be quite short and thus have lower impedance
but be important to BES reliability. Likewise some facilites remote from load centers may have virtually no

19

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment
impact on BES reliability.
There is also insufficient information as to how the impedance would be measured (locations of
measurements within and outside of the "Load pockets". This Exemption Criteria should be removed.
The term "Load centers" is not defined leaving it subject to interpretation. "Loads" are not BES Elements and
therefore can not be exempted from being considered BES Elements.
Item 1.a.i - "Loads within the system seeking exception are in close electrical proximity if they are separated
by an impedance of no greater than TBD." This sentence needs to be deleted.

BGE

No

BGE is not clear as to why “close electrical proximity to load” is appropriate to use as a factor in determining
exclusion.

Spyker

No

We agree with this concept to allow entities to submit an exception application that does not include extensive
technical analysis. Such an option will make the process efficient for all stakeholders, such as entities,
Regions, NERC and relevant regulatory authority. However, our opinion is that there is no real relation
between reliability and the proximity of load. Consistent with references in the FERC Order, we feel that it is
much more important to identify and ensure if the element(s) are serving load pockets associated with large
metropolitan load centers (e.g. New York City, Washington DC, Toronto), loads of significance to national
security and/or as identified by relevant Federal, State or Provincial Regulatory Authority.
We believe that entities should be required to identify the significance of the elements’ physical
characteristics, such as the proximity of element or, being served or impacted by the element to a load of
significant interest. Such identification can be done through a simple checklist along with any relevant
comments.
Therefore, we suggest the SDT to revise the exception criteria to seek an alternative language and/or re-craft
exclusion criteria (a), which will require entities to provide the previously stated information for their element.

Benton Rural Electric
Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc.

No

We believe that the proximity test may be unnecessary, and if an Element or group of Elements meets the
other three tests proposed by the SDT, it should be excluded from the BES, even if it does not meet the
proximity test. Secondly, using impedance to benchmark system load proximity would likely not yield clear
demarcations. High voltage relative or per-unit impedances are considered typically much lower than low
voltage impedances. Hence, in the absence of phase shifting transformers, service compensation, or other
mitigation factors, power typically flows over the highest voltage lines, which offer the lowest impedance.

20

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

Salem Electric
Grant County PUD No. 2 (Grant)
Big Bend Electric Cooperative,
Inc.
Big Bend Electric Cooperative,
Inc.
Kootenai Electric Cooperative
Orange and Rockland Utilities,
Inc.

No

The approach does not differentiate between transmission and distribution. There is no direct relation
between impedance and load. A study of the particular system should be performed to assess impact on
BES.

Pepco Holdings Inc

No

A specific impedance value would not be appropriate for all regions and all configurations.

Consumers Energy Company

No

Consumers Energy Company (CECo) proposes that this criterion be eliminated, as it is not a definitive BES
criterion. There is no correlation between the proximity of Elements that are 100kV and above to load.

Central Lincoln

No

Central Lincoln agrees in principle that one characteristic of local distribution systems is that they are usually
confined to a relatively limited geographic area, as opposed to transmission systems, which (especially in the
West) tend to cover very large distances. We also believe the proximity test may be a sensible way to identify
local distribution facilities. However, as explained in more detail in our response to Question 10, we believe
that the proximity test may be unnecessary, and if an Element or group of Elements meets the other three
tests proposed by the SDT, it should be excluded from the BES, even if it does not meet the proximity test.
Secondly, using impedance to benchmark system load proximity would likely not yield consistent
demarcations. High voltage relative or per-unit impedances are typically much lower than low voltage
impedances. Hence, in the absence of phase shifting transformers, service compensation, or other mitigation
factors, power typically flows over the highest voltage lines, which offer the lowest impedance. Central Lincoln
proposes that “proximity” be determined in the dictionary manner with units of distance.

Duke Energy

No

Duke Energy does not agree that this characteristic materially demonstrates that an Element is not necessary
for operating an interconnected electric transmission network. There is no correlation between the electrical
proximity of an element to load and its necessity for operating an interconnected transmission network. In
general, the path that does not include extensive technical analysis is not adequate to distinguish between the

21

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment
Elements that are and that are not necessary for said operation.

Hydro-Quebec TransEnergie

No

Close electrical proximity to load does not appear to be an appropriate criteria. There is no reason that this
criteria would prevent exclusion of a radial system with long lines feeding far away loads. Instead of
considering proximity to load, it would be better to consider the way the Element is connected to the BES and
the function of the excluded part of the system, mainly to deserve loads or integrate some generation, but not
to transfer power to another Balancing Authority. Those are covered by criteria b., c. and d., so we believe
that criteria a. should not be maintained.

American Transmission
Company, LLC

No

ATC believes the relevance and rationale for this criterion is unknown. If this criterion is intended to exempt
elements, like circuit switchers, that are part of the distribution transformer circuits operated above 100 kV,
and located within a mile of the BES interconnection point, then ATC would expect the wording to be “in close
electric proximity to the BES” rather than in “close electric proximity to Load”. Otherwise, ATC requests the
SDT explain the relevance and rationale for this criterion before agreeing on its inclusion.

Manitoba Hydro

No

The purpose of this exception is unclear. It would be possible that a large transmission station with many
network connections, which is close to a load (irrespective of size), would be excluded from the BES
definition. Similarly, a reduction of system impedance, by transmission line re-conductoring for example, could
remove assets out of the scope of the BES definition. The listed proposed criteria suggest values yet to be
determined. It is unclear how this exception would support BES reliability.

NESCOE

No

The New England States Committee on Electricity (“NESCOE”) appreciates the work of NERC’s standard
drafting team as well as the opportunity to provide comments on this matter. NESCOE is New England’s
Regional State Committee and the comments provided herein reflect the collective views of the six New
England states. NESCOE’s comments below reflect its general perspective that any new costs imposed as a
result of the BES and its implementation, which costs ultimately fall on consumers, should provide meaningful
reliability benefits. NESCOE questions the concept as presented and seeks further clarification.
As a general matter, NESCOE believes the requirement that a proposed exception must meet all four criteria
is overly restrictive and will result in only a narrow category of elements qualifying for exclusion from the BES.
NESCOE suggests that a better approach would allow exclusions to be based on one or more criteria,
depending on the nature of the element that is the subject of the application.
With respect to the proposal, NESCOE does not believe it is possible to obtain agreement on the “proximity to
load” criterion for additional exclusions from the BES when the underlying impedance value has not been
determined and may be the subject of significant debate.

22

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment
While it is possible that NESCOE could support a single impedance value that would govern exclusion
determinations, it notes that a uniform value may not adequately address varying system configurations
throughout ISO-New England and neighboring control areas. NESCOE suggests that the standards setting
process allow for further deliberation on possible proposed values.
Other terms, such as “load center,” also need definition.

Independent Electricity System
Operator

No

We agree with this concept to allow entities to submit an exception application that does not include extensive
technical analysis. Such an option will make the process efficient for all stakeholders, such as entities,
Regions, NERC and relevant regulatory authority. However, we believe that an Element’s electrical proximity
to load is not necessarily a relevant consideration for determining whether the Element is required for reliable
operations.

Tacoma Power

No

Tacoma Power does not believe that a proximity to Load criteria is useful in BES designation when the other
3 exclusion criteria of this path are applied. However, if the SDT retains this item, we suggest an impedance
value of < 0.3 ohms on a 100 MVA base.

Georgia System Operations
Corporation
ACES

The concept of “Load centers” is vague and needs more specificity for this to be clear.

Yes

This seems like a reasonable approach although we have no recommendations for impedance thresholds.
Some analysis of various load pockets might provide data to consider for the threshold.

Clark Public Utilities

Yes

Clark believes the proximity test should be considered be a valid factor in determining whether a facility is part
of the BES or not. Just as this factor is used in the consideration on whether a facility is part of a Local
Distribution Network. Clark is not convinced that “proximity” and “impedance” are interchangeable. While
impedance will be lower for shorter distances it will also be affected by other factors that are not indicative of
close proximity. Distance seems more appropriate to use since it would complement a literal interpretation of
the term proximity.

Blachly Lane Electric
Cooperative

Yes

First, thank you for the opportunity to comment on the Technical Principles for Demonstrating BES
Exceptions. We appreciate the work that NERC has done on these principles and the other related efforts to
revise the definition of the BES. In response to question #1, we note only that using impedance to benchmark
system load proximity would likely not yield clear demarcations. High voltage relative or per-unit impedances
are considered typically much lower than low voltage impedances. Hence, in the absence of phase shifting
transformers, service compensation, or other mitigation factors, power typically flows over the highest voltage

Central Electric Cooperative
Clearwater Power Electric

23

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Cooperative

Question 1 Comment
lines, which offer the lowest impedance.

Consumer's Power Inc.
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Long Island Power Authority

Yes

Agree with close proximity to load concept but further direction (define suggested methodology) is required for
how to calculate impedance value. In addition to impedance value suggest consideration of adding mileage
or relative phase angle differences between locations be also an allowable criteria.

American Electric Power

Yes

Using “proximity to load” is a reasonable metric, but would require further consideration given the impedance
value eventually chosen to replace “TBD”.

24

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

Oregon Public Utility
Commission Staff

Yes

Use of the 100 kV brightline and the core BES definition as proposed is an overreach into local distribution
systems and an overreach of FERC’s authority as set out in the FPA 215. A full engineering technical
analysis - required every 2 years - is too onerous and not necessary for identifying most local distribution
elements miss-identified as BES Elements. A simple screening methodology consistent with the 7-Factor
Test (from FERC Order 888) is needed as the first stage of the exception process.

Harney Electric Cooperative, Inc.

Yes

I don't have a suggestion for an appropriate impedance.

Bonneville Power Administration

Yes

BPA suggests that correlation between the size of the Load and the size of an element is needed. BPA would
like the word “close” in the description “close electric proximity to load” to be better defined. For example, a
line that carries 600 MWs in close electrical proximity to a 20-MW Load may not meet the intent of this
characteristic. In planning models, loads are often aggregated to a higher voltage while, in a distribution
system model, the loads are explicitly represented along the distribution feeder. Because of this, the criteria
should define where the load is located/represented for the measure of electrical proximity.

Western Electricity Coordinating
Council

Yes

As long as this remains an “AND” statement, WECC supports this concept. It helps to support the concept
that the element is used as distribution to serve Load, rather than to transfer bulk power. However, some
correlation between the size of the Load and the size of an element may be needed. For example, a line that
can carry 600 MW in close electrical proximity a 20-MW Load may not meet the intent of this characteristic.
Furthermore, the criteria must define where the load is located for the measure of electrical proximity. In
planning models, loads are often aggregated to a higher voltage substation bus, while in a distribution system
model they are typically modeled along a distribution feeder.
The SDT should clarify how it intends for the load to be modeled for this analysis of close proximity.

Electricity Consumers Resource
Council (ELCON)

Yes

Occidental Energy Ventures
Corp.

Yes

Xcel Energy

Yes

Oncor Electric Delivery

Yes

We recommend that this item be added to the BES definition.

Oncor Electric Delivery agrees with the proposed language as it is stated, related to load proximity.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the
system Element being located in close electrical proximity of Load and the use of impedance as qualifying criteria. Based on industry response and further
analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics
that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a
comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be
valid across all regions and systems. The new process requires an entity to clarify the characteristics of the facilities in question and to document the operational
performance as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being sought. The
appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and
then file the request and recommendation with the ERO as established in the draft Rules of Procedure.
Edison Electric Institute

No

We do not believe that a meaningful “not to exceed” impedance value can be proffered which would be
appropriately useful across all regions. EEI recommends that Exclusion benchmarks should directly correlate
to the BES definition exclusions as written. Although the “4 Item” approach was obviously intended to provide
a simple approach, the outcome suggested in the draft was less than satisfactory and we submit it does not
hold true to the exclusions provided by the Drafting Committee in their proposed BES Definition. (see
additional comments provided at the end of the Comment form)

PacifiCorp

No

All of PacifiCorp’s responses are based on the application of these items to a given interconnection and not
on a continental basis. See comments on question 10. Setting a standard for close electrical proximity using
an impedance measurement does not address a proper measurement in all interconnections. A better, more
accurate measurement would be to utilize fault duty. Low fault duties provide a good measurement of impact
on the BES. Fault Duty at adjacent BES substations should not exceed 5,000 MVA.

for Snohomish County PUD

No

Snohomish agrees in principle that one characteristic of local distribution systems is that they are usually
confined to a relatively limited geographic area, as opposed to transmission systems, which (especially in the
West) tend to cover very large distances. We also believe the proximity test may be a sensible way to identify
local distribution facilities. However, as explained in more detail in our response to Question 10, we believe
that the proximity test may be unnecessary, and if an Element or group of Elements meets the other three
tests proposed by the SDT, it should be excluded from the BES, even if it does not meet the proximity test.
Further, using impedance to benchmark system load proximity would likely not yield clear demarcations. High
voltage relative or per-unit impedances are considered typically much lower than low voltage impedances.
Hence, in the absence of phase shifting transformers, service compensation, or other mitigation factors,
power typically flows over the highest voltage lines, which offer the lowest impedance.

Response:

The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

system Element being located in close electrical proximity of Load and the use of impedance as qualifying criteria. Based on industry response and further
analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics
that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a
comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be
valid across all regions and systems. The new process requires an entity to clarify the characteristics of the facilities in question and to document the operational
performance as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being sought. The
appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and
then file the request and recommendation with the ERO as established in the draft Rules of Procedure.
Also see response to Question 10.
Florida Municipal Power Agency
Transmission Access Policy
Study Group

No

Impedance is a function of a line’s length; it does not measure whether a line serves a BES function. A very
long line can exist only to serve load, and a short line in an urban area (where the load is physically close to
the grid) could be needed for transmission but would have low impedance. This proposed metric is thus both
over- and under-inclusive, and should be discarded.
Transfer distribution factor is a more appropriate metric, as described in FMPA’ response to Question 4.
FMPA supports having two paths for exclusions, one that includes extensive technical analysis and another
that does not. The path with less technical analysis is appropriate for Elements that a relatively high-level
examination shows to be not relevant to the reliability of the grid. This opportunity should be available in the
context of exclusions to reduce the burden on small entities. Reliability will not be impaired by this option; all
exception requests will be reviewed by NERC, and in any case where NERC is less than certain that an
exception is appropriate, NERC can perform any or all of the analyses that would be required for a more
technical exclusion or inclusion, and a positive result on any one of the analyses would be sufficient
justification to deny the exclusion request.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the
system Element being located in close electrical proximity of Load and the use of impedance as qualifying criteria. Based on industry response and further
analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics
that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a
comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be
valid across all regions and systems. The new process requires an entity to clarify the characteristics of the facilities in question and to document the operational
performance as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being sought. The
appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and
then file the request and recommendation with the ERO as established in the draft Rules of Procedure.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

Also see response to Question 4.
In regards to a two-path approach, the SDT has broadened the exception methodology to allow an entity to submit the characteristics of the Facilities in question
without supplying engineering evidence if they feel there is ample supporting documentation for the exception being sought.
Idaho Falls Power

No

We do not agree that all four criteria under exclusion #1 need be applied in combination to an element to
determine its material impact. Assets satisfying all four defining criteria would seem exceedingly small and
likely already excluded by the BES definition. This exception criteria appears redundant to, and shadows the
NERC BES definition draft’s language excluding radial elements and local distribution networks, and as such
add little value to the exclusions built into the BES definitions.
Further, the language of the exception criteria addresses transmission elements and doesn’t provide
exclusion criteria for generation assets. We would hope that NERC could develop criteria to exempt certain
generation, especially those small resources on local distribution networks wherein the generation is
completely allocated to local load. Language in section 215 of the FPA excludes distribution “elements.” We
assert that generation on a distribution network serving only load on that network is an “element” of the
network and deserves exclusionary defining criteria.

Response: The SDT appreciates the comments associated with the Element characteristics and the suggestions for language or clarifications to the proposed
language for technical exception criterion associated with generation. Based on industry response and further analysis, the SDT has abandoned the initial
exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to
a defined value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The
new process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through
submittal of an exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review
the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and
recommendation with the ERO as established in the draft Rules of Procedure.
The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.
PPL Supply

No

See comments in Questions 9 and 10

Response: See response to Q9 & 10.
Southern Company

No

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization
The United Illuminating
Company

Yes or No

Question 1 Comment

No

Response: Thank you for your response but without specific comments there is nothing that the SDT can do to address your opinion. However, based on industry
response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and
operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES.. The initial
proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to establish
values and/or limits that would be valid across all regions and systems. The new process requires an entity to clarify the characteristics of the facilities in question
and to document the operational performance as appropriate through submittal of an exception request form along with any other supporting documentation for
the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support
the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of Procedure.
National Grid

No

We feel that there is no relation between the proximity to load and system reliability. The impedance is
technically irrelevant, and we suggest that this criteria be dropped.
If the criteria is not dropped, there should be clarification on what is meant by “Load”. For instance are you
really referring to “major load centers”? In many areas of the country Load is connected all along a 100kV line
and hence much of a line is in close proximity to Load - but it could be small industrial loads and not
significant load centers. If significant Load Centers is what the drafting team was driving at then, we believe it
should be explicit.
We also believe that if the drafting team is defining some technical criteria, then it should not be in the
exception process. It should be included as part of the core definition. The exception process should be
strictly limited to the procedures for application and approval and should not include substantive elements.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the
system Element being located in close electrical proximity of Load and the use of impedance as qualifying criteria. Based on industry response and further
analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics
that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a
comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be
valid across all regions and systems. The new process requires an entity to clarify the characteristics of the facilities in question and to document the operational
performance as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being sought. The
appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and
then file the request and recommendation with the ERO as established in the draft Rules of Procedure.
The technical criteria are being developed through the Standards Development Process, consistent with the directives in Order 743 and 743A. The scope of the

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 1 Comment

Rules of Procedure is strictly focused on the process that entities shall use to seek and be granted or denied exceptions.
Exelon

No

The term “close proximity” is ambiguous and open ended. Exelon believes that all facilities used in local
distribution of electric energy that are presently under state jurisdiction should be excluded from the BES
regardless of system impedance.

Response: The SDT appreciates your comments. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or
limit. It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires
an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception
request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate
information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as
established in the draft Rules of Procedure.
In regards to the facilities used in local distribution that are presently under state jurisdiction the SDT has added language to the core BES definition that
addresses the exclusion of distribution facilities.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

2. Exclusions - The SDT has set up one path for evidence that does not include extensive technical
analysis. It consists of 4 items, all of which must be addressed in order to submit a completed
request for exclusion. The second item involves Element(s) treated as radial. Do you agree with this
requirement? If you do not support this requirement or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: A significant portion of the comments disagreed with, or had significant concerns about using
various undefined terms such as “regional dispatch”, “disconnection procedures”, and “radial in character”. Comments also
indicated that the example was not clear and many comments indicated that the entire wording of this exception should be
abandoned. Several comments indicated that assessments, studies, and drawings/diagrams should be allowed as evidence to
provide the validity of the exception.
Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is
intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity
with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined
value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be valid across all
regions and systems. The new process requires an entity to clarify the characteristics of the facilities in question and to
document the operational performance as appropriate through submittal of an exception request form along with any other
supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate
information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and
recommendation with the ERO as established in the draft Rules of Procedure.

Organization
Northeast Power Coordinating
Council

Yes or No
No

Question 2 Comment
The term “regional dispatch” is not defined. Provide a definition or reference to a definition to be used in
making this determination. Recommend adoption of the alternate term “operational control.”
1.b.ii, Operational Control - The SDT should consider using the terms “under the operational control of a
Balancing Authority.” It is instructive that the overarching requirement for a finding of transmission system
integration in Mansfield was that the facilities be under operational control of the Independent System
Operator (ISO).** Southern Cal. Edison Co., 92 FERC ¶ 61,070 at 61,255 (2000), reh'g denied 108 FERC
¶ 61,085 (2004).
Replace the example in 1.b.i. with a clearer example.
Entities should be allowed to demonstrate the radial characteristics to determine if they are permitted for an
exception, and demonstrate compliance with radial defining criteria.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization
SPP Standards Review Group

Yes or No
No

Question 2 Comment
Could the SDT clarify what is meant by ‘disconnection procedures’ in 1.b.ii? It appears that the SDT is okay
with excluding an element that can be switched out of service without removing another element. How are
automatic breaker operations or manual switching factored into disconnection procedures? We need
clarification on this.
More and better examples, including the type of connectivity to the grid, would be helpful.

Transmission Access Policy
Study Group

No

Florida Municipal Power Agency

ISO/RTO Standards Review
Committee

We believe that this criterion is intended, like those in 1(a) and (d), to determine whether an Element is
planned and operated to function as part of the interconnected grid. It is, however, too vague to be useful and
should be discarded.
We believe that this criterion is intended, like those in 1(a) and (d), to determine whether an Element is
planned and operated to function as part of the interconnected grid. It is, however, too vague to be useful and
should be discarded.

No

The SRC generally agrees that radial elements likely may be excluded from the BES. However, there is
insufficient information given as to what it means to be “not operated as part of the BES with disconnection
procedures for when a Disturbance occurs”.
Further, is it possible that such radial elements are serving a remote “critical” load? One would think that,
normally, critical loads would have arrangements for multiple sources, but could those multiple sources be
individually considered to be radial?

Iberdrola USA

No

We do not agree with this requirement. These exclusion exception criteria should be deleted in their entirety
and replaced with criteria that are objective, specific, and repeatable, or preferably not replaced at all.
Specific problems with the criteria as stated are: 1. A facility is not BES if all of “a” through “d” below apply:
b. “System elements” are “treated as” radial “in character” - this is also vague, and based on operating
procedures... what does “treated” involve? What is “character” in the context of system elements?

Tri-State Generation and
Transmission Association

No

While we generally agree, 1.(b) should be changed to “normally radial.” “Radial” should not be defined
differently in the Rule of Procedure than in the BES Definition.

Hydro One

No

Entities should be allowed to demonstrate the radial characteristics to determine if they are permitted for an
exception, and demonstrate compliance with radial defining criteria.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment
The term “regional dispatch” is not defined. Therefore we suggest the SDT to provide a definition or reference
to clarify regional dispatch in 1 b) II.
We recommend adoption of the alternate term “operational control” and suggest that the SDT consider using
the terms “under the operational control of a Balancing Authority” (It is instructive that the overarching
requirement for a finding of transmission system integration in Mansfield was that the facilities be under
operational control of the Independent System Operator.*)* Southern Cal. Edison Co., 92 FERC ¶ 61,070 at
61,255 (2000), reh'g denied 108 FERC ¶ 61,085 (2004).

MRO's NERC Standards Review
Forum

No

Radial in Character - NSRF proposes that this criterion be eliminated because it does not describe any
materially different characteristics beyond Exclusion E1 of the bright-line BES definition.

MidAmerican Energy

No

MidAmerican supports the NSRF comments. The NSRF proposes that this criterion be eliminated because it
does not describe any materially different characteristics beyond Exclusion E1 of the bright-line BES
definition. If not eliminated, the IEEE definition of a radial system should be used.

Bonneville Power Administration

No

BPA requests clarification on what the SDT considers radial through additional examples of i “the way the
connections to the BES are operated” and ii “the way the Element(s) are treated in operations.”
BPA emphasizes that this assessment should be conducted using normal system operations.

Muscatine Power and Water

No

Radial in Character -propose that this criterion be removed for the reason that it does not illustrate any
materially different characteristics beyond Exclusion E1 of the bright-line BES definition.

Exelon

No

The term “rarely” is ambiguous and should be removed or quantified.
Furthermore, the requirement for power flow analysis will be viewed by many entities as extensive technical
analysis.

Consolidated Edison Co. of NY,
Inc.

No

We generally support this exclusion option concept, to the extent that it is fashioned after the FERC Seven
Factor test. However, we have a number of questions as to how it might work in practice. For example, the
term “regional dispatch” is not defined. Please provide a definition or reference to a definition to be used in
making this determination.
Below we recommend adoption of the alternate term “operational control.”1.b.ii, Operational Control - The
SDT should consider using the terms “under the operational control of a Balancing Authority.” It is instructive
that the overarching requirement for a finding of transmission system integration in Mansfield was that the

33

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment
facilities be under operational control of the Independent System Operator (ISO).** Southern Cal. Edison Co.,
92 FERC ¶ 61,070 at 61,255 (2000), reh'g denied 108 FERC ¶ 61,085 (2004).
Replace the example in 1.b.i. with a clearer example.

ISO New England

No

This three part definition of radial presented in section 1.b. appears cumbersome and requires more
definition.
With regard to b.i - Where is the disturbance? Is sending a person to the field to perform manual
disconnection a requirement of this exception? This item is so vague that we have difficulty providing
replacement language as we do not understand its intent.
With regard to b.ii - Elements (Excluding generators) are not dispatched in operations. If this approach were
to be taken, what would be the criteria for the way the Element is treated in Operations? Again, this item is so
vague that we have difficulty providing replacement language.
The existing definition appears to require a good deal of technical scrutiny and be at odds with the goal of
having a path for evidence that does not include extensive technical analysis. Overall it seems simpler to
replace section b with a simpler definition of radial such as - all load served from a single substation at a
single voltage level.

The United Illuminating Company

No

Pepco Holdings Inc

No

Radial system is already an explicit Exclusion by definition (E1). Does this imply that ALL radial systems
require a request to be submitted for the RE and NERC approval that the elements are in fact radial?
There may not be internal written procedures describing the radial system operation. The evidence that an
entity can provide should include a description or justification of the radial operation and non impact to the
BES.

Duke Energy

No

This second characteristic does not add clarity to the E1 Exclusion in the proposed BES definition. And in
general, the path that does not include extensive technical analysis is not adequate to distinguish between the
Elements that are and that are not necessary for operating an interconnected electric transmission network.

American Transmission
Company, LLC

No

Radial in Character - ATC proposes that this criterion be eliminated because it does not describe any
materially different characteristics beyond Exclusion E1 of the bright-line BES definition.

34

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment

Manitoba Hydro

No

The proposed criteria to substantiate a request for an exception should be removed as it does not introduce
anything different than what is already proposed under the exclusions in the bright line BES definition.
Specifically, radial systems are already excluded in the bright line definition E1.

NESCOE

No

As noted in Response 1, NESCOE believes exclusion determinations should not require a finding that all four
proposed criteria are met.
In addition, NESCOE believes that the criterion proposed here is overly complex and that developing the
evidence may be overly burdensome to the applicant. Radial paths should have a simple definition related to
how the path is connected from a topological perspective. NESCOE suggests that a radial path be defined
simply as a path having only one connection point to the BES, thereby presenting no opportunity for power
flows parallel to the BES network. Under fault situations, these excluded paths can be isolated from the BES
with suitable NERC compliant protection systems. Note the radial path may be comprised of parallel lines that
terminate at the BES connection point.
In addition, NESCOE believes that a radial path should qualify for exclusion as long as the power flowing into
the BES is less than a threshold MVA.
NESCOE does not at this point have a recommendation as to this specific threshold but believes it should be
developed through the standards-setting process. NESCOE suggests this approach to avoid burdening the
development of generation including renewable generation. As New England is working on facilitating the
development of renewable resources located in and around the region to serve customers most costeffectively, this process should take specific care not to impose undue burdens on renewable resources.

Idaho Falls Power

Blachly Lane Electric Cooperative
Flathead Electric Cooperative,
Inc.
Central Electric Cooperative
Clearwater Power Electric

Using these criteria assumes that every asset must be radial in nature in order to receive consideration that it
may not be material to the BES. This then implies that the BES is a contiguous connected system as only
radial off-shoots could receive exemption consideration. We disagree. Our assertion is that the BES is
comprised of assets that due to their size or location are vital to a sound BES but may or may not necessarily
be connected to each other. This defining criteria in the exception could be a stand-alone criteria or stricken.
Yes

We agree conceptually that facilities operating as radials rather than as integrated portions of the integrated
bulk transmission system should be excluded from the BES definition. However, to be consistent with the
draft BES definition, the term “radial in character” should be explicitly defined as facilities that may include one
or more lines into a load area or referenced as a local distribution network.
In addition, we agree that the manner in which a system is operated during BES disturbances may be an
indication of whether that facility is radial in character. That being said, we are concerned that, to the extent

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Cooperative

Question 2 Comment
the SDT considers regional disconnect procedures, it should be careful to note that UFLS and UVLS relays
are often embedded within local distribution facilities and, while it is necessary for the UFLS and UVLS relays
to be properly armed to protect the BES in the event of a severe system disturbance, the local distribution
facilities interconnected with those relays should not, and cannot legally, be classified as BES.

Consumer's Power Inc.
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc.

South Carolina Electric and Gas
Georgia Transmission
Corporation

Yes

SCE&G agrees with the requirement of an element being radial in character as being a qualifier for exclusion
thru the non-technical analysis.
However, we recommend that the term "radial in character" be better defined.
In addition, the language is confusing and we would like to recommend the following: i.: suggest replacing

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment
“disconnection procedures” with “automatic disconnection devices”
ii.: The intent of this item is not clear, and the term "regional dispatch" is not defined. Recommend the item be
clarified or deleted.

Springfield Utility Board

Yes

SUB agrees with providing an exclusion exception for System Elements that are treated as “radial in
character”, but feels this should be part of the core definition in NERC’s Proposed Continent-wide Definition of
Bulk Electric System rather than requiring an exclusion/exemption application process.
In SUB’s May 27, 2011 BES definition comments SUB expressed concern that there still appears to be
inconsistencies in both definition and application of “radial.” SUB encourages NERC to develop a concise
definition. For example, if a system is normally operated as radial, but could be operated closed (for example,
by manually closing a breaker), would it be considered a radial or close-looped system?

Entergy Services

Yes

Entergy agrees that radial facilities should be excluded directly. However, the "radial in character" language is
nebulous. A simpler approach could be to allow exceptions for facilities which become radial as a
consequence of a normal system response to a disturbance (breakers opening during normal clearing of a
fault).

Clark Public Utilities

Yes

Clark agrees conceptually that systems operating as radials rather than as integrated portions of the
integrated bulk transmission system should be excluded from the BES definition. That is because local
distribution systems typically operate adjacent to, or at the end of transmission lines, and function
operationally to move power from the Transmission Service Provider’s point of delivery of bulk power that has
moved across the integrated bulk transmission system to end-users located within the local distribution
utility’s service territory.

Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc.
Central Lincoln
Salem Electric
Grant County PUD No. 2 (Grant)
for Snohomish County PUD

To be consistent with the draft BES definition, the term “radial in character” should be explicitly defined as a
system that may include one or more lines into a load area or referenced as a local distribution network. In
addition, Clark agrees that the manner in which a system is operated during BES disturbances may be an
indication of whether that system is radial in character. That being said, we are concerned that, to the extent
the SDT considers regional disconnect procedures, it should be careful to note that UFLS and UVLS relays
are often embedded within local distribution systems and, while it is necessary for the UFLS and UVLS relays
to be properly armed to protect the BES in the event of a severe system disturbance, the local distribution
system interconnected with those relays should not.

Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,

37

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment

Inc.
Kootenai Electric Cooperative
Oregon Public Utility Commission
Staff

Yes

Use of the 100 kV brightline and the core BES definition as proposed is an overreach into local distribution
systems and an overreach of FERC’s authority as set out in the FPA 215.
A full engineering technical analysis - required every 2 years - is too onerous and not necessary for
identifying most local distribution elements miss-identified as BES Elements. A simple screening
methodology consistent with the 7-Factor Test (from FERC Order 888) is needed as the first stage of the
exception process.

Hydro-Quebec TransEnergie

Yes

However, the point B.i. is hard to understand and would need clarification. Here is a proposal: "For an
Element to be excluded from BES, its should be demonstrated that there are a proper disconnection
procedure when facing a disturbance that would prevent this Element to impact the BES" ?.
The point should be to make sure a fault on the Element will be isolated effectively without adverse impact on
the BES, even when we have a second transmission source for the syb system seeking exclusion.
Also, for point B. ii., it should be explained what is meant by the expression "regional dispatch". Is it an
alternate way of transfer of power outside the Balancing Authority ?

PacifiCorp

Yes

All of PacifiCorp’s responses are based on the application of these items to a given interconnection and not
on a continental basis. See comments on question 10. If this requirement is added to the four requirements to
capture local distribution networks, which are often operated in a looped configuration, which may still be
included in the BES by the proposed BES bright-line due to generator inclusions, then this requirement has
merit. Otherwise, exclusion E1 in the proposed BES bright-line definition already covers this item and it
becomes redundant.

Independent Electricity System
Operator

Yes

We agree with this concept. Entities should be allowed to demonstrate the radial characteristics to determine
if they are permitted for an exception. However, we believe some further clarification of the meaning of “radial
in character” is needed. The example given in (b)I does not clarify the matter. Would a transmission line
operated with a normally open point to form two radial lines be considered “radial in character”? Please
clarify.
The location of the Disturbance needs to be clarified. For example, if the Disturbance (e.g. a fault) occurs at
the radial part of the Element, then it is necessary for the Element to have the capability to disconnect itself
from the Disturbance to preserve BES reliability but the Element can be by itself a legitimate radial facility that

38

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment
is used solely for supplying load. The phrase “are not included in a regional dispatch” is unclear. We do not
understand what this means.

Tacoma Power

Yes

Tacoma Power generally agrees that radial elements should be an item in this path and we suggest that
radial element operated at below 300 kV should be excluded from the BES. The 300 kV level is linked with
NERC CIP’s proposed version 4 definition of critical asset and should be applied here with the BES definition.

SERC Planning Standards
Subcommittee

Yes

The PSS agrees with the requirement of an element being radial in character as being a qualifier for exclusion
thru the non-technical analysis. However, the PSS recommends that the term "radial in character" needs to be
better defined.
In addition, the language is confusing and the PSS would like to recommend the following:i.: suggest
replacing “disconnection procedures” with “automatic disconnection devices”ii.: The intent of this item is not
clear, and the term "regional dispatch" is not defined. Recommend the item be clarified or deleted.

Tennessee Valley Authority

Yes

We agree with the requirement of an element being radial in character as being a qualifier for exclusion thru
the non-technical analysis. However, we recommend that the term "radial in character" needs to be better
defined.
In addition, the language is confusing and we recommend the following:i.: suggest replacing “disconnection
procedures” with “automatic disconnection devices”
ii.: The intent of this item is not clear, and the term "regional dispatch" is not defined.
Recommend the item be clarified or deleted.

New York State Reliability
Council

Yes

It should be clarified that radial Element(s) include all system elements in load pockets.

Electricity Consumers Resource
Council (ELCON)

Yes

We recommend that that the item be added to the BES definition.

New York Power Authority

Yes

The definition of radial systems needs to be modified to include radials that are connected to a single
transmission source by more than one automatic interruption devices, such as occurs with a “breaker and a
half” arrangement.

Southern Company

Yes

We agree with the requirement of an element being radial in character as being a qualifier for exclusion thru

39

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment
the non-technical analysis. However, we recommend tha the term "radial in character" be better defined.
Item ii.: The intent of this item is not clear, and the term "regional dispatch" is not defined. Recommend the
item be clarified.

ITC

Yes

ITC is in agreement if we are correct in assuming that any one of the three ways ( i, ii, or iii ) can be used to
satisfy the exclusion.
We would also like to request additional clarification as to what "disconnection procedures" would be valid for
consideration in this requirement.

National Grid

Yes

We agree that elements that are treated as radial should be allowed to request an exception.
We would like more clarification about what is meant by “regional dispatch”. To the extent definitions of terms
such as “regional dispatch” are necessary; they should be addressed in the core definition development
process. The exception process should be strictly limited to the procedures for application and approval and
should not include substantive elements.
We would also like clarification on whether all three criteria under bullet b are required to show if the element
is treated as radial, or if meeting one is enough.

Harney Electric Cooperative, Inc.

Yes

Oncor Electric Delivery

Yes

Xcel Energy

Yes

Consumers Energy Company

Yes

Long Island Power Authority

Yes

Elements could be included in a regional dispatch such as a large regional ISO, but still serve only local load
and therefore should still be treated as radial.

American Electric Power

Yes

Considering whether or not the element is treated as radial is a reasonable approach.

Orange and Rockland Utilities,
Inc.

Yes

Oncor Electric Delivery agrees with the proposed language that describes the exclusion criteria for system
Elements that are radial in character.

40

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment

BGE

Yes

No comment.

Spyker

Yes

We agree with this concept. Entities should be allowed to demonstrate the radial characteristics to determine
if they are permitted for an exception.

Occidental Energy Ventures
Corp.

Yes

ReliabilityFirst

Yes

Electric Market Policy

Yes

ACES

Yes

yes only true radial without any impact should be excluded otherwise include it

We agree with this path.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the system
Element being treated as radial in character as qualifying criteria. Based on industry response and further analysis, the SDT has abandoned the initial exclusion
criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and
provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value
and/or limit. It has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new
process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to
validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as
established in the Rules of Procedure as presently being drafted.
NERC Staff Technical Review

No

We believe that restating this measure as “System performance impacts are similar to radial systems” would
be more in-line with the SDT intent and a better measure of whether Element(s) are necessary for reliable
operation.
We also believe that the best measure of whether Element(s) affect system performance in a manner similar
to radial systems is through distribution factor analysis. Such analysis, when limited to this purpose, does not
require extensive technical analysis. Analysis for a limited number of stressed transfer conditions, and
contingencies involving the Element(s) under consideration and in the area of the Element(s) under
consideration, is sufficient to demonstrate whether the system performance impacts are similar to radial
systems.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment

Western Electricity Coordinating
Council

No

This characteristic is vague and subjective. It is unclear what “radial in character” means, and the methods for
demonstration do not appropriately clarify the meaning. WECC recommends that the SDT determine what it is
looking for to show “radial in character” and clearly identify that concept in the methods for demonstration. It is
not clear how Operating Procedures can demonstrate that an element is “radial in character” nor is it clear
how a re-evaluation might be processed if such Operating Procedures, ownership, or operations change.
WECC believes that BES inclusion or exclusion should be based on physical, technical characteristics of the
element, and requests a justification for use of procedural or contractual documentation as evidence of a
technical principle.

Edison Electric Institute

Yes

The verbiage used in the BES Principles document does not closely match the verbiage used in the NERC
Bright-line Exclusion. For that reason, we submit the following alternative language.
System Elements and Facilities treated in total as a radial system shall have the following characteristics:1.
Shall be separated from the BES with an Automatic Interrupting Device, AND2. Only load serving and must
be isolated from other radial systems through a normally open switching device, OR3. Only include
generation resources but cannot include any of the Inclusions (i.e., I2, I3, I4 and I5) identified in the BES
Definition, OR4. Is a combination of Load and Generation but cannot include any of the Inclusions (i.e., I2, I3,
I4 and I5) identified in the BES
DefinitionEvidences to be supplied shall include: o One-line Diagram clearly showing all demarcations
between BES Facilities and the Radial System (including the Automatic Interrupting Device, AND o
Operating procedures or interconnection agreements that indicate Generating Units contained within the
Radial System are not dispatchable (if applicable), AND/OR o Operating procedures that show that the
Radial System is not operated as part of the BES

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the system
Element being treated as radial in character as qualifying criteria.
The new proposed process allows an entity to submit a specified and consistent list of studies that should support the entity’s request and that can then be utilized by
the ERO panel judging the request in making their decision.
Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the
technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The
initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish
continent-wide values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of the facilities in
question and to document the operational performance as appropriate through submittal of an exception request form along with any other supporting documentation
for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support

42

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 2 Comment

the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as presently being drafted.
PPL Supply

No

See comments in Questions 9 and 10

Glacier Electric Cooperative

No

I do agree that radial elements should definitely be excluded. However, I believe that non-radial elements
should be able to be excluded by Path 1 as well. If a small local distribution system is operated non-radially
for the purpose of improving reliability for its loads, then that system should be eligible for exclusion from the
BES. I also believe that language needs to be included that makes the provision for radial elements that can
be temporarily and briefly looped together during switching to prevent an outage (e.g. for transformer
maintenance) to also be excluded from the BES.

City of Redding

Yes

The term Radial could cause confusion. Clarification needs to be added to indicate that the system can have
more than one connection to the BES.

Response: See response to Q9 & Q10.

Response: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to
clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of
BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible
to establish continent-wide values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of the
facilities in question and to document the operational performance as appropriate through submittal of an exception request form along with any other supporting
documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether
or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as presently being
drafted.
Exclusion E1 of the definition allows normally open switches and Exclusion E3 can be used for systems that support load with multiple connections to the BES.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

3. Exclusions - The SDT has set up one path for evidence that does not include extensive technical
analysis. It consists of 4 items, all of which must be addressed in order to submit a completed
request for exclusion. The third item involves power flow. Do you agree with this requirement? If you
do not support this requirement or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments. In addition, in the comment
field, please provide your thoughts on the appropriate MWh value to replace ‘TBD,’ including
technical rationale for your argument.
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion
criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be
considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was
dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not
feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new process
requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as
appropriate through submittal of an exception request form along with any other supporting documentation for the exception
being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of
whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established
in the Rules of Procedure as presently being drafted.

Organization
Northeast Power Coordinating
Council

Yes or No
No

Question 3 Comment
If an entity provides hourly MWh power flow data on a radial for a 12-month period (under v.) showing no
power flow reversals, would transaction data (under i. through iv.) still be required?
Could the entity just say “no transactional records?”
If there were power flow reversals, wouldn’t the power flow data (provided under v.) also show those, e.g., the
amount and duration?
Isn’t this request redundant?
If reversing power flows on a feeder caused it to fail one of the criteria, could the radial still be excluded, or is
it necessary for the Element to pass all requirements?
Alternatively, could the entity choose to file for Exclusion of that Element under the technical analysis option?
What happens and what are the implications when the two approaches produce different outcomes?

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
Recommend that “iv. The maximum amount of energy flowing out” limit be set to no more than 24 hours of
reverse power flows within any rolling 12-month period.
Consider avoiding prescribing values and eliminate bullet (iv). The intended performance outcome should be
described, but without setting values.
This should not have any impact on the reliability of the transmission network if items 1, 2 and 3 are satisfied.

SPP Standards Review Group

No

Rather than combining two conflicting criterion - ‘rarely’ and the number of MHh of backflow allowed annually
- we would suggest the following. 1) That the maximum outflow doesn’t create an issue on the BES. This
would be determined by study of the system and conditions. Or 2) when the condition exists, be able to
mitigate the condition within a prescribed time relevant to the prevailing system conditions.

NERC Staff Technical Review

No

Requiring that power flows into, and rarely out of, the Element(s) considered for exclusion is an appropriate
measure, as is requiring an entity to define the conditions under which power will flow out.
In addition to information such as specified contingencies in item (ii), details on the conditions should include
other relevant information such as the system load level, generation dispatch, system transfer levels, etc., and
the number of hours per year these conditions are expected.
An exception request also should include the maximum flow expected. E.g., the following information would
be useful in evaluating a request for exception: “Power will flow out only when line A is out of service, system
load is at or below X percent of peak load, and generator B is on-line; based on the load duration curve for
this area and the number of hours generator B is dispatched at these load levels, the exposure to power flow
out for this contingency is limited to N hours per year and the maximum flow if the contingency occurred
during these hours would be Y MW.” This type of information will be far more informative than a pass/fail test
as to whether a MWh threshold is expected to be exceeded. While a MWh threshold may be useful for
evaluating requests, it is unlikely that a one-size-fits-all threshold could be established for evaluating
exception requests.

ISO/RTO Standards Review
Committee

No

The SRC believes that, if power EVER flows out, then the area is either not radial or it includes generation
resources. There is insufficient information to determine whether this “limited quantity of energy” is indeed
small. There could be very large amounts of load and generation resources within that area. Such large
quantities could represent a significant potential for sudden increases in load or unexpected energy injections.

Iberdrola USA

No

We do not agree with this requirement. These exclusion exception criteria should be deleted in their entirety
and replaced with criteria that are objective, specific, and repeatable, or preferably not replaced at all.

45

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
Specific problems with the criteria as stated are: 1. A facility is not BES if all of “a” through “d” below apply:
c. Power flows into “the system” most of the time - this is vague and covers much of the 115 kV system.

Hydro One

No

We agree with the criteria set out in 1(c), but suggest the SDT to avoid prescribing values and eliminate bullet
(IV).
The SDT should also consider allowing: a) Power flow-out up to 20% of the minimum forecasted load for the
element(s) over a 12 month period; or b) Maximum amount of energy flowing out be set to no more than 24
hours of reverse power flows within any rolling 12-month period. The intended performance outcome should
be described, but without setting values. This should not have any impact on the reliability of the transmission
network if items 1, 2 and 3 are satisfied.

MRO's NERC Standards Review
Forum

No

NSRF proposes that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the bright-line BES definition.

MidAmerican Energy

No

MidAmerican supports the NSRF comments. The NSRF proposes that this criterion be eliminated because it
does not describe any materially different characteristics beyond Exclusion E3 of the bright-line BES
definition.

ReliabilityFirst

No

All power flow studies can be don eto show a small impact, this is how the system is planned. This will only
cause more confusion and debate between the FERC, NERC the Regions and registered entities

Idaho Falls Power

No

We agree in general, however believe there is little distinction between the defining criteria in this exception
and the local distribution network exclusion already provided for in the BES definition.
We would like to see added language that provides an exclusion for all elements on such a system, to include
generation regardless of MVA rating, wherein the power flows are generally into the system.
We would agree that a number of MWh of annual outflow needs to be established as a limitation to the size
and amount of generation under consideration. This exclusion should be geared towards smaller municipal or
like sized systems having no material impact upon a BA much less the region.

Muscatine Power and Water

No

Proposing that this criterion be eliminated because it does not describe any materially different characteristics
beyond Exclusion E3 of the bright-line BES definition.

Glacier Electric Cooperative

No

Regarding using power flow into and out of a system as a criterion fro BES exclusion, I do not think that

46

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
establishing a hard MWh per year is the proper approach to take. Once again, I believe that the purpose of
the system should be the most important factor. If the purpose of a system is to serve load or transport nonessential generation (i.e. wind power), then that system should be able to be exluded.

Consolidated Edison Co. of NY,
Inc.

No

We generally support this exclusion option concept, to the extent that it is fashioned after the FERC Seven
Factor test. However, we have a number of questions as to how it might work in practice. For example: o If
an entity provides hourly MWh power flow data on a radial for a 12-month period (under v.) showing no power
flow reversals, would transaction data (under i. through iv.) still be required? Couldn’t the entity just say “no
operating records?”
o If there were power flow reversals, wouldn’t the power flow data (provided under v.) also show those, e.g.,
the amount and duration? Isn’t this request redundant? If not, why not? Please explain.
o If reversing power flows on a feeder caused it to fail one of the criteria, could the radial still be excluded, or
is it necessary for the Element to pass all requirements? Alternatively, could the entity choose to file for
Exclusion of that Element under the technical analysis option? What happens and what are the implications
when the two approaches produce different outcomes?
We recommend that “iv. The maximum amount of energy flowing out” limit be set to no more than 24 hours of
reverse power flows within any rolling 12-month period.Replace “transactional records” with “operating
records.”

ISO New England

No

Section 1.c again appears to allow the exclusion of large portions of the system in metropolitan areas. How
does this differ from the LDN exclusion already presented in the definition?
Section c should simply be deleted.

The United Illuminating Company

No

What does rarely mean? How is maintenance conditions considered? This is simply worded but conceptually
extremely complicated.

Entergy Services

No

Power flows into or out of a portion of the BES may characterize BES facilities less important to BES reliability
but without limits to the size of the area, it would be difficult to show compliance. An entire state could be
excluded from the BES.
Additionally, there is no process specified to review the characteristics as transmission topology and
resources change over time.

BGE

No

BGE is generally opposed to this requirement because the MWh factor is too variable and/or may be utilized

47

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
in a way contrary to reliable system operation.

Pepco Holdings Inc

No

The characteristic statement should be reworded to say: “Power flow is generally load serving.”The criteria as
written have very burdensome MWh record requirements. Yearly totals for flows in and out and an overall
description or justification for this exception should be allowable.

Duke Energy

No

This third characteristic does not add clarity to the E3 Exclusion in the proposed BES definition. And in
general, the path that does not include extensive technical analysis is not adequate to distinguish between the
Elements that are and that are not necessary for operating an interconnected electric transmission network.

American Transmission
Company, LLC

No

ATC proposes that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the bright-line BES definition.

Manitoba Hydro

No

Vague language such as “rarely” or “not intentionally” does not support a “bright line” approach, and is not
measureable or auditable. Also, the sample evidence should not be included as part of the criteria.In addition,
the proposed criteria to substantiate a request for an exception should be removed as it does not introduce
anything different than what is already proposed under the exclusions in the bright line BES definition.
Specifically, this item is already excluded in the bright line definition E3.

NESCOE

No

As noted in Response 1, NESCOE believes exclusion determinations should not require a finding that all four
proposed criteria are met. Generally, NESCOE is in agreement with an exception criteria for additional
exclusions that takes into account power flows into the system that rarely flows out. However, additional
clarity is necessary for criteria 1(c)(i),(ii) and (iv). Specifically, what is meant by “very limited set of conditions”
under 1(c)(i) and (ii) and “limited quantity of energy” under 1(c)(i)?
Further, is it appropriate to establish a fixed value of X megawatt hours for the maximum amount of energy
flowing out of the system?
While it is possible that NESCOE could agree upon a uniform value, NESCOE is not in a position to provide
specific comment or support when the MWh value is unspecified. In addition, a fixed value may not
adequately address varying system configurations throughout ISO-New England and neighboring control
areas.

Independent Electricity System
Operator

No

There is an inconsistency between the language used in bullet (c) - “rarely flows out”, and that used in
Exclusion E3(c) of the BES definition - “Power flows only into the LDN”. We have commented during the BES
Definition comment period that Exclusion E3 needs to be modified to match the Exception Principles.

48

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
We agree with the criteria set out in 1(c) except for bullets (iv) and (v). We do not believe it is possible to
establish a limit on the energy flow out of a system for which an exception has been requested.
Further, we suggest that the SDT avoid prescribing set values in the exception criteria since these would only
serve to limit the flexibility of the process.
As an alternative to the proposed bullet (iv), we suggest that power flow study results could be used to
support the exception request. We therefore propose the following wording to replace bullets (iv) and (v).iv.
Power flow simulation results to demonstrate that BES reliability is not dependent upon the power flows
through the Element(s) for which an exception has been submitted, for the conditions specified in (ii).

Georgia System Operations
Corporation

If the BES Definition itself is clarified to allow for some de minimis amount of power flow out of a customarily
radial line that is excluded by definition, this justification for an exclusion may not be necessary. We
encourage the Drafting Team to pursue that approach because we believe it is technically justified and could
significantly reduce the need for exceptions.

Florida Municipal Power Agency

The third item is “power flows into the system, but rarely flows out.” This criterion is vague. FMPA suggests
instead the following language, which is consistent with FMPA’ comments on Exclusion E3 of the BES
definition: “Neither the Element, nor any Elements that it connects to the grid (in aggregate), includes more
than 75 MVA of generation used to meet the resource-adequacy requirements of electric utilities.”

Transmission Access Policy
Study Group
ACES

Yes

We agree with this path although iii and v may be in conflict. One requires 24 months data and the other
requires 12 months of data.

National Grid

Yes

We agree with this requirement, but feel that assigning a specific value to the energy flowing out of the
system in MWh is unnecessary. The energy flowing out of a system depends on the size of the area, and
thus could vary widely.
Another concern is about non-wires alternatives (NWA). One type of non-wires alternative that is considered
during planning studies is to reduce the amount of load on our system by paying customers to not operate
during peak hours. One scenario to consider is a generator connected on a radial line that qualifies as BES,
and will need upgrades if the generator runs frequently. If this generator produces power close to the MWh
threshold in the specified time frame per NERC criteria, does it mean the utility company will have to consider
paying the generator owner money to shut down in order to keep total MWh generation below the threshold
and avoid BES criteria required radial line upgrades? This is another reason assigning a specific value to the
energy flowing out of the system is unnecessary.
We would like clarification on whether all criteria (i,ii,iii,iv,v) need to be met, or if just meeting one criteria is

49

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
sufficient. We feel that meeting criteria 1.c.1, 1.c.ii OR 1.c.iii is sufficient in showing that power rarely flows
out of the system. Criteria 1.c.iv and 1.c.v should be removed.
The exception process should be strictly limited to the procedures for application and approval and should not
include substantive elements.

Blachly Lane Electric Cooperative
Flathead Electric Cooperative,
Inc
Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative

Yes

We agree conceptually that one critical characteristic distinguishing facilities that must be excluded from the
BES from facilities that should be included is the manner in which power flows on those facilities. Hence, the
SDT has properly identified power flows as one important characteristic that identifies BES facilities. We also
agrees conceptually that the fact that power may flow out of facilities onto the grid during a few hours in a
year or during extreme contingencies should not change the characterization of the facilities in question as
excluded from the BES. Accordingly, we support inclusion of power flow analysis as one element of
characteristics that can be used to exclude facilities from the BES even if the facilities do not pass each of the
bright-line thresholds laid down in the BES definition.
We also agree that transactional and hourly generation records are an appropriate basis for making the
determination since these can be used to demonstrate that demand within a system exceeds generation
within that system in most hours and that power therefore does not flow onto the grid, and also to determine
the number of hours where this is not the case and the amount by which generation within the system
exceeds demand. In order to identify facilities that are not necessary for the operation of the BES under this
text, we propose that any facility where real power flows in 90 percent of the time or more under normal (“N-0”
or All Lines in Service) operating conditions should be held to meet this test. That facilities meet this test
could be demonstrated using metering or supervisory control and data acquisition ("SCADA") data records
over the course on two years.

Raft River Rural Electric
Cooperative

While we agree with the SDT’s view that power should flow predominantly in the direction of load for excluded
facilities, we are concerned that this characteristic may no longer be a defining characteristic as the electric
industry evolves in the future. If distributed generation becomes the future norm for new power generation
facilities, it may no longer make sense to look at power flow as a defining characteristic. That is, even if a
sufficient number of small distributed generation facilities were constructed on certain facilities to cause power
to flow out of those facilities more than ten percent of the time, the fundamental character of those facilities
will not have changed.

Salmon River Electric
Cooperative

Finally, we believe that power flow analysis under this item should consider actual power flow, not scheduled
power flow.

Northern Lights Electric
Cooperative
Okanogan Electric Cooperative

Umatilla Electric Cooperative
West Oregon Electric

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment

Yes

Clark agrees conceptually that one critical characteristic distinguishing local distribution facilities that must be
excluded from the BES from transmission facilities that should be included is the manner in which power flows
on those facilities. Power on local distribution systems generally flows only from the interconnected
transmission source and across the distribution system for delivery to end-use customers. By contrast, power
on transmission systems generally flows in two (or multiple, in networked systems) directions and is delivered
in bulk to distribution utilities rather than to end-users. Hence, the SDT has properly identified power flows as
one important characteristic that distinguishes BES transmission systems from local distribution systems. In
order to identify systems that are not necessary for the operation of the BES under this text, we propose that
any system where real power flows into the local distribution system 90 percent of the time or more under
normal operating conditions.

Spyker

Yes

We agree with the criteria set out in 1(c), but suggest the SDT to avoid prescribing values and eliminate bullet
(iv). The SDT should describe the intended performance outcome but avoid setting values. This should have
little, if any impact on reliability of the transmission network if the items 1, 2 and 3 are satisfied.

American Electric Power

Yes

Requiring that “power flows into the system, but rarely flows out” is a reasonable approach, but would require
further consideration given the MWh value eventually chosen to replace “TBD”.

Orange and Rockland Utilities,
Inc.

Yes

The “TBD” value should be reasonable and well justified.

Cooperative
Pacific Northwest Generating
Cooperative

Clark Public Utilities
Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc.
Salem Electric
Grant County PUD No. 2 (Grant)
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc
Kootenai Electric Cooperative

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment

Central Lincoln

Yes

Central Lincoln agrees that one critical characteristic distinguishing local distribution facilities that must be
excluded from the BES from transmission facilities that should be included is the manner in which power flows
on those facilities. Power on local distribution systems generally flows only from the interconnected
transmission source and across the distribution system for delivery to end-use customers. By contrast, power
on transmission systems generally flows in two (or multiple, in networked systems) directions and is delivered
in bulk to distribution utilities rather than to end-users. Hence, the SDT has properly identified power flows as
one important characteristic that distinguishes BES transmission systems from local distribution systems.
Central Lincoln also agrees that the fact that power may flow out of a local distribution system onto the grid
during a few hours in a year or during extreme contingencies should not change the characterization of the
system as local distribution. Accordingly, we support inclusion of power flow analysis as one element of
characteristics that can be used to exclude local distribution facilities from the BES even if the facilities do not
pass each of the bright-line thresholds laid down in the BES definition.
We also agree that transactional and hourly generation records are an appropriate basis for making the
determination since these can be used to demonstrate that demand within a local distribution system exceeds
generation within that system in most hours and that power therefore does not flow onto the grid, and also to
determine the number of hours where this is not the case and the amount by which generation within the
system exceeds demand. In order to identify systems that are not necessary for the operation of the BES
under this test, we propose that any system where real power flows into the local distribution system 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should be held to
meet this test. That a system meets this test could be demonstrated using metering or supervisory control
and data acquisition ("SCADA") data records over the course of two years. In addition, the presence of
generation within a local distribution system that only modifies the level of the load served by the bulk system,
but does not result in power being injection into the bulk system, does not change the reliability effect of the
local network and therefore should not require the local network to be classified as BES.

Oregon Public Utility Commission
Staff

Yes

Use of the 100 kV brightline and the core BES definition as proposed is an overreach into local distribution
systems and an overreach of FERC’s authority as set out in the FPA 215. A full engineering technical
analysis - required every 2 years - is too onerous and not necessary for identifying most local distribution
elements miss-identified as BES Elements. A simple screening methodology consistent with the 7-Factor
Test (from FERC Order 888) is needed as the first stage of the exception process.

Hydro-Quebec TransEnergie

Yes

However, this is only part of an exclusion.
The point c. iv and v, MWh is not relevant for real-time operation. It would be more simple to put a time
reference, such as a total number of days or a % of the time.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
In number iii, do you mean the first self certification ? In fact, the evidence for exclusion will be done once, but
ROP suppose that the self certification will be done many times (every two years).

for Snohomish County PUD

Yes

Snohomish agrees conceptually that one critical characteristic distinguishing local distribution facilities that
must be excluded from the BES from transmission facilities that should be included is the manner in which
power flows on those facilities. Power on local distribution systems generally flows only from the
interconnected transmission source and across the distribution system for delivery to end-use customers. By
contrast, power on transmission systems generally flows in two (or multiple, in networked systems) directions
and is delivered in bulk to distribution utilities rather than to end-users. Hence, the SDT has properly
identified power flows as one important characteristic that distinguishes BES transmission systems from local
distribution systems.
Snohomish also agrees conceptually that the fact that power may flow out of a local distribution system onto
the grid during a few hours in a year or during extreme contingencies should not change the characterization
of the system as local distribution. Accordingly, we support inclusion of power flow analysis as one element
of characteristics that can be used to exclude local distribution facilities from the BES even if the facilities do
not pass each of the bright-line thresholds laid down in the BES definition.
We also agree that transactional and hourly generation records are an appropriate basis for making the
determination since these can be used to demonstrate that demand within a local distribution system exceeds
generation within that system in most hours and that power therefore does not flow onto the grid, and also to
determine the number of hours where this is not the case and the amount by which generation within the
system exceeds demand. In order to identify systems that are not necessary for the operation of the BES
under this test, we propose that any system where real power flows into the local distribution system 90
percent of the time or more under normal (“N-0” or All Lines in Service) operating conditions should be held to
meet this test. That a system meets this test could be demonstrated using metering or supervisory control
and data acquisition ("SCADA") data records over the course on two years.
In addition, the presence of generation within a local distribution system that only modifies the level of the
load served by the bulk system, but does not result in power being injection into the bulk system, does not
change the reliability effect of the local network and therefore should not require the local network to be
classified as BES.

New York Power Authority

Yes

NYPA generally agrees with this item. However, the term “system” needs to be better defined.
It is not clear how power could flow out of a load only system. If reversing power flows on a feeder caused it
to fail one of the criteria, could the radial still be excluded, or is it necessary for the Element to pass all
requirements? Alternatively, could the entity choose to file for Exclusion of that Element under the technical

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
analysis option?
What happens and what are the implications when the two approaches produce different outcomes?
An example of revised wording for “iv. The maximum amount of energy flowing out” would be no more than
24 hours of reverse power flows within any rolling 12-month period.
Consider avoiding prescribing values and eliminate bullet (iv). The intended performance outcome should be
described, but without setting values. This should not have any impact on the reliability of the transmission
network if items 1, 2 and 3 are satisfied.

New York State Reliability
Council

Yes

It should be clarified that this exclusion should not apply to inter-regional transfers, which clearly are
candidates for inclusion as BES.

Western Electricity Coordinating
Council

Yes

WECC agrees in concept with this characteristic, but it needs to be clarified whether the items i-v are “AND”
statements
WECC also suggests that i and ii be switched and re-worded. Suggested language for ii would be “A limited
set of conditions where power flows out must be identified; for example, only under specified Contingency
events.” Then i can become a sub-bullet of ii. It must also be clarified that the specified conditions must have
a technical justification to show that the element is not “necessary for reliable operation.” Otherwise it is not
clear that the “limited conditions” are truly a justification for exclusion.
Any non-zero MWh limit must have a technical justification, otherwise zero should be used. In addition to the
imports/exports from the system, the size of the system (in MW) should also be defined.

Bonneville Power Administration

Yes

BPA generally agrees with the power flow concept, but suggests including language that the assessment
should be “based on normal system operating conditions.”
A MWh value to replace ‘TBD’ for maximum energy flowing out per year could be determined based on on an
annual average MW load level of 25 MW average and below with distribution service of 50MVA and below,
because 25MW loads can be served by lines under 100kv. The energy flowing out per year would be limited
by the size of the load and the ability to import power to the load area (i.e. the export would never be larger
than the initial distribution service minus the local area losses and load).
BPA requests that the drafting team perform a cross-walk analysis on each of the 4 items to ensure the
consistent application of an existing industry process, practice, or standard.

Tri-State Generation and

Yes

It may be more appropriate to use a threshold based on maximum power rather than on an annual energy

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Transmission Association

Question 3 Comment
threshold.

Electric Market Policy

Yes

Harney Electric Cooperative, Inc.

Yes

Oncor Electric Delivery

Yes

Southern Company

Yes

Occidental Energy Ventures
Corp.

Yes

Consumers Energy Company

Yes

The word rarely should be struck from this item. It is meaningless in the context for which it is used and offers
little to characterize an element or connection since it does not contain a measure.

Oncor Electric Delivery agrees with the proposed language that describes the exclusion criteria based upon
power flows.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the
magnitude, direction and time duration of power flow on a system Element as qualifying criterion. Based on industry response and further analysis, the SDT has
abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered
in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s
characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in
operational characteristics. The new process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance
as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the
request and recommendation with the ERO as established in the Rules of Procedure as presently being drafted.
Edison Electric Institute

Yes

Although EEI agrees in principle to the exclusion, we feel the current language has some problems which
need to be addresses. Note the following:The word “rarely should be struck. It is meaningless in the context
for which it is used and offers little to characterize an element or connection since it does not contain a
measure. A more appropriate statement to broadly characterize a Non-BES element or connection would be
the following:”Power flows are broadly characterized as Load Serving.”
Items i. and iii. are excessive requirements which do not aide in defining what is “necessary for operating an
interconnected electric transmission network”. What might be more a more useful measure is a comparison
of total MW hours of load consumed vs. MW hours fed back into the BES as measured on an annual

55

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
basis.Item v. - Hourly energy data (MWh) for the most recent 12 month period for every excluded BES
element is an excessive requirement. Annual records indicating that MW hours consumed annually verses
MW hours that flow through the non-BES element would be a better indicator in line with the definition.

SERC Planning Standards
Subcommittee

Yes

Tennessee Valley Authority

One possible starting point for selecting a MWh threshold: Generators of 20 MVA or less are typically exempt
from detailed modeling requirements. Suggest that reverse flows of this level or less, for a period of 24 hours
or less would be an acceptable threshold. Therefore, this would provide a basis for selecting a threshold
MWh level for reverse flows into the system under part iv. of 20 MW x 24 hours = 480 MWh per year.

Response: The SDT appreciates your comments and your suggestions for the amount of power flow allowed to still be eligible for an exclusion. However, based
on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the
technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The
initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to
establish continent-wide values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of
the facilities in question and to document the operational performance as appropriate through submittal of an exception request form along with any other
supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a
recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of
Procedure as presently being drafted.
PPL Supply

No

See comments in Questions 9 and 10

City of Redding

Yes

To be consistent with E2 of the proposed BES Definition a distribution system should be allowed to export at
least 75 mw. This would be the same as a commercial retail customer can export into the distribution system.

Electricity Consumers Resource
Council (ELCON)

Yes

The thresholds for power flows out of the system should be made consistent with Exclusion E2 in the
definition.We recommend that this item be added to the BES definition.

Response: See responses to Q9 & Q10.

Response: The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.
South Carolina Electric and Gas
Georgia Transmission
Corporation

Yes

One possible starting point for selecting a MWh threshold: Generators of 20 MVA or less are typically exempt
from detailed modeling requirements.
Suggest that reverse flows of this level or less, for a period of 24 hours or less would be an acceptable
threshold. Therefore, this would provide a basis for selecting a threshold MWh level for reverse flows into the

56

Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 3 Comment
system under part iv. of 20 MW x 24 hours = 480 MWh per year

Long Island Power Authority

Yes

Item iv. The maximum amount of energy flowing out is (TBD-1,752,000) MWh per year.
Another measure that may be more appropriate is a percent % of total energy requirements in the area.

Xcel Energy

Yes

Regarding the question on MWH, one possible approach is to use 175,000 MWH/ year which would be just
under the annual hourly output from the smallest generator (not at a plant) that must be registered under the
registry criteria.

Tacoma Power

Yes

Tacoma Power generally agrees that elements primarily serving load, allowing a limited flow out of the local
distribution network, should be excluded from the BES.
We support an annual limitation of 219,000 MWhs, equivalent to 25 aMW, since a system of elements that
primarily serve load under this limit are insignificant to the BES.

PacifiCorp

Yes

All of PacifiCorp’s responses are based on the application of these items to a given interconnection and not
on a continental basis. See comments on question 10. This criterion is very similar to a part of exclusion 3 of
the proposed bright-line, which requires that power flows into the system. If the intent of this requirement is to
capture local distribution networks that may be included under the proposed bright-line definition, then this
requirement has merit. PacifiCorp proposes that instead of using a measure of energy, that the SDT utilize a
measure of time and recommends that flow out of the system be limited to 15% on an annual basis.
PacifiCorp does not have a technical justification for 15%, nor does it believe that a technical justification can
be provided for any reasonable percent of time used, or MWh used to be applied equally to all
interconnections.

Response: The SDT appreciates your comments and your suggestions to fill in some of the gaps in the first posting. However, based on industry response and
further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational
characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was
dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of the facilities in question
and to document the operational performance as appropriate through submittal of an exception request form along with any other supporting documentation for
the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support
the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as presently being drafted.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

4. Exclusions - The SDT has set up one path for evidence that does not include extensive technical
analysis. It consists of 4 items, all of which must be addressed in order to submit a completed
request for exclusion. The fourth item involves power transport. Do you agree with this requirement?
If you do not support this requirement or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an
entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as
presently being drafted.

Organization
SERC Planning Standards
Subcommittee

Yes or No
No

Tennessee Valley Authority

Question 4 Comment
There is not sufficient evidence provided by the SDT to distinguish between this fourth item for exclusion and
the third item for exclusion. They both seem to fall in line with what is excluded per the bright line exclusion
E3 (or Local Distribution Networks), but as written, it would be difficult to measure what is meant by “is not
intentionally transported through” in this fourth item just as it would be difficult to measure what’s meant by
“flows into the system, but rarely flows out” for the third item.
Such an exclusion should be required to include some technical analysis, but not extensive technical analysis
(at least the inclusion of power flow base case as a minimum).

SPP Standards Review Group

No

It may be better to focus on the purpose, or need, of a facility, the functionality of the facility, rather than how
electric flows impacted the facility during a given situation. Therefore, we would suggest moving away from
the term ‘intent’.

NERC Staff Technical Review

No

Limitations on through-flow of power is an appropriate consideration; however, whether the power flow is
intentional should not be a primary consideration. Intent is not measurable and most major disturbances are
the result of unintentionally placing the system in an unreliable operating condition. The main clause in item

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment
(d) should be modified to reflect that transporting power to another system through the Element(s) to be
excluded is prevented (such as by system configuration and/or impedance) or restricted (such as by
Operating Procedures). Sub-items (i) and (ii) already are consistent with this revision to the main clause.

ISO/RTO Standards Review
Committee

No

Hasn’t the reliability concern associated with “loop flows” been related to the unintentional flow of power
through parts of the system?

Iberdrola USA

No

We do not agree with this requirement. These exclusion exception criteria should be deleted in their entirety
and replaced with criteria that are objective, specific, and repeatable, or preferably not replaced at all.
Specific problems with the criteria as stated are: 1. A facility is not BES if all of “a” through “d” below apply:
d. Power “entering” “the system” does not “intentionally” flow into another “system” - what does intentionally
versus unintentionally mean?

MRO's NERC Standards Review
Forum

No

NSRF proposes that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the BES definition.

MidAmerican Energy

No

MidAmerican support the NSRF comments. The NSRF proposes that this criterion be eliminated because it
does not describe any materially different characteristics beyond Exclusion E3 of the BES definition.

ReliabilityFirst

No

no one knows when some event will occur, putting this limitation will only cause debate. Any impact is an
impact and should be included

Idaho Falls Power

No

We generally agree with this requirement. If a system has redundant transmission to move power that is
normally wheeled through, the question of materiality could be addressed by technical analysis.

Southern Company

No

National Grid

No

Muscatine Power and Water

We feel that this requirement is not specific enough. “System” is too general. It should be clear what is
intended by “system”. Also, we would like more clarification about what is meant by “intentionally transport”.
Is the intent to mean there is a contract between a generator and load?
The exception process should be strictly limited to the procedures for application and approval and should not
include substantive elements.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization
South Carolina Electric and Gas

Yes or No

Question 4 Comment

No

There is not sufficient evidence provided by the SDT to distinguish between this fourth item for exclusion and
the third item for exclusion. They both seem to fall in line with what is excluded per the bright line exclusion
E3 (or Local Distribution Networks), but as written, it would be difficult to measure what is meant by “is not
intentionally transported through” in this fourth item just as it would be difficult to measure what’s meant by
“flows into the system, but rarely flows out” for the third item.
Such an exclusion should be required to include some technical analysis, but not extensive technical analysis
(at least the inclusion of power flow base case as a minimum).

Glacier Electric Cooperative

No

I believe that there should be a provision for systems that intentionally transport variable, non-essential
generation (such as systems that transport wind power) to be excluded from the BES. By nature, these types
of systems cannot be essential to the BES due to the variability of the generation, and, therefore, should be
able to be excluded from the BES.

Springfield Utility Board

No

NERC’s Proposed Continent-wide Definition of Bulk Electric System contains Exclusion E3 (LDNs) as part of
the BES core definition. Why would this fourth item be necessary in demonstrating BES Exceptions if LDNs
are already excluded as part of NERC’s core BES definition?

ISO New England

No

This appears to be the same as section 1.c and again possibly allows for the exclusion of large portions of the
system in metropolitan areas. Section 1.d. should simply be deleted.

The United Illuminating Company

No

The wording is ambiguous. What is meant by system?
Different voltage levels, Owners?

Entergy Services

No

There is not sufficient evidence provided by the SDT to distinguish between this fourth item for exclusion and
the third item for exclusion. They both seem to fall in line with what is excluded per the bright line exclusion
E3 (or Local Distribution Networks), but as written, it would be difficult to measure what is meant by “is not
intentionally transported through” in this fourth item just as it would be difficult to measure what’s meant by
“flows into the system, but rarely flows out” for the third item.
Such an exclusion should be required to include some technical analysis, but not extensive technical analysis
(at least the inclusion of power flow base case as a minimum).

Pepco Holdings Inc

No

This criterion is very similar to the third item. Written operating procedures may not exist. The entity should
be allowed to summit a description and justification.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment

Central Lincoln

No

Central Lincoln agrees that the SDT’s fourth test, which asks whether power is intentionally transported
through a system, identifies a key characteristic of local distribution facilities that distinguishes such facilities
from interconnect bulk transmission facilities that are properly considered part of the BES. In fact, we believe
this may be the most important and readily identifiable distinction. As a matter of operation, power is
scheduled across transmission lines. Further, transmission lines in the Western Interconnection (either
individually or as part of a transmission path) are rated for total transmission capacity and available
transmission capacity, and transmission rights can be purchased on such lines, if available, on an OASIS.
Local distribution systems do not share any of these operational characteristics. Accordingly, Central Lincoln
agrees that if power is not intentionally transported through a particular system, that system is not used for
transmission and should not be considered part of the BES.
We also agree that examining the Operating Procedures applicable to a particular system will provide a ready
guide to whether power is intentionally scheduled across that system.
We suggest, however, that the SDT look beyond those protocols that fall within the NERC Glossary’s
definition of Operating Procedure. For example, in the West, transmission paths are almost all listed in the
WECC Path Rating Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and
the other factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test.

Duke Energy

No

This fourth characteristic does not add clarity to the E3 Exclusion in the proposed BES definition. And in
general, the path that does not include extensive technical analysis is not adequate to distinguish between the
Elements that are and that are not necessary for operating an interconnected electric transmission network.

American Transmission
Company, LLC

No

ATC proposes that this criterion be eliminated because it does not describe any materially different
characteristics beyond Exclusion E3 of the BES definition.

Manitoba Hydro

No

Vague language such as “rarely” or “not intentionally” does not support a “bright line” approach, and is not
measureable or auditable. Also, the sample evidence should not be included as part of the criteria.
In addition, the proposed criteria to substantiate a request for an exception should be removed as it does not
introduce anything different than what is already proposed under the exclusions in the bright line BES
definition. Specifically, this item is already excluded in the bright line definition E3.

NESCOE

No

As noted in Response 1, NESCOE believes exclusion determinations should not require a finding that all four
proposed criteria are met. NESCOE further notes that New England’s network has numerous parallel paths
operated at voltages less than 200 kV which may parallel 230 kV and 345 kV BES network paths. If flows on

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment
a given <200 kV path only exceed 200 MVA under contingency conditions and if these paths are connected to
the higher voltage BES elements with suitable NERC compliant protection systems, these paths may be
EXCLUDED from the BES. NESCOE suggests the value of 200 MVA based on typical thermal ratings of 115
kV transmission lines but is open to other values that the drafting team may suggest. NESCOE also
suggests that the phrase “to some other system” be broadened to include any other higher voltage BES
element.

City of Redding

Yes

The SDT needs to address renewable energy and customer owned generation. If an aggregator adds up one
thousand roof top PV units or the power from plugged in electric cars and sells them to an entity outside of
this system it should not affect the ability of the distribution system to qualify for this exclusion, especially if
the power is consumed inside of the distribution system.

Blachly Lane Electric Cooperative

Yes

Central Electric Cooperative

As a matter of operation, power is scheduled across transmission lines. Further, transmission lines in the
Western Interconnection (either individually or as part of a transmission path) are rated for total transmission
capacity and available transmission capacity, and transmission rights can be purchased on such lines, if
available, on an OASIS. Facilities that do not share any of these operational characteristics should not be
part of the BES.

Clearwater Power Electric
Cooperative

Accordingly, we agree that if power is not intentionally transported through particular facilities, those facilities
should not be considered part of the BES.

Consumer's Power Inc.

We also agree that examining the Operating Procedures applicable to particular facilities will provide a ready
guide to whether power is intentionally scheduled across those facilities.

Flathead Electric Cooperative,
Inc.

Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative

We suggest, however, that the SDT look beyond those protocols that fall within the NERC Glossary’s
definition of Operating Procedure. For example, in the West, transmission paths are almost all listed in the
WECC Path Rating Catalog. Similarly, it is not clear whether scheduling protocols, OASIS operations, and
the other factors listed above qualify as Operating Procedures. Hence, we urge the SDT to list such specific
operational characteristics as part of this test.
Finally, as noted in our answer to Question 3, we are concerned that, if distributed generation advances
significantly, power transport may cease to be a meaningful measure for determining whether a facility is part
of the BES, and we believe that power flow analysis should consider actual power flow, not scheduled power
flow.

Okanogan Electric Cooperative
Raft River Rural Electric

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment

Clark Public Utilities

Yes

Clark agrees that the SDT’s fourth test, which asks whether power is intentionally transported through a
system, identifies a key characteristic of local distribution facilities that distinguishes such facilities from
interconnect bulk transmission facilities that are properly considered part of the BES. Clark believes this may
be the most important and readily identifiable distinction. Accordingly, Clark agrees that if power is not
intentionally transported through a particular system, that system is not used for transmission and should not
be considered part of the BES.

BGE

Yes

BGE generally agrees with this requirement, but believes that the term “system” should be clarified.

Benton Rural Electric Association

Yes

Benton REA agrees that the SDT’s fourth test, which asks whether power is intentionally transported through
a system, identifies a key characteristic of local distribution facilities that distinguishes such facilities from
interconnect bulk transmission facilities that are properly considered part of the BES. In fact, we believe this
may be the most important and readily identifiable distinction.

Cooperative
Salmon River Electric
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc

Northern Wasco County PUD
United Electric Co-op Inc.
Oregon Trail Electric
Salem Electric
Grant County PUD No. 2 (Grant)

Accordingly, Benton REA agrees that if power is not intentionally transported through a particular system, that
system is not used for transmission and should not be considered part of the BES. One exception may be for
a small embedded generation unit owned by a different party that may be “scheduled” out of an area, but in
reality, does not produce any physical flow. These circumstances should not trigger inclusion.

Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc
Kootenai Electric Cooperative

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment

Long Island Power Authority

Yes

In addition to Operating Procedures, electrical elements that restrict or control flow over the line should be
allowed to be used as evidence.

Xcel Energy

Yes

It is not clear what ‘some other system’ would be. Is this another point on the BES in general?

for Snohomish County PUD

Yes

Snohomish agrees that the SDT’s fourth test, which asks whether power is intentionally transported through a
system, identifies a key characteristic of local distribution facilities that distinguishes such facilities from
interconnect bulk transmission facilities that are properly considered part of the BES. In fact, we believe this
may be the most important and readily identifiable distinction. As a matter of operation, power is scheduled
across transmission lines. Further, transmission lines in the Western Interconnection (either individually or as
part of a transmission path) are rated for total transmission capacity and available transmission capacity, and
transmission rights can be purchased on such lines, if available, on an OASIS. Local distribution systems do
not share any of these operational characteristics. Accordingly, Snohomish agrees that if power is not
intentionally transported through a particular system, that system is not used for transmission and should not
be considered part of the BES.
We also agree that examining the Operating Procedures applicable to a particular system will provide a ready
guide to whether power is intentionally scheduled across that system. We suggest, however, that the SDT
look beyond those protocols that fall within the NERC Glossary’s definition of Operating Procedure. For
example, in the West, transmission paths are almost all listed in the WECC Path Rating Catalog.
Similarly, it is not clear whether scheduling protocols, OASIS operations, and the other factors listed above
qualify as Operating Procedures.
Hence, we urge the SDT to list such specific operational characteristics as part of this test.

Independent Electricity System
Operator

Yes

There is an inconsistency between the language used in bullet (c) - “rarely flows out”, and that used in
Exclusion E3(c) of the BES definition - “Power flows only into the LDN”. We have commented during the BES
Definition comment period that Exclusion E3 needs to be modified to match the Exception Principles.
We agree with the criteria set out in 1(c) except for bullets (iv) and (v). We do not believe it is possible to
establish a limit on the energy flow out of a system for which an exception has been requested. Further, we
suggest that the SDT avoid prescribing set values in the exception criteria since these would only serve to
limit the flexibility of the process.
As an alternative to the proposed bullet (iv), we suggest that power flow study results could be used to
support the exception request. We therefore propose the following wording to replace bullets (iv) and (v).iv.
Power flow simulation results to demonstrate that BES reliability is not dependent upon the power flows

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Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment
through the Element(s) for which an exception has been submitted, for the conditions specified in (ii).

Tacoma Power

Yes

Tacoma Power generally agrees with fourth item (power transport) when not intentionally transporting power
through a system. In development of the supporting evidence for this item, we suggest a demonstration by
operating studies or the option to demonstrate the criteria by the use of operational procedures.

Tri-State Generation and
Transmission Association

Yes

While we generally agree, "system" needs to be clarified, and should be changed to "transmission system." It
may also need to be qualified by indicating a change in ownership of transmission systems.
We also wonder if the concept of scheduling should be addressed rather than using the word "intentionally?"

Florida Municipal Power Agency

Yes

FMPA supports the criterion in concept, but “intention[]” is a vague term and not relevant to an Element’s
impact on the grid. We suggest instead that to obtain an exclusion for such a quasi-radial Element, the owner
be required to demonstrate that the Element has no more than a 5% transfer distribution factor on any BES
Element for transfers that could be curtailed through the NAESB TLR procedure (e.g., interchange
transactions, or generator to load distribution factors (GLDF) for BES generators). Transfer distribution factor
(or GLDF) is a good measure of an Element’s impact on the grid and is not subject to varying interpretations.
In addition, NAESB standards are also approved by FERC and mandatory to jurisdictional entities. Hence, the
5% TDF “Curtailment Threshold” has already been approved by FERC as indicating an insufficient impact on
the BES to be considered for TLR. And, it shows consistency between NERC and NEASB standards.

Transmission Access Policy
Study Group

Yes

TAPS supports the criterion in concept, but “intention[]” is a vague term and not relevant to an Element’s
impact on the grid. We suggest instead that to obtain an exclusion for such a quasi-radial Element, the owner
be required to demonstrate that energy transfers subject to NAESB TLR procedures (Interchange
Transactions or BES generator to load) have no more than a 5% transfer distribution factor (TDF) on the
Element that is a candidate for exception. Transfer distribution factor is a good measure of an Element’s
impact on the grid and is not subject to varying interpretations.

Edison Electric Institute

Yes

A radial system by definition transports power from the BES System to a Distribution System, similarly an
LDN operates in a like manner. A strict reading of the above criteria would exclude both from consideration
yet the definition allows both. We believe that in an attempt to develop a set of criteria useful for all situations,
the outcome has weakened the original intent as set in the Definition. Although much of the criteria used is
largely appropriate, a stricter adherence to the BES definition criteria would substantially help to avoid
confusion between what was developed as principles and what was developed as the BES Definition.

Bonneville Power Administration

Yes

BPA suggests that the SDT provide a method for assessing power transport based on intake to serve load

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment
versus outflow. BPA requests that the SDT clarify that the qualifying statements i-v for the fourth item are “or”
statements.

PacifiCorp

Yes

All of PacifiCorp’s responses are based on the application of these items to a given interconnection and not
on a continental basis. See comments on question 10. This criterion is very similar to parts of exclusion 3 of
the proposed bright-line, which states “d) Not used to transfer bulk power: The LDN is not used to transfer
energy originating outside the LDN for delivery through the LDN; and e) Not part of a Flowgate or transfer
path: The LDN does not contain a monitored Facility of a permanent flowgate in the Eastern Interconnection,
a major transfer path within the Western Interconnection as defined by the Regional Entity, or a comparable
monitored Facility in the Quebec Interconnection, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).”If the intent of this requirement is to capture local
distribution networks that may be included under the proposed bright-line definition, then this requirement has
merit.

Western Electricity Coordinating
Council

Yes

WECC agrees in concept with this characteristic, but believes that there needs to be more clarity of what
constitutes the evidence. Since flow data is used for characteristic c, it seems that the same sort of data (but
separated into hourly flow in and hourly flow out) could be used to demonstrate this. Otherwise, a simple
procedure that claims “power entering this system is not intentionally transported through the system to some
other system” would meet the letter of the law, but gives no description of how this is achieved. If Operating
Procedures are allowed, more clarity must be provided on what those procedures must entail.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the characteristic associated with the
unintentional transporting of power through a system Element with delivery to another system Element as qualifying criterion. Based on industry response and
further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational
characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was
dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of the facilities in question
and to document the operational performance as appropriate through submittal of an exception request form along with any other supporting documentation for
the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support
the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as presently being drafted.
Electricity Consumers Resource
Council (ELCON)

Yes

This requirement should be further relaxed to allow for intentional flows that are provided as a courtesy to the
local distribution company. In such cases, private, customer-owned facilities may be used to deliver power
from a DP to a small number of the DP's retail customers who are unaffiliated with the owner/operator of the
private network. These flows are generally de minimis.

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Organization

Yes or No

Question 4 Comment
We also recommend that this item (with our qualification) be added to the BES definition.

Oregon Public Utility Commission
Staff

Yes

Use of the 100 kV brightline and the core BES definition as proposed is an overreach into local distribution
systems and an overreach of FERC’s authority as set out in the FPA 215. A full engineering technical
analysis - required every 2 years - is too onerous and not necessary for identifying most local distribution
elements miss-identified as BES Elements. A simple screening methodology consistent with the 7-Factor
Test (from FERC Order 888) is needed as the first stage of the exception process.

Response: The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.
The SDT appreciates your comments. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a
new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide greater
continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It
has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new process
requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to
validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO
as established in the Rules of Procedure as presently being drafted.
Georgia System Operations
Corporation

The concept of “intentional” transport of power is vague and needs more specificity for this to be clear.
Also, it would help to have more information about the sort of “operational procedures” that would be
acceptable as evidence.

Response: The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.
PPL Supply

No

See comments in Questions 9 and 10

Response: See response to Q9 & Q10.
Harney Electric Cooperative, Inc.

Yes

Hydro-Quebec TransEnergie

Yes

Oncor Electric Delivery

Yes

Oncor Electric Delivery agrees with the proposed language that describes the exclusion criteria based upon
the non - intentional flow of power through the system to some other system.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
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Organization

Yes or No

Consumers Energy Company

Yes

American Electric Power

Yes

Orange and Rockland Utilities,
Inc.

Yes

Spyker

Yes

Occidental Energy Ventures
Corp.

Yes

Consolidated Edison Co. of NY,
Inc.

Yes

New York Power Authority

Yes

New York State Reliability
Council

Yes

Hydro One

Yes

Electric Market Policy

Yes

Northeast Power Coordinating
Council

Yes

ACES

Yes

Question 4 Comment

Requiring that “power entering the system is not intentionally transported through the system to some other
system” is a reasonable approach.

NYPA agrees that power flow wheeled through a system indicates that the system potentially has more than
one source. Therefore, the element in question is not radial.

We agree with this path.

Response: Thank you for your support. However, based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Question 4 Comment

limit. It has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new
process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of
an exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the
submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation
with the ERO as established in the Rules of Procedure as presently being drafted.

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5. Exclusions - The SDT has set up one path for evidence that includes technical analysis. Do you agree
with this requirement? If you do not support this requirement or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. In addition, in the comment field, please provide your thoughts on the proposed metrics
for analysis and the appropriate values to replace ‘TBD,’ including technical rationale for your
argument.
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion
criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be
considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The new process
requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as
appropriate through submittal of an exception request form along with any other supporting documentation for the exception
being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of
whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established
in the draft Rules of Procedure.

Organization

Yes or No

Northeast Power Coordinating
Council

No

SERC Planning Standards
Subcommittee

No

SPP Standards Review Group

No

NERC Staff Technical Review

No

Iberdrola USA

No

Tri-State Generation and
Transmission Association

No

Question 5 Comment

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Exceptions — Project 2010-17

Organization

Yes or No

Hydro One

No

MRO's NERC Standards Review
Forum

No

PacifiCorp

No

ReliabilityFirst

No

Tennessee Valley Authority

No

PPL Supply

No

Southern Company

No

Muscatine Power and Water

No

South Carolina Electric and Gas

No

Glacier Electric Cooperative

No

Exelon

No

Georgia Transmission
Corporation

No

Consolidated Edison Co. of NY,
Inc.

No

ISO New England

No

The United Illuminating Company

No

Question 5 Comment

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Entergy Services

No

Orange and Rockland Utilities,
Inc.

No

Pepco Holdings Inc

No

American Transmission
Company, LLC

No

Consumers Energy Company

No

Independent Electricity System
Operator

No

United Electric Co-op Inc.

Yes

Oregon Trail Electric
Cooperative, Inc.

Yes

Central Lincoln

Yes

Oncor Electric Delivery

Yes

Salem Electric

Yes

Duke Energy

Yes

Grant County PUD No. 2 (Grant)

Yes

Hydro-Quebec TransEnergie

Yes

for Snohomish County PUD

Yes

Question 5 Comment

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Northwest Public Power
Association (NWPPA)

Yes

Big Bend Electric Cooperative,
Inc.

Yes

NESCOE

Yes

Kootenai Electric Cooperative

Yes

Tacoma Power

Yes

MidAmerican Energy

Yes

Edison Electric Institute

Yes

Florida Municipal Power Agency

Yes

Transmission Access Policy
Study Group

Yes

ISO/RTO Standards Review
Committee

Yes

Western Electricity Coordinating
Council

Yes

New York State Reliability
Council

Yes

Electricity Consumers Resource
Council (ELCON)

Yes

New York Power Authority

Yes

Question 5 Comment

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Blachly Lane Electric Cooperative

Yes

Springfield Utility Board

Yes

Flathead Electric Cooperative,
Inc.

Yes

Clark Public Utilities

Yes

Central Electric Cooperative

Yes

Clearwater Power Electric
Cooperative

Yes

Consumer's Power Inc.

Yes

Coos-Curry Electric Cooperative

Yes

Douglas Electric Cooperative

Yes

Fall River Electric Cooperative

Yes

Lane Electric Cooperative

Yes

Lincoln Electric Cooperative

Yes

Lost River Electric Cooperative

Yes

Northern Lights Electric
Cooperative

Yes

Okanogan Electric Cooperative

Yes

Question 5 Comment

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
Exceptions — Project 2010-17

Organization

Yes or No

Raft River Rural Electric
Cooperative

Yes

Salmon River Electric
Cooperative

Yes

West Oregon Electric
Cooperative

Yes

Pacific Northwest Generating
Cooperative

Yes

Umatilla Electric Cooperative

Yes

Consumer's Power Inc.

Yes

BGE

Yes

Spyker

Yes

Benton Rural Electric Association

Yes

American Electric Power

Yes

Northern Wasco County PUD

Yes

Xcel Energy

Yes

Question 5 Comment

Response: Thank you for your response.

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Consideration of Comments on Definition of the Bulk Electric System (BES) Technical Principles for Demonstrating BES
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5a. Comments on approach:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion
criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be
considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The new process
requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as
appropriate through submittal of an exception request form along with any other supporting documentation for the exception
being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of
whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established
in the draft Rules of Procedure.

Organization
Northeast Power Coordinating
Council

Yes or No

Question 5a Comment
This method may allow an entity to exclude Elements which perform a transmission function, but that are not
the most limiting Element. “
Not being necessary for reliability operation” needs definition.
The SDT should consider developing a Guidance Document to provide examples and insights to guide
prospective filing entities.
The TPL Reliability Standards already describe the full set of requirements for a reliable system. Why are
added requirements necessary? Why would any such added criteria not conflict with the TPL Reliability
Standards to the extent that they were either more or less restrictive?
Entities should be given an option to conduct an analysis to demonstrate if an element is necessary for the
operation of a transmission network. NERC should specify all the relevant criteria categories to be listed as
under 2 (a). NERC should avoid prescribing numerical values, but instead establish a range of values (or
reference industry standards) that would be consistent with industry/ regional standards or practices without
compromising the reliability of the transmission network.

SERC Planning Standards
Subcommittee
Tennessee Valley Authority
Southern Company

As written, most of this approach makes no sense. The words imply that if you have planned the system
properly, you can exclude it from the BES! In TPL studies you make sure that voltage dips, frequency
excursions, voltage deviations are acceptable, oscillations are damped, and no cascading outages occur. So
if you meet the performance requirements of TPL studies, you can exclude the element from the BES. What
good is this?

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Exceptions — Project 2010-17

Organization

Yes or No

Question 5a Comment

Georgia Transmission
Corporation
City of Redding

It appears the industry experts have a very difficult time identifying any set of measurement factors that can
be applied on a consistant basis to any system and produce similar results, therefore there needs to be
geographical variation where the experts in the local systems can make a determination.

NERC Staff Technical Review

NERC staff is not opposed to development of evidence based on technical analysis; however, the type of
analysis included in this exception criterion requires extensive resources and lacks sufficient detail to allow for
consistent and repeatable application. Concerns with this approach include (1) the ability to provide sufficient
guidance on the system conditions and contingencies necessary to support an exception request,
(2) difficulty with identifying thresholds for items iv-1 through iv-4, and
(3) the ability to address interdependencies among exception requests.
These concerns can be addressed by deleting this second path for evidence and including technical analysis
on a limited basis to assess performance as described in our response to Question 2. If the SDT elects to
retain this second path for evidence, then our three concerns must be addressed. In particular with regard to
our third concern, the ERO must be able to deny requests for exception based on the cumulative impact of all
previously approved exceptions.

ACES

Overall, the approach is reasonable. However, we disgree with 2.b which states that the ERO can override
the criteria. Once criteria is established, the ERO should not be able to override the determination. The
ability of the ERO to override implies the criteria is not sufficient and needs to be modified. Rather than
override, the ERO should seek to modify the criteria if it is not sufficient.

Edison Electric Institute

In general, we agree that an alternative path allowing a technical analysis to demonstrate that a Facility (or
Element) should not be considered part of the BES is appropriate. However, we disagree with the measures
offered and suggest an alignment with efforts already being developed within NERC’s Event Analysis Working
Group.EEI proposes that the technical analysis criterion which has been proposed is too complicated,
inconsistent with what is currently being done across the regions and submits that a better approach would be
to align reliability impacts with the Event Analysis Criteria being developed by NERC’s EAWG.
These criteria would be a better benchmark as to whether a Facility or Element should be excluded from the
BES. The proposed alternate criteria are as follows:(1) The loss of the Facility (or Element) would not
interfere or negatively impact the BES from staying within acceptable limits (i.e., frequency, voltage and

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Exceptions — Project 2010-17

Organization

Yes or No

Question 5a Comment
System Operating limits) following a fault on or loss of that Facility (or Element);
(2) The loss of the Facility (or Element) would not interfere or negatively impact the BES from performing
acceptably after credible contingences;
(3) Facility (or Element) faults, failures, or trips do not push the system to a point of Instability or otherwise
initiate cascading outages;
(4) BES facilities are protected from unacceptable damage by operating the Facility (or Element) within its
ratings; and
(5) The unexpected loss of the Facility (or Element) does not negatively impact the BES from achieving its
mission of to supply the aggregate electric power and energy requirements of its customers.

Florida Municipal Power Agency

FMPA supports including specific technical criteria that Elements must meet to obtain an exclusion through
the exception process. This approach will facilitate uniform application of the exception process. FMPA
responds to the first five proposed criteria in response to 5b-5e below. In the sixth proposed criterion, “steady
state stability” is ambiguous, does the SDT mean voltage stability, power angle curve stability, or small signal
stability?
The seventh proposed criterion, “No cascading outages,” is insufficiently granular and should be discarded.
The criteria are intended to measure whether, among other things, a particular Element can cause a
cascading outage. They need to set out how decision-makers will determine whether an Element can cause
a cascading outage, not simply state that an Element that can cause a cascading outage cannot be excluded
from the BES.

Transmission Access Policy
Study Group

TAPS supports including specific technical criteria that Elements must meet to obtain an exclusion through
the exception process. This approach will facilitate uniform application of the exception process. TAPS
responds to the first five proposed criteria in response to 5b-5e below. The seventh proposed criterion, “No
cascading outages,” is insufficiently granular and should be discarded. The criteria are intended to measure
whether, among other things, a particular Element can cause a cascading outage. They need to set out how
decision-makers will determine whether an Element can cause a cascading outage, not simply state that an
Element that can cause a cascading outage cannot be excluded from the BES.

ISO/RTO Standards Review
Committee

Predictive analysis of an accurate model is useful in determining the importance of various elements of the
system.

Iberdrola USA

A facility is not BES if it is not necessary for reliable system operation, based on a TPL-type analysis similar to

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Organization

Yes or No

Question 5a Comment
NPCC Document A-10 “Classification of Bulk Power System Elements” - this type of analysis was rejected by
FERC. Besides, at 115kV, calculated distribution factors for interfaces between areas (where higher voltage
lines, e.g., at 230kV and 345kV, are included as part of the interface definition) tend to be small and
inaccurate. The method used to calculate distribution factors is an approximate method which must be reevaluated for small values of distribution factors.

Tri-State Generation and
Transmission Association

This appears very similar to the “material impact” proposal that FERC has previously disallowed, so we
recommend removing 2.
If retained, remove 2.(b) because allowing the ERO to override the technical justification and analysis
devalues such analysis to the point of it being meaningless.

Hydro One

We agree that entities should be given an option to conduct an analysis to demonstrate whether or not an
element is necessary for the operation of the transmission network.
We also support that NERC should specify the entire relevant criteria category to be listed under exclusion
criteria 2 (a). However, we suggest that NERC should avoid prescribing numerical values but establish a
range of value (or reference industry standard) that would be consistent with industry/ regional standards or
practices without compromising the reliability of the transmission network.

MRO's NERC Standards Review
Forum

NSRF proposes that this technical analysis criterion be replaced by criteria that are more closely tied to the
Adequate Level of Reliability (ALR) characteristics.
The following alternate criteria are offered as possible examples, “(1) the BES can be controlled to stay within
acceptable limits following a fault on or loss of the Element; (2) the BES performs acceptably after credible
contingences of the Element; (3) the Element does not limit the impact and scope of instability and cascading
outages when they occur; (4) BES facilities are protected from unacceptable damage by operating the
Element within its ratings; (5) the integrity of the BES can be restored promptly following a fault on or loss of
the Element; and (6) the BES has the ability to supply the aggregate electric power and energy requirements
of the electricity consumers at all times, taking into account scheduled or reasonably expected unscheduled
outages of the Element.
In addition, NSRF is not aware of any continent-wide appropriate BES performance measures for voltage dip,
frequency excursion, voltage deviation, stability, etc. and NSRF speculates that different values are likely for
different regions and system characteristics across the continent. As a result, NSRF believes it is not
advisable to try to adopt unproven values without reasonable industry investigation and development.

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Organization
Bonneville Power Administration

Yes or No

Question 5a Comment
BPA comments on the technical analysis are as follows:1. Who is responsible for running these studies (the
BA, individual utilities....?)
.2. The analysis and criteria need to be better defined for the technical analysis.
3. What did SDT mean by “having a distribution factor of TBD% for any other Element”? This should
probably reference a specific PTDF for a path or source/sink group.
4. What contingencies are studied to show the elements meet the transient voltage dip, frequency excursion,
etc. (i.e. are they 3 phase delayed cleared faults, single phase faults, etc.)? Furthermore, the exclusion
criteria needs to be much more specific about how the study is to be conducted in general - i.e.: Regional
Entities have established study guidelines and procedures to determine voltage and frequency criteria.
Specifically, is it the intent that the element being proposed for exclusion be opened in the study and then the
standard contingency list applied to the rest of the system? Presumably, if there is no difference in system
performance with the element in or out, then it could be excluded. Alternatively, is it intended that the
contingency to be tested is simply the loss of the element proposed for exclusion?
5. What elements and/or flow gates should be monitored for these analyses?
6. In “Other”, the SDT should add “The limiting element for a flow-gate cannot be excluded from the BES”.
7. How will the criteria be set? Will they follow current standards? (i.e. TPL-001)? The technical principles
must identify what category(ies) of TPL studies must be run. BPA requests clarification on what the values for
the threshold criteria and/or disturbances would be?

PacifiCorp

5a. Comments on approach: All of PacifiCorp’s responses are based on a given interconnection and not on a
continental basis. See comments on question 10. Using any technical criteria will allow many elements to be
excluded from the BES regardless of the element’s criticality to the interconnected system.
Whatever technical criteria is established should only be applied to elements under 200 kV and any radial
elements above 200 kV

ReliabilityFirst

to complicated and will only raise debate between FERC, NERC, the Regions and the Registered Entities

Western Electricity Coordinating
Council

WECC agrees in concept that a technical analysis can be used and should be allowed to show that an
element is not necessary for reliable operation. However, the technical analysis must be based on sound
reasoning and a justification must be given as to why the analysis makes a showing that the element is not
necessary for reliable operation. Furthermore, the technical principles must identify what category(ies) of TPL

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Organization

Yes or No

Question 5a Comment
studies must be run.
Finally, the values used for the threshold criteria and/or disturbances must be more stringent than the
applicable TPL criteria/disturbances. Otherwise the argument becomes circular because all BES elements
must meet the TPL criteria, so by meeting them all elements could be excluded.

New York State Reliability
Council

A single threshold value for performance based testing does not recognize differences in regional system
characteristics. Therefore, regional approaches for at least generation exclusions should be used, like
NPCC's A-10 criterion.

National Grid

We do not agree with all the criteria listed in point 2.a.iv. For example we believe that the term in 2.a.vi.6
“Steady-state Stability - positively damped” does not relate to the concept of steady-state stability. We
believe an acceptable measure of steady-state stability would be an angle difference across the transmission
line. That difference can vary depending on the line; however, a rule of thumb is typically 45 degrees which
provides a 30% steady state stability margin. As mentioned previously, the exception process should be
strictly limited to the procedures for application and approval and should not include substantive elements.

Muscatine Power and Water

Would like to propose that this technical analysis criterion be changed to criteria that are more closely tied to
the Adequate Level of Reliability (ALR) characteristics.
Would like to offer the following alternate criteria as possible examples, “(1) the BES can be controlled to stay
within acceptable limits following a fault on or loss of the Element;
(2) the BES performs acceptably subsequent to credible contingences of the Element;
(3) the Element does not limit the impact and scope of instability and cascading outages once they occur;
(4) BES Facilities are protected from undesirable damage by operating the Element within its ratings;
(5) the reliability of the BES can be restored promptly subsequent to a fault on or loss of the Element; and
(6) the BES has the ability to supply the aggregate electric power and energy requirements of the electricity
consumers at all times, taking into account scheduled or reasonably expected unscheduled outages of the
Element.
Currently not aware of any continent-wide appropriate BES performance metrics for voltage dip, frequency
excursion, voltage deviation, stability, etc. and would speculate that different values are likely for the different
regions and system characteristics across the continent. Thus, it is not advisable to try to adopt unproven
values without reasonable industry investigation and development.

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Organization
Blachly Lane Electric Cooperative
Flathead Electric Cooperative,
Inc
United Electric Co-op Inc.
Oregon Trail Electric
Cooperative, Inc.
Central Lincoln
Salem Electric
Grant County PUD No. 2 (Grant)
for Snohomish County PUD
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc.

Yes or No

Question 5a Comment
We agree conceptually with the idea that two different paths to exclusion should be adopted, one relying upon
readily identifiable characteristics that are ordinarily associated with non-BES transmission facilities, and one
relying on technical analysis to determine whether or not an Element or group of Elements has a measurable
impact on the threat of cascading outages, separation events, or instability on the interconnected bulk system.
If technical analysis demonstrates that Elements create no material threat of such reliability events, they
should properly be excluded from the BES.
Snohomish Public Utility District has prepared a White Paper proposing a performance-based approach to
support the technical determination whether Elements should be excluded from the BES, which we commend
to the SDT for study.
We also commend the work of the WECC BES Task Force and the WECC Technical Studies Subcommittee,
both of which have devoted substantial time and resources to developing a workable and technically
defensible process for excluding Elements classified as BES based upon their electrical characteristics. See
WECC BES Task Force Proposal 6, App. A at 3-9 & App. B at pp. B-4 to B-7 (posted Feb. 18, 2011)
(available at: http://www.wecc.biz/Standards/Development/BES/default.aspx).
We recommend that the SDT modify its approach to the technical exclusion process to match the approach
advocated in Snohomish’s White Paper, which is based upon the approach recommended by the WECC BES
Task Force.

Kootenai Electric Cooperative

South Carolina Electric and Gas

As written, most of this approach makes no sense. The words imply that if you have planned the system
properly, you can exclude it from the BES! In TPL studies you make sure that voltage dips, frequency
excursions, voltage deviations are acceptable, oscillations are damped, and no cascading outages occur. So
if you meet the performance requirements of TPL studies, you can exclude the element from the BES. This
does not seem to be what was intended.

Glacier Electric Cooperative

I strongly agree that there should be a way for elements to be excluded from the BES based on a technical
analysis. However, the current approach only provides one technical avenue for exclusion and that is through
a transmission planning study. Performing and analyzing such a study could be very, very difficult for a small
entity to do. If this is the approach that NERC continues with, then I believe there needs to be some extra
language outlining who is responsible for performing and analyzing these transmission planning studies. The
question is should the RRO (WECC, etc.) be responsible for performing the study and determining through
the technical criteria what elements are included and excluded in the BES, or should that resposiblity fall on

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Organization

Yes or No

Question 5a Comment
control area operators within an RRO, or should that responsibility fall on individual entities? I believe it
should fall on either the RROs or the control area operators within the RROs.
Perhaps an alternative approach could be to establish a few techincal checks that could be evaluated first
before a transmission planning study is required. For example, a max fault MVA value could be established
and if the available fault MVA at an element is less than the established value, then that element and could be
excluded without having to go through a transmission planning study. If the available fault MVA at the
element is above the established value, then the study would have to be done for determination.

Exelon

This item calls for the use of criteria in order to prove that a facility should be excluded the BES. First of all,
the items 5b - 5e do indeed require extensive technical analysis which will be outside of the capabilities of
many users of the BES.
Furthermore, it is not clear who’s criteria will be used? The user’s? The Transmission Owner’s? The Planning
Authority’s? This question of ownership needs to be resolved and in itself poses a problem for this process.
If differing criteria levels are used across the continent, there remains the possibility that similarly-situated
facilities in different Regions will not be treated consistently.

Consolidated Edison Co. of NY,
Inc.

The technical analysis approach may have merit. However, we have a number of questions about how it
would be implemented in practice. We are concerned that this method may allow an entity to exclude
Elements simply because they are not the most limiting Element in a particular TPL analysis. What does “not
being necessary for reliability operation” mean? Please define.
The SDT should consider developing a Guidance Document to provide examples and insights to guide
prospective filing entities.
The TPL Reliability Standards already describe the full set of requirements for a reliable system. Why are
added requirements necessary? Why would any such added criteria not conflict with the TPL Reliability
Standards to the extent that they were either more or less restrictive?

ISO New England

The use of distribution factors is a significant concern. The term distribution factor is used a number of ways
in the industry. Is this determined using the percentage pickup on the element in question following the loss
of another element, or is this the percentage of a transfer that is picked up on the element in question, or a
combination of both?
Item 2.a.ii states that the TPL studies have to be run if the model is updated. The distribution factor is not
required to be calculated as part of the TPLs and therefore will require additional analysis in all
circumstances, not just when the model is updated.

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Yes or No

Question 5a Comment

The United Illuminating Company

This is not very different from trying to demonstrate no adverse impact outide the local area.

Georgia System Operations
Corporation

It would be helpful to specify which TPL Standard(s) the referenced studies are usually prescribed for.

Entergy Services

The entire approach seems overly complex and difficult to document.

Clark Public Utilities

Clark agrees conceptually with the idea that two different paths to exclusion should be adopted, one relying
upon readily identifiable characteristics that are ordinarily associated with local distribution and not BES
transmission facilities, and one relying on technical analysis to determine whether or not an Element or group
of Elements has a measurable impact on the threat of cascading outages, separation events, or instability on
the interconnected bulk system. If technical analysis demonstrates that Elements create no material threat of
such reliability events, they should properly be excluded from the BES.

Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc.
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative

Clark supports the technical arguments and the White Paper presented by Snohomish County PUD in their
comments. Clark recommends that the SDT modify its approach to the technical exclusion process to match
the approach advocated in the White Paper, which is based upon the approach recommended by the WECC
BES Task Force.

Lane Electric Cooperative
Lincoln Electric Cooperative
Lost Rive Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric

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Organization

Yes or No

Question 5a Comment

Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc
Benton Rural Electric Association
Northern Wasco County PUD

BGE

BGE believes that there is value in allowing for exclusions through a technical analysis path.
Because multiple entities may perform “planning assessments” using different models, the phrase, “*the*
most recent *applicable* planning assessment” should be clarified to avoid ambiguity as to which model(s)
are acceptable. It may be useful to designate the models used in the Planning Authority analyses as
acceptable.

Spyker

We agree that entities should be given an option to conduct an analysis to demonstrate if an element is
necessary or not for the operation of transmission network. We also support that NERC should specify all the
relevant criteria category to be listed as under 2 (a). However, we suggest that NERC should avoid
prescribing numerical values but establish a range of value (or reference industry standard) that would be
consistent with industry/ regional standards or practices without compromising the reliability of transmission
network.

Long Island Power Authority

Exclusion under this criteria would require that the analysis be performed by the registered TP. Criteria
identified is based on interconnection to neighboring utilities.

Orange and Rockland Utilities,
Inc.

This approach is not necessary since NERC TPL Reliability Standards already addressed how to maintain a
reliable electric system.

Pepco Holdings Inc

Generally agree that a specific technical analysis approach (power flow studies) showing no impact on BES is
appropriate, but don’t know how to define specific criteria on which to base decision.

Duke Energy

Duke Energy agrees with the approach of using a technical analysis based on transmission system modeling
but the specific criteria do not need to be specified here - they should be consistent with the latest revision of

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Question 5a Comment
the TPL-001. R5 of TPL-001-2, Transmission System Planning Performance Requirements states that each
Transmission Planner and Planning Coordinator shall have criteria for acceptable System steady state
voltage limits, post-Contingency voltage deviations, and the transient voltage response for its System. The
technical analysis required for exclusion of an Element from the BES should evaluate the loss of the Element
against a more conservative set of criteria than that specified by the Transmission Planner and Planning
Coordinator responsible for that Element. There are currently no continent-wide performance levels defined
for these evaluations, and there is no technical basis for developing performance levels that would be
applicable continent wide.

American Transmission
Company, LLC

ATC proposes that this technical analysis criterion be replaced by criteria that are more closely tied to the
Adequate Level of Reliability (ALR) characteristics. The following alternate criteria are offered as possible
examples, “(1) the BES can be controlled to stay within acceptable limits following a fault on or loss of the
Element;
(2) the BES performs acceptably after credible contingences of the Element;
(3) the Element does not limit the impact and scope of instability and cascading outages when they occur;
(4) BES facilities are protected from unacceptable damage by operating the Element within its ratings; and
(5) the BES has the ability to supply the aggregate electric power and energy requirements of the electricity
consumers at all times, taking into account scheduled or reasonably expected unscheduled outages of the
Element. In addition, ATC is not aware of any continent-wide appropriate BES performance measures for
voltage dip, frequency excursion, voltage deviation, stability, etc. and ATC speculates that different values are
likely for different regions and system characteristics across the continent.
As a result, ATC believes it is not advisable to try to adopt unproven values without reasonable industry
investigation and development.

Manitoba Hydro

Manitoba Hydro does not agree with an impact based approach to establishing BES elements as we believe it
will result in regional differences in the application of the BES definition.
In addition, the resources required to verify the assumptions made in the models used to substantiate a BES
exception would be substantial with no benefit to reliability.
As well, this section appears to be an incomplete process. As currently worded, if the model was not updated
in step ii, then there is no requirement to run the TPL studies indicated in the remainder of step ii.

NESCOE

NESCOE supports the concept of allowing an additional path to justifying an exclusion from the BES.

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Organization

Yes or No

Question 5a Comment
NESCOE could support development of technical criteria such as those proposed, but does not have specific
recommendations at this time.
As stated earlier, any excluded elements must be connected to the BES using fully NERC compliant
protection systems.

Independent Electricity System
Operator

The technical analysis path for exclusions and inclusions allows for override of the listed “criterion”. It is not
clear what will be the basis for overriding, and what process will be followed? Is the “criterion” meant to be all
of (1) to (7) in (a), or is it any one of them? This needs to be clarified.
We agree that entities should be given an option to conduct an analysis to demonstrate if an element is or is
not necessary for the operation of transmission network. However, consistent with our earlier comments, we
suggest that the exception criteria avoid prescribing numerical values.
A transmission element is not necessary for the reliable operation of an interconnected electric transmission
system, if it can be removed without effecting bulk transfer capabilities. In our view, testing in accordance
with the TPL standards should be the basis for establishing this. One way of demonstrating that an element is
not required for the transfer of bulk power is to show that with the element out of service (and with all
elements that received exemptions in the past also out of service) and at the required power transfers:1. Precontingency and post-contingency loadings on all BES elements are within applicable ratings.2. Precontingency and post-contingency voltages on the BES are within established ratings.3. All units on the BES
remain synchronized following contingencies.4. All voltage declines on the BES are within established limits
(if any limits were defined).5. All steady-state oscillations and oscillations following a contingency are
positively damped.6. Transient voltage dips do not exceed established limits anywhere on the BES (if any
limits were defined).7. Frequency excursions do not exceed established limits anywhere on the BES (if any
limits were defined). Our view is that the exception criteria should NOT specify the voltage decline limits,
allowable frequency excursion or the allowable transient voltage dip because every region will have different
limits depending on the characteristics of their power system. This would be consistent with Requirement R5
of the recently balloted standard TPL-001-2, which requires each Transmission Planner and Planning
Coordinator to have criteria for acceptable System steady state voltage limits, post-Contingency voltage
deviations, and the transient voltage response for its System. Required power transfers are the transfers
required to meet the “one day in ten year” loss of load expectation criteria.
Further, exception criteria for generators must also be defined. A power system is typically planned to be able
to service the load under multiple dispatch scenarios and, therefore, multiple generators disconnected from
the transmission system will unlikely reduce the ability of the power system to supply the load. In fact, market
forces typically determine whether or not a generator is connected. However, transmission lines are built to
achieve specific transfer capabilities and, therefore, directly affect the power system’s ability to meet the

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Question 5a Comment
electricity demand. Since, generators and transmission elements contribute to reliability in a very different
ways, the criteria exempting generators should be different from the criteria exempting transmission elements.

MidAmerican Energy

The concept of using TPL analyses and normalized Transmission Distribution Factors makes basic sense as
a way to determine what elements react to system transfers and what elements react primarily to distribution
load.In general all facilities below 100 kV should be exlcuded by default as distribution according to the 2005
Federal Power Act.
Transmission Distribution Factors tend to show low bulk power system transfers (less than 2%) based on their
inherent high impedance when normalized. Normalizing the transmission impedance means diving the ohmic
value by a base impedance which is dominated by a (kV^2) term. Per Unit Impedance = (transmission line
ohms / base impedance) where base impedance = (kV^2 / MVA). Using a common MVA base value of 100
MVA, a base impedance at 69kV = 47.6 ohms versus at 161 kV = 259.2 or at 345 kV = 1190.2 ohms. The
rapid increase of the denominator as kV goes higher insures that a 69 kV system is high impedance
compared to any high kV facilities and therefore nearly insure the 69 kV system is local in nature and reacts
primarily to load. Therefore it is distribution.
This all supports the conclusion that all facilites below 100 kV should be classified as distribution according to
the 2005 FPA and exempted by default. Facilities below 100 kV could be brought into scope if TPL analyses
show instability, uncontrolled separation, or cascading as defined in the 2005 FPA.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters
utilized to analyze system Elements for potential exclusion from the BES. Based on industry response and further analysis, the SDT has abandoned the initial
exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to
a defined value and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The
new process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through
submittal of an exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review
the submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and
recommendation with the ERO as established in the draft Rules of Procedure.
PPL Supply

See comments in Questions 9 and 10

Response: See response to Q9 & Q10.
Tacoma Power

Tacoma Power generally agrees with approach used on the technical analysis path for exclusions.

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Question 5a Comment

Idaho Falls Power

We generally agree with having two paths towards exclusion.

New York Power Authority

In general, NYPA agrees with this approach except as noted below.

Springfield Utility Board

In general, SUB supports a technical analysis approach as a secondary/ alternative option for qualifying to
apply for BES Element exclusions.

Consumers Energy Company

Generally, this approach seems sound.

Oncor Electric Delivery

Oncor Electric Delivery agrees with the proposed language that describes the exclusion criteria based
technical analysis.

Response: The SDT appreciates your support. However, based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.

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5b. Comments on distribution factor measurement:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization
Northeast Power Coordinating
Council

Yes or No

Question 5b Comment
2.a. The term “Planning Assessment” is not a defined term in the NERC Glossary of Terms Used and should
not be capitalized, or it should be defined.
2.a.iv.1. Distribution Factor - This is a judgment of what feeder power flow participation level is material and
what is non-material. While TDF and OTDF analysis is an indication of contributions from the element, the
SDT should avoid setting values and instead describe the intended performance outcome from a distribution
factor measurement. Note that ultimately NERC as an ERO or relevant regulatory authority will approve the
application and can assess the performance outcome in their decision making presented in an entity’s
application.

SERC Planning Standards
Subcommittee

This is the only part of this technical analysis that may make sense. If the loss of any element of the BES
results in a distribution factor of less than X% on the element being considered for exclusion, then exclude it.

Tennessee Valley Authority

We suggest a value of 3% for this, since 3% is the threshold typically used in transfer studies.

Southern Company
South Carolina Electric and Gas
Georgia Transmission
Corporation
SPP Standards Review Group

There are situations where setting a minimum TDF will not work due to the nature of the TDF. For example, a
radial line connected to a bus with two networked lines. The radial line serves only load and would normally

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Yes or No

Question 5b Comment
be excluded from the BES. However, if we use the TDF as a factor the radial line would be included in the
BES since the TDFs would be high.

Edison Electric Institute

In general, we do not agree this is a relevant factor for consideration and should be excluded.

Florida Municipal Power Agency

The first proposed criterion, “Having a distribution factor of 5% for any other Element,” should instead be
“Having a distribution factor of 5% for Interchange Transactions or BES generator to load curtailable in
Transmission Loading Relief stages one through five.”

Transmission Access Policy
Study Group

The first proposed criterion, “Having a distribution factor of 5% for any other Element,” should instead be
“Having a distribution factor of 5% for curtailable Interchange Transactions or BES generator to load identified
in Transmission Loading Relief stages one through five.”
An Element with a higher distribution factor only on a non-BES Element should not be considered part of the
BES on that account.

ACES

Yes

The IDC uses 5% as a distribution factor cutoff so this might be a reasonable value. “Transmission Transfer
Capability” which was published by NERC in 1995 recommends using 3% on page 18 for transfer capability
studies.

ISO/RTO Standards Review
Committee

Distribution factors by themselves are not sufficient evidence that elements are not important to the system.
Multiple elements may have significant distribution factors related to various portions of the system, but that
doesn’t necessarily mean that loss of those elements will result in a reliability risk to the system.

Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

Hydro One

Distribution Factor is an estimate of what feeder power flow participation level material is and what nonmaterial is.While TDF and OTDF analysis is an indication of contributions from the element, hence the SDT
should avoid setting values and instead describe the intended performance outcome from a distribution factor
measurement. Note that ultimately NERC as an ERO or relevant regulatory authority will approve the
application and can assess the performance outcome in their decision making presented in an entity’s
application.

MRO's NERC Standards Review

NSRF proposes replacing this factor with those cited above because a distribution factor measurement
indicates how much system changes affect the element, not how much a fault or loss of the element would

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Organization
Forum

Yes or No

Question 5b Comment
compromise the ALR of the BES.
There is no clear correlation between this factor and any of the six characteristics of Adequate Level of
Reliability (ALR) of the BES.

PacifiCorp

5b.Comments on distribution factor measurement: All of PacifiCorp’s responses are based on a given
interconnection and not on a continental basis. See comments on question 10. Distribution factor has little to
no bearing on entities in the Western Interconnection.

ReliabilityFirst

any impact is an impact, even generation is re-dispatched at 0% in some cases.

New York Power Authority

NYPA does not agree with this measurement. Distribution factors are dependent on the number of radial
transmission lines that connect a single source to a load. For example, if two lines connect a single source to
a load, and one line trips, the distribution factor provides a 100% increase in flow on the remaining line. If
three lines connect the source to the load, and one line trips, the distribution factor for the remaining lines
would be 50%. The SDT should avoid setting values and instead describe the intended performance
outcome from a distribution factor measurement. Note that ultimately NERC as an ERO or relevant regulatory
authority will approve the application and can assess the performance outcome in their decision making
presented in an entity’s application.

National Grid

We don’t think this measurement is necessarily relevant in determining whether an element is necessary to
system reliability. This criterion can be removed from the list.
The exception process should be strictly limited to the procedures for application and approval and should not
include substantive elements.

Muscatine Power and Water

Suggest replacing this aspect with those cited above because a distribution factor measurement indicates
how much system changes influence the element, not how much a loss of the element would compromise the
ALR of the BES.
Currently unable to establish a clear correlation between this factor and any of the six characteristics of
Adequate Level of Reliability (ALR) of the BES.

Blachly Lane Electric Cooperative
Flathead Electric Cooperative,
Inc

The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage Transfer
Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring systems. However in
the Western Interconnection it has never been a definitive indicator of whether a system fault with delayed
clearing would impact a neighboring electric system. While we understand that many entities from the

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Organization
Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative

Yes or No

Question 5b Comment
Eastern Interconnection support the use of such factors, we believe the approach is unlikely to work in the
Western Interconnection.
Based on the significant differences between the four major interconnections in North America, we suggest
that a detailed technical exemption process be allowed on an interconnections wide basis. The Western
Interconnection is a “hub and spoke system” where loads are very remote from large generation plants, with
margins that are based on stability limits. By contrast, the Eastern Interconnection is a tightly meshed system
with loads and generation in close proximity, often creating margins that are based on thermal limitations.
These differences manifest themselves in a variety of ways for various operations. For example, the Western
Interconnection uses a rated-paths methodology while the Eastern Interconnection uses transmission load
relief mechanisms.
Consistent with FERC order 743-A, we support exemption criteria for individual frequency independent
regions, or interconnections.

Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc.
Central Lincoln
for Snohomish County PUD

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Organization
Consolidated Edison Co. of NY,
Inc.

Yes or No

Question 5b Comment
2.a. The term “Planning Assessment” is not a defined term in the NERC Glossary of Terms Used and should
not be capitalized, or alternatively it should be defined.
2.a.iv.1. Distribution Factor - The issue comes down to a judgment call concerning what feeder power flow
participation level is material and what is non-material. In New York, the NYISO has traditionally used a 1%
power transfer distribution factor (power TDF) cut-off. Feeders showing less than a 1% power transfer in a
study are not materially participating in transmission.

ISO New England

The use of distribution factors is a significant concern. The term distribution factor is used a number of ways
in the industry. Is this determined using the percentage pickup on the element in question following the loss
of another element, or is this the percentage of a transfer that is picked up on the element in question, or a
combination of both?
Item 2.a.ii states that the TPL studies have to be run if the model is updated. The distribution factor is not
required to be calculated as part of the TPLs and therefore will require additional analysis in all
circumstances, not just when the model is updated.

The United Illuminating Company

Distribution factor requires a definition.

Clark Public Utilities

The use of distribution factors, such as Power Transfer Distribution Factors (“PTDF”) and Outage Transfer
Distribution Factor ("OTDF") provide insight into the relative impedance of neighboring systems. However in
the Western Interconnection it has never been a definitive indicator of whether a system fault with delayed
clearing would impact a neighboring electric system. While we understand that many entities from the Eastern
Interconnection support the use of such factors, we believe the approach is unlikely to work in the Western
Interconnection.

Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc.
Oregon Trail Electric
Cooperative, Inc.
Salem Electric
Grant County PUD No. 2 (Grant)
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc.

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Organization

Yes or No

Question 5b Comment

Kootenai Electric Cooperative
BGE

BGE requests that it be made clear that the 2(a) iv.1 criteria refers to the of the distribution factor for the loss
of any other facility on the subject Element, whereas criteria 2 through 7 refer to the performance following the
loss of the subject Element.

Spyker

The SDT should avoid setting values and instead describe the intended performance outcomes from the
measurement

Consumers Energy Company

This criterion raises concerns. If based on transfer distribution factor it may have some merit, depending on
the TBD value. However, the criteria should not be based on outage transfer distribution factor, as Draft 1
implies, since loss of certain local distribution facilities can result in local distribution load being transferred to
other local distribution facilities. Distribution facilities should not be prevented from exclusion from BES.

Duke Energy

This should be removed - there is no correlation between distribution factor and whether or not an element is
necessary for reliable operation of the interconnected transmission network.

Hydro-Quebec TransEnergie

Comments on distribution factor measurement: The choice of the maximum distribution factor could be
difficult to establish. For this point, the comparison of the distribution factor prior and after the events could be
considered.

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 5a because a distribution factor measurement
indicates how much system changes affect the element, not how much a fault or loss of the element would
compromise the ALR of the BES. There is no clear correlation between this factor and any of the six
characteristics of Adequate Level of Reliability (ALR) of the BES.

Independent Electricity System
Operator

We do not agree with setting values for this criterion. This should be left to the relevant Transmission Planner
and Planning Coordinator. See our comments in response to Q5a.

Tacoma Power

Tacoma Power generally agrees with the distribution factor measurement in the technical analysis path for
exclusions. We suggest adopting a distribution factor not exceeding 30% on an adjacent system.

MidAmerican Energy

The Distribution Factor measurement is acceptable and should exclude facilities that show a low distribution
factor for bulk power system transfers. An arbitrary low value could be those facilities that show less than a
2% distribution factor.

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Organization

Yes or No

Question 5b Comment

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential exclusion from the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.
Iberdrola USA

See 5a.

Response: See response to Q5a.

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5c. Comments on allowable transient voltage dip measurement:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization

Yes or No

Question 5c Comment

Northeast Power Coordinating
Council

Voltage dip is specified in terms of duration and retained voltage, usually expressed in percentage. Suggest
that either the SDT avoid using voltage dip as a criteria, or clearly specify that the transient voltage not
exceed the X limit of Y cycles (time). References to relevant industry standards such as IEEE standard 13461998 should be made.

SERC Planning Standards
Subcommittee

As stated above, it does not make sense to use this category.

Tennessee Valley Authority
Southern Company
South Carolina Electric and Gas
Georgia Transmission
Corporation
Edison Electric Institute

Presently no regional standards exist for allowable transient voltage dip beyond WECC. It is also doubtful a
useful standard could be developed for all regions or interconnections.

Florida Municipal Power Agency

The second criterion, “Allowable transient voltage dip - criteria TBD,” should specify where the transient
voltage dip is, i.e. “Allowable transient voltage dip on another BES Element for events on the Element that is a
candidate of the Exception Request-criteria TBD.”

Transmission Access Policy

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Yes or No

Question 5c Comment

Study Group
ISO/RTO Standards Review
Committee

These “transient” and “voltage deviation” analyses are highly dependent upon sound and accurate dynamic
system models. Much has been said in recent days about the suspicions that many such models are not truly
accurate enough to predict system response that is close to what actually occurs.

Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

Hydro One

Voltage dip is specified in terms of duration and retained voltage, usually expressed in percentage. We advise
against prescribing limits by the SDT, and instead suggest that either the SDT avoid relating voltage dip
altogether or clearly specify that the transient voltage not exceed the X limit of Y cycles (time). We suggest
SDT to make references to relevant industry standard such as IEEE standard 1346-1998.For example, a
document effective in 2007 titled Ontario Resource and Transmission Assessment Criteria Issue 5.0 mentions
that: “The minimum post-fault positive sequence voltage sag must remain above 70% of nominal voltage and
must not remain below 80% of nominal voltage for more than 250 milliseconds within 10 seconds following a
fault. Specific locations or grandfathered agreements may stipulate minimum post-fault positive sequence
voltage sag criteria higher than 80%. IEEE standard 1346-1998 supports these limits.”

MRO's NERC Standards Review
Forum

NSRF proposes replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable transient voltage dip performance level for evaluating whether a fault or loss of the
element would not compromise the ALR of the BES.
In addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.

ReliabilityFirst

any impact is an impact, planning criteria between 3 & 5 % is often used and not allowed, why inject this into
what define the BES. the criteria is applied it should be included

New York Power Authority

Suggest that either the SDT avoid using voltage dip as a criteria, or clearly specify that the transient voltage
not exceed the X limit of Y cycles (time).
References to relevant industry standards such as IEEE standard 1346-1998 should be made.

Muscatine Power and Water

Suggest replacing this factor with those cited above because there is presently no established, continentwide, acceptable transient voltage dip performance level for evaluating whether a fault or loss of the element

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Organization

Yes or No

Question 5c Comment
would not compromise the ALR of the BES.
In addition, the appropriate performance level for this factor may be different in other areas and system
characteristics across the continent.

Blachly Lane Electric Cooperative
Flathead Electric Cooperative,
Inc.
Clark Public Utilities

Specific transient voltage dip thresholds are proposed on page 15 of Snohomish’s White Paper. For
example, we propose that, if an Element is to be excluded from the BES, removal of that Element should
produce no more than a 20% voltage drop for no more than 20 cycles in a Category B contingency and no
more than a 20% drop for 40 cycles in a Category C contingency. Technical justification for these thresholds
is provided on pages 12-16 of Snohomish’s White Paper.

Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric

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Organization

Yes or No

Question 5c Comment

Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc
Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc.
Salem Electric
Grant County PUD No. 2 (Grant)
for Snohomish County PUD
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc.
Kootenai Electric Cooperative

ISO New England

Is the requirement to evaluate the voltage dip on the element or is the test to evaluate the voltage dip on the
BES due to a contingency on the element? Under the draft TPL standards, this will have to be tested and
investigated anyway, so it is unclear as to what is being added or evaluated here.

The United Illuminating Company

Measured where on the BES?

BGE

For PJM members, this figure is set at 5%. BGE suggests a lower figure such as 2-3%.

Spyker

We suggest SDT to make references to relevant industry standard such as IEEE standards

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Yes or No

Question 5c Comment

Consumers Energy Company

The criterion related to Transient Voltage Deviations should be removed. This criterion, regardless of value
TBD, would be impossible to achieve, and would render this process meaningless.A fault on non-BES
elements will cause significant transient voltage dips on nearby BES elements until the fault is cleared. If the
non-BES element is at the same voltage level, the dip will result in near-zero voltages; if at different voltage
levels, the dip magnitude will be determined by the ratio of the system Thévinen impedance at the BES to
the intervening transformer impedance - if the system Thévinen impedance is 2% and the transformer
impedance is 18%, the voltage on the BES will dip to 10%.

Central Lincoln

Fault induced transient voltage measurements will always be low if taken at a point electrically close to the
fault during the fault. The question should be about voltage recovery following the clearing of the fault as in
the TPL standards. The Technical Principles do not make this distinction, and the resulting effect would be the
exclusion of elements that should be included and the inclusion of elements that should be excluded.

Duke Energy

See general comment on approach.

Hydro-Quebec TransEnergie

Comments on allowable transient voltage dip measurement: The TPL-001 to 004 do not specify any reference
measurement for stability (such as Allowable transient voltage, frequency excursion, voltage deviation, etc.).
Instead, it request that the system shall remain stable, without cascading or uncontrolled islanding. Also, it is
requested that the Planning Entities shall define and document the criteria or methodology used in the
analysis to identify System instability for conditions such as Cascading, voltage instability, or uncontrolled
islanding. This is exactly what should be requested in the analysis and demonstration of Element seeking
exclusion from BES. The analysis and burden of proof should be left to the Entity as is done in the TPL,
considering that there are no common values with the different interconnection.

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 5a because there is presently no established,
continent-wide, acceptable transient voltage dip performance level for evaluating whether a fault or loss of the
element would not compromise the ALR of the BES.
In addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.

Independent Electricity System
Operator

We do not agree with setting values for this criterion. This should be left to the relevant Transmission Planner
and Planning Coordinator. See our comments in response to Q5a.

Tacoma Power

Tacoma Power generally agrees with allowable transient voltage dip measurement in the technical analysis

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Yes or No

Question 5c Comment
path for exclusions.
We suggest adopting an allowable transient voltage dip not exceeding 20% for more than 20 cycles on an
adjacent system’s bus.

MidAmerican Energy

There isn't a nation wide transient voltage dip measurement.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential exclusion from the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.
Iberdrola USA

See 5a.

Response: See response to Q5a.

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5d. Comments on allowable transient frequency response:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization
ISO/RTO Standards Review
Committee

Yes or No

Question 5d Comment
See 5c

Response: see response to 5c.
Iberdrola USA

See 5a.

Response: see response to 5a.
Northeast Power Coordinating
Council

Suggest that for assigning a value for transient frequency response, entities conduct and submit to the SDT
their quantitative and qualitative technical assessment based on the conditions of the element(s) under the
application. Do not establish a fixed binary value within the exception criteria but rather focus on the
performance outcome. See 5 (a) above.

SERC Planning Standards
Subcommittee

As stated above, it does not make sense to use this category.

Tennessee Valley Authority
Southern Company
South Carolina Electric and Gas

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Organization

Yes or No

Question 5d Comment

Georgia Transmission
Corporation
Edison Electric Institute

Presently no regional standards exist for allowable transient frequency response beyond WECC. It is also
doubtful a useful standard could be developed for all regions or interconnections.

Florida Municipal Power Agency

The third proposed criterion, “Allowable transient frequency excursion - criteria TBD,” should be rephrased
like the second: “Allowable transient frequency excursion on another BES Element for events on the Element
that is a candidate of the Exception Request - criteria TBD.”

Transmission Access Policy
Study Group
Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

Hydro One

We suggest that, in terms of assigning a value for transient frequency response, entities conduct and submit
to the SDT their quantitative and qualitative technical assessment based on the conditions of the element(s)
under the application.
We suggest not to establish a fixed binary value within the exception criteria but rather focus on the
performance outcome. See 5 (a)

MRO's NERC Standards Review
Forum

NSRF proposes replacing this factor with those cited above because there are established, continent-wide
transient frequency performance levels in the PRC-006-1 standard, but the elements that are applicable to the
standard do not have to be BES elements and the transient frequency response requirements are not
intended to be a criterion for BES classification.

ReliabilityFirst

any impact is an impact, planning criteria between 5 & 10 % is often used and restricted to guard against
these changes, why inject this into what define the BES. the criteria is applied it should be included

New York Power Authority

Suggest that for assigning a value for transient frequency response, entities conduct and submit to the SDT
their quantitative and qualitative technical assessment based on the conditions of the element(s) under the
application.
Do not establish a fixed binary value within the exception criteria but rather focus on the performance
outcome.

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Yes or No

Question 5d Comment

Muscatine Power and Water

Suggest replacing this factor with those cited above. There are recognized, continent-wide transient
frequency performance levels in the PRC-006-1 standard; however, the elements that are applicable to this
standard are not necessarily BES elements and the transient frequency response requirements are not
intended to be a criterion for BES classification.

Blachly Lane Electric Cooperative

Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of that
Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical justification for
these thresholds is provided on pages 12-16 of the White Paper.

Flathead Electric Cooperative,
Inc
Clark Public Utilities
Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc.
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative

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Organization

Yes or No

Question 5d Comment

West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc.
Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc.
Central Lincoln
Salem Electric
Grant County PUD No. 2 (Grant)
for Snohomish County PUD
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc
Kootenai Electric Cooperative
Spyker

The SDT should avoid setting values and instead describe the intended performance outcomes from the
measurement

Consumers Energy Company

The criterion relative to frequency response should be removed. Frequency deviations can result from large
changes in distribution load.
Distribution facilities should not be prevented from being excluded from BES.

Duke Energy

See general comment on approach.

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Organization

Yes or No

Question 5d Comment

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 5a because there are established, continentwide transient frequency performance levels in the PRC-006-1 standard, but the elements that are applicable
to the standard do not have to be BES elements and the transient frequency response requirements are not
intended to be a criterion for BES classification.

Independent Electricity System
Operator

We do not agree with setting values for this criterion. This should be left to the relevant Transmission Planner
and Planning Coordinator. See our comments in response to Q5a.

Tacoma Power

Tacoma Power generally agrees with the allowable transient frequency response in the technical analysis
path for exclusions. We suggest adopting an allowable transient frequency response of not below 59.6 Hz for
up to 6 cycles on an adjacent system’s bus.

MidAmerican Energy

There isn't a nation wide transient frequency response

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential exclusion from the BES.. Based on industry response and further analysis, the SDT has abandoned the initial exclusion
criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and
provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value
and/or limit. It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process
requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to
validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as
established in the draft Rules of Procedure.

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5e. Comments on voltage deviation measurement:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization
ISO/RTO Standards Review
Committee

Yes or No

Question 5e Comment
See 5c

Response: See response to 5c.
Iberdrola USA

See 5a.

Response: See response to 5a.
Blachly Lane Electric Cooperative

Please see our response to Question 5d.

Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative

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Organization

Yes or No

Question 5e Comment

Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc
Benton Rural Electric Association
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc
Central Lincoln
Salem Electric
Grant County PUD No. 2 (Grant)
for Snohomish County PUD
Northwest Public Power
Association (NWPPA)

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Organization

Yes or No

Question 5e Comment

Big Bend Electric Cooperative,
Inc.
Kootenai Electric Cooperative
Response: See response to 5d.
Clark Public Utilities

See Clark’s comments on 5c and 5d.

Response: See responses to 5c and 5d.
Northeast Power Coordinating
Council
Hydro One

Voltage deviation is generally expressed as a percentage, between the voltage at a given instant at a point in
the system. Do not establish a fixed binary value within the exception criteria but rather focus on the
performance outcome.
Adequate voltage performance does not guarantee system voltage stability. Steady state stability is the ability
of the grid to remain in synchronism during relatively slow or normal load or generation changes, and to damp
out oscillations caused by such changes. The requirement should suggest that following checks are carried
out to ensure system voltage stability for both the pre-contingency period and the steady state postcontingency period: o Properly converged pre- and post-contingency power flows are to be obtained with the
critical parameter increased up to 10% with typical generation as applicable;
o All of the properly converged cases obtained must represent stable operating points. This is to be
determined for each case by carrying out P-V analysis at all critical buses to verify that for each bus the
operating point demonstrates acceptable margin on the power transfer; and
o The damping factor must be acceptable (the real part of the eigen values of the reduced
are positive).

SERC Planning Standards
Subcommittee

Jacobian matrix

As stated above, it does not make sense to use this category.

Tennessee Valley Authority
Southern Company
South Carolina Electric and Gas
Georgia Transmission

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Organization

Yes or No

Question 5e Comment

Corporation
Edison Electric Institute

Presently no regional standards exist for allowable voltage deviation beyond WECC. It is also doubtful a
useful standard could be developed for all regions or interconnections.

Florida Municipal Power Agency

The fourth proposed criterion should be revised in the same way as the second and third: “Voltage deviation
on another BES Element for events on the Element that is a candidate of the Exception Request - criteria
TBD.”The fifth proposed criterion should be similarly revised: “Transient Stability on another BES Element for
events on the Element that is a candidate of the Exception Request - positively damped.”

Transmission Access Policy
Study Group
Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

MRO's NERC Standards Review
Forum

NSRF proposes replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable (steady state) voltage deviation performance level for evaluating whether a fault or
loss of the element would not compromise the ALR of the BES.
In addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.

ReliabilityFirst

any impact is an impact, planning criteria is often used and restricted to guard against these changes, why
inject this into what define the BES. If the criteria is applied to the facility as a BES element it should be
included

New York Power Authority

Voltage deviation is generally expressed as a percentage, between the voltage at a given instant at a point in
the system. Do not establish a fixed binary value within the exception criteria but rather focus on the
performance outcome.

Muscatine Power and Water

Requesting the STD replace this factor with those cited above. At this time there is no established, continentwide, acceptable (steady state) voltage deviation performance level for evaluating whether a fault or loss of
the element would not compromise the ALR of the BES.
Moreover, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.

Consolidated Edison Co. of NY,

The NYISO uses a 0.95 to 1.05 p.u. as the acceptable range for post-transient system conditions.

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Organization

Yes or No

Question 5e Comment

Inc.
ISO New England

Is the requirement to evaluate the voltage dip on the element or is the test to evaluate the voltage dip on the
BES due to a contingency on the element? Under the draft TPL standards, this will have to be tested and
investigated anyway, so it is unclear as to what is being added or evaluated here.

The United Illuminating Company

Measured where on BES?

BGE

BGE believe the loss of the facility in question should cause only a small voltage deviation to the BES (on the
order of 1%).

Spyker

The SDT should avoid setting values and instead describe the intended performance outcomes from the
measurement

Northern Wasco County PUD

Page 15 of Snohomish’s White Paper also sets forth recommended thresholds for transient frequency
response. For example, we propose that, if an Element is to be excluded from the BES, removal of that
Element should not cause any load bus to drop below 59.6 Hz for 6 cycles or more. Technical justification for
these thresholds is provided at pages 12-16 of the White Paper.

Flathead Electric Cooperative,
Inc.

we propose that, if an Element is to be excluded from the BES, removal of that Element should not cause any
load bus to drop below 59.6 Hz for 6 cycles or more.

Consumers Energy Company

This criterion may be reasonable, depending on the TBD value. The TBD value may need to vary for different
voltage levels or system configurations. The criteriona needs to recognize that loss of multiple capacitors at
the distribution level could result in significant voltage deviation at the BES and this must not prevent
distribution facilities from being excluded from BES.

Duke Energy

See general comment on approach.

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 5a because there is presently no established,
continent-wide, acceptable (steady state) voltage deviation performance level for evaluating whether a fault or
loss of the element would not compromise the ALR of the BES.
In addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.

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Organization
Independent Electricity System
Operator

Yes or No

Question 5e Comment
We do not agree with setting values for this criterion. This should be left to the relevant Transmission Planner
and Planning Coordinator. See our comments in response to Q5a.
We suggest that the exception criteria could include the following checks to be carried out in the course of the
TPL analysis referred to above to ensure system voltage stability for both the pre-contingency period and the
steady state post-contingency period: o Properly converged pre- and post-contingency power flows are to be
obtained with the critical parameter increased up to 10% with typical generation as applicable;
o All of the properly converged cases obtained must represent stable operating points. This is to be
determined for each case by carrying out P-V analysis at all critical buses to verify that for each bus the
operating point demonstrates acceptable margin on the power transfer as shown in the following section; and
o The damping factor must be acceptable (the real part of the eigen values of the reduced Jacobian matrix
are positive).”

Tacoma Power

Tacoma Power generally agrees with the voltage deviation measurement in the technical analysis path for
exclusions. We suggest adopting a voltage deviation not exceeding 10% on an adjacent system’s bus.

MidAmerican Energy

Determining a nation wide voltage deviation would be difficult.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential exclusion from the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.

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6. Exclusions – Do you have other methods that may be appropriate for proving an exclusion claim? Or,
other variables/measurements that may be added to the requirements already shown in the posted
Technical Principles for Demonstrating BES Exceptions? If so, please provide your comments here
with technical rationale for why they should be considered.

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an
entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as
presently being drafted.

Organization

Yes or No

NERC Staff Technical Review

No

Edison Electric Institute

No

Iberdrola USA

No

Tri-State Generation and
Transmission Association

No

ReliabilityFirst

No

Idaho Falls Power

No

New York Power Authority

No

Question 6 Comment

None beyond what was offered under question 5

No comments

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Organization

Yes or No

Blachly Lane Electric Cooperative

No

Clark Public Utilities

No

Central Electric Cooperative

No

Clearwater Power Electric
Cooperative

No

Consumer's Power Inc.

No

Coos-Curry Electric Cooperative

No

Douglas Electric Cooperative

No

Fall River Electric Cooperative

No

Lane Electric Cooperative

No

Lincoln Electric Cooperative

No

Lost River Electric Cooperative

No

Northern Lights Electric
Cooperative

No

Okanogan Electric Cooperative

No

Raft River Rural Electric
Cooperative

No

Salmon River Electric
Cooperative

No

Question 6 Comment

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Organization

Yes or No

Umatilla Electric Cooperative

No

West Oregon Electric
Cooperative

No

Pacific Northwest Generating
Cooperative

No

Long Island Power Authority

No

American Electric Power

No

PNGC Power

No

Consumer's Power Inc.

No

BGE

No

Pepco Holdings Inc

No

Northern Wasco County PUD

No

United Electric Co-op Inc.

No

Oregon Trail Electric
Cooperative, Inc.

No

Central Lincoln

No

Oncor Electric Delivery

No

Salem Electric

No

Question 6 Comment

No comment.

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Exceptions — Project 2010-17

Organization

Yes or No

Question 6 Comment

Duke Energy

No

Grant County PUD No. 2 (Grant)

No

No comments

Northwest Public Power
Association (NWPPA)

No

None

Big Bend Electric Cooperative,
Inc.

No

Manitoba Hydro

No

Independent Electricity System
Operator

No

Harney Electric Cooperative, Inc.

No

Kootenai Electric Cooperative

No

Tacoma Power

No

ISO New England

No

Southern Company

Yes

Tacoma Power is not suggesting any other methods at this time.

Response: Thank you for your response.
Flathead Electric Cooperative,
Inc.
for Snohomish County PUD

No

supports the exemption of generation interconnected to local distribution networks if the generation is less
than 300 MW capacity and where the power generated is consumed within the LDN and rarely flows out of
the LDN consistent with the section III.c.4 [Exclusion] of the NERC Statement of Compliance Registry Criteria
as well as the Load modifiers used in the Eastern Interconnection. "Load Modifiers" (small generators that
only affect load at the distribution level).”

Response: The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.

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Organization

Yes or No

Question 6 Comment

The United Illuminating Company

No

Procees is complicated and fraught with interpretations.

Bonneville Power Administration

No

BPA emphasizes that exclusion criteria and analysis should be based on normal operations. An exclusion
should not be unavailable based on temporary system configuration such as load service by a different
transmission segment temporarily used to mitigate system operations due to planned maintenance outages,
i.e. a system that is operated radially over 90% of the time and closed for maintenance outages for safety
and/or reliability purposes, etc.
BPA recommends that the SDT consider not only the single-phase faults, also the effect of more severe
events such as two- or three-phase faults, with delayed clearing and evaluate the necessity of the element in
those cases.

ISO/RTO Standards Review
Committee

SERC Planning Standards
Subcommittee

Very small elements may be candidates for exclusion because such a small loss cannot cause reliability risk.
An exception to this statement may be that, though small, the element is important to the service of a critical
load.
Yes

Tennessee Valley Authority
South Carolina Electric and Gas

Section “Exception Criteria - Exclusions”:Add 1.e. “Generation that is inoperable and not planned to be
placed back into service but not yet officially decommissioned.”Technical rationale: These facilities are not
relied on to insure the reliability of the BES.

Georgia Transmission
Corporation
Entergy Services
Florida Municipal Power Agency
Transmission Access Policy
Study Group

Revise second paragraph to read “Due to the importance of designated Blackstart Resources and their
Cranking Paths to restore efforts, no exceptions will be allowed for those items that are included in a system
restoration plan.”Technical rationale: Multiple Blackstart Resources and Cranking Paths are frequently
available but are not included in a system restoration plan. System restoration plans describe the Blackstart
resources and cranking paths thar are deemed to be necessary for system restoration.

Yes

TAPS proposes a simpler set of exclusion exception criteria:1. Having a distribution factor of 5% for
curtailable Interchange Transactions or BES generator - load identified in Transmission Loading Relief stages
one through five, and
2. Category B and C contingencies on the Element that is the subject of the Exception Request meet the TPL002 criteria for other BES Elements. (With the new TPL-001-3 standard recently approved by ballot, Category
P0 through P7 contingencies on the Element that is subject of the Exception Request meets the criteria of P0
through P3 for other BES Elements)
3. The Element that is the subject of the Exception Request is not: (1) part of an IROL, (ii) part of a blackstart
or cranking path used in a TOP’s restoration plan, and (iii) is not used in NUC-001 to provide service to a

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Organization

Yes or No

Question 6 Comment
nuclear plant.TAPS believes these three criteria meet the intent of all of the criteria presented by the SDT.

Hydro One

Yes

Technical Analysis must fundamentally use NERC - TPL methodology and testing requirements.
We believe that an element may “not be necessary for the operation of the interconnected transmission
system” if the remaining system can be operated without the element(s) for over 30 days and during peak
load conditions. This assumption considers that loss of element(s) may result in outage to the connected load
or generation during this period but will not have any adverse impact on the operation of the interconnected
transmission network.
Following are technical assessment categories that entities could be required when filing for
exception:1.Power flow
oPrimarily unidirectional (less than 20% of min load)2.TPL Assessment
oLoad Flows Analysis
oThermal and Voltage Stability
oTransient Stability3.TDF and OTDF
assessment
For entities filing an exception:[Step 1]Entities should undertake relevant and detailed technical
assessment/analysis and describe their findings under each of the technical categories. Finally, the findings
and conclusions should be listed in the form of maximum 6 bullets.
[Step 2]Findings and conclusions from each of the technical categories should be presented in a spreadsheet
including the categories that may not be relevant to the element(s). If a category is not relevant, it should be
explained why.
[Step 3]The final conclusion should be presented by taking the overall assessment in Step 2 by assessing
contributions of each item and demonstrating that the element(s) is or is not necessary for the operation of
interconnected transmission network.
We suggest the above method and request entities to complete the table below, as this will allow entities to
present their assessment of the element(s) that are under the consideration of exception.
Measured Value==============
------------------------

Load || Critical Load Affected? [yes][No]-------------------

oRadial oLocal supply, e.g. distribution in nature
oLarge load center, critical load, national security
Generation Characteristics || Critical Load Affected?
[yes][No]--------------------------------------------------------------oLocal load modifier, peak shaver oBehind meter or industrial load displacement
oMust Run

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Organization

Yes or No

Question 6 Comment
oFlow contribution outside of the elements under exception
Cascading Outage || Critical Load Affected? [yes][No]----------------------------------------------------Measured Value ==============Max Dip
Practice (IEEE/CSA,Market Rules,etc.)Acceptable Level
Assessment Results
[Yes] [No]
Transient Voltage Dip
Transient Frequency Excursion
[Voltage]

[Voltage] Applicable Industry
[in cycles]

[in cycles]Does the assessment confirm successful recovery?
[voltage]
[Hertz]Voltage deviation

Transient Stability Steady State Stability
MRO's NERC Standards Review
Forum

Yes

A. NSRF recommends this process address the six characteristics of the Definition of Adequate Level of
Reliability (ALR) as listed in the comments above in Question #5.
B. Recommend municipalities and other small entities having transmission systems designed to serve local
load, operated below 200 kV and not having any IROL’s or SOL’s be excluded from the BES definition.
Rational: The standards, especially those for Transmission Operators (TO) aren’t written for the smaller
utilities. A utility may have over 75 MWs of generation and have installed a 115 kV loop around their city that
is used primarily to serve load and get forced into significant compliance requirements that don’t enhance the
reliability of the BES.

PacifiCorp

Yes

All of PacifiCorp’s responses are based on a given interconnection and not on a continental basis. Fault duty
may be appropriate for certain interconnections only.

Western Electricity Coordinating
Council

Yes

WECC recommends that the SDT consider not only the single-phase faults used in the TPL standards, but
also the effect of more severe events such as two- or three-phase faults, with delayed clearing and the
necessity of the element in those cases.

Electricity Consumers Resource
Council (ELCON)

Yes

We recommend an additional method (or alternatively this be added to the BES Definition Exception E1):
System Elements are part of facilities, generally radial in nature, supplying a retail customers from the point of
delivery to the load regardless of voltage. Evidence to support this position could be an interconnection
agreement indicating the point of delivery, a one-line diagram showing the point of delivery and load etc. The
technical rationale is that protection of the BES for facilities serving load is the responsibility of the service

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Organization

Yes or No

Question 6 Comment
provider (e.g., TO/TOP). These facilities are distribution facilities and are not now part of the BPS.

National Grid

Yes

The NERC process could potentially by very lengthy and could interfere with the timely completion of our
studies. In the technical paths for exclusions, bullet v states “If within the criteria in all cases, then the
Elements can be excluded.” This could lead to a very high number of studies that need to be done to prove
an element should be excluded. For this reason, National Grid endorses a more streamlined process. We
propose a process where entities would only need to submit a short form that briefly describes what they
would like to exempt and the reason why, along with a one-line diagram. The entity who is requesting the
exception would have to maintain records that show why the elements can be exempted until NERC performs
an audit. At the audit, the entity can show the proof of why the element should be granted an exception. This
process also allows for the application to remain public and reduces documentation burdens, because the
non-public, CEII, or NERC CIP protected supporting documentation is maintained by the applicant.In this
process, the entity first submits the application to their RE, and if approved by the RE, the application is
submitted to NERC. The entity should be able to appeal if either the RE or NERC denies the application;
however, it should be clear that for the second appeal to NERC, the decision is made by a different group
than whoever decided on the first appeal. The appeal process in this exception procedure could be similar to
the appeal process set by CMEP (compliance, monitoring and enforcement program).For entities that don’t
wish to wait until the next audit, there can be an optional process by which the proposed exception can be
reviewed to provide an immediate ruling. Also, there should be a grace period after the audit is performed if
audit staff concludes that an exception or inclusion granted by the initial application is not supported by
adequate evidence. NERC’s approval of an exception during this initial application process should stand until
an Entity is audited and a final audit report is issued. There should also be an implementation period
included in the audit report for the entity to come into compliance if the audit report disagrees with the initial
exception approval. Absent evidence of fraud or intentional misrepresentation by the entity, there should be
no non-compliance assessed for the period from initial exception approval to the final audit report. This
process would need to allow participation or comments by Regional Entities, Reliability Coordinators, and/or
Balancing Authorities in the application process, but should not allow participation by other third parties.

Muscatine Power and Water

Yes

Recommending that this process address the six characteristics of the Definition of Adequate Level of
Reliability (ALR) as listed in the comments above in Question #5.
Also recommend that municipalities and other small entities having transmission systems designed to serve
local load only, operated below 200 kV and not having any IROL’s or SOL’s be excluded from the BES
definition. Rationale: this could affect smaller registered entities within a BA. The standards, especially those
for Transmission Operators, aren’t written for the smaller utilities. A small, municipal utility could have 75 MW
of generation and operate a 115 kV looped system around their service area that is used primarily to serve
their own load. Subsequently, they get forced into significant compliance requirements that does not enhance

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Organization

Yes or No

Question 6 Comment
the reliability of the BES whatsoever.

Glacier Electric Cooperative

Yes

Perhaps using an element's available fault MVA as a "quick screening" method to quickly determine if an
element should be included or excluded. If an element's available fault MVA exceeds a properly established
value, then a more detailed technical analysis can be done to determine whether or not the element truly
should be included in the BES. But if the elemet's available fault MVA is less than the established value, then
that element could quickly be excluded.

Orange and Rockland Utilities,
Inc.

Yes

FERC Order No. 888 - Seven Factor Test.

Xcel Energy

Yes

Xcel Energy would like the SDT to consider a Capacity Factor exclusion for generating resources that are
rarely used. For example, at least two standards that are currently being drafted exempt generators that have
an average Capacity Factor of 5% or less over a three year period.

American Transmission
Company, LLC

Yes

ATC recommends this process address the five characteristics of the Definition of Adequate Level of
Reliability (ALR) as listed in the comments above in Question #5a.

NESCOE

Yes

Please refer to comments under item 4., above. If the parallel power flow in a given < 200 kV path only
exceed 200 MVA under contingency conditions and if the applicable BES points have fully NERC compliant
protection systems, disturbances on this lower voltage path will not adversely affect the reliability of the BES.
The exclusion determination process should be flexible enough to recognize that any requirement that may
impose substantial new costs on New England transmission owners, and ultimately on consumers, should
also provide meaningful reliability benefits

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language for the technical exception criterion. Based on
industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and
operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal
was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of the facilities in question and to
document the operational performance as appropriate through submittal of an exception request form along with any other supporting documentation for the
exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as presently being drafted.
Northeast Power Coordinating

Yes

An impact-based method should be available for entities seeking Exclusions and Inclusions. The method

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Organization

Yes or No

Council

Question 6 Comment
should not allow excess regional discretion and unintended continent-wide variation. Recommend the power
Transfer Distribution Factor (power TDF) approach mentioned in the reply to Question 5 above. If the
Transmission Planner (TP) or Planning Authority (PA), were tasked with performing such analyses using
standardized assumptions, then regional discretion could be minimized.
Technical Analysis must fundamentally use NERC - TPL methodology and testing requirements.

Consolidated Edison Co. of NY,
Inc.

Yes

An impact-based method should be available for entities seeking Exclusions and Inclusions. The method
should not allow excess regional discretion and unintended continent-wide variation. We recommend the
power Transfer Distribution Factor (power TDF) approach mentioned in the reply to Question 6 above.
If the Transmission Planner (TP) or Planning Authority (PA), e.g., the NYISO, were tasked with performing
such analyses, using standardized assumptions, then regional discretion could be minimized.

Spyker

Yes

Technical Analysis must fundamentally use NERC - TPL methodology and testing requirements.

Hydro-Quebec TransEnergie

Yes

Technical demonstration should not be limited to technical principles stated in the "Technical Principles for
Demonstrating BES Exceptions". Entities should be allowed to do their own demonstration with their own
technical arguments. As an example, an Entity could consider a few level of application for the standards. As
an example, the level #1 being the most important level, all standards would apply to this level, including more
stringent criteria than the TPL standards. This would bring BES level #1 very robust and reliable, ensuring the
reliability of the main system. A second BES level #2 could be define for local transmission to which would be
applied most standards but excluding some of the C section of TPL. Attention would be given to proper
reliable operation of the BES level #2, but with smaller level of investment on the design aspect, those
regional transmission part of the system being able to face higher risk for loss of continuity of service. Finally,
for generation or Load Facility that would be excluded from both level of BES, minimum standards would still
apply such as in protection or for generation. Through its own technical principles, the Entity could
demonstrate that the highest level of BES is more reliable than what is expected by NERC's standard, but that
in regional transmission part of the system, the C TPL standard would not apply with the only risk of lower
continuity of service.

Response: The SDT appreciates your comments. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or
limit. It has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new
process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of
an exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the

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Exceptions — Project 2010-17

Organization

Yes or No

Question 6 Comment

submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation
with the ERO as established in the Rules of Procedure as presently being drafted.
Your specific concerns will be accommodated under the revised process.
SPP Standards Review Group

Yes

We would suggest that the SDT consider an exclusion for networked municipal systems operating below
200kV which have more than 75 MVA of generation and whose systems do not include flowgates or IROLs.

Response: The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.
PPL Supply

Yes

See comments in Questions 9 and 10

Yes

See answer to 5a.

Yes

Suggested additional method. The Element(s) meet all the following characteristics: 1) generally radial in
nature, and

Response: See response to Q9 & Q10.
New York State Reliability
Council
Response: See response to 5a.
Occidental Energy Ventures
Corp.

2) used to supply a retail customer from the point of delivery to the load regardless of voltage.
Evidence to support this position could be an interconnection agreement indicating the point of delivery, a
one-line diagram showing the point of delivery and load, etc. The technical rationale is that protection of the
BES for facilities serving a retail customer is the responsibility of the service provider (e.g., transmission
owner/operator). These facilities are distribution facilities and are not now part of the BPS. Alternatively, this
could be an Exclusion in the BES Definition as it is in the current definition.
MidAmerican Energy

Yes

In general all facilities below 100 kV should be exlcuded by default as distribution according to the 2005
Federal Power Act. Transmission Distribution Factors tend to show low bulk power system transfers (less
than 2%) based on their inherent high impedance when normalized. Normalizing the transmission impedance
means diving the ohmic value by a base impedance which is dominated by a (kV^2) term. Per Unit
Impedance = (transmission line ohms / base impedance) where base impedance = (kV^2 / MVA). Using a
common MVA base value of 100 MVA, a base impedance at 69kV = 47.6 ohms versus at 161 kV = 259.2 or
at 345 kV = 1190.2 ohms. The rapid increase of the denominator as kV goes higher insures that a 69 kV

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Exceptions — Project 2010-17

Organization

Yes or No

Question 6 Comment
system is high impedance compared to any high kV facilities and therefore nearly insure the 69 kV system is
local in nature and reacts primarily to load. Therefore it is distribution. This all supports the conclusion that all
facilites below 100 kV should be classified as distribution according to the 2005 FPA and exempted by
default. Facilities below 100 kV could be brought into scope if TPL analyses show instability, uncontrolled
separation, or cascading as defined in the 2005 FPA.

Response: The SDT appreciates your comments. Your specific concerns will be accommodated under the revised process.
Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the
technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The
initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to
establish continent-wide values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the characteristics of
the facilities in question and to document the operational performance as appropriate through submittal of an exception request form along with any other
supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a
recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of
Procedure as presently being drafted.
The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.

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7. Inclusions - The SDT has set up only one path for evidence that includes technical analysis. Do you
agree with this requirement? If you do not support this requirement or you agree in general but feel
that alternative language would be more appropriate, please provide specific suggestions in your
comments. In addition, in the comment field, please provide your thoughts on the proposed metrics
for analysis and the appropriate values to replace ‘TBD,’ including technical rationale for your
argument.
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization

Yes or No

Northeast Power Coordinating
Council

No

SERC Planning Standards
Subcommittee

No

SPP Standards Review Group

No

NERC Staff Technical Review

No

Iberdrola USA

No

Tri-State Generation and
Transmission Association

No

Hydro One

No

Question 7 Comment

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Organization

Yes or No

MRO's NERC Standards Review
Forum

No

Bonneville Power Administration

No

ReliabilityFirst

No

Tennessee Valley Authority

No

PPL Supply

No

Southern Company

No

Muscatine Power and Water

No

South Carolina Electric and Gas

No

Exelon

No

Georgia Transmission
Corporation

No

Consolidated Edison Co. of NY,
Inc.

No

Springfield Utility Board

No

ISO New England

No

The United Illuminating Company

No

Entergy Services

No

Question 7 Comment

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Organization

Yes or No

American Electric Power

No

Orange and Rockland Utilities,
Inc.

No

Pepco Holdings Inc

No

Consumers Energy Company

No

American Transmission
Company, LLC

No

Manitoba Hydro

No

Independent Electricity System
Operator

No

MidAmerican Energy

No

New York Power Authority

Yes

Blachly Lane Electric Cooperative

Yes

Glacier Electric Cooperative

Yes

Flathead Electric Cooperative,
Inc.

Yes

Clark Public Utilities

Yes

Central Electric Cooperative

Yes

Consumer's Power Inc.

Yes

Question 7 Comment

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Organization

Yes or No

Coos-Curry Electric Cooperative

Yes

Douglas Electric Cooperative

Yes

Fall River Electric Cooperative

Yes

Lane Electric Cooperative

Yes

Lincoln Electric Cooperative

Yes

Lost River Electric Cooperative

Yes

Northern Lights Electric
Cooperative

Yes

Okanogan Electric Cooperative

Yes

Raft River Rural Electric
Cooperative

Yes

Salmon River Electric
Cooperative

Yes

Umatilla Electric Cooperative

Yes

West Oregon Electric
Cooperative

Yes

Pacific Northwest Generating
Cooperative

Yes

PNGC Power

Yes

Question 7 Comment

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Organization

Yes or No

Consumer's Power Inc.

Yes

BGE

Yes

Spyker

Yes

Benton Rural Electric Association

Yes

Clearwater Power Electric
Cooperative

Yes

Long Island Power Authority

Yes

Northern Wasco County PUD

Yes

Xcel Energy

Yes

United Electric Co-op Inc.

Yes

Oregon Trail Electric
Cooperative, Inc.

Yes

Central Lincoln

Yes

Oncor Electric Delivery

Yes

Salem Electric

Yes

Duke Energy

Yes

Grant County PUD No. 2 (Grant)

Yes

Hydro-Quebec TransEnergie

Yes

Question 7 Comment

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Organization

Yes or No

for Snohomish County PUD

Yes

Northwest Public Power
Association (NWPPA)

Yes

Big Bend Electric Cooperative,
Inc.

Yes

Kootenai Electric Cooperative

Yes

Tacoma Power

Yes

Edison Electric Institute

Yes

ISO/RTO Standards Review
Committee

Yes

PacifiCorp

Yes

Idaho Falls Power

Yes

Western Electricity Coordinating
Council

Yes

New York State Reliability
Council

Yes

Electric Market Policy

Yes

Question 7 Comment

Response: Thank you for your response. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a
new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide greater
continuity with the existing definition of BES. The new process requires an entity to clarify the characteristics of the facilities in question and to document the
operational performance as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being
sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or

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Organization

Yes or No

Question 7 Comment

inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of Procedure.

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7a. Comments on approach:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization

Yes or No

Question 7a Comment

Northeast Power Coordinating
Council

Inclusions criteria should mirror the Exclusion criteria, and that consistent values should be employed for
Inclusions here and for Exclusions above. That is, for example, if 0.95 to 1.05 (+/- 5%) p.u. is adopted as an
acceptable voltage deviation range for Exclusions, then Elements resulting in post-transient system voltage
deviations outside that range should be candidates for Inclusion. Further, all assumptions should also be fully
documented for any proposed Inclusions. Also refer to comments on exclusions.

SERC Planning Standards
Subcommittee

The PSS recommends that applications for inclusion of facilities into the BES should include justification for
doing so. However, there should not necessarily be specific criteria that must be met, but the importance of
the facility to the BES should be clearly demonstrated.

Tennessee Valley Authority
Southern Company
South Carolina Electric and Gas
Georgia Transmission
Corporation
NERC Staff Technical Review

NERC staff is not opposed to development of evidence based on technical analysis; however, we have the
same concerns with the exception criterion for including Element(s) as with exception criterion 1 for excluding
Element(s). The type of analysis included in this exception criterion requires extensive resources and lacks
sufficient detail to allow for consistent and repeatable application.
Additional concerns with this approach include (1) the ability to provide sufficient guidance on the system

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Organization

Yes or No

Question 7a Comment
conditions and contingencies necessary to support an exception request,
(2) difficulty with identifying thresholds for items iv-1 through iv-4, and
(3) the ability to address interdependencies among exception requests.

Independent Electricity System
Operator

We support the concept of technical analysis in support of Inclusions but disagree with the approach that
involves setting specific values for criteria. Please refer to our comments on exclusions.

Florida Municipal Power Agency

FMPA supports using a uniform set of technical criteria to decide inclusion exceptions. Such an approach will
facilitate uniform application of the criteria. In addition to having clear and uniform criteria, the technical
analysis for inclusions and exclusions should use the same criteria (though one should of course be the
inverse of the other). We note that the steps laid out for Inclusions do not quite track those in Exclusions 2(a).
For example, Inclusions 1(b) states, confusingly, “Monitor the contribution of the disputed Element(s),” but
there is no corresponding step in Exclusions 2(a). FMPA suggests that Inclusions 1 be revised to mirror
Exclusions 2.

Transmission Access Policy
Study Group

TAPS supports using a uniform set of technical criteria to decide inclusion exceptions. Such an approach will
facilitate uniform application of the criteria. It is appropriate for there to be only one path, using technical
analysis, for inclusions, because the analysis for inclusions should be performed by Regional Entities and
NERC (see TAPS comments on the BES Exception Process, also submitted today), which have more
resources available than do the small entities that TAPS believes are likely to request exclusions based on
the path for exclusions that does not include extensive technical analysis.In addition to having clear and
uniform criteria, the technical analysis for inclusions and exclusions should use the same criteria (though one
should of course be the inverse of the other). We note that the steps laid out for Inclusions do not quite track
those in Exclusions 2(a). For example, Inclusions 1(b) states, confusingly, “Monitor the contribution of the
disputed Element(s),” but there is no corresponding step in Exclusions 2(a). TAPS suggests that Inclusions 1
be revised to mirror Exclusions 2.

ISO/RTO Standards Review
Committee

The SRC generally agrees with the technical analysis approach to determining whether an element should be
included in the BES. However, consideration should also be given to valid and supported evidence given by
RCs and PCs, and, possibly TOPs and BAs to actual historical events that indicate significant importance of
elements which, when lost, have resulted in reliability risk to the system.

Iberdrola USA

A facility is BES if it is necessary for reliable system operation, based on a TPL-type analysis similar to NPCC
Document A-10 “Classification of Bulk Power System Elements” - this type of analysis was rejected by FERC.
In addition, applicable threshold values for these parameters could differ from one system to another, and

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Organization

Yes or No

Question 7a Comment
would require extensive analysis.

Tri-State Generation and
Transmission Association

This appears very similar to the “material impact” proposal that FERC has previously disallowed, so we
recommend removing it, but allowing elements that are included in Regional Entity defined bulk transfer paths
that are not already included in the BES definition.
If retained, remove 1.(f) because allowing the ERO to override the technical justification and analysis
devalues such analysis to the point of it being meaningless.

Hydro One

Inclusions criteria should mirror the Exclusion criteria, and that consistent values should be employed for
Inclusions here and for Exclusions above. [See our comments on exclusions]

MRO's NERC Standards Review
Forum

NSRF proposes that the technical analysis criterion be replaced by criteria that are more closely tied to the
Adequate Level of Reliability (ALR) characteristics.
The following alternate criteria are offered as possible examples, “(1) the BES cannot be controlled to stay
within acceptable limits following a fault on or loss of the Element;
(2) the BES does not perform acceptably after credible contingences of the Element;
(3) the Element limits the impact and scope of instability and cascading outages when they occur;
(4) BES facilities are not protected from unacceptable damage by operating the Element within its ratings;
(5) the integrity of the BES cannot be restored promptly following a fault on or loss of the Element; and
(6) the BES does not have the ability to supply the aggregate electric power and energy requirements of the
electricity consumers at all times, taking into account scheduled or reasonably expected unscheduled outages
of the Element.
In addition, NSRF is not aware of any continent-wide appropriate BES performance measures for voltage dip,
frequency excursion, voltage deviation, stability, etc. and NSRF speculates that different values are likely for
different regions and system characteristics across the continent. As a result, NSRF believes it is not
advisable to try to adopt unproven values without reasonable industry investigation and development.

ReliabilityFirst

to complicated and will only raise debate between FERC, NERC, the Regions and the Registered Entities

New York Power Authority

In general, NYPA agrees with this approach except as noted below. Inclusions criteria should mirror the
Exclusion criteria, and that consistent values should be employed for Inclusions here and for Exclusions

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Organization

Yes or No

Question 7a Comment
above.

National Grid

There should be a non-technical process for inclusions similar to the exclusions process.

Muscatine Power and Water

Would like to propose that the technical analysis criterion be replaced by criteria that are more closely tied to
the Adequate Level of Reliability (ALR) characteristics. The following alternate criteria are offered as possible
examples, “(1) the BES cannot be controlled to stay within acceptable limits following a fault on or loss of the
Element;
(2) the BES does not perform acceptably after credible contingences of the Element;
(3) the Element limits the impact and scope of instability and cascading outages when they occur;
(4) BES facilities are not protected from unacceptable damage by operating the Element within its ratings;
(5) the integrity of the BES cannot be restored promptly following a fault on or loss of the Element; and
(6) the BES does not have the ability to supply the aggregate electric power and energy requirements of the
electricity consumers at all times, taking into account scheduled or reasonably expected unscheduled outages
of the Element. Currently not aware of any continent-wide appropriate BES performance measures for voltage
dip, frequency excursion, voltage deviation, stability, etc. and would speculate that different values are likely
for different regions and system characteristics across the continent.
Therefore, would like to state that it is not advisable to try to adopt unproven values without reasonable
industry investigation and development.

Blachly Lane Electric Cooperative
Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative

As a general matter, we agree with the SDT that Elements otherwise excluded from the BES should be
included only upon a technically valid justification showing that the Elements in question contribute
substantially to the potential for cascading outages, separation events, or instability on the interconnection
bulk transmission system. We also agree that the SDT has, in general, identified the correct technical
approach, although we recommend that the inclusion analysis (which mirrors the technical exclusion analysis)
be modified as discussed in Snohomish’s White Paper, in the WECC BES Task Force Proposal 6, and in our
answer to Question 5.
While we support the SDT’s overall approach, we believe subsection (f) of the proposed inclusion criteria,
which would allow NERC to “override this criterion” if it provides “additional justification” for doing so is both
unnecessary and creates confusion and uncertainty in what is otherwise a clear and concise process.
Subsection (f) is unnecessary because if the technical process laid out in subsections (a) through (e) fails to
provide any evidence that the contested Element(s) create a material impact on the reliability of the bulk

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Organization
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative

Yes or No

Question 7a Comment
interconnected transmission network, there is no reason to classify those Element(s) as BES, and that should
be the end of the question. Subsection (f) creates needless uncertainly because it allows NERC to override
the technical criteria laid out in subsections (a) through (e) if “additional justification” is provided, but there is
no suggestion as to what this additional justification might be. Nor is there any explanation as to why
additional justification might be necessary after the criteria in subsections (a) through (e) have been
exhausted.

Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc.
Central Lincoln
for Snohomish County PUD
Glacier Electric Cooperative

I do strongly agree that there should be an avenue for elements to be included or excluded from the BES
based on technical analysis.
I do believe who's responsibility it will be to perform and analyze the transmission planning studies needs to
be clarified.

Exelon

: Exelon points out that most of the Regions don’t have Region-wide criteria for distribution factor
measurement, voltage excursions, or transient frequency response for use in this proposed Inclusion
Process.
In addition, most of the Regions do not have region-wide criteria developed for these attributes. If differing
criteria levels are used across the continent, there remains the possibility that similarly-situated facilities in
different Regions will not be treated consistently.

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Organization
Consolidated Edison Co. of NY,
Inc.

Yes or No

Question 7a Comment
We believe that Inclusions criteria should mirror the Exclusion criteria, and that consistent values should be
employed for Inclusions here and for Exclusions above. That is, for example, if 0.95 to 1.05 (+/- 5%) p.u. is
adopted as an acceptable voltage deviation range for Exclusions, then Elements resulting in post-transient
system voltage deviations outside that range should be candidates for Inclusion.
Further, all assumptions should also be fully documented for any proposed Inclusions.

Springfield Utility Board

NERC’s Exception Criteria for Inclusions states that, “Entities can submit an application to see an exception
for an inclusion in the BES...”, but SUB would ask NERC to clarify whether an entity can 1) seek an inclusion
exception for them only, or
2) can an entity seek an inclusion exception for another entity? SUB would not support another entity having
the ability to file for another entity.

Flathead Electric Cooperative,
Inc.

Elements otherwise excluded from the BES should be included only upon a technically valid showing that the
Elements contribute substantially to the potential for cascading outages, separation events, or instability on
the interconnection bulk transmission system.

Entergy Services

It is unclear why an inclusion process should be necessary. Including facilities not otherwise included in the
basic definition should be at the discretion of the TO.

Clark Public Utilities

As a general matter, Clark agrees with the SDT that Elements otherwise excluded from the BES should be
included only upon a technically valid showing that the Elements contribute substantially to the potential for
cascading outages, separation events, or instability on the interconnection bulk transmission system. Clark
also agrees that the SDT has, in general, identified the correct technical approach, although Clark
recommends that the inclusion analysis (which mirrors the technical exclusion analysis) be modified as
discussed in the Snohomish PUD White Paper, in the WECC BES Task Force Proposal 6, and in Clark’s
answer to Question 5.

Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc
Salem Electric
Grant County PUD No. 2 (Grant)
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,

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Organization

Yes or No

Question 7a Comment

Inc
Kootenai Electric Cooperative
BGE

BGE believes that there is a value in allowing for inclusions through a technical analysis path; however, it is
critical that such a path does not allow for unreasonable inclusion of facilities that do not warrant BES status.

Spyker

We agree that entities should be allowed to conduct an analysis to demonstrate if an element is necessary or
not for the operation of transmission network. We also support that NERC should specify all the relevant
criteria category to be listed as under 2 (a). However, we suggest that NERC should avoid prescribing
numerical values but establish a range of value (or reference industry standard) that would be consistent with
industry/ regional standards or practices without compromising the reliability of transmission network.

Consumers Energy Company

We believe all of the Inclusion criteria should be replaced by a single criterion, which would include any
element that could cause cascading outages of greater than 1,000 MW.

Oncor Electric Delivery

Oncor Electric Delivery agrees with the proposed language that describes the inclusion criteria based
technical analysis.

Tacoma Power

Tacoma Power generally agrees with approach used on the technical analysis path for inclusions.

Duke Energy

The approach and evaluation values should be consistent with those for the Exclusions.

American Transmission
Company, LLC

ATC proposes that the technical analysis criterion be replaced by criteria that are more closely tied to the
Adequate Level of Reliability (ALR) characteristics. The following alternate criteria are offered as possible
examples, “(1) the BES cannot be controlled to stay within acceptable limits following a fault on or loss of the
Element;
(2) the BES does not perform acceptably after credible contingences of the Element;
(3) the Element limits the impact and scope of instability and cascading outages when they occur;
(4) BES facilities are not protected from unacceptable damage by operating the Element within its ratings; and
(5) the BES does not have the ability to supply the aggregate electric power and energy requirements of the
electricity consumers at all times, taking into account scheduled or reasonably expected unscheduled outages
of the Element.

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Organization

Yes or No

Question 7a Comment
In addition, ATC is not aware of any continent-wide appropriate BES performance measures for voltage dip,
frequency excursion, voltage deviation, stability, etc. and ATC speculates that different values are likely for
different regions and system characteristics across the continent. As a result, ATC believes it is not advisable
to try to adopt unproven values without reasonable industry investigation and development.

Manitoba Hydro

Manitoba Hydro does not agree with an impact based approach to establishing BES elements as we believe it
will result in regional differences in the application of the BES definition. In addition, the resources required to
verify the assumptions made in the models used to substantiate a BES exception would be substantial with
no benefit to reliability.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential inclusion in the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.
New York State Reliability
Council

See answer to 5a.

Response: See response to Q5a.
PPL Supply

See comments in Questions 9 and 10

Response: See response to Q9 & Q10.
PacifiCorp

Please refer to additional comments in question 13 regarding a contiguous BES.

Response: See response to Q13.
Edison Electric Institute

See comments for Question 5 above

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Organization

Yes or No

Question 7a Comment

Bonneville Power Administration

Please refer to BPA’s comments on Question #5.

Orange and Rockland Utilities,
Inc.

The Inclusion criteria should mirror Exclusion criteria. See comments 5.

Pepco Holdings Inc

Same comments as question #5

Response: See response to Q5.

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7b. Comments on distribution factor measurement:
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization

Yes or No

Northeast Power Coordinating
Council

Question 7b Comment
See reply to Questions 5b and 6 above.

Response: See response to Q5b and Q6.
Consolidated Edison Co. of NY,
Inc.

See reply to Question 6.

Response: See response to Q6.
SPP Standards Review Group

Please see our comment in 5b above.

Hydro One

[See Comment 5b]

Central Lincoln

Please see 5b.

for Snohomish County PUD

Please see our response to Question 5b.

Response: See response to Q5b.
Edison Electric Institute

See comments for Question 5 above

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Organization

Yes or No

Question 7b Comment

Florida Municipal Power Agency

See FMPA comments in response to Question 5.

Transmission Access Policy
Study Group

See TAPS comments in response to Question 5.

Blachly Lane Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Clark Public Utilities

See comments in 5.

Central Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Clearwater Power Electric
Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Consumer's Power Inc.

Please see our corresponding answers to Question 5 for 7b-7e.

Coos-Curry Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Douglas Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Fall River Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Lane Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Lincoln Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Lost River Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Northern Lights Electric
Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Okanogan Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

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Organization

Yes or No

Question 7b Comment

Raft River Rural Electric
Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Salmon River Electric
Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Umatilla Electric Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

West Oregon Electric
Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Pacific Northwest Generating
Cooperative

Please see our corresponding answers to Question 5 for 7b-7e.

Consumer's Power Inc.

Please see our corresponding answers to Question 5 for 7b-7e.

Spyker

See comments in section 5

Benton Rural Electric Association

See exclusion comments Question 5

United Electric Co-op Inc.

See exclusion comment.

Oregon Trail Electric
Cooperative, Inc.

See exclusion comment

Salem Electric

See exclusion comment

Grant County PUD No. 2 (Grant)

See exclusion comment

Northwest Public Power
Association (NWPPA)

See exclusion comment

Big Bend Electric Cooperative,
Inc.

See exclusion comment

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Organization
Kootenai Electric Cooperative

Yes or No

Question 7b Comment
See Exclusion comment.

Response: See response to Q5.
Iberdrola USA

See 7a.

Independent Electricity System
Operator

[See Comment 7a]

Response: See response to Q7a.
Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

MRO's NERC Standards Review
Forum

NSRF proposes replacing this factor with those cited above because a distribution factor measurement
indicates how much system changes affect the element, not how a fault or loss of the element would
compromise the ALR of the BES. There is no clear correlation between this factor and any of the six
characteristics of Adequate Level of Reliability (ALR) of the BES.

ReliabilityFirst

any impact is an impact, even generation is re-dispatched at 0% in some cases

New York Power Authority

NYPA does not agree with this measurement. Distribution factors are dependent on the number of radial
transmission lines that connect a single source to a load. For example, if two lines connect a single source to
a load, and one line trips, the distribution factor provides a 100% increase in flow on the remaining line. If
three lines connect the source to the load, and one line trips, the distribution factor for the remaining lines
would be 50%.

Muscatine Power and Water

Proposing to replace this factor with those cited above because a distribution factor measurement indicates
how much system changes affect the element, not how a fault or loss of the element would compromise the
ALR of the BES. There is no clear correlation between this factor and any of the six characteristics of
Adequate Level of Reliability (ALR) of the BES.

Consumers Energy Company

If our suggestion in 7a is not adopted, we propose the following: If based on transfer distribution factor this
criterion may have some merit, depending on the TBD value. However, the criterion should not be based on

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Organization

Yes or No

Question 7b Comment
outage transfer distribution factor, as Draft 1 implies since loss of certain distribution facilities can result in
distribution load being transferred to other interconnection points. Distribution facilities should not be
classified as BES.

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 7a because a distribution factor measurement
indicates how much system changes affect the element, not how a fault or loss of the element would
compromise the ALR of the BES. There is no clear correlation between this factor and any of the six
characteristics of Adequate Level of Reliability (ALR) of the BES.

Tacoma Power

Tacoma Power generally agrees with the distribution factor measurement in the technical analysis path for
inclusions.
We suggest adopting a distribution factor of 30%, or more, on an adjacent system.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential inclusion in the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.

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7c. Comments on allowable transient voltage dip measurement:
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization

Yes or No

Question 7c Comment

Northeast Power Coordinating
Council

Refer to the response to Question 5c

Hydro One

[See Comment 5c]

New York Power Authority

Refer to the response to Question 5c.

Central Lincoln

Please see 5c.

for Snohomish County PUD

Please see our response to Question 5c.

Response: See response to Q5c.
Edison Electric Institute

See comments for Question 5 above

Florida Municipal Power Agency

See FMPA comments in response to Question 5.

Transmission Access Policy
Study Group

See TAPS comments in response to Question 5.

Clark Public Utilities

See comments in 5.

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Organization

Yes or No

Question 7c Comment

Spyker

See comments in section 5

Benton Rural Electric Association

See exclusion comments Question 5

United Electric Co-op Inc.

See exclusion comment.

Oregon Trail Electric
Cooperative, Inc.

See exclusion comment

Salem Electric

See exclusion comment

Grant County PUD No. 2 (Grant)

See exclusion comment

Northwest Public Power
Association (NWPPA)

See exclusion comment

Big Bend Electric Cooperative,
Inc.

See exclusion comment

Kootenai Electric Cooperative

See Exclusion comment.

Response: See response to Q5.
Iberdrola USA

See 7a.

Independent Electricity System
Operator

[See Comment 7a]

Response: See response to Q7a.
Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

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Organization
MRO's NERC Standards Review
Forum

Yes or No

Question 7c Comment
NSRF proposes replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable transient voltage dip performance level for evaluating whether a fault or loss of the
element would compromise the ALR of the BES. In addition, the appropriate performance level for this factor
may vary for different areas and system characteristics across the continent.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential inclusion in the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.
ReliabilityFirst

any impact is an impact, planning criteria between 3 & 5 % is often used and not allowed, why inject this into
what define the BES. the criteria is applied it should be included

Muscatine Power and Water

Propose replacing this factor with those cited above because there is presently no established, continentwide, acceptable transient voltage dip performance level for evaluating whether a fault or loss of the element
would compromise the ALR of the BES. In addition, the appropriate performance level for this factor may vary
for different areas and system characteristics across the continent.

Consumers Energy Company

If our suggestion in 7a is not adopted, we propose the following: The criterion related to Transient Voltage
Deviations should be removed from the Inclusion Process. This criterion, regardless of value TBD, would
cause any element, perhaps even including radial Primary Distribution Facilities (8.2 kV, etc.) to be
sequentially included as BES.A fault on non-BES elements will cause significant transient voltage dips on
nearby BES elements until the fault is cleared. If the non-BES element is at the same voltage level, the dip
will result in near-zero voltages; if at different voltage levels, the dip magnitude will be determined by the ratio
of the system Thévinen impedance at the BES to the intervening transformer impedance - if the system
Thévinen impedance is 2% and the transformer impedance is 18%, the voltage on the BES will dip to 10%.

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 7a because there is presently no established,
continent-wide, acceptable transient voltage dip performance level for evaluating whether a fault or loss of the
element would compromise the ALR of the BES. In addition, the appropriate performance level for this factor

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Organization

Yes or No

Question 7c Comment
may vary for different areas and system characteristics across the continent.

Tacoma Power

Tacoma Power generally agrees with allowable transient voltage dip measurement in the technical analysis
path for inclusions.
We suggest adopting the criteria that includes a transient voltage dip exceeding 20% for more than 20 cycles
on an adjacent system’s bus.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential inclusion in the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.

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7d. Comments on allowable transient frequency response:

Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of
Procedure.

Organization

Yes or No

Question 7d Comment

Northeast Power Coordinating
Council

Refer to the response to Question 5d

Hydro One

[See comment 5d]

New York Power Authority

Refer to the response to Question 5d.

Central Lincoln

Please see 5d.

for Snohomish County PUD

Please see our response to Question 5d.

Response: See response to Q5d.
Edison Electric Institute

See comments for Question 5 above

Florida Municipal Power Agency

See FMPA comments in response to Question 5.

Transmission Access Policy
Study Group

See TAPS comments in response to Question 5.

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Organization

Yes or No

Question 7d Comment

Clark Public Utilities

See comments in 5.

Spyker

See comments in section 5

Benton Rural Electric Association

See exclusion comments Question 5

United Electric Co-op Inc.

See exclusion comment.

Oregon Trail Electric
Cooperative, Inc.

See exclusion comment

Salem Electric

See exclusion comment

Grant County PUD No. 2 (Grant)

See exclusion comment

Northwest Public Power
Association (NWPPA)

See exclusion comment

Big Bend Electric Cooperative,
Inc.

See exclusion comment

Kootenai Electric Cooperative

See Exclusion comment.

Response: See response to Q5.
Iberdrola USA

See 7a.

Independent Electricity System
Operator

[See Comment 7a]

Response: See response to Q7a.
Tri-State Generation and

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for

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Organization

Yes or No

Question 7d Comment

Transmission Association

determining the threshold value.

MRO's NERC Standards Review
Forum

NSRF proposes replacing this factor with those cited above because there are established, continent-wide
transient frequency performance levels in the PRC-006-1 standard, but the elements that are applicable to the
standard do not have to be BES elements and the transient frequency response requirements are not
intended to be a criterion for BES classification.

ReliabilityFirst

any impact is an impact, stability and planning criteria are often used and restricted and guard against these
changes, why inject this into what define the BES. if the criteria is applied it should be included

Muscatine Power and Water

Propose replacing this factor with those cited above because there are established, continent-wide transient
frequency performance levels in the PRC-006-1 standard, but the elements that are applicable to the
standard do not have to be BES elements and the transient frequency response requirements are not
intended to be a criterion for BES classification.

Consumers Energy Company

If our suggestion in 7a is not adopted, we propose the following: The criterion relative to frequency response
should be removed. Frequency deviations can result from large changes in distribution load. Distribution
facilities should not be classified as BES.

American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 7a because there are established, continentwide transient frequency performance levels in the PRC-006-1 standard, but the elements that are applicable
to the standard do not have to be BES elements and the transient frequency response requirements are not
intended to be a criterion for BES classification.

Tacoma Power

Tacoma Power generally agrees with the allowable transient frequency response in the technical analysis
path for inclusions. We suggest adopting the criteria that includes a transient frequency response that goes
below 59.6 Hz for up to 6 cycles on an adjacent system’s bus.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential inclusion in the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria
and developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft

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Organization

Yes or No

Question 7d Comment

Rules of Procedure.

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7e. Comments on voltage deviation measurement:
Summary Consideration: The SDT appreciates your comments. Based on industry response and further analysis, the SDT has
abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics that
are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The new process requires an
entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate
through submittal of an exception request form along with any other supporting documentation for the exception being sought.
The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to
support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules
of Procedure.

Organization

Yes or No

Northeast Power Coordinating
Council

Question 7e Comment
See reply to Questions 5e and 6 above.

Response: See response to Q5e and Q6.
Consolidated Edison Co. of NY,
Inc.

See reply to Question 6.

Response: See response to Q6.
Hydro One

[See comment 5e]

New York Power Authority

Refer to the response to Question 5e.

Central Lincoln

Please see 5e.

Response: See response to Q5e.
Edison Electric Institute

See comments for Question 5 above

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Organization

Yes or No

Question 7e Comment

Florida Municipal Power Agency

See FMPA comments in response to Question 5.

Transmission Access Policy
Study Group

See TAPS comments in response to Question 5.

Clark Public Utilities

See comments in 5.

Spyker

See comments in section 5

Benton Rural Electric Association

See exclusion comments Question 5

United Electric Co-op Inc.

See exclusion comment.

Oregon Trail Electric
Cooperative, Inc.

See exclusion comment

Salem Electric

See exclusion comment

Grant County PUD No. 2 (Grant)

See exclusion comment

Northwest Public Power
Association (NWPPA)

See exclusion comment

Big Bend Electric Cooperative,
Inc.

See exclusion comment

Kootenai Electric Cooperative

See Exclusion comment.

Response: See response to Q5.
Iberdrola USA

See 7a.

Independent Electricity System

[See Comment 7a]

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Organization

Yes or No

Question 7e Comment

Operator
Response: See response to Q7a.
Tri-State Generation and
Transmission Association

If this approach is used, then there needs to be a clear technical rationale for defining the metric and for
determining the threshold value.

MRO's NERC Standards Review
Forum

NSRF proposes replacing this factor with those cited above because there is presently no established,
continent-wide, acceptable (steady state) voltage deviation performance level for evaluating whether a fault or
loss of the element would compromise the ALR of the BES. In addition, the appropriate performance level for
this factor may vary for different areas and system characteristics across the continent

ReliabilityFirst

any impact is an impact, planning criteria is often used and restricted to guard against these changes, why
inject this into what define the BES. the criteria is applied to the facility as a BES element it should be
included

Muscatine Power and Water

Propose replacing this factor with those cited above because there is presently no established, continentwide, acceptable (steady state) voltage deviation performance level for evaluating whether a fault or loss of
the element would compromise the ALR of the BES.
In addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent.

Consumers Energy Company

If our suggestion in 7a is not adopted, we propose the following: This criterion may be reasonable, depending
on the TBD value. The TBD value may need to vary for different voltage levels or system configurations.
Loss of multiple capacitors at the distribution level could result in significant voltage deviation at the BES and
the criterion should be developed so as not to result in Distribution facilities being classified as BES.

for Snohomish County PUD

Please see our response to Question 5d.

Response: See response to Q5d.
American Transmission
Company, LLC

ATC proposes replacing this factor with those cited above in 7a because there is presently no established,
continent-wide, acceptable (steady state) voltage deviation performance level for evaluating whether a fault or
loss of the element would compromise the ALR of the BES.

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Organization

Yes or No

Question 7e Comment
In addition, the appropriate performance level for this factor may vary for different areas and system
characteristics across the continent

Tacoma Power

Tacoma Power generally agrees with the voltage deviation measurement in the technical analysis path for
inclusions. We suggest adopting a voltage deviation that exceeds 10% on an adjacent system’s bus.
We have an additional concern with how the language is constructed on items d. and e. The inclusion criteria
may work for simply inverting the exclusion language but in this initial draft, it does not appear to work as
intended. Our suggestions above are describing criteria for defining elements that can be included in the BES.
If that is the result to be adopted by the SDT, items d. and e. must be rewritten to state that elements within
such criteria can be included in the BES.

Response: The SDT appreciates the suggestions for alternate language or clarifications to the proposed language and application of the study parameters utilized to
analyze system Elements for potential inclusion in the BES. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit.
It has become apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity
to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form
along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make
a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.

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8. Do you have concerns about an entity’s ability to obtain the data they would need to do the indicated
technical analyses? If so, please be specific with your concerns so that the SDT can fully understand
the problem and address it in future drafts.
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an
entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as
presently being drafted.

Organization

Yes or No

Northeast Power Coordinating
Council

No

SERC Planning Standards
Subcommittee

No

NERC Staff Technical Review

No

Iberdrola USA

No

Hydro One

No

MRO's NERC Standards Review
Forum

No

Question 8 Comment

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Organization

Yes or No

Question 8 Comment

Bonneville Power Administration

No

The owner of the asset should have all the data necessary to perform the analysis for an Exclusion. The
Exclusion analysis should use the same data request and sharing requirements of other NERC standards and
the owner conducting the Exclusion analysis should consult with other entities as necessary.

PacifiCorp

No

Tennessee Valley Authority

No

Idaho Falls Power

No

No comments

New York State Reliability
Council

No

NPCC A-10 criteria data is freely available.

New York Power Authority

No

Southern Company

No

National Grid

No

Muscatine Power and Water

No

South Carolina Electric and Gas

No

Georgia Transmission
Corporation

No

ISO New England

No

The United Illuminating Company

No

Entergy Services

No

BGE

No

NERC modeling Standards should be sufficient

No comment.

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Organization

Yes or No

Question 8 Comment

Spyker

No

Orange and Rockland Utilities,
Inc.

No

Xcel Energy

No

Oncor Electric Delivery

No

Duke Energy

No

Hydro-Quebec TransEnergie

No

American Transmission
Company, LLC

No

Tacoma Power

No

MidAmerican Energy

No

American Electric Power

Yes

Each criterion specified would not be able to be provided, or even applicable, for each exclusion requested. If
the criteria provided may be selected from as necessary for each request, then we have no concerns on our
ability to provide the data. Our only concern would be if the intent is that each and every criterion specified
must be provided for each request made.

Pepco Holdings Inc

Yes

The entity may not have the tools, model or resources to do a full transmission planning study

Flathead Electric Cooperative,
Inc.

Yes

Obtaining data creates a cost and should be minimized as possible.

Exelon

Yes

As mentioned above, this process will require extensive technical analysis from users, owners, operators and
the Regions. In many cases, the Principles anticipate the use of criteria that is not in existence today. Rather
than reinforcing the bright line approach, these Principles have the potential to create processes that will
result in high costs with little to no corresponding benefits to reliability.

Tacoma Power has no comment at this time.

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Organization

Yes or No

Question 8 Comment

Glacier Electric Cooperative

Yes

It could be very, very difficult and costly for small utilities to perform the necessary transmission planning
studies described in the proposal. I think there needs to be language clarifying how smaller utilities should be
able to obtain this data.

Electricity Consumers Resource
Council (ELCON)

Yes

NERC (and the BES SDT) should not assume that data pursuant to Large Generator Interconnection
Agreements (LGIA) or the Large Generator Interconnection Procedures (LGIP) will be forthcoming on a timely
basis for the purpose of demonstrating BES exceptions. While such information is generally available from
ISOs and RTOs, it is not so forthcoming from vertically-integrated utilities in regions of the country not served
by ISOs or RTOs because such utilities are generally hostile to third-party generation in their service territory.
They are capable of delaying or otherwise obstructing requests for data and information. We recommend that
NERC or the SDT identify mechanisms for requesting and getting the necessary data and information. This
process should be included in the NERC Rules of Procedure.

Western Electricity Coordinating
Council

Yes

The Owner should have all of the data to perform this analysis for an Exclusion; however, an Inclusion would
likely be sought by an entity other than the Owner (i.e., Regional Entity, RC, BA, TOP) that may not have
sufficient data. It should be clarified in the Rules of Procedure that such an entity has the right to request such
data and that the Owner must provide such data.

ReliabilityFirst

Yes

many smaller entities would require assistance and or consultants to perform this analysis and some data
many not be available or be shared etc.

Edison Electric Institute

Yes

Method 2 is largely based on System Planning Criteria developed by WECC. At the present time, we do not
believe that any of the other regions have similar planning criteria for which they could use or could easily
integrate similar criteria into useable Planning Standards which could be applied in useful manner across all
regions. For this reason, it is recommended that a separate Design Committee be created which would
include representatives from all regions. It is expected that this effort may be substantial but is necessary
before Method 2 or the Inclusion Process as written could be used.
We would further caution the use or imposition of such a process since some transmission owners may not
have the necessary skills or tools required to conduct studies of this type (in-house) and imposing this level of
evidence will likely cause many who cannot meet this requirement to include unnecessary elements diluting
the BES as defined and negating the value of the exclusion process.

Electric Market Policy

Yes

Generation Owners and Generation Operators are typically not given access to non-public transmission
information, especially that where a NDA or CEII signature is required. It would be virtually impossible for a
GO to refute proposed inclusion of an Element owned by the GO unless they procure the services of a

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Organization

Yes or No

Question 8 Comment
consulting firm with access to the data. And, even then, the consultant couldn’t provide specifics of the
evaluation only their findings.

Tri-State Generation and
Transmission Association

Yes

Response: The SDT appreciates the comments concerning an entity’s ability to obtain the required information and technical analysis to meet the requirements of
the technical exception criterion. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new
methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity
with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become
apparent that it is impossible to establish values and/or limits that would be valid across all regions and systems. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an exception request form along with
any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a
recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft
Rules of Procedure.
Blachly Lane Electric Cooperative
Central Electric Cooperative
Clearwater Power Electric
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative

No

As discussed on page 12 of Snohomish’s White Paper, there may be a few isolated cases where additional
data will need to be provided to run a valid technical analysis under the criteria set forth in the Exception
Procedure. These cases should be exceedingly rare, however, because the starting point for the technical
analysis we recommend is the current base case operated by the relevant RE, and in nearly every case, the
base case can be expected to model any Element that conceivably has a material impact on the reliable
operation of the bulk system. In those rare cases where it does not, we believe the owner or operator of the
subject Element should be able to provide the needed data, although we propose that the relevant owner or
operator be relieved of this burden if it can be demonstrated that the nearest electrically interconnected
Element has no material impact on the bulk system.

Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative

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Organization

Yes or No

Question 8 Comment

No

As discussed on page 12 of the Snohomish White Paper, there may be a few isolated cases where additional
data will need to be provided to run a valid technical analysis under the criteria set forth in the Exception
Procedure. These cases should be exceedingly rare, however, because the starting point for the technical
analysis Clark recommends is the current base case operated by the relevant Regional Entity, and in nearly
every case, the base case can be expected to model any Element that conceivably has a material impact on
the reliable operation of the bulk system. In those rare cases where it does not, we believe the owner or
operator of the subject Element should be able to provide the needed data.

Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative
West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc
Central Lincoln
Clark Public Utilities
Benton Rural Electric Association
Northern Wasco County PUD
United Electric Co-op Inc.
Oregon Trail Electric
Cooperative, Inc
Salem Electric
Grant County PUD No. 2 (Grant)
for Snohomish County PUD
Northwest Public Power
Association (NWPPA)
Big Bend Electric Cooperative,
Inc.
Kootenai Electric Cooperative
Response: The SDT believes that the technical criteria represent a base line of information to be presented for justification of the exception. If the applicant

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Exceptions — Project 2010-17

Organization

Yes or No

Question 8 Comment

believes that additional information is needed to justify their request, the SDT agrees that the entity should be able to provide any additional information it believes
necessary. The SDT disagrees that the Regional Entity should assess the adequacy of the application. In order to ensure consistency and uniformity across the
continent, the ERO, not the Regional Entity, can be the only institution to conduct this analysis.
Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the
technical and operational characteristics that are to be considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The
initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It has become apparent that it is impossible to
establish values and/or limits that would be valid across all regions and systems. The new process requires an entity to clarify the characteristics of the facilities in
question and to document the operational performance as appropriate through submittal of an exception request form along with any other supporting
documentation for the exception being sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of
whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO as established in the draft Rules of Procedure.
Manitoba Hydro

No

We are concerned however that assumptions could be made to complete the technical analysis to support an
exclusion that may not be appropriate.

Response: The SDT believes that unwarranted assumptions will be identified in the process and such information will be made available to the industry to
prevent others from utilizing similar assumptions.
Independent Electricity System
Operator

No

We anticipate that entities would be granted access to any required historical operations records and
modeling data after signing of non-disclosure agreements as necessary.

Response: Thank you for your comment.
Consumers Energy Company

Yes

CECo is not able to formulate detailed comments at this time, as the criteria have not been finalized. There
are a number of items that are somewhat open ended, i.e. TBD and Other. Once those gray areas are filled
in, we will have a better idea of our ability to obtain the necessary data.

Response: The SDT looks forward to your future comments.
Long Island Power Authority

Yes

The Reliability Coordinator would be required to provide much of the data needed to perform the technical
analyses.

Response: The SDT believes that the burden of proof for the exception is on the applying entity. The applying entity can utilize any resource including other
Registered Entities in presenting their case to the ERO.

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Organization

Yes or No

PPL Supply

Yes

Question 8 Comment
See comments in Questions 9 and 10

Response: See response to Q9 & Q10.

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Exceptions — Project 2010-17

9. Are you aware of any conflicts between the proposed approach and any regulatory function, rule
order, tariff, rate schedule, legislative requirement or agreement, or jurisdictional issue? If so, please
identify them here and provide suggested language changes that may clarify the issue.
Summary Consideration: Most of the commenters expressed that they were not aware of specific conflicts associated with the BES
exception technical principles and regulatory/jurisdictional matters. However, a substantial number of commenters answering “no” and “yes”
raised concerns that the BES Definition and the Exception Technical Principles should respect FPA Section 215 authority limitations. Commenters
to this question did not provide suggestions for addressing this concern.
Based on the extensive comments received by entities about FPA Section 215 authority excluding local distribution systems, the SDT modified the
BES definition to provide additional clarity in this regard. Specifically, the SDT inserted language into the core of the revised BES definition.
WECC and another commenter brought up concerns associated with the applicability of a specific NERC reliability standard (i.e., IRO-010).
ReliabilityFirst expressed concerns about the proposed BES definition changing the NERC Statement of Compliance Registry Criteria (SCRC). It
should be emphasized that the goal of the SDT is to provide clarity to the BES definition and the technical principles for the NERC Rules of
Procedure (RoP) exception process. The SDT’s scope of work does not include potential changes to the SCRC. The SDT has debated this matter
extensively and believes that NERC reliability standards may be applied to non-BES Elements.
A few commenters brought up concerns about specific unique situations (e.g., black start Cranking Paths in local distribution systems). The SDT
cannot address each and every unique regulatory situation in the BES definition and technical principles for the Rules of Procedure (RoP)
exception process. Entities would need to submit relevant regulatory evidence on a case by case basis using the RoP exception process.
However, the SDT did delete the reference to Cranking Paths.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements operated at 100 kV or higher and Real Power
and Reactive Power resources connected at 100 kV or higher. This does not include facilities used in the local distribution of electric energy.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.

Organization

Yes or No

Question 9 Comment

Bonneville Power Administration

No

Under NERC Standard IRO-010, the Transmission Operators are required to obtain information relating to the
operation of the bulk power system within their respective areas. Transmission Operators may still need
information relating to network facilities that ultimately are determined not to be BES facilities. BPA is
concerned that an exclusion could eliminate a requirement that such information be provided.

ReliabilityFirst

Yes

FERC stated that entities registered were not to be taken off the registry without sound reasons and the
definition sole intent was not to restrict or remove entities, but put in place a sound definition that everyone

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Exceptions — Project 2010-17

Organization

Yes or No

Question 9 Comment
can use. I do not think this is a help, it is very detailed and allot of entities will be confused and lost

Western Electricity Coordinating
Council

Yes

It must be clear that under NERC Standard IRO-010, the Reliability Coordinators are required to obtain
information relating to the operation of the bulk power system within their respective areas. In light of this
requirement, Reliability Coordinators may request the submittal of information for network facilities that
ultimately are not determined to be BES facilities. It would be reasonable to also include a requirement that
Reliability Coordination staff will explain why they require the requested information from non-BES facilities
when seeking such information.

Response: The goal of the SDT is to provide clarity to the BES Definition and the technical principles for the Rules of Procedure exception process not to
address the NERC Statement of Compliance Criteria Registry (SCRC) and the applicability of specific reliability standards. NERC reliability standards may be
applied to non-BES Elements that are necessary for operating the interconnected transmission network.
City of Redding

Yes

State and court rulings that have defined Transmission and Distribution. One possible solution is to state that
the determination made via this methodology is for reliability purposes only and is not intended to redefine
established market and rate determinations.

Northeast Power Coordinating
Council

Yes

It is imperative to understand that the NERC’s revised definition will have a direct impact on entities across
North America and may conflict with regulatory requirements, Codes, and Licenses. FERC in its Orders 743
and 743A has directed NERC to address these concerns. For Ontario, the BES exception criteria shall meet
the expectations of Ontario's regulator (Ontario Energy Board) which has the sole authority and responsibility
for the reliability of customer connections and loads within Ontario. Therefore, it will be necessary to
accommodate NERC's proposed definition of BES or the exception process with the Ontario situation.

Hydro One
Spyker

The SDT and RoP teams should: o Modify the exception criteria and procedure to provide regulatory
flexibility with requirements to conduct basic technical analysis , to allow entities to consistently present their
case to the ERO and/or the regulator for a step by step expedited evaluation.
o Include provisions in both the NERC exception criteria and exception process for federal, state and
provincial jurisdictions. These provisions should provide clear guidance so that, if and when there are
deviations from the exception criteria, they are identified with technical and regulatory justifications ensuring
there is no adverse impact on the interconnected transmission network.
o Understand that the path to generating facilities need not be always BES contiguous. Generating units
can/should be required to be planned, designed, and operated in accordance with a subset of NERC
Standards, but should not always require contiguous paths.

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Organization

Yes or No

Question 9 Comment

Edison Electric Institute

Yes

EEI is concerned that under the technical principles, some facilities that are local distribution facilities may be
included the BES. This is in conflict with the definition of the Bulk Power System in Section 215 which
excludes facilities used in local distribution. In particular, EEI is concerned that the provision of the technical
principles prohibiting the seeking an Exclusion for a cranking path will include local distribution within the
definition of BES.

Consolidated Edison Co. of NY,
Inc.

Yes

See the EEI reply to BES Definition and Designations Question 11.

PacifiCorp

Yes

The SDT proposal combined with the ROP proposal may be in conflict with Section 215 of the Federal Power
Act, which requires “facilities used in the local distribution of electric energy” be excluded. The processes
proposed may be over inclusive and by default require several elements which are not required for the
reliable operation of the BES to in fact be included in the definition of “BES.”

Flathead Electric Cooperative,
Inc.

No

the proposed BES Definition could conflict with Section 215 of the Federal Power Act if the Definition, the
Exception Process, and the Technical Criteria do not effectively exclude facilities used in local distribution
from the BES or if the BES definition does not focus on cascading outages, separation events, and instability
on the interconnected bulk system. These statutory limits on the scope of the BES and reliability standards
are a minimum that must be met.

Electricity Consumers Resource
Council (ELCON)

Yes

The proposed technical principles violate the exemption in FPA section 215 against the inclusion in the BES
of facilities used in the local distribution of electric energy, given that the BES is a subset of the BPS.

Exelon

Yes

To the extent facilities used in local distribution of electric energy may be included in the BES, the proposed
principles are in conflict with the Federal Power Act.

Occidental Energy Ventures
Corp.

Yes

The proposed technical principles seem to be in contradiction to the exemption in FPA Section 215 against
the inclusion in the BES of facilities used in the local distribution of electric energy.

Central Lincoln

No

As we explained in our response to Question 1 of the Comment Form on the 1st Draft of Definition of BES,
filed on May 27, Central Lincoln believes that the proposed BES Definition could conflict with Section 215 of
the Federal Power Act if the Definition, the Exception Process, and the Technical Criteria do not effectively
exclude facilities used in local distribution from the BES or if the BES definition does not focus on cascading
outages, separation events, and instability on the interconnected bulk system. These statutory limits on the

for Snohomish County PUD

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Organization

Yes or No

Question 9 Comment
scope of the BES and reliability standards are a minimum that must be met.

The United Illuminating Company

Yes

under the technical principles, some facilities that are local distribution facilities may be included the BES.
This is in conflict with the definition of the Bulk Power System in Section 215 which excludes facilities used in
local distribution. In particular, Local distribution facilities can not be included in the BES even if they are part
of a cranking path.

Pepco Holdings Inc

Yes

Facilities defined as local distribution facilities should not be forced into BES classification due to this new
bright line definition.

Consumers Energy Company

Yes

The Technical Principles for Demonstrating BES Exceptions should not conflict with the seven-factor test
provisions of FERC Order 888. In particular, provisions should not be established by the Standard Drafting
Team that contradict prior Commission rulings associated with seven-factor test provisions.

Hydro-Quebec TransEnergie

Yes

However, there is a conflict between the proposed approach and the regulatory framework applicable in the
Quebec's Interconnexion or at least there are some important differences between both. Paragraph 95 of
FERC Order 743 acknowledged the situation of non-FERC juridiction. As for the Quebec's Interconnexion, the
BES definition and exclusion approach shall meet the expectations of Quebec's regulator, the Régie de
l'Énergie du Québec, (Quebec Energy Board) which has the responsibility to ensure that electric power
transmission in Quebec is carried out according to the reliability standards it adopts. In a recent order (D2011-068), the Régie de l'Énergie du Québec has recognized several level of application for the
Reliability Standards in Québec. It stated specifically that most reliability standards in Québec shall be
applied to the Main Transmission System (MTS). One other level of application recognised by this decision is
the NPCC Bulk Power System (BPS) to which the standards related to the protection system (PRC-004-1 and
PRC-005-1) and those related to the design of the transmission system (TPL 001-0 to TPL-004-0) will be
applicable (including the rest of the standards). The Main Transmission System definition is somewhat
different than the Bulk Electric System definition. The Main Transmission System includes elements that
impact the reliability of the grid, supply-demand balance and interchanges. It can be described as follows :The
transmission system comprised of equipments and lines generally carrying large quantities of energy and of
generating facilities of 50 MVA or more controlling reliability parameters: o Generation/load balancing o
Frequency control o Level of operating reserves o Voltage control of the system and tie lines o Power flows
within operating limits o Coordination and monitoring of interchange transactions o Monitoring of special
protection systems o System restoration
Therefore, it will be necessary to accommodate NERC's proposed definition of BES or the exception process
with the Quebec situation where Entities are under a different jurisdiction. These differences include more

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Organization

Yes or No

Question 9 Comment
than one level of application for the reliability standards, the Main Transmission System definition being the
main one to which most reliability standards apply.

Manitoba Hydro

Yes

Canadian Entities are not under FERC jurisdiction, so the revised BES Definition may not apply.
A number of Canadian Entities have the BES defined within their provincial legislation. This may introduce
differences and even contradictions between elements that are included in the BES according to provincial
legislation and the NERC definition.

Independent Electricity System
Operator

Yes

Similar to the BES Exception Procedure, the document “Technical Principles for Demonstrating BES
Exceptions” must explicitly recognize the authority of Canadian and Mexican Governmental Entities to adopt
the Technical Principles for Demonstrating BES Exceptions in its entirety or in part with their own deviations,
while ensuring there will be no adverse impact on the interconnected transmission system. Footnote 2 of the
“Procedure for Requesting and Receiving an Exception from the Application of the NERC Definition of Bulk
Electric System” should be repeated in the “Technical Principles” document.

Response: The SDT has clarified this position.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements operated at 100 kV or higher and Real Power and
Reactive Power resources connected at 100 kV or higher. This does not include facilities used in the local distribution of electric energy.
Electric Market Policy

Yes

Dominion is concerned that the provision of the proposed technical principles prohibiting the seeking of an
exclusion for a cranking path for blackstart resources will include local distribution facilities within the definition
of the BES. This conflicts with the definition of “Bulk Power System” in Section 215 of the Federal Power Act,
which excludes facilities used in local distribution.

Response: The SDT has deleted the reference to Cranking Paths.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
PPL Supply

Yes

Based on FERC Order 743 paragraph 120, radial and local distribution facilities should be excluded from the
definition of the Bulk Electric System (BES). The exclusion of non-networked facilities such as radial lines is
further re-enforced with Order 743 paragraph 73 which describes the characteristics of a network and does
not include most generator interconnection facilities. In that order, FERC justified its bright-line, 100 kV
threshold, explaining that "many facilities operated at 100 kV and above have a significant effect on the
overall functioning of the grid" because they share the following characteristics: 1. "operate in parallel with
other high voltage and extra high voltage facilities"i. The “bright line” at 100 kV recognizes many 100 kV lines

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Exceptions — Project 2010-17

Organization

Yes or No

Question 9 Comment
parallel other HV/EHV lines and can be significantly loaded by failure of the HV/EHV lines. This does not
apply to radial lines, even at 100 kV and above.2. "interconnect significant amounts of generation sources"
(emphasis added)3. "operate as part of a defined flow gate"4. have a "parallel nature" and are capable of
“caus[ing] or contribute[ing] to significant bulk system disturbances”.i. Radial lines cannot cause significant
BES disturbances since the outage of a radial line is studied in all N-1 planning studies and if the TPL
standards are followed, an N-1 should not cause such disturbances.Excluding generator lead lines is very
practical because the physical reality of a radial generator lead line is that it cannot be overloaded by outages
on parallel paths because there are no parallel paths. Further, the MW flow on a radial line is well known and
limited to a known maximum (limited to the larger of the generation or load on the end of the line); clearly
these are reasons for excluding radial lines. When and if a generator lead line is tapped by another generator
or load, it is possible that the line between the tap point and the original point of interconnection might need to
be rolled into the electrical network. However, at that time, it might also be possible for the transmission
owner to purchase the line and make the tap point the new point of interconnection.

Response: The SDT cannot address each and every unique situation in the technical principles for the Rules of Procedure (RoP) exception process. Entities
would need to bring relevant evidence on a case by case basis using the RoP exception process.
Springfield Utility Board

Yes

o The four characteristics defined in the “Exception Criteria - Exclusions” portion of Technical Principles for
Demonstrating BES Exceptions appears to be in conflict with, rather than in parallel to, the exceptions which
are part of the proposed “core definition” in the Proposed Continent-wide Definition of Bulk Electric System.
SUB proposes that NERC postpone work related to Technical Principles for Demonstrating BES Exceptions
until a continent-wide BES definition is approved.
o FERC Order No. 743 states, “We believe that it would be worthwhile for NERC to consider formalizing the
criteria for inclusion of critical facilities operated below 100 kV in developing the exemption process”.
However, there is no mention of critical facilities operated below 100 kV in NERC’s Exception Criteria. SUB
would encourage NERC to include critical facilities consideration in their exception criteria.

Response: The SDT is responsible for completing NERC Project 2010-17 (related to the BES Definition process and the exception technical principles process)
before year-end. The SDT does not have sufficient time to bifurcate the two processes.
The technical principles for the Rules of Procedure exception process as proposed by the SDT allows for presenting exception evidence for including critical
Elements energized below 100 kV into the Bulk Electric System.
SERC Planning Standards
Subcommittee

No

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Exceptions — Project 2010-17

Organization

Yes or No

SPP Standards Review Group

No

NERC Staff Technical Review

No

Iberdrola USA

No

Tri-State Generation and
Transmission Association

No

MRO's NERC Standards Review
Forum

No

Idaho Falls Power

No

New York Power Authority

No

Southern Company

No

ITC

No

National Grid

No

Muscatine Power and Water

No

Blachly Lane Electric Cooperative

No

South Carolina Electric and Gas

No

Glacier Electric Cooperative

No

Georgia Transmission
Corporation

No

Question 9 Comment

We believe that the final drafts of the definition and exemptions should comport to the legal requirements of
Section 215.

Insufficient time was provided to fully undertake this inquiry.

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Exceptions — Project 2010-17

Organization

Yes or No

Entergy Services

No

Clark Public Utilities

No

Central Electric Cooperative

No

Clearwater Power Electric
Cooperative

No

Consumer's Power Inc.

No

Coos-Curry Electric Cooperative

No

Douglas Electric Cooperative

No

Fall River Electric Cooperative

No

Lane Electric Cooperative

No

Lincoln Electric Cooperative

No

Lost River Electric Cooperative

No

Northern Lights Electric
Cooperative

No

Okanogan Electric Cooperative

No

Raft River Rural Electric
Cooperative

No

Salmon River Electric
Cooperative

No

Question 9 Comment

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Organization

Yes or No

Question 9 Comment

Umatilla Electric Cooperative

No

West Oregon Electric
Cooperative

No

Pacific Northwest Generating
Cooperative

No

PNGC Power

No

Consumer's Power Inc.

No

Benton Rural Electric Association

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

American Electric Power

No

AEP is not aware of any conflicts between the proposed approach and any regulatory function, rule order,
tariff, rate schedule, legislative requirement or agreement, or jurisdictional issue.

Orange and Rockland Utilities,
Inc.

No

BGE

No

No comment.

Northern Wasco County PUD

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

Xcel Energy

No

United Electric Co-op Inc.

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

Oregon Trail Electric
Cooperative, Inc.

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

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Exceptions — Project 2010-17

Organization

Yes or No

Question 9 Comment

Oncor Electric Delivery

No

Salem Electric

No

Duke Energy

No

Grant County PUD No. 2 (Grant)

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

Northwest Public Power
Association (NWPPA)

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

Big Bend Electric Cooperative,
Inc.

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section 215

American Transmission
Company, LLC

No

Kootenai Electric Cooperative

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

Tacoma Power

No

Tacoma Power is not aware of any conflicts at this time.

MidAmerican Energy

No

ACES

No

As properly constructed Definition and Exceptions process should meet the legal requirements of Section
215.

Response: Thank you for your response.

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Exceptions — Project 2010-17

10. Are there any other concerns with this approach that haven’t been covered in previous questions
and comments? Please be as specific as possible with your comments.
Summary Consideration: Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying
exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an
entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide
values and/or limits due to differences in operational characteristics. The new process requires an entity to clarify the
characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate
Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the
exclusion or inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as
presently being drafted.

Organization

Yes or No

SERC Planning Standards
Subcommittee

No

Iberdrola USA

No

Bonneville Power Administration

No

ReliabilityFirst

No

Tennessee Valley Authority

No

Idaho Falls Power

No

New York State Reliability
Council

No

Question 10 Comment
The comments expressed herein represent a consensus of the views of the above-named members of the
SERC EC Planning Standards Subcommittee only and should not be construed as the position of SERC
Reliability Corporation, its board, or its officers.

No comments

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Exceptions — Project 2010-17

Organization

Yes or No

South Carolina Electric and Gas

No

Glacier Electric Cooperative

No

Exelon

No

Georgia Transmission
Corporation

No

Consolidated Edison Co. of NY,
Inc.

No

Entergy Services

No

Clark Public Utilities

No

Orange and Rockland Utilities,
Inc.

No

Xcel Energy

No

Duke Energy

No

Hydro-Quebec TransEnergie

No

New York Power Authority

No

Question 10 Comment

Response: Thank you for your response. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and developed a
new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide greater
continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or limit. It
has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new process
requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of an
exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the submittal to
validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation with the ERO

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Exceptions — Project 2010-17

Organization

Yes or No

Question 10 Comment

as established in the Rules of Procedure as presently being drafted.
BGE

No

It is important to consider that the Technical Principles for Demonstrating BES Exceptions is only one part of
the BES definition project. The Technical Principles and the Rule of Procedure Process must be evaluated
together with the BES Definition to sufficiently understand the revisions. In the end, the Technical Principles
and the BES Definition must coalesce and be clearly coordinated and understood. The BES Definition
language must include reference to the role of the associated defining documents. One unambiguous
document must not be made ambiguous by an associated document or process.
We appreciate the work of the drafting team and support the goal to produce clear definition language so that
upwards of 95% of the assets are clearly distinguished as either included or excluded from the BES. We are
particularly sensitive to the potential for burdensome processes (e.g. TFEs) to be added to reliability
compliance. We appeal to the team for continued, vigilant consideration of the arduousness of the BES
determination process.

Response: The upcoming posting of the BES definition and the technical principals will be posted simultaneously in order for industry to adequately evaluate the
two documents and their relationship to each other.
Oncor Electric Delivery

No

Although Oncor Electric Delivery understands the need for the ERO to be in a position to override the
inclusion criterion,
Oncor desires more clarity on what factors contribute to an overriding action.

ACES

Yes

The term interconnected transmission network is used throughout this document. Bulk Electric System
should be used in its place. The purpose of the technical principles is to determine if an Element is needed to
support the operation of the Bulk Electric System. Using interconnected transmission network adds more
uncertainty to the document.

Northeast Power Coordinating
Council

Yes

Exception criteria should be crafted at a high-level with key menu items of assessment that can be followed
continent-wide by entities to put forward their exception(s) for element(s) that are not necessary for the
interconnected transmission network based on technical assessment, evidence and justification for unique
characteristics, configuration, and utilization. (Also see suggestions/ comments in Question 6)

SPP Standards Review Group

Yes

In Question 5 regarding the Transient and Steady State Stability criteria, we would suggest establishing
criteria for the damping such that the time required to return to normal is limited. Damping in 1-5% range may
be sufficient to accomplish this.

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Exceptions — Project 2010-17

Organization

Yes or No

Question 10 Comment
Also, delete 2.a.iv.8. in the Exclusion Criteria and 1.c.8. in the Inclusion Criteria.

NERC Staff Technical Review

Yes

A criterion should be added for supporting a request for inclusion of an Element. If an Element has been
identified as causal or contributory to a Category 2 or higher event as defined in the ERO Event Analysis
Process, that should be sufficient evidence that it is necessary for the Element to be planned, designed,
maintained, and operated in accordance with NERC Reliability Standards. An assessment of the Element
should include consideration of any corrective actions that have been implemented to prevent a reoccurrence.
The Exception criteria also should include a list of characteristics of Elements that will not be considered for
exclusion, on the basis that this list of characteristics already identifies the importance of such Elements to
reliable operation of the interconnected transmission network. Characteristics should include: (1) Elements
that are relied on in the determination of an Interconnection Reliability Operating Limit (IROL); (2) Blackstart
resources and the designated blackstart Cranking Paths identified in the Transmission Operator’s restoration
plan regardless of voltage, (3) Elements subject to Nuclear Plant Interface Requirements (NPIRs) as agreed
to by a Nuclear Plant Generator Operator and a Transmission Entity defined in NUC-001, and (4) Elements
identified as required to comply with a NERC Reliability Standard by application of criteria defined within the
standard (e.g., the test defined in PRC-023 to identify sub-200 kV Elements to which the standard is
applicable.)

Florida Municipal Power Agency

Yes

The third paragraph of the introduction to the Technical Principles is awkwardly worded and might be
misconstrued. FMPA suggests the following rewording: “Entities are not required to seek exceptions under
the Exception Procedure to exclude from the BES Element(s) that are already excluded under the BES
definition and designations.”For the sake of consistency, Exclusions (1) should contain a provision analogous
to Exclusions (2)(b) and Inclusions (1)(f) addressing the circumstances under which the ERO can override a
demonstration based on these criteria. As noted above, one of those circumstances would be a
demonstration by NERC that the Element in question meets the criteria for inclusion in the BES.

Yes

The proposed principles seem preliminary and immature. In addition as noted in earlier comments they are
not fully consistent with the proposed BES definition, particularly with respect to radial elements and local
distribution networks. Such consistency should be incorporated before the next posting.

Transmission Access Policy
Study Group

Tri-State Generation and
Transmission Association

We further feel that it is very unlikely that the technical evidence path can be placed on a sound technical
foundation and matured by the end of this year as directed by the FERC.
Key definitions are lacking and should be added to the document. For instance “distribution factor” is not
carefully defined even though such factors can be calculated in a variety of ways.

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Exceptions — Project 2010-17

Organization

Yes or No

Question 10 Comment

Hydro One

Yes

Exception criteria should be crafted at a high-level with key menu items of assessment that can be followed
continent-wide by entities to put forward their exception for element(s) that are not necessary for the
interconnected transmission network and based on technical assessment, evidence and justification for its
unique characteristics, configuration, and utilization. (Also see suggestions/ comments on Question 6)

MRO's NERC Standards Review
Forum

Yes

1. NSRF proposes replacing the wording in the Exclusion preface, Exclusion 2 preface, and Inclusion 1
preface of “not necessary to reliably operate the interconnected transmission network” with “necessary to
maintain an Adequate Level of Reliability (ALR) of the Bulk Electric System”.
2. NSRF has reservations on the following statement made in the introduction of this document:” Due to the
importance of Blackstart Resources and their designated blackstart Cranking Paths to restoration efforts, no
exceptions will be allowed for those items.” This does not allow for a provision to exclude any designated
Blackstart Cranking Path (at any voltage) even though there may be technical justification for it.
3. The first page states that “Specific content of this application is spelled out elsewhere in this appendix.”
NSRF requests the SDT describe where this appendix will be published. Furthermore, is it a compliance
document or just technical “guidance”?
4. Having the following statement included for both exclusions and inclusions will create disagreement:”The
ERO can override this criterion but would need to provide additional justification to support their finding.”
NSRF believes any override should have adequate technical justification and not interfere with other statutory
requirements. Also, it does not clarify or identify who would make the determination whether NERC has made
adequate justification to override the criterion.
5. NSRF believes that the “Inclusion” process should be completely removed from BES Definition. We
recommend using bright-line criteria indentifying everything 100 kV and above to be BES and then allow for
the “Exception” process to take out facilities that do not impact the reliability of the BES. Selecting BES
facilities based on a right-line criteria is what FERC requested in its Order regarding BES Definition. This
would streamline the process and remove some unnecessary paperwork.

MidAmerican Energy

Yes

MidAmerican supports the NSRF comments.

PacifiCorp

Yes

The SDT has proposed several technical criteria to be used to determine if an element has an impact on the
reliability of the BES. PacifiCorp believes that the majority of non-BES elements can be excluded using a
modified proposed bright-line and/or using the non-technical approach. However, in the event an entity
requires additional justification to remove non-BES elements from the BES, then PacifiCorp feels the
technical criteria should be established on an interconnection basis, not on a continent-wide basis. Because

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Exceptions — Project 2010-17

Organization

Yes or No

Question 10 Comment
of the number of operating and geographic differences among the interconnections, to try to establish
technical criteria on a continental basis would introduce confusion. PacifiCorp believes it is impossible to
establish technical criteria that will allow unique interconnections to be treated in a comparable manner.

Western Electricity Coordinating
Council

Yes

The biggest concern is that the Technical Principles and the reasoning behind them need to be fully
explained. The SDT has mentioned on calls the possibility of a white paper or resource document, and WECC
fully supports the creation of such a document. This white paper should describe the rationale for the criteria
as well as how that indicates that the element is necessary for reliable operation.
Also, the justification for the ERO to override these criteria should be clarified. It should be clear that the
ERO’s ability to override these criteria is on a case-by-case basis.

Electricity Consumers Resource
Council (ELCON)

Yes

The bright-line tests used in the revised BES definition and technical principles may capture the facilities of
hundreds of entities that may not know that NERC exists or the enforceability of NERC Reliability Standards.
The technical principles should be supplemented with a technical guide or appendix that provides examples
of the steps that may be necessary to demonstrate BES exceptions.

Alabama Public Service
Commission

Yes

The second paragraph of the proposed Technical Principles states that “[d]ue to the importance of Blackstart
Resources and their designated blackstart Cranking Paths to restoration efforts, no exceptions will be allowed
for those items.” This sentence should be deleted from the technical principles. An unintended consequence
of subjecting all blackstart cranking pathways to inclusion in the BES by default would be to cause a
Registered Entity, in order to minimize costs, to not declare every possible cranking path but instead limit to
the minimum required cranking paths in order to comply with the standards, as opposed to designating
multiple pathways. This consequence could be avoided by allowing blackstart cranking pathways to be
evaluated for exceptions just like any other element.

Southern Company

Yes

The Technical Principles document suggests that no exceptions be allowed for Blackstart Resources and
designated Cranking Paths. Southern Company is concerned with the treatment of these facilities and
recommends that certain statements be removed. In Project 2010-17 Definition of the BES, Southern
Company commented that the proposed inclusion, Inclusion I4, be removed from the BES Definition because
an existing NERC Reliability Standard, EOP-005-2 System Restoration from Blackstart Resources, already
addresses these facilities regardless of voltage.
Further, the proposed inclusion will expand the applicability of some NERC Reliability Standards to facilities
below 100 kV. Southern Company believes this position will unnecessarily cause more facilities to become
applicable to reliability standards without any benefit to reliability. Therefore, we recommend the following
statement be deleted: “Due to the importance of Blackstart Resources and their designated blackstart

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Exceptions — Project 2010-17

Organization

Yes or No

Question 10 Comment
Cranking Paths to restoration efforts, no exceptions will be allowed for those items.”

National Grid

Yes

The exception process should be strictly limited to the procedures for application and approval and should not
include substantive elements.

Muscatine Power and Water

Yes

1. Propose replacing the wording in the Exclusion preface, Exclusion 2 preface, and Inclusion 1 preface of
“not necessary to reliably operate the interconnected transmission network” with “necessary to maintain an
Adequate Level of Reliability (ALR) of the Bulk Electric System”.
2. Currently having reservations concerning the following statement made in the introduction of this
document:” Due to the importance of Blackstart Resources and their designated blackstart Cranking Paths to
restoration efforts, no exceptions will be allowed for those items.” This does not allow for a provision to
exclude any designated Blackstart Cranking Path (at any voltage) even though there may be technical
justification for it.
3. The first page states that “Specific content of this application is spelled out elsewhere in this appendix.”
Request the SDT describe where this appendix will be published and indicate if this is a compliance
document or just technical “guidance”?
4. By having the following statement included for both exclusions and inclusions will lead to
disagreement:”The ERO can override this criterion but would need to provide additional justification to support
their finding.” Suggesting that any override should include adequate technical justification and not interfere
with other statutory requirements. Also, it does not clarify or identify who would make the determination
whether NERC has made adequate justification to override the criterion.
5. Do not believe that the “Inclusion” process should be completely removed from BES Definition. Would like
to recommend using bright-line criteria indentifying everything 100 kV and above to be considered BES and
then allow for the “Exception” process to take out Facilities that do not have an impact on the reliability of the
BES. Selecting BES Facilities based on bright-line criteria is what FERC requested in its Order regarding
BES Definition. This would streamline and simplify the process by removing a large quantity of exceedingly
unnecessary paperwork.

Blachly Lane Electric
Cooperative
Central Electric Cooperative
Clearwater Power Electric

Yes

In general, , as we discuss above, the Technical Principles for Demonstrating BES Exceptions present a
reasonable approach to resolving questions of inclusion and exclusion in the BES that the BES definition itself
does not clearly resolve. However, we caution that these principles for demonstrating exceptions cannot, and
must not, take the place of a consideration of, and criteria under whether, any specific piece of equipment is
subject to FERC, the ERO, and Regional Entity jurisdiction in the first instance. Section 215 of the Federal
power Act (FPA) sets out clear limits of jurisdiction of FERC, the ERO, and Regional Entities for purposes of

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Exceptions — Project 2010-17

Organization
Cooperative
Consumer's Power Inc
Coos-Curry Electric Cooperative
Douglas Electric Cooperative
Fall River Electric Cooperative
Lane Electric Cooperative
Lincoln Electric Cooperative
Lost River Electric Cooperative
Northern Lights Electric
Cooperative
Okanogan Electric Cooperative
Raft River Rural Electric
Cooperative
Salmon River Electric
Cooperative
Umatilla Electric Cooperative

Yes or No

Question 10 Comment
developing and enforcing reliability standards. Specifically, Section 215(i) provides that the ERO “shall have
authority to develop and enforce compliance with reliability standards for only the Bulk-Power System.” 16
U.S.C. § 824o(a)(1) (emphasis added). Section 215(a)(1) of the statute defines the term “Bulk-Power
System” or “BPS” as: (A) facilities and control systems necessary for operating an interconnected electric
energy transmission network (or any portion thereof); and (B) electric energy from generation facilities needed
to maintain transmission system reliability. The term does not include facilities used in the local distribution of
electric energy.” Id. As we have explained in our comments on the BES definition, that definition should
expressly account for these jurisdictional limitations up front. This would allow for the jurisdictional limitation
consideration as the very first step in determining whether or not a particular piece of equipment is part of the
BES.
The Technical Principles for Demonstrating BES Exceptions, on the other hand, provides a completely
separate set of criteria for exclusion from the BES and would come into play only after application of the full
BES definition to a particular piece of equipment and determination that the BES definition does not provide a
satisfactory answer as to whether that piece of equipment is or is not part of the BES. This is acceptable
insofar as it goes, but, because (1) the criteria in the Technical Principles are distinct from the jurisdictional
limits of Section 215 of the FPA, and (2) consideration of the Technical Principles would essentially be the
last, or one of the last, steps in the process, the Technical Principles cannot substitute for, in any way,
consideration of the jurisdictional limitations of the FPA. Again, we cannot overemphasize enough how
important it is to have the jurisdictional consideration be the very first step in the process of determining
whether a particular piece of equipment is or is not part of the BES. Again, thank you for the opportunity to
comment. We look forward to continuing to work with NERC and stakeholders to develop a BES definition
that is both workable and lawful.

West Oregon Electric
Cooperative
Pacific Northwest Generating
Cooperative
Consumer's Power Inc
New York State Department of
Public Service

The core BES definition based on a 100 kV brightline is an overreach of bulk system designation under the
provisions of the Federal Power Act; a properly specified BES core definition would avoid the extensive
analysis required under the exceptions procedure. That said, the proposed principles for use in the
exceptions process are consistent with previous FERC efforts to distinguish between transmission and local
distribution.
The upfront exclusion of applying the proposed principles to blackstart cranking path facilities is a potential

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Exceptions — Project 2010-17

Organization

Yes or No

Question 10 Comment
overreach into the local distribution system and can be counter productive reliability. Mandating compliance
of NERC standards to cranking paths will result in the specification of only one cranking path by host utilities
to minimize costs, where designating multiple paths in restoration paths would provide the flexibility needed to
minimize customer outage duration.

Springfield Utility Board

Yes

SUB has the following concerns regarding NERC’s Technical Principles for Demonstrating BES Exceptions:
o Clear Definition of Radial - As previously addressed in our BES Definition comments, SUB would encourage
a more clear definition of a “radial” versus “closed-loop” system. Because there still appears to be
inconsistencies in both definition and application, SUB encourages NERC to develop a concise definition of a
radial system. For example, if a system is normally operated as radial, but could be operated as closed (by
manually closing a breaker), would it be considered a radial or close-looped system? If the answer is closelooped, then is this in all cases, or are there exceptions?
o Approval of Exceptions - SUB would like for NERC to clarify the process for receiving, reviewing, and
accepting or rejecting exception applications. The Technical Principles for Demonstrating BES Exceptions
states that, “...will be subject to review and remand by the ERO itself, or by any agency having regulatory or
statutory oversight of NERC as the ERO.” During NERC’s presentation at APPA’s BES Definition webinar, it
was explained that the exception process would look like the following:1. Entity applies for expemption,2.
Region receives application, verifies received, and forward to NERC with recommendation(s), and 3. NERC
makes final determination (decision is appealable by entity).For consistent application of the expemption
procedure, SUB would encourage NERC to adopt the process as it was communicated during the APPA
webinar, with regions making recommendations, but NERC making the final decision.
o Duration of Approved Exclusions/Inclusions - The Technical Principles for Demonstrating BES Exceptions
does not indicate the duration for approved exclusions or inclusions. How long are granted
exclusions/inclusions? Permanent? Annual? Other?
o Publication of Exceptions - For consistent application, as well as transparency and accountability, SUB
would request that all exceptions be published ; those applied for, as well as whether they were rejected or
accepted, as well as decision rationale.

ISO New England

Yes

Any generator that is studied individually will not be shown as material since the electric system is designed to
allow the outage of any individual generator. Generators must be studied within the context of the electric
system to assess materiality. The generator and its interconnecting transmission facilities would likely be able
to be excluded based on this process although they meet the Registry Criteria thresholds requiring inclusion.

The United Illuminating

Yes

UI is concerned that the method used to characterize exclusions in Method 1 did not follow the proposed BES

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Exceptions — Project 2010-17

Organization

Yes or No

Company

Question 10 Comment
Definition and believe the process developed for Method 2 (and reused for Sub-100kV Inclusions) is overly
complicated, lacks necessary regional standards to support the process and may prove too difficult for some
companies to fully comply with thereby discouraging a consistent and uniform application of the definition
across all regions and affected BES element owners.
These Principles are not technical Principles. Further the use of these Planning criteria and impact
assessments is not very different from the NPCC functional test that drew the ire of FERC. The Drafting
Team is attempting to develop definitions and identifiers for the fringes of the bulk power system, but they are
replacing one set of ambiguities with a set of technical ambiguity. This product is poor because given the
very first term, that is the first principle to be met, is those facilities necessary for the reliable operation of an
interconnected transmission system, is full of undefined concepts such that anything attempting to define it in
a subtle manner is immediately lost in the ether.
Recognizing that these technical principles will be permanent, UI suggests excluding them and sticking with
the bright line exclusions and inclusions in the proposed definition.

Occidental Energy Ventures
Corp.

Yes

The Technical Principles and the new BES Definition seem to include a significant number of retail customers
as proposed. Surely this is not the intent of these changes.
There should be an exclusion along the lines of Comment 6.

Flathead Electric Cooperative,
Inc.

Grant County PUD No. 2 (Grant)

supports the approach to the exclusion process proposed by the SDT, which provides two different paths to
exclusion, one based on readily-identifiable operational characteristics of a system, and one based on
technical reliability analysis. We believe it is important to provide for the first path, based on operational
characteristics, so that systems that are marginally disqualified under the BES Definition (because, for
example, generation within the system exceeds demand for a few hours a year) can obtain an exclusion
without the large investment of resources that otherwise might be required for a full-scale technical analysis.
we question whether the first subsection of the characteristic test, relating to system proximity, is necessary,
and we are concerned that the requirement that a system meet all four requirements of the characteristics test
may be overly restrictive. For example, it is easy to imagine a distribution system in a rural area that covers a
widely dispersed area, so that load is many miles from the relevant generation/transmission source, and that
the system therefore does not meet the electrical proximity element, but meets the other three elements of the
characteristics test. Such a system should be excluded because it clearly serves a local distribution function,
and not a transmission function, as demonstrated by the fact that the system meets subsections (c) (power
flows into the system but rarely flows out ) and (d) (power is not intentionally transported over the system).
Accordingly, we recommend that the SDT consider eliminating the first test.

Big Bend Electric Cooperative,

In the alternative, the SDT should consider allowing exempting a system from the BES if it, for example,

Benton Rural Electric
Association
Northern Wasco County PUD
United Electric Co-op Inc
Oregon Trail Electric
Cooperative, Inc
Central Lincoln
Salem Electric

Yes

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Exceptions — Project 2010-17

Organization

Yes or No

Inc

Question 10 Comment
meets three of the four criteria rather than all four.

Northwest Public Power
Association (NWPPA)
Kootenai Electric Cooperative
Spyker

Yes

Exception criteria should be crafted at a high-level with key menu items of assessment that can be followed
continent-wide by entities to put forward their exception for element(s) that are not necessary for the
interconnected transmission network and based on technical assessment, evidence and justification for its
unique characteristics, configuration, and utilization.

American Electric Power

Yes

AEP appreciates the work that the drafting teams have done within the various deliverables related to the
BES definition, technical principles for demonstrating BES exceptions, and the BES definition exception
process. AEP acknowledges the benefits of agreeing to a BES definition and exception process, and
appreciates the drafting teams’ requests for industry involvement.
Due to the interrelated nature of the deliverables currently out for review regarding the BES definition and
exception processes, it is difficult if not impossible, to comment “in isolation” on any individual facet of the
project. For example, there needs to be a defined relationship between an approved definition of BES, the
technical principles for demonstrating BES exception, and the exception process itself. When closely related
projects such as these are done simultaneously, no individual deliverable can rely on the completed work of
another. As a result, we risk having conflicting decision making across these projects. As a result, AEP is not
in the position to make further comments at this time beyond those recently and concurrently made regarding
the BES definition and technical principles for demonstrating BES exceptions. We suggest that further work
on these efforts, when appropriate, become more consolidated and that care be taken to not undertake
concurrent efforts before sufficient progress has been made on important aspects of the project. AEP
appreciates the drafting teams’ requests for industry input, and looks forward to its future involvement after
additional progress has been made on these issues.

Consumers Energy Company

Yes

In addition to the owner, only those with jurisdictional authority, such as the ERO and RRO, should be
permitted to register Exception Requests. A third party may have a business reason for wishing to encumber
another entity with regulatory compliance risk and responsibility. In addition, this could create an additional
strain on the Exception Request process due to an excessive number of requests from third parties.
We do want to ensure that the term "Other", used in Exclusion Section 2.a.iv.8., and Inclusion Section 1.c.8.,
not remain in the final Technical Principles document.

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Exceptions — Project 2010-17

Organization
for Snohomish County PUD

Yes or No

Question 10 Comment

Yes

Snohomish County PUD generally supports the approach to the exclusion process proposed by the SDT,
which provides two different paths to exclusion, one based on readily-identifiable operational characteristics of
a system, and one based on technical reliability analysis.
We believe it is important to provide for the first path, based on operational characteristics, so that systems
that are marginally disqualified under the BES Definition (because, for example, generation within the system
exceeds demand for a few hours a year) can obtain an exclusion without the large investment of resources
that otherwise might be required for a full-scale technical analysis.
That being said, we question whether the first subsection of the characteristic test, relating to system
proximity, is necessary, and we are concerned that the requirement that a system meet all four requirements
of the characteristics test may be overly restrictive. For example, it is easy to imagine a distribution system in
a rural area that covers a widely dispersed area, so that load is many miles from the relevant
generation/transmission source, and that the system therefore does not meet the electrical proximity element,
but meets the other three elements of the characteristics test. Such a system should be excluded because it
clearly serves a local distribution function, and not a transmission function, as demonstrated by the fact that
the system meets subsections (c) (power flows into the system but rarely flows out ) and (d) (power is not
intentionally transported over the system). Accordingly, we recommend that the SDT consider eliminating the
first test.
In the alternative, the SDT should consider allowing exempting a system from the BES if it, for example,
meets three of the four criteria rather than all four.We have pasted in the text of our White Paper below.
Please contact us for a more readable version of the White Paper.White PaperA Performance-Based
Exemption Process to Exclude Local Distribution Facilities from the Bulk Electric System April 2011 This
White Paper proposes a transmission planning (“TPL”) “performance-based” process to determine the local
distribution facilities the North American Electric Reliability Corporation (“NERC”) must exclude from the Bulk
Electric System (“BES”) pursuant to Section 215(a)(1) of the Federal Power Act (“FPA”).
This process would apply to those local distribution facilities that are not automatically excluded under a
bright-line BES definition. Consistent with Federal Energy Regulatory Commission (“FERC”) Order Nos. 743
and 743-A, a performance-based exemption process would be objective, consistent, and transparent, and
would adequately differentiate between local distribution and transmission, i.e., BES, facilities.
I. What Is Reliability? FPA Section 215 authorizes NERC to promulgate “reliability standards,” subject to
FERC approval. Section 215 defines “reliability standard” to mean a properly-approved requirement “to
provide for the reliable operation of the bulk-power system.” The statute, in turn, defines “reliable operation”
to mean “operating the elements of the bulk-power system within equipment and electric system thermal,
voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will

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Exceptions — Project 2010-17

Organization

Yes or No

Question 10 Comment
not occur as a result of sudden disturbances, including . . . unanticipated failure of system elements.”
II. What Is “Customer Service” or “Level of Service” (“LOS”)? Local customer service or LOS relates to
service failures on local utility systems that are wholly internalized rather than spilling onto the interconnected
regional grid. These types of service failures relate to local customer service and LOS standards. The
customers of those utilities will bear the full cost of complying with internal LOS standards and will obtain the
full benefit of compliance to the extent that service levels on those systems improve. Accordingly, state public
utility commissions (for regulated utilities) and independent boards (for non-regulated utilities) can fully and
accurately weigh whether the benefits of compliance with such standards are justified by the costs they will
pay. Intervention by NERC and a Regional Entity is not needed because a utility’s actions related to level of
service on its own system will neither unduly burden the customers of other systems, threaten the reliable
delivery of power to those customers, nor create incidental benefits to those remote customers. In the
absence of the need to protect customers of systems remote from the consequences of decisions made by an
individual utility, there is no warrant for NERC or a Regional Entity to interfere with a utility’s internal decisionmaking about the appropriate LOS to its own customers, and the costs that will be borne by those customers
to achieve any particular level of service. In fact, in the “Savings Provisions” of Section 215, Congress
specifically included language prohibiting NERC and Regional Entities from enforcing “compliance with
standards for adequacy” of electric service. By law, these remain the exclusive province of local decisionmakers.
III. The Need for a Material Impact Test In Order No. 743-A, FERC clarified that a material impact test is
appropriate in the reliability context if the test can be shown to identify facilities needed for reliable operation.
The following example of an outage demonstrates the need for an impact test to distinguish between LOS
and Reliability, i.e., local distribution facilities and BES facilities.
A. Pre-Event Facts Local Utility Administration (“LUA”) owns a 115 kV system that moves power from two
points of delivery (“POD”) and serves 1000 MW of load. A DC battery rack had an unexpected failure a few
days after it was routinely inspected and LUA has not implemented Supervisory Control and Data Acquisition
(“SCADA”) so the DC battery voltage is not continuously monitored. The LUA system interconnects with BES
Company’s system which consists of 230 kV and 500 kV lines.
B. Event Facts A fault occurs and the breakers in substation 2 fail to operate due to a battery failure (Figure
1). This results in an outage for customers served by substations 1, 2, and 3 on the LUA system. Figure 1
C. Post-Event Facts Immediately after the outage, LUA customer service receives numerous customer calls
followed by a call from its Public Utility Commission/Local Utility Board (“/PUC/LUB”). LUA dispatches crews
immediately after being informed of the outage to identify and resolve the problem. Within 45 minutes, the
fault is sectionalized and the all load is restored. The PUC/LUB receives complaints from LUA customers
who identify economic and other adverse impacts of the outage. The PUC/LUB demands a report from the

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Exceptions — Project 2010-17

Organization

Yes or No

Question 10 Comment
LUA that describes the event and restoration, as well as potential solutions. LUA submits a report which finds
that the main solution to this problem involves the implementation of a SCADA system. The SCADA system
scope of work includes battery voltage telemetry and would have identified the DC system issue and
prevented the protection system failure, resulting in only the loss of substation 3. The SCADA plan cost
estimate is $30 million and was presented three years earlier. The PUC/LUB evaluated the costs and
benefits of the new SCADA system, but did not approve the project in order to reduce the budget and/or
provide rate stability for the struggling local economy. LUA, the PUC/LUB, and customers will re-evaluate the
merits of adding SCADA as well as other solutions such as increasing substation inspection runs, updating
the batter fleet, and further investigating battery manufacture reliability records. Based on the LUA report, the
battery bank failure rate immediately after routine inspections is expected to occur once every 3,500 years.
Seventy battery banks are used on the LUA system, so a bank failure should be expected every 50 years.
BES Company’s neighboring 230kV and 500kV system does not experience an adverse system impact.
Subsequently, BES Company identifies that one of its breakers operated at the LUA South POD. BES
Company and LUA coordinate a review of the system protection scheme and BES Company determines that
it operated correctly. BES Company verifies that the LUA outage did not create any thermal, voltage, or
transient stability limit violations on the BES Company system. The Regional Entity, NERC, and FERC treat
the outage as a Reliability Standards issue. The LUA System (highlighted in yellow) is considered part of the
BES because it meets the “bright line” 20 MVA and 100 kV thresholds under the current BES definition and
the NERC Statement of Compliance Registry Criteria (“SCRC”). The event would most likely be considered a
TPL-003 category C event specifically C8 SLG Fault, with delayed clearing that may include a stuck breaker
or protection system failure. The LUA Substation Department reviews its inspection records and has
adequate documentation for the battery banks involved in the outage. As a result, LUA avoids substantial
fines. However, during the inspection review, LUA notices that the battery bank in a similar distribution
substation inspection schedule was completed three days late. Upon following further internal procedures,
LUA finds that the battery bank was inspected three days late due to restorations efforts after a major wind
storm. Although there were no LOS impacts, and the inspection schedule was unrelated to the outage, the
Reliability Standards triggered a LUA self report to its Regional Entity which ultimately resulted in a $50,000
penalty.
D. Summary This example identifies that in addition to a “bright line” BES exclusion process a more refined
process such as a “performance based” reliability assessment is needed to distinguish BES facilities from
distribution facilities if the NERC Statement of Compliance Registry Criteria (“SCRC”) continues to be the
benchmark for assessing BES facilities. It is clear from this example that the current 100 kV and 20 MVA
thresholds cannot accurately classify what is and is not considered part of the BES. Defining BES facilities is
important from the “Reliability Standard” and “LOS” perspectives as well as from a local and regional
jurisdictional standpoint. There are multiple agencies identifying and approving what facilities should and
should not be built, what programs should and should not be implemented, and if a fine should be paid by

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customers experiencing an outage without determining if it could have had an adverse impact on neighboring
electric systems. Without a performance-based process, many small and medium electric utilities would be
unnecessarily burdened.  
IV. Neighboring System Rule It is important but not always easy to distinguish the difference between
“reliability” and “LOS” impacts. One way to resolve this is to use the “neighboring system rule.”
Simplistically, if events on the host system’s facilities can create an “adverse” or “material” impact on a
neighboring electric (TO, TOP, BA) system, those facilities should be considered part of the BES as they are
creating a reliability impact. If not, these facilities should not be considered part of the BES.
V. “Adverse” or “Material” Impact A key question in applying the “neighboring system rule” is what is an
“adverse” or “material” impact, and what “performance based” assessment should be used to benchmark
adverse or material. Because the electric system within an interconnection is frequency interdependent,
theoretically every system change impacts the interconnected system to some degree. Turning on a lightswitch that is connected to an operational 20 watt CFL (light bulb) theoretically impacts frequency, although to
an undetectable degree. Therefore the term “material” or “adverse” impacts must be defined to distinguish
observable impacts that affect reliability from minutia. A number of performance based exclusion examples
have been proposed that use, Power Transfer Distribution Factors (“PTDF”), Line Outage Distribution Factors
(“LODF”), fault duty or short circuit levels, reactive margin studies (P-V and Q-V), abbreviated or focused
powerflow and transient stability analysis, as well as complete TPL assessment using multiple seasonal base
cases, loading conditions, transfer levels. These methods demonstrate various metrics, they rank system
strength (both real and reactive), the ability of power to flow through system under normal and outage
conditions, and they determine steady state, voltage stability and transient (angular) stability performance.
Although there may be advantages to a multi-step “performance based” approach that includes the exclusion
examples above, this paper proposes a TPL-based assessment that is consistent with BES performance
benchmarks used in assessing transmission system performance in North America. The Western Electricity
Coordinating Council (“WECC”) BES Exclusion/Inclusion Assessment - 2-16-11 version provides a sound
metrics in assessing the performance of a system as well as determining if a system can materially impact a
neighboring system (Figure 2). It would be envisioned that each interconnection would develop a
“Disturbance Performance Table of Allocable Effects on Other System”. This table is necessary because the
NERC TPL Performance Table does not provide actual performance details on acceptable transient and post
transient voltage perturbations or minimum transient voltage frequencies. Figure 2 show the approved TPL001 through TPL-004 performance tables.Figure 3 - Table 1 from the NERC TPL Reliability Standards 
VI. Performance Based Assessment Process The “performance based” methodology below is based on the
“neighboring system rule” and the WECC BES Exclusion/Inclusion Assessment - 2-16-11 that was developed
by the WECC Bulk Electric System Definition Task Force (“BESDTF”). The process focuses on exclusions
rather than inclusion and specific response times, schedules, and process details have been removed as this

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will likely need to be determined by each, Regional Entity Representing the Interconnection (“RERI”)
A. Purpose The purpose of this document is to set forth a “performance based” technical process for
assessing whether elements with a nominal operating voltage greater than 100 kV and outside the NERC
SCRC based excursion process should be excluded from the Bulk Electric System. An element is necessary
to reliably operate an interconnected transmission system if it significantly affects neighboring Transmission
Owners, Operators, and Balancing Authorities as described in Table 1 below. This paper proposes a method
for assessing whether an element is necessary to support the reliability of an interconnected transmission
system or if the element is limited to supporting local customer service levels.
B. TermsExclusion Assessment (EA) An assessment of whether a Subject Element or System has a material
impact on neighboring Transmission Owners, Operators, and Balancing Authorities as described in Table 1
below and conducted in accordance with the process set forth in this document.EA Base Case The
interconnection approved, Base Case as modified to include the Subject Element, used to perform the
assessment described in this document.Regional Entity Representing the Interconnection The regional entity
representing the interconnectionRegistered Entity The entity registered to comply with mandatory reliability
standards for a Registered Function.Responsible Entity The entity responsible for performing the EA and
verifying the results of the EA to the interconnection.Subject System or Element of a System The System or
Element of a System that is being examined by the EA.
C. Applicabilitya. An EA may be performed:i. By a registered entity, or by a third party on behalf of a
registered entity, to assess whether a Subject Element or system has a material impact on neighboring
Transmission Owners, Operators, and Balancing Authorities as described in Table 1 may be excluded from
the BES as set forth by the RERI. ii. The RERI, or by a third party on behalf of the RERI, to assess whether a
Subject Element or system has a material impact on neighboring Transmission Owners, Operators, and
Balancing Authorities as described in Table 1 should be included as part of the BES as set by the RERI.b.
Frequency of analysis. The confirmed findings of an EA are valid until reversed by a subsequent EA. A new
EA is required if:i. Significant changes are made to the network topology in the vicinity of the Subject
Element; orii. RERI staff requests a new EA. Such request shall be provided in writing and shall include
reasonable justification for the request.
D. Notifying the RERI of the Responsible Entity’s intent to submit an EA finding or to perform an EA.The
Responsible Entity shall notify the RERI in writing of its intent to submit such a finding. Such notice shall
include:a. A general description of the Subject Element(s);b. One-line diagrams representing the Subject
Element and applicable neighboring Elements; andc. A description of the base case that will be used in
performing the EA and how that case will be stressed for the analysis.
E. Performing the Analysis Base Case The base case(s) used for the studies shall be developed from current
interconnection Operating Cases and shall simulate stressed conditions in the area of the element to be

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analyzed which (1) are reasonably expected to be achieved, consistent with the study period selected (e.g.,
hydro generation shall reflect seasonal water availability patterns) and (2) are expected to provide “worstcase” results (i.e., the greatest impact on voltage, flow, or transfer capability) during the upcoming operating
year. The base case(s) shall be “stressed” by committing or de-committing generating units and adjusting
generating unit output to increase the flow on the candidate element and the electrically nearest rated
interconnection transfer path to the greatest extent possible, but not beyond their continuous ratings, for the
initial set of conditions. To help minimize the possibility of dispute as to whether the base case(s) are suitably
stressed, entities are encouraged to solicit input from subregional planning groups or other planning entities
as the suitability of the base case(s) before undertaking the analyses described below.i. Non-represented
Elements. If the Subject Element is not represented in the EA Base case:1. The Responsible Entity shall
provide to the RERI a written request to add the Responsible Entities data to the cases:o all data reasonably
necessary to accurately and completely model the Subject Element in the EA Base case; ando A one-line
diagram showing this element and other nearby Elements. If the nearest connected Element is not found to
be necessary for the operation of an interconnected transmission system, the RERI shall notify the
Responsible Entity to take no further action.
F. Performance Based Methodology The impact an System or Element has on neighboring Transmission
Owners, Operators, and Balancing Authorities as described in Table 1 shall be determined by assessing the
performance of key measures of BES reliability through power flow, post-transient, and transient stability
analysis with (1) the system, and the Subject Element, operating at reasonably stressed conditions that
replicate expected system conditions under which the loss of the Subject Element would have the greatest
impact on the key measures of reliability, and (2) the Subject Element removed from service, but without
allowing for system readjustment. For the purposes of this analysis, “Elements” may be: (1) lines; (2)
transformers; (3) buses or bus sections; (4) generating units; (5) shunt devices . i. Simulation 1: Requirement:
Meet applicable NERC Reliability Standard (TPL-002 and TPL-003) and the RERI Disturbance Performance
Table of Allocable Effects on Other System” Criteria performance for NERC TPL-002 and TPL-003
disturbances.Step 1: Run appropriate TPL-002 (N-1 contingency) studies of elements in the electrical vicinity
of and including the Candidate Element (i.e., simulate primary protection operates as intended)Step 2: Run
appropriate TPL-003 (N-2 contingency) studies of elements in the electrical vicinity of and including the
Candidate Element. This would include both N-2 contingencies in which the Candidate Element would
simultaneously be lost as part of a common mode failure, as well as contingencies in which the Candidate
Element’s primary protection fails.Automatic Remedial Action Schemes (“RAS”) or Special Protection
Schemes (“SPS”) that are fully redundant (i.e., their failure is not credible) may be triggered during this
simulation. If the failure of the RAS/SPS is a credible event, it should be considered as part of the N-2
analysis. ii. Simulation 2:Requirement: Remove the Candidate Element. Do not allow for system
adjustment, and re-solve the base case. Then conduct applicable NERC Reliability Standard (TPL-002 and
TPL-003) contingencies. Step 1: Remove Candidate Element (i.e., simulate unplanned opening of

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facility).Step 2: Assume no system adjustment. At this point, elements may be loaded above their continuous
ratings but may not be loaded above their emergency ratings. Step 3: Perform NERC TPL-002 and TPL-003
(N-1 and N-2 contingency) studies.Step 4: If the analysis demonstrates performance that meets or exceeds
that called for in the NERC Reliability Standards and RERI System Performance Criteria, the Candidate
Element would be determined to not be necessary for the operation of an interconnected transmission
system. Note: Consequential load tripping is allowed, and consequential and out-of-step generation tripping
is allowed.CriteriaTable 1: RERI Disturbance-Performance Table of Allowable Effects on Other
SystemsNERC and WECC Categories Outage Frequency Associated with the Performance Category
(outage/year) Transient Voltage Dip Standard Minimum Transient Frequency Standard Post Transient
Voltage Deviation StandardASystem normal Not Applicable Nothing in addition to NERCBOne elementout-ofservice  0.33 Not to exceed 25% at load busses or 30% at non-load busses.Not to exceed 20% for more
than 20 cycles at load busses. Not below 59.6Hz for 6 cycles or more at a load bus. Not to exceed 5% at any
bus.CTwo or more elementsout-of-service 0.033 - 0.33 Not to exceed 30% at any bus.Not to exceed 20% for
more than 40 cycles at load busses. Not below 59.0Hz for 6 cycles or more at a load bus. Not to exceed 10%
at any bus.DExtreme multiple-element outages < 0.033 Nothing in addition to NERC Figure 1. Voltage
Performance Parameters RERI TPL criteria related to reactive power resources:1. For transfer paths,
voltage stability is required with the pre-contingency path flow modeled at a minimum of 105% of the path
rating for system normal conditions (Category A) and for single contingencies (Category B). For multiple
contingencies (Category C), post-transient voltage stability is required with the pre-contingency transfer path
flow modeled at a minimum of 102.5% of the path rating.2. For load areas, voltage stability is required for the
area modeled at a minimum of 105% of the reference load level for system normal conditions (Category A)
and for single contingencies (Category B). For multiple contingencies (Category C), post-transient voltage
stability is required with the area modeled at a minimum of 102.5% of the reference load level. For this
criterion, the reference load level is the maximum established planned load limit for the area under study.3.
Specific requirements that exceed the minimums specified in 1 and 2 may be established, to be adhered to by
others, provided that technical justification has been approved by the RERI.4. Item 3 applies to internal
interconnection Systems.Submitting a Proposed Finding of Exclusion to the Regional EntityInformation
required. Once the analysis has been performed and the Subject Element/System has been determined to
not have a material impact on neighboring Transmission Owners, Operators, and Balancing Authorities as
described in Table 1, and is unnecessary for the operation of an interconnected transmission system, the
Responsible Entity shall submit the findings to the RERI.RERI Review of Proposed Findings The RERI
operational/planning staff with technical expertise in powerflow studies shall review Proposed Findings of
Exclusion submittals and shall determine if the assessment is deficient or agrees with the finding of exclusion.
The RERI shall exempt the system elements from the BES, if the elements are approved for exclusion. If the
exclusion of the BES elements change the Responsible Entities NERC functional registrations the Region
shall support the Responsible Entity through the NERC deregistration process.

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Dispute Resolution A Responsible Entity or Registered Entity or Owner may appeal a Disputed Finding of
Exclusion with the RERI to NERC.
Ongoing Responsibilitiesa. Logging. The RERI shall create and maintain a comprehensive list, available for
public review, of:i. All Elements with nominal operating voltages at or above 100 KV that have Confirmed
Findings of Exclusion, or, through other aspects of the BES definition, have been excluded from the BES
including an explanation of how the element was excluded through the definition;ii. All Elements with nominal
operating voltages below 100 kV that have Findings of Inclusion; andiii. The status of all EAs in dispute.iv.
The Responsible Entity would continue to provide system data to the neighboring Balancing Authorities and
Transmission Owners and Operators and if applicable continue to coordinate underfrequency load shed and
under voltage load shed scheme information.VII. Conclusion NERC should adopt the TPL-based assessment
as proposed herein. A bright-line BES test will not exclude all load distribution facilities as required by the
FPA. Further, a performance-based exemption process would be objective, consistent, and transparent, and
would adequately differentiate between local distribution and transmission, i.e., BES, facilities.

American Transmission
Company, LLC

Yes

1. ATC proposes replacing the wording in the Exclusion preface, Exclusion 2 preface, and Inclusion 1 preface
of “not necessary to reliably operate the interconnected transmission network” with “necessary to maintain an
Adequate Level of Reliability (ALR) of the Bulk Electric System”.
2. ATC has reservations on the following statement made in the introduction of this document:” Due to the
importance of Blackstart Resources and their designated blackstart Cranking Paths to restoration efforts, no
exceptions will be allowed for those items.” This does not allow for a provision to exclude any designated
Blackstart Cranking Path (at any voltage) even though there may be technical justification for it.
3. The first page states that “Specific content of this application is spelled out elsewhere in this appendix.”
ATC requests the SDT describe where this appendix will be published. Furthermore, is it a compliance
document or just technical “guidance”?
4. Having the following statement included for both exclusions and inclusions will create disagreement:”The
ERO can override this criterion but would need to provide additional justification to support their finding.” ATC
believes any override should have adequate technical justification and not interfere with other statutory
requirements. Also, it does not clarify or identify who would make the determination whether NERC has made
adequate justification to override the criterion.

Manitoba Hydro

Yes

The exception procedure is a complicated and resource intensive process. To be most effective, the BES
definition should be a stand-alone 100kV bright line with any exception criteria being specified within the
definition. Additionally:-FERC Order 743 directed the revision of the Bulk Electric System (BES) definition to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions. The proposed impact

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based exception procedure undermines all three of these targets. -The Technical Exceptions eliminate the
100kV ‘bright-line’ definition and introduce regional differences, both of which are contradictory to the goals of
the BES revision project. -The commitment for NERC to review and continuously monitor BES exceptions
made through this process would be extremely onerous and resource intensive with little benefit to reliability.
-To obtain industry consensus on the precise limits to determine if an element has sufficient impact on the
BES to be included in the BES is not a reasonable or attainable endeavor.

NESCOE

Yes

NESCOE believes that exclusion determinations should be based on clear but flexible criteria that do not
result in the unnecessary inclusion of elements into the BES that do not adversely impact the reliability of the
BES. The process described here is too limiting in its requirement that an application meet all of those four
listed criteria not requiring technical analysis.
Applicants and reviewers should have a broader menu of decision criteria available to them.
Regarding those criteria related to exclusions based on technical analysis, NESCOE suggests that ranges of
values, in recognition of regional differences in network characteristics, be suggested by the drafting team for
further consideration.
Finally, as discussed above in response to questions 1 through 4, NESCOE believes that additional exclusion
determinations should not require a finding that all four proposed criteria are met. Rather, the various criteria
set forth under 1(a) through 1(d) should be treated as alternative criteria to qualify for an additional exclusion,
and entities seeking additional exclusions to the BES should be allowed to demonstrate that one or more
criteria is met, depending on the nature of the element that is the subject of the application.

Response: The SDT appreciates your comments. Based on industry response and further analysis, the SDT has abandoned the initial exclusion criteria and
developed a new methodology is intended to clarify the technical and operational characteristics that are to be considered in identifying exceptions, and provide
greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an entity’s characteristics to a defined value and/or
limit. It has become apparent that it is not feasible to establish continent-wide values and/or limits due to differences in operational characteristics. The new
process requires an entity to clarify the characteristics of the facilities in question and to document the operational performance as appropriate through submittal of
an exception request form along with any other supporting documentation for the exception being sought. The appropriate Regional Entity will review the
submittal to validate information, make a recommendation of whether or not to support the exclusion or inclusion, and then file the request and recommendation
with the ERO as established in the Rules of Procedure as presently being drafted.
Edison Electric Institute

Yes

We are concerned that the method used to characterize exclusions in Method 1 did not follow the proposed
BES Definition and believe the process developed for Method 2 (and reused for Sub-100kV Inclusions) is
overly complicated, lacks necessary regional standards to support the process and may prove too difficult for
some companies to fully comply with thereby discouraging a consistent and uniform application of the

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definition across all regions and affected BES element owners.
In the proposed (BES) definition and accompanying Inclusions and Exclusions, the Drafting Committee went
to some effort to clearly and methodically define what was included and what was permissible to exclude.
Unfortunately the NERC proposed “Technical Principles for Demonstrating BES Exceptions” did not follow
that same clear and concise manner adding some confusion which could lead to inconsistent application of
the Exclusion (and Inclusion) Criteria. For example, at no point did the “Principles” ever identify Inclusions I2
through I5 which were liberally used in the exclusion criteria within the BES definition.
Additionally within the body of the Proposed BES definition, there are three (3) approved Exclusions (E1 Radial System; E2 - Small Customer Generator/Generation System and E3 - Local Distribution Networks).
Each of the Exclusions have its own set of criteria used to define and characterize the methodology
necessary to meet each exclusion, however, the “Principles” contained in this document only loosely follow
the criteria provided and in some cases miss that criteria all together.
We refer the SDT to the EEI comments previously submitted on the BES Definition regarding the relationship
of the BES definition to the statutory exclusion of local distribution facilites.

PPL Supply

Yes

General PPL Supply concerns with draft Technical Principles for exclusion/inclusion:1. It may be premature to
work on an exclusion/exemption/inclusion process since the BES definition is not established yet. A lot of
work could be done on the Exclusion/Inclusion that is meaningless because there is some chance the
exclusion/inclusion process will not complement or might duplicate the BES definition.
2. The proposal will result in inclusion of generation facilities that are not significant to BES reliability.
3. The exclusion/inclusion drafting team does not appear to have considered the FERC assessment in Order
743-A (17-Mar-11) that “material impact assessments” cannot be unduly subjective and must be technically
based as stated in paragraph 47.
a. For the material impact tests in the Exclusion/Inclusion Technical Principles to be technically based, it is
important that the tests actually measure what FERC states are the characteristics of the BES (see Order 743
paragraph 73), namely 1) operate in parallel, 2) carry significant amounts of generation, 3) operate as part of
a defined flowgate, 4) are parallel in nature and 5) are capable of causing or contributing to significant
disturbances. The proposed tests do not make these measurements.
b. Further, since all facilities already meet the technically based NERC planning and operating standards, any
additional measure beyond these standards such as those created by the BES Exclusion/Inclusion drafting
team will be unduly subjective, as these new measures go beyond the technical basis of the NERC
standards.

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4. It is unclear how the exclusion/inclusion drafting team considered FERC’s concerns with the use of
“material impact assessments,” as described in Order 743, paragraph 85 (“no grounds on which to reasonably
assume that the results of the material impact assessment are accurate, consistent, and comprehensive”).
Specific comments on Technical Principles paper from NERC DT 20110510A. Please add wording to make
complete sentences as needed in order to clarify whether facilities meeting these criteria are included or
excluded. For example, the clarifying words are added to the following Exclusion 1 to help the reader better
understand the meaning. 1. “The elements that meet all of the following characteristics are not necessary for
the reliable operation of the grid and are thus excluded:”a. System elements that are located in close
electrical proximity to Load are exempt from inclusion in the BES.B. Notwithstanding the need for complete
sentences to assure proper interpretation, the following comments should be considered by the drafting team:
o Exclusion 1 a) uses an unduly subjective, non-technically based material impact test.
o Exclusion 1 b) i and ii attempts to introduce disconnect procedures in the classification as “radial” which
may hurt reliability by disconnecting radial equipment that could provide voltage support. The exclusion also
introduces commercial (dispatch) considerations which may not be appropriate in a reliability-based
document.
o Exclusion 1 c) assuming “system” is short for “system elements”, this requirement for exclusion is overly
discriminatory to generators which flow power out.
o Exclusion 1 d) is too vague to be useful because “system” seems to have more than one meaning in this
requirement.
o Exclusion 2 and Inclusion 1 in their entirety are unduly subjective, non-technically based material impact
tests.We are concerned that the proposed inclusion and exclusion procedures could result in not only
significant generation interconnection facilities being included in the BES - but also less significant generation
interconnection facilities. Such a result would be inconsistent with FERC Order 743.
Accordingly, PPL Supply respectfully requests NERC to:o Exclude radial facilities less than 100 kV and not
black start (these facilities are excluded in the latest definition of the BES).
o Exclude radial facilities greater than 100 kV but less than 200 MVA (proposed BES now includes generators
over 20 MVA)o Exclude local distribution networks (LDNs) with flow into network up to 200 MVA
o Currently, LDNs are excluded if they only absorb (not produce) net power (Technical Principles Exclusion 1c). It is also appropriate to exclude LDNs with less than net 200 MVA flow into the BES electrical network.
o Inclusion efforts should not consider such issues as proximity to markets, proximity to load or nuclear
facilities, or length of generator lead line.

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Independent Electricity System
Operator

Yes or No
Yes

Question 10 Comment
We hold the view that the path to generating facilities need not be always BES contiguous. Generating units
should be required to meet a subset of NERC Standards, but should not always require contiguous BES
paths.
Finally, we reiterate that exception criteria should be crafted at a high-level with key menu items of
assessment that can be followed continent-wide by entities to put forward their exception for element(s) that
are not necessary for the interconnected transmission network and based on technical assessment, evidence
and justification for its unique characteristics, configuration, and utilization.

Response: The SDT has responded to comments on the BES definition in the Consideration of Comments form for the BES definition posting.
The SDT appreciates the comments and suggestions for the technical exception criterion. Based on industry response and further analysis, the SDT has
abandoned the initial exclusion criteria and developed a new methodology is intended to clarify the technical and operational characteristics that are to be
considered in identifying exceptions, and provide greater continuity with the existing definition of BES. The initial proposal was dependent on a comparison of an
entity’s characteristics to a defined value and/or limit. It has become apparent that it is not feasible to establish continent-wide values and/or limits due to
differences in operational characteristics. The new process requires an entity to clarify the characteristics of the facilities in question and to document the
operational performance as appropriate through submittal of an exception request form along with any other supporting documentation for the exception being
sought. The appropriate Regional Entity will review the submittal to validate information, make a recommendation of whether or not to support the exclusion or
inclusion, and then file the request and recommendation with the ERO as established in the Rules of Procedure as presently being drafted.
Electric Market Policy

Yes

Although Dominion didn’t see a specific form to address comments on Appendix 5B to the NERC ROP,
Dominion would like to point out a particular area of concern with that Appendix. Dominion requests that
NERC include explicit language stating that exclusion or inclusion of an element (for compliance purposes)
begins only after approval/disapproval and any associated appeal has been reviewed and a final decision
reached. Dominion would also like to point out that it assisted in the preparation of the Edison Electric
Institute’s comments and therefore agrees with the comments raised by EEI.

Response: The SDT has forwarded your comments to the RoP team for their consideration.
Pepco Holdings Inc

Yes

Concern that as this proposal is written such that each exclusion in the BES definition (E1, E2 and E3) will
require a submittal to approve that is an exclusion.

City of Redding

Yes

The SDT is encouraged to address generators installed as load modifiers to distribution load.>>>>
As additional evidence of distribution line, if there is not an OATT filed on a line then it is not transmission per
FERC rules.

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Tacoma Power

Yes or No
Yes

Question 10 Comment
Tacoma Power supports the SDT’s efforts to create an acceptable BES definition directly linked to an
exception process. We do have a concerned about the application of the standards to Elements that change
status due to the Exception process. Any Elements that are determined to be newly included in the BES
should have a 24-month period before the standards will apply as a BES Elements. Conversely, a
determination that removes an Element from the BES should apply as soon as practicable.
Please be aware that the WECC has a task force, the Bulk Electric System Definition Task Force(BESDTF),
which has done some notable work on this task. See WECC BESDTF Proposal 6, Appendix C
(http://www.wecc.biz/Standards/Development/BES/default.aspx).
The BES definition is very complex and the BESDTF has already addressed many of the tough issues that
have yet to be addressed in this process, such as: o Local Distribution Network definition for automatic
exemption o Determination of radial facilities o Demarcation of BES and non-BES Elements o Alternate
dispute resolution process o Assignment of the burden of proof for the exemption process o Technical
approach for the inclusion/exclusion determination
Thank you for consideration of our comments.

Response: The SDT has addressed comments on the BES definition under the Consideration of Comments form for the BES definition posting.

END OF REPORT

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Detailed Information to Support an Exception Request

Entities that have Element(s) designated as excluded, under the BES definition and designations, do not
have to seek exception for those Elements under the Exception Procedure.
General Instructions:
A one-line breaker diagram identifying the facility for which the exception is requested must be supplied
with every application. The diagram(s) supplied should also show the Protection Systems at the interface
points associated with the Elements for which the exception is being requested.
Entities are required to supply the data and studies needed to support their submittal. Studies should:
•
•
•

Be based on an Interconnection-wide base case that is suitably complete and detailed to reflect
the facility’s electrical characteristics and system topology
Clearly document all assumptions used
Address key performance measures of BES reliability through steady-state power flow, and
transient stability analysis as necessary to support the entity’s application, consistent with the
methodologies described in the Transmission Planning (TPL) standard and commensurate with
the scope of the request

Supporting statements for your position from other entities are encouraged.
List any attached supporting documents:

1

Detailed Information to Support an Exception Request
For Transmission Facilities:
1. Is there generation connected to the facility?
Yes

No

If yes, what are the individual gross nameplate values of each unit?

Description/Comments:

2. How does the facility impact permanent Flowgates in the Eastern Interconnection, major transfer
paths within the Western Interconnection, or a comparable monitored facility in the ERCOT
Interconnection or the Quebec Interconnection?
Please list the Flowgates or paths considered in your analysis along with any studies or assessments
that illustrate the degree of impact:

3. Is the facility included in an Interconnection Reliability Operating Limit (IROL) in the Eastern
Interconnection, ERCOT Interconnection, or Quebec Interconnection or a major transfer path rating in
the Western Interconnection?
Yes

No

Please provide the appropriate list for your operating area:

4. How does an outage of the facility impact the over-all reliability of the BES? Please provide study
results that demonstrate the most severe system impact of the outage of the facility and the rationale
for your response:

2

Detailed Information to Support an Exception Request

5. Is the facility used for off-site power supply to a nuclear power plant as designated in a mutually
agreed upon Nuclear Plant Interface Requirement (NPIR)?
Yes

No

Description/Comments:

6. Is the facility part of a Cranking Path associated with a Blackstart Resource?
Yes

No

Description/Comments:

7. Does power flow through this facility into the BES?
Yes
If yes,

No
under 10% of the calendar year
25% - 50% of the calendar year

10% - 25% of the calendar year
More than 50% of the calendar year

If yes, then using metered or SCADA data for the most recent consecutive two calendar year period,
what is the minimum and maximum magnitude of the power flow out of the facility and describe the
conditions when this could occur?

3

Detailed Information to Support an Exception Request

For Generation Facilities:
1. What is the MW value of the host Balancing Authority’s most severe single Contingency and what is
the generator’s, or generator facility’s, percent of this value?
Please provide the values and a reference to supporting documents:

2. Is the generator or generator facility used to provide Ancillary Services?
Yes

No

Describe what Ancillary Services the generator or generator facility is supplying:

3. Is the generator designated as a must run unit?
Yes

No

Please provide the appropriate reference for your operating area:

4. How does an outage of the generator impact the over-all reliability of the BES? Please provide study
results that demonstrate the most severe system impact of the outage of the generator and the
rationale for your response:

5. Does the generator use the BES to deliver its actual or scheduled output, or a portion of its actual or
scheduled output, to Load?
Yes

No

Description/Comments:

4

Comment Form for 2nd Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions

Please DO NOT use this form to submit comments on the second draft of the Project 201017: Definition of the Bulk Electric System (BES) Exception Criteria. Use the electronic
comment form only to submit comments on the second draft Exception Criteria. Comments
must be submitted by October 10, 2011.
If you have questions please contact Ed Dobrowolski at ed.dobrowolski@nerc.net or by
telephone at 609-947-3673.

Background Information
Definition of the BES (Project 2010-17)
Technical Principles for Demonstrating BES Exceptions
In parallel with the definition project, another stakeholder team outside the standards
development process has been set up to develop a change to the NERC Rules of Procedure
(RoP) to allow for entities to apply for excluding Elements from the BES that might
otherwise be included according to the proposed definition and designations. This same
process would be used by Registered Entities to justify including Elements in the BES that
might otherwise be excluded according to the proposed definition and designations. The
RoP team will develop the process for seeking an exception from the definition and
designations, but the Definition of the BES Standards Drafting Team (DBESSDT), through
the standards development process, has developed the criteria necessary for applying for an
exception.
The exception process has been set up as a checklist of items that an entity requesting an
exception should supply to the Regional Entity as the first step in the process described in
the Rules of Procedure. The same checklist will be utilized for exceptions dealing with
inclusions or exclusions. The intent of the SDT is to standardize the types of information
that must be supplied when seeking an exception to the extent possible. This will allow for
the Regional Entities to process the requests based on standardized evidence and for the
ERO to make the eventual decision on the request based on this standardized evidence. This
is a significant departure from the first posting on this topic. Based on industry response
from that posting and further analysis the SDT has abandoned the initial exclusion criteria
and developed this new methodology that it believes will provide more clarity and continuity
to the process. The initial proposal was dependent on a comparison of an entity’s
characteristics to a defined value and/or limit. However, it has become apparent that it is
not feasible to establish continent-wide values and/or limits due to differences in operational
characteristics. The new process requires an entity to clarify the characteristics of the
facilities in question and to document the operational performance as appropriate through
submittal of the Detailed Information to Support an Exception Request along with any other
supporting documentation for the exception being sought. The appropriate Regional Entity
will review the submittal to validate information, make a recommendation of whether or not
to support the exclusion or inclusion, and then file the request and recommendation with
the ERO as established in the Rules of Procedure as presently being drafted and posted for
comment. An ERO panel as described in the Rules of Procedure presently being drafted and
posted for comment will then make the decision on the exception. At this point, the
engineering judgment of the ERO panel will be utilized. Using the request document to
dictate the type of supporting material that needs to be supplied plus having a common
panel perform the evaluations will result in an open, transparent, and consistent process.
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404.446.2560 | www.nerc.com

Comment Form for 2nd Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions
The SDT is seeking industry feedback on the approach being presented. Comments
received from this posting will help to determine the final criteria that the industry will be
required to adhere to. Therefore, industry feedback is vital to the development process.
It should be noted that the actual application process is described in the Rules of Procedure
document that will be posted separately from the exception criteria document.

Page 2 of 4

Comment Form for 2nd Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions
You do not have to answer all questions. Enter all comments in simple text
format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Page one of the ‘Detailed Information to Support an Exception Request’ contains general
instructions. Do you agree with the instructions presented or is there information that
you believe needs to be on page one that is missing? Please be as specific as possible
with your comments.
Yes:
No:
Comments:
2. Pages two and three of the Detailed Information to Support an Exception Request
contain a checklist of items that deal with transmission facilities. Do you agree with the
information being requested or is there information that you believe needs to be on page
two or three that is missing? Please be as specific as possible with your comments.
Yes:
No:
Comments:
3. Page four of the ‘Detailed Information to Support an Exception Request’ contains a
checklist of items that deal with generation facilities. Do you agree with the information
being requested or is there information that you believe needs to be on page four that is
missing? Please be as specific as possible with your comments.
Yes:
No:
Comments:
4. Do you have concerns about an entity’s ability to obtain the data they would need to file
the ‘Detailed Information to Support an Exception Request’? If so, please be specific
with your concerns so that the SDT can fully understand the problem.
Yes:
No:
Comments:

Page 3 of 4

Comment Form for 2nd Draft of Project 2010-17: Definition of BES (BES)
Technical Principles for Demonstrating BES Exceptions
5. Are there other specific characteristics that you feel would be important for presenting a
case and which are generic enough that they belong in the request? If so, please
identify them here and provide suggested language that could be added to the
document.
Yes:
No:
Comments:
6. Are you aware of any conflicts between the proposed approach and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement, or
jurisdictional issue? If so, please identify them here and provide suggested language
changes that may clarify the issue.
Yes:
No:
Comments:
7. Are there any other concerns with the proposed approach for demonstrating BES
Exceptions that haven’t been covered in previous questions and comments (bearing in
mind that the definition itself and the proposed Rules of Procedure changes are posted
separately for comments)? Please be as specific as possible with your comments.
Yes:
No:
Comments:

Page 4 of 4

Standards Announcement

Project 2010-17 BES Definition
Two Ballot Pool Windows Open August 26 – September 26, 2011
Two Formal Comment Periods Open August 26 – October 10, 2011
Two Ballot Windows Open September 30 – October 10, 2011
Available tomorrow at: https://standards.nerc.net/BallotPool.aspx
The Definition of Bulk Electric System Standard Drafting Team (DBES SDT) has posted a second draft of the
Definition of Bulk Electric System (BES) and associated implementation plan for a formal 45-day comment
period, through 8 p.m. Eastern on Monday, October 10, 2011.
The Definition of Bulk Electric System Standard Drafting Team (DBES SDT) has also posted a draft
application form titled Detailed Information to Support an Exception Request referenced in the Rules of
Procedure Exception Process for a formal 45-day comment period, through 8 p.m. Eastern on Monday,
October 10, 2011. (Note that the information contained in this draft form includes revisions made to the
Technical Principles for Supporting BES Exceptions that was posted for comment in May and June 2011.)
A separate team is working with NERC to draft a new Appendix 5C to NERC’s Rules of Procedure to address
the process for requesting BES exceptions. This team will be posting the Rules of Procedure changes for
stakeholder comment in September. The comment period for the Rules of Procedure changes will overlap the
comment period for the definition and application form, to provide an opportunity for stakeholders to review all
three documents to understand how they will work together.
Clean and redline versions of the definition and associated implementation plan, along with a technical
justification for the Local Network exclusion and a clean version of the application form titled Detailed
Information to Support an Exception Request have been posted on the project page at:
http://www.nerc.com/filez/standards/Project2010-17_BES.html. The format of the application form titled
Detailed Information to Support an Exception Request has changed substantially since the first posting, making
a redline impractical, so none has been provided.
The Standards Committee and NERC Board of Trustees have recommended that the drafting team address
issues such as generation thresholds in a second phase of this project. This approach will ensure that the
drafting team has sufficient time to adequately consider and develop a sound technical basis for an approach,
and will allow the drafting team to meet the regulatory deadline in FERC Orders 743 and 743a (filing by
January 25, 2012). The drafting team has posted a draft Supplemental Standards Authorization Request (SAR)
for information purposes only; the SAR will be posted for comment at a future time.

Ballot Pools Forming
During the first 30 days of the comment period, two separate ballot pools will be formed: one for balloting the
Definition of Bulk Electric System, and a second for balloting the application form titled Detailed Information
to Support an Exception Request. The ballot pool windows will be open from Friday, August 26 through 8
a.m. Eastern on Monday, September 26, 2011.
During the final 10 days of the comment period, two separate initial ballots will be conducted, one for the
Definition of the Bulk Electric System, and a second for the application form titled Detailed Information to
Support an Exception Request. The ballot windows will begin on Friday, September 30th and end at 8 p.m.
Eastern on Monday, October 10, 2011.
Instructions for Joining Ballot Pools
Registered Ballot Body members must join each of the ballot pools to be eligible to vote in the upcoming
ballots at the following page: https://standards.nerc.net/BallotPool.aspx
During the pre-ballot window, members of each ballot pool may communicate with one another by using their
“ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from using the ballot
pool list servers.) The list servers for this project are:
•

Definition of BES ballot:
bp-2010-17_BES_Def_in@nerc.com

•

Detailed Information to Support an Exception Request form:
bp-2010-17_TechInfo_BES_in@nerc.com

Instructions for Submitting Comments
Please use this electronic comment form to submit comments on the Definition of Bulk Electric System. Please
use this separate electronic comment form to submit comments on the draft form application form titled
Detailed Information to Support an Exception Request.
If you experience any difficulties in using either of these electronic forms, please contact Monica Benson at
monica.benson@nerc.net. An off-line, unofficial copy of each comment form is posted on the project page:
Background
On November 18, 2010 FERC issued Order 743 (amended by Order 743A) and directed NERC to revise the
definition of Bulk Electric System so that the definition encompasses all Elements and Facilities necessary for
the reliable operation and planning of the interconnected bulk power system. Additional specificity will reduce
ambiguity and establish consistency across all Regions in distinguishing between BES and non-BES Elements
and Facilities.
In addition, NERC was directed to develop a process for identifying any Elements or Facilities that should be
excluded from the BES. NERC is working to address these directives with two activities – the definition of
Bulk Electric System (BES) is being revised through the standard development process and a BES Definition
Exception Process is being developed as a proposed modification to the Rules of Procedure. The work of the
BES Definition Exception Process has been publicly posted at:
http://www.nerc.com/filez/standards/Rules_of_Procedure-RF.html. The Rules of Procedure team expects to
post the next draft of its proposed addition to the Rules of Procedure (Appendix 5C – BES Exception Process)
in September.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement

Project 2010-17 BES Definition
Two Ballot Pool Windows Open August 26 – September 26, 2011
Two Formal Comment Periods Open August 26 – October 10, 2011
Two Ballot Windows Open September 30 – October 10, 2011
Available tomorrow at: https://standards.nerc.net/BallotPool.aspx
The Definition of Bulk Electric System Standard Drafting Team (DBES SDT) has posted a second draft of the
Definition of Bulk Electric System (BES) and associated implementation plan for a formal 45-day comment
period, through 8 p.m. Eastern on Monday, October 10, 2011.
The Definition of Bulk Electric System Standard Drafting Team (DBES SDT) has also posted a draft
application form titled Detailed Information to Support an Exception Request referenced in the Rules of
Procedure Exception Process for a formal 45-day comment period, through 8 p.m. Eastern on Monday,
October 10, 2011. (Note that the information contained in this draft form includes revisions made to the
Technical Principles for Supporting BES Exceptions that was posted for comment in May and June 2011.)
A separate team is working with NERC to draft a new Appendix 5C to NERC’s Rules of Procedure to address
the process for requesting BES exceptions. This team will be posting the Rules of Procedure changes for
stakeholder comment in September. The comment period for the Rules of Procedure changes will overlap the
comment period for the definition and application form, to provide an opportunity for stakeholders to review all
three documents to understand how they will work together.
Clean and redline versions of the definition and associated implementation plan, along with a technical
justification for the Local Network exclusion and a clean version of the application form titled Detailed
Information to Support an Exception Request have been posted on the project page at:
http://www.nerc.com/filez/standards/Project2010-17_BES.html. The format of the application form titled
Detailed Information to Support an Exception Request has changed substantially since the first posting, making
a redline impractical, so none has been provided.
The Standards Committee and NERC Board of Trustees have recommended that the drafting team address
issues such as generation thresholds in a second phase of this project. This approach will ensure that the
drafting team has sufficient time to adequately consider and develop a sound technical basis for an approach,
and will allow the drafting team to meet the regulatory deadline in FERC Orders 743 and 743a (filing by
January 25, 2012). The drafting team has posted a draft Supplemental Standards Authorization Request (SAR)
for information purposes only; the SAR will be posted for comment at a future time.

Ballot Pools Forming
During the first 30 days of the comment period, two separate ballot pools will be formed: one for balloting the
Definition of Bulk Electric System, and a second for balloting the application form titled Detailed Information
to Support an Exception Request. The ballot pool windows will be open from Friday, August 26 through 8
a.m. Eastern on Monday, September 26, 2011.
During the final 10 days of the comment period, two separate initial ballots will be conducted, one for the
Definition of the Bulk Electric System, and a second for the application form titled Detailed Information to
Support an Exception Request. The ballot windows will begin on Friday, September 30th and end at 8 p.m.
Eastern on Monday, October 10, 2011.
Instructions for Joining Ballot Pools
Registered Ballot Body members must join each of the ballot pools to be eligible to vote in the upcoming
ballots at the following page: https://standards.nerc.net/BallotPool.aspx
During the pre-ballot window, members of each ballot pool may communicate with one another by using their
“ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from using the ballot
pool list servers.) The list servers for this project are:
•

Definition of BES ballot:
bp-2010-17_BES_Def_in@nerc.com

•

Detailed Information to Support an Exception Request form:
bp-2010-17_TechInfo_BES_in@nerc.com

Instructions for Submitting Comments
Please use this electronic comment form to submit comments on the Definition of Bulk Electric System. Please
use this separate electronic comment form to submit comments on the draft form application form titled
Detailed Information to Support an Exception Request.
If you experience any difficulties in using either of these electronic forms, please contact Monica Benson at
monica.benson@nerc.net. An off-line, unofficial copy of each comment form is posted on the project page:
Background
On November 18, 2010 FERC issued Order 743 (amended by Order 743A) and directed NERC to revise the
definition of Bulk Electric System so that the definition encompasses all Elements and Facilities necessary for
the reliable operation and planning of the interconnected bulk power system. Additional specificity will reduce
ambiguity and establish consistency across all Regions in distinguishing between BES and non-BES Elements
and Facilities.
In addition, NERC was directed to develop a process for identifying any Elements or Facilities that should be
excluded from the BES. NERC is working to address these directives with two activities – the definition of
Bulk Electric System (BES) is being revised through the standard development process and a BES Definition
Exception Process is being developed as a proposed modification to the Rules of Procedure. The work of the
BES Definition Exception Process has been publicly posted at:
http://www.nerc.com/filez/standards/Rules_of_Procedure-RF.html. The Rules of Procedure team expects to
post the next draft of its proposed addition to the Rules of Procedure (Appendix 5C – BES Exception Process)
in September.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement
Project 2010-17 Definition of Bulk Electric System
Initial Ballot Results
Now available
Ballot Results for Definition of Bulk Electric System

The two ballots windows for Project 2010-17 Definition of Bulk Electric System (BES): the first for the
definition of Bulk Electric System and associated implementation plan, and the second for the draft
application form titled Detailed Information to Support an Exception Request referenced in the Rules of
Procedure Exception Process closed at 8 p.m. Eastern on Monday, October 10, 2011.
Voting statistics for each ballot are listed below, and the Ballot Results Web page provides a link to the
detailed results.
BES Definition

Technical Criteria to Support a BES Exception
Request

Quorum: 92.97%

Quorum: 89.53%

Approval: 71.68%

Approval: 64.03%

Next Steps

The drafting team will consider all comments received, and decide whether to make additional
revisions to the definition of Bulk Electric System, the associated implementation plan, and the
application form titled Detailed Information to Support an Exception Request referenced in the Rules of
Procedure Exception Process. The drafting team is working to meet the regulatory deadline
established in FERC Orders 743 and 743A (filing by January 25, 2012).
The Standards Committee and NERC Board of Trustees have recommended that the drafting team
address issues such as generation thresholds in a second phase of this project. This approach will
ensure that the drafting team has sufficient time to adequately consider and develop a sound technical
basis for an approach, and will allow the drafting team to meet the regulatory deadline in FERC Orders
743 and 743A (filing by January 25, 2012). The drafting team has posted a draft Supplemental
Standards Authorization Request (SAR) for information purposes only; the SAR will be posted for
comment at a future time. Additionally, the drafting team has posted a Fact Sheet, which provides an
up to date review of the project scope, project plan - phased approach, current status and upcoming
events, on the project webpage.

Project Background

On November 18, 2010 FERC issued Order 743 (amended by Order 743A) and directed NERC to revise
the definition of Bulk Electric System so that the definition encompasses all Elements and Facilities
necessary for the reliable operation and planning of the interconnected bulk power system. Additional
specificity will reduce ambiguity and establish consistency across all Regions in distinguishing between
BES and non-BES Elements and Facilities.
In addition, NERC was directed to develop a process for identifying any Elements or Facilities that
should be excluded from the BES. NERC is working to address these directives with two activities – the
definition of Bulk Electric System is being revised through the standard development process and a BES
Definition Exception Process is being developed as proposed modifications to the Rules of Procedure.
The proposed modifications have been posted for a comment period through October 27, 2011. The
work of the BES Definition Exception Process has been publicly posted at:
http://www.nerc.com/filez/standards/Rules_of_Procedure-RF.html.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. For more information or assistance,
please contact Monica Benson at monica.benson@nerc.net.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Initial Ballot Results Project 2010-17

2

NERC Standards

Newsroom  •  Site Map  •  Contact NERC

Advanced Search

User Name

Ballot Results

Ballot Name: Project 2010-17 Technical Information to Support BES Exception_in

Password

Ballot Period: 9/30/2011 - 10/10/2011
Ballot Type: Initial

Log in

Total # Votes: 385

Register

Total Ballot Pool: 430
Quorum: 89.53 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
64.03 %
Vote:
Ballot Results: The SDT will review comments to determine the next process step.

 Home Page
Summary of Ballot Results

Affirmative
Segment

1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight

99
11
124
34
82
50
1
11
11
7
430

#
Votes

1
1
1
1
1
1
0
1
0.9
0.6
8.5

#
Votes

Fraction

50
3
72
23
34
31
0
8
5
5
231

Negative
Fraction

0.588
0.3
0.72
0.793
0.567
0.674
0
0.8
0.5
0.5
5.442

Abstain
No
# Votes Vote

35
7
28
6
26
15
0
2
4
1
124

0.412
0.7
0.28
0.207
0.433
0.326
0
0.2
0.4
0.1
3.058

9
1
6
2
8
2
0
0
2
0
30

5
0
18
3
14
2
1
1
0
1
45

Individual Ballot Pool Results

Segment

1
1
1
1
1
1
1
1

Organization

Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Balancing Authority of Northern California
NCR11118
Baltimore Gas & Electric Company

Member

Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
James Armke
Kevin Smith
Gregory S Miller

https://standards.nerc.net/BallotResults.aspx?BallotGUID=5d32eb2d-cf0a-4c84-a5f6-88a6b007a56f[10/12/2011 9:34:18 AM]

Ballot

Comments

Negative
Affirmative
Negative
Negative
Negative
Abstain

View
View
View
View
View

Negative

View

Affirmative

View

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Power Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lakeland Electric
Lee County Electric Cooperative
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
Memphis Light, Gas and Water Division
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
N.W. Electric Power Cooperative, Inc.
National Grid
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
PECO Energy
Platte River Power Authority

Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
Dale Bodden
Michael B Bax
Kevin L Howes

Abstain
Affirmative
Affirmative
Negative
Abstain
Abstain
Negative
Negative

Chang G Choi

Affirmative

Danny McDaniel
Paul Morland
Christopher L de Graffenried
Stuart Sloan
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch

Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

Bob Solomon

Affirmative

Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza

Negative
Negative
Affirmative
Affirmative

Michael Moltane

Affirmative

Ted Hobson
Walter Kenyon
Michael Gammon
Larry E Watt
John W Delucca
Robert Ganley
Ly M Le
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Allan Long

Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

View

View
View
View

View

View

View
View

View
View

Negative
Negative
Negative
Negative
Abstain

View

Negative

View

Terry Harbour
Richard Burt
Mark Ramsey
Saurabh Saksena

Affirmative
Negative

View

Randy MacDonald

Negative

Ernest Hahn

Arnold J. Schuff
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Ronald Schloendorn
John C. Collins

https://standards.nerc.net/BallotResults.aspx?BallotGUID=5d32eb2d-cf0a-4c84-a5f6-88a6b007a56f[10/12/2011 9:34:18 AM]

Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative

View
View

View

View
View

View

NERC Standards
1
1
1
1
1

1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2

Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
South Texas Electric Cooperative
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Transmission Agency of Northern California
Tri-State G & T Association, Inc.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
Alberta Electric System Operator

2

BC Hydro

2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
BC Hydro and Power Authority
Benton Rural Electric Association
Big Bend Electric Cooperative, Inc.
Blachly-Lane Electric Co-op
Blue Ridge Electric
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Electric Power Cooperative
Central Hudson Gas & Electric Corp.
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Cheney
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of McMinnville
City of Redding
City of Ukiah

1

3
3
3
3
3
3
3
3
3
3
3
3
3
3

John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown

Affirmative

Dale Dunckel

Affirmative

Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Richard McLeon
James Jones
Noman Lee Williams
Beth Young
Larry Akens
Bryan Griess
Tracy Sliman
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Michelle Denike
Mark B Thompson
Venkataramakrishnan
Vinnakota
Richard K Vine
Charles B Manning
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Pat G. Harrington
Clint Gerkensmeyer
Benjamin Friederichs
Bud Tracy
James L Layton
Rebecca Berdahl

Affirmative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Abstain
Negative

Negative

View

Dave Markham

Affirmative

View

Ralph J Schulte
Thomas C Duffy
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Joe Noland
Lynne Mila
Linda Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
John C Dietz
Bill Hughes
Colin Murphey

Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=5d32eb2d-cf0a-4c84-a5f6-88a6b007a56f[10/12/2011 9:34:18 AM]

Abstain
Affirmative
Affirmative

View

View
View
View
View
View

View
View

View

View

Abstain
Negative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative

View
View
View
View
View
View

View

Affirmative
Negative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative

Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative

View

View
View

View
View
View

View
View

NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

Clatskanie People's Utility District
Clay Electric Cooperative
Clearwater Power Co.
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Dominion Resources Services
Douglas Electric Cooperative
Duke Energy Carolina
Fall River Rural Electric Cooperative
Fayetteville Public Works Commission
FirstEnergy Energy Delivery
Flathead Electric Cooperative
Florida Municipal Power Agency
Florida Power Corporation
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Idaho Falls Power
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Kootenai Electric Cooperative
La Plata Electric Association
Lakeview Light & Power
Lane Electric Cooperative, Inc.
Lincoln Electric Cooperative, Inc.
Lincoln Electric System
Lost River Electric Cooperative
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
Manitowoc Public Utilities
MidAmerican Energy Co.
Mission Valley Power
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
North Carolina Electric Membership Corp.
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Northern Lights Inc.
Northern Wasco County People's Utility
District (PUD)
NW Electric Power Cooperative, Inc.
Okanogan County Electric Cooperative, Inc.
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission

Brian Fawcett
Howard M. Mott Jr.
Dave Hagen
Michelle A Corley
Lisa Cleary
Bruce Krawczyk
Peter T Yost
CJ Ingersoll
Richard Blumenstock
Roman Gillen
Roger Meader
Russell A Noble
Jose Escamilla
Michael R. Mayer
Michael F. Gildea
Dave Sabala
Henry Ernst-Jr
Bryan Case
Allen R Wallace
Stephan Kern
John M Goroski
Joe McKinney
Lee Schuster
William N. Phinney
Wesley W Gray
Sam Kokkinen
Shane Sweet
William Bush
David Kiguel
Richard Malloy
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Dave Kahly
Ronald Meier
Robert Truesdell
Rick Crinklaw
Michael Henry
Jason Fortik
Richard Reynolds
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas E Reed
Thomas C. Mielnik
Kerry Wiedrich
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
Doug White
Skyler Wiegmann
William SeDoris
Jon Shelby

Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Abstain
Negative
Abstain
Affirmative

View

View
View
View
View
View
View
View
View
View
View
View

View
View

View
View
View
View
View

View
View
View
View
View

Affirmative
Affirmative

View

Negative
Affirmative

View

Negative
Affirmative
Affirmative

View

Paul Titus
David McDowell
Ray Ellis
Blaine R. Dinwiddie
David Burke
ned ratterman
Ballard K Mutters

https://standards.nerc.net/BallotResults.aspx?BallotGUID=5d32eb2d-cf0a-4c84-a5f6-88a6b007a56f[10/12/2011 9:34:18 AM]

NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4

Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Clallam County
Public Utility District No. 1 of Franklin County
Public Utility District No. 2 of Grant County
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salem Electric
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Southern California Edison Co.
Springfield Utility Board
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Umatilla Electric Cooperative
Vigilante Electric Cooperative
West Oregon Electric Cooperative, Inc.
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
American Public Power Association
Arkansas Electric Cooperative Corporation
Central Lincoln PUD
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
National Rural Electric Cooperative
Association
North Carolina Eastern Municipal Power
Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Pacific Northwest Generating Cooperative
Public Power Council
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Transmission Access Policy Study Group

Thomas T Lyons
John H Hagen
John Apperson
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
David Proebstel
Linda Esparza
Greg Lange
Eddy Reece
Thomas M Haire
James Leigh-Kendall
Anthony Schacher
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
David Schiada
Jeff Nelson
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Steve Eldrige
Dave Alberi
Marc Farmer
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Ronnie Frizzell
Shamus J Gamache
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Bob C. Thomas
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke
Barry R. Lawson

Affirmative
Negative
Negative
Affirmative
Affirmative

View
View

Affirmative
Affirmative

View

Affirmative
Negative
Affirmative

View
View

Negative
Affirmative
Negative
Affirmative
Negative
Abstain

View
View

Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative

View
View
View

Affirmative

View

Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative

View

View
View

View
View
View
View
View

View
View

Abstain

Cecil Rhodes

Affirmative

Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Aleka K Scott
Nancy Baker
Henry E. LuBean

Affirmative
Affirmative
Negative
Affirmative

John D Martinsen

Affirmative

View

Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
William Gallagher

Negative
Negative
Affirmative
Affirmative
Affirmative

View
View

https://standards.nerc.net/BallotResults.aspx?BallotGUID=5d32eb2d-cf0a-4c84-a5f6-88a6b007a56f[10/12/2011 9:34:18 AM]

View
View
View

Affirmative

NERC Standards
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

Western Montana Electric G&T
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Grand Island
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Covanta Energy
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
East Kentucky Power Coop.
Electric Power Supply Association
Exelon Nuclear
ExxonMobil Research and Engineering
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Michigan Public Power Agency
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
Proven Compliance Solutions

William Drummond
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Brad Haralson
Clement Ma

Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Abstain

View

Mike D Kukla
Francis J. Halpin
Chifong Thomas
Daniel Mason
Jeanie Doty
Jeff Mead
Paul Cummings

Negative
Abstain
Abstain
Negative
Abstain
Affirmative

Max Emrick

Affirmative

Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Samuel Cabassa
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Stephen Ricker
John R Cashin
Michael Korchynsky
Martin Kaufman
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Alan Beckham
John J Babik
Mike Blough
James M Howard
Dennis Florom
Kenneth Silver
Tom Foreman
S N Fernando

Abstain
Negative
Negative
Affirmative
Negative

David Gordon
Steven Grego
Gary Carlson
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Richard Kinas
Stacie Hebert
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Tim Hattaway
Annette M Bannon
Wayne Lewis
Mitchell E Needham

https://standards.nerc.net/BallotResults.aspx?BallotGUID=5d32eb2d-cf0a-4c84-a5f6-88a6b007a56f[10/12/2011 9:34:18 AM]

Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative

Affirmative
Affirmative
Affirmative
Affirmative
Negative

View

View
View

View
View
View

View
View

View

View

View

Abstain
Negative
Affirmative
Negative
Abstain
Abstain
Negative
Affirmative

View
View
View

Negative

View

Negative
Negative

View
View

Affirmative
Affirmative
Negative

View

Affirmative
Affirmative

View
View

NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6

PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
North Carolina Municipal Power Agency #1
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Tacoma Public Utilities
Tampa Electric Co.
Tenaska Power Services Co.
Tennessee Valley Authority

Mikhail Falkovich
Steven Grega
Tom Flynn
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daniel Prowse
Dennis Kimm
William Palazzo
Matthew Schull
Joseph O'Brien
Alan Johnson
David Ried
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Claire Warshaw
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Michael C Hill
Benjamin F Smith II
John D Varnell
Marjorie S. Parsons

https://standards.nerc.net/BallotResults.aspx?BallotGUID=5d32eb2d-cf0a-4c84-a5f6-88a6b007a56f[10/12/2011 9:34:18 AM]

Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative

View
View
View
View
View
View

View

View
View

View
View
View
View

View
View
View

View
View

View
View

View
View
View
View

View

NERC Standards
6
7
8
8
8
8
8
8
8
8
8
8
8
9
9
9
9
9
9
9
9
9
9
9
10
10
10
10
10
10
10

Xcel Energy, Inc.
Siemens Energy, Inc.

INTELLIBIND
JDRJC Associates
Montana Consumer Counsel
Pacific Northwest Generating Cooperative
Transmission Strategies, LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
Alabama Public Service Commission
California Energy Commission
Central Lincoln PUD
Commonwealth of Massachusetts Department
of Public Utilities
Michigan Public Service Commission
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Oregon Public Utility Commission
Pennsylvania Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

David F. Lemmons
Frank R. McElvain
James A Maenner
Merle Ashton
Roger C Zaklukiewicz
Edward C Stein
Kevin Conway
Jim Cyrulewski
Larry Nordell
Margaret Ryan
Bernie M Pasternack
Brian Evans-Mongeon
Terry Volkmann
John Free
William M Chamberlain
Bruce Lovelin

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Donald Nelson

Affirmative

Diane J Barney

Negative

Thomas Dvorsky
Jerome Murray
darren gill
Philip Riley
Ric Campbell
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Stacy Dochoda
Donald G Jones
Steven L. Rueckert

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Name (50 Responses)
Organization (50 Responses)
Lead Contact (22 Responses)
Contact Organization (22 Responses)
Question 1 (65 Responses)
Question 1 Comments (72 Responses)
Question 2 (65 Responses)
Question 2 Comments (72 Responses)
Question 3 (61 Responses)
Question 3 Comments (72 Responses)
Question 4 (65 Responses)
Question 4 Comments (72 Responses)
Question 5 (61 Responses)
Question 5 Comments (72 Responses)
Question 6 (61 Responses)
Question 6 Comments (72 Responses)
Question 7 (63 Responses)
Question 7 Comments (72 Responses)

Individual
John Bee
Exelon
Yes
Yes
Yes
Yes
This may be a burden on small entities and generators because they would need to use contractors to
run studies in order to obtain the required data. Smaller entities and generators may not have the
expertise, the software or the necessary personnel to perform studies.
No
No
No
Group
Guy Zito
Northeast Power Coordinating Council
No
How an exception application will be assessed by the RE and NERC is not addressed in the document.
Stakeholders need to know how the exception application will be evaluated and processed. Suggest
that the SDT develop a reference or a guidance document as part of the RoP that will provide
guidance to Registered Entities, Regional Entities and the ERO on how an exception application will be
processed. Of particular concern is the lack of clarity and specificity with respect to what analyses and
study results are required under the third bullet on page 1 and under question 4 on both pages 2 and
4. This lack of clarity and specificity will lead to inconsistent application of the Technical Principles by
both Registered Entities and Regional Entities. We recommend the following: the impact and
performance analyses required by the 3rd bullet on page 1 and by #4 on pages 2 and 4 should be
stipulated to be all analyses, scenarios, and contingencies required under NERC Standard TPL-002-1
with the “exception element” removed from the base system model. Entities shall report on all key

performance measures of BES reliability specified in the TPL-002-1 attributable to the removed
“exception element”. On page 1 under General Instructions, it is stated that: “A one-line breaker
diagram identifying the facility for which the exception is requested must be supplied with every
application. The diagram(s) supplied should also show the Protection Systems at the interface points
associated with the Elements for which the exception is being requested.” What is meant by interface
points?
No
For question 2 on page 2 For Transmission Facilities: • What standards will define the “impact”? •
What is a material impact and a non-material impact? • What kinds and types of impacts are
acceptable/unacceptable? • How are impacts determined? Question 6 on page 3 reads “Is the facility
part of a Cranking Path associated with a Blackstart Resource?”, suggest removing the reference to
“Cranking Path” because the Drafting Team does not require that the BES be contiguous, and black
start resource Cranking Paths were deleted from Inclusion I3. Question 7 on page 3 asks, “Does
power flow through this facility into the BES?” This can only apply to a Local Network with two or
more connections to the BES. No power should normally flow through a Local Network (or Radial
system) to another portion of the BES. There may be occasional, brief reverse power flows may be
acceptable during short periods under abnormal operating conditions. Question 7 also requests “data
for the most recent consecutive two calendar year period.” Why is two years worth of data necessary?
One year of data would be sufficient. From Question 7, “what is the minimum and maximum
magnitude of the power flow out of the facility …” What is intended by the use of magnitude? Suggest
that the Drafting Team adopt the FERC Seven Factor test for question 7. Suggest deleting the “% of
the calendar year” check boxes in favor of a statement either that power does not flow through the
Local Network, or alternatively, a blank space for reporting the net peak MWs and MWHs transferred
annually through the facility, and the percentage of these transferred amounts to the peak and annual
MWH demands served by the Local Network. Suggest requesting only one year (8,760 hours) of data
covering four seasons, including Summer and Winter capability periods.
No
This Application generally applies to traditionally fueled generating facilities. Application form and
justifications would be required for non-traditional resources such as solar and wind? Question 2 on
page 4 asks, “Is the generator or generator facility used to provide Ancillary Services?” If some of
these Generator check list items are market-related and not reliability-related, they should not be
present. If the Ancillary Services are reliability-related, please explain their relation to BES reliability.
Suggest inserting the word “reliability” before the words “must run” in question 3. Question 5 on page
4 asks, “Does the generator use the BES to deliver its actual or scheduled output, or a portion of its
actual or scheduled output, to Load?” This could mean the generator may serve local loads through
non-BES facilities. In order to serve these local loads the generator would need to be connected to a
Radial system, a Local Network or to local distribution facilities. Is this what is intended? Were there
any other possibilities envisioned by the BES SDT?
No
According to the Applicability section, the TPL Reliability Standards are only applicable to the Planning
Coordinator (PC) and the Transmission Planner (TP). Was it the BES SDT’s assumption that Applicants
would have the PC or TP run studies for them, or that all Applicants would gain access to those
models and run the models themselves? (Ref. TPL-002-1b, Applicability: Planning Authority, and
Transmission Planner.)
Yes
There is no guidance provided as to how the information asked for in this form will be evaluated, and
what the decision making process will entail. As such, a reference document should be developed and
provide some guidance how to evaluate applications. Suggest that the BES SDT adopt the FERC
Seven Factor test.
No
No
Group
Charles Long

Entergy Services, Inc.
Yes
Yes
Yes
No
No
No
No
Individual
Eric Lee Christensen
Snohomish County PUD
Yes
SNPD agrees generally that the General Instructions set forth the basic information that would be
necessary to support an Exception Request. SNPD is concerned, however, that the statement
“diagram(s) supplied should also show the Protection Systems at the interface points associated with
the Elements for which the exception is being requested” may be subject to differing interpretations.
SNPD envisions that at least four different kinds of documents would be responsive to the description:
one-line diagrams with breakers and switches (status); identification of relays by their ANSI device
numbers; details of the DC control logic for ANSI devices; and, operational scheme descriptions of the
type used by system operators. Accordingly, we suggest that the language be refined to identify the
specific kinds of diagrams necessary to identify protection systems at the interface with the Elements
for which the Exception is sought, including any required details. SNPD suggests that a generic
example of a completed form be provided to the industry to help ensure that Exception Requests are
supported by consistent and complete information. Such a generic example could be addressed in the
Phase 2 BES efforts.
No
SNPD agrees that the checklist of items on pages two and three lists most of the information that
would be necessary to determine if an Exceptions Request is justified. We suggest three modifications
to the proposed language to ensure consistency with Section 215 of the Federal Power Act, with the
BES Definition, and to provide an entity seeking an Exception with the opportunity to submit all
relevant information: (1) SNPD suggests that a new question should be added concerning the function
of the facility, which would read: “Does the facility function as a local distribution facility rather than a
Transmission facility? If yes, please provide a detailed explanation of your answer.” Section 215(a)(1)
of the FPA makes clear that “facilities used in the local distribution of electric energy” are excluded
from the BES, 16 U.S.C. § 824o(a)(1), and the most recent draft of the BES definition incorporates
the same language. SNPD believes a question to address the function of the Element or system
subject to an Exception Request is necessary to determine whether the Element or system is “used”
in local distribution and thereby to ensure that this statutory limit on the BES is observed in the
Exceptions process. Further, we believe a variety of information may be relevant to determining
whether a particular facility functions as local distribution rather than as part of the BES. For example,
if power is not scheduled across the facility or if capacity on the system is not posted on the relevant
OASIS, it is likely to function as local distribution, not transmission. Similarly, if power enters the
system and is delivered to load within the system rather than moving to load located on another
system, its function is local distribution rather than transmission. SNPD proposes the language above
as an open-ended question so that the entity submitting the Exceptions Request can provide this and
any other information it deems relevant to facility function. (2) SNPD suggests modifying question 6
to “Is the facility part a designated Cranking Path associated with a Blackstart Resource identified in a

Transmission Operator’s restoration plan.” This language reflects the most recent revision of the BES
Definition, which removes the reference to “Cranking Paths,” and also helps distinguish between
generators which have Blackstart capability and those generators that are designated as a Blackstart
Resource in the Transmission Operator’s restoration plan. It is only the latter that are included in the
BES under the current draft of the definition. (3) A general “catch-all” question should be added that
will prompt the entity submitting an Exception Request to submit any information it believes is
relevant to the Exception that is not captured in the other questions. We suggest the following
language: "Is there additional information not covered in the questions above that supports the
Exception Request? If yes, please provide the information and explain why it is relevant to the
Exception Request." While SNPD believes the questions set forth in the draft capture the information
that generally would be necessary to determine whether an Exception Request should be granted, it is
foreseeable that there may be unusual circumstances where the information called for either does not
capture the full picture or where studies other than the specific types called for in the draft form
support the Exception. An entity seeking an Exception should have the opportunity to present any
information it believes is relevant.
Yes
SNPD agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. SNPD suggests three refinements to the questions:
(1) Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter is not. (2) The current draft of the BES
Definition contains Exclusions for radials and for Local Networks. To be consistent with these aspects
of the revised BES definition, SNPD suggests modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: "Is there additional information not covered
in questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request." This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the RE receiving the Exceptions Request. For example, in order to answer
Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, SNPD believes that certain additional
questions are necessary to elicit all information that may be relevant to an Exceptions Request. As
discussed in our answer to Question 4, we are also concerned that it may be necessary to obtain
information that is in the hands of the relevant Balancing Authority, Transmission Provider, or other
entity, and not in the hands of the entity submitting an Exceptions Request, to develop a complete
record upon which a reasoned decision concerning an Exceptions Request can be based.

Yes
As discussed in more detail in our response to Question 2, SNPD believes it is necessary to address
the function of an Element or system that is subject to an Exceptions Request to determine whether it
is a “facilit[y] used in the local distribution of electric energy” and therefore excluded from the BES
under Section 215(a)(1) of the Federal Power Act.
No
As a general matter, SNPD believes the SDT has provided a reasonable check list that will work in
most cases to elicit necessary information from the entity submitting an Exception Request. With the
added language suggested in our answers to the previous questions, we believe the proposed form
will serve its intended purpose of ensuring that decisions regarding Exception Requests are based
upon consistent information and are consistent with the requirements of the Federal Power Act and
the BES Definition as developed by the Standards Drafting Team. SNPD also supports the Standards
Drafting Team’s determination to abandon its initial approach to technical criteria, which would have
required adherence to specific numerical thresholds. SNPD agrees that this approach was not
workable on a nationwide basis, and that the approach embodied in the current draft of the Technical
Principles, which would require specific kinds of information on a generic basis but would leave
engineering judgment about the significance of that information to the relevant RE, is more workable
and provides appropriate deference to the experience and judgment of the REs.
Individual
Greg Rowland
Duke Energy
No
Need to include identification of any System Protection Coordination considerations per PRC-001-1.
Also, we believe that a system map showing the geographical location of the facility(s) should be
supplied with the request.
No
Modify wording on #3 as follows: “Please provide the appropriate list for the operating area where the
facility is located.” Modify the wording on #6 as follows: “Is the facility part of a Cranking Path
identified in an entity’s restoration plan for a Blackstart Resource as required by EOP-005-2?”
No
Modify wording on #3 as follows: “Please provide the appropriate reference for the operating area
where the facility is located.”
Yes
What is the process for obtaining data from a 3rd party that is either unregistered or unwilling to
supply the data?
No
No
No
Group
Brent Ingebrigtson
LG&E and KU Energy

Yes
LG&E and KU Energy request clarification as to how the two year data requirement would apply to a

new facility for which the owner/operator requests an exemption.
Individual
Richard Salgo
NV Energy
Yes
Yes
No
In question #7 of the form, it would be useful to the analysis for technical exception to include not
only the minimum and maximum power flow out of the candidate facility, but also a description or
demonstration of the “typical” magnitude or the “average” of such flow. An entity may provide this
sort of information anyhow, but a prompt for this type of information could be useful and prevent
having to solicit more information during the review.
No
The information appears to be readily available to entities seeking exceptions.
No
No
No
Group
Jean Nitz
ACES Power Marketing
No
The first sentence only refers to element(s) designated as excluded. Element(s) designated as
included under the BES definition, shouldn’t have to go through the exception process either.
No
Q1, Q5 and Q6 have a “Description/Comments” section. What type of information should be included
under the Description for each of these questions? Providing more guidance here would help achieve
the “standardization, clarity and continuity of process” that we seek. Regarding Q2: A permanent
flowgate should not be part of the detailed information to support an exception. First, there is no
definition for what constitutes a permanent flowgate. Second, flowgates are often created for a
myriad of reasons that have nothing to do with them being necessary to operate the BES. While
section c) in E3 attempts to limit the applicability to permanent flowgates, there is no definition for
what constitutes a permanent flowgate particularly since no flowgate is truly permanent. The NERC
Glossary of Terms definition of flowgate includes flowgates in the IDC. This is a problem because
flowgates are included in the IDC for many reasons not just because reliability issues are identified.
Flowgates could be included to simply study the impact of schedules on a particular interface as an
example. It does not mean the interface is critical. As an example, it could be used to generate
evidence that there are no transactional impacts to support exclusion from the BES. Furthermore, the
list of flowgates in the IDC is dynamic. The master list of IDC flowgates is updated monthly and IDC
users can add temporary flowgates at anytime. While the "permanent" adjective applied to flowgates
probably limits the applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month and removed
another. Flowgates are created for many reasons that have nothing to do with them being necessary
to operate the BES. First, flowgates are created to manage congestion. The IDC is more of a
congestion management tool than a reliability tool. FERC recognized this in Order 693, when they
directed NERC to make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs that
have been violated. Rather, other actions such as re-dispatch must be used in conjunction. Second,
flowgates are used as a convenient point to calculate flows to sell transmission service. The
characteristics of the flowgate make it a good proxy for estimating how much contractual use has

been sold not necessarily how much flow will actually occur. While some flowgates definitely are
created for reliability issues such as IROLs, many simply are not. We are unclear about what “an
appropriate list” in Q3 is supposed to be. Is it supposed to be a list of all IROLs or only those for
which the answer is yes? Why is a list even necessary since the answer to the question answers
Exclusion E3.c? If the answer is no, is this asking the submitter to prove the negative?
No
Q5 has a “Description/Comments” section. Further clarification on what type of information to include
under the Description would help “standardize” the supporting information and “will provide more
clarity and continuity to the process.” The definition of ancillary services varies and can be quite
broad. It can include reactive power and voltage support for example. All generators provide some
reactive power and voltage support. Thus, ancillary services should be further defined or one could
construe it to limit any generator from being excepted.
Yes
Some generation owners may not be able to obtain their BA’s most severe single Contingency. Many
generator owners will not have access to the data necessary to demonstrate the reliability impact to
the BES. This is particularly true for transmission dependent utilities.
No
Yes
Some organized markets have a must run concept that has nothing to do with reliability. Thus, Q3 for
generation facilities might be confused with these tariff provisions.
No
Individual
Thomas C. Duffy
Central Hudson Gas & Electric Corporation
Yes
Yes
Yes
No
No
No
Yes
The ‘Technical Principles for Demonstrating BES Exceptions’ process was intended to establish
technical exception ‘criteria’ which would be used by the industry to understand what facilities would
qualify for inclusions and exclusions from the BES. What has been produced, however, is essentially a
listing of ‘electrical system indicators’, identified on the form, which may be material to making a
decision regarding, ‘is it BES or not’. The thresholds (or acceptable values) for the indicators,
however, have not been determined. It is understood that in Phase II of the BES Definition
development process, the SDT will attempt to address these issues but until that work has been
completed, the industry will remain enmeshed in confusion and inefficient application of resources and
funding. Without these criteria, it is very difficult to believe that this process can be transparent and
consistent. Re: Question 4. (For Transmission Facilities) For the purposes of responding to this
question, what constitutes the BES? It would seem that you must exclude the elements you are
seeking exceptions for or else the exception request is rendered essentially worthless.
Individual

Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
No
Con Edison’s overall concern is the lack of clarity and specificity with respect to what analyses and
study results are required under the 3rd bullet on page 1 and under #4 on pages 2 and 4. This lack of
clarity and specificity will lead to inconsistent application of the Technical Principles by both
Registered Entities and Regional Entities. We recommend the following: the impact and performance
analyses required by the 3rd bullet on page 1 and by #4 on pages 2 and 4 should be stipulated to be
all analyses, scenarios, and contingencies required under NERC Standard TPL-002-1 with the
“exception element” removed from the base system model. Entities shall report on all key
performance measures of BES reliability specified in the TPL-002-1 attributable to the removed
“exception element”. Note that references to NERC Standard TPL-001-2 should not be made in the
Technical Principles document as TPL-001-2 has not yet been filed with (nor approved by) FERC.
General Instructions One-Line Breaker Diagram questions and comments: Page 1, paragraph 2:
Please explain the phrase “at the interface points.” Where is this location? Please provide several
examples, i.e., for a radial, a local network, a generator, a transformer, a substation buss, and for
other Elements (PARs, reactors, UFLS panels, relays and switches).
No
Application Form Page 2 For Transmission Facilities: Impacts: Flowgates: The Application form at 2
states, “How does the facility impact permanent Flowgates in the Eastern Interconnection …” • What
standards for “impact” does the BES SDT envision? • What is a material impact and a non-material
impact? • What kinds and types of impacts are acceptable and/or unacceptable? • How are impacts
determined, e.g., Power TFD method, short circuit analysis, A-10 method? Impact-Based Studies:
Note that the FERC Seven Factor test is a time-tested method and FERC has identified it as an
acceptable method for reliability purposes; for gauging the expected impact of an Element on the
interconnected transmission grid. The NPCC A-10 method has been used extensively in the
Northeastern U.S. and Canada, and is an impact-based approach. The power TDF (transfer
distribution factor) method is also used by some to assess the impact of changing power flows on
individual Elements within a system. FERC has studied using the ‘TIER’ method for classifying system
Elements based on LBMP impacts. WECC uses a short circuit test. Page 3 Cranking Path Issue: The
Application form at 6 asks, “Is the facility part of a Cranking Path associated with a Blackstart
Resource?” We understand that: (i) The drafting team does not require that the BES be contiguous,
and (ii) Blackstart resource Cranking Paths were deleted from Inclusion I3. Recommendation: Delete
the reference to “Cranking Paths” in this Application form. Power Flow Issue: The Application form at
7 asks, “Does power flow through this facility into the BES?” We assume that this can only apply to a
Local Network with two or more connections to the BES. We believe that no power should normally
flow through a Local Network (or Radial system) to another portion of the BES. Occasional, brief
reverse power flows may be acceptable during short periods under abnormal operating conditions,
e.g., a switch normally open is briefly closed during a forced maintenance outage. The Application
form at 7 requests the following: “data for the most recent consecutive two calendar year period.” •
Please explain why the BES SDT felt that two years worth of data was necessary, as one year of data
would appear sufficient? Our experience has been that one year (8,760 hours) of data covers four
seasons, including Summer and Winter capability periods, and is therefore sufficient. Requiring an
extra year is perhaps unnecessarily burdensome on filing Entities, whether asset owners or Regional
Entities. The Application form at 7 asks, “[W]hat is the minimum and maximum magnitude of the
power flow outflow of the facility …” • Please explain why the BES SDT used the term “magnitude”
when requesting power outflow data? Recommendations: 1) We strongly recommend that the BES
SDT adopt the FERC Seven Factor test for these purposes. The FERC Seven Factor test states that, •
“Power flows into local distribution systems, and rarely, if ever flows out,” and • “When power enters
a local distribution system, it is not reconsigned or transported on to some other market.” 2) We
recommend deleting the “% of the calendar year” check boxes in favor of a statement either that
power does not flow through the Local Network, or alternatively, a blank space for reporting the net
peak MWs and MWH’s transferred annually, and the percentage of these transferred amounts to the
peak and annual MWH demands served by with the Local Network. 3) We recommend requesting only
one year (8,760 hours) of data covering four seasons, including Summer and Winter capability
periods.
No

For Generation Facilities: This Application form would appear to generally apply to traditional
generating facilities. • What Application form and justifications would be required for non-traditional
resources, e.g., solar and wind? • The Application form at 2 asks, “Is the generator or generator
facility used to provide Ancillary Services?”If some of these Generator check list items are marketrelated and not reliability-related, then they should not be present. • If the Ancillary Services are
reliability-related, please explain their relation to BES reliability. Recommendation: Insert the word
“reliability” before the words “must run” in question 3. The Application form at 5 asks, “Does the
generator use the BES to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load?” We assume this mean the generator may serve local loads through non-BES
facilities. In order to serve these local loads the generator would need to be connected to a Radial
system, a Local Network or to local distribution facilities. • Is this meaning above implied and
intended by this question? • Were there any other possibilities envisioned by the BES SDT?
Yes
According to the Applicability section, the TPL Reliability Standards are only applicable to the Planning
Coordinator (PC) and the Transmission Planner (TP). Was it the BES SDT’s assumption that Applicants
would have the PC or TP run studies for them, or that all Applicants would somehow gain access to
those models and run the models themselves? (Ref. TPL-002-1, Applicability: Planning Coordinator,
and Transmission Planner.)
Yes
We strongly recommend that the BES SDT adopt the FERC Seven Factor test for local distribution.

Individual
Thad Ness
American Electric Power
Yes
Though we have no objections to the proposed content, this is contingent on the number and type of
elements eventually found included or excluded as a result of the BES definition itself which is still
being drafted. Any changes in that definition could in turn cause us concern regarding these general
instructions. There needs to some provision for cases where specific elements which are not
specifically contained within the studies. It needs to be clear what additional analysis needs to be
provided under those circumstances. We recommend that the owner of the asset be identified as part
of the general instructions. In the case of wind resources, how is individual gross nameplate
information to be reported?
Yes
We recommend capitalizing “facility”.
No
It is unclear how the process will work with the interaction among the various NERC Functions. For
instance, an exception request from generation might require collaboration among other functional
entities, i.e. GOP, TOP, and RC. The question “How does an outage of the generator impact the overall reliability of the BES” may be subjective and dependent on contingencies at any given time. It
would be dependent on what state the BES would be in the area the generator is located. More detail
would be needed in describing the study required to have consistent results.
No
As stated in the response to question #3, the question “How does an outage of the generator impact
the over-all reliability of the BES” may be subjective and dependent on contingencies at any given
time. It would be dependent on what state the BES would be in the area the generator is located.
More detail would be needed in describing the study required to have consistent results.
No
As stated in the response to question #3, it is unclear how the process will work with the interaction
among the various NERC Functions. For instance, an exception request from generation might require
collaboration among other functional entities, i.e. GOP, TOP, and RC. The existence of a must run unit
means that unit has a material impact on any configuration of the BES and as such would need a
serious waiver to not be considered a BES facility. As such, a must run unit would not receive an

exception. As a result, should question #3 be removed? Criteria for applying for an exception should
be outlined before filling out the form.
No
AEP is not aware of any conflicts between the proposed approach and any regulatory function, rule
order, tariff, rate schedule, legislative requirement or agreement, or jurisdictional issue.
No
AEP agrees with the overall approach demonstrated by the exception request form; however, its
appropriateness will be largely dependent on the process eventually used for its implementation. AEP
would like guidance on how moth-balled generation should be treated. Perhaps this could be added to
the exception form as well.
Individual
Anthony Jablonski
ReliabilityFirst
No
These instructions are at a very high level and provide no clear guidance on what is required.
ReliabilityFirst Staff believes each bulleted item needs to provide clear expectations. As an example in
bullet #2 “Clearly document all assumptions used”, the document and this bullet should include
guidance such as what base case transfers were included, a list of facilities that were assumed out of
service, new facilities places in service and system load levels, etc.
No
All generating units, to some degree, affect the transmission elements that make-up the BES. What
role will this effect have on the determination? If the systems are planned properly and the day-ahead
analysis is done for maintenance work, the outage of any one element is moot. What is the phrase
“impact the over-all reliability” getting at? These studies and analysis will need to look at multiple
outages and groups of elements being taken out and excluded. Will this be on a first come, first out
process? As for the Nuclear Plant Interface Requirement (NPIR) question, ReliabilityFirst Staff believes
these facilities should always be included as part of the BES and taken out of the Detailed Information
to Support an Exception Request. For question 6 ReliabilityFirst Staff believes the Cranking Path
should be included in the BES definition. . ReliabilityFirst Staff feels that without including the
Cranking Paths, the reliability of the system could be jeopardized if a restoration is required and the
Cranking Paths are unavailable due to non-adherence to Reliability Standards. Omit question 7, E3
(LN) of the definition already talks to power flow and even if there is a small percentage of flow, it
makes that entity a user of the BES, which should be included.
No
If the systems are planned properly and the day-ahead analysis is done for maintenance work, the
outage of any one unit and even with the most serve outage happening, the system should be
capable of withstanding. These studies and analysis will need to look at multiple outages and groups
of units being taken out and excluded before any could be exempt. What is the phrase “impact the
over-all reliability” getting at? These studies and analysis will need to look at multiple outages and
groups of elements being taken out and excluded. Will this be on a first come, first out process? As
for the Ancillary Services question, ReliabilityFirst Staff believes that if a unit provides this service, it
should be included in the BES. The same applies for the “must run units” in question 3. Omit question
5, E3 (LN) of the definition already talks to power flow and even if there is a small percentage of
unit’s output flowing onto the BES, it makes that entity a user of the BES, which should be included.
Yes
In some cases, models and even knowledge of the system configurations, operating protocols and
procedures may not be well known by all the entities. System adjustments, load levels, topologies,
maintenance and outage schedules, which happen daily, will or may be unknown to many entities,
including the Regional Entities who may submit a request to include facilities. For cross regional
boundaries, the problem becomes even larger. That coupled with generation unit owners/operators
not permitted to know transmission information (i.e. Questions 4 and 5); this will put them at a huge
disadvantage to participate in the exception request process.
No

Yes
Since the inception of the Open Access Transmission Tariff, transmission models and even knowledge
of the systems, operating protocols and procedures may not be well known or known at all by all the
entities. System adjustments, load levels, topologies, maintenance and outage schedules (i.e. market
sensitive information), which happens daily is not permitted to be known by the generation side of the
industry. An unknown at this point and without a common set of criteria to be used by the Regional
Entities and NERC Staff and Panels, it will be difficult to make consistent determinations across the
ERO Enterprise.
Yes
FERC Order 743-A, paragraph 1, discusses that NERC should “…establish an exemption process and
criteria for excluding facilities that are not necessary for operating the interconnected transmission
network”. It also directed in paragraph 4 that “Order No. 743 also directed the ERO to develop an
exemption process that includes clear, objective, transparent and uniformly applicable criteria for
exempting facilities that are not necessary for operating the interconnected transmission grid.” The
SDT proposed a set of questions titled “Detailed Information to Support an Exception Request” to
assist in the exemption process but in our mind is not “exception criteria” as stated in the FERC
Orders. ReliabilityFirst Staff believes that NERC should develop criteria for which facilities or Elements
could be exempted from the core definition; an example being Local Networks as outlined in the
current draft of the definition. ReliabilityFirst Staff believes the Local Network exclusion is not “bright
line” and could be removed from the core definition and used as criteria for exclusion in the
exemption process. Item b of the LN (E3) exclusion would need evidence to support the historical and
future power flows. Historical data and future power flow study results would be needed to support
this exception. Additionally, another example for exemption criterion for inclusion to the BES could be
any 69 kV network facilities that provide a parallel path to the BES. Evidence such as one-line
diagrams along with power flow studies would need to be provided through the exemption process for
these types of facilities to be included in the BES. ReliabilityFirst Staff believes that any BES facilities
should not be candidates for exemption based upon the arbitrary determination of a panel that
considers the aspects stated in the document “Detailed Information to Support an Exception
Request”. Without uniform criteria as stated in the FERC Orders, it will be difficult for the panels to
make consistent determinations across the ERO Enterprise.
Individual
Joe Petaski
Manitoba Hydro
No
No
No

Yes
Canadian Entities are not under FERC jurisdiction, so the revised BES Definition may not apply. A
number of Canadian Entities have the BES defined within their provincial legislation. This may
introduce differences and even contradictions between elements that are included in the BES
according to provincial legislation and the NERC definition.
Yes
Manitoba Hydro strongly disagrees with the proposed ‘Detailed Information to Support an Exception
Request’ document and associated exception process for the following reasons: -It is not clear what
elements or situations beyond what is covered in the core definition and associated inclusions and
exclusions that the drafting team is hoping to capture through the exception process. Further, it is
unclear what the benefit to reliability would be by allowing an impact based exception process given
that entities will be extremely unlikely to use the exception process to include elements in the BES. The exception process will be extremely resource intensive, particularly in the absence of any

Industry approved threshold criteria. The costs to properly administer and monitor the process to
ensure that impact based modeling is done accurately and that it captures the frequent changes on a
dynamic system will occupy a wealth of Industry, NERC and Regional Entity time to the detriment of
reliability. -It is not reasonable for industry to approve the exception process without knowing what
thresholds are required to demonstrate an element as being part of the BES or not. We are concerned
that BES determinations would be subjective and would vary from case to case with the particular
staff examining the request. BES elements should be established and agreed upon by Industry, not
set by a NERC panel. We understand that the drafting team has made this change in the interests of
time, but the impact of the BES definition is too broad for this project to be rushed. -The 2010-17
project goals to increase the clarity of the BES definition and establish a ‘bright-line’ are compromised
by the exception process. Changes and alterations to the BES definition should be approved by
Industry through the Standards Under Development Process. An interpretation request or SAR should
be developed by an entity if they feel that the core definition and associated exceptions and inclusions
should be modified. We ask that NERC requests that FERC re-examines the directive to develop an
exception process given that the BES definition, which already includes a list of exceptions, is
sufficient to standalone without an associated exception process.
Group
Janet Smith
Arizona Public Service Company

Yes
In accordance with WECC’s position paper issued on October 5, 2011, AZPS agrees with WECC in that
the proposed Technical Principles for Demonstrating BES Exceptions Request does not provide the
necessary clarity as to what applying entities must provide to support their request, nor does it
provide any criteria for consistency among regions in their assessment of requests.
Individual
Robert Ganley
Long Island Power Authority
Yes
Yes
On page 3 why reference if a facility is part of a Cranking Path after the SDT has deleted Cranking
Paths from the Inclusion list as part of the BES definition.
Yes
Need to define the term "must run unit"
No
No
Not aware of any
No
Individual
Eric Salsbury
Consumers Energy
Yes

No
We believe that item 6, should read "Is the facility part of a Primary Cranking Path associated with a
Blackstart Resource?" Currently, the word "Primary" is not included.
Yes
Yes
No
No
No
Group
Jonathan Hayes
Southwest Power Pool
Yes
Yes
Yes
Yes
SCADA line flow data might be hard to capture for the last two years. Specifically the line flows may
not be available.
No
No
No
Individual
David Burke
Orange and Rockland Utilities, Inc.
No
In the first paragraph “Entities that have Element(s) designated as excluded, under the BES definition
and designations, do not have to seek exception for those Elements under the Exception Procedure.”,
before the “General Instruction” it should have had another sentence saying that “for those who do
not clearly meet the Inclusions and Exclusions should use the following instructions”. Otherwise, it’s
still not very clear.
No
Please clarify “facility” and include “N-1” for power-flow studying.
No
However, please clarify “facility” and include “N-1” for power-flow studying.
No
No

No
Group
Steve Rueckert
WECC
No
WECC has several concerns with the instructions on the checklist regarding the studies: • Study Case
– The instructions state the study case that should be used, “Be based on an Interconnection-wide
base case that is suitably complete and detailed to reflect the facility’s electrical characteristics and
system topology.” The phrase “suitably complete and detailed” is vague. WECC recommends
clarification of this phrase and the addition of specific requirements for what will constitute an
appropriate case. Allowing the entity requesting an exception to choose any Interconnection-wide
case could allow an inappropriate choice of case and could lead to inconsistent study results. If there
are no requirements for the chosen case, then it is possible that the most favorable case to an entity’s
argument will be chosen. In some instances that choice would likely be appropriate, but in others it
would not necessarily be appropriate. At a minimum, there should be further description — and
preferably, specific requirements — guiding the determination of which study case is most
appropriate. Of particular importance in clarifying what case is an appropriate case, is the timeliness
of the case. WECC recommends requiring that a recent case be used. In addition, if each entity is able
to chose its own case, without further requirements, there will be no way for the Regional Entity or
NERC to ensure consistency of determinations with respect to the elements tested. • The entities are
asked to address key performance measures of BES reliability through the studies. This instruction is
vague concerning what the study must investigate and it leaves it up to the entity to determine the
key performance measures. The “key performance” measures should be consistent with respect to
similar elements and there is no way to ensure that if there are no specifications regarding such
measures. The exceptions process must be objective and clear as to what performance measures
need to be met for the process to be implemented consistently. WECC recommends further
clarification and the addition of specific requirements beyond the guidance related to consistency with
Transmission Planning (TPL) standards. • The background information on the comment form states:
“The same checklist will be utilized for exceptions dealing with inclusions or exclusions.” But there is
no mention of this in the document. A note should be added to the checklist instruction to state that
the same checklist will be used for exclusions and inclusions.
Yes
The requested information in the checklist is appropriate. However; the exceptions process as drafted,
with no objective criteria defining how to assess the submittals, leaves it to each Regional Entity to
develop their own criteria to evaluate the responses to the checklist included in the submittals,
leading to inconsistency between Regional Entities. In addition, WECC recommends clarifying
Question 7. On its face it is unclear what defines power flowing through a facility in the BES. It should
be clear whether a qualitative or quantitative response is required.
Yes
The requested information in the checklist is appropriate. However; the exceptions process as drafted,
with no objective criteria defining how to assess the submittals, leaves it to each region to develop
their own criteria to evaluate the responses to the checklist included in the submittals, leading to
inconsistency between Regional Entities.
Yes
Entities would have a difficult time deciding what data to obtain. Getting the data for their own
specific facilities should be relatively simple for the majority of entities. However, it is possible smaller
entities may have a higher burden putting together the appropriate information for inclusion in a
study case that they currently may not do. In addition, because the instructions state that a case will
be “suitably complete and detailed,” WECC believes there is insufficient guidance as to what amount
and degree of detail in the data is sufficient for the submittal process. Without thresholds it is difficult
to determine whether the entities will have the ability to obtain necessary data to file for an
exception. At this time, WECC views the instructions as insufficient for these reasons.
Yes

In order to make a determination of BES status of an element, there should be a listing of effects of
the outage on certain facilities, frequencies, voltages, transmission elements, or other information
that should be included in the submittal by the entity. Without further specification of requirements
for presenting a case it is likely that the Regional Entity will receive inconsistent submittals of data.
Leaving open the question of what constitutes a sufficient presentation of a case would likely lead to a
wide spectrum of submittals with respect to the amount of data and level of detail in the data.
No
Yes
WECC is very concerned that there are no specific qualifications or requirements, either for the
entities or for the Regional Entity, with respect to: • the determination of which studies need to be
conducted; • the format of the study data that should be submitted; or • the key performance
measures that should be evaluated. This vagueness will lead to inconsistency in studies run, data
submitted, and measures of data evaluation. If this inconsistency occurs, it will result in a potentially
subjective and discordant process on multiple levels for both the submitting entities and the Regional
Entities. It may result in submitting entity having to run multiple studies in order to determine what
will be acceptable proof, which is overly burdensome on both the submitting entity requesting the
exception and the Regional Entity reviewing the request. It also makes the consistency that FERC has
requested difficult to assess and achieve. If the goal of the exceptions process is to result in
consistent determinations across the regions, then WECC recommends that to the extent possible, the
process be objective, clear, and include detailed instructions. The development of such an objective
and detailed process is a difficult task and will require additional time. WECC believes it is better to
not have an exceptions process in the interim period than to have an inefficient and overly
burdensome process in place. To allow adequate time to complete the task of developing a detailed
and consistent process WECC recommends that the Detailed Information to Support BES Exceptions
Request be included in Phase II of the BES definition project.
Individual
Kathleen Goodman
ISO New England Inc
No
It is unclear what the purpose of submitting diagrams showing the Protection Systems is and we do
not feel that it should be a requirement at the onset of the exception process. In the first bullet, we
do not feel that the term “Interconnection-wide base case” is required as the phrase “suitably
complete and detailed” should provide enough guidance to the submitter that inappropriate
equivalent representations would not be accepted. The concern is that one could interpret
“Interconnection-wide base case” as the entire Eastern Interconnection model is a requirement.
No
- Question 1 o The use of the words “connected to” is unclear. Some may read this as generation
“directly” connected to while others could interpret it more generically. o A generation cut-off should
be included in the requirement to list all individual units that may be connected to a facility. A
suggestion would be to use a 1 MVA cut-off so that machines such as wind turbines would still be
captured but smaller installations would not need to be listed in detail. o When listing individual gross
nameplate values, the form should be specific that it is requesting the nameplate MVA value. Question 3 o It is not clear how a facility could be included in an Interconnection Reliability Operating
Limit (IROL) is a limit and not a specific element. Rather, it is clearer to ask if a facility is used to
identify an IROL either as a part of the interface itself or as a contingency which relevant to the IROL.
- Question 4 o As this question only pertains to the outage of the facility, there may also be a need to
show how the outage of another element could impact the facility seeking exception. A new question
to add to address this would be “How does an outage of other BES facilities impact flows through this
facility and thus, the over-all reliability of the BES?” - Question 6 o This question appears to be
inconsistent with the removal of the “Cranking Path” from the BES definition. o If the question is to
remain, the question should be clarified to state, “With a Blackstart Resource “material to” and
designated as part of a transmission operator entity’s restoration plan. - Question 7 o The question
should be more specific to whether the flow should be measured under all-lines in conditions or postcontingency. o The question should be more specific as to whether the power flow pertains to Real,
Reactive, or Apparent Power. o The use of the word “through” in the question is unclear. This is more

evident when trying to apply this question to facilities which are transmission lines that are not
directly connected to the BES.
No
- Question 1 o The question would be better worded as “How many MW are lost following the host
Balancing Authority’s most severe single Contingency…”. o The question becomes difficult to answer
when the most severe single Contingency can change on a day-to-day and hour-to-hour basis. o The
MVA size of the facility should be requested. - Question 3 o The term “must run unit” is unclear.
No
All concerns were captured in comments provided to the previous questions.
No
All concerns were captured in comments provided to the previous questions.
No
Yes
Given all of these decisional inputs requested by the Exception Application there needs to be some
guidance or clarification here regarding the criteria that will be used to render a yes or no decision
other than simply filling out the Application and allowing the Rules of Procedure process to take place.
The Application process for Exceptions (inclusions or exclusions) appears to be subjective and lacks
the decisional technical criteria for the applicant to be confident of the outcome.
Individual
Diane Barney
New York State Dept. of Public Service
No
Missing from the document are any indicators as to how much information is sufficient, how the
information will be evaluated, what weight will be given to the individual pieces of information, etc.
No
Question 6 should be dropped. Facilities in a cranking path for a blackstart resource should not be a
consideration. Question 7 is circular. If a facility is used to flow power into the BES, by definition it is
outside the BES. Needs clarification as to the information the question is seeking.

Individual
John Seelke
PSEg Services Corp
No
What is meant by “key performance measures of BES reliability” in the third bullet? A descriptive list
would be helpful.
No
Questions #4 requires an analysis of the “most severe impact” associated an outage of the Element
proposed for exception. a. Both the newly Board approved TPL-001-2 standard and the existing TPL004-1 require that severe contingencies be evaluated, but there are no performance requirements for
them. If the team intended the “most-severe impact” analysis to only evaluate TPL outages that
incorporate performance requirements, it should make that clear. b. The most-severe-outage impact
question does not ask key relevant information such as: i. What is the probability that the “most
severe impact “will occur? ii. Could the impact be readily mitigated and service restored? This point is
critical because the impact of an outage lasting several minutes before restoration versus several
hours before restoration should affect the analysis. What does question #7 (“Does power flow through
this facility into the BES?”) with check boxes for various % of a calendar year that power flows into
the BES) imply with respect to a transmission facility’s exception request? Also, is the % of a calendar

year data intended to be forecasted data or historic data? It would seem that forecasted data would
need to be supplied that is consistent with the TPL models. Finally, why are historic flows requested –
they have no relevance except for perhaps explaining historic and forecasted differences?
No
With regards to question #2 (“Is the generator or generating facility used to provide Ancillary
Services”), the answer for most synchronous generators is probably “yes” unless they are in a bidbased market that selects specific generators for Reactive Power delivery. Since most generators
(with the exception of those with nuclear prime movers) provide Reactive Power to meet a
Transmission Operator-specified voltage, they would provide that Ancillary Service. Other generators
(again, with the exception of generators with nuclear prime movers) may be eligible to provide other
Ancillary Services such as Spinning Reserve, but may have rarely done so. However, they still may be
“used do provide” Spinning Reserve at any time. How would those generators respond to question
#2? Questions #4 requires an analysis of the “most severe impact” associated an outage of the
Element proposed for exception. a. Both the newly Board approved TPL-001-2 standard and the
existing TPL-004-1 require that severe contingencies be evaluated, but there are no performance
requirements for them. For consistency, performance requirements for the most-severe-impact
analysis needed to be defined by the team. If the team intended the “most-severe impact” analysis to
only evaluate TPL outages that incorporate performance requirements, it should make that clear. b.
The most-severe-outage impact question does not ask key relevant information such as: i. What is
the probability that the “most severe impact “will occur? ii. Could the impact be readily mitigated and
service restored? This point is critical because the impact of an outage lasting several minutes before
restoration versus several hours before restoration should affect the analysis. What does the answer
to the question #5 in the Generator Facilities section (“Does the generator use the BES to deliver its
actual or scheduled output, or a portion of its actual or scheduled output, to Load?”) imply with
respect to a generator’s exclusion? Also, the phrase “deliver its actual or scheduled output …to load”
needs explanation. The use of “actual output” and “scheduled output” may have several contexts. a.
For example, in a market, a generator’s actual output may suddenly go to zero due a forced outage,
but the generator has financial obligations that accrue for delivering its scheduled output, which is in
fact provided by other sources since the generator is unavailable. Is the question asking about the
use of BPS facilities by resources that may be substituted for delivery of a generator’s scheduled
output when it differs from its actual output? b. Now assume that a generator’s actual output equals
its scheduled output and that several generators are forced out of service in another Balancing
Authority, resulting in a frequency decline. Generators within the interconnection with active
governors and available spinning capacity will automatically increase their output above their
scheduled output, resulting in Inadvertent Interchange. Is the question related to the BES facilities
used to deliver such Inadvertent Interchange? c. Again assume that a generator’s actual output
equals its scheduled output. Is the question related to the actual BES facilities that may be used to
deliver the generator’s power to Load? That would require an analysis of generator and load shift
factors to determine what actual facilities carry the power generated from a generator to a specific
load for a given set of assumptions on the system topology. In a market, this analysis would not be
possible for generators that do not self-schedule for delivery to specific loads.
Yes
It would depend upon the clarifications to the points raised above.
No
No
Yes
An applicant should be able to clearly tell whether or not an exception request will likely be granted
before it is submitted. It is nearly impossible to divine the whether a request will be granted from a
set of data questions. The team is urged to state the exclusion criteria explicitly; data questions
required to evaluate a request should directly reference each criterion. See Order 743, paragraph
115: “NERC should develop an exemption process that includes clear, objective, transparent, and
uniformly applicable criteria for exemption of facilities that are not necessary for operating the grid.”
Individual
Sylvain Clermont

Hydro-Quebec TransEnergie
No
We believe that the new Technical Principles are better than the previous ones, as they allow
flexibility for an Entity to make their case with technical justifications. However, without any guide or
specific criteria, it does not allow an Entity to identify the real possibility to obtain an exception. It is
not clear at all what will guide the Region or ERO to make their decision to grant or not the exception.
In order give confidence to the Industry in the procedure, it would be necessary to define the
elements that will guide the decision. Will impact base study be accepted? Will the threshold
differences with Quebec Interconnection be accepted?
No
No
No
Yes
The general characteristics of the Interconnection (such as frequency or voltage variation), as they
may guide the decision for exclusion of specific elements.
Yes
For HQT's system, the proposed BES definition combined with the exception procedure are presently
incompatible or at least inconsistent with the regulatory framework applicable in Quebec. The
proposed changes have not address this concern, neither the SDT's responses to our previous
comments last May (Q.9). We reiterate that the definition and the exception procedure shall be
determined by Quebec's regulator, the Régie de l'Énergie du Québec, (Quebec Energy Board) which
has the responsibility to ensure that electric power transmission in Quebec is carried out according to
the reliability standards it adopts. Per se, it would be necessary that E1 and E3 grant exclusions with
much higher level of generation. It would also be necessary to allow for several levels of application
for the Reliability Standards, in accordance with the Régie de l’énergie du Québec approach: the Bulk
Power System (BPS) as determined using an impact-based methodology, the Main Transmission
System (MTS), and other parts of Regional System. Standards related to the protection system (PRC004-1 and PRC-005-1) and those related to the design of the transmission system (TPL 001-0 to TPL004-0) shall be applicable to the first level, but all other reliability standards shall be applied to the
second level, the MTS. The MTS definition is somewhat different than the Bulk Electric System
definition, and it includes elements that impact the reliability of the grid, supply-demand balance and
interchanges. We argue that it would be necessary for NERC to address the regulatory issues outside
ot the present context of the SDT and ROP team.
Individual
Rick Hansen
City of St. George
No
While the general instruction information outlined is applicable, it lacks sufficient detail to know
exactly what is needed to be submitted. More importantly the general instructions and the overall
document lacks criteria that if met (through study and other documentation methods) would allow for
exclusion from or inclusion to the BES. Something similar to the criteria or concepts used in the
Appendix 1 of the Local Network Exclusion justification document is needed. Clear criteria should
allow an entity to determine with a reasonable degree of certainty that if the criteria are met as
demonstrated by the associated study effort that an exemption can be obtained. Otherwise without
that criteria, the process will be not far from where the exemption process is today, which will be
costly, time consuming and frustrating for the registered entities as well as the regions and NERC.
The process needs to be repeatable and consistent between all regions and entities. Entities need to
know what is expected and where the finish line is. As presently written each region and NERC would
have to develop their own criteria individually and will be open to opinions which could change as
personnel changes occur in a given position or panel.

No
The questions for transmission facilities seem to be appropriate; however, how the answers are to be
used by the region or NERC is unclear. Will a given response to a question make exclusion
impossible? If so this needs to be known upfront and clearly documented. For example question 4, on
page 2 is open for interpretation and debate as to what the impact to the over-all reliability of the
BES is. The definition of “impact” is really the key to the whole definition effort. Load flow, voltage,
frequency change limits may all be pieces to the puzzle. Are these criteria to be met in normal, N-1,
N-2, etc. system configurations?
No
The questions for generation facilities seem to be appropriate; however, how the answers are to be
used by the region or NERC is unclear. Will a given response to a question make exclusion
impossible? If so this needs to be known upfront and clearly documented. For example question 4, on
page 4 is open for interpretation and debate as to what the impact to the over-all reliability of the
BES is. The definition of “impact” is really the key to the whole definition effort. Load flow, voltage,
frequency change limits may all be pieces to the puzzle. Are these criteria to be met in normal, N-1,
N-2, etc. system configurations?
Yes
The access to the required data would be potentially be a concern especially for smaller entities.
Small entities will typically have to outsource the required studies to consultants and obtaining the
data may be difficult for the consultants. The entities most likely to obtain exemptions (smaller &
lower impact entities) are the ones that probably will have the most difficulty in obtaining the data.
Generally larger utilities “upstream” from the smaller ones are hesitant to give information to other
entities. Depending on the study requirements and criteria for application, this could be a very costly
process.
No
No
Yes
Clear, concise criteria with consistent repeatable results are a must for a successful outcome of the
project effort. The included questions are appropriate questions but the use of those questions and
the ultimate outcome is unclear with the current version. The background information indicates that
continent wide criteria are not feasible. It is understood that this is a very difficult task and will be
difficult to achieve (especially in the time allotted). However, if the decisions are left up to a “panel”
to decide the results will be inconsistent and will vary region by region, as well as differ over time.
The process involved will be very time consuming (i.e. expensive) and will be difficult to control
especially during the initial timeframe. History has demonstrated that review and approval processes
that pass from the entity to the regions, then to NERC and then on to FERC backup very easily due to
limited staff and resources. The drafting team may want to consider moving this topic to Phase 2 of
the project. However, Phase 2 needs to have fairly quick time frame in order to provide the needed
direction to the industry in a timely manner.
Individual
Bud Tracy
Blachly-Lane Electric Cooperative
Yes
The Blachly-Lane Electric Cooperative (BLEC) agrees generally that the General Instructions set forth
the basic information that would be necessary to support an Exception Request. We are concerned,
however, that the statement “diagram(s) supplied should also show the Protection Systems at the
interface points associated with the Elements for which the exception is being requested” may be
subject to differing interpretations. We envision that at least four different kinds of documents could
be responsive to the description: one-line diagrams with breakers and switches (status); identification
of relays by their ANSI device numbers; details of the DC control logic for ANSI devices; and,
operational scheme descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to identify protection
systems at the interface with the Elements for which the Exception is sought, including any required

details. WE suggest that a generic example of a completed form be available to the industry to help
ensure that Exception Requests are supported by consistent and complete information. Such a generic
example could be addressed in the Phase 2 BES efforts.
No
BLEC agrees that the checklist of items on pages two and three lists most of the information that
would be necessary to determine if an Exceptions Request is justified. We suggest two modifications
to the proposed language to ensure consistency with the BES Definition and to provide an entity
seeking an Exception with the opportunity to submit all relevant information: (1) We suggest
modifying question 6 to “Is the facility part of a designated Cranking Path associated with a Blackstart
Resource identified in a Transmission Operator’s restoration plan.” This language reflects the most
recent revision of the BES Definition and also helps distinguish between generators which have
Blackstart capability and those generators that are designated as a Blackstart Resource in the
Transmission Operator’s restoration plan. It is only the latter that are included in the BES under the
current draft of the definition. (2) A general “catch-all” question should be added that will prompt the
entity submitting an Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following language: Is there
additional information not covered in the questions above that supports the Exception Request? If
yes, please provide the information and explain why it is relevant to the Exception Request. While we
believes the questions set forth in the draft capture the information that generally would be necessary
to determine whether an Exception Request should be granted, it is foreseeable that there may be
unusual circumstances where the information called for either does not capture the full picture or
where studies other than the specific types called for in the draft form support the Exception. An
entity seeking an Exception should have the opportunity to present any information it believes is
relevant.
Yes
BLEC agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine

whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, BLEC believes the SDT has provided a reasonable check list that will work in
most cases to elicit necessary information from the entity submitting an Exception Request. With the
added language suggested in our answers to the previous questions, we believe the proposed form
will serve its intended purpose of ensuring that decisions regarding Exception Requests are based
upon consistent information and are consistent with the requirements of the Federal Power Act and
the BES Definition as developed by the Standards Drafting Team. We also support the Standards
Drafting Team’s determination to abandon its initial approach to technical criteria, which would have
required adherence to specific numerical thresholds. We agree that this approach was not workable
on a nationwide basis, and that the approach embodied in the current draft of the Technical
Principles, which would require specific kinds of information on a generic basis but would leave
engineering judgment about the significance of that information to the relevant RE, is more workable
and provides appropriate deference to the experience and judgment of the Registered Entities.
Individual
Dave Markham
Central Electric Cooperative (CEC)
Yes
The Central Electric Cooperative (CEC) agrees generally that the General Instructions set forth the
basic information that would be necessary to support an Exception Request. We are concerned,
however, that the statement “diagram(s) supplied should also show the Protection Systems at the
interface points associated with the Elements for which the exception is being requested” may be
subject to differing interpretations. We envision that at least four different kinds of documents could
be responsive to the description: one-line diagrams with breakers and switches (status); identification
of relays by their ANSI device numbers; details of the DC control logic for ANSI devices; and,
operational scheme descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to identify protection
systems at the interface with the Elements for which the Exception is sought, including any required
details. WE suggest that a generic example of a completed form be available to the industry to help
ensure that Exception Requests are supported by consistent and complete information. Such a generic
example could be addressed in the Phase 2 BES efforts.
No
CEC agrees that the checklist of items on pages two and three lists most of the information that would
be necessary to determine if an Exceptions Request is justified. We suggest two modifications to the
proposed language to ensure consistency with the BES Definition and to provide an entity seeking an
Exception with the opportunity to submit all relevant information: (1) We suggest modifying question
6 to “Is the facility part of a designated Cranking Path associated with a Blackstart Resource identified
in a Transmission Operator’s restoration plan.” This language reflects the most recent revision of the
BES Definition and also helps distinguish between generators which have Blackstart capability and
those generators that are designated as a Blackstart Resource in the Transmission Operator’s
restoration plan. It is only the latter that are included in the BES under the current draft of the
definition. (2) A general “catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the Exception that is not
captured in the other questions. We suggest the following language: Is there additional information
not covered in the questions above that supports the Exception Request? If yes, please provide the

information and explain why it is relevant to the Exception Request. While we believes the questions
set forth in the draft capture the information that generally would be necessary to determine whether
an Exception Request should be granted, it is foreseeable that there may be unusual circumstances
where the information called for either does not capture the full picture or where studies other than
the specific types called for in the draft form support the Exception. An entity seeking an Exception
should have the opportunity to present any information it believes is relevant.
Yes
CEC agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, CEC believes the SDT has provided a reasonable check list that will work in most
cases to elicit necessary information from the entity submitting an Exception Request. With the added
language suggested in our answers to the previous questions, we believe the proposed form will serve
its intended purpose of ensuring that decisions regarding Exception Requests are based upon
consistent information and are consistent with the requirements of the Federal Power Act and the BES

Definition as developed by the Standards Drafting Team. We also support the Standards Drafting
Team’s determination to abandon its initial approach to technical criteria, which would have required
adherence to specific numerical thresholds. We agree that this approach was not workable on a
nationwide basis, and that the approach embodied in the current draft of the Technical Principles,
which would require specific kinds of information on a generic basis but would leave engineering
judgment about the significance of that information to the relevant RE, is more workable and provides
appropriate deference to the experience and judgment of the Registered Entities.
Individual
Dave Hagen
Clearwater Power Company (CPC)
Yes
The Clearwater Power Company (CPC) agrees generally that the General Instructions set forth the
basic information that would be necessary to support an Exception Request. We are concerned,
however, that the statement “diagram(s) supplied should also show the Protection Systems at the
interface points associated with the Elements for which the exception is being requested” may be
subject to differing interpretations. We envision that at least four different kinds of documents could
be responsive to the description: one-line diagrams with breakers and switches (status); identification
of relays by their ANSI device numbers; details of the DC control logic for ANSI devices; and,
operational scheme descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to identify protection
systems at the interface with the Elements for which the Exception is sought, including any required
details. WE suggest that a generic example of a completed form be available to the industry to help
ensure that Exception Requests are supported by consistent and complete information. Such a generic
example could be addressed in the Phase 2 BES efforts.
No
CPC agrees that the checklist of items on pages two and three lists most of the information that would
be necessary to determine if an Exceptions Request is justified. We suggest two modifications to the
proposed language to ensure consistency with the BES Definition and to provide an entity seeking an
Exception with the opportunity to submit all relevant information: (1) We suggest modifying question
6 to “Is the facility part of a designated Cranking Path associated with a Blackstart Resource identified
in a Transmission Operator’s restoration plan.” This language reflects the most recent revision of the
BES Definition and also helps distinguish between generators which have Blackstart capability and
those generators that are designated as a Blackstart Resource in the Transmission Operator’s
restoration plan. It is only the latter that are included in the BES under the current draft of the
definition. (2) A general “catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the Exception that is not
captured in the other questions. We suggest the following language: Is there additional information
not covered in the questions above that supports the Exception Request? If yes, please provide the
information and explain why it is relevant to the Exception Request. While we believes the questions
set forth in the draft capture the information that generally would be necessary to determine whether
an Exception Request should be granted, it is foreseeable that there may be unusual circumstances
where the information called for either does not capture the full picture or where studies other than
the specific types called for in the draft form support the Exception. An entity seeking an Exception
should have the opportunity to present any information it believes is relevant.
Yes
CPC agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the

BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, CPC believes the SDT has provided a reasonable check list that will work in most
cases to elicit necessary information from the entity submitting an Exception Request. With the added
language suggested in our answers to the previous questions, we believe the proposed form will serve
its intended purpose of ensuring that decisions regarding Exception Requests are based upon
consistent information and are consistent with the requirements of the Federal Power Act and the BES
Definition as developed by the Standards Drafting Team. We also support the Standards Drafting
Team’s determination to abandon its initial approach to technical criteria, which would have required
adherence to specific numerical thresholds. We agree that this approach was not workable on a
nationwide basis, and that the approach embodied in the current draft of the Technical Principles,
which would require specific kinds of information on a generic basis but would leave engineering
judgment about the significance of that information to the relevant RE, is more workable and provides
appropriate deference to the experience and judgment of the Registered Entities.
Individual
Roman Gillen
Consumer's Power Inc. (CPI)
Yes
The Consumers Power (CPI) agrees generally that the General Instructions set forth the basic
information that would be necessary to support an Exception Request. We are concerned, however,
that the statement “diagram(s) supplied should also show the Protection Systems at the interface
points associated with the Elements for which the exception is being requested” may be subject to
differing interpretations. We envision that at least four different kinds of documents could be
responsive to the description: one-line diagrams with breakers and switches (status); identification of

relays by their ANSI device numbers; details of the DC control logic for ANSI devices; and,
operational scheme descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to identify protection
systems at the interface with the Elements for which the Exception is sought, including any required
details. WE suggest that a generic example of a completed form be available to the industry to help
ensure that Exception Requests are supported by consistent and complete information. Such a generic
example could be addressed in the Phase 2 BES efforts.
No
CPI agrees that the checklist of items on pages two and three lists most of the information that would
be necessary to determine if an Exceptions Request is justified. We suggest two modifications to the
proposed language to ensure consistency with the BES Definition and to provide an entity seeking an
Exception with the opportunity to submit all relevant information: (1) We suggest modifying question
6 to “Is the facility part of a designated Cranking Path associated with a Blackstart Resource identified
in a Transmission Operator’s restoration plan.” This language reflects the most recent revision of the
BES Definition and also helps distinguish between generators which have Blackstart capability and
those generators that are designated as a Blackstart Resource in the Transmission Operator’s
restoration plan. It is only the latter that are included in the BES under the current draft of the
definition. (2) A general “catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the Exception that is not
captured in the other questions. We suggest the following language: Is there additional information
not covered in the questions above that supports the Exception Request? If yes, please provide the
information and explain why it is relevant to the Exception Request. While we believes the questions
set forth in the draft capture the information that generally would be necessary to determine whether
an Exception Request should be granted, it is foreseeable that there may be unusual circumstances
where the information called for either does not capture the full picture or where studies other than
the specific types called for in the draft form support the Exception. An entity seeking an Exception
should have the opportunity to present any information it believes is relevant.
Yes
CPI agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single

contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, CPI believes the SDT has provided a reasonable check list that will work in most
cases to elicit necessary information from the entity submitting an Exception Request. With the added
language suggested in our answers to the previous questions, we believe the proposed form will serve
its intended purpose of ensuring that decisions regarding Exception Requests are based upon
consistent information and are consistent with the requirements of the Federal Power Act and the BES
Definition as developed by the Standards Drafting Team. We also support the Standards Drafting
Team’s determination to abandon its initial approach to technical criteria, which would have required
adherence to specific numerical thresholds. We agree that this approach was not workable on a
nationwide basis, and that the approach embodied in the current draft of the Technical Principles,
which would require specific kinds of information on a generic basis but would leave engineering
judgment about the significance of that information to the relevant RE, is more workable and provides
appropriate deference to the experience and judgment of the Registered Entities.
Individual
Dave Sabala
Douglas Electric Cooperative (DEC)
Yes
The Douglas Electric Cooperative (DEC) agrees generally that the General Instructions set forth the
basic information that would be necessary to support an Exception Request. We are concerned,
however, that the statement “diagram(s) supplied should also show the Protection Systems at the
interface points associated with the Elements for which the exception is being requested” may be
subject to differing interpretations. We envision that at least four different kinds of documents could
be responsive to the description: one-line diagrams with breakers and switches (status); identification
of relays by their ANSI device numbers; details of the DC control logic for ANSI devices; and,
operational scheme descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to identify protection
systems at the interface with the Elements for which the Exception is sought, including any required
details. WE suggest that a generic example of a completed form be available to the industry to help
ensure that Exception Requests are supported by consistent and complete information. Such a generic
example could be addressed in the Phase 2 BES efforts.
No
DEC agrees that the checklist of items on pages two and three lists most of the information that
would be necessary to determine if an Exceptions Request is justified. We suggest two modifications
to the proposed language to ensure consistency with the BES Definition and to provide an entity
seeking an Exception with the opportunity to submit all relevant information: (1) We suggest
modifying question 6 to “Is the facility part of a designated Cranking Path associated with a Blackstart
Resource identified in a Transmission Operator’s restoration plan.” This language reflects the most
recent revision of the BES Definition and also helps distinguish between generators which have
Blackstart capability and those generators that are designated as a Blackstart Resource in the
Transmission Operator’s restoration plan. It is only the latter that are included in the BES under the
current draft of the definition. (2) A general “catch-all” question should be added that will prompt the
entity submitting an Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following language: Is there

additional information not covered in the questions above that supports the Exception Request? If
yes, please provide the information and explain why it is relevant to the Exception Request. While we
believes the questions set forth in the draft capture the information that generally would be necessary
to determine whether an Exception Request should be granted, it is foreseeable that there may be
unusual circumstances where the information called for either does not capture the full picture or
where studies other than the specific types called for in the draft form support the Exception. An
entity seeking an Exception should have the opportunity to present any information it believes is
relevant.
Yes
DEC agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, DEC believes the SDT has provided a reasonable check list that will work in most
cases to elicit necessary information from the entity submitting an Exception Request. With the added
language suggested in our answers to the previous questions, we believe the proposed form will serve

its intended purpose of ensuring that decisions regarding Exception Requests are based upon
consistent information and are consistent with the requirements of the Federal Power Act and the BES
Definition as developed by the Standards Drafting Team. We also support the Standards Drafting
Team’s determination to abandon its initial approach to technical criteria, which would have required
adherence to specific numerical thresholds. We agree that this approach was not workable on a
nationwide basis, and that the approach embodied in the current draft of the Technical Principles,
which would require specific kinds of information on a generic basis but would leave engineering
judgment about the significance of that information to the relevant RE, is more workable and provides
appropriate deference to the experience and judgment of the Registered Entities.
Individual
Bryan Case
Fall River Electric Cooperative (FALL)
Yes
The Fall River Rural Electric Cooperative (FALL) agrees generally that the General Instructions set
forth the basic information that would be necessary to support an Exception Request. We are
concerned, however, that the statement “diagram(s) supplied should also show the Protection
Systems at the interface points associated with the Elements for which the exception is being
requested” may be subject to differing interpretations. We envision that at least four different kinds of
documents could be responsive to the description: one-line diagrams with breakers and switches
(status); identification of relays by their ANSI device numbers; details of the DC control logic for ANSI
devices; and, operational scheme descriptions of the type used by system operators. Accordingly, we
suggest that the language be refined to identify the specific kinds of diagrams necessary to identify
protection systems at the interface with the Elements for which the Exception is sought, including any
required details. WE suggest that a generic example of a completed form be available to the industry
to help ensure that Exception Requests are supported by consistent and complete information. Such a
generic example could be addressed in the Phase 2 BES efforts.
No
FALL agrees that the checklist of items on pages two and three lists most of the information that
would be necessary to determine if an Exceptions Request is justified. We suggest two modifications
to the proposed language to ensure consistency with the BES Definition and to provide an entity
seeking an Exception with the opportunity to submit all relevant information: (1) We suggest
modifying question 6 to “Is the facility part of a designated Cranking Path associated with a Blackstart
Resource identified in a Transmission Operator’s restoration plan.” This language reflects the most
recent revision of the BES Definition and also helps distinguish between generators which have
Blackstart capability and those generators that are designated as a Blackstart Resource in the
Transmission Operator’s restoration plan. It is only the latter that are included in the BES under the
current draft of the definition. (2) A general “catch-all” question should be added that will prompt the
entity submitting an Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following language: Is there
additional information not covered in the questions above that supports the Exception Request? If
yes, please provide the information and explain why it is relevant to the Exception Request. While we
believes the questions set forth in the draft capture the information that generally would be necessary
to determine whether an Exception Request should be granted, it is foreseeable that there may be
unusual circumstances where the information called for either does not capture the full picture or
where studies other than the specific types called for in the draft form support the Exception. An
entity seeking an Exception should have the opportunity to present any information it believes is
relevant.
Yes
FALL agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the

interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, FALL believes the SDT has provided a reasonable check list that will work in
most cases to elicit necessary information from the entity submitting an Exception Request. With the
added language suggested in our answers to the previous questions, we believe the proposed form
will serve its intended purpose of ensuring that decisions regarding Exception Requests are based
upon consistent information and are consistent with the requirements of the Federal Power Act and
the BES Definition as developed by the Standards Drafting Team. We also support the Standards
Drafting Team’s determination to abandon its initial approach to technical criteria, which would have
required adherence to specific numerical thresholds. We agree that this approach was not workable
on a nationwide basis, and that the approach embodied in the current draft of the Technical
Principles, which would require specific kinds of information on a generic basis but would leave
engineering judgment about the significance of that information to the relevant RE, is more workable
and provides appropriate deference to the experience and judgment of the Registered Entities.
Individual
Rick Crinklaw
Lane Electric Cooperative (LEC)
Yes
The Lane Electric Cooperative (LEC) agrees generally that the General Instructions set forth the basic
information that would be necessary to support an Exception Request. We are concerned, however,
that the statement “diagram(s) supplied should also show the Protection Systems at the interface

points associated with the Elements for which the exception is being requested” may be subject to
differing interpretations. We envision that at least four different kinds of documents could be
responsive to the description: one-line diagrams with breakers and switches (status); identification of
relays by their ANSI device numbers; details of the DC control logic for ANSI devices; and,
operational scheme descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to identify protection
systems at the interface with the Elements for which the Exception is sought, including any required
details. WE suggest that a generic example of a completed form be available to the industry to help
ensure that Exception Requests are supported by consistent and complete information. Such a generic
example could be addressed in the Phase 2 BES efforts.
No
LEC agrees that the checklist of items on pages two and three lists most of the information that would
be necessary to determine if an Exceptions Request is justified. We suggest two modifications to the
proposed language to ensure consistency with the BES Definition and to provide an entity seeking an
Exception with the opportunity to submit all relevant information: (1) We suggest modifying question
6 to “Is the facility part of a designated Cranking Path associated with a Blackstart Resource identified
in a Transmission Operator’s restoration plan.” This language reflects the most recent revision of the
BES Definition and also helps distinguish between generators which have Blackstart capability and
those generators that are designated as a Blackstart Resource in the Transmission Operator’s
restoration plan. It is only the latter that are included in the BES under the current draft of the
definition. (2) A general “catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the Exception that is not
captured in the other questions. We suggest the following language: Is there additional information
not covered in the questions above that supports the Exception Request? If yes, please provide the
information and explain why it is relevant to the Exception Request. While we believes the questions
set forth in the draft capture the information that generally would be necessary to determine whether
an Exception Request should be granted, it is foreseeable that there may be unusual circumstances
where the information called for either does not capture the full picture or where studies other than
the specific types called for in the draft form support the Exception. An entity seeking an Exception
should have the opportunity to present any information it believes is relevant.
Yes
LEC agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than

the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, LEC believes the SDT has provided a reasonable check list that will work in most
cases to elicit necessary information from the entity submitting an Exception Request. With the added
language suggested in our answers to the previous questions, we believe the proposed form will serve
its intended purpose of ensuring that decisions regarding Exception Requests are based upon
consistent information and are consistent with the requirements of the Federal Power Act and the BES
Definition as developed by the Standards Drafting Team. We also support the Standards Drafting
Team’s determination to abandon its initial approach to technical criteria, which would have required
adherence to specific numerical thresholds. We agree that this approach was not workable on a
nationwide basis, and that the approach embodied in the current draft of the Technical Principles,
which would require specific kinds of information on a generic basis but would leave engineering
judgment about the significance of that information to the relevant RE, is more workable and provides
appropriate deference to the experience and judgment of the Registered Entities.
Individual
Michael Falvo
Independent Electricity System Operator
Yes
Yes
Yes
No
We anticipate that entities will be granted access to the required historical operations records and
modeling data after signing of non-disclosure agreements with the providers of the information.
No
No
Yes
We believe that the SDT proposed approach for exception criteria is reasonable recognizing that one
method/criteria cannot be applicable to everyone and every situation within the ERO foot print.
However, we believe that there is huge gap and lack of any transparency on how the exception
application will be evaluated and processed. We strongly suggest that SDT develop a reference or a
guidance document as part of the RoP that should provide some guidance to Registered Entities,
Regional Entities and the ERO on how an exception application should be processed. The absence of

such guidance will pose a challenge for each entity including the ERO, and may result in discrepancies
amongst Regional Entities. The process may be perceived by registered entities as being nontransparency.
Individual
Michael Henry
Lincoln Electric Cooperative (Lincoln)
Yes
The Lincoln Electric Cooperative (Lincoln) agrees generally that the General Instructions set forth the
basic information that would be necessary to support an Exception Request. We are concerned,
however, that the statement “diagram(s) supplied should also show the Protection Systems at the
interface points associated with the Elements for which the exception is being requested” may be
subject to differing interpretations. We envision that at least four different kinds of documents could
be responsive to the description: one-line diagrams with breakers and switches (status); identification
of relays by their ANSI device numbers; details of the DC control logic for ANSI devices; and,
operational scheme descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to identify protection
systems at the interface with the Elements for which the Exception is sought, including any required
details. WE suggest that a generic example of a completed form be available to the industry to help
ensure that Exception Requests are supported by consistent and complete information. Such a generic
example could be addressed in the Phase 2 BES efforts.
No
LINCOLN agrees that the checklist of items on pages two and three lists most of the information that
would be necessary to determine if an Exceptions Request is justified. We suggest two modifications
to the proposed language to ensure consistency with the BES Definition and to provide an entity
seeking an Exception with the opportunity to submit all relevant information: (1) We suggest
modifying question 6 to “Is the facility part of a designated Cranking Path associated with a Blackstart
Resource identified in a Transmission Operator’s restoration plan.” This language reflects the most
recent revision of the BES Definition and also helps distinguish between generators which have
Blackstart capability and those generators that are designated as a Blackstart Resource in the
Transmission Operator’s restoration plan. It is only the latter that are included in the BES under the
current draft of the definition. (2) A general “catch-all” question should be added that will prompt the
entity submitting an Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following language: Is there
additional information not covered in the questions above that supports the Exception Request? If
yes, please provide the information and explain why it is relevant to the Exception Request. While we
believes the questions set forth in the draft capture the information that generally would be necessary
to determine whether an Exception Request should be granted, it is foreseeable that there may be
unusual circumstances where the information called for either does not capture the full picture or
where studies other than the specific types called for in the draft form support the Exception. An
entity seeking an Exception should have the opportunity to present any information it believes is
relevant.
Yes
LINCOLN agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or

a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, LINCOLN believes the SDT has provided a reasonable check list that will work in
most cases to elicit necessary information from the entity submitting an Exception Request. With the
added language suggested in our answers to the previous questions, we believe the proposed form
will serve its intended purpose of ensuring that decisions regarding Exception Requests are based
upon consistent information and are consistent with the requirements of the Federal Power Act and
the BES Definition as developed by the Standards Drafting Team. We also support the Standards
Drafting Team’s determination to abandon its initial approach to technical criteria, which would have
required adherence to specific numerical thresholds. We agree that this approach was not workable
on a nationwide basis, and that the approach embodied in the current draft of the Technical
Principles, which would require specific kinds of information on a generic basis but would leave
engineering judgment about the significance of that information to the relevant RE, is more workable
and provides appropriate deference to the experience and judgment of the Registered Entities.
Individual
Jon Shelby
Northern Lights Inc. (NLI)
Yes
The Northern Lights (NLI) agrees generally that the General Instructions set forth the basic
information that would be necessary to support an Exception Request. We are concerned, however,
that the statement “diagram(s) supplied should also show the Protection Systems at the interface
points associated with the Elements for which the exception is being requested” may be subject to
differing interpretations. We envision that at least four different kinds of documents could be
responsive to the description: one-line diagrams with breakers and switches (status); identification of
relays by their ANSI device numbers; details of the DC control logic for ANSI devices; and,
operational scheme descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to identify protection

systems at the interface with the Elements for which the Exception is sought, including any required
details. WE suggest that a generic example of a completed form be available to the industry to help
ensure that Exception Requests are supported by consistent and complete information. Such a generic
example could be addressed in the Phase 2 BES efforts.
No
NLI agrees that the checklist of items on pages two and three lists most of the information that would
be necessary to determine if an Exceptions Request is justified. We suggest two modifications to the
proposed language to ensure consistency with the BES Definition and to provide an entity seeking an
Exception with the opportunity to submit all relevant information: (1) We suggest modifying question
6 to “Is the facility part of a designated Cranking Path associated with a Blackstart Resource identified
in a Transmission Operator’s restoration plan.” This language reflects the most recent revision of the
BES Definition and also helps distinguish between generators which have Blackstart capability and
those generators that are designated as a Blackstart Resource in the Transmission Operator’s
restoration plan. It is only the latter that are included in the BES under the current draft of the
definition. (2) A general “catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the Exception that is not
captured in the other questions. We suggest the following language: Is there additional information
not covered in the questions above that supports the Exception Request? If yes, please provide the
information and explain why it is relevant to the Exception Request. While we believes the questions
set forth in the draft capture the information that generally would be necessary to determine whether
an Exception Request should be granted, it is foreseeable that there may be unusual circumstances
where the information called for either does not capture the full picture or where studies other than
the specific types called for in the draft form support the Exception. An entity seeking an Exception
should have the opportunity to present any information it believes is relevant.
Yes
NLI agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine

whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, NLI believes the SDT has provided a reasonable check list that will work in most
cases to elicit necessary information from the entity submitting an Exception Request. With the added
language suggested in our answers to the previous questions, we believe the proposed form will serve
its intended purpose of ensuring that decisions regarding Exception Requests are based upon
consistent information and are consistent with the requirements of the Federal Power Act and the BES
Definition as developed by the Standards Drafting Team. We also support the Standards Drafting
Team’s determination to abandon its initial approach to technical criteria, which would have required
adherence to specific numerical thresholds. We agree that this approach was not workable on a
nationwide basis, and that the approach embodied in the current draft of the Technical Principles,
which would require specific kinds of information on a generic basis but would leave engineering
judgment about the significance of that information to the relevant RE, is more workable and provides
appropriate deference to the experience and judgment of the Registered Entities.
Individual
Ray Ellis
Okanogan County Electric Cooperative (OCEC)
Yes
The Okanogan County Electric Cooperative (OCEC) agrees generally that the General Instructions set
forth the basic information that would be necessary to support an Exception Request. We are
concerned, however, that the statement “diagram(s) supplied should also show the Protection
Systems at the interface points associated with the Elements for which the exception is being
requested” may be subject to differing interpretations. We envision that at least four different kinds of
documents could be responsive to the description: one-line diagrams with breakers and switches
(status); identification of relays by their ANSI device numbers; details of the DC control logic for ANSI
devices; and, operational scheme descriptions of the type used by system operators. Accordingly, we
suggest that the language be refined to identify the specific kinds of diagrams necessary to identify
protection systems at the interface with the Elements for which the Exception is sought, including any
required details. WE suggest that a generic example of a completed form be available to the industry
to help ensure that Exception Requests are supported by consistent and complete information. Such a
generic example could be addressed in the Phase 2 BES efforts.
No
OCEC agrees that the checklist of items on pages two and three lists most of the information that
would be necessary to determine if an Exceptions Request is justified. We suggest two modifications
to the proposed language to ensure consistency with the BES Definition and to provide an entity
seeking an Exception with the opportunity to submit all relevant information: (1) We suggest
modifying question 6 to “Is the facility part of a designated Cranking Path associated with a Blackstart
Resource identified in a Transmission Operator’s restoration plan.” This language reflects the most
recent revision of the BES Definition and also helps distinguish between generators which have
Blackstart capability and those generators that are designated as a Blackstart Resource in the
Transmission Operator’s restoration plan. It is only the latter that are included in the BES under the
current draft of the definition. (2) A general “catch-all” question should be added that will prompt the
entity submitting an Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following language: Is there
additional information not covered in the questions above that supports the Exception Request? If

yes, please provide the information and explain why it is relevant to the Exception Request. While we
believes the questions set forth in the draft capture the information that generally would be necessary
to determine whether an Exception Request should be granted, it is foreseeable that there may be
unusual circumstances where the information called for either does not capture the full picture or
where studies other than the specific types called for in the draft form support the Exception. An
entity seeking an Exception should have the opportunity to present any information it believes is
relevant.
Yes
OCEC agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, OCEC believes the SDT has provided a reasonable check list that will work in
most cases to elicit necessary information from the entity submitting an Exception Request. With the
added language suggested in our answers to the previous questions, we believe the proposed form
will serve its intended purpose of ensuring that decisions regarding Exception Requests are based

upon consistent information and are consistent with the requirements of the Federal Power Act and
the BES Definition as developed by the Standards Drafting Team. We also support the Standards
Drafting Team’s determination to abandon its initial approach to technical criteria, which would have
required adherence to specific numerical thresholds. We agree that this approach was not workable
on a nationwide basis, and that the approach embodied in the current draft of the Technical
Principles, which would require specific kinds of information on a generic basis but would leave
engineering judgment about the significance of that information to the relevant RE, is more workable
and provides appropriate deference to the experience and judgment of the Registered Entities.
Individual
Rick Paschall
Pacific Northwest Generating Cooperative (PNGC)
Yes
The Pacific Northwest Generating Cooperative (PNGC) agrees generally that the General Instructions
set forth the basic information that would be necessary to support an Exception Request. We are
concerned, however, that the statement “diagram(s) supplied should also show the Protection
Systems at the interface points associated with the Elements for which the exception is being
requested” may be subject to differing interpretations. We envision that at least four different kinds of
documents could be responsive to the description: one-line diagrams with breakers and switches
(status); identification of relays by their ANSI device numbers; details of the DC control logic for ANSI
devices; and, operational scheme descriptions of the type used by system operators. Accordingly, we
suggest that the language be refined to identify the specific kinds of diagrams necessary to identify
protection systems at the interface with the Elements for which the Exception is sought, including any
required details. WE suggest that a generic example of a completed form be available to the industry
to help ensure that Exception Requests are supported by consistent and complete information. Such a
generic example could be addressed in the Phase 2 BES efforts.
No
PNGC agrees that the checklist of items on pages two and three lists most of the information that
would be necessary to determine if an Exceptions Request is justified. We suggest two modifications
to the proposed language to ensure consistency with the BES Definition and to provide an entity
seeking an Exception with the opportunity to submit all relevant information: (1) We suggest
modifying question 6 to “Is the facility part of a designated Cranking Path associated with a Blackstart
Resource identified in a Transmission Operator’s restoration plan.” This language reflects the most
recent revision of the BES Definition and also helps distinguish between generators which have
Blackstart capability and those generators that are designated as a Blackstart Resource in the
Transmission Operator’s restoration plan. It is only the latter that are included in the BES under the
current draft of the definition. (2) A general “catch-all” question should be added that will prompt the
entity submitting an Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following language: Is there
additional information not covered in the questions above that supports the Exception Request? If
yes, please provide the information and explain why it is relevant to the Exception Request. While we
believes the questions set forth in the draft capture the information that generally would be necessary
to determine whether an Exception Request should be granted, it is foreseeable that there may be
unusual circumstances where the information called for either does not capture the full picture or
where studies other than the specific types called for in the draft form support the Exception. An
entity seeking an Exception should have the opportunity to present any information it believes is
relevant.
Yes
PNGC agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up

generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, PNGC believes the SDT has provided a reasonable check list that will work in
most cases to elicit necessary information from the entity submitting an Exception Request. With the
added language suggested in our answers to the previous questions, we believe the proposed form
will serve its intended purpose of ensuring that decisions regarding Exception Requests are based
upon consistent information and are consistent with the requirements of the Federal Power Act and
the BES Definition as developed by the Standards Drafting Team. We also support the Standards
Drafting Team’s determination to abandon its initial approach to technical criteria, which would have
required adherence to specific numerical thresholds. We agree that this approach was not workable
on a nationwide basis, and that the approach embodied in the current draft of the Technical
Principles, which would require specific kinds of information on a generic basis but would leave
engineering judgment about the significance of that information to the relevant RE, is more workable
and provides appropriate deference to the experience and judgment of the Registered Entities.
Individual
Heber Carpenter
Raft River Rural Electric Cooperative (RAFT)
Yes
The Raft River Rural Electric Cooperative (RAFT) agrees generally that the General Instructions set
forth the basic information that would be necessary to support an Exception Request. We are
concerned, however, that the statement “diagram(s) supplied should also show the Protection
Systems at the interface points associated with the Elements for which the exception is being

requested” may be subject to differing interpretations. We envision that at least four different kinds of
documents could be responsive to the description: one-line diagrams with breakers and switches
(status); identification of relays by their ANSI device numbers; details of the DC control logic for ANSI
devices; and, operational scheme descriptions of the type used by system operators. Accordingly, we
suggest that the language be refined to identify the specific kinds of diagrams necessary to identify
protection systems at the interface with the Elements for which the Exception is sought, including any
required details. WE suggest that a generic example of a completed form be available to the industry
to help ensure that Exception Requests are supported by consistent and complete information. Such a
generic example could be addressed in the Phase 2 BES efforts.
No
RAFT agrees that the checklist of items on pages two and three lists most of the information that
would be necessary to determine if an Exceptions Request is justified. We suggest two modifications
to the proposed language to ensure consistency with the BES Definition and to provide an entity
seeking an Exception with the opportunity to submit all relevant information: (1) We suggest
modifying question 6 to “Is the facility part of a designated Cranking Path associated with a Blackstart
Resource identified in a Transmission Operator’s restoration plan.” This language reflects the most
recent revision of the BES Definition and also helps distinguish between generators which have
Blackstart capability and those generators that are designated as a Blackstart Resource in the
Transmission Operator’s restoration plan. It is only the latter that are included in the BES under the
current draft of the definition. (2) A general “catch-all” question should be added that will prompt the
entity submitting an Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following language: Is there
additional information not covered in the questions above that supports the Exception Request? If
yes, please provide the information and explain why it is relevant to the Exception Request. While we
believes the questions set forth in the draft capture the information that generally would be necessary
to determine whether an Exception Request should be granted, it is foreseeable that there may be
unusual circumstances where the information called for either does not capture the full picture or
where studies other than the specific types called for in the draft form support the Exception. An
entity seeking an Exception should have the opportunity to present any information it believes is
relevant.
Yes
RAFT agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than

the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, RAFT believes the SDT has provided a reasonable check list that will work in
most cases to elicit necessary information from the entity submitting an Exception Request. With the
added language suggested in our answers to the previous questions, we believe the proposed form
will serve its intended purpose of ensuring that decisions regarding Exception Requests are based
upon consistent information and are consistent with the requirements of the Federal Power Act and
the BES Definition as developed by the Standards Drafting Team. We also support the Standards
Drafting Team’s determination to abandon its initial approach to technical criteria, which would have
required adherence to specific numerical thresholds. We agree that this approach was not workable
on a nationwide basis, and that the approach embodied in the current draft of the Technical
Principles, which would require specific kinds of information on a generic basis but would leave
engineering judgment about the significance of that information to the relevant RE, is more workable
and provides appropriate deference to the experience and judgment of the Registered Entities.
Individual
Steve Eldrige
Umatilla Electric Cooperative
Yes
The Umatilla Electric Cooperative (UEC) agrees generally that the General Instructions set forth the
basic information that would be necessary to support an Exception Request. We are concerned,
however, that the statement “diagram(s) supplied should also show the Protection Systems at the
interface points associated with the Elements for which the exception is being requested” may be
subject to differing interpretations. We envision that at least four different kinds of documents could
be responsive to the description: one-line diagrams with breakers and switches (status); identification
of relays by their ANSI device numbers; details of the DC control logic for ANSI devices; and,
operational scheme descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to identify protection
systems at the interface with the Elements for which the Exception is sought, including any required
details. WE suggest that a generic example of a completed form be available to the industry to help
ensure that Exception Requests are supported by consistent and complete information. Such a generic
example could be addressed in the Phase 2 BES efforts.
No
UEC agrees that the checklist of items on pages two and three lists most of the information that
would be necessary to determine if an Exceptions Request is justified. We suggest two modifications
to the proposed language to ensure consistency with the BES Definition and to provide an entity
seeking an Exception with the opportunity to submit all relevant information: (1) We suggest
modifying question 6 to “Is the facility part of a designated Cranking Path associated with a Blackstart
Resource identified in a Transmission Operator’s restoration plan.” This language reflects the most
recent revision of the BES Definition and also helps distinguish between generators which have

Blackstart capability and those generators that are designated as a Blackstart Resource in the
Transmission Operator’s restoration plan. It is only the latter that are included in the BES under the
current draft of the definition. (2) A general “catch-all” question should be added that will prompt the
entity submitting an Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following language: Is there
additional information not covered in the questions above that supports the Exception Request? If
yes, please provide the information and explain why it is relevant to the Exception Request. While we
believes the questions set forth in the draft capture the information that generally would be necessary
to determine whether an Exception Request should be granted, it is foreseeable that there may be
unusual circumstances where the information called for either does not capture the full picture or
where studies other than the specific types called for in the draft form support the Exception. An
entity seeking an Exception should have the opportunity to present any information it believes is
relevant.
Yes
UEC agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No

No
As a general matter, UEC believes the SDT has provided a reasonable check list that will work in most
cases to elicit necessary information from the entity submitting an Exception Request. With the added
language suggested in our answers to the previous questions, we believe the proposed form will serve
its intended purpose of ensuring that decisions regarding Exception Requests are based upon
consistent information and are consistent with the requirements of the Federal Power Act and the BES
Definition as developed by the Standards Drafting Team. We also support the Standards Drafting
Team’s determination to abandon its initial approach to technical criteria, which would have required
adherence to specific numerical thresholds. We agree that this approach was not workable on a
nationwide basis, and that the approach embodied in the current draft of the Technical Principles,
which would require specific kinds of information on a generic basis but would leave engineering
judgment about the significance of that information to the relevant RE, is more workable and provides
appropriate deference to the experience and judgment of the Registered Entities.
Individual
Marc Farmer
West Oregon Electric Cooperative (WOEC)
Yes
The West Oregon Electric Cooperative (WOEC) agrees generally that the General Instructions set forth
the basic information that would be necessary to support an Exception Request. We are concerned,
however, that the statement “diagram(s) supplied should also show the Protection Systems at the
interface points associated with the Elements for which the exception is being requested” may be
subject to differing interpretations. We envision that at least four different kinds of documents could
be responsive to the description: one-line diagrams with breakers and switches (status); identification
of relays by their ANSI device numbers; details of the DC control logic for ANSI devices; and,
operational scheme descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to identify protection
systems at the interface with the Elements for which the Exception is sought, including any required
details. WE suggest that a generic example of a completed form be available to the industry to help
ensure that Exception Requests are supported by consistent and complete information. Such a generic
example could be addressed in the Phase 2 BES efforts.
No
WOEC agrees that the checklist of items on pages two and three lists most of the information that
would be necessary to determine if an Exceptions Request is justified. We suggest two modifications
to the proposed language to ensure consistency with the BES Definition and to provide an entity
seeking an Exception with the opportunity to submit all relevant information: (1) We suggest
modifying question 6 to “Is the facility part of a designated Cranking Path associated with a Blackstart
Resource identified in a Transmission Operator’s restoration plan.” This language reflects the most
recent revision of the BES Definition and also helps distinguish between generators which have
Blackstart capability and those generators that are designated as a Blackstart Resource in the
Transmission Operator’s restoration plan. It is only the latter that are included in the BES under the
current draft of the definition. (2) A general “catch-all” question should be added that will prompt the
entity submitting an Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following language: Is there
additional information not covered in the questions above that supports the Exception Request? If
yes, please provide the information and explain why it is relevant to the Exception Request. While we
believes the questions set forth in the draft capture the information that generally would be necessary
to determine whether an Exception Request should be granted, it is foreseeable that there may be
unusual circumstances where the information called for either does not capture the full picture or
where studies other than the specific types called for in the draft form support the Exception. An
entity seeking an Exception should have the opportunity to present any information it believes is
relevant.
Yes
WOEC agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)

Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, WOEC believes the SDT has provided a reasonable check list that will work in
most cases to elicit necessary information from the entity submitting an Exception Request. With the
added language suggested in our answers to the previous questions, we believe the proposed form
will serve its intended purpose of ensuring that decisions regarding Exception Requests are based
upon consistent information and are consistent with the requirements of the Federal Power Act and
the BES Definition as developed by the Standards Drafting Team. We also support the Standards
Drafting Team’s determination to abandon its initial approach to technical criteria, which would have
required adherence to specific numerical thresholds. We agree that this approach was not workable
on a nationwide basis, and that the approach embodied in the current draft of the Technical
Principles, which would require specific kinds of information on a generic basis but would leave
engineering judgment about the significance of that information to the relevant RE, is more workable
and provides appropriate deference to the experience and judgment of the Registered Entities.
Individual
Steve Alexanderson
Central Lincoln

Yes
Yes
We note that if Q7 is yes, an entity is asked to provide meter or SCADA data. Evidently the team
assumes the facility in question is existing. We propose that study data could be provided instead for
facilities that are in the planning stage.
Yes
No
No
No
No
Group
David Kiguel
Hydro One Networks Inc.
No
On the posted document, we did not find how an exception application will be assessed by the RE and
NERC. We believe that there is a huge gap and a lack of transparency for all stakeholders on how the
exception application will be evaluated and processed. We strongly suggest that the SDT develop a
reference or a guidance document as part of the RoP that will provide guidance to Registered Entities,
Regional Entities and the ERO on how an exception application would/should be processed.
Yes
We believe that the SDT’s proposed approach for exception criteria is reasonable; recognizing that
one method/criteria can not be applicable to everyone and every situation within the ERO foot print.
See our comment in Q1.
Yes
See comments in Q1.
No
Yes
The general approach, information, data, and assessments proposed seem to be reasonable.
However, guidance is not provided as to how this information may be evaluated in the decision
making process. As such, a reference document should be developed and provide guidance how
applications will be assessed. For example” 1) Does the element(s)? • Would have qualified under one
of the exclusions or inclusions but have marginally different threshold as prescribed in the definition;
• transfer bulk power within (intra) or between (inter) two Balancing Authority Areas; • monitor
facilities included in an Interconnection Reliability Operating Limit (IROL); • are not considered
necessary for the operation of interconnected transmission system under normal conditions,
contingency or prolonged outage conditions. 2) Are System Element(s) located in close electrical
proximity to Load? • Electrical proximity may be a measurement of system impedance between load
centers within the system seeking exception. • Other physical characteristics. 3) Are System Elements
treated as primarily radial in character? • Smaller deviation from the exclusion E1. • This can be
demonstrated by the way the connections to the BES are operated (e.g., the local area is not
operated as part of the BES with disconnection procedures when events occur in the local area to
separate it.) • This can also be demonstrated by the way resources in the local area are treated in
operations, for example, they are not included in a regional dispatch or secured by an ISO/RTO. •
Power flows into the system, but rarely flows out. i. This can be demonstrated through transactional
records or load flow analysis where it is shown that flow out does not occur or occurs only under a
very limited set of conditions and for a limited quantity of energy. a. The limited set of conditions

must clearly state the conditions where power flows out, for example, only under specified
contingency events. b. Transactional records provided must be for the same time specified in the
Exception Rules of Procedure for performing periodic exception self-certifications (presently two
years). c. Power entering the system is not recognized or regularly transported on to some other
system. (This can be demonstrated by operational procedures that restrict use of delivered power to
that system, e.g., the absence of a wheeling agreement or an agreement that generally restricts
wheeling under normal) d. The System Element(s) have a very small Distribution Factor on any other
BES Element(s). • System Elements are not necessary for the operation of interconnected
transmission under normal, contingency or prolonged outage conditions.
No
We believe, and support that RoP exception procedures are adequately dealing with this issue.
Yes
As mentioned above, we strongly suggest and encourage that SDT to develop a reference or a
guidance document that will provide guidance to Registered Entities, Regional Entities and the ERO on
how an exception application should/would be processed.
Group
Chris Higgins
Transmission Reliability Program
Yes
BPA suggests clarifying that the interface point is the point where the entity seeking the exception’s
facility or facilities interconnect(s) to the Bulk Electric System facility. Page 1 states “Supporting
statements for your position from other entities are encouraged.” BPA believes coordination with
affected systems should be required under the exemption process.
No
Regarding #4 on page 2: BPA believes the impact to the over-all reliability of the BES needs to
consider more than just an outage of the facility requesting exclusion. One example is a contingency
outage of a parallel facility that could cause an overload. Item 4 needs to include impacts of either the
outage of the facility, or with the facility in service. BPA believes that the entity requesting an
exception may not have information on impacts of the facility on parallel higher-voltage facilities
because the NERC requirements for data sharing for these types of facilities does not necessarily
include owners and operators of lower voltage systems. The entity requesting an exemption would
likely need to coordinate with affected systems, and this coordination should be required in the
exemption process so that affected systems are aware of the possible exclusion.
Yes
Regarding #1 on page 4: BPA Believes seasonality may need to be considered when comparing the
generator with the most severe single contingency.
Yes
BPA believes the studies discussed in pages 2-4 would likely need to be completed and the required
information supplied by the Transmission Planner/Operator of the Balancing Authority Area since
many of the assumptions regarding performance of the BES to delivery under a variety of operating
conditions is known only to the TP and TOP of the system.
Yes
No
No
Individual
Saurabh Saksena
National Grid
Yes

No
We agree with the information requested on pages 2 and 3, however we would like more clarification
regarding Item 7. When answering what % of the calendar year power flows through the facility into
BES, should this be calculated on an hourly basis? We would also like clarification for Item 7 regarding
the request for SCADA data from the last 2 years to determine the minimum and maximum
magnitude of the power flow out of the facility. What data should be used in situations with new
facilities or in situations or where the system configuration (topology) has changed in such a way that
the power flows in the area have changed, so the last 2 years of SCADA data is no longer relevant
Not Applicable
No
No
No
Yes
We are assuming that "yes" answers on this checklist are not intended to result in automatic rejection
of the application. We think the procedure would benefit from a general statement noting that all
answers taken together will be considered to make clear that no single answer will necessarily be
dispositive of the outcome.
Group
Louis Slade
EMP & NERC Compliance
No
Given that the second sentence in the 1st paragraph of this comment form reads “This same process
would be used by Registered Entities to justify including Elements in the BES that might otherwise be
excluded according to the proposed definition and designations.”, Dominion suggests that the 1st
sentence under General Instructions be revised to read “A one-line breaker diagram identifying the
facility for which the exception (or inclusion) is requested must be supplied with every application.
The diagram(s) supplied should also show the Protection Systems at the interface points associated
with the Elements for which the exception (or inclusion) is being requested.”
Yes
No
The SDT language specifying services acceptable for inclusion in an exclusion request references
ancillary services identified under a Transmission Service Provider’s OATT. However, there is great
variation in the services that have actually been implemented and posted across North America under
those OATTs. There is no consistent description or terminology to characterize those services. In
short, Transmission Providers have been permitted to individualize OATT services to fit regional
market structures and vernacular. For example, PJM’s OATT includes a schedule for Blackstart
Service. The FERC pro-forma tariff does not. ISO-NE’s tariff includes the following ancillary services
(which are performed by the ISO and TSP): • Scheduling, System Control and Dispatch Service •
Energy Imbalance Service • Generator Imbalance Service Therefore, Dominion suggests that the SDT
provide a specific list of ancillary services that would be eligible for exclusion, rather than rely on
OATT references. Examples might include: reactive, voltage control or regulation services, frequency
response and blackstart services. Dominion is also aware that the phrase ” ‘must run” is used in some
RTO/ISO market systems to indicate intent to self-schedule the generator. Dominion suggests that
question 3 be revised to read “Is the generator designated as a “must run” unit by eitherthe
Balancing Authority, Resource Planner or Reliability Coordinator?
Yes
It has been Dominion’s experience that CEII or Code/Standards of Conduct rules may restrict
generation entities (GO/GOP) from obtaining some of the information necessary to perform the
analysis needed to file the “Detailed Information to Support an Exception Request”. Dominion is also
aware that, in some cases, generation entities do not have the technical expertise (transmission

planning, power flow and or stability analysis background) to perform such analysis.
No
Yes
Much of the information necessary to perform the analysis required is restricted either by federal
and/or state Codes/Standards of Conduct and/or CEII prohibitions.
Yes
The Detailed Information to Support an Exception Request form has 2 sections; one for transmission
facilities and another for generation facilities. Yet, the Project 2010-17 Definition of Bulk Electric
System document uses other terms such as real and reactive power resources, dispersed power
producing resources, static or dynamic devices, blackstart resources, radial systems, local networks
(LN), and reactive power devices. Dominion suggests that the Detailed Information to Support an
Exception Request form be revised to conform to the Project 2010-17 Definition of Bulk Electric
System document through either use of some sort of ‘selection’ (checkbox, drop down, write in) or
revision of transmission facilities and generation facilities to be more inclusive.
Group
Bill Middaugh
Bill Middaugh
This question is actually asking two questions; Tri-State’s answers would be No & Yes. There needs to
be a better introduction to what and why the exception is being requested.
Again Yes/No is conflicting in the question. The requested information in#2 is too vague and may be
subjective. If the information in#7 is requested in the planning stage the data would not be available.
What objective criteria would be used to determine the state of the exception request?
Again Yes/No is conflicting in the question. Information requested in #4 is subjective and too vague.
Yes
It may be hard for a GO to get the information requested in #1 or #4.
No
No
Yes
TSGT believes that the proposed “Technical Principles for Demonstrating BES Exceptions Request”
does not clearly define the basis for decisions to exclude or include, which will lead to inconsistent
application by the Regions. We believe that the checklist items for transmission and generation
facilities are appropriate questions that must be answered in considering all requests. However,
without objective criteria defining how to assess the materials submitted, the current methodology
leaves it to each region to develop their own methodology and criteria for evaluating the submittals.
We believe the lack of clarity regarding what studies must be submitted and what must be
demonstrated by the studies submitted will be overly burdensome on the submitting entity and the
Region, as multiple studies may be required for the two to agree that there is sufficient justification
for an exemption request. We believe that additional work is necessary to develop clear, objective
methods and criteria for identifying which facilities may be excluded from or should be included in the
Bulk Electric System. Clear, objective methods and criteria will enable the submitter of requests to
understand what is necessary for submitting an exception request and will provide for consistency
among the regions in their initial assessment and recommendations to the ERO.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
Yes
Yes

Yes
No
No
No
No
Group
David Thorne
Pepco Holdings Inc
No
1)Why must the one-line diagram supplied show the Protection Systems at the interface points
associated with the elements for which the exception is being requested? Since Protection Systems
are not part of the new bright-line BES definition why would their presence, or absence, on the oneline diagram influence the exception process? 2)The third bullet needs additional detail of what is
being requested. The phrase “…key performance measures..” and use of methodologies described in
TPS Standards does not provide sufficient direction needed. (see question #4)
No
1) Why is Item 5 (Question pertaining to whether the facility is used for off-site power to a nuclear
plant) included, since this criteria is not part of the proposed bright-line BES definition. 2) Similarly,
why is Item 6 (Question pertaining to whether the facility is part of a Cranking Path associated with a
Black Start Resource) included, since Black Start Cranking Paths were removed from the latest BES
definition. Both Items 5 and 6 should be removed from the Exception Request Form.
Yes
No
Not all TOs have the capability to perform the power flow and stability analysis on their own,
necessary to meet the exception request. It may be burdensome for the TO to hire a consultant or to
have their affiliated TPL perform the rigorous study/analysis as contained in the TPL standards.
Additional details should be provided as to what part of the TPL standards apply. Should the Affiliated
TPL be required to perform TOs studies for exception requests? If so should that be stated in a related
standard as a requirement?
No
No
No
Individual
Roger Meader
Coos-Curry Electric Coooperative
Yes
The Coos-Curry Electric Cooperative (CCEC) agrees generally that the General Instructions set forth
the basic information that would be necessary to support an Exception Request. We are concerned,
however, that the statement “diagram(s) supplied should also show the Protection Systems at the
interface points associated with the Elements for which the exception is being requested” may be
subject to differing interpretations. We envision that at least four different kinds of documents could
be responsive to the description: one-line diagrams with breakers and switches (status); identification
of relays by their ANSI device numbers; details of the DC control logic for ANSI devices; and,

operational scheme descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to identify protection
systems at the interface with the Elements for which the Exception is sought, including any required
details. WE suggest that a generic example of a completed form be available to the industry to help
ensure that Exception Requests are supported by consistent and complete information. Such a generic
example could be addressed in the Phase 2 BES efforts.
No
CCEC agrees that the checklist of items on pages two and three lists most of the information that
would be necessary to determine if an Exceptions Request is justified. We suggest two modifications
to the proposed language to ensure consistency with the BES Definition and to provide an entity
seeking an Exception with the opportunity to submit all relevant information: (1) We suggest
modifying question 6 to “Is the facility part of a designated Cranking Path associated with a Blackstart
Resource identified in a Transmission Operator’s restoration plan.” This language reflects the most
recent revision of the BES Definition and also helps distinguish between generators which have
Blackstart capability and those generators that are designated as a Blackstart Resource in the
Transmission Operator’s restoration plan. It is only the latter that are included in the BES under the
current draft of the definition. (2) A general “catch-all” question should be added that will prompt the
entity submitting an Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following language: Is there
additional information not covered in the questions above that supports the Exception Request? If
yes, please provide the information and explain why it is relevant to the Exception Request. While we
believes the questions set forth in the draft capture the information that generally would be necessary
to determine whether an Exception Request should be granted, it is foreseeable that there may be
unusual circumstances where the information called for either does not capture the full picture or
where studies other than the specific types called for in the draft form support the Exception. An
entity seeking an Exception should have the opportunity to present any information it believes is
relevant.
Yes
CCEC agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. We suggest three refinements to the questions: (1)
Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter clearly is not. (2) The current draft of the
BES Definition contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, we suggest modifying question 5 by adding “radial, or Local
Network” to the question, so that it would read: “Does the generator use the BES, a radial system, or
a Local Network to deliver its actual or scheduled output, or a portion of its actual or scheduled
output, to Load? (3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an Exception Request for a
generator to submit any information it believes is relevant to the Exception that is not captured in the
previous questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the Registered Entity receiving the Exceptions Request. For example, in order
to answer Question 1 on page 4, regarding the impact of the generator under the most severe single

contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, we believe that certain additional questions
are necessary to elicit all information that may be relevant to an Exceptions Request. As discussed in
our answer to Question 4, we are also concerned that it may be necessary to obtain information that
is in the hands of the relevant Balancing Authority, Transmission Provider, or other entity, and not in
the hands of the entity submitting an Exceptions Request, to develop a complete record upon which a
reasoned decision concerning an Exceptions Request can be based.
No
No
As a general matter, CCEC believes the SDT has provided a reasonable check list that will work in
most cases to elicit necessary information from the entity submitting an Exception Request. With the
added language suggested in our answers to the previous questions, we believe the proposed form
will serve its intended purpose of ensuring that decisions regarding Exception Requests are based
upon consistent information and are consistent with the requirements of the Federal Power Act and
the BES Definition as developed by the Standards Drafting Team. We also support the Standards
Drafting Team’s determination to abandon its initial approach to technical criteria, which would have
required adherence to specific numerical thresholds. We agree that this approach was not workable
on a nationwide basis, and that the approach embodied in the current draft of the Technical
Principles, which would require specific kinds of information on a generic basis but would leave
engineering judgment about the significance of that information to the relevant RE, is more workable
and provides appropriate deference to the experience and judgment of the Registered Entities.
Group
Cynthia S. Bogorad
Transmission Access Policy Study Group (please see www.tapsgroup.org for a list of TAPS' more than
40 members)
Glossary terms should be capitalized throughout the document. Lowercase “facility,” especially,
should not be used. The document should use “Element” instead. The term “interface points,” while
common, may not have a sufficiently common understanding to be used in this context. “Boundaries
of the Element(s) for which the exception is being requested” may express the SDT’s meaning more
clearly.
Question 7 asks, “[d]oes power flow through this facility into the BES?” As in the rest of the
document, the reference should be to an “Element(s),” rather than to a “facility.” In addition, we
suggest that the meaning of power flowing “through” the Element(s) be clarified, consistent with
clarification of the same point in Exclusion E3 of the BES Definition. In TAPS’ comments on the BES
Definition, also submitted today, TAPS suggests that the first sentence of Exclusion E3 be revised to
state: “Power flows only into the LN, that is, at each individual connection at 100 kV or higher, the
pre-contingency flow of power is from outside the LN into the LN for all hours of the previous 2
years.” We propose that Question 7 in the Detailed Information to Support an Exception Requests be
similarly revised: “Does power flow from this facility into the BES, i.e., at any individual connection at
100kV or higher, is the pre-contingency flow of power from the LN to the BES for any hour of the
previous 2 years?”

Group
John P. Hughes

Electricity Consumers Resource Council (ELCON)
No
The exception request form should begin with a question asking if the inclusion was triggered by the
entity responding to an emergency request by the applicable BA, RC or TOP. The entity’s response to
support recovery from an emergency may have resulted in (1) power flows through the entity’s
facility into the BES, and/or (2) power injections to the BES that exceed the 20/75-MVA thresholds.
The entity should not be required to provide detailed data and studies (as described in the “General
Instructions”) if either of those conditions would not have occurred but for an emergency situation.
No
A sub-question should be added to Question 1 asking: (1) Does the generation serve all or a part of
retail customer Load, and (2) If so, the maximum net capacity of each unit injected to the BES during
non-emergency conditions.
Yes
Our “Yes” response is conditioned on the comments to Questions 1 and 2 above.
Yes
It may be necessary that the exception request form explicitly address this potential problem by
allowing the entity seeking an exception to state that for reasons beyond its control it failed to acquire
the necessary data, base case or supporting document to enable completion of the filing.

Individual
Kirit Shah
Ameren
Yes
No
From our perspective, the first question should be “Is the facility connected at 100 kV or above?” The
questions should be reordered. Of the questions listed, question #3 should be #1, and questions #1
should be the last question in this section. Regarding the word “permanent” as it is used to describe
Flowgates, it is suggested that the word “limiting” or “constrained” be used instead.
No
It is suggested that question #2 be deleted and replaced with “Is the generator designated as a
black-start unit in an entity’s restoration plan?”
No
No
No
No
Group
William D Shultz
Southern Company Generation
Yes
In the third bullet under the list of study attributes, it is very important to specifically list the "key
performance indicators of BES reliability". This will assist in pointing the studies to focus on the issues
relevant to determining the signifacance of the exception request.
Yes
We agree with the information being requested.

No
We do not agree completely with the information being requested. For checklist item #2, please
specify what is included in "providing Ancillary Services" for a generator. For #4, can the question
include a measure of evaluating the "most severe system impact"? Can the specific study that is
required to be evaluated be outlined?
Yes
An IPP with no Transmission Planning department may find it very difficult to perform an
interconnection wide base case as required in the general instructions.
No
No
No
Individual
Guy Andrews
Georgia System Operations Corporation
No
: The last half of the first sentence should be changed to “do not have to seek an Exclusion Exception
under the Exception Procedure for the Element(s).” The use of “Element(s)” relates back to that term
at the start of the sentence, and the reference to an “Exclusion Exception” is necessary because an
entity (albeit probably not the Owner), still may choose to seek an Inclusion Exception for such an
Element(s). In the 3rd bullet, the reference should be to TPL standards (plural).
Yes
No
Item 2 asks about “the generator or generator Facility,” but 3, 4 and 5 only refer to the generator.
There is no immediately apparent reason for them to be different. The language in Item 2 seems
preferable.
No
Throughout the document, because it will be part of a larger Exception Request Form, it should, when
possible, use terms consistent with the rest of that form (e.g., “Request” rather than “application”).
Similarly, defined terms (even if only defined in the context of the Request Form in which these
Principles will be used) such as “Exception,” “Request,” “Element” or “Facility” should be capitalized; if
the use of lower case is intended to convey a different meaning than what is defined, another term
should be used to avoid confusion. The Definition and Request Form generally use the term
“Element,” so it is unclear why this document should so consistently use “facility.” For consistency,
“Element(s)” or possibly “Element(s) or Facility” should be used.
Yes
Yes
No
Group
John Bussman
AECI
No
An opening statement of this form should make it clear that, prior to its determination, the Facilities
within scope of this exemption request, remain included or excluded based upon the basic BES
Definition Bright Line criteria Inclusions and Exclusions.

No
There is no basis in this draft Standard for including Item 6). Item 7) does appear appropriate within
the Standard, but the intent of the four check-boxes is ambiguous.
No
Most of these questions appear relevant to the LN concept paper, but irrelevant to this standard's
requirements. The last conditional of Item 5) must always be answered Yes, unless the local-network
is islanded.
No

Group
Janelle Marriott Gill
Tri-State Generation and Transmission Assn., Inc. Energy Management
This question is actually asking two questions; Tri-State’s answers would be No & Yes. There needs to
be a better introduction to what and why the exception is being requested.
Again Yes/No is conflicting in the question. The requested information in#2 is too vague and may be
subjective. If the information in#7 is requested in the planning stage the data would not be available.
What objective criteria would be used to determine the state of the exception request?
Again Yes/No is conflicting in the question. Information requested in#4 is subjective and too vague.
Yes
It may be hard for a GO to get the information requested in #1 or #4.
No
No
Yes
TSGT believes that the proposed “Technical Principles for Demonstrating BES Exceptions Request”
does not clearly define the basis for decisions to exclude or include, which will lead to inconsistent
application by the Regions. We believe that the checklist items for transmission and generation
facilities are appropriate questions that must be answered in considering all requests. However,
without objective criteria defining how to assess the materials submitted, the current methodology
leaves it to each region to develop their own methodology and criteria for evaluating the submittals.
We believe the lack of clarity regarding what studies must be submitted and what must be
demonstrated by the studies submitted will be overly burdensome on the submitting entity and the
Region, as multiple studies may be required for the two to agree that there is sufficient justification
for an exemption request. We believe that additional work is necessary to develop clear, objective
methods and criteria for identifying which facilities may be excluded from or should be included in the
Bulk Electric System. Clear, objective methods and criteria will enable the submitter of requests to
understand what is necessary for submitting an exception request and will provide for consistency
among the regions in their initial assessment and recommendations to the ERO.
Group
William Bush
Holland Board of Public works
Yes
The requirement to base flow studies on an “interconnection-wide base case" is likely to include many
more lines and buses than necessary to model the impact of a facility that is not material to the BES.
Holland BPW request the words “or regional reduction of such a case” be added after
“interconnection-wide base case” to avoid unnecessary expense and detail if a more limited study set
is adequate to demonstrate the lack of material impact of the facility(ies) in question.
Yes

Yes
Yes
On Page 4 Question 1, information on the host Balancing Authority’s most severe single contingency
may not be publically available and therefore difficult or impossible for a smaller entity to obtain.
Even if the data is available, it may not be meaningful in a larger Balancing Authority area such as
within MISO where the most severe contingency may be geographically and electrically remote. A
more readily available and meaningful measure would be a comparison of the generator’s capability
as a percent of the peak load for the local Balancing Authority or sub-Balancing Authority, as
applicable.

Yes
The following revisions should be made to the procedures: 1. The Technical Review Panel (TRP)
provided for in Section 5.3 should not include any staff from the host Regional Entity. 2. The Regional
Entity should be required to include an attestation of a qualified individual or individuals to support
the factual and technical bases for the decision. This is necessary for purposes of establishing a record
in the event of an appeal. If a dispute is appealed, there must be someone at the Regional Entity level
that serves as the witness supporting the Regional Entity decision. Currently, there is no
accountability for the arguments and suppositions put forth by the Regional Entity; no individuals that
stand behind the technical bases proffered in the Regional Entity’s written decision. Requiring a
qualified individual to attest to the facts and technical arguments relied upon in arriving at the
decision will ensure that someone at the Regional Entity level is prepared to take responsibility for
reviewing a decision before it is issued, to stand behind the assertions and conclusions reached by the
Regional Entity, and whom the Submitting Party may cross examine at hearing. 3. A party seeking an
exception should have the right to request a hearing and should not be limited to a paper process. 4.
The procedures should not permit the TRP or the Regional Entity to make a decision based upon
information that is outside of the record placed before it. That is, the TRP and the Regional Entity may
not, on their own, conduct an investigation or seek information independently from what has been
presented to it. If the TRP or the Regional Entity requires additional information, it must be requested
and provided transparently, and the Submitting Party must have an opportunity to comment upon or
challenge that information before the TRP or the Regional Entity relies upon it in any way. This is not
currently happening at the Regional Entity and NERC level – decisions have been made based upon
documents and information that are not part of the record; the information is not shared with the
Submitting Party (the party challenging registration) prior to (or after) a decision is made. 5. Section
5.2.2. should be revised as follows: “Upon Acceptance of the Exception Request, the Regional Entity
and Submitting Party (and Owner, if different) shall confer to establish milestones in order to
complete the substantive review of the Exception Request within six months after Acceptance of the
Exception Request or within an alternative time period under Section 5.0. The Regional Entity and the
Submitting Party (and Owner, if different) shall also discuss whether and to what extent a reduced
compliance burden is appropriate during the review period. At the conclusion of the review period, the
Regional Entity shall issue a notice (in accordance with Sections 5.2.3) stating is Recommendation
that the Exception Request be approved or disapproved.”
Individual
Andrew Gallo
City of Austin dba Austin Energy
Yes
AE agrees generally that the General Instructions set forth the basic information that would be
necessary to support an Exception Request. AE is concerned, however, that the statement
“diagram(s) supplied should also show the Protection Systems at the interface points associated with
the Elements for which the exception is being requested” may be subject to differing interpretations.
AE believes that at least four different kinds of documents would respond to the description: (i) oneline diagrams with breakers and switches (status); (ii) identification of relays by their ANSI device
numbers; (iii) details of the DC control logic for ANSI devices; and, (iv) operational scheme

descriptions of the type used by system operators. Accordingly, we suggest the language be refined
to identify the specific kinds of diagrams necessary to identify protection systems at the interface with
the Elements for which the Exception is sought, including any required details, such as breaker
settings. AE suggests that a generic example of a completed form be available to the industry to help
ensure that Exception Requests are supported by consistent and complete information. Such a generic
example could be addressed in the Phase 2 BES efforts.
No
AE agrees that the checklist of items on pages two and three lists most of the information necessary
to determine if an Exceptions Request is justified. We suggest three modifications to the proposed
language to ensure consistency with Section 215 of the Federal Power Act, with the BES Definition,
and to provide an entity seeking an Exception with the opportunity to submit all relevant information:
(1) AE suggests that a new question be added concerning the function of the facility, which would
read: “Does the facility function as a local distribution facility rather than a Transmission facility? If
yes, please provide a detailed explanation of your answer.” AE makes this suggestion because Section
215(a)(1) of the FPA makes clear that “facilities used in the local distribution of electric energy” are
excluded from the BES (16 U.S.C. § 824o(a)(1)) and the most recent draft of the BES definition
incorporates the same language. AE believes a question to address the function of the Element or
system subject to an Exception Request is necessary to determine whether the Element or system is
“used” in local distribution and thereby to ensure observance of the statutory limit on the BES.
Further, we believe a variety of information may be relevant to determining whether a particular
facility functions as local distribution rather than as part of the BES. For example, if power is not
scheduled across the facility or if capacity on the system is not posted on the relevant OASIS, it is
likely to function as local distribution, not transmission. Similarly, if power enters the system and is
delivered to load within the system rather than moving to load located on another system, its function
is local distribution rather than transmission. AE proposes the language above as an open-ended
question so the entity submitting the Exceptions Request can provide this and any other information it
deems relevant to facility function. (2) AE suggests modifying question 6 to “Is the facility part of a
designated Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan.” This language reflects the most recent revision of the BES Definition and
also helps distinguish between generators which have Blackstart capability and those designated as a
Blackstart Resource in the Transmission Operator’s restoration plan. It is only the latter that are
included in the BES under the current draft of the definition. (3) A general “catch-all” question should
be added that will prompt the entity submitting an Exception Request to submit any information it
believes is relevant to the Exception that is not captured in the other questions. We suggest the
following language: Is there additional information not covered in the questions above that supports
the Exception Request? If yes, please provide the information and explain why it is relevant to the
Exception Request. While AE believes the questions set forth in the draft capture the information that
generally would be necessary to determine whether an Exception Request should be granted, there
may be unusual circumstances where the information either does not capture the full picture or where
studies other than the specific types called for in the draft form support the Exception. An entity
seeking an Exception should have the opportunity to present any information it believes is relevant.
Yes
AE agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information generally necessary to make a reasoned determination concerning
the BES status of a generation facility. AE suggests three refinements to the questions: (1) Modify
Question 2 by adding “necessary for the operation of the interconnected bulk transmission system” to
the end of the question, so it reads: “Is the generator or the generator facility used to provide
Ancillary Services necessary for the operation of the interconnected bulk transmission system?” The
italicized language is necessary to distinguish between a generator that provides, for example,
reactive power or regulating reserves that support operation of the interconnected bulk grid and, for
example, a behind-the-meter generator that provides back-up generation to a specific industrial
facility. The former may be necessary for the reliable operation of the interconnected bulk
transmission system, but the latter is not. (2) The current draft of the BES Definition contains
Exclusions for radials and for Local Networks. To be consistent with these aspects of the revised BES
definition, AE suggests modifying question 5 by adding “radial, or Local Network” to the question, so
that it would read: “Does the generator use the BES, a radial system, or a Local Network to deliver its
actual or scheduled output, or a portion of its actual or scheduled output, to Load?” (3) For reasons

similar to those explained in our response to Question 2, a general “catch-all” question should be
added that will prompt an entity submitting an Exception Request for a generator to submit any
information it believes relevant to the Exception that is not captured in the previous questions. We
suggest the following language: Is there additional information not covered in questions 1 through 5
that supports the Exception Request? If yes, please provide the information and explain why it is
relevant to the Exception Request. This will allow an entity seeking an Exception for a generator to
identify any unusual circumstances or non-standard information that might support its Exception
Request. An entity seeking such an Exception should have the opportunity to present any information
it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the RE receiving the Exceptions Request. For example, in order to answer
Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information necessary to determine whether
the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, AE believes that certain additional questions
are necessary to elicit all information relevant to an Exceptions Request. As discussed in our answer
to Question 4, we are also concerned that it may be necessary to obtain information in the hands of
the relevant Balancing Authority, Transmission Provider or other entity and not in the hands of the
entity submitting an Exceptions Request, to develop a complete record upon which a reasoned
decision concerning an Exceptions Request can be based.
Yes
As discussed in more detail in our response to Question 2, AE believes it is necessary to address the
function of an Element or system subject to an Exceptions Request to determine whether it is a
“facilit[y] used in the local distribution of electric energy” and, therefore, excluded from the BES
under Section 215(a)(1) of the Federal Power Act.
No
As a general matter, AE believes the SDT has provided a reasonable check list that will work in most
cases to elicit necessary information from the entity submitting an Exception Request. With the added
language suggested in our answers to the previous questions, we believe the proposed form will serve
its intended purpose of ensuring that decisions regarding Exception Requests are based upon
consistent information and are consistent with the requirements of the Federal Power Act and the BES
Definition as developed by the Standards Drafting Team. AE also supports the Standards Drafting
Team’s determination to abandon its initial approach to technical criteria, which would have required
adherence to specific numerical thresholds. AE agrees that this approach was not workable on a
nationwide basis, and that the approach embodied in the current draft of the Technical Principles,
which would require specific kinds of information on a generic basis but would leave engineering
judgment about the significance of that information to the relevant RE, is more workable and provides
appropriate deference to the experience and judgment of the REs.
Individual
Andy Pusztai
ATC LLC
No
Since an Exception Request may be for approval to designate identified Element(s) as either excluded
from or included in the BES, the wording of the first sentence should be changed and the request
should clearly indicate (e.g. exclusion/inclusion check boxes) whether the request regards exclusion
or inclusion of the Element(s). Here is some draft wording for consideration: Entities that have
Element(s) that are included under the BES definition and designations, but seek to have them
designated as excluded from the BES or that that have Element(s) that are excluded under the BES
definition and designations, but seek to have them designated as included in the BES should submit

an Exception Request according to the NERC Exception Procedures and provide detailed information to
support the Exception Request as indicated below. In addition, ATC suggests the following clarifying
edit. Entities that have BES Element(s) considered as excluded under the BES definition and
designations, do not have to seek exception for those Elements under the Exception Procedure.
No
ATC proposes the following changes to Item #7: 7a. Are Firm Power Transfers scheduled to flow out
of, or through, this facility into the BES in the operating horizon? [for BES designations applicable to
the operating horizon] Note: The consideration for power flowing into the BES should be based on
normal operating conditions or base case (n-0 contingency analysis), not on historical real-time
telemetry. 7b. Are Firm Power Transfers reserved to flow out of, or through, this facility into the BES
in the planning horizon? [for BES designations applicable to the planning horizon)
Yes
No
No
No
No
Group
David Taylor
David.Taylor@nerc.net
Yes
No
In addition to describing how an outage of the facility under consideration affects the rest of the BES,
the Submitting Entity also should be required to provide an assessment of how outages of BES
facilities affect the facility under consideration. This could be achieved with powerflow studies or
distribution factor analysis.
No
For units designated as must run, the Submitting Entity should be required to describe the reasons for
which the unit has been so designated. We believe the general requirement to provide an appropriate
reference is too vague, and should be appended with “. . . including a description of why the unit has
been designated as must run and if applicable, the contingencies that would result in violation of the
NERC Reliability Standards if the unit was not must run.”
No
No
No
Yes
At a minimum, we believe there are some facilities which should not be excluded from the BES under
any circumstances and a list of such facilities should be documented, including facilities such as (1)
Elements that are relied on in the determination of an Interconnection Reliability Operating Limit
(IROL); (2) Blackstart resources and the designated blackstart Cranking Paths identified in the
Transmission Operator’s restoration plan regardless of voltage, (3) Elements subject to Nuclear Plant
Interface Requirements (NPIRs) as agreed to by a Nuclear Plant Generator Operator and a
Transmission Entity defined in NUC-001, (4) Elements identified as required to comply with a NERC
Reliability Standard by application of criteria defined within the standard (e.g., the test defined in

PRC-023 to identify sub-200 kV Elements to which the standard is applicable), and (5) a generating
unit that is designated as a must run unit to assure reliability of the BES. Also, to make the process of
reviewing exception applications consistent and transparent some high level guidance should be
developed as to how the information provided will be assessed by the Regional Entities and NERC. In
addition to supporting the objectives of consistency and transparency, this also would provide benefit
to entities submitting an exception application by allowing them to understand how the Required
Information will be evaluated.
Individual
David Kahly
Kootenai Electric Cooperative
Yes
KEC agrees generally that the General Instructions set forth the basic information that would be
necessary to support an Exception Request. KEC is concerned, however, that the statement
“diagram(s) supplied should also show the Protection Systems at the interface points associated with
the Elements for which the exception is being requested” may be subject to differing interpretations.
KEC envisions that at least four different kinds of documents would be responsive to the description:
one-line diagrams with breakers and switches (status); identification of relays by their ANSI device
numbers; details of the DC control logic for ANSI devices; and, operational scheme descriptions of the
type used by system operators. Accordingly, we suggest that the language be refined to identify the
specific kinds of diagrams necessary to identify protection systems at the interface with the Elements
for which the Exception is sought, including any required details. KEC suggests that a generic
example of a completed form be provided to the industry to help ensure that Exception Requests are
supported by consistent and complete information. Such a generic example could be addressed in the
Phase 2 BES efforts.
No
KEC agrees that the checklist of items on pages two and three lists most of the information that would
be necessary to determine if an Exceptions Request is justified. We suggest three modifications to the
proposed language to ensure consistency with Section 215 of the Federal Power Act, with the BES
Definition, and to provide an entity seeking an Exception with the opportunity to submit all relevant
information: (1) KEC suggests that a new question should be added concerning the function of the
facility, which would read: “Does the facility function as a local distribution facility rather than a
Transmission facility? If yes, please provide a detailed explanation of your answer.” Section 215(a)(1)
of the FPA makes clear that “facilities used in the local distribution of electric energy” are excluded
from the BES, 16 U.S.C. § 824o(a)(1), and the most recent draft of the BES definition incorporates
the same language. KEC believes a question to address the function of the Element or system subject
to an Exception Request is necessary to determine whether the Element or system is “used” in local
distribution and thereby to ensure that this statutory limit on the BES is observed in the Exceptions
process. Further, we believe a variety of information may be relevant to determining whether a
particular facility functions as local distribution rather than as part of the BES. For example, if power
is not scheduled across the facility or if capacity on the system is not posted on the relevant OASIS, it
is likely to function as local distribution, not transmission. Similarly, if power enters the system and is
delivered to load within the system rather than moving to load located on another system, its function
is local distribution rather than transmission. KEC proposes the language above as an open-ended
question so that the entity submitting the Exceptions Request can provide this and any other
information it deems relevant to facility function. (2) KEC suggests modifying question 6 to “Is the
facility part of a designated Cranking Path associated with a Blackstart Resource identified in a
Transmission Operator’s restoration plan.” This language reflects the most recent revision of the BES
Definition, which removes the reference to “Cranking Paths,” and also helps distinguish between
generators which have Blackstart capability and those generators that are designated as a Blackstart
Resource in the Transmission Operator’s restoration plan. It is only the latter that are included in the
BES under the current draft of the definition. (3) A general “catch-all” question should be added that
will prompt the entity submitting an Exception Request to submit any information it believes is
relevant to the Exception that is not captured in the other questions. We suggest the following
language: Is there additional information not covered in the questions above that supports the
Exception Request? If yes, please provide the information and explain why it is relevant to the
Exception Request. While KEC believes the questions set forth in the draft capture the information
that generally would be necessary to determine whether an Exception Request should be granted, it is

foreseeable that there may be unusual circumstances where the information called for either does not
capture the full picture or where studies other than the specific types called for in the draft form
support the Exception. An entity seeking an Exception should have the opportunity to present any
information it believes is relevant.
Yes
KEC agrees that the items listed on page 4 of the Detailed Information to Support an Exception
Request capture the information that generally would be necessary to make a reasoned determination
concerning the BES status of a generation facility. KEC suggests three refinements to the questions:
(1) Question 2 should be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator or the generator
facility used to provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between a generator that
provides, for example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that provides back-up
generation to a specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter is not. (2) The current draft of the BES
Definition contains Exclusions for radials and for Local Networks. To be consistent with these aspects
of the revised BES definition, KEC suggests modifying question 5 by adding “radial, or Local Network”
to the question, so that it would read: “Does the generator use the BES, a radial system, or a Local
Network to deliver its actual or scheduled output, or a portion of its actual or scheduled output, to
Load? (3) For reasons similar to those explained in our response to Question 2, a general “catch-all”
question should be added that will prompt an entity submitting an Exception Request for a generator
to submit any information it believes is relevant to the Exception that is not captured in the previous
questions. We suggest the following language: Is there additional information not covered in
questions 1 through 5 that supports the Exception Request? If yes, please provide the information
and explain why it is relevant to the Exception Request. This will allow an entity seeking an Exception
for a generator to identify any unusual circumstances or non-standard information that might support
its Exception Request. An entity seeking such an Exception should have the opportunity to present
any information it believes is relevant.
Yes
The Standards Drafting Team should consider whether it is necessary to require entities other than
the entity filing the Exception Request to provide relevant information, either to the entity filing the
Exception Request or to the RE receiving the Exceptions Request. For example, in order to answer
Question 1 on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its Most Severe
Single Contingency (“MSSC”) to the registered entity seeking an Exception. Similarly, the relevant
Transmission Operator or Balancing Authority may have information that is necessary to determine
whether the generator has been designated as reliability-must-run or if it provides ancillary services
supporting reliable operation of the interconnected transmission grid.
Yes
As discussed in our responses to Questions 1 through 3, KEC believes that certain additional
questions are necessary to elicit all information that may be relevant to an Exceptions Request. As
discussed in our answer to Question 4, we are also concerned that it may be necessary to obtain
information that is in the hands of the relevant Balancing Authority, Transmission Provider, or other
entity, and not in the hands of the entity submitting an Exceptions Request, to develop a complete
record upon which a reasoned decision concerning an Exceptions Request can be based.
Yes
As discussed in more detail in our response to Question 2, KEC believes it is necessary to address the
function of an Element or system that is subject to an Exceptions Request to determine whether it is a
“facilit[y] used in the local distribution of electric energy” and therefore excluded from the BES under
Section 215(a)(1) of the Federal Power Act.
No
As a general matter, KEC believes the SDT has provided a reasonable check list that will work in most
cases to elicit necessary information from the entity submitting an Exception Request. With the added
language suggested in our answers to the previous questions, we believe the proposed form will serve
its intended purpose of ensuring that decisions regarding Exception Requests are based upon

consistent information and are consistent with the requirements of the Federal Power Act and the BES
Definition as developed by the Standards Drafting Team. KEC also supports the Standards Drafting
Team’s determination to abandon its initial approach to technical criteria, which would have required
adherence to specific numerical thresholds. KEC agrees that this approach was not workable on a
nationwide basis, and that the approach embodied in the current draft of the Technical Principles,
which would require specific kinds of information on a generic basis but would leave engineering
judgment about the significance of that information to the relevant RE, is more workable and provides
appropriate deference to the experience and judgment of the REs.
Group
Silvia Parada Mitchell
Corporate Responsibility Organization
Yes
Yes
“Impact” and “degree of impact” in question 2 should be framed with the criteria expected.
Yes
No
No
No
No
Group
Sandra Shaffer
PacifiCorp
Yes
No
Question 6 implies that if the facility is part of a designated blackstart cranking path then an
exception request would most likely be denied. To the extent that was the intent, such an assumption
would only be reasonable if the blackstart cranking path is the only path available. However,
PacifiCorp suggests modifying the current Question 6 to reflect a situation in which multiple cranking
paths are available, as follows: “6A. Is the facility part of a Cranking Path associated with a Blackstart
Resource? 6B. If yes, does the Blackstart Resource have other viable Cranking Paths?”
Yes
PacifiCorp suggests modifying Question 3 as follows: “Is the generator designated as a must run unit
by the Balancing Authority?”
No
PacifiCorp is speaking from a perspective where the Company is registered for multiple functions (i.e.,
TO, GO, TOP, GOP, BA, TPL, etc.) and the requested information is currently available from Company
resources.
No
No
No
Individual

Linda Jacobson-Quinn
Farmington Electric Utility System
No
The general instructions presented are primarily components to substantiate an Exception Request.
However, a cover sheet (template) should be created that includes overall identifying information of
the Submitting Entity and the and the Owner if the if they are not the same – the template should
align with the draft Appendix 5C Section 4.5.1 of the NERC Rules of Procedure. An Exception Request
can be submitted for Inclusion or Exclusion of the BES. The first sentence in the form, “Entities that
have Element(s) designated as excluded, under the BES definition and designations, so not have to
seek exception for those Element(s) under the Exception Procedure. This would not be true if a
Submitting Entity is seeking an Inclusion Exception. FEUS recommends revising to include Inclusion
Exception Requests.
No
The form should be titled “For Transmission Elements” rather than “Facilities” to align with the BES
definition and Appendix 5C of the NERC Rules of Procedure. The form should align with section 4.5.1
and 4.5.2 of Appendix 5C. It should include a listing of the Element(s) and the status based on the
application of the BES Definition. Question 6 relates to a ‘facility’ that is part of a Cranking Path. The
latest revision of the BES Definition removed the designated blackstart Cranking Paths from the
Inclusion of the BES in I3. Having a question regarding the Cranking Path in the Exception Request
makes it appear Cranking Paths are still automatically included in the BES. Question 7; what is an
alternate method if a Requesting Entity does not have SCADA data for the most recent two
consecutive calendar years.
No
Question 1, the SDT team should consider if the Submitting Entity or Owner is part of a Reserve
Sharing Group. The host BA’s most single severe Contingency vs the obligation of reserves required
as part of a Reserve Sharing Group may be substantial. The SDT team should clarify if it is a single
generator or if it is the aggregate at a facility.
Yes
See response to question 2
Yes
The SDT should consider additional limits on Generation. For example, if a generation prime mover
(turbine) has a maximum output of 35 MW but is coupled to a generator with a rating in excess of 75
MVA. The generator output is limited by the turbine - thus the rating of the turbine should be a taken
into consideration rather than the generator rating.
No
No
Individual
Mary Downey
City of Redding Electric Utility
Yes
Yes
Yes
Yes
Yes
Yes

Yes
Redding acknowledges there is an immediate need for a method where an entity can present evidence
that their facilities are “not necessary for the Reliable Operation of the interconnected bulk power
transmission system” as stated in the NERC Rules of Procedure Section 3.0. “BASIS FOR APPROVAL
OF AN EXCEPTION.” Without a process to present the evidence then the RE and the ERO are under no
mandate to review facilities in light of any criteria besides the BES definition as NERC clearly pointed
out in the City of Holland case where they were forced to register by the RE (RFC). However, Redding
also is very concerned that under the proposed Exception process the final evaluation of an element
or facility is left to the sole judgment of NERC. The concern is there is no method, criteria,
measurement, or standard that NERC will use for the evaluation. It is also a concern that NERC has a
predetermined definition of Distribution Facilities and will not evaluate networked distribution facilities
fairly. NERC has already stated their predetermined position as to what they determine to be
distribution and not distribution facilities in their “MOTION TO INTERVENE AND COMMENTS OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION” filed in the case of the City of Holland,
Michigan (Docket No. RC11-5-000). On page 10 and 11 of this motion, under the section labeled “A.
Holland’s 138 kV lines are transmission rather that local distribution facilities” NERC states
“Distribution facilities generally are characterized as elements that are designed and can carry electric
energy (Watts/MW) in one direction only at any given time from a single source point (distribution
substation) to final load centers.” NERC clearly states that only radial facilities are considered
distribution facilities and are unwilling to consider that network facilities over 100Kv could be
classified as Distribution Facilities. Holland’s claim of NERC over reaching their authority appears to
have credibility. In conclusion, Redding supports this exception process as it stands because it does
allow an entity the right to a process which NERC is currently not obligated to allow, it requires that
NERC judge the facilities on the merit of “necessary for the Reliable Operation of the interconnected
bulk power transmission system”, and it allows an appeals process that must judge if NERC evaluated
facilities on the standard set forth. However, Redding’s vote is conditional on the completion of phase
2 where the term “necessary for the Reliable Operation of the interconnected bulk power transmission
system” needs to be defined.
Individual
Paul Cummings
City of Redding
Yes
Yes
Yes
No
No
No
Yes
Redding acknowledges there is an immediate need for a method where an entity can present evidence
that their facilities are “not necessary for the Reliable Operation of the interconnected bulk power
transmission system” as stated in the NERC Rules of Procedure Section 3.0. “BASIS FOR APPROVAL
OF AN EXCEPTION.” Without a process to present the evidence then the RE and the ERO are under no
mandate to review facilities in light of any criteria besides the BES definition as NERC clearly pointed
out in the City of Holland case where Holland was forced to register by the RE (RFC). However,
Redding is very concerned that under the proposed Exception process the final evaluation of an
element or facility is left to the sole judgment of NERC. The concern is there is no method, criteria,
measurement, or standard that NERC will use for the evaluation. It is also a concern that NERC has a

predetermined definition of Distribution Facilities and will not evaluate networked Distribution
Facilities fairly. NERC has already stated their predetermined position as to what they determine to be
distribution and not distribution facilities in their “MOTION TO INTERVENE AND COMMENTS OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION” filed in the case of the City of Holland,
Michigan (Docket No. RC11-5-000). On page 10 and 11 of this motion, under the section labeled “A.
Holland’s 138 kV lines are transmission rather that local distribution facilities” NERC states
“Distribution facilities generally are characterized as elements that are designed and can carry electric
energy (Watts/MW) in one direction only at any given time from a single source point (distribution
substation) to final load centers.” NERC has clearly stated that only radial facilities are considered
distribution facilities and were unwilling to consider that network facilities over 100Kv could be
classified as Distribution Facilities in this case. Holland’s claim of NERC over-reaching their authority
appears to have credibility. In conclusion, Redding supports the proposed exception process as it
stands on the grounds that it allows an entity the right to a process which NERC is currently not
obligated to allow, it requires that NERC judge the facilities on the merit of “necessary for the Reliable
Operation of the interconnected bulk power transmission system”, and it allows an appeals process
that must judge if NERC evaluated facilities on the standard set forth. However, Redding’s vote is
conditional on the completion of phase 2 where the term “necessary for the Reliable Operation of the
interconnected bulk power transmission system” needs to be defined.
Individual
Edwin Tso
Metropolitan Water District of Southern California
No
General Comments: Metropolitan Water District of Southern California (“MWDSC”) believes that
additional work is necessary to explain how this Detailed Information to Support an Exception
Request will be used in evaluating whether a transmission facility will be an exception to the BES. In
addition, MWDSC agrees WECC that the proposed Technical Principles for Demonstrating BES
Exceptions Request is lack of clarity. It does not provide detail information as to what entities must
provide to support their requests, nor does it provide any criteria for consistency among regions in
their assessment of requests. Lastly, the current proposal leaves it to each region to develop its own
methodology and criteria for evaluating the technical studies. MWDSC believes that drafting team
should establish a common method and criteria to apply continent-wide in achieving uniformity and
consistency among regions in their assessment of exception requests. Comments to Checklist #4:
MWDSC recommends the following changes to emphasize facility impact on the interconnection of the
BES: “How does an outage of the facility impact the over-all reliability of to the interconnection of the
BES?” Comments to Checklist #7: What percentage of power flow through entity’s facility into the
BES will be considered as an exception to the BES?

Group
Al DiCaprio
PJM
Yes
No
We agree with most parts on P.2 and P.3, but question the need for Q6, which asks: “Is the facility
part of a Cranking Path associated with a Blackstart Resource?” I3 in the BES definition stipulates that
Blackstart Resources identified in the Transmission Operator’s restoration plan be included (which we
disagree and commented in the BES Definition Comment Form). There is no inclusion of any
transmission facilities that are part of the cranking path. We suggest this item (Q6) be removed.
We do not agree with the detailed information requirements for generators. In a deregulated

environment, generators are free to bid into the market or offer their availability, to dispatched based
on bid price and resource needs, or overall generation dispatch plans. A generator may be on line but
not dispatched, or not on line at all due to maintenance outage or a decision to not start. Its status
and generation level have little to do in determining whether or not it needs to be included as a BES
facility. Rather, it is the generator’s active contribution to the BES performance, namely, its protective
relay setting and coordination with those of related facilities and its ability to control voltage, respond
to contingencies, ride through frequency and voltage excursion, provide accurate model with
verification, etc., are critical to BES reliability performance. There are currently no standards or
requirements that mandate a generator to be on line or to attain a specific level of output, and we do
not see such a need at all in the future. Whether or not the unit is designed as a MUST RUN will
depend on whether the generator is (a) on line and bid into the market or be included in the dispatch
plan, and (b) the prevailing system conditions such as flow pattern, potential constraints, etc. A
generator may be designated as a MUST RUN one day but not the others. Similar argument applies to
a generator bidding in the ancillary service markets, or be dispatched to provide reserve or AGC
control capability. In our view, generators’ physical characteristics and their response to changes on
the BES are important considerations for them to be included in the BES. These characteristics affect
the assessment and actual performance of the BES in the following key areas: • Voltage and
frequency ride through capability • Voltage control (AVR, etc.) • Underfrequency trip setting •
Protection relay setting coordination • Data submission for modeling; verification of capability and
model We therefore suggest that the entire P.4 be removed as the information it asks for has nothing
to do with a generator’s physical characteristics or material impact on BES reliability. Having a
threshold by MVA suffices to determine if a generator needs to be included as a BES facility, whose
characteristics, expected performance and data provision are important to achieve target BES
performance and hence should be governed by reliability standards.
No
Yes
One acid test to determine if a facility needs to be included or can be excluded from a BES facility is
to simulate an uncleared fault at that facility. If the simulation shows a stable BES performance, then
it suggests that even if the fault is not cleared due to whatever reason, the facility has no adverse
impact that can lead to instability, cascading or collapse of the BES.

Individual
Rex Roehl
Indeck Energy Services

Yes
As acknowledged in the response to Question 12 comments on the previous BES definition, the BES
definition is expansive compared to the definition of the BPS in the FPA Section 215. The inclusion of
the limited Exclusions is an attempt to remedy the situation. However, the Exclusions need to include
a fifth one that if, based on studies or other assessments, it can be shown that any tranmission or
generator element otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There has never been
a study to show that elements, such as a 20 MW wind farm, 60 MW merchant generator (which
operates infrequently in the depressed market) in a large BA (eg NYISO) or a radial transmission line
connecting a small generator are important to the reliability of the BPS. They are covered by the
mandatory standards program through the registration criteria. The BES Definition is the opportunity
to permit an entity to demonstrate that an element is unimportant to reliability of the BPS. The SDT
has identified a small subset of elements that it is willing to exclude. By their very nature, these
exclusions dim the bright line that is the stated goal of this project. However, the SDT’s foresight
seems limited in its selections. Analytical studies are used to evaluate contingencies that could lead to

the Big Three (cascading outages, instability or voltage collapse). Such a study showing that a
transmission or generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable Disturbance of
approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW merchant generator or numerous
other smaller facilities would be bounded by larger contingencies. It would take more than six 60 MW
merchant generators with close location and common mode failure to even be a Reportable
Disturbance, much less become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 Any facility that can be demonstrated to the Regional Entity by analytical study or other assessment
to be unimportant to the reliability of the BPS (with periodic reports by the Regional Entity to NERC of
any such assessments).”
Yes
As acknowledged in the response to Question 12 comments on the previous BES definition, the BES
definition is expansive compared to the definition of the BPS in the FPA Section 215. The inclusion of
the limited Exclusions is an attempt to remedy the situation. However, the Exclusions need to include
a fifth one that if, based on studies or other assessments, it can be shown that any tranmission or
generator element otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There has never been
a study to show that elements, such as a 20 MW wind farm, 60 MW merchant generator (which
operates infrequently in the depressed market) in a large BA (eg NYISO) or a radial transmission line
connecting a small generator are important to the reliability of the BPS. They are covered by the
mandatory standards program through the registration criteria. The BES Definition is the opportunity
to permit an entity to demonstrate that an element is unimportant to reliability of the BPS. The SDT
has identified a small subset of elements that it is willing to exclude. By their very nature, these
exclusions dim the bright line that is the stated goal of this project. However, the SDT’s foresight
seems limited in its selections. Analytical studies are used to evaluate contingencies that could lead to
the Big Three (cascading outages, instability or voltage collapse). Such a study showing that a
transmission or generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable Disturbance of
approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW merchant generator or numerous
other smaller facilities would be bounded by larger contingencies. It would take more than six 60 MW
merchant generators with close location and common mode failure to even be a Reportable
Disturbance, much less become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 Any facility that can be demonstrated to the Regional Entity by analytical study or other assessment
to be unimportant to the reliability of the BPS (with periodic reports by the Regional Entity to NERC of
any such assessments).”
Yes
As acknowledged in the response to Question 12 comments on the previous BES definition, the BES
definition is expansive compared to the definition of the BPS in the FPA Section 215. The inclusion of
the limited Exclusions is an attempt to remedy the situation. However, the Exclusions need to include
a fifth one that if, based on studies or other assessments, it can be shown that any tranmission or
generator element otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There has never been
a study to show that elements, such as a 20 MW wind farm, 60 MW merchant generator (which
operates infrequently in the depressed market) in a large BA (eg NYISO) or a radial transmission line
connecting a small generator are important to the reliability of the BPS. They are covered by the
mandatory standards program through the registration criteria. The BES Definition is the opportunity
to permit an entity to demonstrate that an element is unimportant to reliability of the BPS. The SDT
has identified a small subset of elements that it is willing to exclude. By their very nature, these
exclusions dim the bright line that is the stated goal of this project. However, the SDT’s foresight
seems limited in its selections. Analytical studies are used to evaluate contingencies that could lead to
the Big Three (cascading outages, instability or voltage collapse). Such a study showing that a
transmission or generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable Disturbance of
approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW merchant generator or numerous
other smaller facilities would be bounded by larger contingencies. It would take more than six 60 MW
merchant generators with close location and common mode failure to even be a Reportable
Disturbance, much less become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 -

Any facility that can be demonstrated to the Regional Entity by analytical study or other assessment
to be unimportant to the reliability of the BPS (with periodic reports by the Regional Entity to NERC of
any such assessments).”
Individual
Keith Morisette
Tacoma Power
Yes
Tacoma Power supports the instructions as written.
Yes
Tacoma Power supports the information requested on page 2 and 3.
Yes
Tacoma Power supports the information requested on page 4.
No
Tacoma Power supports the expectation that entities will be able to supply the information requested.
No
Tacoma Power does not know of any characteristics to add at this time.
No
Tacoma Power is not aware of any conflicts at this time.
Yes
Tacoma Power has a concern that the form may be too general in nature. The task before NERC and
the industry is to promote consistency in the application of the BES definition. The form will require
the regions to develop individual criteria for assessing an exception request and making a
recommendation on the request. We recommend in Phase 2 that the SDT develop specific evaluation
criteria for the regions to apply to an exception request. Thank you for consideration of our
comments.
Individual
Tracy Richardson
Springfield Utility Board
Yes
SUB agrees with the instructions, finding them to be clear and reasonable.
Yes
SUB agrees with the instructions, finding them to be clear and reasonable.
No SUB comments as this is not currently applicable to SUB operations.
No

No

Individual
Frank Cumpton
BGE
Yes
No comment.
Yes
No comment.
Yes
No comment.
No

No comment.
No
No comment.
No
No comment.
No
No comment.
Individual
Gary Carlson
Michigan Public Power Agency
Yes
The requirement to base flow studies on an “interconnection-wide base case" is likely to include many
more lines and buses than necessary to model the impact of a facility that is not material to the BES.
MPPA and its members request the words “or regional reduction of such a case” be added after
“interconnection-wide base case” to avoid unnecessary expense and detail if a more limited study set
is adequate to demonstrate the lack of material impact of the facility(ies) in question.
Yes
Yes
Yes
On Page 4 Question 1, information on the host Balancing Authority’s most severe single contingency
may not be publically available and therefore difficult or impossible for a smaller entity to obtain.
Even if the data is available, it may not be meaningful in a larger Balancing Authority area such as
within MISO where the most severe contingency may be geographically and electrically remote. A
more readily available and meaningful measure would be a comparison of the generator’s capability
as a percent of the peak load for the local Balancing Authority or sub-Balancing Authority, as
applicable.
No
No
Yes
The following revisions should be made to the procedures: 1. The Technical Review Panel (TRP)
provided for in Section 5.3 should not include any staff from the host Regional Entity. 2. The Regional
Entity should be required to include an attestation of a qualified individual or individuals to support
the factual and technical bases for the decision. This is necessary for purposes of establishing a record
in the event of an appeal. If a dispute is appealed, there must be someone at the Regional Entity level
that serves as the witness supporting the Regional Entity decision. Currently, there is no
accountability for the arguments and suppositions put forth by the Regional Entity; no individuals that
stand behind the technical bases proffered in the Regional Entity’s written decision. Requiring a
qualified individual to attest to the facts and technical arguments relied upon in arriving at the
decision will ensure that someone at the Regional Entity level is prepared to take responsibility for
reviewing a decision before it is issued, to stand behind the assertions and conclusions reached by the
Regional Entity, and whom the Submitting Party may cross examine at hearing. 3. A party seeking an
exception should have the right to request a hearing and should not be limited to a paper process. 4.
The procedures should not permit the TRP or the Regional Entity to make a decision based upon
information that is outside of the record placed before it. That is, the TRP and the Regional Entity may
not, on their own, conduct an investigation or seek information independently from what has been
presented to it. If the TRP or the Regional Entity requires additional information, it must be requested
and provided transparently, and the Submitting Party must have an opportunity to comment upon or
challenge that information before the TRP or the Regional Entity relies upon it in any way. This is not
currently happening at the Regional Entity and NERC level – decisions have been made based upon

documents and information that are not part of the record; the information is not shared with the
Submitting Party (the party challenging registration) prior to (or after) a decision is made. 5. Section
5.2.2. should be revised as follows: “Upon Acceptance of the Exception Request, the Regional Entity
and Submitting Party (and Owner, if different) shall confer to establish milestones in order to
complete the substantive review of the Exception Request within six months after Acceptance of the
Exception Request or within an alternative time period under Section 5.0. The Regional Entity and the
Submitting Party (and Owner, if different) shall also discuss whether and to what extent a reduced
compliance burden is appropriate during the review period. At the conclusion of the review period, the
Regional Entity shall issue a notice (in accordance with Sections 5.2.3) stating is Recommendation
that the Exception Request be approved or disapproved.”

Additional Comments Submitted: Salt River Project

Consideration of Comments on Initial Ballot
Project 2010-17 BES Technical Exceptions
Date of Initial Ballot: September 30 – October 10, 2011

Summary Consideration: Many commenters followed instructions and cast their ballot while simply pointing to their detailed comments in the
posted comment report. The SDT thanks those commenters as this greatly reduces the administrative workload on the SDT. Those who decided
to place comments in the ballot report for the most part echoed comments that had already been seen by the SDT in the posted comment
report which was administered first by the SDT. As a result, there were no changes to the definition due to comments received in the ballot
report. However, for ease of reference, the changes to the definition made as a result of those comments are repeated here.
The SDT made the following changes to the request form due to industry comments received:
• General – Clarified the use of facility versus Element(s).
• Page 1 – Deleted ‘s’ : List any attached supporting documents and any additional information that is included to supports the request:
• Generation - Q1. Replaced ‘generator’s or generator’s facility’ with ‘generation resource’: What is the MW value of the host Balancing
Authority’s most severe single Contingency and what is the generator’s, or generator facility’s generation resource’s, percent of this
value?
• Generation - Q2. Replaced ‘generator’s or generator’s facility’ with ‘generation resource’: Is the generator or generator facility
generation resource used to provide reliability- related Ancillary Services?
• Generation - Q3. Replaced ‘generator’s or generator’s facility’ with ‘generation resource’: Is the generator generation resource
designated as a must run unit for reliability?
The SDT feels that it is important to remind the industry that Phase II of this project will begin immediately after the conclusion of Phase I as SDT
resources clear up. The same SDT will follow through with Phase II.
The SDT is recommending that this project be moved forward to the recirculation ballot stage.
There were two comments that were repeated multiple times throughout the various documents. The first topic was about how to sort through
the definition inclusions and exclusions, i.e., which takes precedence. The SDT offers this guidance on that issue:

The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast majority
of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and non-BES
Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or higher as included in
the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed. Element is defined in the NERC
Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker, bus
section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application of the
‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific criteria to provide for
a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion language
is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the exclusion
language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The exclusion (E1) only
speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner.
Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and supersedes
inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected transmission
network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude an Element.
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

2

The second item is about providing specific guidance on how the information on the exception request form will be used in making decisions on
inclusions/exclusions in the exception process. The SDT provides the following information on this item:
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like nothing
better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and an initial
attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could have come
up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the commenters that it
directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the Regional
Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the
proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to
remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or
disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis for
what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be supplied
for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making their
decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

3

reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric system
thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a
sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the technical
prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests will result
in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a submitting
entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their
submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious
consideration in this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Herb
Schrayshuen, at 404-446-2560 or at herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Standards Processes Manual: http://www.nerc.com/docs/standards/sc/Standard_Processes_Manual_Approved_May_2010.pdf.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

4

Voter
Kirit Shah

Entity
Ameren
Services

Segment
1

Vote
Negative

Comment
Please refer to Ameren comments submitted using the Comment Form.

Andrew Z
Pusztai

American
Transmission
Company, LLC
Arizona Public
Service Co.

1

Negative

Comments submitted.

1

Negative

Comments submitted

1

Negative

comments posted on comment form

1

Negative

comments submitted for both BES ballots

1

Negative

See Con Edison’s comments on the Technical Principles submitted separately by
electronic survey form.

Michael S
Crowley

Associated
Electric
Cooperative,
Inc.
Bonneville
Power
Administration
Consolidated
Edison Co. of
New York
Dominion
Virginia Power

1

Negative

Please see Dominion’s submitted comments

Bernard
Pelletier

Hydro-Quebec
TransEnergie

1

Negative

Please see our comments on the Technical Information to Support BES Exception.

Chris W Bolick

Associated
Electric
Cooperative,
Inc.
Southwest
Power Pool,
Inc.

3

Negative

Please see comments of Associated Electric Cooperative

2

Negative

2

Negative

SPP's comments on this concurrent ballot/comment period have been submitted
and provide support for our Negative vote. In addition, SPP is a member of the IRC
SRC and is in support of those comments on this standard. Please refer to these
sets of comments for our recommendations.
please refer to detailed comments submitted for this project.

Robert Smith
John Bussman

Donald S.
Watkins
Christopher L
de Graffenried

Charles Yeung

Kathleen
Goodman

ISO New
England, Inc.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

5

Voter
Tracy Sliman

Rebecca
Berdahl
Andrew Gallo

Peter T Yost

Richard
Blumenstock
Michael F.
Gildea
Janelle
Marriott
David Frank
Ronk
Francis J.
Halpin
Jeanie Doty

Wilket (Jack)
Ng

Entity
Tri-State G & T
Association,
Inc.
Bonneville
Power
Administration
City of Austin
dba Austin
Energy
Consolidated
Edison Co. of
New York
Consumers
Energy
Dominion
Resources
Services
Tri-State G & T
Association,
Inc.
Consumers
Energy
Bonneville
Power
Administration
City of Austin
dba Austin
Energy
Consolidated
Edison Co. of
New York

Segment
1

Vote
Negative

Comment
Comments submitted on electronic form.

3

Negative

Please see BPA's responses on the comment form submitted seperately.

3

Negative

Austin Energy (AE) has submitted detailed comments on this issue through its
official Comment document. Please refer to those comments.

3

Negative

Con Edison comments have been submitted separately.

3

Negative

See Consumers Energy's comments on the official submittal form.

3

Negative

See Dominin's submitted comments.

3

Negative

Tri-State G&T Load Serving Entity comments were submitted through the formal
electronic comment process.

4

Negative

See Comments of Consumers Energy Company

5

Negative

Please see BPA's responses on the comment form submitted seperately.

5

Negative

Austin Energy (AE) has submitted detailed comments on this issue through its
official Comment document. Please refer to those comments.

5

Negative

See Con Edison’s comments on the Technical Principles submitted separately by
electronic survey form.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

6

Voter
David C
Greyerbiehl

Entity
Consumers
Energy
Company
Dominion
Resources, Inc.

Segment
5

Vote
Negative

Comment
See Consumers Energy's comments on the official comment submittal forms.

5

Negative

See comments filed on this project.

Dan
Roethemeyer

Dynegy Inc.

5

Negative

Comments to be submitted with the SERC OC Standards Review Group.

Christopher
Schneider

MidAmerican
Energy Co.

5

Negative

Mahmood Z.
Safi

Omaha Public
Power District

5

Negative

See the MidAmerican submitted comments. The BES definition needs additional
specific inclusion or exclusion provisions that clearly exclude variable resource
generation collector circuits rated below 100 kV and generators less than 20 MVA
connected to those collector circuits in accordance with the registration criteria.
See Doug Peterchuck’s comments

Glen Reeves

Salt River
Project

5

Negative

See comments submitted

Brenda S.
Anderson

Bonneville
Power
Administration
City of Austin
dba Austin
Energy
Consolidated
Edison Co. of
New York
Dominion
Resources, Inc.

6

Negative

Please see BPA's responses on the comment form submitted seperately.

6

Negative

Austin Energy (AE) has submitted detailed comments on this issue through its
official Comment document. Please refer to those comments.

6

Negative

Con Edison comments have been submitted separately.

6

Negative

See comments submitted by Dominion.

10

Negative

Comments Submitted

Mike Garton

Lisa L Martin

Nickesha P
Carrol
Louis S. Slade
Steven L.
Rueckert

Western
Electricity
Coordinating
Council

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

7

Voter
Ajay Garg

Entity
Hydro One
Networks, Inc.

Segment
1

Anthony E
Jablonski

ReliabilityFirst
Corporation

10

Guy V. Zito

Northeast
Power
Coordinating
Council, Inc.
Central Lincoln
PUD

10

Affirmative NPCC will be submitting comments on behalf of our members through the formal
comment process along with suggestions to address those comments.

9

Affirmative I support the additional comments prepared by Steve Alexanderson of Central
Lincoln PUD

Pacific
Northwest
Generating
Cooperative
FirstEnergy
Solutions

8

Affirmative Please see PNGC's separate comment form.

6

Florida
Municipal
Power Agency
Florida
Municipal
Power Pool
Southern
Company
Generation
AEP Marketing

6

Affirmative FirstEnergy supports the proposed technical information to support BES
exceptions and offers comments and suggestions through the formal comment
period.
Affirmative Please see comments submitted through the formal comments

6

Affirmative See FMPA's comments

5

Affirmative Comments from Southern Company Generation are being submitted via the
electronic comment form found on the project page.

6

Affirmative Comments are being submitted via electronic form by Thad Ness on behalf of
American Electric Power.

Bruce Lovelin
Margaret Ryan

Kevin Querry

Richard L.
Montgomery
Thomas
Washburn
William D
Shultz
Edward P. Cox

Vote
Negative

Comment
After careful analysis of the proposed documents, Hydro One Networks Inc. is
casting a negative vote. We commend the SDT for the effort in facing the
challenge. However, we believe that the proposed definition and the exception
request criteria still need further work. Some issues need to be resolved before a
final approval is granted. Please see our detailed comments as provided in the online system.
Affirmative Comments submitted

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

8

Voter
Gary Carlson

Entity
Michigan
Public Power
Agency
Florida
Municipal
Power Agency
Lakeland
Electric

Segment
5

Vote
Affirmative Comments submitted separately

5

Affirmative Please see comments submitted through the formal comments

5

Affirmative Refer to comments from FMPA.

Brock Ondayko

AEP Service
Corp.

5

Affirmative Comments are being submitted via electronic form by Thad Ness on behalf of
American Electric Power.

Aleka K Scott

Pacific
Northwest
Generating
Cooperative
Ohio Edison
Company

4

Affirmative Please see PNGC's separate comment form.

4

David
Schumann
James M
Howard

Douglas
Hohlbaugh

Comment

Georgia
System
Operations
Corporation
Madison Gas
and Electric
Co.
Illinois
Municipal
Electric Agency

4

Affirmative FirstEnergy supports the proposed technical information to support BES
exceptions and offers comments and suggestions through the formal comment
period.
Affirmative See electronic comment form submitted by Georgia System Operations Corp

4

Affirmative Please see the MRO NSRF comments concerning this project.

4

Shamus J
Gamache

Central Lincoln
PUD

4

Affirmative Illinois Municipal Electric Agency (IMEA) appreciates the SDT’s diligence in
developing technical inforamtion to support the BES Exception process. With its
Affirmative vote, IMEA supports and recommends comments submitted by the
Transmission Access Policy Study Group.
Affirmative See Central Lincoln PUD comments (CLPUD) Posted by Steve Alexanderson.

John Allen

City Utilities of
Springfield,

4

Affirmative City Utilities of Springfield, Missouri supports the comments from SPP.

Guy Andrews

Joseph
DePoorter
Bob C. Thomas

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

9

Voter

Frank Gaffney

Steve Eldrige

Marc Farmer

Ian S Grant

Jon Shelby
Ray Ellis

John S Bos

Rick Crinklaw

Michael Henry

Stephan Kern

Entity
Missouri

Segment

Florida
Municipal
Power Agency
Umatilla
Electric
Cooperative
West Oregon
Electric
Cooperative,
Inc.
Tennessee
Valley
Authority
Northern
Lights Inc.

4

Affirmative Please see comments submitted through the formal comments

3

Affirmative Please see UEC's separate comment form.

3

Affirmative Please see WOEC's separate comment form.

3

Affirmative My company has submitted comments via the comment form.

3

Affirmative Please see NLI's separate comment form.

3

Affirmative Please see Okanogan's separate comment form.

3

Affirmative MPW agrees with the comments submitted by the MRO NERC Standards Review
Forum (NSRF)

3

Affirmative Please see LEC's separate comment form.

3

Affirmative Please see Lincoln's separate comment form.

3

Affirmative FirstEnergy supports the proposed technical information to support BES
exceptions and offers comments and suggestions through the formal comment

Okanogan
County Electric
Cooperative,
Inc.
Muscatine
Power &
Water
Lane Electric
Cooperative,
Inc.
Lincoln Electric
Cooperative,
Inc.
FirstEnergy
Energy

Vote

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

Comment

10

Voter

Joe McKinney

William N.
Phinney

William Bush

Dave Sabala

Bryan Case

Dave Hagen

Entity
Delivery

Segment

Vote

Comment

Florida
Municipal
Power Agency
Georgia
Systems
Operations
Corporation
Holland Board
of Public
Works
Douglas
Electric
Cooperative
Fall River Rural
Electric
Cooperative
Clearwater
Power Co.

3

Affirmative Please see comments submitted through the formal comments

3

Affirmative See electronic comment form from Georgia System Operations Corporation

3

Affirmative Please see Holland Board of Public Works' comment form.

3

Affirmative Please see DEC's separate comment form.

3

Affirmative Please see FREC's separate comment form.

3

Affirmative Please see Clearwater's separate comment form.

period.

Roman Gillen

Consumers
Power Inc.

3

Affirmative Please see CPI's separate comment form.

Roger Meader

Coos-Curry
Electric
Cooperative,
Inc
Central Lincoln
PUD

3

Affirmative Please see CCEC's separate comment form.

3

Affirmative Comments previously submitted.

Steve
Alexanderson
Dave Markham

Central Electric 3
Cooperative,
Inc. (Redmond,
Oregon)

Affirmative Please see Central's separate comment form.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

11

Voter
Bud Tracy

Entity
Blachly-Lane
Electric Co-op

Segment
3

Vote
Comment
Affirmative Please see BLEC's separate comment form.

Rich Salgo

Sierra Pacific
Power Co.

1

Affirmative Comments Submitted

Electric
Reliability
Council of
Texas, Inc.
David Thorne
Potomac
Electric Power
Co.
Richard Burt
Minnkota
Power Coop.
Inc.
Gordon Pietsch Great River
Energy

2

Affirmative ERCOT ISO has joined the IRC SRC comments submitted.

1

Affirmative Comments submitted

1

Affirmative While MPC is voting affirmative, we ask that you see the comments submitted by
the MRO NERC Standards Review Forum (NSRF).

1

Affirmative Please see MRO NSRF comments

William J Smith FirstEnergy
Corp.

1

Paul B.
Johnson

American
Electric Power

1

Affirmative FirstEnergy supports the proposed technical information to support BES
exceptions and offers comments and suggestions through the formal comment
period.
Affirmative Comments are being submitted via electronic form by Thad Ness on behalf of
American Electric Power.

Stuart Sloan

Consumers
Power Inc.

1

Charles B
Manning

Affirmative Please see CPI's separate comment form.

Response: The SDT thanks you for following the instructions with regard to comments. This greatly reduces the administrative burden for the
SDT and will help accelerate the process.
Paul Morland

Colorado
Springs
Utilities

1

Negative

Colorado Springs Utilities believes that the proposed Technical Information to
Support BES Exceptions Request does not provide the necessary clarity as to what
applying entities must provide to support their request. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. We believe the lack of clarity
regarding what studies must be submitted and what must be demonstrated by the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

12

Voter

Entity

Segment

Vote

Comment
studies submitted will be overly burdensome on our staff. We believe that
additional work is necessary to develop clear, objective methods and criteria for
identifying which facilities may be excluded from or should be included in the Bulk
Electric System. Clear, objective methods and criteria will enable us to understand
what is necessary for submitting an exception request.
To allow sufficient time to complete this difficult task, we believe that the Detailed
Information to Support BES Exceptions Request should not be part of the Phase 1
Bulk Electric System Definition effort, but should be postponed and included in the
Phase 2 effort.
Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and
an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could
have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the
commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive
comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the
Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of
the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of
the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting
or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis
for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

13

Voter
Entity
Segment
Vote
Comment
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making
their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric
system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the
technical prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests
will result in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
The SDT is required to submit the exception process as part of the revised definition on January 25, 2012 as specified in Order743.
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

14

Voter
Martyn Turner

Entity
Lower
Colorado River
Authority

Segment
1

Vote
Negative

Comment
1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support these
changes or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments. Yes: X No:
Comments:
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: No: X Comments: LCRA TSC supports the inclusion of transformers (with both
the primary and secondary windings operated at 100-kV or higher) in the BES
definition; however, additional clarification is suggested. The term transformers
needs to be further defined with respect to function (auto transformers, phase
angle regulators, generator step-up transformers, etc.). Similarly, a separate
definition for “Transformer” could be developed and included in the NERC
Glossary of Terms.
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: No: X Comments:
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: X No: Comments:
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: No: X Comments: LCRA TSC suggests consistency between this inclusion
criteria and the criteria used in I2 for “generation”.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

15

Voter

Entity

Segment

Vote

Comment
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: No: X Comments: This inclusion conflicts with exclusion E4. Which one takes
priority?
7. The SDT has revised the specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E1 (radial system)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: No: X Comments: The current wording is unclear with respect to the
treatment of normally open switching devices. LCRA TSC suggests the following
language to replace the existing language on the note to E1: “Two radial systems
connected by a normally open, manually operated switching device, as depicted
on prints or one-line diagrams for example, may be considered as radial systems
under this exclusion.” The current wording is unclear with respect to “non-retail
generation”. The sudden loss of large, radial-supplied load may result in reliability
deficiencies. LCRA TSC suggests stating a load level or a load capacity in the
exclusion.
8. The SDT has revised the specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel that
alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: No: X Comments:
9. The SDT has revised the specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E3 (local network)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: X No: Comments:
10. The SDT has added specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E4 (reactive resources)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

16

Voter

Comment
Yes: No: X Comments: This exclusion conflicts with inclusion item I5. Which one
takes priority?
11. Are there any other concerns with this definition that haven’t been covered in
previous questions and comments remembering that the exception criteria are
posted separately for comment? Yes: X No: Comments: LCRA TSC supports the
direction the standards drafting team taking with this project on the BES Definition
and encourages further clarification as noted in these comments for proper
application.
Response: The SDT directs LCRA to the detailed responses in the regular comment form as these comments are identical to those contained
there.
Greg C. Parent

Entity

Manitoba
Hydro

Segment

3

Vote

Negative

Manitoba Hydro strongly disagrees with the proposed ‘Detailed Information to
Support an Exception Request’ document and associated exception process for the
following reasons: -It is not clear what elements or situations beyond what is
covered in the core definition and associated inclusions and exclusions that the
drafting team is hoping to capture through the exception process. Further, it is
unclear what the benefit to reliability would be by allowing an impact based
exception process given that entities will be extremely unlikely to use the
exception process to include elements in the BES. -The exception process will be
extremely resource intensive, particularly in the absence of any Industry approved
threshold criteria. The costs to properly administer and monitor the process to
ensure that impact based modeling is done accurately and that it captures the
frequent changes on a dynamic system will occupy a wealth of Industry, NERC and
Regional Entity time to the detriment of reliability. -It is not reasonable for industry
to approve the exception process without knowing what thresholds are required
to demonstrate an element as being part of the BES or not. We are concerned that
BES determinations would be subjective and would vary from case to case with the
particular staff examining the request. BES elements should be established and
agreed upon by Industry, not set by a NERC panel. We understand that the drafting
team has made this change in the interests of time, but the impact of the BES
definition is too broad for this project to be rushed. -The 2010-17 project goals to
increase the clarity of the BES definition and establish a ‘bright-line’ are
compromised by the exception process. Changes and alterations to the BES

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

17

Voter

S N Fernando

Entity

Manitoba
Hydro

Segment

5

Vote

Negative

Comment
definition should be approved by Industry through the Standards Under
Development Process. An interpretation request or SAR should be developed by an
entity if they feel that the core definition and associated exceptions and inclusions
should be modified. We ask that NERC requests that FERC re-examines the
directive to develop an exception process given that the BES definition, which
already includes a list of exceptions, is sufficient to standalone without an
associated exception process.
Manitoba Hydro strongly disagrees with the proposed ‘Detailed Information to
Support an Exception Request’ document and associated exception process for the
following reasons: -It is not clear what elements or situations beyond what is
covered in the core definition and associated inclusions and exclusions that the
drafting team is hoping to capture through the exception process. Further, it is
unclear what the benefit to reliability would be by allowing an impact based
exception process given that entities will be extremely unlikely to use the
exception process to include elements in the BES. -The exception process will be
extremely resource intensive, particularly in the absence of any Industry approved
threshold criteria. The costs to properly administer and monitor the process to
ensure that impact based modeling is done accurately and that it captures the
frequent changes on a dynamic system will occupy a wealth of Industry, NERC and
Regional Entity time to the detriment of reliability. -It is not reasonable for industry
to approve the exception process without knowing what thresholds are required
to demonstrate an element as being part of the BES or not. We are concerned that
BES determinations would be subjective and would vary from case to case with the
particular staff examining the request. BES elements should be established and
agreed upon by Industry, not set by a NERC panel. We understand that the drafting
team has made this change in the interests of time, but the impact of the BES
definition is too broad for this project to be rushed. -The 2010-17 project goals to
increase the clarity of the BES definition and establish a ‘bright-line’ are
compromised by the exception process. Changes and alterations to the BES
definition should be approved by Industry through the Standards Under
Development Process. An interpretation request or SAR should be developed by an
entity if they feel that the core definition and associated exceptions and inclusions
should be modified. We ask that NERC requests that FERC re-examines the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

18

Voter

Daniel Prowse

Entity

Manitoba
Hydro

Segment

6

Vote

Negative

Comment
directive to develop an exception process given that the BES definition, which
already includes a list of exceptions, is sufficient to standalone without an
associated exception process.
Manitoba Hydro strongly disagrees with the proposed ‘Detailed Information to
Support an Exception Request’ document and associated exception process for the
following reasons: -It is not clear what elements or situations beyond what is
covered in the core definition and associated inclusions and exclusions that the
drafting team is hoping to capture through the exception process. Further, it is
unclear what the benefit to reliability would be by allowing an impact based
exception process given that entities will be extremely unlikely to use the
exception process to include elements in the BES. -The exception process will be
extremely resource intensive, particularly in the absence of any Industry approved
threshold criteria. The costs to properly administer and monitor the process to
ensure that impact based modeling is done accurately and that it captures the
frequent changes on a dynamic system will occupy a wealth of Industry, NERC and
Regional Entity time to the detriment of reliability. -It is not reasonable for industry
to approve the exception process without knowing what thresholds are required
to demonstrate an element as being part of the BES or not. We are concerned that
BES determinations would be subjective and would vary from case to case with the
particular staff examining the request. BES elements should be established and
agreed upon by Industry, not set by a NERC panel. We understand that the drafting
team has made this change in the interests of time, but the impact of the BES
definition is too broad for this project to be rushed. -The 2010-17 project goals to
increase the clarity of the BES definition and establish a ‘bright-line’ are
compromised by the exception process. Changes and alterations to the BES
definition should be approved by Industry through the Standards Under
Development Process. An interpretation request or SAR should be developed by an
entity if they feel that the core definition and associated exceptions and inclusions
should be modified. We ask that NERC requests that FERC re-examines the
directive to develop an exception process given that the BES definition, which
already includes a list of exceptions, is sufficient to standalone without an
associated exception process.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

19

Voter
Joe D Petaski

Entity
Manitoba
Hydro

Segment
1

Vote
Negative

Danny Dees

MEAG Power

1

Negative

Comment
Manitoba Hydro strongly disagrees with the proposed ‘Detailed Information to
Support an Exception Request’ document and associated exception process for the
following reasons: -It is not clear what elements or situations beyond what is
covered in the core definition and associated inclusions and exclusions that the
drafting team is hoping to capture through the exception process.
Further, it is unclear what the benefit to reliability would be by allowing an impact
based exception process given that entities will be extremely unlikely to use the
exception process to include elements in the BES. -The exception process will be
extremely resource intensive, particularly in the absence of any Industry approved
threshold criteria. The costs to properly administer and monitor the process to
ensure that impact based modeling is done accurately and that it captures the
frequent changes on a dynamic system will occupy a wealth of Industry, NERC and
Regional Entity time to the detriment of reliability. -It is not reasonable for industry
to approve the exception process without knowing what thresholds are required
to demonstrate an element as being part of the BES or not. We are concerned that
BES determinations would be subjective and would vary from case to case with the
particular staff examining the request. BES elements should be established and
agreed upon by Industry, not set by a NERC panel. We understand that the drafting
team has made this change in the interests of time, but the impact of the BES
definition is too broad for this project to be rushed. -The 2010-17 project goals to
increase the clarity of the BES definition and establish a ‘bright-line’ are
compromised by the exception process. Changes and alterations to the BES
definition should be approved by Industry through the Standards Under
Development Process. An interpretation request or SAR should be developed by an
entity if they feel that the core definition and associated exceptions and inclusions
should be modified. We ask that NERC requests that FERC re-examines the
directive to develop an exception process given that the BES definition, which
already includes a list of exceptions, is sufficient to standalone without an
associated exception process.
We believe that the proposed Technical Principles for Demonstrating BES
Exceptions Request does not provide the necessary clarity as to what applying
entities must provide to support their request, nor does it provide any criteria for
consistency among regions in their assessment of requests. We believe that the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

20

Voter

Ernest Hahn

Entity

Metropolitan
Water District
of Southern
California

Segment

1

Vote

Negative

Comment
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective
criteria defining what must be submitted and how to assess the materials
submitted, the current methodology leaves it to each region to develop their own
methodology and criteria for evaluating the submittals. We believe the lack of
clarity regarding what studies must be submitted and what must be demonstrated
by the studies submitted will be overly burdensome on the submitting entity and
the Region, as multiple studies may be required for the two to agree that there is
sufficient justification for an exemption request. We believe that additional work is
necessary to develop clear, objective methods and criteria for identifying which
facilities may be excluded from or should be included in the Bulk Electric System.
Clear, objective methods and criteria will enable the submitter of requests to
understand what is necessary for submitting an exception request and will provide
for consistency among the regions in their initial assessment and
recommendations to the ERO. We believe that a Yes vote for the Technical
Principles for Demonstrating BES Exceptions Request will result in minimal or no
changes to today’s process under the current definition which includes the
language “as defined by the Regional Reliability Organization.” While the proposed
Technical Principles for Demonstrating BES Exceptions Request includes a checklist
that must be submitted with exception requests, a yes vote will still require each
region to develop their own methods and criteria for assessing materials
submitted with exemption requests. We believe that a No vote with guidance to
the drafting team that objective methods and criteria must be developed and
applied continent-wide will result in the desired uniformity and consistency among
regions in their assessment of exception requests. To allow sufficient time to
complete this difficult task, we believe that the Detailed Information to Support
BES Exceptions Request should not be part of the Phase 1 Bulk Electric System
Definition effort, but should be postponed and included in the Phase 2 effort.
MWDSC supports WECC's comments that proposed Technical Information to
Support BES Exceptions does not provide the necessary clarity, nor does it provide
any criteria for consistency among regions. This detail should be postponed and
included in the Phase 2 SAR effort.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

21

Voter
Kevin Smith

Entity
Balancing
Authority of
Northern
California

Segment
1

Vote
Negative

Terry L Baker

Platte River
Power
Authority

3

Negative

Roland Thiel

Platte River
Power
Authority

5

Negative

Comment
We believe that additional work is necessary to develop clear, objective methods
and criteria for identifying which facilities may be excluded from or should be
included in the Bulk Electric System. Clear, objective methods and criteria will
enable the submitter of requests to understand what is necessary for submitting
an exception request and will provide for consistency among the regions in their
initial assessment and recommendations to the ERO.
Platte River believes that a Yes vote for the Technical Principles for Demonstrating
BES Exceptions Request will result in minimal changes to today’s process under the
current definition which includes the language “as defined by the Regional
Reliability Organization.” While the proposed Technical Principles for
Demonstrating BES Exceptions Request includes a checklist that must be submitted
with exception requests, a yes vote will still require each region to develop their
own methods and criteria for assessing materials submitted with exemption
requests. We believe that a No vote with guidance to the drafting team that
objective methods and criteria must be developed and applied continent-wide will
result in the desired uniformity and consistency among regions in their assessment
of exception requests.
Definition of BES Platte River believes that the SDT has made substantial progress
towards a clear and workable definition of the BES. Although Platte River ballots
“Negative” we strongly support the approach to defining the Bulk Electric System
as proposed here. Platte River recognizes that, given the deadlines imposed by
FERC in Order No. 743, it will not be possible for the SDT to conduct a technical
analysis within the time available. Accordingly, Platte River agrees with the
approach taken by the SDT, which is to propose a Phase II of the standards
development process that would address the generator threshold level and other
issues. However, it is our opinion that the second draft would benefit from further
clarification or modification. That said, Platte River is prepared to support the BES
definition as proposed by the SDT going forward. Platte River has taken the
opportunity to provide this industry feedback, as it is our understanding that we
will be afforded another ballot opportunity. If this were to be our sole occasion to
ballot, we would vote “Affirmative” at this time. We are encouraged by the work
that has been completed and we commend the SDT for their commitment and
extensive work thus far. Detailed Information to Support BES Exceptions Requests

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

22

Voter

Entity

Segment

Vote

Carol
Ballantine

Platte River
Power
Authority

6

Negative

John C. Collins

Platte River
Power
Authority

1

Negative

Comment
Platte River believes that a Yes vote for the Technical Principles for Demonstrating
BES Exceptions Request will result in minimal changes to today’s process under the
current definition which includes the language “as defined by the Regional
Reliability Organization.” While the proposed Technical Principles for
Demonstrating BES Exceptions Request includes a checklist that must be submitted
with exception requests, a yes vote will still require each region to develop their
own methods and criteria for assessing materials submitted with exemption
requests. We believe that a No vote with guidance to the drafting team that
objective methods and criteria must be developed and applied continent-wide will
result in the desired uniformity and consistency among regions in their assessment
of exception requests.
Platte River believes that a Yes vote for the Technical Principles for Demonstrating
BES Exceptions Request will result in minimal changes to today’s process under the
current definition which includes the language “as defined by the Regional
Reliability Organization.” While the proposed Technical Principles for
Demonstrating BES Exceptions Request includes a checklist that must be submitted
with exception requests, a yes vote will still require each region to develop their
own methods and criteria for assessing materials submitted with exemption
requests. We believe that a No vote with guidance to the drafting team that
objective methods and criteria must be developed and applied continent-wide will
result in the desired uniformity and consistency among regions in their assessment
of exception requests.
Platte River believes that a Yes vote for the Technical Principles for Demonstrating
BES Exceptions Request will result in minimal changes to today’s process under the
current definition which includes the language “as defined by the Regional
Reliability Organization.” While the proposed Technical Principles for
Demonstrating BES Exceptions Request includes a checklist that must be submitted
with exception requests, a yes vote will still require each region to develop their
own methods and criteria for assessing materials submitted with exemption
requests. We believe that a No vote with guidance to the drafting team that
objective methods and criteria must be developed and applied continent-wide will
result in the desired uniformity and consistency among regions in their assessment
of exception requests.

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

23

Voter
Dana
Wheelock

Entity
Seattle City
Light

Segment
3

Vote
Negative

Hao Li

Seattle City
Light

4

Negative

Comment
Comments: Seattle City Light (SCL) believes that the SDT has made substantial
progress towards a clear and workable definition of the BES. Although SCL ballots
“Negative” we agree with and strongly support the Technical Exceptions Principles
as a concept. However, SCL finds that the Principles as written do not provide the
necessary clarity as what applying entities must provide to support their request,
nor do they provide adequate criteria for consistency among regions in their
assessment of requests. SCL recommends the development of objective methods
and criteria for identifying which facilities may be excluded from or included in the
BES. SCL also recommends the development of one or more examples that
illustrate what studies must be submitted and what must be documented as part
of an exception request. SCL recognizes that, given the deadlines imposed by FERC
in Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address issues such as the exception process. SCL has taken the opportunity
to provide this industry feedback, as it is our understanding that we will be
afforded another ballot opportunity. If this were to be our sole occasion to ballot,
we would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far. SCL is prepared to support the BES Exception process as proposed
by the SDT going forward.
Comments: Seattle City Light (SCL) believes that the SDT has made substantial
progress towards a clear and workable definition of the BES. Although SCL ballots
“Negative” we agree with and strongly support the Technical Exceptions Principles
as a concept. However, SCL finds that the Principles as written do not provide the
necessary clarity as what applying entities must provide to support their request,
nor do they provide adequate criteria for consistency among regions in their
assessment of requests. SCL recommends the development of objective methods
and criteria for identifying which facilities may be excluded from or included in the
BES. SCL also recommends the development of one or more examples that
illustrate what studies must be submitted and what must be documented as part
of an exception request. SCL recognizes that, given the deadlines imposed by FERC
in Order No. 743, it will not be possible for the SDT to conduct a technical analysis

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

24

Voter

Entity

Segment

Vote

Michael J.
Haynes

Seattle City
Light

5

Negative

Dennis Sismaet

Seattle City
Light

6

Negative

Comment
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address issues such as the exception process. SCL has taken the opportunity
to provide this industry feedback, as it is our understanding that we will be
afforded another ballot opportunity. If this were to be our sole occasion to ballot,
we would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far. SCL is prepared to support the BES Exception process as proposed
by the SDT going forward.
Comments: Seattle City Light (SCL) believes that the SDT has made substantial
progress towards a clear and workable definition of the BES. Although SCL ballots
“Negative” we agree with and strongly support the Technical Exceptions Principles
as a concept. However, SCL finds that the Principles as written do not provide the
necessary clarity as what applying entities must provide to support their request,
nor do they provide adequate criteria for consistency among regions in their
assessment of requests. SCL recommends the development of objective methods
and criteria for identifying which facilities may be excluded from or included in the
BES. SCL also recommends the development of one or more examples that
illustrate what studies must be submitted and what must be documented as part
of an exception request. SCL recognizes that, given the deadlines imposed by FERC
in Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address issues such as the exception process. SCL has taken the opportunity
to provide this industry feedback, as it is our understanding that we will be
afforded another ballot opportunity. If this were to be our sole occasion to ballot,
we would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far. SCL is prepared to support the BES Exception process as proposed
by the SDT going forward.
Comments: Seattle City Light (SCL) believes that the SDT has made substantial
progress towards a clear and workable definition of the BES. Although SCL ballots
“Negative” we agree with and strongly support the Technical Exceptions Principles

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

25

Voter

Pawel Krupa

Entity

Seattle City
Light

Segment

1

Vote

Negative

Comment
as a concept. However, SCL finds that the Principles as written do not provide the
necessary clarity as what applying entities must provide to support their request,
nor do they provide adequate criteria for consistency among regions in their
assessment of requests. SCL recommends the development of objective methods
and criteria for identifying which facilities may be excluded from or included in the
BES. SCL also recommends the development of one or more examples that
illustrate what studies must be submitted and what must be documented as part
of an exception request. SCL recognizes that, given the deadlines imposed by FERC
in Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address issues such as the exception process. SCL has taken the opportunity
to provide this industry feedback, as it is our understanding that we will be
afforded another ballot opportunity. If this were to be our sole occasion to ballot,
we would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far. SCL is prepared to support the BES Exception process as proposed
by the SDT going forward.
Comments: Seattle City Light (SCL) believes that the SDT has made substantial
progress towards a clear and workable definition of the BES. Although SCL ballots
“Negative” we agree with and strongly support the Technical Exceptions Principles
as a concept. However, SCL finds that the Principles as written do not provide the
necessary clarity as what applying entities must provide to support their request,
nor do they provide adequate criteria for consistency among regions in their
assessment of requests. SCL recommends the development of objective methods
and criteria for identifying which facilities may be excluded from or included in the
BES. SCL also recommends the development of one or more examples that
illustrate what studies must be submitted and what must be documented as part
of an exception request. SCL recognizes that, given the deadlines imposed by FERC
in Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address issues such as the exception process. SCL has taken the opportunity

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

26

Voter

Entity

Segment

Vote

Tim Kelley

Sacramento
Municipal
Utility District

1

Negative

Richard K Vine

California ISO

2

Negative

Barbara
Independent
Constantinescu Electricity

2

Negative

Comment
to provide this industry feedback, as it is our understanding that we will be
afforded another ballot opportunity. If this were to be our sole occasion to ballot,
we would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far. SCL is prepared to support the BES Exception process as proposed
by the SDT going forward.
We believe that additional work is necessary to develop clear, objective methods
and criteria for identifying which facilities may be excluded from or should be
included in the Bulk Electric System. Clear, objective methods and criteria will
enable the submitter of requests to understand what is necessary for submitting
an exception request and will provide for consistency among the regions in their
initial assessment and recommendations to the ERO.
The ISO believes that the proposed Technical Principles for Demonstrating BES
Exceptions Request does not provide the necessary clarity as to what applying
entities must provide to support their request, nor does it provide any criteria for
consistency among regions in their assessment of requests. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective
criteria defining what must be submitted and how to assess the materials
submitted, the current methodology leaves it to each region to develop their own
methodology and criteria for evaluating the submittals. The lack of clarity
regarding what studies must be submitted and what must be demonstrated by the
studies submitted will be overly burdensome on the submitting entity and the
Region, as multiple studies may be required for the two to agree that there is
sufficient justification for an exemption request. The ISO believes that additional
work is necessary to develop clear, objective methods and criteria for identifying
which facilities may be excluded from or should be included in the Bulk Electric
System. Clear, objective methods and criteria will enable the submitter of requests
to understand what is necessary for submitting an exception request and will
provide for consistency among the regions in their initial assessment and
recommendations to the ERO.
We believe that the SDT proposed approach for exception criteria is reasonable
recognizing that one method/criteria cannot be applicable to everyone and every

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

27

Voter

Alden Briggs

Steven Grego

Entity
System
Operator

Segment

Vote

New
Brunswick
System
Operator
MEAG Power

2

Negative

5

Negative

Comment
situation within the ERO foot print. However, we believe that there is huge gap
and lack of any transparency on how the exception application will be evaluated
and processed. We strongly suggest that SDT develop a reference or a guidance
document as part of the RoP that should provide some guidance to Registered
Entities, Regional Entities and the ERO on how an exception application should be
processed. The absence of such guidance will pose a challenge for each entity
including the ERO, and may result in discrepancies amongst Regional Entities. The
process may be perceived by registered entities as being non-transparency.
The NBSO has concern about the lack of clarity and specificity with respect to what
analyses and study results are required. This lack of clarity and specificity may lead
to inconsistent application of the Technical Principles by both Registered Entities
and Regional Entities.
We believe that the proposed Technical Principles for Demonstrating BES
Exceptions Request does not provide the necessary clarity as to what applying
entities must provide to support their request, nor does it provide any criteria for
consistency among regions in their assessment of requests. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective
criteria defining what must be submitted and how to assess the materials
submitted, the current methodology leaves it to each region to develop their own
methodology and criteria for evaluating the submittals. We believe the lack of
clarity regarding what studies must be submitted and what must be demonstrated
by the studies submitted will be overly burdensome on the submitting entity and
the Region, as multiple studies may be required for the two to agree that there is
sufficient justification for an exemption request. We believe that additional work is
necessary to develop clear, objective methods and criteria for identifying which
facilities may be excluded from or should be included in the Bulk Electric System.
Clear, objective methods and criteria will enable the submitter of requests to
understand what is necessary for submitting an exception request and will provide
for consistency among the regions in their initial assessment and
recommendations to the ERO. We believe that a Yes vote for the Technical
Principles for Demonstrating BES Exceptions Request will result in minimal or no
changes to today’s process under the current definition which includes the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

28

Voter

Steven M.
Jackson

Entity

Municipal
Electric
Authority of
Georgia

Segment

3

Vote

Negative

Comment
language “as defined by the Regional Reliability Organization.” While the proposed
Technical Principles for Demonstrating BES Exceptions Request includes a checklist
that must be submitted with exception requests, a yes vote will still require each
region to develop their own methods and criteria for assessing materials
submitted with exemption requests. We believe that a No vote with guidance to
the drafting team that objective methods and criteria must be developed and
applied continent-wide will result in the desired uniformity and consistency among
regions in their assessment of exception requests. To allow sufficient time to
complete this difficult task, we believe that the Detailed Information to Support
BES Exceptions Request should not be part of the Phase 1 Bulk Electric System
Definition effort, but should be postponed and included in the Phase 2 effort.
We believe that the proposed Technical Principles for Demonstrating BES
Exceptions Request does not provide the necessary clarity as to what applying
entities must provide to support their request, nor does it provide any criteria for
consistency among regions in their assessment of requests. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective
criteria defining what must be submitted and how to assess the materials
submitted, the current methodology leaves it to each region to develop their own
methodology and criteria for evaluating the submittals. We believe the lack of
clarity regarding what studies must be submitted and what must be demonstrated
by the studies submitted will be overly burdensome on the submitting entity and
the Region, as multiple studies may be required for the two to agree that there is
sufficient justification for an exemption request. We believe that additional work is
necessary to develop clear, objective methods and criteria for identifying which
facilities may be excluded from or should be included in the Bulk Electric System.
Clear, objective methods and criteria will enable the submitter of requests to
understand what is necessary for submitting an exception request and will provide
for consistency among the regions in their initial assessment and
recommendations to the ERO. We believe that a Yes vote for the Technical
Principles for Demonstrating BES Exceptions Request will result in minimal or no
changes to today’s process under the current definition which includes the
language “as defined by the Regional Reliability Organization.” While the proposed

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

29

Voter

Entity

Segment

Vote

John H Hagen

Pacific Gas and
Electric
Company

3

Negative

Mike Ramirez

Sacramento
Municipal
Utility District

4

Negative

Bethany
Hunter

Sacramento
Municipal
Utility District

5

Negative

Claire
Warshaw

Sacramento
Municipal
Utility District

6

Negative

Comment
Technical Principles for Demonstrating BES Exceptions Request includes a checklist
that must be submitted with exception requests, a yes vote will still require each
region to develop their own methods and criteria for assessing materials
submitted with exemption requests. We believe that a No vote with guidance to
the drafting team that objective methods and criteria must be developed and
applied continent-wide will result in the desired uniformity and consistency among
regions in their assessment of exception requests. To allow sufficient time to
complete this difficult task, we believe that the Detailed Information to Support
BES Exceptions Request should not be part of the Phase 1 Bulk Electric System
Definition effort, but should be postponed and included in the Phase 2 effort.
This does not provide clarity on the criteria that will be used to manage the
inclusion/exclusion process. Leaving it up to the regions will only create variances
that this effort was chartered to eliminate. To support a bright line BES defintion,
the exclusion process must not have subjective results baed on regional variances.
We may be better off without an exclusion process and include the exclusions as
written into the definition.
We believe that additional work is necessary to develop clear, objective methods
and criteria for identifying which facilities may be excluded from or should be
included in the Bulk Electric System. Clear, objective methods and criteria will
enable the submitter of requests to understand what is necessary for submitting
an exception request and will provide for consistency among the regions in their
initial assessment and recommendations to the ERO.
We believe that additional work is necessary to develop clear, objective methods
and criteria for identifying which facilities may be excluded from or should be
included in the Bulk Electric System. Clear, objective methods and criteria will
enable the submitter of requests to understand what is necessary for submitting
an exception request and will provide for consistency among the regions in their
initial assessment and recommendations to the ERO.
We believe that additional work is necessary to develop clear, objective methods
and criteria for identifying which facilities may be excluded from or should be
included in the Bulk Electric System. Clear, objective methods and criteria will
enable the submitter of requests to understand what is necessary for submitting
an exception request and will provide for consistency among the regions in their

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

30

Voter

Entity

Segment

Vote

James LeighKendall

Sacramento
Municipal
Utility District

3

Negative

Mark B
Thompson

Alberta
Electric System
Operator

2

Negative

Lisa C
Rosintoski

Colorado
Springs
Utilities

6

Negative

Comment
initial assessment and recommendations to the ERO.
We believe that additional work is necessary to develop clear, objective methods
and criteria for identifying which facilities may be excluded from or should be
included in the Bulk Electric System. Clear, objective methods and criteria will
enable the submitter of requests to understand what is necessary for submitting
an exception request and will provide for consistency among the regions in their
initial assessment and recommendations to the ERO.
The AESO agrees with the WECC, who say: WECC Staff believes that the proposed
Technical Principles for Demonstrating BES Exceptions Request does not provide
the necessary clarity as to what applying entities must provide to support their
request, nor does it provide any criteria for consistency among regions in their
assessment of requests. We believe that the checklist items for transmission and
generation facilities are appropriate questions that must be answered in
considering all requests. However, without objective criteria defining what must
be submitted and how to assess the materials submitted, the current methodology
leaves it to each region to develop their own methodology and criteria for
evaluating the submittals. We believe the lack of clarity regarding what studies
must be submitted and what must be demonstrated by the studies submitted will
be overly burdensome on the submitting entity and the Region, as multiple studies
may be required for the two to agree that there is sufficient justification for an
exemption request. We believe that additional work is necessary to develop clear,
objective methods and criteria for identifying which facilities may be excluded
from or should be included in the Bulk Electric System. Clear, objective methods
and criteria will enable the submitter of requests to understand what is necessary
for submitting an exception request and will provide for consistency among the
regions in their initial assessment and recommendations to the ERO.
Colorado Springs Utilities believes that the proposed Technical Information to
Support BES Exceptions Request does not provide the necessary clarity as to what
applying entities must provide to support their request. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. We believe the lack of clarity
regarding what studies must be submitted and what must be demonstrated by the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

31

Voter

Entity

Segment

Vote

Jennifer Eckels

Colorado
Springs
Utilities

5

Negative

Spencer Tacke

Modesto
Irrigation
District

4

Negative

Comment
studies submitted will be overly burdensome on our staff. We believe that
additional work is necessary to develop clear, objective methods and criteria for
identifying which facilities may be excluded from or should be included in the Bulk
Electric System. Clear, objective methods and criteria will enable us to understand
what is necessary for submitting an exception request. To allow sufficient time to
complete this difficult task, we believe that the Detailed Information to Support
BES Exceptions Request should not be part of the Phase 1 Bulk Electric System
Definition effort, but should be postponed and included in the Phase 2 effort.
Colorado Springs Utilities believes that the proposed Technical Information to
Support BES Exceptions Request does not provide the necessary clarity as to what
applying entities must provide to support their request. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. We believe the lack of clarity
regarding what studies must be submitted and what must be demonstrated by the
studies submitted will be overly burdensome on our staff. We believe that
additional work is necessary to develop clear, objective methods and criteria for
identifying which facilities may be excluded from or should be included in the Bulk
Electric System. Clear, objective methods and criteria will enable us to understand
what is necessary for submitting an exception request. To allow sufficient time to
complete this difficult task, we believe that the Detailed Information to Support
BES Exceptions Request should not be part of the Phase 1 Bulk Electric System
Definition effort, but should be postponed and included in the Phase 2 effort.
We believe that the proposed Technical Principles for Demonstrating BES
Exceptions Request does not provide the necessary clarity as to what applying
entities must provide to support their request, nor does it provide any criteria for
consistency among regions in their assessment of requests. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective
criteria defining what must be submitted and how to assess the materials
submitted, the current methodology leaves it to each region to develop their own
methodology and criteria for evaluating the submittals. We believe the lack of
clarity regarding what studies must be submitted and what must be demonstrated
by the studies submitted will be overly burdensome on the submitting entity and

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

32

Voter

Entity

Segment

William M
Chamberlain

California
Energy
Commission

9

Allen Mosher

American
Public Power
Association

4

Vote

Comment
the Region, as multiple studies may be required for the two to agree that there is
sufficient justification for an exemption request. We believe that additional work is
necessary to develop clear, objective methods and criteria for identifying which
facilities may be excluded from or should be included in the Bulk Electric System.
Clear, objective methods and criteria will enable the submitter of requests to
understand what is necessary for submitting an exception request and will provide
for consistency among the regions in their initial assessment and
recommendations to the ERO. Thank you.
Negative
We agree with WECC that the proposed Technical Principles for Demonstrating
BES Exceptions Request does not provide the necessary clarity as to what applying
entities must provide to support their request, nor does it provide any criteria for
consistency among regions in their assessment of requests. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective
criteria defining what must be submitted and how to assess the materials
submitted, the current methodology leaves it to each region to develop their own
methodology and criteria for evaluating the submittals. We believe the lack of
clarity regarding what studies must be submitted and what must be demonstrated
by the studies submitted will be overly burdensome on the submitting entity and
the Region, as multiple studies may be required for the two to agree that there is
sufficient justification for an exemption request. We believe that additional work is
necessary to develop clear, objective methods and criteria for identifying which
facilities may be excluded from or should be included in the Bulk Electric System.
Clear, objective methods and criteria will enable the submitter of requests to
understand what is necessary for submitting an exception request and will provide
for consistency among the regions in their initial assessment and
recommendations to the ERO. We are voting No to allow the drafting team to
develop objective methods and criteria that can be applied continent-wide,
resulting in the desired uniformity and consistency among regions in their
assessment of exception requests.
Affirmative See comments submitted in response to BES Definition. APPA also requests more
specificity on the detailed information required to support BES exceptions
processed through the NERC Rules of Procedure drafting process. Additional

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

33

Voter

Entity

Segment

Vote

Comment
technical specificity will help ensure consistency between regions and
transparency for registered entities on the technical studies and data required to
support exception requests. These issues should be addressed in Phase 2.
Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and
an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could
have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the
commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive
comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the
Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of
the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of
the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting
or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis
for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making
their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

34

Voter
Entity
Segment
Vote
Comment
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric
system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the
technical prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests
will result in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
3
Negative
1. Page one of the ‘Detailed Information to Support an Exception Request’
Marilyn Brown New York
contains general instructions. Do you agree with the instructions presented or is
Power
there information that you believe needs to be on page one that is missing? Please
Authority
be as specific as possible with your comments. Yes: X No: Comments: No
comments. 2. Pages two and three of the Detailed Information to Support an
Exception Request contain a checklist of items that deal with transmission
facilities. Do you agree with the information being requested or is there
information that you believe needs to be on page two or three that is missing?
Please be as specific as possible with your comments. Yes: No: X Comments: For
Question 2 on page 2, recommend that the specific types of studies to be provided
are defined to add consistency and transparency to the Exception request process.
Recommend that the concept and the words “material to” be included as part of
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

35

Voter

Entity

Segment

Vote

Comment
the question as follows “Is the facility material to permanent Flowgates in the
Eastern Interconnection.....” For Question 4 on page 2, recommend that single
contingency analysis be performed and submitted to demonstrate impacts to the
BES. For Question 6 on page 3, recommend that “Cranking Path” be removed to be
consistent with the draft BES Definition. Recommend that the concept and the
words “material to and designated as part of” be included as part of the question.
Recommend rewording Question 6 as follows “Is the facility a Blackstart resource
material to and designated as part of the Transmission Operator’s restoration
plan?” For Question 7 on page 3, facilities less than two years old or under
construction would not be able to provide SCADA data for the most recent
consecutive two calendar year period. Facility rating changes and the magnitude of
such changes which trigger application or reapplication of the exception process
are not addressed. Recommend that Question 7 be revised to address these
issues. 3. Page four of the ‘Detailed Information to Support an Exception Request’
contains a checklist of items that deal with generation facilities. Do you agree with
the information being requested or is there information that you believe needs to
be on page four that is missing? Please be as specific as possible with your
comments. Yes: No: X Comment Form for 2nd Draft of Project 2010-17: Definition
of BES (BES) Technical Principles for Demonstrating BES Exceptions Page 4 of 5
Comments: For Question 2 on page 4, recommend that the specific generator
ancillary service products be defined to add consistency and transparency to the
Exception Request process. For Question 3 on page 4, recommend that
confirmation of must-run generation be provided by the Reliability Coordinator,
Reliability Planner, or the Balancing Authority as a clarification to the “appropriate
reference”. 4. Do you have concerns about an entity’s ability to obtain the data
they would need to file the ‘Detailed Information to Support an Exception
Request’? If so, please be specific with your concerns so that the SDT can fully
understand the problem. Yes: No: X Comments: No comments. Comment Form for
2nd Draft of Project 2010-17: Definition of BES (BES) Technical Principles for
Demonstrating BES Exceptions Page 5 of 5 5. Are there other specific
characteristics that you feel would be important for presenting a case and which
are generic enough that they belong in the request? If so, please identify them
here and provide suggested language that could be added to the document. Yes:

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

36

Voter

Gerald
Mannarino

Entity

New York
Power
Authority

Segment

5

Vote

Negative

Comment
No: X Comments: No comments. 6. Are you aware of any conflicts between the
proposed approach and any regulatory function, rule order, tariff, rate schedule,
legislative requirement or agreement, or jurisdictional issue? If so, please identify
them here and provide suggested language changes that may clarify the issue. Yes:
No: X Comments: No comments. 7. Are there any other concerns with the
proposed approach for demonstrating BES Exceptions that haven’t been covered
in previous questions and comments (bearing in mind that the definition itself and
the proposed Rules of Procedure changes are posted separately for comments)?
Please be as specific as possible with your comments. Yes: X No: Comments:
Completing the exception form does not provide the entity with any indication of
whether the Exception will be granted or rejected. It would be more effective and
efficient to revise the Exception request questions to provide confirmation or
rejection after completion of the form. Consistent application of the exception
process across regions may become challenging with separate exception request
review teams.
Comments: For Question 2 on page 2, recommend that the specific types of
studies to be provided are defined to add consistency and transparency to the
Exception request process. Recommend that the concept and the words “material
to” be included as part of the question as follows “Is the facility material to
permanent Flowgates in the Eastern Interconnection.....” For Question 4 on page
2, recommend that single contingency analysis be performed and submitted to
demonstrate impacts to the BES. For Question 6 on page 3, recommend that
“Cranking Path” be removed to be consistent with the draft BES Definition.
Recommend that the concept and the words “material to and designated as part
of” be included as part of the question. Recommend rewording Question 6 as
follows “Is the facility a Blackstart resource material to and designated as part of
the Transmission Operator’s restoration plan?” For Question 7 on page 3, facilities
less than two years old or under construction would not be able to provide SCADA
data for the most recent consecutive two calendar year period. Facility rating
changes and the magnitude of such changes which trigger application or
reapplication of the exception process are not addressed. Recommend that
Question 7 be revised to address these issues. Comments: For Question 2 on page
4, recommend that the specific generator ancillary service products be defined to

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

37

Voter

William
Palazzo

Entity

New York
Power
Authority

Segment

6

Vote

Negative

Comment
add consistency and transparency to the Exception Request process. For Question
3 on page 4, recommend that confirmation of must-run generation be provided by
the Reliability Coordinator, Reliability Planner, or the Balancing Authority as a
clarification to the “appropriate reference”.
1. Page one of the ‘Detailed Information to Support an Exception Request’
contains general instructions. Do you agree with the instructions presented or is
there information that you believe needs to be on page one that is missing? Please
be as specific as possible with your comments. Yes: X No: Comments: No
comments. 2. Pages two and three of the Detailed Information to Support an
Exception Request contain a checklist of items that deal with transmission
facilities. Do you agree with the information being requested or is there
information that you believe needs to be on page two or three that is missing?
Please be as specific as possible with your comments. Yes: No: X Comments: For
Question 2 on page 2, recommend that the specific types of studies to be provided
are defined to add consistency and transparency to the Exception request process.
Recommend that the concept and the words “material to” be included as part of
the question as follows “Is the facility material to permanent Flowgates in the
Eastern Interconnection.....” For Question 4 on page 2, recommend that single
contingency analysis be performed and submitted to demonstrate impacts to the
BES. For Question 6 on page 3, recommend that “Cranking Path” be removed to be
consistent with the draft BES Definition. Recommend that the concept and the
words “material to and designated as part of” be included as part of the question.
Recommend rewording Question 6 as follows “Is the facility a Blackstart resource
material to and designated as part of the Transmission Operator’s restoration
plan?” For Question 7 on page 3, facilities less than two years old or under
construction would not be able to provide SCADA data for the most recent
consecutive two calendar year period. Facility rating changes and the magnitude of
such changes which trigger application or reapplication of the exception process
are not addressed. Recommend that Question 7 be revised to address these
issues. 3. Page four of the ‘Detailed Information to Support an Exception Request’
contains a checklist of items that deal with generation facilities. Do you agree with
the information being requested or is there information that you believe needs to
be on page four that is missing? Please be as specific as possible with your

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

38

Voter

Arnold J.
Schuff

Entity

New York
Power
Authority

Segment

1

Vote

Negative

Comment
comments. Yes: No: X Comments: For Question 2 on page 4, recommend that the
specific generator ancillary service products be defined to add consistency and
transparency to the Exception Request process. For Question 3 on page 4,
recommend that confirmation of must-run generation be provided by the
Reliability Coordinator, Reliability Planner, or the Balancing Authority as a
clarification to the “appropriate reference”. 4. Do you have concerns about an
entity’s ability to obtain the data they would need to file the ‘Detailed Information
to Support an Exception Request’? If so, please be specific with your concerns so
that the SDT can fully understand the problem. Yes: No: X Comments: No
comments.
You do not have to answer all questions. Enter all comments in simple text format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas. 1.
Page one of the ‘Detailed Information to Support an Exception Request’ contains
general instructions. Do you agree with the instructions presented or is there
information that you believe needs to be on page one that is missing? Please be as
specific as possible with your comments. Yes: X No: Comments: No comments.
2. Pages two and three of the Detailed Information to Support an Exception
Request contain a checklist of items that deal with transmission facilities. Do you
agree with the information being requested or is there information that you
believe needs to be on page two or three that is missing? Please be as specific as
possible with your comments. Yes: No: X Comments: For Question 2 on page 2,
recommend that the specific types of studies to be provided are defined to add
consistency and transparency to the Exception request process.
Recommend that the concept and the words “material to” be included as part of
the question as follows “Is the facility material to permanent Flowgates in the
Eastern Interconnection.....”
For Question 4 on page 2, recommend that single contingency analysis be
performed and submitted to demonstrate impacts to the BES.
For Question 6 on page 3, recommend that “Cranking Path” be removed to be
consistent with the draft BES Definition. Recommend that the concept and the
words “material to and designated as part of” be included as part of the question.
Recommend rewording Question 6 as follows “Is the facility a Blackstart resource
material to and designated as part of the Transmission Operator’s restoration

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

39

Voter

Entity

Segment

Vote

Comment
plan?”
For Question 7 on page 3, facilities less than two years old or under construction
would not be able to provide SCADA data for the most recent consecutive two
calendar year period. Facility rating changes and the magnitude of such changes
which trigger application or reapplication of the exception process are not
addressed. Recommend that Question 7 be revised to address these issues.
3. Page four of the ‘Detailed Information to Support an Exception Request’
contains a checklist of items that deal with generation facilities. Do you agree with
the information being requested or is there information that you believe needs to
be on page four that is missing? Please be as specific as possible with your
comments. Yes: No: X Comments: For Question 2 on page 4, recommend that the
specific generator ancillary service products be defined to add consistency and
transparency to the Exception Request process.
For Question 3 on page 4, recommend that confirmation of must-run generation
be provided by the Reliability Coordinator, Reliability Planner, or the Balancing
Authority as a clarification to the “appropriate reference”.
4. Do you have concerns about an entity’s ability to obtain the data they would
need to file the ‘Detailed Information to Support an Exception Request’? If so,
please be specific with your concerns so that the SDT can fully understand the
problem. Yes: No: X Comments: No comments.
5. Are there other specific characteristics that you feel would be important for
presenting a case and which are generic enough that they belong in the request? If
so, please identify them here and provide suggested language that could be added
to the document. Yes: No: X Comments: No comments.
6. Are you aware of any conflicts between the proposed approach and any
regulatory function, rule order, tariff, rate schedule, legislative requirement or
agreement, or jurisdictional issue? If so, please identify them here and provide
suggested language changes that may clarify the issue. Yes: No: X Comments: No
comments.
7. Are there any other concerns with the proposed approach for demonstrating
BES Exceptions that haven’t been covered in previous questions and comments
(bearing in mind that the definition itself and the proposed Rules of Procedure
changes are posted separately for comments)? Please be as specific as possible

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

40

Voter

Entity

Segment

Vote

Comment
with your comments. Yes: X No: Comments: Completing the exception form does
not provide the entity with any indication of whether the Exception will be granted
or rejected. It would be more effective and efficient to revise the Exception
request questions to provide confirmation or rejection after completion of the
form. Consistent application of the exception process across regions may become
challenging with separate exception request review teams.

Response: 1. Thank you for your support.
2. See response to #10 below. Material is an unmeasurable concept. No change made. The SDT believes that an entity should follow the TPL
methodology in formulating its request. If the entity believes that an n-1 analysis is all that is needed then it can submit just an n-1 analysis. No
change made. Cranking Path information is just one piece of information that may be of value to the ERO Panel in making its decision. No
change made. If two years worth of data are not available, the SDT believes that a Regional Entity will accept what is available and will work
with the submitter to come up with an acceptable plan to move forward.
3. Ancillary service products differ from region to region so providing a list in the form would be problematic. The form has sufficient flexibility
for the entity to specify which products it is dealing with. However, the SDT has clarified the language concerning ancillary service products and
must run units to indicate that only reliability-based information is pertinent.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Q3. Is the generator generation resource designated as a must run unit for reliability?
4. 5. & 6. Without a specific comment, the SDT is unable to respond.
7. The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like
nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and an
initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could
have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the
commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive
comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

41

Voter
Entity
Segment
Vote
Comment
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the
Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of
the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of
the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting
or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis
for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making
their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric
system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the
technical prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests
will result in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
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42

Voter
Entity
Segment
Vote
Comment
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
Doug
Omaha Public
1
Negative
The technical document on exceptions is appropriate, but there should be a
Peterchuck
Power District
guideline on what a typical exception is. The guideline can easily be created by
what is now listed within the four-item “Exclusion List”. For example when looking
at the current Local Network exclusion (E3), it looks to be based on a regional
request and thus is in direct conflict with FERC’s order. We interpret the creation
of a technical document regarding a proposed BES exclusion as a case that should
be examined during the Exception Process and not during the BES definition
process. The simple question that FERC could eventually ask is why don’t all listed
exclusions include a technical justification?
Response: The SDT did not provide a technical justification for items that are simply being copied from the existing definition. Technical
justification was only provided for items that are new with this revision.
John T.
Underhill

Salt River
Project

3

Negative

Definition of Bulk Electric System (BES) The Blackstart “Cranking Path” has been
deleted from Inclusion 3 of the BES definition. However, NERC standards EOP-005
and CIP-002, R1.2.4 require documenting the Cranking Path. In addition, CIP-002-4
identifies the Cranking Path as a Critical Asset in Attachment 1. Compliance to the
NERC Standards needs to be an exact science whenever possible. SRP does not
argue the inclusion or exclusion of Cranking Path. However, if it is excluded,
guidance must be provided on whether or not a Cranking Path is subject to the
previously mentioned Standards. Detailed Information to Support BES Exceptions
Request SRP agrees with the WECC Staff recommendation on the “Detailed
Information to Support BES Exceptions Request.” “WECC Staff believes that the
proposed Technical Principles for Demonstrating BES Exceptions Request does not
provide the necessary clarity as to what applying entities must provide to support

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43

Voter

Steven J Hulet

Entity

Salt River
Project

Segment

6

Vote

Negative

Comment
their request, nor does it provide any criteria for consistency among regions in
their assessment of requests. We believe that the checklist items for transmission
and generation facilities are appropriate questions that must be answered in
considering all requests. However, without objective criteria defining what must
be submitted and how to assess the materials submitted, the current methodology
leaves it to each region to develop their own methodology and criteria for
evaluating the submittals. We believe the lack of clarity regarding what studies
must be submitted and what must be demonstrated by the studies submitted will
be overly burdensome on the submitting entity and the Region, as multiple studies
may be required for the two to agree that there is sufficient justification for an
exemption request. We believe that additional work is necessary to develop clear,
objective methods and criteria for identifying which facilities may be excluded
from or should be included in the Bulk Electric System. Clear, objective methods
and criteria will enable the submitter of requests to understand what is necessary
for submitting an exception request and will provide for consistency among the
regions in their initial assessment and recommendations to the ERO.”
SRP agrees with the WECC Staff recommendation on the “Detailed Information to
Support BES Exceptions Request.” “WECC Staff believes that the proposed
Technical Principles for Demonstrating BES Exceptions Request does not provide
the necessary clarity as to what applying entities must provide to support their
request, nor does it provide any criteria for consistency among regions in their
assessment of requests. We believe that the checklist items for transmission and
generation facilities are appropriate questions that must be answered in
considering all requests. However, without objective criteria defining what must
be submitted and how to assess the materials submitted, the current methodology
leaves it to each region to develop their own methodology and criteria for
evaluating the submittals. We believe the lack of clarity regarding what studies
must be submitted and what must be demonstrated by the studies submitted will
be overly burdensome on the submitting entity and the Region, as multiple studies
may be required for the two to agree that there is sufficient justification for an
exemption request. We believe that additional work is necessary to develop clear,
objective methods and criteria for identifying which facilities may be excluded
from or should be included in the Bulk Electric System. Clear, objective methods

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

44

Voter

Robert
Kondziolka

Entity

Salt River
Project

Segment

1

Vote

Negative

Comment
and criteria will enable the submitter of requests to understand what is necessary
for submitting an exception request and will provide for consistency among the
regions in their initial assessment and recommendations to the ERO.”
Definition of Bulk Electric System (BES) The Blackstart “Cranking Path” has been
deleted from Inclusion 3 of the BES definition. However, NERC standards EOP-005
and CIP-002, R1.2.4 require documenting the Cranking Path. In addition, CIP-002-4
identifies the Cranking Path as a Critical Asset in Attachment 1. Compliance to the
NERC Standards needs to be an exact science whenever possible. SRP does not
argue the inclusion or exclusion of Cranking Path. However, if it is excluded,
guidance must be provided on whether or not a Cranking Path is subject to the
previously mentioned Standards.
Detailed Information to Support BES Exceptions Request SRP agrees with the
WECC Staff recommendation on the “Detailed Information to Support BES
Exceptions Request.” “WECC Staff believes that the proposed Technical Principles
for Demonstrating BES Exceptions Request does not provide the necessary clarity
as to what applying entities must provide to support their request, nor does it
provide any criteria for consistency among regions in their assessment of requests.
We believe that the checklist items for transmission and generation facilities are
appropriate questions that must be answered in considering all requests.
However, without objective criteria defining what must be submitted and how to
assess the materials submitted, the current methodology leaves it to each region
to develop their own methodology and criteria for evaluating the submittals. We
believe the lack of clarity regarding what studies must be submitted and what
must be demonstrated by the studies submitted will be overly burdensome on the
submitting entity and the Region, as multiple studies may be required for the two
to agree that there is sufficient justification for an exemption request. We believe
that additional work is necessary to develop clear, objective methods and criteria
for identifying which facilities may be excluded from or should be included in the
Bulk Electric System. Clear, objective methods and criteria will enable the
submitter of requests to understand what is necessary for submitting an exception
request and will provide for consistency among the regions in their initial
assessment and recommendations to the ERO.”

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45

Voter
Entity
Segment
Vote
Comment
Response: Cranking Path information is just one piece of information that may be of value to the ERO Panel in making its decision. No change
made.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like nothing
better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and an initial
attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could have
come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the commenters
that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the
Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of
the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of
the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting
or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis
for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making
their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

46

Voter
Entity
Segment
Vote
Comment
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric
system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the
technical prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests
will result in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
Marie Knox
Midwest ISO,
2
Negative
We support the SDT’s decision to exclude the cranking paths from the BES
Inc.
definition since testing and verification of the use of facilities in the cranking path
is already covered by the appropriate EOP standards. However Inclusion I3
(blackstart) is extraneous given there is already designation specific for system
restoration covered by an existing standard; EOP-005-2. Therefore, information on
whether the facility is part of a Cranking Path associated with a Blackstart
Resource, should not be required to receive consideration for an exception.
Response: The SDT disagrees that Blackstart Resources should not be included in the BES Definition. The Commission directed NERC to revise
its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission
network. The SDT interprets this to include operation under both normal and emergency conditions, which includes situations related to black
starts and system restoration. Blackstart Resources have the ability to be started without support from the System or can be energized without
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47

Voter
Entity
Segment
Vote
Comment
connection to the remainder of the System, in order to meet a Transmission Operator’s restoration plan requirements for Real and Reactive
Power capability, frequency, and voltage control. The associated resources of the electric system that can be isolated and then energized to
deliver electric power during a restoration event are essential to enable the startup of one or more other generating units as defined in the
Transmission Operator’s restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in the Transmission
Operator’s restoration plan as BES elements. No change made.
Cranking Path information is just one piece of information that may be of value to the ERO Panel in making its decision. EOP-005-2 has no
relevance in this regard. No change made.
Linda Jacobson City of
3
Negative
FEUS appreciates the efforts of the SDT. However, the Detailed Information to
Farmington
Support an Exception Request does not align with the Draft Appendix 5C as it is
applied to ‘Facilities’ rather than ‘Elements’ and is unclear how it is applied for an
Inclusion Exception. Additional Comments have been submitted using the
comment form.
Response: Please see the detailed responses to comments for Farmington in the general consideration of comments document for the
technical criteria.
Gregg R Griffin

City of Green
Cove Springs

3

Affirmative GCS appreciates the SDT’s work on this project. For the most part,GCS supports
what it believes to be the intent of the proposed language. The proposed specific
exclusion of facilities used in the local distribution of electric energy is appropriate
and consistent with Section 215 of the Federal Power Act. However, we have
suggestions to better carry out what we believe to be the SDT’s intent. The first
sentence can be read as: “... all ... Real Power and Reactive Power resources
connected at 100 kV or higher”, which is surely not what the SDT intends. The
basic problem is that Inclusions I2 and I4 do not modify the first sentence, e.g.,
from a set theory perspective, the set described by the first sentence includes the
sets described in inclusions I2 and I4; hence, I2 and I4 do not modify the first
sentence. From a literal reading, this would cause any size generator connected at
100 kV to be included, which is surely not the intent of the SDT. For similar
reasons, the core definition and Inclusion I5 now has the effect of including all
generators connected at 100 kV since a generator is a “dynamic device ... supplying
or absorbing Reactive Power”. The word “dedicated” in I5 is not sufficient in GCS’s
mind to unambiguously exclude generators from this statement. FMPA suggests
the following wording to address these issues: "Transmission Elements (not
including elements used in the local distribution of electric energy) and Real Power

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Voter

Entity

Segment

Vote

Comment
and Reactive Power resources as described in the list below, unless excluded by
Exclusion or Exception: a. Transmission Elements other than transformers and
reactive resources operated at 100 kV or higher. b. Transformers with primary and
secondary terminals operated at 100 kV or higher. c. Generating resource(s) (with
gross individual or gross aggregate nameplate rating per the ERO Statement of
Compliance Registry Criteria) including the generator terminals through the highside of the step-up transformer(s) connected at a voltage of 100 kV or above. d.
Blackstart Resources identified in the Transmission Operator’s restoration plan. e.
Dispersed power producing resources with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing a system designed primarily for
aggregating capacity, connected at a common point at a voltage of 100 kV or
above, but not including generation on the retail side of the retail meter. f. Nongenerator static or dynamic devices dedicated to supplying or absorbing more than
6 MVAr of Reactive Power that are connected at 100 kV or higher, or through a
dedicated transformer with a high-side voltage of 100 kV or higher, or through a
transformer that is designated in bullet 2 above." 2. The SDT has revised the
specific inclusions to the core definition in response to industry comments. Do you
agree with Inclusion I1 (transformers)? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. Yes: Yes No: Comments:
Please see comments to Question 1 3. The SDT has revised the specific inclusions
to the core definition in response to industry comments. Do you agree with
Inclusion I2 (generation) including the reference to the ERO Statement of
Compliance Registry Criteria? If you do not support this change or you agree in
general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. Yes: yes No: Comments: Please see
comments to Question 1 4. The SDT has revised the specific inclusions to the core
definition in response to industry comments. Do you agree with Inclusion I3
(blackstart)? If you do not support this change or you agree in general but feel that
alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: Yes No: Comments: Please see comments to
Question 1. 5. The SDT has revised the specific inclusions to the core definition in
response to industry comments. Do you agree with Inclusion I4 (dispersed power)?

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If you do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: Yes No: Comments: We recommend clarifying that the dispersed
power resources covered by this inclusion do not include generators on the retail
side of the retail meter. Specifically, we recommend that the Inclusion read:
“Dispersed power producing resources with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing a system designed primarily for
aggregating capacity, connected at a common point at a voltage of 100kV or
above, but not including generation on the retail side of the retail meter.” 6. The
SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I5 (reactive resources)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.
Yes: No: Comments: To help clarify and to avoid inclusion of de minimis reactive
resources, we propose a size threshold of 6 MVAr consistent with the smallest size
generator included in the BES at a 0.95 power factor, which is a common leading
power factor used in Facility Connection Requirements for generators. In other
words, 6 MVAr is consistent with typically the least amount of MVAr required to
be absorbed by the smallest generator meeting the registry criteria. 7. The SDT has
revised the specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E1 (radial system)? If you do not support
this change or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments. Yes: Yes
No: Comments: FMPA supports the exclusion of radial systems from the BES
Definition. Such systems are generally not “necessary for operating an
interconnected electric transmission network,” the standard in Orders 743 and
743-A. We have several suggestions to clarify the proposed language for this
Exclusion. Proposed Exclusion E1 refers to “[a] group of contiguous transmission
Elements that emanates from a single point of connection of 100 kV or higher.”
We appreciate the SDT’s clarification of the point of connection requirement, but
the term “a single point of connection” should be further defined (more clearly
than just by voltage), and should be generic enough to encompass the various bus
configurations. It is not the case, for example, that each individual breaker position

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Voter

Comment
in a ring bus is a separate point of connection for this purpose; in that situation, a
bus at one voltage level at one substation should be considered “a single point of
connection.” Some examples of configurations that should be considered a single
point of connection for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf,
Examples 1-6. Although the core definition (appropriately) refers to “Transmission
Elements” (with a capital “T”), proposed Exclusion E1 refers to “transmission
Elements” (with a lowercase “t”). To avoid confusion, either “Transmission” should
be capitalized in both locations, or the word “transmission” should simply be
deleted from Exclusion E1, leaving a “group of contiguous Elements.” We
understand that the lack of capitalization may have been a deliberate choice by
the SDT in an attempt to avoid confusion that SDT members believe exists in the
Glossary definition. If the Glossary definition of Transmission is unclear-which GCS
does not necessarily believe is the case-the answer is not to simply abandon the
Glossary definition in favor of an entirely und
Response: Please see the detailed responses to comments for Green Cove in the ballot consideration of comments document for the definition.
Jose Escamilla

Entity

CPS Energy

Segment

3

Vote

Negative

The sample form "Request for Exception to the Bulk Electric System Definition"
developed by the BES ROP Team is a more complete form.

Response: The SDT believes that the indicated form was an early draft and is no longer applicable. The SDT has worked closely with the Rules
of Procedure team to make certain that the form is coordinated with the proposed ERO Rules of Procedure changes.
David Kiguel

Hydro One
Networks, Inc.

3

Negative

After careful analysis of the proposed documents, Hydro One Networks Inc. is
casting a negative vote. We commend the SDT for the effort in facing the
challenge. However, we believe that the proposed definition and the exception
request criteria still needs further work. Some issues need to be resolved before a
final approval is granted. Please see our detailed comments as provided in the online system.
Response: Please see the detailed responses to comments for Hydro One in the general consideration of comments document for the technical
criteria.
Jack W Savage

Modesto
Irrigation

3

Negative

MID is voting No with the following comments. Inclusions and exclusions are based
upon the ERO Statement of Compliance Registry Criteria - currently 75MVA. What

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Voter

Entity
District

Segment

Vote

Comment
is the SDT's technical justification for using this generation level? If 75MVA is the
criteria for including facilities as part of the BES, why is that same criteria not
applied at voltages below 100kv? Is 75MVA of generation within an area whose
load far exceeds that 75MVA cause to classify that entire area as part of the BES
and not exclude it as a Local Network?
Why are customer owned generators treated differently than other generators?
Where is "non-retail generation" defined?
The Detailed Information to Support an Exception Request requests information
that is not included or mentioned in the definition of the BES. One example is
reference to a Balancing Authorities most severe single contingency outage. How
does the SDT justify inclusion of these type of questions which are not supported
by the actual definition of the BES?
Response: The SDT recognizes that some candidate local networks will have far in excess of 75 MVA of load demand, yet it believes that the 75
MVA threshold value given in Exclusion E3.a is an appropriate level regardless of the amount of load. This value is consistent with the existing
threshold of aggregate generation in the ERO Statement of Compliance Registry Criteria. The generation values used in the BES definition will
receive more attention and refinement as part of Phase 2 of this Project 2010-17.
The SDT assumes the commenter is referring to Exclusion E2. This exclusion is simply clarifying what already exists in the ERO Statement of
Compliance Registry Criteria for behind-the-meter generation.
Non-retail generation is the generation on the system (supply) side of the meter.
The indicated information is simply one piece of data that the SDT felt might be of value in the decision process and does not believe that data
requested has to match one for one with the actual language of the definition.
Jeff Nelson
Springfield
3
Negative
Excellent progress has been made, but the technical information to support BES
Utility Board
exceptions needs strengthening. For example, unscheduled flows in or out of a
local network should not be used as a determination of whether a network is
excluded.
Reactive devices needs clarification as there are some reactive devices used for
power factor correction, for example, on systems above 100kV that SUB believes
should be exempt from the BES
Response: The SDT believes it is vital to ensure both that power flow is always in the direction from the BES toward the LN at all points of
connection, and that the LN facilities not be used for “wheeling” type transactions. The SDT believes the existing language accomplishes this.
The suggested language in this comment touches on an important aspect, the scheduled use of the facilities, but the SDT believes that the
existing language is more appropriate to express this point. No change made.
Special circumstances such as described by SUB will need to be submitted to the exception process. In general, the SDT believes that reactive
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Voter
Entity
Segment
Vote
devices above 100 kV should be part of the BES.
Mark
Ringhausen

Old Dominion
Electric Coop.

4

Comment

Negative

I cannot vote for this as it references in I2 the ERO Statement of Compliance
Registry Criteria, which can be changed without stakeholder review and approval.
The industry would be held to a changing standard that is not included in the
Standars itself.
Response: This is a factor for the definition and not the criteria. Voting on the two separate issues should be done separately on their own
individual merits.
In response to comments, the SDT has deleted the reference to the ERO Statement of Compliance Registry and replaced it with the existing
numeric values. This way, any changes to the ERO Statement of Compliance Registry prior to resolution of threshold values in Phase II will not
affect the definition
Michelle R
Occidental
5
Negative
1. Page 1 of the Detailed Information to Support an Exception Request contains
DAntuono
Chemical
general instructions. Do you agree with the instructions presented or is there
information that you believe needs to be on page one and is missing? Please be as
specific as possible with your comments. No: X Comments: It would be helpful to
specify what the “key performance measures of BES reliability” are in the
instructions (or at least examples of what these measures are in relation to the TPL
Table 1). There must be some guidance on the relative level that should be
considered acceptable to exclude a facility. Since the Regional Entities are
responsible under the proposed Rules of Procedure to recommend the approval or
disapproval of an exception request, it makes sense that they should provide this
guidance. However, the DBESSDT should suggest an acceptable minimum perhaps 10% of the allowed voltage transient dip or frequency excursion as
assessed under a single contingency scenario.
2. Pages two and three of the Detailed Information to Support an Exception
Request contain a checklist of items that deal with transmission facilities. Do you
agree with the information being requested or is there information that you
believe needs to be on page three and is missing? Please be as specific as possible
with your comments. No: X Comments: Item 4 needs to be expanded to provide
some guidance on what an acceptable “impact to the over-all reliability of the BES”
is. Also, there needs to be some sort of qualifier for the request to specify the
“most severe system impact of an outage of the facility,” i.e., at least add the
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Entity

Segment

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Comment
qualifier that it only requires a credible scenario. For example, what is the status of
the BES when the outage of the facility occurs such that it represents the “most
severe impact.” Most Regional Entities have settled on Transmission Planning
models and thresholds that any new transmission deployment must minimally
meet before it goes online. In some Regions, power transfer distribution factor
may be gating factor - others may look at transient response. Whatever the case,
the Regions should use those same criteria for BES exceptions - reduced to some
conservative percentage level; perhaps 10% of the available margin.
3. Page four of the Detailed Information to Support an Exception Request contains
a checklist of items that deal with generation facilities. Do you agree with the
information being requested or is there information that you believe needs to be
on page four and is missing? Please be as specific as possible with your comments.
No: X Comments: Item 4 needs to be expanded to provide some guidance on what
an acceptable “impact to the over-all reliability of the BES” is. Also, there needs to
be some sort of qualifier for the request to specify the “most severe system impact
of an outage of the facility,” i.e., at least add the qualifier that it only requires a
credible scenario. For example, what is the status of the BES when the outage of
the facility occurs such that it represents the “most severe impact.” Most Regional
Entities have settled on Transmission Planning models and thresholds that any
new generation deployment must minimally meet before it goes online. In some
Regions, power transfer distribution factor may be gating factor - others may look
at transient response. Whatever the case, the Regions should use those same
criteria for BES exceptions - reduced to some conservative percentage level;
perhaps 10% of the available margin.
4. Do you have concerns about an entity’s ability to obtain the data they would
need to file the Detailed Information to Support an Exception Request? If so,
please be specific with your concerns so that the SDT can fully understand the
problem. Yes: X Comments: Having the data to perform studies of generator
outage effects on the BES may require sharing of potentially confidential and/or
classified information between the generator and transmission entities. Obviously,
“base case” and possibly “N-1” information would need to be shared. Hence, there
needs to be some assurance that information will be provided (Possibly in the
proposed Appendix 5C of the NERC Rules of Procedure).

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Comment
5. Are there other specific characteristics that you feel would be important for
presenting a case and generic enough that they belong in the request? If so, please
identify them here and provide suggested language that could be added to the
document. Yes: No: Comments:
6. Are you aware of any conflicts between the proposed approach and any
regulatory function, rule order, tariff, rate schedule, legislative requirement or
agreement, or jurisdictional issue? If so, please identify them here and provide
suggested language changes that may clarify the issue. Yes: X Comments: This
Detailed Information to Support an Exemption Request document obviously does
not conform to FERC Order 743, Sections 115,116 “NERC should develop an
exemption process that includes clear, objective, transparent, and uniformly
applicable criteria for exemption of facilities that are not necessary for operating
the grid.” The question is will the justification for declining to observe this FERC
directive be sufficient. We would assert that is it a lesser consequence for the BES
to raise the single generation threshold to 75 MVA than it is to violate this FERC
directive by not providing clear, objective, transparent and uniform criteria for the
exemption process. We understand that the FERC directive was not well conceived
in that if a bright line criteria could be developed for the exemption process, it
should be included in the BES Definition itself. However, it leaves the exemption
process that FERC had originally conceived non-attainable and causes angst to the
industry.
7. Are there any other concerns with this approach that haven’t been covered in
previous questions and comments bearing in mind that the definition itself and the
proposed Rules of Procedure changes are posted separately for comments? Please
be as specific as possible with your comments. Yes: No: Comments:
Response: 1. 2. & 3. The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If
the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to
the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of
substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
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Voter
Entity
Segment
Vote
Comment
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the
Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of
the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of
the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting
or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis
for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making
their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric
system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the
technical prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests
will result in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
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Entity
Segment
Vote
Comment
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
4. If confidential data is involved in the submittal, the SDT expects the Regional Entity to work with the submitter to get around this problem.
5. & 7. Thank you for your response.
6. The SDT believes the process is in alignment with Order 743 directives as explained above.
Negative
OPG has cast a negative ballot in the BES Definition poll. Since we disagree with
Colin Anderson Ontario Power 5
the Definition, and the justification for it, we don't see the need for an exception
Generation
process. OPG continues to question the need for the changes required (and costs
Inc.
imposed) as a result of the new BES definition. OPG disagrees in general with
proceeding to implement a 100 kV brightline definition in the absence of a
properly quantified cost/benefit analysis. Entities are being asked to incur a high
cost for no demonstrated benefit in wide-area reliability.
Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and
an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could
have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the
commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive
comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going
to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional
discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception
request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at
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Voter
Entity
Segment
Vote
Comment
the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in the
proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and making a recommendation to the
ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts
as an intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to
what information needs to be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the
Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of
the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of
the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting
or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis
for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the
information aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard
and fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either
party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making
their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account.
Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception
request must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within equipment and electric
system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT firmly believes that the
technical prowess of the ERO Panel, the visibility of the process, and the experience gained by having this same panel review multiple requests
will result in an equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the
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Voter
Entity
Segment
Vote
Comment
proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be
solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The
SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The
SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on
actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this
problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and
equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and
casting your ballot and hopes that these changes will result in a favorable outcome.
The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to improve
clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES Elements. The SDT’s
efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s concerns as expressed in the
directives contained in Orders No. 743 & 743-A. To accomplish these goals, the SDT has pursued a definition that remains as consistent as
possible with the existing definition, while not significantly expanding or contracting the current scope of the BES or driving registration or deregistration. With this in mind, the SDT acknowledges that the current BES definition has varying degrees of Regional application and has
resulted in different conclusions on what is currently considered to be part of the BES. This inconsistency in the application and subsequent
results were also identified by the Commission in Orders No. 743 & 743-A as a significant concern. The SDT acknowledges that by developing a
bright-line definition coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on
Regions. Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid on a
continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the development of Regional
transition plans once the definition has been approved by the Commission.
5
Negative
Process should make it easier to prove facility is a non-BES; process should take
Steven Grega
Public Utility
into account the plant load factor, if the plant is dispatchable and if it cricital
District No. 1
resource as determine by the BA. Most facilities should be able to prove they are
of Lewis
not part of the BES. In WECC, only critical cranking paths are part of BES.
County
Response: The SDT has attempted to make the exception process as easy as possible while still providing the information necessary to properly
process a request. Factors such as described by the commenter can be supplied with the submittal as there is no limit or constraint on
additional information that can be supplied by the submitter.
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Voter
Larry Nordell

Entity
Montana
Consumer
Counsel

Segment
8

Vote
Negative

Comment
The BES exception process must be cognizant of costs and benefits. In addition to
the explicit information required in the current proposal it needs to provide an
opportunity for an exception for elements whose failure would have no
consequential impacts on the bulk system, and a process for an exception for
elements for which the costs inclusion can be shown to be clearly in excess of the
benefits of inclusion.
Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES Elements. The
SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s concerns as expressed
in the directives contained in Orders No. 743 & 743-A. To accomplish these goals, the SDT has pursued a definition that remains as consistent as
possible with the existing definition, while not significantly expanding or contracting the current scope of the BES or driving registration or deregistration. With this in mind, the SDT acknowledges that the current BES definition has varying degrees of Regional application and has
resulted in different conclusions on what is currently considered to be part of the BES. This inconsistency in the application and subsequent
results were also identified by the Commission in Orders No. 743 & 743-A as a significant concern. The SDT acknowledges that by developing a
bright-line definition coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on
Regions. Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid on a
continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the development of Regional
transition plans once the definition has been approved by the Commission.
Diane J Barney National
9
Negative
The draft definition has a circularity issue with the Registry, lacks clarity in some
Association of
aspects, and lacks a technical basis and cost/benefit analysis. (See specific
Regulatory
comments submitted.)
Utility
Commissioners
Response: Please see the specific responses provided.
John D Varnell

Tenaska Power
Services Co.

6

Abstain

Which part of this definition has the highest priority inclusions or exclusions.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the
vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and non-BES
Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or higher as included
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Voter
Entity
Segment
Vote
Comment
in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed. Element is defined in the
NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker, bus
section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application of the
‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific criteria to provide
for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion language
is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the exclusion
language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The exclusion (E1) only
speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner.
Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and supersedes
inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected transmission
network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude an Element.
Brenda Powell Constellation
6
Affirmative While the Technical Principles for BES Exception are acceptable, they are quite
Energy
complicated. Further simplification may ease the process.
Commodities
Group
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Entity
Segment
Vote
Comment
Response: The SDT has attempted to make the exception process as easy as possible while still providing the information necessary to properly
process a request.
Greg Lange

Public Utility
District No. 2
of Grant
County

3

Affirmative Public Utility District No. 2 of Grant County (GCPD) agrees that the General
Instructions set forth the basic information that would be necessary to support an
Exception Request. GCPD is concerned, however, that the statement “diagram(s)
supplied should also show the Protection Systems at the interface points
associated with the Elements for which the exception is being requested” may be
subject to differing interpretations. GCPD envisions that at least four different
kinds of documents would be responsive to the description: one-line diagrams
with breakers and switches (status); identification of relays by their ANSI device
numbers; details of the DC control logic for ANSI devices; and, operational scheme
descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to
identify protection systems at the interface with the Elements for which the
Exception is sought, including any required details.
GCPD suggests that a generic example of a completed form be available to the
industry to help ensure that Exception Requests are supported by consistent and
complete information. Such a generic example could be addressed in the Phase 2
BES efforts.
GCPD agrees that the items listed on page 4 of the Detailed Information to Support
an Exception Request capture the information that generally would be necessary
to make a reasoned determination concerning the BES status of a generation
facility. GCPD suggests three refinements to the questions: (1) Question 2 should
be modified by adding “necessary for the operation of the interconnected bulk
transmission system” to the end of the question, so that it reads: “Is the generator
or the generator facility used to provide Ancillary Services necessary for the
operation of the interconnected bulk transmission system?” The italicized
language is necessary to distinguish between a generator that provides, for
example, reactive power or regulating reserves that support operation of the
interconnected bulk grid, and, for example, a behind-the-meter generator that
provides back-up generation to a specific industrial facility. The former may be
necessary for the reliable operation of the interconnected bulk transmission
system, but the latter is not.

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Entity

Segment

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Comment
(2) The current draft of the BES Definition contains Exclusions for radials and for
Local Networks. To be consistent with these aspects of the revised BES definition,
GCPD suggests modifying question 5 by adding “radial, or Local Network” to the
question, so that it would read: “Does the generator use the BES, a radial system,
or a Local Network to deliver its actual or scheduled output, or a portion of its
actual or scheduled output, to Load?
(3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an
Exception Request for a generator to submit any information it believes is relevant
to the Exception that is not captured in the previous questions. We suggest the
following language: Is there additional information not covered in questions 1
through 5 that supports the Exception Request? If yes, please provide the
information and explain why it is relevant to the Exception Request. This will allow
an entity seeking an Exception for a generator to identify any unusual
circumstances or non-standard information that might support its Exception
Request. An entity seeking such an Exception should have the opportunity to
present any information it believes is relevant.
Response: The SDT believes that the form allows for the flexibility of an entity supplying any types of diagrams that it believes will support its
request. This is a preferable situation to coming up with a hard coded list. No change made.
The SDT will consider completing a sample form in Phase II.
The SDT has modified the wording of the question to clarify the intent.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
The SDT does not believe that the suggested wording change provides any additional clarification and may even cause confusion. No change
made.
The SDT agrees that any information that might support a request should be allowed and has clarified the wording on page 1 to that effect.
Page 1 - List any attached supporting documents and any additional information that is included to supports the request:
Jeffrey S
North Carolina 5
Affirmative In general, we support the “Detailed Information to Support an Exception
Brame
Electric
Request”. However, we have identified a few concerns that warrant the SDT’s
Membership
consideration. Q1, Q5 and Q6 in the Transmission Facilities section have a
Corp.
“Description/Comments” section. What type of information should be included
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Voter

Entity

Segment

Vote

Comment
under the Description for each of these questions? Providing more guidance here
would help achieve the “standardization, clarity and continuity of process” that we
seek. Regarding Q2: A permanent flowgate should not be part of the detailed
information to support an exception. First, there is no definition for what
constitutes a permanent flowgate. Second, flowgates are often created for a
myriad of reasons that have nothing to do with them being necessary to operate
the BES. While section c) in E3 attempts to limit the applicability to permanent
flowgates, there is no definition for what constitutes a permanent flowgate
particularly since no flowgate is truly permanent. The NERC Glossary of Terms
definition of flowgate includes flowgates in the IDC. This is a problem because
flowgates are included in the IDC for many reasons not just because reliability
issues are identified. Flowgates could be included to simply study the impact of
schedules on a particular interface as an example. It does not mean the interface is
critical. As an example, it could be used to generate evidence that there are no
ransactional impacts to support exclusion from the BES. Furthermore, the list of
flowgates in the IDC is dynamic. The master list of IDC flowgates is updated
monthly and IDC users can add temporary flowgates at anytime. While the
permanent adjective applied to flowgates probably limits the applicability from the
“temporary” flowgates, it is not clear which of the monthly flowgates would be
included from the IDC since they might be added one month and removed
another. In the Transmission Facilities section, we are unclear about what “an
appropriate list” in Q3 is supposed to be. Is it supposed to be a list of all IROLs or
only those for which the answer is yes? Why is a list even necessary since the
answer to the question answers Exclusion E3.c? If the answer to Q3 is no, is this
asking the submitter to prove the negative? For Q2 in the Generation Facilities
section, the definition of ancillary services varies and can be quite broad. It can
include reactive power and voltage support for example. All generators provide
some reactive power and voltage support. Thus, ancillary services should be
further defined or one could construe it to limit any generator from being
excluded. For Q1 in the Generation Facilities section, some generation owners may
not be able to obtain their BA’s most severe single Contingency. Many generator
owners will not have access to the data necessary to demonstrate the reliability
impact to the BES. This is particularly true for transmission dependent utilities.

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Voter
Doug White

Entity
North Carolina
Electric
Membership
Corp.

Segment
3

Vote
Comment
Affirmative In general, we support the proposed definition of the BES. However, we have
identified a few concerns that warrant the SDT’s consideration. We’d prefer to see
the language from the ERO Statement of Compliance Registry Criteria repeated
within the BES Definition itself instead of referencing an outside document. As it
stands right now, the Compliance Registry Criteria needs to stay intact for Phase I
of this project. That makes the Compliance Registry Criteria reliant on the BES
Definition and vice versa. We understand that the Statement of Compliance
Registry Criteria may be reviewed/revised at the same time Phase 2 of this project
is being developed, therefore we agree with Inclusion I2 of this draft.
Blackstart Resources can actually be on the distribution system. There is still the
question of whether the distribution system would then be subjected to the
enforceable standards. If so, there would most likely be a significant cost increase
associated with tracking compliance for these distribution systems without a
commensurate increase in reliability since Blackstart Resources are rarely used.
This could very well cause entities to un-designate Blackstart Resources on
distribution systems to avoid these distribution systems from becoming part of the
BES. The same rationale that was used for eliminating cranking paths could also be
applied to Blackstart Resources.
A flowgate should not be used to limit applicability of E3. First, there is no
definition for what constitutes a permanent flowgate. Second, flowgates are often
created for a myriad of reasons that have nothing to do with them being necessary
to operate the BES. While section c) in E3 attempts to limit the applicability to
permanent flowgates, there is no definition for what constitutes a permanent
flowgate particularly since no flowgate is truly permanent. The NERC Glossary of
Terms definition of flowgate includes flowgates in the IDC. This is a problem
because flowgates are included in the IDC for many reasons not just because
reliability issues are identified. Flowgates could be included to simply study the
impact of schedules on a particular interface as an example. It does not mean the
interface is critical. As an example, it could be used to generate evidence that
there are no transactional impacts to support exclusion from the BES.
Furthermore, the list of flowgates in the IDC is dynamic. The master list of IDC
flowgates is updated monthly and IDC users can add temporary flowgates at
anytime. While the “permanent” adjective applied to flowgates probably limits the

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Entity

Segment

Vote

Comment
applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month
and removed another. Flowgates are created for many reasons that have nothing
to do with them being necessary to operate the BES. First, flowgates are created to
manage congestion. The IDC is more of a congestion management tool than a
reliability tool. FERC recognized this in Order 693, when they directed NERC to
make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs that
have been violated. Rather, other actions such as re-dispatch must be used in
conjunction. Second, flowgates are used as a convenient point to calculate flows to
sell transmission service. The characteristics of the flowgate make it a good proxy
for estimating how much contractual use has been sold not necessarily how much
flow will actually occur. While some flowgates definitely are created for reliability
issues such as IROLs, many simply are not.
The term “non-retail generation” used in Exclusion E1 (item c) and again in E3
(item a) should be clarified (see comments for question 8 below). The Note after
item c should also be clarified to indicate that closing a normally open switch
doesn’t affect this exclusion.
Detailed Information to Support an Exception Request: Vote affirmative with the
comments below Comments for Ballot (these may be copied and pasted ): In
general, we support the “Detailed Information to Support an Exception Request”.
However, we have identified a few concerns that warrant the SDT’s consideration.
Q1, Q5 and Q6 in the Transmission Facilities section have a
“Description/Comments” section. What type of information should be included
under the Description for each of these questions? Providing more guidance here
would help achieve the “standardization, clarity and continuity of process” that we
seek. Regarding
Q2: A permanent flowgate should not be part of the detailed information to
support an exception. First, there is no definition for what constitutes a permanent
flowgate. Second, flowgates are often created for a myriad of reasons that have
nothing to do with them being necessary to operate the BES. While section c) in E3
attempts to limit the applicability to permanent flowgates, there is no definition
for what constitutes a permanent flowgate particularly since no flowgate is truly
permanent. The NERC Glossary of Terms definition of flowgate includes flowgates

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Voter

Entity

Segment

Vote

Comment
in the IDC. This is a problem because flowgates are included in the IDC for many
reasons not just because reliability issues are identified. Flowgates could be
included to simply study the impact of schedules on a particular interface as an
example. It does not mean the interface is critical. As an example, it could be used
to generate evidence that there are no transactional impacts to support exclusion
from the BES. Furthermore, the list of flowgates in the IDC is dynamic. The master
list of IDC flowgates is updated monthly and IDC users can add temporary
flowgates at anytime. While the permanent adjective applied to flowgates
probably limits the applicability from the “temporary” flowgates, it is not clear
which of the monthly flowgates would be included from the IDC since they might
be added one month and removed another.
In the Transmission Facilities section, we are unclear about what “an appropriate
list” in Q3 is supposed to be. Is it supposed to be a list of all IROLs or only those for
which the answer is yes? Why is a list even necessary since the answer to the
question answers Exclusion E3.c? If the answer to Q3 is no, is this asking the
submitter to prove the negative?
For Q2 in the Generation Facilities section, the definition of ancillary services varies
and can be quite broad. It can include reactive power and voltage support for
example. All generators provide some reactive power and voltage support. Thus,
ancillary services should be further defined or one could construe it to limit any
generator from being excluded.
For Q1 in the Generation Facilities section, some generation owners may not be
able to obtain their BA’s most severe single Contingency. Many generator owners
will not have access to the data necessary to demonstrate the reliability impact to
the BES. This is particularly true for transmission dependent utilities.
Response: In response to comments, the SDT has deleted the reference to the ERO Statement of Compliance Registry and replaced it with the
existing numeric values. This way, any changes to the ERO Statement of Compliance Registry prior to resolution of threshold values in Phase II
will not affect the definition.
The SDT has determined that it should be conservative with regard to allowing exclusion for radial systems that are depended upon for
blackstart functionality, as these will arguably be more important to the reliable operation of the transmission system than equivalent radial
systems without blackstart resources. No change made.
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Entity
Segment
Vote
Comment
The SDT believes that the language in Exclusion E3.c prohibiting “Flowgates” from qualifying for definitional exclusion is appropriate and
necessary. As a definitional exclusion characteristic, Exclusion E3.c must follow the principle of being a bright-line and easily identifiable, and as
such, the SDT feels that the definition cannot allow some types of Flowgates and disallow others. Flowgates must continue to be a prohibiting
characteristic under Exclusion E3, since these facilities are more likely to be used in the transfer of bulk power than not. An entity who wishes
to make a case for exclusion of a unique type of Flowgate facility can do so through the exception process. The SDT believes that the continued
qualifier of “permanent” associated with the term “Flowgate” addresses the majority of the concern in this comment. No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The requesting entity should supply any and all information that it feels will help support its request. No change made.
The SDT has modified the wording of the question to clarify the intent.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Any information that an entity believes will support its request should be included. No change made.
The SDT believes that the language in Exclusion E3.c prohibiting “Flowgates” from qualifying for definitional exclusion is appropriate and
necessary. As a definitional exclusion characteristic, Exclusion E3.c must follow the principle of being a bright-line and easily identifiable, and as
such, the SDT feels that the definition cannot allow some types of Flowgates and disallow others. Flowgates must continue to be a prohibiting
characteristic under Exclusion E3, since these facilities are more likely to be used in the transfer of bulk power than not. An entity who wishes
to make a case for exclusion of a unique type of Flowgate facility can do so through the exception process. The SDT believes that the continued
qualifier of “permanent” associated with the term “Flowgate” addresses the majority of the concern in this comment. No change made.
The SDT believes that the wording is clear as stated and that the list would be those IROLs that include the Element(s) in question. No change
made.
The SDT has modified the wording of the question to clarify the intent.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Based on the comments received, the SDT believes that entities will be able to obtain the requisite information necessary to submit a request.
However, should an entity have difficulty, they will need to obtain the assistance of their Regional Entity to secure the data. If the entity still
can’t obtain the needed data, then the SDT fully expects that entity’s Regional Entity to work with them to come up with a plan that will allow
that entity to fill out the request form in a manner that will be acceptable to the Regional Entity so that processing of the request can continue.
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Voter
Claston
Augustus
Sunanon

Entity
Orlando
Utilities
Commission

Segment
6

Vote
Comment
Affirmative Orlando Utilities Commission supports the new definition, although our support is
conditioned on: (1) a workable Exceptions process being developed in conjunction
with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II
of the standards development process in accordance with the SAR recently put
forward by the SDT, which would address a number of important technical issues
that have been identified in the standards development process to date.
Brad Chase
Orlando
1
Affirmative Orlando Utilities Commission supports the new definition, although our support is
Utilities
conditioned on: (1) a workable Exceptions process being developed in conjunction
Commission
with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II
of the standards development process in accordance with the SAR recently put
forward by the SDT, which would address a number of important technical issues
that have been identified in the standards development process to date. in
addition, phase II should include a clear distinction between the BES and BPS.
3
Affirmative Orlando Utilities Commission supports the new definition, although our support is
Ballard K
Orlando
conditioned on: (1) a workable Exceptions process being developed in conjunction
Mutters
Utilities
with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II
Commission
of the standards development process in accordance with the SAR recently put
forward by the SDT, which would address a number of important technical issues
that have been identified in the standards development process to date.
Response: The exception process is being worked on in parallel with the definition and will be part of the same filing.
Phase II will start up as soon as Phase I is completed and the SDT has the available resources to work on it.
Noman Lee
Williams

Sunflower
Electric Power
Corporation

1

Affirmative Q1, Q5 and Q6 in the Transmission Facilities section have a
“Description/Comments” section. What type of information should be included
under the Description for each of these questions? Providing more guidance here
would help achieve the “standardization, clarity and continuity of process” that we
seek.
Regarding Q2: A permanent flowgate should not be part of the detailed
information to support an exception. First, there is no definition for what
constitutes a permanent flowgate. Second, flowgates are often created for a
myriad of reasons that have nothing to do with them being necessary to operate
the BES. While section c) in E3 attempts to limit the applicability to permanent
flowgates, there is no definition for what constitutes a permanent flowgate
particularly since no flowgate is truly permanent. The NERC Glossary of Terms

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Voter

Entity

Segment

Vote

Comment
definition of flowgate includes flowgates in the IDC. This is a problem because
flowgates are included in the IDC for many reasons not just because reliability
issues are identified. Flowgates could be included to simply study the impact of
schedules on a particular interface as an example. It does not mean the interface is
critical. As an example, it could be used to generate evidence that there are no
transactional impacts to support exclusion from the BES. Furthermore, the list of
flowgates in the IDC is dynamic. The master list of IDC flowgates is updated
monthly and IDC users can add temporary flowgates at anytime. While the
permanent adjective applied to flowgates probably limits the applicability from the
“temporary” flowgates, it is not clear which of the monthly flowgates would be
included from the IDC since they might be added one month and removed
another. Flowgates are created for many reasons that have nothing to do with
them being necessary to operate the BES. First,flowgates are created to manage
congestion. The IDC is more of a congestion management tool than a reliability
tool. FERC recognized this in Order 693, when they directed NERC to make clear in
IRO-006 that the IDC should not be relied upon to relieve IROLs that have been
violated. Rather, other actions such as re-dispatch must be used in conjunction.
Second, flowgates are used as a convenient point to calculate flows to sell
transmission service. The characteristics of the flowgate make it a good proxy for
estimating how much contractual use has been sold not necessarily how much
flow will actually occur. While some flowgates definitely are created for reliability
issues such as IROLs, many simply are not.
In the Transmission Facilities section, we are unclear about what “an appropriate
list” in Q3 is supposed to be. Is it supposed to be a list of all IROLs or only those for
which the answer is yes? Why is a list even necessary since the answer to the
question answers Exclusion E3.c? If the answer to Q3 is no, is this asking the
submitter to prove the negative?
For Q2 in the Generation Facilities section, the definition of ancillary services varies
and can be quite broad. It can include reactive power and voltage support for
example. All generators provide some reactive power and voltage support. Thus,
ancillary services should be further defined or one could construe it to limit any
generator from being excluded.
For Q1 in the Generation Facilities section, some generation owners may not be

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Voter

James Jones

Entity

Southwest
Transmission
Cooperative,
Inc.

Segment

1

Vote

Comment
able to obtain their BA’s most severe single Contingency. Many generator owners
will not have access to the data necessary to demonstrate the reliability impact to
the BES. This is particularly true for transmission dependent utilities.
Affirmative In general, we support the “Detailed Information to Support an Exception
Request”. However, we have identified a few concerns that warrant the SDT’s
consideration. Q1, Q5 and Q6 in the Transmission Facilities section have a
“Description/Comments” section. What type of information should be included
under the Description for each of these questions? Providing more guidance here
would help achieve the “standardization, clarity and continuity of process” that we
seek.
Regarding Q2: A permanent flowgate should not be part of the detailed
information to support an exception. First, there is no definition for what
constitutes a permanent flowgate. Second, flowgates are often created for a
myriad of reasons that have nothing to do with them being necessary to operate
the BES. While section c) in E3 attempts to limit the applicability to permanent
flowgates, there is no definition for what constitutes a permanent flowgate
particularly since no flowgate is truly permanent. The NERC Glossary of Terms
definition of flowgate includes flowgates in the IDC. This is a problem because
flowgates are included in the IDC for many reasons not just because reliability
issues are identified. Flowgates could be included to simply study the impact of
schedules on a particular interface as an example. It does not mean the interface is
critical. As an example, it could be used to generate evidence that there are no
transactional impacts to support exclusion from the BES. Furthermore, the list of
flowgates in the IDC is dynamic. The master list of IDC flowgates is updated
monthly and IDC users can add temporary flowgates at anytime. While the
permanent adjective applied to flowgates probably limits the applicability from the
“temporary” flowgates, it is not clear which of the monthly flowgates would be
included from the IDC since they might be added one month and removed
another. Flowgates are created for many reasons that have nothing to do with
them being necessary to operate the BES. First,flowgates are created to manage
congestion. The IDC is more of a congestion management tool than a reliability
tool. FERC recognized this in Order 693, when they directed NERC to make clear in
IRO-006 that the IDC should not be relied upon to relieve IROLs that have been

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Voter

Entity

Segment

Vote

Comment
violated. Rather, other actions such as re-dispatch must be used in conjunction.
Second, flowgates are used as a convenient point to calculate flows to sell
transmission service. The characteristics of the flowgate make it a good proxy for
estimating how much contractual use has been sold not necessarily how much
flow will actually occur. While some flowgates definitely are created for reliability
issues such as IROLs, many simply are not.
In the Transmission Facilities section, we are unclear about what “an appropriate
list” in Q3 is supposed to be. Is it supposed to be a list of all IROLs or only those for
which the answer is yes? Why is a list even necessary since the answer to the
question answers Exclusion E3.c? If the answer to Q3 is no, is this asking the
submitter to prove the negative?
For Q2 in the Generation Facilities section, the definition of ancillary services varies
and can be quite broad. It can include reactive power and voltage support for
example. All generators provide some reactive power and voltage support. Thus,
ancillary services should be further defined or one could construe it to limit any
generator from being excluded.
For Q1 in the Generation Facilities section, some generation owners may not be
able to obtain their BA’s most severe single Contingency. Many generator owners
will not have access to the data necessary to demonstrate the reliability impact to
the BES. This is particularly true for transmission dependent utilities.
Response: Any information that an entity believes will support its request should be included. No change made.
The SDT believes that the language in Exclusion E3.c prohibiting “Flowgates” from qualifying for definitional exclusion is appropriate and
necessary. As a definitional exclusion characteristic, Exclusion E3.c must follow the principle of being a bright-line and easily identifiable, and as
such, the SDT feels that the definition cannot allow some types of Flowgates and disallow others. Flowgates must continue to be a prohibiting
characteristic under Exclusion E3, since these facilities are more likely to be used in the transfer of bulk power than not. An entity who wishes
to make a case for exclusion of a unique type of Flowgate facility can do so through the exception process. The SDT believes that the continued
qualifier of “permanent” associated with the term “Flowgate” addresses the majority of the concern in this comment. No change made.
Any information that an entity believes will support its request should be included. No change made.
The SDT has modified the wording of the question to clarify the intent.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Based on the comments received, the SDT believes that entities will be able to obtain the requisite information necessary to submit a request.
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Voter
Entity
Segment
Vote
Comment
However, should an entity have difficulty, they will need to obtain the assistance of their Regional Entity to secure the data. If the entity still
can’t obtain the needed data, then the SDT fully expects that entity’s Regional Entity to work with them to come up with a plan that will allow
that entity to fill out the request form in a manner that will be acceptable to the Regional Entity so that processing of the request can continue.
Paul
City of Redding 5
Affirmative Redding's vote is conditional on the adoption and dedication to Phase 2 of this
Cummings
project.
Response: Phase II will begin as soon as Phase I is over and the SDT has the resources available to continue.
Sam Nietfeld

Snohomish
County PUD
No. 1

5

Affirmative Below are SNPD’s responses to the NERC comment form for the Definition of the
BES (Project 2010-17)Technical Principles for Demonstrating BES Exceptions).
SNPD believes the refinements below will clarify the current draft of the BES
definition, without hanging the current intent. 1. Page one of the ‘Detailed
Information to Support an Exception Request’ contains general instructions. Do
you agree with the instructions presented or is there information that you believe
needs to be on page one that is missing? Please be as specific as possible with your
comments. Comments: SNPD agrees generally that the General Instructions set
forth the basic information that would be necessary to support an Exception
Request. SNPD is concerned, however, that the statement “diagram(s) supplied
should also show the Protection Systems at the interface points associated with
the Elements for which the exception is being requested” may be subject to
differing interpretations. SNPD envisions that at least four different kinds of
documents would be responsive to the description: one-line diagrams with
breakers and switches (status); identification of relays by their ANSI device
numbers; details of the DC control logic for ANSI devices; and, operational scheme
descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to
identify protection systems at the interface with the Elements for which the
Exception is sought, including any required details, such as breaker settings. SNPD
suggests that a generic example of a completed form be available to the industry
to help ensure that Exception Requests are supported by consistent and complete
information. Such a generic example could be addressed in the Phase 2 BES
efforts. 2. Pages two and three of the Detailed Information to Support an
Exception Request contain a checklist of items that deal with transmission
facilities. Do you agree with the information being requested or is there

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73

Voter

Entity

Segment

Vote

Comment
information that you believe needs to be on page two or three that is missing?
Please be as specific as possible with your comments. Comments: SNPD agrees
that the checklist of items on pages two and three lists most of the information
that would be necessary to determine if an Exceptions Request is justified. We
suggest three modifications to the proposed language to ensure consistency with
Section 215 of the Federal Power Act, with the BES Definition, and to provide an
entity seeking an Exception with the opportunity to submit all relevant
information: 1) SNPD suggests that a new question should be added concerning
the function of the facility, which would read: “Does the facility function as a local
distribution facility rather than a Transmission facility? If yes, please provide a
detailed explanation of your answer.” Section 215(a)(1) of the FPA makes clear
that “facilities used in the local distribution of electric energy” are excluded from
the BES, 16 U.S.C. § 824o(a)(1), and the most recent draft of the BES definition
incorporates the same language. SNPD believes a question to address the function
of the Element or system subject to an Exception Request is necessary to
determine whether the Element or system is “used” in local distribution and
thereby to ensure that this statutory limit on the BES is observed in the Exceptions
process. Further, we believe a variety of information may be relevant to
determining whether a particular facility functions as local distribution rather than
as part of the BES. For example, if power is not scheduled across the facility or if
capacity on the system is not posted on the relevant OASIS, it is likely to function
as local distribution, not transmission. Similarly, if power enters the system and is
delivered to load within the system rather than moving to load located on another
system, its function is local distribution rather than transmission. SNPD proposes
the language above as an open-ended question so that the entity submitting the
Exceptions Request can provide this and any other information it deems relevant
to facility function. 2) SNPD suggests modifying question 6 to “Is the facility part a
designated Cranking Path associated with a Blackstart Resource identified in a
Transmission Operator’s restoration plan.” This language reflects the most recent
revision of the BES Definition and also helps distinguish between generators which
have Blackstart capability and those generators that are designated as a Blackstart
Resource in the Transmission Operator’s restoration plan. It is only the latter that
are included in the BES under the current draft of the definition. 3) A general

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74

Voter

Entity

Segment

Vote

Comment
“catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following
language: Is there additional information not covered in the questions above that
supports the Exception Request? If yes, please provide the information and explain
why it is relevant to the Exception Request. While SNPD believes the questions set
forth in the draft capture the information that generally would be necessary to
determine whether an Exception Request should be granted, it is foreseeable that
there may be unusual circumstances where the information called for either does
not capture the full picture or where studies other than the specific types called
for in the draft form support the Exception. An entity seeking an Exception should
have the opportunity to present any information it believes is relevant. 3. Page
four of the ‘Detailed Information to Support an Exception Request’ contains a
checklist of items that deal with generation facilities. Do you agree with the
information being requested or is there information that you believe needs to be
on page four that is missing? Please be as specific as possible with your comments.
Comments: SNPD agrees that the items listed on page 4 of the Detailed
Information to Support an Exception Request capture the information that
generally would be necessary to make a reasoned determination concerning the
BES status of a generation facility. SNPD suggests three refinements to the
questions: 1) Question 2 should be modified by adding “necessary for the
operation of the interconnected bulk transmission system” to the end of the
question, so that it reads: “Is the generator or the generator facility used to
provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between
a generator that provides, for example, reactive power or regulating reserves that
support operation of the interconnected bulk grid, and, for example, a behind-themeter generator that provides back-up generation to a specific industrial facility.
The former may be necessary for the reliable operation of the interconnected bulk
transmission system, but the latter is not. 2) The current draft of the BES Definition
contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, SNPD suggests modifying question 5 by
adding “radial, or Local Network” to the question, so that it would read: “Does the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

75

Voter

John D
Martinsen

Entity

Public Utility
District No. 1
of Snohomish
County

Segment

4

Vote

Comment
generator use the BES, a radial system, or a Local Network to deliver its actual or
scheduled output, or a portion of its actual or scheduled output, to Load? 3) For
reasons similar to those explained in our response to Question 2, a general “catchall” question should be added that will prompt an entity submitting an Exception
Request for a generator to submit any information it believes is relevant to the
Exception that is not captured in the previous questions. We suggest the following
language: Is there additional in
Affirmative Below are SNPD’s responses to the NERC comment form for the Definition of the
BES (Project 2010-17)Technical Principles for Demonstrating BES Exceptions).
SNPD believes the refinements below will clarify the current draft of the BES
definition, without hanging the current intent. 1. Page one of the ‘Detailed
Information to Support an Exception Request’ contains general instructions. Do
you agree with the instructions presented or is there information that you believe
needs to be on page one that is missing? Please be as specific as possible with your
comments. Comments: SNPD agrees generally that the General Instructions set
forth the basic information that would be necessary to support an Exception
Request. SNPD is concerned, however, that the statement “diagram(s) supplied
should also show the Protection Systems at the interface points associated with
the Elements for which the exception is being requested” may be subject to
differing interpretations. SNPD envisions that at least four different kinds of
documents would be responsive to the description: one-line diagrams with
breakers and switches (status); identification of relays by their ANSI device
numbers; details of the DC control logic for ANSI devices; and, operational scheme
descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to
identify protection systems at the interface with the Elements for which the
Exception is sought, including any required details, such as breaker settings. SNPD
suggests that a generic example of a completed form be available to the industry
to help ensure that Exception Requests are supported by consistent and complete
information. Such a generic example could be addressed in the Phase 2 BES
efforts. 2. Pages two and three of the Detailed Information to Support an
Exception Request contain a checklist of items that deal with transmission
facilities. Do you agree with the information being requested or is there

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

76

Voter

Entity

Segment

Vote

Comment
information that you believe needs to be on page two or three that is missing?
Please be as specific as possible with your comments. Comments: SNPD agrees
that the checklist of items on pages two and three lists most of the information
that would be necessary to determine if an Exceptions Request is justified. We
suggest three modifications to the proposed language to ensure consistency with
Section 215 of the Federal Power Act, with the BES Definition, and to provide an
entity seeking an Exception with the opportunity to submit all relevant
information: 1) SNPD suggests that a new question should be added concerning
the function of the facility, which would read: “Does the facility function as a local
distribution facility rather than a Transmission facility? If yes, please provide a
detailed explanation of your answer.” Section 215(a)(1) of the FPA makes clear
that “facilities used in the local distribution of electric energy” are excluded from
the BES, 16 U.S.C. § 824o(a)(1), and the most recent draft of the BES definition
incorporates the same language. SNPD believes a question to address the function
of the Element or system subject to an Exception Request is necessary to
determine whether the Element or system is “used” in local distribution and
thereby to ensure that this statutory limit on the BES is observed in the Exceptions
process. Further, we believe a variety of information may be relevant to
determining whether a particular facility functions as local distribution rather than
as part of the BES. For example, if power is not scheduled across the facility or if
capacity on the system is not posted on the relevant OASIS, it is likely to function
as local distribution, not transmission. Similarly, if power enters the system and is
delivered to load within the system rather than moving to load located on another
system, its function is local distribution rather than transmission. SNPD proposes
the language above as an open-ended question so that the entity submitting the
Exceptions Request can provide this and any other information it deems relevant
to facility function. 2) SNPD suggests modifying question 6 to “Is the facility part a
designated Cranking Path associated with a Blackstart Resource identified in a
Transmission Operator’s restoration plan.” This language reflects the most recent
revision of the BES Definition and also helps distinguish between generators which
have Blackstart capability and those generators that are designated as a Blackstart
Resource in the Transmission Operator’s restoration plan. It is only the latter that
are included in the BES under the current draft of the definition. 3) A general

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

77

Voter

Entity

Segment

Vote

Comment
“catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following
language: Is there additional information not covered in the questions above that
supports the Exception Request? If yes, please provide the information and explain
why it is relevant to the Exception Request. While SNPD believes the questions set
forth in the draft capture the information that generally would be necessary to
determine whether an Exception Request should be granted, it is foreseeable that
there may be unusual circumstances where the information called for either does
not capture the full picture or where studies other than the specific types called
for in the draft form support the Exception. An entity seeking an Exception should
have the opportunity to present any information it believes is relevant. 3. Page
four of the ‘Detailed Information to Support an Exception Request’ contains a
checklist of items that deal with generation facilities. Do you agree with the
information being requested or is there information that you believe needs to be
on page four that is missing? Please be as specific as possible with your comments.
Comments: SNPD agrees that the items listed on page 4 of the Detailed
Information to Support an Exception Request capture the information that
generally would be necessary to make a reasoned determination concerning the
BES status of a generation facility. SNPD suggests three refinements to the
questions: 1) Question 2 should be modified by adding “necessary for the
operation of the interconnected bulk transmission system” to the end of the
question, so that it reads: “Is the generator or the generator facility used to
provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between
a generator that provides, for example, reactive power or regulating reserves that
support operation of the interconnected bulk grid, and, for example, a behind-themeter generator that provides back-up generation to a specific industrial facility.
The former may be necessary for the reliable operation of the interconnected bulk
transmission system, but the latter is not. 2) The current draft of the BES Definition
contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, SNPD suggests modifying question 5 by
adding “radial, or Local Network” to the question, so that it would read: “Does the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

78

Voter

William T
Moojen

Entity

Snohomish
County PUD
No. 1

Segment

6

Vote

Comment
generator use the BES, a radial system, or a Local Network to deliver its actual or
scheduled output, or a portion of its actual or scheduled output, to Load? 3) For
reasons similar to those explained in our response to Question 2, a general “catchall” question should be added that will prompt an entity submitting an Exception
Request for a generator to submit any information it believes is relevant to the
Exception that is not captured in the previous questions. We suggest the following
language: Is there additional in
Affirmative Below are SNPD’s responses to the NERC comment form for the Definition of the
BES (Project 2010-17)Technical Principles for Demonstrating BES Exceptions).
SNPD believes the refinements below will clarify the current draft of the BES
definition, without hanging the current intent. 1. Page one of the ‘Detailed
Information to Support an Exception Request’ contains general instructions. Do
you agree with the instructions presented or is there information that you believe
needs to be on page one that is missing? Please be as specific as possible with your
comments. Comments: SNPD agrees generally that the General Instructions set
forth the basic information that would be necessary to support an Exception
Request. SNPD is concerned, however, that the statement “diagram(s) supplied
should also show the Protection Systems at the interface points associated with
the Elements for which the exception is being requested” may be subject to
differing interpretations. SNPD envisions that at least four different kinds of
documents would be responsive to the description: one-line diagrams with
breakers and switches (status); identification of relays by their ANSI device
numbers; details of the DC control logic for ANSI devices; and, operational scheme
descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to
identify protection systems at the interface with the Elements for which the
Exception is sought, including any required details, such as breaker settings. SNPD
suggests that a generic example of a completed form be available to the industry
to help ensure that Exception Requests are supported by consistent and complete
information. Such a generic example could be addressed in the Phase 2 BES
efforts. 2. Pages two and three of the Detailed Information to Support an
Exception Request contain a checklist of items that deal with transmission
facilities. Do you agree with the information being requested or is there

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

79

Voter

Entity

Segment

Vote

Comment
information that you believe needs to be on page two or three that is missing?
Please be as specific as possible with your comments. Comments: SNPD agrees
that the checklist of items on pages two and three lists most of the information
that would be necessary to determine if an Exceptions Request is justified. We
suggest three modifications to the proposed language to ensure consistency with
Section 215 of the Federal Power Act, with the BES Definition, and to provide an
entity seeking an Exception with the opportunity to submit all relevant
information: 1) SNPD suggests that a new question should be added concerning
the function of the facility, which would read: “Does the facility function as a local
distribution facility rather than a Transmission facility? If yes, please provide a
detailed explanation of your answer.” Section 215(a)(1) of the FPA makes clear
that “facilities used in the local distribution of electric energy” are excluded from
the BES, 16 U.S.C. § 824o(a)(1), and the most recent draft of the BES definition
incorporates the same language. SNPD believes a question to address the function
of the Element or system subject to an Exception Request is necessary to
determine whether the Element or system is “used” in local distribution and
thereby to ensure that this statutory limit on the BES is observed in the Exceptions
process. Further, we believe a variety of information may be relevant to
determining whether a particular facility functions as local distribution rather than
as part of the BES. For example, if power is not scheduled across the facility or if
capacity on the system is not posted on the relevant OASIS, it is likely to function
as local distribution, not transmission. Similarly, if power enters the system and is
delivered to load within the system rather than moving to load located on another
system, its function is local distribution rather than transmission. SNPD proposes
the language above as an open-ended question so that the entity submitting the
Exceptions Request can provide this and any other information it deems relevant
to facility function. 2) SNPD suggests modifying question 6 to “Is the facility part a
designated Cranking Path associated with a Blackstart Resource identified in a
Transmission Operator’s restoration plan.” This language reflects the most recent
revision of the BES Definition and also helps distinguish between generators which
have Blackstart capability and those generators that are designated as a Blackstart
Resource in the Transmission Operator’s restoration plan. It is only the latter that
are included in the BES under the current draft of the definition. 3) A general

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

80

Voter

Entity

Segment

Vote

Comment
“catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following
language: Is there additional information not covered in the questions above that
supports the Exception Request? If yes, please provide the information and explain
why it is relevant to the Exception Request. While SNPD believes the questions set
forth in the draft capture the information that generally would be necessary to
determine whether an Exception Request should be granted, it is foreseeable that
there may be unusual circumstances where the information called for either does
not capture the full picture or where studies other than the specific types called
for in the draft form support the Exception. An entity seeking an Exception should
have the opportunity to present any information it believes is relevant. 3. Page
four of the ‘Detailed Information to Support an Exception Request’ contains a
checklist of items that deal with generation facilities. Do you agree with the
information being requested or is there information that you believe needs to be
on page four that is missing? Please be as specific as possible with your comments.
Comments: SNPD agrees that the items listed on page 4 of the Detailed
Information to Support an Exception Request capture the information that
generally would be necessary to make a reasoned determination concerning the
BES status of a generation facility. SNPD suggests three refinements to the
questions: 1) Question 2 should be modified by adding “necessary for the
operation of the interconnected bulk transmission system” to the end of the
question, so that it reads: “Is the generator or the generator facility used to
provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between
a generator that provides, for example, reactive power or regulating reserves that
support operation of the interconnected bulk grid, and, for example, a behind-themeter generator that provides back-up generation to a specific industrial facility.
The former may be necessary for the reliable operation of the interconnected bulk
transmission system, but the latter is not. 2) The current draft of the BES Definition
contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, SNPD suggests modifying question 5 by
adding “radial, or Local Network” to the question, so that it would read: “Does the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

81

Voter

Long T Duong

Entity

Snohomish
County PUD
No. 1

Segment

1

Vote

Comment
generator use the BES, a radial system, or a Local Network to deliver its actual or
scheduled output, or a portion of its actual or scheduled output, to Load? 3) For
reasons similar to those explained in our response to Question 2, a general “catchall” question should be added that will prompt an entity submitting an Exception
Request for a generator to submit any information it believes is relevant to the
Exception that is not captured in the previous questions. We suggest the following
language: Is there additional in
Affirmative Below are SNPD’s responses to the NERC comment form for the Definition of the
BES (Project 2010-17)Technical Principles for Demonstrating BES Exceptions).
SNPD believes the refinements below will clarify the current draft of the BES
definition, without hanging the current intent. 1. Page one of the ‘Detailed
Information to Support an Exception Request’ contains general instructions. Do
you agree with the instructions presented or is there information that you believe
needs to be on page one that is missing? Please be as specific as possible with your
comments. Comments: SNPD agrees generally that the General Instructions set
forth the basic information that would be necessary to support an Exception
Request. SNPD is concerned, however, that the statement “diagram(s) supplied
should also show the Protection Systems at the interface points associated with
the Elements for which the exception is being requested” may be subject to
differing interpretations. SNPD envisions that at least four different kinds of
documents would be responsive to the description: one-line diagrams with
breakers and switches (status); identification of relays by their ANSI device
numbers; details of the DC control logic for ANSI devices; and, operational scheme
descriptions of the type used by system operators. Accordingly, we suggest that
the language be refined to identify the specific kinds of diagrams necessary to
identify protection systems at the interface with the Elements for which the
Exception is sought, including any required details, such as breaker settings. SNPD
suggests that a generic example of a completed form be available to the industry
to help ensure that Exception Requests are supported by consistent and complete
information. Such a generic example could be addressed in the Phase 2 BES
efforts. 2. Pages two and three of the Detailed Information to Support an
Exception Request contain a checklist of items that deal with transmission
facilities. Do you agree with the information being requested or is there

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

82

Voter

Entity

Segment

Vote

Comment
information that you believe needs to be on page two or three that is missing?
Please be as specific as possible with your comments. Comments: SNPD agrees
that the checklist of items on pages two and three lists most of the information
that would be necessary to determine if an Exceptions Request is justified. We
suggest three modifications to the proposed language to ensure consistency with
Section 215 of the Federal Power Act, with the BES Definition, and to provide an
entity seeking an Exception with the opportunity to submit all relevant
information: 1) SNPD suggests that a new question should be added concerning
the function of the facility, which would read: “Does the facility function as a local
distribution facility rather than a Transmission facility? If yes, please provide a
detailed explanation of your answer.” Section 215(a)(1) of the FPA makes clear
that “facilities used in the local distribution of electric energy” are excluded from
the BES, 16 U.S.C. § 824o(a)(1), and the most recent draft of the BES definition
incorporates the same language. SNPD believes a question to address the function
of the Element or system subject to an Exception Request is necessary to
determine whether the Element or system is “used” in local distribution and
thereby to ensure that this statutory limit on the BES is observed in the Exceptions
process. Further, we believe a variety of information may be relevant to
determining whether a particular facility functions as local distribution rather than
as part of the BES. For example, if power is not scheduled across the facility or if
capacity on the system is not posted on the relevant OASIS, it is likely to function
as local distribution, not transmission. Similarly, if power enters the system and is
delivered to load within the system rather than moving to load located on another
system, its function is local distribution rather than transmission. SNPD proposes
the language above as an open-ended question so that the entity submitting the
Exceptions Request can provide this and any other information it deems relevant
to facility function. 2) SNPD suggests modifying question 6 to “Is the facility part a
designated Cranking Path associated with a Blackstart Resource identified in a
Transmission Operator’s restoration plan.” This language reflects the most recent
revision of the BES Definition and also helps distinguish between generators which
have Blackstart capability and those generators that are designated as a Blackstart
Resource in the Transmission Operator’s restoration plan. It is only the latter that
are included in the BES under the current draft of the definition. 3) A general

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

83

Voter

Entity

Segment

Vote

Comment
“catch-all” question should be added that will prompt the entity submitting an
Exception Request to submit any information it believes is relevant to the
Exception that is not captured in the other questions. We suggest the following
language: Is there additional information not covered in the questions above that
supports the Exception Request? If yes, please provide the information and explain
why it is relevant to the Exception Request. While SNPD believes the questions set
forth in the draft capture the information that generally would be necessary to
determine whether an Exception Request should be granted, it is foreseeable that
there may be unusual circumstances where the information called for either does
not capture the full picture or where studies other than the specific types called
for in the draft form support the Exception. An entity seeking an Exception should
have the opportunity to present any information it believes is relevant. 3. Page
four of the ‘Detailed Information to Support an Exception Request’ contains a
checklist of items that deal with generation facilities. Do you agree with the
information being requested or is there information that you believe needs to be
on page four that is missing? Please be as specific as possible with your comments.
Comments: SNPD agrees that the items listed on page 4 of the Detailed
Information to Support an Exception Request capture the information that
generally would be necessary to make a reasoned determination concerning the
BES status of a generation facility. SNPD suggests three refinements to the
questions: 1) Question 2 should be modified by adding “necessary for the
operation of the interconnected bulk transmission system” to the end of the
question, so that it reads: “Is the generator or the generator facility used to
provide Ancillary Services necessary for the operation of the interconnected bulk
transmission system?” The italicized language is necessary to distinguish between
a generator that provides, for example, reactive power or regulating reserves that
support operation of the interconnected bulk grid, and, for example, a behind-themeter generator that provides back-up generation to a specific industrial facility.
The former may be necessary for the reliable operation of the interconnected bulk
transmission system, but the latter is not. 2) The current draft of the BES Definition
contains Exclusions for radials and for Local Networks. To be consistent with these
aspects of the revised BES definition, SNPD suggests modifying question 5 by
adding “radial, or Local Network” to the question, so that it would read: “Does the

Initial Ballot Consideration of Comments – BES Technical Exception Criteria

84

Voter

Comment
generator use the BES, a radial system, or a Local Network to deliver its actual or
scheduled output, or a portion of its actual or scheduled output, to Load? 3) For
reasons similar to those explained in our response to Question 2, a general “catchall” question should be added that will prompt an entity submitting an Exception
Request for a generator to submit any information it believes is relevant to the
Exception that is not captured in the previous questions. We suggest the following
language: Is there additional in
Response: Please see the detailed responses to comments for Snohomish in the general consideration of comments document for the technical
criteria.
Harold Taylor

Entity

Georgia
Transmission
Corporation

Segment

Vote

1

Affirmative Throughout the document, because it will be part of a larger Exception Request
Form, it should, when possible, use terms consistent with the rest of that form
(e.g., “Request” rather than “application”).
Similarly, defined terms (even if only defined in the context of the Request Form in
which these Principles will be used) such as “Exception,” “Request,” “Element” or
“Facility” should be capitalized; if the use of lower case is intended to convey a
different meaning than what is defined, another term should be used to avoid
confusion.
The Definition and Request Form generally use the term “Element,” so it is unclear
why this document should so consistently use “facility.” For consistency,
“Element(s)” or possibly “Element(s) or Facility” should be used.
Response: The SDT has attempted to clean up any inconsistencies in terminology.
Affirmative While the Technical Principles for BES Exception are acceptable, they are quite
Baltimore Gas 1
complicated. Further simplification may ease the process.
& Electric
Company
Response: The SDT would point the commenter to the Phase II draft SAR which contains wording to allow for a review of the principles after a
12 month period of real-world experience.
Gregory S
Miller

Charles A.
Freibert

Louisville Gas
3
Affirmative LG&E and KU Energy request clarification as to how the two year data requirement
and Electric
would apply to a new facility for which the owner/operator requests an
Co.
exemption.
Response: If two years worth of data are not available, the SDT believes that a Regional Entity will accept what is available and will work with
the submitter to come up with an acceptable plan to move forward.
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

85

Voter
Anthony
Schacher

Entity
Salem Electric

Segment
3

Thomas C
Duffy

Central
Hudson Gas &
Electric Corp.

3

Jason Fortik

Lincoln Electric
System

3

Benjamin
Friederichs

Big Bend
3
Electric
Cooperative,
Inc.
Response: Thank you for your support.

Vote
Comment
Affirmative Salem Electric is encouraged to see that the standard drafting team understands
the reality that in many circumstances many small radially fed utilities have no
effect on the bulk electric system. By permitting reasonable and prudent
exceptions it will allow many of the small utilities to be able to spend our limited
time and resources on the reliability of our systems for our end users, instead of
undertaking unnecessary steps to protect a system upon which we have no effect.
The exception process is thorough but still manageable for small utilities with
limited resources. Salem Electric would like to thank the Standards Drafting Team
for their hard work and dedication in defining the Bulk Electric System.
Affirmative The ‘Technical Principles for Demonstrating BES Exceptions’ process was intended
to establish technical exception ‘criteria’ which would be used by the industry to
understand what facilities would qualify for inclusions and exclusions from the
BES. What has been produced, however, is essentially a listing of ‘electrical system
indicators’, identified on the form, which may be material to making a decision
regarding, ‘is it BES or not’. The thresholds (or acceptable values) for the
indicators, however, have not been determined. It is understood that in Phase II of
the BES Definition development process, the SDT will attempt to address these
issues but until that work has been completed, the industry will remain enmeshed
in confusion and inefficient application of resources and funding. Without these
criteria, it is very difficult to believe that this process can be transparent and
consistent.
Affirmative No comments.
Affirmative These principles seem reasonable.

END OF REPORT
Initial Ballot Consideration of Comments – BES Technical Exception Criteria

86

Consideration of Comments

Definition of the Bulk Electric System Exception Criteria (Project 2010-17)
The Bulk Electric System Drafting Team thanks all commenters who submitted comments on the
second draft of the Project 2010-17: Definition of the Bulk Electric System (BES) Exception Criteria.

These standards were posted for a 45-day public comment period from August 26, 2011 through
October 10, 2011. Stakeholders were asked to provide feedback on the standards and associated
documents through a special electronic comment form. There were 72 sets of comments, including
comments from approximately 137 different people from approximately 83 companies representing all
10 Industry Segments as shown in the table on the following pages.
The SDT made the following changes to the request form due to industry comments received:
• General – Clarified the use of facility versus Element(s).
• Page 1 – Corrected typo: List any attached supporting documents and any additional information that is
included to supports the request:
• Generation - Q1. Replaced ‘generator’s or generator facility’s’ with ‘generation resource’s’: What is the
MW value of the host Balancing Authority’s most severe single Contingency and what is the generator’s,
or generator facility’s generation resource’s, percent of this value?
• Generation - Q2. Replaced ‘generator’s or generator facility’s’ with ‘generation resource’s’: Is the
generator or generator facility generation resource used to provide reliability- related Ancillary Services?
• Generation - Q3. Replace ‘generator’ with ‘generation resource’: Is the generator generation resource
designated as a must run unit for reliability?
The SDT feels that it is important to remind the industry that Phase II of this project will begin immediately after the
conclusion of Phase I as SDT resources clear up. The same SDT will follow through with Phase II.
The SDT is recommending that this project be moved forward to the recirculation ballot stage.
There were two comments that were repeated multiple times throughout the various documents. The first topic
was about how to sort through the definition inclusions and exclusions, i.e., which takes precedence. The SDT
offers this guidance on that issue:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied
will identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide
basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation
point between BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and
Reactive Power resources connected at 100 kV or higher as included in the BES. To fully appreciate the scope of
the ‘core’ definition an understanding of the term Element is needed. Element is defined in the NERC Glossary of
Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator,
transformer, circuit breaker, bus section, or transmission line. An element may be comprised of one or more
components. “

Element is basically any electrical device that is associated with the transmission or the generation (generating
resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included
through the application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and
Reactive Power resources with specific criteria to provide for a consistent determination of whether an Element is
classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES
Elements). The exclusion language is written to specifically identify Elements or groups of Elements for potential
exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific
criteria identified in the exclusion language. This does not include the exclusion of Real Power and Reactive
Power resources captured by Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of
the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner. Therefore, the
only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the
customer’s side) and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and
supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the
reliable operation of the interconnected transmission network or an Element as non-BES that is necessary for the
reliable operation of the interconnected transmission network, the Rules of Procedure exception process may be
utilized on a case-by-case basis to either include or exclude an Element.
The second item is about providing specific guidance on how the information on the exception request form will be
used in making decisions on inclusions/exclusions in the exception process. The SDT provides the following
information on this item:
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this
issue. The SDT would like nothing better than to be able to provide a simple continent-wide resolution to this
matter. However, after many hours of discussion and an initial attempt at doing so, it has become obvious to the
SDT that the simple answer that so many desire is not achievable. If the SDT could have come up with the simple
answer, it would have been supplied within the bright-line. The SDT would also like to point out to the
commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very
little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up
front. There are always going to be extenuating circumstances that will influence decisions on individual cases.
One could take this statement to say that the regional discretion hasn’t been removed from the process as
dictated in the Order. However, the SDT disagrees with this position. The exception request form has to be taken
in concert with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks
at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has
been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination.
The Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts as an
intermediary. One can counter that this places the Regional Entity in a position to effectively block a submittal by

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

2

being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the visibility of the
process would belie such an action by the Regional Entity and also believes that one has to have faith in the
integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical
Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This
panel’s findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed
NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the Regional Entity
with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the
exception request. On the other side of this equation, one could make an argument that the Regional Entity has
no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to
be provided and how to interpret the information aren’t shown in the request process. The SDT again points to
the variations that will abound in the requests as negating any hard and fast rules in this regard. However, one is
not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there is
a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this
equation. Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as
to what information needs to be supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for
them to follow in making their decision. The SDT re-iterates the problem with providing such hard and fast rules.
There are just too many variables to take into account. Providing concrete guidelines is going to tie the hands of
the ERO Panel and inevitably result in bad decisions being made. The SDT also refers the commenters to
Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an
exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating
the elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits
so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a
sudden disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT
firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the experience
gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent
approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue
that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been
made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form
will mandate a negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the
proposed NERC Rules of Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece
of evidence provided as part of an Exception Request or response to a question will be solely dispositive in the
determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in
response to industry comments. The SDT believes that these clarifications will make the process tighter and
easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after
12 months of experience. The SDT believes that this time period will allow industry to see if the process is
working correctly and to suggest changes to the process based on actual real-world experience and not just on
suppositions of what may occur in the future. Given the complexity of the technical aspects of this problem and
the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed
a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of
these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

3

All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-17_BES.html
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Standards Processes Manual:
http://www.nerc.com/docs/standards/sc/Standard_Processes_Manual_Approved_May_2010.pdf.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

4

Index to Questions, Comments, and Responses
1.

Page one of the ‘Detailed Information to Support an Exception Request’ contains
general instructions. Do you agree with the instructions presented or is there
information that you believe needs to be on page one that is missing? Please be as
specific as possible with your comments. ....................................................... 13
2. Pages two and three of the Detailed Information to Support an Exception Request
contain a checklist of items that deal with transmission facilities. Do you agree with
the information being requested or is there information that you believe needs to be
on page two or three that is missing? Please be as specific as possible with your
comments. ......................................................................................................49
3. Page four of the ‘Detailed Information to Support an Exception Request’ contains a
checklist of items that deal with generation facilities. Do you agree with the
information being requested or is there information that you believe needs to be on
page four that is missing? Please be as specific as possible with your comments.
....................................................................................................................... 88
4. Do you have concerns about an entity’s ability to obtain the data they would need to
file the ‘Detailed Information to Support an Exception Request’? If so, please be
specific with your concerns so that the SDT can fully understand the problem.108
5. Are there other specific characteristics that you feel would be important for
presenting a case and which are generic enough that they belong in the request? If
so, please identify them here and provide suggested language that could be added to
the document. ............................................................................................... 120
6. Are you aware of any conflicts between the proposed approach and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement, or
jurisdictional issue? If so, please identify them here and provide suggested language
changes that may clarify the issue. ............................................................... 133
7. Are there any other concerns with the proposed approach for demonstrating BES
Exceptions that haven’t been covered in previous questions and comments (bearing
in mind that the definition itself and the proposed Rules of Procedure changes are
posted separately for comments)? Please be as specific as possible with your
comments. .................................................................................................... 142
END OF REPORT ..................................................................................................... 167

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

5

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group
Additional Member

Guy Zito

Northeast Power Coordinating Council
Additional Organization

Region Segment Selection

1.

Alan Adamson

New York State Reliability Council, LLC

NPCC 10

2.

Gregory Campoli

New York Independent System Operator

NPCC 2

3.

Kurtis Chong

Independent Electricity System Operator

NPCC 2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5.

Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC 1

6.

Gerry Dunbar

Northeast Power Coordinating Council

7.

Brian Evans-Mongeon Utility Services

NPCC 8

8.

Mike Garton

Dominion Resources Services, Inc.

NPCC 5

9.

Kathleen Goodman

ISO - New England

NPCC 2

FPL Group, Inc.

NPCC 5

10. Chantel Haswell

NPCC 10

2

3

4

5

6

7

8

9

10

X

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

11. David Kiguel

Hydro One Networks Inc.

NPCC 1

12. Michael Lombardi

Northeast Utilities

NPCC 1

13. Randy MacDonald

New Brunswick Power Transmission

NPCC 9

14. Bruce Metruck

New York Power Authority

NPCC 6

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

16. Robert Pellegrini

The United Illuminating Company

NPCC 1

17. Si Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

18. David Ramkalawan

Ontario Power Generation, Inc.

NPCC 5

19. Saurabh Saksena

National Grid

NPCC 1

20. Michael Schiavone

National Grid

NPCC 1

21. Wayne Sipperly

New York Power Authority

NPCC 5

22. Donald Weaver

New Brunswick System Operator

NPCC 2

23. Ben Wu

Orange and Rockland Utilities

NPCC 1

24. Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC 3

2.

Group

Charles Long

Additional Member

Additional Organization

SERC Planning Standards Subcommittee

SERC

SERC

10

2. John Sullivan

Ameren Services Co.

SERC

1

3. James Manning

NC Electric Membership Corp.

SERC

1

4. Philip Kleckley

SC Electric & Gas Co.

SERC

1

5. Bob Jones

Southern Company Services

SERC

1

6. Jim Kelley

PowerSouth Energy Cooperative SERC

1

Group
Brent Ingebrigtson
No additional members listed.

LG&E and KU Energy

4.

ACES Power Marketing Standards
Collaborators

Group

Jean Nitz

Additional Member

Additional Organization
Buckeye Power, Inc.

2. Susan Sosbe

Wabash Valley Power Association SERC

Group

Jonathan Hayes

4

5

6

7

X

RFC

X

X

X

X

X

3, 4
3

Southwest Power Pool Standards Review

8

9

10

X

Region Segment Selection

1. Mohan Sachdeva

5.

3

Region Segment Selection

1. Pat Huntley

3.

2

X

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

7

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

7

8

9

10

Team
Additional Member

Additional Organization

Region Segment Selection

1. Mark Wurm

Board of Public Utilities City of McPherson SPP

1, 3, 5

2. John Allen

City Utilities of Springfield

1, 4

3. Sean Simpson

Board of Public Utilities City of McPherson SPP

4. Stephen McGie

Coffeyville

SPP

5. Robert Rhodes

Southwest Power Pool

SPP

2

6. Jonathan Hayes

Southwest Power Pool

SPP

2

SPP

6.

1, 3, 5

Group
Steve Rueckert
No additional members listed.

WECC Staff

7.

Bonneville Power Administration

Group

Chris Higgins

Additional Member

Additional Organization
Transmission Internal Ops

WECC 1

2. Chuck Matthews

Transmission Planning

WECC 1

3. Steve Larson

General Counsel

WECC 1, 3, 5, 6

4. Rebecca Berdahl

Long Term Sales and Purchases WECC 3

5. John Anasis

Technical Operations

WECC 1

6. Erika Doot

Generation Support

WECC 1, 3, 5

7. Don Watkins

System Operations

WECC 1

8. Fran Halpin

Duty Scheduling

WECC 5

9. Joe Rogers

Transfer Services

WECC 3

Louis Slade

Dominion

Group

X

X

X

X

X

X

X

X

Region Segment Selection

1. Lorissa Jones

8.

X

Additional Member Additional Organization Region Segment Selection
1. Connie Lowe

RFC

5, 6

2. Mike Garton

MRO

5, 6

3. Michael Gildea

NPCC 5, 6

4. Michael Crowley

Electric Transmission

SERC

1, 3

5. Sean Iseminger

Fossil & Hydro

SERC

5

9.

Group

Bill Middaugh

TSGT G&T

X

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

8

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

7

No additional members listed.
10.

Group

David Thorne

Pepco Holdings Inc

X

X

Additional Member Additional Organization Region Segment Selection
1. Carl Kinsley

Delmarva Power & Light Co RFC

1, 3

11.

Group
Cynthia S. Bogorad
No additional members listed.

Transmission Access Policy Study Group

X

X

12.

Electricity Consumers Resource Council
(ELCON)

X

X

Group
John P. Hughes
No additional members listed.
13.

Group

William D Shultz

Additional Member

Southern Company Generation

Additional Organization

X

X

X

X

X

X

Region Segment Selection

1. Tom Higgins

Southern Company Generation SERC

5

2. Terry Crawley

Southern Company Generation SERC

5

3. Therron Wingard

Southern Company Generation SERC

5

4. Ed Goodwin

Southern Company Generation SERC

5

14.

Group
John Bussman
No additional members listed.

AECI and member G&Ts

15.

Tri-State Generation and Transmission
Assn., Inc. Energy Mangement

16.

Group
David Taylor
No additional members listed.

NERC Staff Technical Review

17.

IRC Standards Review Committee

Group
Janelle Marriott Gill
No additional members listed.

Group

X

Al DiCaprio

X

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Steve Myers

ERCOT

ERCOT 2

2. Mark Thompson

AESO

WECC 2

3. Don Weaver

NBSO

NPCC

2

4. Charles Yeung

SPP

SPP

2

5. Ben Li

IESO

NPCC

2

6. Greg Campoli

NYISO

NPCC

2

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

9

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

7. Katherine Goodman ISO-NE

NPCC

2

8. Terry Bilke

MRO

2

MISO

2

3

4

5

6

8

9

10

X

18.

Individual

William Bush

Holland Board of Public Works

19.

Individual

Silvia Parada Mitchell

Transmission

X

X

X

X

20.

Individual

Sandra Shaffer

PacifiCorp

X

X

X

X

21.

Individual

Janet Smith

Arizona Public Service Company

X

X

X

X

22.

Individual

David Kiguel

Hydro One Networks Inc.

X

X

23.

Individual

John Bee

Exelon

X

X

24.

Individual

Eric Lee Christensen

Snohomish County PUD

X

X

25.

Individual

Greg Rowland

Duke Energy

X

X

26.

Individual

Richard Salgo

NV Energy

X

27.

Individual

Thomas C. Duffy

Central Hudson Gas & Electric Corporation

28.

Individual

Chris de Graffenried

Consolidated Edison Co. of NY, Inc.

X

29.

Individual

Thad Ness

American Electric Power

X

Individual
31. Individual

Anthony Jablonski
Joe Petaski

ReliabilityFirst
Manitoba Hydro

X

32.

Individual

Robert Ganley

Long Island Power Authority

X

33.

Individual

Eric Salsbury

Consumers Energy

34.

Individual

David Burke

Orange and Rockland Utilities, Inc.

35.

Individual

Kathleen Goodman

ISO New England Inc

36.

Individual

Diane Barney

New York State Dept. of Public Service

37.

Individual

John Seelke

PSEg Services Corp

X

38.

Individual

Sylvain Clermont

Hydro-Quebec TransEnergie

X

39.

Individual

Rick Hansen

40.

Individual

41.

Individual

30.

7

X
X

X
X

X

X

X

X

X

X

X

X

X
X
X
X

X
X

X

X

X
X
X
X

X

City of St. George

X

X

Bud Tracy

Blachly-Lane Electric Cooperative

X

Dave Markham

Central Electric Cooperative (CEC)

X

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

X
X

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

42.

Individual

2

3

Clearwater Power Company (CPC)

Individual
44. Individual

Roman Gillen
Dave Sabala

Consumer's Power Inc. (CPI)
Douglas Electric Cooperative (DEC)

45.

Individual

Bryan Case

Fall River Electric Cooperative (FALL)

46.

Individual

Rick Crinklaw

Lane Electric Cooperative (LEC)

47.

Individual

Michael Falvo

Independent Electricity System Operator

48.

Individual

Michael Henry

Lincoln Electric Cooperative (Lincoln)

49.

Individual

Jon Shelby

Individual

Ray Ellis

Individual

Rick Paschall

Northern Lights Inc. (NLI)
Okanogan County Electric Cooperative
(OCEC)
Pacific Northwest Generating Cooperative
(PNGC)

52.

Individual

Heber Carpenter

Raft River Rural Electric Cooperative (RAFT)

53.

Individual

Steve Eldrige

Umatilla Electric Cooperative

54.

Individual

Marc Farmer

West Oregon Electric Cooperative (WOEC)

X

55.

Individual

Steve Alexanderson

Central Lincoln

X

56.

Individual

Saurabh Saksena

National Grid

X

57.

Individual

Darryl Curtis

Oncor Electric Delivery Company LLC

X

58.

Individual

Roger Meader

Coos-Curry Electric Coooperative

59.

Individual

Kirit Shah

Ameren

60.

Individual

Guy Andrews

Georgia System Operations Corporation

Individual
62. Individual

Andrew Gallo
Andy Pusztai

City of Austin dba Austin Energy
ATC LLC

63.

Individual

David Kahly

Kootenai Electric Cooperative

64.

Individual

Linda Jacobson-Quinn

Farmington Electric Utility System

X
X

65.

Individual

Mary Downey

City of Redding Electric Utility

X

50.
51.

61.

5

6

7

8

9

X

Dave Hagen

43.

4

X

X
X
X
X
X
X
X
X
X

X

X

X
X

X
X

X

X
X

X
X

X

X

X

X

X

X

X

X

X

X

X

X

X

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

11

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

66.

Individual

Paul Cummings

Individual

Edwin Tso

City of Redding
Metropolitan Water District of Southern
California

Individual
69. Individual

Rex Roehl
Keith Morisette

Indeck Energy Services
Tacoma Power

70.

Individual

Tracy Richardson

Springfield Utility Board

71.

Individual

Frank Cumpton

BGE

72.

Individual

Gary Carlson

Michigan Public Power Agency

67.
68.

2

3

4

5

6

X
X
X
X

X

X

X

X

X
X

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

X

12

7

8

9

10

1.

Page one of the ‘Detailed Information to Support an Exception Request’ contains general instructions. Do you agree with the
instructions presented or is there information that you believe needs to be on page one that is missing? Please be as specific
as possible with your comments.

Summary Consideration: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on
this issue. The SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However,
after many hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so
many desire is not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the brightline. The SDT would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of
the criteria and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception application form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as
a single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the application to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred
in rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the application process. The SDT again points to the variations that
will abound in the applications as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here.
This is not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on
both the submitter’s and the Regional Entity’s side of this equation. Having viewed the application details, the SDT believes that both
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

13

sides can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO
panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of
the Bulk Electric System. The SDT firmly believes that the technical prowess of the ERO panel, the visibility of the process, and the
experience gained by having this same panel review multiple applications will result in an equitable, transparent, and consistent
approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are outlined in
the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception application form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved
or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the SAR for Phase II of this project that calls for a review of the process after 12 months of experience.
The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the
process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of
the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes
that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all
of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable outcome.
The SDT clarified the point that an entity may submit any information that it feels will help support its request as follows:
Page 1 - List any attached supporting documents and any additional information that is included to supports the request:

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

14

Organization
Northeast Power Coordinating
Council

Yes or No

Question 1 Comment

No

How an exception application will be assessed by the RE and NERC is not
addressed in the document. Stakeholders need to know how the exception
application will be evaluated and processed. Suggest that the SDT develop a
reference or a guidance document as part of the RoP that will provide
guidance to Registered Entities, Regional Entities and the ERO on how an
exception application will be processed. Of particular concern is the lack of
clarity and specificity with respect to what analyses and study results are
required under the third bullet on page 1 and under question 4 on both
pages 2 and 4. This lack of clarity and specificity will lead to inconsistent
application of the Technical Principles by both Registered Entities and
Regional Entities.
We recommend the following: the impact and performance analyses
required by the 3rd bullet on page 1 and by #4 on pages 2 and 4 should be
stipulated to be all analyses, scenarios, and contingencies required under
NERC Standard TPL-002-1 with the “exception element” removed from the
base system model. Entities shall report on all key performance measures of
BES reliability specified in the TPL-002-1 attributable to the removed
“exception element”.
On page 1 under General Instructions, it is stated that:”A one-line breaker
diagram identifying the facility for which the exception is requested must be
supplied with every application. The diagram(s) supplied should also show
the Protection Systems at the interface points associated with the Elements
for which the exception is being requested.”What is meant by interface
points?

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

15

Organization

Yes or No

Question 1 Comment

would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

16

Organization

Yes or No

Question 1 Comment

bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
As far as developing reference or guidance documents, the SDT will consider this recommendation in Phase II of the project.
The recommendation to use “the impact and performance analyses required by the 3rd bullet on page 1 and by #4 on pages 2 and 4
should be stipulated to be all analyses, scenarios, and contingencies required under NERC Standard TPL-002-1 with the “exception
element” removed from the base system model” could be viable as a form of evidence an entity may want to submit if the entity
believes this test provides evidence for the exception of an Element(s). The SDT encourages the submitting entity to provide any
additional information or explanation in the comments section of the questions that it believes will assist in the review of its
Exception Request. The SDT has made a clarifying change to the page 1 instructions to make this point clearer. Also see the answer
to question #4.
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

17

Organization

Yes or No

Question 1 Comment

Page one: List any attached supporting documents and any additional information that is included to supports the request:
As far as interface points, the SDT agrees with BPA’s suggestion that the interface point is the point requested by the entity seeking
the exception where the Element or Elements interconnect(s) to Bulk Electric System Elements.
ACES Power Marketing Standards
Collaborators

No

The first sentence only refers to element(s) designated as excluded.
Element(s) designated as included under the BES definition, shouldn’t have
to go through the exception process either.

Response: The SDT agrees with this comment. This language was added to clarify that Elements that are excluded (or included) do
not have to go through the Exception Process unless they are attempting to change to classification of their Elements.
WECC Staff

No

WECC has several concerns with the instructions on the checklist regarding
the studies: o Study Case - The instructions state the study case that should
be used, “Be based on an Interconnection-wide base case that is suitably
complete and detailed to reflect the facility’s electrical characteristics and
system topology.” The phrase “suitably complete and detailed” is vague.
WECC recommends clarification of this phrase and the addition of specific
requirements for what will constitute an appropriate case. Allowing the
entity requesting an exception to choose any Interconnection-wide case
could allow an inappropriate choice of case and could lead to inconsistent
study results. If there are no requirements for the chosen case, then it is
possible that the most favorable case to an entity’s argument will be chosen.
In some instances that choice would likely be appropriate, but in others it
would not necessarily be appropriate. At a minimum, there should be
further description - and preferably, specific requirements - guiding the
determination of which study case is most appropriate.
Of particular importance in clarifying what case is an appropriate case, is the
timeliness of the case. WECC recommends requiring that a recent case be
used. In addition, if each entity is able to chose its own case, without further

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

18

Organization

Yes or No

Question 1 Comment
requirements, there will be no way for the Regional Entity or NERC to ensure
consistency of determinations with respect to the elements tested.
o The entities are asked to address key performance measures of BES
reliability through the studies. This instruction is vague concerning what the
study must investigate and it leaves it up to the entity to determine the key
performance measures. The “key performance” measures should be
consistent with respect to similar elements and there is no way to ensure
that if there are no specifications regarding such measures. The exceptions
process must be objective and clear as to what performance measures need
to be met for the process to be implemented consistently. WECC
recommends further clarification and the addition of specific requirements
beyond the guidance related to consistency with Transmission Planning
(TPL) standards.
o The background information on the comment form states: “The same
checklist will be utilized for exceptions dealing with inclusions or exclusions.”
But there is no mention of this in the document. A note should be added to
the checklist instruction to state that the same checklist will be used for
exclusions and inclusions.

Response: In response to the comment about an appropriate base case, the SDT expects the entity seeking an exception to supply
an appropriate base case that the Regional Entity will acknowledge as appropriate. Not indicating the explicit types of studies or
base cases to be provided and how to interpret the information in the application process does not fail to provide a basis for the
Regional Entity to determine what constitutes an acceptable submittal.
The SDT again points to the variations that will abound in the applications as negating any hard and fast rules in this regard.
However, this is not something that hasn’t been handled before and there is a great deal of professional experience involved on
both the submitter’s and the Regional Entity’s side of this equation. Having viewed the application details, the SDT believes that
both sides can quickly arrive at a resolution as to what information needs to be supplied for the submittal to move upward to the
ERO panel for a final determination.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

19

Organization

Yes or No

Question 1 Comment

like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

20

Organization

Yes or No

Question 1 Comment

made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
As to the last comment, the SDT finds this wording redundant and not providing any additional clarity. No change made.
Dominion

No

Given that the second sentence in the 1st paragraph of this comment form
reads “This same process would be used by Registered Entities to justify
including Elements in the BES that might otherwise be excluded according to
the proposed definition and designations.”, Dominion suggests that the 1st

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

21

Organization

Yes or No

Question 1 Comment
sentence under General Instructions be revised to read “A one-line breaker
diagram identifying the facility for which the exception (or inclusion) is
requested must be supplied with every application. The diagram(s) supplied
should also show the Protection Systems at the interface points associated
with the Elements for which the exception (or inclusion) is being
requested.”

Response: The SDT reviewed the suggestion to add the phrase “(or inclusion)”and has elected to keep the original language
because the term Exception includes both Exclusions and Inclusions.
Pepco Holdings Inc

No

1) Why must the one-line diagram supplied show the Protection Systems at
the interface points associated with the elements for which the
exception is being requested? Since Protection Systems are not part of
the new bright-line BES definition why would their presence, or absence,
on the one-line diagram influence the exception process?
2) The third bullet needs additional detail of what is being requested. The
phrase “...key performance measures..” and use of methodologies
described in TPS Standards does not provide sufficient direction needed.
(see question #4)

Response: In response to the question about including Protection Systems, the SDT has used the term “should also show the
Protection Systems”. This is not mandatory; however the SDT has suggested this because the criterion for the evaluation of an
exception is “the Elements are necessary for the reliable operation of the interconnected bulk power transmission system”. As an
example, the elements could be part of a Special Protection System or RAS thus they could help the ERO to identify the Elements
“necessary for Reliable Operation…” No change made.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

22

Organization

Yes or No

Question 1 Comment

received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

23

Organization

Yes or No

Question 1 Comment

separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
Also, see the answer to question #4.
Electricity Consumers Resource
Council (ELCON)

No

The exception request form should begin with a question asking if the
inclusion was triggered by the entity responding to an emergency request by
the applicable BA, RC or TOP. The entity’s response to support recovery
from an emergency may have resulted in (1) power flows through the
entity’s facility into the BES, and/or (2) power injections to the BES that
exceed the 20/75-MVA thresholds. The entity should not be required to
provide detailed data and studies (as described in the “General
Instructions”) if either of those conditions would not have occurred but for

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24

Organization

Yes or No

Question 1 Comment
an emergency situation.

Response: While the SDT seriously doubts that such a situation will occur, the entity can choose the amount of and type of
evidence to present; if the entity feels that abnormal operation should be considered in the evaluation of the Element(s) then they
should supply that information to help explain its position.
AECI and member G&Ts

No

An opening statement of this form should make it clear that, prior to its
determination, the Facilities within scope of this exemption request, remain
included or excluded based upon the basic BES Definition Bright Line criteria
Inclusions and Exclusions.

Response: This is a question that relates to the proposed ERO Rules of Procedure Appendix 5C. This question was forwarded to
the RoP team.
Hydro One Networks Inc.

No

On the posted document, we did not find how an exception application will
be assessed by the RE and NERC. We believe that there is a huge gap and a
lack of transparency for all stakeholders on how the exception application
will be evaluated and processed.
We strongly suggest that the SDT develop a reference or a guidance
document as part of the RoP that will provide guidance to Registered
Entities, Regional Entities and the ERO on how an exception application
would/should be processed.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

25

Organization

Yes or No

Question 1 Comment

that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
In response to the comment about developing reference or guidance documents, the SDT will consider this recommendation in Phase
II.
Duke Energy

No

Need to include identification of any System Protection Coordination
considerations per PRC-001-1.
Also, we believe that a system map showing the geographical location of the
facility(s) should be supplied with the request.

Response: The detail of the diagrams and the type of diagrams suggested by Duke could be viable forms of evidence that an entity
may want to submit if the entity believes they provide evidence to support the exception of an Element.
Additionally, the SDT encourages the submitting entity to provide any additional information or explanation in the comments
section of the questions that it believes will assist in the review of its Exception Request.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization
Consolidated Edison Co. of NY, Inc.

Yes or No

Question 1 Comment

No

Con Edison’s overall concern is the lack of clarity and specificity with respect
to what analyses and study results are required under the 3rd bullet on page
1 and under #4 on pages 2 and 4. This lack of clarity and specificity will lead
to inconsistent application of the Technical Principles by both Registered
Entities and Regional Entities. We recommend the following: the impact and
performance analyses required by the 3rd bullet on page 1 and by #4 on
pages 2 and 4 should be stipulated to be all analyses, scenarios, and
contingencies required under NERC Standard TPL-002-1 with the “exception
element” removed from the base system model. Entities shall report on all
key performance measures of BES reliability specified in the TPL-002-1
attributable to the removed “exception element”.
Note that references to NERC Standard TPL-001-2 should not be made in the
Technical Principles document as TPL-001-2 has not yet been filed with (nor
approved by) FERC.
General Instructions One-Line Breaker Diagram questions and comments:
Page 1, paragraph 2: Please explain the phrase “at the interface points.”
Where is this location? Please provide several examples, i.e., for a radial, a
local network, a generator, a transformer, a substation buss, and for other
Elements (PARs, reactors, UFLS panels, relays and switches).

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

28

Organization

Yes or No

Question 1 Comment

single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

29

Organization

Yes or No

Question 1 Comment

Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
2. TPL-001-2 has been approved by the NERC Board of Trustees. As per drafting team guidelines, this document is now to be used in
all cases where the TPL standards are referenced in other standards projects.
3. In response to the comment about interface points, the SDT agrees with BPA’s suggestion that the interface point is the point
requested by the entity seeking the exception were the Element or Elements interconnect(s) to Bulk Electric System Elements.
New York State Dept. of Public
Service

No

Missing from the document are any indicators as to how much information
is sufficient, how the information will be evaluated, what weight will be
given to the individual pieces of information, etc.

ReliabilityFirst

No

These instructions are at a very high level and provide no clear guidance on
what is required. ReliabilityFirst Staff believes each bulleted item needs to
provide clear expectations. As an example in bullet #2 “Clearly document all
assumptions used”, the document and this bullet should include guidance
such as what base case transfers were included, a list of facilities that were

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment
assumed out of service, new facilities places in service and system load
levels, etc.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

31

Organization

Yes or No

Question 1 Comment

adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
Manitoba Hydro

No

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

32

Organization

Yes or No

Question 1 Comment

Response: Without any specific comment the SDT is unable to respond.
Orange and Rockland Utilities, Inc.

No

In the first paragraph “Entities that have Element(s) designated as excluded,
under the BES definition and designations, do not have to seek exception for
those Elements under the Exception Procedure.”, before the “General
Instruction” it should have had another sentence saying that “for those who
do not clearly meet the Inclusions and Exclusions should use the following
instructions”. Otherwise, it’s still not very clear.

Response: The SDT would like to point out that the “Detailed Information to Support an Exception Request” is only one section of
the Exception Form. For clarity, please refer to the complete form contained as part of the proposed ERO Rules of Procedure
Appendix 5C; also, see the RoP’s flow chart that outlines the process.
ISO New England Inc

No

It is unclear what the purpose of submitting diagrams showing the
Protection Systems is and we do not feel that it should be a requirement at
the onset of the exception process.
In the first bullet, we do not feel that the term “Interconnection-wide base
case” is required as the phrase “suitably complete and detailed” should
provide enough guidance to the submitter that inappropriate equivalent
representations would not be accepted. The concern is that one could
interpret “Interconnection-wide base case” as the entire Eastern
Interconnection model is a requirement.

Response: In response to the question about including Protection Systems, the SDT used the term “should also show the Protection
Systems”. This is not mandatory; however the SDT has suggested this because the criterion for the evaluation of an Exception is “the
Elements are necessary for the Reliable Operation of the interconnected bulk power transmission system”. As an example, the
elements could be part of a special protection system or RAS thus they could help the ERO to identify the Elements “necessary for
Reliable Operation…” No change made.
In response to the comment about a base case, the SDT expects the entity seeking an exception to supply a Base Case that the
Regional Entity will acknowledge as appropriate. The SDT points to the variations that will abound in the applications as negating
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

33

Organization

Yes or No

Question 1 Comment

any hard and fast rules in this regard. However, this is not something that hasn’t been handled before and there is a great deal of
professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having viewed the
application details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be supplied
for the submittal to move upward to the ERO panel for a final determination. No change made.
PSEg Services Corp

No

What is meant by “key performance measures of BES reliability” in the third
bullet? A descriptive list would be helpful.

Response: As to the lack of key performance measures, the SDT refers the commenters to Appendix 5C of the proposed ERO Rules
of Procedure, Section 3.1 where the basic premise on evaluating an exception request must be based on whether the Elements are
necessary for the reliable operation of the interconnected transmission system. Further, reliable operation is defined in the Rules
of Procedure as operating the elements of the bulk power system within equipment and electric system thermal, voltage, and
stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden
disturbance, including a cyber security incident, or unanticipated failure of system elements. No change made.
Hydro-Quebec TransEnergie

No

We believe that the new Technical Principles are better than the previous
ones, as they allow flexibility for an Entity to make their case with technical
justifications. However, without any guide or specific criteria, it does not
allow an Entity to identify the real possibility to obtain an exception. It is not
clear at all what will guide the Region or ERO to make their decision to grant
or not the exception. In order give confidence to the Industry in the
procedure, it would be necessary to define the elements that will guide the
decision.
Will impact base study be accepted?
Will the threshold differences with Quebec Interconnection be accepted?

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

34

Organization

Yes or No

Question 1 Comment

received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
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Organization

Yes or No

Question 1 Comment

separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
The SDT refers Hydro-Quebec to Appendix 5C of the proposed ERO Rules of Procedure, Section 3.1 where the basic premise on
evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected bulk transmission system. Further, Reliable Operation is defined in the Rules of Procedure as operating the elements
of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements.
As far as a difference for the Quebec Interconnection, the SDT encourages the submitting entity to provide any additional information
or explanation in the comments section of the questions that it believes will assist in the review of its Exception Request.

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Organization
City of St. George

Yes or No

Question 1 Comment

No

While the general instruction information outlined is applicable, it lacks
sufficient detail to know exactly what is needed to be submitted. More
importantly the general instructions and the overall document lacks criteria
that if met (through study and other documentation methods) would allow
for exclusion from or inclusion to the BES. Something similar to the criteria
or concepts used in the Appendix 1 of the Local Network Exclusion
justification document is needed. Clear criteria should allow an entity to
determine with a reasonable degree of certainty that if the criteria are met
as demonstrated by the associated study effort that an exemption can be
obtained. Otherwise without that criteria, the process will be not far from
where the exemption process is today, which will be costly, time consuming
and frustrating for the registered entities as well as the regions and NERC.
The process needs to be repeatable and consistent between all regions and
entities. Entities need to know what is expected and where the finish line is.
As presently written each region and NERC would have to develop their own
criteria individually and will be open to opinions which could change as
personnel changes occur in a given position or panel.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
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Organization

Yes or No

Question 1 Comment

plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
In response to clear criteria, the SDT refers the commenters to Appendix 5C of the proposed ERO Rules of Procedure, Section 3.1
where the basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable
operation of the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating
the elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber
security incident, or unanticipated failure of system elements.
Georgia System Operations
Corporation

No

: The last half of the first sentence should be changed to “do not have to
seek an Exclusion Exception under the Exception Procedure for the
Element(s).” The use of “Element(s)” relates back to that term at the start of
the sentence, and the reference to an “Exclusion Exception” is necessary
because an entity (albeit probably not the Owner), still may choose to seek
an Inclusion Exception for such an Element(s).
In the 3rd bullet, the reference should be to TPL standards (plural).

Response: In response to the suggestion to change the first sentence, the SDT would like to point out that the “Detailed Information
to Support an Exception Request” is only one section of the Exception Form. For further clarity, please refer to the complete
Exception form contained as part of the proposed ERO Rules of Procedure Appendix 5C; also, see the RoP’s flow chart that outlines

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Organization

Yes or No

Question 1 Comment

the process. No change made.
The SDT notes that there is now only one TPL standard, TPL-001-2; TPL-001-2 has been approved by the NERC Board of Trustees. As
per drafting team guidelines, this document is now to be used in all cases where the TPL standards are referenced in other standards
projects. No change made.
ATC LLC

No

Since an Exception Request may be for approval to designate identified
Element(s) as either excluded from or included in the BES, the wording of
the first sentence should be changed and the request should clearly indicate
(e.g. exclusion/inclusion check boxes) whether the request regards exclusion
or inclusion of the Element(s). Here is some draft wording for consideration:
Entities that have Element(s) that are included under the BES definition and
designations, but seek to have them designated as excluded from the BES or
that that have Element(s) that are excluded under the BES definition and
designations, but seek to have them designated as included in the BES
should submit an Exception Request according to the NERC Exception
Procedures and provide detailed information to support the Exception
Request as indicated below.
In addition, ATC suggests the following clarifying edit. Entities that have BES
Element(s) considered as excluded under the BES definition and
designations, do not have to seek exception for those Elements under the
Exception Procedure.

Response: In response to the suggestion to change the first sentence, the SDT would like to point out that the “Detailed Information
to Support an Exception Request” is only one section of the Exception Form. For further clarity, please refer to the complete form
contained as part of the proposed ERO Rules of Procedure Appendix 5C; also, see the RoP’s flow chart that outlines the process.
The SDT would refer the commenter to the first line of page 1 which clearly states this fact. No change made.
Farmington Electric Utility System

No

The general instructions presented are primarily components to substantiate
an Exception Request. However, a cover sheet (template) should be created
that includes overall identifying information of the Submitting Entity and the

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Organization

Yes or No

Question 1 Comment
and the Owner if the if they are not the same - the template should align
with the draft Appendix 5C Section 4.5.1 of the NERC Rules of Procedure. An
Exception Request can be submitted for Inclusion or Exclusion of the BES.
The first sentence in the form, “Entities that have Element(s) designated as
excluded, under the BES definition and designations, so not have to seek
exception for those Element(s) under the Exception Procedure. This would
not be true if a Submitting Entity is seeking an Inclusion Exception. FEUS
recommends revising to include Inclusion Exception Requests.

Response: The SDT acknowledges that the “Detailed Information to Support an Exception Request” is only one section of the
Exception Form and in itself lacks required information; the complete form contains the information suggested by the commenter.
The full Exception form is part of the proposed ERO Rules of Procedure Appendix 5C; also, see the RoP’s flow chart that outlines
the process.
Transmission Access Policy Study
Group

Glossary terms should be capitalized throughout the document. Lowercase
“facility,” especially, should not be used. The document should use
“Element” instead.
The term “interface points,” while common, may not have a sufficiently
common understanding to be used in this context. “Boundaries of the
Element(s) for which the exception is being requested” may express the
SDT’s meaning more clearly.

Response: The SDT agrees with the commenter and the form was edited to use the term Element instead of Facility where
appropriate.
In response to the comment about interface points, the SDT agrees with BPA’s suggestion that the interface point is the point
requested by the entity seeking the exception were the Element or Elements interconnect(s) to Bulk Electric System Elements.
Tri-State Generation and
Transmission Assn., Inc. Energy
Mangement

This question is actually asking two questions; Tri-State’s answers would be
No & Yes. There needs to be a better introduction to what and why the
exception is being requested.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

TSGT G&T

Question 1 Comment
This question is actually asking two questions; Tri-State’s answers would be
No & Yes. There needs to be a better introduction to what and why the
exception is being requested.

Response: This is a question that relates to the proposed ERO Rules of Procedure Appendix 5C. This question was forwarded to
the RoP team.
American Electric Power

Yes

Though we have no objections to the proposed content, this is contingent
on the number and type of elements eventually found included or excluded
as a result of the BES definition itself which is still being drafted. Any
changes in that definition could in turn cause us concern regarding these
general instructions.
There needs to some provision for cases where specific elements which are
not specifically contained within the studies. It needs to be clear what
additional analysis needs to be provided under those circumstances.
We recommend that the owner of the asset be identified as part of the
general instructions.
In the case of wind resources, how is individual gross nameplate information
to be reported?

Response: In response to a provision for specific elements not contained in studies, the SDT encourages the submitting entity to
provide any additional information or explanation in the comments section of the questions that it believes will assist in the review of
its Exception Request. Additionally, the exception form has been clarified to bring home that point.
Page one: List any attached supporting documents and any additional information that is included to supports the request:
The owner of the asset is identified in the instructions that are being proposed as part of the ERO Rules of Procedures changes.
This revised definition does not change the way that wind resources are reported.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization
Snohomish County PUD
Blachly-Lane Electric Cooperative
Central Electric Cooperative (CEC)
Clearwater Power Company (CPC)
Consumer's Power Inc. (CPI)
Douglas Electric Cooperative (DEC)
Fall River Electric Cooperative (FALL)
Lane Electric Cooperative (LEC)
Lincoln Electric Cooperative (Lincoln)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)

Yes or No

Question 1 Comment

Yes

SNPD agrees generally that the General Instructions set forth the basic
information that would be necessary to support an Exception Request.
SNPD is concerned, however, that the statement “diagram(s) supplied
should also show the Protection Systems at the interface points associated
with the Elements for which the exception is being requested” may be
subject to differing interpretations. SNPD envisions that at least four
different kinds of documents would be responsive to the description: oneline diagrams with breakers and switches (status); identification of relays by
their ANSI device numbers; details of the DC control logic for ANSI devices;
and, operational scheme descriptions of the type used by system operators.
Accordingly, we suggest that the language be refined to identify the specific
kinds of diagrams necessary to identify protection systems at the interface
with the Elements for which the Exception is sought, including any required
details.
SNPD suggests that a generic example of a completed form be provided to
the industry to help ensure that Exception Requests are supported by
consistent and complete information. Such a generic example could be
addressed in the Phase 2 BES efforts.

Raft River Rural Electric Cooperative
(RAFT)
Umatilla Electric Cooperative
West Oregon Electric Cooperative
(WOEC)
Coos-Curry Electric Coooperative
City of Austin dba Austin Energy
Kootenai Electric Cooperative
Response: The various diagrams suggested by SNPD could be viable as forms of evidence that an entity may want to submit if the
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

entity believes they provide evidence to support the exception of an Element.
As far as developing generic examples, reference, or guidance documents, the SDT agrees with SNPD that this should be considered in
Phase II of the project.
Southern Company Generation

Yes

In the third bullet under the list of study attributes, it is very important to
specifically list the "key performance indicators of BES reliability". This will
assist in pointing the studies to focus on the issues relevant to determining
the signifacance of the exception request.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

44

Organization

Yes or No

Question 1 Comment

provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment

consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
Also, see the answer to question #4.
Holland Board of Public Works

Yes

The requirement to base flow studies on an “interconnection-wide base
case" is likely to include many more lines and buses than necessary to model
the impact of a facility that is not material to the BES. Holland BPW request
the words “or regional reduction of such a case” be added after
“interconnection-wide base case” to avoid unnecessary expense and detail if
a more limited study set is adequate to demonstrate the lack of material
impact of the facility(ies) in question.

Michigan Public Power Agency

Yes

The requirement to base flow studies on an “interconnection-wide base
case" is likely to include many more lines and buses than necessary to model
the impact of a facility that is not material to the BES. MPPA and its
members request the words “or regional reduction of such a case” be added
after “interconnection-wide base case” to avoid unnecessary expense and
detail if a more limited study set is adequate to demonstrate the lack of
material impact of the facility(ies) in question.

Response: In response to the comment about a reduction base case, the SDT expects the entity seeking an exception to supply a
Base Case that the Regional Entity will acknowledge as appropriate. The SDT points to the variations that will abound in the
applications as negating any hard and fast rules in this regard. However, this is not something that hasn’t been handled before and
there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation.
Having viewed the application details, the SDT believes that both sides can quickly arrive at a resolution as to what information
needs to be supplied for the submittal to move upward to the ERO panel for a final determination. No change made.
Bonneville Power Administration

Yes

BPA suggests clarifying that the interface point is the point where the entity
seeking the exception’s facility or facilities interconnect(s) to the Bulk
Electric System facility.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 1 Comment
Page 1 states “Supporting statements for your position from other entities
are encouraged.” BPA believes coordination with affected systems should
be required under the exemption process.

Response: In response to the comment about interface points, the SDT agrees with BPA’s suggestion that the interface point is the
point requested by the entity seeking the exception were the Element or Elements interconnect(s) to Bulk Electric System
Elements.
As for the comment about coordination, the SDT refers the commenter to Appendix 5C of the proposed NERC Rules of Procedure,
Section 4.5.2. This section requires the submitting entity to submit a copy of the Exception Request Form Section II to each
Planning Coordinator, Reliability Coordinator, Transmission Operator, Transmission Planner, and Balancing Authority that has (or
will have upon inclusion of the Element(s) in the BES) the Elements covered by an Exception Request within its Scope of
Responsibility.
Independent Electricity System
Operator

Yes

Central Lincoln

Yes

National Grid

Yes

Oncor Electric Delivery Company LLC

Yes

Ameren

Yes

Long Island Power Authority

Yes

Consumers Energy

Yes

NV Energy

Yes

Central Hudson Gas & Electric

Yes

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Organization

Yes or No

Question 1 Comment

Corporation
Exelon

Yes

Transmission

Yes

PacifiCorp

Yes

NERC Staff Technical Review

Yes

IRC Standards Review Committee

Yes

City of Redding Electric Utility

Yes

City of Redding

Yes

Tacoma Power

Yes

Tacoma Power supports the instructions as written.

Springfield Utility Board

Yes

SUB agrees with the instructions, finding them to be clear and reasonable.

BGE

Yes

No comment.

Southwest Power Pool Standards
Review Team

Yes

SERC Planning Standards
Subcommittee

Yes

Response: Thank you for your support.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

48

2. Pages two and three of the Detailed Information to Support an Exception Request contain a checklist of items that deal with
transmission facilities. Do you agree with the information being requested or is there information that you believe needs to be on
page two or three that is missing? Please be as specific as possible with your comments.
Summary Consideration: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on
this issue. The SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter.
However, after many hours of discussion and an initial attempt at doing so, it had become obvious to the SDT that the simple
answer that so many sought is not achievable. If the SDT could have come up with the simple answer, it would have been supplied
within the bright-line. The SDT would also like to point out to the commenters that it directly solicited assistance in this matter in
the first posting of the criteria and received very little in the form of substantive comments.
There are many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to
say that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with
this position. The exception application form has to be taken in concert with the changes to the ERO Rules of Procedure and
looked at as a single package. When one looks at the rules being formulated for the Exception process, it becomes clear that the
role of the Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of
reviewing the submittal for completion and making a recommendation to the ERO panel, not to make the final determination. The
Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter
that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to
be supplied. The SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes
that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC
Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review
Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part
of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides
NERC the option to remand the application to the Regional Entity with the mandate to process the exception if it finds the
Regional Entity erred in rejecting or disapproving the Exception Request. Conversely, an argument could be raised that the
Regional Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies
to be provided and how to interpret the information are not shown in the application process. The SDT again points to the
variations that will abound in the applications as negating any hard and fast rules. However, this is not something that has not
been handled before and there is a great deal of professional experience involved on both the submitter’s and the Regional
Entity’s side of the Exception process. Having viewed the application details, the SDT believes that both sides can quickly arrive at

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a resolution as to what information needs to be supplied for the submittal to move upward to the ERO panel for a final
determination.
While commenters point to lack of direction being supplied to the ERO panel as to specific guidelines for them to follow in making
their decision, the SDT re-iterates the problem with providing such hard and fast rules. There are too many variables to consider.
Providing concrete guidelines is going to tie the hands of the ERO panel and inevitably result in poor decisions. The SDT also refers
the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an
exception request must be based on whether the Elements are necessary for the reliable operation of the interconnected
transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power
system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or
cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or
unanticipated failure of system elements. The SDT firmly believes that the technical expertise of the ERO panel, the visibility of the
process, and the experience gained by having the hindsight resulting from reviewing multiple applications will result in an
equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper
decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception application form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2, which states “No single piece of evidence provided as part of an Exception Request or response to a
question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT has made several minor changes made to the specific items in the form in response to industry comments. The SDT
believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in
a favorable outcome.
The SDT affirms the requirement to provide the most recent consecutive two calendar year period minimum and maximum
magnitude of the power flow out of the Element(s) for which an Exception is sought. The SDT believes that a single year’s data is

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insufficient to determine a pattern of flow on the Element(s). Moreover, many of the NERC Standards already require longer data
retention periods; typically for a full audit period which is either three or six years. See NERC Compliance Process Bulletin #2009005, Current In-Force Document Data Retention Requirements for Registered Entities, Version 1.0, at 1 (Jun.29, 2009). It should be
noted that retaining three second data from an Energy Management System (EMS) or a Supervisory Control And Data Acquisition
(SCADA) system is not sought in this instance.
The SDT declines to further define the “maximum magnitude of the power flow.” It is up to the submitting entity to determine
how best to present the information supporting their request and any responses provided by the submitting entity can be further
described or qualified under the comments section.
The SDT has determined that information on Flowgate impacts and whether Element(s) are included in an Interconnection
Reliability Operating Limit (IROL) are necessary to the Regional Entity’s determination of whether an Element(s) is used to provide
bulk power transfers within the Interconnections or whether the Element(s) is distribution. A number of interchange coordination
Reliability Standards apply to these transfer paths and Flowgates. Accordingly, the SDT believes such facilities are necessary for
the reliable operation of an interconnected electric transmission network and would not be excluded from the definition of the
BES. Furthermore, the SDT understands that each Flowgate list may be added to or subtracted from based on prevailing system
conditions, however, a core set of Flowgates will remain the same. It is up to the submitting entity to determine how best to
present the information supporting their request and the nature of the Element(s) impact on a permanent flowgate can be further
described or qualified under the comments section.
Due to comments received, the SDT made the following clarifying changes to the request form:
Page 1 - List any attached supporting documents and any additional information that is included to supports the request:
Q3. Please provide the appropriate list for yourthe operating area where the Element(s) is located:
Q6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan?
Q7. If yes, then using metered or SCADA data for the most recent consecutive two calendar year period, what is the minimum and
maximum magnitude of the power flow out of the facility Element(s)? and dDescribe the conditions and the time duration when
this could occurs?
Organization

Yes or No

Question 2 Comment

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Organization
Northeast Power Coordinating
Council

Yes or No
No

Question 2 Comment
For question 2 on page 2 For Transmission Facilities: o What standards will
define the “impact”? o What is a material impact and a non-material impact?
o What kinds and types of impacts are acceptable/unacceptable? o How are
impacts determined?
Question 6 on page 3 reads “Is the facility part of a Cranking Path associated
with a Blackstart Resource?”, suggest removing the reference to “Cranking
Path” because the Drafting Team does not require that the BES be contiguous,
and black start resource Cranking Paths were deleted from Inclusion I3.
Question 7 on page 3 asks, “Does power flow through this facility into the BES?”
This can only apply to a Local Network with two or more connections to the
BES. No power should normally flow through a Local Network (or Radial system)
to another portion of the BES. There may be occasional, brief reverse power
flows may be acceptable during short periods under abnormal operating
conditions.
Question 7 also requests “data for the most recent consecutive two calendar
year period.” Why is two years worth of data necessary? One year of data
would be sufficient.
From Question 7, “what is the minimum and maximum magnitude of the power
flow out of the facility ...” What is intended by the use of magnitude?
Suggest that the Drafting Team adopt the FERC Seven Factor test for question 7.
Suggest deleting the “% of the calendar year” check boxes in favor of a
statement either that power does not flow through the Local Network, or
alternatively, a blank space for reporting the net peak MWs and MWHs
transferred annually through the facility, and the percentage of these
transferred amounts to the peak and annual MWH demands served by the Local
Network.
Suggest requesting only one year (8,760 hours) of data covering four seasons,

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Organization

Yes or No

Question 2 Comment
including Summer and Winter capability periods.

Consolidated Edison Co. of NY,
Inc.

No

Application Form Page 2For Transmission Facilities:Impacts:Flowgates: The
Application form at 2 states, “How does the facility impact permanent
Flowgates in the Eastern Interconnection ...” o What standards for “impact”
does the BES SDT envision? o What is a material impact and a non-material
impact? o What kinds and types of impacts are acceptable and/or
unacceptable? o How are impacts determined, e.g., Power TFD method, short
circuit analysis, A-10 method?Impact-Based Studies: Note that the FERC Seven
Factor test is a time-tested method and FERC has identified it as an acceptable
method for reliability purposes; for gauging the expected impact of an Element
on the interconnected transmission grid. The NPCC A-10 method has been used
extensively in the Northeastern U.S. and Canada, and is an impact-based
approach. The power TDF (transfer distribution factor) method is also used by
some to assess the impact of changing power flows on individual Elements
within a system. FERC has studied using the ‘TIER’ method for classifying system
Elements based on LBMP impacts. WECC uses a short circuit test.
Page 3Cranking Path Issue: The Application form at 6 asks, “Is the facility part of
a Cranking Path associated with a Blackstart Resource?”We understand that:(i)
The drafting team does not require that the BES be contiguous, and (ii)
Blackstart resource Cranking Paths were deleted from Inclusion I3.
Recommendation: Delete the reference to “Cranking Paths” in this Application
form.
Power Flow Issue: The Application form at 7 asks, “Does power flow through
this facility into the BES?” We assume that this can only apply to a Local
Network with two or more connections to the BES. We believe that no power
should normally flow through a Local Network (or Radial system) to another
portion of the BES. Occasional, brief reverse power flows may be acceptable
during short periods under abnormal operating conditions, e.g., a switch

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Organization

Yes or No

Question 2 Comment
normally open is briefly closed during a forced maintenance outage.
The Application form at 7 requests the following: “data for the most recent
consecutive two calendar year period.” o Please explain why the BES SDT felt
that two years worth of data was necessary, as one year of data would appear
sufficient? Our experience has been that one year (8,760 hours) of data covers
four seasons, including Summer and Winter capability periods, and is therefore
sufficient. Requiring an extra year is perhaps unnecessarily burdensome on
filing Entities, whether asset owners or Regional Entities.
The Application form at 7 asks, “[W]hat is the minimum and maximum
magnitude of the power flow outflow of the facility ...” o Please explain why
the BES SDT used the term “magnitude” when requesting power outflow data?
Recommendations: 1) We strongly recommend that the BES SDT adopt the
FERC Seven Factor test for these purposes. The FERC Seven Factor test states
that, o “Power flows into local distribution systems, and rarely, if ever flows
out,” and o “When power enters a local distribution system, it is not
reconsigned or transported on to some other market.”
2) We recommend deleting the “% of the calendar year” check boxes in favor of
a statement either that power does not flow through the Local Network, or
alternatively, a blank space for reporting the net peak MWs and MWH’s
transferred annually, and the percentage of these transferred amounts to the
peak and annual MWH demands served by with the Local Network.3) We
recommend requesting only one year (8,760 hours) of data covering four
seasons, including Summer and Winter capability periods.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on the Exception
criteria. The SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However,
after many hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that a simple answer is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
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Organization

Yes or No

Question 2 Comment

received very little in the form of substantive comments.
Not indicating the explicit types of studies to be provided and how to interpret the information in the application process does not
fail to provide a basis for the Regional Entity to determine what constitutes an acceptable submittal. The SDT again points to the
variations that will abound in the applications as negating any hard and fast rules in this regard. However, this is not something that
hasn’t been handled before and there is a great deal of professional experience involved on both the submitter’s and the Regional
Entity’s side of this equation. Having viewed the application details, the SDT believes that both sides can quickly arrive at a resolution
as to what information needs to be supplied for the submittal to move upward to the ERO panel for a final determination.
As to the lack of direction being supplied to the ERO panel in the form of specific guidelines to follow, the SDT refers the commenters
to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception request
must be based on whether the Elements are necessary for the reliable operation of the interconnected transmission system.
Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system within
equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures
of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or unanticipated failure of
system elements. The SDT firmly believes that the technical expertise of the ERO panel, the visibility of the process, and the
experience gained by having the hindsight resulting from reviewing multiple applications will result in an equitable, transparent, and
consistent approach to the problem.
Finally, there are options for a submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they
feel that an improper decision has been made on their submittal.
The SDT disagrees with eliminating the question pertaining to Cranking Path. It is important to realize a distinction between the BES
definition and the Exception process. While the BES definition established bright-line criteria for the determination between BES and
non-BES Element(s), the Exception Process requires an evaluation of all the responses and supporting materials provided as part of
the Exception Request Form. No single response or piece of supporting information will be solely dispositive in an Exception Request
evaluation. It is not correct to assume that simply because an evaluation criterion was removed from the bright-line definition it
should also be eliminated from consideration in the Exception Process. The SDT believes that consideration of Cranking Paths is
among the factors to be given consideration in the evaluation for an Exception Request application. Any further discussion of this
issue is within the scope of the Phase II SAR. No change made.
With respect to concerns about including power flowing through a local network in the Exception Request Form, these concerns fail
to recognize the distinction between the BES definition and the Exception Process. As stated above, while the BES definition

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Organization

Yes or No

Question 2 Comment

established bright-line criteria for the determination between BES and non-BES Element(s), the Exception Process requires an
evaluation of all the responses and supporting materials provided as part of the Exception Request Form. The SDT believes that
power flow through an Element into the BES is among the factors to be given consideration in the evaluation of an Exception
Request. In fact, the example identified by commenters identifies one situation that requires such consideration; where occasional,
brief reverse power flows may be acceptable during short periods under abnormal operating conditions. Further discussion of this
issue is within the scope of the Phase II SAR. No change made.
The SDT affirms the requirement to provide the most recent consecutive two calendar year period minimum and maximum
magnitude of the power flow out of the Element(s) for which an Exception is sought. The SDT believes that a single year’s data is
insufficient to determine a pattern of flow on the Element(s). Moreover, many of the NERC Standards already require longer data
retention periods; typically for a full audit period which is either three or six years. See NERC Compliance Process Bulletin #2009-005,
Current In-Force Document Data Retention Requirements for Registered Entities, Version 1.0, at 1 (Jun.29, 2009). It should be noted
that retaining three second data from an Energy Management System (EMS) or a Supervisory Control And Data Acquisition (SCADA)
system is not sought in this instance. No change made.
The SDT declines to further define the “maximum magnitude of the power flow.” It is up to the submitting entity to determine how
best to present the information supporting their request and any responses provided by the submitting entity can be further
described or qualified under the comments section. No change made.
The General Instruction area on page one has been modified to clarify that a submitting entity may provide documents and any
additional information, including Seven Factor Test related information, which supports their request. It is up to the Submitting
entity to determine how best to present the information supporting their request. If the submitting entity wishes to provide this
additional information it may do so by listing this information in the area provided under General Instructions in the Exception
Request Form.
Page one: List any attached supporting documents and any additional information that is included to supports the request:
The SDT has deleted the checkboxes in Question 7. To replace the checkboxes, language has been added requesting the submitting
entity to describe the conditions and the time duration when power flow through Element(s) into the BES. It is up to the submitting
entity to determine how best to present the information supporting their request.
Q7. If yes, then using metered or SCADA data for the most recent consecutive two calendar year period, what is the minimum
and maximum magnitude of the power flow out of the facility Element(s)? and dDescribe the conditions and the time duration
when this could occurs?
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Organization
ACES Power Marketing
Standards Collaborators

Yes or No
No

Question 2 Comment
Q1, Q5 and Q6 have a “Description/Comments” section. What type of
information should be included under the Description for each of these
questions? Providing more guidance here would help achieve the
“standardization, clarity and continuity of process” that we seek.
Regarding Q2: A permanent flowgate should not be part of the detailed
information to support an exception. First, there is no definition for what
constitutes a permanent flowgate. Second, flowgates are often created for a
myriad of reasons that have nothing to do with them being necessary to
operate the BES. While section c) in E3 attempts to limit the applicability to
permanent flowgates, there is no definition for what constitutes a permanent
flowgate particularly since no flowgate is truly permanent. The NERC Glossary
of Terms definition of flowgate includes flowgates in the IDC. This is a problem
because flowgates are included in the IDC for many reasons not just because
reliability issues are identified. Flowgates could be included to simply study the
impact of schedules on a particular interface as an example. It does not mean
the interface is critical. As an example, it could be used to generate evidence
that there are no transactional impacts to support exclusion from the BES.
Furthermore, the list of flowgates in the IDC is dynamic. The master list of IDC
flowgates is updated monthly and IDC users can add temporary flowgates at
anytime. While the "permanent" adjective applied to flowgates probably limits
the applicability from the “temporary” flowgates, it is not clear which of the
monthly flowgates would be included from the IDC since they might be added
one month and removed another. Flowgates are created for many reasons that
have nothing to do with them being necessary to operate the BES. First,
flowgates are created to manage congestion. The IDC is more of a congestion
management tool than a reliability tool. FERC recognized this in Order 693,
when they directed NERC to make clear in IRO-006 that the IDC should not be
relied upon to relieve IROLs that have been violated. Rather, other actions such
as re-dispatch must be used in conjunction. Second, flowgates are used as a
convenient point to calculate flows to sell transmission service. The

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Organization

Yes or No

Question 2 Comment
characteristics of the flowgate make it a good proxy for estimating how much
contractual use has been sold not necessarily how much flow will actually occur.
While some flowgates definitely are created for reliability issues such as IROLs,
many simply are not.
We are unclear about what “an appropriate list” in Q3 is supposed to be. Is it
supposed to be a list of all IROLs or only those for which the answer is yes?
Why is a list even necessary since the answer to the question answers Exclusion
E3.c? If the answer is no, is this asking the submitter to prove the negative?

Response: The SDT believes the guidance provided on Page 1 of the Exception Request Form is sufficient. A submitting entity may
provide any additional information or explanation in the comments section of the questions that it believes will assist in the review of
its Exception Request. No single response or piece of supporting information will be solely dispositive in an Exception Request
evaluation and all responses and supporting information provided will receive consideration. It is up to the submitting entity to
determine how best to present the information supporting their request in the comment area provided for each question. No change
made.
The SDT has determined that information on Flowgate impacts and whether Element(s) are included in an Interconnection Reliability
Operating Limit (IROL) are necessary to the Regional Entity’s determination of whether an Element(s) is used to provide bulk power
transfers within the Interconnections or whether the Element(s) is distribution. A number of interchange coordination Reliability
Standards apply to these transfer paths and Flowgates. Accordingly, the SDT believes such facilities are necessary for the reliable
operation of an interconnected electric transmission network and would not be excluded from the definition of the BES.
Furthermore, the SDT understands that each Flowgate list may be added to or subtracted from based on prevailing system
conditions, however, a core set of Flowgates will remain the same. It is up to the submitting entity to determine how best to present
the information supporting their request and the nature of the Element(s) impact on a permanent flowgate can be further described
or qualified under the comments section. No change made.
The SDT has clarified that the submitting entity is to provide the appropriate list of IROLs for the operating area where the Element(s)
is/are located.
Q3. Please provide the appropriate list for yourthe operating area where the Element(s) is located:
Bonneville Power

No

Regarding #4 on page 2: BPA believes the impact to the over-all reliability of

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Organization

Yes or No

Administration

Question 2 Comment
the BES needs to consider more than just an outage of the facility requesting
exclusion. One example is a contingency outage of a parallel facility that could
cause an overload. Item 4 needs to include impacts of either the outage of the
facility, or with the facility in service.BPA believes that the entity requesting an
exception may not have information on impacts of the facility on parallel
higher-voltage facilities because the NERC requirements for data sharing for
these types of facilities does not necessarily include owners and operators of
lower voltage systems. The entity requesting an exemption would likely need
to coordinate with affected systems, and this coordination should be required
in the exemption process so that affected systems are aware of the possible
exclusion.

Response: The SDT will continue to monitor the process over next 12 months and if it is determined additional information is
needed, such as how outages of BES facilities impact the Element(s) for which an exception is sought, it will be addressed in Phase II.
Nevertheless, submitting entities are free to include information in response to any question that best supports their request for an
exception. No change made.
Coordination of an exception request with affected systems is already addressed in the Exception Rules of Procedure, Appendix 5C
Sections 4.1, 4.4, 4.5.1, and 4.5.2, requiring the submitting entity, if not the facility owner, to provide a copy of the request to the
facility owner, all involved Regional Entities if it is a cross-border facility, and to the Planning Coordinator, Reliability Coordinator,
Transmission Operator, Transmission Planner, and Balancing Authority that has (or will have upon inclusion in the BES) the Elements
covered by an exception request within its scope of responsibility.
Pepco Holdings Inc

No

1) Why is Item 5 (Question pertaining to whether the facility is used for off-site
power to a nuclear plant) included, since this criteria is not part of the proposed
bright-line BES definition.
2) Similarly, why is Item 6 (Question pertaining to whether the facility is part of
a Cranking Path associated with a Black Start Resource) included, since Black
Start Cranking Paths were removed from the latest BES definition.
Both Items 5 and 6 should be removed from the Exception Request Form.

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Organization

Yes or No

Question 2 Comment

Response: The SDT disagrees with eliminating Questions 5 and 6. It is important to realize a distinction between the BES definition
and the Exception Procedure. While the BES definition established bright-line criteria for the determination between BES and nonBES Element(s), the Exception Process requires an evaluation of all the responses and supporting materials provided as part of the
Exception Request Form. No single response or piece of supporting information will be solely dispositive in an Exception Request
evaluation. It is not correct to assume that simply because an evaluation criterion was removed from the bright-line definition it
should also be eliminated from consideration in the Exception Process. The SDT believes that Cranking Paths and off-site power
supply to a nuclear power plants are among the factors to be given consideration in the evaluation for an Exception Request. Further
discussion of this issue is within the scope of the Phase II SAR. No change made.
Electricity Consumers
Resource Council (ELCON)

No

A sub-question should be added to Question 1 asking: (1) Does the generation
serve all or a part of retail customer Load, and (2) If so, the maximum net
capacity of each unit injected to the BES during non-emergency conditions.

Response: The General Instruction area on page one has been modified to clarify that a submitting entity may provide documents
and any additional information that supports their request. If the submitting entity wishes to provide this additional information it
may do so by listing this information in the area provided under General Instructions. No change made.
AECI and member G&Ts

No

There is no basis in this draft Standard for including Item 6).
Item 7) does appear appropriate within the Standard, but the intent of the four
check-boxes is ambiguous.

Response: The SDT disagrees with eliminating the question pertaining to Cranking Path. It is important to realize a distinction
between the BES definition and the Exception Procedure. While the BES definition established bright-line criteria for the
determination between BES and non-BES Element(s), the Exception Procedure requires an evaluation of all the responses and
supporting materials provided as part of the Exception Request Application Form. No single response or piece of supporting
information will be solely dispositive in an Exception Request evaluation. The SDT believes that the Cranking Path is among the
factors to be given consideration in the evaluation for an Exception Request application. Further discussion of this issue is within the
scope of the Phase II SAR. No change made.
The SDT has deleted the checkboxes in Question 7. To replace the checkboxes, language has been added requesting the submitting
entity to describe the conditions and the time duration when power flow through Element(s) into the BES. It is up to the submitting
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Organization

Yes or No

Question 2 Comment

entity to determine how best to present the information supporting their request.
Q7. If yes, then using metered or SCADA data for the most recent consecutive two calendar year period, what is the minimum
and maximum magnitude of the power flow out of the facility Element(s)? and dDescribe the conditions and the time duration
when this could occurs?
NERC Staff Technical Review

No

In addition to describing how an outage of the facility under consideration
affects the rest of the BES, the Submitting entity also should be required to
provide an assessment of how outages of BES facilities affect the facility under
consideration. This could be achieved with powerflow studies or distribution
factor analysis.

Response: The SDT will continue to monitor the process over next 12 months and if it is determined additional information is
needed, such as how outages of BES facilities impact the Element(s) for which an Exception is sought, it will be addressed in Phase II.
Nevertheless, the General Instruction area on page one has been modified to clarify that a submitting entity may provide documents
and any additional information that supports their request. If the submitting entity wishes to provide this additional information it
may do so by listing this information in the area provided under General Instructions. No change made.
IRC Standards Review
Committee

No

We agree with most parts on P.2 and P.3, but question the need for Q6, which
asks:”Is the facility part of a Cranking Path associated with a Blackstart
Resource?”I3 in the BES definition stipulates that Blackstart Resources
identified in the Transmission Operator’s restoration plan be included (which
we disagree and commented in the BES Definition Comment Form). There is no
inclusion of any transmission facilities that are part of the cranking path. We
suggest this item (Q6) be removed.

Response: The SDT disagrees with eliminating the question pertaining to Cranking Path. It is important to realize a distinction
between the BES definition and the Exception Procedure. While the BES definition established bright-line criteria for the
determination between BES and non-BES Element(s), the Exception Procedure requires an evaluation of all the responses and
supporting materials provided as part of the Exception Request Form. No single response or piece of supporting information will be
solely dispositive in an Exception Request evaluation. It is not correct to assume that simply because an evaluation criterion was
removed from the bright-line definition it should also be eliminated from consideration in the Exception Procedure. The SDT believes
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Organization

Yes or No

Question 2 Comment

that Cranking Path is among the factors to be given consideration in the evaluation for an Exception Request application. Further
discussion of this issue is within the scope of the Phase II SAR. No change made.
PacifiCorp

No

Question 6 implies that if the facility is part of a designated blackstart cranking
path then an exception request would most likely be denied. To the extent that
was the intent, such an assumption would only be reasonable if the blackstart
cranking path is the only path available. However, PacifiCorp suggests modifying
the current Question 6 to reflect a situation in which multiple cranking paths
are available, as follows:”6A. Is the facility part of a Cranking Path associated
with a Blackstart Resource? 6B. If yes, does the Blackstart Resource have other
viable Cranking Paths?”

Response: Several commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will
mandate a negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed ERO Rules of
Procedure, Section 3.2 that states “No single piece of evidence provided as part of an Exception Request or response to a question
will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT has adopted clarifying language to differentiate between multiple Cranking Paths by requiring the Cranking Path “identified
in a Transmission Operator’s restoration plan.”
Q6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan?
Snohomish County PUD

No

SNPD agrees that the checklist of items on pages two and three lists most of the
information that would be necessary to determine if an Exceptions Request is
justified. We suggest three modifications to the proposed language to ensure
consistency with Section 215 of the Federal Power Act, with the BES Definition,
and to provide an entity seeking an Exception with the opportunity to submit all
relevant information: (1) SNPD suggests that a new question should be added
concerning the function of the facility, which would read: “Does the facility
function as a local distribution facility rather than a Transmission facility? If yes,
please provide a detailed explanation of your answer.” Section 215(a)(1) of the

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Question 2 Comment
FPA makes clear that “facilities used in the local distribution of electric energy”
are excluded from the BES, 16 U.S.C. § 824o(a)(1), and the most recent draft of
the BES definition incorporates the same language. SNPD believes a question to
address the function of the Element or system subject to an Exception Request
is necessary to determine whether the Element or system is “used” in local
distribution and thereby to ensure that this statutory limit on the BES is
observed in the Exceptions process. Further, we believe a variety of
information may be relevant to determining whether a particular facility
functions as local distribution rather than as part of the BES. For example, if
power is not scheduled across the facility or if capacity on the system is not
posted on the relevant OASIS, it is likely to function as local distribution, not
transmission. Similarly, if power enters the system and is delivered to load
within the system rather than moving to load located on another system, its
function is local distribution rather than transmission. SNPD proposes the
language above as an open-ended question so that the entity submitting the
Exceptions Request can provide this and any other information it deems
relevant to facility function.
(2) SNPD suggests modifying question 6 to “Is the facility part a designated
Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan.” This language reflects the most recent revision of
the BES Definition, which removes the reference to “Cranking Paths,” and also
helps distinguish between generators which have Blackstart capability and
those generators that are designated as a Blackstart Resource in the
Transmission Operator’s restoration plan. It is only the latter that are included
in the BES under the current draft of the definition.
(3) A general “catch-all” question should be added that will prompt the entity
submitting an Exception Request to submit any information it believes is
relevant to the Exception that is not captured in the other questions. We
suggest the following language:"Is there additional information not covered in
the questions above that supports the Exception Request? If yes, please

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Question 2 Comment
provide the information and explain why it is relevant to the Exception
Request."While SNPD believes the questions set forth in the draft capture the
information that generally would be necessary to determine whether an
Exception Request should be granted, it is foreseeable that there may be
unusual circumstances where the information called for either does not capture
the full picture or where studies other than the specific types called for in the
draft form support the Exception. An entity seeking an Exception should have
the opportunity to present any information it believes is relevant.

Response: The General Instruction area on page one has been modified to clarify that a submitting entity may provide documents
and any additional information that supports their request. It is up to the submitting entity to determine how best to present the
information supporting their request. If the submitting entity wishes to provide this additional information it may do so by listing this
information in the area provided under General Instructions.
Page one: List any attached supporting documents and any additional information that is included to supports the request:
The SDT has adopted clarifying language to differentiate between multiple Cranking Paths by requiring the Cranking Path “identified
in a Transmission Operator’s restoration plan.”
Q6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan?
Duke Energy

No

Modify wording on #3 as follows: “Please provide the appropriate list for the
operating area where the facility is located.”
Modify the wording on #6 as follows: “Is the facility part of a Cranking Path
identified in an entity’s restoration plan for a Blackstart Resource as required by
EOP-005-2?”

Response: The SDT has accepted the recommended wording change to Question 3.
Q3. Please provide the appropriate list for yourthe operating area where the Element(s) is located:
The SDT has adopted clarifying language to differentiate between multiple cranking paths by requiring the cranking path “identified

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Question 2 Comment

in a Transmission Operator’s restoration plan.”
Q6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan?
ReliabilityFirst

No

All generating units, to some degree, affect the transmission elements that
make-up the BES. What role will this effect have on the determination? If the
systems are planned properly and the day-ahead analysis is done for
maintenance work, the outage of any one element is moot. What is the phrase
“impact the over-all reliability” getting at? These studies and analysis will need
to look at multiple outages and groups of elements being taken out and
excluded. Will this be on a first come, first out process?
As for the Nuclear Plant Interface Requirement (NPIR) question, ReliabilityFirst
Staff believes these facilities should always be included as part of the BES and
taken out of the Detailed Information to Support an Exception Request.
For question 6 ReliabilityFirst Staff believes the Cranking Path should be
included in the BES definition. . ReliabilityFirst Staff feels that without including
the Cranking Paths, the reliability of the system could be jeopardized if a
restoration is required and the Cranking Paths are unavailable due to nonadherence to Reliability Standards.
Omit question 7, E3 (LN) of the definition already talks to power flow and even
if there is a small percentage of flow, it makes that entity a user of the BES,
which should be included.

Response: The SDT refers the commenter to the phrase consistent ‘with TPL methodologies’ which the SDT believes will cover the
item in question. The SDT reminds the commenter that the evaluation in question is not for removing the Element from service but
simply from inclusion or exclusion in the BES. Therefore, there should be no problem with evaluating multiple requests in the same
area and no first in, first out scenario.
The questions on nuclear interface facilities and Cranking Paths will be retained. They are just one piece of information in the process

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Question 2 Comment

and the SDT considers them as important considerations. No change made.
Question 7 will be retained. It is important to realize a distinction between the BES definition and the Exception Procedure. While
the BES definition established bright-line criteria for the determination between BES and non-BES Element(s), the Exception
Procedure requires an evaluation of all the responses and supporting materials provided as part of the Exception Request Form. No
single response or piece of supporting information will be solely dispositive in an Exception Request evaluation. The SDT believes
that power flow through this Element(s) into the BES is among the factors to be given consideration in the evaluation for an
Exception Request application.
Hydro-Quebec TransEnergie

No

Manitoba Hydro

No

Response: Without additional information, the SDT is unable to respond.
Consumers Energy

No

We believe that item 6, should read "Is the facility part of a Primary Cranking
Path associated with a Blackstart Resource?" Currently, the word "Primary" is
not included.

Response: The SDT has adopted clarifying language to differentiate between multiple cranking paths by requiring the cranking path
“identified in a Transmission Operator’s restoration plan.”
Q6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan?
Orange and Rockland Utilities,
Inc.

No

Please clarify “facility” and include “N-1” for power-flow studying.

Response: In order to maintain consistency with the nomenclature used in the Exception Process Document, draft Appendix 5C of
the NERC Rules of Procedure, the SDT has replaced “facilities” with “Element(s)”, where appropriate.
The SDT has pointed to the TPL methodology in the document and that should address your comment. No change made.

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ISO New England Inc

Yes or No
No

Question 2 Comment
- Question 1o The use of the words “connected to” is unclear. Some may read
this as generation “directly” connected to while others could interpret it more
generically.
o A generation cut-off should be included in the requirement to list all indiv

Response: The SDT acknowledges and appreciates the comments but has determined no additional clarity is needed to Question 1.
It is up to the submitting entity to determine how best to present the information supporting their request and any responses can be
further described or qualified under the comments section to Question 1. No change made.
The SDT does not believe a generation threshold is appropriate for listing all connected units. The SAR for Phase II of this project calls
for a review of the process after 12 months of experience. The SDT believes that this time period will allow industry to see if the
process is working correctly and to suggest changes to the process based on actual real-world experience and not just on
suppositions of what may occur in the future. No change made.
PSEg Services Corp

No

Questions #4 requires an analysis of the “most severe impact” associated an
outage of the Element proposed for exception. a. Both the newly Board
approved TPL-001-2 standard and the existing TPL-004-1 require that severe
contingencies be evaluated, but there are no performance requirements for
them. If the team intended the “most-severe impact” analysis to only evaluate
TPL outages that incorporate performance requirements, it should make that
clear. b. The most-severe-outage impact question does not ask key relevant
information such as: i. What is the probability that the “most severe impact
“will occur? ii. Could the impact be readily mitigated and service restored? This
point is critical because the impact of an outage lasting several minutes before
restoration versus several hours before restoration should affect the analysis.
What does question #7 (“Does power flow through this facility into the BES?”)
with check boxes for various % of a calendar year that power flows into the BES)
imply with respect to a transmission facility’s exception request? Also, is the %
of a calendar year data intended to be forecasted data or historic data? It
would seem that forecasted data would need to be supplied that is consistent

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Question 2 Comment
with the TPL models.
Finally, why are historic flows requested - they have no relevance except for
perhaps explaining historic and forecasted differences?

Response: The document cites that the TPL methodology should be followed and that should address your concern. An entity does
not have to duplicate TPL studies. No change made.
The SDT has replaced the checkboxes and language has been added requesting the submitting entity to describe the conditions and
the time duration when power flow through Element(s) into the BES. It is up to the submitting entity to determine how best to
present the information supporting their request.
Q7. If yes, then using metered or SCADA data for the most recent consecutive two calendar year period, what is the minimum
and maximum magnitude of the power flow out of the facility Element(s)? and dDescribe the conditions and the time duration
when this could occurs?
Historic flows are requested because they are an indication of power flow patterns. It is up to the submitting entity to determine
how best to present the information supporting their request and any responses can be further described or qualified under the
comments section.
City of St. George

No

The questions for transmission facilities seem to be appropriate; however, how
the answers are to be used by the region or NERC is unclear. Will a given
response to a question make exclusion impossible? If so this needs to be known
upfront and clearly documented.
For example question 4, on page 2 is open for interpretation and debate as to
what the impact to the over-all reliability of the BES is. The definition of
“impact” is really the key to the whole definition effort. Load flow, voltage,
frequency change limits may all be pieces to the puzzle. Are these criteria to be
met in normal, N-1, N-2, etc. system configurations?

Response: Several commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception application form will
mandate a negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules
of Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an
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Question 2 Comment

Exception Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be
approved or disapproved.”
The document cites that an entity should follow the TPL methodology.
Blachly-Lane Electric
Cooperative
Central Electric Cooperative
(CEC)
Clearwater Power Company
(CPC)
Consumer's Power Inc. (CPI)
Douglas Electric Cooperative
(DEC)
Fall River Electric Cooperative
(FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(Lincoln)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric

No

BLEC agrees that the checklist of items on pages two and three lists most of the
information that would be necessary to determine if an Exceptions Request is
justified. We suggest two modifications to the proposed language to ensure
consistency with the BES Definition and to provide an entity seeking an
Exception with the opportunity to submit all relevant information:
(1) We suggest modifying question 6 to “Is the facility part of a designated
Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan.” This language reflects the most recent revision of
the BES Definition and also helps distinguish between generators which have
Blackstart capability and those generators that are designated as a Blackstart
Resource in the Transmission Operator’s restoration plan. It is only the latter
that are included in the BES under the current draft of the definition.
(2) A general “catch-all” question should be added that will prompt the entity
submitting an Exception Request to submit any information it believes is
relevant to the Exception that is not captured in the other questions. We
suggest the following language: Is there additional information not covered in
the questions above that supports the Exception Request? If yes, please
provide the information and explain why it is relevant to the Exception Request.
While we believes the questions set forth in the draft capture the information
that generally would be necessary to determine whether an Exception Request
should be granted, it is foreseeable that there may be unusual circumstances
where the information called for either does not capture the full picture or
where studies other than the specific types called for in the draft form support
the Exception. An entity seeking an Exception should have the opportunity to
present any information it believes is relevant.

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Question 2 Comment

Cooperative (RAFT)
Umatilla Electric Cooperative
West Oregon Electric
Cooperative (WOEC)
Coos-Curry Electric
Coooperative
City of Austin dba Austin
Energy
Kootenai Electric Cooperative
Response: The SDT has clarified the language of question 6.
Q6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in a Transmission
Operator’s restoration plan?
The General Instruction area on page one has been modified to clarify that a submitting entity may provide documents and any
additional information that supports their request. It is up to the submitting entity to determine how best to present the information
supporting their request. If the submitting entity wishes to provide this additional information it may do so by listing this information
in the area provided under General Instructions on the Exception Request Form.
Page one: List any attached supporting documents and any additional information that is included to supports the request:
Central Lincoln

Yes

We note that if Q7 is yes, an entity is asked to provide meter or SCADA data.
Evidently the team assumes the facility in question is existing. We propose that
study data could be provided instead for facilities that are in the planning stage.

Response: The SDT recommends that each submitting entity work with its Regional Entity to resolve issues with information
availability or access and, in the event such information is not available, whether suitable replacement data is acceptable. The SDT
further recommends that where information is unavailable, the submitting entity state such in the comment area and provide the
reason for this unavailability. This will signal the Regional Entity that an issue concerning information availability will need to be

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Question 2 Comment

resolved as part of the review process. No change made.
National Grid

No

We agree with the information requested on pages 2 and 3, however we would
like more clarification regarding Item 7. When answering what % of the
calendar year power flows through the facility into BES, should this be
calculated on an hourly basis?
We would also like clarification for Item 7 regarding the request for SCADA data
from the last 2 years to determine the minimum and maximum magnitude of
the power flow out of the facility. What data should be used in situations with
new facilities or in situations or where the system configuration (topology) has
changed in such a way that the power flows in the area have changed, so the
last 2 years of SCADA data is no longer relevant

Response: The SDT has deleted the checkboxes in Question 7. To replace the checkboxes, language has been added requesting the
submitting entity to describe the conditions and the time duration when power flow through Element(s) into the BES. It is up to the
submitting entity to determine how best to present the information supporting their request.
Q7. If yes, then using metered or SCADA data for the most recent consecutive two calendar year period, what is the minimum
and maximum magnitude of the power flow out of the facility Element(s)? and dDescribe the conditions and the time duration
when this could occurs?
The SDT recommends that each submitting entity work with its Regional Entity to resolve issues with information availability or
access and, in the event such information is not available, whether suitable replacement data is acceptable. The SDT further
recommends that where information is unavailable, the submitting entity state such in the comment area and provide the reason for
this unavailability. This will signal the Regional Entity that an issue concerning information availability will need to be resolved as part
of the review process.
Ameren

No

From our perspective, the first question should be “Is the facility connected at
100 kV or above?” The questions should be reordered. Of the questions listed,
question #3 should be #1, and questions #1 should be the last question in this
section.

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Question 2 Comment
Regarding the word “permanent” as it is used to describe Flowgates, it is
suggested that the word “limiting” or “constrained” be used instead.

Response: The SDT does not believe the order of the questions is significant since no single response or piece of supporting
information will be solely dispositive in an Exception Request evaluation and all responses and supporting information provided will
receive consideration. No change made.
The SDT believes that the continued qualifier of “permanent” associated with the term “Flowgate” addresses the intent of the
definition. No change made.
ATC LLC

No

ATC proposes the following changes to Item #7:7a. Are Firm Power Transfers
scheduled to flow out of, or through, this facility into the BES in the operating
horizon? [for BES designations applicable to the operating horizon] Note: The
consideration for power flowing into the BES should be based on normal
operating conditions or base case (n-0 contingency analysis), not on historical
real-time telemetry. 7b. Are Firm Power Transfers reserved to flow out of, or
through, this facility into the BES in the planning horizon? [for BES designations
applicable to the planning horizon)

Response: The General Instruction area on page one has been modified to clarify that a submitting entity may provide documents
and any additional information that supports the request. It is up to the submitting entity to determine how best to present the
information supporting their request. If the submitting entity wishes to provide this additional information it may do so by listing this
information in the area provided under General Instructions on the Exception Request Form.
Page one: List any attached supporting documents and any additional information that is included to supports the request:
Farmington Electric Utility
System

No

The form should be titled “For Transmission Elements” rather than “Facilities”
to align with the BES definition and Appendix 5C of the NERC Rules of
Procedure.
The form should align with section 4.5.1 and 4.5.2 of Appendix 5C. It should
include a listing of the Element(s) and the status based on the application of the

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Question 2 Comment
BES Definition.
Question 6 relates to a ‘facility’ that is part of a Cranking Path. The latest
revision of the BES Definition removed the designated blackstart Cranking Paths
from the Inclusion of the BES in I3. Having a question regarding the Cranking
Path in the Exception Request makes it appear Cranking Paths are still
automatically included in the BES.
Question 7; what is an alternate method if a Requesting Entity does not have
SCADA data for the most recent two consecutive calendar years.

Response: In order to maintain consistency with the nomenclature used in the Exception Process Document, draft Appendix 5C of
the NERC Rules of Procedure, the SDT has replaced “facilities” with “Element(s)”, where appropriate.
A checkbox for indicating the current BES status and a space for listing elements for which an exception is sought is included in
Sections I and II, respectively, of the Exception Request Form provided by the Rules of Procedure Team in their posting.
The SDT disagrees with eliminating the question pertaining to Cranking Path. It is important to realize a distinction between the BES
definition and the Exception process. While the BES definition established bright-line criteria for the determination between BES and
non-BES Element(s), the Exception Process requires an evaluation of all the responses and supporting materials provided as part of
the Exception Request Form. No single response or piece of supporting information will be solely dispositive in an Exception Request
evaluation. It is not correct to assume that simply because an evaluation criterion was removed from the bright-line definition it
should also be eliminated from consideration in the Exception process. The SDT believes that cranking paths is among the factors to
be given consideration in the evaluation for an Exception Request application. Any further discussion of this issue is within the scope
of the Phase II SAR. No change made.
The SDT further disagrees that including Question 6 in the Exception Request Form, relating to Element(s) that are a part of a
Cranking Path, makes it appear that Cranking Paths are automatically included in the BES. The BES definition and the Exception
Request Procedure are separate processes.
The SDT recommends that each submitting entity work with its Regional Entity to resolve issues with information availability or
access and, in the event such information is not available, whether suitable replacement data is acceptable. The SDT further
recommends that where information is unavailable, the submitting entity state such in the comment area and provide the reason for
this unavailability. This will signal the Regional Entity that an issue concerning information availability will need to be resolved as part
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Question 2 Comment

of the review process. No change made.
Metropolitan Water District of
Southern California

No

General Comments: Metropolitan Water District of Southern California
(“MWDSC”) believes that additional work is necessary to explain how this
Detailed Information to Support an Exception Request will be used in evaluating
whether a transmission facility will be an exception to the BES.
In addition, MWDSC agrees WECC that the proposed Technical Principles for
Demonstrating BES Exceptions Request is lack of clarity. It does not provide
detail information as to what entities must provide to support their requests,
nor does it provide any criteria for consistency among regions in their
assessment of requests.
Lastly, the current proposal leaves it to each region to develop its own
methodology and criteria for evaluating the technical studies. MWDSC believes
that drafting team should establish a common method and criteria to apply
continent-wide in achieving uniformity and consistency among regions in their
assessment of exception requests.
Comments to Checklist #4: MWDSC recommends the following changes to
emphasize facility impact on the interconnection of the BES:”How does an
outage of the facility impact the over-all reliability of to the interconnection of
the BES?”
Comments to Checklist #7: What percentage of power flow through entity’s
facility into the BES will be considered as an exception to the BES?

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
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Question 2 Comment

There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is
not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both
the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides
can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of
the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements
of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
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Question 2 Comment

separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved
or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a
favorable outcome.
The SDT believes no further clarification is needed in Question 4. The General Instruction area on page one has been modified to
clarify that a submitting entity may provide documents and any additional information that supports their request. It is up to the
submitting entity to determine how best to present the information supporting their request. If the submitting entity wishes to
provide this additional information it may do so by listing this information in the area provided under General Instructions on the
Exception Request Form.
Page one: List any attached supporting documents and any additional information that is included to supports the request:
The Exception Process requires an evaluation of all the responses and supporting materials provided as part of the Exception Request
Form. There are no set thresholds, the percentage of power flow through and entity’s facility into the BES will be but one factor
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Organization

Yes or No

Question 2 Comment

among others considered when evaluating a BES Exception Request.
Transmission Access Policy
Study Group

Question 7 asks, “[d]oes power flow through this facility into the BES?” As in
the rest of the document, the reference should be to an “Element(s),” rather
than to a “facility.” In addition, we suggest that the meaning of power flowing
“through” the Element(s) be clarified, consistent with clarification of the same
point in Exclusion E3 of the BES Definition.
In TAPS’ comments on the BES Definition, also submitted today, TAPS suggests
that the first sentence of Exclusion E3 be revised to state: “Power flows only
into the LN, that is, at each individual connection at 100 kV or higher, the precontingency flow of power is from outside the LN into the LN for all hours of the
previous 2 years.” We propose that Question 7 in the Detailed Information to
Support an Exception Requests be similarly revised: “Does power flow from this
facility into the BES, i.e., at any individual connection at 100kV or higher, is the
pre-contingency flow of power from the LN to the BES for any hour of the
previous 2 years?”

Response: In order to maintain consistency with the nomenclature used in the Exception Process Document, draft Appendix 5C of
the NERC Rules of Procedure, the SDT has replaced “facilities” with “Element(s)” where appropriate.
The SDT disagrees with the use of parallel language for exclusions in the BES Definition and Exception Request Form. It is
important to realize a distinction between the BES definition and the Exception process. While the BES definition established
bright-line criteria for the determination between BES and non-BES Element(s), the Exception Process requires an evaluation of
all the responses and supporting materials provided as part of the Exception Request Application Form.
Tri-State Generation and
Transmission Assn., Inc.
Energy Mangement

Again Yes/No is conflicting in the question. The requested information in#2 is
too vague and may be subjective. If the information in#7 is requested in the
planning stage the data would not be available.
What objective criteria would be used to determine the state of the exception
request?

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Organization
TSGT G&T

Yes or No

Question 2 Comment
Again Yes/No is conflicting in the question. The requested information in#2 is
too vague and may be subjective.
If the information in#7 is requested in the planning stage the data would not be
available.
What objective criteria would be used to determine the state of the exception
request?

Response: The SDT disagrees that the information requested in Question 2 is too vague and subjective but understands the concerns
raised by the commenters in not receiving hard and fast guidance on the Exception criteria. The SDT would like nothing better than
to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and an initial
attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could
have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the
commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of
substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
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Organization

Yes or No

Question 2 Comment

rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is
not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both
the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides
can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of
the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements
of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved
or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
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Organization

Yes or No

Question 2 Comment

experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a
favorable outcome.
As to the availability of needed information to support an exception request, the SDT recommends that each submitting entity
work with its Regional Entity to resolve issues with information availability or access, and in the event such information is not
available, whether suitable replacement data is acceptable. The SDT further recommends that where information is
unavailable, the submitting entity state such in the comment area and provide the reason for this unavailability. This will signal
the Regional Entity that an issue concerning information availability will need to be resolved as part of the review process.
Finally, there are options for a submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if
they feel that an improper decision has been made on their submittal.
WECC Staff

Yes

The requested information in the checklist is appropriate. However; the
exceptions process as drafted, with no objective criteria defining how to assess
the submittals, leaves it to each Regional Entity to develop their own criteria to
evaluate the responses to the checklist included in the submittals, leading to
inconsistency between Regional Entities.
In addition, WECC recommends clarifying Question 7. On its face it is unclear
what defines power flowing through a facility in the BES. It should be clear
whether a qualitative or quantitative response is required.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 2 Comment

There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is
not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both
the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides
can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of
the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements
of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

81

Organization

Yes or No

Question 2 Comment

separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved
or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a
favorable outcome.
The SDT has deleted the checkboxes under Question 7. To replace the checkboxes, language has been added requesting the
submitting entity to describe the conditions and the time duration when power flow through Element(s) into the BES. If the
answer is yes to the question “Does power flow through this Element(s) into the BES,” the sub-question seeks a quantitative
amount. However, it is up to the submitting entity to determine how best to present the information supporting their request
and any responses can be further described or qualified under the comments section.
Q7. If yes, then using metered or SCADA data for the most recent consecutive two calendar year period, what is the minimum and
maximum magnitude of the power flow out of the facility Element(s)? and dDescribe the conditions and the time duration when this
could occurs?

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Organization

Yes or No

Transmission

Yes

Question 2 Comment
“Impact” and “degree of impact” in question 2 should be framed with the
criteria expected.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is
not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both
the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides
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Organization

Yes or No

Question 2 Comment

can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of
the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements
of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved
or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future.
Given the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of
this project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT
asks the commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes

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Organization

Yes or No

Question 2 Comment

will result in a favorable outcome.
American Electric Power

Yes

We recommend capitalizing “facility”.

Response: In order to maintain consistency with the nomenclature used in the Exception Process Document, draft Appendix 5C
of the NERC Rules of Procedure, the SDT has replaced “facilities” with “Element(s)”, where appropriate.
Long Island Power Authority

Yes

On page 3 why reference if a facility is part of a Cranking Path after the SDT has
deleted Cranking Paths from the Inclusion list as part of the BES definition.

Response: It is important to realize a distinction between the BES definition and the Exception Procedure. While the BES definition
established bright-line criteria for the determination between BES and non-BES Element(s), the Exception Procedure requires an
evaluation of all the responses and supporting materials provided as part of the Exception Request Application Form. No single
response or piece of supporting information will be solely dispositive in an Exception Request evaluation. It is not correct to assume
that simply because an evaluation criterion was removed from the bright-line definition it should also be eliminated from
consideration in the Exception process. The SDT believes that Cranking Path is among the factors to be given consideration in the
evaluation for an Exception Request application. Further discussion of this issue is within the scope of the Phase II SAR. No change
made.
City of Redding Electric Utility

Yes

City of Redding

Yes

Georgia System Operations
Corporation

Yes

Oncor Electric Delivery
Company LLC

Yes

Independent Electricity
System Operator

Yes

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Organization

Yes or No

Question 2 Comment

NV Energy

Yes

Central Hudson Gas & Electric
Corporation

Yes

Exelon

Yes

Hydro One Networks Inc.

Yes

Holland Board of Public Works

Yes

Southern Company
Generation

Yes

Dominion

Yes

Southwest Power Pool
Standards Review Team

Yes

SERC Planning Standards
Subcommittee

Yes

Tacoma Power

Yes

Tacoma Power supports the information requested on page 2 and 3.

Springfield Utility Board

Yes

SUB agrees with the instructions, finding them to be clear and reasonable.

BGE

Yes

No comment.

Michigan Public Power Agency

Yes

We believe that the SDT’s proposed approach for exception criteria is
reasonable; recognizing that one method/criteria can not be applicable to
everyone and every situation within the ERO foot print. See our comment in Q1.

We agree with the information being requested.

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Organization

Yes or No

Question 2 Comment

Response: Thank you for your support.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

87

3. Page four of the ‘Detailed Information to Support an Exception Request’ contains a checklist of items that deal with generation
facilities. Do you agree with the information being requested or is there information that you believe needs to be on page four that is
missing? Please be as specific as possible with your comments.
Summary Consideration: Several respondents suggested better clarity on whether responses should be market or reliability related.
The SDT made slight modifications to the “Detailed Information to Support an Exception Request” form to request responses that are
specifically reliability related.
Based on the comments received and past history for such situations, the SDT believes that entities will be able to obtain the requisite
information necessary to submit a request. However, should an entity have difficulty, they will need to obtain the assistance of their
Regional Entity to secure the data. If the entity still can’t obtain the needed data, then the SDT fully expects that entity’s Regional Entity
to work with them to come up with a plan that will allow that entity to fill out the request form in a manner that will be acceptable to
the Regional Entity so that processing of the request can continue.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like
nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion
and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the
SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point
out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the
form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single
package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity
has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for
completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in
actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a
position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes
that the visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the
integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3,
and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity
decides to reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the
Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception
request. On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an
acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information
aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard and
fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by
either party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this
equation. Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information
needs to be supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or
unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section
3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to
a question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
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complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
Page 1 - List any attached supporting documents and any additional information that is included to supports the request:
Generation - Q1. What is the MW value of the host Balancing Authority’s most severe single Contingency and what is the generator’s, or
generator facility’s generation resource’s, percent of this value?
Generation - Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Generation - Q3. Is the generator generation resource designated as a must run unit for reliability?

Organization

Yes or No

Northeast Power Coordinating
Council

No

Question 3 Comment
This Application generally applies to traditionally fueled generating facilities.
Application form and justifications would be required for non-traditional resources
such as solar and wind?
Question 2 on page 4 asks, “Is the generator or generator facility used to provide
Ancillary Services?” If some of these Generator check list items are market-related
and not reliability-related, they should not be present. If the Ancillary Services are
reliability-related, please explain their relation to BES reliability.
Suggest inserting the word “reliability” before the words “must run” in question 3.
Question 5 on page 4 asks, “Does the generator use the BES to deliver its actual or
scheduled output, or a portion of its actual or scheduled output, to Load?” This
could mean the generator may serve local loads through non-BES facilities. In order
to serve these local loads the generator would need to be connected to a Radial
system, a Local Network or to local distribution facilities. Is this what is intended?
Were there any other possibilities envisioned by the BES SDT?

Response: The SDT believes the form can be used for any type of generation resource as there are no restrictions on type in the
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Organization

Yes or No

Question 3 Comment

questions. No change made.
The form has been modified to request only reliability related functions be included.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Q3. Is the generator generation resource designated as a must run unit for reliability?
If the entity serves the indicated Load through a radial system, etc., it should supply that information as part of its supporting
information. No change made.
ACES Power Marketing
Standards Collaborators

No

Q5 has a “Description/Comments” section. Further clarification on what type of
information to include under the Description would help “standardize” the
supporting information and “will provide more clarity and continuity to the process.”
The definition of ancillary services varies and can be quite broad. It can include
reactive power and voltage support for example. All generators provide some
reactive power and voltage support. Thus, ancillary services should be further
defined or one could construe it to limit any generator from being excepted.

Response: Entities applying for an exception can include any information they deem appropriate in the general and specific sections
of the form. It would be difficult to establish specific criteria that would be applicable to all systems.
Questions regarding ancillary services have been further clarified.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Farmington Electric Utility
System

No

Question 1, the SDT team should consider if the Submitting entity or Owner is part of
a Reserve Sharing Group. The host BA’s most single severe Contingency vs the
obligation of reserves required as part of a Reserve Sharing Group may be
substantial.
The SDT team should clarify if it is a single generator or if it is the aggregate at a
facility.

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Organization

Yes or No

Question 3 Comment

Response: An entity can supply that information as part of its supporting information in its request. No change made.
The assumption is that the request is being made as a result of the application of the definition which is for single units or aggregate
as appropriate.
Dominion

No

The SDT language specifying services acceptable for inclusion in an exclusion request
references ancillary services identified under a Transmission Service Provider’s OATT.
However, there is great variation in the services that have actually been implemented
and posted across North America under those OATTs. There is no consistent
description or terminology to characterize those services. In short, Transmission
Providers have been permitted to individualize OATT services to fit regional market
structures and vernacular. For example, PJM’s OATT includes a schedule for
Blackstart Service. The FERC pro-forma tariff does not. ISO-NE’s tariff includes the
following ancillary services (which are performed by the ISO and TSP): o Scheduling,
System Control and Dispatch Service o Energy Imbalance Service o Generator
Imbalance Service Therefore, Dominion suggests that the SDT provide a specific list of
ancillary services that would be eligible for exclusion, rather than rely on OATT
references. Examples might include: reactive, voltage control or regulation services,
frequency response and blackstart services.
Dominion is also aware that the phrase “ ‘must run” is used in some RTO/ISO market
systems to indicate intent to self-schedule the generator. Dominion suggests that
question 3 be revised to read “Is the generator designated as a “must run” unit by
either the Balancing Authority, Resource Planner or Reliability Coordinator?

Response: The form has been modified to request only reliability related functions are included.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Q3. Is the generator generation resource designated as a must run unit for reliability?
Southern Company

No

We do not agree completely with the information being requested. For checklist
item #2, please specify what is included in "providing Ancillary Services" for a

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Organization

Yes or No

Generation

Question 3 Comment
generator.
For #4, can the question include a measure of evaluating the "most severe system
impact"? Can the specific study that is required to be evaluated be outlined?

Response: Questions regarding ancillary services have been further clarified.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
The SDT refers the commenter to the statement that TPL methodologies should be followed in formulating the supporting
information for the request.
AECI and member G&Ts

No

Most of these questions appear relevant to the LN concept paper, but irrelevant to
this standard's requirements. The last conditional of Item 5) must always be
answered Yes, unless the local-network is islanded.

Response: The SDT does not see a need for a one-to-one correspondence between the definition items and the information
requested. The form contains questions that will supply information the review panel will need to evaluate the request.
NERC Staff Technical Review

No

For units designated as must run, the Submitting entity should be required to
describe the reasons for which the unit has been so designated. We believe the
general requirement to provide an appropriate reference is too vague, and should be
appended with “. . . including a description of why the unit has been designated as
must run and if applicable, the contingencies that would result in violation of the
NERC Reliability Standards if the unit was not must run.”

Response: The form has been modified to request only reliability related functions are included. Information such as shown in the
comment can be entered as needed by the requesting entity. In general, an entity should supply any and all information that it feels
is needed to support its request.
Q3. Is the generator generation resource designated as a must run unit for reliability?

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Organization

Yes or No

Duke Energy

No

Question 3 Comment
Modify wording on #3 as follows: “Please provide the appropriate reference for the
operating area where the facility is located.”

Response: The SDT does not believe that the suggested wording provides any additional clarity. No change made.
NV Energy

No

In question #7 of the form, it would be useful to the analysis for technical exception
to include not only the minimum and maximum power flow out of the candidate
facility, but also a description or demonstration of the “typical” magnitude or the
“average” of such flow. An entity may provide this sort of information anyhow, but a
prompt for this type of information could be useful and prevent having to solicit
more information during the review.
Should be included in Question 2.

New York State Dept. of Public
Service

No

Question 6 should be dropped. Facilities in a cranking path for a blackstart resource
should not be a consideration.
Question 7 is circular. If a facility is used to flow power into the BES, by definition it is
outside the BES. Needs clarification as to the information the question is seeking.
Should be question 2.

Response: Please see the response to Q2.
Consolidated Edison Co. of NY,
Inc.

No

For Generation Facilities: This Application form would appear to generally apply to
traditional generating facilities. o What Application form and justifications would be
required for non-traditional resources, e.g., solar and wind?
o The Application form at 2 asks, “Is the generator or generator facility used to
provide Ancillary Services?”If some of these Generator check list items are marketrelated and not reliability-related, then they should not be present.
o If the Ancillary Services are reliability-related, please explain their relation to BES

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Organization

Yes or No

Question 3 Comment
reliability.
Recommendation: Insert the word “reliability” before the words “must run” in
question 3.
The Application form at 5 asks, “Does the generator use the BES to deliver its actual
or scheduled output, or a portion of its actual or scheduled output, to Load?” We
assume this mean the generator may serve local loads through non-BES facilities. In
order to serve these local loads the generator would need to be connected to a
Radial system, a Local Network or to local distribution facilities. o Is this meaning
above implied and intended by this question? o Were there any other possibilities
envisioned by the BES SDT?

Response: The SDT believes the form can be used for any type of generation resource as there are no restrictions on type in the
questions.
The form has been modified to request only reliability related functions be included.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Q3. Is the generator generation resource designated as a must run unit for reliability?
Entities applying for an exception can include any information they deem appropriate in the general and specific sections of the form.
If the entity serves the indicated Load through a radial system, etc., it should supply that information as part of its supporting
information. No change made.
American Electric Power

No

It is unclear how the process will work with the interaction among the various NERC
Functions. For instance, an exception request from generation might require
collaboration among other functional entities, i.e. GOP, TOP, and RC.
The question “How does an outage of the generator impact the over-all reliability of
the BES” may be subjective and dependent on contingencies at any given time. It
would be dependent on what state the BES would be in the area the generator is
located. More detail would be needed in describing the study required to have

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Organization

Yes or No

Question 3 Comment
consistent results.

Response: Please refer to the Rules of Procedure for clarity on how the process will provide consistency.
As every generator will have different impact it is up to the entity to complete the studies and to respond appropriately in the
written section of the question.
ReliabilityFirst

No

If the systems are planned properly and the day-ahead analysis is done for
maintenance work, the outage of any one unit and even with the most serve outage
happening, the system should be capable of withstanding. These studies and analysis
will need to look at multiple outages and groups of units being taken out and
excluded before any could be exempt. What is the phrase “impact the over-all
reliability” getting at?
These studies and analysis will need to look at multiple outages and groups of
elements being taken out and excluded. Will this be on a first come, first out
process?
As for the Ancillary Services question, ReliabilityFirst Staff believes that if a unit
provides this service, it should be included in the BES.
The same applies for the “must run units” in question 3.
Omit question 5, E3 (LN) of the definition already talks to power flow and even if
there is a small percentage of unit’s output flowing onto the BES, it makes that entity
a user of the BES, which should be included.

Response: The SDT refers the commenter to the phrase consistent ‘with TPL methodologies’ which the SDT believes will cover the
item in question.
The SDT reminds the commenter the evaluation in question is not for removing the Element from service but simply from inclusion or
exclusion in the BES. Therefore, there should be no problem with evaluating multiple requests in the same area and no first in, first
out scenario.
Ancillary services or must run status is only one piece of information in a total review of the impact of the Element on the BES. The
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Organization

Yes or No

Question 3 Comment

SDT does not believe that simply because a generator provides ancillary services or that it is must run that it should be automatically
included.
There is more to the BES than just the local networks. No change made.
Hydro-Quebec TransEnergie

No

Manitoba Hydro

No

Response: Without any specific comments, the SDT is unable to respond.
ISO New England Inc

No

- Question 1o The question would be better worded as “How many MW are lost
following the host Balancing Authority’s most severe single Contingency...”.o The
question becomes difficult to answer when the most severe single Contingency can
change on a

Response: A slight revision has been made to Question 1 which should provide more clarity in this regard.
Q1. What is the MW value of the host Balancing Authority’s most severe single Contingency and what is the generator’s, or
generator facility’s generation resource’s, percent of this value?
PSEg Services Corp

No

With regards to question #2 (“Is the generator or generating facility used to provide
Ancillary Services”), the answer for most synchronous generators is probably “yes”
unless they are in a bid-based market that selects specific generators for Reactive
Power delivery. Since most generators (with the exception of those with nuclear
prime movers) provide Reactive Power to meet a Transmission Operator-specified
voltage, they would provide that Ancillary Service. Other generators (again, with the
exception of generators with nuclear prime movers) may be eligible to provide other
Ancillary Services such as Spinning Reserve, but may have rarely done so. However,
they still may be “used do provide” Spinning Reserve at any time. How would those
generators respond to question #2?
Questions #4 requires an analysis of the “most severe impact” associated an outage

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Organization

Yes or No

Question 3 Comment
of the Element proposed for exception. a. Both the newly Board approved TPL-001-2
standard and the existing TPL-004-1 require that severe contingencies be evaluated,
but there are no performance requirements for them. For consistency, performance
requirements for the most-severe-impact analysis needed to be defined by the team.
If the team intended the “most-severe impact” analysis to only evaluate TPL outages
that incorporate performance requirements, it should make that clear.b. The mostsevere-outage impact question does not ask key relevant information such as: i.
What is the probability that the “most severe impact “will occur?ii. Could the impact
be readily mitigated and service restored? This point is critical because the impact of
an outage lasting several minutes before restoration versus several hours before
restoration should affect the analysis.
What does the answer to the question #5 in the Generator Facilities section (“Does
the generator use the BES to deliver its actual or scheduled output, or a portion of its
actual or scheduled output, to Load?”) imply with respect to a generator’s exclusion?
Also, the phrase “deliver its actual or scheduled output ...to load” needs explanation.
The use of “actual output” and “scheduled output” may have several contexts. a. For
example, in a market, a generator’s actual output may suddenly go to zero due a
forced outage, but the generator has financial obligations that accrue for delivering
its scheduled output, which is in fact provided by other sources since the generator is
unavailable. Is the question asking about the use of BPS facilities by resources that
may be substituted for delivery of a generator’s scheduled output when it differs
from its actual output?b. Now assume that a generator’s actual output equals its
scheduled output and that several generators are forced out of service in another
Balancing Authority, resulting in a frequency decline. Generators within the
interconnection with active governors and available spinning capacity will
automatically increase their output above their scheduled output, resulting in
Inadvertent Interchange. Is the question related to the BES facilities used to deliver
such Inadvertent Interchange?c. Again assume that a generator’s actual output
equals its scheduled output. Is the question related to the actual BES facilities that
may be used to deliver the generator’s power to Load? That would require an

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Organization

Yes or No

Question 3 Comment
analysis of generator and load shift factors to determine what actual facilities carry
the power generated from a generator to a specific load for a given set of
assumptions on the system topology. In a market, this analysis would not be possible
for generators that do not self-schedule for delivery to specific loads.

Response: The form has been modified to request only reliability related functions are included.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
The SDT reminds the commenter the requirement is only to follow the TPL methodologies which have been spelled out in TPL-001-2.
An entity can supply any and all information that it thinks will support its request.
Entities applying for an exception can include any information they deem appropriate in the general and specific sections of the form.
It is simply just one piece of information that is considered as useful for the review panel in making its ultimate decision. Any
clarifying points an entity wants to make in its request can be supplied as the entity thinks appropriate.
City of St. George

No

The questions for generation facilities seem to be appropriate; however, how the
answers are to be used by the region or NERC is unclear. Will a given response to a
question make exclusion impossible? If so this needs to be known upfront and clearly
documented. For example question 4, on page 4 is open for interpretation and
debate as to what the impact to the over-all reliability of the BES is. The definition of
“impact” is really the key to the whole definition effort. Load flow, voltage,
frequency change limits may all be pieces to the puzzle.
Are these criteria to be met in normal, N-1, N-2, etc. system configurations?

Response: Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will
mandate a negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules
of Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an
Exception Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be
approved or disapproved.”
The SDT refers the commenter to the statement that TPL methodologies should be followed in formulating the supporting

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Organization

Yes or No

Question 3 Comment

information for the request.
Ameren

No

It is suggested that question #2 be deleted and replaced with “Is the generator
designated as a black-start unit in an entity’s restoration plan?”

Response: The SDT assumes the commenter is actually referring to the sixth question for transmission. Please see the detailed
response to Q2.
Georgia System Operations
Corporation

No

Item 2 asks about “the generator or generator Facility,” but 3, 4 and 5 only refer to
the generator. There is no immediately apparent reason for them to be different.
The language in Item 2 seems preferable.

Response: The SDT has reviewed all of the terminology for consistency and made clarifying changes as necessary. For example:
Q1. What is the MW value of the host Balancing Authority’s most severe single Contingency and what is the generator’s, or
generator facility’s generation resource’s, percent of this value?
IRC Standards Review
Committee

We do not agree with the detailed information requirements for generators. In a
deregulated environment, generators are free to bid into the market or offer their
availability, to dispatched based on bid price and resource needs, or overall
generation dispatch plans. A generator may be on line but not dispatched, or not on
line at all due to maintenance outage or a decision to not start. Its status and
generation level have little to do in determining whether or not it needs to be
included as a BES facility. Rather, it is the generator’s active contribution to the BES
performance, namely, its protective relay setting and coordination with those of
related facilities and its ability to control voltage, respond to contingencies, ride
through frequency and voltage excursion, provide accurate model with verification,
etc., are critical to BES reliability performance. There are currently no standards or
requirements that mandate a generator to be on line or to attain a specific level of
output, and we do not see such a need at all in the future. Whether or not the unit is
designed as a MUST RUN will depend on whether the generator is (a) on line and bid
into the market or be included in the dispatch plan, and (b) the prevailing system

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0

Organization

Yes or No

Question 3 Comment
conditions such as flow pattern, potential constraints, etc. A generator may be
designated as a MUST RUN one day but not the others. Similar argument applies to a
generator bidding in the ancillary service markets, or be dispatched to provide
reserve or AGC control capability. In our view, generators’ physical characteristics and
their response to changes on the BES are important considerations for them to be
included in the BES. These characteristics affect the assessment and actual
performance of the BES in the following key areas: o Voltage and frequency ride
through capability o Voltage control (AVR, etc.) o Underfrequency trip setting o
Protection relay setting coordination o Data submission for modeling; verification of
capability and model We therefore suggest that the entire P.4 be removed as the
information it asks for has nothing to do with a generator’s physical characteristics or
material impact on BES reliability. Having a threshold by MVA suffices to determine if
a generator needs to be included as a BES facility, whose characteristics, expected
performance and data provision are important to achieve target BES performance
and hence should be governed by reliability standards.

Response: The form has been modified to request only reliability related functions are included.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Q3. Is the generator generation resource designated as a must run unit for reliability?
Tri-State Generation and
Transmission Assn., Inc.
Energy Mangement

Again Yes/No is conflicting in the question. Information requested in#4 is subjective
and too vague.

TSGT G&T

Again Yes/No is conflicting in the question. Information requested in #4 is subjective
and too vague.

Response: The SDT has attempted to build in maximum flexibility within the form while still providing the review panel information
that will be needed in evaluating a request. No change made.

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1

Organization

Yes or No

Hydro One Networks Inc.

Yes

Question 3 Comment
See comments in Q1.

Response: Please see response to Q1.
Long Island Power Authority

Yes

Need to define the term "must run unit"

PacifiCorp

Yes

PacifiCorp suggests modifying Question 3 as follows: “Is the generator designated as
a must run unit by the Balancing Authority?”

Response: The form has been modified to request only reliability related functions are included.
Q3. Is the generator generation resource designated as a must run unit for reliability?
Electricity Consumers
Resource Council (ELCON)

Yes

Our “Yes” response is conditioned on the comments to Questions 1 and 2 above.

Response: Please see responses to Q1 and Q2.
Bonneville Power
Administration

Yes

Regarding #1 on page 4: BPA Believes seasonality may need to be considered when
comparing the generator with the most severe single contingency.

Response: Seasonality issues can be explained in the written response areas of the application form or additional documentation
can be provided as needed. No change made.
WECC Staff

Yes

The requested information in the checklist is appropriate. However; the exceptions
process as drafted, with no objective criteria defining how to assess the submittals,
leaves it to each region to develop their own criteria to evaluate the responses to the
checklist included in the submittals, leading to inconsistency between Regional
Entities.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
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2

Organization

Yes or No

Question 3 Comment

hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is
not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and
received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is
not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both
the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides
can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
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3

Organization

Yes or No

Question 3 Comment

being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of
the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements
of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved
or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a
favorable outcome.
Kootenai Electric Cooperative
Snohomish County PUD
Blachly-Lane Electric

Yes

KEC agrees that the items listed on page 4 of the Detailed Information to Support an
Exception Request capture the information that generally would be necessary to
make a reasoned determination concerning the BES status of a generation facility.
KEC suggests three refinements to the questions: (1) Question 2 should be modified

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Organization

Yes or No

Cooperative
Central Electric Cooperative
(CEC)
Clearwater Power Company
(CPC)
Consumer's Power Inc. (CPI)
Douglas Electric Cooperative
(DEC)
Fall River Electric Cooperative
(FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(Lincoln)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
Umatilla Electric Cooperative

Question 3 Comment
by adding “necessary for the operation of the interconnected bulk transmission
system” to the end of the question, so that it reads: “Is the generator or the
generator facility used to provide Ancillary Services necessary for the operation of the
interconnected bulk transmission system?” The italicized language is necessary to
distinguish between a generator that provides, for example, reactive power or
regulating reserves that support operation of the interconnected bulk grid, and, for
example, a behind-the-meter generator that provides back-up generation to a
specific industrial facility. The former may be necessary for the reliable operation of
the interconnected bulk transmission system, but the latter is not.
(2) The current draft of the BES Definition contains Exclusions for radials and for Local
Networks. To be consistent with these aspects of the revised BES definition, KEC
suggests modifying question 5 by adding “radial, or Local Network” to the question,
so that it would read: “Does the generator use the BES, a radial system, or a Local
Network to deliver its actual or scheduled output, or a portion of its actual or
scheduled output, to Load?
(3) For reasons similar to those explained in our response to Question 2, a general
“catch-all” question should be added that will prompt an entity submitting an
Exception Request for a generator to submit any information it believes is relevant to
the Exception that is not captured in the previous questions. We suggest the
following language:Is there additional information not covered in questions 1 through
5 that supports the Exception Request? If yes, please provide the information and
explain why it is relevant to the Exception Request.This will allow an entity seeking an
Exception for a generator to identify any unusual circumstances or non-standard
information that might support its Exception Request. An entity seeking such an
Exception should have the opportunity to present any information it believes is
relevant.

West Oregon Electric
Cooperative (WOEC)
Coos-Curry Electric
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Organization

Yes or No

Question 3 Comment

Coooperative
City of Austin dba Austin
Energy
Response: (1) Questions regarding ancillary services have been further clarified.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
(2) If the entity serves the indicated Load through a radial system, etc., it should supply that information as part of its supporting
information. No change made.
(3) This type of question is covered by the clarified line item on page 1 of the form:
List any attached supporting documents and any additional information that is included to supports the request:
Central Lincoln

Yes

Oncor Electric Delivery
Company LLC

Yes

Independent Electricity
System Operator

Yes

Consumers Energy

Yes

Central Hudson Gas & Electric
Corporation

Yes

Exelon

Yes

Holland Board of Public Works

Yes

Transmission

Yes

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Organization

Yes or No

Question 3 Comment

Pepco Holdings Inc

Yes

ATC LLC

Yes

Southwest Power Pool
Standards Review Team

Yes

SERC Planning Standards
Subcommittee

Yes

City of Redding Electric Utility

Yes

City of Redding

Yes

Tacoma Power

Yes

Tacoma Power supports the information requested on page 4.

BGE

Yes

No comment.

Michigan Public Power Agency

Yes

Response: Thank you for your support. The SDT did make some clarifying changes due to comments received.
Q2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary Services?
Q3. Is the generator generation resource designated as a must run unit for reliability?

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4. Do you have concerns about an entity’s ability to obtain the data they would need to file the ‘Detailed Information to Support
an Exception Request’? If so, please be specific with your concerns so that the SDT can fully understand the problem.

Summary Consideration: Based on the comments received, the SDT believes that entities will be able to obtain the requisite
information necessary to submit a request. However, should an entity have difficulty, they will need to obtain the assistance of their
Regional Entity to secure the data. If the entity still can’t obtain the needed data, then the SDT fully expects that entity’s Regional
Entity to work with them to come up with a plan that will allow that entity to fill out the request form in a manner that will be
acceptable to the Regional Entity so that processing of the request can continue. The SDT recognizes that there will be costs associated
with the request. The SDT feels that an entity may have to conduct a cost and benefit analysis in order to determine the value of
pursuing a request.
No significant changes were made to the request form as a result of comments received to this question. There were suggestions to
use some terms more consistently, and this suggestion was adopted. The SDT had used, “facility” and “element” to mean the same
things, and has now adopted the word, “Element” throughout the revised document. Similarly the team changed the word,
“application” to “request” for greater clarity.

Organization

Yes or No

AECI and member G&Ts

No

Ameren

No

ATC LLC

No

BGE

No

Central Hudson Gas & Electric
Corporation

No

Central Lincoln

No

Question 4 Comment

No comment.

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Organization

Yes or No

City of Redding

No

Hydro One Networks Inc.

No

Hydro-Quebec TransEnergie

No

IRC Standards Review
Committee

No

ISO New England Inc

No

Long Island Power Authority

No

National Grid

No

NERC Staff Technical Review

No

NV Energy

No

Oncor Electric Delivery
Company LLC

No

PacifiCorp

No

SERC Planning Standards
Subcommittee

No

Springfield Utility Board

No

Question 4 Comment

All concerns were captured in comments provided to the previous questions.

The information appears to be readily available to entities seeking exceptions.

PacifiCorp is speaking from a perspective where the Company is registered for
multiple functions (i.e., TO, GO, TOP, GOP, BA, TPL, etc.) and the requested
information is currently available from Company resources.

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Organization

Yes or No

Tacoma Power

No

Question 4 Comment
Tacoma Power supports the expectation that entities will be able to supply the
information requested.

Response: Thank you for your support.
American Electric Power

No

As stated in the response to question #3, the question “How does an outage of the
generator impact the over-all reliability of the BES” may be subjective and dependent
on contingencies at any given time. It would be dependent on what state the BES
would be in the area the generator is located. More detail would be needed in
describing the study required to have consistent results.

No

Throughout the document, because it will be part of a larger Exception Request Form,
it should, when possible, use terms consistent with the rest of that form (e.g.,
“Request” rather than “application”).

Response: See response to Q3.
Georgia System Operations
Corporation

Similarly, defined terms (even if only defined in the context of the Request Form in
which these Principles will be used) such as “Exception,” “Request,” “Element” or
“Facility” should be capitalized; if the use of lower case is intended to convey a
different meaning than what is defined, another term should be used to avoid
confusion.
The Definition and Request Form generally use the term “Element,” so it is unclear
why this document should so consistently use “facility.” For consistency, “Element(s)”
or possibly “Element(s) or Facility” should be used.
Response: The SDT has made changes to the Request Form based upon your comments, changing the word, “facility” to “Element”
and “application” to “request” for consistency throughout the document.
Independent Electricity
System Operator

No

We anticipate that entities will be granted access to the required historical operations
records and modeling data after signing of non-disclosure agreements with the

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Organization

Yes or No

Question 4 Comment
providers of the information.

Response: The SDT concurs that it may be necessary for entities to execute such agreements.
Northeast Power Coordinating
Council

No

According to the Applicability section, the TPL Reliability Standards are only applicable
to the Planning Coordinator (PC) and the Transmission Planner (TP). Was it the BES
SDT’s assumption that Applicants would have the PC or TP run studies for them, or
that all Applicants would gain access to those models and run the models themselves?
(Ref. TPL-002-1b, Applicability: Planning Authority, and Transmission Planner.)

Pepco Holdings Inc

No

Not all TOs have the capability to perform the power flow and stability analysis on
their own, necessary to meet the exception request. It may be burdensome for the
TO to hire a consultant or to have their affiliated TPL perform the rigorous
study/analysis as contained in the TPL standards. Additional details should be
provided as to what part of the TPL standards apply. Should the Affiliated TPL be
required to perform TOs studies for exception requests? If so should that be stated in
a related standard as a requirement?

Southern Company
Generation

Yes

An IPP with no Transmission Planning department may find it very difficult to perform
an interconnection wide base case as required in the general instructions.

Bonneville Power
Administration

Yes

BPA believes the studies discussed in pages 2-4 would likely need to be completed and
the required information supplied by the Transmission Planner/Operator of the
Balancing Authority Area since many of the assumptions regarding performance of the
BES to delivery under a variety of operating conditions is known only to the TP and
TOP of the system.

Consolidated Edison Co. of NY,
Inc.

Yes

According to the Applicability section, the TPL Reliability Standards are only applicable
to the Planning Coordinator (PC) and the Transmission Planner (TP). Was it the BES
SDT’s assumption that Applicants would have the PC or TP run studies for them, or
that all Applicants would somehow gain access to those models and run the models

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Organization

Yes or No

Question 4 Comment
themselves? (Ref. TPL-002-1, Applicability: Planning Coordinator, and Transmission
Planner.)

Response: The Request Form includes language indicating that studies need to be consistent with the methodologies described in
the TPL standards, not that the studies need to be the actual Planning Coordinator or Transmission Planner studies. The SDT feels that
it is up to the Registered Entity to work out the details for studies needed for a request.
Orange and Rockland Utilities,
Inc.

No

However, please clarify “facility” and include “N-1” for power-flow studying.

Response: The SDT has modified the document to consistently use the term, “Element” rather than facility throughout the document.
The SDT believes that solely relying upon a single case study, i.e., N-1; would be inappropriate for the purposes of making a decision
under this definition. Entities will need to consider the use of the Elements in a variety of cases to determine whether or not the
Elements would be BES or not.
WECC Staff

Yes

Entities would have a difficult time deciding what data to obtain. Getting the data for
their own specific facilities should be relatively simple for the majority of entities.
However, it is possible smaller entities may have a higher burden putting together the
appropriate information for inclusion in a study case that they currently may not do. In
addition, because the instructions state that a case will be “suitably complete and
detailed,” WECC believes there is insufficient guidance as to what amount and degree
of detail in the data is sufficient for the submittal process. Without thresholds it is
difficult to determine whether the entities will have the ability to obtain necessary
data to file for an exception. At this time, WECC views the instructions as insufficient
for these reasons.

Response: The SDT understands the concerns raised by the commenter in not receiving hard and fast guidance on this issue. The SDT
would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would
also like to point out to the commenter that it directly solicited assistance in this matter in the first posting of the criteria and received
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Organization

Yes or No

Question 4 Comment

very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the application to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred
in rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the application process. The SDT again points to the variations that
will abound in the applications as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here.
This is not something that hasn’t been handled before by either party and there is a great deal of professional experience involved on
both the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both
sides can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO
Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1, where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
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Organization

Yes or No

Question 4 Comment

bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple applications will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 that states “No single piece of evidence provided as part of an Exception Request or response to a question will be solely
dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
Blachly-Lane Electric
Cooperative
Central Electric Cooperative
(CEC)
City of Austin dba Austin
Energy
Clearwater Power Company

Yes

The Standards Drafting Team should consider whether it is necessary to require
entities other than the entity filing the Exception Request to provide relevant
information, either to the entity filing the Exception Request or to the Registered
Entity receiving the Exceptions Request. For example, in order to answer Question 1
on page 4, regarding the impact of the generator under the most severe single
contingency, it may be necessary for the relevant Balancing Authority to provide its
Most Severe Single Contingency (“MSSC”) to the registered entity seeking an
Exception. Similarly, the relevant Transmission Operator or Balancing Authority may

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4

Organization

Yes or No

(CPC)
Consumer's Power Inc. (CPI)
Coos-Curry Electric
Coooperative

Question 4 Comment
have information that is necessary to determine whether the generator has been
designated as reliability-must-run or if it provides ancillary services supporting reliable
operation of the interconnected transmission grid.

Douglas Electric Cooperative
(DEC)
Fall River Electric Cooperative
(FALL)
Kootenai Electric Cooperative
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(Lincoln)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
Snohomish County PUD
Umatilla Electric Cooperative
West Oregon Electric
Cooperative (WOEC)

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Organization

Yes or No

Question 4 Comment

Response: Based on the comments received, the SDT believes that entities will be able to obtain the requisite information necessary
to submit a request. However, should an entity have difficulty, it will need to obtain the assistance of its Regional Entity to secure the
data. If the entity still can’t obtain the needed data, then the SDT fully expects that entity’s Regional Entity to work with them to
come up with a plan that will allow that entity to fill out the request form in a manner that will be acceptable to the Regional Entity so
that processing of the request can continue.
Exelon

Yes

This may be a burden on small entities and generators because they would need to
use contractors to run studies in order to obtain the required data. Smaller entities
and generators may not have the expertise, the software or the necessary personnel
to perform studies.

Response: The SDT recognizes that there will be costs associated with the request. The SDT feels that an entity may have to conduct
a cost and benefit analysis in order to determine the value of pursuing a request.
PSEg Services Corp

Yes

It would depend upon the clarifications to the points raised above.

Response: The SDT suggests that you review the responses to the points raised above and if concerns still exist, please submit those
concerns to the SDT as we proceed to the second phase of this project.
Holland Board of Public Works
Michigan Public Power Agency

Yes

On Page 4 Question 1, information on the host Balancing Authority’s most severe
single contingency may not be publically available and therefore difficult or impossible
for a smaller entity to obtain. Even if the data is available, it may not be meaningful in
a larger Balancing Authority area such as within MISO where the most severe
contingency may be geographically and electrically remote. A more readily available
and meaningful measure would be a comparison of the generator’s capability as a
percent of the peak load for the local Balancing Authority or sub-Balancing Authority,
as applicable.

Response: The SDT believes that an entity can use any data or information available to it in order to make its request, especially if
other information is not available. Note that the SDT modified the form to clarify that entities may submit additional information

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Organization

Yes or No

Question 4 Comment

(beyond the information listed on the form as “required”) to support their request for an exception.
Duke Energy

Yes

What is the process for obtaining data from a 3rd party that is either unregistered or
unwilling to supply the data?

Response: The SDT is not aware of any instance where an unregistered entity would have vital information relevant to a request. For
an organization unwilling to share, the SDT expects that entities may need to execute confidentiality or other agreements in order to
obtain the use of the necessary information and data.
ACES Power Marketing
Standards Collaborators

Yes

Some generation owners may not be able to obtain their BA’s most severe single
Contingency. Many generator owners will not have access to the data necessary to
demonstrate the reliability impact to the BES. This is particularly true for transmission
dependent utilities.

City of St. George

Yes

The access to the required data would be potentially be a concern especially for
smaller entities. Small entities will typically have to outsource the required studies to
consultants and obtaining the data may be difficult for the consultants. The entities
most likely to obtain exemptions (smaller & lower impact entities) are the ones that
probably will have the most difficulty in obtaining the data. Generally larger utilities
“upstream” from the smaller ones are hesitant to give information to other entities.
Depending on the study requirements and criteria for application, this could be a very
costly process.

Dominion

Yes

It has been Dominion’s experience that CEII or Code/Standards of Conduct rules may
restrict generation entities (GO/GOP) from obtaining some of the information
necessary to perform the analysis needed to file the “Detailed Information to Support
an Exception Request”. Dominion is also aware that, in some cases, generation entities
do not have the technical expertise (transmission planning, power flow and or stability
analysis background) to perform such analysis.

Electricity Consumers

Yes

It may be necessary that the exception request form explicitly address this potential

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Organization

Yes or No

Resource Council (ELCON)

Question 4 Comment
problem by allowing the entity seeking an exception to state that for reasons beyond
its control it failed to acquire the necessary data, base case or supporting document to
enable completion of the filing.

ReliabilityFirst

Yes

In some cases, models and even knowledge of the system configurations, operating
protocols and procedures may not be well known by all the entities. System
adjustments, load levels, topologies, maintenance and outage schedules, which
happen daily, will or may be unknown to many entities, including the Regional Entities
who may submit a request to include facilities. For cross regional boundaries, the
problem becomes even larger. That coupled with generation unit owners/operators
not permitted to know transmission information (i.e. Questions 4 and 5); this will put
them at a huge disadvantage to participate in the exception request process.

Southwest Power Pool
Standards Review Team

Yes

SCADA line flow data might be hard to capture for the last two years. Specifically the
line flows may not be available.

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

Yes

It may be hard for a GO to get the information requested in #1 or #4.

TSGT G&T

Yes

It may be hard for a GO to get the information requested in #1 or #4.

Response: Based on the comments received, the SDT believes that entities will be able to obtain the requisite information necessary
to submit a request. However, should an entity have difficulty, it will need to obtain the assistance of its Regional Entity to secure the
data. If the entity still can’t obtain the needed data, then the SDT fully expects that entity’s Regional Entity to work with them to
come up with a plan that will allow that entity to fill out the request form in a manner that will be acceptable to the Regional Entity so
that processing of the request can continue. The SDT expects that entities my need to execute confidentiality type or other
agreements in order to obtain the use of the necessary information and data.
Farmington Electric Utility
System

Yes

See response to question 2

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Organization

Yes or No

Question 4 Comment

Response: Please see response to Q2.
Consumers Energy

Yes

City of Redding Electric Utility

Yes

Response: Without any specific comment, the SDT is unable to respond.

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5.

Are there other specific characteristics that you feel would be important for presenting a case and which are generic enough
that they belong in the request? If so, please identify them here and provide suggested language that could be added to the
document.

Summary Consideration: Based on the responses to this question, the SDT offers the following for summary consideration.
Regarding the FERC seven factor test, an entity requesting an exception can always submit data related to that test for the Regional
Entity and ERO to evaluate.
In response to the suggestions for additional inclusion in the technical criteria document, there are no restrictions on what data can be
submitted in an exception request. An entity requesting an exception can always submit data it believes will be beneficial to its
exception request for the Regional Entity and ERO to evaluate.
Finally, if an entity that is submitting an exception request cannot gain access to certain information that is listed in the technical criteria
document, it should work with its Regional Entity to come up with substitute data that is acceptable. The submitting entity should state
in its exception request submittal that it is unable to access certain data from other parties and explain the reasons why that is the case.
Organization
Northeast Power Coordinating
Council

Yes or No

Question 5 Comment

Yes

There is no guidance provided as to how the information asked for in this form will be
evaluated, and what the decision making process will entail. As such, a reference
document should be developed and provide some guidance how to evaluate
applications.
Suggest that the BES SDT adopt the FERC Seven Factor test.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT
would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would
also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received
very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
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0

Organization

Yes or No

Question 5 Comment

always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package.
When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been
drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and
making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving
or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a position to
effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the
visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity of
the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4,
provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity decides to
reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to NERC.
Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the Regional
Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception request.
On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an acceptable
submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t shown in
the request process. The SDT again points to the variations that will abound in the requests as negating any hard and fast rules in this
regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and
there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take
into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made.
The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on
evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the interconnected
transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system
within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading
failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or unanticipated failure of
system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the experience
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1

Organization

Yes or No

Question 5 Comment

gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent approach to the
problem. The SDT would also point out that there are options for a submitting entity to pursue that are outlined in the proposed ERO
Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2
of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a
question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to
the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of
the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes
that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of
these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable outcome.
Regarding the FERC seven factor test, an entity requesting an exception can always submit data related to that test for the Regional
Entity and ERO to evaluate.
Hydro One Networks Inc.

Yes

The general approach, information, data, and assessments proposed seem to be
reasonable. However, guidance is not provided as to how this information may be
evaluated in the decision making process. As such, a reference document should be
developed and provide guidance how applications will be assessed. For example”1)
Does the element(s)? o Would have qualified under one of the exclusions or
inclusions but have marginally different threshold as prescribed in the definition; o
transfer bulk power within (intra) or between (inter) two Balancing Authority Areas;
o monitor facilities included in an Interconnection Reliability Operating Limit (IROL);
o are not considered necessary for the operation of interconnected transmission

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Organization

Yes or No

Question 5 Comment
system under normal conditions, contingency or prolonged outage conditions.2) Are
System Element(s) located in close electrical proximity to Load? o Electrical
proximity may be a measurement of system impedance between load centers within
the system seeking exception. o Other physical characteristics.3) Are System
Elements treated as primarily radial in character? o Smaller deviation from the
exclusion E1. o This can be demonstrated by the way the connections to the BES are
operated (e.g., the local area is not operated as part of the BES with disconnection
procedures when events occur in the local area to separate it.) o This can also be
demonstrated by the way resources in the local area are treated in operations, for
example, they are not included in a regional dispatch or secured by an ISO/RTO. o
Power flows into the system, but rarely flows out. i. This can be demonstrated
through transactional records or load flow analysis where it is shown that flow out
does not occur or occurs only under a very limited set of conditions and for a limited
quantity of energy. a. The limited set of conditions must clearly state the conditions
where power flows out, for example, only under specified contingency events. b.
Transactional records provided must be for the same time specified in the Exception
Rules of Procedure for performing periodic exception self-certifications (presently two
years). c. Power entering the system is not recognized or regularly transported on
to some other system. (This can be demonstrated by operational procedures that
restrict use of delivered power to that system, e.g., the absence of a wheeling
agreement or an agreement that generally restricts wheeling under normal) d. The
System Element(s) have a very small Distribution Factor on any other BES Element(s).
o System Elements are not necessary for the operation of interconnected transmission
under normal, contingency or prolonged outage conditions.

WECC Staff

Yes

In order to make a determination of BES status of an element, there should be a listing
of effects of the outage on certain facilities, frequencies, voltages, transmission
elements, or other information that should be included in the submittal by the entity.
Without further specification of requirements for presenting a case it is likely that the
Regional Entity will receive inconsistent submittals of data. Leaving open the question
of what constitutes a sufficient presentation of a case would likely lead to a wide

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Organization

Yes or No

Question 5 Comment
spectrum of submittals with respect to the amount of data and level of detail in the
data.

Response: The technical criteria document currently includes a request for information related to an outage of an element on the BES.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like
nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion
and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the
SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out
to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form
of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package.
When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been
drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and
making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving
or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a position to
effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the
visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity of
the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4,
provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity decides to
reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to NERC.
Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the Regional
Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception request.
On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an acceptable
submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t shown in
the request process. The SDT again points to the variations that will abound in the requests as negating any hard and fast rules in this
regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and
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Organization

Yes or No

Question 5 Comment

there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take
into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made.
The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on
evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the interconnected
transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system
within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading
failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or unanticipated failure of
system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the experience
gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent approach to the
problem. The SDT would also point out that there are options for a submitting entity to pursue that are outlined in the proposed ERO
Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2
of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a
question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to
the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of
the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes
that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of
these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable outcome.
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Organization

Yes or No

City of Redding Electric Utility

Yes

Georgia System Operations
Corporation

Yes

Bonneville Power
Administration

Yes

Question 5 Comment

Response: Without specific comments, the SDT is unable to respond.
IRC Standards Review
Committee

Yes

One acid test to determine if a facility needs to be included or can be excluded from a
BES facility is to simulate an uncleared fault at that facility. If the simulation shows a
stable BES performance, then it suggests that even if the fault is not cleared due to
whatever reason, the facility has no adverse impact that can lead to instability,
cascading or collapse of the BES.

Response: There are no restrictions on what data can be submitted in an exception request. Regarding an uncleared fault test, an entity
requesting an exception can always submit data related to that test for the RE and NERC to evaluate.
Snohomish County PUD
Blachly-Lane Electric
Cooperative
Central Electric Cooperative
(CEC)
Clearwater Power Company
(CPC)

Yes

As discussed in our responses to Questions 1 through 3, SNPD believes that certain
additional questions are necessary to elicit all information that may be relevant to an
Exceptions Request. As discussed in our answer to Question 4, we are also concerned
that it may be necessary to obtain information that is in the hands of the relevant
Balancing Authority, Transmission Provider, or other entity, and not in the hands of
the entity submitting an Exceptions Request, to develop a complete record upon
which a reasoned decision concerning an Exceptions Request can be based.

Consumer's Power Inc. (CPI)
Douglas Electric Cooperative
(DEC)

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Organization

Yes or No

Question 5 Comment

Fall River Electric Cooperative
(FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(Lincoln)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
Umatilla Electric Cooperative
West Oregon Electric
Cooperative (WOEC)
Coos-Curry Electric
Coooperative
City of Austin dba Austin
Energy
Kootenai Electric Cooperative
Response: Please see the detailed responses to Q1 – Q4.
Consolidated Edison Co. of NY,
Inc.

Yes

We strongly recommend that the BES SDT adopt the FERC Seven Factor test for local
distribution.

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Organization

Yes or No

Question 5 Comment

Response: There are no restrictions on what data can be submitted in an exception request. Regarding the FERC seven factor test, an
entity requesting an exception can always submit data related to that test for the Regional Entity and ERO to evaluate.
American Electric Power

No

As stated in the response to question #3, it is unclear how the process will work with
the interaction among the various NERC Functions. For instance, an exception request
from generation might require collaboration among other functional entities, i.e. GOP,
TOP, and RC.
The existence of a must run unit means that unit has a material impact on any
configuration of the BES and as such would need a serious waiver to not be considered
a BES facility. As such, a must run unit would not receive an exception. As a result,
should question #3 be removed?
Criteria for applying for an exception should be outlined before filling out the form.

Response: If an entity that is submitting an exception request cannot gain access to certain information that is listed in the technical
criteria document, it should work with its Regional Entity to come up with substitute data that is acceptable. The submitting entity
should state in its exception request submittal that it is unable to access certain data from other parties and explain the reasons why
that is the case.
As stated in the proposed ERO Rules of Procedure, ““No single piece of evidence provided as part of an Exception Request or response
to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”.
Please see the proposed ERO Rules of Procedure for details on filling out a form.
Farmington Electric Utility
System

Yes

The SDT should consider additional limits on Generation. For example, if a generation
prime mover (turbine) has a maximum output of 35 MW but is coupled to a generator
with a rating in excess of 75 MVA. The generator output is limited by the turbine - thus
the rating of the turbine should be a taken into consideration rather than the
generator rating.

Hydro-Quebec TransEnergie

Yes

The general characteristics of the Interconnection (such as frequency or voltage
variation), as they may guide the decision for exclusion of specific elements.

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Organization

Yes or No

Question 5 Comment

Response: Regarding the suggestions for inclusion in the technical criteria document, there are no restrictions on what data can be
submitted in an exception request. An entity requesting an exception can always submit data it believes will be beneficial to its
exception request for the RE and NERC to evaluate. No change made.
Indeck Energy Services

Yes

As acknowledged in the response to Question 12 comments on the previous BES
definition, the BES definition is expansive compared to the definition of the BPS in the
FPA Section 215. The inclusion of the limited Exclusions is an attempt to remedy the
situation. However, the Exclusions need to include a fifth one that if, based on studies
or other assessments, it can be shown that any tranmission or generator element
otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There
has never been a study to show that elements, such as a 20 MW wind farm, 60 MW
merchant generator (which operates infrequently in the depressed market) in a large
BA (eg NYISO) or a radial transmission line connecting a small generator are important
to the reliability of the BPS. They are covered by the mandatory standards program
through the registration criteria. The BES Definition is the opportunity to permit an
entity to demonstrate that an element is unimportant to reliability of the BPS. The
SDT has identified a small subset of elements that it is willing to exclude. By their very
nature, these exclusions dim the bright line that is the stated goal of this project.
However, the SDT’s foresight seems limited in its selections. Analytical studies are
used to evaluate contingencies that could lead to the Big Three (cascading outages,
instability or voltage collapse). Such a study showing that a transmission or
generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable
Disturbance of approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW
merchant generator or numerous other smaller facilities would be bounded by larger
contingencies. It would take more than six 60 MW merchant generators with close
location and common mode failure to even be a Reportable Disturbance, much less
become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 - Any
facility that can be demonstrated to the Regional Entity by analytical study or other

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Organization

Yes or No

Question 5 Comment
assessment to be unimportant to the reliability of the BPS (with periodic reports by
the Regional Entity to NERC of any such assessments).”

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline
of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that
would warrant a change from the current values that exist through the application of the definition today. These and similar issues
have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in
conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and
provide compelling justification for modifications to the existing values.
City of Redding

No

ATC LLC

No

Ameren

No

Central Lincoln

No

National Grid

No

Oncor Electric Delivery
Company LLC

No

Independent Electricity
System Operator

No

City of St. George

No

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0

Organization

Yes or No

PSEg Services Corp

No

ReliabilityFirst

No

Long Island Power Authority

No

Consumers Energy

No

Orange and Rockland Utilities,
Inc.

No

ISO New England Inc

No

Duke Energy

No

NV Energy

No

Central Hudson Gas & Electric
Corporation

No

Exelon

No

Transmission

No

PacifiCorp

No

NERC Staff Technical Review

No

Dominion

No

TSGT G&T

No

Question 5 Comment

All concerns were captured in comments provided to the previous questions.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 5 Comment

Pepco Holdings Inc

No

Southern Company
Generation

No

Tri-State Generation and
Transmission Assn., Inc.
Energy Mangement

No

SERC Planning Standards
Subcommittee

No

ACES Power Marketing
Standards Collaborators

No

Southwest Power Pool
Standards Review Team

No

Tacoma Power

No

Tacoma Power does not know of any characteristics to add at this time.

BGE

No

No comment.

Michigan Public Power Agency

No

Response: Thank you for your support.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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2

6.

Are you aware of any conflicts between the proposed approach and any regulatory function, rule order, tariff, rate schedule,
legislative requirement or agreement, or jurisdictional issue? If so, please identify them here and provide suggested language
changes that may clarify the issue.

Summary Consideration: The majority of commenters responded that they were not aware of any conflicts. However, some
comments were supplied indicating concerns.
Three commenters expressed the need to address the function of an Element or system that is subject to an exception request to
determine whether it is a “facilit[y] used in the local distribution of electric energy” and therefore excluded from the BES under
Section 215(a)(1) of the Federal Power Act. Those commenters have been directed to question 2 for detailed responses on this
issue.
Two commenters submitted concerns that the ERO does not have the authority to apply the BES definition in Canada. The SDT is
attempting to craft a BES definition that can be applied within the ERO footprint. It is neither within the scope of the SDT nor is it
appropriate for the SDT to provide a Canadian regulatory resolution within the definition. As such, the SDT agrees that the ERO
will have to address these types of non-jurisdictional situations with relevant Regions through the exception procedure.
Two commenters expressed a concern that information necessary to perform an analysis may be restricted either by federal/state Codes/Standards of Conduct and/or CEII prohibitions. Based on the comments received, the SDT believes that entities will
be able to obtain the requisite information necessary to submit a request. However, should an entity have difficulty, it will need to
obtain the assistance of its Regional Entity to secure the data. If the entity still can’t obtain the needed data, then the SDT fully
expects that entity’s Regional Entity to work with them to come up with a plan that will allow that entity to fill out the request
form in a manner that will be acceptable to the Regional Entity so that processing of the request can continue.
One comment stated that organized markets have a “must run” generator concept that has nothing to do with reliability. Thus, Q3
for generation facilities might be confused with market tariff provisions. To resolve this concern, the SDT has clarified Q3 for
generation resources as follows:
3. Is the generator generation resource designated as a must run unit for reliability?
Organization

Yes or No

Northeast Power Coordinating

Question 6 Comment

No

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3

Organization

Yes or No

Question 6 Comment

Council
SERC Planning Standards
Subcommittee

No

Southwest Power Pool
Standards Review Team

No

WECC Staff

No

Bonneville Power
Administration

No

TSGT G&T

No

Pepco Holdings Inc

No

Southern Company
Generation

No

Tri-State Generation and
Transmission Assn., Inc.
Energy Mangement

No

NERC Staff Technical Review

No

Transmission

No

PacifiCorp

No

Hydro One Networks Inc.

No

We believe, and support that RoP exception procedures are adequately dealing with

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Question 6 Comment
this issue.

Exelon

No

Duke Energy

No

NV Energy

No

Central Hudson Gas & Electric
Corporation

No

American Electric Power

No

Consumers Energy

No

Orange and Rockland Utilities,
Inc.

No

ISO New England Inc

No

PSEg Services Corp

No

City of St. George

No

Blachly-Lane Electric
Cooperative

No

Central Electric Cooperative
(CEC)

No

AEP is not aware of any conflicts between the proposed approach and any regulatory
function, rule order, tariff, rate schedule, legislative requirement or agreement, or
jurisdictional issue.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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Organization

Yes or No

Clearwater Power Company
(CPC)

No

Consumer's Power Inc. (CPI)

No

Douglas Electric Cooperative
(DEC)

No

Fall River Electric Cooperative
(FALL)

No

Lane Electric Cooperative
(LEC)

No

Independent Electricity
System Operator

No

Lincoln Electric Cooperative
(Lincoln)

No

Northern Lights Inc. (NLI)

No

Okanogan County Electric
Cooperative (OCEC)

No

Pacific Northwest Generating
Cooperative (PNGC)

No

Raft River Rural Electric
Cooperative (RAFT)

No

Question 6 Comment

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6

Organization

Yes or No

Umatilla Electric Cooperative

No

West Oregon Electric
Cooperative (WOEC)

No

Central Lincoln

No

National Grid

No

Oncor Electric Delivery
Company LLC

No

Coos-Curry Electric
Coooperative

No

Ameren

No

Georgia System Operations
Corporation

Yes

ATC LLC

No

Farmington Electric Utility
System

No

City of Redding

No

Tacoma Power

No

Springfield Utility Board

No

Question 6 Comment

Tacoma Power is not aware of any conflicts at this time.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

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7

Organization

Yes or No

BGE

No

Michigan Public Power Agency

No

Long Island Power Authority

Question 6 Comment
No comment.

Not aware of any

Response: Thank you for your response.
Indeck Energy Services

Yes

As acknowledged in the response to Question 12 comments on the previous BES
definition, the BES definition is expansive compared to the definition of the BPS in the
FPA Section 215. The inclusion of the limited Exclusions is an attempt to remedy the
situation. However, the Exclusions need to include a fifth one that if, based on studies
or other assessments, it can be shown that any tranmission or generator element
otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There
has never been a study to show that elements, such as a 20 MW wind farm, 60 MW
merchant generator (which operates infrequently in the depressed market) in a large
BA (eg NYISO) or a radial transmission line connecting a small generator are important
to the reliability of the BPS. They are covered by the mandatory standards program
through the registration criteria. The BES Definition is the opportunity to permit an
entity to demonstrate that an element is unimportant to reliability of the BPS. The
SDT has identified a small subset of elements that it is willing to exclude. By their very
nature, these exclusions dim the bright line that is the stated goal of this project.
However, the SDT’s foresight seems limited in its selections. Analytical studies are
used to evaluate contingencies that could lead to the Big Three (cascading outages,
instability or voltage collapse). Such a study showing that a transmission or
generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable
Disturbance of approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW
merchant generator or numerous other smaller facilities would be bounded by larger
contingencies. It would take more than six 60 MW merchant generators with close

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8

Organization

Yes or No

Question 6 Comment
location and common mode failure to even be a Reportable Disturbance, much less
become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 - Any
facility that can be demonstrated to the Regional Entity by analytical study or other
assessment to be unimportant to the reliability of the BPS (with periodic reports by
the Regional Entity to NERC of any such assessments).”

Response: The SDT has already incorporated a note at the bottom of the definition stating that exceptions can be pursued through
the exception process. The SDT feels that this note is sufficient to address the concerns raised herein. In addition, the SDT reminds
the commenter that all threshold values will be examined in Phase II of this project. No change made.
City of Redding Electric Utility

Yes

Response: Without a specific comment, the SDT is unable to respond.
Hydro-Quebec TransEnergie

Yes

For HQT's system, the proposed BES definition combined with the exception
procedure are presently incompatible or at least inconsistent with the regulatory
framework applicable in Quebec. The proposed changes have not address this
concern, neither the SDT's responses to our previous comments last May (Q.9).We
reiterate that the definition and the exception procedure shall be determined by
Quebec's regulator, the Régie de l'Énergie du Québec, (Quebec Energy Board)
which has the responsibility to ensure that electric power transmission in Quebec is
carried out according to the reliability standards it adopts. Per se, it would be
necessary that E1 and E3 grant exclusions with much higher level of generation. It
would also be necessary to allow for several levels of application for the Reliability
Standards, in accordance with the Régie de l’énergie du Québec approach: the
Bulk Power System (BPS) as determined using an impact-based methodology, the
Main Transmission System (MTS), and other parts of Regional System. Standards
related to the protection system (PRC-004-1 and PRC-005-1) and those related to the
design of the transmission system (TPL 001-0 to TPL-004-0) shall be applicable to the
first level, but all other reliability standards shall be applied to the second level, the
MTS. The MTS definition is somewhat different than the Bulk Electric System

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Organization

Yes or No

Question 6 Comment
definition, and it includes elements that impact the reliability of the grid, supplydemand balance and interchanges.We argue that it would be necessary for NERC to
address the regulatory issues outside ot the present context of the SDT and ROP team.

Manitoba Hydro

Yes

Canadian Entities are not under FERC jurisdiction, so the revised BES Definition may
not apply. A number of Canadian Entities have the BES defined within their provincial
legislation. This may introduce differences and even contradictions between elements
that are included in the BES according to provincial legislation and the NERC definition.

Response: The SDT is attempting to craft a BES definition that can be applied within the ERO footprint. It is neither within the scope
of the SDT nor is it appropriate for the SDT to provide a Canadian regulatory resolution within the definition. As such, the SDT agrees
that the ERO will have to address these types of non-jurisdictional situations with relevant Regions through the exception procedure.
Kootenai Electric Cooperative

Yes

As discussed in more detail in our response to Question 2, KEC believes it is necessary
to address the function of an Element or system that is subject to an Exceptions
Request to determine whether it is a “facilit[y] used in the local distribution of electric
energy” and therefore excluded from the BES under Section 215(a)(1) of the Federal
Power Act.

City of Austin dba Austin
Energy

Yes

As discussed in more detail in our response to Question 2, AE believes it is necessary
to address the function of an Element or system subject to an Exceptions Request to
determine whether it is a “facilit[y] used in the local distribution of electric energy”
and, therefore, excluded from the BES under Section 215(a)(1) of the Federal Power
Act.

Snohomish County PUD

Yes

As discussed in more detail in our response to Question 2, SNPD believes it is
necessary to address the function of an Element or system that is subject to an
Exceptions Request to determine whether it is a “facilit[y] used in the local distribution
of electric energy” and therefore excluded from the BES under Section 215(a)(1) of the
Federal Power Act.

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Organization

Yes or No

Question 6 Comment

Response: Please see response to Q2.
ReliabilityFirst

Yes

Since the inception of the Open Access Transmission Tariff, transmission models and
even knowledge of the systems, operating protocols and procedures may not be well
known or known at all by all the entities. System adjustments, load levels, topologies,
maintenance and outage schedules (i.e. market sensitive information), which happens
daily is not permitted to be known by the generation side of the industry. An unknown
at this point and without a common set of criteria to be used by the Regional Entities
and NERC Staff and Panels, it will be difficult to make consistent determinations across
the ERO Enterprise.

Dominion

Yes

Much of the information necessary to perform the analysis required is restricted
either by federal and/or state Codes/Standards of Conduct and/or CEII prohibitions.

Response: Please see response to Q4.
ACES Power Marketing
Standards Collaborators

Yes

Some organized markets have a must run concept that has nothing to do with
reliability. Thus, Q3 for generation facilities might be confused with these tariff
provisions.

Response: To resolve this concern, the SDT has clarified question 3 for generation resources to read:
3. Is the generator generation resource designated as a must run unit for reliability?

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7.

Are there any other concerns with the proposed approach for demonstrating BES Exceptions that haven’t been covered in
previous questions and comments (bearing in mind that the definition itself and the proposed Rules of Procedure changes are
posted separately for comments)? Please be as specific as possible with your comments.

Summary Consideration: Based on the responses to this question, the SDT offers the following for summary consideration.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria
and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to
say that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with
this position. The exception application form has to be taken in concert with the changes to the ERO Rules of Procedure and
looked at as a single package. When one looks at the rules being formulated for the exception process, it becomes clear that the
role of the Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of
reviewing the submittal for completion and making a recommendation to the ERO panel, not to make the final determination. The
Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter
that this places the Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to
be supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and
also believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the
proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent
Technical Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s
findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure,
Section 7.0, provides NERC the option to remand the application to the Regional Entity with the mandate to process the exception
if it finds the Regional Entity erred in rejecting or disapproving the exception request. On the other side of this equation, one
could make an argument that the Regional Entity has no basis for what constitutes an acceptable submittal. Commenters point
out that the explicit types of studies to be provided and how to interpret the information aren’t shown in the application process.
The SDT again points to the variations that will abound in the applications as negating any hard and fast rules in this regard.
However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there
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is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the application details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to
be supplied for the submittal to travel upward to the ERO panel for adjudication.
In addition, the SDT would point to the SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in
a favorable outcome.
NERC and the industry cannot wait until Phase 2 for the development of the exception process as it is an Order No. 743 directive
that must be addressed by the FERC established deadline of January 25, 2012.
If an entity that is submitting an exception request cannot gain access to certain information that is listed in the technical criteria
document, it should work with its Regional Entity to come up with substitute data that is acceptable. In addition, the submitting
entity should state in its exception request submittal that it is unable to access certain data from other parties and explain the
reasons why that is the case.
Organization

Yes or No

LG&E and KU Energy

Yes

Question 7 Comment
LG&E and KU Energy request clarification as to how the two year data requirement
would apply to a new facility for which the owner/operator requests an exemption.

Response: The SDT recommends that a submitting entity work with its Regional Entity to determine how best to handle this type of a
situation.
Tacoma Power

Yes

Tacoma Power has a concern that the form may be too general in nature. The task
before NERC and the industry is to promote consistency in the application of the BES
definition. The form will require the regions to develop individual criteria for assessing
an exception request and making a recommendation on the request. We recommend
in Phase 2 that the SDT develop specific evaluation criteria for the regions to apply to

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Organization

Yes or No

Question 7 Comment
an exception request. Thank you for consideration of our comments.

City of Redding
City of Redding Electric Utility

Yes

Redding acknowledges there is an immediate need for a method where an entity can
present evidence that their facilities are “not necessary for the Reliable Operation of
the interconnected bulk power transmission system” as stated in the NERC Rules of
Procedure Section 3.0. “BASIS FOR APPROVAL OF AN EXCEPTION.” Without a process
to present the evidence then the RE and the ERO are under no mandate to review
facilities in light of any criteria besides the BES definition as NERC clearly pointed out
in the City of Holland case where Holland was forced to register by the RE (RFC).
However, Redding is very concerned that under the proposed Exception process the
final evaluation of an element or facility is left to the sole judgment of NERC. The
concern is there is no method, criteria, measurement, or standard that NERC will use
for the evaluation. It is also a concern that NERC has a predetermined definition of
Distribution Facilities and will not evaluate networked Distribution Facilities fairly.
NERC has already stated their predetermined position as to what they determine to be
distribution and not distribution facilities in their “MOTION TO INTERVENE AND
COMMENTS OF THE NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION” filed in
the case of the City of Holland, Michigan (Docket No. RC11-5-000). On page 10 and 11
of this motion, under the section labeled “A. Holland’s 138 kV lines are transmission
rather that local distribution facilities” NERC states “Distribution facilities generally are
characterized as elements that are designed and can carry electric energy (Watts/MW)
in one direction only at any given time from a single source point (distribution
substation) to final load centers.” NERC has clearly stated that only radial facilities are
considered distribution facilities and were unwilling to consider that network facilities
over 100Kv could be classified as Distribution Facilities in this case. Holland’s claim of
NERC over-reaching their authority appears to have credibility. In conclusion, Redding
supports the proposed exception process as it stands on the grounds that it allows an
entity the right to a process which NERC is currently not obligated to allow, it requires
that NERC judge the facilities on the merit of “necessary for the Reliable Operation of
the interconnected bulk power transmission system”, and it allows an appeals process
that must judge if NERC evaluated facilities on the standard set forth. However,

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Organization

Yes or No

Question 7 Comment
Redding’s vote is conditional on the completion of phase 2 where the term “necessary
for the Reliable Operation of the interconnected bulk power transmission system”
needs to be defined.

Independent Electricity
System Operator

Yes

We believe that the SDT proposed approach for exception criteria is reasonable
recognizing that one method/criteria cannot be applicable to everyone and every
situation within the ERO foot print. However, we believe that there is huge gap and
lack of any transparency on how the exception application will be evaluated and
processed. We strongly suggest that SDT develop a reference or a guidance document
as part of the RoP that should provide some guidance to Registered Entities, Regional
Entities and the ERO on how an exception application should be processed. The
absence of such guidance will pose a challenge for each entity including the ERO, and
may result in discrepancies amongst Regional Entities. The process may be perceived
by registered entities as being non-transparency.

City of St. George

Yes

Clear, concise criteria with consistent repeatable results are a must for a successful
outcome of the project effort. The included questions are appropriate questions but
the use of those questions and the ultimate outcome is unclear with the current
version. The background information indicates that continent wide criteria are not
feasible. It is understood that this is a very difficult task and will be difficult to achieve
(especially in the time allotted). However, if the decisions are left up to a “panel” to
decide the results will be inconsistent and will vary region by region, as well as differ
over time. The process involved will be very time consuming (i.e. expensive) and will
be difficult to control especially during the initial timeframe. History has
demonstrated that review and approval processes that pass from the entity to the
regions, then to NERC and then on to FERC backup very easily due to limited staff and
resources.The drafting team may want to consider moving this topic to Phase 2 of the
project. However, Phase 2 needs to have fairly quick time frame in order to provide
the needed direction to the industry in a timely manner.

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Organization

Yes or No

Question 7 Comment

PSEg Services Corp

Yes

An applicant should be able to clearly tell whether or not an exception request will
likely be granted before it is submitted. It is nearly impossible to divine the whether a
request will be granted from a set of data questions. The team is urged to state the
exclusion criteria explicitly; data questions required to evaluate a request should
directly reference each criterion. See Order 743, paragraph 115: “NERC should
develop an exemption process that includes clear, objective, transparent, and
uniformly applicable criteria for exemption of facilities that are not necessary for
operating the grid.”

ISO New England Inc

Yes

Given all of these decisional inputs requested by the Exception Application there
needs to be some guidance or clarification here regarding the criteria that will be used
to render a yes or no decision other than simply filling out the Application and
allowing the Rules of Procedure process to take place. The Application process for
Exceptions (inclusions or exclusions) appears to be subjective and lacks the decisional
technical criteria for the applicant to be confident of the outcome.

Manitoba Hydro

Yes

Manitoba Hydro strongly disagrees with the proposed ‘Detailed Information to
Support an Exception Request’ document and associated exception process for the
following reasons: -It is not clear what elements or situations beyond what is covered
in the core definition and associated inclusions and exclusions that the drafting team
is hoping to capture through the exception process. Further, it is unclear what the
benefit to reliability would be by allowing an impact based exception process given
that entities will be extremely unlikely to use the exception process to include
elements in the BES. -The exception process will be extremely resource intensive,
particularly in the absence of any Industry approved threshold criteria. The costs to
properly administer and monitor the process to ensure that impact based modeling is
done accurately and that it captures the frequent changes on a dynamic system will
occupy a wealth of Industry, NERC and Regional Entity time to the detriment of
reliability.-It is not reasonable for industry to approve the exception process without
knowing what thresholds are required to demonstrate an element as being part of the

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Organization

Yes or No

Question 7 Comment
BES or not. We are concerned that BES determinations would be subjective and would
vary from case to case with the particular staff examining the request. BES elements
should be established and agreed upon by Industry, not set by a NERC panel. We
understand that the drafting team has made this change in the interests of time, but
the impact of the BES definition is too broad for this project to be rushed. -The
2010-17 project goals to increase the clarity of the BES definition and establish a
‘bright-line’ are compromised by the exception process. Changes and alterations to
the BES definition should be approved by Industry through the Standards Under
Development Process. An interpretation request or SAR should be developed by an
entity if they feel that the core definition and associated exceptions and inclusions
should be modified. We ask that NERC requests that FERC re-examines the directive to
develop an exception process given that the BES definition, which already includes a
list of exceptions, is sufficient to standalone without an associated exception process.

ReliabilityFirst

Yes

FERC Order 743-A, paragraph 1, discusses that NERC should “...establish an exemption
process and criteria for excluding facilities that are not necessary for operating the
interconnected transmission network”. It also directed in paragraph 4 that “Order No.
743 also directed the ERO to develop an exemption process that includes clear,
objective, transparent and uniformly applicable criteria for exempting facilities that
are not necessary for operating the interconnected transmission grid.” The SDT
proposed a set of questions titled “Detailed Information to Support an Exception
Request” to assist in the exemption process but in our mind is not “exception criteria”
as stated in the FERC Orders. ReliabilityFirst Staff believes that NERC should develop
criteria for which facilities or Elements could be exempted from the core definition; an
example being Local Networks as outlined in the current draft of the definition.
ReliabilityFirst Staff believes the Local Network exclusion is not “bright line” and could
be removed from the core definition and used as criteria for exclusion in the
exemption process. Item b of the LN (E3) exclusion would need evidence to support
the historical and future power flows. Historical data and future power flow study
results would be needed to support this exception. Additionally, another example for
exemption criterion for inclusion to the BES could be any 69 kV network facilities that

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Organization

Yes or No

Question 7 Comment
provide a parallel path to the BES. Evidence such as one-line diagrams along with
power flow studies would need to be provided through the exemption process for
these types of facilities to be included in the BES. ReliabilityFirst Staff believes that any
BES facilities should not be candidates for exemption based upon the arbitrary
determination of a panel that considers the aspects stated in the document “Detailed
Information to Support an Exception Request”. Without uniform criteria as stated in
the FERC Orders, it will be difficult for the panels to make consistent determinations
across the ERO Enterprise.

Hydro One Networks Inc.

Yes

As mentioned above, we strongly suggest and encourage that SDT to develop a
reference or a guidance document that will provide guidance to Registered Entities,
Regional Entities and the ERO on how an exception application should/would be
processed.

Arizona Public Service
Company

Yes

In accordance with WECC’s position paper issued on October 5, 2011, AZPS agrees
with WECC in that the proposed Technical Principles for Demonstrating BES Exceptions
Request does not provide the necessary clarity as to what applying entities must
provide to support their request, nor does it provide any criteria for consistency
among regions in their assessment of requests.

SRP

Yes

SRP agrees with WECC Staff comments.

WECC Staff

Yes

WECC is very concerned that there are no specific qualifications or requirements,
either for the entities or for the Regional Entity, with respect to: o the determination
of which studies need to be conducted; o the format of the study data that should be
submitted; or o the key performance measures that should be evaluated. This
vagueness will lead to inconsistency in studies run, data submitted, and measures of
data evaluation. If this inconsistency occurs, it will result in a potentially subjective and
discordant process on multiple levels for both the submitting entities and the Regional
Entities. It may result in submitting entity having to run multiple studies in order to
determine what will be acceptable proof, which is overly burdensome on both the

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Organization

Yes or No

Question 7 Comment
submitting entity requesting the exception and the Regional Entity reviewing the
request. It also makes the consistency that FERC has requested difficult to assess and
achieve. If the goal of the exceptions process is to result in consistent determinations
across the regions, then WECC recommends that to the extent possible, the process
be objective, clear, and include detailed instructions. The development of such an
objective and detailed process is a difficult task and will require additional time. WECC
believes it is better to not have an exceptions process in the interim period than to
have an inefficient and overly burdensome process in place. To allow adequate time to
complete the task of developing a detailed and consistent process WECC recommends
that the Detailed Information to Support BES Exceptions Request be included in Phase
II of the BES definition project.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT
would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would
also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received
very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package.
When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been
drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and
making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving
or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a position to
effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the
visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity of
the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4,
provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity decides to
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Organization

Yes or No

Question 7 Comment

reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to NERC.
Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the Regional
Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception request.
On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an acceptable
submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t shown in
the request process. The SDT again points to the variations that will abound in the requests as negating any hard and fast rules in this
regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and
there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take
into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made.
The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on
evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the interconnected
transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system
within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading
failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or unanticipated failure of
system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the experience
gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent approach to the
problem. The SDT would also point out that there are options for a submitting entity to pursue that are outlined in the proposed ERO
Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2
of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a
question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
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Organization

Yes or No

Question 7 Comment

Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to
the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of
the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes
that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of
these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable outcome.
In addition, NERC and the industry cannot wait until Phase 2 for the development of the exception process as it is an Order No. 743
directive that must be addressed by the FERC established deadline of January 25, 2012.
Dominion

Yes

The Detailed Information to Support an Exception Request form has 2 sections; one
for transmission facilities and another for generation facilities. Yet, the Project 201017 Definition of Bulk Electric System document uses other terms such as real and
reactive power resources, dispersed power producing resources, static or dynamic
devices, blackstart resources, radial systems, local networks (LN), and reactive power
devices. Dominion suggests that the Detailed Information to Support an Exception
Request form be revised to conform to the Project 2010-17 Definition of Bulk Electric
System document through either use of some sort of ‘selection’ (checkbox, drop
down, write in) or revision of transmission facilities and generation facilities to be
more inclusive.

Response: The SDT is only determining the content of the technical criteria document. NERC will be responsible for addressing the
format and user features of the final technical criteria document.
TSGT G&T

Yes

Tri-State Generation and
Transmission Assn., Inc.
Energy Mangement

TSGT believes that the proposed “Technical Principles for Demonstrating BES
Exceptions Request” does not clearly define the basis for decisions to exclude or
include, which will lead to inconsistent application by the Regions. We believe that the
checklist items for transmission and generation facilities are appropriate questions
that must be answered in considering all requests. However, without objective criteria
defining how to assess the materials submitted, the current methodology leaves it to

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Organization

Yes or No

Question 7 Comment
each region to develop their own methodology and criteria for evaluating the
submittals. We believe the lack of clarity regarding what studies must be submitted
and what must be demonstrated by the studies submitted will be overly burdensome
on the submitting entity and the Region, as multiple studies may be required for the
two to agree that there is sufficient justification for an exemption request. We believe
that additional work is necessary to develop clear, objective methods and criteria for
identifying which facilities may be excluded from or should be included in the Bulk
Electric System. Clear, objective methods and criteria will enable the submitter of
requests to understand what is necessary for submitting an exception request and will
provide for consistency among the regions in their initial assessment and
recommendations to the ERO.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT
would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would
also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received
very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package.
When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been
drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and
making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving
or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a position to
effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the
visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity of
the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4,
provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity decides to
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Question 7 Comment

reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to NERC.
Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the Regional
Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception request.
On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an acceptable
submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t shown in
the request process. The SDT again points to the variations that will abound in the requests as negating any hard and fast rules in this
regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and
there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take
into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made.
The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on
evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the interconnected
transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system
within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading
failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or unanticipated failure of
system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the experience
gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent approach to the
problem. The SDT would also point out that there are options for a submitting entity to pursue that are outlined in the proposed ERO
Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2
of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a
question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
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Question 7 Comment

Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to
the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of
the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes
that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of
these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable outcome.
NERC Staff Technical Review

Yes

At a minimum, we believe there are some facilities which should not be excluded from
the BES under any circumstances and a list of such facilities should be documented,
including facilities such as (1) Elements that are relied on in the determination of an
Interconnection Reliability Operating Limit (IROL); (2) Blackstart resources and the
designated blackstart Cranking Paths identified in the Transmission Operator’s
restoration plan regardless of voltage, (3) Elements subject to Nuclear Plant Interface
Requirements (NPIRs) as agreed to by a Nuclear Plant Generator Operator and a
Transmission Entity defined in NUC-001, (4) Elements identified as required to comply
with a NERC Reliability Standard by application of criteria defined within the standard
(e.g., the test defined in PRC-023 to identify sub-200 kV Elements to which the
standard is applicable), and (5) a generating unit that is designated as a must run unit
to assure reliability of the BES.
Also, to make the process of reviewing exception applications consistent and
transparent some high level guidance should be developed as to how the information
provided will be assessed by the Regional Entities and NERC. In addition to supporting
the objectives of consistency and transparency, this also would provide benefit to
entities submitting an exception application by allowing them to understand how the
Required Information will be evaluated.

Response: The SDT notes that all BES definition exception requests are considered unique and will be handled on a case-by-case basis.
In addition, there is no prohibition on what facilities can be included in an exception request. To say that an Element(s) can be
automatically excluded or included on a continent-wide basis is contrary to the SDT’s intent. While most of the items noted do reside
on the exception request form, the SDT reminds the commenter that the proposed ERO Rules of Procedure state that “No single piece
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Question 7 Comment

of evidence provided as part of an Exception Request or response to a question will be solely dispositive in the determination of
whether an Exception Request shall be approved or disapproved.”
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like
nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion
and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the
SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out
to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form
of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single package.
When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity has been
drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for completion and
making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in actually approving
or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a position to
effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the
visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity of
the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4,
provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity decides to
reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to NERC.
Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the Regional
Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception request.
On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an acceptable
submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t shown in
the request process. The SDT again points to the variations that will abound in the requests as negating any hard and fast rules in this
regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and
there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
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Question 7 Comment

supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take
into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made.
The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on
evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the interconnected
transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power system
within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading
failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or unanticipated failure of
system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the experience
gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent approach to the
problem. The SDT would also point out that there are options for a submitting entity to pursue that are outlined in the proposed ERO
Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2
of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a
question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.

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Yes or No

Michigan Public Power Agency

Yes

Question 7 Comment
The following revisions should be made to the procedures: 1. The Technical Review
Panel (TRP) provided for in Section 5.3 should not include any staff from the host
Regional Entity.
2. The Regional Entity should be required to include an attestation of a qualified
individual or individuals to support the factual and technical bases for the decision.
This is necessary for purposes of establishing a record in the event of an appeal. If a
dispute is appealed, there must be someone at the Regional Entity level that serves as
the witness supporting the Regional Entity decision. Currently, there is no
accountability for the arguments and suppositions put forth by the Regional Entity; no
individuals that stand behind the technical bases proffered in the Regional Entity’s
written decision. Requiring a qualified individual to attest to the facts and technical
arguments relied upon in arriving at the decision will ensure that someone at the
Regional Entity level is prepared to take responsibility for reviewing a decision before
it is issued, to stand behind the assertions and conclusions reached by the Regional
Entity, and whom the Submitting Party may cross examine at hearing.
3. A party seeking an exception should have the right to request a hearing and should
not be limited to a paper process.
4. The procedures should not permit the TRP or the Regional Entity to make a decision
based upon information that is outside of the record placed before it. That is, the TRP
and the Regional Entity may not, on their own, conduct an investigation or seek
information independently from what has been presented to it. If the TRP or the
Regional Entity requires additional information, it must be requested and provided
transparently, and the Submitting Party must have an opportunity to comment upon
or challenge that information before the TRP or the Regional Entity relies upon it in
any way. This is not currently happening at the Regional Entity and NERC level decisions have been made based upon documents and information that are not part
of the record; the information is not shared with the Submitting Party (the party
challenging registration) prior to (or after) a decision is made.

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Question 7 Comment
5. Section 5.2.2. should be revised as follows: “Upon Acceptance of the Exception
Request, the Regional Entity and Submitting Party (and Owner, if different) shall
confer to establish milestones in order to complete the substantive review of the
Exception Request within six months after Acceptance of the Exception Request or
within an alternative time period under Section 5.0. The Regional Entity and the
Submitting Party (and Owner, if different) shall also discuss whether and to what
extent a reduced compliance burden is appropriate during the review period. At the
conclusion of the review period, the Regional Entity shall issue a notice (in accordance
with Sections 5.2.3) stating is Recommendation that the Exception Request be
approved or disapproved.”

Holland Board of Public Works

Yes

The following revisions should be made to the procedures: 1. The Technical Review
Panel (TRP) provided for in Section 5.3 should not include any staff from the host
Regional Entity.
2. The Regional Entity should be required to include an attestation of a qualified
individual or individuals to support the factual and technical bases for the decision.
This is necessary for purposes of establishing a record in the event of an appeal. If a
dispute is appealed, there must be someone at the Regional Entity level that serves as
the witness supporting the Regional Entity decision. Currently, there is no
accountability for the arguments and suppositions put forth by the Regional Entity; no
individuals that stand behind the technical bases proffered in the Regional Entity’s
written decision. Requiring a qualified individual to attest to the facts and technical
arguments relied upon in arriving at the decision will ensure that someone at the
Regional Entity level is prepared to take responsibility for reviewing a decision before
it is issued, to stand behind the assertions and conclusions reached by the Regional
Entity, and whom the Submitting Party may cross examine at hearing.
3. A party seeking an exception should have the right to request a hearing and should
not be limited to a paper process.
4. The procedures should not permit the TRP or the Regional Entity to make a decision

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Question 7 Comment
based upon information that is outside of the record placed before it. That is, the TRP
and the Regional Entity may not, on their own, conduct an investigation or seek
information independently from what has been presented to it. If the TRP or the
Regional Entity requires additional information, it must be requested and provided
transparently, and the Submitting Party must have an opportunity to comment upon
or challenge that information before the TRP or the Regional Entity relies upon it in
any way. This is not currently happening at the Regional Entity and NERC level decisions have been made based upon documents and information that are not part
of the record; the information is not shared with the Submitting Party (the party
challenging registration) prior to (or after) a decision is made.
5. Section 5.2.2. should be revised as follows: “Upon Acceptance of the Exception
Request, the Regional Entity and Submitting Party (and Owner, if different) shall
confer to establish milestones in order to complete the substantive review of the
Exception Request within six months after Acceptance of the Exception Request or
within an alternative time period under Section 5.0. The Regional Entity and the
Submitting Party (and Owner, if different) shall also discuss whether and to what
extent a reduced compliance burden is appropriate during the review period. At the
conclusion of the review period, the Regional Entity shall issue a notice (in accordance
with Sections 5.2.3) stating is Recommendation that the Exception Request be
approved or disapproved.”

Response: Your comments are not focused on the technical criteria document and they have been forwarded to the BES ROP team for
consideration in their separate process.
Central Hudson Gas & Electric
Corporation

Yes

The ‘Technical Principles for Demonstrating BES Exceptions’ process was intended to
establish technical exception ‘criteria’ which would be used by the industry to
understand what facilities would qualify for inclusions and exclusions from the BES.
What has been produced, however, is essentially a listing of ‘electrical system
indicators’, identified on the form, which may be material to making a decision
regarding, ‘is it BES or not’. The thresholds (or acceptable values) for the indicators,

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Question 7 Comment
however, have not been determined. It is understood that in Phase II of the BES
Definition development process, the SDT will attempt to address these issues but until
that work has been completed, the industry will remain enmeshed in confusion and
inefficient application of resources and funding. Without these criteria, it is very
difficult to believe that this process can be transparent and consistent. Re: Question 4.
(For Transmission Facilities)For the purposes of responding to this question, what
constitutes the BES? It would seem that you must exclude the elements you are
seeking exceptions for or else the exception request is rendered essentially worthless.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT
would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would
also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received
very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception application form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single
package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity
has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for
completion and making a recommendation to the ERO panel, not to make the final determination. The Regional Entity plays no role in
actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a
position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that
the visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity
of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and
5.2.4, provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity decides
to reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to NERC.
Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the application to the Regional
Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception request.
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Question 7 Comment

On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an acceptable
submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t shown in
the application process. The SDT again points to the variations that will abound in the applications as negating any hard and fast rules in
this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and
there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having
viewed the application details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO panel for adjudication.
Finally, the SDT would point to the SAR for Phase II of this project that calls for a review of the process after 12 months of experience.
The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process
based on actual real-world experience and not just on suppositions of what may occur in the future. Given the complexity of the
technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this project, the SDT believes that it
has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to consider all of these
facts in making your decision and casting your ballot and hopes that these changes will result in a favorable outcome.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects (i.e.,
the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being responsive
to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not
afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a change from the current
values that exist through the application of the definition today. These and similar issues have prompted the SDT to separate the project
into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT
will consider all recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17
Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop
analyses which will properly assess the threshold values and provide compelling justification for modifications to the existing values.
National Grid

Yes

We are assuming that "yes" answers on this checklist are not intended to result in
automatic rejection of the application. We think the procedure would benefit from a
general statement noting that all answers taken together will be considered to make
clear that no single answer will necessarily be dispositive of the outcome.

Response: Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception application form will
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Question 7 Comment

mandate a negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
disapproved.”
Indeck Energy Services

Yes

As acknowledged in the response to Question 12 comments on the previous BES
definition, the BES definition is expansive compared to the definition of the BPS in the
FPA Section 215. The inclusion of the limited Exclusions is an attempt to remedy the
situation. However, the Exclusions need to include a fifth one that if, based on studies
or other assessments, it can be shown that any tranmission or generator element
otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There
has never been a study to show that elements, such as a 20 MW wind farm, 60 MW
merchant generator (which operates infrequently in the depressed market) in a large
BA (eg NYISO) or a radial transmission line connecting a small generator are important
to the reliability of the BPS. They are covered by the mandatory standards program
through the registration criteria. The BES Definition is the opportunity to permit an
entity to demonstrate that an element is unimportant to reliability of the BPS. The
SDT has identified a small subset of elements that it is willing to exclude. By their very
nature, these exclusions dim the bright line that is the stated goal of this project.
However, the SDT’s foresight seems limited in its selections. Analytical studies are
used to evaluate contingencies that could lead to the Big Three (cascading outages,
instability or voltage collapse). Such a study showing that a transmission or
generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable
Disturbance of approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW
merchant generator or numerous other smaller facilities would be bounded by larger
contingencies. It would take more than six 60 MW merchant generators with close
location and common mode failure to even be a Reportable Disturbance, much less
become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 - Any
facility that can be demonstrated to the Regional Entity by analytical study or other

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Question 7 Comment
assessment to be unimportant to the reliability of the BPS (with periodic reports by
the Regional Entity to NERC of any such assessments).”

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline
of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that
would warrant a change from the current values that exist through the application of the definition today. These and similar issues
have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in
conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and
provide compelling justification for modifications to the existing values.
American Electric Power

No

AEP agrees with the overall approach demonstrated by the exception request form;
however, its appropriateness will be largely dependent on the process eventually used
for its implementation.AEP would like guidance on how moth-balled generation
should be treated. Perhaps this could be added to the exception form as well.

Response: The SDT is not able to respond to specific requests related to potential future exception requests. Please use the BES
definition and the exception request form, after its approval by the NERC Board of Trustees and FERC, for such a request. Also, please
consider working with your Regional Entity to determine how moth-balled facilities should be treated.
Snohomish County PUD
Blachly-Lane Electric
Cooperative
Central Electric Cooperative
(CEC)
Clearwater Power Company

No

As a general matter, SNPD believes the SDT has provided a reasonable check list that
will work in most cases to elicit necessary information from the entity submitting an
Exception Request. With the added language suggested in our answers to the
previous questions, we believe the proposed form will serve its intended purpose of
ensuring that decisions regarding Exception Requests are based upon consistent
information and are consistent with the requirements of the Federal Power Act and
the BES Definition as developed by the Standards Drafting Team. SNPD also supports
the Standards Drafting Team’s determination to abandon its initial approach to

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(CPC)
Consumer's Power Inc. (CPI)
Douglas Electric Cooperative
(DEC)
Fall River Electric Cooperative
(FALL)

Question 7 Comment
technical criteria, which would have required adherence to specific numerical
thresholds. SNPD agrees that this approach was not workable on a nationwide basis,
and that the approach embodied in the current draft of the Technical Principles, which
would require specific kinds of information on a generic basis but would leave
engineering judgment about the significance of that information to the relevant RE, is
more workable and provides appropriate deference to the experience and judgment
of the REs.

Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(Lincoln)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
Umatilla Electric Cooperative
West Oregon Electric
Cooperative (WOEC)
Coos-Curry Electric
Coooperative
City of Austin dba Austin
Energy

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

16
4

Organization

Yes or No

Question 7 Comment

Kootenai Electric Cooperative
BGE

No

Farmington Electric Utility
System

No

ATC LLC

No

Ameren

No

Georgia System Operations
Corporation

No

Oncor Electric Delivery
Company LLC

No

Central Lincoln

No

Long Island Power Authority

No

Consumers Energy

No

Orange and Rockland Utilities,
Inc.

No

Duke Energy

No

NV Energy

No

Exelon

No

No comment.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

16
5

Organization

Yes or No

Transmission

No

PacifiCorp

No

Pepco Holdings Inc

No

Southern Company
Generation

No

Bonneville Power
Administration

No

Southwest Power Pool
Standards Review Team

No

ACES Power Marketing
Standards Collaborators

No

Northeast Power Coordinating
Council

No

SERC Planning Standards
Subcommittee

No

Question 7 Comment

Response: Thank you for your support.

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

16
6

END OF REPORT

Consideration of Comments: Definition of the Bulk Electric System (BES) Exception Criteria

16
7

Project 2010-17 Definition of Bulk Electric System

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.

Development Steps Completed
1. SAR posted for comment 12/17/10 – 1/21/11
2. SC authorized moving the SAR forward to standard development 3/25/11
3. First posting of definition 4/28/11 – 5/27/11
4. First posting of criteria 5/11/11 – 6/10/11

Description of Current Draft
This draft is the second posting of the revised definition of the Bulk Electric System (BES). It is
for a 45-day formal comment and parallel voting period.

Anticipated Actions

Anticipated Date

45-day Formal Comment Period with Parallel Initial Ballot

8/26/11 – 10/10/11

Recirculation ballot

December 2011

BOT adoption

January 2011

Dra ft #2: Au g u s t 24, 2011

Page 1 of 4

Project 2010-17 Definition of Bulk Electric System

Effective Dates
This definition shall become effective on the first day of the second calendar quarter after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
the definition will go into effect on the first day of the second calendar quarter after Board of
Trustees adoption. Compliance obligations for Elements included by the definition shall begin
24 months after the applicable effective date of the definition.

Version History

Version
1

Date
TBD

Dra ft #2: Au g u s t 24, 2011

Action

Change
Tracking

Respond to FERC Order No. 743 to
N/A
clarify the definition of the Bulk Electric
System

Page 2 of 4

Project 2010-17 Definition of Bulk Electric System

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission
Elements operated at 100 kV or higher and Real Power and Reactive Power resources connected
at 100 kV or higher. This does not include facilities used in the local distribution of electric
energy.
Inclusions:
•
•

•
•

•

I1 - Transformers with primary and secondary terminals operated at 100 kV or higher
unless excluded under Exclusion E1 or E3.
I2 - Generating resource(s) (with gross individual or gross aggregate nameplate rating per
the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or
above.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily for aggregating
capacity, connected at a common point at a voltage of 100 kV or above.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that
are connected at 100 kV or higher, or through a dedicated transformer with a high-side
voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.

Exclusions:
•

•

E1 - Radial systems: A group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusion I3, with an
aggregate capacity less than or equal to 75 MVA (gross nameplate rating).
Or,
c) Where the radial system serves Load and includes generation resources,
not identified in Inclusion I3, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted
on prints or one-line diagrams for example, does not affect this exclusion.
E2 - A generating unit or multiple generating units that serve all or part of retail customer
Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity

Dra ft #2: Au g u s t 24, 2011

Page 3 of 4

Project 2010-17 Definition of Bulk Electric System

•

•

provided to the BES does not exceed75 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating
units or to the retail Load by a Balancing Authority, or provided pursuant to a binding
obligation with a Generator Owner or Generator Operator, or under terms approved by
the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at or
above 100 kV but less than 300 kV that distribute power to Load rather than transfer bulk
power across the interconnected system. LN’s emanate from multiple points of
connection at 100 kV or higher to improve the level of service to retail customer Load
and not to accommodate bulk power transfer across the interconnected system. The LN is
characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do
not include generation resources identified in Inclusion I3 and do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating) ;
b) Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain a
monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection,
or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices owned and operated by the retail customer solely for its
own use.

Note - Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.

Dra ft #2: Au g u s t 24, 2011

Page 4 of 4

Project 2010-17 Definition of Bulk Electric System

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.

Development Steps Completed
1. SAR posted for comment 12/17/10 – 1/21/11
2. SC authorized moving the SAR forward to standard development 3/25/11
3. First posting of definition 4/28/11 – 5/27/11
3.4.First posting of criteria 5/11/11 – 6/10/11

Description of Current Draft
This draft is the firstsecond posting of the revised definition of the Bulk Electric System (BES).
It is for a 3045-day formal comment and parallel voting period.

Anticipated Actions

Anticipated Date

30-day Formal Comment Period

4/28/11

45-day Formal Comment Period with Parallel Initial Ballot

8/2326/11 –
10/10/11

Recirculation ballot

12/9/11December
2011

BOT adoption

12/30/11January
2011

Dra ft #2: Da te Au g u s t 24, 2011

Page 1 of 5

Project 2010-17 Definition of Bulk Electric System

Effective Dates
This definition shall become effective on the first day of the firstsecond calendar quarter, 24
months after applicable regulatory approval. In those jurisdictions where no regulatory approval
is required, all requirements the definition will go into effect on the first day of the firstsecond
calendar quarter, 24 months after Board of Trustees adoption. Compliance obligations for
Elements included by the definition shall begin 24 months after the applicable effective date of
the definition.

Version History

Version
1

Date
TBD

Dra ft #2: Da te Au g u s t 24, 2011

Action

Change
Tracking

Respond to FERC Order No. 743 to
N/A
clarify the definition of the Bulk Electric
System

Page 2 of 5

Project 2010-17 Definition of Bulk Electric System

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, Aall Transmission
Elements operated at 100 kV or higher, and Real Power and Reactive Power resources as
described below, and Reactive Power resources connected at 100 kV or higher unless such
designation is modified by the list shown below. This does not include facilities used in the local
distribution of electric energy.
Inclusions:
•

•

•
•

•

I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase
Angle Regulators, with two primary and secondary windingsterminals ofoperated at 100
kV or higher unless excluded under Exclusions E1 andor E3.
I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including
the generator terminals through the GSU which has a high side voltage of 100 kV or
above.
I32 - Generating unitsresource(s) located at a single site with aggregate capacity greater
than 75 MVA (with gross individual or gross aggregate nameplate rating) per the ERO
Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up GSUstransformer(s), connected through a common bus operated
at a voltage of 100 kV or above.
I43 - Blackstart Resources and the designated blackstart Cranking Paths identified in the
Transmission Operator’s restoration plan regardless of voltage.
I54 - Dispersed power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily for
aggregating capacitycollector system , connected throughat a common point of
interconnection to a system Element at a voltage of 100 kV or above.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that
are connected at 100 kV or higher, or through a dedicated transformer with a high-side
voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.

Exclusions:
•

E1 - Any rRadial systems: which is described as connected A group of contiguous
transmission Elements that emanates from a single point of connection of 100 kV or
higher from a single Transmission source originating with an automatic interruption
device and:

Dra ft #2: Da te Au g u s t 24, 2011

Page 3 of 5

Project 2010-17 Definition of Bulk Electric System

•

•

a) Only servingserves Load. A normally open switching device between
radial systems may operate in a ‘make-before-break’ fashion to allow for
reliable system reconfiguration to maintain continuity of electrical service.
Or,
b) Only includingincludes generation resources, not identified in Inclusions
I2, I3, I4 and I5 with an aggregate capacity less than or equal to 75 MVA
(gross nameplate rating). Or,
c) Is a combination of items (a.) and (b.) wWhere the radial system serves
Load and includes generation resources, not identified in Inclusions I2, I3,
I4 and I5. with an aggregate capacity of non-retail generation less than or
equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted
on prints or one-line diagrams for example, does not affect this exclusion.
E2 - A generating unit or multiple generating units that serve all or part of retail customer
Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity
provided to the BES does not exceed the criteria identified in Inclusions I2 or I375 MVA,
and (ii) standby, back-up, and maintenance power services are provided to the generating
unit or multiple generating units or to the retail Load by a Balancing Authority, or
provided pursuant to a binding obligation with a Balancing Authority or another
Generator Owner / or Generator Operator, or under terms approved by the applicable
regulatory authority.
E3 - Local Distribution Nnetworks (LDN): A Ggroups of contiguous transmission
Elements operated at or above 100 kV but less than 300 kV that distribute power to Load
rather than transfer bulk power across the Iinterconnected Ssystem. LDN’s emanate from
multiple points of connection at 100 kV or higherare connected to the Bulk Electric
System (BES) at more than one location solely to improve the level of service to retail
customer Load and not to accommodate bulk power transfer across the interconnected
system. The LDN is characterized by all of the following:
Separable by automatic fault interrupting devices: Wherever connected to
the BES, the LDN must be connected through automatic fault-interrupting
devices;
a) Limits on connected generation: Neither tThe LDN, norand its underlying
Elements do not include generation resources identified in Inclusion I3
and do not have an aggregate capacity of non-retail generation greater than
75 MVA (gross nameplate rating) (in aggregate), includes more than 75
MVA generation;
b) Power flows only into the Local Distribution NetworkLN: The generation
within the LDN shall not exceed the electric Demand within the LDN The
LN does not transfer energy originating outside the LN for delivery
through the LN; and

Dra ft #2: Da te Au g u s t 24, 2011

Page 4 of 5

Project 2010-17 Definition of Bulk Electric System

•

Not used to transfer bulk power: The LDN is not used to transfer energy
originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Ttransfer Ppath: The LDN does not contain a
monitored Facility of a permanent fFlowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection
as defined by the Regional Entity, or a comparable monitored Facility in
the ERCOT or Quebec Interconnections, and is not a monitored Facility
included in an Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices owned and operated by the retail customer solely for its
own use.

Note - Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.

Dra ft #2: Da te Au g u s t 24, 2011

Page 5 of 5

Implementation Plan for Project 2010-17: Definition of BES
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this project can be implemented. However, this definition
relies heavily on the fact that an approved exception process exists in the NERC Rules of Procedure.
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required the definition shall go
into effect on the first day of the second calendar quarter after Board of Trustees adoption.
Compliance obligations for Elements included by the definition shall begin 24 months after the applicable
effective date of the definition.
The SDT realizes that Order 743 suggested a maximum of 18 months for implementation of a revised
definition of the BES. The 24 month period cited here is based on the various rehearing requests filed by
entities expected to be affected by the revised definition. Thus, the SDT believes that this is a more
realistic timeframe in which to effect any changes.
The SDT believes that the timeframe shown is needed to:
• Effectively produce reasonable transition plans – As shown in Order 743, part of the overall
process of revising the definition of BES is for the ERO and Regional Entities to develop
transition plans on a region by region basis to accommodate any changes needed in those regions
due to the revised definition. The transition plans will include any actions necessary for entities
to achieve compliance on any issues brought about by the revised definition.
• Submit any necessary registration changes – While Order 743 states that a revised definition
should provide clarity and not necessarily require major changes to registration; it is possible that
the revised definition may cause some registration changes. Entities will need time to submit
their changes and for those changes to work their way through the process.
• File for exceptions – The revised definition does not exist in a vacuum. There is a corresponding
process for entities to request exceptions for specific equipment or configurations. This process
will be defined in the NERC Rules of Procedure and will involve individual entities or the
Regional Entities having to make a technical case to justify the exception. This process will take
some time to complete and it would be expected that there will be an initial backlog of cases to
process.
• Provide training – Entities will need to train their operators and personnel on changes to their
operations brought about by the revised definition.
The existing definition of BES shall be retired at midnight of the day immediately prior to the effective
date of the new definition of BES in the particular jurisdiction in which the new definition is becoming
effective.

1

Implementation Plan for Project 2010-17: Definition of BES
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this project can be implemented. However, this definition
relies heavily on the fact that an approved exception process exists in the NERC Rules of Procedure.
Revision to Sections of Approved Standards and Definitions
There is one new definition associated with this project.
Bulk Electric System (BES): All Transmission Elements operated at 100 kV or higher, Real Power
resources as described below, and Reactive Power resources connected at 100 kV or higher unless such
designation is modified by the list shown below.
Inclusions:
• I1 - Transformers, other than Generator Step-up (GSU) transformers, including Phase Angle
Regulators, with two windings of 100 kV or higher unless excluded under Exclusions E1 and E3.
• I2 - Individual generating units greater than 20 MVA (gross nameplate rating) including the
generator terminals through the GSU which has a high side voltage of 100 kV or above.
• I3 - Multiple generating units located at a single site with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) including the generator terminals through the GSUs,
connected through a common bus operated at a voltage of 100 kV or above.
• I4 - Blackstart Resources and the designated blackstart Cranking Paths identified in the
Transmission Operator’s restoration plan regardless of voltage.
• I5 - Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a collector system through a common point of
interconnection to a system Element at a voltage of 100 kV or above.
Exclusions:
• E1 - Any radial system which is described as connected from a single Transmission source
originating with an automatic interruption device and:
a) Only serving Load. A normally open switching device between radial systems
may operate in a ‘make-before-break’ fashion to allow for reliable system
reconfiguration to maintain continuity of electrical service. Or,
b) Only including generation resources not identified in Inclusions I2, I3, I4 and I5.
Or,
Is a combination of items (a.) and (b.) where the radial system serves Load and
includes generation resources not identified in Inclusions I2, I3, I4 and I5.
• E2 - A generating unit or multiple generating units that serve all or part of retail Load with
electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the
BES does not exceed the criteria identified in Inclusions I2 or I3, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating units or to
the retail Load pursuant to a binding obligation with a Balancing Authority or another Generator
Owner/Generator Operator, or under terms approved by the applicable regulatory authority.

1

•

E3 - Local Distribution Networks (LDN): Groups of Elements operated above 100 kV that
distribute power to Load rather than transfer bulk power across the Interconnected System.
LDN’s are connected to the Bulk Electric System (BES) at more than one location solely to
improve the level of service to retail customer Load. The LDN is characterized by all of the
following:
Separable by automatic fault interrupting devices: Wherever connected to the
BES, the LDN must be connected through automatic fault-interrupting devices;
a) Limits on connected generation: Neither the LDN, nor its underlying Elements
(in aggregate), includes more than 75 MVA generation;
b) Power flows only into the Local Distribution Network: The generation within
the LDN shall not exceed the electric Demand within the LDN;
Not used to transfer bulk power: The LDN is not used to transfer energy
originating outside the LDN for delivery through the LDN; and
c) Not part of a Flowgate or Transfer Path: The LDN does not contain a monitored
Facility of a permanent flowgate in the Eastern Interconnection, a major transfer
path within the Western Interconnection as defined by the Regional Entity, or a
comparable monitored Facility in the Quebec Interconnection, and is not a
monitored Facility included in an Interconnection Reliability Operating Limit
(IROL).

•
Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception
process.
Effective Dates
The effective date is the date entities are expected to meet the performance identified.
This definition shall become effective on the first day of the firstsecond calendar quarter, 24 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required, all
requirements the definition shall go into effect on the first day of the firstsecond calendar quarter, 24
months after Board of Trustees adoption.
Compliance obligations for Elements included by the definition shall begin 24 months after the applicable
effective date of the definition.
The SDT realizes that Order 743 suggested a maximum of 18 months for implementation of a revised
definition of the BES. The 24 month period cited here is based on the various rehearing requests filed by
entities expected to be affected by the revised definition. Thus, the SDT believes that this is a more
realistic timeframe in which to effect any changes.
The SDT believes that the timeframe shown is needed to:
• Effectively produce reasonable transition plans – As shown in Order 743, part of the overall
process of revising the definition of BES is for the ERO and Regional Entities to develop
transition plans on a region by region basis to accommodate any changes needed in those regions
due to the revised definition. The transition plans will include any actions necessary for entities
to achieve compliance on any issues brought about by the revised definition.

2

• Submit any necessary registration changes – While Order 743 states that a revised definition
should provide clarity and not necessarily require major changes to registration; it is possible that
the revised definition may cause some registration changes. Entities will need time to submit
their changes and for those changes to work their way through the process.
• File for exceptions – The revised definition does not exist in a vacuum. There is a corresponding
process for entities to request exceptions for specific equipment or configurations. This process
will be defined in the NERC Rules of Procedure and will involve individual entities or the
Regional Entities having to make a technical case to justify the exception. This process will take
some time to complete and it would be expected that there will be an initial backlog of cases to
process.
• Provide training – Entities will need to train their operators and personnel on changes to their
operations brought about by the revised definition.
The existing definition of BES shall be retired at midnight of the day immediately prior to upon the
effective date of the new definition of BES in the particular jurisdiction in which the new definition is
becoming effective.

3

Comment Form for 2nd Draft of Definition of BES (Project 2010-17)

Please DO NOT use this form to submit comments on the 2nd draft of the Definition of the
Bulk Electric System (Project 2010-17). Use the electronic comment form only to submit
comments. Comments must be submitted by October 10, 2011.
If you have questions please contact Ed Dobrowolski at ed.dobrowolski@nerc.net or by
telephone at 609-947-3673.

Background Information
Definition of the BES (Project 2010-17)
The SDT responded to the comments received for the first posting of the definition for this
project by clarifying the core definition, inclusions, and exclusions to meet the concerns of
the industry. The SDT has also utilized a variety of other inputs including work that was
done by regional entities such as WECC, NPCC, RFC, and FRCC in coming up with the
present definition. Another input was FERC Orders No. 743 and 743a which provided
several specific directives on clarifying the existing definition. It should be noted that the
revised definition does not address functional entity registration or standards requirements
applicability. Those are separate issues.
The core definition represents a true bright-line; but, it is clear that by itself, it does not
cover all of the known situations and configurations that are needed for a complete
definition. Therefore, the SDT developed several specific inclusions and exclusions that will
be added to the core definition to complete it. At the present time, the SDT has drafted five
specific inclusions and four specific exclusions.
Inclusions represent those items that are included as part of the Bulk Electric System (BES)
where they would not have been included as part of the simple core definition. The reasons
that the SDT has added these items are as follows:
•

•
•
•

•

I1 – Since transformers have windings operating at different voltages, it was felt that
clarification was required so as to more explicitly identify which transformers were to
be included in the BES. The SDT believes that the present draft provides this needed
clarification.
I2 – This inclusion represents a merger of the original Inclusion I2 and the original
Inclusion I3 concerning generation thresholds.
I3 – Blackstart units are considered vital to the overall operation of the BES.
Consequently, the SDT has included Blackstart Resources. However, due to industry
comments, the SDT has deleted the inclusion of Cranking Paths.
I4 – This item was added in order to accommodate the effects of variable generation
on the BES. The intent of this configuration is to include variable generation (e.g.,
wind and solar resources) with an aggregate rating greater than 75 MVA and was
considered different enough from what was proposed in Inclusion I2 as to warrant a
separate inclusion statement in order to provide greater clarity in this area.
I5 – This is a new inclusion brought about by industry comments to clarify the
inclusion of Reactive Power devices.

In addition to inclusions, in order to complete the picture, specific exclusions also need to be
considered. The SDT has currently drafted four specific exclusions:
•

E1 – This item was added to address the basic issue of radial systems. Radial
exclusion was part of the existing definition and was supported moving forward in all
of the regional work as well as Order No. 743 (and Order No. 743a). The SDT has
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com

Comment Form for 2nd Draft of Definition of BES (Project 2010-17)

•
•

•

clarified this exclusion in response to industry comments by deleting the automatic
interruption device.
E2 – This item was added to address the situation of behind-the-meter generation.
The wording is basically extracted from the ERO Statement of Compliance Registry
Criteria.
E3 – Local networks were added to the exclusion list after considerable discussions
among the SDT and various registered entities that have configurations meeting
these conditions. The SDT believes that any network that simply supports
distribution should be excluded from the BES. The SDT has clarified the language for
the exclusion and added a 300 kV upper limit.
E4 – The SDT has added an exclusion for Reactive Power devices used solely by
retail customers for their own use as a result of comments received.

Several commenters objected to simply carrying through the generation and voltage
thresholds from the ERO Statement of Compliance Registry Criteria as part of the revised
definition. However, no respondents provided technical justifications for changing these
values. Furthermore, the scope of this project deals mainly with responding to FERC Orders
743 and 743a which clearly stated that the intent of the order was to maintain the status
quo and to only address those urgent issues identified in the order. Hence, the tight
schedule that was provided in the order. After consulting with the NERC Board of Trustees
and the NERC Standards Committee, the SDT has decided to forgo any attempt at changing
generation or voltage thresholds at this time. There simply isn’t enough time or resources
to do those topics justice with the mandated schedule. Therefore, the focus of the SDT
efforts will be to address the directives in Orders 743 and 743a. However, this does not
mean that the issues will be dropped. Both the NERC Board of Trustees and the NERC
Standards Committee have endorsed the idea that the Project 2010-17 SDT take a phased
approach to this project with a new Standards Authorization Request (SAR) to address
generation thresholds as well as several other issues that have arisen from SDT
deliberations. Issues such as what is necessary for the reliable operation of the BES,
whether the BES needs to be a contiguous, possible interconnection difference, who is a
user of the BES, and correlation of the definition of BES and the ERO Statement of
Compliance Registry Criteria will be addressed with this new SAR. The proposed SAR has
been posted for information purposes only concurrent with the second posting of this
project. A formal comment period will follow.
In parallel with the definition project, another team has been set up to develop a change to
the NERC Rules of Procedure (RoP) to allow for entities to technically justify excluding
Elements from the BES that might otherwise be included according to the proposed
definition. This same process would be used by Registered Entities to justify including
Elements in the BES that might otherwise be excluded according to the proposed definition.
This RoP team will develop the process for seeking an exemption from the definition but the
DBESSDT will develop the criteria necessary for applying for an exemption through the
standards development process. The DBESSDT developed exception criteria is posted
separately but simultaneously to the second posting of the definition.

Page 2 of 5

Comment Form for 2nd Draft of Definition of BES (Project 2010-17)

You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
The SDT has asked one specific question for each specific aspect of the definition.
1. The SDT has made clarifying changes to the core definition in response to industry
comments. Do you agree with these changes? If you do not support these changes or
you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments.
Yes:
No:
Comments:
2. The SDT has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1 (transformers)? If you do not support this
change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.
Yes:
No:
Comments:
3. The SDT has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I2 (generation) including the reference to the
ERO Statement of Compliance Registry Criteria? If you do not support this change or
you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments.
Yes:
No:
Comments:
4. The SDT has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I3 (blackstart)? If you do not support this
change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.
Yes:
No:
Comments:

Page 3 of 5

Comment Form for 2nd Draft of Definition of BES (Project 2010-17)

5. The SDT has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I4 (dispersed power)? If you do not support
this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.
Yes:
No:
Comments:
6. The SDT has added specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I5 (reactive resources)? If you do not support
this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.
Yes:
No:
Comments:
7. The SDT has revised the specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E1 (radial system)? If you do not support this
change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.
Yes:
No:
Comments:
8. The SDT has revised the specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E2 (behind-the-meter generation)? If you do
not support this change or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments.
Yes:
No:
Comments:
9. The SDT has revised the specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E3 (local network)? If you do not support this
change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.
Yes:
No:

Page 4 of 5

Comment Form for 2nd Draft of Definition of BES (Project 2010-17)

Comments:
10. The SDT has added specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E4 (reactive resources)? If you do not support
this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.
Yes:
No:
Comments:
11. Are there any other concerns with this definition that haven’t been covered in previous
questions and comments remembering that the exception criteria are posted separately
for comment?
Yes:
No:
Comments:

Page 5 of 5

Standard Authorization Request Form

E-mail completed form to
maureen.long@nerc.net

Title of Proposed Standard: NERC Glossary of Terms - Phase 2: Revision of the Bulk Electric
System definition.
Request Date:
SC Approval Date:

SAR Type (Check a box for each one
that applies.)

SAR Requester Information
Name: Project 2010-17 Definition of Bulk
Electric System (BES) SDT

New Standard

Primary Contact: Peter Heidrich (Manager of
Reliability Standards, FRCC) , Project 2010-17
Definition of Bulk Electric System (BES) SDT
Chair

Revision to existing Standard

Telephone: (813) 207-7994

Withdrawal of existing Standard

Fax: (813) 289-5646
E-mail: pheidrich@frcc.com

Urgent Action

Purpose (Describe what the standard action will achieve in support of bulk power system
reliability.)

Research possible revisions to the definition of Bulk Electric System (BES) (Phase 2) to address the issues
identified through Project 2010-17 Definition of Bulk Electric System (BES) (Phase 1). The definition
encompasses all Elements necessary for the reliable operation of the interconnected transmission
network. The definition development may include other improvements to the definition as deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent with establishing a
high quality and technically sound definition of the Bulk Electric System (BES).
Industry Need (Provide a justification for the development or revision of the standard,
including an assessment of the reliability and market interface impacts of implementing or
not implementing the standard action.)

This project supports the ERO’s obligation to identify the Elements necessary for the reliable operation
of the interconnected transmission network to ensure that the ERO, the Regional Entities, and the
industry have the ability to properly identify the applicable entities and Elements subject to the NERC
Reliability Standards.
Brief Description (Provide a paragraph that describes the scope of this standard action.)

Research possible revisions to the definition of Bulk Electric System (BES) developed in Phase 1 of this
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Standards Authorization Request Form

project to provide a technically justifiable definition that identifies the appropriate electrical
components necessary for the reliable operation of the interconnected transmission network. The
definition development may include other improvements to the definition as deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing a high quality and
technically sound definition of the Bulk Electric System (BES).
Detailed Description (Provide a description of the proposed project with sufficient details
for the standard drafting team to execute the SAR.)

Research possible revisions to the definition of Bulk Electric System (BES) developed in Phase 1 of this
project to provide a technically justifiable definition that identifies the appropriate electrical
components necessary for the reliable operation of the interconnected transmission network. The
definition development will include an analysis of the following issues, from a continent-wide and an
interconnection-wide basis, which were identified by the drafting team during the development of
Project 2010-17 Definition of the Bulk Electric System. Clarification of these issues will appropriately
define which Elements are necessary for the reliable operation of the interconnected transmission
network.
•
•
•
•
•

Determine the reliability benefit of a contiguous BES
Determine the appropriate ‘points of demarcation’ between Transmission, Generation, and
Distribution
Determine the appropriate threshold for Generation Resources which supports reliable
operation of the Bulk Electric System (BES)
Determine the scope and significance of the equipment which supports the reliable operation of
the Bulk Electric System (BES)
Clarify the relationship between the BES definition and the ERO Statement of Compliance
Registry Criteria established in FERC Order 693

Phase 2 of the definition development may include other improvements to the definition as deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent with establishing a
high quality and technically justifiable definition of the Bulk Electric System (BES).
Based on the potential revisions to the definition of the Bulk Electric System (BES) and an analysis of the
application of, and the results from, the exception process, the drafting team will review and if
necessary propose revisions to the ‘Technical Principles’ associated with the Rules of Procedure
Exception Process to ensure consistency in the application of the definition and the exception process.

SAR–2

Standards Authorization Request Form

Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)
Reliability
Assurer

Monitors and evaluates the activities related to planning and
operations, and coordinates activities of Responsible Entities to
secure the reliability of the bulk power system within a Reliability
Assurer Area and adjacent areas.

Reliability
Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing
Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.

Interchange
Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.

Planning
Coordinator

Assesses the longer-term reliability of its Planning Coordinator
Area.

Resource
Planner

Develops a >one year plan for the resource adequacy of its
specific loads within its portion of the Planning Coordinator’s Area.

Transmission
Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.

Transmission
Planner

Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within the Transmission Planner Area.

Transmission
Service
Provider

Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).

Distribution
Provider

Delivers electrical energy to the End-use customer.

Generator
Owner

Owns and maintains generation facilities.

Generator
Operator

Operates generation unit(s) to provide real and reactive power.

PurchasingSelling Entity

Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.

LoadServing
Entity

Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.

SAR–3

Standards Authorization Request Form

Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes

SAR–4

Standards Authorization Request Form

Related Standards
Standard No.

Explanation

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

FRCC
MRO
NPCC
SERC
TRE
RFC
SPP
WECC

SAR–5

John Q. Anderson
Chair, NERC Board of Trustees

September 1, 2011
Mr. Allen Mosher
Chair, NERC Standards Committee
Re: Report Regarding the Status of the Bulk Electric System Definition Development Project
Dear Allen,
On behalf of the NERC Board of Trustees, I want to thank you and the drafting team for the early
response relative to our inquiry on the status of the Bulk Electric System definition development
project. The Standards Committee’s report fulfills all of our expectations regarding the resolution that
the Board approved at its August 4, 2011 meeting. It is gratifying to see that the industry has adopted
a way forward that should enable NERC to meet the schedule set by the Federal Energy Regulatory
Commission and we remain hopeful this highly important project will remain on track toward the
January filing date.
The Trustees also recognize the industry has identified the generator threshold issue as one it believes
important to defining the extent of the Bulk Electric System. It is also possible there will be future
similar issues requiring deeper exploration. We believe the solution of separating out those elements
requiring more thought and development time into separate phases is an appropriate solution. We
support these additional efforts and look forward to future discussions related to them.
Should any additional issue arise that may impede the schedule, please work with the Board’s
Standards Oversight and Technology Committee to keep us informed and feel free to seek our
guidance relative to proposed solutions.
Sincerely,

John Q. Anderson
Chair
cc: Mr. Pete Heidrich, Chair, BES Definition Drafting Team
NERC Board of Trustees
3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

August 24, 2011
John Q. Anderson
Chairman
NERC Board of Trustees
Dear Chairman Anderson:
At the NERC Board of Trustees August 4, 2011 meeting, the Board approved the following Resolution on
Definition of Bulk Electric System:
In furtherance of the Board’s oversight of the standards development process and in anticipation of
the Board’s ultimate responsibility to determine whether the revised definition of “Bulk Electric
System” that emerges from the standards development process should be approved and filed with the
Federal Energy Regulatory Commission no later than January 25, 2012, as NERC’s response to the
directives in Order No. 743, the Board:
(1) directs the Standards Committee and the Standard Drafting Team to consider the feedback heard
at the August 4, 2011 board meeting regarding the development of the Bulk Electric System
definition; and
(2) further directs that the Standards Committee submit to the Board by September 9, 2011:
(a) the draft of the proposed Bulk Electric System definition as it exists on that date;
(b) the best justification that the Standard Drafting Team has prepared to support the change
in generator threshold from 20 MVA to 75 MVA; and
(c) an options paper that addresses possible options for moving forward with the
development of the proposed definition and responding to the Commission by the
January 25, 2012 deadline; and
(3) expects the Standards Drafting Team to continue its work on the Bulk Electric System definition.
The Drafting Team (DT) for Project 2010-17 Definition of the Bulk Electric System met the week of
August 7, 2011 and determined that it was highly unlikely that the DT could develop an adequate
technical justification to support revision of the single unit generator threshold criteria (20 to 75 MVA) in
the time frame established by Order 743. The team revised its proposed definition and provided us with
an update to its action plan that reflects adoption of the guidance provided by the Member
Representatives Committee and Board of Trustees.
•

Attachment A is a copy of the latest draft of the proposed definition of Bulk Electric System as of
August 19, 2011. The revised definition is silent on generator threshold; there is no proposed
change from 20 MVA to 75 MVA.

•

Attachment B is a copy of the letter provided by the drafting team’s chair, Peter Heidrich, on
August 23, 2011 relative to the status of the project.

•

Attachment C is a copy of the team’s proposed action plan for moving this project forward to
meet the applicable Commission directives by January 25, 2012. This includes splitting the

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609.452.8060 | www.nerc.com

project into two phases, with phase 1 focused solely on meeting the Commission’s relevant
directives. Phase 2 will address other issues, including the generator threshold issue, raised by
stakeholders or during drafting team deliberations.
It is our view that the drafting team’s proposed course of action meets the intent of the Board’s August 4
Resolution that the Standards Committee and the Standard Drafting Team consider the feedback heard at
the August 4, 2011 Board meeting regarding the development of the Bulk Electric System definition and
that the drafting team continue its work on the Bulk Electric System definition. The team expects to post
its latest documents for a stakeholder comment period starting on August 25, 2011.
Sincerely yours,

Allen Mosher
Chair, Standards Committee

Cc: Herbert Schrayshuen
Standards Committee
BES Definition SDT

-2-

Attachment A
August 19, 2011 Draft of BES Definition
August 24, 2011 Letter to John Q. Anderson from A. Mosher

Project 2010-17 Definition of Bulk Electric System
Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.

Development Steps Completed
1. SAR posted for comment 12/17/10 – 1/21/11
2. SC authorized moving the SAR forward to standard development 3/25/11
3. First posting of definition 4/28/11 – 5/27/11
4. First posting of criteria 5/11/11 – 6/10/11

Description of Current Draft
This draft is the second posting of the revised definition of the Bulk Electric System (BES). It is
for a 45-day formal comment and parallel voting period.

Anticipated Actions

Anticipated Date

30-day Formal Comment Period

April 28, 2011

45-day Formal Comment Period with Parallel Initial Ballot

September 2011

Recirculation ballot

December 2011

BOT adoption

January 2011

Dra ft #2: Au g u s t 19, 2011

Page 1 of 4

Project 2010-17 Definition of Bulk Electric System
Effective Dates
This definition shall become effective on the first day of the second calendar quarter after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
the definition will go into effect on the first day of the second calendar quarter after Board of
Trustees adoption. Compliance obligations for Elements included by the definition shall begin
24 months after the applicable effective date of the definition.

Version History

Version
1

Date
TBD

Dra ft #2: Au g u s t 19, 2011

Action

Change
Tracking

Respond to FERC Order No. 743 to
N/A
clarify the definition of the Bulk Electric
System

Page 2 of 4

Project 2010-17 Definition of Bulk Electric System
Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission
Elements operated at 100 kV or higher and Real Power and Reactive Power resources connected
at 100 kV or higher. This does not include facilities used in the local distribution of electric
energy.
Inclusions:
•
•

•
•

•

I1 - Transformers with primary and secondary terminals operated at 100 kV or higher
unless excluded under Exclusion E1 or E3.
I2 - Generating resource(s) (with gross aggregate nameplate rating per the ERO
Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily for aggregating
capacity, connected at a common point at a voltage of 100 kV or above.
I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that
are connected at 100 kV or higher, or through a dedicated transformer with a high-side
voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.

Exclusions:
•

E1 - Radial systems: A group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusion I3, with an
aggregate capacity less than or equal to 75 MVA (gross nameplate rating).
Or,
c) Where the radial system serves Load and includes generation resources,
not identified in Inclusion I3, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted
on prints or one-line diagrams for example, does not affect this exclusion.

Dra ft #2: Au g u s t 19, 2011

Page 3 of 4

Project 2010-17 Definition of Bulk Electric System
•

•

•

E2 - A generating unit or multiple generating units that serve all or part of retail customer
Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity
provided to the BES does not exceed 75 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating
units or to the retail Load by a Balancing Authority, or provided pursuant to a binding
obligation with a Generator Owner or Generator Operator, or under terms approved by
the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at or
above 100 kV but less than 300 kV that distribute power to Load rather than transfer bulk
power across the interconnected system. LN’s emanate from multiple points of
connection at 100 kV or higher to improve the level of service to retail customer Load
and not to accommodate bulk power transfer across the interconnected system. The LN is
characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do
not include generation resources identified in Inclusion I3 and do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating) ;
b) Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain a
monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection,
or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices owned and operated by the retail customer solely for its
own use.

Note - Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.

Dra ft #2: Au g u s t 19, 2011

Page 4 of 4

Attachment B
Letter from BES DT Chair - Project Status
August 24, 2011 Letter to John Q. Anderson from A. Mosher

August 23, 2011
Allen Mosher, Chair of NERC Standards Committee
Ben Li, Vice Chair of NERC Standards Committee
Herbert Schrayshuen, Vice President and Director of Standards, NERC
RE: Project 2010-17 Definition of the Bulk Electric System - Action Plan
Gentlemen;
This letter provides the Standards Committee, the Board of Trustees and NERC staff with the
Drafting Team’s action plan for Project 2010-17 Definition of the Bulk Electric System (BES).
The project is currently on schedule to complete the revision of the definition of the BES, the
development of the associated Implementation Plan and all documents supporting the Rules of
Procedure Exception Process by January 25, 2012, in response to the directives established by
the Commission (FERC) in Order Nos. 743 and 743-A.
The drafting team submitted the following documents for quality review on Friday, August 19,
2011, in preparation for the next scheduled posting. The goal is to post the documents for
stakeholder formal comment and initial ballot no later than September 2, 2011:
•

•

•
•
•

Draft BES Definition
o Responses to the initial posting of definition
o Technical Justification for the Local Network exclusion (E3)
o Second posting comment form for definition
Draft Technical Principles for Demonstrating BES Exceptions (evidence document to
support Rules of Procedure Process)
o Responses to the initial posting of Technical Principles document
o Second posting comment form for Technical Principles
Draft Implementation Plan
Table identifying how the team addressed applicable FERC directives
Phase 2 SAR (to be posted for informational purposes only)

I have attached the latest action plan for successful completion of this project in phases which
encompasses the MRC and BOT recommendations.
Sincerely,

Peter A. Heidrich
Chair, Project 2010-17 Definition of the Bulk Electric System Drafting Team

cc: NERC Board of Trustees
NERC Standards Committee

Attachment C
BES Definition Drafting Team Action Plan
August 24, 2011 Letter to John Q. Anderson from A. Mosher

August 23, 2011 Action Plan for Completion of Project 2010-17 – Definition of
Bulk Electric System
The Standard Drafting Team (SDT) for Project 2010-17 Definition of the Bulk Electric System
met the week of August 7, 2011 and determined that the feasibility of developing an adequate
technical justification for the revision of the single unit generator threshold criteria (20 to 75
MVA) is highly unlikely in the time frame established by Order No. 743 (filing deadline of
January 25, 2012). Therefore the SDT adopted the recommendations of the Member
Representatives Committee (MRC) and the NERC Board of Trustees (BOT) and developed the
following plan to meet the schedule for addressing the directives established by the Commission
(FERC) in Order Nos. 743 and 743-A while also addressing concerns raised by SDT members
and concerns received from stakeholders through the standard development process.

1

•

The SDT revised the draft definition to eliminate any change in the generation thresholds.
To accomplish this, the SDT has chosen to remain silent as to the actual values associated
with the generator thresholds for units and referenced the ERO Statement of Compliance
Registry Criteria for additional clarification. This will ensure that the current ‘status-quo’
application of the BES definition and the registration process will continue as it is today.

•

The SDT developed a second Standard Authorization Request (SAR) for the project
(Project 2010-17 Definition of the Bulk Electric System) to establish a phased approach
where phase 1 addresses the directives from Order Nos. 743 and 743-A and phase 2 will
address the concerns raised by SDT members and stakeholders through the Standard
Development Process.

•

The SDT finalized the revised draft BES definition and all associated documents for a 45day concurrent posting (formal comment period and initial ballot) scheduled to begin no
later than September 2, 2011. The SDT also prepared a revised version of the “Technical
Principles for Demonstrating BES Exceptions 1” for posting (formal comment period and
initial ballot) in parallel with the posting of the BES definition.

The “Technical Principles for Demonstrating BES Exceptions” was developed to supplement the Rules of
Procedure Exception Process by providing guidance to the ERO, the Regional Entities and the industry on the
detailed information and evidence necessary to support a BES Definition exception request.

Local Network Exclusion
Introduction

The purpose of this document is to provide the justification for the definitional exclusion of local
networks (LN) from the definition of the Bulk Electric System (BES) as proposed in NERC Standards
Development Project 2010-17. Presented herein are technical, logical, and practical considerations that
provide such justification for exclusion of these facilities from the Bulk Electric System.

Summary of Justification
The local network exclusion proposal is shown to be justified through the following facts:
1. In accordance with Commission Orders 743 and 743a on the matter of the revision of the
Definition of the Bulk Electric System, the facilities used in the local distribution of electric
energy are to be excluded;
2. The exclusion for local networks, as provided in the revised definition of the BES, ensures that a
candidate for local network exclusion must satisfy all of the exclusion principles thus
demonstrating that the candidate facilities are not performing a transmission function;
3. The limit on connected generation within the local network is consistent with the existing
threshold above which a generating plant in aggregate becomes subject to owner and operator
registration in the ERO Statement of Compliance Registry Criteria;
4. The voltage cap applied to the qualifications for a local network is established at 300 kV, which
is consistent with the distinction being made between Extra High Voltage and High Voltage in
the NERC Board of Trustees-approved Reliability Standard on transmission planning, TPL-001-2;
5. The power flow “shifts” that would occur on the elements of a local network are but a
negligible fraction of that which distributes upon the BES elements for a given power transfer
and is fully eclipsed by the Load in the local network; and
6. The interaction of the local network with the BES is similar in character to that of a radial facility.

Description of Local Network
Local networks are defined in the draft BES Definition as:
A group of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that
distribute power to Load rather than transfer bulk power across the interconnected system. LN’s
emanate from multiple points of connection at 100 kV or higher to improve the level of service to retail
customer Load and not to accommodate bulk power transfer across the interconnected system. The LN
is characterized by all of the following:

Page 1 of 16

a) Limits on connected generation: The LN and its underlying Elements do not include
generation resources identified in Inclusion I3 and do not have an aggregate capacity of
non-retail generation greater than 75 MVA (gross nameplate rating) ;
b) Power flows only into the LN: The LN does not transfer energy originating outside the LN for
delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain a monitored Facility of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within the
Western Interconnection, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability
Operating Limit (IROL).
Local networks are present to provide local electrical distribution service and are not planned, designed,
nor operated to benefit or support the balance of the interconnected electrical transmission network.
Their purpose is to provide local distribution service, not to provide transfer capacity for the
interconnected electric transmission network. Their design and operation is such that at the point of
connection with the interconnected electric transmission network, their effect on that network is similar
to that of a radial facility, particularly in that flow always moves in a direction that is from the BES into
the facility. Any distribution of parallel flows into the local network from the BES, as governed by the
fundamentals of parallel electric circuits, is negligible, and, more importantly, is overcome by the Load
served by the local network, thereby ensuring that the net actual power flow direction will always be
into the local network at all interface points. The presence of a local network is not for the operability of
the interconnected electric transmission network; neither will the local network’s separation or
retirement diminish the reliability of the interconnected electric transmission network.

Commission Determination on Exclusion of Local Distribution – Relation
to Local Network
In Order 743a, the Commission made it clear that facilities that are used in the local distribution of
electric energy will be excluded from the Bulk Electric System. Such clarification was provided in both
paragraphs 22 and 25 of the Order. The Commission agreed with certain commenters that facilities
used in the local distribution of energy should be excluded from the revised Bulk Electric System
definition.
In response to this facet of the Order, in developing the BES definition, the SDT has followed this
guidance. Exclusion E3 was specifically designed to capture for exclusion those high voltage non-radial
facilities being used for the local distribution of energy.
The exclusion characteristics in items a, b, and c above are further explained in the next section. These
exclusion principles serve to ensure that facilities excluded under the local network exclusion (E3) are
not necessary for the reliable operation of the interconnected electric transmission network and are
instead used in the local distribution of energy.

Page 2 of 16

Exclusion Principles
Of key importance is that Exclusion E3 in the draft BES definition requires the facilities of a candidate
network to meet all of the characteristics listed in the exclusion. The SDT adopted this approach to
ensure that none of the characteristics typical of interconnected electric transmission networks, or
necessary for the operation of the interconnected electric transmission system, would be permissible in
those facilities that are qualified for Exclusion E3. In the discussion below, it is shown that these
characteristics successfully prevent exclusion of facilities necessary for operating an interconnected
electric transmission network, and allow only facilities that are not necessary for such operation to be
excluded from the BES.
A. First Exclusion Principle: Limits on Connected Generation
Limits on connected generation: The LN and its underlying Elements do not include generation
resources identified in Inclusion I3, and do not have an aggregate capacity of non-retail
generation greater than 75 MVA (gross nameplate rating);
This characteristic places restrictions on the type and size of generation resources that can be connected
within the candidate facility. By placing this generation restriction on the local network, it is ensured
that that the candidate facility will not under any circumstance act as a host to generation that exceeds
the existing aggregate generation threshold in the ERO Statement of Compliance Registry Criteria (SCRC)
and that the candidate facility will not contain Blackstart Resources. The SDT submits that this
characteristic minimizes the contribution and influence the local network may have over the
neighboring Elements of the BES by limiting both the magnitude and the function of the connected
generation. The threshold of 75 MVA was chosen in a manner to provide consistency with the criteria
applied in the ERO’s SCRC regarding the registration for entities owning and operating generation plants
in aggregate.
B. Second Exclusion Principle: Power Flow and Function
Power flows only into the LN: The LN does not transfer energy originating outside the LN for
delivery through the LN;
This characteristic ensures that the real power flow direction at all connection points to the BES is into
the candidate local network, thereby ensuring that the candidate facilities behave in a manner that is
radial in character. Further, the local network is restricted as to its use; i.e., it cannot be used for
“wheel” transactions, or the transfer of energy originating outside the local network for delivery through
the local network. By restricting the flow direction to be exclusively into the network at its connection
points to the BES and precluding the network from providing transmission wheeling service, this
exclusion characteristic further ensures that the local network is providing only a distribution service,
and is not contributing to, nor is necessary for, the reliable operation of the interconnected electric
transmission network. Regarding the location of the connection points to the BES, Exclusion E3
specifies that local networks “emanate from multiple points of connection at 100 kV or higher…” These
points of emanation, where the local network begins and the BES ends, are established on a case-byPage 3 of 16

case basis, but will necessarily be the points, below 300 kV, at which all of the qualifying exclusion
principles are satisfied. As an example, see Appendix 1 to this document, which provides, among other
things, a single line diagram depicting a local network and its interface with the BES.
C. Third Exclusion Principle: Flowgates and Transfer Paths
Not part of a Flowgate or transfer path: The LN does not contain a monitored Facility of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within the Western
Interconnection, or a comparable monitored Facility in the ERCOT or the Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability
Operating Limit (IROL).
This characteristic further ensures that the candidate local network facilities do not contain nor
comprise facilities of well-established flowgates and transfer paths throughout the Interconnections of
North America. These transfer paths are customarily used to provide bulk power transfers within the
Interconnections, and therefore, the function and purpose of any candidate facilities included in or
among such paths extends beyond the distribution function. A number of interchange coordination
Reliability Standards apply to these transfer paths and flowgates. The SDT feels that such facilities are
necessary for the reliable operation of an interconnected electric transmission network and would not
be excluded from the definition of the BES.

The Use of a 300 kV Cap is Appropriate for Local Network Exclusion
The selection of a 300 kV cap for the applicability of an exclusion for a local network was based upon
recent NERC Standards Development work in Project 2006-02 “Assess Transmission Future Needs and
Develop Transmission Plans.” As conveyed in its work product, TPL-001-2, the Project 2006-02 SDT sets
a voltage level of 300 kV to differentiate Extra High Voltage (EHV) facilities from High Voltage facilities
acting as a threshold to distinguish between expected system performance criteria. 1 The Project 201017 SDT seeks to establish consistency in the limitations placed on the exclusion applicability for local
network facilities, and has therefore adopted this 300 kV level to ensure that EHV facilities, which under
the TPL-001-2 Standard are held to a higher standard of performance, are not subject to this exclusion.

There is Minimal Effect to Flow in the Local Network due to BES Power
Transfer
Similar to the character of a radial facility, and in order to qualify for exclusion from the BES under
Exclusion E3.b,a local network must only have power flow into the network at all connection points to
the BES. As demonstrated below, while this flow at the connection points is always into the local
Per footnote #3 in TPL-001-2, “Bulk Electric System (BES) level references include extra-high voltage (EHV)
Facilities defined as greater than 300 kV and high voltage (HV) Facilities defined as the 300 kV and lower voltage
Systems. The designation of EHV and HV is used to distinguish between stated performance criteria allowances for
interruption of Firm Transmission Service and Non-Consequential Load Loss.”
1

Page 4 of 16

network, the magnitude of the flow at these connection points will exhibit very slight shifts as bulk
power transactions are implemented on neighboring BES facilities. This occurs because local network
facilities are electrically parallel to Elements comprising the BES, and hence, the local network will
experience a small effect due to changes in power angle across the parallel network as BES dispatch and
flow patterns change. However, such flow shift is shown to be minimal, and the resultant power flow at
all BES interface points is dominated by the superimposed load flow serving the distribution Load
connected within the local network. Again, Exclusion E3.b ensures that flow shall always be from the
BES into the local network in order to qualify for exclusion.
In order to provide a realistic example of the electrical interaction between a typical local network and
the BES, an electric system in the western United States was examined from a power transfer
distribution factor (PTDF) perspective. In a PTDF analysis, the branch elements of an electrical network
are examined on the basis of the percentage split of a given power flow as it propagates through the
network. In the simplest example of two identical lines operated at the same voltage, arranged in
parallel between a given sending bus and receiving bus, the total power transfer will divide equally
among the two parallel line elements, and hence, each element would be found to have a 50% PTDF. In
a more complicated network, the line elements will carry a portion of the total flow in a manner that is
inversely proportional to their impedance; i.e., the lower the impedance of the network branch, the
higher portion of the flow that will distribute along that branch.
The electric system in question is depicted in Appendix 1. The station name identifiers and the network
topology (but not electrical connectivity) have been changed to respect the confidentiality of the
information. In the represented system, a bulk power transfer was simulated, with a point of receipt
(injection) at BES bus T9 and a point of delivery at the other end of the system at BES bus T10. With this
simulated power transfer, power flow analysis tools were used to determine the distribution of this
simulated transfer as it propagates across the various parallel branches of the network. As depicted in
Appendix 1, the facilities that are presumed to be excluded via the local network exclusion (E3) are
shown to carry negligible flow, with the largest PTDF at a mere 0.23% of the total transfer. Note that a
PTDF analysis shows only the incremental shift in power flow and does not imply that this 0.23% actually
flows in and then back out of the network. The power flow results demonstrate that the flow measured
at the interface points of the BES continues to flow into the local network, and is essentially unchanged,
as it is only shifted in magnitude by a mere 0.23% of the modeled transaction amount.
In addition to the PTDF analysis, another analysis of Line Outage Distribution Factors (LODF), examines
the re-distribution of flow that occurs on parallel elements after a subject element is removed from
service. For example, if a BES element is carrying 500 MW, and is taken out of service, LODF describes
how that flow re-distributes among all parallel paths in a given network. LODF factors are measured in
percent of the pre-outage flow on the outaged element. Conducting this analysis on the example
network and modeling the worst case outage, which is the loss of the line element between BES buses
T9 and T10, shows that the net shift in flow for the local network is 4.0% of the pre-outage flow, and the
largest shift in flow on any of the individual local network elements is 2.7%. The flow direction at the
interface points between the local network and the BES continues to be into the local network.
Page 5 of 16

This degree of flow shift on the local network facilities is de minimus, and neither diminishes or
improves the reliability of the parallel BES facilities. From both a PTDF and an LODF analysis perspective,
the local network exhibits qualities equivalent to radial facilities in that the power flow emanates from
the point of BES connection in one direction – the only difference being that in the case of the local
network, in order to provide source reliability to the distribution Load, more than one connection is
provided to the BES.

Page 6 of 16

Appendix 1
Local Network Technical Justification
Power Transfer Distribution Factor Analysis
This appendix provides Power Transfer Distribution Factor (PTDF) and Line Outage Distribution Factor
(LODF) analyses and assessments using a relevant power flow case used in actual operating studies in
the Western Interconnection to assess reliable Operating Transfer Capability on a rated path in the
Western Electricity Coordinating Council ("WECC"). The electrical system representation is accurate;
however, the bus names and topology have been graphically rearranged to address any Critical Energy
Infrastructure Information (“CEII”) concerns.
Although linear analyses, such as these, are relatively independent of actual power transfer levels, the
modeled system conditions represented peak load demand and high power transfer conditions. The
PTDF analyzes the injection of power from BES electrical bus T9 and delivering it to BES bus T10, which is
consistent with the use of the BES transfer path. Based on the PTDF assessment, 92% of the power flow
is transferred over the 500 kV line that directly connects BES buses T9 and T10. The remaining flow
appears on the underlying 230 kV lines and adjacent 345 kV and 500 kV lines. The largest PTDF on any
local network is 0.23 percent.
The LODF analysis considers the “worst-case” outage of the strongest (lowest impedance) transmission
element, the line between BES buses T9 and T10. The LODF values that are computed represent the
percentage of the pre-outage T9-T10 flow that re-distributes on each of the remaining branches. The
analysis shows that the net shift in flow for the local network is 4.0% of the pre-outage flow, and the
largest shift in flow on any of the individual local network elements is 2.7%. The 2.7% shift occurs on the
local network branch between buses LN19 and LN28, and a 1.3% shift occurs on the branch between
LN27 and LN33. The flow direction at the interface points between the local network and the BES
continues to be into the local network.
Below are three single line diagrams, which depict the 1) powerflow, 2) percentage distribution of flows
for the PTDF analysis, and 3) the percent of flow distribution for the LODF analysis. In these diagrams,
the local network elements are indicated by a green line color, and the local network station buses are
indicated with an “LN” designation, for example, “LN23”.
Following the single line diagrams are two tables: Table 1 - a tabulation of the PTDF values for the
network, and Table 2 - depicting the LODF values for the T9-T10 line outage case.

Page 7 of 16

The Powerflow Single Line

T18

T16

T9
T6

T10

T5
T8

T11

T19
T36

T17

T35

T20
T23

T21

T22

T27

T25

T24

T29

T28

T31
LN2

LN10

Local Network

LN4

LN1

LN22

LN6

To generation
LN51

LN25

T26

Local Network
LN50

LN9
LN57
LN7

LN21

LN13

LN52
LN58
LN26

LN15
LN8

T33

LN23

LN12

LN5

LN6

T34

LN24

LN3
LN11

T32

T30

LN15

LN53

LN17

LN31

LN49
LN54

LN16

LN55

LN36
LN48

LN32
LN18

LN37

Red lines are 345 kV to 500 kV

LN20

Orange lines are 230 kV

LN56

LN27

LN33

LN38

Green lines are 115 kV
LN29

The size of the arrow is proportional to the magnitude of powerflow in
MWs
Arrows do not appear when the level of powerflow is very low

LN57

LN30

LN47
LN39

LN19

LN28

LN40
LN46

LN34
LN41
LN45
LN35

LN42
LN43
LN44

Page 8 of 16

The Power Transfer Distribution Factors (“PTDF”) Single Line

T18

T9
T6

PTDF
The transaction is from bus T9 to bus T10 where T9 is the seller and T10 is the buyer

T8

PTDF

T21

T11

T19
T35

2%

T22

PTDF

T27

T25

T24

T29

T28

T31
LN2

LN10

Local Network

LN11

LN1
LN6
LN6

To generation
LN51

LN25

T26

Local Network
LN50

LN9
LN57
LN7

LN21

LN13

LN52
LN58
LN26

LN15
LN8

T34

T33

LN23

LN12

LN5

T32

T30

LN24

LN22

LN3
LN4

T36

T17

2%
T23

T10

92%

T5

T20

T16

LN15

LN53

LN17

LN31

LN49
LN54

LN16

LN48

LN32
LN18

LN37

Red lines are 345 kV to 500 kV

LN20

LN56

LN27

Orange lines are 230 kV

LN33

0%

Green lines are 115 kV

LN38

PTDF

LN29

The size of the arrow is proportional to the magnitude of PTDF
Arrows do not appear when the level of PTDF is very low

LN55

LN36

0%

LN19

PTDF

LN57

LN30

LN47
LN39

LN28

LN40
LN46

LN34
LN41
LN45
LN35

LN42
LN43
LN44

Page 9 of 16

The Line Outage Distribution Factors ("LODF") Single Line identifying the revised PTDF values of the transmission line from T9 to T10 is opened

For the LODF assessment the transmission line from bus T9 to bus T10 is opened and the PTDF are
recalculated (See the LODF table for additional details)

T9
T6

T18

T16

T10

T5
T8

T11

T19
PTDF

T20
T23

T21

T35

22%

T22

PTDF

T27

T25

T24

T29

T28

T31
LN2

LN10

Local Network

LN22

LN11

LN4

LN6
LN6

To generation
LN51
T26

LN12

Local Network
LN50

LN9
LN57
LN7

LN21

LN13

LN52
LN58
LN26

LN15
LN8

T34

T33

LN23
LN25

LN5

T32

T30

LN24

LN3
LN1

T36

T17

22%

LN15

LN53

LN17

LN31

LN49
LN54

LN16

LN48

LN18

LN37

Red lines are 345 kV to 500 kV

LN20

LN56

LN27

Orange lines are 230 kV

LN33

1%

Green lines are 115 kV

LN38

PTDF

LN29

The size of the arrow is proportional to the magnitude of PTDF
Arrows do not appear when the level of PTDF is very low

LN55

LN36
LN32

3%

LN19

PTDF

LN57

LN30

LN47
LN39

LN28

LN40
LN46

LN34
LN41
LN45
LN35

LN42
LN43
LN44

Page 10 of 16

Table 1 - Power Flow Transfer Distribution Factor Results

From
Name
T10
T10
T5
T11
T36
T12
T19
T19
T22
T34
T34
T41
T40
T37
LN16
LN28
LN19
T30
LN50
LN32
LN31
LN20
LN12
LN11
LN3
T29
T29
LN30
LN9
LN5
T28
T32
LN50
LN53
LN55
LN41
T33
LN39
T42
LN47
LN1
LN41
LN25

Line PTDF Records
%
%
To
PTDF
PTDF
Name
From
To
T9
-91.61
91.61
T11
-5.4
5.4
T9
-4.77
4.77
T36
-4.13
4.13
T35
-3.08
3.08
T11
-2.4
2.4
T20
-1.84
1.84
T22
-1.81
1.81
T21
-1.74
1.74
T30
-1.3
1.3
T30
-1.29
1.29
T40
-0.57
0.57
T39
-0.55
0.55
T38
-0.49
0.49
LN8
-0.23
0.23
LN19
-0.23
0.23
LN18
-0.23
0.23
T33
-0.11
0.11
LN36
-0.11
0.11
LN33
-0.11
0.11
LN32
-0.11
0.11
LN17
-0.11
0.11
LN11
-0.11
0.11
LN10
-0.11
0.11
LN2
-0.1
0.1
T32
-0.09
0.09
T17
-0.09
0.09
LN29
-0.09
0.09
T23
-0.08
0.08
LN7
-0.08
0.08
T31
-0.07
0.07
T31
-0.07
0.07
LN49
-0.07
0.07
T33
-0.06
0.06
LN54
-0.06
0.06
LN43
-0.06
0.06
T32
-0.05
0.05
LN41
-0.05
0.05
T39
-0.04
0.04
T32
-0.04
0.04
T23
-0.04
0.04
LN42
-0.04
0.04
LN23
-0.04
0.04

Nom
kV
(Max)
500
500
500
230
230
500
230
230
230
230
230
230
230
230
115
115
115
115
115
115
115
115
115
115
115
115
230
115
115
115
115
115
115
115
115
115
115
115
230
115
115
115
115

From
Name
LN22
LN13
LN15
LN45
LN57
LN50
T1
LN51
T33
LN4
LN6
LN38
LN30
LN35
LN38
LN24
LN26
T25
LN26
LN14
LN22
LN17
LN23
T25
T24
T6
T19
T19
T19
LN47
LN46
LN25
LN22
LN13
LN53
LN45
LN44
LN41
LN9
LN37
T16
LN30
T20
LN3
T24

Line PTDF Records
%
%
To
PTDF
PTDF
Name
From
To
LN21
-0.04
0.04
LN15
-0.04
0.04
LN1
-0.04
0.04
LN57
-0.03
0.03
LN56
-0.03
0.03
LN48
-0.03
0.03
T2
0
0
LN52
0
0
LN52
0
0
LN5
0
0
LN5
0
0
LN37
0
0
LN35
0
0
LN34
0
0
LN34
0
0
LN27
0
0
LN25
0
0
LN23
0
0
LN20
0
0
LN15
0
0
LN11
0
0
LN10
0
0
LN10
0
0
T24
0.01
-0.01
T23
0.02
-0.02
T4
0.03
-0.03
T26
0.03
-0.03
T26
0.03
-0.03
T26
0.03
-0.03
LN46
0.04
-0.04
LN42
0.04
-0.04
LN24
0.04
-0.04
LN23
0.04
-0.04
LN21
0.04
-0.04
LN54
0.06
-0.06
LN44
0.06
-0.06
LN43
0.06
-0.06
LN40
0.06
-0.06
LN7
0.08
-0.08
T31
0.09
-0.09
T17
0.09
-0.09
LN37
0.09
-0.09
T23
0.1
-0.1
LN5
0.1
-0.1
LN2
0.1
-0.1

Nom
kV
(Max)
115
115
115
115
115
115
500
115
115
115
115
115
115
115
115
115
115
115
115
115
115
115
115
115
115
500
230
230
230
115
115
115
115
115
115
115
115
115
115
115
345
115
115
115
115

12

From
Name
LN50
T22
LN57
LN12
LN31
LN27
LN20
LN58
T25
LN50
T21
T19
LN5
LN28
LN16
T2
T2
T37
T13
T14
T38
T27
T28
T4
T19
T19
T19
T1
T4
T34
T34
T21
T6
T5
T5
T29
T15
T12
T9
T8

Line PTDF Records
%
%
To
PTDF
PTDF
Name
From
To
T31
0.11
-0.11
T25
0.11
-0.11
LN58
0.11
-0.11
LN57
0.11
-0.11
LN36
0.11
-0.11
LN33
0.11
-0.11
LN27
0.11
-0.11
LN17
0.11
-0.11
LN10
0.11
-0.11
T33
0.12
-0.12
T24
0.12
-0.12
T18
0.13
-0.13
LN8
0.23
-0.23
LN29
0.23
-0.23
LN18
0.23
-0.23
T7
0.3
-0.3
T7
0.34
-0.34
T34
0.49
-0.49
T12
0.59
-0.59
T11
0.71
-0.71
T39
0.78
-0.78
T28
0.94
-0.94
T29
1.1
-1.1
T3
1.15
-1.15
T29
1.21
-1.21
T27
1.22
-1.22
T38
1.26
-1.26
T7
1.28
-1.28
T1
1.28
-1.28
T35
1.54
-1.54
T35
1.54
-1.54
T20
1.77
-1.77
T2
2.34
-2.34
T6
2.37
-2.37
T4
2.4
-2.4
T30
2.48
-2.48
T11
2.97
-2.97
T10
3
-3
T8
3.62
-3.62
T21
3.62
-3.62

Nom
kV
(Max)
115
115
115
115
115
115
115
115
115
115
115
230
115
115
115
500
500
230
500
500
230
230
230
500
230
230
230
500
500
230
230
230
500
500
500
230
500
500
500
230

13

Table 2 - Line Outage Distribution Factor Results (Outage of T9-T10)

From
Name
T10
T9
T8
T12
T15

To
Name
T9
T8
T21
T10
T11

T29
T5
T5
T6
T21
T34
T34
T4
T1
T19
T19
T19
T4
T28
T27
T38
T14
T13
T37
T2
T2
LN5
LN16
LN28
T19
T22
T21
LN50
T25
LN12
LN57
LN58
LN20
LN27
LN31
LN50
T24
T20

T30
T4
T6
T2
T20
T35
T35
T1
T7
T38
T27
T29
T3
T29
T28
T39
T11
T12
T34
T7
T7
LN8
LN18
LN29
T18
T25
T24
T33
LN10
LN57
LN58
LN17
LN27
LN33
LN36
T31
LN2
T23

Line LODF Records
%
MW
MW
CTG MW
LODF
From
To
From
-100 -1482.1 1483.7
0
-43.2
217.9 -217.8
857.5
-43.2
217.8 -217.5
857.4
-35.7
-937.2
937.2
-408.3
-35.4
1632.1
2156.2
1596.9
-29.5
404.1 -404.1
841.8
-28.6
-835.5
835.5
-411.4
-28.2
-873.5
873.5
-455.2
-27.8
-911.5
912.6
-499
-21
69
-69
380.8
-18.3
29.2
-29.1
300.9
-18.3
29.2
-29.1
300.9
-15.3 -1783.5 1802.5
-1557.4
-15.3 -1802.5 1802.5
-1576.4
-15
107.3
-107
330.4
-14.5
-53.1
53.2
162.3
-14.4
-50.9
51
162.8
-13.8
986
-985
1189.8
-13.1
155.8 -155.8
349.4
-11.2
-154.7
154.7
11.3
-9.2
326.8 -319.7
463.7
-8.4 -1656.8 1684.2
-1532.1
-7.1 -1308.7 1329.4
-1204.2
-5.8
-219.8
220.1
-133.7
-4.1
-826.9
833.1
-766.2
-3.5
-714.3
719.6
-661.9
-2.7
21.8
-21.8
62.3
-2.7
21.1
-21.1
61.6
-2.7
-8.4
8.5
32.1
-1.5
203.2 -202.5
225.6
-1.4
83.1
-83
103.2
-1.4
78.4
-78.3
99.1
-1.4
-38.6
38.7
-18.2
-1.3
35.7
-35.7
54.4
-1.3
22.3
-22.3
41
-1.3
12.4
-12.4
31.1
-1.3
0.1
-0.1
18.8
-1.3
0.1
-0.1
18.8
-1.3
0.1
-0.1
18.8
-1.3
-20.3
20.3
-1.6
-1.3
-36.7
36.7
-16.7
-1.2
80.3
-80.2
98.3
-1.2
77.4
-77.2
95.8

14

CTG MW
To
1.6
-857.4
-857.1
408.3
-2120.9
-841.8
411.4
455.2
500.1
-380.8
-300.9
-300.9
1576.4
1576.4
-330
-162.2
-162.7
-1188.9
-349.4
-11.3
-456.6
1559.6
1224.8
133.9
772.4
667.2
-62.3
-61.6
-32.1
-224.8
-103.1
-99
18.3
-54.4
-41
-31.1
-18.8
-18.8
-18.8
1.6
16.8
-98.2
-95.7

LN3
T16

LN5
T17

From
Name
LN9
LN30
LN37
LN45
LN44
LN53
LN41
LN46
LN47
LN13
LN22
LN25
T6
T24
T19
T19
T19
T25
LN51
LN30
LN17
LN23
LN22
LN26
T25
LN24
LN35
LN38
T1
LN38
LN26
LN14
T33
LN4
LN6
LN50
LN57
LN45
LN25
T42
LN22
LN41
LN13
LN15

To
Name
LN7
LN37
T31
LN44
LN43
LN54
LN40
LN42
LN46
LN21
LN23
LN24
T4
T23
T26
T26
T26
T24
LN52
LN35
LN10
LN10
LN11
LN20
LN23
LN27
LN34
LN34
T2
LN37
LN25
LN15
LN52
LN5
LN5
LN48
LN56
LN57
LN23
T39
LN21
LN42
LN15
LN1

-1.2
53.6
-53.5
71.6
-1
449.4 -436.5
464.6
Line LODF Records
%
MW
MW
CTG MW
LODF
From
To
From
-1
48.7
-48.6
63.3
-1
-39.1
39.1
-24
-1
-48.3
48.4
-33.2
-0.7
70.8
-70.8
81.3
-0.7
67.7
-67.6
78.2
-0.7
59.5
-59.5
69.6
-0.7
53.2
-53.1
63.1
-0.5
55.6
-55.6
63.5
-0.5
55.8
-55.6
63.7
-0.5
47.9
-47.9
55.7
-0.5
24.6
-24.6
32.5
-0.5
14.4
-14.4
22.2
-0.4
38
-38
43.8
-0.3
45.3
-45.3
49.4
-0.3
-152.9
157.7
-148.1
-0.3
-152.9
157.7
-148.1
-0.3
-152.9
157.7
-148.1
-0.1
47.3
-47.3
48.7
0
30.6
-30.5
30.6
0
24.4
-24.4
24.4
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-9.1
9.1
-9.1
0
-10.2
10.2
-10.2
0
-12.4
12.4
-12.4
0
-22
22.1
-22.1
0
-22.4
22.4
-22.4
0
-33.9
33.9
-33.9
0.3
29.9
-29.9
25.4
0.3
-17.2
17.3
-21.7
0.3
-37.6
37.6
-42
0.5
-24.6
24.6
-32.4
0.5
-28.5
30.5
-35.9
0.5
-38.1
38.1
-45.9
0.5
-48.9
48.9
-56.8
0.5
-51.6
51.6
-59.4
0.5
-64
64
-71.8

15

-71.5
-451.7
CTG MW
To
-63.3
24
33.3
-81.3
-78.1
-69.5
-63
-63.5
-63.5
-55.7
-32.5
-22.2
-43.8
-49.4
153
153
153
-48.7
-30.5
-24.4
0
0
0
0
0
0
0
0
0
9.1
10.2
12.4
22.1
22.4
33.9
-25.3
21.7
42
32.5
37.9
46
56.8
59.4
71.9

LN1
LN47
T33
LN39

T23
T32
T32
LN41

From
Name
LN55
LN41
LN53
T32
T28
LN50
T29
LN30
LN5
LN9
T29
LN3
T30
LN50
LN31
LN20
LN32
LN11
LN12
LN28
LN19
LN16
T37
T40
T41
T34
T34
T22
T19
T19
T12
T36
T11
T5

To
Name
LN54
LN43
T33
T31
T31
LN49
T32
LN29
LN7
T23
T17
LN2
T33
LN36
LN32
LN17
LN33
LN10
LN11
LN19
LN18
LN8
T38
T39
T40
T30
T30
T21
T22
T20
T11
T35
T36
T9

T10

T11

0.5
-64
64
-71.9
0.5
-66.5
66.6
-74.4
0.6
45.7
-45.7
36.4
0.6
-46.7
46.8
-55.3
Line LODF Records
%
MW
MW
CTG MW
LODF
From
To
From
0.7
-50.6
50.7
-60.7
0.7
-58.7
58.8
-69.2
0.7
-62.8
63
-72.9
0.8
65.9
-65.9
54.4
0.9
125.9 -125.5
112.9
0.9
61.9
-61.8
49.1
1
136.8 -136.4
121.6
1
-4.5
4.5
-19.7
1
-38.7
38.7
-53.4
1
-58.4
58.5
-73
1
-436.1
436.5
-451.3
1.2
-61.9
62
-79.9
1.3
125.6 -125.3
105.9
1.3
29.7
-29.7
11
1.3
11.2
-11.2
-7.5
1.3
-0.1
0.1
-18.8
1.3
-0.1
0.1
-18.8
1.3
-35.7
35.7
-54.4
1.3
-35.6
35.7
-54.3
2.7
-2.1
2.1
-42.6
2.7
-12.6
12.6
-53.1
2.7
-21.7
21.8
-62.3
5.8
219.8 -219.8
133.7
6.6
-221.1
222.8
-318.7
6.8
-308.2
309.9
-408.2
15.4
-138.7
138.7
-366.6
15.5
-139.7
139.7
-369.2
20.7
-70.2
70.2
-377.3
21.5
-90.4
90.7
-409.8
21.9
-91.6
91.9
-416.3
28.6
-392.2
392.2
-816.5
36.7
-58.2
58.2
-601.7
49.2
65.3
-64.8
-663.5
56.8
1709
866.6
1701.6
64.3
544.9 -544.9
-408.3

16

71.9
74.5
-36.4
55.4
CTG MW
To
60.7
69.3
73
-54.4
-112.5
-49
-121.1
19.7
53.4
73.2
451.7
80
-105.7
-11
7.5
18.8
18.8
54.4
54.4
42.6
53.1
62.3
-133.7
320.4
409.9
366.7
369.2
377.3
410
416.6
816.5
601.7
664
-859.1
408.3

Standards Announcement
Project 2010-17 Definition of Bulk Electric System

Two Ballot Windows Now Open September 30 – October 10, 2011
Now available at: https://standards.nerc.net/CurrentBallots.aspx
Two ballots windows are now open for Project 2010-17 Definition of Bulk Electric System (BES). The first is for
the definition of Bulk Electric System, and the second is for a draft application form titled Detailed Information
to Support an Exception Request referenced in the Rules of Procedure Exception Process. Both ballots are
open through 8 p.m. Eastern on Monday, October 10, 2011.
The revised definition of Bulk Electric System, draft application form titled Detailed Information to Support an
Exception Request, associated implementation plan and several informational documents have been posted
on the project page at http://www.nerc.com/filez/standards/Project2010-17_BES.html.
Instructions for Balloting Revisions

Members of each of the two ballot pools associated with this project may log in and submit their votes for
both the definition and the Detailed Information to Support an Exception Request from the following page:
https://standards.nerc.net/CurrentBallots.aspx.
Special Instructions for Submitting Comments With a Ballot

Comments submitted with ballots are extremely valuable to help the drafting team revise its work. In an
effort to reduce the burden on stakeholders providing comments, the drafting team requests that all
comments (both those submitted with a ballot and those submitted by stakeholders not balloting) be
submitted through the electronic comment forms posted at:
https://www.nerc.net/nercsurvey/Survey.aspx?s=e82643bb1de1434c9834c69757faa8d0
https://www.nerc.net/nercsurvey/Survey.aspx?s=9995ac42ce2644d9aebc87f58dd166ad
This will ensure that stakeholders only provide a single set of comments, but have an opportunity to notify the
drafting team if they have provided comments.
When submitting a ballot with comments, submit the comments through the electronic form and then
simply record a “Comments submitted” in the comments field of the ballot to indicate that comments were
submitted.
Please note that comments submitted during the formal comment period and the ballot use the same
electronic form, and it is NOT necessary for ballot pool members to submit more than one set of comments
(one during the comment period and a second with a ballot).

Next Steps

The drafting team will consider all comments received, and decide whether to make additional revisions to the
definition and Detailed Information to Support an Exception Request. The drafting team is working to meet
the regulatory deadline in FERC Orders 743 and 743A (filing by January 25, 2012).
The Standards Committee and NERC Board of Trustees have recommended that the drafting team address
issues such as generation thresholds in a second phase of this project. This approach will ensure that the
drafting team has sufficient time to adequately consider and develop a sound technical basis for an approach,
and will allow the drafting team to meet the regulatory deadline in FERC Orders 743 and 743A (filing by
January 25, 2012). The drafting team has posted a draft Supplemental Standards Authorization Request (SAR)
for information purposes only; the SAR will be posted for comment at a future time. Additional information
about the project, including a Fact Sheet and additional informational documents, has been posted on the
project webpage at http://www.nerc.com/filez/standards/Project2010-17_BES.html.
Project Background

On November 18, 2010 FERC issued Order 743 (amended by Order 743A) and directed NERC to revise the
definition of Bulk Electric System so that the definition encompasses all Elements and Facilities necessary for
the reliable operation and planning of the interconnected bulk power system. Additional specificity will reduce
ambiguity and establish consistency across all Regions in distinguishing between BES and non-BES Elements
and Facilities.
In addition, NERC was directed to develop a process for identifying any Elements or Facilities that should be
excluded from the BES. NERC is working to address these directives with two activities – the definition of Bulk
Electric System is being revised through the standard development process and a BES Definition Exception
Process is being developed as proposed modifications to the Rules of Procedure. The proposed modifications
have been posted for a comment period through October 27, 2011. The work of the BES Definition Exception
Process has been publicly posted at: http://www.nerc.com/filez/standards/Rules_of_Procedure-RF.html.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement

Project 2010-17 BES Definition
Two Ballot Pool Windows Open August 26 – September 26, 2011
Two Formal Comment Periods Open August 26 – October 10, 2011
Two Ballot Windows Open September 30 – October 10, 2011
Available tomorrow at: https://standards.nerc.net/BallotPool.aspx
The Definition of Bulk Electric System Standard Drafting Team (DBES SDT) has posted a second draft of the
Definition of Bulk Electric System (BES) and associated implementation plan for a formal 45-day comment
period, through 8 p.m. Eastern on Monday, October 10, 2011.
The Definition of Bulk Electric System Standard Drafting Team (DBES SDT) has also posted a draft
application form titled Detailed Information to Support an Exception Request referenced in the Rules of
Procedure Exception Process for a formal 45-day comment period, through 8 p.m. Eastern on Monday,
October 10, 2011. (Note that the information contained in this draft form includes revisions made to the
Technical Principles for Supporting BES Exceptions that was posted for comment in May and June 2011.)
A separate team is working with NERC to draft a new Appendix 5C to NERC’s Rules of Procedure to address
the process for requesting BES exceptions. This team will be posting the Rules of Procedure changes for
stakeholder comment in September. The comment period for the Rules of Procedure changes will overlap the
comment period for the definition and application form, to provide an opportunity for stakeholders to review all
three documents to understand how they will work together.
Clean and redline versions of the definition and associated implementation plan, along with a technical
justification for the Local Network exclusion and a clean version of the application form titled Detailed
Information to Support an Exception Request have been posted on the project page at:
http://www.nerc.com/filez/standards/Project2010-17_BES.html. The format of the application form titled
Detailed Information to Support an Exception Request has changed substantially since the first posting, making
a redline impractical, so none has been provided.
The Standards Committee and NERC Board of Trustees have recommended that the drafting team address
issues such as generation thresholds in a second phase of this project. This approach will ensure that the
drafting team has sufficient time to adequately consider and develop a sound technical basis for an approach,
and will allow the drafting team to meet the regulatory deadline in FERC Orders 743 and 743a (filing by
January 25, 2012). The drafting team has posted a draft Supplemental Standards Authorization Request (SAR)
for information purposes only; the SAR will be posted for comment at a future time.

Ballot Pools Forming
During the first 30 days of the comment period, two separate ballot pools will be formed: one for balloting the
Definition of Bulk Electric System, and a second for balloting the application form titled Detailed Information
to Support an Exception Request. The ballot pool windows will be open from Friday, August 26 through 8
a.m. Eastern on Monday, September 26, 2011.
During the final 10 days of the comment period, two separate initial ballots will be conducted, one for the
Definition of the Bulk Electric System, and a second for the application form titled Detailed Information to
Support an Exception Request. The ballot windows will begin on Friday, September 30th and end at 8 p.m.
Eastern on Monday, October 10, 2011.
Instructions for Joining Ballot Pools
Registered Ballot Body members must join each of the ballot pools to be eligible to vote in the upcoming
ballots at the following page: https://standards.nerc.net/BallotPool.aspx
During the pre-ballot window, members of each ballot pool may communicate with one another by using their
“ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from using the ballot
pool list servers.) The list servers for this project are:
•

Definition of BES ballot:
bp-2010-17_BES_Def_in@nerc.com

•

Detailed Information to Support an Exception Request form:
bp-2010-17_TechInfo_BES_in@nerc.com

Instructions for Submitting Comments
Please use this electronic comment form to submit comments on the Definition of Bulk Electric System. Please
use this separate electronic comment form to submit comments on the draft form application form titled
Detailed Information to Support an Exception Request.
If you experience any difficulties in using either of these electronic forms, please contact Monica Benson at
monica.benson@nerc.net. An off-line, unofficial copy of each comment form is posted on the project page:
Background
On November 18, 2010 FERC issued Order 743 (amended by Order 743A) and directed NERC to revise the
definition of Bulk Electric System so that the definition encompasses all Elements and Facilities necessary for
the reliable operation and planning of the interconnected bulk power system. Additional specificity will reduce
ambiguity and establish consistency across all Regions in distinguishing between BES and non-BES Elements
and Facilities.
In addition, NERC was directed to develop a process for identifying any Elements or Facilities that should be
excluded from the BES. NERC is working to address these directives with two activities – the definition of
Bulk Electric System (BES) is being revised through the standard development process and a BES Definition
Exception Process is being developed as a proposed modification to the Rules of Procedure. The work of the
BES Definition Exception Process has been publicly posted at:
http://www.nerc.com/filez/standards/Rules_of_Procedure-RF.html. The Rules of Procedure team expects to
post the next draft of its proposed addition to the Rules of Procedure (Appendix 5C – BES Exception Process)
in September.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement
Project 2010-17 Definition of Bulk Electric System

Two Ballot Windows Now Open September 30 – October 10, 2011
Now available at: https://standards.nerc.net/CurrentBallots.aspx
Two ballots windows are now open for Project 2010-17 Definition of Bulk Electric System (BES). The first is for
the definition of Bulk Electric System, and the second is for a draft application form titled Detailed Information
to Support an Exception Request referenced in the Rules of Procedure Exception Process. Both ballots are
open through 8 p.m. Eastern on Monday, October 10, 2011.
The revised definition of Bulk Electric System, draft application form titled Detailed Information to Support an
Exception Request, associated implementation plan and several informational documents have been posted
on the project page at http://www.nerc.com/filez/standards/Project2010-17_BES.html.
Instructions for Balloting Revisions

Members of each of the two ballot pools associated with this project may log in and submit their votes for
both the definition and the Detailed Information to Support an Exception Request from the following page:
https://standards.nerc.net/CurrentBallots.aspx.
Special Instructions for Submitting Comments With a Ballot

Comments submitted with ballots are extremely valuable to help the drafting team revise its work. In an
effort to reduce the burden on stakeholders providing comments, the drafting team requests that all
comments (both those submitted with a ballot and those submitted by stakeholders not balloting) be
submitted through the electronic comment forms posted at:
https://www.nerc.net/nercsurvey/Survey.aspx?s=e82643bb1de1434c9834c69757faa8d0
https://www.nerc.net/nercsurvey/Survey.aspx?s=9995ac42ce2644d9aebc87f58dd166ad
This will ensure that stakeholders only provide a single set of comments, but have an opportunity to notify the
drafting team if they have provided comments.
When submitting a ballot with comments, submit the comments through the electronic form and then
simply record a “Comments submitted” in the comments field of the ballot to indicate that comments were
submitted.
Please note that comments submitted during the formal comment period and the ballot use the same
electronic form, and it is NOT necessary for ballot pool members to submit more than one set of comments
(one during the comment period and a second with a ballot).

Next Steps

The drafting team will consider all comments received, and decide whether to make additional revisions to the
definition and Detailed Information to Support an Exception Request. The drafting team is working to meet
the regulatory deadline in FERC Orders 743 and 743A (filing by January 25, 2012).
The Standards Committee and NERC Board of Trustees have recommended that the drafting team address
issues such as generation thresholds in a second phase of this project. This approach will ensure that the
drafting team has sufficient time to adequately consider and develop a sound technical basis for an approach,
and will allow the drafting team to meet the regulatory deadline in FERC Orders 743 and 743A (filing by
January 25, 2012). The drafting team has posted a draft Supplemental Standards Authorization Request (SAR)
for information purposes only; the SAR will be posted for comment at a future time. Additional information
about the project, including a Fact Sheet and additional informational documents, has been posted on the
project webpage at http://www.nerc.com/filez/standards/Project2010-17_BES.html.
Project Background

On November 18, 2010 FERC issued Order 743 (amended by Order 743A) and directed NERC to revise the
definition of Bulk Electric System so that the definition encompasses all Elements and Facilities necessary for
the reliable operation and planning of the interconnected bulk power system. Additional specificity will reduce
ambiguity and establish consistency across all Regions in distinguishing between BES and non-BES Elements
and Facilities.
In addition, NERC was directed to develop a process for identifying any Elements or Facilities that should be
excluded from the BES. NERC is working to address these directives with two activities – the definition of Bulk
Electric System is being revised through the standard development process and a BES Definition Exception
Process is being developed as proposed modifications to the Rules of Procedure. The proposed modifications
have been posted for a comment period through October 27, 2011. The work of the BES Definition Exception
Process has been publicly posted at: http://www.nerc.com/filez/standards/Rules_of_Procedure-RF.html.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement

Project 2010-17 BES Definition
Two Ballot Pool Windows Open August 26 – September 26, 2011
Two Formal Comment Periods Open August 26 – October 10, 2011
Two Ballot Windows Open September 30 – October 10, 2011
Available tomorrow at: https://standards.nerc.net/BallotPool.aspx
The Definition of Bulk Electric System Standard Drafting Team (DBES SDT) has posted a second draft of the
Definition of Bulk Electric System (BES) and associated implementation plan for a formal 45-day comment
period, through 8 p.m. Eastern on Monday, October 10, 2011.
The Definition of Bulk Electric System Standard Drafting Team (DBES SDT) has also posted a draft
application form titled Detailed Information to Support an Exception Request referenced in the Rules of
Procedure Exception Process for a formal 45-day comment period, through 8 p.m. Eastern on Monday,
October 10, 2011. (Note that the information contained in this draft form includes revisions made to the
Technical Principles for Supporting BES Exceptions that was posted for comment in May and June 2011.)
A separate team is working with NERC to draft a new Appendix 5C to NERC’s Rules of Procedure to address
the process for requesting BES exceptions. This team will be posting the Rules of Procedure changes for
stakeholder comment in September. The comment period for the Rules of Procedure changes will overlap the
comment period for the definition and application form, to provide an opportunity for stakeholders to review all
three documents to understand how they will work together.
Clean and redline versions of the definition and associated implementation plan, along with a technical
justification for the Local Network exclusion and a clean version of the application form titled Detailed
Information to Support an Exception Request have been posted on the project page at:
http://www.nerc.com/filez/standards/Project2010-17_BES.html. The format of the application form titled
Detailed Information to Support an Exception Request has changed substantially since the first posting, making
a redline impractical, so none has been provided.
The Standards Committee and NERC Board of Trustees have recommended that the drafting team address
issues such as generation thresholds in a second phase of this project. This approach will ensure that the
drafting team has sufficient time to adequately consider and develop a sound technical basis for an approach,
and will allow the drafting team to meet the regulatory deadline in FERC Orders 743 and 743a (filing by
January 25, 2012). The drafting team has posted a draft Supplemental Standards Authorization Request (SAR)
for information purposes only; the SAR will be posted for comment at a future time.

Ballot Pools Forming
During the first 30 days of the comment period, two separate ballot pools will be formed: one for balloting the
Definition of Bulk Electric System, and a second for balloting the application form titled Detailed Information
to Support an Exception Request. The ballot pool windows will be open from Friday, August 26 through 8
a.m. Eastern on Monday, September 26, 2011.
During the final 10 days of the comment period, two separate initial ballots will be conducted, one for the
Definition of the Bulk Electric System, and a second for the application form titled Detailed Information to
Support an Exception Request. The ballot windows will begin on Friday, September 30th and end at 8 p.m.
Eastern on Monday, October 10, 2011.
Instructions for Joining Ballot Pools
Registered Ballot Body members must join each of the ballot pools to be eligible to vote in the upcoming
ballots at the following page: https://standards.nerc.net/BallotPool.aspx
During the pre-ballot window, members of each ballot pool may communicate with one another by using their
“ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from using the ballot
pool list servers.) The list servers for this project are:
•

Definition of BES ballot:
bp-2010-17_BES_Def_in@nerc.com

•

Detailed Information to Support an Exception Request form:
bp-2010-17_TechInfo_BES_in@nerc.com

Instructions for Submitting Comments
Please use this electronic comment form to submit comments on the Definition of Bulk Electric System. Please
use this separate electronic comment form to submit comments on the draft form application form titled
Detailed Information to Support an Exception Request.
If you experience any difficulties in using either of these electronic forms, please contact Monica Benson at
monica.benson@nerc.net. An off-line, unofficial copy of each comment form is posted on the project page:
Background
On November 18, 2010 FERC issued Order 743 (amended by Order 743A) and directed NERC to revise the
definition of Bulk Electric System so that the definition encompasses all Elements and Facilities necessary for
the reliable operation and planning of the interconnected bulk power system. Additional specificity will reduce
ambiguity and establish consistency across all Regions in distinguishing between BES and non-BES Elements
and Facilities.
In addition, NERC was directed to develop a process for identifying any Elements or Facilities that should be
excluded from the BES. NERC is working to address these directives with two activities – the definition of
Bulk Electric System (BES) is being revised through the standard development process and a BES Definition
Exception Process is being developed as a proposed modification to the Rules of Procedure. The work of the
BES Definition Exception Process has been publicly posted at:
http://www.nerc.com/filez/standards/Rules_of_Procedure-RF.html. The Rules of Procedure team expects to
post the next draft of its proposed addition to the Rules of Procedure (Appendix 5C – BES Exception Process)
in September.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement
Project 2010-17 Definition of Bulk Electric System
Initial Ballot Results
Now available
Ballot Results for Definition of Bulk Electric System

The two ballots windows for Project 2010-17 Definition of Bulk Electric System (BES): the first for the
definition of Bulk Electric System and associated implementation plan, and the second for the draft
application form titled Detailed Information to Support an Exception Request referenced in the Rules of
Procedure Exception Process closed at 8 p.m. Eastern on Monday, October 10, 2011.
Voting statistics for each ballot are listed below, and the Ballot Results Web page provides a link to the
detailed results.
BES Definition

Technical Criteria to Support a BES Exception
Request

Quorum: 92.97%

Quorum: 89.53%

Approval: 71.68%

Approval: 64.03%

Next Steps

The drafting team will consider all comments received, and decide whether to make additional
revisions to the definition of Bulk Electric System, the associated implementation plan, and the
application form titled Detailed Information to Support an Exception Request referenced in the Rules of
Procedure Exception Process. The drafting team is working to meet the regulatory deadline
established in FERC Orders 743 and 743A (filing by January 25, 2012).
The Standards Committee and NERC Board of Trustees have recommended that the drafting team
address issues such as generation thresholds in a second phase of this project. This approach will
ensure that the drafting team has sufficient time to adequately consider and develop a sound technical
basis for an approach, and will allow the drafting team to meet the regulatory deadline in FERC Orders
743 and 743A (filing by January 25, 2012). The drafting team has posted a draft Supplemental
Standards Authorization Request (SAR) for information purposes only; the SAR will be posted for
comment at a future time. Additionally, the drafting team has posted a Fact Sheet, which provides an
up to date review of the project scope, project plan - phased approach, current status and upcoming
events, on the project webpage.

Project Background

On November 18, 2010 FERC issued Order 743 (amended by Order 743A) and directed NERC to revise
the definition of Bulk Electric System so that the definition encompasses all Elements and Facilities
necessary for the reliable operation and planning of the interconnected bulk power system. Additional
specificity will reduce ambiguity and establish consistency across all Regions in distinguishing between
BES and non-BES Elements and Facilities.
In addition, NERC was directed to develop a process for identifying any Elements or Facilities that
should be excluded from the BES. NERC is working to address these directives with two activities – the
definition of Bulk Electric System is being revised through the standard development process and a BES
Definition Exception Process is being developed as proposed modifications to the Rules of Procedure.
The proposed modifications have been posted for a comment period through October 27, 2011. The
work of the BES Definition Exception Process has been publicly posted at:
http://www.nerc.com/filez/standards/Rules_of_Procedure-RF.html.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. For more information or assistance,
please contact Monica Benson at monica.benson@nerc.net.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Initial Ballot Results Project 2010-17

2

NERC Standards

Newsroom  •  Site Map  •  Contact NERC

Advanced Search

User Name

Ballot Results

Ballot Name: Project 2010-17 BES Definition_Initial Ballot_in

Password

Ballot Period: 9/30/2011 - 10/10/2011
Ballot Type: Initial

Log in

Total # Votes: 410

Register

Total Ballot Pool: 441
Quorum: 92.97 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
71.68 %
Vote:
Ballot Results: The SDT will review comments to determine the next process step.

 Home Page
Summary of Ballot Results

Affirmative
Segment

1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight

102
11
125
35
86
51
1
11
12
7
441

#
Votes

1
1
1
1
1
1
0.1
0.9
1
0.6
8.6

#
Votes

Fraction

59
5
88
28
51
34
1
8
5
5
284

Negative
Fraction

0.641
0.5
0.793
0.903
0.689
0.739
0.1
0.8
0.5
0.5
6.165

Abstain
No
# Votes Vote

33
5
23
3
23
12
0
1
5
1
106

0.359
0.5
0.207
0.097
0.311
0.261
0
0.1
0.5
0.1
2.435

6
1
3
3
4
2
0
1
0
0
20

4
0
11
1
8
3
0
1
2
1
31

Individual Ballot Pool Results

Segment

1
1
1
1
1
1
1
1

Organization

Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Balancing Authority of Northern California
NCR11118
Baltimore Gas & Electric Company

Member

Ballot

Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
James Armke
Kevin Smith
Gregory S Miller

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d262178d-6deb-4b81-932d-b37c2baa06bd[10/12/2011 9:35:07 AM]

Comments

Negative
Negative
Negative
Affirmative
Negative
Abstain

View
View
View
View
View

Negative

View

Affirmative

View

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Power Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lakeland Electric
Lee County Electric Cooperative
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
Memphis Light, Gas and Water Division
Metropolitan Water District of Southern
California
Mid-Continent Area Power Pool
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid
New Brunswick Power Transmission
Corporation
New York Power Authority
North Carolina Electric Membership Corp.
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company

Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
Dale Bodden
Michael B Bax
Kevin L Howes

Abstain
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
Negative

Chang G Choi

Affirmative

Danny McDaniel
Paul Morland
Christopher L de Graffenried
Stuart Sloan
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

Bob Solomon

Affirmative

Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza

Negative
Negative
Affirmative
Affirmative

Michael Moltane

Affirmative

Walter Kenyon
Michael Gammon
Larry E Watt
John W Delucca
Robert Ganley
Ly M Le
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Allan Long

Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Negative
Affirmative

Ernest Hahn

Affirmative

View

Larry E. Brusseau
Terry Harbour
Richard Burt
Tim Reed
Mark Ramsey
Saurabh Saksena

Abstain
Negative
Affirmative
Affirmative
Negative

View
View
View

Randy MacDonald

Negative

Arnold J. Schuff
Gary Ofner
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d262178d-6deb-4b81-932d-b37c2baa06bd[10/12/2011 9:35:07 AM]

Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative

View

View
View

View

View

View
View

View
View

View
View
View
View

View
View
View

View
View

NERC Standards
1
1
1
1
1
1
1
1

1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2

PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
South Texas Electric Cooperative
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Transmission Agency of Northern California
Tri-State G & T Association, Inc.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
Alberta Electric System Operator

2

BC Hydro

2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
BC Hydro and Power Authority
Benton Rural Electric Association
Big Bend Electric Cooperative, Inc.
Blachly-Lane Electric Co-op
Blue Ridge Electric
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Electric Power Cooperative
Central Hudson Gas & Electric Corp.
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Cheney
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs

1

3
3
3
3
3
3
3
3
3
3
3

Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown

Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

View

Affirmative

Dale Dunckel

Affirmative

Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Richard McLeon
James Jones
Noman Lee Williams
Beth Young
Larry Akens
Bryan Griess
Tracy Sliman
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Michelle Denike
Mark B Thompson
Venkataramakrishnan
Vinnakota
Richard K Vine
Charles B Manning
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Pat G. Harrington
Clint Gerkensmeyer
Benjamin Friederichs
Bud Tracy
James L Layton
Rebecca Berdahl

Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Abstain
Affirmative

Dave Markham

Affirmative

Ralph J Schulte
Thomas C Duffy
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Joe Noland
Lynne Mila
Linda Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin

Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d262178d-6deb-4b81-932d-b37c2baa06bd[10/12/2011 9:35:07 AM]

View

View
View
View
View
View
View
View

View
View
View
View

View

Abstain
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Negative

View
View
View
View
View
View

View

Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative

Negative
Abstain
Affirmative

View

View
View
View
View
View
View
View
View
View
View

NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

City of McMinnville
City of Redding
City of Ukiah
Clatskanie People's Utility District
Clay Electric Cooperative
Clearwater Power Co.
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Dominion Resources Services
Douglas Electric Cooperative
Duke Energy Carolina
East Kentucky Power Coop.
Fall River Rural Electric Cooperative
Fayetteville Public Works Commission
FirstEnergy Energy Delivery
Flathead Electric Cooperative
Florida Municipal Power Agency
Florida Power Corporation
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Idaho Falls Power
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Kootenai Electric Cooperative
La Plata Electric Association
Lakeview Light & Power
Lane Electric Cooperative, Inc.
Lincoln Electric Cooperative, Inc.
Lincoln Electric System
Lost River Electric Cooperative
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
Manitowoc Public Utilities
MidAmerican Energy Co.
Mission Valley Power
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Northern Lights Inc.
Northern Wasco County People's Utility
District (PUD)
NW Electric Power Cooperative, Inc.
Okanogan County Electric Cooperative, Inc.
Omaha Public Power District

John C Dietz
Bill Hughes
Colin Murphey
Brian Fawcett
Howard M. Mott Jr.
Dave Hagen
Michelle A Corley
Lisa Cleary
Bruce Krawczyk
Peter T Yost
CJ Ingersoll
Richard Blumenstock
Roman Gillen
Roger Meader
Russell A Noble
Jose Escamilla
Michael R. Mayer
Michael F. Gildea
Dave Sabala
Henry Ernst-Jr
Patrick Woods
Bryan Case
Allen R Wallace
Stephan Kern
John M Goroski
Joe McKinney
Lee Schuster
William N. Phinney
Wesley W Gray
Sam Kokkinen
Shane Sweet
William Bush
David Kiguel
Richard Malloy
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Dave Kahly
Ronald Meier
Robert Truesdell
Rick Crinklaw
Michael Henry
Jason Fortik
Richard Reynolds
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas E Reed
Thomas C. Mielnik
Kerry Wiedrich
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
Skyler Wiegmann
William SeDoris
Jon Shelby

Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Abstain
Negative
Affirmative
Affirmative

Paul Titus

Affirmative

David McDowell
Ray Ellis
Blaine R. Dinwiddie

Negative
Affirmative
Negative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d262178d-6deb-4b81-932d-b37c2baa06bd[10/12/2011 9:35:07 AM]

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative

View
View
View

View
View
View
View
View
View

View
View

View
View
View
View

View
View

View

View
View
View

View

View
View
View
View
View
View

View

View

NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4

Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Clallam County
Public Utility District No. 1 of Franklin County
Public Utility District No. 2 of Grant County
Raft River Rural Electric Cooperative
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salem Electric
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Southern California Edison Co.
Springfield Utility Board
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Umatilla Electric Cooperative
Vigilante Electric Cooperative
West Oregon Electric Cooperative, Inc.
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
American Public Power Association
Arkansas Electric Cooperative Corporation
Central Lincoln PUD
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
National Rural Electric Cooperative
Association
North Carolina Eastern Municipal Power
Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Pacific Northwest Generating Cooperative
Public Power Council
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County

David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
John Apperson
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
David Proebstel
Linda Esparza
Greg Lange
Heber Carpenter
Eddy Reece
Thomas M Haire
James Leigh-Kendall
Anthony Schacher
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
David Schiada
Jeff Nelson
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Steve Eldrige
Dave Alberi
Marc Farmer
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Ronnie Frizzell
Shamus J Gamache
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Bob C. Thomas
Diana U Torres
Jack Alvey
Christopher Plante
Richard Comeaux
Joseph DePoorter
Spencer Tacke
Barry R. Lawson

Negative
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Abstain

Cecil Rhodes

Affirmative

Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Aleka K Scott
Nancy Baker
Henry E. LuBean

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

John D Martinsen

Affirmative

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NERC Standards
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Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Transmission Access Policy Study Group
Western Montana Electric G&T
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Grand Island
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Covanta Energy
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
East Kentucky Power Coop.
Electric Power Supply Association
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Michigan Public Power Agency
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.

Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
William Gallagher
William Drummond
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Brad Haralson
Clement Ma
George Tatar

Negative
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Affirmative
Negative
Affirmative
Negative
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Negative
Abstain
Affirmative

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Mike D Kukla
Francis J. Halpin
Chifong Thomas
Daniel Mason
Jeanie Doty
Jeff Mead
Paul Cummings

Negative
Negative
Affirmative
Negative
Abstain
Affirmative

Max Emrick

Affirmative

Brian Horton
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Samuel Cabassa
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Stephen Ricker
John R Cashin
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Alan Beckham
John J Babik
Mike Blough
James M Howard
Dennis Florom
Kenneth Silver
Tom Foreman
S N Fernando

Affirmative
Affirmative
Affirmative
Affirmative
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Negative

David Gordon
Steven Grego
Gary Carlson
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson

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Negative
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Negative
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NERC Standards
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Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Westar Energy
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
MidAmerican Energy Co.
Muscatine Power & Water
New York Power Authority
North Carolina Municipal Power Agency #1
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project

Richard Kinas
Stacie Hebert
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Tim Hattaway
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Bo Jones
Linda Horn
Leonard Rentmeester
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daniel Prowse
Dennis Kimm
John Stolley
William Palazzo
Matthew Schull
Joseph O'Brien
Alan Johnson
David Ried
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Claire Warshaw
Steven J Hulet

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NERC Standards
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Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Tacoma Public Utilities
Tampa Electric Co.
Tenaska Power Services Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.

INTELLIBIND
JDRJC Associates
Montana Consumer Counsel
Pacific Northwest Generating Cooperative
Transmission Strategies, LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
Alabama Public Service Commission
California Energy Commission
Central Lincoln PUD
Commonwealth of Massachusetts Department
of Public Utilities
Michigan Public Service Commission
National Association of Regulatory Utility
Commissioners
New Hampshire Public Utilities Commission
New York State Department of Public Service
Oregon Public Utility Commission
Pennsylvania Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Michael C Hill
Benjamin F Smith II
John D Varnell
Marjorie S. Parsons

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Affirmative
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Peter H Kinney
David F. Lemmons
Frank R. McElvain
Edward C Stein
Merle Ashton
Roger C Zaklukiewicz
James A Maenner
Kevin Conway
Jim Cyrulewski
Larry Nordell
Margaret Ryan
Bernie M Pasternack
Brian Evans-Mongeon
Terry Volkmann
John Free
William M Chamberlain
Bruce Lovelin

Affirmative
Affirmative
Affirmative
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Donald Nelson

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Donald J Mazuchowski
Diane J Barney
Michael Harrington
Thomas Dvorsky
Jerome Murray
darren gill
Philip Riley
Ric Campbell
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Stacy Dochoda
Donald G Jones
Steven L. Rueckert

Copyright © 2010 by the North American Electric Reliability Corporation.  :  All rights reserved.
A New Jersey Nonprofit Corporation

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Individual or group. (113 Responses)
Name (82 Responses)
Organization (82 Responses)
Lead Contact (31 Responses)
Contact Organization (31 Responses)
Question 1 (108 Responses)
Question 1 Comments (113 Responses)
Question 2 (103 Responses)
Question 2 Comments (113 Responses)
Question 3 (102 Responses)
Question 3 Comments (113 Responses)
Question 4 (101 Responses)
Question 4 Comments (113 Responses)
Question 5 (99 Responses)
Question 5 Comments (113 Responses)
Question 6 (103 Responses)
Question 6 Comments (113 Responses)
Question 7 (106 Responses)
Question 7 Comments (113 Responses)
Question 8 (97 Responses)
Question 8 Comments (113 Responses)
Question 9 (104 Responses)
Question 9 Comments (113 Responses)
Question 10 (102 Responses)
Question 10 Comments (113 Responses)
Question 11 (103 Responses)
Question 11 Comments (113 Responses)

Group
Gerald Beckerle
Ameren
Yes
The SERC OC Standards Review Group agrees to the clarifying changes to the core definition in
general; however, we maintain that 200kV and above is the correct bright line for the Bulk Electric
System.
Yes
We agree in general with the revisions to the specific inclusions for transformers in I1; however, we
believe the transformer voltage level should be 200kV or above.
Yes
We agree in general with the revisions to I2 for generation; however, we maintain that 200kV and
above is the correct bright line for the Bulk Electric System.
No
We agree with the changes but believe clarity would be added by changing the word “identified” to
“designated”.
Yes
No
We feel that this inclusion should be limited to dynamic devices with an aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) connected through a common point.
Yes
We suggest the wording “non-retail generation’ should be clarified with an explanation of why it is
used in this exclusion.
No

Clarification needs to be provided for what is meant by E2 (ii), regarding generation on the
customer’s side of the retail meter; otherwise we have trouble developing a position on this question.
No
We would agree with the exclusion if the wording of the exclusion includes the following phrase (in
quotation marks) added at the end of E3 b): Power flows only into the LN: The LN does not transfer
energy originating outside the LN for delivery through the LN “under normal operating conditions”.
Yes
Yes
The definition of the BES is referenced in several existing standards and the Statement of Compliance
Registry Criteria. The SERC OC standards Review Group is concerned how this revised definition will
impact entity registration, i.e., how will the revised definition be integrated into the Compliance
Registry Criteria. The implementation plan should include how the integration is going to occur. The
Rules of Procedure exception process should be further defined or referenced in this definition. “The
comments expressed herein represent a consensus of the views of the above named members of the
SERC OC Standards Review Group only and should not be construed as the position of SERC
Reliability Corporation, its board or its officers.”
Individual
Doug Hohlbaugh
FirstEnergy Corp.
Yes
However, consider changing the last sentence to read "This does not include facilities operated at less
than 100kV, unless modified below, which are are used in the local sub-transmission and distribution
of electric energy."
Yes
Yes
Yes
We agree with the team's conclusion to remove cranking paths from the BES definition since NERC
(i.e. EOP standards) specifically address reliability matters associated with cranking paths. Although
we believe item I3 (blackstart unit) is unnecessary as part of the BES Definition, we will not object to
its inclusion. A blackstart unit is a facility necessary for BES restoration, but not necessarily required
to be included within the BES Definition.
Yes
Yes
While we do not object to I5, we question its need based on item I2 and believe I2 also covers this
item
Yes
No
We suggest striking item "ii"
Yes
Yes
Yes
FE supports the SDT's phased project approach which was well articulated in the NERC BES Definition
Fact Sheet
Individual

John Bee
Exelon
Yes
Yes
Yes
Yes

Yes
Yes
Yes
Yes
Yes
No
Individual
Gary Carlson
Michigan Public Power Agency
Yes
The Michigan Public Power Agency (MPPA) believes the SDT continues to make substantial progress
towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly improves
both the existing definition and the SDT’s previous proposal. MPPA therefore strongly supports the
new definition, although our support is conditioned on: (1) A workable Exceptions process being
developed in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on
Phase II of the standards development process in accordance with the SAR recently put forward by
the SDT, which would address a number of important technical issues that have been identified in the
standards development process to date. MPPA strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100 kV or higher and Real Time and Reactive Power resources connected at 100 kV or
higher”). (2) The exclusion for Local Distribution Facilities. As the starting point for the BES definition,
MPPA supports use of the phrase “all Transmission Elements” and the qualifying sentence: “This does
not include facilities used in the local distribution of electric energy.” This language helps ensure that
FERC, NERC, and the Regional Entities (“REs”) will act within the jurisdictional constrains Congress
placed in Section 215 of the Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally
excluded “facilities used in the local distribution of electric energy” from the keystone “bulk-power
system” definition. 16 U.S.C. § 824o(a)(1). Including the same language in the definition helps
ensure that entities involved in enforcement of reliability standards will act within their statutory
limits. In addition, as a practical matter, inclusion of the language will help focus both the industry
and responsible agencies on the high-voltage interstate transmission system, where the reliability
problems Congress intended to regulate – “instability, uncontrolled separation, [and] cascading
failures,” 16 U.S.C. § 824o(a)(4) – will originate. At the same time, level-of-service issues arising in

local distribution systems will be left to the authority of state and local regulatory agencies and
governing bodies, just as Congress intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local
authorities enforcement of standards for adequacy of service). MPPA also believes the use of the
phrase “Transmission Elements” as the starting point for the base definition is desirable because both
“Transmission” and “Elements” are already defined in the NERC Glossary of Terms Used, and the term
“Transmission” makes clear that the BES includes only Elements used in Transmission and therefore
excludes Elements used in local distribution of electric power. MPPA believes this was one of the many
key elements addressed by FERC in Order No. 743 and reinforced by FERC Order No. 743A and has
been missing from the previous definition as well as the original definition being used since
Compliance efforts commenced in June, 2007 . Because of this lack of clarity MPPA has had numerous
discussions with the region regarding all 17 of our member’s connection to the TO/TOP in Michigan.
Our discussions have resulted in defending 6 of our members specifically from the “Bright Line
definition” path while having no tools in our tool box to substantiate our exclusion. When a small
municipality with a peak load of 12.6 MW and no generation must be defended from a TO and/or TOP
registration just because of its connection to it’s TO/TOP the process requires needed adjustment for
clarity. This was too small to even qualify as a DP under the Statement of Compliance Registry
Criteria but must have to defend itself from a TO/TOP registration issue. (3) Appropriate Generator
Thresholds. In the standards development process, it has become apparent that the thresholds for
classifying generators as BES in the current NERC Statement of Compliance Registry Criteria (“SCRC”)
(20 MVA for individual generators, 75 MVA for multiple generators aggregated at a single site), which
predate the adoption of FPA Section 215, were never the product of a careful analysis to determine
whether generators of that size are necessary for operation of the interconnected bulk transmission
system. Ideally, such an analysis would be conducted as part of the current standards development
process. A member of MPPA has been involved in a registration issue and it has a 3rd party study
conducted by a nation consulting firm showing for the MISO area, generation levels of 100 MVA and
300 MVA aggregate or above are below the standard calculation mathematical significant impact
criteria for static and dynamic planning protocol. MPPA recognizes that, given the deadlines imposed
by FERC in Order No. 743, it will not be possible for the SDT to conduct such an analysis within the
time available. Accordingly, MPPA agrees with the approach taken by the SDT, which is to propose a
Phase II of the standards development process that would address the generator threshold issue and
several other technical issues that have arisen during the current process. As long as Phase II
proceeds expeditiously, MPPA is prepared to support the BES definition as proposed by the SDT. While
MPPA strongly supports the overall approach adopted by the SDT and much of the specific language
incorporated into the second draft of the BES definition, we believe the second draft would benefit
from further clarification or modification in a number of respects, most of which are detailed in our
subsequent answers. Our support for the definition is not contingent upon these changes being
adopted. Further, we believe a workable Exclusion Process is essential for a BES Definition that will
meet the legal requirements of FPA Section 215, especially for systems operating in the Eastern
Interconnection. That being said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Eastern Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
MPPA will support the SDT’s proposal. Finally, we suggest that the SDT address the circumstances
when a facility is covered by both an Inclusion and an Exclusion. We note that some of the inclusions
already contain language addressing this question. For example, Inclusion 1 indicates that
transformers falling within the specified parameters are part of the BES “. . . unless excluded under
Exclusions E1 or E3.” Where it is not already included, similar language should be included in the
other Inclusions and/or Exclusions to explain whether the SDT intends the Inclusions or the
Exclusions to predominate in situations where facilities might be covered by both. We suggest
clarifying language in our comments to I1 and I4 below.
Yes
MPPA supports the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As MPPA understands it, the BES intends
to include transformers only if both the primary and secondary terminals operate at 100 kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution

loads, and which therefore function as distribution rather than transmission facilities. MPPA believes
the SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100 kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. There are many different configurations of transformers and other equipment that may lie
at the juncture between the BES and non-BES systems. If the point of demarcation is designated at
the transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. MPPA has some
members who have been forced to sell of such assets in the hopes of remove the necessity for a
TO/TOP registration path in this region. We also support the incorporation of language (“. . . unless
excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
MPPA supports the changes made in Inclusion 2 and believe that the definition in its current form
adds clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the
previous draft definition into a single Inclusion that addresses the treatment of generation for
purposes of the BES definition. MPPA also supports the SDT’s proposal for a Phase II of the BES
Definition process that would examine the technical justification for these thresholds and that would
establish new thresholds based on a careful technical analysis. It is our understanding that the
generator threshold issue will be vetted through the complete standards development process. We
agree with this approach because if the generator threshold is treated as merely an element of
NERC’s Rules of Procedure, it can be changed with considerably less due process and industry input
than the Standards Development Process. Compare NERC Rules of Procedure § 1400 (providing for
changes to Rules of Procedure upon approval of the NERC board and FERC) with NERC Standards
Process Manual (Sept. 3, 2010) (providing for, e.g., posting of SDT proposals for comment,
successive balloting, and super-majority approval requirements). See also Order No. 743-A, 134 FERC
¶ 61,210 at P 4 (2011) (“Order No. 743 directed the ERO to revise the definition of ‘bulk electric
system’ through the NERC Standards Development Process” (emph. added)). Addressing all aspects
of Phase II through the Standards Development Process will improve the content of the definition by
bringing to bear industry expertise on all aspects of the definition and will ensure that, once firm
guidelines are established, they can be relied upon by both industry and regulators without threat
that they will be changed with little notice and little due process. MPPA also believes further
clarification of the proposed language would be appropriate. The SDT proposes continued reliance
upon the thresholds that are used in the NERC Statement of Compliance Registry Criteria for
registration of Generation Owners and Generation Operators, which is currently 20 MVA for an
individual generation unit and 75 MVA for multiple units on a single site. Conceptually, we are
concerned about this approach because, as we understand it, the purpose of the Compliance Registry
is to sweep in all generators that might be material to the reliable operation of the BES, and not to
definitively determine whether a given generator is, in fact, material to the reliable operation of the
BES. As the SCRC itself states, the SCRC is intended only to identify “candidates for registration.”
SCRC at p.3, § 1 (emph. added). Accordingly, we believe that the generator threshold determined in
Phase II should be incorporated directly into the BES Definition rather than being incorporated by
reference from the SCRC. We also believe that the specific language proposed by the SDT could be
further clarified. The SDT proposes to include generation in the BES if the “Generation resource(s)”
has a “nameplate rating per the ERO Statement of Compliance Registry.” We understand this

language is intended to be a placeholder for the results of the technical analysis that would occur in
Phase II but we believe simply stating that the threshold will be “per the ERO Statement of
Compliance Registry” is ambiguous. Further, for the reasons noted above, we believe the threshold
should be part of the BES Definition, and should not simply be a cross-reference to the SCRC (and,
given the different purposes of the BES Definition and the SCRC, it is not clear that the same
threshold should be used in both). We therefore propose that Inclusion 2 be rewritten to state:
“Qualifying Individual Generation Resources or Qualifying Aggregate Resources connected at a voltage
of 100 kV or above.” Two definitions would then be added to the note at the end of the definition to
read as follows: For purposes of this BES Definition, Qualifying Individual Generation Resources
means an individual generating unit that meets the materiality threshold to be included in this
definition or, in the absence of such a materiality threshold, that meets the gross nameplate capacity
voltage threshold requiring registration of the owner of such a resource as a Generation Owner under
the ERO Statement of Compliance Registry Criteria. For purposes of this BES Definition, Qualifying
Aggregate Generation Resources means any facility consisting of one or more generating units that
are connected at a common bus that meets the materiality threshold to be included in this definition,
or, in the absence of such a threshold, that meets the gross nameplate capacity voltage threshold
requiring registration of the owner of multiple-unit generator as a Generation Owner under the ERO
Statement of Compliance Registry Criteria.. The “materiality threshold” is intended to refer to the
generator threshold developed in Phase II. We suggest using definitions in this fashion for several
reasons. First, we believe the language we suggest more clearly states the intention of the SDT,
which we understand is to classify generation units as part of the BES if they are necessary for
operation of the BES, but to exclude smaller generating units because they are not material to the
operation of the interconnected transmission grid. Second, we believe use of the defined terms better
reflects the intention of the SDT to reserve the specific question about generator thresholds to the
technical analysis that will occur in Phase II without having to revise the BES Definition at the end of
that process. That is, the definitions are designed to allow the SDT to include revised thresholds in the
definition at the conclusion of the Phase II process based upon the technical analysis planned for
Phase II, and the revised thresholds will be automatically incorporated into the BES Definition if the
language we suggest is used. The thresholds used in the SCRC would only be a fall-back, to be used
only until Phase II is completed. Third, the definitions can be incorporated into other parts of the BES
Definition, which will add consistency and clarity. As noted in our answers to several of the questions
below, the specific 75 MVA threshold is retained in several of the Exclusions and Inclusions, and we
believe the industry would be better served if the revised thresholds arrived at after technical analysis
in Phase II are automatically incorporated into all relevant provisions of the BES Definition. There is
no reason for the SDT to continue to rely on the 75 MVA threshold once the analysis planned for
Phase II on the threshold issue is completed. Fourth, the phrase “or that meets the materiality
threshold to be included in this definition” is intended to preserve the SDT’s flexibility to make a
determination that generators below a specific threshold are not “necessary to” maintain the reliability
of the interconnected transmission system, and to incorporate that finding as part of the definition
itself, even if a different threshold is used in the SCRC to identify potential candidates for registration.
Accordingly, our proposed language makes clear that a specific threshold in the definition controls
over any threshold that might be included in the SCRC. For the reasons stated above, we believe is it
highly desirable to include any material threshold in the BES Definition itself rather than relegating
the threshold to the SCRC, which is merely a procedural rule rather than a full-fledged Reliability
Standard. Finally, we agree with the SDT’s decision to examine the question of where the line
between BES and non-BES Elements should be drawn more closely in Phase II under the rubric of
“contiguous vs. non-contiguous BES,” and commend the work of the Project 2010-07 Standards
Drafting Team and the GO-TO Team as a good starting point for the SDT’s analysis on this issue. We
understand Inclusion 2 would classify generators exceeding specific thresholds as part of the BES, but
would not necessarily require facilities interconnecting such generators to be part of the BES. As
discussed more fully in our answer to Question 9, based on extensive technical analysis that has
already been performed by the NERC Project 2010-07 Standards Drafting Team and its predecessor,
the NERC “GO-TO Team,” regulating as part of the BES a dedicated interconnection facility connecting
a BES generator to the interconnected bulk transmission grid will result in an unnecessary regulatory
burden that produces considerable expense for the owner of the interconnection facility with little or
no improvement in bulk system reliability. We also believe the clauses at the end of Inclusion 2 are
somewhat confusing and that greater clarity would be achieved by changing “. . . including the
generator terminals through the high-side of the step-up transformer(s) connected at a voltage of

100 kV or above” so that the Inclusion covers transformers with terminals “connected at a voltage of
100 kV or above, including the generator terminal(s) on the high side of the step-up transformer(s) if
operated at a voltage of 100 kV or above.” MPPA and its members believe it is essential that regional
entities and NERC recognize that “facilities used in the local distribution of electric energy” are not
included in the definition of BES, regardless of the gross individual or gross aggregate nameplate
rating of generation resources. While the addition of the second sentence in the core definition makes
this clarification, MPPA and its members believes it is necessary that regional entities and NERC
recognize that neither this Inclusion nor any of the Inclusions may be used as a basis to compel
registration and compliance in such instances, regardless of the size of the generators. The statutory
exemption of facilities used in the local distribution of electric energy is not limited by generator
number or capacity. NERC’s definitions cannot impose limitations that are not set forth in the statute.
For purposes of the exclusion of facilities that might otherwise meet the definition of BES, the
thresholds for determining what generating resources constitute BES facilities should be modified
from the current levels (gross individual nameplate capacity of 20 MVA or gross aggregate nameplate
rating of 75 MVA). MPPA and its members would support modification of the thresholds to not less
than 100 MVA (gross individual capacity) and 300 MVA (gross aggregate nameplate).
Yes
Yes
MPPA supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which is discussed in more detail in our response to
Question 3. This language, or some equivalent, will preserve the SDT’s ability to revise the 75 MVA
threshold in Phase II, with the result of Phase II included in the BES Definition by operation rather
than requiring further revision of the Definition. More generally, we are not certain what is
accomplished by Inclusion 4 that is not already accomplished by Inclusion 2, which also addresses
whether generation should be defined as BES. The SDT’s stated concern is with variable generation
units such as wind and solar plants. It is not clear to us why this concern is not fully addressed in
Inclusion 2, which addresses multiple generation units connected at a common bus, the configuration
of most variable generation plants with multiple units. We are also concerned that the language, as
proposed, could have unintended consequences and improperly classify local distribution systems as
BES in certain circumstances. This is because multiple distributed generation units could render a
local distribution system a “collector system” and the entire system the equivalent of an aggregated
generation unit, causing the local distribution system to be improperly denied status as a LN. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
MPPA has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Finally, MPPA believes the

appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Without such
analysis either: 1) no threshold except for those connected at 100kV, or: 2) of .95 power factor of a
20 MVA generator, or 6 MVAr and use the fact that most Facility Connection Requirements require a
power factor in the range of between 0.85 – 0.9 lagging to 0.9 – 0.95 leading for a generator. Hence,
a 20 MVA generator (the smallest to meet the registry criteria) will need to absorb a minimum of 6
MVAr and use that as the technical justification.
Yes
MPPA and its members continue to support the radial system exclusion, which is necessary as a legal
matter, because, for example, FERC in Orders No. 743 and 743-A has required that the existing radial
exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. But we believe that further
clarification is necessary. First, the deletion of “originating with an automatic interruption device” is a
step in the right direction. However, “emanates from a single point of connection” could be too
narrowly interpreted (i.e., multiple buses within a single substation could be viewed as multiple points
of connection). MPPA and its members proposes the following modification: “emanates from a single
substation connected to the BES at 100 kV or higher …”. Entities whose only connection emanates
from a single substation and otherwise meet the BES definition should not be denied exclusion under
E1 solely because they connect to multiple buses within a single substation. Additionally, adoption of
“E3- Local Networks” renders specious any argument that clams that connecting to multiple buses
within a single suvstation makes a material difference for reliability purposes since local networks
would have multiple connections anyway. Additionally, it is not clear why it is necessary to include the
note at the end of the revised definition. (“A normally open switching device between radial systems,
as depicted on prints or one-line diagrams for example, does not affect this exclusion.”) This rasies
questions as to what “normally open” means, and wheither the only evidence demonstrating what
“normally open” means will be prints or one-line diagrams. Further, it is not entirely clear what is
meant by the language “does not affect this exclusion”. If the note remains, it should be modified to
read something like, “a normally open switching device between radial systems does not prevent
application of this exclusion.” Finally, the generation threshold limit in E1(b) and E1(c) should be
revised as discussed in response to Q1. Specifically, the proposed threshold of 75 MVA for this
exclusion should be raised to not lessd than 300 MVA in both E1(b) and E1 (c).
Yes
MPPA and its members support the revised language. The language provides clarity regarding the BES
status of customer-owned cogeneration facilities. However, MPPA and its members urge the SDT to
remove the reference to the 75 MVA threshhold and replace it with the defined term “Qualifying
Aggregate Generation Resources” or some equivalent language for the reasons stated in our
responses to Questions 3, 5, and 7. In addition, we are concerned that Exclusion 2 will place local
distribution utilities in a difficult position because, under Exclusion 1 or Exclusion 3 as drafted, they
could lose their status as a Radial System or a Local Network through the actions of a customer
constructing behind-the-meter generation, With respect to Radial Systems, the appearance of behindthe-meter generators could cause the Radial System to exceed the thresholds specified in
subparagraphs (b) and (c) of Exclusion 1 through no fault of the Radial System owner. Similar, a
Local Network could lose its status because behind-the-meter generation could be of sufficient size
that power moves into the interconnected grid in certain hours or under certain contingencies, rather
than moving purely onto the Local Network, as required in subparagraph (b) of Exclusion 3. The
Exclusions for Radial Systems and Local Networks should be made consistent with the Exclusion for
behind-the-meter generation. There is no technical reason to believe the power flowing from a
behind-the-meter customer-owned generator will have less impact on the bulk system than an
equivalent-sized generator owned by a utility operating a Radial System or LN.
Yes
MPPA and its members strongly supports the categorical exclusion of Local Networks (“LNs”) from the
BES. We believe the exclusion is necessary to ensure that the BES definition complies with the
statutory requirement, discussed in our response to Question 1, to exclude all facilities used in the
local distribution of electric power. LNs are, of course, probably the most common form of local
distribution facility. Further, the conversion of radial systems to local distribution networks should be

encouraged because networked systems generally reduce losses, increase system efficiency, and
increase the level of service to retail customers. If the BES definition were to provide an exclusion for
radials without providing a similar exclusion for LNs, however, it would discourage networking local
distribution systems because of the significantly increased regulatory burdens faced by the local
distribution utility if it elected to network its radial facilities. By placing radial systems and LNs on the
same regulatory footing, the proposed definition will ensure that decisions about whether to network
radial systems are made on the basis of costs and benefits to the retail customers served by those
radials, and not on the basis of disparate regulatory treatment. Consumers will ultimately benefit from
the path chosen by the SDT. MPPA and its members also support specific refinements made to the LN
exclusion by the SDT in the current draft of the BES definition. In particular, MPPA supports the
clarification of the purposes of a LN. The current draft states that LNs connect at multiple points to
“improve the level of service to retail customer Load and not to accommodate bulk power transfer
across the interconnected system.” Snohomish supports this change in language because it reflects
the fundamental purposes of a LN and emphasizes one of the key distinctions between LNs and bulk
transmission facilities, namely, that LNs are designed primarily to serve local retail load while bulk
transmission facilities are designed primarily to move bulk power from a bulk source (generally either
the point of interconnection of a wholesale generator or a the point of interconnection with another
bulk transmission system) to one or more wholesale purchasers. MPPA believes further improvement
of the language could be achieved with additional modifications and clarifications. With respect to the
core language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100 kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100 kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
MPPA also believes that subparagraphs (a) and (b) are redundant in the sense that whatever
protection is offered by the generation limit in subparagraph (a) is duplicated by the limit in
subparagraph (b) requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a)
of Exclusion 3 and simply rely on subparagraph (b) because if power only flows into the LN even if it
interconnects more than 75 MVA of generation, the interconnected generation interconnected will
have no significant interaction with the interconnected bulk transmission system. It will only interact
with the LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a
large number of very small distributed generators are interconnected into a LDN, so that the
aggregate capacity of these generators exceeds 75 MVA. However, because the generators are small
and dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN
rather than transmitting power onto the interconnected grid, those generators would not have a
material impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more
clearly drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than
out of it, includes this description: “The LN does not transfer energy originating outside the LN for
delivery through the LN.” We understand this language is intended to distinguish a LN from a link in
the transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is

meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to mean generation that is used by retail customers located
within a LN rather than being exported and sold on wholesale markets outside the LN. We therefore
suggest that the SDT replace the phrase “non-retail generation” with the phrase “generation sold in
wholesale markets and transmitted outside the LN.” Similarly, we are unsure what is meant by the
phrase “the LN and its underlying Elements.” We believe the phrase “and its underlying Elements”
could simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3.
Finally, MPPA believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated
as long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified
as a Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities
that allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
transmission of electricity on the interconnected bulk system. Apart from these specific improvements
that we believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may
need to re-examine certain assumptions that appear to underlie the current draft. Specifically,
subparagraph (a) suggests that if BES generation is embedded within a LN, the LN itself must also be
BES. But two NERC bodies have already addressed similar questions and concluded there is no
technical basis for such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force” were formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. The GO-TO Team concluded that by complying with a handful of reliability
standards, primarily related to vegetation management, reliable operation of the bulk interconnected
system could be protected without unduly burdening the owners of such interconnection systems.
Therefore, there is no reason, according to the GO-TO Team, that dedicated high-voltage
interconnection facilities must be treated as “Transmission” and classified as part of the BES in order
to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO Task
Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most often
not part of the integrated bulk power system, and as such should not be subject to the same level of
standards applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” White Paper
Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at the
Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply
with the same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of the
equipment that actually produces electricity – the generation equipment itself.” Id. We believe that
interconnection of BES generators within a LN is analogous and that, based on the findings of the
Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply because a large
generator is embedded in the LN will result in substantial overregulation and unnecessary expense
with little gain for bulk system reliability. If anything, generation interconnected through a LN is less
likely to produce material impacts on the interconnected bulk transmission system than the
equivalent generator interconnected through a single dedicated line because an LN is interconnected
to the bulk system at several points, so that if one interconnection goes down, power can still flow
from the BES generator to the bulk system on other interconnection points. Where a dedicated
interconnection facility is involved, by contrast, if the interconnection line fails, the generator is
unavailable to the interconnected bulk system. Similarly, we suggest that the SDT re-examine the
assumptions underlying subparagraph (b), which seems to suggest that a local distribution system
cannot be classified as a Local Network if power flows out of that system at any time, even if the
amount is de minimis, the outward flow is only for a few hours a year, or the outward flow occurs
only in an extreme contingency. Accordingly, we suggest that the initial clause of subparagraph (b) be
revised to read: “Except in unusual circumstances, power flows only into the LN.”
Yes
Yes, MPPA and its members support the revised language because retail reactive devices are used to

address local customer or retail voltage issues, rather than voltage issues on the interconnected bulk
grid, and such local devices should therefore be excluded from the BES definition.
No
MPPA and its members extends its thanks to the SDT and to the many industry entities that have
actively participating in the Standards Development Process. MPPA strongly supports the current draft
and believes, with certain refinements discussed in our comments, that the definition will serve the
industry and reliability regulators well for many years to come. In addition, as noted earlier, MPPA is
encouraged that the 20/75 MVA generation thresholds referred to in the NERC Statement of
Compliance Registry Criteria, which have been relied upon by the SDT largely as a matter of
necessity, will be reviewed and a technical assessment will be performed to identify the appropriate
generation unit and plant size threshold to ensure a reliable North America. Finally, we understand
that the Rules of Procedure Team will continue to move forward with developing an Exceptions
Process that will complement the BES Definition and ensure that, to the extent the BES Definition is
over-inclusive, facilities that should not be classified as BES will be excluded from the BES. Because
the Exceptions Process is integral to a workable BES Definition, we support the current process for
moving forward with the Exceptions Process and the BES Definition on parallel paths. We note that
MPPA and its members specifically supports the changes made by the SDT in the “Effective Date”
provision of the BES Definition, which shortens the effective date of the new definition to the
beginning of the first calendar quarter after regulatory approval (as opposed to the first calendar
quarter twenty-four months after regulatory approval), with a 24-month transition period. MPPA
supports this conclusion because it will allow entities seeking deregistration under the terms of the
new BES definition to obtain the benefits of the new definition without an unreasonable wait, while
allowing any entities that may be newly-classified as BES owners or operators sufficient time to come
into compliance with newly-applicable Reliability Standards. MPPA and its members also supports the
24-month transition period for the reasons laid out by the SDT.
Individual
Richard Malloy
Idaho Falls Power
Yes
We generally support the changes made.
Yes
We support the language as drafted.
No
Reliance upon the Registry Criteria falls back to the 20MVA threshold. We believe this threshold is
very low and unnecessarily draws in small entities for which there is no impact to the BES. We
understand the barriers and the volume of tenchnical evidence required for any change and we
therefore have no alternative language to suggest.
Yes
We support the inclusion as drafted.
No
As drafted, it appears to draw in all generation resources that sum to 75 MVA or higher. We question
then if there is value of categorizing every wind turbine on a >75MVA wind farm as a BES asset and,
what would be the unintended consequences. Perhaps language delineating the point of aggregation
as the demarcation point of a BES asset would better serve.
Yes
We have no comments.
Yes
We support the exclusion as drafted.
Yes
We support the exclusion as drafted.
Yes
We support the exclusion as drafted.
Yes

We have no comments.
No
Individual
Anthony Jablonski
ReliabilityFirst
No
This seems very confusing, but should be clear and easy enough for anyone to pickup, read,
understand, apply and arrive at the same conclusion. The term local distribution needs to be either
defined or have some guidance provided on what it is intended to cover. A suggestion for defining
distribution would be that radials and local networks makeup distribution facilities. Radials usually
terminate at distribution or customer substations and local networks are primarily used for
distribution also. The Commission granted NERC the ability to define distribution in Order 743-A,
paragraphs 67-71. It is not clear if the BES is meant to be a contiguous system or not from the
language in the revised definition. ReliabilityFirst Staff believes that the BES should be contiguous,
and therefore, any facilities needed to connect real and reactive resources to the BES need to be
included. To maintain reliability, the BES cannot have pockets of generation that are not connected to
the BES via BES facilities. ReliabilityFirst Staff believes that without including the paths from BES
generators in the BES, the reliable operation of the system could be jeopardized if the paths are
unavailable due to non-compliance to Reliability Standards. For example, wind farm collector systems
at voltages operated at less than 100 kV should be included in the BES for the above reason.
Yes
Yes
No
Blackstart Resource is a defined NERC term, but as outlined in the definition, it could be read to
include the transmission assets that also make up the resource as part of the TOP plan. Is that the
intent? ReliabilityFirst Staff also feels that without including the Cranking Paths, the reliable operation
of the system could be jeopardized if a restoration is required and the Cranking Paths are unavailable
due to non-compliance to Reliability Standards.
No
The term “Dispersed Power Producing Resource” is not a defined term and needs further clarification.
However, I4 is not needed and is already included in I2. I4 does not add any additional facilities that
are not already included in I2. How are “dispersed power producing resources” different from
“generating resources” described in I2? If the intent of I4 is to include wind generators but exclude
wind farm collector systems in the BES, ReliabilityFirst Staff disagrees. To maintain reliability, the BES
cannot have pockets of generation that are not connected to the BES via BES facilities. ReliabilityFirst
Staff believes that without including the paths from BES generators in the BES, the reliable operation
of the system could be jeopardized if the paths are unavailable due to non-compliance to Reliability
Standards. For example, wind farm collector systems at voltages operated at less than 100 kV should
be included in the BES for the above reason. I4 could be deleted.
Yes
No
The term radial must be specifically defined in this application. ReliabilityFirst Staff believes this to
mean a true radial in the sense that an adverse impact by the radial facilities does NOT affect or
impact BES facilities. In the first sentence the word “Element” is capitalized but “transmission” is not,
we believe both terms should be capitalized. The phrase “single point of connection” should have
guidance so that everyone reading this definition reads the single point of interconnection the same.
Some have read this phrase to be a single substation, while others have read this phrase to be one
and only one line or supply (i.e. interconnection point), which is it? The “Note” we disagree with. In
any and all cases if there is any operation or use of the BES, the facilities should be included. By the
wording of this exclusion, one cannot determine if taps (sections of line from a BES transmission line

to a single substation) are intended to be included in the BES or not. More specifically, where does
the radial facility begin and the BES end? This determination was clearer in the previous version of
the definition with the use of the language “…originating with an automatic interruption device…”.
No
It is not clear why “ii” is needed. If the net generation exceeds 75 MVA, then it is included in the BES
whether or not there are ancillary services provided for that generation. Would customer owned
generation less than a net of 75 MVA but greater than 20 MVA be included in the BES if item ii was
not met?
No
ReliabilityFirst Staff proposes to use the LN exclusion as part of the definition of what elements make
up the facilities used in the local “distribution” of electric energy and could be included in the
Exception Process as a criterion for exclusion.
Yes
Yes
This definition needs to be clear and easy enough for anyone to pickup, read, understand, apply and
arrive at the same conclusion on whether the facility or element is included or excluded. This
definition leaves room for continued debate and interpretation. To help make this definition clearer,
ReliabilityFirst Staff has provided a redline version of the core definition under a separate cover (file
titled “Bulk Electric System definition by RFC Staff 10-4-2011”).
Group
David Taylor
NERC
No
The sentence, “This does not include facilities used in the local distribution of electricity,” is a
commentary or statement of objective rather than a definition of what facilities comprise the BES.
Including such information that does not define the facilities to be included or excluded will be a
source of confusion in applying the definition. The BES definition as proposed by the SDT may in fact
include such facilities and as stated in paragraph 37 of Order 743: “Determining where the line
between “transmission” and “local distribution” lies, which includes an inquiry into which lower voltage
“transmission” facilities are necessary to operate the interconnected transmission system, should be
part of the exemption process the ERO develops.” If the drafting team believes that Exclusions E1
through E4 in the definition are sufficient to not include any facilities used in the local distribution of
electricity then those exclusions, and not the aforementioned sentence in the “core definition,” define
the facilities that are not included (i.e., the sentence is unnecessary).
Yes
Yes
The drafting team’s proposed approach for Inclusion I2 (generation), including the reference to the
ERO Statement of Compliance Registry Criteria, is generally acceptable given the scope of this project
and the breaking of the project into two phases. Thresholds for generator MVA rating and
interconnection voltage should be considered in the second phase of this project.
No
The cranking path(s) identified in the Transmission Operator’s restoration plan should be included in
the BES definition.
Yes
Yes
No
While we appreciate the improvement in the text for Exclusion E1, but we continue to believe that E1
should require (i) the normally open switch must not be used to make a parallel connection if the
normally switch is operated at 100 kV or higher and (ii) an automatic interrupting device that is part

of the BES must be provided at the point of interconnection between the radial system and the BES.
Yes
No
While we appreciate the improvement in the text of Exclusion E3, but we continue to believe that E3
should require automatic interrupting devices that are part of the BES must be provided at the points
of interconnection between the Local Network and the BES.
Yes
No
Individual
Colin Anderson
Ontario Power Generation Inc.
No
OPG continues to question the need for the changes required (and costs imposed) as a result of this
new definition. This is particularly true in the NPCC region where an impact based methodology is
being used to determine the set of BES elements. A very clear 100kV bright line, as proposed in this
draft, will dramatically increase the list of generation elements that must meet reliability standards,
without a corresponding increase in wide-area reliability. OPG recommends that the work planned for
phase II, technical justification of the generation and voltage thresholds, should be completed before
implementing the new definition of BES.
Yes
No
OPG does not agree that the question of the 20 MVA (single) versus 75 MVA (aggregate) threshold
should be deferred until a subsequent phase of the standard development process ("Phase II"). This
question should be resolved now. In general, key elements of the development process should not be
parsed out into multiple phases, in hopes that "Standard Development Fatigue" will eliminate critics of
the approach. Further, selecting the generator terminals as the boundary for BES within the
generating station means that the Isolated Phase Bus (IPB), which connects the generator terminals
to the Low Voltage (LV) terminals of the generator step-up (GSU) transformer, is now included as a
BES element. The IPB is operated at low voltage, no more than 22kV, so including it as a BES
element is going beyond the FERC order 743 and 743a. OPG strongly recommends that the BES
boundary be moved to the LV terminals of the GSU transformer.
No
To assure availability of the generation blackstart resources identified in the Transmission Operator’s
Power System Restoration Plan the generators are tested according to the requirements of reliability
standard EOP-009. Blackstart resources are only required post LOBES (Loss of Bulk Electric System)
and in many cases do not contribute to the reliability of the BES under normal operating conditions.
OPG recommends that this inclusion be removed from the new definition of BES.
Yes
No
OPG recommends that the wording of this inclusion be made clear that the BES boundary extends to
the Low Voltage terminals of the transformer, used in the interface connection, and does not include
the static or dynamic reactive power source itself unless it is directly connected to the BES.
No
Non-retail generation needs to be properly defined in the text of the exclusion.
Yes
No

Non-retail generation needs to be properly defined in the text of the exclusion.
Yes
Yes
Further to comments submitted in Question #1, OPG disagrees in general with proceeding to
implement a 100 kV brightline definition in the absence of a properly quantified cost/benefit analysis.
Entities are being asked to incur a high cost for no demonstrated benefit in wide-area reliability.
Group
Guy Zito
Northeast Power Coordinating Council
Yes
No
More specific description is needed for the equipment intended to be included in I1. For example, is it
intended to include autotransformers, PARs, primary, secondary, tertiary windings, etc.? There will be
difficulty applying the definition to facilities without this detail. Suggest rewording to: All transformers
(including auto-transformers, voltage regulators, and phase angle regulators and all windings) with
primary and secondary terminals operated at or above 100kV, and generator step-up (GSU)
transformers with one terminal operated at or above 100KV, unless excluded by E1 or E3.
No
In deference to direction given to the Drafting Team, Inclusion I2 should remove the reference to the
Statement of Compliance Registry Criteria. The current language induces circular arguments without a
true governing document. The definition should drive what appears in the registration criteria. I2
should be revised to read: “Generating resources with a gross nameplate rating of 20MVA or greater,
or generating plant/facility connected at a common bus, with an aggregate nameplate rating of
75MVA or greater and is directly connected to a BES Element.” This is consistent with the proposed I2
and the current Compliance Registry Criteria. Ultimately the definition should be the governing
document and provide the details of what generation should be included. It is understood that Phase
2 of this project will address this.
No
Eliminating I3 should be considered based on the availability and performance expectations of black
start resources being ensured by existing standards, and unless they meet the BES definition under
the I2 inclusion they do not have any reliability impact on BES operation. If I3 is retained, suggest
rewording Inclusion I3 to read as follows: Black start resources material to and designated as part of
the Transmission Operator’s restoration plan.
No
Suggest the term “common point” needs clarification and/or definition (is risk of single mode failure
intended, i.e. where all the resources could be lost for a single event?). Suggest the following
wording: “connected at a common point through a dedicated step-up transformer with a high-side
voltage of 100 KV or above.” Dispersed power producing sources such as wind and solar should not
be included as BES elements because of the variable and intermittent nature of these resources. If
these dispersed power producing resources had dedicated energy storage facilities only then that
could make them BES elements. Generally the collector systems for these resources (from the bulk
transmission system reliability perspective) do not differ from distribution systems which are excluded
from the BES.
No
Technical studies need to be conducted to confirm reactive resource impacts on the reliability of the
BES. The inclusion of reactive resources is a significant expansion of the current BES definition and
therefore requires technical justification for inclusion. Inclusion I5 as written is confusing with a
reference to Inclusion I1 in the definition. Suggest removing references to reactive resources from
Phase 1 until technical justification can be demonstrated (as part of Phase 2).
No
E1 can be simplified by not dividing in three subsets of a, b and c. The end result is that a Radial
system is excluded if it does not have more than 75 MVA aggregate non-retail generation. There

seems to be an error with reference to I3. Black start unit paths are not designated as BES and were
taken out in this version under I3 so E1 and E3 should not reference I3. This contradicts the radial or
LN exclusion from I3. Suggest deleting the reference to I3 in E1 and E3 because this reference is in
contradiction to I3. I3 does not require a path to be BES, but it implied that a radial cannot be
excluded if there is a black start unit on the radial. Further clarification is needed to the language in
the Note referring to the “Normally Open switch”. The E1 reference Note should be re-worded to state
“Radial systems shall be assessed with all normally open switching devices in their open positions.”
Explanatory figures should be included to illustrate the system configurations addressed. Black start
unit paths must be considered in the construction of E1. In E1c, what is meant by “non-retail”?
No
Why are references to Balancing Authority, Generator Owner, and Generator Operator included in E2
which is part of the BES definition? The wording of Exclusion E2 should be consistent with the
Statement of Compliance Registry Criteria in Section III.c.4.
No
What is the technical justification for 300kv and higher? Local Network is capitalized (network not
capitalized at the beginning of E3) throughout E3, yet it is not defined in the NERC Glossary. The
installed generation limit in a Local Network should be addressed in Phase 2. Any studies supporting
E3 should be made available.
No
Consider using other wording to replace “retail”. The statement “owned or operated by the retail
customer” is confusing and arguably inaccurate and should be revised. Refer to comments related to
reactive resources for Question 6 regarding Inclusion I5. Retail and non-retail generation should be
defined.
Yes
Technical bases have not been provided for the proposed definition of the BES. Additionally, the cost
impacts have not been assessed and weighed against the potential benefits of this proposal. There is
confusion arising from the construction and interactions of the Inclusion, and Exclusion sections.
System diagrams, put in a separate guidance document, would help in understanding. The situation
of using Exceptions to understand Exclusions must be avoided. Suggest consider incorporating
Inclusions directly, and leave the Exclusions as is format wise. The Implementation period discusses a
24 month timeframe( the Order suggests 18) from when the standard becomes effective to begin
Compliance obligations. If construction is required to become compliant or meet performance
requirements with standards, or CIP Version 5 standards increase the amount of BES assets this will
be insufficient when considering budgeting, designing, siting requirements, and permitting. Concern
exists over the paradigm that the definition should “mirror” the NERC Compliance Registry Criteria
regarding who is registered. Some RSC members believe the definition should drive any changes to
the registry criteria and not the criteria perpetuating the thresholds in the definition. However, there
is a need to confirm that Phase 2 of this project will address this. The Inclusions and Exclusions listed
need clarifications and perhaps diagrams and accompanying guidelines to clarify and explain the
intent.
Individual
Thomas C. Duffy
Central Hudson Gas & Electric Corporation
Yes
Yes
Yes
Yes
Yes

Yes
Yes
Yes
No
Under the proposed definition, clause E3.b. stipulates that ‘power only flows into the Local Network
(LN): The LN does not transfer energy originating outside the LN for delivery through the LN.’ Clearly,
this is a bright line. The Local Network Exclusion document, however, describes that ‘power flow
“shifts”’ of ‘negligible fraction’ are acceptable. Further, the document acknowledges that parallel flows
through the LN, ‘as governed by the fundamentals of parallel circuits’ will occur. Finally, the document
goes on to exhibit that flows through the LN, however minimal, will result from both power transfer
distribution factor (PTDF) and line outage distribution factor (LODF) analysis. If this is the case, what
bright line criterion should be applied for this Exclusion Principal if no maximum PTDF and/or LODF
are specified?
Yes
Yes
Due to the movement to a phased BES definition development process and assuming the definition is
approved as proposed, there is an urgent need for NERC to provide clear guidance to Registered
Entities regarding how to proceed with facilities and address changes to the NERC Compliance
Registry registration obligations brought in/on by the application of the new definition. The problem
stems from a likely scenario whereby the affected Registered Entities may be faced with an
Implementation Plan and an Exception Request Procedure which must be completed prior to the
completion of the Phase II definition development process. If that is the case, many Registered
Entities will be confronted with either (1) spending large amounts of human and financial resources,
not yet acquired, to address facilities/procedures necessary to address possible new compliance
obligations only to find their efforts rendered unnecessary by the results produced in Phase II or, (2)
waiting until the results of Phase II are provided and risking being found non-compliant and subject to
substantial penalties in the future. Neither option can be viewed as a desirable, or for that matter, an
acceptable position to be placed in.
Group
Charles Long
Entergy Services, Inc.
Yes
Yes
Yes
We are concerned that the generator MVA limits are too low and strongly support addressing this
issue in Phase 2 of this project.
Yes
Yes
Yes
Yes
The SDT needs to clarify what is meant by "non-retail generation." Is this what is commonly referred
to as "customer owned" or "behind-the-meter" generation?
Yes

Yes
The term "non-retail generation" in E3a should be changed to simply "generation."
Yes
No
The comments expressed herein represent a consensus of the views of the above-named members of
the SERC EC Planning Standards Subcommittee only and should not be construed as the position of
SERC Reliability Corporation, its board, or its officers”
Individual
Manny Robledo
City of Anaheim
No
The City of Anaheim recommends either changing the E1 (b) language back to that of the previous
BES definition draft, i.e. 75 MVA or above connected at 100 kV or above, or limit the amount of
generation allowed within a Radial Element or Local Network to 300 MVA or less, which is the amount
of uncontrolled load loss that constitutes a reportable "disturbance" pursuant to EOP-004 and DOE
Form OE-417. If DOE and NERC do not consider a 300 MW uncontrolled loss of load a reportable
event, then why would the potential loss of a 75 MVA of non-critical generator connected at 69 kV
make a Radial Element or Local Network critical to the reliability of the BES? The current ERO
Statement of Compliance Criteria does not require GO/GOP registration for generation connected
below 100 kV as long as it's not critical to the reliability of the BES, i.e. black start, etc., even if the
amount of generation is greater than 75 MVA. There is good reason for this because the mere loss of
75 MVA generator would not affect the reliability of a system as big as the Western Interconnection,
at all, and a fault at say 69 kV would have sufficient impedance not to affect the BES from an
electrical perspective.
Yes
Yes
Yes
Yes
This is OK because the 75 MVA is connected at 100 kV or above.
Yes
No
The City of Anaheim recommends either changing the E1 (b) language back to that of the previous
BES definition draft, i.e. 75 MVA or above connected at 100 kV or above, or limit the amount of
generation allowed within a Radial Element or Local Network to 300 MVA or less, which is the amount
of uncontrolled load loss that constitutes a reportable "disturbance" pursuant to EOP-004 and DOE
Form OE-417. If DOE and NERC do not consider a 300 MW uncontrolled loss of load a reportable
event, then why would the potential loss of a 75 MVA of non-critical generator connected at 69 kV
make a Radial Element or Local Network critical to the reliability of the BES? The current ERO
Statement of Compliance Criteria does not require GO/GOP registration for generation connected
below 100 kV as long as it's not critical to the reliability of the BES, i.e. black start, etc., even if the
amount of generation is greater than 75 MVA. There is good reason for this because the mere loss of
75 MVA generator would not affect the reliability of a system as big as the Western Interconnection,
at all, and a fault at say 69 kV would have sufficient impedance not to affect the BES from an
electrical perspective.
No
Again, 75 MVA should be increased to 300 MVA in E2 for the reasons stated in response to Question
7.

No
Again, 75 MVA should be increased to 300 MVA in E2 for the reasons stated in response to Question
7.
Yes
No
Individual
Deborah J Chance
Chevron U.S.A. Inc.
Yes
Yes. Very good progress was made in the process. The initial overly broad language was inadvertently
including parties that are not necessary to meet the NERC and FERC goals. The current language has
clarified some of the ambiguities.
Yes
No
It is not logical to allow an aggregate of 75 MVA at a single site for multiple generators while
maintaining 20 MVA for a single generator. Further, if a party exceeds export of 75 MVA to meet an
emergency condition on the grid, it should not be a triggering event for BES definition. Parties should
be concerned with keeping the grid operational rather than the adverse effect of exceeding 75 MVA.
Yes
Yes
Yes
Yes
This is very important exclusion for an entity operating in remote areas of the country that provides
distribution service to third parties where utilities are unable or unwilling to serve. While the
distribution is at a low voltage, the power was initially received by the operating entity at a high
voltage.
Yes
This is a very important exclusion for Combined Heat and Power facilities that utilize large amounts of
steam and power, and secure and/or provide their own operating reserves.
Yes
This provision complements E1 in defining the difference between distribution and transmission
Yes
No
Individual
Alice Ireland
Xcel Energy
In general, Xcel Energy supports the changes to the core definition of Bulk Electric System. Some
additional clarification may be required as suggested below under the individual Inclusions or
Exclusions.

No
Xcel Energy believes that this inclusion is still a little vague and could use some clarification. For
instance, if a wind farm has an aggregated capacity greater than 75 MVA (and therefore meets
Inclusion I4) exactly what facilities are included as part of the BES, every turbine, all distribution
transformers and cables, etc. If all equipment is included, what level of detail is required of this BES
facility for modeling purposes, and who is responsible for modeling this system. Or, is the intent to
only include the facilities at the common point of connection, whereby the facility could be modeled as
1 large facility?
No
Xcel Energy believes that some more definition is required to clarify the intent of the note under
Exclusion E1 related to normal open switching device. A direct statement would remove any
ambiguity, such as “a normally open switch in a system that could be interconnected or experience
loop flows will be considered (BES/non BES)”.

Individual
Edwin Tso
Metropolitan Water District of Southern California
Yes
Metropolitan Water District of Southern California (“MWDSC”) generally supports the core definition of
the Bulk Electric System as proposed. However, some of the proposed Inclusions and Exclusions need
to be clarified as identified in questionnaires #6 and #10 below.
Yes
Yes
Yes
Yes
No
Inclusion 5 should be changed to be consistent with the core definition and to clarify Reactive Power
devices. Under I5, the additional phrase "or through a dedicated transformer with a high side voltage
of 100 kV or higher," appears to conflict with the core definition's phrase "and Real Power and
Reactive Power resources connected at 100 kV or higher". For example, if you have a device
connected to a 69Kv system which is used solely for an end-user's load, but the 69kv system is
transformed up to a 115kV system, such device could be included as BES or you would have to define
what is meant by "dedicated. If Reactive Power is meant to agree with the definition under NERC's
Glossary of Terms, there should be consistency and less verbiage. MWDSC also agrees with WECC's
comment that there should be some minimum threshold for Reactive Power devices similar to that
identified for generating resources in Inclusion 2. MWDSC recommends that Inclusion 5 be changed
as follows: I5 - "Reactive Power devices dedicated to support the BES that are connected at 100kV or
higher, or through a transformer that is designated in Inclusion I1."
Yes
Yes
Yes

No
Exclusion 4 appears to limit the devices just to retail customers. However, any end-user load,
including wholesale or retail, should be included. NERC's Glossary of Terms uses the phrase "end-use
customer", not retail customers to describe loads. MWDSC recommends that Exclusion 4 be changed
as follows: E4 - Reactive Power devices owned and operated by an end-use customer solely for its
own use.
No
Individual
Greg Rowland
Duke Energy
Yes
No
For clarity regarding 3 and 4 winding transformers, it should say “primary and at least one secondary
terminal operated at 100 kV or higher.
Yes
Yes
Yes
No
Need to add the exception for exclusions under E1 or E3, and also reword to exclude devices
connected to a transformer winding less than 100 kV unless that is the only connection to that
winding. Suggested rewording of I5 : “Unless excluded under Exclusions E1 or E3, static or dynamic
devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher,
or through a dedicated transformer with a high-side voltage or 100 kV or higher, or through a
transformer winding less than 100 kV that is designated in Inclusion I1 if the winding does not have
any circuits or load connected to it.” This would eliminate having to include a capacitor connected to
the 69 kV winding of a three winding BES transformer such as 230/138/69 kV if that winding had
other connections such as 69 kV circuits. The voltage threshold of 100 kV and above should capture
devices connected to 100 kV or higher windings of transformers designated in Inclusion I1.
Yes
Yes
Yes
Yes
No
Individual
David Proebstel
Clallam County PUD No.1
Yes
The Public Utility District No. 1 of Clallam County (“CLPD”) believes the SDT continues to make
substantial progress towards a clear and workable definition of the Bulk Electric System (“BES”) that
markedly improves both the existing definition and the SDT’s previous proposal. CLPD therefore
strongly supports the new definition, although our support is conditioned on: (1) a workable

Exceptions process being developed in conjunction with the BES definition; and, (2) the SDT moving
forward expeditiously on Phase II of the standards development process in accordance with the SAR
recently put forward by the SDT, which would address a number of important technical issues that
have been identified in the standards development process to date. CLPD strongly supports the
following elements of the revised BES definition: (1) Clarification of how lists of Inclusions and
Exclusions applies: The revised core definition moves the phrase “Unless modified by the lists shown
below” to the beginning of the definition. This change makes clear that the Inclusions and Exclusions
apply to all Elements that would otherwise be included in or excluded from the core definition (i.e.,
“all Transmission Elements operated at 100 kV or higher and Real Time and Reactive Power resources
connected at 100 kV or higher”) and eliminates a latent ambiguity in the first draft of the definition,
discussed further in our comments on the first draft. (2) The exclusion for Local Distribution Facilities.
As the starting point for the BES definition, CLPD supports use of the phrase “all Transmission
Elements” and the qualifying sentence: “This does not include facilities used in the local distribution of
electric energy.” This language helps ensure that FERC, NERC, and the Regional Entities (“REs”) will
act within the jurisdictional constrains Congress placed in Section 215 of the Federal Power Act
(“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in the local distribution
of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C. § 824o(a)(1).
Including the same language in the definition helps ensure that entities involved in enforcement of
reliability standards will act within their statutory limits. In addition, as a practical matter, inclusion of
the language will help focus both the industry and responsible agencies on the high-voltage interstate
transmission system, where the reliability problems Congress intended to regulate – “instability,
uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) – will originate. At the
same time, level-of-service issues arising in local distribution systems will be left to the authority of
state and local regulatory agencies and governing bodies, just as Congress intended. 16 U.S.C. §
824o(i)(2) (reserving to state and local authorities enforcement of standards for adequacy of service).
For similar reasons, Clallam believes use of the phrase “Transmission Elements” as the starting point
for the base definition is desirable because both “Transmission” and “Elements” are already defined in
the NERC Glossary of Terms Used, and the term “Transmission” makes clear that the BES includes
only Elements used in Transmission and therefore excludes Elements used in local distribution of
electric power. (3) Appropriate Generator Thresholds. In the standards development process, it has
become apparent that the thresholds for classifying generators as BES in the current NERC Statement
of Compliance Registry Criteria (“SCRC”) (20 MVA for individual generators, 75 MVA for multiple
generators aggregated at a single site), which predate the adoption of FPA Section 215, were never
the product of a careful analysis to determine whether generators of that size are necessary for
operation of the interconnected bulk transmission system. Ideally, such an analysis would be
conducted as part of the current standards development process. Clallam recognizes that, given the
deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to conduct such an
analysis within the time available. Accordingly, Clallam agrees with the approach taken by the SDT,
which is to propose a Phase II of the standards development process that would address the
generator threshold issue and several other technical issues that have arisen during the current
process.As long as Phase II proceeds expeditiously, Clallam is prepared to support the BES definition
as proposed by the SDT. While Clallam strongly supports the overall approach adopted by the SDT
and much of the specific language incorporated into the second draft of the BES definition, we believe
the second draft would benefit from further clarification or modification in a number of respects, most
of which are detailed in our subsequent answers. Our support for the definition is not contingent upon
these changes being adopted. Further, we believe a workable Exclusion Process is essential for a BES
Definition that will meet the legal requirements of FPA Section 215, especially for systems operating
in the Western Interconnection. As detailed in our II proceeds expeditiously, Clallam is prepared to
support the BES definition as proposed by the SDT. While Clallam strongly supports the overall
approach adopted by the SDT and much of the specific language incorporated into the second draft of
the BES definition, we believe the second draft would benefit from further clarification or modification
in a number of respects, most of which are detailed in our subsequent answers. Our support for the
definition is not contingent upon these changes being adopted. Further, we believe a workable
Exclusion Process is essential for a BES Definition that will meet the legal requirements of FPA Section
215, especially for systems operating in the Western Interconnection. As detailed in our previous
comments, Clallam believes a 200-kV threshold would be more appropriate for WECC than a 100-kV
threshold. In addition, a 200-kV threshold for the West is backed by solid technical analysis conducted
by the WECC Bulk Electric System Definition Task Force, and repeated claims that there is no

technical analysis to support this view is therefore incorrect. That being said, we raise the issue here
to emphasize the importance of the Exclusions for Local Networks and Radial Systems and the
Exceptions process. These Exclusions and the Exceptions are essential for a definition that works in
the Western Interconnection because the core definition will be over-inclusive in our region. As long
as those Exclusions and the Exceptions Process are retained in a form substantially equivalent to
those produced by the SDT at this juncture, Clallam will support the SDT’s proposal and will not
further pursue its claims regarding the 200-kV threshold.
Yes
We support the SDT’s changes to the first Inclusionbecause it is more clear and simple than the initial
approach. That being said, we suggest that an additional sentence of clarification would help avoid
future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to include
transformers only if both the primary and secondary terminals operate at 100 kV or above, which is
why the definition uses the word “and” (“the primary and secondary terminals”). We support this
approach since it would exclude transformers where the secondary terminals serve distribution loads,
and which therefore function as distribution rather than transmission facilities. We believe the SDT’s
intent would be clarified by adding a sentence at the end of Inclusion 1 that reads: “Transformers
with either primary or secondary terminals, or both, that operate at or below 100 kV are not part of
the BES.” This language will help ensure that there is no controversy over whether the SDT’s use of
the word “and” in the phrase “the primary and secondary terminals” was intentional. We also support
the SDT’s proposal to develop detailed guidance concerning the point of demarcation between BES
and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion 1 at least
implicitly suggests that the dividing line between BES and non-BES Elements should be at the
transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
CLPD supports the changes made in Inclusion 2 and believe that the definition in its current form adds
clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the previous
draft definition into a single Inclusion that addresses the treatment of generation for purposes of the
BES definition. We also support that aspect of the SDT’s proposal for a Phase II of the BES Definition
process that would examine the technical justification for these thresholds and that would establish
new thresholds based on a careful technical analysis. It is our understanding that the generator
threshold issue will be vetted through the complete standards development process. We agree with
this approach becauseif the generator threshold is treated as merely an element of NERC’s Rules of
Procedure, it can be changed with considerably less due process and industry input than the
Standards Development Process. Compare NERC Rules of Procedure § 1400 (providing for changes to
Rules of Procedure upon approval of the NERC board and FERC) with NERC Standards Process Manual
(Sept. 3, 2010) (providing for, e.g., posting of SDT proposals for comment, successive balloting, and
super-majority approval requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011)
(“Order No. 743 directed the ERO to revise the definition of ‘bulk electric system’ through the NERC
Standards Development Process” (emph. added)). Addressing all aspects of Phase II through the
Standards Development Process will improve the content of the definition by bringing to bear industry
expertise on all aspects of the definition and will ensure that, once firm guidelines are established,

they can be relied upon by both industry and regulators without threat that they will be changed with
little notice and little due process. CLPD believes further clarification of the proposed language would
be appropriate. The SDT proposes continued reliance upon the thresholds that are used in the NERC
Statement of Compliance Registry Criteria for registration of Generation Owners and Generation
Operators, which is currently 20 MVA for an individual generation unit and 75 MVA for multiple units
on a single site. as we understand it, the purpose of the Compliance Registry is to sweep in all
generators that might be material to the reliable operation of the BES, and not to definitively
determine whether a given generator is, in fact, material to the reliable operation of the BES. As the
SCRC itself states, the SCRC is intended only to identify “candidates for registration.” SCRC at p.3, §
1 (emph. added). Accordingly, we believe that the generator threshold determined in Phase II should
be incorporated directly into the BES Definition rather than being incorporated by reference from the
SCRC. We also believe that the specific language proposed by the SDT could be further clarified. The
SDT proposes that generation be included in the BES if the “Generation resource(s)” has a
“nameplate rating per the ERO Statement of Compliance Registry.” We understand this language is
intended to be a placeholder for the results of the technical analysis that would occur in Phase II but
we believe simply stating that the threshold will be “per the ERO Statement of Compliance Registry” is
ambiguous. Further, for the reasons noted above, we believe the threshold should be part of the BES
Definition, and should not simply be a cross-reference to the SCRC (and, given the different purposes
of the BES Definition and the SCRC, it is not clear that the same threshold should be used in both).
We therefore propose that Inclusion 2 be rewritten to state: “Qualifying Individual Generation
Resources or Qualifying Aggregate Resources connected at a voltage of 100 kV or above.” Two
definitions would then be added to the note at the end of the definition to read as follows: For
purposes of this BES Definition, Qualifying Individual Generation Resources means an individual
generating unit that meets the materiality threshold to be included in this definition or, in the absence
of such a materiality threshold, that meets the gross nameplate capacity voltage threshold requiring
registration of the owner of such a resource as a Generation Owner under the ERO Statement of
Compliance Registry Criteria. For purposes of this BES Definition, Qualifying Aggregate Generation
Resources means any facility consisting of one or more generating unitsthat are connected at a
common bus that meets the materiality threshold to be included in this definition, or, in the absence
of such a threshold, that meets the gross nameplate capacity voltage threshold requiring registration
of the owner of multiple-unit generator as a Generation Owner under the ERO Statement of
Compliance RegistryCriteria.. The “materiality threshold” is intended to refer to the generator
threshold developed in Phase II. We suggest using definitions in this fashion for several reasons. First,
we believe the language we suggest more clearly states the intention of the SDT, which we
understand is to classify generation units as part of the BES if they are necessary for operation of the
BES, but to exclude smaller generating units because they are not material to the operation of the
interconnected transmission grid. Second, we believe use of the defined terms better reflects the
intention of the SDT to reserve the specific question about generator thresholds to the technical
analysis that will occur in Phase II without having to revise the BES Definition at the end of that
process. That is, the definitions are designed to allow the SDT to include revised thresholds in the
definition at the conclusion of the Phase II process based upon the technical analysis planned for
Phase II, and the revised thresholds will be automatically incorporated into the BES Definition if the
language we suggest is used. The thresholds used in the SCRC would only be a fall-back, to be used
only until Phase II is completed. Third, the definitions can be incorporated into other parts of the BES
Definition, which will add consistency and clarity. As noted in our answers to several of the questions
below, the specific 75 MVA threshold is retained in several of the Exclusions and Inclusions, and we
believe the industry would be better served if the revised thresholds arrived at after technical analysis
in Phase II are automatically incorporated into all relevant provisions of the BES Definition. There is
no reason for the SDT to continue to rely on the 75 MVA threshold once the analysis planned for
Phase II on the threshold issue is completed. Fourth, the phrase “or that meets the materiality
threshold to be included in this definition” is intended to preserve the SDT’s flexibility to make a
determination that generators below a specific threshold are not “necessary to” maintain the reliability
of the interconnected transmission system, and to incorporate that finding as part of the definition
itself, even if a different threshold is used in the SCRC to identify potential candidates for registration.
Accordingly, our proposed language makes clear that a specific threshold in the definition controls
over any threshold that might be included in the SCRC. For the reasons stated above, we believe is it
highly desirable to include any material threshold in the BES Definition itself rather than relegating
the threshold to the SCRC, which is merely a procedural rule rather than a full-fledged Reliability

Standard. Finally, we agree with the SDT’s decision to examine the question of where the line
between BES and non-BES Elements should be drawn more closely in Phase II under the rubric of
“contiguous vs. non-contiguous BES,” and commend the work of the Project 2010-07 Standards
Drafting Team and the GO-TO Team as a good starting point for the SDT’s analysis on this issue. We
understand Inclusion 2 would classify generators exceeding specific thresholds as part of the BES, but
would not necessarily require facilities interconnecting such generators to be part of the BES. As
discussed more fully in our answer to Question 9, based on extensive technical analysis that has
already been performed by the NERC Project 2010-07 Standards Drafting Team and its predecessor,
the NERC “GO-TO Team,” regulating as part of the BES a dedicated interconnection facility connecting
a BES generator to the interconnected bulk transmission grid will result in an unnecessary regulatory
burden that produces considerable expense for the owner of the interconnection facility with little or
no improvement in bulk system reliability. We also believe the clauses at the end of Inclusion 2 are
somewhat confusing and that greater clarity would be achieved by changing “. . . including the
generator terminals through the high-side of the step-up transformer(s) connected at a voltage of
100 kV or above” so that the Inclusion covers transformers with terminals “connected at a voltage of
100 kV or above, including the generator terminal(s) on the high side of the step-up transformer(s) if
operated at a voltage of 100 kV or above.”
Yes
CLPD supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
CLPD supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which is discussed in more detail in our response to
Question 3. This language, or some equivalent, will preserve the SDT’s ability to revise the 75 MVA
threshold in Phase II, with the result of Phase II included in the BES Definition by operation rather
than requiring further revision of the Definition. More generally, we are not certain what is
accomplished by Inclusion 4 that is not already accomplished by Inclusion 2, which also addresses
whether generation should be defined as BES. The SDT’s stated concern is with variable generation
units such as wind and solar plants. It is not clear to us why this concern is not fully addressed in
Inclusion 2, which addresses multiple generation units connected at a common bus, the configuration
of most variable generation plants with multiple units. We are also concerned that the language, as
proposed, could have unintended consequences and improperly classify local distribution systems as
BES in certain circumstances. This is because multiple distributed generation units could render a
local distribution system a “collector system” and the entire system the equivalent of an aggregated
generation unit, causing the local distribution system to be improperly denied status as a LN. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase“. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
CLPD has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity

threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Finally, CLPD believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process.
Yes
CLPD continues to support the radial system exclusion, which is necessary as a legal matter, because,
for example, FERC in Orders No. 743 and 743-A has required that the existing radial exemption in the
NERC Statement of Compliance Registry Criteria be maintained. As a practical matter, radial systems
are used for service to retail loads, usually in remote or rural areas, and not for the transmission of
bulk power. Hence, operation of the radials has little or nothing to do with the reliable operation of
the interconnected bulk transmission network. We also support the inclusion of the note discussing
normally open switches because this language provides needed clarity for a common radial system
configuration. We also agree with the substantive thrust of this language, which is that a radial
system should not be considered part of the BES if it is interconnected at a single point, even if there
is an alternative point of delivery that is normally open. While we support the Exclusion for Radial
Systems, we believe several clarifications and refinements are necessary. (1) The term “transmission
Elements” in the initial paragraph should be changed to “Elements.” Radial systems are not
transmission systems and including the word “transmission” in the Radial System exclusion is
therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to“generation
resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)”). We
urge the SDT to replace this language with the defined term “Qualifying Aggregate Generation
Resources,” discussed in more detail in our response to Question 3. This language, or some
equivalent, will preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result
of Phase II included in the BES Definition by operation rather than requiring further revision of the
Definition. (3) Subparagraph (b) also seems to assume that if a Radial System contains a generator
exceeding the 75 MVA threshhold, the Radial System itself must be included in the BES because it
links the generator to the interconnected bulk transmission system. As discussed more fully in our
response to Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task
Force have both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT
indicates that “a normally open switching device between radial systems” will not serve to disqualify
the Radial from exclusion under Exclusion 1. As noted above, CLPD strongly supports the note
conceptually. However, we believe this language should be included in a separate subparagraph (d),
rather than a note, because treatment as a “note” suggests it is less important than other portions of
the Exclusion. We also suggest the language be changed to read: (d) Normally-open switching
devices between radial elements as depicted and properly identified on system one-line diagrams
does not affect this exclusion. This will make clear that a radial with more than one normally-open
switch connecting it to another radial is still a radial. From the perspective of the BES Definition, the
key question is whether switches operating between Radials are normally open, not whether there is
more than one normally-open switch.
Yes
CLPD supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, CLPD urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System

or LN.
Yes
CLPD strongly supports the categorical exclusion of Local Networks (“LNs”) from the BES. We believe
the exclusion is necessary to ensure that the BES definition complies with the statutory requirement,
discussed in our response to Question 1, to exclude all facilities used in the local distribution of
electric power. LNs are, of course, probably the most common form of local distribution facility.
Further, the conversion of radial systems to local distribution networks should be encouraged because
networked systems generally reduce losses, increase system efficiency, and increase the level of
service to retail customers. If the BES definition were to provide an exclusion for radials without
providing a similar exclusion for LNs, however, it would discourage networking local distribution
systems because of the significantly increased regulatory burdens faced by the local distribution utility
if it elected to network its radial facilities. By placing radial systems and LNs on the same regulatory
footing, the proposed definition will ensure that decisions about whether to network radial systems
are made on the basis of costs and benefits to the retail customers served by those radials, and not
on the basis of disparate regulatory treatment. Consumers will ultimately benefit from the path
chosen by the SDT. CLPD also supports specific refinements made to the LN exclusion by the SDT in
the current draft of the BES definition. In particular, CLPD supports the clarification of the purposes of
a LN. The current draft states that LNs connect at multiple points to “improve the level of service to
retail customer Load and not to accommodate bulk power transfer across the interconnected system.”
Clallam supports this change in language because it reflects the fundamental purposes of a LN and
emphasizes one of the key distinctions between LNs and bulk transmission facilities, namely, that LNs
are designed primarily to serve local retail load while bulk transmission facilities are designed
primarily to move bulk power from a bulk source (generally either the point of interconnection of a
wholesale generator or a the point of interconnection with another bulk transmission system) to one
or more wholesale purchasers. CLPD believes further improvement of the language could be achieved
with additional modifications and clarifications. With respect to the core language of Exclusion 3, we
believe the language making a “group of contiguous transmission Elements operated at or above 100
kV” the starting point for identifying a LN would be improved by deleting the term “transmission” from
this phrase. This is so because LNs are not used for transmission and the use of the term
“transmission Elements” is therefore both confusing and unnecessary. There would be no room for
argument about what the SDT intended by including the word “transmission” if the word is deleted
and the Exclusion applies to any “group of Elements operated at 100 kV or above” that meets the
remaining requirement of the Exclusion. Further, any definitional value that is added by using the
term “transmission Elements” is accomplished by using that term in the core definition, and there is
no reason to carry the term through in the Exclusions. CLPD also believesthat subparagraphs (a) and
(b) are redundant in the sense that whatever protection is offered by the generation limit in
subparagraph (a) is duplicated by the limit in subparagraph (b) requiring no flow out of the LN. We
believe the SDT can eliminate subparagraph (a) of Exclusion 3 and simply rely on subparagraph (b)
because if power only flows into the LN even if it interconnects more than 75 MVA of generation, the
interconnected generation interconnected will have no significant interaction with the interconnected
bulk transmission system. It will only interact with the LN. And, with the advent of distributed
generation, it is easy to foresee a situation in which a large number of very small distributed
generators are interconnected into a LDN, so that the aggregate capacity of these generators exceeds
75 MVA. However, because the generators are small and dispersed and, under the criterion in
subparagraph (b), would be wholly absorbed within the LN rather than transmitting power onto the
interconnected grid, those generators would not have a material impact on the grid. We also suggest
that subparagraph (b) of Exclusion 3 could be more clearly drafted. Subparagraph (b), as part of the
requirement that power flow into a LN rather than out of it, includes this description: “The LN does
not transfer energy originating outside the LN for delivery through the LN.” We understand this
language is intended to distinguish a LN from a link in the transmission system – power on a
transmission link passes through the transmission link to a load located elsewhere, while power in a
LN enters the LN and is consumed by retail load within the LN. While we agree with the concept
proposed by the SDT, we believe the language would be clearer if it read: “The LN does not transfer
energy originating outside the LN for delivery through the LN to loads located outside the LN.” We
believe the italicized language is necessary to distinguish between a transmission system, where
power that originates outside a system is delivered through the system and passes through the
system to a sink located somewhere outside the system, from a LN, in which power originating
outside the LN passes through the LN and is delivered to retail load within the LN. To put it another

way, the italicized language helps distinguish a transmission system from an LN, in which the LN
“transfers energy originating outside the LN for delivery through the LN to loads located within the
LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3.
Finally, CLPD believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated
as long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified
as a Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities
that allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
transmission of electricity on the interconnected bulk system. Apart from these specific improvements
that we believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may
need to re-examine certain assumptions that appear to underlie the current draft. Specifically,
subparagraph (a) suggests that if BES generation is embedded within a LN, the LN itself must also be
BES. But two NERC bodies have already addressed similar questions and concluded there is no
technical basis for such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force” were formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. The GO-TO Teamconcluded that by complying with a handful of reliability standards,
primarily related to vegetation management, reliable operation of the bulk interconnected system
could be protected without unduly burdening the owners of such interconnection systems. Therefore,
there is no reason, according to the GO-TO Team, that dedicated high-voltage interconnection
facilities must be treated as “Transmission” and classified as part of the BES in order to make
reliability standards effective. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO Task
Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most often
not part of the integrated bulk power system, and as such should not be subject to the same level of
standards applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” White Paper
Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at the
Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply
with the same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of the
equipment that actually produces electricity – the generation equipment itself.” Id. We believe that
interconnection of BES generators within a LN is analogous and that, based on the findings of the
Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply because a large
generator is embedded in the LN will result in substantial overregulation and unnecessary expense
with little gain for bulk system reliability. If anything, generation interconnected through a LN is less
likely to produce material impacts on the interconnected bulk transmission system than the
equivalent generator interconnected through a single dedicated line because an LN is interconnected
to the bulk system at several points, so that if one interconnection goes down, power can still flow
from the BES generator to the bulk system on other interconnection points. Where a dedicated
interconnection facility is involved, by contrast, if the interconnection line fails, the generator is
unavailable to the interconnected bulk system. Similarly, we suggest that the SDT re-examine the

assumptions underlying subparagraph (b), which seems to suggest that a local distribution system
cannot be classified as a Local Network if power flows out of that system at any time, even if the
amount is de minimis, the outward flow is only for a few hours a year, or the outward flow occurs
only in an extreme contingency. Accordingly, we suggest that the initial clause of subparagraph (b) be
revised to read: “Except in unusual circumstances, power flows only into the LN.”
Yes
Yes, CLPD supports the revised language because retail reactive devices are used to address local
customer or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such
local devices should therefore be excluded from the BES definition.
No
CLPD extends its thanks to the SDT and to the many industry entities that have actively participating
in the Standards Development Process. CLPD strongly supports the current draft and believes, with
certain refinements discussed in our comments, that the definition will serve the industry and
reliability regulators well for many years to come. In addition, as noted earlier, CLPD is encouraged
that the 20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry
Criteria, which have been relied upon by the SDT largely as a matter of necessity, will be reviewed
and a technical assessment will be performed to identify the appropriate generation unit and plant
size threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure
Team will continue to move forward with developing an Exceptions Process that will complement the
BES Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should
not be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that CLPD specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. CLPD supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. CLPD
also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Richard Salgo
NV Energy
Yes
The core definition is simpler than the prior version. We support the addition of the last sentence
regarding the exclusion of facilities used in the local distribution of electric energy.
Yes
The changes made to I1 (Transformers) appropriately resolves several of the industry concerns about
three-winding transformers as well as an inadvertent use of the word “and” rather than “or”.
No
While we do not agree with making specific reference and linkage to the generator thresholds of the
SCRC, it is understood that a timely justification of any alternative threshold was not possible. It is of
paramount importance that the subject of generation thresholds be addressed in subsequent
development of this Definition. We are of the opinion that generation ought to be considered as a
“user” of the BES, not necessarily a part of the BES, similar in concept to the way Load uses the BES.
Using this concept, the BES would be restricted to the “wires” type facilities. Standards would
nevertheless be applicable to generators that use the BES, so no gap in reliability would exist.
Yes
Yes
Yes
The SDT has appropriately captured the necessary inclusion of high voltage transmission reactive

resources.
Yes
There may be an opportunity to consolidate the sub-items of E1 into a single inclusion statement in
order to simplify this exclusion designation. We propose the following replacement option: “E1 Radial systems: A group of contiguous transmission Elements that emanates from a single point of
connection of 100 kV or higher and serves any combination of load and/or generation, provided that
the generation resources are not identified in Inclusion I3 and do not have an aggregate capacity of
non-retail generation greater than 75 MVA (gross nameplate rating).”
Yes
Yes
Yes
No
Group
Ian Grant
Tennessee Valley Authority
Yes
TVA agrees to the clarifying changes to the core definition in general; however, we maintain that
200kV and above is the correct bright line for the Bulk Electric System, and requests that the Phase 2
for the project use 200kV and above or develop a transmission voltage and/or an MVA threshold that
is technically based.
Yes
TVA agrees in general with the revisions to the specific inclusions for transformers in I1; however, we
believe the low side transformer voltage level should be 200kV or above, and requests that the Phase
2 for the project use 200kV and above or develop a transmission voltage and/or an MVA threshold
that is technically based.
Yes
TVA agrees in general with the revisions to I2 for generation; however, we maintain that 200kV and
above is the correct bright line for generation connected to the Bulk Electric System, and requests
that the Phase 2 for the project use 200kV and above or develop a transmission voltage and/or an
MVA threshold that is technically based.
No
TVA agrees with the changes but believe clarity would be added by changing the word “identified” to
“designated”.
Yes
No
TVA feels that this inclusion should be limited to dynamic devices with an aggregate capacity greater
than 75 MVAR (gross aggregate nameplate rating) connected through a common point at a voltage of
200kV or above, and requests that the Phase 2 for the project use 75 MVAR connected at 200kV or
above or develop a transmission voltage and/or an MVAR threshold that is technically based.
Yes
TVA suggests the wording “non-retail generation’ should be clarified with an explanation of why it is
used in this exclusion.
No
Clarification needs to be provided for what is meant by E2 (ii), regarding generation on the
customer’s side of the retail meter; otherwise we have trouble developing a position on this question.
No
TVA would agree with the exclusion if the wording of the exclusion includes the following phrase (in

italics) added at the end of E3 b): “Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN under normal operating conditions; and”
Yes
Yes
The definition of the BES is referenced in several existing standards and the Statement of Compliance
Registry Criteria. TVA is concerned with this revised definition’s impact on entity registrations, i.e.,
how will the revised definition be integrated into the Compliance Registry Criteria. The
implementation plan should include how the integration is going to occur. The 24 month period for
new facilities that are to become BES elements as a result of this definition is very important to
successful implementation of the definition. An period shorter that 24 months would be very
problematic for the industry.
Individual
Jerome Murray
Oregon Public Utility Commission Staff

No
Reference to NERC Statement of Compliance Registry Criteria (SCRC) needs to be eliminated from the
BES Definition. This circularity must be eliminated. Proposed revised language is: “I2 - Generating
resource(s) with a gross individual nameplate rating greater than 20 MVA or with a gross aggregate
nameplate rating greater than 75 MVA including the generator terminals through the high-side of the
step-up transformer(s) connected at a voltage of 100 kV or above.”

Yes
Yes
Yes

Individual
Mary Jo Cooper
Z Global Engineering and Energy Solutions
Yes
We support these changes however feel that further clarification needs to be made regarding the E1
Note. This note currently states "Note – A normally open switching device between radial systems, as
depicted on prints or one-line diagrams for example, does not affect this exclusion" This note is not
clear. We recommend that the note is rewritten to be clear that a normally open switching device
should not be viewed as normally closed as the regions are currently doing. Possible language: "Note:
A normally open switching device between radial systems, as depicted on prints or oneline diagrams,
for example, does not classify the two or more radial lines as a loop line. The exclusion will still
apply.”}"
Yes
Yes
Yes

Yes
Yes
Yes
As stated in comment one. I recommend the Note is rewritten: "Note – A normally open switching
device between radial systems, as depicted on prints or oneline diagrams, for example, does not
classify the two or more radial lines as a loop line. The exclusion will still apply."
Yes
Yes
Yes
No
Individual
Eric Salsbury
Consumers Energy
Yes
Yes
Yes
Yes
Yes
We agree, but would like further clarification on what wind farm equipment (e.g., collector systems or
other equipment) would be considered a part of the BES. Is the system designed for aggregating
capacity considered to be part of the dispersed plant or part of the BES.
No
This inclusion appears to pull small generators that have an AVR that are connected to 138 kV into
the BES. These generators are primarily intended to provide real power.
No
In general we agree, but believe the word "transmission" should be removed from "A group of
contiguous transmission Elements…"
Yes
No
In general we agree, but believe the word "transmission" should be removed from "A group of
contiguous transmission Elements…"
Yes
No
Individual
Tracy Richardson

Springfield Utility Board
Yes
SUB particularly agrees with the addition of, “This does not include facilities used in the local
distribution of electric energy.” to the BES draft definition.
Yes
SUB supports and appreciates the change in language from, “unless excluded under Exclusions E1
and E3” to “Exclusion E1 or E3”. This makes it clear that Radial System or Local Network transformers
should not be considered BES facilities, regardless of operating voltage.
No SUB comment as this is not currently applicable to SUB's operations.
No SUB comment as this is not currently applicable to SUB's operations.
No SUB comment as this is not currently applicable to SUB's operations.
Yes
SUB agrees in general, but does not agree that ALL reactive resources should be automatically
included in the BES Definition. For example, is a local network (100 kV or above), which is otherwise
excluded, but has a reactive device used for power factor correction (100 kV or above), still excluded?
There are a significant number of reactive resources that are used to serve systems that provide
service primarily to load, with either no or a minimal amount of generation. If this section is included,
the Exclusion language needs to be modified to exclude those reactive resources from the BES that
are radial serving only load or local networks that serve load (with less than 75MVa of generation).
SUB does not agree with the language referring to only those “retail customer” reactive power devices
for Exclusion E.4. This is too narrow and does not accurately reflect the use of reactive power devices
installed by registered entities when retail customers do not “fix” their reactive power issues on their
own. SUB recommends that the language in I5 and E4 be consistent, and that “retail customer”
should include Registered Entities as well as end users. This present language is overly broad and,
absent modifications to the BES definition, will generate a significant amount of paperwork. SUB
suggests the following language change: I5 –Static or dynamic devices dedicated to supplying or
absorbing Reactive Power that: a)are connected at 100 kV or higher and are not part of a radial
system or area network that are excluded from the BES, or; b)are connected through a dedicated
transformer with a high-side voltage of 100 kV or higher and are not part of a radial system or area
network that are excluded from the BES, or; c)are connected through a transformer that is
designated in Inclusion I1 and are not part of a radial system or area network that are excluded from
the BES .
Yes
SUB supports a radial system exclusion.
No SUB comments as this is not currently applicable to SUB's operations.
Yes
SUB strongly supports the exclusion of Local Networks from the BES. SUB particularly agrees with the
addition of, “LN’s emanate from multiple points of connection at 100 kV or higher to improve the level
of service to customer Load and not to accommodate bulk power transfer across the interconnected
system.” language to the draft E3 Exclusion, as well as the LN characterization being more clearly
defined. SUB is concerned that the E3 Exclusion does not specify that these power flows would be
“under normal operating conditions” and specify if all power flow is considered. SUB recommends that
unscheduled power flow should not be considered, but that it is applicable only to scheduled power
flow. While SUB supports the exclusion of LNs from the BES, we believe there is additional work that
needs to done regarding the Local Network Exclusion Technical Justification. Without specific
parameters, determining inclusions and exclusions will be left to the discretion of too many. This will
create ambiguity and inconsistency of application.
Yes
Reactive power devices used to serve radial networks or Local Networks are often owned and
operated by the registered entity (not the “retail customer”) to address Area Network – wide reactive
power issues. This language should read: “E4. Reactive power devices that are within a radial system
excluded under E1 or within a local network excluded under E3” If the current draft language is left as
it is, there will likely be a lot of unnecessary paperwork to exclude reactive power devices within
radial system or local networks from the BES through the exclusion process. SUB suggests that the
language in the E4 Exclusion be consistent with that in the I5 Inclusion.

Yes
When submitting BES Definition comments, SUB would suggest a “not-applicable”, “no-impact” or
“abstain” option in addition to “yes” or “no”. In some cases, the draft language has no impact on an
entity’s system, yet that entity’s selection of “yes” or “no” may imply agreement or disagreement
rather than expressing lack of applicability. This could skew the perception of agreement or
disagreement, and create a potential issue for those who are directly impacted by the changes.
Individual
Kerry Wiedrich
Mission Valley Power
Yes
Mission Valley Power - We agree with the changes. We must point out that the overall flow, or how
one proceeds through the inclusions and exclusions is not clear. Can an item that meets an inclusion
be subsequently excluded? If so, this needs to be explicitly stated. So far, we only have the flow chart
produced by the ROP team that indicates otherwise
(http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf). This was made evident
by the question at the 9/28 webinar regarding an I5 capacitor on an E3 local network. The questioner
thought the capacitor was BES per I5, but the answer was that it was excluded per E3. We can find
no support for the answer given. The listing of specific exclusions within I1 (exception proves the
rule) argues for questioner’s stance that the capacitor is BES as written. Also, if included items could
subsequently be excluded, they would be no different from any other item that met the voltage
threshold of 100kV. There would be no need for any of the inclusions if all possible outputs from the
inclusion tests go to the same exclusion test inputs. We strongly support the addition of the language
regarding local distribution facilities, as it matches congressional intent to leave the regulation of
these facilities to state and local authorities.
Yes
Mission Valley Power - Comments: Mission Valley Power strongly agrees with this inclusion as written.
It is consistent with the recent PRC-004 and PRC-005 interpretation and the NERC definition of
Transmission. We believe the recent changes to this inclusion add clarity.
No
Mission Valley Power - Referencing the Criteria which in turn references the BES definition creates a
circular definition. Mission Valley Power encourages the adoption of specific thresholds that are
technically justified. We also note that the Criteria and its revisions do not go through the standards
development process, so that thresholds may change with little warning and without triggering an
implementation plan for facilities that may be swept into the BES as a result.
Yes
Mission Valley Power - We agree with the removal of the voltage language, since the inclusions and
exclusions apply only to equipment over 100 kV.
Yes
Mission Valley Power agrees both with the inclusion and with the revised language. The revised
language removes the need to provide a separate definition for “Collector System”.
No
Mission Valley Power - While we agree that reactive devices of sizable capacity connected at 100 kV
or higher are needed for BES reliability, Mission Valley Power fails to see why this inclusion is needed
as they are already captured by the 100 kV threshold. We would propose instead to eliminate this
inclusion and substitute an exclusion for smaller capacity devices. If the SDT really believes an
inclusion for reactive devices is needed, we suggest the SDT provide a technically justified capacity
limit within the inclusion. In addition we suggest also including the phrase “…unless excluded under
Exclusion E1, E2 or E4” similar to that in I1. Please see the answer to Q1 above Q10 below.
No
Mission Valley Power notes that a new term has been introduced, “non-retail generation,” with no
definition provided. The answer to the question on this during the 9/28 webinar indicated that nonretail generation was behind the retail customer’s meter. We can see no reason why the net-metered
PV systems should count toward the aggregate limit (exceeding the limit means no exclusion) while a
non-blackstart thermal plant doesn’t (the radial system is excluded if any amount of load is present).

We have also heard the SDT meant just the opposite of what was stated in the webinar. We ask that
a reasonable definition for non-retail be provided within the BES definition document. We strongly
agree that radial systems should be excluded and that the presence of normally open switching
devices between radial systems should not cause them to be considered non-radial. Such a result
would cause the removal of these devices to the detriment of the local level of service. We note that
the singular “A normally open switching device” is used and suggest that an allowance be made for
the possibility of multiple devices. “Normally open switching devices…”
Yes
No
Mission Valley Power - : We strongly agree that local networks should be excluded, since they act
much like the radial systems excluded in E1 while providing a higher level of service to customers.
These networks should not be discouraged in the name of reliability. We again object to the
introduction of the new confusing term “non-retail generation” with no definition provided.
No
Mission Valley Power - : We strongly agree that local networks should be excluded, since they act
much like the radial systems excluded in E1 while providing a higher level of service to customers.
These networks should not be discouraged in the name of reliability. We again object to the
introduction of the new confusing term “non-retail generation” with no definition provided.
Yes
Mission Valley Power - In order to help meet the fast approaching target date, Mission Valley Power
will be voting affirmative in this ballot, with the hope these comments will be addressed in Phase II. If
the ballot should fail, please address these comments in this phase. Thanks to the team for their good
work.
Individual
Denise M. Lietz
Puget Sound Energy
Yes
This draft of the defintion is very much improved. We appreciate the work of the Standard
Development Team and its efforts to increase the clarity of this important definition. For additional
clarity, the first paragraph should read "Unless specifically excluded under the list of exclusions below
or included or excluded through the Procedure for Requesting and Receiving an Exception from the
Application of the NERC Definition of Bulk Electric System, all Transmission Elements operated at 100
kV or higher and Real Power and Reactive Power resources connected at 100 kV or higher, including
those Transmission Elements described in the list of inclusions below." The sentence "This does not
include facilities used in the local distribution of electric energy." should be removed from the first
paragraph. Because this issue is specifically addressed in exclusions E1 and E3, the inclusion of this
general sentence here is unnecessary and could even be ambiguous (raising the question of whether
additional Transmission Elements might be excluded even if not described in E1 or E2).
Yes
Inclusion I1 references primary and secondary terminals of transformers, while Inclusions I2 and I5
reference the high-side of transformers. The SDT should consider using consistent terminology
throughout the definition for this concept.
Yes
The term "per" should be replaced by "greater than the levels specified for a Generator
Owner/Operator in". For a definition of this importance, the term "per" is too vague.
Yes
Yes
Yes
Yes

The language addressing generation resources in sections b and c of E1 could be more clear (an
example of clearer language is section a of E3). At the least, the language in these two sections
should be revised to read "... includes generation resources that are not identified in Inclusion I3 and
that do not have an aggregate capacity exceeding 75 MVA ...".
Yes
Yes
Yes
No
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
No
• Please clarify the phrase “facilities used in local distribution” as used in the ‘core’ BES Definition.
What is the purpose of this phrase in the BES Definition? How does the SDT propose that an entity
demonstrate that a facility is used in local distribution? • Does this phrase “facilities used in local
distribution” establish a jurisdictional boundary which takes precedence over all other parts of the BES
Definition and Designations? • If this phrase does not take precedence over the remainder of the BES
Definition and Designations, i.e., perhaps only over some parts BES Definition and Designations, or
over none of the BES Definition and Designations, then what was the drafting teams understanding of
and intent with regard to “facilities used in local distribution?” • What are Entities supposed to do with
respect to “facilities used in local distribution” identified by State and Provincial regulators? • How has
NERC assured that the posted BES Definition and Designations meet the intent of the Commission to
establish an exemption process that avoids identifying “facilities used in local distribution” as part of
the BES (¶37 and ¶39 below)? Recommendations: If “facilities used in local distribution” are to be
excluded on jurisdictional grounds, then • The last sentence in the Core definition should be revised
as follows: “This does not include facilities used in the local distribution of electric energy, as
identified by a jurisdictional governmental authority.“ • We strongly recommend that the BES SDT
adopt the FERC Seven Factor test as a proven basis for establishing the boundary between
jurisdictional Transmission and non-jurisdictional “facilities used in local distribution.” Supporting
Discussion: In FERC Order 743-A the Commission stated 69. We agree … that the Seven Factor Test
could be relevant and possibly is a logical starting point for determining which facilities are local
distribution for reliability purposes” By adopting this FERC Seven Factor test, the BES SDT will have
fulfilled its obligation to respond to these FERC mandates relating to “local distribution” as stated in
FERC Order 743: “Determining where the line between ‘transmission’ and ‘local distribution’ lies,”
(¶37), “To the extent that any individual line would be considered to be local distribution, that line
would not be considered part of the bulk electric system” (¶39), to establish “[A] means to track and
review facilities that are classified as local distribution to ensure accuracy and consistent application of
the definition” (¶119). Supporting References: FERC Order 743 observed some believe that “the
Commission’s [and by extension NERC’s] proposal exceeds its jurisdiction by encompassing local
distribution facilities that are not necessary for operating the interconnected transmission network.”
[FERC Order 743, ¶27.] In this regard FERC Order 743 states: At ¶37, Congress specifically exempted
“facilities used in the local distribution of electric energy” from the definition. … Determining where
the line between “transmission” and “local distribution” lies, which includes an inquiry into which
lower voltage “transmission” facilities are necessary to operate the interconnected transmission
system, should be part of the exemption process the ERO develops. And at ¶39, To the extent that
any individual line would be considered to be local distribution, that line would not be considered part
of the bulk electric system. And at ¶119, … [W]e believe that it would be beneficial for the ERO in
maintaining a list of exempted facilities, to consider including a means to track and review facilities
that are classified as local distribution to ensure accuracy and consistent application of the definition.
Similarly, the ERO could track exemptions for radial facilities. [Emphasis added] Note that in ¶119 the
Commission clearly distinguishes between “radial facilities” and “local distribution” just as it

differentiates between jurisdictional radials and non-jurisdictional local distribution facilities in
footnote 82: 82 As discussed further below, the Commission uses the term “exclusion” herein when
discussing facilities expressly excluded by the statute (i.e., local distribution) and the term
“exemption” when referring to the exemption process NERC will develop for use with facilities other
than local distribution that may be exempted from compliance with the mandatory Reliability
Standards for other reasons. FERC Order 743-A suggests: 69. We agree with Consumers Energy,
Portland General and others that the Seven Factor Test could be relevant and possibly is a logical
starting point for determining which facilities are local distribution for reliability purposes …”

No
We suggest using wording from the Statement of Compliance Registry Criteria: Any generator
regardless of size which is material to … [Ref: Statement of Compliance Registry Criteria, III.c.3Blackstart] Define “material to” as a generator listed as a necessary part of the TOP-defined minimum
system to restore the BES. This term “material to” should exclude Blackstart-capable generators not
necessary for BES restoration or only used for local distribution system restoration. Wording
Recommendation: Following the words “identified in” add the words “and material to” so that the new
Inclusion reads: I3 - Blackstart Resources identified in and material to the Transmission Operator’s
restoration plan.
No
Normally, static and dynamic devices supply Reactive Power (VARs) to or absorb VARs from the
surrounding system. By their nature, VARs do not travel far, e.g., miles. So, VARs by their nature
only produce local impacts. Please explain the meaning of the phrase “dedicated to supplying or
absorbing Reactive Power,” with emphasis on explaining why the term “dedicated” was employed?
How does an Entity determine if a particular static or dynamic device is “dedicated” to the BES? What
Guidance documents can the BES SDT provide describing “dedicated” static and dynamic devices?
Yes
Please define the term “non-retail generation.”

Yes
Con Edison shares the concerns raised by the State of New York Department of Public Service
(NYPSC) in its September 12, 2011 letter to NERC Chairman Anderson. The NYPSC expressed concern
that the proposed BES Definition “would impose significant costs, costs that New York ratepayers will
be expected to bear, with little or no increase in reliability benefits.” The BES definition is being
revised without an assessment of costs or benefits. The SDT is encouraged to work with NERC Staff to
perform such an assessment prior to providing the revised BES definition to the NERC Board. Regional
Entities share this concern with cost effectiveness. In NPCC, the Board of Directors directed NPCC
Staff to develop a methodology to assess the cost and benefit of Standards. This NPCC Cost
Effectiveness Analysis Procedure (CEAP) establishes a process to address those concerns. The CEAP
introduces two assessments of the estimated industry-wide costs of requirements into that Standard’s
development process. The procedure adds supporting information and background for the NPCC
stakeholders, ballot body and the NPCC Board of Directors. Moreover, during a 2010 FERC technical
conference the Commission recognized that “reliability does not come without cost.” As a result,
significant interest was expressed in development of a process to identify the costs for draft reliability
Standards and the ability of the proposed standards to achieve the reliability objective(s) sought in a
cost effective manner. We understand that it is a NERC priority to define adequate level of reliability
and use it as the basis for determining the cost effectiveness of a proposed rule. While this has not
yet been finalized, NERC could use this proposed standard as a test case for determining the
relationship between costs and benefits.
Individual
Gail Shaw

Tillamook PUD
Yes
We strongly support the addition of the language regarding local distribution facilities, as it matches
congressional intent to leave the regulation of these facilities to state and local authorities.
Yes
Tillamook PUD strongly agrees with this inclusion as written. It is consistent with the recent PRC-004
and PRC-005 interpretation and the NERC definition of Transmission. We believe the recent changes
to this inclusion add clarity.
No
Referencing the Criteria which in turn references the BES definition creates a circular definition.
Tillamook PUD encourages the adoption of specific thresholds that are technically justified. We also
note that the Criteria and its revisions do not go through the standards development process, so that
thresholds may change with little warning and without triggering an implementation plan for facilities
that may be swept into the BES as a result.
Yes
Tillamook PUD agrees with the removal of the voltage language since the inclusions and exclusions
only apply to equipment over 100 kV.
Yes
Tillamook PUD agrees both with the inclusion and with the revised language. The revised language
removes the need to provide a separate definition for “Collector System”.
No
While we agree that reactive devices of sizable capacity connected at 100 kV or higher are needed for
BES reliability, Tillamook PUD fails to see why this inclusion is needed as they are already captured by
the 100 kV threshold. We would propose instead to eliminate this inclusion and substitute an
exclusion for smaller capacity devices. If the SDT really believes an inclusion for reactive devices is
needed, we suggest the SDT provide a technically justified capacity limit within the inclusion. In
addition we suggest also including the phrase “…unless excluded under Exclusion E1, E2 or E4” similar
to that in I1.
No
Tillamook PUD notes that a new term has been introduced, “non-retail generation,” with no definition
provided. The answer to the question on this during the 9/28 webinar indicated that non-retail
generation was behind the retail customer’s meter. We can see no reason why the net-metered PV
systems should count toward the aggregate limit (exceeding the limit means no exclusion) while a
non-blackstart thermal plant doesn’t (the radial system is excluded if any amount of load is present).
We have also heard the SDT meant just the opposite of what was stated in the webinar. We ask that
a reasonable definition for non-retail be provided within the BES definition document. We strongly
agree that radial systems should be excluded and that the presence of normally open switching
devices between radial systems should not cause them to be considered non-radial. Such a result
would cause the removal of these devices to the detriment of the local level of service. We note that
the singular “A normally open switching device” is used and suggest that an allowance be made for
the possibility of multiple devices. “Normally open switching devices…”
Yes
No
We strongly agree that local networks should be excluded, since they act much like the radial systems
excluded in E1 while providing a higher level of service to customers. These networks should not be
discouraged in the name of reliability. We again object to the introduction of the new confusing term
“non-retail generation” with no definition provided.
No
Any device that might be excluded under E4 has already been included per I5. Unless I5 is removed,
or rewritten as suggested above; this exclusion will exclude nothing.
Yes
If Tillamook PUD had signed up to ballot in time, we would be voting yes with the hope that these

comments would be addressed in Phase II. If the ballot fails, please address these comments in this
phase.
Individual
Thad Ness
American Electric Power
Yes
Yes
No
AEP is a proponent of cross-referencing related documents to avoid elements from becoming out of
sync, however, rather than having the BES Definition document reference the ERO Statement of
Compliance Registry Criteria, perhaps it should be the other way around. This definition document
undergoes a more thorough industry development and review process. The ERO Statement of
Compliance Registry Criteria does not get specific in regards to device types. The BES Definition
document is a more appropriate place to designate inclusion criteria.
Yes
No
We believe more clarity is needed as to where exactly the “common point” is, for example in the case
of a wind farm. This first common point could be interpreted as the output voltage of the wind
generator, would be less than the 100kv threshold and thereby could (unintentionally?) exclude the
facility as a whole. If this was unintentional, we recommend rewording I4 in a manner similar to I2.
No
I5 only specifies voltage limits, and makes no mention of reactive limits. We suggest that the drafting
team consider adding reactive capacity to these criteria as well.
No
AEP supports the concept of the exclusion of radial systems, however further clarification is needed
regarding whether or not the source equipment is included as part of the radial system (for example,
ring bus or breaker and a half bus configurations). Regarding the following text: “Note – A normally
open switching device between radial systems, as depicted on prints or one-line diagrams for
example, does not affect this exclusion.” We interpret this as not including two radial lines which
could be tied together through a normally open switch, are we correct? Additional clarity may be
needed regarding this note.
No
It appears an entity with less than 75 MVA would not have been included as part of the earlier
inclusions. Is it necessary to note this threshold once again in the exclusion section? Might it be
possible to add some of the “behind the meter load” to the inclusion section to reduce the amount of
both the inclusions and exclusions? Doing so would likely provide more clarity to the standard.
Yes
No
Does this refer to distribution level or reactive power resources? If so, it would appear these are not
included as part of I5. Or instead, does this refer to customer equipment at BES voltages? If it is the
latter, we recommend E4 be reworded to state “Reactive Power devices that meet the Inclusion
criteria of I5 that are owned and operated by the retail customer solely for its own use...”
Yes
There needs to be some clarification regarding the default status of an asset, as well as the order and
priority of the inclusion and exclusion classifications within the definition. First, prior to any evaluation
by virtue of the definition, is an asset by default excluded from the BES, or rather, it is included? In
addition, once the definition is used to evaluate an asset which has both inclusion attributes and
exclusion attributes, which of the two classifications has greater weight? For example, if an asset is
first included by the BES definition inclusion criteria can it then be excluded by BES definition

exclusion criteria? Or instead, if an asset is first excluded by BES definition exclusion criteria can it
then be included by the BES definition inclusion criteria? AEP’s recommendation is that an asset, by
default, not be considered part of the BES. Next, the asset would be evaluated by the inclusion
criteria as specified within the definition. Next, any asset explicitly included by the inclusion criteria is
then evaluated using the exclusion criteria. Once the entity has made their determination based on
the definition, exception requests could then be made to include or exclude assets as appropriate. We
believe our interpretation is what is implied by the draft definition, however, this needs to be explicitly
communicated within the definition itself.
Individual
Joe Petaski
Manitoba Hydro
Yes
Manitoba Hydro agrees in general with the changes made to the core definition but the sentence ‘This
does not include facilities used in the local distribution of electric energy’ should be removed as it is
covered under Exclusion E3 and reduces the clarity of the core definition.
Yes
Yes
No
Inclusion I3 should specifically state that only the Blackstart Resources specified through EOP-005-2
R1.4 are included in the BES since “Transmission Operator restoration plan’ is not a NERC defined
term. Suggested wording: “I3 - Blackstart Resources identified through EOP-005-2 R1.4”
Yes
Manitoba Hydro agrees with I4 but it does create a discrepancy between the BES Definition and the
Registration Criteria Document. The Registration Criteria document should be updated and I2 and I4
should be combined into a single Inclusion.
Yes
Yes
Manitoba Hydro agrees with E1 but the wording of the note regarding ‘normally open switching
devices’ is unclear. In the Industry Webinar on September 28th, the Drafting Team made it clear that
the note means that if an element can be connected to the BES from multiple points but under normal
operating conditions it is only connected to the BES at a single point by means of normally open
switches, then the element is still excluded from the BES provided it meets either the E1 a, b, or c
criteria. The team also noted that the discretion to operate the normally open switching devices in the
best interests of reliability rests with the operating entity. Suggested wording: “Note: The ability to
connect a group of contiguous transmission Elements from multiple connection points of 100kV or
higher through normally open switching devices does not negate this Exclusion. “ As well, part c) of
E1 should be changed to “c) Only serves Load and includes…”
Yes
Manitoba Hydro agrees with E2 but suggests that the phrase ‘A generating unit or multiple generating
units’ be replaced with ‘Generating resource(s)’ for clarity and consistency.
No
Manitoba Hydro agrees with the Local Network Exclusion but disagrees with the drafting team’s
removal of the requirement to have protective devices protecting the BES from the LN. We suggest
that the following requirement is re-inserted into E3 to meet the LN Exclusion: “a) Wherever
connected to the BES, the LN must be connected with a Protection System.”
Yes
No
Group

Janet Smith
Arizona Public Service Company

No
Individual
Robert Ganley
Long Island Power Authority
Yes
Need to define the term "local distribution"
Yes
Yes
Yes
Yes
Need to define the term "common point"
Yes
Yes
Need to clarify what is a "single point of interconnection" e.g. is it a bus section or a substation
Yes
No
Main paragraph and items E3b and E3c adequately define a Local Network. It seems like the intent to
exclude non bulk distribution systems would still be included because of E3a. E3a should be
eliminated. If not eliminated, need to define the term "underlying Elements".
Yes
Exclusion should identify a maximum value.
No
Individual
John A. Gray
The Dow Chemical Company
Yes
The Dow Chemical Company (“Dow) is an international chemical and plastics manufacturing firm and
a leader in science and technology, providing chemical, plastic, and agricultural products and services
to many essential consumer markets throughout the world. Dow and certain of its worldwide affiliates
and subsidiaries, including Union Carbide Corporation, own and operate electrical facilities at a

number of industrial sites within the U.S., principally, in Texas and Louisiana. The electrical facilities
at these various industrial sites are configured similarly and perform similar functions. In most cases,
a tie line or lines connect the industrial site to the electric transmission grid. Power is delivered from
the electric transmission grid to the industrial site through the tie line(s). Lines “behind-the-meter”
within the industrial site then deliver power to individual manufacturing plants within the site.
Additionally, cogeneration facilities, some of which are well over 75 MW in size, are located at a
number of industrial sites owned by Dow and its subsidiaries. These cogeneration facilities generate
power that is distributed within the industrial site and used for manufacturing plant operations. In
some instances, excess power not required for plant operations is delivered back into the electric
transmission grid through the tie line(s) connecting the industrial site to the grid. While the tie lines
and some of the internal lines at these industrial sites operate at 100kV or higher, they do not
perform anything that resembles a transmission function. Rather than transmit power long distances
from generation to load centers, the tie lines and internal lines perform primarily an end user
distribution function consisting of the distribution of power brought in from the grid or generated
internally to different plants within each industrial site. In some cases, the facilities also perform an
interconnection function to the extent they enable power from cogeneration facilities to be delivered
into the grid. The voltage of the tie lines and internal lines at these industrial sites is dictated by the
load and basic configuration of each site. Higher voltage lines are used when necessary to meet
applicable load requirements or to reduce line losses. That does not mean that such lines perform a
transmission function. At some sites, Dow is registered as a Generation Owner and Generation
Operator. At other sites, the applicable Regional Entity has found that such registration is not required
because of the relatively small amount of power supplied to the grid from the applicable cogeneration
resources, even though those cogeneration resources have an aggregate capacity greater than 75
MVA (gross aggregate nameplate rating). Tie lines (to the grid) and internal lines at an industrial site
that operate at 100kV or higher should be excluded from the BES definition if, due to the relatively
small amount of power supplied to the grid from the generation resources at the site, the owner of
those generation resources is not required to be registered as a Generation Owner and the operator
of those generation resources is not required to be registered as a Generation Operator. At sites
where the owner of the generation resources is registered as a Generation Owner and the operator of
those generation resources is registered as a Generation Operator, the internal lines (between the
generation resources and the manufacturing plants) that operate at 100kV or higher should be
excluded from the BES definition, because they are distribution and not transmission facilities. The
lines interconnecting the generation resources at such sites to the transmission grid should be
included in the BES definition, but the owner and operator of such interconnection lines should not be
registered as a Transmission Owner or Transmission Operator. In no instance has a Regional Entity
determined that Dow or any subsidiary should be registered as a Transmission Owner or Transmission
Operator. Instead, such interconnection lines should be considered as part of the generation resource
and Generation Owners and Generation Operators should be subject to reliability standards
specifically developed for such interconnection lines. Dow is strongly opposed to any BES definition
that would result in either the tie lines or the internal lines at industrial sites being subject to the
mandatory reliability standards applicable to Transmission Owners and Transmission Operators.
Complying with reliability standards would cause Dow and its subsidiaries to incur substantial
compliance costs and create potential exposure to penalties in the future for noncompliance. Perhaps
such costs and exposure could be justified if subjecting these facilities to compliance with reliability
standards resulted in a material increase in reliability of the BES, but there is no reason to believe
that will be the case. In fact, the opposite might be true. The tie lines and internal lines at industrial
sites owned by Dow and its subsidiaries have been operated for decades as end user distribution and
interconnection facilities, and practices and procedures have developed over the years that have
enabled such operations to achieve a high degree of reliability for such sites. Requiring these facilities
to now operate in a different manner as transmission facilities may well result in a degradation of the
reliability of the manufacturing plants located at such sites. For example, outages would have to be
coordinated with the RTO, which may not be interested in coordinating such outages with scheduled
manufacturing plant outages. In light of these considerations, Dow agrees with the proposed revisions
to the core definition, particularly the proposal to include a sentence expressly excluding facilities
used in the local distribution of electric energy, provided it is understood that end user-owned
delivery facilities located “behind-the-meter” are, regardless of voltage level, presumptively outside
the scope of this definition.
Yes

No
Comments: Dow agrees with the proposed revisions to Inclusion I2, particularly the proposal to
expressly reference the ERO Statement of Compliance Registry Criteria, but the following phrase
should be added at the end “unless excluded under Exclusion E2”.
Yes
No
It is not clear how “Dispersed power producing resources” differ from “Generating Resource (s)” in I2.
Inclusion I4 should clarify this. We suggest that the phrase “Variable Energy Resources” be used
instead of “Dispersed power producing resources”. Variable Energy Resources should be defined as
“Resources producing electricity using wind or solar energy.” The following phrase should be added at
the end “unless excluded under Exclusion E2”.
No
The phrase “or through a dedicated transformer with a high-side voltage of 100 kV or higher” is
inconsistent with I1 and would bring Reactive Power Equipment that is lower than 100Kv into the BES
definition. This phrase should be deleted. The following phrase should be added at the end “unless
excluded under Exclusion E4”.
Yes
Dow generally agrees with the proposed revisions to Exclusion E1, but believes that several additional
clarifying revisions should be made. First, the phrase “a single point of connection” in the introductory
sentence should be revised to read “a single point of connection (including multiple connections to the
same ring bus or different buses where the energy normally flows in the same direction)”. This
revision is intended to ensure that radial systems include arrangements involving multiple parallel
lines that are designed to operate as a single radial system, but that nevertheless connect at the grid
ring bus or different buses on the grid for reliability. Second, for this same reason, an additional (i.e.,
second) note should be added to the end of Exclusion E1 that reads as follows: “Note, a normally
closed switching device that enables multiple lines emanating from the same grid ring bus or different
grid buses to operate as a single radial system does not affect this exclusion.” Third, in “c),” the
phrase “with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating)” is confusing and potentially inconsistent to the extent that “non-retail generation”
may be different from “gross nameplate rating.” The apparent intent of the clause is to exclude radial
systems that serve both load and generation, provided the generation capacity made available to the
transmission grid does not exceed 75 MVA. Dow would recommend that the phrase be revised to read
“where the net capacity provided to the transmission grid does not exceed 75 MVA.” This revision
would provide greater clarity and is consistent with the language used in Exclusion E2.
Yes
Dow generally agrees with the proposed revisions to Exclusion E2, but believes that a clarifying
revision should be made. Substitute “transmission grid” for “BES” in the phrase “provided to the BES”
to insure that the measurement is to the grid.
Yes
Dow is uncertain whether end user-owned, behind-the-meter delivery facilities of the sort it has
described above would fall within the scope of the core BES definition proposed by NERC. To date,
none of the Regional Entities has suggested that Dow should register as a Transmission Owner or
Transmission Operator with respect to any of these Dow-owned delivery facilities. If a literal
application of the proposed BES Definition would, because of their voltage level or for any other
reason, include such facilities, then Dow has an interest in assuring that the E3 exclusion for "local
network" facilities is structured to embrace them. To that end, Dow would propose, first, the
elimination of the 300 Kv cap for these facilities. Dow has systems that operate above 300 Kv due
solely to the capacity of the lines to supply power over the distance required at our large
manufacturing sites. Second, for the same reasons discussed above (in response to question #7), the
phrase “do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating)” in “a)” should be changed to “the net capacity provided to the transmission grid
does not exceed 75 MVA.” Third, the introductory phrase in “b)” -- “Power flows only into the LN” -- is
inconsistent with the recognition in “a)” (as amended pursuant to Dow’s above suggestion) that

power may flow out of an LN and into the transmission grid if there is generation connected to the LN
and the 75 MVA limit is observed. Dow recommends either deleting the introductory clause or
correcting it to read “Power is not transferred through the LN.”
No
The term “solely” should be replaced by the term “primarily”. All devices to control Reactive power
behind-the-meter arguably provide some benefit to the transmission grid.
No
Group
Jonathan Hayes
Southwest Power Pool
No
The last sentence of the core states that no distribution facilities will be included, but some of these
facilities could be included due to blackstart resources. We don’t disagree with the idea of removing
distribution facilities, but would like to see some clarification or qualifier.
Yes
Yes
Yes
No
We believe that the removal of the wording “single site” in I2 would remove the need to cover
dispersed power producing resources in I4. What is the reason for keeping I4 in this version? Also we
understand that 75MVA is held in I4 because of no direct link to the registry criteria, but feel that this
number could change in phase two of the project which would create unnecessary work in the future.
No
We understand that this inclusion is used to capture those devices other than generation resources,
but the language leads us to believe that it could include all generators used to supply or absorb
reactive power. We would suggest that I5 be changed to read “ –Static or dynamic devices specifically
used for supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a
dedicated transformer with a high-side voltage of 100 kV or higher, or through a transformer that is
designated in Inclusion I1.
No
Why was the defined term for “T”ransmission dropped in this version of the definition? This should be
kept in this version of the definition as well.
No
This number could change in phase two of the project which would create unnecessary work in the
future.
Yes
No
This particular Exclusion doesn’t address the qualifier as to the impact to the BES. We request that it
emulate the language provided for E2 (behind the meter gen) and classified for this specific exclusion.
Yes
A reference needs to be made to the ROP changes which also provide a mechanism whereby Elements
may be excluded/included in the BES. Without that reference the proposed definition does not
completely include all means for exceptions/inclusions. We would suggest the definition be expanded
to say ‘...modified by the list shown below or as provided by Appendix 5C of the NERC Rules of
Procedure. We submitted this in the original posting and the response received was that it was
inadvertently left out and that it would be placed back in. We don’t see the reference in this draft of
the definition.

Individual
Rick Hansen
City of St. George
Yes
The core definition is acceptable as long as the concerns for inclusion and exclusion are addressed as
outlined in the other comments.
Yes
No
The basis for the Compliance Registry Criteria generation levels for inclusion seems to be arbitrary
with little or no justification. As currently proposed, a small 20 MVA generator must comply with same
requirements as large units of several hundred MVA of generation capacity. Phase 2 of the BES
project may help address the issue but in the meantime many facilities must comply with numerous
standards with little or no benefit to the reliability of the actual BES. No timeline for Phase 2 is
indicated. Finding a bright line number for the generation levels on a per unit or overall plant basis
will be a difficult task, but the present MVA levels of the Registration Criteria are very low for
automatic inclusion. The compliance requirements of an entity should match the impact to the
system.
Yes
No
This language follows the 75 MVA plant requirements from the Registration Criteria. See comments to
question 3 (for I2) above. Additional detail is needed to clarify exactly at what point in the dispersed
system the BES starts and what is not BES.
No
A reasonable minimum value for inclusion should be added. As presently written all static or dynamic
devices would be included in the BES regardless of size.
No
Radial systems should be excluded as generally outlined in E1, however the generation levels (of 75
MVA) are too restrictive. The primary criteria should be, does power flow into the radial system? If
there is always flow into the radial system, generation levels should not prevent exclusion from the
BES.
No
Same basic comments and concerns as question #7.
No
The exclusion of Local Networks should be provided, however the generation level limits are too
restrictive. As long as the power flow is into the system the generation level of the local network
shouldn’t matter as long as it is being used to serve local load. E3a should be deleted from the
definition, or at least some higher level of allowed generation should be included. Another possibility
would be a ratio of local load to local generation. Areas with local generation serving local load will
have similar characteristics or affects to the BES system as were used in the Local Network
justification paper (Appendix 1) included with the documents. If some reasonable level of local
generation was added to the example system it is unlikely that the affects to the BES flows would
change from what was presented in the example.
Yes
Yes
The small utility exclusion issues discussed in the first draft of the documents are not included (draft
1 proposed E4) nor addressed in the draft 2 documentation. Under the present definition many small
utilities with local generation to serve its own local load will be required to register for additional
functions, or at a minimum go through a long, expensive, time consuming process to get an individual
exclusion from the BES. The topics that have been postponed to Phase 2 of the project are critical to
and will have a direct impact to many utilities. Phase 2 needs to have specific shorter than normal

timelines established, similar to what Phase 1 has had. The present definition and standards in
general makes little or no consideration for the actual impact of an entity or facility on the bulk
system. As such small utilities with a few miles of 115 kV or 138 kV lines and some generation are
required to meet the same requirements as large utilities with 100’s or 1,000’s of miles of 345 kV or
500 kV lines and that operate very large generation plants of several hundred MVA of capacity. All
utilities support reliability improvement, but the requirements and associated costs need to match
their actual impact to the overall system.
Group
Frank Gaffney
Florida Municipal Power Agency
Yes
FMPA appreciates the SDT’s work on this project. For the most part, FMPA supports what it believes to
be the intent of the proposed language. The proposed specific exclusion of facilities used in the local
distribution of electric energy is appropriate and consistent with Section 215 of the Federal Power Act.
However, we have suggestions to better carry out what we believe to be the SDT’s intent. The first
sentence can be read as: “… all … Real Power and Reactive Power resources connected at 100 kV or
higher”, which is surely not what the SDT intends. The basic problem is that Inclusions I2 and I4 do
not modify the first sentence, e.g., from a set theory perspective, the set described by the first
sentence includes the sets described in inclusions I2 and I4; hence, I2 and I4 do not modify the first
sentence. From a literal reading, this would cause any size generator connected at 100 kV to be
included, which is surely not the intent of the SDT. For similar reasons, the core definition and
Inclusion I5 now has the effect of including all generators connected at 100 kV since a generator is a
“dynamic device … supplying or absorbing Reactive Power”. The word “dedicated” in I5 is not
sufficient in FMPA’s mind to unambiguously exclude generators from this statement. FMPA suggests
the following wording to address these issues: "Transmission Elements (not including elements used
in the local distribution of electric energy) and Real Power and Reactive Power resources as described
in the list below, unless excluded by Exclusion or Exception: a. Transmission Elements other than
transformers and reactive resources operated at 100 kV or higher. b. Transformers with primary and
secondary terminals operated at 100 kV or higher. c. Generating resource(s) (with gross individual or
gross aggregate nameplate rating per the ERO Statement of Compliance Registry Criteria) including
the generator terminals through the high-side of the step-up transformer(s) connected at a voltage of
100 kV or above. d. Blackstart Resources identified in the Transmission Operator’s restoration plan. e.
Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) utilizing a system designed primarily for aggregating capacity, connected at a
common point at a voltage of 100 kV or above, but not including generation on the retail side of the
retail meter. f. Non-generator static or dynamic devices dedicated to supplying or absorbing more
than 6 MVAr of Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated
in bullet 2 above."
Yes
Please see comments to Question 1
Yes
Please see comments to Question 1
Yes
Please see comments to Question 1
Yes
We recommend clarifying that the dispersed power resources covered by this inclusion do not include
generators on the retail side of the retail meter. Specifically, we recommend that the Inclusion read:
“Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) utilizing a system designed primarily for aggregating capacity, connected at a
common point at a voltage of 100kV or above, but not including generation on the retail side of the
retail meter.”
To help clarify and to avoid inclusion of de minimis reactive resources, we propose a size threshold of
6 MVAr consistent with the smallest size generator included in the BES at a 0.95 power factor, which
is a common leading power factor used in Facility Connection Requirements for generators. In other

words, 6 MVAr is consistent with typically the least amount of MVAr required to be absorbed by the
smallest generator meeting the registry criteria.
Yes
FMPA supports the exclusion of radial systems from the BES Definition. Such systems are generally
not “necessary for operating an interconnected electric transmission network,” the standard in Orders
743 and 743-A. We have several suggestions to clarify the proposed language for this Exclusion.
Proposed Exclusion E1 refers to “[a] group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher.” We appreciate the SDT’s clarification of the point of
connection requirement, but the term “a single point of connection” should be further defined (more
clearly than just by voltage), and should be generic enough to encompass the various bus
configurations. It is not the case, for example, that each individual breaker position in a ring bus is a
separate point of connection for this purpose; in that situation, a bus at one voltage level at one
substation should be considered “a single point of connection.” Some examples of configurations that
should be considered a single point of connection for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples 1-6.
Although the core definition (appropriately) refers to “Transmission Elements” (with a capital “T”),
proposed Exclusion E1 refers to “transmission Elements” (with a lowercase “t”). To avoid confusion,
either “Transmission” should be capitalized in both locations, or the word “transmission” should
simply be deleted from Exclusion E1, leaving a “group of contiguous Elements.” We understand that
the lack of capitalization may have been a deliberate choice by the SDT in an attempt to avoid
confusion that SDT members believe exists in the Glossary definition. If the Glossary definition of
Transmission is unclear—which FMPA does not necessarily believe is the case—the answer is not to
simply abandon the Glossary definition in favor of an entirely undefined term; it is to submit a SAR to
improve the Glossary definition. Exclusion E1(c) refers to “an aggregate capacity of non-retail
generation less than or equal to 75 MVA.” “Non-retail generation” is potentially ambiguous, because it
could be read as distinguishing between generation that will be sold at wholesale and generation that
is used by the retail provider to meet retail load. On the understanding that the intent is in fact to
describe generation behind the end-user meter, sometimes referred to as “behind-the-second-meter
generation,” we suggest the following revision: “an aggregate generation capacity less than or equal
to 75 MVA, not including generation on the retail customer’s side of the retail meter.” Exclusion E1
concludes with a “Note”: “A normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion.” The Note should not specify
the types of evidence required to prove a normally open switch, and the phrase “as depicted on prints
or one-line diagrams” should be deleted. This phrase is equivalent to a “Measure” in a standard and
should not be embedded in the equivalent of a “Requirement.” Since the phrase only gives an
“example,” it does not in fact add anything to the Note, but may lead to confusion over what sort of
evidence is required.
Yes
Yes
: FMPA supports the exclusion of Local Networks from the BES. Such systems are generally not
“necessary for operating an interconnected electric transmission network,” the standard in Orders 743
and 743-A. However, we have several suggestions to clarify the proposed language for this Exclusion.
Exclusion E3(c) states: “Power flows only into the LN: The LN does not transfer energy originating
outside the LN for delivery through the LN.” This statement is unclear because the two parts mean
different things. FMPA proposes rewriting this sentence to state: “Power flows only into the LN, that
is, at each individual connection at 100 kV or higher, the pre-contingency flow of power is from
outside the LN into the LN for all hours of the previous 2 years” to help clarify the intent. Two years is
suggested because it is the time period set out in the draft exception application form for which an
applicant should state whether power flows through an Element to the BES. FMPA’ comments in
response to Question 7 above regarding “points of connection at 100kV or higher” and “non-retail
generation” are applicable to Exclusion E3 as well. The term “bulk power,” which occurs twice in
Exclusion E3, is vague and could be read incorrectly as a reference to the statutorily-defined “bulkpower system,” which is not, we think, the SDT’s intent. The word “bulk” should be deleted, so that
the Exclusion simply refers to transferring “power” across the interconnected system. FMPA raised
this concern in response to the last posting of the BES Definition. In response, the SDT removed
some instances of “bulk power” but left the remaining two, stating that “the SDT believes it provides

conceptual value to the exclusion principle.” The SDT does not state what conceptual value the term
is intended to provide; on the assumption that it relates to a distinction between transferring power
from local generation to serve local load, and transferring power over longer distances, FMPA
suggests, as an alternative to simply deleting the word “bulk,” that the Exclusion be revised to refer
to “transfers of power from non-LN generation to non-LN load.”
Yes

Individual
Donald E. Nelson
Massachusetts Department of Public Utilities
No
The Massachusetts Department of Public Utilities (“MA DPU”) appreciates the opportunity to provide
comments on the second draft definition of the Bulk Electric System (“BES”). Massachusetts is the
largest state by population and load in New England. It comprises 46% of both the region’s
population and electricity consumption. Generating plants located in Massachusetts represent 42% of
New England’s capacity and our capitol city, Boston, is the largest load center in the region. Some of
the revisions since the last posting of the draft BES definition have improved the proposed language.
However, the MA DPU has a number of concerns regarding both the substance of the definition and
the process for developing this standard: 1) Phased Approach. While well-intentioned, separating the
BES definition project into two separate phases is problematic from both a procedural and substantive
perspective. While we recognize that the filing due date is rapidly approaching, the BES definition
cannot be considered in a vacuum, divorced from the concerns raised by a number of parties in
response to past postings of the BES definition. The issues NERC has identified for consideration
during the proposed “Phase 2” are inseparable from the development of the BES definition (e.g.,
generation thresholds, technical justification for the 100 kV threshold) and should be squarely
addressed before a definition is adopted and ratepayers incur costs related to compliance with
mandates that may or may not be revised through the second phase of the project. The importance of
considering concerns before adopting a definition is heightened by the proposed two-year
implementation requirement. This short implementation period almost guarantees that entities will
commit resources shortly after adoption of the definition to ensure compliance within the mandated
period. In other words, ratepayers will bear costs related to compliance irrespective of any change
resulting from the Phase 2 process or the exception process. Expediency, while understandable given
the filing deadline, must be balanced against the risk that a multi-phased approach could lead to
significant consumer costs without attendant meaningful reliability benefits. 2) Cost-Benefit Analysis.
A cost impact analysis should be performed as part of developing any reliability standard. However,
the development of the BES definition has failed to consider the cost impacts of the definition (and its
inclusions and exclusions) and has not weighed these impacts against identified benefits that the
definition would achieve. The MA DPU supported the May 21, 2011 comments from the New England
States Committee on Electricity (“NESCOE”) on the last posting of the BES definition. In these
comments, NESCOE stated that “any new costs a revised definition imposes – which fall ultimately on
consumers – should provide meaningful reliability benefits.” A cost-benefit analysis should be integral
to the development of a BES definition and, indeed, any reliability standard. This analysis should
include a probabilistic risk assessment examining the likelihood of an event and the costs and risks
resulting from such event, which should be weighed against the costs of complying with the proposed
reliability measures. 3) Technical Justification. In addition to performing a cost-benefit analysis, a
technical basis must be provided to justify a proposed reliability standard. However, the proposed BES
definition does not provide a technical justification for the 100 kV threshold, the threshold for
generation resources, or other elements of the definition. As stated above, while well-intentioned and
understandable, deferring this technical justification to a later and separate phase of the project is a
flawed and potentially costly approach. Providing a technical justification for a reliability standard is a
core function of standards development and should be addressed at the forefront of the process
rather than relegated to a separate phase largely undertaken after a standard is filed. In Order 743,
the Federal Energy Regulatory Commission (“FERC” or “the Commission”) directed NERC to revise the
BES definition. Revision to Electric Reliability Organization Definition of Bulk Electric System, Order
No. 743A, 134 FERC ¶ 61,210 (Mar. 17, 2011) at P 8, citing to Revision to Electric Reliability

Organization Definition of Bulk Electric System, Order No. 743, 133 FERC ¶ 61,150 (2010). The
Commission stated that one way NERC could address the technical and policy concerns FERC had
identified would be to institute a “bright-line threshold that includes all facilities operated at or above
100 kV except defined radial facilities, and establish an exemption process and criteria for excluding
facilities [NERC] determines are not necessary for operating the interconnected transmission
network.” Id. at P 8. However, the Commission made clear in Order 743 that NERC may propose an
alternative proposal and that the 100 kV threshold is an “initial line of demarcation” to be refined
through exclusions and exemptions. Id. at PP 8, 40. Accordingly, unless and until NERC provides a
technical justification for its approach, the Standard should use the 100 kV threshold concept in a way
that is consistent with the Commission’s guidance. Specifically, the two criteria that bound the BES
definition are (1) the statutory exclusion of facilities used in local distribution, and (2) the
requirement that the facilities included be “necessary for reliable operation” of the interconnected
transmission system. A definition that recognizes these limits, coupled with an efficient and
transparent exception process, would appear to meet the Commission’s expectations. For these
reasons, absent a technical justification for imposing a 100 kV threshold, the MA DPU supports the
revised core definition offered by NESCOE in comments filed on this 2nd Draft: “All Transmission
Elements operated at 100 kV or higher and Real Power and Reactive Power resources connected at
100 kV or higher that are necessary for the reliable operation of the interconnected transmission
network, including but not limited to the facilities listed below as Inclusions, and excluding (1)
facilities that are used in the local distribution of electric energy, and (2) the facilities and systems
listed below as Exclusions. Other Elements may be included or excluded on a case-by-case basis
through the Rules of Procedure exception process.” The definition of the BES is critical to NERC’s role
as ERO and will have a significant impact on system reliability and cost to consumers. While FERC had
concerns that the existing definitions for the bulk power system were under-inclusive, the proposed
Standard, as drafted, risks erring in the opposite direction and appears inconsistent with the
Commission’s guidance in this area.
No
The MA DPU supports the revised Inclusion I1 language that treats Exclusions E1 and E3 as
alternative exclusions, either of which may qualify as an exclusion. However, specificity is needed
regarding what equipment is included in I1 (e.g., autotransformers, PARs, primary, secondary,
tertiary windings).
No
Failing to establish a known MVA rating at this stage is problematic. The BES definition cannot be
considered in a vacuum, and adjusting or establishing thresholds such as MVA ratings will create
regulatory uncertainty and may result in additional costs and unnecessary system upgrades.
Additionally, Inclusion I2 should remove the reference to the Statement of Compliance Registry
Criteria. The definition should be the governing document regarding generation that is included in the
BES.
No
The inclusion should be revised to specify that only those blackstart units that are “material to” the
BES are included in the definition.
No
The aggregate 75 MVA of connected generation does not appear to be adequately supported by
technical analysis and appears, on its face, as too low. Among our concerns is that such a low level
will have a potential adverse impact on the development of renewable generation resources. In
addition, the inclusion needs to be clarified in order that entities have clear guidance on what is
meant by “common point of interconnection.”
No
The inclusion of all devices that supply reactive power to the BES is unnecessary and will result in
unjustified costs to the ratepayer. Static devices (fixed capacitors) should remain excluded from the
BES as they are dispatched by operations personnel, and if one fixed capacitor bank fails, the
operator can replace its impact by switching in another fixed bank. This represents routine operation
of the system. On the other hand, dynamic devices may be important to maintaining voltage stability
of the system. These installations typically are rated to supply or absorb 75 MVA or more to or from
the BES. Therefore, the MA DPU suggests that dynamic reactive power devices rated at 75 MVA or
more could be included in the BES. Further, revised inclusion I5 is a new inclusion that lacks definition

(and appears to be redundant with the general BES definition). NERC should provide technical
justification for the additional language under Inclusion I5.
Yes
The aggregate 75 MVA of connected generation appears too low and would benefit from additional
technical justification.
Yes
While the MA DPU generally supports Exclusion E2, no information has been provided by NERC
demonstrating that the 75 MVA rating is based on any sound technical analysis.
Yes
The MA DPU generally supports this exclusion but believes it is too narrow. As noted in the response
to question 7, Exclusion E3 should likely allow a higher level of aggregate generation MVA on a Local
Network. In addition, local networks should not necessarily be ineligible for Exclusion E3 simply
because an amount of power may transfer out of the network at times. NERC’s draft technical
network exclusions document should be amended such that local networks would be permitted to
qualify for network exclusions under E3 if power flowing out of the network is minimal and would not
likely adversely impact the BES.
Yes
While we are generally supportive of this exclusion, the term “retail” needs to be clarified (i.e., are
retail customers of all sizes intended to be excluded?).
No
Individual
David Burke
Orange and Rockland Utilities, Inc.
Yes
Yes

Minimum Power system and material? NERC registry criteria for generation section "3C3"
No
Should also mention "unless excluded under Exclusion E1 or E3".
No
Please clarify on “single point of connection”. It seems like less confusion if “single source” is used
here instead of “single point of connection”.
No
We know that N-1 is assumed when power-flow study is performed, however, N-1 should be
mentioned here for clarification.
Yes

Individual
Bud Tracy
Blachly-Lane Electric Cooperative (BLEC)
Yes
The Blachly-Lane Electric Cooperative (BLEC) believes the SDT continues to make substantial
progress towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly
improves both the existing definition and the SDT’s previous proposal. BLEC therefore supports the
new definition, although our support is conditioned on: (1) a workable Exceptions process being

developed in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on
Phase II of the standards development process in accordance with the SAR recently put forward by
the SDT, which would address a number of important technical issues that have been identified in the
standards development process to date. BLEC strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, BLEC supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). BLEC thanks the SDT for the excellent work to include this sentence. For
similar reasons, BLEC believes the use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes clear
that the BES includes only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. BLEC recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, BLEC agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, BLEC is prepared to support the BES definition as
proposed by the SDT. While BLEC supports the overall approach adopted by the SDT and much of the
specific language incorporated into the second draft of the BES definition, we believe the second draft
would benefit from further clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential for
a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, BLEC believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
BLEC will support the SDT’s proposal.
Yes

We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
BLEC supports the changes made in Inclusion 2 and believes that the definition in its current form
adds clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the
previous draft definition into a single Inclusion that addresses the treatment of generation for
purposes of the BES definition. We also support the SDT’s proposal for a Phase II of the BES
Definition process that would examine the technical justification for these thresholds and that would
establish new thresholds based on a careful technical analysis. It is our understanding that the
generator threshold issue will be vetted through the complete standards development process. We
agree with this approach because if the generator threshold is treated as merely an element of
NERC’s Rules of Procedure, it can be changed with considerably less process and industry input than
the Standards Development Process. Compare NERC Rules of Procedure § 1400 (providing for
changes to Rules of Procedure upon approval of the NERC board and FERC) with NERC Standards
Process Manual (Sept. 3, 2010) (providing for, e.g., posting of SDT proposals for comment,
successive balloting, and super-majority approval requirements). See also Order No. 743-A, 134 FERC
¶ 61,210 at P 4 (2011) (“Order No. 743 directed the ERO to revise the definition of ‘bulk electric
system’ through the NERC Standards Development Process” (emph. added)). Addressing all aspects
of Phase II through the Standards Development Process will improve the content of the definition by
bringing to bear industry expertise on all aspects of the definition and will ensure that, once firm
guidelines are established, they can be relied upon by both industry and regulators without threat
that they will be changed with little notice and little process. BLEC believes further clarification of the
proposed language would be appropriate. The SDT proposes continued reliance upon the thresholds
that are used in the NERC Statement of Compliance Registry Criteria for registration of Generation
Owners and Generation Operators, which is currently 20 MVA for an individual generation unit and 75
MVA for multiple units on a single site. Conceptually, we are concerned about this approach because,
as we understand it, the purpose of the Compliance Registry is to sweep in all generators that might
be material to the reliable operation of the BES, and not to definitively determine whether a given
generator is, in fact, material to the reliable operation of the BES. As the SCRC itself states, the SCRC

is intended only to identify “candidates for registration.” SCRC at p.3, § 1 (emph. added).
Accordingly, we believe that the generator threshold determined in Phase II should be incorporated
directly into the BES Definition rather than being incorporated by reference from the SCRC. We also
believe that the specific language proposed by the SDT could be further clarified. The SDT proposes
that generation be included in the BES if the “Generation resource(s)” has a “nameplate rating per the
ERO Statement of Compliance Registry.” We understand this language is intended to be a placeholder
for the results of the technical analysis that would occur in Phase II but we believe simply stating that
the threshold will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the
reasons noted above, we believe the threshold should be part of the BES Definition, and should not
simply be a cross-reference to the SCRC (and, given the different purposes of the BES Definition and
the SCRC, it is not clear that the same threshold should be used in both). We therefore propose that
Inclusion 2 be rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate
Resources connected at a voltage of 100kV or above.” Two definitions would then be added to the
note at the end of the definition to read as follows: For purposes of this BES Definition, Qualifying
Individual Generation Resources means an individual generating unit that meets the materiality
threshold to be included in this definition or, in the absence of such a materiality threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of such a
resource as a Generation Owner under the ERO Statement of Compliance Registry Criteria. For
purposes of this BES Definition, Qualifying Aggregate Generation Resources means any facility
consisting of one or more generating units that are connected at a common bus that meets the
materiality threshold to be included in this definition, or, in the absence of such a threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of multipleunit generator as a Generation Owner under the ERO Statement of Compliance Registry Criteria.. The
“materiality threshold” is intended to refer to the generator threshold developed in Phase II. We
suggest using definitions in this fashion for several reasons. First, we believe the language we suggest
more clearly states the intention of the SDT, which we understand is to classify generation units as
part of the BES if they are necessary for operation of the BES, but to exclude smaller generating units
because they are not material to the operation of the interconnected transmission grid. Second, we
believe use of the defined terms better reflects the intention of the SDT to reserve the specific
question about generator thresholds to the technical analysis that will occur in Phase II without
having to revise the BES Definition at the end of that process. That is, the definitions are designed to
allow the SDT to include revised thresholds in the definition at the conclusion of the Phase II process
based upon the technical analysis planned for Phase II, and the revised thresholds will be
automatically incorporated into the BES Definition if the language we suggest is used. The thresholds
used in the SCRC would only be a fall-back, to be used only until Phase II is completed. Third, the
definitions can be incorporated into other parts of the BES Definition, which will add consistency and
clarity. As noted in our answers to several of the questions below, the specific 75 MVA threshold is
retained in several of the Exclusions and Inclusions, and we believe the industry would be better
served if the revised thresholds arrived at after technical analysis in Phase II are automatically
incorporated into all relevant provisions of the BES Definition. There is no reason for the SDT to
continue to rely on the 75 MVA threshold once the analysis planned for Phase II on the threshold
issue is completed. Fourth, the phrase “or that meets the materiality threshold to be included in this
definition” is intended to preserve the SDT’s flexibility to make a determination that generators below
a specific threshold are not “necessary to” maintain the reliability of the interconnected transmission
system, and to incorporate that finding as part of the definition itself, even if a different threshold is
used in the SCRC to identify potential candidates for registration. Accordingly, our proposed language
makes clear that a specific threshold in the definition controls over any threshold that might be
included in the SCRC. For the reasons stated above, we believe is it highly desirable to include any
material threshold in the BES Definition itself rather than relegating the threshold to the SCRC, which
is merely a procedural rule rather than a full-fledged Reliability Standard. Finally, we agree with the
SDT’s decision to examine the question of where the line between BES and non-BES Elements should
be drawn more closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and
commend the work of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good
starting point for the SDT’s analysis on this issue. We understand Inclusion 2 would classify
generators exceeding specific thresholds as part of the BES, but would not necessarily require
facilities interconnecting such generators to be part of the BES. As discussed more fully in our answer
to Question 9, based on extensive technical analysis that has already been performed by the NERC
Project 2010-07 Standards Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating

as part of the BES a dedicated interconnection facility connecting a BES generator to the
interconnected bulk transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no improvement in bulk
system reliability. We also believe the clauses at the end of Inclusion 2 are somewhat confusing and
that greater clarity would be achieved by changing “. . . including the generator terminals through the
high-side of the step-up transformer(s) connected at a voltage of 100kV or above” so that the
Inclusion covers transformers with terminals “connected at a voltage of 100kV or above, including the
generator terminal(s) on the high side of the step-up transformer(s) if operated at a voltage of 100kV
or above.”
Yes
BLEC supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
BLEC supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
BLEC has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, BLEC believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally, BLEC
believes this issue should be addressed in Phase 2 since there is not technical justification or analysis
done to determine the thresholds. BLEC strongly believes that there should be technical justification
for thresholds for this issue and all other issues.

Yes
BLEC continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, BLEC strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.
BLEC supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, BLEC urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN.
Yes
BLEC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of
radial systems to local networks should be encouraged because networked systems generally reduce
losses, increase system efficiency, and increase the level of service to retail customers. If the BES
definition were to provide an exclusion for radials without providing a similar exclusion for LNs,

however, it would discourage networking local distribution systems because of the significantly
increased regulatory burdens faced by the local distribution utility if it elected to network its radial
facilities. By placing radial systems and LNs on the same regulatory footing, the proposed definition
will ensure that decisions about whether to network radial systems are made on the basis of costs
and benefits to the retail customers served by those radials, and not on the basis of disparate
regulatory treatment. Consumers would ultimately benefit. BLEC also supports specific refinements
made to the LN exclusion by the SDT in the current draft of the BES definition. In particular, BLEC
supports the clarification of the purposes of a LN. The current draft states that LNs connect at multiple
points to “improve the level of service to retail customer Load and not to accommodate bulk power
transfer across the interconnected system.” BLEC supports this change in language because it reflects
the fundamental purposes of a LN and emphasizes one of the key distinctions between LNs and bulk
transmission facilities, namely, that LNs are designed primarily to serve local retail load while bulk
transmission facilities are designed primarily to move bulk power from a bulk source (generally either
the point of interconnection of a wholesale generator or a the point of interconnection with another
bulk transmission system) to one or more wholesale purchasers. BLEC believes further improvement
of the language could be achieved with additional modifications and clarifications. With respect to the
core language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
BLEC also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and
dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own

load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3.
BLEC also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as
long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as
a Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that
allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
transmission of electricity on the interconnected bulk system. Apart from these specific improvements
that we believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may
need to re-examine certain assumptions that appear to underlie the current draft. Specifically,
subparagraph (a) suggests that if BES generation is embedded within a LN, the LN itself must also be
BES. But two NERC bodies have already addressed similar questions and concluded there is no
technical basis for such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force” were formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. The GO-TO Team concluded that by complying with a handful of reliability
standards, primarily related to vegetation management, reliable operation of the bulk interconnected
system could be protected without unduly burdening the owners of such interconnection systems.
Therefore, there is no reason, according to the GO-TO Team, that dedicated high-voltage
interconnection facilities must be treated as “Transmission” and classified as part of the BES in order
to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO Task
Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most often
not part of the integrated bulk power system, and as such should not be subject to the same level of
standards applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” White Paper
Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at the
Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply
with the same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of the
equipment that actually produces electricity – the generation equipment itself.” Id. We believe that
interconnection of BES generators within a LN is analogous and that, based on the findings of the
Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply because a large
generator is embedded in the LN will result in substantial overregulation and unnecessary expense
with little gain for bulk system reliability. If anything, generation interconnected through a LN is less
likely to produce material impacts on the interconnected bulk transmission system than the
equivalent generator interconnected through a single dedicated line because an LN is interconnected
to the bulk system at several points, so that if one interconnection goes down, power can still flow
from the BES generator to the bulk system on other interconnection points. Where a dedicated
interconnection facility is involved, by contrast, if the interconnection line fails, the generator is
unavailable to the interconnected bulk system. Similarly, we suggest that the SDT re-examine the
assumptions underlying subparagraph (b), which seems to suggest that a local distribution system
cannot be classified as a Local Network if power flows out of that system at any time, even if the
amount is de minimis, the outward flow is only for a few hours, a year, or the outward flow occurs
only in an extreme contingency. Accordingly, we suggest that the initial clause of subparagraph (b) be
revised to read: “Except in unusual circumstances, power flows only into the LN.” Finally, we note
that the LN exclusion must not operate in any way as a substitution for the statutory prohibition on
including “facilities used in the local distribution of electric energy” in the BES. Therefore, even with
the LN exclusion, the SDT must retain this statutory language in the core definition of the BES, as
discussed in our answer to Question One. If a certain piece of equipment is a “facility used in the local
distribution of electric energy,” then it is not part of the BES in the first instance, and so consideration

of the LN Exclusion, or of any other Exclusion, any Inclusion, or any Exception, would be both
unnecessary and uncalled for.
Yes
BLEC supports the revised language because retail reactive devices are used to address local
customer or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such
local devices should therefore be excluded from the BES definition.
No
BLEC extends its thanks to the SDT and to the many industry entities that have actively participating
in the Standards Development Process. BLEC supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, BLEC is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that BLEC specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. BLEC supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. BLEC
also supports the 24-month transition period for the reasons laid out by the SDT.
Group
Steve Rueckert
WECC
Yes
Yes
Yes
Yes
WECC agrees with the inclusion of the blackstart units, but does not agree with the deletion of the
cranking path from the I3. The cranking path should be included in the definition since the NERC
standards EOP-005 and CIP-002 R1.2.4 require documenting the cranking path. The revised CIP-0024 Standard identifies the cranking path as a critical asset in Attachment 1 (1.5).
Yes
WECC seeks further clarification on Inclusion 4. Several comments were submitted in the last round of
comments whether each individual wind turbine in a wind farm, will be included in the BES. WECC
believes the language change to I4 by the SDT did not address this issue. The current language in I4
could be interpreted as each individual turbine (example 1MW) would be part of the BES. WECC
believes that I4 is not intended to include each individual wind turbine in a wind farm as a BES
element but rather to include the point at which the aggregation becomes large enough to meet the
aggregate capacity threshold of 75 MVA. WECC recommends the SDT modify the language in I4 to
clarify this issue.
Yes
WECC believes I5 should be modified to identify a minimum Reactive Power threshold for static or
dynamic devices similar to the threshold identified for generating resources in I2. As worded, any size

device dedicated to supplying or absorbing Reactive Power that is conected at 100 kV or higher, no
matter how small, would be included in the BES.
Yes
The use of the word “affect” in the note may cause problems with interpretation by users. WECC
suggests replacing the term "affect" with “alter”.
Yes
E2 is inconsistent with Section III.c. of the NERC Statement of Compliance Registry Criteria and is in
conflict with I2. As written, E2 uses a net capacity threshold of 75MVA, which does not distinguish
between a single generating unit and multiple generating units. The threshold in the NERC Statement
of Compliance Registry Criteria for a single generating unit is 20MVA. As a result, E2 would appear to
exclude generators from 20MVA to 75MVA that serve any amount of retail load behind the meter.
WECC recommends replacing “(i) the net capacity provided to the BES does not exceed 75 MVA” with
“(i) the net capacity provided to the BES does not exceed the individual or gross nameplate ratings
provided in the NERC Statement of Compliance Registry Criteria.” WECC’s recommended change
makes E2 consistent with I2 and the SDT’s plan to address generator thresholds in Phase II.
Yes
Yes
Yes
Following are additional comments not covered in previous questions: • Under the section “Effective
Dates”: There may be confusion with the statement “Compliance Obligations for Elements included by
definition shall begin 24 months after the applicable effective data of the definition.” The phrase
“included by definition” can be interpreted broadly. • WECC notes that a generation threshold of
75MVA is specified in Exclusions E1, E2, and E3. WECC believes that generation thresholds for
Exclusions should be addressed in Phase II when generation thresholds for Inclusions are being
considered.
Individual
Roger Meader
Coos-Curry Electric Cooperative (CCEC)
Yes
The Coos-Curry Electric Cooperative (CCEC ) believes the SDT continues to make substantial progress
towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly improves
both the existing definition and the SDT’s previous proposal. CCEC therefore supports the new
definition, although our support is conditioned on: (1) a workable Exceptions process being developed
in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II of
the standards development process in accordance with the SAR recently put forward by the SDT,
which would address a number of important technical issues that have been identified in the
standards development process to date. CCEC strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, CCEC supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the

high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). CCEC thanks the SDT for the excellent work to include this sentence. For
similar reasons, CCEC believes the use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes clear
that the BES includes only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. CCEC recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, CCEC agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, CCEC is prepared to support the BES definition
as proposed by the SDT. While CCEC supports the overall approach adopted by the SDT and much of
the specific language incorporated into the second draft of the BES definition, we believe the second
draft would benefit from further clarification or modification in a number of respects, most of which
are detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential
for a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, CCEC believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
CCEC will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations

and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
CCEC supports the changes made in Inclusion 2 and believes that the definition in its current form
adds clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the
previous draft definition into a single Inclusion that addresses the treatment of generation for
purposes of the BES definition. We also support the SDT’s proposal for a Phase II of the BES
Definition process that would examine the technical justification for these thresholds and that would
establish new thresholds based on a careful technical analysis. It is our understanding that the
generator threshold issue will be vetted through the complete standards development process. We
agree with this approach because if the generator threshold is treated as merely an element of
NERC’s Rules of Procedure, it can be changed with considerably less process and industry input than
the Standards Development Process. Compare NERC Rules of Procedure § 1400 (providing for
changes to Rules of Procedure upon approval of the NERC board and FERC) with NERC Standards
Process Manual (Sept. 3, 2010) (providing for, e.g., posting of SDT proposals for comment,
successive balloting, and super-majority approval requirements). See also Order No. 743-A, 134 FERC
¶ 61,210 at P 4 (2011) (“Order No. 743 directed the ERO to revise the definition of ‘bulk electric
system’ through the NERC Standards Development Process” (emph. added)). Addressing all aspects
of Phase II through the Standards Development Process will improve the content of the definition by
bringing to bear industry expertise on all aspects of the definition and will ensure that, once firm
guidelines are established, they can be relied upon by both industry and regulators without threat
that they will be changed with little notice and little process. CCEC believes further clarification of the
proposed language would be appropriate. The SDT proposes continued reliance upon the thresholds
that are used in the NERC Statement of Compliance Registry Criteria for registration of Generation
Owners and Generation Operators, which is currently 20 MVA for an individual generation unit and 75
MVA for multiple units on a single site. Conceptually, we are concerned about this approach because,
as we understand it, the purpose of the Compliance Registry is to sweep in all generators that might
be material to the reliable operation of the BES, and not to definitively determine whether a given
generator is, in fact, material to the reliable operation of the BES. As the SCRC itself states, the SCRC
is intended only to identify “candidates for registration.” SCRC at p.3, § 1 (emph. added).
Accordingly, we believe that the generator threshold determined in Phase II should be incorporated
directly into the BES Definition rather than being incorporated by reference from the SCRC. We also
believe that the specific language proposed by the SDT could be further clarified. The SDT proposes
that generation be included in the BES if the “Generation resource(s)” has a “nameplate rating per the
ERO Statement of Compliance Registry.” We understand this language is intended to be a placeholder
for the results of the technical analysis that would occur in Phase II but we believe simply stating that
the threshold will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the
reasons noted above, we believe the threshold should be part of the BES Definition, and should not
simply be a cross-reference to the SCRC (and, given the different purposes of the BES Definition and
the SCRC, it is not clear that the same threshold should be used in both). We therefore propose that
Inclusion 2 be rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate
Resources connected at a voltage of 100kV or above.” Two definitions would then be added to the
note at the end of the definition to read as follows: For purposes of this BES Definition, Qualifying
Individual Generation Resources means an individual generating unit that meets the materiality
threshold to be included in this definition or, in the absence of such a materiality threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of such a
resource as a Generation Owner under the ERO Statement of Compliance Registry Criteria. For
purposes of this BES Definition, Qualifying Aggregate Generation Resources means any facility
consisting of one or more generating units that are connected at a common bus that meets the

materiality threshold to be included in this definition, or, in the absence of such a threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of multipleunit generator as a Generation Owner under the ERO Statement of Compliance Registry Criteria.. The
“materiality threshold” is intended to refer to the generator threshold developed in Phase II. We
suggest using definitions in this fashion for several reasons. First, we believe the language we suggest
more clearly states the intention of the SDT, which we understand is to classify generation units as
part of the BES if they are necessary for operation of the BES, but to exclude smaller generating units
because they are not material to the operation of the interconnected transmission grid. Second, we
believe use of the defined terms better reflects the intention of the SDT to reserve the specific
question about generator thresholds to the technical analysis that will occur in Phase II without
having to revise the BES Definition at the end of that process. That is, the definitions are designed to
allow the SDT to include revised thresholds in the definition at the conclusion of the Phase II process
based upon the technical analysis planned for Phase II, and the revised thresholds will be
automatically incorporated into the BES Definition if the language we suggest is used. The thresholds
used in the SCRC would only be a fall-back, to be used only until Phase II is completed. Third, the
definitions can be incorporated into other parts of the BES Definition, which will add consistency and
clarity. As noted in our answers to several of the questions below, the specific 75 MVA threshold is
retained in several of the Exclusions and Inclusions, and we believe the industry would be better
served if the revised thresholds arrived at after technical analysis in Phase II are automatically
incorporated into all relevant provisions of the BES Definition. There is no reason for the SDT to
continue to rely on the 75 MVA threshold once the analysis planned for Phase II on the threshold
issue is completed. Fourth, the phrase “or that meets the materiality threshold to be included in this
definition” is intended to preserve the SDT’s flexibility to make a determination that generators below
a specific threshold are not “necessary to” maintain the reliability of the interconnected transmission
system, and to incorporate that finding as part of the definition itself, even if a different threshold is
used in the SCRC to identify potential candidates for registration. Accordingly, our proposed language
makes clear that a specific threshold in the definition controls over any threshold that might be
included in the SCRC. For the reasons stated above, we believe is it highly desirable to include any
material threshold in the BES Definition itself rather than relegating the threshold to the SCRC, which
is merely a procedural rule rather than a full-fledged Reliability Standard. Finally, we agree with the
SDT’s decision to examine the question of where the line between BES and non-BES Elements should
be drawn more closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and
commend the work of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good
starting point for the SDT’s analysis on this issue. We understand Inclusion 2 would classify
generators exceeding specific thresholds as part of the BES, but would not necessarily require
facilities interconnecting such generators to be part of the BES. As discussed more fully in our answer
to Question 9, based on extensive technical analysis that has already been performed by the NERC
Project 2010-07 Standards Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating
as part of the BES a dedicated interconnection facility connecting a BES generator to the
interconnected bulk transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no improvement in bulk
system reliability. We also believe the clauses at the end of Inclusion 2 are somewhat confusing and
that greater clarity would be achieved by changing “. . . including the generator terminals through the
high-side of the step-up transformer(s) connected at a voltage of 100kV or above” so that the
Inclusion covers transformers with terminals “connected at a voltage of 100kV or above, including the
generator terminal(s) on the high side of the step-up transformer(s) if operated at a voltage of 100kV
or above.”
Yes
CCEC supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
CCEC supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to

Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
CCEC has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, CCEC believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally, CCEC
believes this issue should be addressed in Phase 2 since there is not technical justification or analysis
done to determine the thresholds. CCEC strongly believes that there should be technical justification
for thresholds for this issue and all other issues.
Yes
CCEC continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II

included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, CCEC strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.
Yes
CCEC supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, CCEC urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN.
Yes
CCEC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of
radial systems to local networks should be encouraged because networked systems generally reduce
losses, increase system efficiency, and increase the level of service to retail customers. If the BES
definition were to provide an exclusion for radials without providing a similar exclusion for LNs,
however, it would discourage networking local distribution systems because of the significantly
increased regulatory burdens faced by the local distribution utility if it elected to network its radial
facilities. By placing radial systems and LNs on the same regulatory footing, the proposed definition
will ensure that decisions about whether to network radial systems are made on the basis of costs
and benefits to the retail customers served by those radials, and not on the basis of disparate
regulatory treatment. Consumers would ultimately benefit. CCEC also supports specific refinements
made to the LN exclusion by the SDT in the current draft of the BES definition. In particular, CCEC
supports the clarification of the purposes of a LN. The current draft states that LNs connect at multiple
points to “improve the level of service to retail customer Load and not to accommodate bulk power
transfer across the interconnected system.” CCEC supports this change in language because it reflects
the fundamental purposes of a LN and emphasizes one of the key distinctions between LNs and bulk
transmission facilities, namely, that LNs are designed primarily to serve local retail load while bulk
transmission facilities are designed primarily to move bulk power from a bulk source (generally either
the point of interconnection of a wholesale generator or a the point of interconnection with another
bulk transmission system) to one or more wholesale purchasers. CCEC believes further improvement
of the language could be achieved with additional modifications and clarifications. With respect to the
core language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by

deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
CCEC also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and
dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3.
CCEC also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as
long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as
a Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that
allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
transmission of electricity on the interconnected bulk system. Apart from these specific improvements
that we believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may
need to re-examine certain assumptions that appear to underlie the current draft. Specifically,
subparagraph (a) suggests that if BES generation is embedded within a LN, the LN itself must also be

BES. But two NERC bodies have already addressed similar questions and concluded there is no
technical basis for such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force” were formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. The GO-TO Team concluded that by complying with a handful of reliability
standards, primarily related to vegetation management, reliable operation of the bulk interconnected
system could be protected without unduly burdening the owners of such interconnection systems.
Therefore, there is no reason, according to the GO-TO Team, that dedicated high-voltage
interconnection facilities must be treated as “Transmission” and classified as part of the BES in order
to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO Task
Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most often
not part of the integrated bulk power system, and as such should not be subject to the same level of
standards applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” White Paper
Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at the
Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply
with the same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of the
equipment that actually produces electricity – the generation equipment itself.” Id. We believe that
interconnection of BES generators within a LN is analogous and that, based on the findings of the
Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply because a large
generator is embedded in the LN will result in substantial overregulation and unnecessary expense
with little gain for bulk system reliability. If anything, generation interconnected through a LN is less
likely to produce material impacts on the interconnected bulk transmission system than the
equivalent generator interconnected through a single dedicated line because an LN is interconnected
to the bulk system at several points, so that if one interconnection goes down, power can still flow
from the BES generator to the bulk system on other interconnection points. Where a dedicated
interconnection facility is involved, by contrast, if the interconnection line fails, the generator is
unavailable to the interconnected bulk system. Similarly, we suggest that the SDT re-examine the
assumptions underlying subparagraph (b), which seems to suggest that a local distribution system
cannot be classified as a Local Network if power flows out of that system at any time, even if the
amount is de minimis, the outward flow is only for a few hours, a year, or the outward flow occurs
only in an extreme contingency. Accordingly, we suggest that the initial clause of subparagraph (b) be
revised to read: “Except in unusual circumstances, power flows only into the LN.” Finally, we note
that the LN exclusion must not operate in any way as a substitution for the statutory prohibition on
including “facilities used in the local distribution of electric energy” in the BES. Therefore, even with
the LN exclusion, the SDT must retain this statutory language in the core definition of the BES, as
discussed in our answer to Question One. If a certain piece of equipment is a “facility used in the local
distribution of electric energy,” then it is not part of the BES in the first instance, and so consideration
of the LN Exclusion, or of any other Exclusion, any Inclusion, or any Exception, would be both
unnecessary and uncalled for.
Yes
CCEC supports the revised language because retail reactive devices are used to address local
customer or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such
local devices should therefore be excluded from the BES definition.
No
CCEC extends its thanks to the SDT and to the many industry entities that have actively participating
in the Standards Development Process. CCEC supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, CCEC is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not

be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that CCEC specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. CCEC supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. CCEC
also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Kathleen Goodman
ISO New England Inc
Yes
The second sentence is unclear with respect to its intent. If it’s intended to cover the exclusion
described in E3, the sentence is not needed. If it’s intended to mean something else, it is unclear as
to what is intended and likely should be deleted.
No
I1 needs to be clarified such that it is clear on whether this includes autotransformers, phase angle
regulators, and devices which have a tertiary winding. Using the tertiary winding as an example, it is
not clear whether the tertiary winding itself is considered BES, especially if it is serving a radial
system as described in E1.
Yes
No
The SDT has interpreted the FERC Directive to revise the BES definition in a manner that goes beyond
the mandate of ensuring that the definition encompasses all facilities necessary for operating an
interconnected electric transmission network. The SDT states that operation is interpreted as being
under both normal and emergency conditions. However, loss of all electric power is the end state
condition when all normal and emergency remediating actions have failed to prevent a collapse of the
grid. System restoration involves the use of blackstart generators that are not resources necessary
for operating the electrical grid but rather a means to recover following (not part of the emergency
itself) an extreme emergency. The SDT should simply refer to the current Compliance Registry,
which, for now, appears to adequately deal with the issue of how to treat Blackstart resources. I3
states “Blackstart Resources identified in the Transmission Operator’s restoration plan”. This is
contrary to the preferred language that is part of the approved ERO Statement of Compliance
Registry, III.C.3 that states, “Any generator, regardless of size, that is a blackstart unit material to
(emphasis added) and designated as part of a transmission operator entity’s restoration plan”. This
language is necessary to distinguish between those Blackstart Resources that are depended upon to
restore the BES following an emergency (“Key Facilities”) as compared to those Blackstart Resources
that are used to restore power to customer load. Additionally, discussions with others during the
preparation of comments have revealed that some interpret this requirement to include the GSU. We
do not interpret this in this manner, but this should be clarified to avoid confusion.
No
I4 is unclear as to whether or not the collector system (or system designed primarily for aggregating
capacity) itself is BES or just the resource. “Utilizing a system designed primarily for aggregating
capacity” needs to be more clearly defined to account for multiple systems that may exist out of one
common point. A suggestion would be to modify the end of the sentence to say “connected at any
common point.” I4 will allow for significant amounts of dispersed power producing resources to be
excluded from the BES. This includes wind resources which are increasing in numbers and having a
significant impact on system operations. It does not seem appropriate that having ten 70 MVA (total
of 700 MVA) installations each with their own connection to a 115 kV bus should fall outside of the
BES. As currently written, they would fall outside of the inclusion if they do not utilize the same
collector system. It is unclear whether or not supplemental equipment associated with the dispersed

power producing resources is included in the BES. As an example, many wind resources are being
interconnected utilizing supplemental dynamic and static reactive devices which are crucial to the
operation of these resources. The dynamic devices are often controlling themselves and static
reactive devices, which may or may not be connected above 100 kV. Leaving these devices out of the
BES definition seems to be a potential gap.
Yes
No
The term “single point” is not clear. A better explanation is necessary. For example, the same bus in a
bus/branch model should suffice as a “single point”. There should not be a requirement to be at the
same node as found in a nodal model. The term “a group of contiguous transmission elements” is
ambiguous and needs to be clarified. The “Non-retail” qualifier in E1.c) should be deleted. It adds
confusion to the exclusion and is not defined.
No
Exclusion E2 is confusing as written and seems counter intuitive. As an example, a 400 MW generator
which is behind the meter with a 400 MW load could be excluded. This generator could have a
significant impact on the performance of the system and yet it is excluded. As a simple example, loss
of the 400 MW generator would require that the 400 MW load be supplied from the system, possibly
leading to low voltages and thermal overloads. Additionally, a machine of this size could adversely
impact the dynamic response of the system, leading to damping concerns or unit instability. If E2 is to
be retained, it is not clear under what load conditions should the load at the facility be measured.
Load levels, and resulting net flows to the system, can be significantly different between seasons,
time of day, and the status of end user equipment at large industrial/manufacturing sites. The term
“Retail Customer Load” needs to be defined. The Balancing Authority should not be included as an
entity providing this service. In general the Statement of Compliance Registry has provided the
preferred language to use here (Page 9, [Exclusions: second paragraph).
No
E3 could result in many large load pockets being excluded from the BES definition and should be
deleted. Assuming that it is retained, we offer the following additional comments. The term “a group
of contiguous transmission elements” is ambiguous and needs to be clarified. Please clarify in the
exclusion if the flows into the LN as described in E3.b) are pre-contingency flows only. Please clarify
the system conditions (time of year, peak or off-peak) that should be considered in determining of
flow is only into the LN. The “Non-retail” qualifier in E3.a) should be deleted.
No
The term “retail customer” is unclear and will lead to confusion. This exclusion should be removed as
there are many instances where a generator may be using the reactive power device to meet other
interconnection requirements and the reactive device should be held to the same BES requirements
as the generator.
Yes
There are a number of possible scenarios where an element falls under both an inclusion and
exclusion. The definition is unclear as to whether or not this would have the element be BES or not.
During the webinar an example was given about a static shunt device meeting the requirements of I5,
but is part of a radial network. The response during the webinar was that this would be excluded. If
this is correct, it means that an exclusion takes precedence over an inclusion. Is this always the case?
This needs to be clarified and stated somewhere in this document. To be consistent with regard to the
terms “Operated at 100 kV” and “Connected at 100 kV “, we suggest that reference to generators
should state, “Connected at a transmission element operated at 100 kV”. This will avoid confusion in
cases where a generator is connected to a transmission element rated at 100 kV but operated at a
lower voltage.
Individual
Dave Markham
Central Electric Cooperatve (CEC)
Yes
The Central Electric Cooperative (CEC) believes the SDT continues to make substantial progress

towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly improves
both the existing definition and the SDT’s previous proposal. CEC therefore supports the new
definition, although our support is conditioned on: (1) a workable Exceptions process being developed
in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II of
the standards development process in accordance with the SAR recently put forward by the SDT,
which would address a number of important technical issues that have been identified in the
standards development process to date. CEC strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, CEC supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). CEC thanks the SDT for the excellent work to include this sentence. For
similar reasons, CEC believes the use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes clear
that the BES includes only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. CEC recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, CEC agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, CEC is prepared to support the BES definition as
proposed by the SDT. While CEC supports the overall approach adopted by the SDT and much of the
specific language incorporated into the second draft of the BES definition, we believe the second draft
would benefit from further clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential for
a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, CEC believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions

Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
CEC will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
CEC supports the changes made in Inclusion 2 and believes that the definition in its current form adds
clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the previous
draft definition into a single Inclusion that addresses the treatment of generation for purposes of the
BES definition. We also support the SDT’s proposal for a Phase II of the BES Definition process that
would examine the technical justification for these thresholds and that would establish new thresholds
based on a careful technical analysis. It is our understanding that the generator threshold issue will
be vetted through the complete standards development process. We agree with this approach
because if the generator threshold is treated as merely an element of NERC’s Rules of Procedure, it
can be changed with considerably less process and industry input than the Standards Development
Process. Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of Procedure upon
approval of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3, 2010)
(providing for, e.g., posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011) (“Order No. 743
directed the ERO to revise the definition of ‘bulk electric system’ through the NERC Standards
Development Process” (emph. added)). Addressing all aspects of Phase II through the Standards
Development Process will improve the content of the definition by bringing to bear industry expertise
on all aspects of the definition and will ensure that, once firm guidelines are established, they can be
relied upon by both industry and regulators without threat that they will be changed with little notice
and little process. CEC believes further clarification of the proposed language would be appropriate.
The SDT proposes continued reliance upon the thresholds that are used in the NERC Statement of
Compliance Registry Criteria for registration of Generation Owners and Generation Operators, which is
currently 20 MVA for an individual generation unit and 75 MVA for multiple units on a single site.

Conceptually, we are concerned about this approach because, as we understand it, the purpose of the
Compliance Registry is to sweep in all generators that might be material to the reliable operation of
the BES, and not to definitively determine whether a given generator is, in fact, material to the
reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to identify
“candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we believe that the
generator threshold determined in Phase II should be incorporated directly into the BES Definition
rather than being incorporated by reference from the SCRC. We also believe that the specific
language proposed by the SDT could be further clarified. The SDT proposes that generation be
included in the BES if the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder for the results of
the technical analysis that would occur in Phase II but we believe simply stating that the threshold
will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the reasons noted
above, we believe the threshold should be part of the BES Definition, and should not simply be a
cross-reference to the SCRC (and, given the different purposes of the BES Definition and the SCRC, it
is not clear that the same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate Resources
connected at a voltage of 100kV or above.” Two definitions would then be added to the note at the
end of the definition to read as follows: For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality threshold to be
included in this definition or, in the absence of such a materiality threshold, that meets the gross
nameplate capacity voltage threshold requiring registration of the owner of such a resource as a
Generation Owner under the ERO Statement of Compliance Registry Criteria. For purposes of this BES
Definition, Qualifying Aggregate Generation Resources means any facility consisting of one or more
generating units that are connected at a common bus that meets the materiality threshold to be
included in this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit generator as a
Generation Owner under the ERO Statement of Compliance Registry Criteria.. The “materiality
threshold” is intended to refer to the generator threshold developed in Phase II. We suggest using
definitions in this fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as part of the BES
if they are necessary for operation of the BES, but to exclude smaller generating units because they
are not material to the operation of the interconnected transmission grid. Second, we believe use of
the defined terms better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase II without having to revise the
BES Definition at the end of that process. That is, the definitions are designed to allow the SDT to
include revised thresholds in the definition at the conclusion of the Phase II process based upon the
technical analysis planned for Phase II, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase II is completed. Third, the definitions can be
incorporated into other parts of the BES Definition, which will add consistency and clarity. As noted in
our answers to several of the questions below, the specific 75 MVA threshold is retained in several of
the Exclusions and Inclusions, and we believe the industry would be better served if the revised
thresholds arrived at after technical analysis in Phase II are automatically incorporated into all
relevant provisions of the BES Definition. There is no reason for the SDT to continue to rely on the 75
MVA threshold once the analysis planned for Phase II on the threshold issue is completed. Fourth, the
phrase “or that meets the materiality threshold to be included in this definition” is intended to
preserve the SDT’s flexibility to make a determination that generators below a specific threshold are
not “necessary to” maintain the reliability of the interconnected transmission system, and to
incorporate that finding as part of the definition itself, even if a different threshold is used in the SCRC
to identify potential candidates for registration. Accordingly, our proposed language makes clear that
a specific threshold in the definition controls over any threshold that might be included in the SCRC.
For the reasons stated above, we believe is it highly desirable to include any material threshold in the
BES Definition itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Finally, we agree with the SDT’s decision to
examine the question of where the line between BES and non-BES Elements should be drawn more
closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and commend the work
of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting point for the
SDT’s analysis on this issue. We understand Inclusion 2 would classify generators exceeding specific

thresholds as part of the BES, but would not necessarily require facilities interconnecting such
generators to be part of the BES. As discussed more fully in our answer to Question 9, based on
extensive technical analysis that has already been performed by the NERC Project 2010-07 Standards
Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a
dedicated interconnection facility connecting a BES generator to the interconnected bulk transmission
grid will result in an unnecessary regulatory burden that produces considerable expense for the owner
of the interconnection facility with little or no improvement in bulk system reliability. We also believe
the clauses at the end of Inclusion 2 are somewhat confusing and that greater clarity would be
achieved by changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100kV or above” so that the Inclusion covers transformers
with terminals “connected at a voltage of 100kV or above, including the generator terminal(s) on the
high side of the step-up transformer(s) if operated at a voltage of 100kV or above.”
Yes
CEC supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
CEC supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
CEC has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, CEC believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally, CEC

believes this issue should be addressed in Phase 2 since there is not technical justification or analysis
done to determine the thresholds. CEC strongly believes that there should be technical justification for
thresholds for this issue and all other issues.
Yes
CEC continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, CEC strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.
Yes
CEC supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, CEC urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN.
Yes

CEC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of radial
systems to local networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. If the BES definition
were to provide an exclusion for radials without providing a similar exclusion for LNs, however, it
would discourage networking local distribution systems because of the significantly increased
regulatory burdens faced by the local distribution utility if it elected to network its radial facilities. By
placing radial systems and LNs on the same regulatory footing, the proposed definition will ensure
that decisions about whether to network radial systems are made on the basis of costs and benefits to
the retail customers served by those radials, and not on the basis of disparate regulatory treatment.
Consumers would ultimately benefit. CEC also supports specific refinements made to the LN exclusion
by the SDT in the current draft of the BES definition. In particular, CEC supports the clarification of
the purposes of a LN. The current draft states that LNs connect at multiple points to “improve the
level of service to retail customer Load and not to accommodate bulk power transfer across the
interconnected system.” CEC supports this change in language because it reflects the fundamental
purposes of a LN and emphasizes one of the key distinctions between LNs and bulk transmission
facilities, namely, that LNs are designed primarily to serve local retail load while bulk transmission
facilities are designed primarily to move bulk power from a bulk source (generally either the point of
interconnection of a wholesale generator or a the point of interconnection with another bulk
transmission system) to one or more wholesale purchasers. CEC believes further improvement of the
language could be achieved with additional modifications and clarifications. With respect to the core
language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
CEC also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and
dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term

“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3. CEC
also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as long as
subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as a Flow
Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that allow
reliable transmission of bulk electric power on the interconnected grid. If a LN has not been identified
as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable transmission
of electricity on the interconnected bulk system. Apart from these specific improvements that we
believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may need to
re-examine certain assumptions that appear to underlie the current draft. Specifically, subparagraph
(a) suggests that if BES generation is embedded within a LN, the LN itself must also be BES. But two
NERC bodies have already addressed similar questions and concluded there is no technical basis for
such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO
Task Force” were formed to address how the dedicated interconnection facilities linking a BES
generator to high-voltage transmission facilities should be treated under the NERC standards. The
GO-TO Team concluded that by complying with a handful of reliability standards, primarily related to
vegetation management, reliable operation of the bulk interconnected system could be protected
without unduly burdening the owners of such interconnection systems. Therefore, there is no reason,
according to the GO-TO Team, that dedicated high-voltage interconnection facilities must be treated
as “Transmission” and classified as part of the BES in order to make reliability standards effective.
See Final Report from the NERC Ad Hoc Group for Generator Requirements at the Transmission
Interface (Nov. 16, 2009) (paper written by the GO-TO Task Force). Similarly, the Project 2010-07
Team observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to Transmission
Owners and Transmission Operators who own and operate transmission Facilities and Elements that
are part of the integrated bulk power system.” White Paper Proposal for Information Comment, NERC
Project 2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011).
Requiring Generation Owners and Operators to comply with the same standards as BES Transmission
Owners and Operators “would do little, if anything, to improve the reliability of the Bulk Electric
System,” especially “when compared to the operation of the equipment that actually produces
electricity – the generation equipment itself.” Id. We believe that interconnection of BES generators
within a LN is analogous and that, based on the findings of the Project 2010-07 and GO-TO Teams,
automatically classifying a LN as “BES” simply because a large generator is embedded in the LN will
result in substantial overregulation and unnecessary expense with little gain for bulk system
reliability. If anything, generation interconnected through a LN is less likely to produce material
impacts on the interconnected bulk transmission system than the equivalent generator interconnected
through a single dedicated line because an LN is interconnected to the bulk system at several points,
so that if one interconnection goes down, power can still flow from the BES generator to the bulk
system on other interconnection points. Where a dedicated interconnection facility is involved, by
contrast, if the interconnection line fails, the generator is unavailable to the interconnected bulk
system. Similarly, we suggest that the SDT re-examine the assumptions underlying subparagraph
(b), which seems to suggest that a local distribution system cannot be classified as a Local Network if
power flows out of that system at any time, even if the amount is de minimis, the outward flow is
only for a few hours, a year, or the outward flow occurs only in an extreme contingency. Accordingly,
we suggest that the initial clause of subparagraph (b) be revised to read: “Except in unusual
circumstances, power flows only into the LN.” Finally, we note that the LN exclusion must not operate
in any way as a substitution for the statutory prohibition on including “facilities used in the local

distribution of electric energy” in the BES. Therefore, even with the LN exclusion, the SDT must retain
this statutory language in the core definition of the BES, as discussed in our answer to Question One.
If a certain piece of equipment is a “facility used in the local distribution of electric energy,” then it is
not part of the BES in the first instance, and so consideration of the LN Exclusion, or of any other
Exclusion, any Inclusion, or any Exception, would be both unnecessary and uncalled for.
Yes
CEC supports the revised language because retail reactive devices are used to address local customer
or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such local
devices should therefore be excluded from the BES definition.
No
CEC extends its thanks to the SDT and to the many industry entities that have actively participating in
the Standards Development Process. CEC supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, CEC is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that CEC specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. CEC supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. CEC
also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Dave Hagen
Clearwater Power Company (CPC)
Yes
The Clearwater Power Company (CPC) believes the SDT continues to make substantial progress
towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly improves
both the existing definition and the SDT’s previous proposal. CPC therefore supports the new
definition, although our support is conditioned on: (1) a workable Exceptions process being developed
in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II of
the standards development process in accordance with the SAR recently put forward by the SDT,
which would address a number of important technical issues that have been identified in the
standards development process to date. CPC strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, CPC supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.

§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). CPC thanks the SDT for the excellent work to include this sentence. For
similar reasons, CPC believes the use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes clear
that the BES includes only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. CPC recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, CPC agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, CPC is prepared to support the BES definition as
proposed by the SDT. While CPC supports the overall approach adopted by the SDT and much of the
specific language incorporated into the second draft of the BES definition, we believe the second draft
would benefit from further clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential for
a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, CPC believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
CPC will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the

juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
CPC supports the changes made in Inclusion 2 and believes that the definition in its current form adds
clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the previous
draft definition into a single Inclusion that addresses the treatment of generation for purposes of the
BES definition. We also support the SDT’s proposal for a Phase II of the BES Definition process that
would examine the technical justification for these thresholds and that would establish new thresholds
based on a careful technical analysis. It is our understanding that the generator threshold issue will
be vetted through the complete standards development process. We agree with this approach
because if the generator threshold is treated as merely an element of NERC’s Rules of Procedure, it
can be changed with considerably less process and industry input than the Standards Development
Process. Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of Procedure upon
approval of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3, 2010)
(providing for, e.g., posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011) (“Order No. 743
directed the ERO to revise the definition of ‘bulk electric system’ through the NERC Standards
Development Process” (emph. added)). Addressing all aspects of Phase II through the Standards
Development Process will improve the content of the definition by bringing to bear industry expertise
on all aspects of the definition and will ensure that, once firm guidelines are established, they can be
relied upon by both industry and regulators without threat that they will be changed with little notice
and little process. CPC believes further clarification of the proposed language would be appropriate.
The SDT proposes continued reliance upon the thresholds that are used in the NERC Statement of
Compliance Registry Criteria for registration of Generation Owners and Generation Operators, which is
currently 20 MVA for an individual generation unit and 75 MVA for multiple units on a single site.
Conceptually, we are concerned about this approach because, as we understand it, the purpose of the
Compliance Registry is to sweep in all generators that might be material to the reliable operation of
the BES, and not to definitively determine whether a given generator is, in fact, material to the
reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to identify
“candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we believe that the
generator threshold determined in Phase II should be incorporated directly into the BES Definition
rather than being incorporated by reference from the SCRC. We also believe that the specific
language proposed by the SDT could be further clarified. The SDT proposes that generation be
included in the BES if the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder for the results of
the technical analysis that would occur in Phase II but we believe simply stating that the threshold
will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the reasons noted
above, we believe the threshold should be part of the BES Definition, and should not simply be a
cross-reference to the SCRC (and, given the different purposes of the BES Definition and the SCRC, it
is not clear that the same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate Resources
connected at a voltage of 100kV or above.” Two definitions would then be added to the note at the
end of the definition to read as follows: For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality threshold to be
included in this definition or, in the absence of such a materiality threshold, that meets the gross
nameplate capacity voltage threshold requiring registration of the owner of such a resource as a

Generation Owner under the ERO Statement of Compliance Registry Criteria. For purposes of this BES
Definition, Qualifying Aggregate Generation Resources means any facility consisting of one or more
generating units that are connected at a common bus that meets the materiality threshold to be
included in this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit generator as a
Generation Owner under the ERO Statement of Compliance Registry Criteria.. The “materiality
threshold” is intended to refer to the generator threshold developed in Phase II. We suggest using
definitions in this fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as part of the BES
if they are necessary for operation of the BES, but to exclude smaller generating units because they
are not material to the operation of the interconnected transmission grid. Second, we believe use of
the defined terms better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase II without having to revise the
BES Definition at the end of that process. That is, the definitions are designed to allow the SDT to
include revised thresholds in the definition at the conclusion of the Phase II process based upon the
technical analysis planned for Phase II, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase II is completed. Third, the definitions can be
incorporated into other parts of the BES Definition, which will add consistency and clarity. As noted in
our answers to several of the questions below, the specific 75 MVA threshold is retained in several of
the Exclusions and Inclusions, and we believe the industry would be better served if the revised
thresholds arrived at after technical analysis in Phase II are automatically incorporated into all
relevant provisions of the BES Definition. There is no reason for the SDT to continue to rely on the 75
MVA threshold once the analysis planned for Phase II on the threshold issue is completed. Fourth, the
phrase “or that meets the materiality threshold to be included in this definition” is intended to
preserve the SDT’s flexibility to make a determination that generators below a specific threshold are
not “necessary to” maintain the reliability of the interconnected transmission system, and to
incorporate that finding as part of the definition itself, even if a different threshold is used in the SCRC
to identify potential candidates for registration. Accordingly, our proposed language makes clear that
a specific threshold in the definition controls over any threshold that might be included in the SCRC.
For the reasons stated above, we believe is it highly desirable to include any material threshold in the
BES Definition itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Finally, we agree with the SDT’s decision to
examine the question of where the line between BES and non-BES Elements should be drawn more
closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and commend the work
of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting point for the
SDT’s analysis on this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities interconnecting such
generators to be part of the BES. As discussed more fully in our answer to Question 9, based on
extensive technical analysis that has already been performed by the NERC Project 2010-07 Standards
Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a
dedicated interconnection facility connecting a BES generator to the interconnected bulk transmission
grid will result in an unnecessary regulatory burden that produces considerable expense for the owner
of the interconnection facility with little or no improvement in bulk system reliability. We also believe
the clauses at the end of Inclusion 2 are somewhat confusing and that greater clarity would be
achieved by changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100kV or above” so that the Inclusion covers transformers
with terminals “connected at a voltage of 100kV or above, including the generator terminal(s) on the
high side of the step-up transformer(s) if operated at a voltage of 100kV or above.”
Yes
CPC supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
CPC supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate

nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
CPC has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, CPC believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally, CPC
believes this issue should be addressed in Phase 2 since there is not technical justification or analysis
done to determine the thresholds. CPC strongly believes that there should be technical justification for
thresholds for this issue and all other issues.
Yes
CPC continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate

Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, CPC strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.
Yes
CPC supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, CPC urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN.
Yes
CPC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of radial
systems to local networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. If the BES definition
were to provide an exclusion for radials without providing a similar exclusion for LNs, however, it
would discourage networking local distribution systems because of the significantly increased
regulatory burdens faced by the local distribution utility if it elected to network its radial facilities. By
placing radial systems and LNs on the same regulatory footing, the proposed definition will ensure
that decisions about whether to network radial systems are made on the basis of costs and benefits to
the retail customers served by those radials, and not on the basis of disparate regulatory treatment.
Consumers would ultimately benefit. CPC also supports specific refinements made to the LN exclusion
by the SDT in the current draft of the BES definition. In particular, CPC supports the clarification of
the purposes of a LN. The current draft states that LNs connect at multiple points to “improve the
level of service to retail customer Load and not to accommodate bulk power transfer across the
interconnected system.” CPC supports this change in language because it reflects the fundamental
purposes of a LN and emphasizes one of the key distinctions between LNs and bulk transmission
facilities, namely, that LNs are designed primarily to serve local retail load while bulk transmission
facilities are designed primarily to move bulk power from a bulk source (generally either the point of
interconnection of a wholesale generator or a the point of interconnection with another bulk
transmission system) to one or more wholesale purchasers. CPC believes further improvement of the
language could be achieved with additional modifications and clarifications. With respect to the core

language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
CPC also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and
dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3. CPC
also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as long as
subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as a Flow
Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that allow
reliable transmission of bulk electric power on the interconnected grid. If a LN has not been identified
as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable transmission
of electricity on the interconnected bulk system. Apart from these specific improvements that we
believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may need to

re-examine certain assumptions that appear to underlie the current draft. Specifically, subparagraph
(a) suggests that if BES generation is embedded within a LN, the LN itself must also be BES. But two
NERC bodies have already addressed similar questions and concluded there is no technical basis for
such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO
Task Force” were formed to address how the dedicated interconnection facilities linking a BES
generator to high-voltage transmission facilities should be treated under the NERC standards. The
GO-TO Team concluded that by complying with a handful of reliability standards, primarily related to
vegetation management, reliable operation of the bulk interconnected system could be protected
without unduly burdening the owners of such interconnection systems. Therefore, there is no reason,
according to the GO-TO Team, that dedicated high-voltage interconnection facilities must be treated
as “Transmission” and classified as part of the BES in order to make reliability standards effective.
See Final Report from the NERC Ad Hoc Group for Generator Requirements at the Transmission
Interface (Nov. 16, 2009) (paper written by the GO-TO Task Force). Similarly, the Project 2010-07
Team observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to Transmission
Owners and Transmission Operators who own and operate transmission Facilities and Elements that
are part of the integrated bulk power system.” White Paper Proposal for Information Comment, NERC
Project 2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011).
Requiring Generation Owners and Operators to comply with the same standards as BES Transmission
Owners and Operators “would do little, if anything, to improve the reliability of the Bulk Electric
System,” especially “when compared to the operation of the equipment that actually produces
electricity – the generation equipment itself.” Id. We believe that interconnection of BES generators
within a LN is analogous and that, based on the findings of the Project 2010-07 and GO-TO Teams,
automatically classifying a LN as “BES” simply because a large generator is embedded in the LN will
result in substantial overregulation and unnecessary expense with little gain for bulk system
reliability. If anything, generation interconnected through a LN is less likely to produce material
impacts on the interconnected bulk transmission system than the equivalent generator interconnected
through a single dedicated line because an LN is interconnected to the bulk system at several points,
so that if one interconnection goes down, power can still flow from the BES generator to the bulk
system on other interconnection points. Where a dedicated interconnection facility is involved, by
contrast, if the interconnection line fails, the generator is unavailable to the interconnected bulk
system. Similarly, we suggest that the SDT re-examine the assumptions underlying subparagraph
(b), which seems to suggest that a local distribution system cannot be classified as a Local Network if
power flows out of that system at any time, even if the amount is de minimis, the outward flow is
only for a few hours, a year, or the outward flow occurs only in an extreme contingency. Accordingly,
we suggest that the initial clause of subparagraph (b) be revised to read: “Except in unusual
circumstances, power flows only into the LN.” Finally, we note that the LN exclusion must not operate
in any way as a substitution for the statutory prohibition on including “facilities used in the local
distribution of electric energy” in the BES. Therefore, even with the LN exclusion, the SDT must retain
this statutory language in the core definition of the BES, as discussed in our answer to Question One.
If a certain piece of equipment is a “facility used in the local distribution of electric energy,” then it is
not part of the BES in the first instance, and so consideration of the LN Exclusion, or of any other
Exclusion, any Inclusion, or any Exception, would be both unnecessary and uncalled for.
Yes
CPC supports the revised language because retail reactive devices are used to address local customer
or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such local
devices should therefore be excluded from the BES definition.
No
CPC extends its thanks to the SDT and to the many industry entities that have actively participating in
the Standards Development Process. CPC supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, CPC is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES

Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that CPC specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. CPC supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. CPC
also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Eric Lee Christensen
Snohomish County PUD
Yes
The Public Utility District No. 1 of Snohomish County (“SNPD”) believes the SDT continues to make
substantial progress towards a clear and workable definition of the Bulk Electric System (“BES”) that
markedly improves both the existing definition and the SDT’s previous proposal. SNPD therefore
strongly supports the new definition, although our support is conditioned on: (1) a workable
Exceptions process being developed in conjunction with the BES definition; and, (2) the SDT moving
forward expeditiously on Phase II of the standards development process in accordance with the SAR
recently put forward by the SDT, which would address a number of important technical issues that
have been identified in the standards development process to date. SNPD strongly supports the
following elements of the revised BES definition: (1) Clarification of how lists of Inclusions and
Exclusions applies: The revised core definition moves the phrase “Unless modified by the lists shown
below” to the beginning of the definition. This change makes clear that the Inclusions and Exclusions
apply to all Elements that would otherwise be included in or excluded from the core definition (i.e.,
“all Transmission Elements operated at 100 kV or higher and Real Time and Reactive Power resources
connected at 100 kV or higher”) and eliminates a latent ambiguity in the first draft of the definition,
discussed further in our comments on the first draft. (2) The exclusion for Local Distribution Facilities.
As the starting point for the BES definition, SNPD supports use of the phrase “all Transmission
Elements” and the qualifying sentence: “This does not include facilities used in the local distribution of
electric energy.” This language helps ensure that FERC, NERC, and the Regional Entities (“REs”) will
act within the jurisdictional constrains Congress placed in Section 215 of the Federal Power Act
(“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in the local distribution
of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C. § 824o(a)(1).
Including the same language in the definition helps ensure that entities involved in enforcement of
reliability standards will act within their statutory limits. In addition, as a practical matter, inclusion of
the language will help focus both the industry and responsible agencies on the high-voltage interstate
transmission system, where the reliability problems Congress intended to regulate – “instability,
uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) – will originate. At the
same time, level-of-service issues arising in local distribution systems will be left to the authority of
state and local regulatory agencies and governing bodies, just as Congress intended. 16 U.S.C. §
824o(i)(2) (reserving to state and local authorities enforcement of standards for adequacy of service).
For similar reasons, Snohomish believes use of the phrase “Transmission Elements” as the starting
point for the base definition is desirable because both “Transmission” and “Elements” are already
defined in the NERC Glossary of Terms Used, and the term “Transmission” makes clear that the BES
includes only Elements used in Transmission and therefore excludes Elements used in local
distribution of electric power. (3) Appropriate Generator Thresholds. In the standards development
process, it has become apparent that the thresholds for classifying generators as BES in the current
NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual generators, 75 MVA
for multiple generators aggregated at a single site), which predate the adoption of FPA Section 215,
were never the product of a careful analysis to determine whether generators of that size are
necessary for operation of the interconnected bulk transmission system. Ideally, such an analysis
would be conducted as part of the current standards development process. Snohomish recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to

conduct such an analysis within the time available. Accordingly, Snohomish agrees with the approach
taken by the SDT, which is to propose a Phase II of the standards development process that would
address the generator threshold issue and several other technical issues that have arisen during the
current process. As long as Phase II proceeds expeditiously, Snohomish is prepared to support the
BES definition as proposed by the SDT. While Snohomish strongly supports the overall approach
adopted by the SDT and much of the specific language incorporated into the second draft of the BES
definition, we believe the second draft would benefit from further clarification or modification in a
number of respects, most of which are detailed in our subsequent answers. Our support for the
definition is not contingent upon these changes being adopted. Further, we believe a workable
Exclusion Process is essential for a BES Definition that will meet the legal requirements of FPA Section
215, especially for systems operating in the Western Interconnection. As detailed in our previous
comments, Snohomish believes a 200-kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200-kV threshold for the West is backed by solid technical analysis
conducted by the WECC Bulk Electric System Definition Task Force, and repeated claims that there is
no technical analysis to support this view is therefore incorrect. That being said, we raise the issue
here to emphasize the importance of the Exclusions for Local Networks and Radial Systems and the
Exceptions process. These Exclusions and the Exceptions are essential for a definition that works in
the Western Interconnection because the core definition will be over-inclusive in our region. As long
as those Exclusions and the Exceptions Process are retained in a form substantially equivalent to
those produced by the SDT at this juncture, Snohomish will support the SDT’s proposal and will not
further pursue its claims regarding the 200-kV threshold. Finally, we suggest that the SDT address
the circumstance when an Element is covered by both an Inclusion and an Exclusion. We note that
some of the inclusions already contain language addressing this question. For example, Inclusion 1
indicates that transformers falling within the specified parameters are part of the BES “. . . unless
excluded under Exclusions E1 or E3.” Where it is not already included, similar language should be
included in the other Inclusions and/or Exclusions to explain whether the SDT intends the Inclusions
or the Exclusions to predominate in situations where facilities might be covered by both. We suggest
clarifying language in our responses to Questions 2 and 5.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100 kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100 kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the

transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
SNPD supports the changes made in Inclusion 2 and believe that the definition in its current form
adds clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the
previous draft definition into a single Inclusion that addresses the treatment of generation for
purposes of the BES definition. We also support the SDT’s proposal for a Phase II of the BES
Definition process to examine the technical justification for these thresholds and to establish new
thresholds based on a careful technical analysis. It is our understanding that the generator threshold
issue will be vetted through the complete standards development process. We agree with this
approach because if the generator threshold is treated as merely an element of NERC’s Rules of
Procedure, it can be changed with considerably less due process and industry input than the
Standards Development Process. Compare NERC Rules of Procedure § 1400 (providing for changes to
Rules of Procedure upon approval of the NERC board and FERC) with NERC Standards Process Manual
(Sept. 3, 2010) (providing for, e.g., posting of SDT proposals for comment, successive balloting, and
super-majority approval requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011)
(“Order No. 743 directed the ERO to revise the definition of ‘bulk electric system’ through the NERC
Standards Development Process” (emph. added)). Addressing all aspects of Phase II through the
Standards Development Process will improve the content of the definition by bringing to bear industry
expertise on all aspects of the definition and will ensure that, once firm guidelines are established,
they can be relied upon by both industry and regulators without threat that they will be changed with
little notice and little due process. SNPD also believes further clarification of the proposed language
would be appropriate. The SDT proposes continued reliance upon the thresholds that are used in the
NERC Statement of Compliance Registry Criteria for registration of Generation Owners and Generation
Operators, which is currently 20 MVA for an individual generation unit and 75 MVA for multiple units
on a single site. Conceptually, we are concerned about this approach because, as we understand it,
the purpose of the Compliance Registry is to sweep in all generators that might be material to the
reliable operation of the BES, and not to definitively determine whether a given generator is, in fact,
material to the reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to
identify “candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we believe that
the generator threshold determined in Phase II should be incorporated directly into the BES Definition
rather than being incorporated by reference from the SCRC. We also believe that the specific
language proposed by the SDT could be further clarified. The SDT proposes to include generation in
the BES if the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder for the results of
the technical analysis that would occur in Phase II but we believe simply stating that the threshold
will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the reasons noted
above, we believe the threshold should be part of the BES Definition, and should not simply be a
cross-reference to the SCRC (and, given the different purposes of the BES Definition and the SCRC, it
is not clear that the same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate Resources
connected at a voltage of 100 kV or above.” Two definitions would then be added to the note at the
end of the definition to read as follows: "For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality threshold to be
included in this definition or, in the absence of such a materiality threshold, that meets the gross
nameplate capacity voltage threshold requiring registration of the owner of such a resource as a
Generation Owner under the ERO Statement of Compliance Registry Criteria." "For purposes of this
BES Definition, Qualifying Aggregate Generation Resources means any facility consisting of one or
more generating units that are connected at a common bus that meets the materiality threshold to be
included in this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit generator as a
Generation Owner under the ERO Statement of Compliance Registry Criteria." The “materiality
threshold” is intended to refer to the generator threshold developed in Phase II. We suggest using
definitions in this fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as part of the BES
if they are necessary for operation of the BES, but to exclude smaller generating units because they
are not material to the operation of the interconnected transmission grid. Second, we believe use of
the defined terms better reflects the intention of the SDT to reserve the specific question about

generator thresholds to the technical analysis that will occur in Phase II without having to revise the
BES Definition at the end of that process. That is, the definitions are designed to allow the SDT to
include revised thresholds in the definition at the conclusion of the Phase II process based upon the
technical analysis planned for Phase II, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase II is completed. Third, the definitions can be
incorporated into other parts of the BES Definition, which will add consistency and clarity. As noted in
our answers to several of the questions below, the specific 75 MVA threshold is retained in several of
the Exclusions and Inclusions, and we believe the industry would be better served if the revised
thresholds arrived at after technical analysis in Phase II are automatically incorporated into all
relevant provisions of the BES Definition. There is no reason for the SDT to continue to rely on the 75
MVA threshold once the analysis planned for Phase II on the threshold issue is completed. Fourth, the
phrase “or that meets the materiality threshold to be included in this definition” is intended to
preserve the SDT’s flexibility to make a determination that generators below a specific threshold are
not “necessary to” maintain the reliability of the interconnected transmission system, and to
incorporate that finding as part of the definition itself, even if a different threshold is used in the SCRC
to identify potential candidates for registration. Accordingly, our proposed language makes clear that
a specific threshold in the definition controls over any threshold that might be included in the SCRC.
For the reasons stated above, we believe is it highly desirable to include any material threshold in the
BES Definition itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Hence, we agree with the SDT’s decision to
examine the question of where the line between BES and non-BES Elements should be drawn more
closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and commend the work
of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting point for the
SDT’s analysis on this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities interconnecting such
generators to be part of the BES. As discussed more fully in our answer to Question 9, based on
extensive technical analysis that has already been performed by the NERC Project 2010-07 Standards
Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a
dedicated interconnection facility connecting a BES generator to the interconnected bulk transmission
grid will result in an unnecessary regulatory burden that produces considerable expense for the owner
of the interconnection facility with little or no improvement in bulk system reliability. We also believe
the clauses at the end of Inclusion 2 are somewhat confusing and that greater clarity would be
achieved by changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above” so that the Inclusion covers transformers
with terminals “connected at a voltage of 100 kV or above, including the generator terminal(s) on the
high side of the step-up transformer(s) if operated at a voltage of 100 kV or above.” Finally, as
discussed further in our answer to Questions 5 and 6, SNPD believes more clarity may be achieved by
collapsing Inclusion 5, addressing Reactive Power resources, and Inclusion 4, which addresses
dispersed renewable resources, into a single Inclusion that addresses “power producing resources”
(the language used in current Inclusion 4).
Yes
SNPD supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
SNPD supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which is discussed in more detail in our response to
Question 3. This language, or some equivalent, will preserve the SDT’s ability to revise the 75 MVA
threshold in Phase II, with the result of Phase II included in the BES Definition by operation rather
than requiring further revision of the Definition. More generally, we are not certain what is
accomplished by Inclusion 4 that is not already accomplished by Inclusion 2, which also addresses
whether generation should be defined as BES. The SDT’s stated concern is with variable generation
units such as wind and solar plants. It is not clear to us why this concern is not fully addressed in

Inclusion 2, which addresses multiple generation units connected at a common bus, the configuration
of most variable generation plants with multiple units. We are also concerned that the language, as
proposed, could have unintended consequences and improperly classify local distribution systems as
BES in certain circumstances. This is because multiple distributed generation units could render a
local distribution system a “collector system” and the entire system the equivalent of an aggregated
generation unit, causing the local distribution system to be improperly denied status as a LN. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
SNPD has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Finally, SNPD believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process.
Yes
SNPD continues to support the radial system exclusion, which is necessary as a legal matter, because,
for example, FERC in Orders No. 743 and 743-A has required that the existing radial exemption in the
NERC Statement of Compliance Registry Criteria be maintained. As a practical matter, radial systems
are used for service to retail loads, usually in remote or rural areas, and not for the transmission of
bulk power. Hence, operation of the radials has little or nothing to do with the reliable operation of
the interconnected bulk transmission network. We also support the inclusion of the note discussing
normally open switches because this language provides needed clarity for a common radial system
configuration. We also agree with the substantive thrust of this language, which is that a radial
system should not be considered part of the BES if it is interconnected at a single point, even if there
is an alternative point of delivery that is normally open. While we support the Exclusion for Radial
Systems, we believe several clarifications and refinements are necessary. (1) The term “transmission
Elements” in the initial paragraph should be changed to “Elements.” Radial systems are not
transmission systems and including the word “transmission” in the Radial System exclusion is
therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to “generation
resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)”). We
urge the SDT to replace this language with the defined term “Qualifying Aggregate Generation
Resources,” discussed in more detail in our response to Question 3. This language, or some
equivalent, will preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result
of Phase II included in the BES Definition by operation rather than requiring further revision of the
Definition. (3) Subparagraph (b) also seems to assume that if a Radial System contains a generator
exceeding the 75 MVA threshhold, the Radial System itself must be included in the BES because it
links the generator to the interconnected bulk transmission system. As discussed more fully in our
response to Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task
Force have both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT
indicates that “a normally open switching device between radial systems” will not serve to disqualify
the Radial from exclusion under Exclusion 1. As noted above, SNPD strongly supports the note
conceptually. However, we believe this language should be included in a separate subparagraph (d),

rather than a note, because treatment as a “note” suggests it is less important than other portions of
the Exclusion. We also suggest the language be changed to read: "d) Normally-open switching
devices between radial elements as depicted and identified on system one-line diagrams does not
affect this exclusion." This will make clear that a radial with more than one normally-open switch
connecting it to another radial is still a radial. From the perspective of the BES Definition, the key
question is whether switches operating between Radials are normally open, not whether there is more
than one normally-open switch.
Yes
SNPD supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, SNPD urges the SDT to remove the reference to
the 75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation
Resources” or some equivalent language for the reasons stated in our responses to Questions 3, 5,
and 7. In addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult
position because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial
System or a Local Network through the actions of a customer constructing behind-the-meter
generation, With respect to Radial Systems, the appearance of behind-the-meter generators could
cause the Radial System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion
1 through no fault of the Radial System owner. Similar, a Local Network could lose its status because
behind-the-meter generation could be of sufficient size that power moves into the interconnected grid
in certain hours or under certain contingencies, rather than moving purely onto the Local Network, as
required in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks
should be made consistent with the Exclusion for behind-the-meter generation. There is no technical
reason to believe the power flowing from a behind-the-meter customer-owned generator will have
less impact on the bulk system than an equivalent-sized generator owned by a utility operating a
Radial System or LN.
Yes
SNPD strongly supports the categorical exclusion of Local Networks (“LNs”) from the BES. We believe
the exclusion is necessary to ensure that the BES definition complies with the statutory requirement,
discussed in our response to Question 1, to exclude all facilities used in the local distribution of
electric power. LNs are, of course, probably the most common form of local distribution facility.
Further, the conversion of radial systems to local distribution networks should be encouraged because
networked systems generally reduce losses, increase system efficiency, and increase the level of
service to retail customers. If the BES definition were to provide an exclusion for radials without
providing a similar exclusion for LNs, however, it would discourage networking local distribution
systems because of the significantly increased regulatory burdens faced by the local distribution utility
if it elected to network its radial facilities. By placing radial systems and LNs on the same regulatory
footing, the proposed definition will ensure that decisions about whether to network radial systems
are made on the basis of costs and benefits to the retail customers served by those radials, and not
on the basis of disparate regulatory treatment. Consumers will ultimately benefit from the path
chosen by the SDT. SNPD also supports specific refinements made to the LN exclusion by the SDT in
the current draft of the BES definition. In particular, SNPD supports the clarification of the purposes of
a LN. The current draft states that LNs connect at multiple points to “improve the level of service to
retail customer Load and not to accommodate bulk power transfer across the interconnected system.”
Snohomish supports this change in language because it reflects the fundamental purposes of a LN
and emphasizes one of the key distinctions between LNs and bulk transmission facilities, namely, that
LNs are designed primarily to serve local retail load while bulk transmission facilities are designed
primarily to move bulk power from a bulk source (generally either the point of interconnection of a
wholesale generator or a the point of interconnection with another bulk transmission system) to one
or more wholesale purchasers. SNPD believes further improvement of the language could be achieved
with additional modifications and clarifications. With respect to the core language of Exclusion 3, we
believe the language making a “group of contiguous transmission Elements operated at or above 100
kV” the starting point for identifying a LN would be improved by deleting the term “transmission” from
this phrase. This is so because LNs are not used for transmission and the use of the term
“transmission Elements” is therefore both confusing and unnecessary. There would be no room for
argument about what the SDT intended by including the word “transmission” if the word is deleted
and the Exclusion applies to any “group of Elements operated at 100 kV or above” that meets the
remaining requirement of the Exclusion. Further, any definitional value that is added by using the

term “transmission Elements” is accomplished by using that term in the core definition, and there is
no reason to carry the term through in the Exclusions. SNPD also believes that subparagraphs (a) and
(b) are redundant in the sense that whatever protection is offered by the generation limit in
subparagraph (a) is duplicated by the limit in subparagraph (b) requiring no flow out of the LN. We
believe the SDT can eliminate subparagraph (a) of Exclusion 3 and simply rely on subparagraph (b)
because if power only flows into the LN even if it interconnects more than 75 MVA of generation, the
interconnected generation interconnected will have no significant interaction with the interconnected
bulk transmission system. It will only interact with the LN. And, with the advent of distributed
generation, it is easy to foresee a situation in which a large number of very small distributed
generators are interconnected into a LDN, so that the aggregate capacity of these generators exceeds
75 MVA. However, because the generators are small and dispersed and, under the criterion in
subparagraph (b), would be wholly absorbed within the LN rather than transmitting power onto the
interconnected grid, those generators would not have a material impact on the grid. We also suggest
that subparagraph (b) of Exclusion 3 could be more clearly drafted. Subparagraph (b), as part of the
requirement that power flow into a LN rather than out of it, includes this description: “The LN does
not transfer energy originating outside the LN for delivery through the LN.” We understand this
language is intended to distinguish a LN from a link in the transmission system – power on a
transmission link passes through the transmission link to a load located elsewhere, while power in a
LN enters the LN and is consumed by retail load within the LN. While we agree with the concept
proposed by the SDT, we believe the language would be clearer if it read: “The LN does not transfer
energy originating outside the LN for delivery through the LN to loads located outside the LN.” We
believe the italicized language is necessary to distinguish between a transmission system, where
power that originates outside a system is delivered through the system and passes through the
system to a sink located somewhere outside the system, from a LN, in which power originating
outside the LN passes through the LN and is delivered to retail load within the LN. To put it another
way, the italicized language helps distinguish a transmission system from an LN, in which the LN
“transfers energy originating outside the LN for delivery through the LN to loads located within the
LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to mean generation that is used by retail customers located
within a LN rather than being exported and sold on wholesale markets outside the LN. We therefore
suggest that the SDT replace the phrase “non-retail generation” with the phrase “generation sold in
wholesale markets and transmitted outside the LN.” Similarly, we are unsure what is meant by the
phrase “the LN and its underlying Elements.” We believe the phrase “and its underlying Elements”
could simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3.
Finally, SNPD believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated
as long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified
as a Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities
that allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
transmission of electricity on the interconnected bulk system. Apart from these specific improvements
that we believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may
need to re-examine certain assumptions that appear to underlie the current draft. Specifically,
subparagraph (a) suggests that if BES generation is embedded within a LN, the LN itself must also be
BES. But two NERC bodies have already addressed similar questions and concluded there is no
technical basis for such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force” were formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. The GO-TO Team concluded that by complying with a handful of reliability

standards, primarily related to vegetation management, reliable operation of the bulk interconnected
system could be protected without unduly burdening the owners of such interconnection systems.
Therefore, there is no reason, according to the GO-TO Team, that dedicated high-voltage
interconnection facilities must be treated as “Transmission” and classified as part of the BES in order
to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO Task
Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most often
not part of the integrated bulk power system, and as such should not be subject to the same level of
standards applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” White Paper
Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at the
Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply
with the same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of the
equipment that actually produces electricity – the generation equipment itself.” Id. We believe that
interconnection of BES generators within a LN is analogous and that, based on the findings of the
Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply because a large
generator is embedded in the LN will result in substantial overregulation and unnecessary expense
with little gain for bulk system reliability. If anything, generation interconnected through a LN is less
likely to produce material impacts on the interconnected bulk transmission system than the
equivalent generator interconnected through a single dedicated line because an LN is interconnected
to the bulk system at several points, so that if one interconnection goes down, power can still flow
from the BES generator to the bulk system on other interconnection points. Where a dedicated
interconnection facility is involved, by contrast, if the interconnection line fails, the generator is
unavailable to the interconnected bulk system. Similarly, we suggest that the SDT re-examine the
assumptions underlying subparagraph (b), which seems to suggest that a local distribution system
cannot be classified as a Local Network if power flows out of that system at any time, even if the
amount is de minimis, the outward flow is only for a few hours a year, or the outward flow occurs
only in an extreme contingency. Accordingly, we suggest that the initial clause of subparagraph (b) be
revised to read: “Except in unusual circumstances, power flows only into the LN.”
Yes
Yes, SNPD supports the revised language because retail reactive devices are used to address local
customer or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such
local devices should therefore be excluded from the BES definition.
No
SNPD extends its thanks to the SDT and to the many industry entities that have actively participating
in the Standards Development Process. SNPD strongly supports the current draft and believes, with
certain refinements discussed in our comments, that the definition will serve the industry and
reliability regulators well for many years to come. In addition, as noted earlier, SNPD is encouraged
that the 20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry
Criteria, which have been relied upon by the SDT largely as a matter of necessity, will be reviewed
and a technical assessment will be performed to identify the appropriate generation unit and plant
size threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure
Team will continue to move forward with developing an Exceptions Process that will complement the
BES Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should
not be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that SNPD specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. SNPD supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. SNPD
also supports the 24-month transition period for the reasons laid out by the SDT.
Group

Chris Higgins
Transmission Reliability Program
Yes
Yes
Yes
BPA agrees with the I2 changes and feels that they are excellent.
Yes
Yes
BPA suggests adding, “Including generating terminals of the high side” as clarifying language to the
end of the sentence. (Specifically where the 100kV is to be measured as clarified in I2). BPA believes
that Inclusion 4 is not intended to include each individual wind turbine/generator unit in a wind farm
as a BES element, but rather to include the point at which the aggregation becomes large enough to
meet the aggregate capacity threshold of 75 MVA.
Yes
No
BPA believes that a system left connected in a network configuration, via use of a normally open
switch for temporary network connection, without the protections afforded through the standards that
apply to BES should be limited to less than 24 hours. BPA believes that the term “non-retail
generation” in E1(c) should be clearly defined. In addition, BPA believes that there needs to be a
means to isolate the radial system from the BES during a fault on the radial system by means of a
automatic fault interrupting device. Automatic fault interrupting device should be a defined term.
Yes
BPA believes that if E2 is intended to exclude behind-the-meter generation, the phrase “on the
customer’s side of the retail meter” should immediately follow “generating units” in the first line.
Otherwise, the phrase could be seen as modifying “retail customer Load.”
No
BPA has several concerns regarding Exclusion E3. First, BPA strongly believes that Exclusion E3 must
retain the requirement that the local network (LN) be separable from the BES by an automatic fault
interrupting device wherever the LN interconnects with the BES. BPA believes that this is necessary in
order to protect both the BES and the LN during faults, especially if there is any possibility that
backfeed could occur. BPA recommends retaining the original language: Separable by automatic fault
interrupting devices: Wherever connected to the BES, the LN must be connected through automatic
fault interrupting devices. In addition, as stated in our comments in May, 2011, “automatic fault
interrupting device” should be a defined term. BPA strongly believes that Exclusion E3 should not be
allowed for any facilities above 200kV instead of the 300kV limit in shown in the current proposal.
Networks operated above 200kV have significant fault duties, carry much more power, and have a
greater potential for cascading if something does not operate properly than networks operated below
200kV. Therefore, BPA believes that these networks should be part of the BES. BPA believes the term
“non-retail generation” in E3(a) should also be defined.
Yes
No
Individual
Roman Gillen
Consumer's Power Inc.
Yes
The Consumers Power (CPI) believes the SDT continues to make substantial progress towards a clear

and workable definition of the Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. CPI therefore supports the new definition, although our
support is conditioned on: (1) a workable Exceptions process being developed in conjunction with the
BES definition; and, (2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the SDT, which would
address a number of important technical issues that have been identified in the standards
development process to date. CPI strongly supports the following elements of the revised BES
definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, CPI supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). CPI thanks the SDT for the excellent work to include this sentence. For
similar reasons, CPI believes the use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes clear
that the BES includes only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. CPI recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, CPI agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, CPI is prepared to support the BES definition as
proposed by the SDT. While CPI supports the overall approach adopted by the SDT and much of the
specific language incorporated into the second draft of the BES definition, we believe the second draft
would benefit from further clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential for
a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, CPI believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions

Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
CPI will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
CPI supports the changes made in Inclusion 2 and believes that the definition in its current form adds
clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the previous
draft definition into a single Inclusion that addresses the treatment of generation for purposes of the
BES definition. We also support the SDT’s proposal for a Phase II of the BES Definition process that
would examine the technical justification for these thresholds and that would establish new thresholds
based on a careful technical analysis. It is our understanding that the generator threshold issue will
be vetted through the complete standards development process. We agree with this approach
because if the generator threshold is treated as merely an element of NERC’s Rules of Procedure, it
can be changed with considerably less process and industry input than the Standards Development
Process. Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of Procedure upon
approval of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3, 2010)
(providing for, e.g., posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011) (“Order No. 743
directed the ERO to revise the definition of ‘bulk electric system’ through the NERC Standards
Development Process” (emph. added)). Addressing all aspects of Phase II through the Standards
Development Process will improve the content of the definition by bringing to bear industry expertise
on all aspects of the definition and will ensure that, once firm guidelines are established, they can be
relied upon by both industry and regulators without threat that they will be changed with little notice
and little process. CPI believes further clarification of the proposed language would be appropriate.
The SDT proposes continued reliance upon the thresholds that are used in the NERC Statement of
Compliance Registry Criteria for registration of Generation Owners and Generation Operators, which is
currently 20 MVA for an individual generation unit and 75 MVA for multiple units on a single site.

Conceptually, we are concerned about this approach because, as we understand it, the purpose of the
Compliance Registry is to sweep in all generators that might be material to the reliable operation of
the BES, and not to definitively determine whether a given generator is, in fact, material to the
reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to identify
“candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we believe that the
generator threshold determined in Phase II should be incorporated directly into the BES Definition
rather than being incorporated by reference from the SCRC. We also believe that the specific
language proposed by the SDT could be further clarified. The SDT proposes that generation be
included in the BES if the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder for the results of
the technical analysis that would occur in Phase II but we believe simply stating that the threshold
will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the reasons noted
above, we believe the threshold should be part of the BES Definition, and should not simply be a
cross-reference to the SCRC (and, given the different purposes of the BES Definition and the SCRC, it
is not clear that the same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate Resources
connected at a voltage of 100kV or above.” Two definitions would then be added to the note at the
end of the definition to read as follows: For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality threshold to be
included in this definition or, in the absence of such a materiality threshold, that meets the gross
nameplate capacity voltage threshold requiring registration of the owner of such a resource as a
Generation Owner under the ERO Statement of Compliance Registry Criteria. For purposes of this BES
Definition, Qualifying Aggregate Generation Resources means any facility consisting of one or more
generating units that are connected at a common bus that meets the materiality threshold to be
included in this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit generator as a
Generation Owner under the ERO Statement of Compliance Registry Criteria.. The “materiality
threshold” is intended to refer to the generator threshold developed in Phase II. We suggest using
definitions in this fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as part of the BES
if they are necessary for operation of the BES, but to exclude smaller generating units because they
are not material to the operation of the interconnected transmission grid. Second, we believe use of
the defined terms better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase II without having to revise the
BES Definition at the end of that process. That is, the definitions are designed to allow the SDT to
include revised thresholds in the definition at the conclusion of the Phase II process based upon the
technical analysis planned for Phase II, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase II is completed. Third, the definitions can be
incorporated into other parts of the BES Definition, which will add consistency and clarity. As noted in
our answers to several of the questions below, the specific 75 MVA threshold is retained in several of
the Exclusions and Inclusions, and we believe the industry would be better served if the revised
thresholds arrived at after technical analysis in Phase II are automatically incorporated into all
relevant provisions of the BES Definition. There is no reason for the SDT to continue to rely on the 75
MVA threshold once the analysis planned for Phase II on the threshold issue is completed. Fourth, the
phrase “or that meets the materiality threshold to be included in this definition” is intended to
preserve the SDT’s flexibility to make a determination that generators below a specific threshold are
not “necessary to” maintain the reliability of the interconnected transmission system, and to
incorporate that finding as part of the definition itself, even if a different threshold is used in the SCRC
to identify potential candidates for registration. Accordingly, our proposed language makes clear that
a specific threshold in the definition controls over any threshold that might be included in the SCRC.
For the reasons stated above, we believe is it highly desirable to include any material threshold in the
BES Definition itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Finally, we agree with the SDT’s decision to
examine the question of where the line between BES and non-BES Elements should be drawn more
closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and commend the work
of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting point for the
SDT’s analysis on this issue. We understand Inclusion 2 would classify generators exceeding specific

thresholds as part of the BES, but would not necessarily require facilities interconnecting such
generators to be part of the BES. As discussed more fully in our answer to Question 9, based on
extensive technical analysis that has already been performed by the NERC Project 2010-07 Standards
Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a
dedicated interconnection facility connecting a BES generator to the interconnected bulk transmission
grid will result in an unnecessary regulatory burden that produces considerable expense for the owner
of the interconnection facility with little or no improvement in bulk system reliability. We also believe
the clauses at the end of Inclusion 2 are somewhat confusing and that greater clarity would be
achieved by changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100kV or above” so that the Inclusion covers transformers
with terminals “connected at a voltage of 100kV or above, including the generator terminal(s) on the
high side of the step-up transformer(s) if operated at a voltage of 100kV or above.”
Yes
CPI supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
CPI supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
CPI has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, CPI believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally, CPI

believes this issue should be addressed in Phase 2 since there is not technical justification or analysis
done to determine the thresholds. CPI strongly believes that there should be technical justification for
thresholds for this issue and all other issues.
Yes
CPI continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, CPI strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.
Yes
CPI supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, CPI urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN.
Yes

CPI strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of radial
systems to local networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. If the BES definition
were to provide an exclusion for radials without providing a similar exclusion for LNs, however, it
would discourage networking local distribution systems because of the significantly increased
regulatory burdens faced by the local distribution utility if it elected to network its radial facilities. By
placing radial systems and LNs on the same regulatory footing, the proposed definition will ensure
that decisions about whether to network radial systems are made on the basis of costs and benefits to
the retail customers served by those radials, and not on the basis of disparate regulatory treatment.
Consumers would ultimately benefit. CPI also supports specific refinements made to the LN exclusion
by the SDT in the current draft of the BES definition. In particular, CPI supports the clarification of the
purposes of a LN. The current draft states that LNs connect at multiple points to “improve the level of
service to retail customer Load and not to accommodate bulk power transfer across the
interconnected system.” CPI supports this change in language because it reflects the fundamental
purposes of a LN and emphasizes one of the key distinctions between LNs and bulk transmission
facilities, namely, that LNs are designed primarily to serve local retail load while bulk transmission
facilities are designed primarily to move bulk power from a bulk source (generally either the point of
interconnection of a wholesale generator or a the point of interconnection with another bulk
transmission system) to one or more wholesale purchasers. CPI believes further improvement of the
language could be achieved with additional modifications and clarifications. With respect to the core
language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
CPI also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and
dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term

“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3. CPI
also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as long as
subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as a Flow
Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that allow
reliable transmission of bulk electric power on the interconnected grid. If a LN has not been identified
as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable transmission
of electricity on the interconnected bulk system. Apart from these specific improvements that we
believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may need to
re-examine certain assumptions that appear to underlie the current draft. Specifically, subparagraph
(a) suggests that if BES generation is embedded within a LN, the LN itself must also be BES. But two
NERC bodies have already addressed similar questions and concluded there is no technical basis for
such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO
Task Force” were formed to address how the dedicated interconnection facilities linking a BES
generator to high-voltage transmission facilities should be treated under the NERC standards. The
GO-TO Team concluded that by complying with a handful of reliability standards, primarily related to
vegetation management, reliable operation of the bulk interconnected system could be protected
without unduly burdening the owners of such interconnection systems. Therefore, there is no reason,
according to the GO-TO Team, that dedicated high-voltage interconnection facilities must be treated
as “Transmission” and classified as part of the BES in order to make reliability standards effective.
See Final Report from the NERC Ad Hoc Group for Generator Requirements at the Transmission
Interface (Nov. 16, 2009) (paper written by the GO-TO Task Force). Similarly, the Project 2010-07
Team observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to Transmission
Owners and Transmission Operators who own and operate transmission Facilities and Elements that
are part of the integrated bulk power system.” White Paper Proposal for Information Comment, NERC
Project 2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011).
Requiring Generation Owners and Operators to comply with the same standards as BES Transmission
Owners and Operators “would do little, if anything, to improve the reliability of the Bulk Electric
System,” especially “when compared to the operation of the equipment that actually produces
electricity – the generation equipment itself.” Id. We believe that interconnection of BES generators
within a LN is analogous and that, based on the findings of the Project 2010-07 and GO-TO Teams,
automatically classifying a LN as “BES” simply because a large generator is embedded in the LN will
result in substantial overregulation and unnecessary expense with little gain for bulk system
reliability. If anything, generation interconnected through a LN is less likely to produce material
impacts on the interconnected bulk transmission system than the equivalent generator interconnected
through a single dedicated line because an LN is interconnected to the bulk system at several points,
so that if one interconnection goes down, power can still flow from the BES generator to the bulk
system on other interconnection points. Where a dedicated interconnection facility is involved, by
contrast, if the interconnection line fails, the generator is unavailable to the interconnected bulk
system. Similarly, we suggest that the SDT re-examine the assumptions underlying subparagraph
(b), which seems to suggest that a local distribution system cannot be classified as a Local Network if
power flows out of that system at any time, even if the amount is de minimis, the outward flow is
only for a few hours, a year, or the outward flow occurs only in an extreme contingency. Accordingly,
we suggest that the initial clause of subparagraph (b) be revised to read: “Except in unusual
circumstances, power flows only into the LN.” Finally, we note that the LN exclusion must not operate
in any way as a substitution for the statutory prohibition on including “facilities used in the local

distribution of electric energy” in the BES. Therefore, even with the LN exclusion, the SDT must retain
this statutory language in the core definition of the BES, as discussed in our answer to Question One.
If a certain piece of equipment is a “facility used in the local distribution of electric energy,” then it is
not part of the BES in the first instance, and so consideration of the LN Exclusion, or of any other
Exclusion, any Inclusion, or any Exception, would be both unnecessary and uncalled for.
Yes
CPI supports the revised language because retail reactive devices are used to address local customer
or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such local
devices should therefore be excluded from the BES definition.
No
CPI extends its thanks to the SDT and to the many industry entities that have actively participating in
the Standards Development Process. CPI supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, CPI is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that CPI specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. CPI supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. CPI also
supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Dave Sabala
Douglas Electric Cooperative (DEC)
Yes
The Douglas Electric Cooperative (DEC) believes the SDT continues to make substantial progress
towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly improves
both the existing definition and the SDT’s previous proposal. DEC therefore supports the new
definition, although our support is conditioned on: (1) a workable Exceptions process being developed
in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II of
the standards development process in accordance with the SAR recently put forward by the SDT,
which would address a number of important technical issues that have been identified in the
standards development process to date. DEC strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, DEC supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.

§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). DEC thanks the SDT for the excellent work to include this sentence. For
similar reasons, DEC believes the use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes clear
that the BES includes only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. DEC recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, DEC agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, DEC is prepared to support the BES definition as
proposed by the SDT. While DEC supports the overall approach adopted by the SDT and much of the
specific language incorporated into the second draft of the BES definition, we believe the second draft
would benefit from further clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential for
a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, DEC believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
DEC will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the

juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
DEC supports the changes made in Inclusion 2 and believes that the definition in its current form adds
clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the previous
draft definition into a single Inclusion that addresses the treatment of generation for purposes of the
BES definition. We also support the SDT’s proposal for a Phase II of the BES Definition process that
would examine the technical justification for these thresholds and that would establish new thresholds
based on a careful technical analysis. It is our understanding that the generator threshold issue will
be vetted through the complete standards development process. We agree with this approach
because if the generator threshold is treated as merely an element of NERC’s Rules of Procedure, it
can be changed with considerably less process and industry input than the Standards Development
Process. Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of Procedure upon
approval of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3, 2010)
(providing for, e.g., posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011) (“Order No. 743
directed the ERO to revise the definition of ‘bulk electric system’ through the NERC Standards
Development Process” (emph. added)). Addressing all aspects of Phase II through the Standards
Development Process will improve the content of the definition by bringing to bear industry expertise
on all aspects of the definition and will ensure that, once firm guidelines are established, they can be
relied upon by both industry and regulators without threat that they will be changed with little notice
and little process. DEC believes further clarification of the proposed language would be appropriate.
The SDT proposes continued reliance upon the thresholds that are used in the NERC Statement of
Compliance Registry Criteria for registration of Generation Owners and Generation Operators, which is
currently 20 MVA for an individual generation unit and 75 MVA for multiple units on a single site.
Conceptually, we are concerned about this approach because, as we understand it, the purpose of the
Compliance Registry is to sweep in all generators that might be material to the reliable operation of
the BES, and not to definitively determine whether a given generator is, in fact, material to the
reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to identify
“candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we believe that the
generator threshold determined in Phase II should be incorporated directly into the BES Definition
rather than being incorporated by reference from the SCRC. We also believe that the specific
language proposed by the SDT could be further clarified. The SDT proposes that generation be
included in the BES if the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder for the results of
the technical analysis that would occur in Phase II but we believe simply stating that the threshold
will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the reasons noted
above, we believe the threshold should be part of the BES Definition, and should not simply be a
cross-reference to the SCRC (and, given the different purposes of the BES Definition and the SCRC, it
is not clear that the same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate Resources
connected at a voltage of 100kV or above.” Two definitions would then be added to the note at the
end of the definition to read as follows: For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality threshold to be
included in this definition or, in the absence of such a materiality threshold, that meets the gross
nameplate capacity voltage threshold requiring registration of the owner of such a resource as a

Generation Owner under the ERO Statement of Compliance Registry Criteria. For purposes of this BES
Definition, Qualifying Aggregate Generation Resources means any facility consisting of one or more
generating units that are connected at a common bus that meets the materiality threshold to be
included in this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit generator as a
Generation Owner under the ERO Statement of Compliance Registry Criteria.. The “materiality
threshold” is intended to refer to the generator threshold developed in Phase II. We suggest using
definitions in this fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as part of the BES
if they are necessary for operation of the BES, but to exclude smaller generating units because they
are not material to the operation of the interconnected transmission grid. Second, we believe use of
the defined terms better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase II without having to revise the
BES Definition at the end of that process. That is, the definitions are designed to allow the SDT to
include revised thresholds in the definition at the conclusion of the Phase II process based upon the
technical analysis planned for Phase II, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase II is completed. Third, the definitions can be
incorporated into other parts of the BES Definition, which will add consistency and clarity. As noted in
our answers to several of the questions below, the specific 75 MVA threshold is retained in several of
the Exclusions and Inclusions, and we believe the industry would be better served if the revised
thresholds arrived at after technical analysis in Phase II are automatically incorporated into all
relevant provisions of the BES Definition. There is no reason for the SDT to continue to rely on the 75
MVA threshold once the analysis planned for Phase II on the threshold issue is completed. Fourth, the
phrase “or that meets the materiality threshold to be included in this definition” is intended to
preserve the SDT’s flexibility to make a determination that generators below a specific threshold are
not “necessary to” maintain the reliability of the interconnected transmission system, and to
incorporate that finding as part of the definition itself, even if a different threshold is used in the SCRC
to identify potential candidates for registration. Accordingly, our proposed language makes clear that
a specific threshold in the definition controls over any threshold that might be included in the SCRC.
For the reasons stated above, we believe is it highly desirable to include any material threshold in the
BES Definition itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Finally, we agree with the SDT’s decision to
examine the question of where the line between BES and non-BES Elements should be drawn more
closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and commend the work
of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting point for the
SDT’s analysis on this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities interconnecting such
generators to be part of the BES. As discussed more fully in our answer to Question 9, based on
extensive technical analysis that has already been performed by the NERC Project 2010-07 Standards
Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a
dedicated interconnection facility connecting a BES generator to the interconnected bulk transmission
grid will result in an unnecessary regulatory burden that produces considerable expense for the owner
of the interconnection facility with little or no improvement in bulk system reliability. We also believe
the clauses at the end of Inclusion 2 are somewhat confusing and that greater clarity would be
achieved by changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100kV or above” so that the Inclusion covers transformers
with terminals “connected at a voltage of 100kV or above, including the generator terminal(s) on the
high side of the step-up transformer(s) if operated at a voltage of 100kV or above.”
Yes
DEC supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
DEC supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate

nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
DEC has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, DEC believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally, DEC
believes this issue should be addressed in Phase 2 since there is not technical justification or analysis
done to determine the thresholds. DEC strongly believes that there should be technical justification
for thresholds for this issue and all other issues.
Yes
DEC continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate

Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, DEC strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.
Yes
DEC supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, DEC urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN.
Yes
DEC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of radial
systems to local networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. If the BES definition
were to provide an exclusion for radials without providing a similar exclusion for LNs, however, it
would discourage networking local distribution systems because of the significantly increased
regulatory burdens faced by the local distribution utility if it elected to network its radial facilities. By
placing radial systems and LNs on the same regulatory footing, the proposed definition will ensure
that decisions about whether to network radial systems are made on the basis of costs and benefits to
the retail customers served by those radials, and not on the basis of disparate regulatory treatment.
Consumers would ultimately benefit. DEC also supports specific refinements made to the LN exclusion
by the SDT in the current draft of the BES definition. In particular, DEC supports the clarification of
the purposes of a LN. The current draft states that LNs connect at multiple points to “improve the
level of service to retail customer Load and not to accommodate bulk power transfer across the
interconnected system.” DEC supports this change in language because it reflects the fundamental
purposes of a LN and emphasizes one of the key distinctions between LNs and bulk transmission
facilities, namely, that LNs are designed primarily to serve local retail load while bulk transmission
facilities are designed primarily to move bulk power from a bulk source (generally either the point of
interconnection of a wholesale generator or a the point of interconnection with another bulk
transmission system) to one or more wholesale purchasers. DEC believes further improvement of the
language could be achieved with additional modifications and clarifications. With respect to the core

language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
DEC also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and
dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3. DEC
also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as long as
subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as a Flow
Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that allow
reliable transmission of bulk electric power on the interconnected grid. If a LN has not been identified
as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable transmission
of electricity on the interconnected bulk system. Apart from these specific improvements that we
believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may need to

re-examine certain assumptions that appear to underlie the current draft. Specifically, subparagraph
(a) suggests that if BES generation is embedded within a LN, the LN itself must also be BES. But two
NERC bodies have already addressed similar questions and concluded there is no technical basis for
such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO
Task Force” were formed to address how the dedicated interconnection facilities linking a BES
generator to high-voltage transmission facilities should be treated under the NERC standards. The
GO-TO Team concluded that by complying with a handful of reliability standards, primarily related to
vegetation management, reliable operation of the bulk interconnected system could be protected
without unduly burdening the owners of such interconnection systems. Therefore, there is no reason,
according to the GO-TO Team, that dedicated high-voltage interconnection facilities must be treated
as “Transmission” and classified as part of the BES in order to make reliability standards effective.
See Final Report from the NERC Ad Hoc Group for Generator Requirements at the Transmission
Interface (Nov. 16, 2009) (paper written by the GO-TO Task Force). Similarly, the Project 2010-07
Team observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to Transmission
Owners and Transmission Operators who own and operate transmission Facilities and Elements that
are part of the integrated bulk power system.” White Paper Proposal for Information Comment, NERC
Project 2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011).
Requiring Generation Owners and Operators to comply with the same standards as BES Transmission
Owners and Operators “would do little, if anything, to improve the reliability of the Bulk Electric
System,” especially “when compared to the operation of the equipment that actually produces
electricity – the generation equipment itself.” Id. We believe that interconnection of BES generators
within a LN is analogous and that, based on the findings of the Project 2010-07 and GO-TO Teams,
automatically classifying a LN as “BES” simply because a large generator is embedded in the LN will
result in substantial overregulation and unnecessary expense with little gain for bulk system
reliability. If anything, generation interconnected through a LN is less likely to produce material
impacts on the interconnected bulk transmission system than the equivalent generator interconnected
through a single dedicated line because an LN is interconnected to the bulk system at several points,
so that if one interconnection goes down, power can still flow from the BES generator to the bulk
system on other interconnection points. Where a dedicated interconnection facility is involved, by
contrast, if the interconnection line fails, the generator is unavailable to the interconnected bulk
system. Similarly, we suggest that the SDT re-examine the assumptions underlying subparagraph
(b), which seems to suggest that a local distribution system cannot be classified as a Local Network if
power flows out of that system at any time, even if the amount is de minimis, the outward flow is
only for a few hours, a year, or the outward flow occurs only in an extreme contingency. Accordingly,
we suggest that the initial clause of subparagraph (b) be revised to read: “Except in unusual
circumstances, power flows only into the LN.” Finally, we note that the LN exclusion must not operate
in any way as a substitution for the statutory prohibition on including “facilities used in the local
distribution of electric energy” in the BES. Therefore, even with the LN exclusion, the SDT must retain
this statutory language in the core definition of the BES, as discussed in our answer to Question One.
If a certain piece of equipment is a “facility used in the local distribution of electric energy,” then it is
not part of the BES in the first instance, and so consideration of the LN Exclusion, or of any other
Exclusion, any Inclusion, or any Exception, would be both unnecessary and uncalled for.
Yes
DEC supports the revised language because retail reactive devices are used to address local customer
or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such local
devices should therefore be excluded from the BES definition.
No
DEC extends its thanks to the SDT and to the many industry entities that have actively participating
in the Standards Development Process. DEC supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, DEC is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES

Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that DEC specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. DEC supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. DEC
also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Bryan Case
Fall River Rural Electric Cooperative (FALL)
Yes
The Fall River Rural Electric Cooperative (FALL) believes the SDT continues to make substantial
progress towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly
improves both the existing definition and the SDT’s previous proposal. FALL therefore supports the
new definition, although our support is conditioned on: (1) a workable Exceptions process being
developed in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on
Phase II of the standards development process in accordance with the SAR recently put forward by
the SDT, which would address a number of important technical issues that have been identified in the
standards development process to date. FALL strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, FALL supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). FALL thanks the SDT for the excellent work to include this sentence. For
similar reasons, FALL believes the use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes clear
that the BES includes only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. FALL recognizes

that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, FALL agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, FALL is prepared to support the BES definition as
proposed by the SDT. While FALL supports the overall approach adopted by the SDT and much of the
specific language incorporated into the second draft of the BES definition, we believe the second draft
would benefit from further clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential for
a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, FALL believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
FALL will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
FALL supports the changes made in Inclusion 2 and believes that the definition in its current form
adds clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the
previous draft definition into a single Inclusion that addresses the treatment of generation for
purposes of the BES definition. We also support the SDT’s proposal for a Phase II of the BES

Definition process that would examine the technical justification for these thresholds and that would
establish new thresholds based on a careful technical analysis. It is our understanding that the
generator threshold issue will be vetted through the complete standards development process. We
agree with this approach because if the generator threshold is treated as merely an element of
NERC’s Rules of Procedure, it can be changed with considerably less process and industry input than
the Standards Development Process. Compare NERC Rules of Procedure § 1400 (providing for
changes to Rules of Procedure upon approval of the NERC board and FERC) with NERC Standards
Process Manual (Sept. 3, 2010) (providing for, e.g., posting of SDT proposals for comment,
successive balloting, and super-majority approval requirements). See also Order No. 743-A, 134 FERC
¶ 61,210 at P 4 (2011) (“Order No. 743 directed the ERO to revise the definition of ‘bulk electric
system’ through the NERC Standards Development Process” (emph. added)). Addressing all aspects
of Phase II through the Standards Development Process will improve the content of the definition by
bringing to bear industry expertise on all aspects of the definition and will ensure that, once firm
guidelines are established, they can be relied upon by both industry and regulators without threat
that they will be changed with little notice and little process. FALL believes further clarification of the
proposed language would be appropriate. The SDT proposes continued reliance upon the thresholds
that are used in the NERC Statement of Compliance Registry Criteria for registration of Generation
Owners and Generation Operators, which is currently 20 MVA for an individual generation unit and 75
MVA for multiple units on a single site. Conceptually, we are concerned about this approach because,
as we understand it, the purpose of the Compliance Registry is to sweep in all generators that might
be material to the reliable operation of the BES, and not to definitively determine whether a given
generator is, in fact, material to the reliable operation of the BES. As the SCRC itself states, the SCRC
is intended only to identify “candidates for registration.” SCRC at p.3, § 1 (emph. added).
Accordingly, we believe that the generator threshold determined in Phase II should be incorporated
directly into the BES Definition rather than being incorporated by reference from the SCRC. We also
believe that the specific language proposed by the SDT could be further clarified. The SDT proposes
that generation be included in the BES if the “Generation resource(s)” has a “nameplate rating per the
ERO Statement of Compliance Registry.” We understand this language is intended to be a placeholder
for the results of the technical analysis that would occur in Phase II but we believe simply stating that
the threshold will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the
reasons noted above, we believe the threshold should be part of the BES Definition, and should not
simply be a cross-reference to the SCRC (and, given the different purposes of the BES Definition and
the SCRC, it is not clear that the same threshold should be used in both). We therefore propose that
Inclusion 2 be rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate
Resources connected at a voltage of 100kV or above.” Two definitions would then be added to the
note at the end of the definition to read as follows: For purposes of this BES Definition, Qualifying
Individual Generation Resources means an individual generating unit that meets the materiality
threshold to be included in this definition or, in the absence of such a materiality threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of such a
resource as a Generation Owner under the ERO Statement of Compliance Registry Criteria. For
purposes of this BES Definition, Qualifying Aggregate Generation Resources means any facility
consisting of one or more generating units that are connected at a common bus that meets the
materiality threshold to be included in this definition, or, in the absence of such a threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of multipleunit generator as a Generation Owner under the ERO Statement of Compliance Registry Criteria.. The
“materiality threshold” is intended to refer to the generator threshold developed in Phase II. We
suggest using definitions in this fashion for several reasons. First, we believe the language we suggest
more clearly states the intention of the SDT, which we understand is to classify generation units as
part of the BES if they are necessary for operation of the BES, but to exclude smaller generating units
because they are not material to the operation of the interconnected transmission grid. Second, we
believe use of the defined terms better reflects the intention of the SDT to reserve the specific
question about generator thresholds to the technical analysis that will occur in Phase II without
having to revise the BES Definition at the end of that process. That is, the definitions are designed to
allow the SDT to include revised thresholds in the definition at the conclusion of the Phase II process
based upon the technical analysis planned for Phase II, and the revised thresholds will be
automatically incorporated into the BES Definition if the language we suggest is used. The thresholds
used in the SCRC would only be a fall-back, to be used only until Phase II is completed. Third, the
definitions can be incorporated into other parts of the BES Definition, which will add consistency and

clarity. As noted in our answers to several of the questions below, the specific 75 MVA threshold is
retained in several of the Exclusions and Inclusions, and we believe the industry would be better
served if the revised thresholds arrived at after technical analysis in Phase II are automatically
incorporated into all relevant provisions of the BES Definition. There is no reason for the SDT to
continue to rely on the 75 MVA threshold once the analysis planned for Phase II on the threshold
issue is completed. Fourth, the phrase “or that meets the materiality threshold to be included in this
definition” is intended to preserve the SDT’s flexibility to make a determination that generators below
a specific threshold are not “necessary to” maintain the reliability of the interconnected transmission
system, and to incorporate that finding as part of the definition itself, even if a different threshold is
used in the SCRC to identify potential candidates for registration. Accordingly, our proposed language
makes clear that a specific threshold in the definition controls over any threshold that might be
included in the SCRC. For the reasons stated above, we believe is it highly desirable to include any
material threshold in the BES Definition itself rather than relegating the threshold to the SCRC, which
is merely a procedural rule rather than a full-fledged Reliability Standard. Finally, we agree with the
SDT’s decision to examine the question of where the line between BES and non-BES Elements should
be drawn more closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and
commend the work of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good
starting point for the SDT’s analysis on this issue. We understand Inclusion 2 would classify
generators exceeding specific thresholds as part of the BES, but would not necessarily require
facilities interconnecting such generators to be part of the BES. As discussed more fully in our answer
to Question 9, based on extensive technical analysis that has already been performed by the NERC
Project 2010-07 Standards Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating
as part of the BES a dedicated interconnection facility connecting a BES generator to the
interconnected bulk transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no improvement in bulk
system reliability. We also believe the clauses at the end of Inclusion 2 are somewhat confusing and
that greater clarity would be achieved by changing “. . . including the generator terminals through the
high-side of the step-up transformer(s) connected at a voltage of 100kV or above” so that the
Inclusion covers transformers with terminals “connected at a voltage of 100kV or above, including the
generator terminal(s) on the high side of the step-up transformer(s) if operated at a voltage of 100kV
or above.”
Yes
FALL supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
FALL supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be

established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
FALL has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, FALL believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally, FALL
believes this issue should be addressed in Phase 2 since there is not technical justification or analysis
done to determine the thresholds. FALL strongly believes that there should be technical justification
for thresholds for this issue and all other issues.
Yes
FALL continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, FALL strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.

Yes
FALL supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, FALL urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN.
Yes
FALL strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of radial
systems to local networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. If the BES definition
were to provide an exclusion for radials without providing a similar exclusion for LNs, however, it
would discourage networking local distribution systems because of the significantly increased
regulatory burdens faced by the local distribution utility if it elected to network its radial facilities. By
placing radial systems and LNs on the same regulatory footing, the proposed definition will ensure
that decisions about whether to network radial systems are made on the basis of costs and benefits to
the retail customers served by those radials, and not on the basis of disparate regulatory treatment.
Consumers would ultimately benefit. FALL also supports specific refinements made to the LN exclusion
by the SDT in the current draft of the BES definition. In particular, FALL supports the clarification of
the purposes of a LN. The current draft states that LNs connect at multiple points to “improve the
level of service to retail customer Load and not to accommodate bulk power transfer across the
interconnected system.” FALL supports this change in language because it reflects the fundamental
purposes of a LN and emphasizes one of the key distinctions between LNs and bulk transmission
facilities, namely, that LNs are designed primarily to serve local retail load while bulk transmission
facilities are designed primarily to move bulk power from a bulk source (generally either the point of
interconnection of a wholesale generator or a the point of interconnection with another bulk
transmission system) to one or more wholesale purchasers. FALL believes further improvement of the
language could be achieved with additional modifications and clarifications. With respect to the core
language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
FALL also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and

dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3.
FALL also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as
long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as
a Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that
allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
transmission of electricity on the interconnected bulk system. Apart from these specific improvements
that we believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may
need to re-examine certain assumptions that appear to underlie the current draft. Specifically,
subparagraph (a) suggests that if BES generation is embedded within a LN, the LN itself must also be
BES. But two NERC bodies have already addressed similar questions and concluded there is no
technical basis for such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force” were formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. The GO-TO Team concluded that by complying with a handful of reliability
standards, primarily related to vegetation management, reliable operation of the bulk interconnected
system could be protected without unduly burdening the owners of such interconnection systems.
Therefore, there is no reason, according to the GO-TO Team, that dedicated high-voltage
interconnection facilities must be treated as “Transmission” and classified as part of the BES in order
to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO Task
Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most often
not part of the integrated bulk power system, and as such should not be subject to the same level of
standards applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” White Paper
Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at the

Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply
with the same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of the
equipment that actually produces electricity – the generation equipment itself.” Id. We believe that
interconnection of BES generators within a LN is analogous and that, based on the findings of the
Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply because a large
generator is embedded in the LN will result in substantial overregulation and unnecessary expense
with little gain for bulk system reliability. If anything, generation interconnected through a LN is less
likely to produce material impacts on the interconnected bulk transmission system than the
equivalent generator interconnected through a single dedicated line because an LN is interconnected
to the bulk system at several points, so that if one interconnection goes down, power can still flow
from the BES generator to the bulk system on other interconnection points. Where a dedicated
interconnection facility is involved, by contrast, if the interconnection line fails, the generator is
unavailable to the interconnected bulk system. Similarly, we suggest that the SDT re-examine the
assumptions underlying subparagraph (b), which seems to suggest that a local distribution system
cannot be classified as a Local Network if power flows out of that system at any time, even if the
amount is de minimis, the outward flow is only for a few hours, a year, or the outward flow occurs
only in an extreme contingency. Accordingly, we suggest that the initial clause of subparagraph (b) be
revised to read: “Except in unusual circumstances, power flows only into the LN.” Finally, we note
that the LN exclusion must not operate in any way as a substitution for the statutory prohibition on
including “facilities used in the local distribution of electric energy” in the BES. Therefore, even with
the LN exclusion, the SDT must retain this statutory language in the core definition of the BES, as
discussed in our answer to Question One. If a certain piece of equipment is a “facility used in the local
distribution of electric energy,” then it is not part of the BES in the first instance, and so consideration
of the LN Exclusion, or of any other Exclusion, any Inclusion, or any Exception, would be both
unnecessary and uncalled for.
Yes
FALL supports the revised language because retail reactive devices are used to address local customer
or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such local
devices should therefore be excluded from the BES definition.
No
FALL extends its thanks to the SDT and to the many industry entities that have actively participating
in the Standards Development Process. FALL supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, FALL is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that FALL specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. FALL supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. FALL
also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Rick Crinklaw
Lane Electric Cooperative (LEC)
Yes

The Lane Electric Cooperative (LEC) believes the SDT continues to make substantial progress towards
a clear and workable definition of the Bulk Electric System (“BES”) that markedly improves both the
existing definition and the SDT’s previous proposal. LEC therefore supports the new definition,
although our support is conditioned on: (1) a workable Exceptions process being developed in
conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II of the
standards development process in accordance with the SAR recently put forward by the SDT, which
would address a number of important technical issues that have been identified in the standards
development process to date. LEC strongly supports the following elements of the revised BES
definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, LEC supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). LEC thanks the SDT for the excellent work to include this sentence. For
similar reasons, LEC believes the use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes clear
that the BES includes only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. LEC recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, LEC agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, LEC is prepared to support the BES definition as
proposed by the SDT. While LEC supports the overall approach adopted by the SDT and much of the
specific language incorporated into the second draft of the BES definition, we believe the second draft
would benefit from further clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential for
a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, LEC believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the

core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
LEC will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
LEC supports the changes made in Inclusion 2 and believes that the definition in its current form adds
clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the previous
draft definition into a single Inclusion that addresses the treatment of generation for purposes of the
BES definition. We also support the SDT’s proposal for a Phase II of the BES Definition process that
would examine the technical justification for these thresholds and that would establish new thresholds
based on a careful technical analysis. It is our understanding that the generator threshold issue will
be vetted through the complete standards development process. We agree with this approach
because if the generator threshold is treated as merely an element of NERC’s Rules of Procedure, it
can be changed with considerably less process and industry input than the Standards Development
Process. Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of Procedure upon
approval of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3, 2010)
(providing for, e.g., posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011) (“Order No. 743
directed the ERO to revise the definition of ‘bulk electric system’ through the NERC Standards
Development Process” (emph. added)). Addressing all aspects of Phase II through the Standards
Development Process will improve the content of the definition by bringing to bear industry expertise
on all aspects of the definition and will ensure that, once firm guidelines are established, they can be
relied upon by both industry and regulators without threat that they will be changed with little notice
and little process. LEC believes further clarification of the proposed language would be appropriate.
The SDT proposes continued reliance upon the thresholds that are used in the NERC Statement of
Compliance Registry Criteria for registration of Generation Owners and Generation Operators, which is

currently 20 MVA for an individual generation unit and 75 MVA for multiple units on a single site.
Conceptually, we are concerned about this approach because, as we understand it, the purpose of the
Compliance Registry is to sweep in all generators that might be material to the reliable operation of
the BES, and not to definitively determine whether a given generator is, in fact, material to the
reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to identify
“candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we believe that the
generator threshold determined in Phase II should be incorporated directly into the BES Definition
rather than being incorporated by reference from the SCRC. We also believe that the specific
language proposed by the SDT could be further clarified. The SDT proposes that generation be
included in the BES if the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder for the results of
the technical analysis that would occur in Phase II but we believe simply stating that the threshold
will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the reasons noted
above, we believe the threshold should be part of the BES Definition, and should not simply be a
cross-reference to the SCRC (and, given the different purposes of the BES Definition and the SCRC, it
is not clear that the same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate Resources
connected at a voltage of 100kV or above.” Two definitions would then be added to the note at the
end of the definition to read as follows: For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality threshold to be
included in this definition or, in the absence of such a materiality threshold, that meets the gross
nameplate capacity voltage threshold requiring registration of the owner of such a resource as a
Generation Owner under the ERO Statement of Compliance Registry Criteria. For purposes of this BES
Definition, Qualifying Aggregate Generation Resources means any facility consisting of one or more
generating units that are connected at a common bus that meets the materiality threshold to be
included in this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit generator as a
Generation Owner under the ERO Statement of Compliance Registry Criteria.. The “materiality
threshold” is intended to refer to the generator threshold developed in Phase II. We suggest using
definitions in this fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as part of the BES
if they are necessary for operation of the BES, but to exclude smaller generating units because they
are not material to the operation of the interconnected transmission grid. Second, we believe use of
the defined terms better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase II without having to revise the
BES Definition at the end of that process. That is, the definitions are designed to allow the SDT to
include revised thresholds in the definition at the conclusion of the Phase II process based upon the
technical analysis planned for Phase II, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase II is completed. Third, the definitions can be
incorporated into other parts of the BES Definition, which will add consistency and clarity. As noted in
our answers to several of the questions below, the specific 75 MVA threshold is retained in several of
the Exclusions and Inclusions, and we believe the industry would be better served if the revised
thresholds arrived at after technical analysis in Phase II are automatically incorporated into all
relevant provisions of the BES Definition. There is no reason for the SDT to continue to rely on the 75
MVA threshold once the analysis planned for Phase II on the threshold issue is completed. Fourth, the
phrase “or that meets the materiality threshold to be included in this definition” is intended to
preserve the SDT’s flexibility to make a determination that generators below a specific threshold are
not “necessary to” maintain the reliability of the interconnected transmission system, and to
incorporate that finding as part of the definition itself, even if a different threshold is used in the SCRC
to identify potential candidates for registration. Accordingly, our proposed language makes clear that
a specific threshold in the definition controls over any threshold that might be included in the SCRC.
For the reasons stated above, we believe is it highly desirable to include any material threshold in the
BES Definition itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Finally, we agree with the SDT’s decision to
examine the question of where the line between BES and non-BES Elements should be drawn more
closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and commend the work
of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting point for the

SDT’s analysis on this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities interconnecting such
generators to be part of the BES. As discussed more fully in our answer to Question 9, based on
extensive technical analysis that has already been performed by the NERC Project 2010-07 Standards
Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a
dedicated interconnection facility connecting a BES generator to the interconnected bulk transmission
grid will result in an unnecessary regulatory burden that produces considerable expense for the owner
of the interconnection facility with little or no improvement in bulk system reliability. We also believe
the clauses at the end of Inclusion 2 are somewhat confusing and that greater clarity would be
achieved by changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100kV or above” so that the Inclusion covers transformers
with terminals “connected at a voltage of 100kV or above, including the generator terminal(s) on the
high side of the step-up transformer(s) if operated at a voltage of 100kV or above.”
Yes
LEC supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
LEC supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
LEC has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, LEC believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be

subject to the same technical analysis that will cover generators in the Phase II process. Finally, LEC
believes this issue should be addressed in Phase 2 since there is not technical justification or analysis
done to determine the thresholds. LEC strongly believes that there should be technical justification for
thresholds for this issue and all other issues.
Yes
LEC continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, LEC strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.
Yes
LEC supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, LEC urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN.

Yes
LEC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of radial
systems to local networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. If the BES definition
were to provide an exclusion for radials without providing a similar exclusion for LNs, however, it
would discourage networking local distribution systems because of the significantly increased
regulatory burdens faced by the local distribution utility if it elected to network its radial facilities. By
placing radial systems and LNs on the same regulatory footing, the proposed definition will ensure
that decisions about whether to network radial systems are made on the basis of costs and benefits to
the retail customers served by those radials, and not on the basis of disparate regulatory treatment.
Consumers would ultimately benefit. LEC also supports specific refinements made to the LN exclusion
by the SDT in the current draft of the BES definition. In particular, LEC supports the clarification of
the purposes of a LN. The current draft states that LNs connect at multiple points to “improve the
level of service to retail customer Load and not to accommodate bulk power transfer across the
interconnected system.” LEC supports this change in language because it reflects the fundamental
purposes of a LN and emphasizes one of the key distinctions between LNs and bulk transmission
facilities, namely, that LNs are designed primarily to serve local retail load while bulk transmission
facilities are designed primarily to move bulk power from a bulk source (generally either the point of
interconnection of a wholesale generator or a the point of interconnection with another bulk
transmission system) to one or more wholesale purchasers. LEC believes further improvement of the
language could be achieved with additional modifications and clarifications. With respect to the core
language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
LEC also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and
dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and

7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3. LEC
also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as long as
subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as a Flow
Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that allow
reliable transmission of bulk electric power on the interconnected grid. If a LN has not been identified
as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable transmission
of electricity on the interconnected bulk system. Apart from these specific improvements that we
believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may need to
re-examine certain assumptions that appear to underlie the current draft. Specifically, subparagraph
(a) suggests that if BES generation is embedded within a LN, the LN itself must also be BES. But two
NERC bodies have already addressed similar questions and concluded there is no technical basis for
such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO
Task Force” were formed to address how the dedicated interconnection facilities linking a BES
generator to high-voltage transmission facilities should be treated under the NERC standards. The
GO-TO Team concluded that by complying with a handful of reliability standards, primarily related to
vegetation management, reliable operation of the bulk interconnected system could be protected
without unduly burdening the owners of such interconnection systems. Therefore, there is no reason,
according to the GO-TO Team, that dedicated high-voltage interconnection facilities must be treated
as “Transmission” and classified as part of the BES in order to make reliability standards effective.
See Final Report from the NERC Ad Hoc Group for Generator Requirements at the Transmission
Interface (Nov. 16, 2009) (paper written by the GO-TO Task Force). Similarly, the Project 2010-07
Team observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to Transmission
Owners and Transmission Operators who own and operate transmission Facilities and Elements that
are part of the integrated bulk power system.” White Paper Proposal for Information Comment, NERC
Project 2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011).
Requiring Generation Owners and Operators to comply with the same standards as BES Transmission
Owners and Operators “would do little, if anything, to improve the reliability of the Bulk Electric
System,” especially “when compared to the operation of the equipment that actually produces
electricity – the generation equipment itself.” Id. We believe that interconnection of BES generators
within a LN is analogous and that, based on the findings of the Project 2010-07 and GO-TO Teams,
automatically classifying a LN as “BES” simply because a large generator is embedded in the LN will
result in substantial overregulation and unnecessary expense with little gain for bulk system
reliability. If anything, generation interconnected through a LN is less likely to produce material
impacts on the interconnected bulk transmission system than the equivalent generator interconnected
through a single dedicated line because an LN is interconnected to the bulk system at several points,
so that if one interconnection goes down, power can still flow from the BES generator to the bulk
system on other interconnection points. Where a dedicated interconnection facility is involved, by
contrast, if the interconnection line fails, the generator is unavailable to the interconnected bulk
system. Similarly, we suggest that the SDT re-examine the assumptions underlying subparagraph
(b), which seems to suggest that a local distribution system cannot be classified as a Local Network if
power flows out of that system at any time, even if the amount is de minimis, the outward flow is
only for a few hours, a year, or the outward flow occurs only in an extreme contingency. Accordingly,
we suggest that the initial clause of subparagraph (b) be revised to read: “Except in unusual
circumstances, power flows only into the LN.” Finally, we note that the LN exclusion must not operate

in any way as a substitution for the statutory prohibition on including “facilities used in the local
distribution of electric energy” in the BES. Therefore, even with the LN exclusion, the SDT must retain
this statutory language in the core definition of the BES, as discussed in our answer to Question One.
If a certain piece of equipment is a “facility used in the local distribution of electric energy,” then it is
not part of the BES in the first instance, and so consideration of the LN Exclusion, or of any other
Exclusion, any Inclusion, or any Exception, would be both unnecessary and uncalled for.
Yes
LEC supports the revised language because retail reactive devices are used to address local customer
or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such local
devices should therefore be excluded from the BES definition.
No
LEC extends its thanks to the SDT and to the many industry entities that have actively participating in
the Standards Development Process. LEC supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, LEC is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that LEC specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. LEC supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. LEC
also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Michael Henry
Lincoln Electric Cooperative (LEC)
Yes
The Lincoln Electric Cooperative (LEC) believes the SDT continues to make substantial progress
towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly improves
both the existing definition and the SDT’s previous proposal. LEC therefore supports the new
definition, although our support is conditioned on: (1) a workable Exceptions process being developed
in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II of
the standards development process in accordance with the SAR recently put forward by the SDT,
which would address a number of important technical issues that have been identified in the
standards development process to date. LEC strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, LEC supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in

the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). LEC thanks the SDT for the excellent work to include this sentence. For
similar reasons, LEC believes the use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes clear
that the BES includes only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. LEC recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, LEC agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, LEC is prepared to support the BES definition as
proposed by the SDT. While LEC supports the overall approach adopted by the SDT and much of the
specific language incorporated into the second draft of the BES definition, we believe the second draft
would benefit from further clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential for
a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, LEC believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
LEC will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is

necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
LEC supports the changes made in Inclusion 2 and believes that the definition in its current form adds
clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the previous
draft definition into a single Inclusion that addresses the treatment of generation for purposes of the
BES definition. We also support the SDT’s proposal for a Phase II of the BES Definition process that
would examine the technical justification for these thresholds and that would establish new thresholds
based on a careful technical analysis. It is our understanding that the generator threshold issue will
be vetted through the complete standards development process. We agree with this approach
because if the generator threshold is treated as merely an element of NERC’s Rules of Procedure, it
can be changed with considerably less process and industry input than the Standards Development
Process. Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of Procedure upon
approval of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3, 2010)
(providing for, e.g., posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011) (“Order No. 743
directed the ERO to revise the definition of ‘bulk electric system’ through the NERC Standards
Development Process” (emph. added)). Addressing all aspects of Phase II through the Standards
Development Process will improve the content of the definition by bringing to bear industry expertise
on all aspects of the definition and will ensure that, once firm guidelines are established, they can be
relied upon by both industry and regulators without threat that they will be changed with little notice
and little process. LEC believes further clarification of the proposed language would be appropriate.
The SDT proposes continued reliance upon the thresholds that are used in the NERC Statement of
Compliance Registry Criteria for registration of Generation Owners and Generation Operators, which is
currently 20 MVA for an individual generation unit and 75 MVA for multiple units on a single site.
Conceptually, we are concerned about this approach because, as we understand it, the purpose of the
Compliance Registry is to sweep in all generators that might be material to the reliable operation of
the BES, and not to definitively determine whether a given generator is, in fact, material to the
reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to identify
“candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we believe that the
generator threshold determined in Phase II should be incorporated directly into the BES Definition
rather than being incorporated by reference from the SCRC. We also believe that the specific
language proposed by the SDT could be further clarified. The SDT proposes that generation be
included in the BES if the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder for the results of
the technical analysis that would occur in Phase II but we believe simply stating that the threshold
will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the reasons noted
above, we believe the threshold should be part of the BES Definition, and should not simply be a
cross-reference to the SCRC (and, given the different purposes of the BES Definition and the SCRC, it
is not clear that the same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate Resources
connected at a voltage of 100kV or above.” Two definitions would then be added to the note at the
end of the definition to read as follows: For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality threshold to be
included in this definition or, in the absence of such a materiality threshold, that meets the gross

nameplate capacity voltage threshold requiring registration of the owner of such a resource as a
Generation Owner under the ERO Statement of Compliance Registry Criteria. For purposes of this BES
Definition, Qualifying Aggregate Generation Resources means any facility consisting of one or more
generating units that are connected at a common bus that meets the materiality threshold to be
included in this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit generator as a
Generation Owner under the ERO Statement of Compliance Registry Criteria.. The “materiality
threshold” is intended to refer to the generator threshold developed in Phase II. We suggest using
definitions in this fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as part of the BES
if they are necessary for operation of the BES, but to exclude smaller generating units because they
are not material to the operation of the interconnected transmission grid. Second, we believe use of
the defined terms better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase II without having to revise the
BES Definition at the end of that process. That is, the definitions are designed to allow the SDT to
include revised thresholds in the definition at the conclusion of the Phase II process based upon the
technical analysis planned for Phase II, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase II is completed. Third, the definitions can be
incorporated into other parts of the BES Definition, which will add consistency and clarity. As noted in
our answers to several of the questions below, the specific 75 MVA threshold is retained in several of
the Exclusions and Inclusions, and we believe the industry would be better served if the revised
thresholds arrived at after technical analysis in Phase II are automatically incorporated into all
relevant provisions of the BES Definition. There is no reason for the SDT to continue to rely on the 75
MVA threshold once the analysis planned for Phase II on the threshold issue is completed. Fourth, the
phrase “or that meets the materiality threshold to be included in this definition” is intended to
preserve the SDT’s flexibility to make a determination that generators below a specific threshold are
not “necessary to” maintain the reliability of the interconnected transmission system, and to
incorporate that finding as part of the definition itself, even if a different threshold is used in the SCRC
to identify potential candidates for registration. Accordingly, our proposed language makes clear that
a specific threshold in the definition controls over any threshold that might be included in the SCRC.
For the reasons stated above, we believe is it highly desirable to include any material threshold in the
BES Definition itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Finally, we agree with the SDT’s decision to
examine the question of where the line between BES and non-BES Elements should be drawn more
closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and commend the work
of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting point for the
SDT’s analysis on this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities interconnecting such
generators to be part of the BES. As discussed more fully in our answer to Question 9, based on
extensive technical analysis that has already been performed by the NERC Project 2010-07 Standards
Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a
dedicated interconnection facility connecting a BES generator to the interconnected bulk transmission
grid will result in an unnecessary regulatory burden that produces considerable expense for the owner
of the interconnection facility with little or no improvement in bulk system reliability. We also believe
the clauses at the end of Inclusion 2 are somewhat confusing and that greater clarity would be
achieved by changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100kV or above” so that the Inclusion covers transformers
with terminals “connected at a voltage of 100kV or above, including the generator terminal(s) on the
high side of the step-up transformer(s) if operated at a voltage of 100kV or above.”
Yes
LEC supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
LEC supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA

generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
LEC has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, LEC believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally, LEC
believes this issue should be addressed in Phase 2 since there is not technical justification or analysis
done to determine the thresholds. LEC strongly believes that there should be technical justification for
thresholds for this issue and all other issues.
Yes
LEC continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate

rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, LEC strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.
Yes
LEC supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, LEC urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN.
Yes
LEC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of radial
systems to local networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. If the BES definition
were to provide an exclusion for radials without providing a similar exclusion for LNs, however, it
would discourage networking local distribution systems because of the significantly increased
regulatory burdens faced by the local distribution utility if it elected to network its radial facilities. By
placing radial systems and LNs on the same regulatory footing, the proposed definition will ensure
that decisions about whether to network radial systems are made on the basis of costs and benefits to
the retail customers served by those radials, and not on the basis of disparate regulatory treatment.
Consumers would ultimately benefit. LEC also supports specific refinements made to the LN exclusion
by the SDT in the current draft of the BES definition. In particular, LEC supports the clarification of
the purposes of a LN. The current draft states that LNs connect at multiple points to “improve the
level of service to retail customer Load and not to accommodate bulk power transfer across the
interconnected system.” LEC supports this change in language because it reflects the fundamental
purposes of a LN and emphasizes one of the key distinctions between LNs and bulk transmission
facilities, namely, that LNs are designed primarily to serve local retail load while bulk transmission
facilities are designed primarily to move bulk power from a bulk source (generally either the point of
interconnection of a wholesale generator or a the point of interconnection with another bulk
transmission system) to one or more wholesale purchasers. LEC believes further improvement of the

language could be achieved with additional modifications and clarifications. With respect to the core
language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
LEC also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and
dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3. LEC
also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as long as
subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as a Flow
Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that allow
reliable transmission of bulk electric power on the interconnected grid. If a LN has not been identified
as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable transmission
of electricity on the interconnected bulk system. Apart from these specific improvements that we

believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may need to
re-examine certain assumptions that appear to underlie the current draft. Specifically, subparagraph
(a) suggests that if BES generation is embedded within a LN, the LN itself must also be BES. But two
NERC bodies have already addressed similar questions and concluded there is no technical basis for
such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO
Task Force” were formed to address how the dedicated interconnection facilities linking a BES
generator to high-voltage transmission facilities should be treated under the NERC standards. The
GO-TO Team concluded that by complying with a handful of reliability standards, primarily related to
vegetation management, reliable operation of the bulk interconnected system could be protected
without unduly burdening the owners of such interconnection systems. Therefore, there is no reason,
according to the GO-TO Team, that dedicated high-voltage interconnection facilities must be treated
as “Transmission” and classified as part of the BES in order to make reliability standards effective.
See Final Report from the NERC Ad Hoc Group for Generator Requirements at the Transmission
Interface (Nov. 16, 2009) (paper written by the GO-TO Task Force). Similarly, the Project 2010-07
Team observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to Transmission
Owners and Transmission Operators who own and operate transmission Facilities and Elements that
are part of the integrated bulk power system.” White Paper Proposal for Information Comment, NERC
Project 2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011).
Requiring Generation Owners and Operators to comply with the same standards as BES Transmission
Owners and Operators “would do little, if anything, to improve the reliability of the Bulk Electric
System,” especially “when compared to the operation of the equipment that actually produces
electricity – the generation equipment itself.” Id. We believe that interconnection of BES generators
within a LN is analogous and that, based on the findings of the Project 2010-07 and GO-TO Teams,
automatically classifying a LN as “BES” simply because a large generator is embedded in the LN will
result in substantial overregulation and unnecessary expense with little gain for bulk system
reliability. If anything, generation interconnected through a LN is less likely to produce material
impacts on the interconnected bulk transmission system than the equivalent generator interconnected
through a single dedicated line because an LN is interconnected to the bulk system at several points,
so that if one interconnection goes down, power can still flow from the BES generator to the bulk
system on other interconnection points. Where a dedicated interconnection facility is involved, by
contrast, if the interconnection line fails, the generator is unavailable to the interconnected bulk
system. Similarly, we suggest that the SDT re-examine the assumptions underlying subparagraph
(b), which seems to suggest that a local distribution system cannot be classified as a Local Network if
power flows out of that system at any time, even if the amount is de minimis, the outward flow is
only for a few hours, a year, or the outward flow occurs only in an extreme contingency. Accordingly,
we suggest that the initial clause of subparagraph (b) be revised to read: “Except in unusual
circumstances, power flows only into the LN.” Finally, we note that the LN exclusion must not operate
in any way as a substitution for the statutory prohibition on including “facilities used in the local
distribution of electric energy” in the BES. Therefore, even with the LN exclusion, the SDT must retain
this statutory language in the core definition of the BES, as discussed in our answer to Question One.
If a certain piece of equipment is a “facility used in the local distribution of electric energy,” then it is
not part of the BES in the first instance, and so consideration of the LN Exclusion, or of any other
Exclusion, any Inclusion, or any Exception, would be both unnecessary and uncalled for.
Yes
LEC supports the revised language because retail reactive devices are used to address local customer
or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such local
devices should therefore be excluded from the BES definition.
No
LEC extends its thanks to the SDT and to the many industry entities that have actively participating in
the Standards Development Process. LEC supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, LEC is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team

will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that LEC specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. LEC supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. LEC
also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Jon Shelby
Northern Lights Inc. (NLI)
Yes
The Northern Lights (NLI) believes the SDT continues to make substantial progress towards a clear
and workable definition of the Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. NLI therefore supports the new definition, although our
support is conditioned on: (1) a workable Exceptions process being developed in conjunction with the
BES definition; and, (2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the SDT, which would
address a number of important technical issues that have been identified in the standards
development process to date. NLI strongly supports the following elements of the revised BES
definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, NLI supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). NLI thanks the SDT for the excellent work to include this sentence. For
similar reasons, NLI believes the use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes clear
that the BES includes only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an

analysis would be conducted as part of the current standards development process. NLI recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, NLI agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, NLI is prepared to support the BES definition as
proposed by the SDT. While NLI supports the overall approach adopted by the SDT and much of the
specific language incorporated into the second draft of the BES definition, we believe the second draft
would benefit from further clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential for
a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, NLI believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
NLI will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
NLI supports the changes made in Inclusion 2 and believes that the definition in its current form adds
clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the previous
draft definition into a single Inclusion that addresses the treatment of generation for purposes of the

BES definition. We also support the SDT’s proposal for a Phase II of the BES Definition process that
would examine the technical justification for these thresholds and that would establish new thresholds
based on a careful technical analysis. It is our understanding that the generator threshold issue will
be vetted through the complete standards development process. We agree with this approach
because if the generator threshold is treated as merely an element of NERC’s Rules of Procedure, it
can be changed with considerably less process and industry input than the Standards Development
Process. Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of Procedure upon
approval of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3, 2010)
(providing for, e.g., posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011) (“Order No. 743
directed the ERO to revise the definition of ‘bulk electric system’ through the NERC Standards
Development Process” (emph. added)). Addressing all aspects of Phase II through the Standards
Development Process will improve the content of the definition by bringing to bear industry expertise
on all aspects of the definition and will ensure that, once firm guidelines are established, they can be
relied upon by both industry and regulators without threat that they will be changed with little notice
and little process. NLI believes further clarification of the proposed language would be appropriate.
The SDT proposes continued reliance upon the thresholds that are used in the NERC Statement of
Compliance Registry Criteria for registration of Generation Owners and Generation Operators, which is
currently 20 MVA for an individual generation unit and 75 MVA for multiple units on a single site.
Conceptually, we are concerned about this approach because, as we understand it, the purpose of the
Compliance Registry is to sweep in all generators that might be material to the reliable operation of
the BES, and not to definitively determine whether a given generator is, in fact, material to the
reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to identify
“candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we believe that the
generator threshold determined in Phase II should be incorporated directly into the BES Definition
rather than being incorporated by reference from the SCRC. We also believe that the specific
language proposed by the SDT could be further clarified. The SDT proposes that generation be
included in the BES if the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder for the results of
the technical analysis that would occur in Phase II but we believe simply stating that the threshold
will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the reasons noted
above, we believe the threshold should be part of the BES Definition, and should not simply be a
cross-reference to the SCRC (and, given the different purposes of the BES Definition and the SCRC, it
is not clear that the same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate Resources
connected at a voltage of 100kV or above.” Two definitions would then be added to the note at the
end of the definition to read as follows: For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality threshold to be
included in this definition or, in the absence of such a materiality threshold, that meets the gross
nameplate capacity voltage threshold requiring registration of the owner of such a resource as a
Generation Owner under the ERO Statement of Compliance Registry Criteria. For purposes of this BES
Definition, Qualifying Aggregate Generation Resources means any facility consisting of one or more
generating units that are connected at a common bus that meets the materiality threshold to be
included in this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit generator as a
Generation Owner under the ERO Statement of Compliance Registry Criteria.. The “materiality
threshold” is intended to refer to the generator threshold developed in Phase II. We suggest using
definitions in this fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as part of the BES
if they are necessary for operation of the BES, but to exclude smaller generating units because they
are not material to the operation of the interconnected transmission grid. Second, we believe use of
the defined terms better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase II without having to revise the
BES Definition at the end of that process. That is, the definitions are designed to allow the SDT to
include revised thresholds in the definition at the conclusion of the Phase II process based upon the
technical analysis planned for Phase II, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase II is completed. Third, the definitions can be

incorporated into other parts of the BES Definition, which will add consistency and clarity. As noted in
our answers to several of the questions below, the specific 75 MVA threshold is retained in several of
the Exclusions and Inclusions, and we believe the industry would be better served if the revised
thresholds arrived at after technical analysis in Phase II are automatically incorporated into all
relevant provisions of the BES Definition. There is no reason for the SDT to continue to rely on the 75
MVA threshold once the analysis planned for Phase II on the threshold issue is completed. Fourth, the
phrase “or that meets the materiality threshold to be included in this definition” is intended to
preserve the SDT’s flexibility to make a determination that generators below a specific threshold are
not “necessary to” maintain the reliability of the interconnected transmission system, and to
incorporate that finding as part of the definition itself, even if a different threshold is used in the SCRC
to identify potential candidates for registration. Accordingly, our proposed language makes clear that
a specific threshold in the definition controls over any threshold that might be included in the SCRC.
For the reasons stated above, we believe is it highly desirable to include any material threshold in the
BES Definition itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Finally, we agree with the SDT’s decision to
examine the question of where the line between BES and non-BES Elements should be drawn more
closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and commend the work
of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting point for the
SDT’s analysis on this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities interconnecting such
generators to be part of the BES. As discussed more fully in our answer to Question 9, based on
extensive technical analysis that has already been performed by the NERC Project 2010-07 Standards
Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a
dedicated interconnection facility connecting a BES generator to the interconnected bulk transmission
grid will result in an unnecessary regulatory burden that produces considerable expense for the owner
of the interconnection facility with little or no improvement in bulk system reliability. We also believe
the clauses at the end of Inclusion 2 are somewhat confusing and that greater clarity would be
achieved by changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100kV or above” so that the Inclusion covers transformers
with terminals “connected at a voltage of 100kV or above, including the generator terminal(s) on the
high side of the step-up transformer(s) if operated at a voltage of 100kV or above.”
Yes
NLI supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
NLI supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be

established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
NLI has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, NLI believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally, NLI
believes this issue should be addressed in Phase 2 since there is not technical justification or analysis
done to determine the thresholds. NLI strongly believes that there should be technical justification for
thresholds for this issue and all other issues.
Yes
NLI continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, NLI strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.

Yes
NLI supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, NLI urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN.
Yes
NLI strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of radial
systems to local networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. If the BES definition
were to provide an exclusion for radials without providing a similar exclusion for LNs, however, it
would discourage networking local distribution systems because of the significantly increased
regulatory burdens faced by the local distribution utility if it elected to network its radial facilities. By
placing radial systems and LNs on the same regulatory footing, the proposed definition will ensure
that decisions about whether to network radial systems are made on the basis of costs and benefits to
the retail customers served by those radials, and not on the basis of disparate regulatory treatment.
Consumers would ultimately benefit. NLI also supports specific refinements made to the LN exclusion
by the SDT in the current draft of the BES definition. In particular, NLI supports the clarification of the
purposes of a LN. The current draft states that LNs connect at multiple points to “improve the level of
service to retail customer Load and not to accommodate bulk power transfer across the
interconnected system.” NLI supports this change in language because it reflects the fundamental
purposes of a LN and emphasizes one of the key distinctions between LNs and bulk transmission
facilities, namely, that LNs are designed primarily to serve local retail load while bulk transmission
facilities are designed primarily to move bulk power from a bulk source (generally either the point of
interconnection of a wholesale generator or a the point of interconnection with another bulk
transmission system) to one or more wholesale purchasers. NLI believes further improvement of the
language could be achieved with additional modifications and clarifications. With respect to the core
language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
NLI also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and

dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3. NLI
also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as long as
subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as a Flow
Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that allow
reliable transmission of bulk electric power on the interconnected grid. If a LN has not been identified
as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable transmission
of electricity on the interconnected bulk system. Apart from these specific improvements that we
believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may need to
re-examine certain assumptions that appear to underlie the current draft. Specifically, subparagraph
(a) suggests that if BES generation is embedded within a LN, the LN itself must also be BES. But two
NERC bodies have already addressed similar questions and concluded there is no technical basis for
such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO
Task Force” were formed to address how the dedicated interconnection facilities linking a BES
generator to high-voltage transmission facilities should be treated under the NERC standards. The
GO-TO Team concluded that by complying with a handful of reliability standards, primarily related to
vegetation management, reliable operation of the bulk interconnected system could be protected
without unduly burdening the owners of such interconnection systems. Therefore, there is no reason,
according to the GO-TO Team, that dedicated high-voltage interconnection facilities must be treated
as “Transmission” and classified as part of the BES in order to make reliability standards effective.
See Final Report from the NERC Ad Hoc Group for Generator Requirements at the Transmission
Interface (Nov. 16, 2009) (paper written by the GO-TO Task Force). Similarly, the Project 2010-07
Team observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to Transmission
Owners and Transmission Operators who own and operate transmission Facilities and Elements that
are part of the integrated bulk power system.” White Paper Proposal for Information Comment, NERC
Project 2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011).

Requiring Generation Owners and Operators to comply with the same standards as BES Transmission
Owners and Operators “would do little, if anything, to improve the reliability of the Bulk Electric
System,” especially “when compared to the operation of the equipment that actually produces
electricity – the generation equipment itself.” Id. We believe that interconnection of BES generators
within a LN is analogous and that, based on the findings of the Project 2010-07 and GO-TO Teams,
automatically classifying a LN as “BES” simply because a large generator is embedded in the LN will
result in substantial overregulation and unnecessary expense with little gain for bulk system
reliability. If anything, generation interconnected through a LN is less likely to produce material
impacts on the interconnected bulk transmission system than the equivalent generator interconnected
through a single dedicated line because an LN is interconnected to the bulk system at several points,
so that if one interconnection goes down, power can still flow from the BES generator to the bulk
system on other interconnection points. Where a dedicated interconnection facility is involved, by
contrast, if the interconnection line fails, the generator is unavailable to the interconnected bulk
system. Similarly, we suggest that the SDT re-examine the assumptions underlying subparagraph
(b), which seems to suggest that a local distribution system cannot be classified as a Local Network if
power flows out of that system at any time, even if the amount is de minimis, the outward flow is
only for a few hours, a year, or the outward flow occurs only in an extreme contingency. Accordingly,
we suggest that the initial clause of subparagraph (b) be revised to read: “Except in unusual
circumstances, power flows only into the LN.” Finally, we note that the LN exclusion must not operate
in any way as a substitution for the statutory prohibition on including “facilities used in the local
distribution of electric energy” in the BES. Therefore, even with the LN exclusion, the SDT must retain
this statutory language in the core definition of the BES, as discussed in our answer to Question One.
If a certain piece of equipment is a “facility used in the local distribution of electric energy,” then it is
not part of the BES in the first instance, and so consideration of the LN Exclusion, or of any other
Exclusion, any Inclusion, or any Exception, would be both unnecessary and uncalled for.
Yes
NLI supports the revised language because retail reactive devices are used to address local customer
or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such local
devices should therefore be excluded from the BES definition.
No
NLI extends its thanks to the SDT and to the many industry entities that have actively participating in
the Standards Development Process. NLI supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, NLI is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that NLI specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. NLI supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. NLI also
supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Randy MacDonald
NBPT

Yes
• When an exclusion and inclusion principles overlap which takes precedence? For example I5 may be
excluded if in a LN (E3) • The Local Network Exclusion criterion does not appear to consider voltage
support and the effects of shifting of load or impacts due to a loss of load. The 75 MW generation
threshold has no technical basis. The LN exclusion should allow for studies demonstrating no through
flow benefit regardless if there is. • 75 MW Generation has no technical justification. • Black Start
resources should not be included in all GO/GOP standards except for those standards specific to black
start units.
Individual
Ray Ellis
Okanogan County Electric Cooperative (OCEC)
Yes
The Okanogan County Electric Cooperative (OCEC) believes the SDT continues to make substantial
progress towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly
improves both the existing definition and the SDT’s previous proposal. OCEC therefore supports the
new definition, although our support is conditioned on: (1) a workable Exceptions process being
developed in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on
Phase II of the standards development process in accordance with the SAR recently put forward by
the SDT, which would address a number of important technical issues that have been identified in the
standards development process to date. OCEC strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, OCEC supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). OCEC thanks the SDT for the excellent work to include this sentence. For
similar reasons, OCEC believes the use of the phrase “Transmission Elements” as the starting point
for the base definition is desirable because both “Transmission” and “Elements” are already defined in
the NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes
clear that the BES includes only Elements used in Transmission and therefore excludes Elements used
in local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards

development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. OCEC recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, OCEC agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, OCEC is prepared to support the BES definition
as proposed by the SDT. While OCEC supports the overall approach adopted by the SDT and much of
the specific language incorporated into the second draft of the BES definition, we believe the second
draft would benefit from further clarification or modification in a number of respects, most of which
are detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential
for a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, OCEC believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
OCEC will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”

Yes
OCEC supports the changes made in Inclusion 2 and believes that the definition in its current form
adds clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the
previous draft definition into a single Inclusion that addresses the treatment of generation for
purposes of the BES definition. We also support the SDT’s proposal for a Phase II of the BES
Definition process that would examine the technical justification for these thresholds and that would
establish new thresholds based on a careful technical analysis. It is our understanding that the
generator threshold issue will be vetted through the complete standards development process. We
agree with this approach because if the generator threshold is treated as merely an element of
NERC’s Rules of Procedure, it can be changed with considerably less process and industry input than
the Standards Development Process. Compare NERC Rules of Procedure § 1400 (providing for
changes to Rules of Procedure upon approval of the NERC board and FERC) with NERC Standards
Process Manual (Sept. 3, 2010) (providing for, e.g., posting of SDT proposals for comment,
successive balloting, and super-majority approval requirements). See also Order No. 743-A, 134 FERC
¶ 61,210 at P 4 (2011) (“Order No. 743 directed the ERO to revise the definition of ‘bulk electric
system’ through the NERC Standards Development Process” (emph. added)). Addressing all aspects
of Phase II through the Standards Development Process will improve the content of the definition by
bringing to bear industry expertise on all aspects of the definition and will ensure that, once firm
guidelines are established, they can be relied upon by both industry and regulators without threat
that they will be changed with little notice and little process. OCEC believes further clarification of the
proposed language would be appropriate. The SDT proposes continued reliance upon the thresholds
that are used in the NERC Statement of Compliance Registry Criteria for registration of Generation
Owners and Generation Operators, which is currently 20 MVA for an individual generation unit and 75
MVA for multiple units on a single site. Conceptually, we are concerned about this approach because,
as we understand it, the purpose of the Compliance Registry is to sweep in all generators that might
be material to the reliable operation of the BES, and not to definitively determine whether a given
generator is, in fact, material to the reliable operation of the BES. As the SCRC itself states, the SCRC
is intended only to identify “candidates for registration.” SCRC at p.3, § 1 (emph. added).
Accordingly, we believe that the generator threshold determined in Phase II should be incorporated
directly into the BES Definition rather than being incorporated by reference from the SCRC. We also
believe that the specific language proposed by the SDT could be further clarified. The SDT proposes
that generation be included in the BES if the “Generation resource(s)” has a “nameplate rating per the
ERO Statement of Compliance Registry.” We understand this language is intended to be a placeholder
for the results of the technical analysis that would occur in Phase II but we believe simply stating that
the threshold will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the
reasons noted above, we believe the threshold should be part of the BES Definition, and should not
simply be a cross-reference to the SCRC (and, given the different purposes of the BES Definition and
the SCRC, it is not clear that the same threshold should be used in both). We therefore propose that
Inclusion 2 be rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate
Resources connected at a voltage of 100kV or above.” Two definitions would then be added to the
note at the end of the definition to read as follows: For purposes of this BES Definition, Qualifying
Individual Generation Resources means an individual generating unit that meets the materiality
threshold to be included in this definition or, in the absence of such a materiality threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of such a
resource as a Generation Owner under the ERO Statement of Compliance Registry Criteria. For
purposes of this BES Definition, Qualifying Aggregate Generation Resources means any facility
consisting of one or more generating units that are connected at a common bus that meets the
materiality threshold to be included in this definition, or, in the absence of such a threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of multipleunit generator as a Generation Owner under the ERO Statement of Compliance Registry Criteria.. The
“materiality threshold” is intended to refer to the generator threshold developed in Phase II. We
suggest using definitions in this fashion for several reasons. First, we believe the language we suggest
more clearly states the intention of the SDT, which we understand is to classify generation units as
part of the BES if they are necessary for operation of the BES, but to exclude smaller generating units
because they are not material to the operation of the interconnected transmission grid. Second, we
believe use of the defined terms better reflects the intention of the SDT to reserve the specific
question about generator thresholds to the technical analysis that will occur in Phase II without
having to revise the BES Definition at the end of that process. That is, the definitions are designed to

allow the SDT to include revised thresholds in the definition at the conclusion of the Phase II process
based upon the technical analysis planned for Phase II, and the revised thresholds will be
automatically incorporated into the BES Definition if the language we suggest is used. The thresholds
used in the SCRC would only be a fall-back, to be used only until Phase II is completed. Third, the
definitions can be incorporated into other parts of the BES Definition, which will add consistency and
clarity. As noted in our answers to several of the questions below, the specific 75 MVA threshold is
retained in several of the Exclusions and Inclusions, and we believe the industry would be better
served if the revised thresholds arrived at after technical analysis in Phase II are automatically
incorporated into all relevant provisions of the BES Definition. There is no reason for the SDT to
continue to rely on the 75 MVA threshold once the analysis planned for Phase II on the threshold
issue is completed. Fourth, the phrase “or that meets the materiality threshold to be included in this
definition” is intended to preserve the SDT’s flexibility to make a determination that generators below
a specific threshold are not “necessary to” maintain the reliability of the interconnected transmission
system, and to incorporate that finding as part of the definition itself, even if a different threshold is
used in the SCRC to identify potential candidates for registration. Accordingly, our proposed language
makes clear that a specific threshold in the definition controls over any threshold that might be
included in the SCRC. For the reasons stated above, we believe is it highly desirable to include any
material threshold in the BES Definition itself rather than relegating the threshold to the SCRC, which
is merely a procedural rule rather than a full-fledged Reliability Standard. Finally, we agree with the
SDT’s decision to examine the question of where the line between BES and non-BES Elements should
be drawn more closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and
commend the work of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good
starting point for the SDT’s analysis on this issue. We understand Inclusion 2 would classify
generators exceeding specific thresholds as part of the BES, but would not necessarily require
facilities interconnecting such generators to be part of the BES. As discussed more fully in our answer
to Question 9, based on extensive technical analysis that has already been performed by the NERC
Project 2010-07 Standards Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating
as part of the BES a dedicated interconnection facility connecting a BES generator to the
interconnected bulk transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no improvement in bulk
system reliability. We also believe the clauses at the end of Inclusion 2 are somewhat confusing and
that greater clarity would be achieved by changing “. . . including the generator terminals through the
high-side of the step-up transformer(s) connected at a voltage of 100kV or above” so that the
Inclusion covers transformers with terminals “connected at a voltage of 100kV or above, including the
generator terminal(s) on the high side of the step-up transformer(s) if operated at a voltage of 100kV
or above.”
Yes
OCEC supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
OCEC supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,

causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
OCEC has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, OCEC believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally,
OCEC believes this issue should be addressed in Phase 2 since there is not technical justification or
analysis done to determine the thresholds. OCEC strongly believes that there should be technical
justification for thresholds for this issue and all other issues.
Yes
OCEC continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, OCEC strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between

radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.
Yes
OCEC supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, OCEC urges the SDT to remove the reference to
the 75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation
Resources” or some equivalent language for the reasons stated in our responses to Questions 3, 5,
and 7. In addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult
position because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial
System or a Local Network through the actions of a customer constructing behind-the-meter
generation, With respect to Radial Systems, the appearance of behind-the-meter generators could
cause the Radial System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion
1 through no fault of the Radial System owner. Similar, a Local Network could lose its status because
behind-the-meter generation could be of sufficient size that power moves into the interconnected grid
in certain hours or under certain contingencies, rather than moving purely onto the Local Network, as
required in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks
should be made consistent with the Exclusion for behind-the-meter generation. There is no technical
reason to believe the power flowing from a behind-the-meter customer-owned generator will have
less impact on the bulk system than an equivalent-sized generator owned by a utility operating a
Radial System or LN.
Yes
OCEC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of
radial systems to local networks should be encouraged because networked systems generally reduce
losses, increase system efficiency, and increase the level of service to retail customers. If the BES
definition were to provide an exclusion for radials without providing a similar exclusion for LNs,
however, it would discourage networking local distribution systems because of the significantly
increased regulatory burdens faced by the local distribution utility if it elected to network its radial
facilities. By placing radial systems and LNs on the same regulatory footing, the proposed definition
will ensure that decisions about whether to network radial systems are made on the basis of costs
and benefits to the retail customers served by those radials, and not on the basis of disparate
regulatory treatment. Consumers would ultimately benefit. OCEC also supports specific refinements
made to the LN exclusion by the SDT in the current draft of the BES definition. In particular, OCEC
supports the clarification of the purposes of a LN. The current draft states that LNs connect at multiple
points to “improve the level of service to retail customer Load and not to accommodate bulk power
transfer across the interconnected system.” OCEC supports this change in language because it reflects
the fundamental purposes of a LN and emphasizes one of the key distinctions between LNs and bulk
transmission facilities, namely, that LNs are designed primarily to serve local retail load while bulk
transmission facilities are designed primarily to move bulk power from a bulk source (generally either
the point of interconnection of a wholesale generator or a the point of interconnection with another
bulk transmission system) to one or more wholesale purchasers. OCEC believes further improvement
of the language could be achieved with additional modifications and clarifications. With respect to the
core language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
OCEC also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects

more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and
dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3.
OCEC also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as
long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as
a Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that
allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
transmission of electricity on the interconnected bulk system. Apart from these specific improvements
that we believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may
need to re-examine certain assumptions that appear to underlie the current draft. Specifically,
subparagraph (a) suggests that if BES generation is embedded within a LN, the LN itself must also be
BES. But two NERC bodies have already addressed similar questions and concluded there is no
technical basis for such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force” were formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. The GO-TO Team concluded that by complying with a handful of reliability
standards, primarily related to vegetation management, reliable operation of the bulk interconnected
system could be protected without unduly burdening the owners of such interconnection systems.
Therefore, there is no reason, according to the GO-TO Team, that dedicated high-voltage
interconnection facilities must be treated as “Transmission” and classified as part of the BES in order
to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO Task

Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most often
not part of the integrated bulk power system, and as such should not be subject to the same level of
standards applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” White Paper
Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at the
Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply
with the same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of the
equipment that actually produces electricity – the generation equipment itself.” Id. We believe that
interconnection of BES generators within a LN is analogous and that, based on the findings of the
Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply because a large
generator is embedded in the LN will result in substantial overregulation and unnecessary expense
with little gain for bulk system reliability. If anything, generation interconnected through a LN is less
likely to produce material impacts on the interconnected bulk transmission system than the
equivalent generator interconnected through a single dedicated line because an LN is interconnected
to the bulk system at several points, so that if one interconnection goes down, power can still flow
from the BES generator to the bulk system on other interconnection points. Where a dedicated
interconnection facility is involved, by contrast, if the interconnection line fails, the generator is
unavailable to the interconnected bulk system. Similarly, we suggest that the SDT re-examine the
assumptions underlying subparagraph (b), which seems to suggest that a local distribution system
cannot be classified as a Local Network if power flows out of that system at any time, even if the
amount is de minimis, the outward flow is only for a few hours, a year, or the outward flow occurs
only in an extreme contingency. Accordingly, we suggest that the initial clause of subparagraph (b) be
revised to read: “Except in unusual circumstances, power flows only into the LN.” Finally, we note
that the LN exclusion must not operate in any way as a substitution for the statutory prohibition on
including “facilities used in the local distribution of electric energy” in the BES. Therefore, even with
the LN exclusion, the SDT must retain this statutory language in the core definition of the BES, as
discussed in our answer to Question One. If a certain piece of equipment is a “facility used in the local
distribution of electric energy,” then it is not part of the BES in the first instance, and so consideration
of the LN Exclusion, or of any other Exclusion, any Inclusion, or any Exception, would be both
unnecessary and uncalled for.
Yes
OCEC supports the revised language because retail reactive devices are used to address local
customer or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such
local devices should therefore be excluded from the BES definition.
No
OCEC extends its thanks to the SDT and to the many industry entities that have actively participating
in the Standards Development Process. OCEC supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, OCEC is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that OCEC specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. OCEC supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. OCEC
also supports the 24-month transition period for the reasons laid out by the SDT.

Individual
Donald Jones
Texas Reliability Entity

No
We feel that the Cranking Path should be included in the BES definition. Inclusion of the Cranking
Path is vital to a functional, sustainable and reliable system restoration (and restoration plan)
regardless of where the Cranking Path is located. CIP-002-4 Attachment 1 recognizes the critical
nature of the Cranking Path.

No
There should be language that includes UFLS, UVLS, or load fully removable for Reserves even in a
local network to avoid a lapse in reliability in operation of the BES. Even if it is to be included in any
Phase 2 work, it should be mentioned here to avoid gaps.
Yes
(1) It is unclear exactly what is intended by “non-retail generation” in Exclusion E1(c). We suggest
that the term be explained or defined in the BES definition or in a collateral document. This term does
not have a commonly understood unambiguous meaning in our Region. (2) Phase 2 has to be
completed or explicitly defined/scoped to fully capture all of the components necessary for reliable
operation of the BES.
Individual
Diane Barney
New York State Dept of Public Service
No
The core definition is still deficient due to a lack of technical support for basing the BES definition on
100 kV and for lack of any cost/benefit analysis.
No
• I1 lacks specificity that can lead to confusion and required clarifications. Suggested wording change:
All transformers (including auto-transformers, voltage regulators, and phase angle regulators and all
windings) with primary and secondary terminals operated at or above 100 kV, and generator step-up
(GSU) transformers with one terminal operated at or above 100 kV, unless excluded by E1 or E3.
No
In I2, there is a reference to the Statement of Compliance Registry Criteria. However, the Statement
references the BES definition. This circular logic results in a fatally flawed definition. The statement
reference should be replaced with the actual intended words.
No
I4 reference to a “common point” lacks clarity that can lead to confusion and required clarifications.
Suggested wording change: … connected at a common point through a dedicated step-up transformer
with a high-side voltage of 100 kV or above.”
No
I5 – which has been newly added and significantly expands the BES definition – should be dropped
due to lack of technical justification.

Yes
• Per NERC’s obligations under the Energy Power Act of 2005 to provide FERC technical advice, no
technical justification has been provided for basing the BES definition on the 100 kV and MVA
thresholds. • No cost analysis on either the reliability benefits of the overall definition or on the
implementation plan has been performed to determine whether the likely high cost of the definition to
ratepayers is justified. • The definition of the BES should be the driver for the application of all other
NERC reliability standards and criteria. The definition uses the Statement of Compliance Registry
Criteria as a driver of the definition when the reverse should be taking place; contents of the
Statement should be driven by the BES definition.
Individual
Rick Paschall
Pacific Northwest Generating Cooperative (PNGC)
Yes
The Pacific Northwest Generating Cooperative (PNGC) believes the SDT continues to make substantial
progress towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly
improves both the existing definition and the SDT’s previous proposal. PNGC therefore supports the
new definition, although our support is conditioned on: (1) a workable Exceptions process being
developed in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on
Phase II of the standards development process in accordance with the SAR recently put forward by
the SDT, which would address a number of important technical issues that have been identified in the
standards development process to date. PNGC strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, PNGC supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). PNGC thanks the SDT for the excellent work to include this sentence. For
similar reasons, PNGC believes the use of the phrase “Transmission Elements” as the starting point
for the base definition is desirable because both “Transmission” and “Elements” are already defined in
the NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes
clear that the BES includes only Elements used in Transmission and therefore excludes Elements used
in local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. PNGC recognizes

that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, PNGC agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, PNGC is prepared to support the BES definition
as proposed by the SDT. While PNGC supports the overall approach adopted by the SDT and much of
the specific language incorporated into the second draft of the BES definition, we believe the second
draft would benefit from further clarification or modification in a number of respects, most of which
are detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential
for a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, PNGC believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
PNGC will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
PNGC supports the changes made in Inclusion 2 and believes that the definition in its current form
adds clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the
previous draft definition into a single Inclusion that addresses the treatment of generation for
purposes of the BES definition. We also support the SDT’s proposal for a Phase II of the BES

Definition process that would examine the technical justification for these thresholds and that would
establish new thresholds based on a careful technical analysis. It is our understanding that the
generator threshold issue will be vetted through the complete standards development process. We
agree with this approach because if the generator threshold is treated as merely an element of
NERC’s Rules of Procedure, it can be changed with considerably less process and industry input than
the Standards Development Process. Compare NERC Rules of Procedure § 1400 (providing for
changes to Rules of Procedure upon approval of the NERC board and FERC) with NERC Standards
Process Manual (Sept. 3, 2010) (providing for, e.g., posting of SDT proposals for comment,
successive balloting, and super-majority approval requirements). See also Order No. 743-A, 134 FERC
¶ 61,210 at P 4 (2011) (“Order No. 743 directed the ERO to revise the definition of ‘bulk electric
system’ through the NERC Standards Development Process” (emph. added)). Addressing all aspects
of Phase II through the Standards Development Process will improve the content of the definition by
bringing to bear industry expertise on all aspects of the definition and will ensure that, once firm
guidelines are established, they can be relied upon by both industry and regulators without threat
that they will be changed with little notice and little process. PNGC believes further clarification of the
proposed language would be appropriate. The SDT proposes continued reliance upon the thresholds
that are used in the NERC Statement of Compliance Registry Criteria for registration of Generation
Owners and Generation Operators, which is currently 20 MVA for an individual generation unit and 75
MVA for multiple units on a single site. Conceptually, we are concerned about this approach because,
as we understand it, the purpose of the Compliance Registry is to sweep in all generators that might
be material to the reliable operation of the BES, and not to definitively determine whether a given
generator is, in fact, material to the reliable operation of the BES. As the SCRC itself states, the SCRC
is intended only to identify “candidates for registration.” SCRC at p.3, § 1 (emph. added).
Accordingly, we believe that the generator threshold determined in Phase II should be incorporated
directly into the BES Definition rather than being incorporated by reference from the SCRC. We also
believe that the specific language proposed by the SDT could be further clarified. The SDT proposes
that generation be included in the BES if the “Generation resource(s)” has a “nameplate rating per the
ERO Statement of Compliance Registry.” We understand this language is intended to be a placeholder
for the results of the technical analysis that would occur in Phase II but we believe simply stating that
the threshold will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the
reasons noted above, we believe the threshold should be part of the BES Definition, and should not
simply be a cross-reference to the SCRC (and, given the different purposes of the BES Definition and
the SCRC, it is not clear that the same threshold should be used in both). We therefore propose that
Inclusion 2 be rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate
Resources connected at a voltage of 100kV or above.” Two definitions would then be added to the
note at the end of the definition to read as follows: For purposes of this BES Definition, Qualifying
Individual Generation Resources means an individual generating unit that meets the materiality
threshold to be included in this definition or, in the absence of such a materiality threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of such a
resource as a Generation Owner under the ERO Statement of Compliance Registry Criteria. For
purposes of this BES Definition, Qualifying Aggregate Generation Resources means any facility
consisting of one or more generating units that are connected at a common bus that meets the
materiality threshold to be included in this definition, or, in the absence of such a threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of multipleunit generator as a Generation Owner under the ERO Statement of Compliance Registry Criteria.. The
“materiality threshold” is intended to refer to the generator threshold developed in Phase II. We
suggest using definitions in this fashion for several reasons. First, we believe the language we suggest
more clearly states the intention of the SDT, which we understand is to classify generation units as
part of the BES if they are necessary for operation of the BES, but to exclude smaller generating units
because they are not material to the operation of the interconnected transmission grid. Second, we
believe use of the defined terms better reflects the intention of the SDT to reserve the specific
question about generator thresholds to the technical analysis that will occur in Phase II without
having to revise the BES Definition at the end of that process. That is, the definitions are designed to
allow the SDT to include revised thresholds in the definition at the conclusion of the Phase II process
based upon the technical analysis planned for Phase II, and the revised thresholds will be
automatically incorporated into the BES Definition if the language we suggest is used. The thresholds
used in the SCRC would only be a fall-back, to be used only until Phase II is completed. Third, the
definitions can be incorporated into other parts of the BES Definition, which will add consistency and

clarity. As noted in our answers to several of the questions below, the specific 75 MVA threshold is
retained in several of the Exclusions and Inclusions, and we believe the industry would be better
served if the revised thresholds arrived at after technical analysis in Phase II are automatically
incorporated into all relevant provisions of the BES Definition. There is no reason for the SDT to
continue to rely on the 75 MVA threshold once the analysis planned for Phase II on the threshold
issue is completed. Fourth, the phrase “or that meets the materiality threshold to be included in this
definition” is intended to preserve the SDT’s flexibility to make a determination that generators below
a specific threshold are not “necessary to” maintain the reliability of the interconnected transmission
system, and to incorporate that finding as part of the definition itself, even if a different threshold is
used in the SCRC to identify potential candidates for registration. Accordingly, our proposed language
makes clear that a specific threshold in the definition controls over any threshold that might be
included in the SCRC. For the reasons stated above, we believe is it highly desirable to include any
material threshold in the BES Definition itself rather than relegating the threshold to the SCRC, which
is merely a procedural rule rather than a full-fledged Reliability Standard. Finally, we agree with the
SDT’s decision to examine the question of where the line between BES and non-BES Elements should
be drawn more closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and
commend the work of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good
starting point for the SDT’s analysis on this issue. We understand Inclusion 2 would classify
generators exceeding specific thresholds as part of the BES, but would not necessarily require
facilities interconnecting such generators to be part of the BES. As discussed more fully in our answer
to Question 9, based on extensive technical analysis that has already been performed by the NERC
Project 2010-07 Standards Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating
as part of the BES a dedicated interconnection facility connecting a BES generator to the
interconnected bulk transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no improvement in bulk
system reliability. We also believe the clauses at the end of Inclusion 2 are somewhat confusing and
that greater clarity would be achieved by changing “. . . including the generator terminals through the
high-side of the step-up transformer(s) connected at a voltage of 100kV or above” so that the
Inclusion covers transformers with terminals “connected at a voltage of 100kV or above, including the
generator terminal(s) on the high side of the step-up transformer(s) if operated at a voltage of 100kV
or above.”
Yes
PNGC supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
PNGC supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be

established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
PNGC has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, PNGC believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally,
PNGC believes this issue should be addressed in Phase 2 since there is not technical justification or
analysis done to determine the thresholds. PNGC strongly believes that there should be technical
justification for thresholds for this issue and all other issues.
Yes
PNGC continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, PNGC strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.

Yes
PNGC supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, PNGC urges the SDT to remove the reference to
the 75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation
Resources” or some equivalent language for the reasons stated in our responses to Questions 3, 5,
and 7. In addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult
position because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial
System or a Local Network through the actions of a customer constructing behind-the-meter
generation, With respect to Radial Systems, the appearance of behind-the-meter generators could
cause the Radial System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion
1 through no fault of the Radial System owner. Similar, a Local Network could lose its status because
behind-the-meter generation could be of sufficient size that power moves into the interconnected grid
in certain hours or under certain contingencies, rather than moving purely onto the Local Network, as
required in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks
should be made consistent with the Exclusion for behind-the-meter generation. There is no technical
reason to believe the power flowing from a behind-the-meter customer-owned generator will have
less impact on the bulk system than an equivalent-sized generator owned by a utility operating a
Radial System or LN.
Yes
PNGC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of
radial systems to local networks should be encouraged because networked systems generally reduce
losses, increase system efficiency, and increase the level of service to retail customers. If the BES
definition were to provide an exclusion for radials without providing a similar exclusion for LNs,
however, it would discourage networking local distribution systems because of the significantly
increased regulatory burdens faced by the local distribution utility if it elected to network its radial
facilities. By placing radial systems and LNs on the same regulatory footing, the proposed definition
will ensure that decisions about whether to network radial systems are made on the basis of costs
and benefits to the retail customers served by those radials, and not on the basis of disparate
regulatory treatment. Consumers would ultimately benefit. PNGC also supports specific refinements
made to the LN exclusion by the SDT in the current draft of the BES definition. In particular, PNGC
supports the clarification of the purposes of a LN. The current draft states that LNs connect at multiple
points to “improve the level of service to retail customer Load and not to accommodate bulk power
transfer across the interconnected system.” PNGC supports this change in language because it reflects
the fundamental purposes of a LN and emphasizes one of the key distinctions between LNs and bulk
transmission facilities, namely, that LNs are designed primarily to serve local retail load while bulk
transmission facilities are designed primarily to move bulk power from a bulk source (generally either
the point of interconnection of a wholesale generator or a the point of interconnection with another
bulk transmission system) to one or more wholesale purchasers. PNGC believes further improvement
of the language could be achieved with additional modifications and clarifications. With respect to the
core language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
PNGC also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and

dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3.
PNGC also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as
long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as
a Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that
allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
transmission of electricity on the interconnected bulk system. Apart from these specific improvements
that we believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may
need to re-examine certain assumptions that appear to underlie the current draft. Specifically,
subparagraph (a) suggests that if BES generation is embedded within a LN, the LN itself must also be
BES. But two NERC bodies have already addressed similar questions and concluded there is no
technical basis for such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force” were formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. The GO-TO Team concluded that by complying with a handful of reliability
standards, primarily related to vegetation management, reliable operation of the bulk interconnected
system could be protected without unduly burdening the owners of such interconnection systems.
Therefore, there is no reason, according to the GO-TO Team, that dedicated high-voltage
interconnection facilities must be treated as “Transmission” and classified as part of the BES in order
to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO Task
Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most often
not part of the integrated bulk power system, and as such should not be subject to the same level of
standards applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” White Paper
Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at the

Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply
with the same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of the
equipment that actually produces electricity – the generation equipment itself.” Id. We believe that
interconnection of BES generators within a LN is analogous and that, based on the findings of the
Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply because a large
generator is embedded in the LN will result in substantial overregulation and unnecessary expense
with little gain for bulk system reliability. If anything, generation interconnected through a LN is less
likely to produce material impacts on the interconnected bulk transmission system than the
equivalent generator interconnected through a single dedicated line because an LN is interconnected
to the bulk system at several points, so that if one interconnection goes down, power can still flow
from the BES generator to the bulk system on other interconnection points. Where a dedicated
interconnection facility is involved, by contrast, if the interconnection line fails, the generator is
unavailable to the interconnected bulk system. Similarly, we suggest that the SDT re-examine the
assumptions underlying subparagraph (b), which seems to suggest that a local distribution system
cannot be classified as a Local Network if power flows out of that system at any time, even if the
amount is de minimis, the outward flow is only for a few hours, a year, or the outward flow occurs
only in an extreme contingency. Accordingly, we suggest that the initial clause of subparagraph (b) be
revised to read: “Except in unusual circumstances, power flows only into the LN.” Finally, we note
that the LN exclusion must not operate in any way as a substitution for the statutory prohibition on
including “facilities used in the local distribution of electric energy” in the BES. Therefore, even with
the LN exclusion, the SDT must retain this statutory language in the core definition of the BES, as
discussed in our answer to Question One. If a certain piece of equipment is a “facility used in the local
distribution of electric energy,” then it is not part of the BES in the first instance, and so consideration
of the LN Exclusion, or of any other Exclusion, any Inclusion, or any Exception, would be both
unnecessary and uncalled for.
Yes
PNGC supports the revised language because retail reactive devices are used to address local
customer or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such
local devices should therefore be excluded from the BES definition.
No
PNGC extends its thanks to the SDT and to the many industry entities that have actively participating
in the Standards Development Process. PNGC supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, PNGC is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that PNGC specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. PNGC supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. PNGC
also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Heber Carpenter
Raft River Rural Electric Cooperative (RAFT)
Yes

The Raft River Rural Electric Cooperative (RAFT) believes the SDT continues to make substantial
progress towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly
improves both the existing definition and the SDT’s previous proposal. RAFT therefore supports the
new definition, although our support is conditioned on: (1) a workable Exceptions process being
developed in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on
Phase II of the standards development process in accordance with the SAR recently put forward by
the SDT, which would address a number of important technical issues that have been identified in the
standards development process to date. RAFT strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, RAFT supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). RAFT thanks the SDT for the excellent work to include this sentence. For
similar reasons, RAFT believes the use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes clear
that the BES includes only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. RAFT recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, RAFT agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, RAFT is prepared to support the BES definition as
proposed by the SDT. While RAFT supports the overall approach adopted by the SDT and much of the
specific language incorporated into the second draft of the BES definition, we believe the second draft
would benefit from further clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential for
a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, RAFT believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the

core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
RAFT will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
RAFT supports the changes made in Inclusion 2 and believes that the definition in its current form
adds clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the
previous draft definition into a single Inclusion that addresses the treatment of generation for
purposes of the BES definition. We also support the SDT’s proposal for a Phase II of the BES
Definition process that would examine the technical justification for these thresholds and that would
establish new thresholds based on a careful technical analysis. It is our understanding that the
generator threshold issue will be vetted through the complete standards development process. We
agree with this approach because if the generator threshold is treated as merely an element of
NERC’s Rules of Procedure, it can be changed with considerably less process and industry input than
the Standards Development Process. Compare NERC Rules of Procedure § 1400 (providing for
changes to Rules of Procedure upon approval of the NERC board and FERC) with NERC Standards
Process Manual (Sept. 3, 2010) (providing for, e.g., posting of SDT proposals for comment,
successive balloting, and super-majority approval requirements). See also Order No. 743-A, 134 FERC
¶ 61,210 at P 4 (2011) (“Order No. 743 directed the ERO to revise the definition of ‘bulk electric
system’ through the NERC Standards Development Process” (emph. added)). Addressing all aspects
of Phase II through the Standards Development Process will improve the content of the definition by
bringing to bear industry expertise on all aspects of the definition and will ensure that, once firm
guidelines are established, they can be relied upon by both industry and regulators without threat
that they will be changed with little notice and little process. RAFT believes further clarification of the
proposed language would be appropriate. The SDT proposes continued reliance upon the thresholds
that are used in the NERC Statement of Compliance Registry Criteria for registration of Generation

Owners and Generation Operators, which is currently 20 MVA for an individual generation unit and 75
MVA for multiple units on a single site. Conceptually, we are concerned about this approach because,
as we understand it, the purpose of the Compliance Registry is to sweep in all generators that might
be material to the reliable operation of the BES, and not to definitively determine whether a given
generator is, in fact, material to the reliable operation of the BES. As the SCRC itself states, the SCRC
is intended only to identify “candidates for registration.” SCRC at p.3, § 1 (emph. added).
Accordingly, we believe that the generator threshold determined in Phase II should be incorporated
directly into the BES Definition rather than being incorporated by reference from the SCRC. We also
believe that the specific language proposed by the SDT could be further clarified. The SDT proposes
that generation be included in the BES if the “Generation resource(s)” has a “nameplate rating per the
ERO Statement of Compliance Registry.” We understand this language is intended to be a placeholder
for the results of the technical analysis that would occur in Phase II but we believe simply stating that
the threshold will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the
reasons noted above, we believe the threshold should be part of the BES Definition, and should not
simply be a cross-reference to the SCRC (and, given the different purposes of the BES Definition and
the SCRC, it is not clear that the same threshold should be used in both). We therefore propose that
Inclusion 2 be rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate
Resources connected at a voltage of 100kV or above.” Two definitions would then be added to the
note at the end of the definition to read as follows: For purposes of this BES Definition, Qualifying
Individual Generation Resources means an individual generating unit that meets the materiality
threshold to be included in this definition or, in the absence of such a materiality threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of such a
resource as a Generation Owner under the ERO Statement of Compliance Registry Criteria. For
purposes of this BES Definition, Qualifying Aggregate Generation Resources means any facility
consisting of one or more generating units that are connected at a common bus that meets the
materiality threshold to be included in this definition, or, in the absence of such a threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of multipleunit generator as a Generation Owner under the ERO Statement of Compliance Registry Criteria.. The
“materiality threshold” is intended to refer to the generator threshold developed in Phase II. We
suggest using definitions in this fashion for several reasons. First, we believe the language we suggest
more clearly states the intention of the SDT, which we understand is to classify generation units as
part of the BES if they are necessary for operation of the BES, but to exclude smaller generating units
because they are not material to the operation of the interconnected transmission grid. Second, we
believe use of the defined terms better reflects the intention of the SDT to reserve the specific
question about generator thresholds to the technical analysis that will occur in Phase II without
having to revise the BES Definition at the end of that process. That is, the definitions are designed to
allow the SDT to include revised thresholds in the definition at the conclusion of the Phase II process
based upon the technical analysis planned for Phase II, and the revised thresholds will be
automatically incorporated into the BES Definition if the language we suggest is used. The thresholds
used in the SCRC would only be a fall-back, to be used only until Phase II is completed. Third, the
definitions can be incorporated into other parts of the BES Definition, which will add consistency and
clarity. As noted in our answers to several of the questions below, the specific 75 MVA threshold is
retained in several of the Exclusions and Inclusions, and we believe the industry would be better
served if the revised thresholds arrived at after technical analysis in Phase II are automatically
incorporated into all relevant provisions of the BES Definition. There is no reason for the SDT to
continue to rely on the 75 MVA threshold once the analysis planned for Phase II on the threshold
issue is completed. Fourth, the phrase “or that meets the materiality threshold to be included in this
definition” is intended to preserve the SDT’s flexibility to make a determination that generators below
a specific threshold are not “necessary to” maintain the reliability of the interconnected transmission
system, and to incorporate that finding as part of the definition itself, even if a different threshold is
used in the SCRC to identify potential candidates for registration. Accordingly, our proposed language
makes clear that a specific threshold in the definition controls over any threshold that might be
included in the SCRC. For the reasons stated above, we believe is it highly desirable to include any
material threshold in the BES Definition itself rather than relegating the threshold to the SCRC, which
is merely a procedural rule rather than a full-fledged Reliability Standard. Finally, we agree with the
SDT’s decision to examine the question of where the line between BES and non-BES Elements should
be drawn more closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and
commend the work of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good

starting point for the SDT’s analysis on this issue. We understand Inclusion 2 would classify
generators exceeding specific thresholds as part of the BES, but would not necessarily require
facilities interconnecting such generators to be part of the BES. As discussed more fully in our answer
to Question 9, based on extensive technical analysis that has already been performed by the NERC
Project 2010-07 Standards Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating
as part of the BES a dedicated interconnection facility connecting a BES generator to the
interconnected bulk transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no improvement in bulk
system reliability. We also believe the clauses at the end of Inclusion 2 are somewhat confusing and
that greater clarity would be achieved by changing “. . . including the generator terminals through the
high-side of the step-up transformer(s) connected at a voltage of 100kV or above” so that the
Inclusion covers transformers with terminals “connected at a voltage of 100kV or above, including the
generator terminal(s) on the high side of the step-up transformer(s) if operated at a voltage of 100kV
or above.”
Yes
RAFT supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
RAFT supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
RAFT has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, RAFT believes the

appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally, RAFT
believes this issue should be addressed in Phase 2 since there is not technical justification or analysis
done to determine the thresholds. RAFT strongly believes that there should be technical justification
for thresholds for this issue and all other issues.
Yes
RAFT continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, RAFT strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.
Yes
RAFT supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, RAFT urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System

or LN.
Yes
RAFT strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of
radial systems to local networks should be encouraged because networked systems generally reduce
losses, increase system efficiency, and increase the level of service to retail customers. If the BES
definition were to provide an exclusion for radials without providing a similar exclusion for LNs,
however, it would discourage networking local distribution systems because of the significantly
increased regulatory burdens faced by the local distribution utility if it elected to network its radial
facilities. By placing radial systems and LNs on the same regulatory footing, the proposed definition
will ensure that decisions about whether to network radial systems are made on the basis of costs
and benefits to the retail customers served by those radials, and not on the basis of disparate
regulatory treatment. Consumers would ultimately benefit. RAFT also supports specific refinements
made to the LN exclusion by the SDT in the current draft of the BES definition. In particular, RAFT
supports the clarification of the purposes of a LN. The current draft states that LNs connect at multiple
points to “improve the level of service to retail customer Load and not to accommodate bulk power
transfer across the interconnected system.” RAFT supports this change in language because it reflects
the fundamental purposes of a LN and emphasizes one of the key distinctions between LNs and bulk
transmission facilities, namely, that LNs are designed primarily to serve local retail load while bulk
transmission facilities are designed primarily to move bulk power from a bulk source (generally either
the point of interconnection of a wholesale generator or a the point of interconnection with another
bulk transmission system) to one or more wholesale purchasers. RAFT believes further improvement
of the language could be achieved with additional modifications and clarifications. With respect to the
core language of Exclusion 3, we believe the language making a “group of contiguous transmission
Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
RAFT also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and
dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater

than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3.
RAFT also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as
long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as
a Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that
allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
transmission of electricity on the interconnected bulk system. Apart from these specific improvements
that we believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may
need to re-examine certain assumptions that appear to underlie the current draft. Specifically,
subparagraph (a) suggests that if BES generation is embedded within a LN, the LN itself must also be
BES. But two NERC bodies have already addressed similar questions and concluded there is no
technical basis for such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force” were formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. The GO-TO Team concluded that by complying with a handful of reliability
standards, primarily related to vegetation management, reliable operation of the bulk interconnected
system could be protected without unduly burdening the owners of such interconnection systems.
Therefore, there is no reason, according to the GO-TO Team, that dedicated high-voltage
interconnection facilities must be treated as “Transmission” and classified as part of the BES in order
to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO Task
Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most often
not part of the integrated bulk power system, and as such should not be subject to the same level of
standards applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” White Paper
Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at the
Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply
with the same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of the
equipment that actually produces electricity – the generation equipment itself.” Id. We believe that
interconnection of BES generators within a LN is analogous and that, based on the findings of the
Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply because a large
generator is embedded in the LN will result in substantial overregulation and unnecessary expense
with little gain for bulk system reliability. If anything, generation interconnected through a LN is less
likely to produce material impacts on the interconnected bulk transmission system than the
equivalent generator interconnected through a single dedicated line because an LN is interconnected
to the bulk system at several points, so that if one interconnection goes down, power can still flow
from the BES generator to the bulk system on other interconnection points. Where a dedicated
interconnection facility is involved, by contrast, if the interconnection line fails, the generator is
unavailable to the interconnected bulk system. Similarly, we suggest that the SDT re-examine the
assumptions underlying subparagraph (b), which seems to suggest that a local distribution system
cannot be classified as a Local Network if power flows out of that system at any time, even if the
amount is de minimis, the outward flow is only for a few hours, a year, or the outward flow occurs
only in an extreme contingency. Accordingly, we suggest that the initial clause of subparagraph (b) be

revised to read: “Except in unusual circumstances, power flows only into the LN.” Finally, we note
that the LN exclusion must not operate in any way as a substitution for the statutory prohibition on
including “facilities used in the local distribution of electric energy” in the BES. Therefore, even with
the LN exclusion, the SDT must retain this statutory language in the core definition of the BES, as
discussed in our answer to Question One. If a certain piece of equipment is a “facility used in the local
distribution of electric energy,” then it is not part of the BES in the first instance, and so consideration
of the LN Exclusion, or of any other Exclusion, any Inclusion, or any Exception, would be both
unnecessary and uncalled for.
Yes
RAFT supports the revised language because retail reactive devices are used to address local
customer or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such
local devices should therefore be excluded from the BES definition.
No
RAFT extends its thanks to the SDT and to the many industry entities that have actively participating
in the Standards Development Process. RAFT supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, RAFT is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that RAFT specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. RAFT supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. RAFT
also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Marc Farmer
West Oregon Electric Cooperative
Yes
The West Oregon Electric Cooperative (WOEC) believes the SDT continues to make substantial
progress towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly
improves both the existing definition and the SDT’s previous proposal. WOEC therefore supports the
new definition, although our support is conditioned on: (1) a workable Exceptions process being
developed in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on
Phase II of the standards development process in accordance with the SAR recently put forward by
the SDT, which would address a number of important technical issues that have been identified in the
standards development process to date. WOEC strongly supports the following elements of the
revised BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised
core definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, WOEC supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional

Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in
enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). WOEC thanks the SDT for the excellent work to include this sentence. For
similar reasons, WOEC believes the use of the phrase “Transmission Elements” as the starting point
for the base definition is desirable because both “Transmission” and “Elements” are already defined in
the NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes
clear that the BES includes only Elements used in Transmission and therefore excludes Elements used
in local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. WOEC recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, WOEC agrees with the approach
taken by the SDT, which is to propose a Phase II of the standards development process that would
address the generator threshold issue and several other technical issues that have arisen during the
current process. As long as Phase II proceeds expeditiously, WOEC is prepared to support the BES
definition as proposed by the SDT. While WOEC supports the overall approach adopted by the SDT
and much of the specific language incorporated into the second draft of the BES definition, we believe
the second draft would benefit from further clarification or modification in a number of respects, most
of which are detailed in our subsequent answers. Further, we believe a workable Exclusion Process is
essential for a BES Definition that will meet the legal requirements of FPA Section 215, especially for
systems operating in the Western Interconnection. As detailed in our previous comments, WOEC
believes a 200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition,
a 200kV threshold for the West is backed by solid technical analysis conducted by the WECC Bulk
Electric System Definition Task Force, and repeated claims that there is no technical analysis to
support this view are therefore incorrect. That said, we raise the issue here to emphasize the
importance of the Exclusions for Local Networks and Radial Systems and the Exceptions process.
These Exclusions and the Exceptions are essential for a definition that works in the Western
Interconnection because the core definition will be over-inclusive in our region. As long as those
Exclusions and the Exceptions Process are retained in a form substantially equivalent to those
produced by the SDT at this juncture, WOEC will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at

the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
WOEC supports the changes made in Inclusion 2 and believes that the definition in its current form
adds clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the
previous draft definition into a single Inclusion that addresses the treatment of generation for
purposes of the BES definition. We also support the SDT’s proposal for a Phase II of the BES
Definition process that would examine the technical justification for these thresholds and that would
establish new thresholds based on a careful technical analysis. It is our understanding that the
generator threshold issue will be vetted through the complete standards development process. We
agree with this approach because if the generator threshold is treated as merely an element of
NERC’s Rules of Procedure, it can be changed with considerably less process and industry input than
the Standards Development Process. Compare NERC Rules of Procedure § 1400 (providing for
changes to Rules of Procedure upon approval of the NERC board and FERC) with NERC Standards
Process Manual (Sept. 3, 2010) (providing for, e.g., posting of SDT proposals for comment,
successive balloting, and super-majority approval requirements). See also Order No. 743-A, 134 FERC
¶ 61,210 at P 4 (2011) (“Order No. 743 directed the ERO to revise the definition of ‘bulk electric
system’ through the NERC Standards Development Process” (emph. added)). Addressing all aspects
of Phase II through the Standards Development Process will improve the content of the definition by
bringing to bear industry expertise on all aspects of the definition and will ensure that, once firm
guidelines are established, they can be relied upon by both industry and regulators without threat
that they will be changed with little notice and little process. WOEC believes further clarification of the
proposed language would be appropriate. The SDT proposes continued reliance upon the thresholds
that are used in the NERC Statement of Compliance Registry Criteria for registration of Generation
Owners and Generation Operators, which is currently 20 MVA for an individual generation unit and 75
MVA for multiple units on a single site. Conceptually, we are concerned about this approach because,
as we understand it, the purpose of the Compliance Registry is to sweep in all generators that might
be material to the reliable operation of the BES, and not to definitively determine whether a given
generator is, in fact, material to the reliable operation of the BES. As the SCRC itself states, the SCRC
is intended only to identify “candidates for registration.” SCRC at p.3, § 1 (emph. added).
Accordingly, we believe that the generator threshold determined in Phase II should be incorporated
directly into the BES Definition rather than being incorporated by reference from the SCRC. We also
believe that the specific language proposed by the SDT could be further clarified. The SDT proposes
that generation be included in the BES if the “Generation resource(s)” has a “nameplate rating per the
ERO Statement of Compliance Registry.” We understand this language is intended to be a placeholder
for the results of the technical analysis that would occur in Phase II but we believe simply stating that
the threshold will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the
reasons noted above, we believe the threshold should be part of the BES Definition, and should not
simply be a cross-reference to the SCRC (and, given the different purposes of the BES Definition and
the SCRC, it is not clear that the same threshold should be used in both). We therefore propose that
Inclusion 2 be rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate
Resources connected at a voltage of 100kV or above.” Two definitions would then be added to the
note at the end of the definition to read as follows: For purposes of this BES Definition, Qualifying

Individual Generation Resources means an individual generating unit that meets the materiality
threshold to be included in this definition or, in the absence of such a materiality threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of such a
resource as a Generation Owner under the ERO Statement of Compliance Registry Criteria. For
purposes of this BES Definition, Qualifying Aggregate Generation Resources means any facility
consisting of one or more generating units that are connected at a common bus that meets the
materiality threshold to be included in this definition, or, in the absence of such a threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the owner of multipleunit generator as a Generation Owner under the ERO Statement of Compliance Registry Criteria.. The
“materiality threshold” is intended to refer to the generator threshold developed in Phase II. We
suggest using definitions in this fashion for several reasons. First, we believe the language we suggest
more clearly states the intention of the SDT, which we understand is to classify generation units as
part of the BES if they are necessary for operation of the BES, but to exclude smaller generating units
because they are not material to the operation of the interconnected transmission grid. Second, we
believe use of the defined terms better reflects the intention of the SDT to reserve the specific
question about generator thresholds to the technical analysis that will occur in Phase II without
having to revise the BES Definition at the end of that process. That is, the definitions are designed to
allow the SDT to include revised thresholds in the definition at the conclusion of the Phase II process
based upon the technical analysis planned for Phase II, and the revised thresholds will be
automatically incorporated into the BES Definition if the language we suggest is used. The thresholds
used in the SCRC would only be a fall-back, to be used only until Phase II is completed. Third, the
definitions can be incorporated into other parts of the BES Definition, which will add consistency and
clarity. As noted in our answers to several of the questions below, the specific 75 MVA threshold is
retained in several of the Exclusions and Inclusions, and we believe the industry would be better
served if the revised thresholds arrived at after technical analysis in Phase II are automatically
incorporated into all relevant provisions of the BES Definition. There is no reason for the SDT to
continue to rely on the 75 MVA threshold once the analysis planned for Phase II on the threshold
issue is completed. Fourth, the phrase “or that meets the materiality threshold to be included in this
definition” is intended to preserve the SDT’s flexibility to make a determination that generators below
a specific threshold are not “necessary to” maintain the reliability of the interconnected transmission
system, and to incorporate that finding as part of the definition itself, even if a different threshold is
used in the SCRC to identify potential candidates for registration. Accordingly, our proposed language
makes clear that a specific threshold in the definition controls over any threshold that might be
included in the SCRC. For the reasons stated above, we believe is it highly desirable to include any
material threshold in the BES Definition itself rather than relegating the threshold to the SCRC, which
is merely a procedural rule rather than a full-fledged Reliability Standard. Finally, we agree with the
SDT’s decision to examine the question of where the line between BES and non-BES Elements should
be drawn more closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and
commend the work of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good
starting point for the SDT’s analysis on this issue. We understand Inclusion 2 would classify
generators exceeding specific thresholds as part of the BES, but would not necessarily require
facilities interconnecting such generators to be part of the BES. As discussed more fully in our answer
to Question 9, based on extensive technical analysis that has already been performed by the NERC
Project 2010-07 Standards Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating
as part of the BES a dedicated interconnection facility connecting a BES generator to the
interconnected bulk transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no improvement in bulk
system reliability. We also believe the clauses at the end of Inclusion 2 are somewhat confusing and
that greater clarity would be achieved by changing “. . . including the generator terminals through the
high-side of the step-up transformer(s) connected at a voltage of 100kV or above” so that the
Inclusion covers transformers with terminals “connected at a voltage of 100kV or above, including the
generator terminal(s) on the high side of the step-up transformer(s) if operated at a voltage of 100kV
or above.”
Yes
WOEC supports the removal of the Cranking Path language in I3. As noted in our response to
Question 9, there is no reason to classify as BES the facilities interconnecting a BES generator to the
bulk interstate system. A Cranking Path is simply a specific type of such an interconnection facility.

Yes
WOEC supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
WOEC has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, WOEC believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally,
WOEC believes this issue should be addressed in Phase 2 since there is not technical justification or
analysis done to determine the thresholds. WOEC strongly believes that there should be technical
justification for thresholds for this issue and all other issues.
Yes
WOEC continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial

systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will
preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, WOEC strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.
Yes
WOEC supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, WOEC urges the SDT to remove the reference to
the 75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation
Resources” or some equivalent language for the reasons stated in our responses to Questions 3, 5,
and 7. In addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult
position because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial
System or a Local Network through the actions of a customer constructing behind-the-meter
generation, With respect to Radial Systems, the appearance of behind-the-meter generators could
cause the Radial System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion
1 through no fault of the Radial System owner. Similar, a Local Network could lose its status because
behind-the-meter generation could be of sufficient size that power moves into the interconnected grid
in certain hours or under certain contingencies, rather than moving purely onto the Local Network, as
required in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks
should be made consistent with the Exclusion for behind-the-meter generation. There is no technical
reason to believe the power flowing from a behind-the-meter customer-owned generator will have
less impact on the bulk system than an equivalent-sized generator owned by a utility operating a
Radial System or LN.
Yes
WOEC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of
radial systems to local networks should be encouraged because networked systems generally reduce
losses, increase system efficiency, and increase the level of service to retail customers. If the BES
definition were to provide an exclusion for radials without providing a similar exclusion for LNs,
however, it would discourage networking local distribution systems because of the significantly
increased regulatory burdens faced by the local distribution utility if it elected to network its radial
facilities. By placing radial systems and LNs on the same regulatory footing, the proposed definition
will ensure that decisions about whether to network radial systems are made on the basis of costs
and benefits to the retail customers served by those radials, and not on the basis of disparate
regulatory treatment. Consumers would ultimately benefit. WOEC also supports specific refinements
made to the LN exclusion by the SDT in the current draft of the BES definition. In particular, WOEC
supports the clarification of the purposes of a LN. The current draft states that LNs connect at multiple
points to “improve the level of service to retail customer Load and not to accommodate bulk power
transfer across the interconnected system.” WOEC supports this change in language because it
reflects the fundamental purposes of a LN and emphasizes one of the key distinctions between LNs
and bulk transmission facilities, namely, that LNs are designed primarily to serve local retail load

while bulk transmission facilities are designed primarily to move bulk power from a bulk source
(generally either the point of interconnection of a wholesale generator or a the point of
interconnection with another bulk transmission system) to one or more wholesale purchasers. WOEC
believes further improvement of the language could be achieved with additional modifications and
clarifications. With respect to the core language of Exclusion 3, we believe the language making a
“group of contiguous transmission Elements operated at or above 100kV” the starting point for
identifying a LN would be improved by deleting the term “transmission” from this phrase. This is so
because LNs are not used for transmission and the use of the term “transmission Elements” is
therefore both confusing and unnecessary. There would be no room for argument about what the SDT
intended by including the word “transmission” if the word is deleted and the Exclusion applies to any
“group of Elements operated at 100kV or above” that meets the remaining requirement of the
Exclusion. Further, any definitional value that is added by using the term “transmission Elements” is
accomplished by using that term in the core definition, and there is no reason to carry the term
through in the Exclusions. WOEC also believes that subparagraphs (a) and (b) are redundant,
because whatever protection is offered by the generation limit in subparagraph (a) is duplicated by
the limit in subparagraph (b) requiring no flow out of the LN. We believe the SDT can eliminate
subparagraph (a) of Exclusion 3 and simply rely on subparagraph (b) because if power only flows into
the LN even if it interconnects more than 75 MVA of generation, the interconnected generation
interconnected will have no significant interaction with the interconnected bulk transmission system.
It will only interact with the LN. And, with the advent of distributed generation, it is easy to foresee a
situation in which a large number of very small distributed generators are interconnected into a LN, so
that the aggregate capacity of these generators exceeds 75 MVA. However, because the generators
are small and dispersed and, under the criterion in subparagraph (b), would be wholly absorbed
within the LN rather than transmitting power onto the interconnected grid, those generators would
not have a material impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could
be more clearly drafted. Subparagraph (b), as part of the requirement that power flow into a LN
rather than out of it, includes this description: “The LN does not transfer energy originating outside
the LN for delivery through the LN.” We understand this language is intended to distinguish a LN from
a link in the transmission system – power on a transmission link passes through the transmission link
to a load located elsewhere, while power in a LN enters the LN and is consumed by retail load within
the LN. While we agree with the concept proposed by the SDT, we believe the language would be
clearer if it read: “The LN does not transfer energy originating outside the LN for delivery through the
LN to loads located outside the LN.” We believe the italicized language is necessary to distinguish
between a transmission system, where power that originates outside a system is delivered through
the system and passes through the system to a sink located somewhere outside the system, from a
LN, in which power originating outside the LN passes through the LN and is delivered to retail load
within the LN. To put it another way, the italicized language helps distinguish a transmission system
from an LN, in which the LN “transfers energy originating outside the LN for delivery through the LN
to loads located within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could
be improved. Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail
generation greater than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to
Questions 3, 5 and 7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the
defined term “Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain
what is meant by the use of the term “non-retail generation” in subparagraph (a). From context, we
believe the SDT considers “non-retail generation” to be the equivalent of generation that is located
behind the retail meter, usually but not always owned by the customer and used to serve the
customer’s own load. We therefore suggest that the SDT replace the term “non-retail generation” with
“generation located behind the retail customer’s meter.” Similarly, we are unsure what is meant by
the phrase “the LN and its underlying Elements.” We believe the phrase “and its underlying Elements”
could simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3.
WOEC also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as
long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as
a Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that

allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
transmission of electricity on the interconnected bulk system. Apart from these specific improvements
that we believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may
need to re-examine certain assumptions that appear to underlie the current draft. Specifically,
subparagraph (a) suggests that if BES generation is embedded within a LN, the LN itself must also be
BES. But two NERC bodies have already addressed similar questions and concluded there is no
technical basis for such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force” were formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. The GO-TO Team concluded that by complying with a handful of reliability
standards, primarily related to vegetation management, reliable operation of the bulk interconnected
system could be protected without unduly burdening the owners of such interconnection systems.
Therefore, there is no reason, according to the GO-TO Team, that dedicated high-voltage
interconnection facilities must be treated as “Transmission” and classified as part of the BES in order
to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO Task
Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most often
not part of the integrated bulk power system, and as such should not be subject to the same level of
standards applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” White Paper
Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at the
Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply
with the same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of the
equipment that actually produces electricity – the generation equipment itself.” Id. We believe that
interconnection of BES generators within a LN is analogous and that, based on the findings of the
Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply because a large
generator is embedded in the LN will result in substantial overregulation and unnecessary expense
with little gain for bulk system reliability. If anything, generation interconnected through a LN is less
likely to produce material impacts on the interconnected bulk transmission system than the
equivalent generator interconnected through a single dedicated line because an LN is interconnected
to the bulk system at several points, so that if one interconnection goes down, power can still flow
from the BES generator to the bulk system on other interconnection points. Where a dedicated
interconnection facility is involved, by contrast, if the interconnection line fails, the generator is
unavailable to the interconnected bulk system. Similarly, we suggest that the SDT re-examine the
assumptions underlying subparagraph (b), which seems to suggest that a local distribution system
cannot be classified as a Local Network if power flows out of that system at any time, even if the
amount is de minimis, the outward flow is only for a few hours, a year, or the outward flow occurs
only in an extreme contingency. Accordingly, we suggest that the initial clause of subparagraph (b) be
revised to read: “Except in unusual circumstances, power flows only into the LN.” Finally, we note
that the LN exclusion must not operate in any way as a substitution for the statutory prohibition on
including “facilities used in the local distribution of electric energy” in the BES. Therefore, even with
the LN exclusion, the SDT must retain this statutory language in the core definition of the BES, as
discussed in our answer to Question One. If a certain piece of equipment is a “facility used in the local
distribution of electric energy,” then it is not part of the BES in the first instance, and so consideration
of the LN Exclusion, or of any other Exclusion, any Inclusion, or any Exception, would be both
unnecessary and uncalled for.
Yes
WOEC supports the revised language because retail reactive devices are used to address local
customer or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such
local devices should therefore be excluded from the BES definition.
No
WOEC extends its thanks to the SDT and to the many industry entities that have actively participating
in the Standards Development Process. WOEC supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, WOEC is encouraged that the

20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not
be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that WOEC specifically supports the
changes made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the
effective date of the new definition to the beginning of the first calendar quarter after regulatory
approval (as opposed to the first calendar quarter twenty-four months after regulatory approval), with
a 24-month transition period. WOEC supports this conclusion because it will allow entities seeking
deregistration under the terms of the new BES definition to obtain the benefits of the new definition
without an unreasonable wait, while allowing any entities that may be newly-classified as BES owners
or operators sufficient time to come into compliance with newly-applicable Reliability Standards.
WOEC also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
John Seelke
PSEG Services Corp
Yes
Yes
Yes
Yes
Yes
Yes
Yes
1. If a 50 MVA generator that is included per I2 is connected to an excluded radial system, would the
generator be excluded or included per E1b)? If yes, then the language “unless excluded under
Exclusion E1 and E3” in I1 needs to be added to I2, I4, and I5. 2. Non-retail generation in E1c) was
described behind-the-meter generation in the Webinar. The term “non-retail generation” should be
defined because one could infer that generation defined by E2 is “retail generation.” Also, is the 75
MVA limit intended apply to the generator (as stated) or its net capacity as defined in E2? If it means
the generator MVA, does that mean that generation excluded in E2 cannot exceed 75 MVA when
connected to an excluded radial system? 3. In general, the definition needs to better define the
impact that “exclusion” has on a different “inclusion” or “exclusion.”
Yes
Yes
Yes
No
Group
Bruce Wertz

Power Utility Compliance Consultants
Yes
However, one of the FERC directives in Order 743 charged NERC with delineating the difference
between transmission and distribution. The Inclusions and Exclusions are a step in that direction, but
this subject will need more consideration in Phase II.
Yes
No
Since an aggregate of 75 MVA is allowed at a single site, there is no basis for maintaining the 20 MVA
for a single generator. The proposed MOD-026 assigns thresholds by region that are much higher
than 20 MVA for modeling purposes. Since modeling generally would require more granularity than
what is necessary for the reliable operation of the interconnected transmission system (BES), the SDT
might want to review the threshold basis for NERC Project 2007-09 (Generator Verification).
Yes
Yes
To distinguish this Inclusion from Inclusion I2, the SDT might want to clarify that the collection
system (usually at voltage below 100 KV anyway) is not part of the BES—just the resources and any
transformers included by I1, if this is indeed the intent of this Inclusion.
Yes
Yes
This is a much needed change from the first posting, as this will maintain the status quo referred to in
the introduction text.
Yes
Yes
This Exclusion and Exclusion E1 aid in the delineation of distribution versus transmission.
Yes
This is a needed exception to Inclusion I5 as these reactive power resources are used by retail
customers for power factor correction at their own facilities in order avoid imposed power factor
penalties.
Yes
It might be worthwhile to explain the relationship (timeline) between the BES Definition
implementation plan and the compliance implementation plan proposed in the BES RoP team’s new
Appendix 5C for the NERC Rules of Procedure.
Individual
Sylvain Clermont
Hydro-Quebec TransEnergie
No
The proposed revision to the definition maintaining this bright line of 100 kV would expand
significantly what is considered to be BES in HQT's case (the amount of added facilities could be ten
times more). Since the main structure of Quebec system is included in the BES where the best norms
and standards apply, the inclusion in the BES of sub-systems at lower voltage and including
generation will not bring significant impact on the reliable operation of the interconnected system,
because of the nature of the Quebec Interconnection. Furthermore for HQT's system, the proposed
BES definition combined with the exception procedure are presently incompatible or at least
inconsistent with the regulatory framework applicable in Quebec. The proposed changes have not
address this concern, neither the SDT's responses to our previous comments last May (Q.1 and 12).
We reiterate that the definition and the exception procedure shall be determined by Quebec's
regulator, the Régie de l'Énergie du Québec, (Quebec Energy Board) which has the responsibility to
ensure that electric power transmission in Quebec is carried out according to the reliability standards

it adopts. Per se, it would be necessary that E1 and E3 grant exclusions with much higher level of
generation. It would also be necessary to allow for several levels of application for the Reliability
Standards, in accordance with the Régie de l’énergie du Québec approach: the Bulk Power System
(BPS) as determined using an impact-based methodology, the Main Transmission System (MTS), and
other parts of Regional System. Standards related to the protection system (PRC-004-1 and PRC-0051) and those related to the design of the transmission system (TPL 001-0 to TPL-004-0) shall be
applicable to the first level, but all other reliability standards shall be applied to the second level, the
MTS. The MTS definition is somewhat different than the Bulk Electric System definition, and it includes
elements that impact the reliability of the grid, supply-demand balance and interchanges. We argue
that it would be necessary for NERC to address the regulatory issues outside ot the present context of
the SDT and ROP team.
Yes
We believe that automatic inclusion of such generation and the path to connect them to the BES
would bring a great amount of facilities in the BES. Generation should be considered on a different
level such as "BES Support Elements" and provisions should be made so that some specific reliability
standards would apply to them.
Yes
Same comment than Q. 3. Also, since the path to connect the dispersed generation is often done at
distribution voltage, that lower voltage path should not be included in BES.
No
No
Even with the modification proposed, it is too much restrictive to refuse exclusion of radial system
when they have generator or multiple generating units of aggregate capacity greater than 75 MVA,
especially when a system is able to function reliably with the loss of generation much higher than this
amount. To count on the exception procedure to exclude radial system with greater generation is
risky since no specific criteria have been given to guide such exclusion. In most cases for radial or
local system including generation, the path that connects the generation should not be included in the
BES. Generators should be allowed to be considered "BES support elements" and reliability standards
should apply to them in specific.
Same comment than Q7.
Yes
Yes
In the Implementation plan, it is given only 24 months for compliance after applicable regulatory
approval. Considering the possibility that a proposed transition plan may involve commissioning of
long term projects, a provision for such situation should be made with longer delay.
Individual
Michael Falvo
Independent Electricity System Operator
Yes
Yes
Yes
While we agree with Inclusion I2, we suggest removing the parentheses enclosing the text “with gross
individual…” since their inclusion may lead to an erroneous reading of provision to include generators
that do not meet ERO Statement of Compliance Registry Criteria.
No

We thank the SDT for excluding the cranking paths from the BES definition, a point we had raised in
our comments to the previous posting. However, we had also disagreed with the inclusion of
Blackstart Resources and reiterate our view that their inclusion is superfluous given there is already a
designation specific for system restoration covered by an existing standard, to recognize their
reliability impacts and to ensure their expected performance. NERC Standards EOP-005-2 stipulates
the requirements for testing blackstart resource and cranking paths. This testing requirement suffices
to ensure that the facilities critical to system restoration are functional when needed, which meets the
intent of identifying their criticality to reliability. We therefore suggest removing Inclusion I3 entirely.
Yes
The revised Inclusion I4 does indeed clarify that there is no requirement for a contiguous BES path
from the dispersed generation resources to the point of interconnection to the BES.
Yes
The provisions of Inclusion I5 fully address the concerns we expressed in our previous comments.
No
We support the provisions of E1 in principle but require clarification of some issues and suggest
alternative wording in some cases. It is unclear if the connection voltage of generation referred to in
E1.b affects whether a radial system could be excluded under E1 although from the context it appears
that it would. For clarity we suggest appending “connected at 100 kV or higher.” Please provide in the
BES definition document an explanation of “non-retail” and “retail” generation used in E1.c.
Additionally, despite the fact the revisions to Inclusion I3 (Blackstart Resources) removed any
reference to Cranking Paths, Exclusion 1 (b) and (c) both indicate that the exclusion of a radial
system would not be allowed if generation identified in I3 were connected to it. This implies that the
Cranking Path for this Blackstart Resource would have to be BES. This appears to be an inconsistency.
We suggest removing the phrase “not identified in Inclusion I3” in both instances. We disagree with
notion that the capacity of generation connected to a radial system ought to determine whether that
radial system should be classified as BES. Firstly, it is a given that the generation connected to the
subject radial that meets the registry criteria would already be captured within the core BES definition
and Inclusion I2. The function served by a radial that is of importance in the current context is that of
delivering surplus power to the rest of the bulk power system and so, the impact on the BES of loss of
the radial system or its connected generation needs to be considered. In our view, the “BES-status” of
the radial itself is immaterial and so too is the aggregate capacity of generation resources connected
to it. Detailed arguments regarding impact on the BES can be made in support of an application for an
exclusion under the Exception Process, but it would be beneficial to avoid unnecessarily including a
radial merely because it has more than 75 MVA of qualifying generation connected to it, without equal
consideration of the connected load. To put a “bright line” on the consideration of impact referred to
above, we suggest: In E1 (b): Replace "an aggregate capacity less than or equal to 75 MVA (gross
nameplate rating)" with "a net capacity provided to the BES of less than or equal to 75 MVA." In E1
(c): Replace "an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating)" with "a net capacity of non-retail generation provided to the BES of 75 MVA." This
wording would be consistent with E2 (i). Finally the word “affect” stated in the note accompanying E1
lends itself to mis-interpretation. We therefore suggest the following revision to achieve greater
clarity: “This exclusion applies to radial systems connected by a normally open switch.”
Yes
No
Consistent with our comments in response to Q7, we propose removing E3 (a) since, as explicitly
described in E3 (b), one of the characteristic of the LN is that power flows only into the LN. The level
of generation contained within the LN is therefore immaterial, particularly where the most onerous
contingency or system operating condition occurring within the LN, results in acceptable BES
performance as defined by the applicable criteria of the NERC transmission planning standards. The
generation connected within the LN that meets the registry criteria would already be captured within
the definition of the BES as provided for in Inclusion I2.
Yes
Yes

We wish to also express our support for phased approach proposed in the draft supplemental SAR.
Development of the revised BES definition is an important and complex undertaking. The product of
this work is fundamental to establishing the applicability of NERC Reliability Standards. The issues
identified for attention in Phase 2 of this project warrant careful investigation and as such allowing
additional time to properly research and stakeholder them is justified. The draft Implementation Plan
for the BES definition sates “Compliance obligations for Elements included by the definition shall begin
24 months after the applicable effective date of the definition.” We are concerned that the stated
implementation period may be insufficient time to (1) prepare and file exception requests and have
these assessed; and (2) in cases where these exception requests are not approved, to develop and
complete transition plans for newly identified BES Elements and Facilities, particularly where those
plans require major investments for the procurement, installation and commissioning of additional
equipment. We therefore propose the following alternative wording for the Implementation Plan:
“Compliance obligations for elements included by the definition shall be evaluated and an
implementation schedule established within 24 months.” Throughout the document various phrases
are used to describe generating units/resource, viz. “generation resources”, “generating resources”,
“generating unit” and “power producing resources”. Please review these to identify and address any
possible inconsistencies.
Individual
John Allen
Rochester Gas & Electric and New York State Electric & Gas
No
The second sentence, “This does not include facilities used in the local distribution of electric energy,”
is vague and not sufficiently clear for northeast industry expert colleagues to be certain of what is
“not included.” This sentence seems to apply only to distribution facilities that have already been
classified based on the FERC “Seven Factor Test” in Order 888. If so, this sentence be re-written as
follows for clarity: “This does not include facilities classified as distribution facilities.” For US entities,
this classification is clearly delineated in our annual FERC Form 1 filing.
No
We generally agree, but suggest modification to the language of Inclusion I1 to clarify its application
for transformers with more than two windings: “Transformers with two or more terminals operated at
100 kV or higher, unless excluded under Exclusion E1 and E3.” Based on this wording, transformer
tertiary windings would also be BES – is that the intent?
No
Inclusion I2 should remove the reference to the Statement of Compliance Registry Criteria. The
definition should stand on its own. I2 should be revised to read: “Generators with a gross nameplate
rating of 20 MVA or greater, or a generating plant/facility connected at a common bus, with a gross
aggregate nameplate rating of 75 MVA or greater and is directly connected at a voltage of 100 kV or
above. BES includes the generator terminals through the high-side of the step-up transformer(s)
connected at a voltage of 100 kV or above.” This is consistent with the proposed I2 and the current
Compliance Registry Criteria.
No
Inclusion I3 should be changed to include the phrase, “material to,” currently in the Statement of
Compliance Registry Criteria (Section 3C3). Based on the definition wording, the Generator Step-Up
transformer (GSU) would not be BES if the generator would not otherwise already be included as BES
under another definition provision.
No
The term “common point” needs clarification and/or definition. (e.g., is it intended to apply to the risk
of single mode failure, where all the resources could be lost for a single event?) Some northeast
industry expert colleagues interpret I2 to mean the collector system itself needs to be 100 kV or
above in order to be BES. I2 seems to not include the collector system itself in BES. I4 be restated as
follows: “Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a collector system connected at a common point. BES includes
the interconnecting substation with the step-up transformer(s) connected at a voltage of 100 kV or
above.” [alternatively, replace the bold italics with, “generator terminals through the high-side of”]
Also note that some wind collector systems require supplemental dynamic reactive resources or

special control system to met reliability standards. As written, these reactive resources or controls
may not be considered to be BES.
Yes
There is no such thing as “supplying or absorbing Reactive Power” but the intended meaning is
sufficiently clear since it is industry ‘shorthand’. Suggest alternative wording: “Static or dynamic
Reactive Power resources that are connected at 100 kV or higher, or…”
No
E1 needs to be revised to make it less confusing. “Radial systems” leaves the impression that E1 is
not simply a “radial line exclusion”, because of the plural and the word “systems.” Northeast industry
expert colleagues are not clear at all what this sentence specifies: “A group of contiguous
transmission Elements that emanates from a single point of connection of 100 kV or higher.” • Does
E1 apply only to a single radial transmission line (and its associated “group of Elements”)? •
Alternatively, does E1 apply to multiple radial lines “emanating from” the same substation regardless
of the bus configuration – would a ring bus or a two-bus system that is connected with a tie breaker
be considered as “a single point of connection”? This definition is not clear. Clarity is imperative. E1(c)
should define or replace the term “non-retail”. Industry needs clarity on exactly what generation this
applies to, in order to properly apply this definition. The Note referring to the “Normally Open switch”
needs further clarification. As written, it seems to conflict with FERC order 743, paragraph 55: “While
commenters would like to expand the scope of the term “radial” to exclude certain transmission
facilities such as tap lines and secondary feeds via a normally open line, we are not persuaded that
such categorical exemption is warranted.” E1 should be restated as follows: “Radial systems: A single
transmission line or transformer not otherwise identified in the Inclusions above, with a single point of
connection of 100 kV or higher and: a) Only serves Load. Or, b) Only includes generation resources,
not identified in the Inclusions above. Or, c) Both serves Load and only includes generation resources,
not identified in the Inclusions above.
No
E2 should be consistent with the Statement of Compliance Registry Criteria. References to Balancing
Authority, Generator Owner, and Generator Operator should not be included in the BES definition.
“Net capacity” is unclear – must flow never exceed 75 MVA on an instantaneous or integrated hourly
energy basis per either design or operating experience? There is a potential for hundreds of MW to be
interconnected at a customer facility, with the “net capacity” (= flow into the transmission system?
Instantaneous? Annual average? On an integrated hourly basis at any hour?) being less than 75 MVA
– are hundreds of MW of generation “not material” to BES reliability? The conditions under which
direction of flow (i.e., “net capacity”) is assessed are critical, but E2(i) is silent on this. In E2(ii), the
“and”, “or”, and “or” are not clear – what are the necessary terms of the referenced “binding
obligation” and what is an “applicable regulatory authority”? Are “standby” and “back-up” and
“maintenance” power services independently defined and provided by a GOP, GO, or BA? Northeast
industry expert colleagues do not understand the relevance of E2(ii) to BES reliability. E2 should be
restated as follows: “A generating unit or multiple generating units that serve all or part of retail
customer Load with electric energy on the customer’s side of the meter if the flow to or from the BES
never exceeds 75 MVA”
No
“Local Network” is capitalized (network not capitalized at the beginning of E3) throughout E3, yet it is
not defined in the NERC Glossary. This exclusion is vague. This exclusion applies to a network with
“multiple points of connection” with the purpose “to improve the level of service to retail customer
load” – this phrase is intent-based and not reliability-based – most/all transmission “improves
service” compared to it not being there. In essence, this exclusion can be obtained if a portion of the
network: 1. Doesn’t have significant generation (again, “non-retail” phrase is unclear) 2. Power only
flows “into” this portion of the network, and not (ever? Even under any TPL design contingencies?)
“out.” Is this considering only pre-contingency steady state conditions? During contingency conditions
and for the period following a contingency the LN could supply power to other parts of the network
depending on the nature of the contingency. The conditions under which direction of flow is assessed
are critical, but E3(b) is silent on this. 3. This portion of the network is not part of a monitored
transmission interface This “Local Network Exclusion” is supported by a technical analysis which relied
on transfer distribution factors (see
http://www.nerc.com/docs/standards/sar/bes_definition_technical_justification_local_network_20110

819.pdf on the NERC BES Definition standard page http://www.nerc.com/filez/standards/Project201017_BES.html ). This transfer distribution factor (TDF) method was rejected by FERC in Order 743.
Paragraph 85 of the Order states: “Given the questionable and inconsistent exclusions of facilities
from the bulk electric system by the material impact assessment and the variable results of the
Transmission Distribution Factor test proposed in NPCC’s compliance filing in Docket No. RC09-3,
there are no grounds on which to reasonably assume that the results of the material impact
assessment are accurate, consistent, and comprehensive.93 Additionally, we have noted how the
results of multiple material impact tests can vary depending on how the test is implemented.” Unless
E3 is made more specific and clear, it should be stricken.
No
Consider using other wording to replace “retail”.
Yes
If the definition and inclusions and exclusions are not sufficiently specific and clear, stakeholders will
flood NERC and RROs with interpretation requests and/or apply the definition and its inclusions or
exclusions incorrectly. Explanatory figures with one-line diagrams should be developed and shared to
illustrate the system configurations included and excluded in this BES Definition. This would be very
helpful for definition clarity. This should be done as part of an “Application Guide” for the BES
Definition – this has precedence in CIP-002 version 5. Attached is a sample set of one-line diagrams
with interpretations based upon the inclusions and exclusions developed by Northeast Power
Coordinating Council members for discussion purposes as an example, but note that there is not a
uniform agreement on these diagrams based on the BES Definition as written, due to lack of clarity.
Group
David Kiguel
Hydro One Newtoeks Inc.
No
Although we agree with the concept and commend the SDT for developing explicit inclusions and
exclusions as part of the definition, we believe there are several outstanding issues and concerns
listed as our response to Q11 that need to be addressed by the SDT and by NERC as the ERO.
Yes
No
We do not agree with the thresholds of 20 MVA for a single unit and 75 MVA aggregate at a plant,
carried forward from the compliance registry. We understand the suggested phased approach and
expect that the issue will be dealt with at that future time. With the exception of units that are must
runs for reliability reasons, we suggest that the SDT should consider units smaller than 75 MVA or x
MVA is designated as BES support element and not BES element. These units should only be required
to comply with a handful of relevant NERC Standards. For example, • Voltage and frequency ride
through capability • Voltage control (AVR, etc.) • Underfrequency trip setting • Protection relay
setting coordination • Data submission for modeling; verification of capability and model These
smaller and geographically dispersed generating resources should neither be designated as BES
element nor be required to have its connection path be designated as BES. We suggest removing the
parentheses enclosing the text “with gross individual…” since their inclusion may lead to an erroneous
reading of provision to include generators that do not meet ERO Statement of Compliance Registry
Criteria.
No
We agree with the SDT in excluding the cranking paths from the BES definition, a point we had raised
in our comments to the previous posting. We also disagree with the inclusion of blackstart resources
and reiterate our view that their inclusion is superfluous given there is already a designation specific
for system restoration covered by an existing standard, to recognize their reliability impacts and to
ensure their expected performance. NERC Standard EOP-005-2 stipulates the requirements for testing
blackstart resources and cranking paths. This testing requirement suffices to ensure that the facilities
critical to system restoration are functional when needed, which meets the intent of identifying their
criticality to reliability. We therefore suggest completely removing Inclusion I3. We suggest the SDT
to drop I3 on the basis that: • The availability and performance expectations of blackstart resources
are ensured by existing related standards; and • Unless they meet the BES definition under inclusion

I2, there is no perceived reliability value in everyday operation of the BES.
No
Although we agree with the I4 concept, we suggest that the SDT should consider that this category
primarily includes wind and solar farms and their collector system. We believe these facilities should
not be included as BES elements but rather as supporting elements (see comments under I2) for the
following reasons: a) Any additional benefit of classifying these resources as BES is insignificant for
the reliability of supply (capacity and energy), considering the intermittent and widely variable nature
of these resources. The planning and operational standards and practices make sure that their
unavailability or unexpected (sudden) loss, which are significantly more likely due to the natural
elements than those due to mechanical or electrical causes, will not jeopardize the reliability of the
supply; and b) The reliability of the aspects of the collector system of these resources (their impact
on reliability of the bulk transmission system) is not different from that of distribution systems (load
serving feeders) which are excluded from the BES. We agree with the revised portion of Inclusion I4
which does indeed clarify that there is no requirement for a contiguous BES path from the dispersed
generation resources to the point of interconnection to the BES.
Yes
No
Although we agree with the exclusion of radial systems, we believe that the reliability of the
interconnected transmission network should not be determined by the amount of installed generation
on the radial system. We believe that the generation limit is restrictive and has little or no technical
basis. It is not the size of a unit on the radial system that should determine the reliability impact on
the BES but more importantly its location, configuration and system characteristics such as reliability
must run unit. We believe that there is no reason to divide E1 in three subsets of a, b and c. The end
result is that a radial system is excluded if it does not have more than 75 MW of aggregate non-retail
generation. However, consistent with E2 we suggest replacing "an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating)" with "a maximum net capacity of
non-retail generation provided to the BES of 75 MVA." We suggest deleting the references to I3 in E1
and E3 because we believe that this reference is in contradiction to I3 and probably an oversight and
should be corrected. I3 does not require path to be BES but it implies here that a radial system
cannot be excluded if there is a Blackstart unit on it.
Yes
No
We agree with the exclusion concept of LN. However, the reliability of the interconnected transmission
network should not be determined by the amount of installed generation in the local network. We
believe that the generation limit is restrictive and has little or no technical basis. It is not the size of a
unit in the LN that will determine the reliability impact on the BES but more importantly its location,
configuration and system characteristics such as reliability must run unit. We suggest that the SDT
should address this in phase 2 to increase the installed generation limit in a LN. We suggest deleting
the references to I3 in E1 and E3 because we believe that this reference is in contradiction to I3 and
probably an oversight and should be corrected. I3 does not require a path to be BES but it implies
here that a radial system cannot be excluded if there is a Blackstart unit on it.
Yes
Yes
• The definition of the Bulk Electric System (BES) is a foundational construct for the North American
Electric Reliability Corporation (NERC). FERC Orders 743 and 743-A do not mandate a 100 kV
approach. Instead, it states that a 100 kV bright line threshold is one approach to defining the BES. It
further states that only “some” 115/138 kV facilities are necessary for the reliable operation of the
bulk system. We believe that if one subset issue (such as 20 MVA vs. 75 MVA) of the entire definition,
requires more time and resources to arrive at the correct answer, the much larger and more
fundamental issue of how to define BES should not have been dismissed without the appropriate
analysis before another definition is proposed to be adopted by the ERO. • The proposed definition, in
combination with other new and/or modified Reliability Standards such as newly modified and

approved TPL Standards will require significant system upgrades with high dollar investments. We are
deeply concerned that a) no such assessment has been undertaken by the SDT and/or the ERO and
b) the proposed definition of the BES is not based on a technical analysis that will enhance the
reliability of the interconnected transmission network. o The NERC as the ERO should at least
undertake a cost and incremental reliability benefit analysis for its proposed definition of BES.
Furthermore, cost impacts and reliability benefit assessments of the BES definition coupled with other
new and modified reliability standards (such as the TPL Standards) must also be undertaken and
weighed against the potential benefits, if any, of this or any proposal. Not providing such an
assessment but using the 100 kV level as a starting point for the BES definition, gives no assurances
of benefits for any stakeholder including respective governmental and regulatory authorities and rate
payers in Canada or the USA. o The proposed definition would significantly increase the population of
BES elements. Many of the standards requirements for these new elements will introduce
administrative burden and operating expenses. This would impose significant costs, costs that
ratepayers will have to bear, with little or no gain in reliability benefits for the interconnected
transmission system. We suggest that the resulting BES definition must identify incremental reliability
benefits by the ERO for the interconnected transmission network based on sound technical analysis to
justify the change to those who will pay for any required system upgrades – the ratepayer. • The
draft Implementation Plan for the BES definition states “Compliance obligations for Elements included
by the definition shall begin 24 months after the applicable effective date of the definition.” We are
concerned that the stated implementation period will give insufficient time to complete transition
plans for newly identified BES Elements and Facilities, where those plans require approval,
procurement, installation and commissioning of additional equipment. We believe a period of 60
months at a minimum is more appropriate. Finally, we believe that the SDT proposed approach for
exception criteria is reasonable recognizing that one method/criteria can not be applicable to
everyone and every situation within the ERO footprint. However, we believe that there is a huge gap
and lack of any transparency on how the exception application will be evaluated and processed. We
strongly suggest that the SDT develop a reference or a guidance document as part of the RoP that
should provide guidance to Registered Entities, Regional Entities and the ERO on how an exception
application should be processed. Else, (a) it will pose a challenge for each of the entities including
ERO, and (b) may introduce Regional discretion and be perceived as having no transparency for the
registered entities.
Individual
Steve Eldrige
Umatilla Electric Cooperative (UEC)
Yes
The Umatilla Electric Cooperative (UEC) believes the SDT continues to make substantial progress
towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly improves
both the existing definition and the SDT’s previous proposal. UEC therefore supports the new
definition, although our support is conditioned on: (1) a workable Exceptions process being developed
in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II of
the standards development process in accordance with the SAR recently put forward by the SDT,
which would address a number of important technical issues that have been identified in the
standards development process to date. UEC strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100kV or higher and Real Time and Reactive Power resources connected at 100kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for “facilities used in the local distribution of electric
energy.” As the starting point for the BES definition, UEC supports the use of the phrase “all
Transmission Elements” and the qualifying sentence: “This does not include facilities used in the local
distribution of electric energy.” This language helps ensure that FERC, NERC, and the Regional
Entities (“REs”) will act within the jurisdictional constrains Congress placed in Section 215 of the
Federal Power Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities used in
the local distribution of electric energy” from the keystone “bulk-power system” definition. 16 U.S.C.
§ 824o(a)(1). Including the same language in the definition helps ensure that entities involved in

enforcement of reliability standards will act within their statutory limits. In addition, as a practical
matter, inclusion of the language will help focus both the industry and responsible agencies on the
high-voltage interstate transmission system, where the reliability problems Congress intended to
regulate – “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) –
will originate. At the same time, level-of-service issues arising in local distribution systems will be left
to the authority of state and local regulatory agencies and governing bodies, just as Congress
intended. 16 U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). UEC thanks the SDT for the excellent work to include this sentence. For
similar reasons, UEC believes the use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used in NERC Reliability Standards, and the term “Transmission” makes clear
that the BES includes only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. (3) Appropriate Generator Thresholds. In the standards
development process, it has become apparent that the thresholds for classifying generators as BES in
the current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for individual
generators, 75 MVA for multiple generators aggregated at a single site), which predate the adoption
of FPA Section 215, were never the product of a careful analysis to determine whether generators of
that size are necessary for operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development process. UEC recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to
conduct such an analysis within the time available. Accordingly, UEC agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process that would address
the generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, UEC is prepared to support the BES definition as
proposed by the SDT. While UEC supports the overall approach adopted by the SDT and much of the
specific language incorporated into the second draft of the BES definition, we believe the second draft
would benefit from further clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Further, we believe a workable Exclusion Process is essential for
a BES Definition that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our previous comments, UEC believes a
200kV threshold would be more appropriate for WECC than a 100kV threshold. In addition, a 200kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view are therefore incorrect. That said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western Interconnection because the
core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
UEC will support the SDT’s proposal.
Yes
We support the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the

transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus, and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
UEC supports the changes made in Inclusion 2 and believes that the definition in its current form adds
clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the previous
draft definition into a single Inclusion that addresses the treatment of generation for purposes of the
BES definition. We also support the SDT’s proposal for a Phase II of the BES Definition process that
would examine the technical justification for these thresholds and that would establish new thresholds
based on a careful technical analysis. It is our understanding that the generator threshold issue will
be vetted through the complete standards development process. We agree with this approach
because if the generator threshold is treated as merely an element of NERC’s Rules of Procedure, it
can be changed with considerably less process and industry input than the Standards Development
Process. Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of Procedure upon
approval of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3, 2010)
(providing for, e.g., posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011) (“Order No. 743
directed the ERO to revise the definition of ‘bulk electric system’ through the NERC Standards
Development Process” (emph. added)). Addressing all aspects of Phase II through the Standards
Development Process will improve the content of the definition by bringing to bear industry expertise
on all aspects of the definition and will ensure that, once firm guidelines are established, they can be
relied upon by both industry and regulators without threat that they will be changed with little notice
and little process. UEC believes further clarification of the proposed language would be appropriate.
The SDT proposes continued reliance upon the thresholds that are used in the NERC Statement of
Compliance Registry Criteria for registration of Generation Owners and Generation Operators, which is
currently 20 MVA for an individual generation unit and 75 MVA for multiple units on a single site.
Conceptually, we are concerned about this approach because, as we understand it, the purpose of the
Compliance Registry is to sweep in all generators that might be material to the reliable operation of
the BES, and not to definitively determine whether a given generator is, in fact, material to the
reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to identify
“candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we believe that the
generator threshold determined in Phase II should be incorporated directly into the BES Definition
rather than being incorporated by reference from the SCRC. We also believe that the specific
language proposed by the SDT could be further clarified. The SDT proposes that generation be
included in the BES if the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder for the results of
the technical analysis that would occur in Phase II but we believe simply stating that the threshold
will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the reasons noted
above, we believe the threshold should be part of the BES Definition, and should not simply be a
cross-reference to the SCRC (and, given the different purposes of the BES Definition and the SCRC, it
is not clear that the same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate Resources
connected at a voltage of 100kV or above.” Two definitions would then be added to the note at the
end of the definition to read as follows: For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality threshold to be
included in this definition or, in the absence of such a materiality threshold, that meets the gross
nameplate capacity voltage threshold requiring registration of the owner of such a resource as a
Generation Owner under the ERO Statement of Compliance Registry Criteria. For purposes of this BES

Definition, Qualifying Aggregate Generation Resources means any facility consisting of one or more
generating units that are connected at a common bus that meets the materiality threshold to be
included in this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit generator as a
Generation Owner under the ERO Statement of Compliance Registry Criteria.. The “materiality
threshold” is intended to refer to the generator threshold developed in Phase II. We suggest using
definitions in this fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as part of the BES
if they are necessary for operation of the BES, but to exclude smaller generating units because they
are not material to the operation of the interconnected transmission grid. Second, we believe use of
the defined terms better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase II without having to revise the
BES Definition at the end of that process. That is, the definitions are designed to allow the SDT to
include revised thresholds in the definition at the conclusion of the Phase II process based upon the
technical analysis planned for Phase II, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase II is completed. Third, the definitions can be
incorporated into other parts of the BES Definition, which will add consistency and clarity. As noted in
our answers to several of the questions below, the specific 75 MVA threshold is retained in several of
the Exclusions and Inclusions, and we believe the industry would be better served if the revised
thresholds arrived at after technical analysis in Phase II are automatically incorporated into all
relevant provisions of the BES Definition. There is no reason for the SDT to continue to rely on the 75
MVA threshold once the analysis planned for Phase II on the threshold issue is completed. Fourth, the
phrase “or that meets the materiality threshold to be included in this definition” is intended to
preserve the SDT’s flexibility to make a determination that generators below a specific threshold are
not “necessary to” maintain the reliability of the interconnected transmission system, and to
incorporate that finding as part of the definition itself, even if a different threshold is used in the SCRC
to identify potential candidates for registration. Accordingly, our proposed language makes clear that
a specific threshold in the definition controls over any threshold that might be included in the SCRC.
For the reasons stated above, we believe is it highly desirable to include any material threshold in the
BES Definition itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Finally, we agree with the SDT’s decision to
examine the question of where the line between BES and non-BES Elements should be drawn more
closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and commend the work
of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting point for the
SDT’s analysis on this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities interconnecting such
generators to be part of the BES. As discussed more fully in our answer to Question 9, based on
extensive technical analysis that has already been performed by the NERC Project 2010-07 Standards
Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a
dedicated interconnection facility connecting a BES generator to the interconnected bulk transmission
grid will result in an unnecessary regulatory burden that produces considerable expense for the owner
of the interconnection facility with little or no improvement in bulk system reliability. We also believe
the clauses at the end of Inclusion 2 are somewhat confusing and that greater clarity would be
achieved by changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100kV or above” so that the Inclusion covers transformers
with terminals “connected at a voltage of 100kV or above, including the generator terminal(s) on the
high side of the step-up transformer(s) if operated at a voltage of 100kV or above.”
Yes
UEC supports the removal of the Cranking Path language in I3. As noted in our response to Question
9, there is no reason to classify as BES the facilities interconnecting a BES generator to the bulk
interstate system. A Cranking Path is simply a specific type of such an interconnection facility.
Yes
UEC supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term

“Qualifying Aggregate Generation Resources,” which we discuss in more detail in our response to
Question 3. This language will preserve the SDT’s ability to revise the 75 MVA threshold in Phase II,
with the result of Phase II included in the BES Definition by operation rather than requiring further
revision of the Definition. More generally, we are not certain what is accomplished by Inclusion 4 that
is not already accomplished by Inclusion 2, which also addresses whether generation should be
defined as BES. The SDT’s stated concern is with variable generation units such as wind and solar
plants. It is not clear to us why this concern is not fully addressed in Inclusion 2, which addresses
multiple generation units connected at a common bus, the configuration of most variable generation
plants with multiple units. We are also concerned that the language, as proposed, could have
unintended consequences and improperly classify local distribution systems as BES in certain
circumstances. This is because multiple distributed generation units could render a local distribution
system a “collector system” and the entire system the equivalent of an aggregated generation unit,
causing the local distribution system to be improperly denied status as a Local Network. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the
Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
UEC has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Third, UEC believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process. Finally, UEC
believes this issue should be addressed in Phase 2 since there is not technical justification or analysis
done to determine the thresholds. UEC strongly believes that there should be technical justification for
thresholds for this issue and all other issues.
Yes
UEC continues to strongly support the radial system exclusion, which is necessary as a legal matter,
because, among other reasons, FERC in Orders No. 743 and 743-A has required that the existing
radial exemption in the NERC Statement of Compliance Registry Criteria be maintained. As a practical
matter, radial systems are used for service to retail loads, usually in remote or rural areas, and not
for the transmission of bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. We also support the inclusion of
the note discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of this language,
which is that a radial system should not be considered part of the BES if it is interconnected at a
single point, even if there is an alternative point of delivery that is normally open. While we support
the Exclusion for Radial Systems, we believe several clarifications and refinements are necessary. (1)
The term “transmission Elements” in the initial paragraph should be changed to “Elements.” Radial
systems are not transmission systems and including the word “transmission” in the Radial System
exclusion is therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to
“generation resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate
rating)”). We urge the SDT to replace this language with the defined term “Qualifying Aggregate
Generation Resources,” discussed in more detail in our response to Question 3. This language will

preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result of Phase II
included in the BES Definition by operation rather than requiring further revision of the Definition. (3)
Subparagraph (b) also seems to assume that if a Radial System contains a generator exceeding the
75 MVA threshhold, the Radial System itself must be included in the BES because it links the
generator to the interconnected bulk transmission system. As discussed more fully in our response to
Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task Force have
both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT indicates
that “a normally open switching device between radial systems” will not serve to disqualify the Radial
from exclusion under Exclusion 1. As discussed above, UEC strongly supports the note conceptually.
However, we believe this language should be included in a separate subparagraph (d), rather than a
note, because treatment as a “note” suggests it is less important than other portions of the Exclusion.
We also suggest the language be changed to read: (d) Normally-open switching devices between
radial elements as depicted and identified on system one-line diagrams does not affect this exclusion.
This will make clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is whether switches
operating between Radials are normally open, not whether there is more than one normally-open
switch.
Yes
UEC supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, UEC urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similar, a Local Network could lose its status because behind-themeter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN.
Yes
UEC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of radial
systems to local networks should be encouraged because networked systems generally reduce losses,
increase system efficiency, and increase the level of service to retail customers. If the BES definition
were to provide an exclusion for radials without providing a similar exclusion for LNs, however, it
would discourage networking local distribution systems because of the significantly increased
regulatory burdens faced by the local distribution utility if it elected to network its radial facilities. By
placing radial systems and LNs on the same regulatory footing, the proposed definition will ensure
that decisions about whether to network radial systems are made on the basis of costs and benefits to
the retail customers served by those radials, and not on the basis of disparate regulatory treatment.
Consumers would ultimately benefit. UEC also supports specific refinements made to the LN exclusion
by the SDT in the current draft of the BES definition. In particular, UEC supports the clarification of
the purposes of a LN. The current draft states that LNs connect at multiple points to “improve the
level of service to retail customer Load and not to accommodate bulk power transfer across the
interconnected system.” UEC supports this change in language because it reflects the fundamental
purposes of a LN and emphasizes one of the key distinctions between LNs and bulk transmission
facilities, namely, that LNs are designed primarily to serve local retail load while bulk transmission
facilities are designed primarily to move bulk power from a bulk source (generally either the point of
interconnection of a wholesale generator or a the point of interconnection with another bulk
transmission system) to one or more wholesale purchasers. UEC believes further improvement of the
language could be achieved with additional modifications and clarifications. With respect to the core
language of Exclusion 3, we believe the language making a “group of contiguous transmission

Elements operated at or above 100kV” the starting point for identifying a LN would be improved by
deleting the term “transmission” from this phrase. This is so because LNs are not used for
transmission and the use of the term “transmission Elements” is therefore both confusing and
unnecessary. There would be no room for argument about what the SDT intended by including the
word “transmission” if the word is deleted and the Exclusion applies to any “group of Elements
operated at 100kV or above” that meets the remaining requirement of the Exclusion. Further, any
definitional value that is added by using the term “transmission Elements” is accomplished by using
that term in the core definition, and there is no reason to carry the term through in the Exclusions.
UEC also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3
and simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects
more than 75 MVA of generation, the interconnected generation interconnected will have no
significant interaction with the interconnected bulk transmission system. It will only interact with the
LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a large
number of very small distributed generators are interconnected into a LN, so that the aggregate
capacity of these generators exceeds 75 MVA. However, because the generators are small and
dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN rather
than transmitting power onto the interconnected grid, those generators would not have a material
impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more clearly
drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than out of it,
includes this description: “The LN does not transfer energy originating outside the LN for delivery
through the LN.” We understand this language is intended to distinguish a LN from a link in the
transmission system – power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to be the equivalent of generation that is located behind the
retail meter, usually but not always owned by the customer and used to serve the customer’s own
load. We therefore suggest that the SDT replace the term “non-retail generation” with “generation
located behind the retail customer’s meter.” Similarly, we are unsure what is meant by the phrase
“the LN and its underlying Elements.” We believe the phrase “and its underlying Elements” could
simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3. UEC
also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as long as
subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as a Flow
Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that allow
reliable transmission of bulk electric power on the interconnected grid. If a LN has not been identified
as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable transmission
of electricity on the interconnected bulk system. Apart from these specific improvements that we
believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may need to
re-examine certain assumptions that appear to underlie the current draft. Specifically, subparagraph

(a) suggests that if BES generation is embedded within a LN, the LN itself must also be BES. But two
NERC bodies have already addressed similar questions and concluded there is no technical basis for
such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its predecessor, the “GO-TO
Task Force” were formed to address how the dedicated interconnection facilities linking a BES
generator to high-voltage transmission facilities should be treated under the NERC standards. The
GO-TO Team concluded that by complying with a handful of reliability standards, primarily related to
vegetation management, reliable operation of the bulk interconnected system could be protected
without unduly burdening the owners of such interconnection systems. Therefore, there is no reason,
according to the GO-TO Team, that dedicated high-voltage interconnection facilities must be treated
as “Transmission” and classified as part of the BES in order to make reliability standards effective.
See Final Report from the NERC Ad Hoc Group for Generator Requirements at the Transmission
Interface (Nov. 16, 2009) (paper written by the GO-TO Task Force). Similarly, the Project 2010-07
Team observed that interconnection facilities “are most often not part of the integrated bulk power
system, and as such should not be subject to the same level of standards applicable to Transmission
Owners and Transmission Operators who own and operate transmission Facilities and Elements that
are part of the integrated bulk power system.” White Paper Proposal for Information Comment, NERC
Project 2010-07: Generator Requirements at the Transmission Interface, at 3 (March 2011).
Requiring Generation Owners and Operators to comply with the same standards as BES Transmission
Owners and Operators “would do little, if anything, to improve the reliability of the Bulk Electric
System,” especially “when compared to the operation of the equipment that actually produces
electricity – the generation equipment itself.” Id. We believe that interconnection of BES generators
within a LN is analogous and that, based on the findings of the Project 2010-07 and GO-TO Teams,
automatically classifying a LN as “BES” simply because a large generator is embedded in the LN will
result in substantial overregulation and unnecessary expense with little gain for bulk system
reliability. If anything, generation interconnected through a LN is less likely to produce material
impacts on the interconnected bulk transmission system than the equivalent generator interconnected
through a single dedicated line because an LN is interconnected to the bulk system at several points,
so that if one interconnection goes down, power can still flow from the BES generator to the bulk
system on other interconnection points. Where a dedicated interconnection facility is involved, by
contrast, if the interconnection line fails, the generator is unavailable to the interconnected bulk
system. Similarly, we suggest that the SDT re-examine the assumptions underlying subparagraph
(b), which seems to suggest that a local distribution system cannot be classified as a Local Network if
power flows out of that system at any time, even if the amount is de minimis, the outward flow is
only for a few hours, a year, or the outward flow occurs only in an extreme contingency. Accordingly,
we suggest that the initial clause of subparagraph (b) be revised to read: “Except in unusual
circumstances, power flows only into the LN.” Finally, we note that the LN exclusion must not operate
in any way as a substitution for the statutory prohibition on including “facilities used in the local
distribution of electric energy” in the BES. Therefore, even with the LN exclusion, the SDT must retain
this statutory language in the core definition of the BES, as discussed in our answer to Question One.
If a certain piece of equipment is a “facility used in the local distribution of electric energy,” then it is
not part of the BES in the first instance, and so consideration of the LN Exclusion, or of any other
Exclusion, any Inclusion, or any Exception, would be both unnecessary and uncalled for.
Yes
UEC supports the revised language because retail reactive devices are used to address local customer
or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such local
devices should therefore be excluded from the BES definition.
No
UEC extends its thanks to the SDT and to the many industry entities that have actively participating
in the Standards Development Process. UEC supports the current draft and believes, with certain
refinements discussed in our comments, that the definition will serve the industry and reliability
regulators well for many years to come. In addition, as noted earlier, UEC is encouraged that the
20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry Criteria,
which have been relied upon by the SDT largely as a matter of necessity, will be reviewed and a
technical assessment will be performed to identify the appropriate generation unit and plant size
threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure Team
will continue to move forward with developing an Exceptions Process that will complement the BES
Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should not

be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that UEC specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. UEC supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. UEC
also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Steve Alexanderson
Central Lincoln
Yes
We agree with the changes. We must point out that the overall flow, or how one proceeds through the
inclusions and exclusions is not clear. Can an item that meets an inclusion be subsequently excluded?
If so, this needs to be explicitly stated. So far, we only have the flow chart produced by the ROP team
that indicates otherwise (http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf).
This was made evident by the question at the 9/28 webinar regarding an I5 capacitor on an E3 local
network. The questioner thought the capacitor was BES per I5, but the answer was that it was
excluded per E3. We can find no support for the answer given. The listing of specific exclusions within
I1 (exception proves the rule) argues for questioner’s stance that the capacitor is BES as written.
Also, if included items could subsequently be excluded, they would be no different from any other
item that met the voltage threshold of 100kV. There would be no need for any of the inclusions if all
possible outputs from the inclusion tests go to the same exclusion test inputs. We strongly support
the addition of the language regarding local distribution facilities, as it matches congressional intent
to leave the regulation of these facilities to state and local authorities.
Yes
Central Lincoln strongly agrees with this inclusion as written. It is consistent with the recent PRC-004
and PRC-005 interpretation and the NERC definition of Transmission. We believe the recent changes
to this inclusion add clarity.
No
Referencing the Criteria which in turn references the BES definition creates a circular definition.
Central Lincoln encourages the adoption of specific thresholds that are technically justified. We also
note that the Criteria and its revisions do not go through the standards development process, so that
thresholds may change with little warning and without triggering an implementation plan for facilities
that may be swept into the BES as a result.
Yes
We agree with the removal of the voltage language, since the inclusions and exclusions apply only to
equipment over 100 kV.
Yes
Central Lincoln agrees both with the inclusion and with the revised language. The revised language
removes the need to provide a separate definition for “Collector System”.
No
While we agree that reactive devices of sizable capacity connected at 100 kV or higher are needed for
BES reliability, Central Lincoln fails to see why this inclusion is needed as they are already captured
by the 100 kV threshold. We would propose instead to eliminate this inclusion and substitute an
exclusion for smaller capacity devices. If the SDT really believes an inclusion for reactive devices is
needed, we suggest the SDT provide a technically justified capacity limit within the inclusion. In
addition we suggest also including the phrase “…unless excluded under Exclusion E1, E2 or E4” similar
to that in I1. Please see the answer to Q1 above Q10 below.
No
Central Lincoln notes that a new term has been introduced, “non-retail generation,” with no definition

provided. The answer to the question on this during the 9/28 webinar indicated that non-retail
generation was behind the retail customer’s meter. We can see no reason why the net-metered PV
systems should count toward the aggregate limit (exceeding the limit means no exclusion) while a
non-blackstart thermal plant doesn’t (the radial system is excluded if any amount of load is present).
We have also heard the SDT meant just the opposite of what was stated in the webinar. We ask that
a reasonable definition for non-retail be provided within the BES definition document. We strongly
agree that radial systems should be excluded and that the presence of normally open switching
devices between radial systems should not cause them to be considered non-radial. Such a result
would cause the removal of these devices to the detriment of the local level of service. We note that
the singular “A normally open switching device” is used and suggest that an allowance be made for
the possibility of multiple devices. “Normally open switching devices…”
Yes
No
We strongly agree that local networks should be excluded, since they act much like the radial systems
excluded in E1 while providing a higher level of service to customers. These networks should not be
discouraged in the name of reliability. We again object to the introduction of the new confusing term
“non-retail generation” with no definition provided.
No
Please see Central Lincoln’s answers to Q1 and Q6. Any device that might be excluded under E4 has
already been included per I5. Unless I5 is removed, or rewritten as suggested above; this exclusion
will exclude nothing.
Yes
We note that the SAR for Phase II, like that for Phase I, does not include all entity types. We see no
reason to maintain dual definitions for the different entity types, and the resulting confusion. In order
to help meet the fast approaching January target date, Central Lincoln will be voting affirmative in
this ballot, with the hope these comments will be addressed in Phase II. If the ballot should fail,
please address these comments in this phase. Thanks to the team for their good work.
Individual
Allan Long
Memphis Light, Gas and Water Division
Yes
Yes
We believe further clarification is needed to limit BES transformers only to those serving the
transmission system and not distribution loads, such as excluding transformers with one or both
terminals operating below 100 kV.

Yes
We are in general agreement with this inclusion, except that there is no threshold for reactive
resources as there is for generators and transformers. We recommend that a minimum level be
established for this equipment, such as 100 MVAr, or that studies be conducted to determine an
appropriate threshold.
Yes

Yes
Yes

No
We appreciate the work the drafting team has done in preparing this document.
Individual
Shane Sweet
Harney Electric Cooperative, Inc.
Yes
HEC agrees with the changes by the SDT. Although HEC believes that there needs to be explicit
language stating whether or not an item that meets inclusion can be overridden by an exclusion. An
example of this was given during the Webinar on 9/28 regarding a Capacitor included under I5 yet
excluded under E3 according to the NERC representative.
Yes
HEC agrees with the inclusions to I1 and believes that add clarity to the definition.
No
HEC would like to see the inclusion of specific thresholds that are technically justified.
Yes
HEC agrees with the inclusions to the core definition.
Yes
HEC agrees with the inclusions and revised language to the definition
No
HEC believes this inclusion should include a technically justified capacity limit on reactive resources to
warrant inclusion.
Yes
HEC strongly agrees that radial systems should be excluded from the BES and that the presence of a
normally open switching device between radial systems should not cause them to be considered nonradial
Yes
Yes
HEC believes that local networks should be excluded from the BES and agrees with exclusions to the
definition.
Yes
HEC agrees with E4.
No
Group
Joe Tarantino
Braun Blasing McLaughlin, PC
Yes
In an effort to avoid potential confusion and provide clarity we believe the following sentence “This
does not include facilities used in the local distribution of electric energy” more appropriately fits
under the “exclusions,” rather than “inclusions,” section.
Yes
We believe additional clarification of transformers that are to be included may be achieved with
respect to auto transformers, phase angle regulators and generator step-up transformers by adding
the following recommended sentence: “All transformers (including autotransformers, voltage
regulators, and phase angle regulators) with primary and secondary terminals operated at or above
100kV, unless excluded by E1 or E3.”
No
We recommend removing the reference of the ERO Statement of Compliance Registry Criteria
(Registry Criteria). The BES Definition should be the governing document and independent of ERO
registration requirements. The definition should drive what appears in the Registry Criteria.

Additionally, we support using the BES Phase 2 technical analysis to identify and provide technical
support for determining the appropriate minimum MVA rating that a single unit, or the aggregation of
multiple units, must meet to be considered part of the BES.
Yes
We recommend rewording Inclusion I3 as follows: “Only Primary Blackstart resources designated as
part of the Transmission Operator’s restoration plan.” We have concerns that making all Blackstart
generation either primary or secondary BES elements will create an incentive to remove those
secondary Blackstart capable units in order to avoid BES inclusion. Making the primary Blackstart unit
the only BES element will remove this incentive. In so doing, this will allow the secondary Blackstart
units to remain in the Transmission Operator’s plan and training program as an alternate tool for the
Transmission Operator to restore the system.
Yes
Yes
However, appropriate MVAr level should be established. Reactive resources should be treated similar
to generation criteria and included in the technical studies associated with the Phase 2 technical
analysis in order to establish the appropriate MVAr level included as BES.
Yes
For the E1 reference “Note,” we would benefit from additional clarification identifying the treatment of
a normally open switch and offer the following: “Radial systems shall be assessed with all normally
open switching devices in their open positions.” The wording in Exclusion 1-c should more clearly
reflect what is intended by using the term “non-retail generation.” Also, as with the technical
justification for Inclusions I2 and I4, it is recommended that the generation threshold, i.e. gross
nameplate values, be deferred to Phase 2.
Yes
It is preferred to hold reference to gross nameplate rating/threshold values until generation technical
justification is completed as part of Phase 2; these studies should apply to any real or reactive power
threshold reference. For Exclusion E3-b using the phrase “[p]ower flows only into the LN” is too
restrictive. An allowable MW threshold of LN power producing resources should be deferred to the
Phase 2 BES technical analysis. Where no generation is present in the LN, it is recommended that an
allowance for residual flow through the LN.
Yes

Individual
Russell Noble
Cowlitz County PUD
Yes
Cowlitz County PUD No. 1 (Cowlitz) commends the SDT for the simplified concise core definition.
However, Cowlitz believes that only Real and Reactive Power resources necessary for the support of
the BES should be included. Therefore, Cowlitz suggests the core definition or the Inclusions section
state this. This will allow basis for demonstrating resource Elements should be excluded from the BES
through the Rules of Procedure exception process. This is not to say that owners of non-BES resource
Elements should not be registered, as such entities may still have an obligation to contribute BES
Reliability functions. Cowlitz votes affirmative and believes the above concern can be addressed in
Phase II.
Yes
Cowlitz supports the SDT’s efforts to simplify this inclusion. However, Cowlitz suggests the following
change to clarify the inclusive nature of the use of “and:” Transformers with primary and secondary
terminals both operated at 100 kV or higher…
Yes
Cowlitz also strongly supports Phase II to address the lack of technical justification of the MVA bright

line criteria.
Yes
Yes
However, Cowlitz suggests Inclusion 4 be made parallel with Inclusion 2: …(greater than the gross
aggregate name plate rating per the ERO Statement of Compliance Registry Criteria) utilizing…
No
Cowlitz has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Finally, Cowlitz believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process.
Yes
Yes
Cowlitz is concerned that Exclusion 2 will place local distribution utilities in a difficult position; under
Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System or a Local
Network through the actions of a customer constructing behind-the-meter generation. With respect to
Radial Systems, the appearance of behind-the-meter generators could cause the Radial System to
exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no fault of the
Radial System owner. Similar, a Local Network could lose its status because behind-the-meter
generation could be of sufficient size that power moves into the interconnected grid in certain hours
or under certain contingencies, rather than moving purely onto the Local Network, as required in
subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN. However, Cowlitz understands the difficulty of pressing the argument at this time for any
generation that is connected directly through a dedicated step-up transformer to Elements at or
greater than 100 kV.
Yes
Cowlitz strongly supports the categorical exclusion of Local Networks (“LNs”) from the BES. This
exclusion will allow conversion of radial systems to LNs without compliance impact, and should be
encouraged rather than discouraged as networked systems generally reduce losses, increase system
efficiency, and increase the level of service to retail customers. The decision of whether to network
radial systems should be made on the basis of costs and benefits to the retail customers served by
those radials, and not on the basis of disparate regulatory treatment. Consumers will ultimately
benefit from the path chosen by the SDT. Cowlitz believes that the word “transmission” does not add
clarity to the Exclusion; simply stating “Elements” is sufficient. This will allow for a gradual acceptance
that transmission is not defined by a certain voltage, but more a medium in which electrical power is
efficiently transported from power resources to load centers where it is distributed. The old
convention of transmission versus distribution no longer fits in the current regulatory environment,
and as such should be retired. Cowlitz also believes that subparagraphs (a) and (b) are redundant;
subparagraph (a) is duplicated by the limit in subparagraph (b) requiring no flow out of the LN.
However, Cowlitz also believes that removing (a) will complicate FERC’s acceptance of this exclusion.
Therefore this should be addressed in Phase II. Cowlitz is confused by the use of the term “non-retail
generation” in subparagraph (a). From context, we believe the SDT considers “non-retail generation”
to mean generation that is not connected through a dedicated step-up transformer to voltages at or
above 100 kV, is consumed by the retail customer’s load, or consumed within the LN rather than
being physically exported and sold to markets outside the LN. Cowlitz suggests that the SDT rewrite
subparagraph (a) to read “Limits on connected generation: The LN and its underlying Elements do not
include generation resources identified in Inclusion I3 and does not have any generation net power
flow greater than 75 MVA across any single retail revenue metering point into an Element operated at

or greater than 100 kV.”
Yes
No
Cowlitz appreciates the opportunity to comment, and the hard work of the SDT.
Individual
Brian Evans-Mongeon
Utility Services, Inc.
Yes
Upon reflection of the core definition and BES Inclusion Designations, Utility Services believes that
there is an unintended redundancy between the two. Utility Services would like to suggest that the
portion of the core definition that refers to the Real and Reactive Power resources be removed from
the core and to leave the Inclusions as is.
Yes
Utility Services supports the comments offered by other commenters who suggest that transformers
and other related devices be mentioned in the inclusion.
Yes
Yes
Utility Services supports suggestions by others that request that the language of the Inclusion use the
exact language of the SCRC III.3.c. Leaving the language as is will likely increase the number of black
start facilities beyond those currently applicable.
Yes
Yes
Yes
Utility Services is very concerned that the "single point of connection" lacks clarity and applications
need to be identified. Utility Services suggests that the SDT publish illustrative one-line diagrams to
aid the industry in determining when the designations are best applied.
Yes
Utility Services suppports the comments offered by others suggesting that the language be revised to
be identical to the language in the SCRC.
Yes
Yes
Yes
Utility Services would like to raise the question of whether SCRC III.3.d (the so-called "Generator
Materiality" clause)is incorporated within the BES Inclusion Designations. One theory suggests that
given that I2 is designed to deal with III.3.a and III.3.b and I3 reflects the need to incorporate black
start generation; then generators under the materiality clause are not identified with the inclusion
criteria. However, the second theory suggests that resources identifed through I2 reflect the entire
III.c.1-4 language of the SCRC, then the generators in the material clause are captured under I2. But
if this is the case, then I3 is redundant to I2 and does not need to separately addressed.
Group
Jean Nitz
ACES Power Marketing
Yes
Yes

Yes
We’d prefer to see the language from the ERO Statement of Compliance Registry Criteria repeated
within the BES Definition itself instead of referencing an outside document. As it stands right now, the
Compliance Registry Criteria needs to stay intact for Phase I of this project. That makes the
Compliance Registry Criteria reliant on the BES Definition and vice versa. We understand that the
Statement of Compliance Registry Criteria may be reviewed/revised at the same time Phase 2 of this
project is being developed, therefore we agree with Inclusion I2 of this draft.
No
Blackstart Resources can actually be on the distribution system. There is still the question of whether
the distribution system would then be subjected to the enforceable standards. If so, there would most
likely be a significant cost increase associated with tracking compliance for these distribution systems
without a commensurate increase in reliability since Blackstart Resources are rarely used. This could
very well cause entities to un-designate Blackstart Resources on distribution systems to avoid these
distribution systems from becoming part of the BES. The same rationale that was used for eliminating
cranking paths could also be applied to Blackstart Resources.
Yes
Further clarification on what “dispersed power” means would be helpful. How does it compare to
distributed generation?
Yes
We understand the SDT’s logic behind not setting any threshold values for reactive resources during
Phase 1 of this project. Ample time and effort should be given to developing the technical justification
behind such values. However, we encourage the SDT to consider adding threshold values in Phase 2
of the project to provide even more clarity to this inclusion.
Yes
The term “non-retail generation” used in Exclusion E1 (item c) and again in E3 (item a) should be
clarified (see comments for question 8 below). The Note after item c should also be clarified to
indicate that closing a normally open switch doesn’t affect this exclusion.
Yes
“A generating unit or multiple generating units that serve all or part of retail customer Load with
electric energy on the customer’s side of the retail meter” sounds a lot like “non-retail generation”
that is used in E1 and E3 which was described in the webinar as generation that resides on the
customer side of the retail meter and is used to supply energy to that customer’s load and is owned
by the customer. Is E2 assuming that this generation is not owned by the customer? Also, part ii)
adds to the confusion. Conceptually we agree with this exclusion but further clarification is preferred.
No
The term “non-retail generation” used in Exclusion E1 (item c) and again in E3 (item a) should be
clarified. The following applies to E3 (item c): A flowgate should not be used to limit applicability of
E3. First, there is no definition for what constitutes a permanent flowgate. Second, flowgates are
often created for a myriad of reasons that have nothing to do with them being necessary to operate
the BES. While section c) in E3 attempts to limit the applicability to permanent flowgates, there is no
definition for what constitutes a permanent flowgate particularly since no flowgate is truly permanent.
The NERC Glossary of Terms definition of flowgate includes flowgates in the IDC. This is a problem
because flowgates are included in the IDC for many reasons not just because reliability issues are
identified. Flowgates could be included to simply study the impact of schedules on a particular
interface as an example. It does not mean the interface is critical. As an example, it could be used to
generate evidence that there are no transactional impacts to support exclusion from the BES.
Furthermore, the list of flowgates in the IDC is dynamic. The master list of IDC flowgates is updated
monthly and IDC users can add temporary flowgates at anytime. While the "permanent" adjective
applied to flowgates probably limits the applicability from the “temporary” flowgates, it is not clear
which of the monthly flowgates would be included from the IDC since they might be added one month
and removed another. Flowgates are created for many reasons that have nothing to do with them
being necessary to operate the BES. First, flowgates are created to manage congestion. The IDC is
more of a congestion management tool than a reliability tool. FERC recognized this in Order 693,
when they directed NERC to make clear in IRO-006 that the IDC should not be relied upon to relieve

IROLs that have been violated. Rather, other actions such as re-dispatch must be used in conjunction.
Second, flowgates are used as a convenient point to calculate flows to sell transmission service. The
characteristics of the flowgate make it a good proxy for estimating how much contractual use has
been sold not necessarily how much flow will actually occur. While some flowgates definitely are
created for reliability issues such as IROLs, many simply are not.
Yes
No
Individual
Martyn Turner
LCRA Transmission Services Corporation
Yes
No
LCRA TSC supports the inclusion of transformers (with both the primary and secondary windings
operated at 100-kV or higher) in the BES definition; however, additional clarification is suggested.
The term transformers needs to be further defined with respect to function (auto transformers, phase
angle regulators, generator step-up transformers, etc.). Similarly, a separate definition for
“Transformer” could be developed and included in the NERC Glossary of Terms.
No
Yes
No
LCRA TSC suggests consistency between this inclusion criteria and the criteria used in I2 for
“generation”.
No
This inclusion conflicts with exclusion E4. Which one takes priority?
No
The current wording is unclear with respect to the treatment of normally open switching devices.
LCRA TSC suggests the following language to replace the existing language on the note to E1: “Two
radial systems connected by a normally open, manually operated switching device, as depicted on
prints or one-line diagrams for example, may be considered as radial systems under this exclusion.”
The current wording is unclear with respect to “non-retail generation”. The sudden loss of large,
radial-supplied load may result in reliability deficiencies. LCRA TSC suggests stating a load level or a
load capacity in the exclusion.
No
Yes
No
This exclusion conflicts with inclusion item I5. Which one takes priority?
Yes
LCRA TSC supports the direction the standards drafting team taking with this project on the BES
Definition and encourages further clarification as noted in these comments for proper application.
Individual
Saurabh Saksena
National Grid
No
While we agree that the BES should not include facilities used in the local distribution of energy, we

feel that this is already captured in Exclusion E3. Stating it in the core definition is confusing, and
should be eliminated. We suggest removing “This does not include facilities used in the distribution of
electric energy” from the core definition.
Yes
Yes
Yes
Yes
We agree with Inclusion I4, however we feel that the inclusion could be interpreted in some different
ways. This inclusion could be interpreted to exclude dispersed generation greater than 75 MVA if the
first common point is less than 100 kV. To eliminate any confusion in the interpretation of this
inclusion, we suggest this wording: Dispersed power producing resources with aggregate capacity
greater than 75 MVA (gross aggregate nameplate rating) connected to a Transmission Element at 100
kV or above, utilizing a system designed primarily for aggregating capacity which includes all
transformers between the generator(s) and the Transmission Element.
No
We see some potential conflicts between this inclusion and the exclusions. Without some additional
wording, it seems like some devices that are in a Local Distribution Network would be considered BES.
In addition, reference to a transformer in Inclusion I1 is not necessary since the definition includes
“all Transmission Elements operated at 100 kV”, thus by definition and I5, those connected to 100 kV
and higher are already included. We suggest: Static or dynamic devices dedicated to supplying or
absorbing Reactive Power that are connected at 100kV or higher unless the device is in an area
excluded from BES by Exclusion E1 or E3, or through a dedicated transformer with a high-side voltage
of 100kV or higher, unless excluded by Exclusion E4.
Yes
Yes
We agree with this exclusion, but the intention of point (i), the net capacity provided to the BES does
not exceed 75 MVA, is not clear. We suggest this wording: “the net capacity provided to the BES for
90% of the hours of the year does not exceed 75 MVA”.
Yes
We agree with Exclusion E3 on local networks, however we suggest this clarification to the first
sentence: A group of contiguous transmission Elements operated at or above 100kV but less than
300kV that distribute power to Load rather than transfer bulk power across the interconnected system
under normal (“all-lines-in”) configuration and conditions. We also suggest the following clarification
to part c, so that the IROLs don’t get overlooked: Not part of Flowgate, transfer path, or an
Interconnected Reliability Operating Limit (IROL). The LN does not contain a monitored Facility of a
permanent Flowgate in the Easter Interconnection, a major transfer path within the Western
Interconnection, or a comparable monitored Facility in the ERCOT or Quebec Interconnection, and is
not a monitored Facility included in an IROL.
Yes
Yes
The proposed implementation period in the draft definition is too short. The new BES definition will
likely result in increased operational costs during the implementation period that will ultimately be
borne by customers. Implicit in the Commission's directive to change the BES definition is the
Commission's determination that the benefits of this change, including consistency among the
regions, outweigh the ratepayer impacts. However, National Grid remains concerned that the
ratepayer impacts have not been fully taken into account. The implementation period is a tool that
can allow NERC to meet the Commission's directive while softening any resulting ratepayer impacts.
Implementation can and should be staged in order to mitigate and even out rate increases. National
Grid suggests that the implementation period be flexible to allow entities who anticipate that large

and/or expensive upgrades to the BES will be necessary to meet compliance can submit an alternate
implementation plan to spread compliance and the associated rate changes over a longer period; we
would suggest a minimum of 7 years. This time period was also recognized as a reasonable
implementation time period in the recent TPL-001-2 for those portions of the standard that would also
result in plans that would require siting, permitting and construction activities. This BES definition is
likely to have similar impacts for some entities and allowing for an implementation timeline with the
definition change enables achievement of the goals while recognizing the realities of constructing
facilities in today's environment.
Group
Louis Slade
EMP & NERC Compliance
Yes
Dominion agrees with the clarifying changes provided that the use of the capitalized terms
“Transmission” and “Elements” mean that an Element that is radial is not part of the BES regardless
of whether it is specifically included in the Exclusions (E1 through E4).
Yes
The proposed changes are much clearer than proposed language in the 1st draft of this BES
definition.
Yes
Dominion interprets the revised language to exclude generating resources connected at less than 100
kV. If this interpretation is not accurate, then Dominion does not support the revised language.
Yes
Yes
No
The language in the last part of Inclusion I5 “….or through a transformer that is designated in
Inclusion I1” introduces ambiguity. Specifically, it is not clear how implememtation of this language
would result in the inclusion of any Static or dynamic device that is not already included. Dominion
suggests that the language in I5 be revised to read “Static or dynamic devices dedicated to supplying
or absorbing Reactive Power that are connected at 100 kV or higher, or connected through a
dedicated transformer with at least one terminal voltage of 100 kV or higher.” Dominion understands
that the SDT intended for this Inclusion to not address generators or power producing resources
because they are covered elsewhere (I2 and I4) and requests that the SDT confirm this
understanding.
No
Dominion does not agree that exclusion of a radial should be based upon the aggregate capacity of
generation. A radial serving only generation should be excluded just as it is for load (as proposed by
the SDT in 1a). No reliability gaps exist since the owner and/or operator of generation (with an
individual with gross individual or gross aggregate nameplate rating per the ERO Statement of
Compliance Registry Criteria) must comply with applicable reliability standards. Dominion requests
that the SDT provide technical justification for E1a and E1b as it did for E3, and explain the intent of
the footnote in E1.
No
Dominion supports exclusion for behind-the-meter generation, (if connected at >100 kV) if the load
behind the meter (to which that generation is intended to support) does not rely on generation
outside that metered point for purposes of back-up energy or any type of ancillary services at any
time. The proposed language appears to suggest that standby, back-up, and maintenance power
services are always required. There are alternative means to provide these services, such as reducing
load to match ‘reliability services’ provided by the available behind-the-meter generation. Further,
even if standby, back-up, and maintenance power services are always required, the exclusion criteria
obligation should be placed on the retail load, not the generation outside the metered point
No
Dominion could support if E3a were eliminated.

Yes
Yes
As a general policy, Dominion believes that attempting to precisely refine the definition of the BES
may not be the best way to insure BES reliability. Instead, industry effort should be focused on
developing specific reliability standard requirements targeted toward solving problems that need to be
addressed. Stated differently, every Element that could have an impact on the BES does not need to
be included in the definition of the BES. NERC’s Functional Model addresses the broad range of
functions performed by the electric utility industry. When reliability concerns are identified and can
best be addressed via a standard, modifying the requirements in that standard as applicable to that
functional model should occur rather than attempting to modify the BES definition. Effort spent on
developing specific reliability standard requirements mentioned above is superior to the industry
engaging in definitional debates that do not address to the underlying reliability drivers. It is not
essential that each reliability standard explicitly apply to each registered entity. The existing reliability
requirements, as applied to the various functional entities require communication of information
necessary to insure there are no reliability gaps, either directly or indirectly among the various
entities. The existing standards typically have a hierarchy wherein: • Planners (PA, TP) receive
information predominately from the owners (GO, DP, TO) and those that represent end-use
customers (LSE and PSE); • Reliability entities (BA, RC and TOP) receive information predominately
from operating entities (GOP, TOP) and those that represent end-use customers (LSE and PSE); •
Planners provide reliability assessments to Reliability entities (BA, RC and TOP) and receive feedback
on these reliability assessments (including validity of assumptions and result); and • Reliability
entities (BA, RC and TOP) give instructions (including when necessary directives) to operating entities
(GOP, TOP) and those that represent end-use customers (LSE and PSE). This is how the industry has
historically operated, how it operates today and why the standards in place today are structured as
they are. Reliability is best served when the standards themselves contain the appropriate
requirements and are applied to either an Element or Facility or to the appropriate functional entity
(DP, GO, GOP, LSE, TO, TOP, etc.). Definitional boundaries can create the potential for false positives
in reliability and, in fact, may be detrimental to reliability in the longer term if they impose additional
compliance burdens without closing a reliability gap.
Individual
Jennifer Flandermeyer
Kansas City Power & Light Company
No
There is no established basis for the generation thresholds referenced through the ERO Statement of
Compliance Registry Criteria in Appendix 5B and the specificity of 75 MVA in the proposed BES
definition. The objectives identified in the Phase 2 SAR for the definition of the Bulk Electric System
include establishing an engineering basis for the generation thresholds. Phase 2 will be critical in
refining and improving the Bulk Electric System definition and bringing additional clarity to the
definition.
Yes
No
Nameplate rating of the generator is not a reflection of what can be actually injected into the
transmission system with resulting electrical impacts on transmission loading and behavior.
Recommend the BES definition be based on a generators established net accredited generating
capacity instead of what it could do by nameplate rating. In addition, many generators do not achieve
their nameplate rating due to limitations imposed by the limitations and capabilities of their
turbine/boiler capabilities. Using the nameplate rating will not allow the exclusion of some generators
that should be excluded. Recommend the following language: Generating resource(s) with a net
accredited capability per the ERO Statement of Compliance Registry Criteria and including the
generator terminals through the high-side of the step-up transformer(s), connected at a voltage of
100 kV or above.
Yes

No
It is not clear that it is the injection at the collection point that is the defining point for the injection.
Nameplate rating of the generator is not a reflection of what can be actually injected into the
transmission system with resulting electrical impacts on transmission loading and behavior.
Recommend the BES definition be based on a generating resource(s) established net accredited
generating capacity at the common point instead of what it could do by nameplate rating that may
not be achievable. Recommend the following language: Dispersed power producing resources utilizing
a system designed primarily for aggregating capacity connected through a common point at a voltage
of 100 kV or above with aggregate net accredited capacity at the common point of greater than 75
MVA.
Yes
No
Nameplate rating of the generator is not a reflection of what can be actually injected into the
transmission system with resulting electrical impacts on transmission loading and behavior.
Recommend the BES definition be based on a generating resource(s) established net accredited
generating capacity instead of what it could do by nameplate rating that may not be achievable.
Recommend the following change to the b) and c) parts of E1: b) Only includes generation resources
not identified in Inclusion I3 with an aggregate net accredited capacity less than or equal to 75 MVA.
Or, c) Where the radial system serves Load and includes generation resources not identified in
Inclusion I3 with an aggregate net accredited capacity of non-retail generation less than or equal to
75 MVA.
No
Any facilities that are customer owned regardless of size or configuration are not under the
jurisdiction or responsibility of the Registered Entity and should not be considered as included with a
Registered Entity.
No
Although the Technical Justification Local Network guidance document is helpful in explaining the
principles and concepts involved with determination of what constitutes a Local Network, criteria
needs to be established regarding the impacts of LODF and PTDF that will clearly define what
constitutes a Local Network to avoid debate and controversy.
Yes
No
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
Yes
Yes
Yes
Yes
Yes
Yes
Yes

Yes
Yes
Yes
No
Group
Mark Conner
Bill Middaugh
Yes
We believe that the new definition is a good clarification.
Yes
No
1. The parenthetical phrase regarding the ERO SCRC is not clear. Is the intent that the inclusion
applies to any generating resource that is required to register as a Generator or Generator Operator
per the ERO SCRC? Or was a reference to the 75 MVA threshold inadvertently omitted? It also seems
that it wouldn’t need to be in parentheses, just make it a phrase in the sentence. 2. The wording of
the sentence after the parenthetical phrase is also worded awkwardly. Suggest changing it to
“including the generator terminals and all electrical equipment up to and including the high side of
generator step up transformers, if they are connected at a voltage of 100 kV or higher.
Yes
Yes
No
There should be a limitation on what reactive components needs to be included. The limits could be
based on capacity of the units or on the voltage step that occurs upon switching of the device.
Yes
Yes
No
1. b) should be reworded to “Normally there is power flow only into the LN: The LN is not normally
used to transfer power originating outside of the LN for delivery through the LN.” There could be
conditions inside the LN, such as large loads shut down for maintenance, which would allow the
parallel transmission Elements to allow power to flow through the LN. Those conditions would have no
negative or adverse effect on the BES. 2. Capitalize “Network” at the beginning of the Exclusion.
Yes
No
Group
David Thorne
Pepco Holdings Inc
Yes
Yes

No
The definition should not reference the ERO Statement of Compliance Registry Criteria; rather the
actual generation threshold criteria should be listed in the definition itself. This way the definition can
stand on it’s own without having to refer to another document for applicability. Also, the wording
should be changed to read “including the generator terminals through the high side of any dedicated
generator step-up transformer(s), connected at a voltage of 100kV or above.” Otherwise, the present
wording could ensnare distribution facilities (similar to the cranking path argument in I3) if a 21 MVA
generator was connected on a distribution line with no dedicated generator step-up transformer. In
that case the distribution line and substation feeder transformer might be construed to be in scope.
Yes
Agree with the SDT decision to delete the inclusion of Black Start Cranking Paths.
No
The SDT reworded Inclusion I4 to use the phrase “utilizing a system designed primarily for
aggregating capacity”. This was to address a concern that the previous definition could ensnare
distributed generation or small generators in a distribution system. We agree with the intent of this
modification. I4 was intended solely to address wind and solar farms that use a collector system to
aggregate their capacity. Therefore, to provide better clarity on the intent of this Inclusion, perhaps it
would be better to specifically mention these examples in the wording: “Dispersed power producing
resources (such as wind and solar farms, etc.) which utilize a system designed primarily for
aggregating capacity, where the capacity is greater than 75MVA (gross aggregate nameplate rating)
and the facility is connected at a common point at a voltage of 100kV or above.”
No
Agree in principle. However, the last phrase “or through a transformer that is designated in Inclusion
I1” is unnecessary, since if the resource were connected through a transformer meeting Inclusion I1 it
would by nature be connected at 100kV or higher.
No
1) Additional clarification is needed on whether certain bus sections supplying radial systems would be
considered part of the BES. It is critical that the BES definition address this issue, since it will define
what transmission Protection Systems fall in scope for PRC-004 & 005. One way to address this issue
would be to add a qualifier to Exclusion E1 that states, “if a radial system is supplied from a bus
section in a substation, then this bus section is considered part of the radial system and is not
considered part of the BES if the tripping of this bus section does not result in an interruption to any
BES facilities when the station is operating in its normal configuration.” 2) Since the SDT deleted the
inclusion of Black Start Cranking Paths in I3 then reference to I3 in criteria E1b and E1c should also
be removed. Limits on connected generation should only be constrained by the 75MVA limit. In
summary, delete the phrase “not identified in Inclusion I3” from both Exclusions E1b and E1c.
Yes
No
1) In the Drafting Teams Consideration of Comments on the previous version, it was stated, “….It is
not the SDT’s intent to specifically exclude any facilities in major metropolitan areas; it expects that
the specific examples mentioned (NYC, Washington DC) would not qualify for exclusion under the
revised Exclusion E3.” The currently proposed E3 will result in specific exclusion of major local
networks in major metropolitan areas. These major LNs qualify for exclusion under proposed E3, and
its qualifiers, in that they distribute power to the local load rather than act as facilities to transfer bulk
power across the interconnected system. However, the LNs that supply large amounts of load in very
dense load areas should have some transmission reliability considerations. To capture the appropriate
LNs in question, consideration should be given to limiting the amount of load supplied by a LN to
some load level. For example if an LN has a peak load level of less than 1,000MVA it would qualify for
LN exclusion and if it exceeds 1,000MVA it would not qualify for exclusion. There are certainly many
LNs that supply relatively small amounts of load, just as radial facilities. They should be excluded. It
is important to develop a load level that would provide the proper balance between the small LNs and
the major LNs. 2) Since the SDT deleted the inclusion of Black Start Cranking Paths in I3 then
reference to I3 in criteria E3a should also be removed. Limits on connected generation should only be

constrained by the 75MVA limit. Therefore E3a should then read “Limits on connected generation: The
LN and its underlying Elements do not include generation resources with an aggregate capacity of
non-retail generation greater than 75 MVA (gross nameplate rating);”
Yes
Yes
1) From the proposed BES definition and Exclusion E1 it is very clear that a 138-12kV distribution
transformer serving radial load would not be considered part of the BES. However, suppose this
transformer was connected to a position in a ring-bus or a breaker-and-a-half arrangement. Would
the physical bus between the transformer high side terminals and the two breakers in the ring-bus, or
breaker-and-a-half-bus, be considered part of the BES? They would be contiguous transmission
elements (bus) operating at 138kV and supplying a radial distribution transformer. Also, tripping of
this “radial” bus section would not interrupt any BES facilities, due to the station bus arrangement. As
such, by definition and Exclusion E1 this 138kV bus section (element) would not be part of the BES,
and no special exclusion filing would be required. Is this correct? However, take the same 138-12kV
transformer but this time connected in a typical line-bus arrangement. The transformer by definition
is not a BES element. As was the case above, the bus section between the transformer and the two
breakers in the line-bus would be contiguous elements (bus) operating at 138kV and supplying a
radial distribution transformer. Again, by definition and Exclusion E1 this bus section (element) would
not be part of the BES. However, in this case tripping of the “radial” bus section would result in an
interruption to the through path of the station, and could therefore interrupt the through flow on BES
facilities. Does this make either the transformer, or its associated bus section, or both part of the
BES? Based on the above examples, if the type of bus connection could influence whether an element
is included in the BES or not, then additional language needs to be added to the definition (either as
an Inclusion or Exclusion) to make this point clear. The BES definition needs to be specific enough to
eliminate any confusion as to what is included, and what is not included, and thereby greatly
minimize, if not eliminate, the need to request interpretations. A sample FAQ document, with
examples, would be extremely helpful, but should not be a substitute for a BES description which
leaves little room for interpretation. 2) As seen from the above attempt to describe issues that need
clarification, without a diagram to show specific situations, it is difficult to fully explain the concerns
on ensuring that the BES definition stands on its own. Since the commenting process does not
accommodate diagrams, PHI is sending separately a white paper with diagrams in an attempt to
clarify the definition and make it as unambiguous as possible, leaving little room for interpretation.
This paper may be helpful in developing a FAQ document. 3) The definition should state that it applies
to a system “normal” configuration. It does not include maintenance or N-1 or any abnormal
configurations. 4) There was no place on the comment forms to comment on the proposed
Implementation Plan for the BES definition. So comments are included here. The proposed plan states
“compliance obligations for Elements included by the definition shall begin 24 months after the
applicable effective date of the definition." This is fine for most applications; however, there is an
effect with PRC-005 compliance. PRC-005 (Protection System Maintenance Standard) requires that
evidence for the last two maintenance intervals, in order to demonstrate that you are following the
prescribed intervals in your maintenance plan. If additional facilities are brought into scope by the
new BES definition, and the protection systems associated with these facilities were not previously
maintained on the same interval as other BES facilities, then it may not be possible within the allotted
24 months to demonstrate the facilities were maintained within the prescribed intervals for BES
facilities. An implementation plan at least as long as one full maintenance cycle would be required to
assure compliance. This issue needs to be addressed or coordinated with PRC-005.
Group
Cynthia S. Bogorad
Transmission Access Policy Study Group (please see www.tapsgroup.org for a list of TAPS' more than
40 members)
Yes
TAPS appreciates the SDT’s work on this project. For the most part, TAPS supports what it believes to
be the intent of the proposed language. The proposed specific exclusion of facilities used in the local
distribution of electric energy is appropriate and consistent with Section 215 of the Federal Power Act.
However, we have one suggestion to better carry out what we believe to be the SDT’s intent. The SDT

proposes to change the core generation definition from the prior version’s “…Real Power resources as
described below, and Reactive Power resources connected at 100 kV or higher unless such
designation is modified by the list shown below,” to “Unless modified by the lists shown below, ...
Real Power and Reactive Power resources connected at 100 kV or higher....” Because of this change
from “as described below… unless… modified by the list shown below” to simply “unless modified by
the lists shown below,” the proposed core definition now has the effect of including all generation,
regardless of size, that is connected at over 100kV. We do not think this is the SDT’s intent. For the
same reason, the core definition now has the effect of including all Reactive Power resources
connected at over 100kV, including generators; Inclusion I5, which includes “[s]tatic or dynamic
devices dedicated to supplying or absorbing Reactive Power,” does not alter the core definition’s
inclusion of all Reactive Power resources connected at over 100kV (whether “dedicated” or not). The
most straightforward solution to this problem is to simply delete Real and Reactive Power resources
from the core definition, so that such resources are instead handled entirely in the Inclusions. The
core definition would thus read: “Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher. This does not include facilities used in the local distribution of electric
energy.”
Yes
TAPS supports the intent of proposed Inclusion I2. For the sake of clarity, we suggest revising “per
the ERO Statement of Compliance Registry Criteria” to “as described in the ERO Statement of
Compliance Registry Criteria.”
Yes
We recommend clarifying that the dispersed power resources covered by this inclusion do not include
generators on the retail side of the retail meter. Specifically, we recommend that the Inclusion read:
“Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) utilizing a system designed primarily for aggregating capacity, connected at a
common point at a voltage of 100kV or above, but not including generation on the retail side of the
retail meter.”
Yes
Yes
TAPS supports the exclusion of radial systems from the BES Definition. Such systems are generally
not “necessary for operating an interconnected electric transmission network,” the standard in Orders
743 and 743-A. We have several suggestions to clarify the proposed language for this Exclusion.
Proposed Exclusion E1 refers to “[a] group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher.” We appreciate the SDT’s clarification of the point of
connection requirement, but the term “a single point of connection” should be further defined (more
clearly than just by voltage), and should be generic enough to encompass the various bus
configurations. It is not the case, for example, that each individual breaker position in a ring bus is a
separate point of connection for this purpose; in that situation, a bus at one voltage level at one
substation should be considered “a single point of connection.” Some examples of configurations that
should be considered a single point of connection for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf, Examples 1-6.
Although the core definition (appropriately) refers to “Transmission Elements” (with a capital “T”),
proposed Exclusion E1 refers to “transmission Elements” (with a lowercase “t”). To avoid confusion,
either “Transmission” should be capitalized in both locations, or the word “transmission” should
simply be deleted from Exclusion E1, leaving a “group of contiguous Elements.” We understand that
the lack of capitalization may have been a deliberate choice by the SDT in an attempt to avoid
confusion that SDT members believe exists in the Glossary definition. If the Glossary definition of
Transmission is unclear—which TAPS does not necessarily believe is the case—the answer is not to
simply abandon the Glossary definition in favor of an entirely undefined term; it is to submit a SAR to
improve the Glossary definition. Exclusion E1(c) refers to “an aggregate capacity of non-retail
generation less than or equal to 75 MVA.” “Non-retail generation” is potentially ambiguous, because it
could be read as distinguishing between generation that will be sold at wholesale and generation that
is used by the retail provider to meet retail load. On the understanding that the intent is in fact to

describe generation behind the end-user meter, sometimes referred to as “behind-the-second-meter
generation,” we suggest the following revision: “an aggregate generation capacity less than or equal
to 75 MVA, not including generation on the retail customer’s side of the retail meter.” Exclusion E1
concludes with a “Note”: “A normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion.” The Note should not specify
the types of evidence required to prove a normally open switch, and the phrase “as depicted on prints
or one-line diagrams” should be deleted. This phrase is equivalent to a “Measure” in a standard and
should not be embedded in the equivalent of a “Requirement.” Since the phrase only gives an
“example,” it does not in fact add anything to the Note, but may lead to confusion over what sort of
evidence is required. If the phrase remains in the Note, it should at minimum be better explained: “A
normally open switching device between radial systems, as depicted on prints or one-line diagrams
used in the normal course of business for example, does not affect this exclusion.” In addition, while
we believe the SDT’s intent is that two otherwise radial lines connected to each other by a normally
open breaker are both excluded, the statement that a normally open switching device “does not affect
this exclusion” is unclear. We suggest that the note be modified to state that a normally open
switching device “does not prevent this exclusion from applying,” or words to that effect.
Yes
Yes
TAPS supports the exclusion of Local Networks from the BES. Such systems are generally not
“necessary for operating an interconnected electric transmission network,” the standard in Orders 743
and 743-A. We have several suggestions to clarify the proposed language for this Exclusion. TAPS’
comments in response to Question 7 above regarding “points of connection at 100kV or higher” and
“non-retail generation” are applicable to Exclusion E3 as well. The term “bulk power,” which occurs
twice in Exclusion E3, is vague and could be read incorrectly as a reference to the statutorily-defined
“bulk-power system,” which is not, we think, the SDT’s intent. The word “bulk” should be deleted, so
that the Exclusion simply refers to transferring “power” across the interconnected system. TAPS
raised this concern in response to the last posting of the BES Definition. In response, the SDT
removed some instances of “bulk power” but left the remaining two, stating that “the SDT believes it
provides conceptual value to the exclusion principle.” The SDT does not state what conceptual value
the term is intended to provide; on the assumption that it relates to a distinction between transferring
power from local generation to serve local load, and transferring power over longer distances, TAPS
suggests, as an alternative to simply deleting the word “bulk,” that the Exclusion be revised to refer
to “transfers of power from non-LN generation to non-LN load.” Exclusion E3(c) states: “Power flows
only into the LN: The LN does not transfer energy originating outside the LN for delivery through the
LN.” This statement is unclear because the two parts mean different things. TAPS proposes rewriting
this sentence to state: “Power flows only into the LN, that is, at each individual connection at 100 kV
or higher, the pre-contingency flow of power is from outside the LN into the LN for all hours of the
previous 2 years” to help clarify the intent. Two years is suggested because it is the time period set
out in the draft exception application form for which an applicant should state whether power flows
through an Element to the BES.
Yes

Individual
Joe Tarantino
Sacramento Municipal Utility District
Yes
In an effort to avoid potential confusion and provide clarity we believe the following sentence “This
does not include facilities used in the local distribution of electric energy” more appropriately fits
under the “exclusions,” rather than “inclusions,” section.
Yes
We believe additional clarification of transformers that are to be included may be achieved with
respect to auto transformers, phase angle regulators and generator step-up transformers by adding
the following recommended sentence: “All transformers (including autotransformers, voltage

regulators, and phase angle regulators) with primary and secondary terminals operated at or above
100kV, unless excluded by E1 or E3.”
No
We recommend removing the reference of the ERO Statement of Compliance Registry Criteria
(Registry Criteria). The BES Definition should be the governing document and independent of ERO
registration requirements. The definition should drive what appears in the Registry Criteria.
Additionally, we support using the BES Phase 2 technical analysis to identify and provide technical
support for determining the appropriate minimum MVA rating that a single unit, or the aggregation of
multiple units, must meet to be considered part of the BES.
Yes
We recommend rewording Inclusion I3 as follows: “Only Primary Blackstart resources designated as
part of the Transmission Operator’s restoration plan.” We have concerns that making all Blackstart
generation either primary or secondary BES elements will create an incentive to remove those
secondary Blackstart capable units in order to avoid BES inclusion. Making the primary Blackstart unit
the only BES element will remove this incentive. In so doing, this will allow the secondary Blackstart
units to remain in the Transmission Operator’s plan and training program as an alternate tool for the
Transmission Operator to restore the system.
Yes
We support using the BES Phase 2 technical analysis to identify and provide technical support for
determining the appropriate minimum MVA rating that the aggregation of multiple units must meet to
be considered part of the BES. We also support using the Phase 2 studies to identify an appropriate
minimum MVA level that a single unit of the aggregation of multiple units must be considered BES.
Yes
However, appropriate MVAr level should be established. Reactive resources should be treated similar
to generation criteria and included in the technical studies associated with the Phase 2 technical
analysis in order to establish the appropriate MVAr level included as BES.
Yes
For the E1 reference “Note,” we would benefit from additional clarification identifying the treatment of
a normally open switch and offer the following: “Radial systems shall be assessed with all normally
open switching devices in their open positions.” The wording in Exclusion 1-c should more clearly
reflect what is intended by using the term “non-retail generation.” Also, as with the technical
justification for Inclusions I2 and I4, it is recommended that the generation threshold, i.e. gross
nameplate values, be deferred to Phase 2.
Yes
It is preferred to hold reference to gross nameplate rating/threshold values until generation technical
justification is completed as part of Phase 2; these studies should apply to any real or reactive power
threshold reference. For Exclusion E3-b using the phrase “[p]ower flows only into the LN” is too
restrictive. An allowable MW threshold of LN power producing resources should be deferred to the
Phase 2 BES technical analysis. Where no generation is present in the LN, it is recommended that an
allowance for residual flow through the LN.
Yes

Group
John P. Hughes
Electricity Consumers Resource Council (ELCON)
Yes
However, one of the FERC directives in Order 743 charged NERC with delineating the difference
between transmission and distribution. The Inclusions and Exclusions are a step in that direction, but
this subject will need more consideration in Phase II.
Yes

No
Since an aggregate of 75 MVA is allowed at a single site, there is no basis for maintaining the 20 MVA
for a single generator. The proposed MOD-026 assigns thresholds by region that are much higher
than 20 MVA for modeling purposes. Since modeling generally would require more granularity than
what is necessary for the reliable operation of the interconnected transmission system (BES), the SDT
might want to review the threshold basis for NERC Project 2007-09 (Generator Verification). It is
understood that the threshold will be reconsidered in Phase II of the BES Definition Project; however,
a modest change from 20 to 75 MVA seems appropriate on an interim basis justified by the current 75
MVA aggregate per site. The following phrase should be added at the end “unless excluded under
Exclusion E2.”
Yes
Yes
The term “dispersed power” and “dispersed generation” are often synonymous with distributed
generation, which includes behind-the-meter generation (CHP). The Inclusion should be clarified by
specifically referencing wind and solar, or adopt the FERC term “Variable Energy Resources.” Also, to
distinguish this Inclusion from Inclusion I2, the SDT might want to clarify that the collection system
(usually at voltage below 100 KV anyway) is not part of the BES—just the resources and any
transformers included by I1, if this is indeed the intent of this Inclusion. The following phrase should
be added at the end “unless excluded under Exclusion E2.”
Yes
Yes
ELCON supports the changes made from the first posting for both E1 and E3 (which complements E1),
as this will help maintain the status quo referred to in the introductory text. We seek one clarification:
Some large industrial customers that operate in remote, rural locations provide distribution services
to third parties (usually on a pro bono basis) where the local utility (LSE) is unable or unwilling to
serve. These transactions, which are akin to “border-line sales” in utility parlance, are typically de
minimis relative to the Load of the entity that delivers the power. While the distribution is at low
voltages (less than 100 kV), the power may have been received by the entity at a higher voltage. We
seek affirmation by the SDT that such situations are not precluded by Exclusion E1.
Yes
ELCON supports the proposed revisions to Exclusion E2.
Yes
This Exclusion and Exclusion E1 aid in the delineation of local distribution versus transmission. We
suggest three clarifying revisions. First, the phase “but less than 300 kV” should be deleted. Many
large industrial facilities have on-site distribution systems that operate above 300 kV due solely to the
capacity of the lines to supply power over the distance required at the manufacturing sites. Second,
for the same reasons discussed above (in response to question #7), the phrase “do not have an
aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating)” in “a)”
should be changed to “the net capacity provided to the transmission grid does not exceed 75 MVA.”
Third, the introductory phrase in “b)” -- “Power flows only into the LN” -- is inconsistent with the
recognition in “a)” that power may flow out of an LN and into the transmission grid if there is
generation connected to the LN and the 75 MVA limit is observed. We recommend either deleting the
introductory clause or correcting it to read “Power is not transferred through the LN.”
Yes
This is a needed exception to Inclusion I5 as these reactive power resources are used by retail
customers for power factor correction at their own facilities in order avoid imposed power factor
penalties.
No
Individual
Don Schmit
Nebraska Public Power District

Yes
The drafting team has done a great job of adding clarity and to improving the BES definition.
Although more work is needed as noted in comments below, overall the drafting team is on the right
track with the BES defintion.
Yes
No
Inclusion 2 does not take into consideration a later exclusion (Exclusion 3). At the end of Inclusion 2
after the words “..100 kV or above.” Add the words “, unless excluded under Exclusion 3”.
Yes

Yes
However the exclusion needs to be noted in I2, so as to non conflict with I2. (See comment on #2
above.)
No
In E3 (a): please define “non-retail generation” as usued in E3(a). Also, what is the criterion that
makes this genertion BES generation? The MVA rating only, or is there other criteria? A generator
may have a 75 MVA gross nameplate rating, but may be limited physically or electrically to below the
75 MVA. Is this a basis for exclusion for this generator?
Yes
Regarding the Local Network: Can there be some additional technical documents or examples
provided for the most common configurations? The LN document is a good document to provide
guidance, however the supply of common configuration examples would be very helpful in
determining LN applicability. Examples where technical document with examples would be helpful: 1.
If a breaker and a half source substation provides two parallel 115 kV lines feeding a load only
substation from separate breaker and a half legs at the source substation, would the two parallel lines
feeding the load be a LN distribution network feed since theyare from the same source substation? 2.
if there is a radial feed from a ring bus or a breaker and a half configuration to a radial load on a
single line can the portion of the ring bus or breaker and a half bus between the line breakers and the
breakers themselves at the source substation be excluded from the BES? 3. Can some legs of a
115kV breaker and a half substation be disgnated BES and the other legs be non BES depending on
how the BES lines and loads tie in to the breaker and half legs? 4. In determining if elements are BES
is there any consideration to fault locations and if these faults would interrupt BES flow on ring bus or
breaker and a half configurations to help determine what is BES? If so, how many contingencies
would be considered to interrupt BES flow?
Individual
David M. Conroy
Central Maine Power Company
No
The second sentence, “This does not include facilities used in the local distribution of electric energy,”
is vague and not sufficiently clear for northeast industry expert colleagues to be certain of what is
“not included.” This sentence seems to apply only to distribution facilities that have already been
classified based on the FERC “Seven Factor Test” in Order 888. If so, this sentence should be restated
as follows for clarity: “This does not include facilities classified as distribution facilities.” For US
entities, this classification is clearly delineated in our annual FERC Form 1 filing.
Yes
We generally agree, but suggest modification to the language of Inclusion I1 to clarify its application
for transformers with more than two windings: “Transformers with two or more terminals operated at
100 kV or higher, unless excluded under Exclusion E1 or E3.” Based on this wording, transformer

tertiary windings would also be BES – is that the intent?
No
Inclusion I2 should remove the reference to the Statement of Compliance Registry Criteria. The
definition should stand on its own. I2 should be revised to read: “Generators with a gross nameplate
rating of 20 MVA or greater, or a generating plant/facility connected at a common bus, with a gross
aggregate nameplate rating of 75 MVA or greater; and is directly connected at a voltage of 100 kV or
above. BES includes the generator terminals through the high-side of the step-up transformer(s)
connected at a voltage of 100 kV or above.” This is consistent with the proposed I2 and the current
Compliance Registry Criteria.
No
Inclusion I3 should be changed to include the phrase, “material to,” currently in the Statement of
Compliance Registry Criteria (Section 3C3). Based on the definition wording, the Generator Step-Up
transformer (GSU) would not be BES if the generator would not otherwise already be included as BES
under another definition provision.
No
The term “common point” needs clarification and/or definition. (e.g., is it intended to apply to the risk
of single mode failure, where all the resources could be lost for a single event?) Some northeast
industry expert colleagues interpret I2 to mean the collector system itself needs to be 100 kV or
above in order to be BES. I2 seems to not include the collector system itself in BES. I4 should be
restated as follows: “Dispersed power producing resources with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing a collector system connected at a common point.
BES includes the interconnecting substation with the step-up transformer(s) connected at a voltage of
100 kV or above.” [alternatively, replace "interconnecting substation with" with, “generator terminals
through the high-side of” if the entire collector system is intended to be BES] Also note that some
wind collector systems require supplemental dynamic reactive resources or special control system to
met reliability standards. As written, these reactive resources or controls may not be considered to be
BES.
Yes
There is no such thing as “supplying or absorbing Reactive Power” but the intended meaning is
sufficiently clear since it is industry ‘shorthand’. We suggest an alternative wording of: “Static or
dynamic Reactive Power resources that are connected at 100 kV or higher, or…”
No
E1 needs to be revised to make it less confusing. “Radial systems” leaves the impression that E1 is
not simply a “radial line exclusion”, because of the plural and the word “systems.” Northeast industry
expert colleagues are not clear what this sentence specifies: “A group of contiguous transmission
Elements that emanates from a single point of connection of 100 kV or higher.” • Does E1 apply only
to a single radial transmission line (and its associated “group of Elements”)? • Alternatively, does E1
apply to multiple radial lines “emanating from” the same substation regardless of the bus
configuration – would a ring bus or a two-bus system that is connected with a tie breaker be
considered as “a single point of connection”? • If the radial line is simply tapped off a BES line without
any automatic interruption device, should not the radial line be included as part of the BES since a
permanent fault on this radial line will take out the BES line it is tapping off of? If the radial line is
defined as part of the BES, it could be subject to certain requirements such as vegetation
management for overhead lines. • Should not the exclusion include some description of the
operational requirements to help resolve the ambiguity? As it is, the exclusion is scenarios-based.
When a specific scenario is overlooked, the oversight becomes a source of ambiguity. This definition is
not clear. Clarity is imperative. E1(c) should define or replace the term “non-retail”. Industry needs
clarity on exactly what generation this clause applies to, in order to properly apply this definition. The
Note referring to the “Normally Open switch” needs further clarification. As written, it seems to
conflict with FERC order 743, paragraph 55: “While commenters would like to expand the scope of the
term “radial” to exclude certain transmission facilities such as tap lines and secondary feeds via a
normally open line, we are not persuaded that such categorical exemption is warranted.” E1 should be
restated as follows: “Radial systems: A single transmission line or transformer not otherwise identified
in the Inclusions above, with a single point of connection of 100 kV or higher and: a) Only serves
Load. Or, b) Only includes generation resources, not identified in the Inclusions above. Or, c) Both
serves Load and only includes generation resources not identified in the Inclusions above."

No
E2 should be consistent with the Statement of Compliance Registry Criteria. References to Balancing
Authority, Generator Owner, and Generator Operator should not be included in the BES definition.
“Net capacity” is unclear – must flow never exceed 75 MVA on an instantaneous or integrated hourly
energy basis per either design or operating experience? There is a potential for hundreds of MW to be
interconnected at a customer facility, with the “net capacity” (= flow into the transmission system?
Instantaneous? Annual average? On an integrated hourly basis at any hour?) being less than 75 MVA
– are hundreds of MW of generation “not material” to BES reliability? The conditions under which
direction of flow (i.e., “net capacity”) is assessed are critical, but E2(i) is silent on this. In E2(ii), the
“and”, “or”, and “or” are not clear – what are the necessary terms of the referenced “binding
obligation” and what is an “applicable regulatory authority”? Are “standby” and “back-up” and
“maintenance” power services independently defined and provided by a GOP, GO, or BA? Northeast
industry expert colleagues do not understand the relevance of E2(ii) to BES reliability. E2 should be
restated as follows: “A generating unit or multiple generating units that serve all or part of retail
customer Load with electric energy on the customer’s side of the meter if the flow to or from the BES
can never exceeds 75 MVA."
No
“Local Network” is capitalized (network not capitalized at the beginning of E3) throughout E3, yet it is
not defined in the NERC Glossary. This exclusion is vague. This exclusion applies to a network with
“multiple points of connection” with the purpose “to improve the level of service to retail customer
load” – this phrase is intent-based and not reliability-based – most/all transmission “improves
service” compared to it not being there. In essence, this exclusion can be obtained if a portion of the
network: 1. Doesn’t have significant generation (again, “non-retail” phrase is unclear) 2. Power only
flows “into” this portion of the network, and not (ever? Even under any TPL design contingencies?)
“out.” Is this considering only pre-contingency steady state conditions? During contingency conditions
and for the period following a contingency the LN could supply power to other parts of the network
depending on the nature of the contingency. The conditions under which direction of flow is assessed
are critical, but E3(b) is silent on this. 3. This portion of the network is not part of a monitored
transmission interface This “Local Network Exclusion” is supported by a technical analysis which relied
on transmission distribution factors (see
http://www.nerc.com/docs/standards/sar/bes_definition_technical_justification_local_network_20110
819.pdf on the NERC BES Definition standard page http://www.nerc.com/filez/standards/Project201017_BES.html ). This transfer distribution factor (TDF) method was rejected by FERC in Order 743.
Paragraph 85 of the Order states: “Given the questionable and inconsistent exclusions of facilities
from the bulk electric system by the material impact assessment and the variable results of the
Transmission Distribution Factor test proposed in NPCC’s compliance filing in Docket No. RC09-3,
there are no grounds on which to reasonably assume that the results of the material impact
assessment are accurate, consistent, and comprehensive.93 Additionally, we have noted how the
results of multiple material impact tests can vary depending on how the test is implemented.” The
phrase “contiguous transmission elements” is also not clear, especially when qualified as not being
part of a monitored transmission interface. Should the “contiguous transmission elements” comprise a
complete and exhaustive set of contiguous elements? Or can they be a subset of a larger contiguous
set in which the other elements of the larger set are actually part of a monitored interface? Unless E3
is made more specific and clear, it should be stricken.
No
Consider using other wording to replace “retail”
Yes
If the definition and inclusions and exclusions are not sufficiently specific and clear, stakeholders will
flood NERC and RROs with interpretation requests and/or apply the definition and its inclusions or
exclusions incorrectly. Explanatory figures with one-line diagrams should be developed and shared to
illustrate the system configurations included and excluded in a BES Definition. This would be very
helpful for definition clarity. This should be done as part of an “Application Guide” for the BES
Definition – there is precedence for an “Application Guide” with graphical support in CIP-002 version
5. A sample set of one-line diagrams with interpretations based upon the inclusions and exclusions
developed by Northeast Power Coordinating Council members for discussion purposes is available as
an example, but note that there is not a uniform agreement on these diagrams based on the BES
Definition as written, due to lack of clarity.

Individual
Kirit Shah
Ameren
Yes
a)The general concept is sound, but the Inclusion and Exclusion sections create so many circular
references it is virtually impossible to take a definitive stance on whether an asset is included or
excluded to the BES definition. Please revise the inclusion and exclusion criteria to give pinpointed
statements that are final and do not reference other criteria, that then again reference other
criteria.b)We believe that 200kV and above is the appropriate bright line for the Bulk Electric System.
c)In I5, only those Reactive Power devices applied for the purpose of BES support or BES voltage
control should be included. A Reactive Power device connected at >100kV but used for the purpose of
voltage support to local load should not be included. d)The core definition uses "Transmission
Elements" while E1 uses "transmission Elements". What is the difference? If one or both terms are
applicable, their definition should be included.
Yes
Agree in general, but have the following comments:a)We agree in general with the revisions to the
specific inclusions for transformers in I1; however, we believe the transformer voltage level should be
200kV or above. b)The inclusion is unclear since it includes a certain voltage transformers, but
excludes those that have E1 or E3 Exclusion criteria. Each exclusion criteria has multiple stipulations
to its applicability, and then has a final inclusive reference to I3. Please make the wording exact and
not dependent on clausal statements.
No
a)This definition becomes dependent on a document that can be changed without direct correlation to
the BES definition. Remove the reference to the ERO Statement of Compliance Registry Criteria, and
simply state the criteria as currently used. There is no need to look up another definition in another
document to identify what is included in the BES definition. b)All MOD Standards' requirements for
generators should also follow this definition.
Yes
a)The definition should include only those black start generators connected 100 kV and above and
included in the restoration plan. b)We agree with the changes but believe clarity would be added by
changing the word “identified” to “designated”.
Yes
a)For a consistent application, we suggest that the definition of the terms "Dispersed power producing
resources" is included. Consider including some examples also.
No
a)Only those Reactive Power devices applied for the purpose of BES support or BES voltage control
should be included. A Reactive Power device connected at >100kV but used for the purpose of voltage
support to local load and/or needed to support local networks should be excluded. b)We believe that
this inclusion should be limited to dynamic devices with an aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) connected through a common point. c)See the response to
question 2: The inclusion is unclear since it includes a certain voltage transformers, but excludes
those that have E1 or E3 Exclusion criteria. Each exclusion criteria has multiple stipulations to its
applicability, and then has a final inclusive reference to I3. Please make the wording exact and not
dependent on clausal statements.
Yes
a)We suggest the wording “non-retail generation’ should be clarified with an explanation of why it is
used in this exclusion. b)This exclusion criterion has multiple stipulations to its applicability, and also
has a final inclusive reference to I3. Please make the wording exact and not dependent on clausal
statements.
No
a)If retail generation fails to meet (i) or (ii) it appears that the retail generation would be included.
The wording of (ii) is complex. Who will police this with retail behind-the-meter generators?
b)Clarification needs to be provided for what is meant by E2 (ii), regarding generation on the
customer’s side of the retail meter; otherwise we have trouble developing a position on this question.

No
a) The exclusion should also be extended to reactive resources needed to support the local area
network (see response to Q10). It is also suggested that “local network” be renamed to “local area
network” to better describe or distinguish itself from a wide-area network such as the BES. b)We
would agree with the exclusion if the wording of the exclusion includes the following phrase (in italics)
added at the end of E3 b): Power flows only into the LN: The LN does not transfer energy originating
outside the LN for delivery through the LN “under normal operating conditions”.
No
a)Reactive Power devices connected 100 kV and above applied for the purpose of voltage support to
local load and/or local area network should also be excluded.
Yes
a)We believe this revised definition is an improvement over the previous posting, a step in the right
direction. b)The definition of the BES is referenced in several existing standards and the Statement of
Compliance Registry Criteria. Our concern is how this revised definition will impact entity registration,
i.e., how will the revised definition be integrated into the Compliance Registry Criteria. The
implementation plan should include how the integration is going to occur. The Rules of Procedure
exception process should be further defined or referenced in this definition. c)See Question 1
response: The general concept is sound, but the Inclusion and Exclusion sections create so many
circular references it is virtually impossible to take a definitive stance on whether an asset is included
or excluded to the BES definition. Please revise the inclusion and exclusion criteria to give pinpointed
statements that are final and do not reference other criteria, that then again reference other criteria
Group
William D Shultz
Southern Company Generation
No
We have two concerns with the changes that are proposed. First, the use of "effective dates" and
"compliance obilgations ... shall begin" in the implementation plan of the definition change is
confusing. Effective date is usually used to indicate the mandatory and enforceable date of a new
item. Second, a radial circuit from 100kV to a generating facility with two (2) 20 MVA generators
seems to meet both the inclusion criteria (I2) and the exculsion criteria (E1). Which criteria is
dominant, inclusion or exclusion?
Yes
Yes
Yes, provided that the minimum gross individual nameplate rating threshold is the same as the gross
aggregate nameplate rating (currently > 75MVA). The MVA ratings are specified in many places in the
BES definition, where a reference is made in I2 to using the Statement of Compliance Registry
Criteria. We believe that the BES definition should point to the Statement of Compliance Registry
Criteria and not include MVA values. We also believe individual units < 75MVA should be excluded
unless they have been shown to be critical to BES reliability through a technical justification study
performed by the transmission planning authority.
Yes
Yes
Yes
We believe that the size of the reactive power resource should be considered as a key factor to be
part of BES. When considering generating resources, the size, e.g., greater than 75 MVA, was a key
part of criteria to be included or excluded as BES. A similar approach should be applied when
considering reactive power resources. Moreover, the language at the end of I5, "or through a
transformer that is designated in Inclusion I1," appears to be redundant since the reactive power
resources are connected to 100 kV or higher already without this additional language. The following
language is suggested: I5 - Static or dynamic devices dedicated to supplying or absorbing Reactive
Power that are connected at 100 kV or higher, or through a dedicated transformer with a high-side

voltage of 100 kV or higher, and with an aggregate continuous nameplate rating greater than 30
MVA.
No
Subpart (b) uses the term "generation resources" while subpart (c) uses the term "non-retail
generation", why are these different terms used? Further, why is it important that the term "nonretail generation" is used in subpart (c)? In addition, the SDT needs to clarify what the term "nonretail generation" means. Is this what is commonly referred to as "customer owned" or "behind-themeter" generation? The change in version 2 that removed the requirement that an excluded radial
system have an automatic interruption device at the single point of connection to the rest of the BES
creates a problem. Three-terminal circuits are common below 230 kV. The "tapped portion" should
not be left out of the BES since a fault on that portion takes out the whole line. We propose this
revised language in the first sentence on E1: “E1 - Radial systems: A group of contiguous
transmission Elements that emanates from a single point of connection of 100 kV or higher, where
the connection has an automatic interruption device,…” Exclusion E1, subpart (c) uses the phrase "an
aggregate capacity of … less than or equal to 75 MVA …". Exclusion E3. subpart (a) provides that the
local networks "do not have an aggregate capacity of … greater than 75 MVA …". Why are these
phrases stated differently even though they appear to address the same resources?
Yes
Some editing is needed. The second part, (ii), of the and logic provided for the exclusion criteria E2 is
confusing. The initial criteria, (i), seems to be adequate regarding impact to the BES. The criteria
listed after "(ii)" does not seem to be relevant to the impact on the BES. What does it mean to
provide standby, back-up, and maintenance power services to a generating unit or multiple
generating units? It is unclear who is providing the power service. If this is needed, the statement
needs to be simplified so it can be understood. What is the difference between the terms "retail Load"
and "retail customer Load" as used in Exclusions E2 and E3?
Yes
What does the term "non-retail generation" mean? Can the term "non-retail generation" in E3a be
changed to simply "generation."
Yes
Yes
1) On page 1, the year of the anticipated date for the BOT adoption is correctly 2012. 2) We believe
that the last two sentences of the first paragraph of the Background Information section of the 2nd
draft of the definition document is incorrect. The statements read: " It should be noted that the
revised definition does not address functional entity registration or standards requirements
applicability. Those are separate issues." The definition of the BES that is approved will govern the
scope of the equipment that is relevant to many of the reliability standards. This issue cannot be
separated from the applicability of the requirements of the reliability standards. What is the purpose
of creating a continent wide definition of the BES if is is not to provide instruction the enetties subject
to the requirements of the standards? Refer to these sample standard requirements to see that this
definition already plays a major part in the applicability of the requirements: EOP-005-2 R1, R4; EOP006-2 R1; EOP-008-1 R1; FAC-008-1 R1.2; and PRC-005-1a for example - there are many others.
Individual
Guy Andrews
Georgia System Operations Corporation
Yes
Yes
Yes
Yes

Yes
Yes
Yes
Yes
No
Item (b) is unclear: Although the first sentence says “Power flows only into the LN,” which suggests
there will be no exports, the second sentence says “The LN does not transfer energy originating
outside the LN for delivery through the LN,” which suggests it could deliver power originating within
the LN. This would seem to be reasonable by comparison to E-2, so long as no more than 75 MVA is
exported (which is indeed the limitation on the quantity of “non-retail generation” in the LN). On a
related point, if the limit on connected generation is not intended to be a limit on possible exports,
and therefore any power from interconnected non-retail generation must be sold within the LN, why
does the limit need to be so low; why should the aggregate quantity of such internally-consumed
generation be an issue? Also, is the “non-retail” designation intended to exclude customer-owned
generation from the 75 MVA calculation?
Yes
No
Group
Brandy A. Dunn
Western Area Power Administration (Corporate Services Office)
Yes
Yes
Yes
Yes
No
Need to clarify the systems associated with this inclusion. The phrase “dispersed power producing
resources” in inclusion (I4) is confusing and does not clearly communicate the focus of this inclusion.
Without reviewing the reference information provided in the 1st draft comment form, it’s not clear
that dispersed power producing resources refer to wind and solar resources. Recommendation:
Include examples after phrase “dispersed power producing resources” for clarification to this
inclusion. Change I4 to read - Dispersed power producing resources (i.e. wind and solar resources)
with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system
designed primarily for aggregating capacity, connected at a common point at a voltage of 100 kV or
above.
No
This inclusion should be worded to only include static or dynamic reactive devices which are necessary
to meet the NERC Planning Criteria in terms of normal and post-disturbance voltage profiles. We
shouldn't have to include smaller shunt cap banks and reactors which are used primarily for voltage
support (not voltage collapse). Recommendation: Change I5 to read - Static or dynamic devices
dedicated to supplying or absorbing Reactive Power which are necessary to meet the NERC Planning
Criteria in terms of normal and post-disturbance voltage profiles that are connected at 100 kV or
higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through a

transformer that is designated in Inclusion I1
Yes
Yes
Yes
Yes
Yes
Yes, the definition should also provide clarification on mobile equipment installed to support
maintenance or equipment failures. Adding mobile equipment is a common practice for our industry
and should be addressed in the definition to bring a general awareness and common understanding of
the practice regarding the NERC standards. Recommendation: Add the following Exclusion to BES
definition for mobile equipment. Exclude all mobile equipment on stand-by that has not been placed
into service as well as all components of mobile equipment that does not meet the inclusion criteria
for the primary function of the device being installed (e.g. ,battery bank on mobile transformer
installed on radial feed would also be excluded)
Individual
Scott Miller
MEAG Power
Yes
MEAG agrees to the clarifying changes to the core definition in general, however, we maintain that
200kV and above is the correct bright line for the BES.
Yes
We agree in general with the revisions to the specific inclusions for transformers in I1; however, we
believe the transformer voltage level should be 200kV or above.
Yes
We agree in general with the revisions to I2 for generation; however, we maintain that 200kV and
above is the correct bright line for the Bulk Electric System.
No
We agree with the changes but believe clarity would be added by changing the word “identified” to
“designated”.
Yes
No
We feel that this inclusion should be limited to dynamic devices with an aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) connected through a common point.
Yes
We suggest the wording “non-retail generation’ should be clarified with an explanation of why it is
used in this exclusion.
No
Clarification needs to be provided for what is meant by E2 (ii), regarding generation on the
customer’s side of the retail meter; otherwise we have trouble developing a position on this question.
No
We would agree with the exclusion if the wording of the exclusion includes the following phrase (in
italics) added at the end of E3 b): Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN “under normal operating conditions”.
Yes
Yes

The definition of the BES is referenced in several existing standards and the Statement of Compliance
Registry Criteria. We are concerned how this revised definition will impact entity registration, i.e., how
will the revised definition be integrated into the Compliance Registry Criteria. The implementation
plan should include how the integration is going to occur.
Group
David Dockery or John Bussman
AECI
Yes
In general, we agree with this revision. We however believe the correct voltage thresholds to be,
transformer primary voltage of 200 kV or higher and secondary voltage of 100 kV or higher.
No
“100 kV or above” should be modified to “200 kV or above with a registered rating of 150 MVA or
greater.”
Yes
The word “identified” should be replaced with “designated”.
Yes
In general, we agree with this revision. However, the aggregate MVA threshold should be 150 MVA or
greater, and threshold voltage level should be 200kV or higher.
Yes
This inclusion should be limited to reactive devices 150 MVAR or greater (gross aggregate nameplate
rating) connected through a common point at the 200 kV level or higher level.
Yes
This inclusion should be limited to reactive devices 150 MVAR or greater (gross aggregate nameplate
rating) connected through a common point at the 200 kV level or higher level.
Yes
Remove “non-retail” because it is irrelevant to reliability. In general, we agree with the remaining
concepts. However transformer voltage threshold should be 200 kV or higher, the power thresholds
should be 150 MVA or greater.
Yes
E2 “retail meter” should read “retail meter(s)”. (i) Should be reworded as “the maximum net impact
to the BES does not exceed 150 MVA, connected at 200 kV or higher.” (ii) if we understand this
clause correctly, we believe our proposed (i) wording will handle the issue. Also, all load’s inclusion,
within a BA, is dictated within the BAL standards and so remove entirely or additional clarification is
needed.
Yes
We would agree in principle with the LN exclusion if the wording of the exclusion includes the
following phrase (in italics) added at the end of E3 b): Power flows only into the LN: The LN does not
transfer energy originating outside the LN for delivery through the LN “under normal operating
conditions”. Also, the correct BES threshold level should be 200 kV rather than 100 kV. Finally, the
nomenclature of Flowgate (FG) components appears to be confused. AECI believes E3 c) should be
changed to read “contingent Facility” rather than “monitored Facility”. Although unspecified within the
NERC Glossary, we believe FG monitored Facilities are typically the impacted facilities in danger of
overload, while the contingent facilities are those which, if lost, would cause the monitored Facility to
become overloaded. As currently written, a formerly qualified LN could later become disqualified due
to an external entity’s ill-designing a parallel EHV line, thereby causing one or more potential (N-1)
overloaded Facility within that LN. Further, operational FG loading conditions are often relieved by
opening-up LN elements near the monitored Facility, with little impact upon BES reliability, yet with
lesser reliability to the underlying LN loads. This implies that the monitored elements of Flowgates are
typically non-essential to the BES reliability. AECI can support “contingent” FG Facilities disqualifying
a LN claim, but it cannot support “monitored” Facilities as disqualifying factors for rejecting a LN
claim.
Yes
Ownership is irrelevant, so “owned and operated by the retail customer solely for its own use”, should

be replaced by “owned and operated solely in conjunction with specific industrial customer loads.”
Yes
: AECI supports the bright-line concept, but believes the SDT should adopt a core voltage threshold of
“200 kV or higher”, and MVA capacity of “150 MVA or greater”. A proper threshold is critical, because
an inappropriately low threshold will divert significant industry attention and resource away from what
truly benefits the BES reliability. (The number of facilities tend to rise more geometrically than
linearly as the voltage threshold drops.) We believe that an evaluation of the transmission-line Surge
Impedance Loading (SIL), at various kV levels, could provide technical insight as to why many
industry planning engineers believe sub-230kV Facilities, in general do not belong within the BES.
AECI suggests that the SDT consider a more consistent bright-line facility threshold of 150 MVA
capability for all equipment. This would include transmission lines as well, where an Surge Impedance
Loading analysis demonstrates that lines below 230 kV, can support 150 MVA flow up to 280 miles
(applying 1.1 p.u. line-loadability of SIL, IEEE Transactions on Power Apparatus and Systems,
Vol.PAS-98, No.2 March/April 1979, p 609, Figure 7),without additional reactive compensation. In
comparison, single-conductor 138 kV lines, in same table, can support 150 MVA transfers no more
than 50 miles, while 345 kV lines are capable of supporting 150 MVA transfers well over 600 miles.
Individual
Paul Titus
Northern Wasco County PUD
Yes
We agree with the changes. We must point out that the overall flow, or how one proceeds through the
inclusions and exclusions is not clear. Can an item that meets an inclusion be subsequently excluded?
If so, this needs to be explicitly stated. So far, we only have the flow chart produced by the ROP team
that indicates otherwise (http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf).
This was made evident by the question at the 9/28 webinar regarding an I5 capacitor on an E3 local
network. The questioner thought the capacitor was BES per I5, but the answer was that it was
excluded per E3. We can find no support for the answer given. The listing of specific exclusions within
I1 (exception proves the rule) argues for questioner’s stance that the capacitor is BES as written.
Also, if included items could subsequently be excluded, they would be no different from any other
item that met the voltage threshold of 100kV. There would be no need for any of the inclusions if all
possible outputs from the inclusion tests go to the same exclusion test inputs. We strongly support
the addition of the language regarding local distribution facilities, as it matches congressional intent
to leave the regulation of these facilities to state and local authorities.
Yes
Northern Wasco County PUD strongly agrees with this inclusion as written. It is consistent with the
recent PRC-004 and PRC-005 interpretation and the NERC definition of Transmission. We believe the
recent changes to this inclusion add clarity.
No
Referencing the Criteria which in turn references the BES definition creates a circular definition.
Northern Wasco County PUD encourages the adoption of specific thresholds that are technically
justified. We also note that the Criteria and its revisions do not go through the standards
development process, so that thresholds may change with little warning and without triggering an
implementation plan for facilities that may be swept into the BES as a result.
Yes
We agree with the removal of the voltage language, since the inclusions and exclusions apply only to
equipment over 100 kV.
Yes
Northern Wasco County PUD agrees both with the inclusion and with the revised language. The
revised language removes the need to provide a separate definition for “Collector System”.
No
While we agree that reactive devices of sizable capacity connected at 100 kV or higher are needed for
BES reliability, Northern Wasco County PUD fails to see why this inclusion is needed as they are
already captured by the 100 kV threshold. We would propose instead to eliminate this inclusion and
substitute an exclusion for smaller capacity devices. If the SDT really believes an inclusion for reactive

devices is needed, we suggest the SDT provide a technically justified capacity limit within the
inclusion. In addition we suggest also including the phrase “…unless excluded under Exclusion E1, E2
or E4” similar to that in I1. Please see the answer to Q1 above Q10 below.
No
Northern Wasco County PUD notes that a new term has been introduced, “non-retail generation,” with
no definition provided. The answer to the question on this during the 9/28 webinar indicated that nonretail generation was behind the retail customer’s meter. We can see no reason why the net-metered
PV systems should count toward the aggregate limit (exceeding the limit means no exclusion) while a
non-blackstart thermal plant doesn’t (the radial system is excluded if any amount of load is present).
We have also heard the SDT meant just the opposite of what was stated in the webinar. We ask that
a reasonable definition for non-retail be provided within the BES definition document. We strongly
agree that radial systems should be excluded and that the presence of normally open switching
devices between radial systems should not cause them to be considered non-radial. Such a result
would cause the removal of these devices to the detriment of the local level of service. We note that
the singular “A normally open switching device” is used and suggest that an allowance be made for
the possibility of multiple devices. “Normally open switching devices…”
Yes
No
We strongly agree that local networks should be excluded, since they act much like the radial systems
excluded in E1 while providing a higher level of service to customers. These networks should not be
discouraged in the name of reliability. We again object to the introduction of the new confusing term
“non-retail generation” with no definition provided.
No
Please see Northern Wasco County PUD’s answers to Q1 and Q6. Any device that might be excluded
under E4 has already been included per I5. Unless I5 is removed, or rewritten as suggested above;
this exclusion will exclude nothing.
Yes
In order to help meet the fast approaching target date, Northern Wasco County PUD will be voting
affirmative in this ballot, with the hope these comments will be addressed in Phase II. If the ballot
should fail, please address these comments in this phase. Thanks to the team for their good work.
Group
Janelle Marriott Gill
Tri-State Generation and Transmission Assn., Inc., Energy Management
Yes
We believe that the new definiation is a good clarification.
Yes
No
1. The parenthetical phrase regarding the ERO SCRC is not clear. Is the intent that the inclusion
applies to any generating resource that is required to register as a Generator or Generator Operator
per the ERO SCRC? Or was a reference to the 75 MVA threshold inadvertently omitted? It also seems
that it wouldn’t need to be in parentheses, just make it a phrase in the sentence. 2. The wording of
the sentence after the parenthetical phrase is also worded awkwardly. Suggest changing it to
“including the generator terminals and all electrical equipment up to and including the high side of
generator step up transformers, if they are connected at a voltage of 100 kV or higher.
Yes
Yes
No
There should be a limitation on what reactive components needs to be included. The limits could be
based on capacity of the units or on the voltage step that occurs upon switching of the device

Yes
Yes
No
1. b) should be reworded to “Normally there is power flow only into the LN: The LN is not normally
used to transfer power originating outside of the LN for delivery through the LN.” There could be
conditions inside the LN, such as large loads shut down for maintenance, which would allow the
parallel transmission Elements to allow power to flow through the LN. Those conditions would have no
negative or adverse effect on the BES. 2. Capitalize “Network” at the beginning of the Exclusion
Yes
No
Group
Will Smith
Midwest Reliability Organization
Yes
Yes
No
Unless excluded under E2.
Yes
Yes
I4 – Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a system designed primarily for aggregating capacity, connected
at a common point at a voltage of 100 kV or above starting at the point of aggregation to 75 MVA or
more through to the point of interconnection at 100 kV or above.”
No
NSRF recommends the following proposed language for I5 to address the concern: "I5 -Static or
dynamic devices which 1) are dedicated to supplying or absorbing Reactive Power that are connected
at 100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher,
or through a transformer that is designated in Inclusion I1 and 2) are pertinent to meeting the NERC
Planning Criteria in terms of normal and post-disturbance voltage profiles."
Yes
Unless there is a specific reason to the contrary the NSRF suggests that E1b include the qualification
of “aggregate capacity of non-retail generation less thatn or equal to 75 MVA” be added to be
consistent with the wording in E1c.
Yes
No
THE NSRF suggestion considering a different approach for the power flow criteria in I3b. I3b: No form
Power Transfers are scheduled out of, or thorough, the LN in the operating horizon [for BES
designations applicable to the operating horizon] and not Firm Power Transfers are reserved to flow
out of , or through, the LN in the planning horizon [for BES designations applicable to the planning
horizon].
Yes
Yes

NSRF recommends that the following statement be added after I5. If an element is not included based
upon the core definition or I1 – I5, the elements is not consider to be a part of the BES.
Individual
Linda Jacobson-Quinn
Farmington Electric Utility System
Yes
Yes
No
FEUS is concerned I2 is dependent on the Statement of Compliance Registry Criteria (SCRC).
Modification of the SCRC is not required to go through the same process of modification of a Standard
but section 1400 of the NERC Rules of Procedure. Section 1400 does allow for industry comment and
requires multiple tiers of approval. However, it seems by changing the SCRC generating resources
may be included or excluded from the BES – without requiring modification to the definition of the
BES through the Standards Development Process. In addition, Page 4 Section I of the SCRC is
dependent on the NERC definition of the BES. Logically, the SCRC should be dependent on the
definition of the BES not the inverse.
Yes
No
FEUS feels additional clarity should be added to I4. It appears I4 is not intended to include each
individual wind turbine generating unit in a wind farm as a BES element, but rather to include the
point at which the aggregation becomes large enough to meet the aggregate capacity threshold of
75MVA.
No
I5 should be modified to identify a minimum Reactive Power threshold for static or dynamic devices.
As drafted a 1 MVA device supplying or absorbing Reactive Power that is connected at 100 kV or
higher would be included in the BES.
Yes
No
E2 should be modified to include a size and threshold for individual generating units, similar to that
identified in I2. As currently worded E2 places the same threshold (75 MVA) on a single generating
unit as is placed on multiple generating units.
Yes
Yes
No
Individual
Allen Rinard
South Houston Green Power, LLC
No
South Houston Green Power, LLC [SHGP], a registered generator owner in ERCOT, submits the
following comments: Cogeneration facilities, some of which are well over 75 MW in size, are located
at a number of industrial sites owned by SHGP and its affiliates. Some of these cogeneration facilities
generate power that is distributed within the industrial site and used for manufacturing plant
operations. In some instances, excess power not required for plant operations is delivered back into
the electric transmission grid through the tie line(s) connecting the industrial site to the grid. While
the tie lines and some of the internal lines at these industrial sites operate at 100kV or higher, they

do not perform anything that resembles a transmission function. Rather than transmit power long
distances from generation to load centers, the tie lines and internal lines perform primarily an end
user distribution function consisting of the distribution of power brought in from the grid or generated
internally to different plants within each industrial site. In some cases, the facilities also perform an
interconnection function to the extent they enable power from cogeneration facilities to be delivered
into the grid. The voltage of the tie lines and internal lines at these industrial sites is dictated by the
load and basic configuration of each site. Higher voltage lines are used when necessary to meet
applicable load requirements or to reduce line losses. That does not mean that such lines perform a
transmission function. SHGP would oppose any BES definition that would by default subject either the
tie lines or the internal lines at such industrial sites to the mandatory reliability standards applicable
to Transmission Owners and Transmission Operators when they more readily fit the Generation Owner
/ Generation Operator standards. Such an expanded BES definition would subject registered entities
to substantial compliance costs and create potential exposure to penalties, but would not likely
substantially enhance the reliability of the BES. Perhaps such costs and exposure could be justified in
exceptional circumstances, if subjecting these facilities to compliance with reliability standards were
to result in a material increase in reliability of the BES. There is reason to believe, however, that in
many cases the additional reliability benefit would be minimal at best. The tie lines and internal lines
at industrial sites owned by SHGP and its affiliates have been operated for years as end user
distribution and interconnection facilities, and practices and procedures have developed over the
years that have enabled such operations to achieve a high degree of reliability for such sites.
Requiring these facilities to now operate in a different manner as transmission facilities may well
result in a degradation of the reliability of the manufacturing plants located at such sites. For
example, outages would have to be coordinated with the RTO, which may not be interested in
coordinating such outages with scheduled manufacturing plant outages. In light of these
considerations, SHGP agrees with the proposed revisions to the core definition, particularly the
proposal to include a sentence expressly excluding facilities used in the local distribution of electric
energy, provided it is understood that end user-owned delivery facilities located “behind-the-meter”
are, regardless of voltage level, by default outside the scope of this definition.
Yes
No
SHGP agrees with the proposed revisions to Inclusion I2, but requests the following phrase added at
the end “unless excluded under Exclusion E2”.
Yes
No
Further clarification of “Dispersed power producing resources” is needed. Multiple small resources
should not be included. The following phrase should be added at the end of Inclusion I4 “unless
excluded under Exclusion E2”.
No
The phrase should be added at the end “unless excluded under Exclusion E4”.
No
SHGP generally supports with the proposed revisions to Exclusion E1, but suggests several additional
clarifying revisions should be made. First, the phrase “a single point of connection” in the introductory
sentence should be revised to read “a single point of connection (including multiple connections to the
same ring bus or substation where the energy normally flows in the same direction)”. This revision is
intended to ensure that radial systems which involve multiple parallel lines and are designed to
operate as a single radial system, but that nevertheless connect to the grid through more than line for
reliability. Second, for this same reason, an additional (i.e., second) note should be added to the end
of Exclusion E1 that reads as follows: “Note, a normally closed switching device that enables multiple
lines emanating from the same grid ring bus or different grid buses to operate as a single radial
system does not affect this exclusion.” Third, the phrase “with an aggregate capacity of non-retail
generation less than or equal to 75 MVA should be eliminated.
Yes
SHGP generally agrees with the proposed revisions to Exclusion E2, but believes that a clarifying

revision should be made. Substitute “transmission grid” for “BES” in the phrase “provided to the BES”
to insure that the metering is to the grid.
SHGP would like to broaden the scope of Local Networks. If a Local Network does not allow transfer of
Bulk Power across the Interconnected System, then the Local Network should be excluded regardless
of the amount of generation behind the meter. Often, large industrial sites install large combined Heat
& Power cogeneration units due to a hefty steam load. Subjecting industrial facilities to additional
reporting and coordination efforts [other than those already required by the TO and RTO] may have
little, if any, increase in grid reliability. The 75 MVA (gross nameplate rating) needs to be eliminated.
To date, none of the Regional Entities has suggested that SHGP or its affiliates register as a
Transmission Owner or Transmission Operator with respect to any SHGP or affiliated delivery
facilities.
Yes

Group
William Bush
Holland Board of Public Works
Yes
Holland BPW believes that the proposed definition is an improvement to the status quo, but requires
additional work. The thresholds for classifying generators as Bulk Electric System (BES) must be
revised. There was little technical support for proposing the current thresholds. No greater evidence
than that which was proffered for the initial thresholds should be required to modify those standards.
Four years of compliance experience and industry feedback support increasing these thresholds.
Holland BPW supports increasing the generation thresholds from 20 MVA (individual gross nameplate)
and 75 MVA (aggregate gross nameplate) to not less than 100 MVA (individual gross nameplate) and
300 MVA (aggregate gross nameplate). Holland BPW recognizes that the SDT and NERC have
committed to making these revisions as part of “Phase II”, and are asking the industry to trust that
such an initiative will not succumb to work on other initiatives. However, even if work on this initiative
commences immediately, entities that should be removed from the Compliance Registry face costs of
compliance or the risk of non-compliance penalties even though their facilities are not necessary for
the reliable operation of the interconnected transmission system. That said, there are two significant
improvements in the revised draft. First, it is essential to make clear that the “Inclusions” and
“Exclusions” apply only to the first sentence of the core definition (i.e., “Transmission Elements”). The
revised definition appears to address this. By placing “Unless modified by the lists shown below” at
the beginning of the first sentence of the definition clarifies that the lists of Inclusions and Exclusions
pertain only to “Transmission Elements” that would otherwise be included or excluded from the core
definition. The revised definition and the lists of Inclusions and Exclusions do not and cannot be
applied in a manner to pull in facilities used in the local distribution of electric energy as BES facilities
because Congress, by statute, has already determined that such facilities are outside of NERC’s reach,
as recognized by the second sentence of the definition. Second, Holland BPW supports the addition of
the second sentence of the core definition that states, “This does not include facilities used in the local
distribution of electric energy.” This language provides necessary recognition to the jurisdictional
limitation provided for in Section 215 of the Federal Power Act, and as recognized by the FERC in
Orders 743 and 743-A (see, e.g., ¶¶ 58-59 in 743-A). Finally, if the revised definition goes forward, it
is imperative that the rules of procedure providing for an exception process be adopted at the same
time.
No
It is essential that regional entities and NERC recognize that “facilities used in the local distribution of
electric energy” are not included in the definition of BES, regardless of the gross individual or gross
aggregate nameplate rating of generation resources. While the addition of the second sentence in the
core definition makes this clarification, Holland BPW believes it is necessary that regional entities and
NERC recognize that neither this Inclusion nor any of the Inclusions may be used as a basis to compel
registration and compliance in such instances, regardless of the size of the generators. The statutory
exemption of facilities used in the local distribution of electric energy is not limited by generator
number or capability. NERC’s definitions cannot impose limitations that are not set forth in the

statute. For purposes of the exclusion of facilities that might otherwise meet the definition of BES, the
thresholds for determining what generating resources constitute BES facilities should be modified
from the current levels (gross individual nameplate capacity of 20 MVA or gross aggregate nameplate
rating of 75 MVA). Holland BPW supports modification of the thresholds to not less than 100 MVA
(gross individual nameplate capacity) and 300 MVA (gross aggregate nameplate).

Yes
Holland BPW supports the exclusion of radial systems from the BES definition, but believes that
further clarification is necessary. First, the deletion of “originating with an automatic interruption
device” is a step in the right direction. However, “emanates from a single point of connection” could
be too narrowly interpreted (i.e., multiple buses within a single substation could be viewed as multiple
points of connection). Holland BPW proposes the following modification: “emanates from a single
substation connected to the BES at 100 kV or higher…” Entities whose only connection emanates from
a single substation and otherwise meet the BES definition should not be denied exclusion under E1
solely because they connect to multiple buses at that single substation. Additionally, adoption of “E3 –
Local Networks” renders specious any argument that claims that connecting to multiple buses within a
single substation makes a material difference for reliability purposes since local networks would have
multiple connections anyway. Additionally, it is not clear why it is necessary to include the note at the
end of the revised definition. (“A normally open switching device between radial systems, as depicted
on prints or one-line diagrams for example, does not affect this exclusion.”) This raises questions as
to what “normally open” means, and whether the only evidence demonstrating what “normally open”
means will be prints or one-line diagrams. Further, it is not entirely clear what is meant by the
language “does not affect this exclusion”. If the note remains, it should be modified to read
something like, “a normally open switching device between radial systems does not prevent
application of this exclusion.” Finally, the generation threshold limit in E1(b) and E1(c) should be
revised as discussed in response to Q1. Specifically, the proposed threshold of 75 MVA for this
exclusion should be raised to not less than 300 MVA in both E1(b) and E1(c).
Yes
Holland BPW supports the exclusion of Local Networks (LN) from the definition of BES. Such systems
are generally not necessary for the reliable operation of the interconnected transmission network.
However, some revisions are necessary. Holland BPW believes that E3(a) and E3(b) can and should
be eliminated, provided E3(c) remains. E3(c) provides that an LN is BES if it is classified as a Flow
Gate or Transfer Path. The bases for removing E3(a) and E3(b) are as follows: (1) Provision E3(a)
establishes a 75 MVA limit on connected generation. This is inconsistent with the concept of a LN and
should be removed. If not removed, it should be increased to not less than 300 MVA, consistent with
the discussion in response to Q1. If an LN does not accommodate bulk power transfer across the
interconnected system, the amount of generation that exists and is distributed within that system is
immaterial for purposes of the reliable operation of the interconnected transmission system. During
the NERC Webinar, NERC representatives suggested that placing an upper limit on generation within a
LN might be desirable based upon an assumption that if that entity’s internal generation is lost, then
replacement generation would have to come from the BES, and could therefore affect reliability. This
assumption has not been substantiated. In most instances, generation resources are dispersed
throughout the LN – it is unlikely an event would result in the loss in the amount of the aggregate
generation. Additionally, LNs have local load shedding and system restoration plans for such
contingencies. (2) E3(b) is unnecessary and should be removed. The proposed language in E3(b)
appears to be concerned with flows originating from outside of the LN, coming into the LN, and then
exiting the LN to loads outside of the LN. As noted above, E3(c) appears to address this concern. If
E3(b) is maintained, then the introductory clause (“Power flows only into the LN:”) should be deleted,
because it is inconsistent with the second clause (“The LN does not transfer energy originating outside
the LN for delivery through then LN.”) If E3(b) is retained, Holland BPW supports the second clause
(“The LN does not transfer energy originating outside the LN for delivery through then LN”) because it
appears to be the portion of the provision that addresses the concern about flows into, through, and
then out of, the LN. (3) E3(b) should also be removed or modified because it fails to recognize typical

municipal system operations. An LN may have internal generation that is less than its peak load but in
excess of off-peak or holiday load levels. The language “Load flows only into the LN” does not
recognize this situation and prevents an LN from making the most economic use of surplus
generation. There are no reliability reasons to discourage such sales since with or without such
transactions, this generation is not necessary for the reliable operation of the interconnected
transmission system.

Group
Katie Coleman
Andrews Kurth, LLP
Yes
Yes
Yes
The interplay between Inclusion I2, which references the Statement of Registry Compliance, and
Exclusions E1-E3 is unclear. Under the Registry criteria, “a customer-owned or operated
generator/generation that serves all or part of retail load with electric energy on the customer’s side
of the retail meter may be excluded as a candidate for registration … if (i) the net capacity provided
to the bulk power system does not exceed the criteria above.” It appears that the SDT intended to
invoke this provision by referencing the Statement of Registry Compliance, which counts only the
“net” capacity provided, by referencing the Statement of Compliance Registry Criteria. However,
Exclusions E1 and E3 exclude generation on the basis of “gross nameplate ratings.” For customerowned facilities, this treatment is inconsistent with netting treatment provided in the Statement of
Registry Compliance. Exclusions E1-E3 should be revised to reference the Statement of Compliance
Registry Criteria as well so that customer-owned generation is included or excluded based on its net
capacity to the grid rather than its gross nameplate capacity. TIEC also supports revisiting and
potentially raising the thresholds that trigger registration as a Generation Owner or Operator. TIEC
understands that the SDT has decided to maintain the status quo as reflected in NERC’s Registry
Criteria at this time. TIEC looks forward to addressing potential modifications to the thresholds in the
appropriate context.
Yes
Yes
Yes
Yes
As noted in response to Question 3, above, Exclusion E1 would only allow exclude radial systems with
“aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).”
The reference to “non-retail” generation in subsection (c) indicates that the SDT may have intended
to preserve the “netting” approach set forth in the Statement of Registry Compliance, but this should
be made clearer. The description in subsection (c) should be revised to exclude “Where the radial
system serves Load and includes generation resources not identified in Inclusions I2 or I3,” and the
remainder of that sentence referencing a 75 MVA gross nameplate rating should be removed. This will
provide a reference back to the Statement of Registry Compliance and clarify that only net capacity is
considered for customer-owned facilities.
Yes
Please see the response to Question 3, above. Unlike exclusions E1 and E3, this exclusion refers
specifically to the “net capacity” provided, which is consistent with existing treatment for generation
that is netted against internal load under the Statement of Registry Compliance.
Yes

As noted in response to Question 3, above, subsection (a) of Exclusion E3 would only exclude Local
Networks with “aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating).” The reference to “non-retail” generation in subsection (a) indicates that the SDT
may have intended to preserve the “netting” approach set forth in the Statement of Registry
Compliance, but this should be made clearer. The description in subsection (a) should be revised to
exclude “Where the radial system serves Load and includes generation resources not identified in
Inclusions I2 or I3,” and the remainder of that sentence referencing a 75 MVA gross nameplate rating
should be removed. This will provide a reference back to the Statement of Registry Compliance and
clarify that only net capacity is considered for customer-owned facilities. TIEC also disagrees with the
300 kV upper limitation on transmission elements within a Local Network. Consistent with TIEC’s
comments to FERC, if these facilities are serving a distribution function, their voltage level is
irrelevant. The transmission versus distribution distinction should be based on function, not voltage
level. The remainder of this exclusion clarifies what constitutes a distribution function, so the 300 kV
limit is unnecessary and should be removed.
Yes
No
Individual
Angela P Gaines
Portland General Electric Company
Yes
Yes
Yes
Yes
Yes
PGE requests additional clarity in the wording of Inclusion 4. Inclusion 4 is not intended to include
each individual wind turbine generating unit in a wind farm as a BES element, but rather to include
the point at which the aggregation becomes large enough to meet the aggregate capacity threshold of
75 MVA. However, the response to comments from the last comment posting and the current wording
of Inclusion 4 does not provide sufficient clarity to answer this question.
Yes
Yes
Yes
Yes
PGE agrees with Exclusion E3, but believes additional clarification is necessary to facilitate a complete
understanding and application of the exclusion criteria. First, there is no specific definition of “nonretail” generation provided. Additionally, E3 b) states “Power flows only into the LN: The LN does not
transfer energy originating outside the LN for delivery through the LN.” PGE believes that a local
network should still qualify for the LN exclusion if power may flow out of the LN at a discrete point or
certain discrete points during abnormal operating conditions, but power still flows into the LN on an
aggregate basis during all operating conditions, and power flows only into the LN at all discrete points
during normal operating conditions.
Yes

No
Individual
Andrew Gallo
City of Austin dba Austin Energy
Yes
In an effort to avoid potential confusion and provide clarity we believe the sentence, “This does not
include facilities used in the local distribution of electric energy,” more appropriately fits under the
“exclusions” (rather “inclusions”) section.
Yes
We believe additional clarification of transformers to be included may be achieved with respect to
auto transformers, phase angle regulators and generator step-up transformers by adding the
following sentence: All transformers (including autotransformers, voltage regulators, and phase angle
regulators) with primary and secondary terminals operated at or above 100kV, unless excluded by E1
or E3.
No
We recommend removing the reference of the ERO Statement of Compliance Registry Criteria
(Registry Criteria). The BES Definition should be the governing document and independent of ERO
registration requirements. The definition should drive what appears in the Registry Criteria.
Additionally, we support using the BES Phase 2 technical analysis to identify and provide technical
support for determining the appropriate minimum MVA rating that a single unit, or the aggregation of
multiple units, must meet to be part of the BES.
Yes
We recommend rewording Inclusion I3 as follows: “Only Primary Blackstart resources designated as
part of the Transmission Operator’s restoration plan.” We have concerns that making all Blackstart
generation either primary or secondary BES elements creates an incentive to remove those secondary
Blackstart capable units in an effort to avoid BES inclusion. We believe that making the primary
Blackstart unit the only BES element will remove this incentive. In so doing, this will allow the
secondary Blackstart units to remain in the Transmission Operator’s plan and training program as an
alternate tool for the Transmission Operator to restore the system.
Yes
Yes
Appropriate MVAr level should be established. Reactive resources should be treated similar to
generation criteria and included in the technical studies associated with the Phase 2 technical analysis
in order to establish the appropriate MVAr level included as BES.
Yes
For the E1 reference “Note,” we would benefit from additional clarification identifying the treatment of
a normally open switch and offer the following: “Radial systems shall be assessed with all normally
open switching devices in their open positions.” The wording in Exclusion 1-c should more clearly
reflect what is intended by using the term “non-retail generation.” Also, as with the technical
justification for Inclusions I2 and I4, we recommend that the generation threshold, i.e. gross
nameplate values, be deferred to Phase 2.
Yes
Yes
We prefer to hold reference to gross nameplate rating/threshold values until generation technical
justification is completed as part of Phase 2; these studies should apply to any real or reactive power
threshold reference. For Exclusion E3-b using the phrase “[p]ower flows only into the Local Network”
is too restrictive. An allowable MW threshold of Local Network power producing resources should be
deferred to the Phase 2 BES technical analysis. Where no generation is present in the Local Network,
it is recommended that an allowance for residual flow through the Local Network.
Yes

No
Individual
Martin Kaufman
ExxonMobil Research and Engineering
Yes
However, in Order 743, FERC directed NERC to further delineate the differences between transmission
systems (used to transfer electric power between regions) and distribution systems (used to deliver
electric power locally). The inclusions and exclusions defined in the draft BES definition are a step in
the right direction, but further work is necessary during Phase II to meet the intention of the order.
Additionally, the SDT should consider defining terms, such as non-retail generation, or providing
references (footnotes) that elaborate on the referenced concept.
Yes
The Inclusion I1 contains the phrase “unless excluded under Exclusion E1 or E3”. While recognizing
that this is a welcomed clarification on how I1 interacts with the Exclusion section, it is inconsistent
with Inclusions I2 through I5. The BES SDT team should consider how to standardize the language
around the interactions between the Inclusions and Exclusions (perhaps add an “unless” qualifier for
each Inclusion).
No
The Inclusion I1 contains the phrase “unless excluded under Exclusion E1 or E3”. While recognizing
that this is a welcomed clarification on how I1 interacts with the Exclusion section, it is inconsistent
with Inclusions I2 through I5. The BES SDT team should consider how to standardize the language
around the interactions between the Inclusions and Exclusions (perhaps add an “unless” qualifier for
each Inclusion).
Yes
Yes
The BES SDT should clarify the difference between “dispersed power producing resources” and
“generation resources” in such a manner that it is clear that an industrial plant containing providing
the BES with power from ten 7.5MVA machines connected at a common point at a voltage of 100 kV
or higher meets the qualifications for generation resources and does not meet the qualifications for a
“dispersed power producing resource”.
No
The BES SDT should work on clarifying the differences between Inclusion I5 and Exclusion E4. The
phrase “solely for its own use” in Exclusion E4 is vague and open to interpretation. It is unclear
whether equipment, such as power factor correction facilities, surge capacitors located in motor
terminal boxes and excitation capacitors installed for use by a motor located on the low side of a 138
kV primary transformer would be excluded from the BES. Is the intent of this requirement to capture
“reactive resources” that provide VARs to the BES in regions that exhibit voltage stability issues?
Yes
The removal of the requirement for an automatic fault interrupting device from this requirement is a
welcomed change from the first posting. This Exclusion helps preserve the current NERC Registry and
explicitly excludes many facilities used in the distribution of electric power.
Yes
Yes
Exclusion E1 and E3 aid in the delineation of distribution and transmission facilities. However, we
request that the BES SDT review paragraphs 108 and 109 of FERC Order 743. In order to meet
reliability target requirements to safely and economically operate manufacturing and production
facilities, many industrial facilities are fed by two or more utility transmission lines that originate at
independently fed utility substations. Due to the magnitude of an industrial site’s load, these
transmission lines are typically designed to operate at levels in excess of 100 kV at the request of the

utility company. These transmission lines typically terminate into an interconnection facility, owned by
the industrial facility, that spot networks the transmission lines via a ring buss or breaker and a half
substation within the industrial facility’s private use network in order to serve the load of the facility’s
private use network. These private use networks typically satisfy the requirements set forth in the
definition of a Local Network (power flows in, not a flowgate, etc.); however, the term “non-retail
generation” is not a term that is implicitly defined or consistent with this documents use of “net
capacity provided…” phrasing in similar exclusions.
Yes
The BES SDT should work on clarifying the differences between Inclusion I5 and Exclusion E4. The
phrase “solely for its own use” in Exclusion E4 is vague and open to interpretation. It is unclear
whether equipment, such as power factor correction facilities, surge capacitors located in motor
terminal boxes and excitation capacitors installed for use by a motor located on the low side of a 138
kV primary transformer would be excluded from the BES.
Yes
It would be worthwhile to explain the relationship (timeline) between the BES Definition
implementation plan and the compliance implementation plan proposed in the BES RoP team’s new
Appendix 5C for the NERC Rules of Procedure.
Individual
David Kahly
Kootenai Electric Cooperative
Yes
Kootenai Electric Cooperative (“KEC”) believes the SDT continues to make substantial progress
towards a clear and workable definition of the Bulk Electric System (“BES”) that markedly improves
both the existing definition and the SDT’s previous proposal. KEC therefore strongly supports the new
definition, although our support is conditioned on: (1) a workable Exceptions process being developed
in conjunction with the BES definition; and, (2) the SDT moving forward expeditiously on Phase II of
the standards development process in accordance with the SAR recently put forward by the SDT,
which would address a number of important technical issues that have been identified in the
standards development process to date. KEC strongly supports the following elements of the revised
BES definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the beginning of the
definition. This change makes clear that the Inclusions and Exclusions apply to all Elements that
would otherwise be included in or excluded from the core definition (i.e., “all Transmission Elements
operated at 100 kV or higher and Real Time and Reactive Power resources connected at 100 kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition, discussed further in our
comments on the first draft. (2) The exclusion for Local Distribution Facilities. As the starting point for
the BES definition, KEC supports use of the phrase “all Transmission Elements” and the qualifying
sentence: “This does not include facilities used in the local distribution of electric energy.” This
language helps ensure that FERC, NERC, and the Regional Entities (“REs”) will act within the
jurisdictional constrains Congress placed in Section 215 of the Federal Power Act (“FPA”). In Section
215(a)(1), Congress unequivocally excluded “facilities used in the local distribution of electric energy”
from the keystone “bulk-power system” definition. 16 U.S.C. § 824o(a)(1). Including the same
language in the definition helps ensure that entities involved in enforcement of reliability standards
will act within their statutory limits. In addition, as a practical matter, inclusion of the language will
help focus both the industry and responsible agencies on the high-voltage interstate transmission
system, where the reliability problems Congress intended to regulate – “instability, uncontrolled
separation, [and] cascading failures,” 16 U.S.C. § 824o(a)(4) – will originate. At the same time, levelof-service issues arising in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16 U.S.C. § 824o(i)(2)
(reserving to state and local authorities enforcement of standards for adequacy of service). For similar
reasons, KEC believes use of the phrase “Transmission Elements” as the starting point for the base
definition is desirable because both “Transmission” and “Elements” are already defined in the NERC
Glossary of Terms Used, and the term “Transmission” makes clear that the BES includes only
Elements used in Transmission and therefore excludes Elements used in local distribution of electric
power. (3) Appropriate Generator Thresholds. In the standards development process, it has become
apparent that the thresholds for classifying generators as BES in the current NERC Statement of

Compliance Registry Criteria (“SCRC”) (20 MVA for individual generators, 75 MVA for multiple
generators aggregated at a single site), which predate the adoption of FPA Section 215, were never
the product of a careful analysis to determine whether generators of that size are necessary for
operation of the interconnected bulk transmission system. Ideally, such an analysis would be
conducted as part of the current standards development process. KEC recognizes that, given the
deadlines imposed by FERC in Order No. 743, it will not be possible for the SDT to conduct such an
analysis within the time available. Accordingly, KEC agrees with the approach taken by the SDT,
which is to propose a Phase II of the standards development process that would address the
generator threshold issue and several other technical issues that have arisen during the current
process. As long as Phase II proceeds expeditiously, KEC is prepared to support the BES definition as
proposed by the SDT. While KEC strongly supports the overall approach adopted by the SDT and
much of the specific language incorporated into the second draft of the BES definition, we believe the
second draft would benefit from further clarification or modification in a number of respects, most of
which are detailed in our subsequent answers. Our support for the definition is not contingent upon
these changes being adopted. Further, we believe a workable Exclusion Process is essential for a BES
Definition that will meet the legal requirements of FPA Section 215, especially for systems operating
in the Western Interconnection. As detailed in our previous comments, KEC believes a 200-kV
threshold would be more appropriate for WECC than a 100-kV threshold. In addition, a 200-kV
threshold for the West is backed by solid technical analysis conducted by the WECC Bulk Electric
System Definition Task Force, and repeated claims that there is no technical analysis to support this
view is therefore incorrect. That being said, we raise the issue here to emphasize the importance of
the Exclusions for Local Networks and Radial Systems and the Exceptions process. These Exclusions
and the Exceptions are essential for a definition that works in the Western Interconnection because
the core definition will be over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by the SDT at this juncture,
KEC will support the SDT’s proposal and will not further pursue its claims regarding the 200-kV
threshold. Finally, we suggest that the SDT address the circumstance when an Element is covered by
both an Inclusion and an Exclusion. We note that some of the inclusions already contain language
addressing this question. For example, Inclusion 1 indicates that transformers falling within the
specified parameters are part of the BES “. . . unless excluded under Exclusions E1 or E3.” Where it is
not already included, similar language should be included in the other Inclusions and/or Exclusions to
explain whether the SDT intends the Inclusions or the Exclusions to predominate in situations where
facilities might be covered by both. We suggest clarifying language in our responses to Questions 2
and 5.
Yes
KEC supports the SDT’s changes to the first Inclusion because it is more clear and simple than the
initial approach. That being said, we suggest that an additional sentence of clarification would help
avoid future controversy about the meaning of Inclusion 1. As we understand it, the BES intends to
include transformers only if both the primary and secondary terminals operate at 100 kV or above,
which is why the definition uses the word “and” (“the primary and secondary terminals”). We support
this approach since it would exclude transformers where the secondary terminals serve distribution
loads, and which therefore function as distribution rather than transmission facilities. We believe the
SDT’s intent would be clarified by adding a sentence at the end of Inclusion 1 that reads:
“Transformers with either primary or secondary terminals, or both, that operate at or below 100 kV
are not part of the BES.” This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary terminals” was intentional. We
also support the SDT’s proposal to develop detailed guidance concerning the point of demarcation
between BES and non-BES elements in the Phase II SAR. In this regard, we note that, while Inclusion
1 at least implicitly suggests that the dividing line between BES and non-BES Elements should be at
the transformer where transmission-level voltages are stepped down to distribution-level voltages, we
believe further clarification of this point of demarcation between the BES and non-BES Elements is
necessary. Many different configurations of transformers and other equipment that may lie at the
juncture between the BES and non-BES systems. If the point of demarcation is designated at the
transformer without further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately stringent regulations
and undue costs. For example, distribution-only utilities commonly own the switches, bus and
transformer protection devices on the high side of transformers where they take delivery from their
transmission provider. Ownership of these protective devices and high-voltage bus on the high side of

the transformer should not cause these entities to be classified as BES owners. As the Phase II
process moves forward, we commend to the SDT the extensive work performed on the point of
demarcation question by the WECC BESDTF. We also support the incorporation of language (“. . .
unless excluded under Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES facilities, regardless
of their operating voltage. Further clarification might be achieved by using the phrase “. . . unless the
transformer is operated as part of a Radial System meeting the requirements of Exclusion E1 or a
Local Network meeting the requirements of Exclusion E2.”
Yes
KEC supports the changes made in Inclusion 2 and believe that the definition in its current form adds
clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the previous
draft definition into a single Inclusion that addresses the treatment of generation for purposes of the
BES definition. We also support the SDT’s proposal for a Phase II of the BES Definition process to
examine the technical justification for these thresholds and to establish new thresholds based on a
careful technical analysis. It is our understanding that the generator threshold issue will be vetted
through the complete standards development process. We agree with this approach because if the
generator threshold is treated as merely an element of NERC’s Rules of Procedure, it can be changed
with considerably less due process and industry input than the Standards Development Process.
Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of Procedure upon approval
of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3, 2010) (providing for,
e.g., posting of SDT proposals for comment, successive balloting, and super-majority approval
requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011) (“Order No. 743 directed
the ERO to revise the definition of ‘bulk electric system’ through the NERC Standards Development
Process” (emph. added)). Addressing all aspects of Phase II through the Standards Development
Process will improve the content of the definition by bringing to bear industry expertise on all aspects
of the definition and will ensure that, once firm guidelines are established, they can be relied upon by
both industry and regulators without threat that they will be changed with little notice and little due
process. KEC also believes further clarification of the proposed language would be appropriate. The
SDT proposes continued reliance upon the thresholds that are used in the NERC Statement of
Compliance Registry Criteria for registration of Generation Owners and Generation Operators, which is
currently 20 MVA for an individual generation unit and 75 MVA for multiple units on a single site.
Conceptually, we are concerned about this approach because, as we understand it, the purpose of the
Compliance Registry is to sweep in all generators that might be material to the reliable operation of
the BES, and not to definitively determine whether a given generator is, in fact, material to the
reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to identify
“candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we believe that the
generator threshold determined in Phase II should be incorporated directly into the BES Definition
rather than being incorporated by reference from the SCRC. We also believe that the specific
language proposed by the SDT could be further clarified. The SDT proposes to include generation in
the BES if the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder for the results of
the technical analysis that would occur in Phase II but we believe simply stating that the threshold
will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the reasons noted
above, we believe the threshold should be part of the BES Definition, and should not simply be a
cross-reference to the SCRC (and, given the different purposes of the BES Definition and the SCRC, it
is not clear that the same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate Resources
connected at a voltage of 100 kV or above.” Two definitions would then be added to the note at the
end of the definition to read as follows: For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality threshold to be
included in this definition or, in the absence of such a materiality threshold, that meets the gross
nameplate capacity voltage threshold requiring registration of the owner of such a resource as a
Generation Owner under the ERO Statement of Compliance Registry Criteria. For purposes of this BES
Definition, Qualifying Aggregate Generation Resources means any facility consisting of one or more
generating units that are connected at a common bus that meets the materiality threshold to be
included in this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit generator as a
Generation Owner under the ERO Statement of Compliance Registry Criteria. The “materiality

threshold” is intended to refer to the generator threshold developed in Phase II. We suggest using
definitions in this fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as part of the BES
if they are necessary for operation of the BES, but to exclude smaller generating units because they
are not material to the operation of the interconnected transmission grid. Second, we believe use of
the defined terms better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase II without having to revise the
BES Definition at the end of that process. That is, the definitions are designed to allow the SDT to
include revised thresholds in the definition at the conclusion of the Phase II process based upon the
technical analysis planned for Phase II, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase II is completed. Third, the definitions can be
incorporated into other parts of the BES Definition, which will add consistency and clarity. As noted in
our answers to several of the questions below, the specific 75 MVA threshold is retained in several of
the Exclusions and Inclusions, and we believe the industry would be better served if the revised
thresholds arrived at after technical analysis in Phase II are automatically incorporated into all
relevant provisions of the BES Definition. There is no reason for the SDT to continue to rely on the 75
MVA threshold once the analysis planned for Phase II on the threshold issue is completed. Fourth, the
phrase “or that meets the materiality threshold to be included in this definition” is intended to
preserve the SDT’s flexibility to make a determination that generators below a specific threshold are
not “necessary to” maintain the reliability of the interconnected transmission system, and to
incorporate that finding as part of the definition itself, even if a different threshold is used in the SCRC
to identify potential candidates for registration. Accordingly, our proposed language makes clear that
a specific threshold in the definition controls over any threshold that might be included in the SCRC.
For the reasons stated above, we believe it is highly desirable to include any material threshold in the
BES Definition itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Hence, we agree with the SDT’s decision to
examine the question of where the line between BES and non-BES Elements should be drawn more
closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and commend the work
of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting point for the
SDT’s analysis on this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities interconnecting such
generators to be part of the BES. As discussed more fully in our answer to Question 9, based on
extensive technical analysis that has already been performed by the NERC Project 2010-07 Standards
Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a
dedicated interconnection facility connecting a BES generator to the interconnected bulk transmission
grid will result in an unnecessary regulatory burden that produces considerable expense for the owner
of the interconnection facility with little or no improvement in bulk system reliability. We also believe
the clauses at the end of Inclusion 2 are somewhat confusing and that greater clarity would be
achieved by changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above” so that the Inclusion covers transformers
with terminals “connected at a voltage of 100 kV or above, including the generator terminal(s) on the
high side of the step-up transformer(s) if operated at a voltage of 100 kV or above.” Finally, as
discussed further in our answer to Questions 5 and 6, KEC believes more clarity may be achieved by
collapsing Inclusion 5, addressing Reactive Power resources, and Inclusion 4, which addresses
dispersed renewable resources, into a single Inclusion that addresses “power producing resources”
(the language used in current Inclusion 4).
Yes
KEC supports the changes made in Inclusion 3 and believe that the definition in its current form adds
clarity. In particular, we support the SDT’s decision to collapse Inclusions 2 and 3 from the previous
draft definition into a single Inclusion that addresses the treatment of generation for purposes of the
BES definition. We also support the SDT’s proposal for a Phase II of the BES Definition process to
examine the technical justification for these thresholds and to establish new thresholds based on a
careful technical analysis. It is our understanding that the generator threshold issue will be vetted
through the complete standards development process. We agree with this approach because if the
generator threshold is treated as merely an element of NERC’s Rules of Procedure, it can be changed
with considerably less due process and industry input than the Standards Development Process.
Compare NERC Rules of Procedure § 1400 (providing for changes to Rules of Procedure upon approval

of the NERC board and FERC) with NERC Standards Process Manual (Sept. 3, 2010) (providing for,
e.g., posting of SDT proposals for comment, successive balloting, and super-majority approval
requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011) (“Order No. 743 directed
the ERO to revise the definition of ‘bulk electric system’ through the NERC Standards Development
Process” (emph. added)). Addressing all aspects of Phase II through the Standards Development
Process will improve the content of the definition by bringing to bear industry expertise on all aspects
of the definition and will ensure that, once firm guidelines are established, they can be relied upon by
both industry and regulators without threat that they will be changed with little notice and little due
process. KEC also believes further clarification of the proposed language would be appropriate. The
SDT proposes continued reliance upon the thresholds that are used in the NERC Statement of
Compliance Registry Criteria for registration of Generation Owners and Generation Operators, which is
currently 20 MVA for an individual generation unit and 75 MVA for multiple units on a single site.
Conceptually, we are concerned about this approach because, as we understand it, the purpose of the
Compliance Registry is to sweep in all generators that might be material to the reliable operation of
the BES, and not to definitively determine whether a given generator is, in fact, material to the
reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to identify
“candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we believe that the
generator threshold determined in Phase II should be incorporated directly into the BES Definition
rather than being incorporated by reference from the SCRC. We also believe that the specific
language proposed by the SDT could be further clarified. The SDT proposes to include generation in
the BES if the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder for the results of
the technical analysis that would occur in Phase II but we believe simply stating that the threshold
will be “per the ERO Statement of Compliance Registry” is ambiguous. Further, for the reasons noted
above, we believe the threshold should be part of the BES Definition, and should not simply be a
cross-reference to the SCRC (and, given the different purposes of the BES Definition and the SCRC, it
is not clear that the same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying Aggregate Resources
connected at a voltage of 100 kV or above.” Two definitions would then be added to the note at the
end of the definition to read as follows: For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality threshold to be
included in this definition or, in the absence of such a materiality threshold, that meets the gross
nameplate capacity voltage threshold requiring registration of the owner of such a resource as a
Generation Owner under the ERO Statement of Compliance Registry Criteria. For purposes of this BES
Definition, Qualifying Aggregate Generation Resources means any facility consisting of one or more
generating units that are connected at a common bus that meets the materiality threshold to be
included in this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit generator as a
Generation Owner under the ERO Statement of Compliance Registry Criteria. The “materiality
threshold” is intended to refer to the generator threshold developed in Phase II. We suggest using
definitions in this fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as part of the BES
if they are necessary for operation of the BES, but to exclude smaller generating units because they
are not material to the operation of the interconnected transmission grid. Second, we believe use of
the defined terms better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase II without having to revise the
BES Definition at the end of that process. That is, the definitions are designed to allow the SDT to
include revised thresholds in the definition at the conclusion of the Phase II process based upon the
technical analysis planned for Phase II, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase II is completed. Third, the definitions can be
incorporated into other parts of the BES Definition, which will add consistency and clarity. As noted in
our answers to several of the questions below, the specific 75 MVA threshold is retained in several of
the Exclusions and Inclusions, and we believe the industry would be better served if the revised
thresholds arrived at after technical analysis in Phase II are automatically incorporated into all
relevant provisions of the BES Definition. There is no reason for the SDT to continue to rely on the 75
MVA threshold once the analysis planned for Phase II on the threshold issue is completed. Fourth, the
phrase “or that meets the materiality threshold to be included in this definition” is intended to

preserve the SDT’s flexibility to make a determination that generators below a specific threshold are
not “necessary to” maintain the reliability of the interconnected transmission system, and to
incorporate that finding as part of the definition itself, even if a different threshold is used in the SCRC
to identify potential candidates for registration. Accordingly, our proposed language makes clear that
a specific threshold in the definition controls over any threshold that might be included in the SCRC.
For the reasons stated above, we believe it is highly desirable to include any material threshold in the
BES Definition itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Hence, we agree with the SDT’s decision to
examine the question of where the line between BES and non-BES Elements should be drawn more
closely in Phase II under the rubric of “contiguous vs. non-contiguous BES,” and commend the work
of the Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting point for the
SDT’s analysis on this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities interconnecting such
generators to be part of the BES. As discussed more fully in our answer to Question 9, based on
extensive technical analysis that has already been performed by the NERC Project 2010-07 Standards
Drafting Team and its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a
dedicated interconnection facility connecting a BES generator to the interconnected bulk transmission
grid will result in an unnecessary regulatory burden that produces considerable expense for the owner
of the interconnection facility with little or no improvement in bulk system reliability. We also believe
the clauses at the end of Inclusion 2 are somewhat confusing and that greater clarity would be
achieved by changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above” so that the Inclusion covers transformers
with terminals “connected at a voltage of 100 kV or above, including the generator terminal(s) on the
high side of the step-up transformer(s) if operated at a voltage of 100 kV or above.” Finally, as
discussed further in our answer to Questions 5 and 6, KEC believes more clarity may be achieved by
collapsing Inclusion 5, addressing Reactive Power resources, and Inclusion 4, which addresses
dispersed renewable resources, into a single Inclusion that addresses “power producing resources”
(the language used in current Inclusion 4).
Yes
KEC supports the revised language generally, but believes additional changes would make the
language clearer. Specifically, we believe Inclusion 4 should not incorporate a hard 75 MVA
generation threshold (i.e, “resources with aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating)”). Instead, we urge the SDT to replace this language with the defined term
“Qualifying Aggregate Generation Resources,” which is discussed in more detail in our response to
Question 3. This language, or some equivalent, will preserve the SDT’s ability to revise the 75 MVA
threshold in Phase II, with the result of Phase II included in the BES Definition by operation rather
than requiring further revision of the Definition. More generally, we are not certain what is
accomplished by Inclusion 4 that is not already accomplished by Inclusion 2, which also addresses
whether generation should be defined as BES. The SDT’s stated concern is with variable generation
units such as wind and solar plants. It is not clear to us why this concern is not fully addressed in
Inclusion 2, which addresses multiple generation units connected at a common bus, the configuration
of most variable generation plants with multiple units. We are also concerned that the language, as
proposed, could have unintended consequences and improperly classify local distribution systems as
BES in certain circumstances. This is because multiple distributed generation units could render a
local distribution system a “collector system” and the entire system the equivalent of an aggregated
generation unit, causing the local distribution system to be improperly denied status as a LN. If many
different distributed generation units are connected to a local distribution system, it is very unlikely
that more than a few of those units would fail simultaneously, and it is therefore unlikely that multiple
generation units would produce a measureable impact on the interconnected bulk transmission
system, especially if the units individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase II. Further, we are concerned that, if small distributed generation
units become the industry norm, Inclusion 4 could unintentionally sweep in local distribution systems,
especially where local policies favor the growth of small solar or other renewable generation systems
for public policy reasons. Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the requirements of Exclusion E1
or a Local Network meeting the requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that dispersed small-scale generators
scattered throughout a Radial System or Local Network serving retail load would not convert the

Radial System or Local Network into a BES system, even if the aggregate capacity of those small
generators exceeds the relevant threshold.
No
KEC has several concerns about the new language in Inclusion 5. First, because Reactive Power
devices produce power, they are “power producing resources” and we therefore believe Inclusion 5 is
duplicative of Inclusion 4, which addresses “power producing devices.” Second, there is no capacity
threshold specified in Inclusion 5 for Reactive Power devices that would be considered part of the
BES. This is inconsistent with the approach taken in the balance of the definition, where thresholds
are specified for generators and other types of power producing devices. Finally, KEC believes the
appropriate threshold for inclusion or exclusion of Reactive Power devices from the BES should be
subject to the same technical analysis that will cover generators in the Phase II process.
Yes
KEC continues to support the radial system exclusion, which is necessary as a legal matter, because,
for example, FERC in Orders No. 743 and 743-A has required that the existing radial exemption in the
NERC Statement of Compliance Registry Criteria be maintained. As a practical matter, radial systems
are used for service to retail loads, usually in remote or rural areas, and not for the transmission of
bulk power. Hence, operation of the radials has little or nothing to do with the reliable operation of
the interconnected bulk transmission network. We also support the inclusion of the note discussing
normally open switches because this language provides needed clarity for a common radial system
configuration. We also agree with the substantive thrust of this language, which is that a radial
system should not be considered part of the BES if it is interconnected at a single point, even if there
is an alternative point of delivery that is normally open. While we support the Exclusion for Radial
Systems, we believe several clarifications and refinements are necessary. (1) The term “transmission
Elements” in the initial paragraph should be changed to “Elements.” Radial systems are not
transmission systems and including the word “transmission” in the Radial System exclusion is
therefore unnecessary and confusing. (2) Subparagraph (b) of Exclusion 1 refers to “generation
resources . . . with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)”). We
urge the SDT to replace this language with the defined term “Qualifying Aggregate Generation
Resources,” discussed in more detail in our response to Question 3. This language, or some
equivalent, will preserve the SDT’s ability to revise the 75 MVA threshhold in Phase II, with the result
of Phase II included in the BES Definition by operation rather than requiring further revision of the
Definition. (3) Subparagraph (b) also seems to assume that if a Radial System contains a generator
exceeding the 75 MVA threshhold, the Radial System itself must be included in the BES because it
links the generator to the interconnected bulk transmission system. As discussed more fully in our
response to Question 9, below, NERC’s Project 2010-17 Standards Drafting Team and GO-TO Task
Force have both concluded that this assumption is unwarranted. (4) The “Note” as drafted by the SDT
indicates that “a normally open switching device between radial systems” will not serve to disqualify
the Radial from exclusion under Exclusion 1. As noted above, KEC strongly supports the note
conceptually. However, we believe this language should be included in a separate subparagraph (d),
rather than a note, because treatment as a “note” suggests it is less important than other portions of
the Exclusion. We also suggest the language be changed to read: (d) Normally-open switching
devices between radial elements as depicted and identified on system one-line diagrams does not
affect this exclusion. This will make clear that a radial with more than one normally-open switch
connecting it to another radial is still a radial. From the perspective of the BES Definition, the key
question is whether switches operating between Radials are normally open, not whether there is more
than one normally-open switch.
Yes
KEC supports the revised language. The language provides clarity regarding the BES status of
customer-owned cogeneration facilities. However, KEC urges the SDT to remove the reference to the
75 MVA threshhold and replace it with the defined term “Qualifying Aggregate Generation Resources”
or some equivalent language for the reasons stated in our responses to Questions 3, 5, and 7. In
addition, we are concerned that Exclusion 2 will place local distribution utilities in a difficult position
because, under Exclusion 1 or Exclusion 3 as drafted, they could lose their status as a Radial System
or a Local Network through the actions of a customer constructing behind-the-meter generation, With
respect to Radial Systems, the appearance of behind-the-meter generators could cause the Radial
System to exceed the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no
fault of the Radial System owner. Similarly, a Local Network could lose its status because behind-the-

meter generation could be of sufficient size that power moves into the interconnected grid in certain
hours or under certain contingencies, rather than moving purely onto the Local Network, as required
in subparagraph (b) of Exclusion 3. The Exclusions for Radial Systems and Local Networks should be
made consistent with the Exclusion for behind-the-meter generation. There is no technical reason to
believe the power flowing from a behind-the-meter customer-owned generator will have less impact
on the bulk system than an equivalent-sized generator owned by a utility operating a Radial System
or LN.
Yes
KEC strongly supports the categorical exclusion of Local Networks (“LNs”) from the BES. We believe
the exclusion is necessary to ensure that the BES definition complies with the statutory requirement,
discussed in our response to Question 1, to exclude all facilities used in the local distribution of
electric power. LNs are, of course, probably the most common form of local distribution facility.
Further, the conversion of radial systems to local distribution networks should be encouraged because
networked systems generally reduce losses, increase system efficiency, and increase the level of
service to retail customers. If the BES definition were to provide an exclusion for radials without
providing a similar exclusion for LNs, however, it would discourage networking local distribution
systems because of the significantly increased regulatory burdens faced by the local distribution utility
if it elected to network its radial facilities. By placing radial systems and LNs on the same regulatory
footing, the proposed definition will ensure that decisions about whether to network radial systems
are made on the basis of costs and benefits to the retail customers served by those radials, and not
on the basis of disparate regulatory treatment. Consumers will ultimately benefit from the path
chosen by the SDT. KEC also supports specific refinements made to the LN exclusion by the SDT in
the current draft of the BES definition. In particular, KEC supports the clarification of the purposes of
a LN. The current draft states that LNs connect at multiple points to “improve the level of service to
retail customer Load and not to accommodate bulk power transfer across the interconnected system.”
KEC supports this change in language because it reflects the fundamental purposes of a LN and
emphasizes one of the key distinctions between LNs and bulk transmission facilities, namely, that LNs
are designed primarily to serve local retail load while bulk transmission facilities are designed
primarily to move bulk power from a bulk source (generally either the point of interconnection of a
wholesale generator or a the point of interconnection with another bulk transmission system) to one
or more wholesale purchasers. KEC believes further improvement of the language could be achieved
with additional modifications and clarifications. With respect to the core language of Exclusion 3, we
believe the language making a “group of contiguous transmission Elements operated at or above 100
kV” the starting point for identifying a LN would be improved by deleting the term “transmission” from
this phrase. This is so because LNs are not used for transmission and the use of the term
“transmission Elements” is therefore both confusing and unnecessary. There would be no room for
argument about what the SDT intended by including the word “transmission” if the word is deleted
and the Exclusion applies to any “group of Elements operated at 100 kV or above” that meets the
remaining requirement of the Exclusion. Further, any definitional value that is added by using the
term “transmission Elements” is accomplished by using that term in the core definition, and there is
no reason to carry the term through in the Exclusions. KEC also believes that subparagraphs (a) and
(b) are redundant in the sense that whatever protection is offered by the generation limit in
subparagraph (a) is duplicated by the limit in subparagraph (b) requiring no flow out of the LN. We
believe the SDT can eliminate subparagraph (a) of Exclusion 3 and simply rely on subparagraph (b)
because if power only flows into the LN even if it interconnects more than 75 MVA of generation, the
interconnected generation interconnected will have no significant interaction with the interconnected
bulk transmission system. It will only interact with the LN. And, with the advent of distributed
generation, it is easy to foresee a situation in which a large number of very small distributed
generators are interconnected into a LDN, so that the aggregate capacity of these generators exceeds
75 MVA. However, because the generators are small and dispersed and, under the criterion in
subparagraph (b), would be wholly absorbed within the LN rather than transmitting power onto the
interconnected grid, those generators would not have a material impact on the grid. We also suggest
that subparagraph (b) of Exclusion 3 could be more clearly drafted. Subparagraph (b), as part of the
requirement that power flow into a LN rather than out of it, includes this description: “The LN does
not transfer energy originating outside the LN for delivery through the LN.” We understand this
language is intended to distinguish a LN from a link in the transmission system – power on a
transmission link passes through the transmission link to a load located elsewhere, while power in a
LN enters the LN and is consumed by retail load within the LN. While we agree with the concept

proposed by the SDT, we believe the language would be clearer if it read: “The LN does not transfer
energy originating outside the LN for delivery through the LN to loads located outside the LN.” We
believe the italicized language is necessary to distinguish between a transmission system, where
power that originates outside a system is delivered through the system and passes through the
system to a sink located somewhere outside the system, from a LN, in which power originating
outside the LN passes through the LN and is delivered to retail load within the LN. To put it another
way, the italicized language helps distinguish a transmission system from an LN, in which the LN
“transfers energy originating outside the LN for delivery through the LN to loads located within the
LN.” We also believe the language of subparagraph (a) of Exclusion 3 could be improved.
Subparagraph (d) would make LNs part of the BES if they interconnect “non-retail generation greater
than 75 MVA (gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and
7, we urge the SDT to replace the reference to a hard 75 MVA threshold with the defined term
“Qualifying Aggregate Generation Resources” or some equivalent. We are also uncertain what is
meant by the use of the term “non-retail generation” in subparagraph (a). From context, we believe
the SDT considers “non-retail generation” to mean generation that is used by retail customers located
within a LN rather than being exported and sold on wholesale markets outside the LN. We therefore
suggest that the SDT replace the phrase “non-retail generation” with the phrase “generation sold in
wholesale markets and transmitted outside the LN.” Similarly, we are unsure what is meant by the
phrase “the LN and its underlying Elements.” We believe the phrase “and its underlying Elements”
could simply be deleted from the definition without loss of meaning. In the alternative, the SDT might
consider using the phrase “the LN, including all Elements located on the distribution side of any
Automatic Fault Interrupting Devices (or other points of demarcation) separating the LN from the bulk
interstate transmission system.” We believe this phrase more accurately reflects the SDT’s intent,
which appears to be that generation exceeding 75 MVA in aggregate capacity interconnected
anywhere within the LN disqualifies that LN from being excluded from the BES under Exclusion 3.
Finally, KEC believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as
long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as
a Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that
allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
transmission of electricity on the interconnected bulk system. Apart from these specific improvements
that we believe could be achieved by modifying the language of Exclusion 3, we believe the SDT may
need to re-examine certain assumptions that appear to underlie the current draft. Specifically,
subparagraph (a) suggests that if BES generation is embedded within a LN, the LN itself must also be
BES. But two NERC bodies have already addressed similar questions and concluded there is no
technical basis for such concerns. NERC’s Standards Drafting Team for Project 2010-07 and its
predecessor, the “GO-TO Task Force” were formed to address how the dedicated interconnection
facilities linking a BES generator to high-voltage transmission facilities should be treated under the
NERC standards. The GO-TO Team concluded that by complying with a handful of reliability
standards, primarily related to vegetation management, reliable operation of the bulk interconnected
system could be protected without unduly burdening the owners of such interconnection systems.
Therefore, there is no reason, according to the GO-TO Team, that dedicated high-voltage
interconnection facilities must be treated as “Transmission” and classified as part of the BES in order
to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for Generator
Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO Task
Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most often
not part of the integrated bulk power system, and as such should not be subject to the same level of
standards applicable to Transmission Owners and Transmission Operators who own and operate
transmission Facilities and Elements that are part of the integrated bulk power system.” White Paper
Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at the
Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to comply
with the same standards as BES Transmission Owners and Operators “would do little, if anything, to
improve the reliability of the Bulk Electric System,” especially “when compared to the operation of the
equipment that actually produces electricity – the generation equipment itself.” Id. We believe that
interconnection of BES generators within a LN is analogous and that, based on the findings of the
Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply because a large
generator is embedded in the LN will result in substantial overregulation and unnecessary expense
with little gain for bulk system reliability. If anything, generation interconnected through a LN is less

likely to produce material impacts on the interconnected bulk transmission system than the
equivalent generator interconnected through a single dedicated line because an LN is interconnected
to the bulk system at several points, so that if one interconnection goes down, power can still flow
from the BES generator to the bulk system on other interconnection points. Where a dedicated
interconnection facility is involved, by contrast, if the interconnection line fails, the generator is
unavailable to the interconnected bulk system. Similarly, we suggest that the SDT re-examine the
assumptions underlying subparagraph (b), which seems to suggest that a local distribution system
cannot be classified as a Local Network if power flows out of that system at any time, even if the
amount is de minimis, the outward flow is only for a few hours a year, or the outward flow occurs
only in an extreme contingency. Accordingly, we suggest that the initial clause of subparagraph (b) be
revised to read: “Except in unusual circumstances, power flows only into the LN.”
Yes
KEC supports the revised language because retail reactive devices are used to address local customer
or retail voltage issues, rather than voltage issues on the interconnected bulk grid, and such local
devices should therefore be excluded from the BES definition.
No
KEC extends its thanks to the SDT and to the many industry entities that have actively participating in
the Standards Development Process. KEC strongly supports the current draft and believes, with
certain refinements discussed in our comments, that the definition will serve the industry and
reliability regulators well for many years to come. In addition, as noted earlier, KEC is encouraged
that the 20/75 MVA generation thresholds referred to in the NERC Statement of Compliance Registry
Criteria, which have been relied upon by the SDT largely as a matter of necessity, will be reviewed
and a technical assessment will be performed to identify the appropriate generation unit and plant
size threshold to ensure a reliable North America. Finally, we understand that the Rules of Procedure
Team will continue to move forward with developing an Exceptions Process that will complement the
BES Definition and ensure that, to the extent the BES Definition is over-inclusive, facilities that should
not be classified as BES will be excluded from the BES. Because the Exceptions Process is integral to a
workable BES Definition, we support the current process for moving forward with the Exceptions
Process and the BES Definition on parallel paths. We note that KEC specifically supports the changes
made by the SDT in the “Effective Date” provision of the BES Definition, which shortens the effective
date of the new definition to the beginning of the first calendar quarter after regulatory approval (as
opposed to the first calendar quarter twenty-four months after regulatory approval), with a 24-month
transition period. KEC supports this conclusion because it will allow entities seeking deregistration
under the terms of the new BES definition to obtain the benefits of the new definition without an
unreasonable wait, while allowing any entities that may be newly-classified as BES owners or
operators sufficient time to come into compliance with newly-applicable Reliability Standards. KEC
also supports the 24-month transition period for the reasons laid out by the SDT.
Individual
Andy Pusztai
ATC LLC
Yes
Yes
Yes
Yes
Yes
No
ATC agrees with the inclusion provided the last clause is removed, as noted below. The BES definition
is intended to establish a bright line BES definition. The clause “dedicated transformer” is undefined
and unclear. Inclusion I5 –Static or dynamic devices dedicated to supplying or absorbing Reactive

Power that are connected at 100 kV or higher (deletion of remainder of clause).
Yes
Unless there is a specific reason to the contrary, ATC suggests that Exclusion E1b include the
qualification of “aggregate capacity of non-retail generation less than or equal to 75 MVA” to be
consistent with the wording in E1c.
Yes
No
ATC agrees in general with the exclusions for E3 pending the following changes: Power flows only into
the LN: The LN does not transfer energy originating outside the LN for delivery through the LN under
normal operating conditions (n-0 contingency); and ATC suggests considering a different approach for
the power flow criteria in Exclusion E3b: Inclusion E3b - No Firm Power Transfers are scheduled to
flow out of, or through, the LN in the operating horizon [for BES designations applicable to the
operating horizon] and no Firm Power Transfers are reserved to flow out of, or through, the LN in the
planning horizon [for BES designations applicable to the planning horizon).
Yes
No
Group
Sandra Shaffer
PacifiCorp
Yes
PacifiCorp believes the SDT continues to make substantial progress towards a clear and workable
definition of the Bulk Electric System (“BES”) that markedly improves both the existing definition and
the SDT’s previous proposal. PacifiCorp strongly supports the new definition, conditioned on: (1) a
workable Exceptions process being developed in conjunction with the BES definition; and, (2) the SDT
moving forward expeditiously on Phase II of the standards development process in accordance with
the SAR recently put forward by the SDT.
Yes
PacifiCorp suggests a clarification to I1 to provide as follows: “Transformers with either primary or
secondary terminals, or both, that operate at or below 100 kV are not part of the BES.”
No
Requiring owners of single generators (20 MVA – 75 MVA) to meet reliability standards that owners of
distributed power producing resources (See I4) do not have to meet is discriminatory. The limit for a
single unit should be set to 75 MVA until such time as a technical review can determine the
appropriate levels for all generation resources. However, even with this concern, PacifiCorp supports
the entire BES definition in its current form based on the timeframe under which the SDT is operating
and with an emphasis based on a phase II SAR to address PacifiCorp’s objections regarding
generation levels.
Yes
PacifiCorp supports the removal of reference to Cranking Paths in I3. There is no reason to classify as
BES the facilities interconnecting a BES generator to the interconnected transmission system.
No
Setting a dispersed power producing resource limit to 75 MVA at a common point discriminates
against single generator owners who own generators between 20 MVA and 75 MVA (inclusion I1),
typically connected at a common point and requires such owners to be subject to additional standards
that dispersed power producing owners are not required. However, even with this concern, PacifiCorp
supports the entire BES definition in its current form based on the timeframe under which the SDT is
operating and with an emphasis based on a phase II SAR to address PacifiCorp’s objections regarding
generation levels. Under the attached scenario, please identify which elements would be considered
BES: This response included a drawing. This format will not allow the submission of the drawing. The
drawing will be sent separately in an email. Reference "Proj 2010-17 PAC Drawing".

No
PacifiCorp recommends the addition of the phrase “…unless excluded under E1 or E3.” Otherwise,
PacifiCorp believes that I5 is currently acceptable. However, phase II should identify limits and
technically justify the appropriate limit(s).
Yes
: The note in E1 as written is ambiguous and requires clarification. PacifiCorp assumes the note
means that two radial systems separated by a normally open switching device allows for the exclusion
of both radial systems. PacifiCorp recommends that the SDT revise the note to serve as a paragraph
clarifying E1 that, “Radial systems separated by normally open switching device(s) as depicted on
prints or one-line diagrams for example, and operated in the normally open position, except during
abnormal operating conditions, qualifies both radial systems under this exclusion.”
Yes
Yes
PacifiCorp strongly supports the categorical exclusion of Local Networks (“LNs”) from the BES.
PacifiCorp believes the exclusion is necessary to ensure that the BES definition complies with FERC’s
statutory jurisdictional requirements. PacifiCorp recommends the following modifications: • Change
“contiguous transmission Elements” to “contiguous Elements”. • Modify item b to state, “Power flows
only into the LN during normal operating conditions: The LN does not transfer energy originating
outside the LN for delivery to loads located outside the LN…” • Add an item (may be included in item
b) to provide as follows: “The LN is not critical (or is not relied upon) to maintain the reliability of the
interconnected system during abnormal operating conditions.”
Yes
No
It is absolutely imperative that phase II continue as proposed by the STD. If phase II was not
proposed PacifiCorp would vote no on this proposal.
Group
Heather Hunt
NESCOE
No
The New England States Committee on Electricity (“NESCOE”) appreciates the opportunity to provide
comments on the revised BES definition. NESCOE is New England’s Regional State Committee and
represents the collective views of the six New England states. Please consider this submission to
reflect the views of the States of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island
and Vermont. Some of these states may submit separate comments in addition to this joint filing.
NESCOE does not believe that the proposed changes address our fundamental concerns. As NESCOE
pointed out in its comments on the previous draft, the definition’s reliance on a 100 kV “bright line”
threshold may impose substantial costs on New England ratepayers without achieving meaningful
reliability benefits. NERC and the drafting team have not provided any technical justification for
imposing the 100 kV test, despite its potential for over-inclusiveness and significant costs. NESCOE
believes that the Federal Energy Regulatory Commission (“FERC” or “the Commission”) recognizes the
need to avoid this result. As the Commission pointed out in Order 743A, Order 743 does not mandate
the application of a 100 kV threshold, and NERC is free to propose alternatives. Unless and until NERC
provides a technical justification for its approach, the Standard should use the 100 kV threshold
concept in a way that is consistent with the Commission’s guidance. Specifically, the Standard should
make clear that the 100 kV threshold is an “initial line of demarcation,” and not the end of the
analysis. According to Order 743A, the two criteria that bound the BES definition are (1) the statutory
exclusion of facilities used in local distribution, and (2) the requirement that the facilities included be
“necessary for reliable operation” of the interconnected transmission system. A definition that
recognizes these limits, coupled with an efficient and transparent exceptions process, would meet
FERC’s expectations. The proposed definition does not meet this standard. For these reasons, absent
a technical justification for imposing a 100 kV threshold, NESCOE suggests the following revised core
definition: “All Transmission Elements operated at 100 kV or higher and Real Power and Reactive
Power resources connected at 100 kV or higher that are necessary for the reliable operation of the

interconnected transmission network, including but not limited to the facilities listed below as
Inclusions, and excluding (1) facilities that are used in the local distribution of electric energy, and (2)
the facilities and systems listed below as Exclusions. Other Elements may be included or excluded on
a case-by-case basis through the Rules of Procedure exception process.” Where FERC had concerns
that the existing definitions for the bulk power system were under-inclusive, the proposed Standard
risks erring in the opposite direction. Because the definition of the BES is critical to NERC’s role as
ERO and will have a significant impact on ratepayers, NESCOE believes the drafting team should track
FERC’s guidelines as closely as possible, or provide a specific technical justification for relying on the
100 kV bright line threshold.
No
NESCOE supports the revised Inclusion I1 language that treats Exclusions E1 and E3 as alternative
exclusions, either of which may qualify as an exclusion. However, specificity is needed regarding what
equipment is included in I1 (e.g., autotransformers, PARs, primary, secondary, tertiary windings).
No
Failing to establish a known MVA rating at this stage is problematic. The BES definition cannot be
considered in a vacuum, and adjusting or establishing thresholds such as MVA ratings will create
regulatory uncertainty and may result in additional costs and unnecessary system upgrades.
Additionally, Inclusion I2 should remove the reference to the Statement of Compliance Registry
Criteria. The definition should be the governing document regarding generation that is included in the
BES.
No
While NESCOE appreciates that cranking paths were excluded in response to industry comments, as
we stated in comments to the prior posting of the BES definition, blackstart units should be excluded
from the BES. Such units are appropriately covered under regional restoration procedures and
applicable NERC standards (see for example, Emergency Operating Procedure EOP-005-2). However,
should blackstart units be included in subsequent postings of the definition, we suggest that the
language be revised to state that only those units “material to” the BES are included.
No
NESCOE continues to disagree with this proposed inclusion. NESCOE is concerned with the potential
adverse impact this may have on the development of renewable generation resources. In addition,
NESCOE suggests that the aggregate 75 MVA of connected generation is too low and is not
adequately supported by technical analysis. The threshold value should be related to the largest
contingency the applicable control area is designed to operate to. A level of 300 MVA would be
appropriate. Finally, the inclusion needs to be clarified in order that entities have clear guidance on
what is meant by “common point of interconnection.”
No
NESCOE believes that inclusion of all devices that supply reactive power to the BES is unnecessary
and will result in transferring unjustified costs to the ratepayer. Static devices (fixed capacitors)
should remain excluded from the BES as they are dispatched by operations personnel, and if one
fixed capacitor bank fails, the operator can replace its impact by switching in another fixed bank. This
represents routine operation of the system. On the other hand, dynamic devices may be important to
maintaining voltage stability of the system. These installations typically are rated to supply or absorb
75 MVA or more to or from the BES. Therefore, NESCOE suggests that dynamic reactive power
devices rated at 75 MVA or more be included in the BES. Further, revised inclusion I5 is a new
inclusion that lacks definition (and appears to be redundant with the general BES definition). NERC
should provide additional technical justification for the additional language under Inclusion I5.
Yes
NESCOE suggests that the aggregate 75 MVA of connected generation is too low and would benefit
from additional technical justification. The threshold value should be related to the largest
contingency to which the applicable control area is designed to operate. A level of 300 MVA would be
appropriate. This 300 MVA limit represents 25% of the 1200 MVA loss of source that is typically
assumed for operation of the Northeast portion of the Eastern Interconnection. Depending on system
conditions, this number may be as high as 1500 MVA. Therefore, the suggested value of 300 MVA has
a technical basis and falls well within typical loss of source expectations for the Northeast.
Yes

While NESCOE generally supports Exclusion E2, no information has been provided by NERC
demonstrating that the 75 MVA rating is based on any sound technical analysis.
Yes
NESCOE generally supports this exclusion but believes it is too narrow. As noted in the response to
question 7, Exclusion E3 should allow a higher level of aggregate generation MVA on a Local Network
(at least 300 MVA). In addition, NESCOE believes that local networks should not necessarily be
ineligible for Exclusion E3 simply because an amount of power may transfer out of the network at
times. NERC’s draft technical network exclusions document should be amended such that local
networks would be permitted to qualify for network exclusions under E3 if power flowing out of the
network is minimal and would not likely adversely impact the BES. For example, transfers of less than
or equal to 100 MVA should not have any adverse impact on the BES. The draft technical network
exclusions document should be amended to state that transfers of 100 MVA MVA into the BES from
the local distribution network are acceptable. The 100 MVA limit suggested here represents 25% of
the rated value of a typical 345/115 substation (typically on the order of 400 MVA). Rarely does more
than a fraction of the rated MVA flow from the low voltage side to the high voltage side. An allowance
of 100 MVA represents a flow level will have no significant impact to the interconnected bulk power
network.
Yes
While we are generally supportive of this exclusion, the term “retail” needs to be clarified (i.e., are
retail customers of all sizes intended to be excluded?).
Yes
NESCOE offers the following additional comments: 1) Phased Approach. While well-intentioned,
separating the BES definition project into two separate phases is problematic from both a procedural
and substantive perspective. While we recognize that the filing due date is rapidly approaching, the
BES definition cannot be considered in a vacuum, divorced from the concerns raised by a number of
parties in response to past postings of the BES definition. The issues NERC has identified for
consideration during the proposed “Phase 2” are inseparable from the development of the BES
definition and should be squarely addressed before a definition is adopted. In particular, the
development of criteria for determining what facilities are “necessary for the reliable operation” of the
interconnected system cannot be put off for a second phase. Contrary to FERC’s direction, NERC’s
proposal will force ratepayers to incur costs related to compliance with mandates that may or may not
be revised through the second phase of the project. The importance of considering and resolving such
concerns before adopting a definition is heightened by the proposed two-year implementation
requirement. This short implementation period almost guarantees that entities will commit resources
shortly after adoption of the definition to ensure compliance within the mandated period. In other
words, ratepayers will bear costs related to compliance irrespective of any change resulting from the
Phase 2 process or the exception process. Expediency, while understandable given the filing deadline,
must be balanced against the risk that a multi-phased approach could lead to significant consumer
costs without attendant meaningful reliability benefits. 2) Cost-Benefit Analysis. A cost impact
analysis should be performed as part of developing any reliability standard. However, the
development of the BES definition has failed to consider the cost impacts of the definition (and its
inclusions and exclusions) and weigh these impacts against identified benefits that the definition
would achieve. NESCOE stated in its May 21, 2011 comments on the last posting of the BES definition
that “any new costs a revised definition imposes – which fall ultimately on consumers – should
provide meaningful reliability benefits.” A cost-benefit analysis should be integral to the development
of a BES definition and, indeed, any reliability standard. This analysis should include a probabilistic
risk assessment examining the likelihood of an event and the costs and risks resulting from such
event, which should be weighed against the costs of complying with the proposed reliability
measures. 3) Technical Justification. In addition to performing a cost-benefit analysis, a technical
basis must be provided to justify a proposed reliability standard. However, as we state above, the
proposed BES definition does not provide a technical justification for the 100 kV threshold. Nor does it
provide a technical justification for the threshold for generation resources or other elements of the
definition. As stated above, while well-intentioned and understandable, deferring this technical
justification to a later and separate phase of the project is a flawed and potentially costly approach.
Providing a technical justification for a reliability standard is a core function of standards development
and should be addressed at the forefront of the process rather than relegated to a separate phase
largely undertaken after a standard is filed.

Individual
Bo Jones
Westar Energy
No
The last sentence of the core part of the definition states that no distribution facilities will be included,
but we feel that some of these facilities could be included due to also being blackstart resources. We
agree with the idea of removing distribution facilities, but would like to see some clarification or a
qualifier with regards to blackstart resources.
Yes
Yes
Yes
No
We believe that the removal of the wording “single site” in I2 would eliminate the need to include
dispersed power producing resources in I4. We feel that I4 should be removed to reduce redundancy
in the definition, unless there is some other reason to include it. Also, we understand that 75 MVA is
retained in I4 because there is no direct link to the ERO Statement of Compliance Registry Criteria,
but we have concerns that this number could change in phase two of the project, creating
unnecessary work in the future.
No
We understand that I5 is being used to capture those devices other than generation resources, but
the language used leads us to believe that it could include all generators that supply or absorb
reactive power. We also believe the language should be changed to be consistent with I1. We suggest
that I5 be changed to read: “Static or dynamic devices specifically used for supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with a
high-side terminal operated at 100 kV or higher, or through a transformer that is designated in
Inclusion I1.”
Yes
No
As expressed in our comment to question 5, we have concerns that the 75 MVA number could change
in phase two of the project, creating unnecessary work in the future.
Yes
No
This particular Exclusion doesn’t address the qualifier as to the impact to the BES. We believe the
qualification language in E2, in regards to behind the meter generation, should also be included in
Exclusion E4 for clarification purposes.
Yes
We believe a reference should be made to the ROP changes which also provide a mechanism whereby
Elements may be excluded or included in the BES. Without that reference, the proposed definition is
not all inclusive of all means for exclusions or inclusions. We would suggest the definition be
expanded to say “Unless modified by the lists shown below or as provided by Appendix 5C of the
NERC Rules of Procedure, all Transmission…” This comment was submitted in response to the original
posting and the response received was that it was inadvertently left out and that it would be placed
back in, but we don’t see the reference in this draft of the definition.
Individual
Mary Downey
Redding Electric Utility
Yes

Yes
Yes
Redding believes that the definition should drive what appears in the Registry Criteria, therefore we
only support this on a temporary basis based on the premise that the BES Phase 2 technical analysis
will identify and provide technical support for determining the appropriate minimum MVA rating for a
single unit or the aggregation of multiple units.
Yes
Redding recommends the following rewording: “The Primary Blackstart resources designated in the
Transmission Operator’s restoration plan.” We believe it reduces reliability if all Blackstart generation
either primary or secondary are required to be BES. Requiring all Blackstart capable units to be BES
creates an incentive to leave certain blacstart units out of restoration plans in order to avoid BES
inclusion. By making only the primary Blackstart unit a BES element then Transmission Operators will
be more willing to include ALL Blackstart units in their plan thus creating a complete procedure for the
Transmission Operator to restore the system.
Yes
Yes
Redding believes that an appropriate MVAr level should be established during Phase 2.
Yes
Yes
Yes
Yes
Yes
Individual
Paul Cummings
City of Redding
Yes
Redding is concerned that NERC has a predetermined definition of Distribution Facilities and will not
evaluate networked distribution facilities fairly. NERC stated their predetermined position in their
“MOTION TO INTERVENE AND COMMENTS OF THE NORTH AMERICAN ELECTRIC RELIABILITY
CORPORATION” filed in the case of the City of Holland, Michigan (Docket No. RC11-5-000). On page
10 and 11 of this motion, under the section labeled “A. Holland’s 138 kV lines are transmission rather
that local distribution facilities” NERC states “Distribution facilities generally are characterized as
elements that are designed and can carry electric energy (Watts/MW) in one direction only at any
given time from a single source point (distribution substation) to final load centers.” NERC is clearly
states that only radial facilities are considered distribution facilities and are unwilling to consider that
network facilities over 100Kv could be classified as Distribution Facilities. Holland’s claim of NERC over
reaching their authority appears to have credibility. In conclusion, Redding supports the addition of
Distribution Facilities as an exclusion but believes that the BES Definition phase 2 needs to clearly
define the difference between Distribution and Transmission Facilities by identifying the equipment
“necessary for the Reliable Operation of the interconnected bulk power transmission system”.
Yes
Yes
Redding believes that the definition should drive what appears in the Registry Criteria, therefore we

only support this on a temporary basis based on the premise that the BES Phase 2 technical analysis
will identify and provide technical support for determining the appropriate minimum MVA rating for a
single unit or the aggregation of multiple units.
Yes
Redding recommends the following rewording: “The Primary Blackstart resources designated in the
Transmission Operator’s restoration plan.” We believe it reduces reliability if all Blackstart generation
either primary or secondary are required to be BES. Requiring all Blackstart capable units to be BES
creates an incentive to leave certain blacstart units out of restoration plans in order to avoid BES
inclusion. By making only the primary Blackstart unit a BES element then Transmission Operators will
be more willing to include ALL Blackstart units in their plan thus creating a complete procedure for the
Transmission Operator to restore the system.
Yes
Yes
Redding believes that an appropriate MVAr level should be established in during Phase 2.
Yes
Yes
Yes
Yes
Yes
Redding is concerned that phase 2 will not produce significant rules or criteria that further define the
BES; the desire to dedicate adaquate resourses is currently high since FERC has a looming deadline
upon NERC, however without deadlines Redding believes that NERC will find it difficult to find the
expertise or desire to finish the Project.
Individual
Keith Morisette
Tacoma Power
Yes
Tacoma Power supports the core definition as currently written.
Yes
Tacoma Power supports Inclusion I1 as currently written.
Yes
Tacoma Power generally supports Inclusion I2 and deferring the appropriate quantitative thresholds
to those that will be determined in Phase 2. However, the term “gross individual” and “gross
aggregate” nameplate rating, although industry used terms, are not industry defined or uniformly
understood and applied. Nameplate ratings are determined from discussions and negotiations
between the designer, supplier and the owner and it is the owner that makes the final determination
of the generating station equipment nameplate ratings. Nameplate ratings for thermal or hydro plants
may be based on such things as: fuel mix (best, worst and average), fuel delivery capacity, reservoir
level, best efficiency point, normal operating point, ancillary equipment capacities, emissions and
discharge restrictions, continuous versus peak output and designed versus installed and tested
capacities. It would be more uniform to establish new or use existing criteria to define “gross
individual” and “gross aggregate” nameplate ratings, such as that used in the Code of Federal
Regulations CFR 18, Part 11.1, “Authorized Installed Capacity” for hydraulic units and CFR 18, Part
287.101, “Determination of Powerplant Design Capacity” for steam electric, combustion turbine and
combined cycle units.
Yes
Tacoma Power generally support Inclusion I3 as written. We continue to believe the BES should only

include the Blackstart Resources that support a regional recovery. We propose changing Inclusion I3
to read, “Blackstart Resources identified in the Transmission Operator’s restoration plan and included
in a regional restoration plan.”
Yes
Tacoma Power generally supports the Inclusion I4 as currently written. However, we support further
refinement of the aggregate nameplate rating definition and support deferring the appropriate
quantitative thresholds to those that will be determined in Phase 2.
No
Tacoma Power generally supports the intent of Inclusion I5 as currently written. However, we believe
the definition of the MVAr threshold level must be included in the Phase 2 evaluation and should be
determined in a similar manner to the generator threshold that will be determined for I2.
Yes
Tacoma Power generally supports the Exclusion E1 as currently written. However, the “note” at the
end of E1 is confusing and can be interpreted inconsistently. We recommend moving the language
from the “note” to part of the exclusion as its own section, as follows: (d) Normally-open switching
devices between radial elements as depicted and properly identified on system one-line diagrams
should not be used to deny this exclusion. Additionally, we believe it is not appropriate for E1 to state
an MVA threshold in Section b) when determining such thresholds is the purpose for Phase 2. We urge
the SDT to defer the determination of a MVA threshold in E1 to Phase 2.
Yes
Tacoma Power supports the Exclusion E2 as currently written.
No
Tacoma Power does not support the Exclusion E3 as currently written. We strongly believe that
Section c) of E3 must replace the term “transfer path” with “Major Transfer Path” to distinguish these
paths from any common ATC path. This revision is consistent with the existing language used in the
form, Detailed Information to Support an Exception Request. Additionally, we believe it is not
appropriate for E3 to state an MVA threshold in Section a) when determining such thresholds is the
purpose for Phase 2. We urge the SDT to defer the determination of a MVA threshold in E3 to Phase
2. Finally, the term “non-retail generation” is not a universally understood term in the industry. We
suggest that the SDT replace the phrase “non-retail generation” with “generation located on the retail
customer’s side of the meter.”
Yes
Tacoma Power supports the Exclusion E4 as currently written.
No
Tacoma Power does not have any other concerns at this time. Thank you for consideration of our
comments.
Individual
Rex Roehl
Indeck Energy Services
No
As acknowledged in the response to Question 12 comments on the previous BES definition, the BES
definition is expansive compared to the definition of the BPS in the FPA Section 215. The inclusion of
the limited Exclusions is an attempt to remedy the situation. However, the Exclusions need to include
a fifth one that if, based on studies or other assessments, it can be shown that any tranmission or
generator element otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There has never been
a study to show that elements, such as a 20 MW wind farm, 60 MW merchant generator (which
operates infrequently in the depressed market) in a large BA (eg NYISO) or a radial transmission line
connecting a small generator are important to the reliability of the BPS. They are covered by the
mandatory standards program through the registration criteria. The BES Definition is the opportunity
to permit an entity to demonstrate that an element is unimportant to reliability of the BPS. The SDT
has identified a small subset of elements that it is willing to exclude. By their very nature, these
exclusions dim the bright line that is the stated goal of this project. However, the SDT’s foresight
seems limited in its selections. Analytical studies are used to evaluate contingencies that could lead to

the Big Three (cascading outages, instability or voltage collapse). Such a study showing that a
transmission or generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable Disturbance of
approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW merchant generator or numerous
other smaller facilities would be bounded by larger contingencies. It would take more than six 60 MW
merchant generators with close location and common mode failure to even be a Reportable
Disturbance, much less become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 Any facility that can be demonstrated to the Regional Entity by analytical study or other assessment
to be unimportant to the reliability of the BPS (with periodic reports by the Regional Entity to NERC of
any such assessments).”

Yes
As acknowledged in the response to Question 12 comments on the previous BES definition, the BES
definition is expansive compared to the definition of the BPS in the FPA Section 215. The inclusion of
the limited Exclusions is an attempt to remedy the situation. However, the Exclusions need to include
a fifth one that if, based on studies or other assessments, it can be shown that any tranmission or
generator element otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There has never been
a study to show that elements, such as a 20 MW wind farm, 60 MW merchant generator (which
operates infrequently in the depressed market) in a large BA (eg NYISO) or a radial transmission line
connecting a small generator are important to the reliability of the BPS. They are covered by the
mandatory standards program through the registration criteria. The BES Definition is the opportunity
to permit an entity to demonstrate that an element is unimportant to reliability of the BPS. The SDT
has identified a small subset of elements that it is willing to exclude. By their very nature, these
exclusions dim the bright line that is the stated goal of this project. However, the SDT’s foresight
seems limited in its selections. Analytical studies are used to evaluate contingencies that could lead to
the Big Three (cascading outages, instability or voltage collapse). Such a study showing that a
transmission or generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable Disturbance of
approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW merchant generator or numerous
other smaller facilities would be bounded by larger contingencies. It would take more than six 60 MW
merchant generators with close location and common mode failure to even be a Reportable
Disturbance, much less become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 Any facility that can be demonstrated to the Regional Entity by analytical study or other assessment
to be unimportant to the reliability of the BPS (with periodic reports by the Regional Entity to NERC of
any such assessments).”
Group
Antonio Grayson
Transmission
Yes
Yes
Yes
No

We agree with the changes but believe clarity would be added by changing the word “identified” to
“designated”.
Yes
No
We believe that the size of the reactive power resource should be considered as a key factor to be
part of BES. When considering generating resources, the size, e.g., greater than 75 MVA, was a key
part of criteria to be included or excluded as BES. A similar approach should be applied when
considering reactive power resources. We also suggest the removal of static reactive resources from
this inclusion.
No
Subpart (b) uses the term "generation resources" while subpart (c) uses the term "non-retail
generation", why are these different terms used? Further, why is it important that the term "nonretail generation" is used in subpart (c)? In addition, the SDT needs to clarify what the term "nonretail generation" means. Is this what is commonly referred to as "customer owned" or "behind-themeter" generation? The change in version 2 that removed the requirement that an excluded radial
system have an automatic interruption device at the single point of connection to the rest of the BES
creates a problem. Three-terminal circuits are common below 230 kV. The "tapped portion" should
not be left out of the BES since a fault on that portion takes out the whole line. We propose this
revised language in the first sentence on E1: “E1 - Radial systems: A group of contiguous
transmission Elements that emanates from a single point of connection of 100 kV or higher, where
the connection has an automatic interruption device,…” Exclusion E1, subpart (c) uses the phrase "an
aggregate capacity of … less than or equal to 75 MVA …". Exclusion E3. subpart (a) provides that the
local networks "do not have an aggregate capacity of … greater than 75 MVA …". Why are these
phrases stated differently even though they appear to address the same resources?
No
We suggest that clarification is needed for what is meant by E2 (ii), regarding generation on the
customer’s side of the retail meter. Also, we would like for a clarification of the difference between the
terms "retail load" and "retail customer load" as used in exclusions E2 and E3.
No
We would agree with the exclusion if the wording of the exclusion includes the following phrase (in
italics) added at the end of E3 b): “Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN “under normal operating conditions”. What does
the term "non-retail generation" mean? Can the term "non-retail generation in E3a be changed to
simply "generation"?
Yes
Yes
The definition of the BES is referenced in several existing standards and the Statement of Compliance
Registry Criteria. Southern Companies are concerned how this revised definition will impact entity
registration, i.e., how will the revised definition be integrated into the Compliance Registry Criteria.
The implementation plan should include how the integration is going to occur. The Rules of Procedure
exception process should be further defined or referenced in this definition.
Group
Al DiCaprio
PJM
No
While we agree with the changes to the definition, we do not understand the purpose of the final
sentence “This does not include facilities used in the local distribution of electric energy.” Since the
issue of local (distribution) networks is addressed under Exclusion E3, we do not see the added
benefit of the referenced text.
Yes

Yes
No
We support the SDT’s decision to exclude the cranking paths from the BES definition since testing and
verification of the use of facilities in the cranking path is already covered by the appropriate EOP
standards. This inclusion is extraneous given there is already a designation specific for system
restoration covered by an existing standard to recognize their reliability impacts and to ensure their
expected performance. NERC Standards EOP-005-2 stipulates the requirements for testing blackstart
resource and cranking paths. This testing requirement suffices to ensure that the facilities critical to
system restoration are functional when needed, which meets the intent of identifying their criticality
to reliability. We therefore suggest removing Inclusion I3.
Yes
The revised Inclusion I4 does clarify that there is no requirement for a contiguous BES path from the
dispersed generation resources to the point of interconnection to the BES.
Yes
No
While we support the provisions of E1 in principle, we are seeking clarification to the following issues.
Does the connection voltage of generation referred to in E1.b affect whether a radial system could be
excluded under E1? Please clarify the meaning of “non-retail” generation used in E1.c.
Yes
Yes
Yes
Yes
(1) We support a phased approach proposed in the draft supplemental SAR. Development of the
revised BES definition is an important and complex undertaking. The product of this work is
fundamental to establishing the applicability of NERC Reliability Standards. The issues identified for
attention in Phase 2 of this project warrant careful investigation and as such allowing additional time
to properly research and provide for stakeholders to vett them is justified. Specific to the assessment
of raising the generator rating threshold from 20 MVA to 75 MVA per unit, we would point out that
this needs to be looked at from a different perspective. Industry debates so far have been on the
apparent lack of reliability contribution and economic benefits for keeping the threshold at 20 MVA.
The former point implies that any negative reliability impact that could be contributed by a generator
higher than 20 MVA but lower than 75 MVA could be negligible. Some examples of the standards that
the 20-75 MVA units may need to comply with to ensure reliability are: • Voltage and frequency ride
through capability • Voltage control (AVR, etc.) • Underfrequency trip setting • Protection relay
setting coordination • Data submission for modeling; verification of capability and model A Venn
diagram developed by an industry group shows that generators at 20 to 74.99 MVA account for about
13.8% of the total installed capacity in the US. Out of this, 3.0% are currently deemed non-BES
whereas the other 10.8% are BES. We do not know how the BES reliability may be affected if these
10.8% generators are no longer deemed BES facilities (after an increase of threshold to 75 MVA) and
subject to compliance with NERC standards, including those mentioned above. An assessment from
both a positive contribution and a negative impact viewpoints are thus required to aid the
determination of the merit of raising the rating threshold. (2) The draft Implementation Plan for the
BES definition states “Compliance obligations for Elements included by the definition shall begin 24
months after the applicable effective date of the definition.” We are concerned that the stated
implementation period may be insufficient time to complete transition plans for newly identified BES
Elements and Facilities, where those plans require procurement, installation and commissioning of
additional equipment. We believe a period of 24 months may be more appropriate.
Individual
Frank Cumpton

BGE
Yes
No comment.
Yes
No comment.
Yes
No comment.
Yes
No comment.
Yes
No comment.
Yes
No comment.
No
During the previous comment period, BGE asked for clarification regarding the exclusion of “radial
facilities”. The particular example configuration in question involved two 115 kV lines emanating from
two different points of connection and “tied” on the “low side” at 34.5 kV. The SDT responded that
this was not a radial facility but would be excluded under the E3-Local Network exclusion. BGE
believes that this particular configuration should be excluded under the E1-Radial Systems exclusion.
BGE does not beleive that two otherwise radial lines are made “non-radial” because they are tied at a
voltage lower than 100 kV.
Yes
No comment.
Yes
No comment.
Yes
No comment.
No
No comment.
Group
Irion A. Sanger
Davison Van Cleve PC
Yes
The Industrial Customers of Northwest Utilities (“ICNU”) submits the following comments regarding
the North American Electric Reliability Corporation’s (“NERC”) proposal for defining the Bulk Electric
System (“BES”). ICNU is an incorporated, non-profit association of large end-use electric customers in
the Pacific Northwest, with offices in Portland, Oregon. ICNU previously submitted comments in the
Western Electricity Coordinating Council’s (“WECC”) process for defining the BES. ICNU’s members
are not electric utilities, but some ICNU members own substations that are interconnected to utility
transmission systems and utility distribution systems. In addition, in some cases, ICNU members
operate local distribution facilities behind their substations to serve their end-use loads. In some
cases, the ICNU member’s interconnection to the utility-owned transmission system or distribution
system is via a utility-owned radial line; and, in others, the ICNU member’s distribution system is
looped into the utility’s transmission system for reliability purposes. Finally, some ICNU members
have local distribution systems that include the ICNU member’s backup generating facilities. ICNU is
submitting comments, because these facilities arguably could fall within NERC’s proposed definition of
BES. ICNU appreciates the work that NERC has done to date, and encourages NERC to develop a rule
that recognizes the unique aspects of the Pacific Northwest transmission system and the particular
needs of end-use customers. Given the arbitrary requirements and limitations imposed by the Federal
Energy Regulatory Commission, ICNU supports NERC’s overall approach to defining the BES. NERC
has proposed a bright line rule in which all transmission elements operated 100 kV or higher will be
included in the definition, subject to certain inclusions and exclusions. ICNU supports NERC’s goal of

excluding facilities in the local distribution of electric energy. NERC proposes three general classes of
exclusions, which includes certain radial systems, generating units that serve all or part of retail
customer’s load, and local networks. Specifically, NERC proposes that: 1) radial systems 100 kV and
higher shall be excluded if they only serve load, or only include certain generation resources less than
75 MVA; 2) generating units that serve customer load on the customer meter are excluded if the net
capacity provided to the BES does not exceed 75 MVA and standby, back up and maintenance power
services are provided; 3) local networks operated less than 300 kV that distribute power to load
rather than transfer bulk power across the interconnected system; and 4) reactive power owned and
operated by a retail customer solely for its own benefit. ICNU supports these exclusions; however,
ICNU is concerned that certain end-use retail customer facilities that do not impact the BES may still
be inappropriately included. NERC appears to recognize this possibility and includes an exception
process to include or exclude facilities on a case-by-case basis. ICNU urges NERC to develop this
exception process, and to review the work by WECC regarding how to structure an appropriate
exception. At a minimum, the exception process should not require end-use customers to perform
costly and complex studies, but should instead require utilities or regional organizations that have the
relevant expertise to conduct the necessary studies to determine if a specific facility should be
removed or included in the BES. ICNU is also concerned about the term “non-retail generation,” which
does not appear to have a corresponding definition. ICNU understands that non-retail generation is
intended to apply to generation behind the retail customer’s meter. ICNU recommends that net
metered systems should not count towards the generation limits for radial and local network systems.

Additional Comments Submitted:
Salt River Project:

Additional Comments Submitted:
PacifiCorp
5.

The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments.

Yes:

No: X

Comments: Setting a dispersed power producing resource limit to 75 MVA at a common
point discriminates against single generator owners who own generators between 20
MVA and 75 MVA (inclusion I1), typically connected at a common point and requires
such owners to be subject to additional standards that dispersed power producing
owners are not required.
However, even with this concern, PacifiCorp supports the entire BES definition in its
current form based on the timeframe under which the SDT is operating and with an
emphasis based on a phase II SAR to address PacifiCorp’s objections regarding
generation levels.
Under the attached scenario, please identify which elements would be considered BES:

Additional Comments Submitted
RFC Staff:
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements
operated at 100 kV or higher and Real Power and Reactive Power resources connected at 100 kV or
higher. This does not include facilities used in the local distribution of electric energy. The BES includes:
Inclusions:
• I1 - Transformers with primary and secondary terminals operated at 100 kV or higher. unless
excluded under Exclusion E1 or E3for local distribution or retail customers.
• I2 - Generating resources as described in the ERO Statement of Compliance Registry Criteria
including the generator terminals through the high-side of the step-up transformer(s), connected
at a voltage of 100 kV or above.
• I3 - Blackstart Resources and associated designated blackstart Cranking Paths operated at 100 kV
or higher, identified in the Transmission Operator’s restoration plan. regardless of voltage level.
• I4 - Dispersed power producing resources as described in the ERO Statement of Compliance
Registry Criteria utilizing a system designed primarily for aggregating capacity, connected at
common point at a voltage of 100 kV or above.
• I45 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are
connected at 100 kV or higher, or through a dedicated transformer with a high-side voltage of 100
kV or higher, or through a transformer that is designated in Inclusion I1.
This definition does not include facilities used in the local distribution of electric energy or retail
customers, which are:. Exclusions:
• E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher from a single Transmission source originating with a
singlen automatic interruption device and:
a) Only serves Load. Or,
b) Only includes generation resources not identified in Inclusion I3, with an
aggregate capacity less than or equal to 75 MVA (gross nameplate rating). Or,
c) Where the radial system serves Load and includes generation resources, not
identified in Inclusion I3, with an aggregate capacity of non-retail generation
less than or equal to 75 MVA (gross nameplate rating).
Note - A normally open switching device between radial systems, as depicted

on prints or one-line diagrams for example, does not affect this exclusion.
•

•

E2 - A generating unit or multiple generating units that serve all or part of retail customer Load
with electric energy on the customer’s side of the retail meter if:
o (i) the net capacity provided to the BES does not exceed 75 MVA, and
o (ii) standby, back-up, and maintenance power services are provided to the generating unit
or multiple generating units or to the retail Load by a Balancing Authority, or provided
pursuant to a binding obligation with a Generator Owner or Generator Operator, or
under terms approved by the applicable regulatory authority.
E3 - Local Network (LN): A group of contiguous transmission Elements operated at or above 100
kV but less than 300 kV that distribute power to Load rather than transfer bulk power across the
interconnected system. LN’s emanate from multiple points of connection at 100 kV or higher to
improve the level of service to retail customer Load and not to accommodate bulk power transfer
across the interconnected system. The LN is characterized by all of the following:

a) Limits on connected generation: The LN and its underlying Elements do not

include generation resources identified in Inclusion I3 and do not have an
aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating);
b) Power flows only into the LN: The LN does not transfer energy originating
outside the LN for delivery through the LN; and;
c) Not part of a Flowgate or transfer path: The LN does not contain a monitored
Facility of a permanent Flowgate in the Eastern Interconnection, a major transfer
path within the Western Interconnection, or a comparable monitored Facility in
the ERCOT or Quebec Interconnections, and is not a monitored Facility included
in an Interconnection Reliability Operating Limit (IROL).
•

E4 – Reactive Power devices owned and operated by the retail customer solely for its
own use.

Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure
exception process.

Consideration of Comments on Initial Ballot — Definition of BES (Project 2010-17)
Date of Initial Ballot: September 30, 2011 - October 10, 2011
Summary Consideration: Many commenters followed instructions and cast their ballot while simply pointing to their detailed comments in the posted
comment report. The SDT thanks those commenters as this greatly reduces the administrative workload on the SDT. Those who decided to place
comments in the ballot report for the most part echoed comments that had already been seen by the SDT in the posted comment report which was
administered first by the SDT. As a result, there were no changes to the definition due to comments received in the ballot report. However, for ease of
reference, the changes to the definition made as a result of those comments are repeated here.
The SDT made the following changes to the definition due to industry comments received:
• Clarified the wording in Inclusion I1 to indicate that at least one secondary terminal must be at 100 kV or higher to accommodate multiple terminal
transformers.
• Removed the reference to the ERO Statement of Compliance Registry Criteria in Inclusion I2 so that there is no chance of the registry values
being changed and affecting the definition prior to resolution of threshold values in Phase II of this project.
• Clarified that generators were not part of Inclusion I5 to avoid improperly pulling in small generators.
• Clarified the language of Exclusion E2 by re-ordering the text as suggested.
• Clarified the language of Exclusion E3.b as suggested.
The SDT feels that it is important to remind the industry that Phase II of this project will begin immediately after the conclusion of Phase I as SDT
resources clear up. The same SDT will follow through with Phase II.
The SDT is recommending that this project be moved forward to the recirculation ballot stage.
There were two comments that were repeated multiple times throughout the various documents. The first topic was about how to sort through the
definition inclusions and exclusions, i.e., which takes precedence. The SDT offers this guidance on that issue:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast majority of BES
Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and non-BES Elements.
Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or higher as included in the BES. To fully
appreciate the scope of the ‘core’ definition an understanding of the term Element is needed. Element is defined in the NERC Glossary of Terms as:

“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker, bus section, or
transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application of the ‘core’
definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific criteria to provide for a consistent
determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion language is
written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the exclusion language.
This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The exclusion (E1) only speaks to the
transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner. Therefore, the only inclusion
that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and supersedes inclusion
I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the interconnected
transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected transmission network, the Rules of
Procedure exception process may be utilized on a case-by-case basis to either include or exclude an Element.
The second item is about providing specific guidance on how the information on the exception request form will be used in making decisions on
inclusions/exclusions in the exception process. While not technically part of this document which is about the definition, since the question did come up in
these comments, the SDT provides the following information:
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like nothing better
than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and an initial attempt at doing so, it
has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could have come up with the simple answer, it
would have been supplied within the bright-line. The SDT would also like to point out to the commenters that it directly solicited assistance in this matter in
the first posting of the criteria and received very little in the form of substantive comments.

Project 2010-17 BES Definition Ballot Comments

2

There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are always going to be
extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that the regional discretion hasn’t been
removed from the process as dictated in the Order. However, the SDT disagrees with this position. The exception request form has to be taken in concert
with the changes to the ERO Rules of Procedure and looked at as a single package. When one looks at the rules being formulated for the exception
process, it becomes clear that the role of the Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now
one of reviewing the submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a
position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes that the visibility of the
process would belie such an action by the Regional Entity and also believes that one has to have faith in the integrity of the Regional Entity in such a
process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection
requiring an independent Technical Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s
findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides
NERC the option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or
disapproving the exception request. On the other side of this equation, one could make an argument that the Regional Entity has no basis for what
constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information aren’t
shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard and fast rules in this regard.
However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there is a great deal of
professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT
believes that both sides can quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel
for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in making their decision.
The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to take into account. Providing concrete
guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made. The SDT also refers the commenters to Appendix
5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic premise on evaluating an exception request must be based on whether the
Elements are necessary for the reliable operation of the interconnected transmission system. Further, reliable operation is defined in the Rules of
Procedure as operating the elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a cyber security incident, or
unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the
experience gained by having this same panel review multiple requests will result in an equitable, transparent, and consistent approach to the problem.
The SDT would also point out that there are options for a submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if
they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative response to the
request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the proposed Rules of

Project 2010-17 BES Definition Ballot Comments

3

Procedure that states “No single piece of evidence provided as part of an Exception Request or response to a question will be solely dispositive in the
determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry comments. The SDT
believes that these clarifications will make the process tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of experience. The SDT
believes that this time period will allow industry to see if the process is working correctly and to suggest changes to the process based on actual real-world
experience and not just on suppositions of what may occur in the future. Given the complexity of the technical aspects of this problem and the filing
deadline that the SDT is working under for Phase I of this project, the SDT believes that it has developed a fair and equitable method of approaching this
difficult problem. The SDT asks the commenter to consider all of these facts in making your decision and casting your ballot and hopes that these
changes will result in a favorable outcome.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious consideration in
this process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 4041
446-2560 or at herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.

Voter

Segment

Vote

Comment

Ameren
Services

1

Negative

Please refer to Ameren comments submitted using the Comment Form.

Andrew Z
Pusztai

American
Transmission
Company, LLC
Associated
Electric
Cooperative,
Inc.
Dominion
Virginia Power

1

Negative

Comments submitted.

1

Negative

comments posted on comment form

1

Negative

Please see Dominion’s submitted comments

John Bussman

Michael S
Crowley

1

Entity

Kirit Shah

The appeals process is in the Standards Processes Manual: http://www.nerc.com/docs/standards/sc/Standard_Processes_Manual_Approved_May_2010.pdf.

Project 2010-17 BES Definition Ballot Comments

4

Vote

Comment

Bernard
Pelletier

Voter

Hydro-Quebec
TransEnergie

1

Negative

Please see our comments on the BES Definition

Terry Harbour

MidAmerican
Energy Co.

1

Negative

Tracy Sliman

Tri-State G & T
Association,
Inc.
ISO New
England, Inc.

1

Negative

See the MidAmerican submitted comments. The BES definition needs additional
specific inclusion or exclusion provisions that clearly exclude variable resource
generation collector circuits rated below 100 kV and generators less than 20 MVA
connected to those collector circuits in accordance with the registration criteria.
Comments submitted by electronic form.

2

Negative

please refer to detailed comments submitted for this project.
SPP's comments on this concurrent ballot/comment period have been submitted
and provide support for our Negative vote. In addition, SPP is a member of the
IRC SRC and is in support of those comments on this standard. Please refer to
these sets of comments for our recommendations.
Please see comments of AECI.

Kathleen
Goodman

Entity

Segment

Charles Yeung

Southwest
Power Pool,
Inc.

2

Negative

Chris W Bolick

3

Negative

Linda
Jacobson

Associated
Electric
Cooperative,
Inc.
City of
Farmington

3

Negative

Richard
Blumenstock

Consumers
Energy

3

Negative

FEUS appreciates the SDT work in defining the BES. While the proposed definition
is an improvement over the current definition, FEUS feels there is some additional
clarification necessary before approval. Seperate comments have been submitted.
See Consumers Energy's comments on the official submittal form.

Michael F.
Gildea

Dominion
Resources
Services
Hydro One
Networks, Inc.

3

Negative

See Dominion's submitted comments.

3

Negative

After careful analysis of the proposed documents, Hydro One Networks Inc. is
casting a negative vote. We commend the SDT for the effort in facing the
challenge. However, we believe that the proposed definition and the exception
request criteria still need further work. Some issues need to be resolved before a

David Kiguel

Project 2010-17 BES Definition Ballot Comments

5

Voter

Entity

Segment

Vote

Comment
final approval is granted. Please see our detailed comments as provided in the
on-line system.

Tony
Eddleman

Nebraska
Public Power
District
Tri-State G & T
Association,
Inc.
Consumers
Energy

3

Negative

Comments were submitted through the Nebraska Public Power District comment
form.

3

Negative

Tri-State G&T Load Serving Entity comments were submitted via electronic
comment process.

4

Negative

See Comments provided by Consumers Energy Company

Brock Ondayko

AEP Service
Corp.

5

Negative

Francis J.
Halpin

Bonneville
Power
Administration
Consumers
Energy
Company
Dominion
Resources, Inc.

5

Negative

AEP believes the drafting team is on the correct path, and the concepts expressed
appear to be appropriate. However, AEP has a number of questions and
recommended refinements that if addressed by the drafting team, will make the
definition more clear to industry. These comments are being submitted via
electronic form by Thad Ness on behalf of American Electric Power.
Please refer to formal BPA Comments submitted on 10/7/2011.

5

Negative

See Consumers Energy's comments on the official comment submittal forms.

5

Negative

See comments filed on this project.

Dan
Roethemeyer

Dynegy Inc.

5

Negative

Comments will be included with those to be submitted with the SERC OC
Standards Review Group.

Christopher
Schneider

MidAmerican
Energy Co.

5

Negative

See the MidAmerican submitted comments. The BES definition needs additional
specific inclusion or exclusion provisions that clearly exclude variable resource
generation collector circuits rated below 100 kV and generators less than 20 MVA
connected to those collector circuits in accordance with the registration criteria.

Janelle
Marriott
David Frank
Ronk

David C
Greyerbiehl
Mike Garton

Project 2010-17 BES Definition Ballot Comments

6

Voter
Don Schmit

Entity

Segment

Vote

Comment

5

Negative

Please see comments submitted by Nebraska Public Power District on
10/10/2011.

Mahmood Z.
Safi

Nebraska
Public Power
District
Omaha Public
Power District

5

Negative

see Doug Peterchuck’s comments

Bo Jones

Westar Energy

5

Negative

Please see comments submitted electronically.

Edward P. Cox

AEP Marketing

6

Negative

Louis S. Slade

Dominion
Resources, Inc.

6

Negative

AEP believes the drafting team is on the correct path, and the concepts expressed
appear to be appropriate. However, AEP has a number of questions and
recommended refinements that if addressed by the drafting team, will make the
definition more clear to industry. These comments are being submitted via
electronic form by Thad Ness on behalf of American Electric Power.
See comments submitted by Dominion.

David Ried

Omaha Public
Power District

6

Negative

See Doug Peterchucks comments from OPPD.

Donald G
Jones

Texas
Reliability
Entity, Inc.
Rochester Gas
and Electric
Corp.
American
Electric Power

10

Negative

See comment form submitted separately.

1

Negative

Comments to be submitted separately.

1

Negative

Hydro One
Networks, Inc.

1

Negative

AEP believes the drafting team is on the correct path, and the concepts expressed
appear to be appropriate. However, AEP has a number of questions and
recommended refinements that if addressed by the drafting team, will make the
definition more clear to industry. These comments are being submitted via
electronic form by Thad Ness on behalf of American Electric Power.
After careful analysis of the proposed documents, Hydro One Networks Inc. is
casting a negative vote. We commend the SDT for the effort in facing the
challenge. However, we believe that the proposed definition and the exception

John C. Allen
Paul B.
Johnson

Ajay Garg

Project 2010-17 BES Definition Ballot Comments

7

Voter

Vote

Comment

10

Affirmative

request criteria still need further work. Some issues need to be resolved before a
final approval is granted. Please see our detailed comments as provided in the
on-line system.
Comments Submitted

1

Affirmative

Comments submitted

Consolidated
Edison Co. of
New York
Consumers
Power Inc.

1

Affirmative

See Con Edison’s comments on the BES Definition submitted separately by
electronic survey form.

1

Affirmative

Please see CPI's separate comment form.

William J
Smith

FirstEnergy
Corp.

1

Affirmative

FirstEnergy supports the proposed BES definition and offers comments and
suggestions through the formal comment period.

Gordon Pietsch

Great River
Energy

1

Affirmative

Please see MRO NSRF comments.

Joe D Petaski

Manitoba
Hydro

1

Affirmative

Please see comments provided by Manitoba Hydro in formal commenting period

David Thorne

Potomac
Electric Power
Co.
Puget Sound
Energy, Inc.

1

Affirmative

Comments submitted

1

Affirmative

See comments of Denise Lietz.

Sierra Pacific
Power Co.

1

Affirmative

Comments submitted.

Steven L.
Rueckert
Robert Smith
Christopher L
de Graffenried
Stuart Sloan

Denise M Lietz
Rich Salgo

Entity

Western
Electricity
Coordinating
Council
Arizona Public
Service Co.

Segment

Project 2010-17 BES Definition Ballot Comments

8

Voter

Vote

Comment

Minnkota
Power Coop.
Inc.
Muscatine
Power & Water

1

Affirmative

While MPC is voting affirmative, we ask that you see the comments submitted by
the MRO NERC Standards Review Forum (NSRF).

1

Affirmative

MPW agrees with the comments submitted by the MRO NERC Standards Review
Forum (NSRF).

David
Boguslawski

Northeast
Utilities

1

Affirmative

NU contributed to and joins with NPCC comments.

Larry Akens

Tennessee
Valley
Authority
Electric
Reliability
Council of
Texas, Inc.
Blachly-Lane
Electric Co-op

1

Affirmative

TVA has submitted comments through the Comment Form for 2nd Draft of
Definitions of BES (Project 2010-17)

2

Affirmative

ERCOT ISO has joined the IRC SRC comments submitted.

3

Affirmative

Please see BLEC's separate comment form.

Central Electric
Cooperative,
Inc.
(Redmond,
Oregon)
Central Lincoln
PUD

3

Affirmative

Please see Central's separate comment form.

3

Affirmative

Comments previously submitted.

Dave Hagen

Clearwater
Power Co.

3

Affirmative

Please see Clearwater Power's separate comment form.

Peter T Yost

Consolidated
Edison Co. of
New York

3

Affirmative

Con Edison comments have been submitted separately.

Richard Burt
Tim Reed

Charles B
Manning
Bud Tracy
Dave Markham

Steve
Alexanderson

Entity

Segment

Project 2010-17 BES Definition Ballot Comments

9

Voter

Entity

Segment

Vote

Comment

Roman Gillen

Consumers
Power Inc.

3

Affirmative

Please see CPI's separate comment form.

Roger Meader

Coos-Curry
Electric
Cooperative,
Inc
Cowlitz County
PUD

3

Affirmative

Please see CCEC's separate comment form.

3

Affirmative

Comments submitted.

Douglas
Electric
Cooperative
Fall River Rural
Electric
Cooperative
FirstEnergy
Energy
Delivery
Florida
Municipal
Power Agency
Georgia
Systems
Operations
Corporation
Holland Board
of Public Works

3

Affirmative

Please see DEC's separate comment form.

3

Affirmative

Please see FREC's separate comment form.

3

Affirmative

FirstEnergy supports the proposed BES definition and offers comments and
suggestions through the formal comment period.

3

Affirmative

Please see comments submitted through the formal comments

3

Affirmative

See electronic comment form from Georgia System Operations Corporation

3

Affirmative

Please see comment form.

Kootenai
Electric
Cooperative

3

Affirmative

Reference the comments of KEC in response to the SDT comment form.

Russell A
Noble
Dave Sabala
Bryan Case
Stephan Kern
Joe McKinney
William N.
Phinney
William Bush
Dave Kahly

Project 2010-17 BES Definition Ballot Comments
1
0

Voter
Rick Crinklaw
Michael Henry
Greg C. Parent

Entity
Lane Electric
Cooperative,
Inc.
Lincoln Electric
Cooperative,
Inc.
Manitoba
Hydro

Segment

Vote

Comment

3

Affirmative

Please see LEC's separate comment form.

3

Affirmative

Please see Lincoln's separate comment form.

3

Affirmative

Please see comments provided by Manitoba Hydro in formal commenting period

Jeff Franklin

Mississippi
Power

3

Affirmative

"Comments Submitted"

John S Bos

Muscatine
Power & Water

3

Affirmative

MPW agrees with the comments submitted by the MRO NERC Standards Review
Forum (NSRF)

Jon Shelby

Northern Lights
Inc.

3

Affirmative

Please see NLI's separate comment form.

Ray Ellis

Okanogan
County Electric
Cooperative,
Inc.
Raft River
Rural Electric
Cooperative
Springfield
Utility Board

3

Affirmative

Please see Okanogan's separate comment form.

3

Affirmative

Please see RREC's separate comment form.

3

Affirmative

Please refer to SUB's comments on the BES Definition.

Tennessee
Valley
Authority
Umatilla
Electric
Cooperative

3

Affirmative

My company has submitted comments via the comment form.

3

Affirmative

Please see UEC's separate comment form.

Heber
Carpenter
Jeff Nelson
Ian S Grant
Steve Eldrige

Project 2010-17 BES Definition Ballot Comments
1
1

Voter
Marc Farmer

James R Keller
Shamus J
Gamache
John Allen
Frank Gaffney
Guy Andrews

Joseph
DePoorter
Douglas
Hohlbaugh
Aleka K Scott

Wilket (Jack)
Ng

Entity
West Oregon
Electric
Cooperative,
Inc.
Wisconsin
Electric Power
Marketing
Central Lincoln
PUD

Segment

Vote

Comment

3

Affirmative

Please see WOEC's separate comment form.

3

Affirmative

Comments submitted.

4

Affirmative

See Central Lincoln PUD comments (CLPUD) Posted by Steve Alexanderson.

City Utilities of
Springfield,
Missouri
Florida
Municipal
Power Agency
Georgia
System
Operations
Corporation
Madison Gas
and Electric
Co.
Ohio Edison
Company

4

Affirmative

City Utilities of Springfield, Missouri supports the comments from SPP.

4

Affirmative

Please see comments through the formal comments

4

Affirmative

See electronic comment form submitted by Georgia System Operations Corp

4

Affirmative

Please see the MRO NSRF comments concerning this project.

4

Affirmative

FirstEnergy supports the proposed BES definition and offers comments and
suggestions through the formal comment period.

Pacific
Northwest
Generating
Cooperative
Consolidated
Edison Co. of
New York

4

Affirmative

Please see PNGC's separate comment form.

5

Affirmative

See Con Edison’s comments on the BES Definition submitted separately by
electronic survey form.

Project 2010-17 BES Definition Ballot Comments
1
2

Voter
David
Schumann

Entity

Segment

Vote

Comment

Preston L
Walsh

Florida
Municipal
Power Agency
Great River
Energy

James M
Howard

Lakeland
Electric

5

Affirmative

Refer to comments from FMPA.

Gary Carlson

Michigan Public
Power Agency

5

Affirmative

Comments submitted separately

William D
Shultz

Southern
Company
Generation
Wisconsin
Electric Power
Co.
Consolidated
Edison Co. of
New York
FirstEnergy
Solutions

5

Affirmative

Comments from Southern Company Generation are being submitted via the
electronic comment form available on the project web page.

5

Affirmative

Comments submitted.

6

Affirmative

Con Edison comments have been submitted separately.

6

Affirmative

FirstEnergy supports the proposed BES definition and offers comments and
suggestions through the formal comment period.

Florida
Municipal
Power Agency
Florida
Municipal
Power Pool
Manitoba
Hydro

6

Affirmative

Please see comments submitted through the formal comments

6

Affirmative

See FMPA's comments

6

Affirmative

Please see comments provided by Manitoba Hydro in formal commenting period

Linda Horn
Nickesha P
Carrol
Kevin Querry
Richard L.
Montgomery
Thomas
Washburn
Daniel Prowse

5

Affirmative

Please see comments submitted through the formal comments

5

Affirmative

Please see the comments submitted by the MRO / NSRF

Project 2010-17 BES Definition Ballot Comments
1
3

Voter

Entity

Margaret Ryan

Pacific
Northwest
Generating
Cooperative
Central Lincoln
PUD

8

Affirmative

Please see PNGC's separate comment form.

9

Affirmative

I support the comments sent in by Steve Alexanderson of Central Lincoln PUD

New York State
Reliability
Council
Northeast
Power
Coordinating
Council, Inc.
ReliabilityFirst
Corporation

10

Affirmative

The New York State Reliability Council will be separately submitting a commemt
form.

10

Affirmative

NPCC will be submitting comments regarding concerns expressed by our
members through the formal comment process along with suggestions to address
those comments.

10

Affirmative

Comments submitted

Bruce Lovelin
Alan Adamson
Guy V. Zito

Anthony E
Jablonski

Segment

Vote

Comment

Response: The SDT thanks you for following the instructions on submitting comments. This greatly decreases the amount of
administrative work for the SDT and will help accelerate the process.
Mike Ramirez

Sacramento
Municipal
Utility District

4

Negative

SMUD believes that the SDT has made substantial progress towards a clear and
workable definition of the BES. Although SMUD in balloting “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. SMUD recognizes that, given the deadlines imposed by FERC in Order No.
743, it will not be possible for the SDT to conduct a technical analysis within the
time available. Accordingly, SMUD agrees with the approach taken by the SDT,
which is to propose a Phase II of the standards development process that would
address the generator threshold level and other issues. However, it is our opinion
that the second draft would benefit from further clarification or modification in a
number of respects, as are detailed in our comments. That said, SMUD is
prepared to support the BES definition as proposed by the SDT going forward.
SMUD has taken the opportunity to provide this industry feedback, as it is our
understanding that we will be afforded another ballot opportunity. If this were to
be our sole occasion to ballot, we would vote “Affirmative” at this time. We are

Project 2010-17 BES Definition Ballot Comments
1
4

Voter

Entity

Segment

Vote

James LeighKendall

Sacramento
Municipal
Utility District

3

Negative

Terry L Baker

Platte River
Power
Authority

3

Negative

Comment
encouraged by the work that has been completed and we commend the SDT for
their commitment and extensive work thus far. Detailed Comments submitted
separately.
SMUD believes that the SDT has made substantial progress towards a clear and
workable definition of the BES. Although SMUD in balloting “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. SMUD recognizes that, given the deadlines imposed by FERC in Order No.
743, it will not be possible for the SDT to conduct a technical analysis within the
time available. Accordingly, SMUD agrees with the approach taken by the SDT,
which is to propose a Phase II of the standards development process that would
address the generator threshold level and other issues. However, it is our opinion
that the second draft would benefit from further clarification or modification in a
number of respects, as are detailed in our comments. That said, SMUD is
prepared to support the BES definition as proposed by the SDT going forward.
SMUD has taken the opportunity to provide this industry feedback, as it is our
understanding that we will be afforded another ballot opportunity. If this were to
be our sole occasion to ballot, we would vote “Affirmative” at this time. We are
encouraged by the work that has been completed and we commend the SDT for
their commitment and extensive work thus far. Detailed Comments submitted
separately.
Platte River believes that the SDT has made substantial progress towards a clear
and workable definition of the BES. Although Platte River ballots “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. Platte River recognizes that, given the deadlines imposed by FERC in Order
No. 743, it will not be possible for the SDT to conduct a technical analysis within
the time available. Accordingly, Platte River agrees with the approach taken by
the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold level and other issues. However, it is
our opinion that the second draft would benefit from further clarification or
modification. That said, Platte River is prepared to support the BES definition as
proposed by the SDT going forward. Platte River has taken the opportunity to
provide this industry feedback, as it is our understanding that we will be afforded

Project 2010-17 BES Definition Ballot Comments
1
5

Voter

Entity

Segment

Vote

Jeanie Doty

City of Austin
dba Austin
Energy

5

Negative

Lisa L Martin

City of Austin
dba Austin
Energy

6

Negative

Comment
another ballot opportunity. If this were to be our sole occasion to ballot, we
would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far.
AE believes the SDT has made substantial progress towards a clear and workable
definition of the BES. Although AE voted “Negative,” we strongly support the
approach to defining the Bulk Electric System as proposed here. AE recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be
possible for the SDT to conduct a technical analysis within the time available.
Accordingly, AE agrees with the approach taken by the SDT, which is to propose
a Phase II of the standards development process that would address the
generator threshold level and other issues. However, it is our opinion that the
second draft would benefit from further clarification or modification in a number
of respects, as detailed in our comments. That said, AE is prepared to support the
BES definition as proposed by the SDT going forward. AE has taken the
opportunity to provide this industry feedback, as it is our understanding that we
will be afforded another ballot opportunity. If this were to be our sole occasion to
ballot, we would vote “Affirmative” at this time. We are encouraged by the work
that has been completed and we commend the SDT for their commitment and
extensive work thus far.
AE believes the SDT has made substantial progress towards a clear and workable
definition of the BES. Although AE voted “Negative,” we strongly support the
approach to defining the Bulk Electric System as proposed here. AE recognizes
that, given the deadlines imposed by FERC in Order No. 743, it will not be
possible for the SDT to conduct a technical analysis within the time available.
Accordingly, AE agrees with the approach taken by the SDT, which is to propose
a Phase II of the standards development process that would address the
generator threshold level and other issues. However, it is our opinion that the
second draft would benefit from further clarification or modification in a number
of respects, as detailed in our comments. That said, AE is prepared to support the
BES definition as proposed by the SDT going forward. AE has taken the
opportunity to provide this industry feedback, as it is our understanding that we

Project 2010-17 BES Definition Ballot Comments
1
6

Voter

Entity

Segment

Vote

Andrew Gallo

City of Austin
dba Austin
Energy

3

Negative

Kevin Smith

Balancing
Authority of
Northern
California
NCR11118

1

Negative

Comment
will be afforded another ballot opportunity. If this were to be our sole occasion to
ballot, we would vote “Affirmative” at this time. We are encouraged by the work
that has been completed and we commend the SDT for their commitment and
extensive work thus far.
Austin Energy (AE) believes the SDT has made substantial progress toward a
clear and workable definition of the BES. Although AE votes “Negative,” we
strongly support the approach to defining the BES as proposed here. AE
recognizes that, given the deadlines imposed by FERC in Order No. 743, it will not
be possible for the SDT to conduct a technical analysis within the time available.
Accordingly, AE agrees with the approach taken by the SDT, which is to propose
a Phase II of the standards development process that would address the
generator threshold level and other issues. However, we believe the second draft
would benefit from further clarification or modification in a number of respects, as
detailed in our comments (filed separately). That said, AE is prepared to support
the BES definition as proposed by the SDT going forward. AE has taken the
opportunity to provide this industry feedback, as it is our understanding that we
will have another ballot opportunity (on a recirculation ballot). If this were to be
our sole opportunity to vote, we would vote “Affirmative” at this time. We are
encouraged by the work completed to date and commend the SDT for their
commitment and extensive work thus far.
BANC believes that the SDT has made substantial progress towards a clear and
workable definition of the BES. Although BANC in balloting “Negative” we strongly
support the approach to defining the Bulk Electric System as proposed here.
BANC recognizes that, given the deadlines imposed by FERC in Order No. 743, it
will not be possible for the SDT to conduct a technical analysis within the time
available. Accordingly, BANC agrees with the approach taken by the SDT, which is
to propose a Phase II of the standards development process that would address
the generator threshold level and other issues. However, it is our opinion that the
second draft would benefit from further clarification or modification in a number
of respects, as are detailed in our comments. That said, BANC is prepared to
support the BES definition as proposed by the SDT going forward. BANC has
taken the opportunity to provide this industry feedback, as it is our understanding

Project 2010-17 BES Definition Ballot Comments
1
7

Voter

Entity

Segment

Vote

Carol
Ballantine

Platte River
Power
Authority

6

Negative

John C. Collins

Platte River
Power
Authority

1

Negative

Comment
that we will be afforded another ballot opportunity. If this were to be our sole
occasion to ballot, we would vote “Affirmative” at this time. We are encouraged
by the work that has been completed and we commend the SDT for their
commitment and extensive work thus far. Detailed Comments submitted
separately.
Platte River believes that the SDT has made substantial progress towards a clear
and workable definition of the BES. Although Platte River ballots “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. Platte River recognizes that, given the deadlines imposed by FERC in Order
No. 743, it will not be possible for the SDT to conduct a technical analysis within
the time available. Accordingly, Platte River agrees with the approach taken by
the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold level and other issues. However, it is
our opinion that the second draft would benefit from further clarification or
modification. That said, Platte River is prepared to support the BES definition as
proposed by the SDT going forward. Platte River has taken the opportunity to
provide this industry feedback, as it is our understanding that we will be afforded
another ballot opportunity. If this were to be our sole occasion to ballot, we
would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far.
Platte River believes that the SDT has made substantial progress towards a clear
and workable definition of the BES. Although Platte River ballots “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. Platte River recognizes that, given the deadlines imposed by FERC in Order
No. 743, it will not be possible for the SDT to conduct a technical analysis within
the time available. Accordingly, Platte River agrees with the approach taken by
the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold level and other issues. However, it is
our opinion that the second draft would benefit from further clarification or
modification. That said, Platte River is prepared to support the BES definition as
proposed by the SDT going forward. Platte River has taken the opportunity to

Project 2010-17 BES Definition Ballot Comments
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8

Voter

Entity

Segment

Vote

Bethany
Hunter

Sacramento
Municipal
Utility District

5

Negative

Claire
Warshaw

Sacramento
Municipal
Utility District

6

Negative

Comment
provide this industry feedback, as it is our understanding that we will be afforded
another ballot opportunity. If this were to be our sole occasion to ballot, we
would vote “Affirmative” at this time. We are encouraged by the work that has
been completed and we commend the SDT for their commitment and extensive
work thus far.
SMUD believes that the SDT has made substantial progress towards a clear and
workable definition of the BES. Although SMUD in balloting “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. SMUD recognizes that, given the deadlines imposed by FERC in Order No.
743, it will not be possible for the SDT to conduct a technical analysis within the
time available. Accordingly, SMUD agrees with the approach taken by the SDT,
which is to propose a Phase II of the standards development process that would
address the generator threshold level and other issues. However, it is our opinion
that the second draft would benefit from further clarification or modification in a
number of respects, as are detailed in our comments. That said, SMUD is
prepared to support the BES definition as proposed by the SDT going forward.
SMUD has taken the opportunity to provide this industry feedback, as it is our
understanding that we will be afforded another ballot opportunity. If this were to
be our sole occasion to ballot, we would vote “Affirmative” at this time. We are
encouraged by the work that has been completed and we commend the SDT for
their commitment and extensive work thus far. Detailed Comments submitted
separately.
SMUD believes that the SDT has made substantial progress towards a clear and
workable definition of the BES. Although SMUD in balloting “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. SMUD recognizes that, given the deadlines imposed by FERC in Order No.
743, it will not be possible for the SDT to conduct a technical analysis within the
time available. Accordingly, SMUD agrees with the approach taken by the SDT,
which is to propose a Phase II of the standards development process that would
address the generator threshold level and other issues. However, it is our opinion
that the second draft would benefit from further clarification or modification in a
number of respects, as are detailed in our comments. That said, SMUD is

Project 2010-17 BES Definition Ballot Comments
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9

Voter

Tim Kelley

Entity

Sacramento
Municipal
Utility District

Segment

1

Vote

Negative

Comment
prepared to support the BES definition as proposed by the SDT going forward.
SMUD has taken the opportunity to provide this industry feedback, as it is our
understanding that we will be afforded another ballot opportunity. If this were to
be our sole occasion to ballot, we would vote “Affirmative” at this time. We are
encouraged by the work that has been completed and we commend the SDT for
their commitment and extensive work thus far. Detailed Comments submitted
separately.
SMUD believes that the SDT has made substantial progress towards a clear and
workable definition of the BES. Although SMUD in balloting “Negative” we
strongly support the approach to defining the Bulk Electric System as proposed
here. SMUD recognizes that, given the deadlines imposed by FERC in Order No.
743, it will not be possible for the SDT to conduct a technical analysis within the
time available. Accordingly, SMUD agrees with the approach taken by the SDT,
which is to propose a Phase II of the standards development process that would
address the generator threshold level and other issues. However, it is our opinion
that the second draft would benefit from further clarification or modification in a
number of respects, as are detailed in our comments. That said, SMUD is
prepared to support the BES definition as proposed by the SDT going forward.
SMUD has taken the opportunity to provide this industry feedback, as it is our
understanding that we will be afforded another ballot opportunity. If this were to
be our sole occasion to ballot, we would vote “Affirmative” at this time. We are
encouraged by the work that has been completed and we commend the SDT for
their commitment and extensive work thus far. Detailed Comments submitted
separately.

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step in
Phase II will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit comments
for the inclusion of items and issues to be considered by the SDT in Phase II.
Philip Riley

Public Service
Commission of
South Carolina

9

Negative

The Public Service Commission of South Carolina does not believe adequate
technical evaluations have been done for basing the BES definition on the 100 kV
and 20 MVA thresholds as proposed.
In addition, the Public Service Commission of South Carolina does not believe
adequate cost benefit studies have been done to justify the proposal for the 100

Project 2010-17 BES Definition Ballot Comments
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0

Voter

Entity

Segment

Vote

Comment
kV and 20 MVA thresholds. Lack of cost benefit analyses has been a recurring
comment of the Public Service Commission of South Carolina on proposed NERC
standards.

Response: Both the 20 MVA and 100 kV thresholds are items for consideration in Phase II. At that time, technical evaluations and
studies will be performed to provide the details the SDT needs to have to adequately address the issues.
The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 & 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
contracting the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the
current BES definition has varying degrees of Regional application and has resulted in different conclusions on what is currently
considered to be part of the BES. This inconsistency in the application and subsequent results were also identified by the
Commission in Orders No. 743 & 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition
coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on Regions.
Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid
on a continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the
development of Regional transition plans once the definition has been approved by the Commission.
Dale Bodden

CenterPoint
Energy
Houston
Electric

1

Negative

Inclusion I5 provides for the inclusion of static devices dedicated to supplying or
absorbing Reactive Power based upon their connection to the transmission
system. The wording concerning their connection to the transmission system
appears reasonable; however, CenterPoint Energy believes the size of a static
reactive device should be taken into consideration. Static reactive devices are
more widely distributed across a transmission system than generation resources.
We recommend that only static reactive devices that are greater than 150 MVAR
be included. CenterPoint Energy could support Draft 2 if a reasonable size
threshold is established for static reactive devices.

Project 2010-17 BES Definition Ballot Comments
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Voter
Entity
Segment
Vote
Comment
Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow
the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values. No change made.
Robert Ganley

Long Island
Power
Authority

1

Negative

LIPA has voted NO to the proposed definition of Bulk Electric System as posted
and offers the following comments with our vote: 1. The SDT needs to provide
clarifying language for the following terms so that facilities can be adequately
addressed in determining whether they are BES elements or not:
a. “local distribution” as used in the BES core definition
b. “common point” as used in Inclusion I4
c. “single point of interconnection” as used in Exclusion E1
d. “underlying Elements” as used in Exclusion E3a
2. The core definition and exclusion E3b and E3c adequately define a Local
Network. It seems like the intent to exclude non bulk distribution systems would
still be included because of E3a. ( limits on connected generation ) We believe
E3a should be eliminated in defining a Local Network.

Response: a) The SDT believes that the wording in the core definition plus Exclusions E1 and E3 provide the basis for defining local
distribution. In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable
operation of the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element.
b) While the SDT has determined no additional clarification of the term “common point” is needed in the BES definition, the
following guidance is provided. The SDT believes the common point of connection, which is the point from where generation is
Project 2010-17 BES Definition Ballot Comments
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2

Voter
Entity
Segment
Vote
Comment
aggregated to determine if the 75 MVA threshold is met, to be the point where the individual transmission Element(s) of a collector
system ultimately meet the 100 kV transmission system.
c) The “single point of connection of 100 kV or higher” is where the radial system will begin if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the radial
system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the transmission
line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker and a half
bus configuration could also be the beginning of the radial system and the owner of the bus would need to insure the reliability of
the substation.
d) The SDT believes that the existing phrase in ExclusionE3.a “and its underlying Elements” has sufficient clarity and meets the
intent of the exclusion with brevity. No change made.
e) The SDT continues to believe that it is necessary to establish a limit on the allowable quantity of generation that may be
significant to the reliable operation of the surrounding interconnected transmission system. Please note that the issues
surrounding the appropriate generation threshold, among other topics, will be taken up in Phase 2 of this BES definition effort. No
change made.
Martyn Turner

Lower
Colorado River
Authority

1

Negative

1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. Yes:
X No: Comments:
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: LCRA TSC supports the inclusion of
transformers (with both the primary and secondary windings operated at 100-kV
or higher) in the BES definition; however, additional clarification is suggested.
The term transformers needs to be further defined with respect to function (auto
transformers, phase angle regulators, generator step-up transformers, etc.).
Similarly, a separate definition for “Transformer” could be developed and included

Project 2010-17 BES Definition Ballot Comments
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3

Voter

Entity

Segment

Vote

Comment
in the NERC Glossary of Terms.
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments:
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments:
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: LCRA TSC suggests consistency between this
inclusion criteria and the criteria used in I2 for “generation”.
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: This inclusion conflicts with exclusion E4.
Which one takes priority?
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The current wording is unclear with respect to
the treatment of normally open switching devices. LCRA TSC suggests the
following language to replace the existing language on the note to E1: “Two
radial systems connected by a normally open, manually operated switching

Project 2010-17 BES Definition Ballot Comments
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Voter

Entity

Segment

Vote

Comment
device, as depicted on prints or one-line diagrams for example, may be
considered as radial systems under this exclusion.” The current wording is unclear
with respect to “non-retail generation”. The sudden loss of large, radial-supplied
load may result in reliability deficiencies. LCRA TSC suggests stating a load level
or a load capacity in the exclusion.
8. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: No: X Comments:
9. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E3 (local network)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments:
10. The SDT has added specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E4 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: This exclusion conflicts with inclusion item I5.
Which one takes priority?
11. Are there any other concerns with this definition that haven’t been covered in
previous questions and comments remembering that the exception criteria are
posted separately for comment? Yes: X No: Comments: LCRA TSC supports the
direction the standards drafting team taking with this project on the BES
Definition and encourages further clarification as noted in these comments for
proper application.

Response: The SDT refers LCRA to the individual comment responses in the definition comment form as the comments expressed
here are exactly identical to the comments submitted by LCRA on that form.
Danny Dees

MEAG Power

1

Negative

MEAG believes that a Yes vote for the draft BES Definition will result in minimal or
no changes. We have identified a few changes that if made will secure a Yes vote
on the next ballot.

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Comment
The most important change is needed in I5 reactive resources noted below. I5
reactive resources - We feel that this inclusion should be limited to dynamic
devices with an aggregate capacity greater than 75 MVA (gross aggregate
nameplate rating) connected through a common point.
E1 - Non-retail generation needs to be defined to clarify why it is used in this
exclusion.
E2 (ii) The reference to generation on the customer’s side of the retail meter
needs to be clarified to provide a better understanding as to what is intended
with this phrase.
E3 b - We would agree with the exclusion if the wording of the exclusion includes
the following phrase (in italics) added at the end of E3 b): Power flows only into
the LN: The LN does not transfer energy originating outside the LN for delivery
through the LN “under normal operating conditions”.

Response: The SDT refers MEAG to the individual comment responses in the definition comment form as the comments expressed
here are exactly identical to the comments submitted by MEAG on that form.
Ernest Hahn

Metropolitan
Water District
of Southern
California

1

Affirmative

MWDSC generally supports the core definition of the Bulk Electric System as
proposed. However, some of the proposed Inclusions and Exclusions need to be
clarified as identified below.
Inclusion 5 should be changed to be consistent with the core definition and to
clarify Reactive Power devices. Under I5, the additional phrase "or through a
dedicated transformer with a high-side voltage of 100 kV or higher," appears to
conflict with the core definition's phrase "and Real Power and Reactive Power
resources connected at 100 kV or higher". For example, if you have a device
connected to a 69Kv system which is used solely for an end-user's load, but the
69kv system is transformed up to a 115kV system, such device could be included
as BES or you would have to define what is meant by "dedicated. If Reactive
Power is meant to agree with the definition under NERC's Glossary of Terms,
there should be consistency and less verbiage.
MWDSC also agrees with WECC's comment that there should be some minimum
threshold for Reactive Power devices similar to that identified for generating
resources in Inclusion 2.
MWDSC recommends that Inclusion 5 be changed as follows: I5 - "Reactive

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Comment
Power devices dedicated to support the BES that are connected at 100kV or
higher, or through a transformer that is designated in Inclusion I1."
Exclusion 4 appears to limit the devices just to retail customers. However, any
end-user load, including wholesale or retail, should be included. NERC's Glossary
of Terms uses the phrase "end-use customer", not retail customers to describe
loads. MWDSC recommends that Exclusion 4 be changed as follows: E4 - Reactive
Power devices owned and operated by an end-use customer solely for its own
use.

Response: The SDT refers MWDSC to the individual comment responses in the definition comment form as the comments
expressed here are exactly identical to the comments submitted by MWDSC on that form.
William
Palazzo

New York
Power
Authority

6

Negative

1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. Yes:
X No: Comments: In general NYPA agrees with the definition. However, NYPA
believes that clarifying revisions need to be made as described in the responses
to Questions 2 -11 below.
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The wording of Inclusion I1 is not clear. The
term transformers needs to be further defined with respect to auto transformers,
phase angle regulators and generator step-up transformers. Recommend the
following wording: “All transformers (including auto-transformers, voltage
regulators, and phase angle regulators) with primary and secondary terminals
operated at or above 100kV, and generator step-up transformers (GSU) with one
terminal operated at or above 100KV, unless excluded by E1 or E3.”
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language

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Entity

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Comment
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Recommend removing the reference to the
Statement of Compliance Registry Criteria. The definition should be the governing
document and provide the details of what generating resources should be
included. The current language induces circular arguments without a true
governing document. The definition should drive what appears in the Registry
Criteria. Inclusion I2 should be revised to read: “Generating resources with a
gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion I2 and the current Compliance Registry Criteria.
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Recommend that the concept and the words
“material to and designated as part of” be included in Inclusion I3. Recommend
rewording Inclusion I3 as follows “Blackstart resources material to and designated
as part of the Transmission Operator’s restoration plan.”
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The term “common point” needs clarification
with respect to connection to the BES. Recommend the following wording:
“connected at a common point through a dedicated step-up transformer with a
high-side voltage of 100 KV or above.”
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Technical studies need to be conducted to

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confirm reactive resource impacts on the reliability of the BES. The inclusion of
reactive resources is a significant expansion of the current BES definition and
therefore requires technical justification for inclusion. Inclusion I5 as written is
generally confusing with multiple references to other inclusions and exclusions in
the definition. Recommend removing references to reactive resources from Phase
1 until technical justification can be demonstrated (as part of Phase 2).
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The wording in E1c should more clearly reflect
what is intended by using the term “non-retail”. The E1 reference Note should be
re-worded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. Recommend that the potential inclusion in the BES of protective
relay systems which protect radial lines emanating from a ring bus or breaker and
a half bus design be confirmed in Phase 2 pursuant to technical studies.
8. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: No: X Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E3 (local network)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments: It is our understanding that a sub-team of the
SDT performed a technical study to support the limits outlined in Exclusion E3.

Project 2010-17 BES Definition Ballot Comments
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Voter

Marilyn Brown

Entity

New York
Power
Authority

Segment

3

Vote

Negative

Comment
This study should be made available. Recommend removing the sentence in the
definition that states: “This does not include facilities used in the local distribution
of electric energy.” This sentence leads to confusion as it overlaps with language
in Exclusion E3.
10. The SDT has added specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E4 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The statement “owned or operated by the
retail customer” is confusing and arguably inaccurate and should be revised.
Refer to comments related to reactive resources for Question 6 regarding
Inclusion I5.
11. Are there any other concerns with this definition that haven’t been covered in
previous questions and comments remembering that the exception criteria are
posted separately for comment? Yes: X No: Comments: Recommend integrating
the Inclusions into the base definition wording to eliminate confusion. Format of
the definition is confusing by referencing both Inclusions and Exclusions. NYPA
supports many of the comments
1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. Yes:
X No: Comments: In general NYPA agrees with the definition. However, NYPA
believes that clarifying revisions need to be made as described in the responses
to Questions 2 -11 below.
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The wording of Inclusion I1 is not clear. The
term transformers needs to be further defined with respect to auto transformers,
phase angle regulators and generator step-up transformers. Recommend the

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Entity

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Comment
following wording: “All transformers (including autotransformers, voltage
regulators, and phase angle regulators) with primary and secondary terminals
operated at or above 100kV, and generator step-up transformers (GSU) with one
terminal operated at or above 100KV, unless excluded by E1 or E3.”
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Recommend removing the reference to the
Statement of Compliance Registry Criteria. The definition should be the governing
document and provide the details of what generating resources should be
included. The current language induces circular arguments without a true
governing document. The definition should drive what New York Power
Authority’s Comments Final: October 05, 2011 Comment Form for 2nd Draft of
Definition of BES (Project 2010-17) Page 4 of 6 appears in the Registry Criteria.
Inclusion I2 should be revised to read: “Generating resources with a gross
nameplate rating of 20MVA or greater, or generating plant/facility connected at a
common bus, with an aggregate nameplate rating of 75MVA or greater and is
directly connected to a BES Element.” This is consistent with proposed Inclusion
I2 and the current Compliance Registry Criteria.
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Recommend that the concept and the words
“material to and designated as part of” be included in Inclusion I3. Recommend
rewording Inclusion I3 as follows “Blackstart resources material to and designated
as part of the Transmission Operator’s restoration plan.”
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language

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Entity

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Comment
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The term “common point” needs clarification
with respect to connection to the BES. Recommend the following wording:
“connected at a common point through a dedicated step-up transformer with a
high-side voltage of 100 KV or above.”
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Technical studies need to be conducted to
confirm reactive resource impacts on the reliability of the BES. The inclusion of
reactive resources is a significant expansion of the current BES definition and
therefore requires technical justification for inclusion. Inclusion I5 as written is
generally confusing with multiple references to other inclusions and exclusions in
the definition. Recommend removing references to reactive resources from Phase
1 until technical justification can be demonstrated (as part of Phase 2). New York
Power Authority’s Comments Final: October 05, 2011 Comment Form for 2nd
Draft of Definition of BES (Project 2010-17) Page 5 of 6
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The wording in E1c should more clearly reflect
what is intended by using the term “non-retail”. The E1 reference Note should be
re-worded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. Recommend that the potential inclusion in the BES of protective
relay systems which protect radial lines emanating from a ring bus or breaker and
a half bus design be confirmed in Phase 2 pursuant to technical studies.
8. The SDT has revised the specific exclusions to the core definition in response

Project 2010-17 BES Definition Ballot Comments
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Voter

Arnold J.
Schuff

Entity

New York
Power
Authority

Segment

1

Vote

Negative

Comment
to industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: No: X Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E3 (local network)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments: It is our understanding that a sub-team of the
SDT performed a technical study to support the limits outlined in Exclusion E3.
This study should be made available. Recommend removing the sentence in the
definition that states: “This does not include facilities used in the local distribution
of electric energy.” This sentence leads to confusion as it overlaps with language
in Exclusion E3. New York Power Authority’s Comments Final: October 05, 2011
Comment Form for 2nd Draft of Definition of BES (Project 2010-17) Page 6 of 6
10. The SDT has added specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E4 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The statement “owned or operated by the
retail customer” is confusing and arguably inaccurate and should be revised.
Refer to comments related to reactive resources for Question 6 regarding
Inclusion I5.
11.Are there any other concerns with this definition that haven’t been covered in
previous questions and comments remembering
You do not have to answer all questions. Enter All Comments in Simple Text
Format. Insert a “check” mark in the appropriate boxes by double-clicking the
gray areas. The SDT has asked one specific question for each specific aspect of
the definition.
1. The SDT has made clarifying changes to the core definition in response to

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Comment
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. Yes:
X No: Comments: In general NYPA agrees with the definition. However, NYPA
believes that clarifying revisions need to be made as described in the responses
to Questions 2 -11 below.
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The wording of Inclusion I1 is not clear. The
term transformers needs to be further defined with respect to auto transformers,
phase angle regulators and generator step-up transformers. Recommend the
following wording: “All transformers (including auto-transformers, voltage
regulators, and phase angle regulators) with primary and secondary terminals
operated at or above 100kV, and generator step-up transformers (GSU) with one
terminal operated at or above 100KV, unless excluded by E1 or E3.”
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Recommend removing the reference to the
Statement of Compliance Registry Criteria. The definition should be the governing
document and provide the details of what generating resources should be
included. The current language induces circular arguments without a true
governing document. The definition should drive what appears in the Registry
Criteria. Inclusion I2 should be revised to read: “Generating resources with a
gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion I2 and the current Compliance Registry Criteria.

Project 2010-17 BES Definition Ballot Comments
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Comment
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Recommend that the concept and the words
“material to and designated as part of” be included in Inclusion I3. Recommend
rewording Inclusion I3 as follows “Blackstart resources material to and designated
as part of the Transmission Operator’s restoration plan.”
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The term “common point” needs clarification
with respect to connection to the BES. Recommend the following wording:
“connected at a common point through a dedicated step-up transformer with a
high-side voltage of 100 KV or above.”
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Technical studies need to be conducted to
confirm reactive resource impacts on the reliability of the BES. The inclusion of
reactive resources is a significant expansion of the current BES definition and
therefore requires technical justification for inclusion. Inclusion I5 as written is
generally confusing with multiple references to other inclusions and exclusions in
the definition. Recommend removing references to reactive resources from Phase
1 until technical justification can be demonstrated (as part of Phase 2).
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The wording in E1c should more clearly reflect

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Entity

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Comment
what is intended by using the term “non-retail”. The E1 reference Note should be
re-worded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. Recommend that the potential inclusion in the BES of protective
relay systems which protect radial lines emanating from a ring bus or breaker and
a half bus design be confirmed in Phase 2 pursuant to technical studies.
8. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: No: X Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E3 (local network)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments: It is our understanding that a sub-team of the
SDT performed a technical study to support the limits outlined in Exclusion E3.
This study should be made available. Recommend removing the sentence in the
definition that states: “This does not include facilities used in the local distribution
of electric energy.” This sentence leads to confusion as it overlaps with language
in Exclusion E3.
10. The SDT has added specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E4 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: The statement “owned or operated by the
retail customer” is confusing and arguably inaccurate and should be revised.
Refer to comments related to reactive resources for Question 6 regarding

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Comment
Inclusion I5.
11. Are there any other concerns with this definition that haven’t been covered in
previous questions and comments remembering that the exception criteria are
posted separately for

Response: 1. The SDT refers NYPA to the responses below for Q2 – Q10.
2. The SDT believes the existing language is clear and the proposed additional language would be redundant. No change made.
3. The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2, instead
specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and thus
affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
4. The SDT believes that adding language such as “material to” does not provide clarity and remains immeasurable. No change
made.
5. The “single point of connection of 100 kV or higher” is where the radial system will begin if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the radial
system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the transmission
line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker and a half
bus configuration could also be the beginning of the radial system and the owner of the bus would need to insure the reliability of
the substation.
6. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects of the definition. However, the SDT has responsibilities associated with being responsive to the directives established in
Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with
sufficient time for the development of strong technical justifications. These and similar issues have prompted the SDT to separate
the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities.
Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for inclusion in
Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical
Standing Committees, to develop analyses which will provide compelling justification. No change made.
7. “Non-retail generation” means that generation which is on the system (supply) side of the retail meter. Radial systems should be
assessed with all normally open (NO) switches in the open position and these NO switches will not prevent the owner or operator
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Comment
from using this exclusion. The note provides an example that can be used to indicate the switch is operated in the normally open
position; however, it is the owner and operator’s responsibility to indicate how a switch is used in the normal operating
environment. The “single point of connection of 100 kV or higher” is where the radial system will begin if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of
the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Treatment of protection systems is but one of many items to be studied and clarified in
Phase II.
8. The threshold levels of generators and the relationship between the ERO Statement of Compliance Registry Criteria and the BES
definition will be considered in the Phase 2 review. However, the SDT believes that a value was needed for Phase I and decided to
proceed with the single 75 MVA threshold. No change made.
9. No study was run by the SDT concerning the limits in E3. The SDT does not see any conflict between the cited statement and the
language in E3.
10. The SDT believes the wording is clear and absent any concrete suggestions has not made a change in this regard.
Doug
Peterchuck

Omaha Public
Power District

1

Negative

We believe that this version of the definition and associated Inclusion and
Exclusion criteria will again create regional inconsistency in identifying BES
facilities. We believe the best way to address this is to condense the definition by
applying a bright-line threshold within the definition itself that uses the defined
inclusions to describe transmission and generation facilities operating or
connecting at 100 kV or above as BES facilities.
Further, the definition should include existing registration criteria for generation
facilities (including real and reactive resources), which includes both single units
at or above 20 MVA and aggregate units at 75 MVA or above that are directly
connected to facilities at 100kV or higher.
The proposed Exception Process should only allow Registered Entities to remove
facilities from BES designation based on technical justification (i.e. perform
system impact studies to show facility not impacting reliable operation of BES).
If the BES definition is properly created and defined, there should not be a need

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to have an exception process for a registered entity to add a facility to the BES.
With coordination led by NERC, the RE should have the final approval of any
registered entity requesting a facility exemption. Exemptions should be granted
based on result of the system impact study performed. Saying this, the proposed
exclusion list should actually be listed as “Typical Exceptions to be considered by
Regional Entities and NERC”.

Response: The SDT strived to create a bright-line as requested in the comment. The inclusions and exclusions are seen as
necessary clarifications to the core definition and every attempt was made to make them bright-line as well.
The SDT has reverted to specific numeric thresholds consistent with the ERO Statement of Compliance Registry Criteria for Phase I.
The exception process has been designed with maximum flexibility in mind to allow for all possible conditions. Therefore, it is set
up to allow for both deletion and inclusion requests.
Order 743 directs that the ERO be the final arbiter of exception requests.
Robert
Kondziolka

Salt River
Project

1

Negative

Definition of Bulk Electric System (BES) The Blackstart “Cranking Path” has been
deleted from Inclusion 3 of the BES definition. However, NERC standards EOP005 and CIP-002, R1.2.4 require documenting the Cranking Path. In addition,
CIP-002-4 identifies the Cranking Path as a Critical Asset in Attachment 1.
Compliance to the NERC Standards needs to be an exact science whenever
possible. SRP does not argue the inclusion or exclusion of Cranking Path.
However, if it is excluded, guidance must be provided on whether or not a
Cranking Path is subject to the previously mentioned Standards.
Detailed Information to Support BES Exceptions Request SRP agrees with the
WECC Staff recommendation on the “Detailed Information to Support BES
Exceptions Request.” “WECC Staff believes that the proposed Technical Principles
for Demonstrating BES Exceptions Request does not provide the necessary clarity
as to what applying entities must provide to support their request, nor does it
provide any criteria for consistency among regions in their assessment of
requests. We believe that the checklist items for transmission and generation
facilities are appropriate questions that must be answered in considering all
requests. However, without objective criteria defining what must be submitted
and how to assess the materials submitted, the current methodology leaves it to

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John T.
Underhill

Entity

Salt River
Project

Segment

3

Vote

Negative

Comment
each region to develop their own methodology and criteria for evaluating the
submittals. We believe the lack of clarity regarding what studies must be
submitted and what must be demonstrated by the studies submitted will be
overly burdensome on the submitting entity and the Region, as multiple studies
may be required for the two to agree that there is sufficient justification for an
exemption request. We believe that additional work is necessary to develop clear,
objective methods and criteria for identifying which facilities may be excluded
from or should be included in the Bulk Electric System. Clear, objective methods
and criteria will enable the submitter of requests to understand what is necessary
for submitting an exception request and will provide for consistency among the
regions in their initial assessment and recommendations to the ERO.”
Definition of Bulk Electric System (BES) The Blackstart “Cranking Path” has been
deleted from Inclusion 3 of the BES definition. However, NERC standards EOP005 and CIP-002, R1.2.4 require documenting the Cranking Path. In addition,
CIP-002-4 identifies the Cranking Path as a Critical Asset in Attachment 1.
Compliance to the NERC Standards needs to be an exact science whenever
possible. SRP does not argue the inclusion or exclusion of Cranking Path.
However, if it is excluded, guidance must be provided on whether or not a
Cranking Path is subject to the previously mentioned Standards.
Detailed Information to Support BES Exceptions Request SRP agrees with the
WECC Staff recommendation on the “Detailed Information to Support BES
Exceptions Request.” “WECC Staff believes that the proposed Technical Principles
for Demonstrating BES Exceptions Request does not provide the necessary clarity
as to what applying entities must provide to support their request, nor does it
provide any criteria for consistency among regions in their assessment of
requests. We believe that the checklist items for transmission and generation
facilities are appropriate questions that must be answered in considering all
requests. However, without objective criteria defining what must be submitted
and how to assess the materials submitted, the current methodology leaves it to
each region to develop their own methodology and criteria for evaluating the
submittals. We believe the lack of clarity regarding what studies must be

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submitted and what must be demonstrated by the studies submitted will be
overly burdensome on the submitting entity and the Region, as multiple studies
may be required for the two to agree that there is sufficient justification for an
exemption request. We believe that additional work is necessary to develop clear,
objective methods and criteria for identifying which facilities may be excluded
from or should be included in the Bulk Electric System. Clear, objective methods
and criteria will enable the submitter of requests to understand what is necessary
for submitting an exception request and will provide for consistency among the
regions in their initial assessment and recommendations to the ERO.”

Response: Cranking Paths are subject to any standard in which they are specifically spelled out.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria
and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to
say that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with
this position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at
as a single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional
Entity plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this
places the Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be
supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also
believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the
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proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent
Technical Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s
findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure,
Section 7.0, provides NERC the option to remand the request to the Regional Entity with the mandate to process the exception if it
finds the Regional Entity erred in rejecting or disapproving the exception request. On the other side of this equation, one could
make an argument that the Regional Entity has no basis for what constitutes an acceptable submittal. Commenters point out that
the explicit types of studies to be provided and how to interpret the information aren’t shown in the request process. The SDT
again points to the variations that will abound in the requests as negating any hard and fast rules in this regard. However, one is
not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there is a great deal of
professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having viewed the request
details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be supplied for the
submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables
to take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation
of the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the
elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result ofa sudden disturbance, including a cyber
security incident, or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel,
the visibility of the process, and the experience gained by having this same panel review multiple requests will result in an
equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision
has been made on their submittal.
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Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be
approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in
a favorable outcome.
Barbara
Constantinescu

Independent
Electricity
System
Operator

2

Negative

This is our response to Question 4 in the comment form: We thank the SDT for
excluding the cranking paths from the BES definition, a point we had raised in our
comments to the previous posting. However, we had also disagreed with the
inclusion of Blackstart Resources and reiterate our view that their inclusion is
superfluous given there is already a designation specific for system restoration
covered by an existing standard, to recognize their reliability impacts and to
ensure their expected performance. NERC Standards EOP-005-2 stipulates the
requirements for testing blackstart resource and cranking paths. This testing
requirement suffices to ensure that the facilities critical to system restoration are
functional when needed, which meets the intent of identifying their criticality to
reliability. We therefore suggest removing Inclusion I3 entirely.

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We support the provisions of E1 in principle but require clarification of some
issues and suggest alternative wording in some cases. It is unclear if the
connection voltage of generation referred to in E1.b affects whether a radial
system could be excluded under E1 although from the context it appears that it
would. For clarity we suggest appending “connected at 100 kV or higher.” Please
provide in the BES definition document an explanation of “non-retail” and “retail”
generation used in E1.c.
Additionally, despite the fact the revisions to Inclusion I3 (Blackstart Resources)
removed any reference to Cranking Paths, Exclusion 1 (b) and (c) both indicate
that the exclusion of a radial system would not be allowed if generation identified
in I3 were connected to it. This implies that the Cranking Path for this Blackstart
Resource would have to be BES. This appears to be an inconsistency. We suggest
removing the phrase “not identified in Inclusion I3” in both instances. We
disagree with notion that the capacity of generation connected to a radial system
ought to determine whether that radial system should be classified as BES.
Firstly, it is a given that the generation connected to the subject radial that meets
the registry criteria would already be captured within the core BES definition and
Inclusion I2.
This is our response to Question 7 in the comment form: The function served by
a radial that is of importance in the current context is that of delivering surplus
power to the rest of the bulk power system and so, the impact on the BES of loss
of the radial system or its connected generation needs to be considered. In our
view, the “BES-status” of the radial itself is immaterial and so too is the aggregate
capacity of generation resources connected to it. Detailed arguments regarding
impact on the BES can be made in support of an application for an exclusion
under the Exception Process, but it would be beneficial to avoid unnecessarily
including a radial merely because it has more than 75 MVA of qualifying
generation connected to it, without equal consideration of the connected load. To
put a “bright line” on the consideration of impact referred to above, we suggest:
In E1 (b): Replace "an aggregate capacity less than or equal to 75 MVA (gross

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nameplate rating)" with "a net capacity provided to the BES of less than or equal
to 75 MVA." In E1 (c): Replace "an aggregate capacity of non-retail generation
less than or equal to 75 MVA (gross nameplate rating)" with "a net capacity of
non-retail generation provided to the BES of 75 MVA." This wording would be
consistent with E2 (i).
Finally the word “affect” stated in the note accompanying E1 lends itself to misinterpretation. We therefore suggest the following revision to achieve greater
clarity: “This exclusion applies to radial systems connected by a normally open
switch.”
This is our response to Question 9 of the comment form: Consistent with our
comments in response to Q7, we propose removing E3 (a) since, as explicitly
described in E3 (b), one of the characteristic of the LN is that power flows only
into the LN. The level of generation contained within the LN is therefore
immaterial, particularly where the most onerous contingency or system operating
condition occurring within the LN, results in acceptable BES performance as
defined by the applicable criteria of the NERC transmission planning standards.
The generation connected within the LN that meets the registry criteria would
already be captured within the definition of the BES as provided for in Inclusion
I2.

Response: The SDT refers IESO to the individual comment responses in the definition comment form as the comments expressed
here are exactly identical to the comments submitted by IESO on that form.
Marie Knox

Midwest ISO,
Inc.

2

Negative

While we agree with the changes to the definition of the Bulk Electric System
(BES), there are a few key refinements left to be addressed. The BES drafting
team needs to clarify that facilities below 100 kV are defined “local distribution
facilities”, are beyond NERC jurisdiction, and are excluded from the NERC BES.
Facilities below 100 kV are used for the local distribution of electric energy. We
fear that equipment that is connected to the BES, would be considered a part of
the BES as well, and we disagree.

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Response: The SDT points the commenter to the core definition which clearly states that the BES is 100 kV and above unless
modified by the inclusions/exclusions and also clearly states that local distribution facilities are not included. The
inclusions/exclusions were carefully developed to try to avoid bringing in any equipment that is truly local distribution. The SDT
would also point out that the way the definition has been framed that it would not bring in local distribution facilities simply
because they were connected to the BES at some location.
Alden Briggs

New Brunswick
System
Operator

2

Negative

Please see comments submitted by the Reliability Standards Committee. The draft
definition will significantly increase the number of BES elements. Many elements
and connected facilities will be added to the BES and subject to NERC standards
under the draft definition. Most of these requirements for elements will
unnecessary introduce administrative burden and operating expenses. As a NPCC
study identifies, this would impose significant costs to the ratepayer, with little or
no increase in reliability benefits to the Bulk Power System (BPS) as currently
defined by NPCC.

Response: The SDT refers NBSO to the individual comment responses in the definition comment form as the comments expressed
here are identical to the comments submitted by NBSO on that form.
Jack W Savage

Modesto
Irrigation
District

3

Negative

MID is voting No with the following comments. Inclusions and exclusions are
based upon the ERO Statement of Compliance Registry Criteria - currently
75MVA. What is the SDT's technical justification for using this generation level?
If 75MVA is the criteria for including facilities as part of the BES, why is that same
criteria not applied at voltages below 100kv?
Is 75MVA of generation within an area whose load far exceeds that 75MVA cause
to classify that entire area as part of the BES and not exclude it as a Local
Network?
Why are customer owned generators treated differently than other generators?
Where is "non-retail generation" defined?
As worded, I5 will make any and all reactive devices connected at 100kv or
higher part of the BES. Is is intended that capacitors attached to the tertiary of a
115/69kv transformer for local voltage support be included as part of the BES? By
implication, if they are, then the 115/69kv transformer should also be included. Is
that the intent?
Did the SDT consider and attempt to include and reconcile the WECC BES Task

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Force's definition of the BES and their technical basis for defining exclusions?
Please explain.

Response: As has been previously stated in the first posting consideration of comments, the SDT is using the existing thresholds for
generation due to the scope limitations of the FERC Order. Phase II of this project will include a thorough investigation of, and a
technical justification for, any threshold values used in the definition.
The SDT is using the same criteria that exists in today’s definition for generation threshold values and will be exploring all issues
associated with these threshold values in Phase II of this project when more time will be available for technical analysis of the
issues.
The SDT recognizes that some candidate local networks will have far in excess of 75 MVA of load demand, yet it believes that the 75
MVA threshold value given in Exclusion E3.a is an appropriate level regardless of the amount of load. This value is consistent with
the existing threshold of aggregate generation in the ERO Statement of Compliance Registry Criteria. The generation values used in
the BES definition will receive more attention and refinement as part of phase 2 of this Project 2010-17.
Customer owned generation has traditionally been treated differently and the SDT is retaining this important distinction.
Non-retail generation is a widely used and understood term and is not defined here.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
The SDT considered all of the previous work done by several of the regional entities in the revision of the definition. WECC is well
represented on the SDT.
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Steven M.
Jackson

Municipal
Electric
Authority of
Georgia

3

Negative

Steven Grego

MEAG Power

5

Negative

Comment
MEAG believes that a Yes vote for the draft BES Definition will result in minimal or
no changes. We have identified a few changes that if made will secure a Yes vote
on the next ballot. The most important change is needed in I5 reactive resources
noted below. I5 reactive resources - We feel that this inclusion should be limited
to dynamic devices with an aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) connected through a common point.
E1 - Non-retail generation needs to be defined to clarify why it is used in this
exclusion.
E2 (ii) The reference to generation on the customer’s side of the retail meter
needs to be clarified to provide a better understanding as to what is intended
with this phrase.
E3 b - We would agree with the exclusion if the wording of the exclusion includes
the following phrase (in italics) added at the end of E3 b): Power flows only into
the LN: The LN does not transfer energy originating outside the LN for delivery
through the LN “under normal operating conditions”.
MEAG believes that a Yes vote for the draft BES Definition will result in minimal or
no changes. We have identified a few changes that if made will secure a Yes vote
on the next ballot. The most important change is needed in I5 reactive resources
noted below. I5 reactive resources - We feel that this inclusion should be limited
to dynamic devices with an aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) connected through a common point.
E1 - Non-retail generation needs to be defined to clarify why it is used in this
exclusion.
E2 (ii) The reference to generation on the customer’s side of the retail meter
needs to be clarified to provide a better understanding as to what is intended
with this phrase.
E3 b - We would agree with the exclusion if the wording of the exclusion includes
the following phrase (in italics) added at the end of E3 b): Power flows only into
the LN: The LN does not transfer energy originating outside the LN for delivery
through the LN “under normal operating conditions”.

Response: The SDT refers MEAG to the individual comment responses in the definition comment form as the comments expressed
here are identical to the comments submitted by MEAG on that form.
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Spencer Tacke

Entity
Modesto
Irrigation
District

Segment
4

Vote
Negative

Comment
The choice of 75 MVA as the determining generating capacity seems to have
been an arbitrary choice with no technical basis. We strongly support the E3
(Local Networks) exception, if it were not for the 75 MVA generation requirement.
So I believe a technical basis for selecting 75 MVA as the generator size needs to
be developed before the definition would be acceptable. Thank you.

Response: Comments were received that either posed a challenge to the generator thresholds in Exclusion E3.a or suggested that
the Exclusion for local networks should be silent on generator thresholds until such time as the additional consideration of
appropriate generation thresholds is addressed in Phase 2 of Project 2010-17. The SDT agrees that the threshold(s) for generation
throughout the BES definition are appropriately addressed in Phase 2 of this effort; however, in the meantime and for the purpose
of satisfying the Commission’s Order in 743 and 743a in a timely fashion, the SDT believes it is necessary to use a generation
threshold that is consistent with the in-force ERO Statement of Compliance Registry Criteria.
Chifong
Thomas

BrightSource
Energy, Inc.

5

Negative

BrightSource Energy supports the core definition of the Bulk Electric System as
proposed. However, we believe the following clarification will be needed. For
Inclusion 3 we agree that Blackstart units should be considered vital to the overall
operation of the BES, and therefore included in the definition of the BES.
However, we do not agree with the deletion of the cranking path from Inclusion
3. The cranking path should be included in the definition since NERC standards
EOP-005 and CIP-002, R1.2.4 require documenting the cranking path and the
revised CIP-002-4 identifies the cranking path as a critical asset. To be able to
count on a Blackstart unit to perform as designed in the Blackstart Restoration
Plan, it must be ensured that the cranking path is available.
We believe that additional clarity is needed in the wording of Inclusion 4. It is our
understanding, for example, that Inclusion 4 is not intended to include each
individual wind turbine generating unit in a wind farm, or each PV panel as a BES
element, but rather to include the point at which the aggregated capacity reaches
the threshold of 75 MVA. However, the current wording of Inclusion 4 does not
provide sufficient clarity. We believe that the wording of Inclusion 4 could be
modified to add clarity on this topic.
We believe that Inclusion 5 should be modified to identify some minimum
Reactive Power threshold for static or dynamic devices similar to that identified
for generating sources in Inclusion 2. As worded a 1 MVA device supplying or

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absorbing Reactive Power that is connected at 100 kV or higher would be
included in the BES.
We believe that Exclusion 2 should be modified to include a size threshold for
individual generating units, similar to that identified in Inclusion 2. As currently
worded Exclusion 2 places the same threshold (75 MVA) on a single generating
unit as is placed on multiple generating units.

Response: Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system
Elements. The Transmission Operator’s restoration plans identify a number of possible system restoration scenarios to address the
uncertainty of the actual requirements needed to address a particular restoration event including Cranking Paths. Therefore, the
SDT maintains that Cranking Paths are not required to be included in the BES definition as they are essentially a moving target and
could include distribution Elements. The Cranking Paths issue will be discussed anew in Phase II of this project. No change made.
Inclusion I4 denotes an aggregate threshold. This is clear from the requirement inclusion threshold of “aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating).”
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
The threshold levels of generators and the relationship between the ERO Statement of Compliance Registry Criteria and the BES
definition will be considered in the Phase 2 review. However, the SDT believes that a value was needed for Phase I and decided to
proceed with the single 75 MVA threshold. No change made.
Rex A Roehl

Indeck Energy
Services, Inc.

5

Negative

As acknowledged in the response to Question 12 comments on the previous BES
definition, the BES definition is expansive compared to the definition of the BPS in

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the FPA Section 215. The inclusion of the limited Exclusions is an attempt to
remedy the situation. However, the Exclusions need to include a fifth one that if,
based on studies or other assessments, it can be shown that any tranmission or
generator element otherwise identified as part of the BES is not important to the
reliability of the BPS, then that element should be excluded from the mandatory
standards program. There has never been a study to show that elements, such as
a 20 MW wind farm, 60 MW merchant generator (which operates infrequently in
the depressed market) in a large BA (eg NYISO) or a radial transmission line
connecting a small generator are important to the reliability of the BPS. They are
covered by the mandatory standards program through the registration criteria.
The BES Definition is the opportunity to permit an entity to demonstrate that an
element is unimportant to reliability of the BPS. The SDT has identified a small
subset of elements that it is willing to exclude. By their very nature, these
exclusions dim the bright line that is the stated goal of this project. However, the
SDT’s foresight seems limited in its selections. Analytical studies are used to
evaluate contingencies that could lead to the Big Three (cascading outages,
instability or voltage collapse). Such a study showing that a transmission or
generation element is bounded by the N-1 or N-2 contingency would exclude it
from the BES definition. For example, in a BA with a NERC definition Reportable
Disturbance of approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW
merchant generator or numerous other smaller facilities would be bounded by
larger contingencies. It would take more than six 60 MW merchant generators
with close location and common mode failure to even be a Reportable
Disturbance, much less become the N-1 contingency for the Big Three. Exclusion
E5 should be “E5 - Any facility that can be demonstrated to the Regional Entity by
analytical study or other assessment to be unimportant to the reliability of the
BPS (with periodic reports by the Regional Entity to NERC of any such
assessments).”

Response: The SDT refers Indeck to the individual comment responses in the definition comment form as the comments expressed
here are identical to the comments submitted by Indeck on that form.

Project 2010-17 BES Definition Ballot Comments
5
1

Voter
Gerald
Mannarino

Entity
New York
Power
Authority

Segment
5

Vote
Negative

Comment
Comments: For Question 2 on page 2, recommend that the specific types of
studies to be provided are defined to add consistency and transparency to the
Exception request process. Recommend that the concept and the words “material
to” be included as part of the question as follows “Is the facility material to
permanent Flowgates in the Eastern Interconnection.....”
For Question 4 on page 2, recommend that single contingency analysis be
performed and submitted to demonstrate impacts to the BES.
For Question 6 on page 3, recommend that “Cranking Path” be removed to be
consistent with the draft BES Definition. Recommend that the concept and the
words “material to and designated as part of” be included as part of the question.
Recommend rewording Question 6 as follows “Is the facility a Blackstart resource
material to and designated as part of the Transmission Operator’s restoration
plan?”
For Question 7 on page 3, facilities less than two years old or under construction
would not be able to provide SCADA data for the most recent consecutive two
calendar year period. Facility rating changes and the magnitude of such changes
which trigger application or reapplication of the exception process are not
addressed. Recommend that Question 7 be revised to address these issues.
Comments: For Question 2 on page 4, recommend that the specific generator
ancillary service products be defined to add consistency and transparency to the
Exception Request process.
For Question 3 on page 4, recommend that confirmation of must-run generation
be provided by the Reliability Coordinator, Reliability Planner, or the Balancing
Authority as a clarification to the “appropriate reference”.

Response: These questions have been provided to those members of the SDT who are working on responses to the criteria posting
questions. They will be responded to in detail in those documents.
Colin Anderson

Ontario Power
Generation Inc.

5

Negative

OPG continues to question the need for the changes required (and costs
imposed) as a result of this new definition. This is particularly true in the NPCC
region where an impact based methodology is being used to determine the set of
BES elements. A very clear 100kV bright line, as proposed in this draft, will
dramatically increase the list of generation elements that must meet reliability
standards, without a corresponding increase in wide-area reliability.

Project 2010-17 BES Definition Ballot Comments
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2

Voter

Entity

Segment

Vote

Comment
OPG recommends that the work planned for phase II, technical justification of the
generation and voltage thresholds, should be completed before implementing the
new definition of BES. OPG does not agree that the question of the 20 MVA
(single) versus 75 MVA (aggregate) threshold should be deferred until a
subsequent phase of the standard development process ("Phase II"). This
question should be resolved now. In general, key elements of the development
process should not be parsed out into multiple phases, in hopes that "Standard
Development Fatigue" will eliminate critics of the approach.
Further, selecting the generator terminals as the boundary for BES within the
generating station means that the Isolated Phase Bus (IPB), which connects the
generator terminals to the Low Voltage (LV) terminals of the generator step-up
(GSU) transformer, is now included as a BES element. The IPB is operated at low
voltage, no more than 22kV, so including it as a BES element is going beyond the
FERC order 743 and 743a. OPG strongly recommends that the BES boundary be
moved to the LV terminals of the GSU transformer.
To assure availability of the generation blackstart resources identified in the
Transmission Operator’s Power System Restoration Plan the generators are tested
according to the requirements of reliability standard EOP-009. Blackstart
resources are only required post LOBES (Loss of Bulk Electric System) and in
many cases do not contribute to the reliability of the BES under normal operating
conditions. OPG recommends that this inclusion be removed from the new
definition of BES.
OPG disagrees in general with proceeding to implement a 100 kV brightline
definition in the absence of a properly quantified cost/benefit analysis. Entities
are being asked to incur a high cost for no demonstrated benefit in wide-area
reliability.

Response: The SDT refers OPG to the individual comment responses in the definition comment form as the comments expressed
here are identical to the comments submitted by OPG on that form.
Roland Thiel

Platte River
Power
Authority

5

Negative

Definition of BES Platte River believes that the SDT has made substantial progress
towards a clear and workable definition of the BES. Although Platte River ballots
“Negative” we strongly support the approach to defining the Bulk Electric System
as proposed here. Platte River recognizes that, given the deadlines imposed by

Project 2010-17 BES Definition Ballot Comments
5
3

Voter

Entity

Segment

Vote

Comment
FERC in Order No. 743, it will not be possible for the SDT to conduct a technical
analysis within the time available. Accordingly, Platte River agrees with the
approach taken by the SDT, which is to propose a Phase II of the standards
development process that would address the generator threshold level and other
issues. However, it is our opinion that the second draft would benefit from further
clarification or modification. That said, Platte River is prepared to support the BES
definition as proposed by the SDT going forward. Platte River has taken the
opportunity to provide this industry feedback, as it is our understanding that we
will be afforded another ballot opportunity. If this were to be our sole occasion to
ballot, we would vote “Affirmative” at this time. We are encouraged by the work
that has been completed and we commend the SDT for their commitment and
extensive work thus far.
Detailed Information to Support BES Exceptions Requests Platte River believes
that a Yes vote for the Technical Principles for Demonstrating BES Exceptions
Request will result in minimal changes to today’s process under the current
definition which includes the language “as defined by the Regional Reliability
Organization.” While the proposed Technical Principles for Demonstrating BES
Exceptions Request includes a checklist that must be submitted with exception
requests, a yes vote will still require each region to develop their own methods
and criteria for assessing materials submitted with exemption requests. We
believe that a No vote with guidance to the drafting team that objective methods
and criteria must be developed and applied continent-wide will result in the
desired uniformity and consistency among regions in their assessment of
exception requests.

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step in
Phase II will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit comments
for the inclusion of items and issues to be considered by the SDT in Phase II.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
Project 2010-17 BES Definition Ballot Comments
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4

Voter
Entity
Segment
Vote
Comment
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria
and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to
say that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with
this position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at
as a single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional
Entity plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this
places the Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be
supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also
believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the
proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent
Technical Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s
findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure,
Section 7.0, provides NERC the option to remand the request to the Regional Entity with the mandate to process the exception if it
finds the Regional Entity erred in rejecting or disapproving the exception request. On the other side of this equation, one could
make an argument that the Regional Entity has no basis for what constitutes an acceptable submittal. Commenters point out that
the explicit types of studies to be provided and how to interpret the information aren’t shown in the request process. The SDT
again points to the variations that will abound in the requests as negating any hard and fast rules in this regard. However, one is
not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there is a great deal of
professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having viewed the request
details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be supplied for the
submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables
Project 2010-17 BES Definition Ballot Comments
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5

Voter
Entity
Segment
Vote
Comment
to take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation
of the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the
elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result ofa sudden disturbance, including a cyber
security incident, or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel,
the visibility of the process, and the experience gained by having this same panel review multiple requests will result in an
equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision
has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be
approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in
a favorable outcome.
Project 2010-17 BES Definition Ballot Comments
5
6

Voter
Steven Grega

Entity
Public Utility
District No. 1
of Lewis
County

Segment
5

Vote
Negative

Comment
The bright line definition makes the BES too inclusive. Many smaller facilities are
cought in the definition that are NOT BES facilities. Would suggest only the major
transmission cranking paths, in our area, as defined by WECC, should be
included. Why subject so many to these regulation when there is no or little
return on reliability to the system. We worry about compliance not reliability. In
our case, our small public utility has a run-of-river 70MW hydro (29MWave), nondispatchable, similar to wind. We made the mistake of connection to BPA's 230kV
system rather than our 69kV system. Our portion of the 230kV is uncontrolled by
a SCADA system. In our utility, we rely on phone calls for all outage reporting.
Since the 230kV line our feeds our utility substation and we have an alternitive
69kV connection, many time it is not a concern if the 230kV line is out. The
definition of the BES should be limited to truly only the major transmission paths
and major generation plants. I beleive it is good utility practce to make sure right
of ways are clear and relays are tested, but a number of Standards go way too
far with little or no benefit to the system, especially for smaller utilities. I think it
is time that we step back and evaluate what is truly important in making the BES
more reliable. Limiting the BES definition would be a good start.

Response: The bright-line definition is a continent-wide definition. In these instances, there will always be one off situations where
the bright-line might not apply. With the changes to the ERO Rules of Procedure for exception requests, an entity will have the right
to request exception from the definition even if the application of the bright-line would have brought them into the fold.
Dennis Kimm

MidAmerican
Energy Co.

6

Negative

The BES definition needs additional specific inclusion or exclusion provisions that
clearly exclude variable resource generation collector circuits rated below 100 kV
and generators less than 20 MVA connected to those collector circuits in
accordance with the registration criteria.

Response: Inclusion I4 denotes an aggregate threshold. This is clear from the requirement inclusion threshold of “aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating).”
Steven J Hulet

Salt River
Project

6

Negative

The Blackstart “Cranking Path” has been deleted from Inclusion 3 of the BES
definition. However, NERC standards EOP-005 and CIP-002, R1.2.4 require
documenting the Cranking Path. In addition, CIP-002-4 identifies the Cranking
Path as a Critical Asset in Attachment 1. Compliance to the NERC Standards
needs to be an exact science whenever possible. SRP does not argue the

Project 2010-17 BES Definition Ballot Comments
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7

Voter

Entity

Segment

Vote

Comment
inclusion or exclusion of Cranking Path. However, if it is excluded, guidance must
be provided on whether or not a Cranking Path is subject to the previously
mentioned Standards.

Response: Cranking Paths are subject to any standard in which they are specifically spelled out.
Donald Nelson

Commonwealth
of
Massachusetts
Department of
Public Utilities

9

Negative

Please refer to our detailed comments filed today. As described further in our
comments, the MA DPU is primarly concerned with the substance of the definition
and the process for developing this standard as follows: 1) Phased Approach.
While well-intentioned, separating the BES definition project into two separate
phases is problematic from both a procedural and substantive perspective. While
we recognize that the filing due date is rapidly approaching, the BES definition
cannot be considered in a vacuum, divorced from the concerns raised by a
number of parties in response to past postings of the BES definition. The issues
NERC has identified for consideration during the proposed “Phase 2” are
inseparable from the development of the BES definition (e.g., generation
thresholds, technical justification for the 100 kV threshold) and should be
squarely addressed before a definition is adopted and ratepayers incur costs
related to compliance with mandates that may or may not be revised through the
second phase of the project. The importance of considering concerns before
adopting a definition is heightened by the proposed two-year implementation
requirement. This short implementation period almost guarantees that entities
will commit resources shortly after adoption of the definition to ensure
compliance within the mandated period. In other words, ratepayers will bear
costs related to compliance irrespective of any change resulting from the Phase 2
process or the exception process. Expediency, while understandable given the
filing deadline, must be balanced against the risk that a multi-phased approach
could lead to significant consumer costs without attendant meaningful reliability
benefits.
2) Cost-Benefit Analysis. A cost impact analysis should be performed as part of
developing any reliability standard. However, the development of the BES
definition has failed to consider the cost impacts of the definition (and its
inclusions and exclusions) and has not weighed these impacts against identified

Project 2010-17 BES Definition Ballot Comments
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8

Voter

Entity

Segment

Vote

Comment
benefits that the definition would achieve. The MA DPU supported the May 21,
2011 comments from the New England States Committee on Electricity
(“NESCOE”) on the last posting of the BES definition. In these comments,
NESCOE stated that “any new costs a revised definition imposes - which fall
ultimately on consumers - should provide meaningful reliability benefits.” A costbenefit analysis should be integral to the development of a BES definition and,
indeed, any reliability standard. This analysis should include a probabilistic risk
assessment examining the likelihood of an event and the costs and risks resulting
from such event, which should be weighed against the costs of complying with
the proposed reliability measures.
3) Technical Justification. In addition to performing a cost-benefit analysis, a
technical basis must be provided to justify a proposed reliability standard.
However, the proposed BES definition does not provide a technical justification
for the 100 kV threshold, the threshold for generation resources, or other
elements of the definition. As stated above, while well-intentioned and
understandable, deferring this technical justification to a later and separate phase
of the project is a flawed and potentially costly approach. Providing a technical
justification for a reliability standard is a core function of standards development
and should be addressed at the forefront of the process rather than relegated to
a separate phase largely undertaken after a standard is filed.

Response: 1. Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step
in Phase II will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit
comments for the inclusion of items and issues to be considered by the SDT in Phase II. Since the revised definition relies heavily
on the status quo of the current definition, the SDT does not anticipate that many entities will be burdened with additional costs.
2. The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 & 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
contracting the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the
Project 2010-17 BES Definition Ballot Comments
5
9

Voter
Entity
Segment
Vote
Comment
current BES definition has varying degrees of Regional application and has resulted in different conclusions on what is currently
considered to be part of the BES. This inconsistency in the application and subsequent results were also identified by the
Commission in Orders No. 743 & 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition
coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on Regions.
Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid
on a continent-wide basis. Therefore, the SDT believes the best opportunity to address cost concerns will be through the
development of Regional transition plans once the definition has been approved by the Commission.
3. Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step in Phase II
will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit comments for the
inclusion of items and issues to be considered by the SDT in Phase II. Technical justifications for all variables involved in the
definition will be done in Phase II.
Diane J Barney

National
Association of
Regulatory
Utility
Commissioners

9

Negative

There is a lack of clarity as to how the information is to be used and by what
weight in the exception process.

Response: The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The
SDT would like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many
hours of discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire
is not achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The
SDT would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the
criteria and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to
say that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with
this position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at
Project 2010-17 BES Definition Ballot Comments
6
0

Voter
Entity
Segment
Vote
Comment
as a single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional
Entity plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this
places the Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be
supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also
believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the
proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent
Technical Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s
findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure,
Section 7.0, provides NERC the option to remand the request to the Regional Entity with the mandate to process the exception if it
finds the Regional Entity erred in rejecting or disapproving the exception request. On the other side of this equation, one could
make an argument that the Regional Entity has no basis for what constitutes an acceptable submittal. Commenters point out that
the explicit types of studies to be provided and how to interpret the information aren’t shown in the request process. The SDT
again points to the variations that will abound in the requests as negating any hard and fast rules in this regard. However, one is
not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there is a great deal of
professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having viewed the request
details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be supplied for the
submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables
to take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation
of the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the
elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result ofa sudden disturbance, including a cyber
Project 2010-17 BES Definition Ballot Comments
6
1

Voter
Entity
Segment
Vote
Comment
security incident, or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel,
the visibility of the process, and the experience gained by having this same panel review multiple requests will result in an
equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision
has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be
approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in
a favorable outcome.
Thomas
Dvorsky

New York State
Department of
Public Service

9

Negative

The currently proposed definition of the BES is based neither on a technical
analysis nor on a cost impact study.

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step in
Phase II will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit comments
for the inclusion of items and issues to be considered by the SDT in Phase II. Technical justifications for all variables involved in the
definition will be done in Phase II.
Project 2010-17 BES Definition Ballot Comments
6
2

Voter
Entity
Segment
Vote
Comment
The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 & 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
contracting the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the
current BES definition has varying degrees of Regional application and has resulted in different conclusions on what is currently
considered to be part of the BES. This inconsistency in the application and subsequent results were also identified by the
Commission in Orders No. 743 & 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition
coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on Regions.
Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid
on a continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the
development of Regional transition plans once the definition has been approved by the Commission.
Larry Nordell

Montana
Consumer
Counsel

8

Abstain

The BES definition must be cognizant of costs and benefits. At the very least it
needs to have an exclusion for elements whose failure would have no
consequential impacts on the bulk system, and an exclusion for elements for
which the costs inclusion are clearly in excess of the benefits of inclusion.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and
non-BES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 & 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
contracting the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the
current BES definition has varying degrees of Regional application and has resulted in different conclusions on what is currently
considered to be part of the BES. This inconsistency in the application and subsequent results were also identified by the
Commission in Orders No. 743 & 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition
Project 2010-17 BES Definition Ballot Comments
6
3

Voter
Entity
Segment
Vote
Comment
coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on Regions.
Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid
on a continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the
development of Regional transition plans once the definition has been approved by the Commission.
John D Varnell

Tenaska Power
Services Co.

6

Abstain

Which part of this definition has the highest priority inclusions or exclusions.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES
and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100
kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is
needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
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Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 –
I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks)
should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
William M
Chamberlain

California
Energy
Commission

9

Affirmative

While we are voting in favor of this definition as an improvement over the current
status quo, we agree with WECC that additional improvements are necessary as
set forth below. For Inclusion 3 we agree that Blackstart units should be
considered vital to the overall operation of the BES, and therefore included in the
definition of the BES. However, we do not agree with the deletion of the cranking
path from Inclusion 3. The cranking path should be included in the definition
since NERC standards EOP-005 and CIP-002, R1.2.4 require documenting the
cranking path and the revised CIP-002-4 identifies the cranking path as a critical
asset in Attachment 1. To be able to count on a Blackstart unit to perform as
designed in the Blackstart Restoration Plan, it must be ensured that the cranking
path is available.
We believe that additional clarity is needed in the wording of Inclusion 4. It is our
understanding, for example, that Inclusion 4 is not intended to include each
individual wind turbine generating unit in a wind farm as a BES element, but

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rather to include the point at which the aggregation becomes large enough to
meet the aggregate capacity threshold of 75 MVA. However, the response to
comments from the last comment posting and the current wording of Inclusion 4
do not provide sufficient clarity to answer this question. We believe that the
wording of Inclusion 4 could be modified to add clarity on this topic.
We believe that Inclusion 5 should be modified to identify some minimum
Reactive Power threshold for static or dynamic devices similar to that identified
for generating sources in Inclusion 2. As worded a 1 MVA device supplying or
absorbing Reactive Power that is connected at 100 kV or higher would be
included in the BES. We believe that Exclusion 2 should be modified to include a
size threshold for individual generating units, similar to that identified in Inclusion
2.
As currently worded Exclusion 2 places the same threshold (75 MVA) on a single
generating unit as is placed on multiple generating units.

Response: Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system
Elements. The Transmission Operator’s restoration plans identify a number of possible system restoration scenarios to address the
uncertainty of the actual requirements needed to address a particular restoration event including Cranking Paths. Therefore, the
SDT maintains that Cranking Paths are not required to be included in the BES definition as they are essentially a moving target and
could include distribution Elements. The Cranking Paths issue will be discussed anew in Phase II of this project. No change made.
Inclusion I4 denotes an aggregate threshold. This is clear from the requirement inclusion threshold of “aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating).”
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
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with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
The threshold levels of generators and the relationship between the ERO Statement of Compliance Registry Criteria and the BES
definition will be considered in the Phase 2 review. However, the SDT believes that a value was needed for Phase I and decided to
proceed with the single 75 MVA threshold. No change made.
Claston
Augustus
Sunanon

Orlando
Utilities
Commission

6

Affirmative

Orlando Utilities Commission supports the new definition, although our support is
conditioned on: (1) a workable Exceptions process being developed in
conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date.

Response: The exceptions process and the definition are being worked on in parallel and will b efiled as one document.
Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step in Phase II
will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit comments for the
inclusion of items and issues to be considered by the SDT in Phase II.
Brenda Powell

Constellation
Energy
Commodities
Group

6

Affirmative

While we support the proposed definition to satisfy the FERC Order, we also
support continued work on the threshold questions slated for "Phase II", in
particular the refinement of the generation thresholds.

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. Thresholds will
be analyzed at that time.
Michelle R
DAntuono

Occidental
Chemical

5

Affirmative

1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. Yes:
X Comments: However, one of the FERC directives in Order 743 charged NERC
with delineating the difference between transmission and distribution. The
Inclusions and Exclusions are a step in that direction, but this subject will need
more consideration in Phase II.

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2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments:
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. No: X Comments: Since an aggregate of 75 MVA is allowed at a single
site, there is no basis for maintaining the 20 MVA for a single generator. The
proposed MOD-026 assigns thresholds by region that are much higher than 20
MVA for modeling purposes. Since modeling generally would require more
granularity than what is necessary for the reliable operation of the interconnected
transmission system (BES), the SDT might want to review the threshold basis for
NERC Project 2007-09 (Generator Verification). It is understood that the threshold
will be reconsidered in Phase II of the BES Definition Project; however, a modest
change from 20 to 75 MVA seems appropriate in the interim period justified by
the current 75f MVA aggregate per site. For clarity purposes the following should
be added at the end "unless excluded under Exclusion E2".
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments:
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments: To distinguish this Inclusion from Inclusion I2, the
SDT might want to clarify that the collection system (usually at voltage below 100

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KV anyway) is not part of the BES-just the resources and any transformers
included by I1, if this is indeed the intent of this Inclusion.
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments:
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments: A much needed change from the first posting, as
this will maintain the status quo referred to in the introduction text.
8. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: X Comments:
9. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E3 (local network)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments: This Exclusion and Exclusion E1 aid in the
delineation of distribution versus transmission.
10. The SDT has added specific exclusions to the core definition in response to
industry comments. Do you agree with Exclusion E4 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: X Comments: This is a needed exception to Inclusion I5 as these
reactive power resources are used by retail customers for power factor correction
at their own facilities in order avoid imposed power factor penalties.
11. Are there any other concerns with this definition that haven’t been covered in

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previous questions and comments remembering that the exception criteria are
posted separately for comment? Yes: X Comments: It might be worthwhile to
explain the relationship (timeline) between the BES Definition implementation
plan and the compliance implementation plan proposed in the BES RoP team’s
new Appendix 5C for the NERC Rules of Procedure.

Response: 1. Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up. The first step
in Phase II will be the posting of the Phase II draft SAR for comment. At that time, you will have the opportunity to submit
comments for the inclusion of items and issues to be considered by the SDT in Phase II.
2. Thank you for your support.
3. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. Correlation to MOD standards would be included in Phase II.
4. Thank you for your support.
5. The essential distinction between Inclusions I2 and I4 is that Inclusion I2 may not include generating resources that use lower
voltage collection systems while Inclusion I4 is specifically designed to accomplish this purpose. Inclusion I4 speaks towards the
inclusion of the resources themselves, not the transmission Element(s) of the collector systems operated below 100 kV or not
included under Inclusion I2.
6. – 10. Thank you for your support.
11. For a newly identified Element(s) under the revised BES definition, the time period to be in full compliance with all applicable
Reliability Standards is 24 months from the effective date of the definition. If the entity wishes to file for an exception of a newly
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identified Element(s) under the revised BES definition through the Rules of Procedure Exception Process, the entity will have 12
months from the effective date of the revised BES definition in which to file such a request. If the exception request is rejected or
disapproved and the classification of the Element(s) remains as a BES Element, the Regional Entity and the owner of such a BES
Element(s) shall agree to an Implementation Plan for full compliance obligations, which will establish an implementation date no
earlier than the date established by the definition Implementation Plan (24 months from the effective date of the definition).
Gary Ofner

North Carolina
Electric
Membership
Corp.

1

Affirmative

In general, we support the proposed definition of the BES. However, we have
identified a few concerns that warrant the SDT’s consideration. We’d prefer to see
the language from the ERO Statement of Compliance Registry Criteria repeated
within the BES Definition itself instead of referencing an outside document. As it
stands right now, the Compliance Registry Criteria needs to stay intact for Phase I
of this project. That makes the Compliance Registry Criteria reliant on the BES
Definition and vice versa.
We understand that the Statement of Compliance Registry Criteria may be
reviewed/revised at the same time Phase 2 of this project is being developed,
therefore we agree with Inclusion I2 of this draft.
Blackstart Resources can actually be on the distribution system. There is still the
question of whether the distribution system would then be subjected to the
enforceable standards. If so, there would most likely be a significant cost increase
associated with tracking compliance for these distribution systems without a
commensurate increase in reliability since Blackstart Resources are rarely used.
This could very well cause entities to un-designate Blackstart Resources on
distribution systems to avoid these distribution systems from becoming part of
the BES. The same rationale that was used for eliminating cranking paths could
also be applied to Blackstart Resources.
A flowgate should not be used to limit applicability of E3. First, there is no
definition for what constitutes a permanent flowgate. Second, flowgates are often
created for a myriad of reasons that have nothing to do with them being
necessary to operate the BES. While section c) in E3 attempts to limit the
applicability to permanent flowgates, there is no definition for what constitutes a
permanent flowgate particularly since no flowgate is truly permanent. The NERC
Glossary of Terms definition of flowgate includes flowgates in the IDC. This is a

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Jeffrey S
Brame

Entity

North Carolina
Electric
Membership
Corp.

Segment

5

Vote

Affirmative

Comment
problem because flowgates are included in the IDC for many reasons not just
because reliability issues are identified. Flowgates could be included to simply
study the impact of schedules on a particular interface as an example. It does not
mean the interface is critical. As an example, it could be used to generate
evidence that there are no transactional impacts to support exclusion from the
BES. Furthermore, the list of flowgates in the IDC is dynamic. The master list of
IDC flowgates is updated monthly and IDC users can add temporary flowgates at
anytime. While the “permanent” adjective applied to flowgates probably limits the
applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month
and removed another. Flowgates are created for many reasons that have nothing
to do with them being necessary to operate the BES. First, flowgates are created
to manage congestion. The IDC is more of a congestion management tool than a
reliability tool. FERC recognized this in Order 693, when they directed NERC to
make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs
that have been violated. Rather, other actions such as re-dispatch must be used
in conjunction. Second, flowgates are used as a convenient point to calculate
flows to sell transmission service. The characteristics of the flowgate make it a
good proxy for estimating how much contractual use has been sold not
necessarily how much flow will actually occur. While some flowgates definitely are
created for reliability issues such as IROLs, many simply are not. The term “nonretail generation” used in Exclusion E1 (item c) and again in E3 (item a) should
be clarified (see comments for question 8 below). The Note after item c should
also be clarified to indicate that closing a normally open switch doesn’t affect this
exclusion.
In general, we support the proposed definition of the BES. However, we have
identified a few concerns that warrant the SDT’s consideration. We’d prefer to see
the language from the ERO Statement of Compliance Registry Criteria repeated
within the BES Definition itself instead of referencing an outside document. As it
stands right now, the Compliance Registry Criteria needs to stay intact for Phase I
of this project. That makes the Compliance Registry Criteria reliant on the BES
Definition and vice versa.

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We understand that the Statement of Compliance Registry Criteria may be
reviewed/revised at the same time Phase 2 of this project is being developed,
therefore we agree with Inclusion I2 of this draft.
Blackstart Resources can actually be on the distribution system. There is still the
question of whether the distribution system would then be subjected to the
enforceable standards. If so, there would most likely be a significant cost increase
associated with tracking compliance for these distribution systems without a
commensurate increase in reliability since Blackstart Resources are rarely used.
This could very well cause entities to un-designate Blackstart Resources on
distribution systems to avoid these distribution systems from becoming part of
the BES. The same rationale that was used for eliminating cranking paths could
also be applied to Blackstart Resources.
A flowgate should not be used to limit applicability of E3. First, there is no
definition for what constitutes a permanent flowgate. Second, flowgates are often
created for a myriad of reasons that have nothing to do with them being
necessary to operate the BES. While section c) in E3 attempts to limit the
applicability to permanent flowgates, there is no definition for what constitutes a
permanent flowgate particularly since no flowgate is truly permanent. The NERC
Glossary of Terms definition of flowgate includes flowgates in the IDC. This is a
problem because flowgates are included in the IDC for many reasons not just
because reliability issues are identified. Flowgates could be included to simply
study the impact of schedules on a particular interface as an example. It does not
mean the interface is critical. As an example, it could be used to generate
evidence that there are no transactional impacts to support exclusion from the
BES. Furthermore, the list of flowgates in the IDC is dynamic. The master list of
IDC flowgates is updated monthly and IDC users can add temporary flowgates at
anytime. While the “permanent” adjective applied to flowgates probably limits the
applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month
and removed another. Flowgates are created for many reasons that have nothing
to do with them being necessary to operate the BES. First, flowgates are created
to manage congestion. The IDC is more of a congestion management tool than a

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reliability tool. FERC recognized this in Order 693, when they directed NERC to
make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs
that have been violated. Rather, other actions such as re-dispatch must be used
in conjunction. Second, flowgates are used as a convenient point to calculate
flows to sell transmission service. The characteristics of the flowgate make it a
good proxy for estimating how much contractual use has been sold not
necessarily how much flow will actually occur. While some flowgates definitely are
created for reliability issues such as IROLs, many simply are not.
The term “non-retail generation” used in Exclusion E1 (item c) and again in E3
(item a) should be clarified (see comments for question 8 below).
The Note after item c should also be clarified to indicate that closing a normally
open switch doesn’t affect this exclusion.

Response: The SDT has reverted to specific numeric thresholds consistent with the ERO Statement of Compliance Registry Criteria
for Phase I.
Thank you for your support.
The SDT disagrees that Blackstart Resources should not be included in the BES Definition. The Commission directed NERC to revise
its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric
transmission network. The SDT interprets this to include operation under both normal and emergency conditions, which includes
situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from
the System or can be energized without connection to the remainder of the System, in order to meet a Transmission Operator’s
restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of
the electric system that can be isolated and then energized to deliver electric power during a restoration event are essential to
enable the startup of one or more other generating units as defined in the Transmission Operator’s restoration plan. For these
reasons, the SDT continues to include Blackstart Resources indentified in the Transmission Operator’s restoration plan as BES
elements. No change made.
The SDT believes that the language in Exclusion E3.c prohibiting “Flowgates” from qualifying for definitional exclusion is appropriate
and necessary. As a definitional exclusion characteristic, Exclusion E3.c must follow the principle of being a bright-line and easily
identifiable, and as such, the SDT feels that the definition cannot allow some types of Flowgates and disallow others. Flowgates
must continue to be a prohibiting characteristic under Exclusion E3, since these facilities are more likely to be used in the transfer
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of bulk power than not. An entity who wishes to make a case for exclusion of a unique type of Flowgate facility can do so through
the exception process. The SDT believes that the continued qualifier of “permanent” associated with the term “Flowgate”
addresses the majority of the concern in this comment. No change made.
“Non-retail generation” means that generation which is on the system (supply) side of the retail meter.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is
operated in the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in
the normal operating environment.
Paul
Cummings

City of Redding

5

Affirmative

An affirmative vote is conditional on NERC's dedication to phase 2 of the Project.

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up.
Pawel Krupa

Seattle City
Light

1

Affirmative

Comments: 1. Core Definition: Yes Comments: Seattle City Light (SCL) believes
that the SDT has made substantial progress towards a clear and workable
definition of the BES. We strongly support the approach to defining the Bulk
Electric System as proposed here. SCL recognizes that, given the deadlines
imposed by FERC in Order No. 743, it will not be possible for the SDT to conduct
a technical analysis within the time available. Accordingly, SCL agrees with the
approach taken by the SDT, which is to propose a Phase II of the standards
development process that would address the generator threshold level and other
issues. However, it is our opinion that the second draft would benefit from further
clarification or modification in a number of respects, as are detailed in our
comments.
2. I1 - Transformer inclusions: No Comments: The wording of Inclusion I1 is not
clear. The term transformers needs to be further defined with respect to
multiphase transformers and generator step-up transformers. Recommend the
following wording: “All transformers with at least two primary and secondary
terminals operated at or above 100kV, and generator step-up transformers (GSU)
with one terminal operated at or above 100kV, unless excluded by E1 or E3.”
3. I2 - Generation Thresholds: Yes Comments: Recommend removing the

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reference to the Statement of Compliance Registry Criteria. The definition should
be the governing document and provide the details of what generating resources
should be included. The current language induces circular arguments without a
true governing document. The definition should drive what appears in the
Registry Criteria. Inclusion I2 should be revised to read: “Generating resources
with a gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion.
4. I3 - Blackstart Units: Yes Comments: None
5. I4 - Dispersed Power: No Comments: The term “common point” needs
clarification with respect to connection to the BES. Recommend the following
wording: “connected at a common point through a dedicated step-up transformer
with a high-side voltage of 100 KV or above.”
6. I5 - Reactive Power devices: No Comments: Technical studies need to be
conducted to confirm reactive resource impacts on the reliability of the BES. The
inclusion of reactive resources is a significant expansion of the current BES
definition and therefore requires technical justification for inclusion. Inclusion I5
as written is generally confusing with multiple references to other inclusions and
exclusions in the definition. Recommend removing references to reactive
resources from Phase 1 until technical justification can be demonstrated (as part
of Phase 2).
7. E1 - Radial System: Yes Comments: (1) The E1 Reference Note should be reworded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. (2) Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. (3) Recommend that the potential inclusion in the BES of
protective relay systems which reach beyond a load network or ring bus should
be confirmed in Phase 2 pursuant to technical studies.
8. E2 - Behind-the-Meter-Generation: Yes Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in

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Dana
Wheelock

Entity

Seattle City
Light

Segment

3

Vote

Affirmative

Comment
Section III.c.4.
9. E3 - Local Network: Yes Comments: Defining characteristic b) “Power flows
only into the LN” is confusing. For example, is this condition meant as an
absolute, that power never under any circumstances flows out? Are exceptions
allowed, such as during a switching operation or a catastrophic outage? Does
power flow through a local net load sink, as might be determined by
superposition of supply sources over time, negate that sink from exclusion as a
LN? Recommend additional clarity for this characteristic.
10. E4 - Customer Reactive Power devices: No Comments: Refer to comments
related to reactive resources for Question 6 regarding Inclusion I5.
11. Other concerns: No Comments: Seattle City Light (SCL) believes that the SDT
has made substantial progress towards a clear and workable definition of the
BES. We strongly support the approach to defining the Bulk Electric System as
proposed here. SCL recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address the generator threshold level and other issues. However, it is our
opinion that the second draft would benefit from further clarification or
modification in a number of respects, as are detailed in our comments.
Comments: 1. Core Definition: Yes Comments: Seattle City Light (SCL) believes
that the SDT has made substantial progress towards a clear and workable
definition of the BES. We strongly support the approach to defining the Bulk
Electric System as proposed here. SCL recognizes that, given the deadlines
imposed by FERC in Order No. 743, it will not be possible for the SDT to conduct
a technical analysis within the time available. Accordingly, SCL agrees with the
approach taken by the SDT, which is to propose a Phase II of the standards
development process that would address the generator threshold level and other
issues. However, it is our opinion that the second draft would benefit from further
clarification or modification in a number of respects, as are detailed in our
comments.
2. I1 - Transformer inclusions: No Comments: The wording of Inclusion I1 is not

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Comment
clear. The term transformers needs to be further defined with respect to
multiphase transformers and generator step-up transformers. Recommend the
following wording: “All transformers with at least two primary and secondary
terminals operated at or above 100kV, and generator step-up transformers (GSU)
with one terminal operated at or above 100kV, unless excluded by E1 or E3.”
3. I2 - Generation Thresholds: Yes Comments: Recommend removing the
reference to the Statement of Compliance Registry Criteria. The definition should
be the governing document and provide the details of what generating resources
should be included. The current language induces circular arguments without a
true governing document. The definition should drive what appears in the
Registry Criteria. Inclusion I2 should be revised to read: “Generating resources
with a gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion.
4. I3 - Blackstart Units: Yes Comments: None
5. I4 - Dispersed Power: No Comments: The term “common point” needs
clarification with respect to connection to the BES. Recommend the following
wording: “connected at a common point through a dedicated step-up transformer
with a high-side voltage of 100 KV or above.”
6. I5 - Reactive Power devices: No Comments: Technical studies need to be
conducted to confirm reactive resource impacts on the reliability of the BES. The
inclusion of reactive resources is a significant expansion of the current BES
definition and therefore requires technical justification for inclusion. Inclusion I5
as written is generally confusing with multiple references to other inclusions and
exclusions in the definition. Recommend removing references to reactive
resources from Phase 1 until technical justification can be demonstrated (as part
of Phase 2).
7. E1 - Radial System: Yes Comments: (1) The E1 Reference Note should be reworded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. (2) Recommend that

Project 2010-17 BES Definition Ballot Comments
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Voter

Dennis
Sismaet

Entity

Seattle City
Light

Segment

6

Vote

Affirmative

Comment
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. (3) Recommend that the potential inclusion in the BES of
protective relay systems which reach beyond a load network or ring bus should
be confirmed in Phase 2 pursuant to technical studies.
8. E2 - Behind-the-Meter-Generation: Yes Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. E3 - Local Network: Yes Comments: Defining characteristic b) “Power flows
only into the LN” is confusing. For example, is this condition meant as an
absolute, that power never under any circumstances flows out? Are exceptions
allowed, such as during a switching operation or a catastrophic outage? Does
power flow through a local net load sink, as might be determined by
superposition of supply sources over time, negate that sink from exclusion as a
LN? Recommend additional clarity for this characteristic.
10. E4 - Customer Reactive Power devices: No Comments: Refer to comments
related to reactive resources for Question 6 regarding Inclusion I5.
11. Other concerns: No Comments: Seattle City Light (SCL) believes that the SDT
has made substantial progress towards a clear and workable definition of the
BES. We strongly support the approach to defining the Bulk Electric System as
proposed here. SCL recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address the generator threshold level and other issues. However, it is our
opinion that the second draft would benefit from further clarification or
modification in a number of respects, as are detailed in our comments.
Comments: 1. Core Definition: Yes Comments: Seattle City Light (SCL) believes
that the SDT has made substantial progress towards a clear and workable
definition of the BES. We strongly support the approach to defining the Bulk
Electric System as proposed here. SCL recognizes that, given the deadlines
imposed by FERC in Order No. 743, it will not be possible for the SDT to conduct
a technical analysis within the time available. Accordingly, SCL agrees with the

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Comment
approach taken by the SDT, which is to propose a Phase II of the standards
development process that would address the generator threshold level and other
issues. However, it is our opinion that the second draft would benefit from further
clarification or modification in a number of respects, as are detailed in our
comments.
2. I1 - Transformer inclusions: No Comments: The wording of Inclusion I1 is not
clear. The term transformers needs to be further defined with respect to
multiphase transformers and generator step-up transformers. Recommend the
following wording: “All transformers with at least two primary and secondary
terminals operated at or above 100kV, and generator step-up transformers (GSU)
with one terminal operated at or above 100kV, unless excluded by E1 or E3.”
3. I2 - Generation Thresholds: Yes Comments: Recommend removing the
reference to the Statement of Compliance Registry Criteria. The definition should
be the governing document and provide the details of what generating resources
should be included. The current language induces circular arguments without a
true governing document. The definition should drive what appears in the
Registry Criteria. Inclusion I2 should be revised to read: “Generating resources
with a gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion.
4. I3 - Blackstart Units: Yes Comments: None
5. I4 - Dispersed Power: No Comments: The term “common point” needs
clarification with respect to connection to the BES. Recommend the following
wording: “connected at a common point through a dedicated step-up transformer
with a high-side voltage of 100 KV or above.”
6. I5 - Reactive Power devices: No Comments: Technical studies need to be
conducted to confirm reactive resource impacts on the reliability of the BES. The
inclusion of reactive resources is a significant expansion of the current BES
definition and therefore requires technical justification for inclusion. Inclusion I5
as written is generally confusing with multiple references to other inclusions and
exclusions in the definition. Recommend removing references to reactive

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resources from Phase 1 until technical justification can be demonstrated (as part
of Phase 2).
7. E1 - Radial System: Yes Comments: (1) The E1 Reference Note should be reworded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. (2) Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. (3) Recommend that the potential inclusion in the BES of
protective relay systems which reach beyond a load network or ring bus should
be confirmed in Phase 2 pursuant to technical studies.
8. E2 - Behind-the-Meter-Generation: Yes Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. E3 - Local Network: Yes Comments: Defining characteristic b) “Power flows
only into the LN” is confusing. For example, is this condition meant as an
absolute, that power never under any circumstances flows out? Are exceptions
allowed, such as during a switching operation or a catastrophic outage? Does
power flow through a local net load sink, as might be determined by
superposition of supply sources over time, negate that sink from exclusion as a
LN? Recommend additional clarity for this characteristic.
10. E4 - Customer Reactive Power devices: No Comments: Refer to comments
related to reactive resources for Question 6 regarding Inclusion I5.
11. Other concerns: No Comments: Seattle City Light (SCL) believes that the SDT
has made substantial progress towards a clear and workable definition of the
BES. We strongly support the approach to defining the Bulk Electric System as
proposed here. SCL recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address the generator threshold level and other issues. However, it is our
opinion that the second draft would benefit from further clarification or
modification in a number of respects, as are detailed in our comments.

Project 2010-17 BES Definition Ballot Comments
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Voter
Michael J.
Haynes

Entity
Seattle City
Light

Segment
5

Vote

Comment

Affirmative

1. Core Definition: Yes Comments: Seattle City Light (SCL) believes that the SDT
has made substantial progress towards a clear and workable definition of the
BES. We strongly support the approach to defining the Bulk Electric System as
proposed here. SCL recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address the generator threshold level and other issues. However, it is our
opinion that the second draft would benefit from further clarification or
modification in a number of respects, as are detailed in our comments.
2. I1 - Transformer inclusions: No Comments: The wording of Inclusion I1 is not
clear. The term transformers needs to be further defined with respect to
multiphase transformers and generator step-up transformers. Recommend the
following wording: “All transformers with at least two primary and secondary
terminals operated at or above 100kV, and generator step-up transformers (GSU)
with one terminal operated at or above 100kV, unless excluded by E1 or E3.”
3. I2 - Generation Thresholds: Yes Comments: Recommend removing the
reference to the Statement of Compliance Registry Criteria. The definition should
be the governing document and provide the details of what generating resources
should be included. The current language induces circular arguments without a
true governing document. The definition should drive what appears in the
Registry Criteria. Inclusion I2 should be revised to read: “Generating resources
with a gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion.
4. I3 - Blackstart Units: Yes Comments: None
5. I4 - Dispersed Power: No Comments: The term “common point” needs
clarification with respect to connection to the BES. Recommend the following
wording: “connected at a common point through a dedicated step-up transformer
with a high-side voltage of 100 KV or above.”
6. I5 - Reactive Power devices: No Comments: Technical studies need to be

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conducted to confirm reactive resource impacts on the reliability of the BES. The
inclusion of reactive resources is a significant expansion of the current BES
definition and therefore requires technical justification for inclusion. Inclusion I5
as written is generally confusing with multiple references to other inclusions and
exclusions in the definition. Recommend removing references to reactive
resources from Phase 1 until technical justification can be demonstrated (as part
of Phase 2).
7. E1 - Radial System: Yes Comments: (1) The E1 Reference Note should be reworded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. (2) Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. (3) Recommend that the potential inclusion in the BES of
protective relay systems which reach beyond a load network or ring bus should
be confirmed in Phase 2 pursuant to technical studies.
8. E2 - Behind-the-Meter-Generation: Yes Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. E3 - Local Network: Yes Comments: Defining characteristic b) “Power flows
only into the LN” is confusing. For example, is this condition meant as an
absolute, that power never under any circumstances flows out? Are exceptions
allowed, such as during a switching operation or a catastrophic outage? Does
power flow through a local net load sink, as might be determined by
superposition of supply sources over time, negate that sink from exclusion as a
LN? Recommend additional clarity for this characteristic.
10. E4 - Customer Reactive Power devices: No Comments: Refer to comments
related to reactive resources for Question 6 regarding Inclusion I5.
11. Other concerns: No Comments: Seattle City Light (SCL) believes that the SDT
has made substantial progress towards a clear and workable definition of the
BES. We strongly support the approach to defining the Bulk Electric System as
proposed here. SCL recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct a technical analysis

Project 2010-17 BES Definition Ballot Comments
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3

Voter

Hao Li

Entity

Seattle City
Light

Segment

4

Vote

Affirmative

Comment
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address the generator threshold level and other issues. However, it is our
opinion that the second draft would benefit from further clarification or
modification in a number of respects, as are detailed in our comments.
Comments: 1. Core Definition: Yes Comments: Seattle City Light (SCL) believes
that the SDT has made substantial progress towards a clear and workable
definition of the BES. We strongly support the approach to defining the Bulk
Electric System as proposed here. SCL recognizes that, given the deadlines
imposed by FERC in Order No. 743, it will not be possible for the SDT to conduct
a technical analysis within the time available. Accordingly, SCL agrees with the
approach taken by the SDT, which is to propose a Phase II of the standards
development process that would address the generator threshold level and other
issues. However, it is our opinion that the second draft would benefit from further
clarification or modification in a number of respects, as are detailed in our
comments.
2. I1 - Transformer inclusions: No Comments: The wording of Inclusion I1 is not
clear. The term transformers needs to be further defined with respect to
multiphase transformers and generator step-up transformers. Recommend the
following wording: “All transformers with at least two primary and secondary
terminals operated at or above 100kV, and generator step-up transformers (GSU)
with one terminal operated at or above 100kV, unless excluded by E1 or E3.”
3. I2 - Generation Thresholds: Yes Comments: Recommend removing the
reference to the Statement of Compliance Registry Criteria. The definition should
be the governing document and provide the details of what generating resources
should be included. The current language induces circular arguments without a
true governing document. The definition should drive what appears in the
Registry Criteria. Inclusion I2 should be revised to read: “Generating resources
with a gross nameplate rating of 20MVA or greater, or generating plant/facility
connected at a common bus, with an aggregate nameplate rating of 75MVA or
greater and is directly connected to a BES Element.” This is consistent with
proposed Inclusion.

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4. I3 - Blackstart Units: Yes Comments: None
5. I4 - Dispersed Power: No Comments: The term “common point” needs
clarification with respect to connection to the BES. Recommend the following
wording: “connected at a common point through a dedicated step-up transformer
with a high-side voltage of 100 KV or above.”
6. I5 - Reactive Power devices: No Comments: Technical studies need to be
conducted to confirm reactive resource impacts on the reliability of the BES. The
inclusion of reactive resources is a significant expansion of the current BES
definition and therefore requires technical justification for inclusion. Inclusion I5
as written is generally confusing with multiple references to other inclusions and
exclusions in the definition. Recommend removing references to reactive
resources from Phase 1 until technical justification can be demonstrated (as part
of Phase 2).
7. E1 - Radial System: Yes Comments: (1) The E1 Reference Note should be reworded to state “Radial systems shall be assessed with all normally open
switching devices in their open positions.” The current wording is unclear with
respect to the treatment of normally open switching devices. (2) Recommend that
load bus tie-breakers be excluded from the BES as these devices apply to the
users of the BES. (3) Recommend that the potential inclusion in the BES of
protective relay systems which reach beyond a load network or ring bus should
be confirmed in Phase 2 pursuant to technical studies.
8. E2 - Behind-the-Meter-Generation: Yes Comments: The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in
Section III.c.4.
9. E3 - Local Network: Yes Comments: Defining characteristic b) “Power flows
only into the LN” is confusing. For example, is this condition meant as an
absolute, that power never under any circumstances flows out? Are exceptions
allowed, such as during a switching operation or a catastrophic outage? Does
power flow through a local net load sink, as might be determined by
superposition of supply sources over time, negate that sink from exclusion as a
LN? Recommend additional clarity for this characteristic.
10. E4 - Customer Reactive Power devices: No Comments: Refer to comments

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related to reactive resources for Question 6 regarding Inclusion I5.
11. Other concerns: No Comments: Seattle City Light (SCL) believes that the SDT
has made substantial progress towards a clear and workable definition of the
BES. We strongly support the approach to defining the Bulk Electric System as
proposed here. SCL recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct a technical analysis
within the time available. Accordingly, SCL agrees with the approach taken by the
SDT, which is to propose a Phase II of the standards development process that
would address the generator threshold level and other issues. However, it is our
opinion that the second draft would benefit from further clarification or
modification in a number of respects, as are detailed in our comments.

Response: 1. Thank you for your support.
2. The SDT believes the existing language is clear and the proposed additional language would be redundant. No change made.
3. The SDT has reverted to specific numeric thresholds consistent with the ERO Statement of Compliance Registry Criteria for Phase
I.
4. Thank you for your support.
5. The “single point of connection of 100 kV or higher” is where the radial system will begin if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the radial
system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the transmission
line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker and a half
bus configuration could also be the beginning of the radial system and the owner of the bus would need to insure the reliability of
the substation.
6. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
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definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
7. Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is
operated in the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in
the normal operating environment. The treatment of protection systems is but one of many items to be analyzed in Phase II.
8. The wording of Exclusion E2 is essentially the same as the wording on this topic in the ERO Statement of Registry Criteria which
has been in existence for several years and is well understood in the industry. The roles of the Balancing Authority, Generator
Owner, and Generator Operator are implied in the ERO Statement of Compliance Registry Criteria and the terms were added to
Exclusion E2 as the result of industry requests for clarification.
9. Several commenters suggested that the requirement under Exclusion E3.b should apply only during normal operating conditions,
in other words, commenters felt that some power flow should be allowed to flow from the candidate local network back into the
BES as long as it only occurred under abnormal conditions. To this suggestion, the SDT considered the addition of the phrase
“under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined that in order to maintain the intent of a
bright-line characteristic in the BES definition such a qualifier could not be accommodated. However, the SDT pointed out that for
those circumstances where a candidate for local network is unable to utilize the local network exclusion due to an abnormal
situation that caused power to flow out of the network, the network could be a suitable candidate that could apply for exclusion
under the Exception Process.
10. See response in #6 above.
11. Thank you for your support.
Long T Duong

Snohomish
County PUD
No. 1

1

Affirmative

The Public Utility District No. 1 of Snohomish County (“SNPD”) believes the SDT
continues to make substantial progress towards a clear and workable definition of
the Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. SNPD therefore strongly supports the
new definition, although our support is conditioned on: (1) a workable Exceptions
process being developed in conjunction with the BES definition; and,

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(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date.
Below are SNPD’s responses to the NERC comment form for the 2nd Draft of
Definition of BES (Project 2010-17). SNPD believes the refinements below will
clarify the current draft of the BES definition, without changing the current intent.
1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments.
Comments: SNPD strongly supports the following elements of the revised BES
definition: (1) Clarification of how lists of Inclusions and Exclusions applies: The
revised core definition moves the phrase “Unless modified by the lists shown
below” to the beginning of the definition. This change makes clear that the
Inclusions and Exclusions apply to all Elements that would otherwise be included
in or excluded from the core definition (i.e., “all Transmission Elements operated
at 100 kV or higher and Real Time and Reactive Power resources connected at
100 kV or higher”) and eliminates a latent ambiguity in the first draft of the
definition, discussed further in our comments on the first draft.
(2) The exclusion for Local Distribution Facilities. As the starting point for the BES
definition, SNPD supports use of the phrase “all Transmission Elements” and the
qualifying sentence: “This does not include facilities used in the local distribution
of electric energy.” This language helps ensure that FERC, NERC, and the
Regional Entities (“REs”) will act within the jurisdictional constrains Congress
placed in Section 215 of the Federal Power Act (“FPA”). In Section 215(a)(1),
Congress unequivocally excluded “facilities used in the local distribution of electric
energy” from the keystone “bulk-power system” definition. 16 U.S.C. §
824o(a)(1). Including the same language in the definition helps ensure that
entities involved in enforcement of reliability standards will act within their
statutory limits. In addition, as a practical matter, inclusion of the language will

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help focus both the industry and responsible agencies on the high-voltage
interstate transmission system, where the reliability problems Congress intended
to regulate - “instability, uncontrolled separation, [and] cascading failures,” 16
U.S.C. § 824o(a)(4) - will originate. At the same time, level-of-service issues
arising in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16 U.S.C.
§ 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). For similar reasons, Snohomish believes use of the
phrase “Transmission Elements” as the starting point for the base definition is
desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used, and the term “Transmission” makes clear that the
BES includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power.
(3) Appropriate Generator Thresholds. In the standards development process, it
has become apparent that the thresholds for classifying generators as BES in the
current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for
individual generators, 75 MVA for multiple generators aggregated at a single site),
which predate the adoption of FPA Section 215, were never the product of a
careful analysis to determine whether generators of that size are necessary for
operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development
process. Snohomish recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct such an analysis
within the time available. Accordingly, Snohomish agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold issue and several other technical
issues that have arisen during the current process. As long as Phase II proceeds
expeditiously, Snohomish is prepared to support the BES definition as proposed
by the SDT. While Snohomish strongly supports the overall approach adopted by
the SDT and much of the specific language incorporated into the second draft of
the BES definition, we believe the second draft would benefit from further
clarification or modification in a number of respects, most of which are detailed in

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our subsequent answers. Our support for the definition is not contingent upon
these changes being adopted.
Further, we believe a workable Exclusion Process is essential for a BES Definition
that will meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection.
As detailed in our previous comments, Snohomish believes a 200-kV threshold
would be more appropriate for WECC than a 100-kV threshold. In addition, a 200kV threshold for the West is backed by solid technical analysis conducted by the
WECC Bulk Electric System Definition Task Force, and repeated claims that there
is no technical analysis to support this view is therefore incorrect. That being said,
we raise the issue here to emphasize the importance of the Exclusions for Local
Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western
Interconnection because the core definition will be over-inclusive in our region. As
long as those Exclusions and the Exceptions Process are retained in a form
substantially equivalent to those produced by the SDT at this juncture,
Snohomish will support the SDT’s proposal and will not further pursue its claims
regarding the 200-kV threshold.
Finally, we suggest that the SDT language address the circumstance when a
facility is covered by both an Inclusion and an Exclusion. We note that some of
the inclusions already contain language addressing this question. For example,
Inclusion 1 indicates that transformers falling within the specified parameters are
part of the BES “. . . unless excluded under Exclusions E1 or E3.” Where it is not
already included, similar language should be included in the other Inclusions
and/or Exclusions to explain whether the SDT intends the Inclusions or the
Exclusions to predominate in situations where facilities might be covered by both.
We suggest clarifying language in our comments to I1 and I4 below. 2. The SDT
has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1 (transformers)? If you do not support
this change or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments.
Comments: We support the SDT’s changes to the first Inclusion because it is

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more clear and simple than the initial approach. That being said, we suggest that
an additional sentence o

William T
Moojen

Snohomish
County PUD
No. 1

6

Affirmative

The Public Utility District No. 1 of Snohomish County (“SNPD”) believes the SDT
continues to make substantial progress towards a clear and workable definition of
the Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. SNPD therefore strongly supports the
new definition, although our support is conditioned on: (1) a workable Exceptions
process being developed in conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date. Below are SNPD’s
responses to the NERC comment form for the 2nd Draft of Definition of BES
(Project 2010-17). SNPD believes the refinements below will clarify the current
draft of the BES definition, without changing the current intent.
1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments.
Comments: SNPD strongly supports the following elements of the revised BES
definition:
(1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the
beginning of the definition. This change makes clear that the Inclusions and
Exclusions apply to all Elements that would otherwise be included in or excluded
from the core definition (i.e., “all Transmission Elements operated at 100 kV or
higher and Real Time and Reactive Power resources connected at 100 kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition,
discussed further in our comments on the first draft.
(2) The exclusion for Local Distribution Facilities. As the starting point for the BES
definition, SNPD supports use of the phrase “all Transmission Elements” and the
qualifying sentence: “This does not include facilities used in the local distribution

Project 2010-17 BES Definition Ballot Comments
9
1

Voter

Entity

Segment

Vote

Comment
of electric energy.” This language helps ensure that FERC, NERC, and the
Regional Entities (“REs”) will act within the jurisdictional constrains Congress
placed in Section 215 of the Federal Power Act (“FPA”). In Section 215(a)(1),
Congress unequivocally excluded “facilities used in the local distribution of electric
energy” from the keystone “bulk-power system” definition. 16 U.S.C. §
824o(a)(1). Including the same language in the definition helps ensure that
entities involved in enforcement of reliability standards will act within their
statutory limits. In addition, as a practical matter, inclusion of the language will
help focus both the industry and responsible agencies on the high-voltage
interstate transmission system, where the reliability problems Congress intended
to regulate - “instability, uncontrolled separation, [and] cascading failures,” 16
U.S.C. § 824o(a)(4) - will originate. At the same time, level-of-service issues
arising in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16 U.S.C.
§ 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). For similar reasons, Snohomish believes use of the
phrase “Transmission Elements” as the starting point for the base definition is
desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used, and the term “Transmission” makes clear that the
BES includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power.
(3) Appropriate Generator Thresholds. In the standards development process, it
has become apparent that the thresholds for classifying generators as BES in the
current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for
individual generators, 75 MVA for multiple generators aggregated at a single site),
which predate the adoption of FPA Section 215, were never the product of a
careful analysis to determine whether generators of that size are necessary for
operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development
process. Snohomish recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct such an analysis
within the time available. Accordingly, Snohomish agrees with the approach taken

Project 2010-17 BES Definition Ballot Comments
9
2

Voter

Entity

Segment

Vote

Comment
by the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold issue and several other technical
issues that have arisen during the current process. As long as Phase II proceeds
expeditiously, Snohomish is prepared to support the BES definition as proposed
by the SDT. While Snohomish strongly supports the overall approach adopted by
the SDT and much of the specific language incorporated into the second draft of
the BES definition, we believe the second draft would benefit from further
clarification or modification in a number of respects, most of which are detailed in
our subsequent answers. Our support for the definition is not contingent upon
these changes being adopted. Further, we believe a workable Exclusion Process is
essential for a BES Definition that will meet the legal requirements of FPA Section
215, especially for systems operating in the Western Interconnection. As detailed
in our previous comments, Snohomish believes a 200-kV threshold would be
more appropriate for WECC than a 100-kV threshold. In addition, a 200-kV
threshold for the West is backed by solid technical analysis conducted by the
WECC Bulk Electric System Definition Task Force, and repeated claims that there
is no technical analysis to support this view is therefore incorrect. That being said,
we raise the issue here to emphasize the importance of the Exclusions for Local
Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western
Interconnection because the core definition will be over-inclusive in our region. As
long as those Exclusions and the Exceptions Process are retained in a form
substantially equivalent to those produced by the SDT at this juncture,
Snohomish will support the SDT’s proposal and will not further pursue its claims
regarding the 200-kV threshold.
Finally, we suggest that the SDT language address the circumstance when a
facility is covered by both an Inclusion and an Exclusion. We note that some of
the inclusions already contain language addressing this question. For example,
Inclusion 1 indicates that transformers falling within the specified parameters are
part of the BES “. . . unless excluded under Exclusions E1 or E3.” Where it is not
already included, similar language should be included in the other Inclusions
and/or Exclusions to explain whether the SDT intends the Inclusions or the

Project 2010-17 BES Definition Ballot Comments
9
3

Voter

Sam Nietfeld

Entity

Snohomish
County PUD
No. 1

Segment

5

Vote

Affirmative

Comment
Exclusions to predominate in situations where facilities might be covered by both.
We suggest clarifying language in our comments to I1 and I4 below. 2. The SDT
has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1 (transformers)? If you do not support
this change or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments.
Comments: We support the SDT’s changes to the first Inclusion because it is
more clear and simple than the initial approach. That being said, we suggest that
an additional sentence o
The Public Utility District No. 1 of Snohomish County (“SNPD”) believes the SDT
continues to make substantial progress towards a clear and workable definition of
the Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. SNPD therefore strongly supports the
new definition, although our support is conditioned on: (1) a workable Exceptions
process being developed in conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date. Below are SNPD’s
responses to the NERC comment form for the 2nd Draft of Definition of BES
(Project 2010-17). SNPD believes the refinements below will clarify the current
draft of the BES definition, without changing the current intent.
1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments.
Comments: SNPD strongly supports the following elements of the revised BES
definition:
(1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the
beginning of the definition. This change makes clear that the Inclusions and
Exclusions apply to all Elements that would otherwise be included in or excluded

Project 2010-17 BES Definition Ballot Comments
9
4

Voter

Entity

Segment

Vote

Comment
from the core definition (i.e., “all Transmission Elements operated at 100 kV or
higher and Real Time and Reactive Power resources connected at 100 kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition,
discussed further in our comments on the first draft.
(2) The exclusion for Local Distribution Facilities. As the starting point for the BES
definition, SNPD supports use of the phrase “all Transmission Elements” and the
qualifying sentence: “This does not include facilities used in the local distribution
of electric energy.” This language helps ensure that FERC, NERC, and the
Regional Entities (“REs”) will act within the jurisdictional constrains Congress
placed in Section 215 of the Federal Power Act (“FPA”). In Section 215(a)(1),
Congress unequivocally excluded “facilities used in the local distribution of electric
energy” from the keystone “bulk-power system” definition. 16 U.S.C. §
824o(a)(1). Including the same language in the definition helps ensure that
entities involved in enforcement of reliability standards will act within their
statutory limits. In addition, as a practical matter, inclusion of the language will
help focus both the industry and responsible agencies on the high-voltage
interstate transmission system, where the reliability problems Congress intended
to regulate - “instability, uncontrolled separation, [and] cascading failures,” 16
U.S.C. § 824o(a)(4) - will originate. At the same time, level-of-service issues
arising in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16 U.S.C.
§ 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). For similar reasons, Snohomish believes use of the
phrase “Transmission Elements” as the starting point for the base definition is
desirable because both “Transmission” and “Elements” are already defined in the
NERC Glossary of Terms Used, and the term “Transmission” makes clear that the
BES includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power.
(3) Appropriate Generator Thresholds. In the standards development process, it
has become apparent that the thresholds for classifying generators as BES in the
current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for
individual generators, 75 MVA for multiple generators aggregated at a single site),

Project 2010-17 BES Definition Ballot Comments
9
5

Voter

Entity

Segment

Vote

Comment
which predate the adoption of FPA Section 215, were never the product of a
careful analysis to determine whether generators of that size are necessary for
operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development
process. Snohomish recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct such an analysis
within the time available. Accordingly, Snohomish agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold issue and several other technical
issues that have arisen during the current process. As long as Phase II proceeds
expeditiously, Snohomish is prepared to support the BES definition as proposed
by the SDT. While Snohomish strongly supports the overall approach adopted by
the SDT and much of the specific language incorporated into the second draft of
the BES definition, we believe the second draft would benefit from further
clarification or modification in a number of respects, most of which are detailed in
our subsequent answers. Our support for the definition is not contingent upon
these changes being adopted. Further, we believe a workable Exclusion Process is
essential for a BES Definition that will meet the legal requirements of FPA Section
215, especially for systems operating in the Western Interconnection. As detailed
in our previous comments, Snohomish believes a 200-kV threshold would be
more appropriate for WECC than a 100-kV threshold. In addition, a 200-kV
threshold for the West is backed by solid technical analysis conducted by the
WECC Bulk Electric System Definition Task Force, and repeated claims that there
is no technical analysis to support this view is therefore incorrect. That being said,
we raise the issue here to emphasize the importance of the Exclusions for Local
Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western
Interconnection because the core definition will be over-inclusive in our region. As
long as those Exclusions and the Exceptions Process are retained in a form
substantially equivalent to those produced by the SDT at this juncture,
Snohomish will support the SDT’s proposal and will not further pursue its claims
regarding the 200-kV threshold.

Project 2010-17 BES Definition Ballot Comments
9
6

Voter

John D
Martinsen

Entity

Public Utility
District No. 1
of Snohomish
County

Segment

4

Vote

Affirmative

Comment
Finally, we suggest that the SDT language address the circumstance when a
facility is covered by both an Inclusion and an Exclusion. We note that some of
the inclusions already contain language addressing this question. For example,
Inclusion 1 indicates that transformers falling within the specified parameters are
part of the BES “. . . unless excluded under Exclusions E1 or E3.” Where it is not
already included, similar language should be included in the other Inclusions
and/or Exclusions to explain whether the SDT intends the Inclusions or the
Exclusions to predominate in situations where facilities might be covered by both.
We suggest clarifying language in our comments to I1 and I4 below. 2. The SDT
has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1 (transformers)? If you do not support
this change or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments.
Comments: We support the SDT’s changes to the first Inclusion because it is
more clear and simple than the initial approach. That being said, we suggest that
an additional sentence o
The Public Utility District No. 1 of Snohomish County (“SNPD”) believes the SDT
continues to make substantial progress towards a clear and workable definition of
the Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. SNPD therefore strongly supports the
new definition, although our support is conditioned on: (1) a workable Exceptions
process being developed in conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date. Below are SNPD’s
responses to the NERC comment form for the 2nd Draft of Definition of BES
(Project 2010-17). SNPD believes the refinements below will clarify the current
draft of the BES definition, without changing the current intent.
1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would

Project 2010-17 BES Definition Ballot Comments
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7

Voter

Entity

Segment

Vote

Comment
be more appropriate, please provide specific suggestions in your comments.
Comments: SNPD strongly supports the following elements of the revised BES
definition:
(1) Clarification of how lists of Inclusions and Exclusions applies: The revised core
definition moves the phrase “Unless modified by the lists shown below” to the
beginning of the definition. This change makes clear that the Inclusions and
Exclusions apply to all Elements that would otherwise be included in or excluded
from the core definition (i.e., “all Transmission Elements operated at 100 kV or
higher and Real Time and Reactive Power resources connected at 100 kV or
higher”) and eliminates a latent ambiguity in the first draft of the definition,
discussed further in our comments on the first draft.
(2) The exclusion for Local Distribution Facilities. As the starting point for the BES
definition, SNPD supports use of the phrase “all Transmission Elements” and the
qualifying sentence: “This does not include facilities used in the local distribution
of electric energy.” This language helps ensure that FERC, NERC, and the
Regional Entities (“REs”) will act within the jurisdictional constrains Congress
placed in Section 215 of the Federal Power Act (“FPA”). In Section 215(a)(1),
Congress unequivocally excluded “facilities used in the local distribution of electric
energy” from the keystone “bulk-power system” definition. 16 U.S.C. §
824o(a)(1). Including the same language in the definition helps ensure that
entities involved in enforcement of reliability standards will act within their
statutory limits. In addition, as a practical matter, inclusion of the language will
help focus both the industry and responsible agencies on the high-voltage
interstate transmission system, where the reliability problems Congress intended
to regulate - “instability, uncontrolled separation, [and] cascading failures,” 16
U.S.C. § 824o(a)(4) - will originate. At the same time, level-of-service issues
arising in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16 U.S.C.
§ 824o(i)(2) (reserving to state and local authorities enforcement of standards
for adequacy of service). For similar reasons, Snohomish believes use of the
phrase “Transmission Elements” as the starting point for the base definition is
desirable because both “Transmission” and “Elements” are already defined in the

Project 2010-17 BES Definition Ballot Comments
9
8

Voter

Entity

Segment

Vote

Comment
NERC Glossary of Terms Used, and the term “Transmission” makes clear that the
BES includes only Elements used in Transmission and therefore excludes
Elements used in local distribution of electric power.
(3) Appropriate Generator Thresholds. In the standards development process, it
has become apparent that the thresholds for classifying generators as BES in the
current NERC Statement of Compliance Registry Criteria (“SCRC”) (20 MVA for
individual generators, 75 MVA for multiple generators aggregated at a single site),
which predate the adoption of FPA Section 215, were never the product of a
careful analysis to determine whether generators of that size are necessary for
operation of the interconnected bulk transmission system. Ideally, such an
analysis would be conducted as part of the current standards development
process. Snohomish recognizes that, given the deadlines imposed by FERC in
Order No. 743, it will not be possible for the SDT to conduct such an analysis
within the time available. Accordingly, Snohomish agrees with the approach taken
by the SDT, which is to propose a Phase II of the standards development process
that would address the generator threshold issue and several other technical
issues that have arisen during the current process. As long as Phase II proceeds
expeditiously, Snohomish is prepared to support the BES definition as proposed
by the SDT. While Snohomish strongly supports the overall approach adopted by
the SDT and much of the specific language incorporated into the second draft of
the BES definition, we believe the second draft would benefit from further
clarification or modification in a number of respects, most of which are detailed in
our subsequent answers. Our support for the definition is not contingent upon
these changes being adopted. Further, we believe a workable Exclusion Process is
essential for a BES Definition that will meet the legal requirements of FPA Section
215, especially for systems operating in the Western Interconnection. As detailed
in our previous comments, Snohomish believes a 200-kV threshold would be
more appropriate for WECC than a 100-kV threshold. In addition, a 200-kV
threshold for the West is backed by solid technical analysis conducted by the
WECC Bulk Electric System Definition Task Force, and repeated claims that there
is no technical analysis to support this view is therefore incorrect. That being said,
we raise the issue here to emphasize the importance of the Exclusions for Local

Project 2010-17 BES Definition Ballot Comments
9
9

Voter

Entity

Segment

Vote

Comment
Networks and Radial Systems and the Exceptions process. These Exclusions and
the Exceptions are essential for a definition that works in the Western
Interconnection because the core definition will be over-inclusive in our region. As
long as those Exclusions and the Exceptions Process are retained in a form
substantially equivalent to those produced by the SDT at this juncture,
Snohomish will support the SDT’s proposal and will not further pursue its claims
regarding the 200-kV threshold.
Finally, we suggest that the SDT language address the circumstance when a
facility is covered by both an Inclusion and an Exclusion. We note that some of
the inclusions already contain language addressing this question. For example,
Inclusion 1 indicates that transformers falling within the specified parameters are
part of the BES “. . . unless excluded under Exclusions E1 or E3.” Where it is not
already included, similar language should be included in the other Inclusions
and/or Exclusions to explain whether the SDT intends the Inclusions or the
Exclusions to predominate in situations where facilities might be covered by both.
We suggest clarifying language in our comments to I1 and I4 below. 2. The SDT
has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1 (transformers)? If you do not support
this change or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments.
Comments: We support the SDT’s changes to the first Inclusion because it is
more clear and simple than the initial approach. That being said, we suggest that
an additional sentence o

Response: The SDT refers Snohomish to the individual comment responses in the definition comment form as the comments
expressed here are identical to the comments submitted by Snohomish on that form.
Thomas
Richards

Fort Pierce
Utilities
Authority

4

Affirmative

FPUA supports the exclusion of Local Networks from the BES. Such systems are
generally not “necessary for operating an interconnected electric transmission
network,” the standard in Orders 743 and 743-A. However, we have some
suggestions to clarify the proposed language for this Exclusion. We have a major
concern with the wording in E3 defining a Local Network. The requirement that
“Power flows only into the LN” fails to recognize that loop flows are inevitable in a
networked system, particularly during a contingency. It just doesn’t make sense

Project 2010-17 BES Definition Ballot Comments
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Voter

Entity

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Comment
that E3 allows flows out of the LN when exporting power that was generated
within the LN, yet de minimis loop flows are not. I am suggesting that the “Power
flows only into the LN” requirement be replaced with different criteria to allow
“minor” inadvertent transfers across the LN. Such a modification would bring E3
in line with the technical justification paper developed for this project. FPUA
supports FMPA’s suggested change: “Power flows only into the LN, that is, at
each individual connection at 100 kV or higher, the pre-contingency flow of power
is from outside the LN into the LN for all hours of the previous 2 years” to help
clarify the intent. Two years is suggested because it is the time period set out in
the draft exception application form for which an applicant should state whether
power flows through an Element to the BES.

Response: Several commenters suggested that the requirement under Exclusion E3.b should apply only during normal operating
conditions, in other words, commenters felt that some power flow should be allowed to flow from the candidate local network
back into the BES as long as it only occurred under abnormal conditions. To this suggestion, the SDT considered the addition of the
phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined that in order to maintain the intent of
a bright-line characteristic in the BES definition such a qualifier could not be accommodated. However, the SDT pointed out that
for those circumstances where a candidate for local network is unable to utilize the local network exclusion due to an abnormal
situation that caused power to flow out of the network, the network could be a suitable candidate that could apply for exclusion
under the Exception Process.
Allen Mosher

American
Public Power
Association

4

Affirmative

APPA would like to thank the Standard Drafting Team (SDT) for their work on this
standard and will continue to support approval of the current draft of the Bulk
Electric System (BES) definition to meet the FERC imposed deadline. APPA also
fully supports immediate consideration in Phase 2 of this project of the technical
issues raised by the drafting team and commenters in response to the current
draft definition.
The SDT should be applauded for addressing the issue of local distribution
facilities by placing the exclusion in the BES definition itself: “This does not
include facilities used in the local distribution of electric energy.” It is clearly
spelled out in Section 215 that local distribution facilities are not subject to
compliance with NERC standards. Including this statement in the definition
ensures consistency between NERC’s technical standards and the legal foundation

Project 2010-17 BES Definition Ballot Comments
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Entity

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Comment
upon which these standards are based. The current BES definition allows for
various interpretations which could allow for excessive compliance documentation
on facilities that are not part of the BES. The drafting team has provided
sufficient granularity through the specific inclusions and exclusions to provide
clear direction to NERC, regional entities and registered entities on the specific
subset of electric facilities that are included within (or excluded from) the BES.
APPA applauds the SDT for understanding that many utilities have unique system
configurations and there is a need to differentiate between networked and radial
systems. Allowing the exclusion for radial systems serving only load to have a
normally open switch between the BES and such a radial system provides an
important distinction. This clarifies the issue that a single radial fed system is the
same as a system with multiple feeds with normally open switches between them.
The SDT should be commended for identifying and addressing the issue of local
networks (LN). Even though these systems are built in a networked configuration,
the electric energy delivered is intended only to serve local distribution load. APPA
believes that level-of-service/quality-of-service issues arising in local distribution
systems must be left to the authority of state and local regulatory agencies and
governing bodies. Therefore local networks should be excluded from the BES.
APPA is concerned that the 20MVA & 75MVA generation threshold was not
addressed in Phase 1 of this project, but fully recognizes the difficulty in timely
completing development of the necessary technical studies and consensus
development required to include this improvement in Phase 1. For these reasons,
APPA supports the current draft BES definition and requests that the SDT move
quickly to the phase 2 process to study what generation is necessary for reliable
operation of the BES.
APPA also requests more specificity on the detailed information required to
support BES exceptions processed through the NERC Rules of Procedure drafting
process. Additional technical specificity will help ensure consistency between
regions and transparency for registered entities on the technical studies and data

Project 2010-17 BES Definition Ballot Comments
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Entity

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Comment
required to support exception requests.

Response: Thank you for your support.
Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would
like nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of
discussion and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not
achievable. If the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT
would also like to point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria
and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to
say that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with
this position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at
as a single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional
Entity plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this
places the Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be
supplied. In addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also
believes that one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the
proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent
Technical Review Panel assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s
findings become part of the exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure,
Section 7.0, provides NERC the option to remand the request to the Regional Entity with the mandate to process the exception if it
finds the Regional Entity erred in rejecting or disapproving the exception request. On the other side of this equation, one could
make an argument that the Regional Entity has no basis for what constitutes an acceptable submittal. Commenters point out that
Project 2010-17 BES Definition Ballot Comments
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Voter
Entity
Segment
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Comment
the explicit types of studies to be provided and how to interpret the information aren’t shown in the request process. The SDT
again points to the variations that will abound in the requests as negating any hard and fast rules in this regard. However, one is
not dealing with amateurs here. This is not something that hasn’t been handled before by either party and there is a great deal of
professional experience involved on both the submitter’s and the Regional Entity’s side of this equation. Having viewed the request
details, the SDT believes that both sides can quickly arrive at a resolution as to what information needs to be supplied for the
submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables
to take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions
being made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the
basic premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation
of the interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the
elements of the bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result ofa sudden disturbance, including a cyber
security incident, or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel,
the visibility of the process, and the experience gained by having this same panel review multiple requests will result in an
equitable, transparent, and consistent approach to the problem. The SDT would also point out that there are options for a
submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision
has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of
Procedure, Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception
Request or response to a question will be solely dispositive in the determination of whether an Exception Request shall be
approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of
the submittals.
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Finally, the SDT would point to the draft SAR for Phase II of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest
changes to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given
the complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase I of this
project, the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the
commenter to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in
a favorable outcome.
Greg Lange

Public Utility
District No. 2
of Grant
County

3

Affirmative

The Public Utility District No. 1 of Grant County (“GCPD”) believes the SDT
continues to make substantial progress towards a clear and workable definition of
the Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. GCPD therefore strongly supports the
new definition, although our support is conditioned on: (1) a workable Exceptions
process being developed in conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date.
GCPD strongly supports the addition of the language regarding local distribution
facilities, as it matches congressional intent to leave the regulation of these
facilities to state and local authorities.
We also support the SDT’s proposal to develop detailed guidance concerning the
point of demarcation between BES and non-BES elements in the Phase II SAR. In
this regard, we note that, while Inclusion 1 at least implicitly suggests that the
dividing line between BES and non-BES Elements should be at the transformer
where transmission-level voltages are stepped down to distribution-level voltages,
we believe further clarification of this point of demarcation between the BES and
non-BES Elements is necessary. Many different configurations of transformers and
other equipment that may lie at the juncture between the BES and non-BES
systems. If the point of demarcation is designated at the transformer without
further elaboration, many entities that own equipment on the high side of a
transformer will be swept into the BES, and thereby exposed to inappropriately

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stringent regulations and undue costs. For example, distribution-only utilities
commonly own the switches, bus and transformer protection devices on the high
side of transformers where they take delivery from their transmission provider.
Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners. As
the Phase II process moves forward, we recommend that SDT consider the
extensive work performed on the point of demarcation question by the WECC
BESDTF.
GCPD does not support The inclusion of Reactive Power devices because Reactive
Power devices produce power, they are “power producing resources” and we
therefore believe Inclusion 5 is duplicative of Inclusion 4, which addresses “power
producing devices.”
Also, there is no capacity threshold specified in Inclusion 5 for Reactive Power
devices that would be considered part of the BES. This is inconsistent with the
approach taken in the balance of the definition, where thresholds are specified for
generators and other types of power producing devices. Reactive Power devices
should be subject to the same technical analysis for inclusion or exclusion that
will cover generators in the Phase II process.
GCPD strongly supports the revised Local Networks (“LNs”) exclusion from the
BES. GCPD also supports specific refinements made to the LN exclusion by the
SDT in the current draft of the BES definition. In particular, GCPD supports the
clarification of the purposes of a LN. The current draft states that LNs connect at
multiple points to “improve the level of service to retail customer Load and not to
accommodate bulk power transfer across the interconnected system.” GCPD
supports this change in language because it reflects the fundamental purposes of
a LN and emphasizes one of the key distinctions between LNs and bulk
transmission facilities. Similarly, we suggest that the SDT re-examine the
assumptions underlying subparagraph (b), which seems to suggest that a local
distribution system cannot be classified as a Local Network if power flows out of
that system at any time, even if the amount is very small, the outward flow is
only for a few hours a year, or the outward flow occurs only in an extreme
contingency. Accordingly, we suggest that the initial clause of subparagraph (b)

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be revised to read: “Except in unusual circumstances, power flows only into the
LN.”

Response: The exception process is being worked on in parallel with the definition.
Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up.
Thank you for your support.
The development of demarcation points will be included in Phase 2 of this project. Work done at WECC and other regions will be
utilized as appropriate.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
Several commenters suggested that the requirement under Exclusion E3.b should apply only during normal operating conditions, in
other words, commenters felt that some power flow should be allowed to flow from the candidate local network back into the BES
as long as it only occurred under abnormal conditions. To this suggestion, the SDT considered the addition of the phrase “under
normal operating conditions”, as a qualifier to Exclusion E3.b, and determined that in order to maintain the intent of a bright-line
characteristic in the BES definition such a qualifier could not be accommodated. However, the SDT pointed out that for those
circumstances where a candidate for local network is unable to utilize the local network exclusion due to an abnormal situation
that caused power to flow out of the network, the network could be a suitable candidate that could apply for exclusion under the
Exception Process.

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John H Hagen

Pacific Gas and
Electric
Company

Segment
3

Vote
Affirmative

Comment
We support the overall approach with the following concerns: 1) Clarify what is
included as a Blackstart Resource and do not rely on what is defined in local or
regional restoration plans, as this will create regional variances;
2) Inclusion of generating units >20mva seems to low and

Response: 1. Blackstart Resource is a defined term that can be found in the NERC Glossary.
2. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values.
Brad Chase

Orlando
Utilities
Commission

1

Affirmative

Ballard K
Mutters

Orlando
Utilities
Commission

3

Affirmative

Orlando Utilities Commission supports the new definition, although our support is
conditioned on: (1) a workable Exceptions process being developed in
conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date. in addition, phase II
should include a clear distinction between the BES and BPS.
Orlando Utilities Commission supports the new definition, although our support is
conditioned on: (1) a workable Exceptions process being developed in
conjunction with the BES definition; and,
(2) the SDT moving forward expeditiously on Phase II of the standards
development process in accordance with the SAR recently put forward by the
SDT, which would address a number of important technical issues that have been
identified in the standards development process to date.

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Response: The exception process is being worked on in parallel with the definition.
Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up.
CJ Ingersoll

Constellation
Energy

3

Affirmative

While we support the proposed definition to satisfy the FERC Order, we also
support continued work on the threshold questions slated for "Phase II", in
particular the refinement of the generation thresholds.

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up.
Howard M.
Mott Jr.

Clay Electric
Cooperative

3

Affirmative

The Note under Exclusions: E1 - Radial Systems: should not include "...as
depicted on prints or one-line diagrams..." and should be changed. "Note - A
normally open switching device between radial systems, as depicted on prints or
one-line diagrams for example, does not affect this exclusion." I recommend the
note be changed to read: Note - A normally open switching device between radial
systems operated in a 'make-before-break' fashion does not affect this exclusion.

Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will
not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in
the normal operating environment.
Brian Fawcett

Clatskanie
People's Utility
District

3

Affirmative

1. The SDT has made clarifying changes to the core definition in response to
industry comments. Do you agree with these changes? If you do not support
these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. Yes:
Yes No: Comments: We agree with the changes. We must point out that the
overall flow, or how one proceeds through the inclusions and exclusions is not
clear. Can an item that meets an inclusion be subsequently excluded? If so, this
needs to be explicitly stated. So far, we only have the flow chart produced by the
ROP team that indicates otherwise
(http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf). This
was made evident by the question at the 9/28 webinar regarding an I5 capacitor
on an E3 local network. The questioner thought the capacitor was BES per I5, but
the answer was that it was excluded per E3. We can find no support for the

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answer given. The listing of specific exclusions within I1 (exception proves the
rule) argues for questioner’s stance that the capacitor is BES as written. Also, if
included items could subsequently be excluded, they would be no different from
any other item that met the voltage threshold of 100kV. There would be no need
for any of the inclusions if all possible outputs from the inclusion tests go to the
same exclusion test inputs.
We strongly support the addition of the language regarding local distribution
facilities, as it matches congressional intent to leave the regulation of these
facilities to state and local authorities.
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments: Clatskanie PUD strongly agrees with this
inclusion as written. It is consistent with the recent PRC-004 and PRC-005
interpretation and the NERC definition of Transmission. We believe the recent
changes to this inclusion add clarity.
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Referencing the Criteria which in turn
references the BES definition creates a circular definition. Clatskanie PUD
encourages the adoption of specific thresholds that are technically justified. We
also note that the Criteria and its revisions do not go through the standards
development process, so that thresholds may change with little warning and
without triggering an implementation plan for facilities that may be swept into the
BES as a result.
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language

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would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments: We agree with the removal of the voltage
language, since the inclusions and exclusions apply only to equipment over 100
kV.
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: X No: Comments: Clatskanie PUD agrees both with the inclusion
and with the revised language. The revised language removes the need to
provide a separate definition for “Collector System”.
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you
do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: While we agree that reactive devices of sizable
capacity connected at 100 kV or higher are needed for BES reliability, Clatskanie
PUD fails to see why this inclusion is needed as they are already captured by the
100 kV threshold. We would propose instead to eliminate this inclusion and
substitute an exclusion for smaller capacity devices. If the SDT really believes an
inclusion for reactive devices is needed, we suggest the SDT provide a technically
justified capacity limit within the inclusion. In addition we suggest also including
the phrase “...unless excluded under Exclusion E1, E2 or E4” similar to that in I1.
Please see the answer to Q1 above Q10 below.
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: Clatskanie PUD notes that a new term has
been introduced, “non-retail generation,” with no definition provided. The answer
to the question on this during the 9/28 webinar indicated that non-retail
generation was behind the retail customer’s meter. We can see no reason why

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the net-metered PV systems should count toward the aggregate limit (exceeding
the limit means no exclusion) while a non-blackstart thermal plant doesn’t (the
radial system is excluded if any amount of load is present). We have also heard
the SDT meant just the opposite of what was stated in the webinar. We ask that
a reasonable definition for non-retail be provided within the BES definition
document. We strongly agree that radial systems should be excluded and that the
presence of normally open switching devices between radial systems should not
cause them to be considered non-radial. Such a result would cause the removal
of these devices to the detriment of the local level of service. We note that the
singular “A normally open switching device” is used and suggest that an
allowance be made for the possibility of multiple devices. “Normally open
switching devices...”
8. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E2 (behind-the-meter
generation)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific
suggestions in your comments. Yes: X No: Comments:
9. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E3 (local network)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: No: X Comments: We strongly agree that local networks should
be excluded, since they act much like the radial systems excluded in E1 while
providing a higher level of service to customers. These networks should not be
discouraged in the name of reliability. We again object to the introduction of the
new confusing term “non-retail generation” with no definition provided.

Response: 1. The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES
and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100
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kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is
needed. Element as defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 –
I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks)
should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind-the-retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
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interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
2. Thank you for your support.
3. The SDT has reverted to specific numeric thresholds consistent with the ERO Statement of Compliance Registry Criteria for Phase
I.
4. Thank you for your support.
5. Thank you for your support.
6. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
7. “Non-retail generation” means that generation which is on the system (supply) side of the retail meter. Radial systems should be
assessed with all normally open (NO) switches in the open position and these NO switches will not prevent the owner or operator
from using this exclusion. The note provides an example that can be used to indicate the switch is operated in the normally open
position; however, it is the owner and operator’s responsibility to indicate how a switch is used in the normal operating
environment.
8. Thank you for your support.
9. Thank you for your support. “Non-retail generation” means that generation which is on the system (supply) side of the retail
meter.
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Voter
Gregg R Griffin

Entity
City of Green
Cove Springs

Segment
3

Vote

Comment

Affirmative

GCS appreciates the SDT’s work on this project. For the most part, GCS supports
what it believes to be the intent of the proposed language. The proposed specific
exclusion of facilities used in the local distribution of electric energy is appropriate
and consistent with Section 215 of the Federal Power Act. However, we have
suggestions to better carry out what we believe to be the SDT’s intent.
The first sentence can be read as: “... all ... Real Power and Reactive Power
resources connected at 100 kV or higher”, which is surely not what the SDT
intends. The basic problem is that Inclusions I2 and I4 do not modify the first
sentence, e.g., from a set theory perspective, the set described by the first
sentence includes the sets described in inclusions I2 and I4; hence, I2 and I4 do
not modify the first sentence. From a literal reading, this would cause any size
generator connected at 100 kV to be included, which is surely not the intent of
the SDT. For similar reasons, the core definition and Inclusion I5 now has the
effect of including all generators connected at 100 kV since a generator is a
“dynamic device ... supplying or absorbing Reactive Power”. The word
“dedicated” in I5 is not sufficient in GCS’s mind to unambiguously exclude
generators from this statement. GCS suggests the following wording to address
these issues: "Transmission Elements (not including elements used in the local
distribution of electric energy) and Real Power and Reactive Power resources as
described in the list below, unless excluded by Exclusion or Exception: a.
Transmission Elements other than transformers and reactive resources operated
at 100 kV or higher. b. Transformers with primary and secondary terminals
operated at 100 kV or higher. c. Generating resource(s) (with gross individual or
gross aggregate nameplate rating per the ERO Statement of Compliance Registry
Criteria) including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above. d. Blackstart
Resources identified in the Transmission Operator’s restoration plan. e. Dispersed
power producing resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating) utilizing a system designed primarily for aggregating
capacity, connected at a common point at a voltage of 100 kV or above, but not
including generation on the retail side of the retail meter. f. Non-generator static
or dynamic devices dedicated to supplying or absorbing more than 6 MVAr of

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Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a
transformer that is designated in bullet 2 above."
2. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I1 (transformers)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: Yes No: Comments: Please see comments to Question 1
3. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I2 (generation) including the
reference to the ERO Statement of Compliance Registry Criteria? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: yes No: Comments: Please see comments to Question 1
4. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I3 (blackstart)? If you do not
support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: Yes No: Comments: Please see comments to Question 1.
5. The SDT has revised the specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I4 (dispersed power)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: Yes No: Comments: We recommend clarifying that the dispersed
power resources covered by this inclusion do not include generators on the retail
side of the retail meter. Specifically, we recommend that the Inclusion read:
“Dispersed power producing resources with aggregate capacity greater than 75
MVA (gross aggregate nameplate rating) utilizing a system designed primarily for
aggregating capacity, connected at a common point at a voltage of 100kV or
above, but not including generation on the retail side of the retail meter.”
6. The SDT has added specific inclusions to the core definition in response to
industry comments. Do you agree with Inclusion I5 (reactive resources)? If you

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do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your
comments. Yes: No: Comments: To help clarify and to avoid inclusion of de
minimis reactive resources, we propose a size threshold of 6 MVAr consistent with
the smallest size generator included in the BES at a 0.95 power factor, which is a
common leading power factor used in Facility Connection Requirements for
generators. In other words, 6 MVAr is consistent with typically the least amount
of MVAr required to be absorbed by the smallest generator meeting the registry
criteria.
7. The SDT has revised the specific exclusions to the core definition in response
to industry comments. Do you agree with Exclusion E1 (radial system)? If you do
not support this change or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your
comments. Yes: Yes No: Comments: GCS supports the exclusion of radial systems
from the BES Definition. Such systems are generally not “necessary for operating
an interconnected electric transmission network,” the standard in Orders 743 and
743-A. We have several suggestions to clarify the proposed language for this
Exclusion. Proposed Exclusion E1 refers to “[a] group of contiguous transmission
Elements that emanates from a single point of connection of 100 kV or higher.”
We appreciate the SDT’s clarification of the point of connection requirement, but
the term “a single point of connection” should be further defined (more clearly
than just by voltage), and should be generic enough to encompass the various
bus configurations. It is not the case, for example, that each individual breaker
position in a ring bus is a separate point of connection for this purpose; in that
situation, a bus at one voltage level at one substation should be considered “a
single point of connection.” Some examples of configurations that should be
considered a single point of connection for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf,
Examples 1-6.
Although the core definition (appropriately) refers to “Transmission Elements”
(with a capital “T”), proposed Exclusion E1 refers to “transmission Elements”
(with a lowercase “t”). To avoid confusion, either “Transmission” should be

Project 2010-17 BES Definition Ballot Comments
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Voter

Entity

Segment

Vote

Comment
capitalized in both locations, or the word “transmission” should simply be deleted
from Exclusion E1, leaving a “group of contiguous Elements.” We understand that
the lack of capitalization may have been a deliberate choice by the SDT in an
attempt to avoid confusion that SDT members believe exists in the Glossary
definition.

Response: 1. – 4. The SDT refers the commenter to the first phrase of the core definition starting with “Unless modified…” which
the SDT believes handles the concern brought out here. The SDT considered your wording changes in its deliberations and refers
the commenter to the revised redline of the definition posted in response to the consideration of comments.
5. The SDT further clarifies that generating units on the customer’s side of the retail meter are not included under Inclusion I4 since
customer-side retail generation typically does not “utilize[e] a system designed primarily for aggregating capacity, connected at a
common point at a voltage of 100 kV or above.”
6. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 & 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values. No change made.
7. The “single point of connection of 100 kV or higher” is where the radial system will begin if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the radial
system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the transmission
line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker and a half
bus configuration could also be the beginning of the radial system and the owner of the bus would need to insure the reliability of
the substation. The SDT considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that retention
of this word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
Project 2010-17 BES Definition Ballot Comments
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Voter

Entity

Segment

Vote

Comment

Affirmative

Due to the movement to a phased BES definition development process and
assuming the definition is approved as proposed, there is an urgent need for
NERC to provide clear guidance to Registered Entities regarding how to proceed
with facilities and address changes to the NERC Compliance Registry registration
obligations brought in/on by the application of the new definition. The problem
stems from a likely scenario whereby the affected Registered Entities may be
faced with an Implementation Plan and an Exception Request Procedure which
must be completed prior to the completion of the Phase II definition development
process. If that is the case, many Registered Entities will be confronted with
either (1) spending large amounts of human and financial resources, not yet
acquired, to address facilities/procedures necessary to address possible new
compliance obligations only to find their efforts rendered unnecessary by the
results produced in Phase II or, (2) waiting until the results of Phase II are
provided and risking being found non-compliant and subject to substantial
penalties in the future. Neither option can be viewed as a desirable, or for that
matter, an acceptable position to be placed in.

included in the term “Element”.
Thomas C
Duffy

Central Hudson
Gas & Electric
Corp.

3

Response: Part of the implementation plan for this project is for NERC to work with regional entities on transition plans. Those
regional entities would then work with registered entities to try to avoid the situation described by the commenter.
Richard K Vine

California ISO

2

Affirmative

We support the SDT’s decision to exclude the cranking paths from the BES
definition since testing and verification of the use of facilities in the cranking path
is already covered by the appropriate EOP standards. However, we suggest
removing the entirety of Inclusion I3. This inclusion is extraneous given there is
already a designation specific for system restoration covered by an existing
standard to recognize their reliability impacts and to ensure their expected
performance. NERC Standards EOP-005-2 stipulates the requirements for testing
blackstart resource and cranking paths. This testing requirement suffices to
ensure that the facilities critical to system restoration are functional when
needed, which meets the intent of identifying their criticality to reliability.

Project 2010-17 BES Definition Ballot Comments
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Voter
Entity
Segment
Vote
Comment
Response: The SDT disagrees that Blackstart Resources should not be included in the BES Definition. The Commission directed
NERC to revise its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected
electric transmission network. The SDT interprets this to include operation under both normal and emergency conditions, which
includes situations related to black starts and system restoration. Blackstart Resources have the ability to be started without
support from the System or can be energized without connection to the remainder of the System, in order to meet a Transmission
Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated
resources of the electric system that can be isolated and then energized to deliver electric power during a restoration event are
essential to enable the startup of one or more other generating units as defined in the Transmission Operator’s restoration plan.
For these reasons, the SDT continues to include Blackstart Resources indentified in the Transmission Operator’s restoration plan as
BES elements. No change made.
James Jones

Southwest
Transmission
Cooperative,
Inc.

1

Affirmative

In general, we support the proposed definition of the BES. However, we have
identified a few concerns that warrant the SDT’s consideration. We’d prefer to see
the language from the ERO Statement of Compliance Registry Criteria repeated
within the BES Definition itself instead of referencing an outside document. As it
stands right now, the Compliance Registry Criteria needs to stay intact for Phase I
of this project. That makes the Compliance Registry Criteria reliant on the BES
Definition and vice versa. We understand that the Statement of Compliance
Registry Criteria may be reviewed/revised at the same time Phase 2 of this
project is being developed, therefore we agree with Inclusion I2 of this draft.
Blackstart Resources can actually be on the distribution system. There is still the
question of whether the distribution system would then be subjected to the
enforceable standards. If so, there would most likely be a significant cost increase
associated with tracking compliance for these distribution systems without a
commensurate increase in reliability since Blackstart Resources are rarely used.
This could very well cause entities to un-designate Blackstart Resources on
distribution systems to avoid these distribution systems from becoming part of
the BES. The same rationale that was used for eliminating cranking paths could
also be applied to Blackstart Resources.
A flowgate should not be used to limit applicability of E3. First, there is no

Project 2010-17 BES Definition Ballot Comments
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Voter

Entity

Segment

Vote

Comment
definition for what constitutes a permanent flowgate. Second, flowgates are often
created for a myriad of reasons that have nothing to do with them being
necessary to operate the BES. While section c) in E3 attempts to limit the
applicability to permanent flowgates, there is no definition for what constitutes a
permanent flowgate particularly since no flowgate is truly permanent. The NERC
Glossary of Terms definition of flowgate includes flowgates in the IDC. This is a
problem because flowgates are included in the IDC for many reasons not just
because reliability issues are identified. Flowgates could be included to simply
study the impact of schedules on a particular interface as an example. It does not
mean the interface is critical. As an example, it could be used to generate
evidence that there are no transactional impacts to support exclusion from the
BES. Furthermore, the list of flowgates in the IDC is dynamic. The master list of
IDC flowgates is updated monthly and IDC users can add temporary flowgates at
anytime. While the “permanent” adjective applied to flowgates probably limits the
applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month
and removed another. Flowgates are created for many reasons that have nothing
to do with them being necessary to operate the BES. First, flowgates are created
to manage congestion. The IDC is more of a congestion management tool than a
reliability tool. FERC recognized this in Order 693, when they directed NERC to
make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs
that have been violated. Rather, other actions such as re-dispatch must be used
in conjunction. Second, flowgates are used as a convenient point to calculate
flows to sell transmission service. The characteristics of the flowgate make it a
good proxy for estimating how much contractual use has been sold not
necessarily how much flow will actually occur. While some flowgates definitely are
created for reliability issues such as IROLs, many simply are not.
The term “non-retail generation” used in Exclusion E1 (item c) and again in E3
(item a) should be clarified (see comments for question 8 below).
The Note after item c should also be clarified to indicate that closing a normally
open switch doesn’t affect this exclusion.

Project 2010-17 BES Definition Ballot Comments
1
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Voter
Noman Lee
Williams

Entity
Sunflower
Electric Power
Corporation

Segment
1

Vote

Comment

Affirmative

In general, we support the proposed definition of the BES. However, we have
identified a few concerns that warrant the SDT’s consideration.
We’d prefer to see the language from the ERO Statement of Compliance Registry
Criteria repeated within the BES Definition itself instead of referencing an outside
document. As it stands right now, the Compliance Registry Criteria needs to stay
intact for Phase I of this project. That makes the Compliance Registry Criteria
reliant on the BES Definition and vice versa. We understand that the Statement of
Compliance Registry Criteria may be reviewed/revised at the same time Phase 2
of this project is being developed, therefore we agree with Inclusion I2 of this
draft.
Blackstart Resources can actually be on the distribution system. There is still the
question of whether the distribution system would then be subjected to the
enforceable standards. If so, there would most likely be a significant cost increase
associated with tracking compliance for these distribution systems without a
commensurate increase in reliability since Blackstart Resources are rarely used.
This could very well cause entities to un-designate Blackstart Resources on
distribution systems to avoid these distribution systems from becoming part of
the BES. The same rationale that was used for eliminating cranking paths could
also be applied to Blackstart Resources.
A flowgate should not be used to limit applicability of E3. First, there is no
definition for what constitutes a permanent flowgate. Second, flowgates are often
created for a myriad of reasons that have nothing to do with them being
necessary to operate the BES. While section c) in E3 attempts to limit the
applicability to permanent flowgates, there is no definition for what constitutes a
permanent flowgate particularly since no flowgate is truly permanent. The NERC
Glossary of Terms definition of flowgate includes flowgates in the IDC. This is a
problem because flowgates are included in the IDC for many reasons not just
because reliability issues are identified. Flowgates could be included to simply
study the impact of schedules on a particular interface as an example. It does not
mean the interface is critical. As an example, it could be used to generate
evidence that there are no transactional impacts to support exclusion from the
BES. Furthermore, the list of flowgates in the IDC is dynamic. The master list of

Project 2010-17 BES Definition Ballot Comments
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Voter

Entity

Segment

Vote

Comment
IDC flowgates is updated monthly and IDC users can add temporary flowgates at
anytime. While the “permanent” adjective applied to flowgates probably limits the
applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month
and removed another. Flowgates are created for many reasons that have nothing
to do with them being necessary to operate the BES. First, flowgates are created
to manage congestion. The IDC is more of a congestion management tool than a
reliability tool. FERC recognized this in Order 693, when they directed NERC to
make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs
that have been violated. Rather, other actions such as re-dispatch must be used
in conjunction. Second, flowgates are used as a convenient point to calculate
flows to sell transmission service. The characteristics of the flowgate make it a
good proxy for estimating how much contractual use has been sold not
necessarily how much flow will actually occur. While some flowgates definitely are
created for reliability issues such as IROLs, many simply are not.
The term “non-retail generation” used in Exclusion E1 (item c) and again in E3
(item a) should be clarified (see comments for question 8 below).
The Note after item c should also be clarified to indicate that closing a normally
open switch doesn’t affect this exclusion.

Response: The SDT has reverted to specific numeric thresholds consistent with the ERO Statement of Compliance Registry Criteria
for Phase I.
The SDT disagrees that Blackstart Resources should not be included in the BES Definition. The Commission directed NERC to revise
its BES definition to ensure that the definition encompasses all facilities necessary for operating an interconnected electric
transmission network. The SDT interprets this to include operation under both normal and emergency conditions, which includes
situations related to black starts and system restoration. Blackstart Resources have the ability to be started without support from
the System or can be energized without connection to the remainder of the System, in order to meet a Transmission Operator’s
restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The associated resources of
the electric system that can be isolated and then energized to deliver electric power during a restoration event are essential to
enable the startup of one or more other generating units as defined in the Transmission Operator’s restoration plan. For these
reasons, the SDT continues to include Blackstart Resources indentified in the Transmission Operator’s restoration plan as BES
Project 2010-17 BES Definition Ballot Comments
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Voter
Entity
Segment
Vote
Comment
elements. No change made.
The SDT believes that the language in Exclusion E3.c prohibiting “Flowgates” from qualifying for definitional exclusion is appropriate
and necessary. As a definitional exclusion characteristic, Exclusion E3.c must follow the principle of being a bright-line and easily
identifiable, and as such, the SDT feels that the definition cannot allow some types of Flowgates and disallow others. Flowgates
must continue to be a prohibiting characteristic under Exclusion E3, since these facilities are more likely to be used in the transfer
of bulk power than not. An entity who wishes to make a case for exclusion of a unique type of Flowgate facility can do so through
the exception process. The SDT believes that the continued qualifier of “permanent” associated with the term “Flowgate”
addresses the majority of the concern in this comment. No change made.
“Non-retail generation” means that generation which is on the system (supply) side of the retail meter.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is
operated in the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in
the normal operating environment.
Jerome Murray

Oregon Public
Utility
Commission

9

Affirmative

With the condition that reference is not made to the NERC Statement of
Compliance Registry Criteria (SCRC) within the BES definition. This circularity
must be eliminated. Recommended language should be: “I2 - Generating
resource(s) with a gross individual nameplate rating greater than 20 MVA or with
a gross aggregate nameplate rating greater than 75 MVA including the generator
terminals through the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above.”

Response: The SDT has reverted to specific numeric thresholds consistent with the ERO Statement of Compliance Registry Criteria
for Phase I.
Gregory S
Miller

Baltimore Gas
& Electric
Company

1

Affirmative

While BGE supports the proposed definition to satisfy the FERC Order, we also
support continued work on the threshold questions slated for "Phase II".

Response: Phase II will be starting up immediately following the filing of Phase I as the SDT resources get freed up.

Project 2010-17 BES Definition Ballot Comments
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Voter

Vote

Comment

Gainesville
Regional
Utilities
Alberta Electric
System
Operator

1

Affirmative

2

Affirmative

Benjamin
Friederichs

Big Bend
Electric
Cooperative,
Inc.

3

Affirmative

James L
Layton

Blue Ridge
Electric

3

Affirmative

GVL feels that the effort to improve this standard is heading in the right direction.
We look forward to the phase 2 segment of the process where additional clairity
can be offered. Thanks for all your hard work.
The AESO agrees with the NERC BES definition. It should be noted however that
when the AESO adopts a NERC definition in Alberta the AESO must consider the
applicability of the NERC definition in Alberta which may result in revisions to
such definition to align it with our current electric energy market framework.
I believe this definition would include those elements necessary to the reliable
operation of the BES while excluding those elements that would not have a
material impact. NERC's willingness to exclude radial 115kv transmission lines is
especially beneficial to smaller utilities like us. Their inclusion would not improve
the reliability of the BES, but would vastly increase our costs and
regulatory/reporting burdens.
The SDT has done a good job of clearly defining the BES and developing a clear
inclusion and exculsion list.

Joe Noland

City of Cheney

3

Affirmative

The City of Cheney agrees with changes made to the BES definition

Jason Fortik

Lincoln Electric
System

3

Affirmative

No comments.

Anthony
Schacher

Salem Electric

3

Affirmative

Bob C.
Thomas

Illinois
Municipal
Electric Agency

4

Affirmative

Salem Electric is encouraged to see that the standard drafting team understands
the reality that in many circumstances many small radially fed utilities have no
effect on the bulk electric system. By permitting reasonable and prudent
exceptions it will allow many of the small utilities to be able to spend our limited
time and resources on the reliability of our systems for our end users, instead of
undertaking unnecessary steps to protect a system upon which we have no
effect. The exception process is thorough but still manageable for small utilities
with limited resources. Salem Electric would like to thank the Standards Drafting
Team for their hard work and dedication in defining the Bulk Electric System.
Illinois Municipal Electric Agency (IMEA) appreciates the SDT’s diligence in
developing bright-line BES Definition language; particularly, language clarifying
the exclusion of local distribution facilities, achieving more realistic/reasonable

Luther E. Fair
Mark B
Thompson

Entity

Segment

Project 2010-17 BES Definition Ballot Comments
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25

Voter

Frank R.
McElvain

Entity

Siemens
Energy, Inc.

Segment

7

Vote

Affirmative

Comment
identification of radial systems, and recognizing the distinction of local networks.
With its Affirmative vote, IMEA supports and recommends comments submitted
by the Transmission Access Policy Study Group.
I am not completely satisfied with the arbitrary nature of the 100 kV demarcation.
I know of 60 kV systems that parallel 500 kV circuits. However, this draft
captures my concept of the Bulk Electric System pretty well.

Response: Thank you for your support.

Project 2010-17 BES Definition Ballot Comments
1
26

Consideration of Comments

Definition of the Bulk Electric System (Project 2010-17)
The Bulk Electric System Drafting Team thanks all commenters who submitted comments on the 2nd
draft of the Definition of the Bulk Electric System (Project 2010-17). These standards were posted
for a 45-day public comment period from August 26, 2011 through October 10, 2011. Stakeholders
were asked to provide feedback on the standards and associated documents through a special
electronic comment form. There were 113 sets of comments, including comments from approximately
255 different people from approximately 156 companies representing all 10 Industry Segments as
shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page:
http://www.nerc.com/filez/standards/Project2010-17_BES.html
The SDT made the following changes to the definition due to industry comments received:
• Clarified the wording in Inclusion I1 to indicate that at least one secondary terminal must be at
100 kV or higher to accommodate multiple terminal transformers.
• Removed the reference to the ERO Statement of Compliance Registry Criteria in Inclusion I2 so
that there is no chance of the registry values being changed and affecting the definition prior to
resolution of threshold values in Phase 2 of this project.
• Clarified that generators were not part of Inclusion I5 to avoid improperly pulling in small
generators.
• Clarified the language of Exclusion E2 by re-ordering the text as suggested.
• Clarified the language of Exclusion E3.b as suggested.
• Clarified the compliance obligation date of the revised definition in the Implementation Plan.
The SDT feels that it is important to remind the industry that Phase 2 of this project will begin
immediately after the conclusion of Phase 1. For consistency, the same SDT will follow through with
Phase 2.
Minority opinions expressed in this document are as follows:
• Some commenters feel that threshold values should be resolved in Phase 1. The SDT
acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the
BES definition. However, the SDT has responsibilities associated with being responsive to the
directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline
of January 25, 2012, and this has not afforded the SDT with sufficient time for the development
of strong technical justifications that would warrant a change from the current values that exist

•

•

through the application of the definition today. These and similar issues have prompted the SDT
to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all
recommendations for modifications to the technical aspects of the definition for inclusion in
Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in
conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to
the existing values.
Several commenters suggested that the requirement under Exclusion E3.b should apply only
during normal operating conditions, in other words, commenters felt that some power flow
should be allowed to flow from the candidate local network back into the BES as long as it only
occurred under abnormal conditions. The SDT considered the addition of the phrase “under
normal operating conditions”, as a qualifier to Exclusion E3.b, and determined that in order to
maintain the intent of a bright-line characteristic in the BES definition such a qualifier could not
be accommodated. However, the SDT pointed out that for those circumstances where a
candidate for local network is unable to utilize the local network exclusion due to an abnormal
situation that caused power to flow out of the network, the network could be a suitable
candidate that could apply for exclusion under the Exception Process.
Some commenters expressed the opinion that Blackstart Resources are not required for the
normal operation of the interconnected transmission system. The directive by FERC to revise
the definition of the BES has been interpreted by the SDT to include all Facilities necessary for
reliably operating the interconnected transmission system under both normal and emergency
conditions. This interpretation by the SDT includes situations related to Blackstart Resources
and system restoration. Blackstart Resources have the ability to be started without the support
of the interconnected transmission system in order to meet a Transmission Operator’s
restoration plan requirements for Real and Reactive Power capability, frequency, and voltage
control. The SDT maintains that Blackstart Resources must be included in the definition.

The SDT is recommending that this project be moved forward to the recirculation ballot stage.
There were two comments that were repeated multiple times throughout the various documents. The
first topic was about how to sort through the definition inclusions and exclusions, i.e., which takes
precedence. The SDT offers this guidance on that issue:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when
appropriately applied will identify the vast majority of BES Elements in a consistent manner that can be
applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall
demarcation point between BES and non-BES Elements. Additionally, the ‘core’ definition identifies the

2

Real Power and Reactive Power resources connected at 100 kV or higher as included in the BES. To fully
appreciate the scope of the ‘core’ definition an understanding of the term Element is needed. Element
is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices
such as a generator, transformer, circuit breaker, bus section, or transmission line. An
element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation
(generating resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are
included through the application of the ‘core’ definition. The Inclusions address transmission Elements
and Real Power and Reactive Power resources with specific criteria to provide for a consistent
determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as
non-BES Elements). The exclusion language is written to specifically identify Elements or groups of
Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the
specific criteria identified in the exclusion language. This does not include the exclusion of Real Power
and Reactive Power resources captured by Inclusions I2 – I5. The exclusion (E1) only speaks to the
transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied
in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter
(on the customer’s side) and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices
and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for
the reliable operation of the interconnected transmission network or an Element as non-BES that is
necessary for the reliable operation of the interconnected transmission network, the Rules of
Procedure exception process may be utilized on a case-by-case basis to either include or exclude an
Element.
The second item is about providing specific guidance on how the information on the exception request
form will be used in making decisions on inclusions/exclusions in the exception process. While not

3

technically part of this document which is about the definition, since the question did come up in these
comments, the SDT provides the following information:
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance
on this issue. The SDT would like nothing better than to be able to provide a simple continent-wide
resolution to this matter. However, after many hours of discussion and an initial attempt at doing so, it
has become obvious to the SDT that the simple answer that so many desire is not achievable. If the
SDT could have come up with the simple answer, it would have been supplied within the bright-line.
The SDT would also like to point out to the commenters that it directly solicited assistance in this
matter in the first posting of the criteria and received very little in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover
everything up front. There are always going to be extenuating circumstances that will influence
decisions on individual cases. One could take this statement to say that the regional discretion hasn’t
been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of
Procedure and looked at as a single package. When one looks at the rules being formulated for the
exception process, it becomes clear that the role of the Regional Entity has been drastically reduced in
the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for
completion and making a recommendation to the ERO Panel, not to make the final determination. The
Regional Entity plays no role in actually approving or rejecting the submittal. It simply acts as an
intermediary. One can counter that this places the Regional Entity in a position to effectively block a
submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes
that the visibility of the process would belie such an action by the Regional Entity and also believes that
one has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C
of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of
protection requiring an independent Technical Review Panel assessment where a Regional Entity
decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure,
Section 7.0, provides NERC the option to remand the request to the Regional Entity with the mandate
to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception
request. On the other side of this equation, one could make an argument that the Regional Entity has
no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of
studies to be provided and how to interpret the information aren’t shown in the request process. The
SDT again points to the variations that will abound in the requests as negating any hard and fast rules
in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been
handled before by either party and there is a great deal of professional experience involved on both
the submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the
SDT believes that both sides can quickly arrive at a resolution as to what information needs to be
supplied for the submittal to travel upward to the ERO Panel for adjudication.

4

Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific
guidelines for them to follow in making their decision. The SDT re-iterates the problem with providing
such hard and fast rules. There are just too many variables to take into account. Providing concrete
guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being made.
The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section
3.1 where the basic premise on evaluating an exception request must be based on whether the
Elements are necessary for the reliable operation of the interconnected transmission system. Further,
reliable operation is defined in the Rules of Procedure as operating the elements of the bulk power
system within equipment and electric system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result ofa sudden
disturbance, including a cyber security incident, or unanticipated failure of system elements. The SDT
firmly believes that the technical prowess of the ERO Panel, the visibility of the process, and the
experience gained by having this same panel review multiple requests will result in an equitable,
transparent, and consistent approach to the problem. The SDT would also point out that there are
options for a submitting entity to pursue that are outlined in the proposed ERO Rules of Procedure
changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception
request form will mandate a negative response to the request. To that item, the SDT refers
commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.2 of the proposed
Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request
shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made
in response to industry comments. The SDT believes that these clarifications will make the process
tighter and easier to follow and improve the quality of the submittals.
Finally, the SDT would point to the draft SAR for Phase 2 of this project that calls for a review of the
process after 12 months of experience. The SDT believes that this time period will allow industry to see
if the process is working correctly and to suggest changes to the process based on actual real-world
experience and not just on suppositions of what may occur in the future. Given the complexity of the
technical aspects of this problem and the filing deadline that the SDT is working under for Phase 1 of
this project, the SDT believes that it has developed a fair and equitable method of approaching this
difficult problem. The SDT asks the commenter to consider all of these facts in making your decision
and casting your ballot and hopes that these changes will result in a favorable outcome.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,

5

you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 404-446-2560 or at
herb.schrayshuen@nerc.net. In addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Reliability Standards Development Procedures: http://www.nerc.com/standards/newstandardsprocess.html.

6

Index to Questions, Comments, and Responses
1.

The SDT has made clarifying changes to the core definition in response to industry comments.
Do you agree with these changes? If you do not support these changes or you agree in general
but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments. ....................................................................................................... 20

2.

The SDT has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I1 (transformers)? If you do not support this change or
you agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ............................................................................ 77

3.

The SDT has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I2 (generation) including the reference to the ERO
Statement of Compliance Registry Criteria? If you do not support this change or you agree in
general but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments. ....................................................................................................... 97

4.

The SDT has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I3 (blackstart)? If you do not support this change or
you agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ...........................................................................139

5.

The SDT has revised the specific inclusions to the core definition in response to industry
comments. Do you agree with Inclusion I4 (dispersed power)? If you do not support this
change or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. ...............................................................158

6.

The SDT has added specific inclusions to the core definition in response to industry comments.
Do you agree with Inclusion I5 (reactive resources)? If you do not support this change or you
agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments. ........................................................................................190

7.

The SDT has revised the specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E1 (radial system)? If you do not support this change
or you agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ...........................................................................223

8.

The SDT has revised the specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E2 (behind-the-meter generation)? If you do not
support this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments. .........................................269

9.

The SDT has revised the specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E3 (local network)? If you do not support this change
or you agree in general but feel that alternative language would be more appropriate, please
provide specific suggestions in your comments. ...........................................................................289

10.

The SDT has added specific exclusions to the core definition in response to industry
comments. Do you agree with Exclusion E4 (reactive resources)? If you do not support this
change or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. ...............................................................338

7

11.

Are there any other concerns with this definition that haven’t been covered in previous
questions and comments remembering that the exception criteria are posted separately for
comment?.........................................................................................................................................358

RFC Suggested changes to definition: ...................................................................................................411
Pacificorp additional comments: ............................................................................................................413
Rochester Diagrams:. ..............................................................................................................................415

8

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Gerald Beckerle

SERC OC Standards Review Group

Additional Member Additional Organization Region Segment Selection
1.

Jeff Harrison

AECI

1, 3, 5, 6

2.

Eugend Warnecke

Ameren

1, 3

3.

Dan Roethemeyer

Dynegy

5

4.

Danny Dees

MEAG

SERC

1, 3, 5

5.

Brad Young

LGE/KU

SERC

3

6.

Marc Butts

Southern

SERC

1, 5

7.

Scott Brame

NCEMC

SERC

1, 3, 4, 5

8.

Tim Hattaway

PowerSouth

SERC

1, 5

9.

Steve McElhaney

SMEPA

SERC

1, 3, 4, 5

TVA

SERC

1, 3, 5, 6

10. Joel Wise

X

2

3

X

4

5

6

7

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

11. Dwayne Roberts

OMU

SERC

3, 5

12. Jake Miller

Dynegy

SERC

5

13. Andy Burch

EEI

SERC

5

14. Tom Burns

PJM

SERC

2

15. M. R. Castello

Alabama Power

SERC

3

16. Bob Dalrymple

TVA

SERC

1, 3, 5, 6

17. Robert Thomasson BREC

SERC

1

18. Randy Hubbert

Southern

SERC

1, 5

19. Phil Whitmer

Southern

SERC

1, 5

20. Alvis Lanton

SIPC

SERC

1

21. Jim Case

Entergy

SERC

1, 3, 6

22. Mike Hirst

Cogentrix

SERC

5

23. Gene Delk

SCEandG

SERC

1, 3, 5, 6

24. Mike Bryson

PJM

SERC

2

25. John Troha

SERC

SERC

10

2.

Group
David Taylor
No additional members listed.

NERC Staff Technical Review

3.

Northeast Power Coordinating Council

Group
Additional Member

Guy Zito

Additional Organization

2

3

4

5

6

7

8

9

10

X

Region Segment Selection

1.

Alan Adamson

New York State Reliability Council, LLC

NPCC 10

2.

Gregory Campoli

New York Independent System Operator

NPCC 2

3.

Kurtis Chong

Independent Electricity System Operator

NPCC 2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5.

Chris de Graffenried Consolidated Edison Co. of New York Inc. NPCC 1

6.

Gerry Dunbar

Northeast Power Coordinating Council

7.

Peter Yost

Consoldiated Edison Co. of New York, Inc. NPCC 3

8.

Mike Garton

Dominion Resources Services, Inc.

9.

Kathleen Goodman ISO - New England

NPCC 10
NPCC 5
NPCC 2

10. Chantel Haswell

FPL Group, Inc.

NPCC 5

11. David Kiguel

Hydro One Networks Inc.

NPCC 1

12. Michael Lombardi

Northeast Utilities

NPCC 1

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

13. Randy MacDonald

New Brunswick Power Transmission

NPCC 9

14. Bruce Metruck

New York Power Authority

NPCC 6

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

16. Robert Pellegrini

The United Illumianting Company

NPCC 1

17. Si Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

18. David Ramkalawan Ontario Power Generation, Inc.

NPCC 5

19. Saurabh Saksena

National Grid

NPCC 1

20. Michael Schiavone

National Grid

NPCC 1

21. Wayne Sipperly

New York Power Authority

NPCC 5

22. Donald Weaver

New Brunswick System Operator

NPCC 2

23. Ben Wu

Orange and Rockland Utilities

NPCC 1

4.

Charles Long

Group
Additional Member

Additional Organization

SERC Planning Standards Subcommittee

SERC

SERC

10

2. John Sullivan

Ameren Services Co.

SERC

1

3. James Manning

NC Electric Membership Corp.

SERC

1

4. Philip Kleckley

SC Electric and Gas Co.

SERC

1

5. Bob Jones

Southern Company Services

SERC

1

6. Jim Kelley

PowerSouth Energy Cooperative SERC

1

Group

Jonathan Hayes

Additional Member

X

3

4

5

6

7

8

9

10

X

Region Segment Selection

1. Pat Huntley

5.

2

Southwest Power Pool Standards Review
Team

Additional Organization

X

Region Segment Selection

1.

Gregory McAuley

Oklahoma Gas and Electric

SPP

1, 3, 5

2.

Harold Wyble

Kansas City Power and Light

SPP

1, 3, 5, 6

3.

Jamie Strickland

Oklahoma Gas and Electric

SPP

1, 3, 5

4.

Mark Wurm

Board of Public Utilities City of McPherson SPP

1, 3, 5

5.

John Allen

City Utilities of Springfield

SPP

1, 4

6.

Louis Guidry

CLECO

SPP

1, 3, 5

7.

Robert Cox

Lea County Electric

SPP

8.

Sean Simpson

Board of Public Utilities City of McPherson SPP

9.

Stephen McGie

Coffeyville

1, 3, 5

SPP

11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

10. Valerie Pinamonti

American Electric Power

SPP

11. Michael Bensky

2

3

4

5

6

7

8

9

10

1, 3, 5

SPP

12. Robert Rhodes

Southwest Power Pool

SPP

2

13. Jonathan Hayes

Southwest Power Pool

SPP

2

6.

Frank Gaffney

Group

Florida Municipal Power Agency

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Tim Beyrle

City of New Smyrna Beach FRCC

4

2. Greg Woessner

Kissimmee Utility Authority FRCC

3

3. Jim Howard

Lakeland Electric

FRCC

3

4. Lynne Mila

City of Clewiston

FRCC

3

5. Joe Stonecipher

Beaches Energy Services FRCC

1

6. Cairo Vanegas

FPUA

FRCC

4

7. Randy Hahn

Ocala Utility Services

FRCC

3

7.

Group
Steve Rueckert
No additional members listed.

WECC Staff

8.

Bonneville Power Administration

Group

Chris Higgins

Additional Member

Additional Organization
Transmission Internal Ops

WECC 1

2. Steve Larson

General Counsel

WECC 1, 3, 5, 6

3. Rebecca Berdahl

Long Term Sales and Purchases WECC 3

4. John Anasis

Technical Operations

WECC 1

5. Erika Doot

Generation Support

WECC 3, 5, 6

6. Don Watkins

System Operations

WECC 1

7. Fran Halpin

Duty Scheduling

WECC 5

8. Joe Rogers

Transfer Services

WECC 3

Group
Additional Member

Bruce Wertz
Additional Organization

X

X

X

X

Region Segment Selection

1. Lorissa Jones

9.

X

Texas RE NERC Standards Subcommittee
Region

X

Segment Selection

1.

David Baker

Bandera Electric Cooperative

ERCOT

NA

2.

Gary L. Rayborn

Wharton County Electric Cooperative ERCOT

NA

3.

Phillip Amaya

Magic Valley EC

ERCOT

NA

4.

Gary Nietsche

Fayette EC

ERCOT

NA

12

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

5.

Tim Soles

Occidental Power Services

ERCOT

NA

6.

Lee Stubblefield

City of Fredericksburg

ERCOT

NA

7.

Lowell Ogle

City of Brenham

ERCOT

NA

8.

John Ohlhausen

Medina EC

ERCOT

NA

9.

Jimmy Sikes

City of Georgetown

ERCOT

NA

10. Ron Hughes

San Patricio EC

ERCOT

NA

11. Lou White

City of San Marcos

ERCOT

NA

12. David Peterson

Central Texas EC

ERCOT

NA

13. Gerry Nunan

Karnes EC

ERCOT

NA

14. Joe Farley

City of Weatherford

ERCOT

NA

15. Flint Geagley

City of Lampasas

ERCOT

NA

16. William Bissette

City of Seguin

ERCOT

NA

17. Brian Green

Farmers EC

18. Jose Escamilla

CPS Energy

ERCOT

19. Pam Zdenek

Infigen

NA - Not Applicable NA

10.

Joe Tarantino

Group

2

3

4

5

6

7

8

9

10

NA
NA

Balancing Authority Northern California

X

Additional Member Additional Organization Region Segment Selection
1. SMUD

WECC 1, 3, 4, 5, 6

2. MID

WECC 4, 5

3. City of Redding

WECC 3, 4, 5, 6

4. City of Roseville

WECC NA

11.

Group

Additional Member

ACES Power Marketing Standards
Collaborators

Jean Nitz
Additional Organization

1. Mohan Sachdeva

Buckeye Power, Inc.

2. Susan Sosbe

Wabash Valley Power Association SERC

12.

Group

RFC

Louis Slade

X

Region Segment Selection
3, 4
3

Dominion

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Connie Lowe

RFC

5, 6

2. Mike Garton

MRO

5, 6

3. Michael Gildea

NPCC 5, 6

13

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

4. Michael Crowley

SERC

1, 3

5. Sean Iseminger

SERC

5, 6

13.

Group

David Thorne

Pepco Holdings Inc and Affiliates

2

3

X

X

X

X

X

X

4

5

6

7

8

9

10

Additional Member Additional Organization Region Segment Selection
1. Carl Kinsley

Delmarva Power and Light
Co

RFC

1, 3

14.

Group
Cynthia S. Bogorad
Transmission Access Policy Study Group
Please see www.tapsgroup.org for TAPS’ more than 40 members.
Electricity Consumers Resource Council
15.
Group
John P. Hughes
(ELCON)
No additional members listed.
16.

Group

William D Shultz

Additional Member

Additional Organization

Southern Company Generation SERC

5

Southern Company Generation SERC

5

3. Therron Wingard

Southern Company Genreation SERC

5

4. Ed Goodwin

Southern Company Generation SERC

5

17.

David Dockery or John
Group
Bussman
No additional members listed.
18.

Group
Janelle Marriott Gill
No additional members listed.
Additional Member

X

X

X

X

Region Segment Selection

2. Terry Crawley

Group

X

X

Southern Company Generation

1. Tom Higgins

19.

X

Will Smith

AECI and member GandTs, Central Electric
Power Cooperative, KAMO Power, MandA
Electric Power Cooperative, Northeast
Missouri Electric Power Cooperative, NW
Electric Power Cooperative Sho-Me Power
Electric Power Cooperative
Tri-State Generation and Transmission
Assn., Inc. Energy Management
MRO NERC Standards Review Forum (NSRF)

Additional Organization

X

X

X

X

X

X

X

Region Segment Selection

1.

Mahmood Safi

Omaha Public Utility District

MRO

1, 3, 5, 6

2.

Chuck Lawrence

American Transmission Company

MRO

1

14

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

3.

Tom Webb

Wisconsin Public Service Corporation MRO

3, 4, 5, 6

4.

Jodi Jenson

Western Aera Power Administration

MRO

1, 6

5.

Ken Goldsmith

Alliant Energy

MRO

4

6.

Alice Ireland

Xcel Energy

MRO

1, 3, 4, 6

7.

Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

8.

Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

9.

Joe DePoorter

Madison Gas and Electric

MRO

3, 4, 5, 6

10. Scott Nickels

Rochester Public Utilities

MRO

4

11. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

12. Marie Knox

Midwest ISO Inc.

MRO

2

13. Lee Kittleson

Otter Tail Power Company

MRO

1, 3, 4, 5

14. Scott Bos

Muscantine Power and Water

MRO

1, 3, 5, 6

15. Tony Eddleman

Nebraska Public Power District

MRO

1, 3, 5

16. Mike Brytowski

Great River Energy

MRO

1, 3, 5, 6

17. Richard Burt

Minnkota Power Cooperative

MRO

1, 3, 5, 6

18. Will Smith

Midwest Reliability Orgnization

MRO

10

20.

Al DiCaprio

Group

2

3

4

5

6

7

8

9

10

X

IRC Standards Review Committee

Additional Member Additional Organization Region Segment Selection
1. Steve Myers

ERCOT

ERCOT 2

2. Terry Bilke

MISO

MRO

2

3. Don Weaver

NBSO

NPCC

2

4. Mark Thompson

AESO

WECC 2

5. Greg Campoli

NYISO

NPCC

2

6. Charles Yeung

SPP

SPP

2

7. Ben Li

IESO

NPCC

2

21.

Individual

Ian Grant

Tennessee Valley Authority

X

X

X

22.

Individual

Janet Smith

Arizona Public Service Company

Individual

David Kiguel

Hydro One Networks Inc.

X
X

X

23.

X
X

24.

Individual

Mark Conner

Tri-State GandT

X

25.

Individual

Brandy A. Dunn

Western Area Power Administration

X

X
X

15

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

26.

Individual

2

3

Holland Board of Public Works

Individual
28. Individual

Katie Coleman
Sandra Shaffer

Texas Industrial Energy Consumers
PacifiCorp

29.

Individual

Heather Hunt

NESCOE

30.

Individual

Antonio Grayson

Southern Company

31.

Individual

Irion A. Sanger

Industrial Customers of Northwest Utilities

32.

Individual

Doug Hohlbaugh

FirstEnergy Corp.

X

X

33.

Individual

John Bee

Exelon

X

X

34.

Individual

Gary Carlson

Michigan Public Power Agency

35.

Individual

Richard Malloy

Idaho Falls Power

36.

Individual

Anthony Jablonski

ReliabilityFirst

37.

Individual

Colin Anderson

X

Individual

Thomas C. Duffy

Ontario Power Generation Inc.
Central Hudson Gas and Electric
Corporation

39.

Individual

Manny Robledo

City of Anaheim

X

40.

Individual

Deborah J Chance

Chevron U.S.A. Inc.

41.

Individual

Alice Ireland

X

Individual

Edwin Tso

Xcel Energy
Metropolitan Water District of Southern
California

43.

Individual

Greg Rowland

Duke Energy

X

44.

Individual

David Proebstel

Clallam County PUD No.1

Individual
46. Individual

Richard Salgo
Jerome Murray

NV Energy
Oregon Public Utility Commission Staff

47.

Individual

Mary Jo Cooper

Z Global Engineering and Energy Solutions

48.

Individual

Eric Salsbury

Consumers Energy

X
X

49.

Individual

Tracy Richardson

Springfield Utility Board

X

38.

42.

45.

5

6

7

8

9

10

X

William Bush

27.

4

X
X

X

X

X
X

X

X
X
X

X

X

X
X

X

X
X
X

X
X

X

X

X

X

X

X

X

X

X

X
X
X
X

X

16

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

50.

Individual

Kerry Wiedrich

Mission Valley Power

Individual
52. Individual

Denise M. Lietz
Chris de Graffenried

Puget Sound Energy
Consolidated Edison Co. of NY, Inc.

53.

Individual

Gail Shaw

Tillamook PUD

54.

Individual

Thad Ness

55.

Individual

56.

2

3

4

5

6

9

10

X

X

X

X

X

X

American Electric Power

X

X
X

X

X

Joe Petaski

Manitoba Hydro

X

X

X

X

Individual

Robert Ganley

Long Island Power Authority

X

57.

Individual

John A. Gray

The Dow Chemical Company

58.

Individual

Rick Hansen

Individual

Donald E. Nelson

City of St. George
Massachusetts Department of Public
Utilities

60.

Individual

David Burke

Orange and Rockland Utilities, Inc.

61.

Individual

Bud Tracy

Blachly-Lane Electric Cooperative (BLEC)

X

62.

Individual

Roger Meader

Coos-Curry Electric Cooperative (CCEC)

X

63.

Individual

Kathleen Goodman

ISO New England Inc

64.

Individual

Dave Markham

Central Electric Cooperatve (CEC)

X

65.

Individual

Dave Hagen

Clearwater Power Company (CPC)

X

66.

Individual

Eric Lee Christensen

Snohomish County PUD

X

X

67.

Individual

Roman Gillen

Consumer's Power Inc.

X

X

68.

Individual

Dave Sabala

Douglas Electric Cooperative (DEC)

X

69.

Individual

Bryan Case

Fall River Rural Electric Cooperative (FALL)

X

70.

Individual

Rick Crinklaw

Lane Electric Cooperative (LEC)

X

71.

Individual

Michael Henry

Lincoln Electric Cooperative (LEC)

72.

Individual

Jon Shelby

Northern Lights Inc. (NLI)

73.

Individual

Randy MacDonald

NBPT

74.

Individual

Ray Ellis

Okanogan County Electric Cooperative

59.

8

X
X

51.

7

X
X

X
X

X

X

X

X
X

X

X

X

X

X

X
X
X
X

17

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

7

8

9

10

(OCEC)
X

75.

Individual

Donald Jones

Texas Reliability Entity

76.

Individual

Diane Barney
Rick Paschall

New York State Dept of Public Service
Pacific Northwest Generating Cooperative
(PNGC)

Individual
79. Individual

Heber Carpenter
Marc Farmer

Raft River Rural Electric Cooperative (RAFT)
West Oregon Electric Cooperative

80.

Individual

John Seelke

PSEG Services Corp

81.

Individual

Sylvain Clermont

Hydro-Quebec TransEnergie

82.

Individual

Michael Falvo

X

Individual

John Allen

Independent Electricity System Operator
Rochester Gas and Electric and New York
State Electric and Gas

84.

Individual

Steve Eldrige

Umatilla Electric Cooperative (UEC)

X

85.

Individual

Steve Alexanderson

Central Lincoln

86.

Individual

Allan Long

Memphis Light, Gas and Water Division

87.

Individual

Shane Sweet

Harney Electric Cooperative, Inc.

X

88.

Individual

Russell Noble

Cowlitz County PUD

X

89.

Individual

Brian Evans-Mongeon

Utility Services, Inc.

90.

Individual

Martyn Turner

LCRA Transmission Services Corporation

X

91.

Individual

Saurabh Saksena

National Grid

X

X

92.

Individual

Jennifer Flandermeyer

Kansas City Power and Light Company

X

X

93.

Individual

Darryl Curtis

Oncor Electric Delivery Company LLC

X

94.

Individual

Joe Tarantino

Sacramento Municipal Utility District

X

X

Individual
96. Individual

Don Schmit
David M. Conroy

Nebraska Public Power District
Central Maine Power Company

X

X

X

97.

Individual

Kirit Shah

Ameren

X

X

98.

Individual

Guy Andrews

Georgia System Operations Corporation

X
X

77.

Individual

78.

83.

95.

X
X

X

X

X

X
X
X
X

X

X

X
X

X

X
X

X

X

X
X

X
X

X

X

X

X

X

X
X

X

18

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

99.

Individual

X

2

3

X

Scott Miller

MEAG Power

101. Individual

Paul Titus
Linda Jacobson-Quinn

Northern Wasco County PUD
Farmington Electric Utility System

102. Individual

Allen Rinard

South Houston Green Power, LLC

103. Individual

Angela P Gaines

Portland General Electric Company

X

X

104. Individual

Andrew Gallo

City of Austin dba Austin Energy

X

X

105. Individual

Martin Kaufman

ExxonMobil Research and Engineering

X

106. Individual

David Kahly

Kootenai Electric Cooperative

107. Individual

Andy Pusztai

ATC LLC

X

108. Individual

Bo Jones

Westar Energy

X

109. Individual

Mary Downey

Redding Electric Utility

110. Individual

Paul Cummings

City of Redding

111. Individual

Keith Morisette

Tacoma Power

112. Individual

Rex Roehl

Indeck Energy Services

113. Individual

Frank Cumpton

BGE

100. Individual

4

5

6

7

8

9

10

X

X
X

X

X
X

X
X

X

X

X
X
X
X

X

X

X

X

X

X
X

X

X

X

X

X
X

19

1.

The SDT has made clarifying changes to the core definition in response to industry comments. Do you agree with these
changes? If you do not support these changes or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.

Summary Consideration: After consideration of the comments below, the SDT has decided against making any changes to the draft
core definition as the changes suggested do not provide additional clarity. The SDT acknowledges and appreciates the comments and
recommendations associated with modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES
definition. However, the SDT has responsibilities associated with being responsive to the directives established in Orders No. 743 and
743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the
development of strong technical justifications that would warrant a change from the current values that exist through the application
of the definition today. These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT
to address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly
assess the threshold values and provide compelling justification for modifications to the existing values.
No changes were made to the core definition.
Organization
NERC Staff Technical Review

Yes or No

Question 1 Comment

No

The sentence, “This does not include facilities used in the local distribution
of electricity,” is a commentary or statement of objective rather than a
definition of what facilities comprise the BES. Including such information
that does not define the facilities to be included or excluded will be a source
of confusion in applying the definition. The BES definition as proposed by
the SDT may in fact include such facilities and as stated in paragraph 37 of
Order 743: “Determining where the line between “transmission” and “local
distribution” lies, which includes an inquiry into which lower voltage
“transmission” facilities are necessary to operate the interconnected
transmission system, should be part of the exemption process the ERO
develops.”If the drafting team believes that Exclusions E1 through E4 in the
20

Organization

Yes or No

Question 1 Comment
definition are sufficient to not include any facilities used in the local
distribution of electricity then those exclusions, and not the aforementioned
sentence in the “core definition,” define the facilities that are not included
(i.e., the sentence is unnecessary).

Response: The SDT discussed your comment and decided against deletion of the sentence in the core definition that refers to
facilities used in the local distribution of electricity. There were many commenters who were in favor of the inclusion of the
sentence in the core definition. Additionally, the SDT does not agree with the premise that the exclusions are fully sufficient to not
include any facilities used in the local distribution of electricity in the definition. No change made.
Southwest Power Pool Standards
Review Team

No

The last sentence of the core states that no distribution facilities will be
included, but some of these facilities could be included due to blackstart
resources. We don’t disagree with the idea of removing distribution
facilities, but would like to see some clarification or qualifier.

Westar Energy

No

The last sentence of the core part of the definition states that no distribution
facilities will be included, but we feel that some of these facilities could be
included due to also being blackstart resources. We agree with the idea of
removing distribution facilities, but would like to see some clarification or a
qualifier with regards to blackstart resources.

Response: The inclusion of Blackstart Resources in Inclusion I3 is meant to include the blackstart generators but is not meant to
include any local distribution facilities at voltage levels < 100 kV that may connect the Blackstart Resources to the BES. No change
made.
Southern Company Generation

No

We have two concerns with the changes that are proposed. First, the use
of "effective dates" and "compliance obilgations ... shall begin" in the
implementation plan of the definition change is confusing. Effective date is
usually used to indicate the mandatory and enforceable date of a new item.
Second, a radial circuit from 100kV to a generating facility with two (2) 20
MVA generators seems to meet both the inclusion criteria (I2) and the
21

Organization

Yes or No

Question 1 Comment
exculsion criteria (E1). Which criteria is dominant, inclusion or exclusion?

Response: See the responses addressing the Effective Dates and the C compliance Obligations in Question 11.
As to the second part of your question, the two generators would be included in the BES by virtue of their gross individual
nameplate ratings. However, the radial circuit itself would be excluded since the gross generation was not equal to or greater than
75 MVA.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the
vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES
and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100
kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is
needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 –
I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks)
should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
22

Organization

Yes or No

Question 1 Comment

Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion
I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or
exclude an Element.
National Grid

No

While we agree that the BES should not include facilities used in the local
distribution of energy, we feel that this is already captured in Exclusion E3.
Stating it in the core definition is confusing, and should be eliminated. We
suggest removing “This does not include facilities used in the distribution of
electric energy” from the core definition.

IRC Standards Review Committee

No

While we agree with the changes to the definition, we do not understand
the purpose of the final sentence “This does not include facilities used in the
local distribution of electric energy.” Since the issue of local (distribution)
networks is addressed under Exclusion E3, we do not see the added benefit
of the referenced text.

Response: The SDT discussed your comment and decided against deletion of the sentence in the core definition that refers to
facilities used in the local distribution of electricity. There were many commenters who were in favor of the inclusion of the
sentence in the core definition. Furthermore, Exclusion E3 does not by itself define the entire population of facilities used in the
local distribution of electricity.
Hydro One Networks Inc.

No

Although we agree with the concept and commend the SDT for developing
explicit inclusions and exclusions as part of the definition, we believe there
are several outstanding issues and concerns listed as our response to Q11
that need to be addressed by the SDT and by NERC as the ERO.

Response: Please see the detailed response to Q11.
23

Organization
Massachusetts Department of Public
Utilities

Yes or No

Question 1 Comment

No

The Massachusetts Department of Public Utilities (“MA DPU”) appreciates
the opportunity to provide comments on the second draft definition of the
Bulk Electric System (“BES”). Massachusetts is the largest state by
population and load in New England. It comprises 46% of both the region’s
population and electricity consumption. Generating plants located in
Massachusetts represent 42% of New England’s capacity and our capitol
city, Boston, is the largest load center in the region. Some of the revisions
since the last posting of the draft BES definition have improved the
proposed language. However, the MA DPU has a number of concerns
regarding both the substance of the definition and the process for
developing this standard: 1) Phased Approach. While well-intentioned,
separating the BES definition project into two separate phases is
problematic from both a procedural and substantive perspective. While we
recognize that the filing due date is rapidly approaching, the BES definition
cannot be considered in a vacuum, divorced from the concerns raised by a
number of parties in response to past postings of the BES definition. The
issues NERC has identified for consideration during the proposed “Phase 2”
are inseparable from the development of the BES definition (e.g., generation
thresholds, technical justification for the 100 kV threshold) and should be
squarely addressed before a definition is adopted and ratepayers incur costs
related to compliance with mandates that may or may not be revised
through the second phase of the project. The importance of considering
concerns before adopting a definition is heightened by the proposed twoyear implementation requirement. This short implementation period almost
guarantees that entities will commit resources shortly after adoption of the
definition to ensure compliance within the mandated period. In other
words, ratepayers will bear costs related to compliance irrespective of any
change resulting from the Phase 2 process or the exception process.
Expediency, while understandable given the filing deadline, must be
balanced against the risk that a multi-phased approach could lead to
24

Organization

Yes or No

Question 1 Comment
significant consumer costs without attendant meaningful reliability benefits.
2) Cost-Benefit Analysis. A cost impact analysis should be performed as part
of developing any reliability standard. However, the development of the
BES definition has failed to consider the cost impacts of the definition (and
its inclusions and exclusions) and has not weighed these impacts against
identified benefits that the definition would achieve. The MA DPU
supported the May 21, 2011 comments from the New England States
Committee on Electricity (“NESCOE”) on the last posting of the BES
definition. In these comments, NESCOE stated that “any new costs a revised
definition imposes - which fall ultimately on consumers - should provide
meaningful reliability benefits.” A cost-benefit analysis should be integral to
the development of a BES definition and, indeed, any reliability standard.
This analysis should include a probabilistic risk assessment examining the
likelihood of an event and the costs and risks resulting from such event,
which should be weighed against the costs of complying with the proposed
reliability measures.
3) Technical Justification. In addition to performing a cost-benefit analysis, a
technical basis must be provided to justify a proposed reliability standard.
However, the proposed BES definition does not provide a technical
justification for the 100 kV threshold, the threshold for generation
resources, or other elements of the definition. As stated above, while wellintentioned and understandable, deferring this technical justification to a
later and separate phase of the project is a flawed and potentially costly
approach. Providing a technical justification for a reliability standard is a
core function of standards development and should be addressed at the
forefront of the process rather than relegated to a separate phase largely
undertaken after a standard is filed. In Order 743, the Federal Energy
Regulatory Commission (“FERC” or “the Commission”) directed NERC to
revise the BES definition. Revision to Electric Reliability Organization
Definition of Bulk Electric System, Order No. 743A, 134 FERC ¶ 61,210
25

Organization

Yes or No

Question 1 Comment
(Mar. 17, 2011) at P 8, citing to Revision to Electric Reliability Organization
Definition of Bulk Electric System, Order No. 743, 133 FERC ¶ 61,150
(2010). The Commission stated that one way NERC could address the
technical and policy concerns FERC had identified would be to institute a
“bright-line threshold that includes all facilities operated at or above 100 kV
except defined radial facilities, and establish an exemption process and
criteria for excluding facilities [NERC] determines are not necessary for
operating the interconnected transmission network.” Id. at P 8. However,
the Commission made clear in Order 743 that NERC may propose an
alternative proposal and that the 100 kV threshold is an “initial line of
demarcation” to be refined through exclusions and exemptions. Id. at PP 8,
40. Accordingly, unless and until NERC provides a technical justification for
its approach, the Standard should use the 100 kV threshold concept in a way
that is consistent with the Commission’s guidance. Specifically, the two
criteria that bound the BES definition are (1) the statutory exclusion of
facilities used in local distribution, and (2) the requirement that the facilities
included be “necessary for reliable operation” of the interconnected
transmission system. A definition that recognizes these limits, coupled with
an efficient and transparent exception process, would appear to meet the
Commission’s expectations. For these reasons, absent a technical
justification for imposing a 100 kV threshold, the MA DPU supports the
revised core definition offered by NESCOE in comments filed on this 2nd
Draft: “All Transmission Elements operated at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher that are
necessary for the reliable operation of the interconnected transmission
network, including but not limited to the facilities listed below as Inclusions,
and excluding (1) facilities that are used in the local distribution of electric
energy, and (2) the facilities and systems listed below as Exclusions. Other
Elements may be included or excluded on a case-by-case basis through the
Rules of Procedure exception process.”
The definition of the BES is
26

Organization

Yes or No

Question 1 Comment
critical to NERC’s role as ERO and will have a significant impact on system
reliability and cost to consumers. While FERC had concerns that the existing
definitions for the bulk power system were under-inclusive, the proposed
Standard, as drafted, risks erring in the opposite direction and appears
inconsistent with the Commission’s guidance in this area.

NESCOE

No

The New England States Committee on Electricity (“NESCOE”) appreciates
the opportunity to provide comments on the revised BES definition.
NESCOE is New England’s Regional State Committee and represents the
collective views of the six New England states. Please consider this
submission to reflect the views of the States of Connecticut, Maine,
Massachusetts, New Hampshire, Rhode Island and Vermont. Some of these
states may submit separate comments in addition to this joint filing.
NESCOE does not believe that the proposed changes address our
fundamental concerns. As NESCOE pointed out in its comments on the
previous draft, the definition’s reliance on a 100 kV “bright line” threshold
may impose substantial costs on New England ratepayers without achieving
meaningful reliability benefits. NERC and the drafting team have not
provided any technical justification for imposing the 100 kV test, despite its
potential for over-inclusiveness and significant costs. NESCOE believes that
the Federal Energy Regulatory Commission (“FERC” or “the Commission”)
recognizes the need to avoid this result. As the Commission pointed out in
Order 743A, Order 743 does not mandate the application of a 100 kV
threshold, and NERC is free to propose alternatives. Unless and until NERC
provides a technical justification for its approach, the Standard should use
the 100 kV threshold concept in a way that is consistent with the
Commission’s guidance. Specifically, the Standard should make clear that
the 100 kV threshold is an “initial line of demarcation,” and not the end of
the analysis. According to Order 743A, the two criteria that bound the BES
definition are (1) the statutory exclusion of facilities used in local
27

Organization

Yes or No

Question 1 Comment
distribution, and (2) the requirement that the facilities included be
“necessary for reliable operation” of the interconnected transmission
system. A definition that recognizes these limits, coupled with an efficient
and transparent exceptions process, would meet FERC’s expectations. The
proposed definition does not meet this standard. For these reasons, absent
a technical justification for imposing a 100 kV threshold, NESCOE suggests
the following revised core definition: “All Transmission Elements operated
at 100 kV or higher and Real Power and Reactive Power resources connected
at 100 kV or higher that are necessary for the reliable operation of the
interconnected transmission network, including but not limited to the
facilities listed below as Inclusions, and excluding (1) facilities that are used
in the local distribution of electric energy, and (2) the facilities and systems
listed below as Exclusions. Other Elements may be included or excluded on
a case-by-case basis through the Rules of Procedure exception process.”
Where FERC had concerns that the existing definitions for the bulk power
system were under-inclusive, the proposed Standard risks erring in the
opposite direction. Because the definition of the BES is critical to NERC’s
role as ERO and will have a significant impact on ratepayers, NESCOE
believes the drafting team should track FERC’s guidelines as closely as
possible, or provide a specific technical justification for relying on the 100 kV
bright line threshold.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and
non-BES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT
has pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
contracting the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges the
current BES definition has varying degrees of Regional application and has resulted in different conclusions on what is currently
considered to be part of the BES. This inconsistency in the application and subsequent results were also identified by the
Commission in Orders No. 743 and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition
28

Organization

Yes or No

Question 1 Comment

coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on Regions.
Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid on
a continent-wide basis. Therefore, the SDT believes that the best opportunity to address cost concerns will be through the
development of Regional transition plans once the definition has been approved by the Commission.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that
would warrant a change from the current values that exist through the application of the definition today. These and similar issues
have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in
conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
ReliabilityFirst

No

This seems very confusing, but should be clear and easy enough for anyone
to pickup, read, understand, apply and arrive at the same conclusion. The
term local distribution needs to be either defined or have some guidance
provided on what it is intended to cover. A suggestion for defining
distribution would be that radials and local networks makeup distribution
facilities. Radials usually terminate at distribution or customer substations
and local networks are primarily used for distribution also. The Commission
granted NERC the ability to define distribution in Order 743-A, paragraphs
67-71.
It is not clear if the BES is meant to be a contiguous system or not from the
language in the revised definition. ReliabilityFirst Staff believes that the BES
should be contiguous, and therefore, any facilities needed to connect real
and reactive resources to the BES need to be included. To maintain
reliability, the BES cannot have pockets of generation that are not connected
29

Organization

Yes or No

Question 1 Comment
to the BES via BES facilities. ReliabilityFirst Staff believes that without
including the paths from BES generators in the BES, the reliable operation of
the system could be jeopardized if the paths are unavailable due to noncompliance to Reliability Standards. For example, wind farm collector
systems at voltages operated at less than 100 kV should be included in the
BES for the above reason.

Response: The SDT discussed your comment and decided against deletion of the sentence in the core definition that refers to
facilities used in the local distribution of electricity. There were many commenters who were in favor of the inclusion of the
sentence in the core definition. Additionally, the SDT does not agree that Exclusions E1 and E3 are fully sufficient to not include
any facilities used in the local distribution of electricity in the definition. No change made.
The SDT has previously stated the existing BES definition does not mandate contiguity of the BES and the proposed definition is
carrying that principle forward. Simply making a blanket statement the BES must be contiguous could have unintended
consequences. However, the BES understands the importance of the concept and has agreed to discuss contiguity issues in Phase
2 of this project.
Ontario Power Generation Inc.

No

OPG continues to question the need for the changes required (and costs
imposed) as a result of this new definition. This is particularly true in the
NPCC region where an impact based methodology is being used to
determine the set of BES elements. A very clear 100kV bright line, as
proposed in this draft, will dramatically increase the list of generation
elements that must meet reliability standards, without a corresponding
increase in wide-area reliability. OPG recommends that the work planned for
phase II, technical justification of the generation and voltage thresholds,
should be completed before implementing the new definition of BES.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
30

Organization

Yes or No

Question 1 Comment

contracting the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the
current BES definition has varying degrees of Regional application and has resulted in different conclusions on what is currently
considered to be part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission
in Orders No. 743 and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with
the inconsistency in application of the current definition there is a potential for varying degrees of impact on Regions. Without an
approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results would have
little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid on a continentwide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the development of Regional
transition plans once the definition has been approved by the Commission.
Kansas City Power and Light
Company

No

There is no established basis for the generation thresholds referenced
through the ERO Statement of Compliance Registry Criteria in Appendix 5B
and the specificity of 75 MVA in the proposed BES definition. The objectives
identified in the Phase 2 SAR for the definition of the Bulk Electric System
include establishing an engineering basis for the generation thresholds.
Phase 2 will be critical in refining and improving the Bulk Electric System
definition and bringing additional clarity to the definition.

New York State Dept of Public
Service

No

The core definition is still deficient due to a lack of technical support for
basing the BES definition on 100 kV and for lack of any cost/benefit analysis.

City of Anaheim

No

The City of Anaheim recommends either changing the E1 (b) language back
to that of the previous BES definition draft, i.e. 75 MVA or above connected
at 100 kV or above, or limit the amount of generation allowed within a
Radial Element or Local Network to 300 MVA or less, which is the amount of
uncontrolled load loss that constitutes a reportable "disturbance" pursuant
to EOP-004 and DOE Form OE-417. If DOE and NERC do not consider a 300
MW uncontrolled loss of load a reportable event, then why would the
potential loss of a 75 MVA of non-critical generator connected at 69 kV
make a Radial Element or Local Network critical to the reliability of the BES?
The current ERO Statement of Compliance Criteria does not require GO/GOP
31

Organization

Yes or No

Question 1 Comment
registration for generation connected below 100 kV as long as it's not critical
to the reliability of the BES, i.e. black start, etc., even if the amount of
generation is greater than 75 MVA. There is good reason for this because
the mere loss of 75 MVA generator would not affect the reliability of a
system as big as the Western Interconnection, at all, and a fault at say 69 kV
would have sufficient impedance not to affect the BES from an electrical
perspective.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow
the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the
threshold values and provide compelling justification for modifications to the existing values.
Consolidated Edison Co. of NY, Inc.

No

o Please clarify the phrase “facilities used in local distribution” as used in
the ‘core’ BES Definition. What is the purpose of this phrase in the BES
Definition? How does the SDT propose that an entity demonstrate that a
facility is used in local distribution?
o Does this phrase “facilities used in local distribution” establish a
jurisdictional boundary which takes precedence over all other parts of the
BES Definition and Designations?
o If this phrase does not take precedence over the remainder of the BES
Definition and Designations, i.e., perhaps only over some parts BES
Definition and Designations, or over none of the BES Definition and
Designations, then what was the drafting teams understanding of and intent
32

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Yes or No

Question 1 Comment
with regard to “facilities used in local distribution?”
o What are Entities supposed to do with respect to “facilities used in local
distribution” identified by State and Provincial regulators?
o How has NERC assured that the posted BES Definition and Designations
meet the intent of the Commission to establish an exemption process that
avoids identifying “facilities used in local distribution” as part of the BES
(¶37 and ¶39 below)? Recommendations: If “facilities used in local
distribution” are to be excluded on jurisdictional grounds, then o The last
sentence in the Core definition should be revised as follows: “This does not
include facilities used in the local distribution of electric energy, as identified
by a jurisdictional governmental authority.”
o We strongly recommend that the BES SDT adopt the FERC Seven Factor
test as a proven basis for establishing the boundary between jurisdictional
Transmission and non-jurisdictional “facilities used in local distribution.”
Supporting Discussion: In FERC Order 743-A the Commission stated69. We
agree ... that the Seven Factor Test could be relevant and possibly is a logical
starting point for determining which facilities are local distribution for
reliability purposes” By adopting this FERC Seven Factor test, the BES SDT
will have fulfilled its obligation to respond to these FERC mandates relating
to “local distribution” as stated in FERC Order 743: “Determining where the
line between ‘transmission’ and ‘local distribution’ lies,” (¶37),”To the
extent that any individual line would be considered to be local distribution,
that line would not be considered part of the bulk electric system” (¶39),
to establish “[A] means to track and review facilities that are classified as
local distribution to ensure accuracy and consistent application of the
definition” (¶119).Supporting References: FERC Order 743 observed some
believe that “the Commission’s [and by extension NERC’s] proposal exceeds
its jurisdiction by encompassing local distribution facilities that are not
necessary for operating the interconnected transmission network.” [FERC
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Order 743, ¶27.]In this regard FERC Order 743 states: At ¶37, Congress
specifically exempted “facilities used in the local distribution of electric
energy” from the definition. ... Determining where the line between
“transmission” and “local distribution” lies, which includes an inquiry into
which lower voltage “transmission” facilities are necessary to operate the
interconnected transmission system, should be part of the exemption
process the ERO develops. And at ¶39, To the extent that any individual
line would be considered to be local distribution, that line would not be
considered part of the bulk electric system. And at ¶119, ... [W]e believe
that it would be beneficial for the ERO in maintaining a list of exempted
facilities, to consider including a means to track and review facilities that are
classified as local distribution to ensure accuracy and consistent application
of the definition. Similarly, the ERO could track exemptions for radial
facilities. [Emphasis added]Note that in ¶119 the Commission clearly
distinguishes between “radial facilities” and “local distribution” just as it
differentiates between jurisdictional radials and non-jurisdictional local
distribution facilities in footnote 82:82 As discussed further below, the
Commission uses the term “exclusion” herein when discussing facilities
expressly excluded by the statute (i.e., local distribution) and the term
“exemption” when referring to the exemption process NERC will develop for
use with facilities other than local distribution that may be exempted from
compliance with the mandatory Reliability Standards for other reasons. FERC
Order 743-A suggests:69. We agree with Consumers Energy, Portland
General and others that the Seven Factor Test could be relevant and possibly
is a logical starting point for determining which facilities are local
distribution for reliability purposes ...”

Response: The SDT discussed your comments and decided not to make changes to the core definition. The SDT included the last
sentence in the draft BES core definition as a reference to Section 215 of the Energy Power Act that excludes these facilities from
the bulk power system. In addition, FERC specifically excluded these facilities in Orders No. 743 and 743-A. By asking if this
sentence defines a jurisdictional boundary, you are asking the SDT for a legal conclusion that is beyond the scope of the project.
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The SDT expects that most of the facilities used in the local distribution of energy will be covered by the 100 kV voltage level as
well as Exclusions E1 through E4. In the event the BES definition does not provide a definitive determination on whether an
Element is classified as BES or non-BES, the Rules of Procedure Exception Process may be utilized on a case-by-case basis to either
include or exclude an Element.
While the SDT does not agree with the premise that Exclusions E1 through E4 are fully sufficient to not include any facilities used in
the local distribution of electricity in the definition, the SDT declined to use the FERC Seven Factor Test to define the dividing line
between transmission and distribution as this is not an applicable test in all areas of North America which includes the Canadian
Provinces.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that
would warrant a change from the current values that exist through the application of the definition today. These and similar issues
have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in
conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
Hydro-Quebec TransEnergie

No

The proposed revision to the definition maintaining this bright line of 100 kV
would expand significantly what is considered to be BES in HQT's case (the
amount of added facilities could be ten times more). Since the main
structure of Quebec system is included in the BES where the best norms and
standards apply, the inclusion in the BES of sub-systems at lower voltage and
including generation will not bring significant impact on the reliable
operation of the interconnected system, because of the nature of the
Quebec Interconnection.
Furthermore for HQT's system, the proposed BES definition combined with
the exception procedure are presently incompatible or at least inconsistent
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with the regulatory framework applicable in Quebec. The proposed changes
have not address this concern, neither the SDT's responses to our previous
comments last May (Q.1 and 12).We reiterate that the definition and the
exception procedure shall be determined by Quebec's regulator, the Régie
de l'Énergie du Québec, (Quebec Energy Board) which has the
responsibility to ensure that electric power transmission in Quebec is carried
out according to the reliability standards it adopts. Per se, it would be
necessary that E1 and E3 grant exclusions with much higher level of
generation. It would also be necessary to allow for several levels of
application for the Reliability Standards, in accordance with the Régie de
l’énergie du Québec approach: the Bulk Power System (BPS) as
determined using an impact-based methodology, the Main Transmission
System (MTS), and other parts of Regional System. Standards related to the
protection system (PRC-004-1 and PRC-005-1) and those related to the
design of the transmission system (TPL 001-0 to TPL-004-0) shall be
applicable to the first level, but all other reliability standards shall be applied
to the second level, the MTS. The MTS definition is somewhat different than
the Bulk Electric System definition, and it includes elements that impact the
reliability of the grid, supply-demand balance and interchanges. We argue
that it would be necessary for NERC to address the regulatory issues outside
ot the present context of the SDT and ROP team.

Response: While the SDT appreciates the differences within the North American continent, it attempted to craft a BES definition
that can be applied within the ERO footprint. It is neither within the scope of the SDT nor is it appropriate for the SDT to provide
any regulatory resolution within the definition. As previously stated in our responses, the SDT believes that Acts and Regulations
supersede the requirements of any Standard setting body. As such, we agree that NERC along with relevant Regions will have to
address these types of non-jurisdictional situations directly or explicitly through the Exception Process.
Rochester Gas and Electric and New
York State Electric and Gas

No

The second sentence, “This does not include facilities used in the local
distribution of electric energy,” is vague and not sufficiently clear for
northeast industry expert colleagues to be certain of what is “not included.”
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Question 1 Comment
This sentence seems to apply only to distribution facilities that have already
been classified based on the FERC “Seven Factor Test” in Order 888. If so,
this sentence be re-written as follows for clarity: “This does not include
facilities classified as distribution facilities.” For US entities, this classification
is clearly delineated in our annual FERC Form 1 filing.

Central Maine Power Company

No

The second sentence, “This does not include facilities used in the local
distribution of electric energy,” is vague and not sufficiently clear for
northeast industry expert colleagues to be certain of what is “not included.”
This sentence seems to apply only to distribution facilities that have already
been classified based on the FERC “Seven Factor Test” in Order 888. If so,
this sentence should be restated as follows for clarity: “This does not
include facilities classified as distribution facilities.” For US entities, this
classification is clearly delineated in our annual FERC Form 1 filing.

Response: The SDT discussed your comment and decided against revision of the sentence in the core definition that refers to
facilities used in the local distribution of electricity. There were many commenters who were in favor of the inclusion of the
sentence as written in the core definition.
South Houston Green Power, LLC

No

South Houston Green Power, LLC [SHGP], a registered generator owner in
ERCOT, submits the following comments: Cogeneration facilities, some of
which are well over 75 MW in size, are located at a number of industrial
sites owned by SHGP and its affiliates. Some of these cogeneration facilities
generate power that is distributed within the industrial site and used for
manufacturing plant operations. In some instances, excess power not
required for plant operations is delivered back into the electric transmission
grid through the tie line(s) connecting the industrial site to the grid. While
the tie lines and some of the internal lines at these industrial sites operate at
100kV or higher, they do not perform anything that resembles a
transmission function. Rather than transmit power long distances from
generation to load centers, the tie lines and internal lines perform primarily
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an end user distribution function consisting of the distribution of power
brought in from the grid or generated internally to different plants within
each industrial site. In some cases, the facilities also perform an
interconnection function to the extent they enable power from
cogeneration facilities to be delivered into the grid. The voltage of the tie
lines and internal lines at these industrial sites is dictated by the load and
basic configuration of each site. Higher voltage lines are used when
necessary to meet applicable load requirements or to reduce line losses.
That does not mean that such lines perform a transmission function. SHGP
would oppose any BES definition that would by default subject either the tie
lines or the internal lines at such industrial sites to the mandatory reliability
standards applicable to Transmission Owners and Transmission Operators
when they more readily fit the Generation Owner / Generation Operator
standards. Such an expanded BES definition would subject registered
entities to substantial compliance costs and create potential exposure to
penalties, but would not likely substantially enhance the reliability of the
BES. Perhaps such costs and exposure could be justified in exceptional
circumstances, if subjecting these facilities to compliance with reliability
standards were to result in a material increase in reliability of the BES.
There is reason to believe, however, that in many cases the additional
reliability benefit would be minimal at best. The tie lines and internal lines
at industrial sites owned by SHGP and its affiliates have been operated for
years as end user distribution and interconnection facilities, and practices
and procedures have developed over the years that have enabled such
operations to achieve a high degree of reliability for such sites. Requiring
these facilities to now operate in a different manner as transmission
facilities may well result in a degradation of the reliability of the
manufacturing plants located at such sites. For example, outages would
have to be coordinated with the RTO, which may not be interested in
coordinating such outages with scheduled manufacturing plant outages. In
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light of these considerations, SHGP agrees with the proposed revisions to
the core definition, particularly the proposal to include a sentence expressly
excluding facilities used in the local distribution of electric energy, provided
it is understood that end user-owned delivery facilities located “behind-themeter” are, regardless of voltage level, by default outside the scope of this
definition.

Response: See the detailed comments on this issue in the responses to the comments on the Exception Process as well as the
Detailed Information to Support an Exception Request Form.
Indeck Energy Services

No

As acknowledged in the response to Question 12 comments on the previous
BES definition, the BES definition is expansive compared to the definition of
the BPS in the FPA Section 215. The inclusion of the limited Exclusions is an
attempt to remedy the situation. However, the Exclusions need to include a
fifth one that if, based on studies or other assessments, it can be shown that
any tranmission or generator element otherwise identified as part of the BES
is not important to the reliability of the BPS, then that element should be
excluded from the mandatory standards program. There has never been a
study to show that elements, such as a 20 MW wind farm, 60 MW merchant
generator (which operates infrequently in the depressed market) in a large
BA (eg NYISO) or a radial transmission line connecting a small generator are
important to the reliability of the BPS. They are covered by the mandatory
standards program through the registration criteria. The BES Definition is
the opportunity to permit an entity to demonstrate that an element is
unimportant to reliability of the BPS. The SDT has identified a small subset
of elements that it is willing to exclude. By their very nature, these
exclusions dim the bright line that is the stated goal of this project.
However, the SDT’s foresight seems limited in its selections. Analytical
studies are used to evaluate contingencies that could lead to the Big Three
(cascading outages, instability or voltage collapse). Such a study showing
that a transmission or generation element is bounded by the N-1 or N-2
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Question 1 Comment
contingency would exclude it from the BES definition. For example, in a BA
with a NERC definition Reportable Disturbance of approximately 400 MW
(eg NYISO), a 20 MW wind farm, 60 MW merchant generator or numerous
other smaller facilities would be bounded by larger contingencies. It would
take more than six 60 MW merchant generators with close location and
common mode failure to even be a Reportable Disturbance, much less
become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 Any facility that can be demonstrated to the Regional Entity by analytical
study or other assessment to be unimportant to the reliability of the BPS
(with periodic reports by the Regional Entity to NERC of any such
assessments).”

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow
the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values.
In the event that the BES definition does not provide a definitive determination on whether an Element is classified as BES or nonBES, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude an Element.
Snohomish County PUD
Kootenai Electric Cooperative

Yes

The Public Utility District No. 1 of Snohomish County (“SNPD”) believes the
SDT continues to make substantial progress towards a clear and workable
definition of the Bulk Electric System (“BES”) that markedly improves both
the existing definition and the SDT’s previous proposal. SNPD therefore
strongly supports the new definition, although our support is conditioned
on: (1) a workable Exceptions process being developed in conjunction with
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the BES definition; and, (2) the SDT moving forward expeditiously on Phase 2
of the standards development process in accordance with the SAR recently
put forward by the SDT, which would address a number of important
technical issues that have been identified in the standards development
process to date. SNPD strongly supports the following elements of the
revised BES definition:
(1) Clarification of how lists of Inclusions and Exclusions applies: The revised
core definition moves the phrase “Unless modified by the lists shown below”
to the beginning of the definition. This change makes clear that the
Inclusions and Exclusions apply to all Elements that would otherwise be
included in or excluded from the core definition (i.e., “all Transmission
Elements operated at 100 kV or higher and Real Time and Reactive Power
resources connected at 100 kV or higher”) and eliminates a latent ambiguity
in the first draft of the definition, discussed further in our comments on the
first draft.
(2) The exclusion for Local Distribution Facilities. As the starting point for
the BES definition, SNPD supports use of the phrase “all Transmission
Elements” and the qualifying sentence: “This does not include facilities used
in the local distribution of electric energy.” This language helps ensure that
FERC, NERC, and the Regional Entities (“REs”) will act within the
jurisdictional constrains Congress placed in Section 215 of the Federal Power
Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities
used in the local distribution of electric energy” from the keystone “bulkpower system” definition. 16 U.S.C. § 824o(a)(1). Including the same
language in the definition helps ensure that entities involved in enforcement
of reliability standards will act within their statutory limits. In addition, as a
practical matter, inclusion of the language will help focus both the industry
and responsible agencies on the high-voltage interstate transmission
system, where the reliability problems Congress intended to regulate “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. §
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Question 1 Comment
824o(a)(4) - will originate. At the same time, level-of-service issues arising
in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16
U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of
standards for adequacy of service). For similar reasons, Snohomish
believes use of the phrase “Transmission Elements” as the starting point for
the base definition is desirable because both “Transmission” and “Elements”
are already defined in the NERC Glossary of Terms Used, and the term
“Transmission” makes clear that the BES includes only Elements used in
Transmission and therefore excludes Elements used in local distribution of
electric power.
(3) Appropriate Generator Thresholds. In the standards development
process, it has become apparent that the thresholds for classifying
generators as BES in the current NERC Statement of Compliance Registry
Criteria (“SCRC”) (20 MVA for individual generators, 75 MVA for multiple
generators aggregated at a single site), which predate the adoption of FPA
Section 215, were never the product of a careful analysis to determine
whether generators of that size are necessary for operation of the
interconnected bulk transmission system. Ideally, such an analysis would be
conducted as part of the current standards development process.
Snohomish recognizes that, given the deadlines imposed by FERC in Order
No. 743, it will not be possible for the SDT to conduct such an analysis within
the time available. Accordingly, Snohomish agrees with the approach taken
by the SDT, which is to propose a Phase 2 of the standards development
process that would address the generator threshold issue and several other
technical issues that have arisen during the current process. As long as
Phase 2 proceeds expeditiously, Snohomish is prepared to support the BES
definition as proposed by the SDT. While Snohomish strongly supports the
overall approach adopted by the SDT and much of the specific language
incorporated into the second draft of the BES definition, we believe the
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Question 1 Comment
second draft would benefit from further clarification or modification in a
number of respects, most of which are detailed in our subsequent answers.
Our support for the definition is not contingent upon these changes being
adopted. Further, we believe a workable Exclusion Process is essential for a
BES Definition that will meet the legal requirements of FPA Section 215,
especially for systems operating in the Western Interconnection. As detailed
in our previous comments, Snohomish believes a 200-kV threshold would be
more appropriate for WECC than a 100-kV threshold. In addition, a 200-kV
threshold for the West is backed by solid technical analysis conducted by the
WECC Bulk Electric System Definition Task Force, and repeated claims that
there is no technical analysis to support this view is therefore incorrect.
That being said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions
process. These Exclusions and the Exceptions are essential for a definition
that works in the Western Interconnection because the core definition will
be over-inclusive in our region. As long as those Exclusions and the
Exceptions Process are retained in a form substantially equivalent to those
produced by the SDT at this juncture, Snohomish will support the SDT’s
proposal and will not further pursue its claims regarding the 200-kV
threshold.
Finally, we suggest that the SDT address the circumstance when an Element
is covered by both an Inclusion and an Exclusion. We note that some of the
inclusions already contain language addressing this question. For example,
Inclusion 1 indicates that transformers falling within the specified
parameters are part of the BES “. . . unless excluded under Exclusions E1 or
E3.” Where it is not already included, similar language should be included in
the other Inclusions and/or Exclusions to explain whether the SDT intends
the Inclusions or the Exclusions to predominate in situations where facilities
might be covered by both.

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Question 1 Comment
We suggest clarifying language in our responses to Questions 2 and 5.

Response: The exception process will be filed concurrently with the definition.
Phase 2 of this project will begin immediately following the conclusion of Phase 1 as SDT resources free up.
The goal of the SDT and the Rules of Procedure Team is to have the Exception Process begin concurrently with the implementation
of the revised BES Definition.
Please see responses to Q2 and Q5.
Metropolitan Water District of
Southern California

Yes

Metropolitan Water District of Southern California (“MWDSC”) generally
supports the core definition of the Bulk Electric System as proposed.
However, some of the proposed Inclusions and Exclusions need to be
clarified as identified in questionnaires #6 and #10 below.

Response: Please see the detailed responses in Q6 and Q11 below.
Clallam County PUD No.1
Blachly-Lane Electric Cooperative
(BLEC)
Coos-Curry Electric Cooperative
(CCEC)
Central Electric Cooperatve (CEC)
Clearwater Power Company (CPC)
Consumer's Power Inc.
Douglas Electric Cooperative (DEC)
Fall River Rural Electric Cooperative
(FALL)

Yes

The Public Utility District No. 1 of Clallam County (“CLPD”) believes the SDT
continues to make substantial progress towards a clear and workable
definition of the Bulk Electric System (“BES”) that markedly improves both
the existing definition and the SDT’s previous proposal. CLPD therefore
strongly supports the new definition, although our support is conditioned
on: (1) a workable Exceptions process being developed in conjunction with
the BES definition; and, (2) the SDT moving forward expeditiously on Phase 2
of the standards development process in accordance with the SAR recently
put forward by the SDT, which would address a number of important
technical issues that have been identified in the standards development
process to date.
CLPD strongly supports the following elements of the revised BES definition:
(1) Clarification of how lists of Inclusions and Exclusions applies: The revised
core definition moves the phrase “Unless modified by the lists shown below”
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Lane Electric Cooperative (LEC)
Lincoln Electric Cooperative (LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric Cooperative
(RAFT)
West Oregon Electric Cooperative
Umatilla Electric Cooperative (UEC)

Yes or No

Question 1 Comment
to the beginning of the definition. This change makes clear that the
Inclusions and Exclusions apply to all Elements that would otherwise be
included in or excluded from the core definition (i.e., “all Transmission
Elements operated at 100 kV or higher and Real Time and Reactive Power
resources connected at 100 kV or higher”) and eliminates a latent ambiguity
in the first draft of the definition, discussed further in our comments on the
first draft.
(2) The exclusion for Local Distribution Facilities. As the starting point for
the BES definition, CLPD supports use of the phrase “all Transmission
Elements” and the qualifying sentence: “This does not include facilities used
in the local distribution of electric energy.” This language helps ensure that
FERC, NERC, and the Regional Entities (“REs”) will act within the
jurisdictional constrains Congress placed in Section 215 of the Federal Power
Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities
used in the local distribution of electric energy” from the keystone “bulkpower system” definition. 16 U.S.C. § 824o(a)(1). Including the same
language in the definition helps ensure that entities involved in enforcement
of reliability standards will act within their statutory limits. In addition, as a
practical matter, inclusion of the language will help focus both the industry
and responsible agencies on the high-voltage interstate transmission
system, where the reliability problems Congress intended to regulate “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. §
824o(a)(4) - will originate. At the same time, level-of-service issues arising
in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16
U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of
standards for adequacy of service).For similar reasons, Clallam believes use
of the phrase “Transmission Elements” as the starting point for the base
definition is desirable because both “Transmission” and “Elements” are
already defined in the NERC Glossary of Terms Used, and the term
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Question 1 Comment
“Transmission” makes clear that the BES includes only Elements used in
Transmission and therefore excludes Elements used in local distribution of
electric power.
(3) Appropriate Generator Thresholds. In the standards development
process, it has become apparent that the thresholds for classifying
generators as BES in the current NERC Statement of Compliance Registry
Criteria (“SCRC”) (20 MVA for individual generators, 75 MVA for multiple
generators aggregated at a single site), which predate the adoption of FPA
Section 215, were never the product of a careful analysis to determine
whether generators of that size are necessary for operation of the
interconnected bulk transmission system. Ideally, such an analysis would be
conducted as part of the current standards development process. Clallam
recognizes that, given the deadlines imposed by FERC in Order No. 743, it
will not be possible for the SDT to conduct such an analysis within the time
available. Accordingly, Clallam agrees with the approach taken by the SDT,
which is to propose a Phase 2 of the standards development process that
would address the generator threshold issue and several other technical
issues that have arisen during the current process. As long as Phase 2
proceeds expeditiously, Clallam is prepared to support the BES definition as
proposed by the SDT. While Clallam strongly supports the overall approach
adopted by the SDT and much of the specific language incorporated into the
second draft of the BES definition, we believe the second draft would
benefit from further clarification or modification in a number of respects,
most of which are detailed in our subsequent answers. Our support for the
definition is not contingent upon these changes being adopted. Further, we
believe a workable Exclusion Process is essential for a BES Definition that will
meet the legal requirements of FPA Section 215, especially for systems
operating in the Western Interconnection. As detailed in our II proceeds
expeditiously, Clallam is prepared to support the BES definition as proposed
by the SDT. While Clallam strongly supports the overall approach adopted
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Question 1 Comment
by the SDT and much of the specific language incorporated into the second
draft of the BES definition, we believe the second draft would benefit from
further clarification or modification in a number of respects, most of which
are detailed in our subsequent answers. Our support for the definition is
not contingent upon these changes being adopted.
Further, we believe a workable Exclusion Process is essential for a BES
Definition that will meet the legal requirements of FPA Section 215,
especially for systems operating in the Western Interconnection. As detailed
in our previous comments, Clallam believes a 200-kV threshold would be
more appropriate for WECC than a 100-kV threshold. In addition, a 200-kV
threshold for the West is backed by solid technical analysis conducted by the
WECC Bulk Electric System Definition Task Force, and repeated claims that
there is no technical analysis to support this view is therefore incorrect.
That being said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions
process. These Exclusions and the Exceptions are essential for a definition
that works in the Western Interconnection because the core definition will
be over-inclusive in our region. As long as those Exclusions and the
Exceptions Process are retained in a form substantially equivalent to those
produced by the SDT at this juncture, Clallam will support the SDT’s proposal
and will not further pursue its claims regarding the 200-kV threshold.

Response: The exception process will be filed concurrently with the definition.
Phase 2 of this project will begin immediately following the conclusion of Phase 1 as SDT resources free up.
The goal of the SDT and the Rules of Procedure Team is to have the Exception Process begin concurrently with the implementation
of the revised BES Definition.
Michigan Public Power Agency

Yes

The Michigan Public Power Agency (MPPA) believes the SDT continues to
make substantial progress towards a clear and workable definition of the
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Question 1 Comment
Bulk Electric System (“BES”) that markedly improves both the existing
definition and the SDT’s previous proposal. MPPA therefore strongly
supports the new definition, although our support is conditioned on: (1) A
workable Exceptions process being developed in conjunction with the BES
definition; and, (2) the SDT moving forward expeditiously on Phase 2 of the
standards development process in accordance with the SAR recently put
forward by the SDT, which would address a number of important technical
issues that have been identified in the standards development process to
date.
MPPA strongly supports the following elements of the revised BES
definition: (1) Clarification of how lists of Inclusions and Exclusions applies:
The revised core definition moves the phrase “Unless modified by the lists
shown below” to the beginning of the definition. This change makes clear
that the Inclusions and Exclusions apply to all Elements that would
otherwise be included in or excluded from the core definition (i.e., “all
Transmission Elements operated at 100 kV or higher and Real Time and
Reactive Power resources connected at 100 kV or higher”).
(2) The exclusion for Local Distribution Facilities. As the starting point for
the BES definition, MPPA supports use of the phrase “all Transmission
Elements” and the qualifying sentence: “This does not include facilities used
in the local distribution of electric energy.” This language helps ensure that
FERC, NERC, and the Regional Entities (“REs”) will act within the
jurisdictional constrains Congress placed in Section 215 of the Federal Power
Act (“FPA”). In Section 215(a)(1), Congress unequivocally excluded “facilities
used in the local distribution of electric energy” from the keystone “bulkpower system” definition. 16 U.S.C. § 824o(a)(1). Including the same
language in the definition helps ensure that entities involved in enforcement
of reliability standards will act within their statutory limits. In addition, as a
practical matter, inclusion of the language will help focus both the industry
and responsible agencies on the high-voltage interstate transmission
48

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Yes or No

Question 1 Comment
system, where the reliability problems Congress intended to regulate “instability, uncontrolled separation, [and] cascading failures,” 16 U.S.C. §
824o(a)(4) - will originate. At the same time, level-of-service issues arising
in local distribution systems will be left to the authority of state and local
regulatory agencies and governing bodies, just as Congress intended. 16
U.S.C. § 824o(i)(2) (reserving to state and local authorities enforcement of
standards for adequacy of service).
MPPA also believes the use of the phrase “Transmission Elements” as the
starting point for the base definition is desirable because both
“Transmission” and “Elements” are already defined in the NERC Glossary of
Terms Used, and the term “Transmission” makes clear that the BES includes
only Elements used in Transmission and therefore excludes Elements used in
local distribution of electric power. MPPA believes this was one of the many
key elements addressed by FERC in Order No. 743 and reinforced by FERC
Order No. 743A and has been missing from the previous definition as well as
the original definition being used since Compliance efforts commenced in
June, 2007 . Because of this lack of clarity MPPA has had numerous
discussions with the region regarding all 17 of our member’s connection to
the TO/TOP in Michigan. Our discussions have resulted in defending 6 of our
members specifically from the “Bright Line definition” path while having no
tools in our tool box to substantiate our exclusion. When a small
municipality with a peak load of 12.6 MW and no generation must be
defended from a TO and/or TOP registration just because of its connection
to it’s TO/TOP the process requires needed adjustment for clarity. This was
too small to even qualify as a DP under the Statement of Compliance
Registry Criteria but must have to defend itself from a TO/TOP registration
issue.
(3) Appropriate Generator Thresholds. In the standards development
process, it has become apparent that the thresholds for classifying
generators as BES in the current NERC Statement of Compliance Registry
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Question 1 Comment
Criteria (“SCRC”) (20 MVA for individual generators, 75 MVA for multiple
generators aggregated at a single site), which predate the adoption of FPA
Section 215, were never the product of a careful analysis to determine
whether generators of that size are necessary for operation of the
interconnected bulk transmission system. Ideally, such an analysis would be
conducted as part of the current standards development process. A
member of MPPA has been involved in a registration issue and it has a 3rd
party study conducted by a nation consulting firm showing for the MISO
area, generation levels of 100 MVA and 300 MVA aggregate or above are
below the standard calculation mathematical significant impact criteria for
static and dynamic planning protocol. MPPA recognizes that, given the
deadlines imposed by FERC in Order No. 743, it will not be possible for the
SDT to conduct such an analysis within the time available. Accordingly,
MPPA agrees with the approach taken by the SDT, which is to propose a
Phase 2 of the standards development process that would address the
generator threshold issue and several other technical issues that have arisen
during the current process. As long as Phase 2 proceeds expeditiously,
MPPA is prepared to support the BES definition as proposed by the SDT.
While MPPA strongly supports the overall approach adopted by the SDT and
much of the specific language incorporated into the second draft of the BES
definition, we believe the second draft would benefit from further
clarification or modification in a number of respects, most of which are
detailed in our subsequent answers. Our support for the definition is not
contingent upon these changes being adopted. Further, we believe a
workable Exclusion Process is essential for a BES Definition that will meet
the legal requirements of FPA Section 215, especially for systems operating
in the Eastern Interconnection.
That being said, we raise the issue here to emphasize the importance of the
Exclusions for Local Networks and Radial Systems and the Exceptions
process. These Exclusions and the Exceptions are essential for a definition
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that works in the Eastern Interconnection because the core definition will be
over-inclusive in our region. As long as those Exclusions and the Exceptions
Process are retained in a form substantially equivalent to those produced by
the SDT at this juncture, MPPA will support the SDT’s proposal.
Finally, we suggest that the SDT address the circumstances when a facility is
covered by both an Inclusion and an Exclusion. We note that some of the
inclusions already contain language addressing this question. For example,
Inclusion 1 indicates that transformers falling within the specified
parameters are part of the BES “. . . unless excluded under Exclusions E1 or
E3.” Where it is not already included, similar language should be included in
the other Inclusions and/or Exclusions to explain whether the SDT intends
the Inclusions or the Exclusions to predominate in situations where facilities
might be covered by both. We suggest clarifying language in our comments
to I1 and I4 below.

Response: The exception process will be filed concurrently with the definition.
Phase 2 of this project will begin immediately following the conclusion of Phase 1 as SDT resources free up.
The goal of the SDT and the Rules of Procedure Team is to have the Exception Process begin concurrently with the implementation
of the revised BES Definition.
See the detailed response to your comments regarding Inclusion I1 and I4 in the specific questions and responses below.
FirstEnergy Corp.

Yes

However, consider changing the last sentence to read "This does not include
facilities operated at less than 100kV, unless modified below, which are are
used in the local sub-transmission and distribution of electric energy."

Response: The SDT discussed your comments and decided not to change the core definition. The BES definition does not include
facilities operated at less than 100 kV.
Industrial Customers of Northwest

Yes

The Industrial Customers of Northwest Utilities (“ICNU”) submits the
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Utilities

Yes or No

Question 1 Comment
following comments regarding the North American Electric Reliability
Corporation’s (“NERC”) proposal for defining the Bulk Electric System
(“BES”). ICNU is an incorporated, non-profit association of large end-use
electric customers in the Pacific Northwest, with offices in Portland, Oregon.
ICNU previously submitted comments in the Western Electricity
Coordinating Council’s (“WECC”) process for defining the BES. ICNU’s
members are not electric utilities, but some ICNU members own substations
that are interconnected to utility transmission systems and utility
distribution systems. In addition, in some cases, ICNU members operate
local distribution facilities behind their substations to serve their end-use
loads. In some cases, the ICNU member’s interconnection to the utilityowned transmission system or distribution system is via a utility-owned
radial line; and, in others, the ICNU member’s distribution system is looped
into the utility’s transmission system for reliability purposes. Finally, some
ICNU members have local distribution systems that include the ICNU
member’s backup generating facilities. ICNU is submitting comments,
because these facilities arguably could fall within NERC’s proposed definition
of BES. ICNU appreciates the work that NERC has done to date, and
encourages NERC to develop a rule that recognizes the unique aspects of the
Pacific Northwest transmission system and the particular needs of end-use
customers. Given the arbitrary requirements and limitations imposed by the
Federal Energy Regulatory Commission, ICNU supports NERC’s overall
approach to defining the BES. NERC has proposed a bright line rule in which
all transmission elements operated 100 kV or higher will be included in the
definition, subject to certain inclusions and exclusions. ICNU supports
NERC’s goal of excluding facilities in the local distribution of electric energy.
NERC proposes three general classes of exclusions, which includes certain
radial systems, generating units that serve all or part of retail customer’s
load, and local networks. Specifically, NERC proposes that: 1) radial systems
100 kV and higher shall be excluded if they only serve load, or only include
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certain generation resources less than 75 MVA; 2) generating units that
serve customer load on the customer meter are excluded if the net capacity
provided to the BES does not exceed 75 MVA and standby, back up and
maintenance power services are provided; 3) local networks operated less
than 300 kV that distribute power to load rather than transfer bulk power
across the interconnected system; and 4) reactive power owned and
operated by a retail customer solely for its own benefit. ICNU supports
these exclusions; however, ICNU is concerned that certain end-use retail
customer facilities that do not impact the BES may still be inappropriately
included. NERC appears to recognize this possibility and includes an
exception process to include or exclude facilities on a case-by-case basis.
ICNU urges NERC to develop this exception process, and to review the work
by WECC regarding how to structure an appropriate exception. At a
minimum, the exception process should not require end-use customers to
perform costly and complex studies, but should instead require utilities or
regional organizations that have the relevant expertise to conduct the
necessary studies to determine if a specific facility should be removed or
included in the BES.
ICNU is also concerned about the term “non-retail generation,” which does
not appear to have a corresponding definition. ICNU understands that nonretail generation is intended to apply to generation behind the retail
customer’s meter. ICNU recommends that net metered systems should not
count towards the generation limits for radial and local network systems.

Response: See the detailed comments on this issue in the responses to the comments on the Rules of Procedure Exception Process
as well as the Detailed Information to Support an Exception Request Form.
To address your second comment, the SDT declined to change the term “non-retail generation”. Non-retail generation is the
generation on the system (supply) side of the retail meter.

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PacifiCorp

Yes or No

Question 1 Comment

Yes

PacifiCorp believes the SDT continues to make substantial progress towards
a clear and workable definition of the Bulk Electric System (“BES”) that
markedly improves both the existing definition and the SDT’s previous
proposal. PacifiCorp strongly supports the new definition, conditioned on:
(1) a workable Exceptions process being developed in conjunction with the
BES definition; and,
(2) the SDT moving forward expeditiously on Phase 2 of the standards
development process in accordance with the SAR recently put forward by
the SDT.

Response: The SDT appreciates your support for the clarifying changes made to the core definition. The goal of the SDT and the
Rules of Procedure Team is to have the Exception Process begin concurrently with the implementation of the revised BES
Definition.
Phase 2 of this project will begin immediately following the conclusion of Phase 1 as SDT resources free up.
Holland Board of Public Works

Yes

Holland BPW believes that the proposed definition is an improvement to the
status quo, but requires additional work. The thresholds for classifying
generators as Bulk Electric System (BES) must be revised. There was little
technical support for proposing the current thresholds. No greater evidence
than that which was proffered for the initial thresholds should be required
to modify those standards. Four years of compliance experience and
industry feedback support increasing these thresholds. Holland BPW
supports increasing the generation thresholds from 20 MVA (individual gross
nameplate) and 75 MVA (aggregate gross nameplate) to not less than 100
MVA (individual gross nameplate) and 300 MVA (aggregate gross
nameplate). Holland BPW recognizes that the SDT and NERC have
committed to making these revisions as part of “Phase 2”, and are asking the
industry to trust that such an initiative will not succumb to work on other
initiatives. However, even if work on this initiative commences
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immediately, entities that should be removed from the Compliance Registry
face costs of compliance or the risk of non-compliance penalties even
though their facilities are not necessary for the reliable operation of the
interconnected transmission system.
That said, there are two significant improvements in the revised draft. First,
it is essential to make clear that the “Inclusions” and “Exclusions” apply only
to the first sentence of the core definition (i.e., “Transmission Elements”).
The revised definition appears to address this. By placing “Unless modified
by the lists shown below” at the beginning of the first sentence of the
definition clarifies that the lists of Inclusions and Exclusions pertain only to
“Transmission Elements” that would otherwise be included or excluded from
the core definition. The revised definition and the lists of Inclusions and
Exclusions do not and cannot be applied in a manner to pull in facilities used
in the local distribution of electric energy as BES facilities because Congress,
by statute, has already determined that such facilities are outside of NERC’s
reach, as recognized by the second sentence of the definition.
Second, Holland BPW supports the addition of the second sentence of the
core definition that states, “This does not include facilities used in the local
distribution of electric energy.” This language provides necessary
recognition to the jurisdictional limitation provided for in Section 215 of the
Federal Power Act, and as recognized by the FERC in Orders 743 and 743-A
(see, e.g., ¶¶ 58-59 in 743-A).
Finally, if the revised definition goes forward, it is imperative that the rules
of procedure providing for an exception process be adopted at the same
time.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
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deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow
the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the
threshold values and provide compelling justification for modifications to the existing values.
As for your second group of comments, the SDT appreciates your support for the clarifying changes made to the core definition.
The goal of the SDT and the Rules of Procedure Team is to have the Exception Process begin concurrently with the implementation
of the revised BES Definition.
Dominion

Yes

Dominion agrees with the clarifying changes provided that the use of the
capitalized terms “Transmission” and “Elements” mean that an Element that
is radial is not part of the BES regardless of whether it is specifically included
in the Exclusions (E1 through E4).

Response: To the extent that a radial facility that is >100 kV does not meet the exclusion criteria as specified in Exclusions E1
through E4, the Exception Process can be used to provide a final decision on whether the facility is or is not a BES Element.
Sacramento Municipal Utility District

Yes

In an effort to avoid potential confusion and provide clarity we believe the
following sentence “This does not include facilities used in the local
distribution of electric energy” more appropriately fits under the
“exclusions,” rather than “inclusions,” section.

ISO New England Inc

Yes

The second sentence is unclear with respect to its intent. If it’s intended to
cover the exclusion described in E3, the sentence is not needed. If it’s
intended to mean something else, it is unclear as to what is intended and
likely should be deleted.

Manitoba Hydro

Yes

Manitoba Hydro agrees in general with the changes made to the core
definition but the sentence ‘This does not include facilities used in the local
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Question 1 Comment
distribution of electric energy’ should be removed as it is covered under
Exclusion E3 and reduces the clarity of the core definition.

City of Austin dba Austin Energy

Yes

In an effort to avoid potential confusion and provide clarity we believe the
sentence, “This does not include facilities used in the local distribution of
electric energy,” more appropriately fits under the “exclusions” (rather
“inclusions”) section.

Balancing Authority Northern
California

Yes

In an effort to avoid potential confusion and provide clarity we believe the
following sentence “This does not include facilities used in the local
distribution of electric energy” more appropriately fits under the
“exclusions,” rather than “inclusions,” section.

Response: The SDT discussed your comment and decided against moving the sentence in the core definition that refers to facilities
used in the local distribution of electricity to the Exclusions section. There were many commenters who were in favor of the
inclusion of the sentence in the core definition.
ExxonMobil Research and
Engineering

Yes

However, in Order 743, FERC directed NERC to further delineate the
differences between transmission systems (used to transfer electric power
between regions) and distribution systems (used to deliver electric power
locally). The inclusions and exclusions defined in the draft BES definition are
a step in the right direction, but further work is necessary during Phase 2 to
meet the intention of the order.
Additionally, the SDT should consider defining terms, such as non-retail
generation, or providing references (footnotes) that elaborate on the
referenced concept.

Response: Thank you for your support of Phase 2.
Non-retail generation is the generation on the system (supply) side of the retail meter.

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Question 1 Comment

Transmission Access Policy Study
Group

Yes

TAPS appreciates the SDT’s work on this project. For the most part, TAPS
supports what it believes to be the intent of the proposed language. The
proposed specific exclusion of facilities used in the local distribution of
electric energy is appropriate and consistent with Section 215 of the Federal
Power Act. However, we have one suggestion to better carry out what we
believe to be the SDT’s intent. The SDT proposes to change the core
generation definition from the prior version’s “...Real Power resources as
described below, and Reactive Power resources connected at 100 kV or
higher unless such designation is modified by the list shown below,” to
“Unless modified by the lists shown below, ... Real Power and Reactive
Power resources connected at 100 kV or higher....” Because of this change
from “as described below... unless... modified by the list shown below” to
simply “unless modified by the lists shown below,” the proposed core
definition now has the effect of including all generation, regardless of size,
that is connected at over 100kV. We do not think this is the SDT’s intent.
For the same reason, the core definition now has the effect of including all
Reactive Power resources connected at over 100kV, including generators;
Inclusion I5, which includes “[s]tatic or dynamic devices dedicated to
supplying or absorbing Reactive Power,” does not alter the core definition’s
inclusion of all Reactive Power resources connected at over 100kV (whether
“dedicated” or not). The most straightforward solution to this problem is to
simply delete Real and Reactive Power resources from the core definition, so
that such resources are instead handled entirely in the Inclusions. The core
definition would thus read: “Unless modified by the lists shown below, all
Transmission Elements operated at 100 kV or higher. This does not include
facilities used in the local distribution of electric energy.”

Florida Municipal Power Agency

Yes

FMPA appreciates the SDT’s work on this project. For the most part, FMPA
supports what it believes to be the intent of the proposed language. The
proposed specific exclusion of facilities used in the local distribution of
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Question 1 Comment
electric energy is appropriate and consistent with Section 215 of the Federal
Power Act. However, we have suggestions to better carry out what we
believe to be the SDT’s intent. The first sentence can be read as: “... all ...
Real Power and Reactive Power resources connected at 100 kV or higher”,
which is surely not what the SDT intends. The basic problem is that
Inclusions I2 and I4 do not modify the first sentence, e.g., from a set theory
perspective, the set described by the first sentence includes the sets
described in inclusions I2 and I4; hence, I2 and I4 do not modify the first
sentence. From a literal reading, this would cause any size generator
connected at 100 kV to be included, which is surely not the intent of the
SDT.
For similar reasons, the core definition and Inclusion I5 now has the effect of
including all generators connected at 100 kV since a generator is a “dynamic
device ... supplying or absorbing Reactive Power”. The word “dedicated” in
I5 is not sufficient in FMPA’s mind to unambiguously exclude generators
from this statement.
FMPA suggests the following wording to address these issues:"Transmission
Elements (not including elements used in the local distribution of electric
energy) and Real Power and Reactive Power resources as described in the
list below, unless excluded by Exclusion or Exception: a. Transmission
Elements other than transformers and reactive resources operated at 100 kV
or higher. b. Transformers with primary and secondary terminals operated
at 100 kV or higher. c. Generating resource(s) (with gross individual or gross
aggregate nameplate rating per the ERO Statement of Compliance Registry
Criteria) including the generator terminals through the high-side of the stepup transformer(s) connected at a voltage of 100 kV or above. d. Blackstart
Resources identified in the Transmission Operator’s restoration plan. e.
Dispersed power producing resources with aggregate capacity greater than
75 MVA (gross aggregate nameplate rating) utilizing a system designed
primarily for aggregating capacity, connected at a common point at a
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Question 1 Comment
voltage of 100 kV or above, but not including generation on the retail side of
the retail meter. f. Non-generator static or dynamic devices dedicated to
supplying or absorbing more than 6 MVAr of Reactive Power that are
connected at 100 kV or higher, or through a dedicated transformer with a
high-side voltage of 100 kV or higher, or through a transformer that is
designated in bullet 2 above."

Response: The SDT discussed your comments and declined to make changes to the core definition. However, clarifying changes
were made to Inclusion I2 to specify the generation thresholds to be included in the BES. In addition, the SDT added a clarifying
phrase to Inclusion I5 to emphasize that the item is not meant to apply to generators.
MEAG Power

Yes

MEAG agrees to the clarifying changes to the core definition in general,
however, we maintain that 200kV and above is the correct bright line for the
BES.

Electricity Consumers Resource
Council (ELCON)

Yes

However, one of the FERC directives in Order 743 charged NERC with
delineating the difference between transmission and distribution. The
Inclusions and Exclusions are a step in that direction, but this subject will
need more consideration in Phase 2.

Texas RE NERC Standards
Subcommittee

Yes

However, one of the FERC directives in Order 743 charged NERC with
delineating the difference between transmission and distribution. The
Inclusions and Exclusions are a step in that direction, but this subject will
need more consideration in Phase 2.

SERC OC Standards Review Group

Yes

The SERC OC Standards Review Group agrees to the clarifying changes to the
core definition in general; however, we maintain that 200kV and above is the
correct bright line for the Bulk Electric System.

AECI and member GandTs, Central
Electric Power Cooperative, KAMO

Yes

In general, we agree with this revision. We however believe the correct
voltage thresholds to be, transformer primary voltage of 200 kV or higher and
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Power, MandA Electric Power
Cooperative, Northeast Missouri
Electric Power Cooperative, NW
Electric Power Cooperative Sho-Me
Power Electric Power Cooperative
Tennessee Valley Authority

Question 1 Comment
secondary voltage of 100 kV or higher.

Yes

TVA agrees to the clarifying changes to the core definition in general;
however, we maintain that 200kV and above is the correct bright line for the
Bulk Electric System, and requests that the Phase 2 for the project use 200kV
and above or develop a transmission voltage and/or an MVA threshold that is
technically based.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow
the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the
threshold values and provide compelling justification for modifications to the existing values. No change made.
Puget Sound Energy

Yes

This draft of the defintion is very much improved. We appreciate the work
of the Standard Development Team and its efforts to increase the clarity of
this important definition. For additional clarity, the first paragraph should
read "Unless specifically excluded under the list of exclusions below or
included or excluded through the Procedure for Requesting and Receiving an
Exception from the Application of the NERC Definition of Bulk Electric
System, all Transmission Elements operated at 100 kV or higher and Real
Power and Reactive Power resources connected at 100 kV or higher,
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Question 1 Comment
including those Transmission Elements described in the list of inclusions
below."
The sentence "This does not include facilities used in the local distribution of
electric energy." should be removed from the first paragraph. Because this
issue is specifically addressed in exclusions E1 and E3, the inclusion of this
general sentence here is unnecessary and could even be ambiguous (raising
the question of whether additional Transmission Elements might be
excluded even if not described in E1 or E2).

Response: The SDT discussed your comment and decided against deletion of the sentence in the core definition that refers to
facilities used in the local distribution of electricity. There were many commenters who were in favor of the inclusion of the
sentence in the core definition. Additionally, the SDT does not agree with the premise that the exclusions are fully sufficient to not
include any facilities used in the local distribution of electricity in the definition. No change made.
Z Global Engineering and Energy
Solutions

Yes

We support these changes however feel that further clarification needs to
be made regarding the E1 Note. This note currently states "Note - A
normally open switching device between radial systems, as depicted on
prints or one-line diagrams for example, does not affect this exclusion" This
note is not clear. We recommend that the note is rewritten to be clear that
a normally open switching device should not be viewed as normally closed
as the regions are currently doing. Possible language: "Note: A normally
open switching device between radial systems, as depicted on prints or
oneline diagrams, for example, does not classify the two or more radial lines
as a loop line. The exclusion will still apply.”}"

Response: The SDT discussed your comment and declined to make the suggested change. It is the intent of the SDT that a switch
that is marked normally open as depicted on prints or one-lines be treated as normally open when deciding whether a facility is or
is not a BES Element.
Northern Wasco County PUD

Yes

We agree with the changes. We must point out that the overall flow, or how
one proceeds through the inclusions and exclusions is not clear. Can an item
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Question 1 Comment
that meets an inclusion be subsequently excluded? If so, this needs to be
explicitly stated. So far, we only have the flow chart produced by the ROP
team that indicates otherwise
(http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf).
This was made evident by the question at the 9/28 webinar regarding an I5
capacitor on an E3 local network. The questioner thought the capacitor was
BES per I5, but the answer was that it was excluded per E3. We can find no
support for the answer given. The listing of specific exclusions within I1
(exception proves the rule) argues for questioner’s stance that the capacitor
is BES as written. Also, if included items could subsequently be excluded,
they would be no different from any other item that met the voltage
threshold of 100kV. There would be no need for any of the inclusions if all
possible outputs from the inclusion tests go to the same exclusion test
inputs. We strongly support the addition of the language regarding local
distribution facilities, as it matches congressional intent to leave the
regulation of these facilities to state and local authorities.

Harney Electric Cooperative, Inc.

Yes

HEC agrees with the changes by the SDT. Although HEC believes that there
needs to be explicit language stating whether or not an item that meets
inclusion can be overridden by an exclusion. An example of this was given
during the Webinar on 9/28 regarding a Capacitor included under I5 yet
excluded under E3 according to the NERC representative.

Central Lincoln

Yes

We agree with the changes. We must point out that the overall flow, or how
one proceeds through the inclusions and exclusions is not clear. Can an item
that meets an inclusion be subsequently excluded? If so, this needs to be
explicitly stated. So far, we only have the flow chart produced by the ROP
team that indicates otherwise
(http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf).
This was made evident by the question at the 9/28 webinar regarding an I5
capacitor on an E3 local network. The questioner thought the capacitor was
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Question 1 Comment
BES per I5, but the answer was that it was excluded per E3. We can find no
support for the answer given. The listing of specific exclusions within I1
(exception proves the rule) argues for questioner’s stance that the capacitor
is BES as written. Also, if included items could subsequently be excluded,
they would be no different from any other item that met the voltage
threshold of 100kV. There would be no need for any of the inclusions if all
possible outputs from the inclusion tests go to the same exclusion test
inputs.We strongly support the addition of the language regarding local
distribution facilities, as it matches congressional intent to leave the
regulation of these facilities to state and local authorities.

Mission Valley Power

Yes

Mission Valley Power - We agree with the changes. We must point out that
the overall flow, or how one proceeds through the inclusions and exclusions
is not clear. Can an item that meets an inclusion be subsequently excluded?
If so, this needs to be explicitly stated. So far, we only have the flow chart
produced by the ROP team that indicates otherwise
(http://www.nerc.com/docs/standards/sar/20110428_BES_Flowcharts.pdf).
This was made evident by the question at the 9/28 webinar regarding an I5
capacitor on an E3 local network. The questioner thought the capacitor was
BES per I5, but the answer was that it was excluded per E3. We can find no
support for the answer given. The listing of specific exclusions within I1
(exception proves the rule) argues for questioner’s stance that the capacitor
is BES as written. Also, if included items could subsequently be excluded,
they would be no different from any other item that met the voltage
threshold of 100kV. There would be no need for any of the inclusions if all
possible outputs from the inclusion tests go to the same exclusion test
inputs. We strongly support the addition of the language regarding local
distribution facilities, as it matches congressional intent to leave the
regulation of these facilities to state and local authorities.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
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Question 1 Comment

identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES
and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100
kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is
needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 –
I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks)
should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion
I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or
exclude an Element.
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Long Island Power Authority

Yes or No
Yes

Question 1 Comment
Need to define the term "local distribution"

Response: The SDT believes that with the last sentence in the core definition and Exclusions E1 and E3 that the term has been
sufficiently distinguished with regard to the BES. No change made.
Utility Services, Inc.

Yes

Upon reflection of the core definition and BES Inclusion Designations, Utility
Services believes that there is an unintended redundancy between the two.
Utility Services would like to suggest that the portion of the core definition
that refers to the Real and Reactive Power resources be removed from the
core and to leave the Inclusions as is.

Response: The SDT discussed your comment and decided against making a change to the core definition. However, a new
parenthetical was added in Inclusion I5 to clarify that the item is meant to exclude generators.
Cowlitz County PUD

Yes

Cowlitz County PUD No. 1 (Cowlitz) commends the SDT for the simplified
concise core definition. However, Cowlitz believes that only Real and
Reactive Power resources necessary for the support of the BES should be
included. Therefore, Cowlitz suggests the core definition or the Inclusions
section state this. This will allow basis for demonstrating resource Elements
should be excluded from the BES through the Rules of Procedure exception
process. This is not to say that owners of non-BES resource Elements should
not be registered, as such entities may still have an obligation to contribute
BES Reliability functions. Cowlitz votes affirmative and believes the above
concern can be addressed in Phase 2.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
66

Organization

Yes or No

Question 1 Comment

industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow
the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the
threshold values and provide compelling justification for modifications to the existing values.
Ameren

Yes

a)The general concept is sound, but the Inclusion and Exclusion sections
create so many circular references it is virtually impossible to take a
definitive stance on whether an asset is included or excluded to the BES
definition. Please revise the inclusion and exclusion criteria to give
pinpointed statements that are final and do not reference other criteria, that
then again reference other criteria.
b)We believe that 200kV and above is the appropriate bright line for the
Bulk Electric System.
c)In I5, only those Reactive Power devices applied for the purpose of BES
support or BES voltage control should be included. A Reactive Power device
connected at >100kV but used for the purpose of voltage support to local
load should not be included.
d)The core definition uses "Transmission Elements" while E1 uses
"transmission Elements". What is the difference? If one or both terms are
applicable, their definition should be included.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES
and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100
kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is
needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
67

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Yes or No

Question 1 Comment

breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 –
I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks)
should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion
I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects
(i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being
responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would
warrant a change from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders
and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the
68

Organization

Yes or No

Question 1 Comment

definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction
with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide
compelling justification for modifications to the existing values.
The SDT points the commenter to Exclusion E4 for the handling of such a situation.
The SDT considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that retention of this
word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise
be included in the term “Element”.
The Dow Chemical Company

Yes

The Dow Chemical Company (“Dow) is an international chemical and plastics
manufacturing firm and a leader in science and technology, providing
chemical, plastic, and agricultural products and services to many essential
consumer markets throughout the world. Dow and certain of its worldwide
affiliates and subsidiaries, including Union Carbide Corporation, own and
operate electrical facilities at a number of industrial sites within the U.S.,
principally, in Texas and Louisiana. The electrical facilities at these various
industrial sites are configured similarly and perform similar functions. In
most cases, a tie line or lines connect the industrial site to the electric
transmission grid. Power is delivered from the electric transmission grid to
the industrial site through the tie line(s). Lines “behind-the-meter” within
the industrial site then deliver power to individual manufacturing plants
within the site. Additionally, cogeneration facilities, some of which are well
over 75 MW in size, are located at a number of industrial sites owned by
Dow and its subsidiaries. These cogeneration facilities generate power that
is distributed within the industrial site and used for manufacturing plant
operations. In some instances, excess power not required for plant
operations is delivered back into the electric transmission grid through the
tie line(s) connecting the industrial site to the grid. While the tie lines and
some of the internal lines at these industrial sites operate at 100kV or
higher, they do not perform anything that resembles a transmission
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Yes or No

Question 1 Comment
function. Rather than transmit power long distances from generation to load
centers, the tie lines and internal lines perform primarily an end user
distribution function consisting of the distribution of power brought in from
the grid or generated internally to different plants within each industrial site.
In some cases, the facilities also perform an interconnection function to the
extent they enable power from cogeneration facilities to be delivered into
the grid. The voltage of the tie lines and internal lines at these industrial
sites is dictated by the load and basic configuration of each site. Higher
voltage lines are used when necessary to meet applicable load requirements
or to reduce line losses. That does not mean that such lines perform a
transmission function. At some sites, Dow is registered as a Generation
Owner and Generation Operator. At other sites, the applicable Regional
Entity has found that such registration is not required because of the
relatively small amount of power supplied to the grid from the applicable
cogeneration resources, even though those cogeneration resources have an
aggregate capacity greater than 75 MVA (gross aggregate nameplate rating).
Tie lines (to the grid) and internal lines at an industrial site that operate at
100kV or higher should be excluded from the BES definition if, due to the
relatively small amount of power supplied to the grid from the generation
resources at the site, the owner of those generation resources is not
required to be registered as a Generation Owner and the operator of those
generation resources is not required to be registered as a Generation
Operator. At sites where the owner of the generation resources is registered
as a Generation Owner and the operator of those generation resources is
registered as a Generation Operator, the internal lines (between the
generation resources and the manufacturing plants) that operate at 100kV
or higher should be excluded from the BES definition, because they are
distribution and not transmission facilities. The lines interconnecting the
generation resources at such sites to the transmission grid should be
included in the BES definition, but the owner and operator of such
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Organization

Yes or No

Question 1 Comment
interconnection lines should not be registered as a Transmission Owner or
Transmission Operator. In no instance has a Regional Entity determined that
Dow or any subsidiary should be registered as a Transmission Owner or
Transmission Operator. Instead, such interconnection lines should be
considered as part of the generation resource and Generation Owners and
Generation Operators should be subject to reliability standards specifically
developed for such interconnection lines. Dow is strongly opposed to any
BES definition that would result in either the tie lines or the internal lines at
industrial sites being subject to the mandatory reliability standards
applicable to Transmission Owners and Transmission Operators.
Complying with reliability standards would cause Dow and its subsidiaries to
incur substantial compliance costs and create potential exposure to
penalties in the future for noncompliance. Perhaps such costs and exposure
could be justified if subjecting these facilities to compliance with reliability
standards resulted in a material increase in reliability of the BES, but there is
no reason to believe that will be the case. In fact, the opposite might be
true. The tie lines and internal lines at industrial sites owned by Dow and its
subsidiaries have been operated for decades as end user distribution and
interconnection facilities, and practices and procedures have developed
over the years that have enabled such operations to achieve a high degree
of reliability for such sites. Requiring these facilities to now operate in a
different manner as transmission facilities may well result in a degradation
of the reliability of the manufacturing plants located at such sites. For
example, outages would have to be coordinated with the RTO, which may
not be interested in coordinating such outages with scheduled
manufacturing plant outages. In light of these considerations, Dow agrees
with the proposed revisions to the core definition, particularly the proposal
to include a sentence expressly excluding facilities used in the local
distribution of electric energy, provided it is understood that end userowned delivery facilities located “behind-the-meter” are, regardless of
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Organization

Yes or No

Question 1 Comment
voltage level, presumptively outside the scope of this definition.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and
non-BES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT
has pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or
contracting the current scope of the BES or driving registration or de-registration.
City of Redding

Yes

Redding is concerned that NERC has a predetermined definition of
Distribution Facilities and will not evaluate networked distribution facilities
fairly. NERC stated their predetermined position in their “MOTION TO
INTERVENE AND COMMENTS OF THE NORTH AMERICAN ELECTRIC
RELIABILITY CORPORATION” filed in the case of the City of Holland, Michigan
(Docket No. RC11-5-000). On page 10 and 11 of this motion, under the
section labeled “A. Holland’s 138 kV lines are transmission rather that local
distribution facilities” NERC states “Distribution facilities generally are
characterized as elements that are designed and can carry electric energy
(Watts/MW) in one direction only at any given time from a single source
point (distribution substation) to final load centers.” NERC is clearly states
that only radial facilities are considered distribution facilities and are
unwilling to consider that network facilities over 100Kv could be classified as
Distribution Facilities. Holland’s claim of NERC over reaching their authority
appears to have credibility. In conclusion, Redding supports the addition of
Distribution Facilities as an exclusion but believes that the BES Definition
phase 2 needs to clearly define the difference between Distribution and
Transmission Facilities by identifying the equipment “necessary for the
Reliable Operation of the interconnected bulk power transmission system”.

Response: See the detailed comments on this issue in the Responses to the comments to the Question 2 of the Exception Process

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Organization

Yes or No

Question 1 Comment

as well as the Detailed Information to Support an Exception Request Form.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that
would warrant a change from the current values that exist through the application of the definition today. These and similar issues
have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in
conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
Xcel Energy

In general, Xcel Energy supports the changes to the core definition of Bulk
Electric System. Some additional clarification may be required as suggested
below under the individual Inclusions or Exclusions.

Tacoma Power

Yes

Redding Electric Utility

Yes

ATC LLC

Yes

Portland General Electric Company

Yes

Farmington Electric Utility System

Yes

Georgia System Operations
Corporation

Yes

Nebraska Public Power District

Yes

Tacoma Power supports the core definition as currently written.

The drafting team has done a great job of adding clarity and to improving
the BES definition. Although more work is needed as noted in comments
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Organization

Yes or No

Question 1 Comment
below, overall the drafting team is on the right track with the BES defintion.

Oncor Electric Delivery Company LLC

Yes

LCRA Transmission Services
Corporation

Yes

Memphis Light, Gas and Water
Division

Yes

Independent Electricity System
Operator

Yes

PSEG Services Corp

Yes

Orange and Rockland Utilities, Inc.

Yes

City of St. George

Yes

American Electric Power

Yes

Tillamook PUD

Yes

Consumers Energy

Yes

Springfield Utility Board

Yes

The core definition is acceptable as long as the concerns for inclusion and
exclusion are addressed as outlined in the other comments.

We strongly support the addition of the language regarding local distribution
facilities, as it matches congressional intent to leave the regulation of these
facilities to state and local authorities.

SUB particularly agrees with the addition of, “This does not include facilities
used in the local distribution of electric energy.” to the BES draft definition.

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Organization

Yes or No

Question 1 Comment

NV Energy

Yes

The core definition is simpler than the prior version. We support the
addition of the last sentence regarding the exclusion of facilities used in the
local distribution of electric energy.

Duke Energy

Yes

Chevron U.S.A. Inc.

Yes

Central Hudson Gas and Electric
Corporation

Yes

Idaho Falls Power

Yes

Exelon

Yes

Southern Company

Yes

Texas Industrial Energy Consumers

Yes

Tri-State GandT

Yes

Western Area Power Administration

Yes

Tri-State Generation and
Transmission Assn., Inc. Energy
Management

Yes

MRO NERC Standards Review Forum

Yes

Yes. Very good progress was made in the process. The initial overly broad
language was inadvertently including parties that are not necessary to meet
the NERC and FERC goals. The current language has clarified some of the
ambiguities.

We generally support the changes made.

We believe that the new definition is a good clarification.

We believe that the new definiation is a good clarification.

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Organization

Yes or No

Question 1 Comment

(NSRF)
Pepco Holdings Inc and Affiliates

Yes

ACES Power Marketing Standards
Collaborators

Yes

WECC Staff

Yes

Bonneville Power Administration

Yes

Northeast Power Coordinating
Council

Yes

SERC Planning Standards
Subcommittee

Yes

BGE

Yes

No comment.

Response: Thank you for your support.

76

2.

The SDT has revised the specific inclusions to the core definition in response to industry comments. Do you agree with Inclusion
I1 (transformers)? If you do not support this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.

Summary Consideration: Several commenters asked for additional clarity in the description of the types of transformers covered by
Inclusion I1 and in response the SDT has slightly revised the language in Inclusion I1 based upon comments received and to provide
additional clarity as shown below.
Several commenters suggested that Inclusion I1 contain a statement to identify the subset of transformers that are not covered by
Inclusion I1 and the SDT declined to make this revision. The SDT believes the use of language in the definition to state what is also
excluded is redundant and not needed in the definition.
Some comments were received suggesting modifying to Inclusion I1 to add a 200 kV threshold. Using a 200 kV voltage threshold and/or
an MVA threshold for inclusion of transformers in the BES and the addition of demarcation points will be considered in Phase 2 of this
effort. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with
being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a
change from the current values that exist through the application of the definition today. These and similar issues have prompted the
SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory
authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for
inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC
Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide compelling justification
for modifications to the existing values.
Several commenters asked for additional clarity on the hierarchy of inclusions and exclusions. The SDT provides the following guidance
on this topic.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
77

“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker,
bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application
of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific
criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The
exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied
in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude an
Element.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless excluded under
Exclusion E1 or E3.

Organization

Yes or No

Question 2 Comment

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Organization

Yes or No

Question 2 Comment

Northeast Power Coordinating
Council

No

More specific description is needed for the equipment intended to be included
in I1. For example, is it intended to include autotransformers, PARs, primary,
secondary, tertiary windings, etc.? There will be difficulty applying the
definition to facilities without this detail. Suggest rewording to: All
transformers (including auto-transformers, voltage regulators, and phase angle
regulators and all windings) with primary and secondary terminals operated at
or above 100kV, and generator step-up (GSU) transformers with one terminal
operated at or above 100KV, unless excluded by E1 or E3.

NESCOE

No

NESCOE supports the revised Inclusion I1 language that treats Exclusions E1 and
E3 as alternative exclusions, either of which may qualify as an exclusion.
However, specificity is needed regarding what equipment is included in I1 (e.g.,
autotransformers, PARs, primary, secondary, tertiary windings).

Massachusetts Department of
Public Utilities

No

The MA DPU supports the revised Inclusion I1 language that treats Exclusions E1
and E3 as alternative exclusions, either of which may qualify as an exclusion.
However, specificity is needed regarding what equipment is included in I1 (e.g.,
autotransformers, PARs, primary, secondary, tertiary windings).

Response: Several commenters indicated that additional specificity is needed to describe the transformers in Inclusion I1 and
the SDT added the word, “terminal” and the phrase, “at least one” to Inclusion I1 for additional clarity. The revised Inclusion I1
now reads:
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
The SDT provides the following guidance with respect to inclusions and exclusions to provide clarity on how to use the
definition and in response to your comment:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify
the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between
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Organization

Yes or No

Question 2 Comment

BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources
connected at 100 kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of
the term Element is needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified
in the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by
Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3
(local networks) should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is
Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes
Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element.
AECI and member GandTs,

No

“100 kV or above” should be modified to “200 kV or above with a registered
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Organization

Yes or No

Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power
Cooperative

Question 2 Comment
rating of 150 MVA or greater.”

Response: The issue of transformer voltage level and possibly an MVA threshold level will be discussed in Phase 2 of this
project. No change made.
Duke Energy

No

For clarity regarding 3 and 4 winding transformers, it should say “primary and at
least one secondary terminal operated at 100 kV or higher.

Response: The SDT has revised the language to provide the clarity suggested in the comment.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
New York State Dept of Public
Service

No

o I1 lacks specificity that can lead to confusion and required clarifications.
Suggested wording change: All transformers (including auto-transformers,
voltage regulators, and phase angle regulators and all windings) with primary
and secondary terminals operated at or above 100 kV, and generator step-up
(GSU) transformers with one terminal operated at or above 100 kV, unless
excluded by E1 or E3.

ISO New England Inc

No

I1 needs to be clarified such that it is clear on whether this includes
autotransformers, phase angle regulators, and devices which have a tertiary
winding. Using the tertiary winding as an example, it is not clear whether the
tertiary winding itself is considered BES, especially if it is serving a radial system
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Question 2 Comment
as described in E1.

Response: The SDT has slightly revised the language in Inclusion I1 based upon comments received and to provide clarity.
Since a transformer is one Element, any additional tertiary windings would be included in the BES if a transformer meets this
criterion for inclusion.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
Rochester Gas and Electric
and New York State Electric
and Gas

No

We generally agree, but suggest modification to the language of Inclusion I1 to
clarify its application for transformers with more than two windings:
“Transformers with two or more terminals operated at 100 kV or higher, unless
excluded under Exclusion E1 and E3.” Based on this wording, transformer
tertiary windings would also be BES - is that the intent?

Central Maine Power
Company

Yes

We generally agree, but suggest modification to the language of Inclusion I1 to
clarify its application for transformers with more than two windings:
“Transformers with two or more terminals operated at 100 kV or higher, unless
excluded under Exclusion E1 or E3.” Based on this wording, transformer tertiary
windings would also be BES - is that the intent?

Response: It is correct that associated tertiary windings are included in the BES if the transformer is based upon the language
in Inclusion I1. Also, the SDT has slightly revised the language in Inclusion I1 based upon comments received and to provide
clarity. Since a transformer is one Element, any additional tertiary windings would be included in the BES if a transformer
meets this criterion for inclusion.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
LCRA Transmission Services
Corporation

No

LCRA TSC supports the inclusion of transformers (with both the primary and
secondary windings operated at 100-kV or higher) in the BES definition;
however, additional clarification is suggested. The term transformers needs to
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Question 2 Comment
be further defined with respect to function (auto transformers, phase angle
regulators, generator step-up transformers, etc.). Similarly, a separate
definition for “Transformer” could be developed and included in the NERC
Glossary of Terms.

Response: The SDT believes the existing language is clear and the proposed additional language would be redundant.
However, in response to comments from others, the SDT has made clarifying changes to Inclusion I1 that should address your
concerns and obviate the need for a separate definition for transformers.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
ExxonMobil Research and
Engineering

Yes

The Inclusion I1 contains the phrase “unless excluded under Exclusion E1 or E3”.
While recognizing that this is a welcomed clarification on how I1 interacts with
the Exclusion section, it is inconsistent with Inclusions I2 through I5. The BES
SDT team should consider how to standardize the language around the
interactions between the Inclusions and Exclusions (perhaps add an “unless”
qualifier for each Inclusion).

Response: The SDT provides the following guidance with respect to inclusions and exclusions to provide clarity on how to use
the definition and in response to your comment:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify
the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between
BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources
connected at 100 kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of
the term Element is needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
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Yes or No

Question 2 Comment

electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified
in the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by
Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3
(local networks) should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is
Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes
Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element.
Ameren

Yes

Agree in general, but have the following comments: a) We agree in general with
the revisions to the specific inclusions for transformers in I1; however, we
believe the transformer voltage level should be 200kV or above.
b ) The inclusion is unclear since it includes a certain voltage transformers, but
excludes those that have E1 or E3 Exclusion criteria. Each exclusion criteria has
multiple stipulations to its applicability, and then has a final inclusive reference
to I3. Please make the wording exact and not dependent on clausal statements.
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Question 2 Comment

Response: The issue of transformer voltage level and possibly an MVA threshold level will be discussed in Phase 2 of this
project.
The SDT provides the following guidance with respect to inclusions and exclusions to provide clarity on how to use the
definition and in response to your comment:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify
the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between
BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources
connected at 100 kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of
the term Element is needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified
in the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by
Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3
(local networks) should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is
Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
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Question 2 Comment

Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes
Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element.
Memphis Light, Gas and
Water Division

Yes

We believe further clarification is needed to limit BES transformers only to
those serving the transmission system and not distribution loads, such as
excluding transformers with one or both terminals operating below 100 kV.

Response: Transformers are excluded from the BES if the secondary terminal operates below 100 kV. No change made.
Puget Sound Energy

Yes

Inclusion I1 references primary and secondary terminals of transformers, while
Inclusions I2 and I5 reference the high-side of transformers. The SDT should
consider using consistent terminology throughout the definition for this
concept.

Response: The SDT has reviewed the entire document for consistency in phrasing but in this particular situation finds no
problem in the terminology employed. No change made.
Michigan Public Power Agency
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)
Central Electric Cooperatve
(CEC)

Yes

MPPA supports the SDT’s changes to the first Inclusion because it is more clear
and simple than the initial approach. That being said, we suggest that an
additional sentence of clarification would help avoid future controversy about
the meaning of Inclusion 1. As MPPA understands it, the BES intends to include
transformers only if both the primary and secondary terminals operate at 100
kV or above, which is why the definition uses the word “and” (“the primary and
secondary terminals”). We support this approach since it would exclude
transformers where the secondary terminals serve distribution loads, and which
therefore function as distribution rather than transmission facilities. MPPA
believes the SDT’s intent would be clarified by adding a sentence at the end of
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Organization
Clearwater Power Company
(CPC)
Snohomish County PUD
Consumer's Power Inc.
Douglas Electric Cooperative
(DEC)
Fall River Rural Electric
Cooperative (FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric Cooperative
(UEC)
Kootenai Electric Cooperative

Yes or No

Question 2 Comment
Inclusion 1 that reads: “Transformers with either primary or secondary
terminals, or both, that operate at or below 100 kV are not part of the BES.”
This language will help ensure that there is no controversy over whether the
SDT’s use of the word “and” in the phrase “the primary and secondary
terminals” was intentional.
We also support the SDT’s proposal to develop detailed guidance concerning
the point of demarcation between BES and non-BES elements in the Phase 2
SAR. In this regard, we note that, while Inclusion 1 at least implicitly suggests
that the dividing line between BES and non-BES Elements should be at the
transformer where transmission-level voltages are stepped down to
distribution-level voltages, we believe further clarification of this point of
demarcation between the BES and non-BES Elements is necessary. There are
many different configurations of transformers and other equipment that may
lie at the juncture between the BES and non-BES systems. If the point of
demarcation is designated at the transformer without further elaboration,
many entities that own equipment on the high side of a transformer will be
swept into the BES, and thereby exposed to inappropriately stringent
regulations and undue costs. For example, distribution-only utilities commonly
own the switches, bus and transformer protection devices on the high side of
transformers where they take delivery from their transmission provider.
Ownership of these protective devices and high-voltage bus on the high side of
the transformer should not cause these entities to be classified as BES owners.
MPPA has some members who have been forced to sell of such assets in the
hopes of remove the necessity for a TO/TOP registration path in this region.
We also support the incorporation of language (“. . . unless excluded under
Exclusions E1 or E3”) making it clear that transformers that are operated as an
integral part of a Radial System or Local Network should not be considered BES
facilities, regardless of their operating voltage. Further clarification might be
achieved by using the phrase “. . . unless the transformer is operated as part of
a Radial System meeting the requirements of Exclusion E1 or a Local Network
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Question 2 Comment
meeting the requirements of Exclusion E2.”

Response: The SDT has slightly revised Inclusion I1 to provide additional clarity. The SDT believes it is not necessary to state
what transformers are not included in the BES, which would be redundant.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
The development of demarcation points will be included in Phase 2 of this project.
The SDT provides the following guidance with respect to inclusions and exclusions to provide clarity on how to use the
definition and in response to your comment:
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify
the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between
BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources
connected at 100 kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of
the term Element is needed. Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified
in the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by
Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3
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Question 2 Comment

(local networks) should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is
Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes
Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element.
Cowlitz County PUD

Yes

Cowlitz supports the SDT’s efforts to simplify this inclusion. However, Cowlitz
suggests the following change to clarify the inclusive nature of the use of “and:”
Transformers with primary and secondary terminals both operated at 100 kV or
higher...

City of Austin dba Austin
Energy

Yes

We believe additional clarification of transformers to be included may be
achieved with respect to auto transformers, phase angle regulators and
generator step-up transformers by adding the following sentence: All
transformers (including autotransformers, voltage regulators, and phase angle
regulators) with primary and secondary terminals operated at or above 100kV,
unless excluded by E1 or E3.

Sacramento Municipal Utility
District

Yes

We believe additional clarification of transformers that are to be included may
be achieved with respect to auto transformers, phase angle regulators and
generator step-up transformers by adding the following recommended
sentence: “All transformers (including autotransformers, voltage regulators, and
phase angle regulators) with primary and secondary terminals operated at or
above 100kV, unless excluded by E1 or E3.”
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Question 2 Comment

Utility Services, Inc.

Yes

Utility Services supports the comments offered by other commenters who
suggest that transformers and other related devices be mentioned in the
inclusion.

PacifiCorp

Yes

PacifiCorp suggests a clarification to I1 to provide as follows: “Transformers
with either primary or secondary terminals, or both, that operate at or below
100 kV are not part of the BES.”

Balancing Authority Northern
California

Yes

We believe additional clarification of transformers that are to be included may
be achieved with respect to auto transformers, phase angle regulators and
generator step-up transformers by adding the following recommended
sentence: “All transformers (including autotransformers, voltage regulators, and
phase angle regulators) with primary and secondary terminals operated at or
above 100kV, unless excluded by E1 or E3.”

Response: The SDT has slightly revised the language in Inclusion I1 based upon comments received and to provide clarity.
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.
PacifiCorp

Yes

PacifiCorp suggests a clarification to I1 to provide as follows: “Transformers
with either primary or secondary terminals, or both, that operate at or below
100 kV are not part of the BES.”

Response: The SDT believes it is not necessary to state what transformers are not included in the BES, which would be
redundant. No change made.
Florida Municipal Power
Agency

Yes

Please see comments to Question 1

Response: Please see response to Q1.
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Yes or No

Question 2 Comment

MEAG Power

Yes

We agree in general with the revisions to the specific inclusions for
transformers in I1; however, we believe the transformer voltage level should be
200kV or above.

Tennessee Valley Authority

Yes

TVA agrees in general with the revisions to the specific inclusions for
transformers in I1; however, we believe the low side transformer voltage level
should be 200kV or above, and requests that the Phase 2 for the project use
200kV and above or develop a transmission voltage and/or an MVA threshold
that is technically based.

SERC OC Standards Review
Group

Yes

We agree in general with the revisions to the specific inclusions for
transformers in I1; however, we believe the transformer voltage level should be
200kV or above.

Response: The issue of transformer voltage level and possibly an MVA threshold level will be discussed in Phase 2 of this
project. No change made.
National Grid

Yes

Farmington Electric Utility
System

Yes

South Houston Green Power,
LLC

Yes

Portland General Electric
Company

Yes

Northern Wasco County PUD

Yes

Northern Wasco County PUD strongly agrees with this inclusion as written. It is
consistent with the recent PRC-004 and PRC-005 interpretation and the NERC
definition of Transmission. We believe the recent changes to this inclusion add
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Question 2 Comment
clarity.

Georgia System Operations
Corporation

Yes

Nebraska Public Power District

Yes

Kansas City Power and Light
Company

Yes

Oncor Electric Delivery
Company LLC

Yes

Harney Electric Cooperative,
Inc.

Yes

HEC agrees with the inclusions to I1 and believes that add clarity to the
definition.

Central Lincoln

Yes

Central Lincoln strongly agrees with this inclusion as written. It is consistent
with the recent PRC-004 and PRC-005 interpretation and the NERC definition of
Transmission. We believe the recent changes to this inclusion add clarity.

PSEG Services Corp

Yes

Hydro-Quebec TransEnergie

Yes

Independent Electricity
System Operator

Yes

Orange and Rockland Utilities,
Inc.

Yes

Tillamook PUD

Yes

Tillamook PUD strongly agrees with this inclusion as written. It is consistent with
the recent PRC-004 and PRC-005 interpretation and the NERC definition of
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Yes or No

Question 2 Comment
Transmission. We believe the recent changes to this inclusion add clarity.

American Electric Power

Yes

Manitoba Hydro

Yes

Long Island Power Authority

Yes

The Dow Chemical Company

Yes

City of St. George

Yes

Mission Valley Power

Yes

Mission Valley Power - Comments: Mission Valley Power strongly agrees with
this inclusion as written. It is consistent with the recent PRC-004 and PRC-005
interpretation and the NERC definition of Transmission. We believe the recent
changes to this inclusion add clarity.

NV Energy

Yes

The changes made to I1 (Transformers) appropriately resolves several of the
industry concerns about three-winding transformers as well as an inadvertent
use of the word “and” rather than “or”.

Z Global Engineering and
Energy Solutions

Yes

Consumers Energy

Yes

Springfield Utility Board

Yes

SUB supports and appreciates the change in language from, “unless excluded
under Exclusions E1 and E3” to “Exclusion E1 or E3”. This makes it clear that
Radial System or Local Network transformers should not be considered BES
facilities, regardless of operating voltage.

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Yes or No

Chevron U.S.A. Inc.

Yes

Metropolitan Water District of
Southern California

Yes

Idaho Falls Power

Yes

ReliabilityFirst

Yes

Ontario Power Generation Inc.

Yes

Central Hudson Gas and
Electric Corporation

Yes

City of Anaheim

Yes

Southern Company

Yes

FirstEnergy Corp.

Yes

Exelon

Yes

Hydro One Networks Inc.

Yes

Tri-State GandT

Yes

Western Area Power
Administration

Yes

Texas Industrial Energy
Consumers

Yes

Question 2 Comment

We support the language as drafted.

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Organization

Yes or No

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

Yes

MRO NERC Standards Review
Forum (NSRF)

Yes

IRC Standards Review
Committee

Yes

ACES Power Marketing
Standards Collaborators

Yes

Dominion

Yes

Pepco Holdings Inc and
Affiliates

Yes

Electricity Consumers
Resource Council (ELCON)

Yes

Southern Company
Generation

Yes

WECC Staff

Yes

Bonneville Power
Administration

Yes

Texas RE NERC Standards

Yes

Question 2 Comment

The proposed changes are much clearer than proposed language in the 1st draft
of this BES definition.

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Yes or No

Question 2 Comment

Subcommittee
SERC Planning Standards
Subcommittee

Yes

Southwest Power Pool
Standards Review Team

Yes

NERC Staff Technical Review

Yes

ATC LLC

Yes

Westar Energy

Yes

Redding Electric Utility

Yes

City of Redding

Yes

Tacoma Power

Yes

Tacoma Power supports Inclusion I1 as currently written.

BGE

Yes

No comment.

Response: Thank you for your support. Due to comments received from others the SDT has made clarifying changes as follows:
I1 - Transformers with the primary terminal and at least one secondary terminals operated at 100 kV or higher unless
excluded under Exclusion E1 or E3.

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3.

The SDT has revised the specific inclusions to the core definition in response to industry comments. Do you agree with Inclusion
I2 (generation) including the reference to the ERO Statement of Compliance Registry Criteria? If you do not support this change
or you agree in general but feel that alternative language would be more appropriate, please provide specific suggestions in
your comments.

Summary Consideration: Comments received regarding the threshold level for generators, the relationship between the NERC
Compliance Registry and the BES Definition and the need for contiguous BES elements will be considered in the Phase 2 review.
In response to comments regarding the reference to the ERO Statement of Compliance Registry Criteria (SCRC) the SDT made a clarifying
change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2, instead specifying the 20/75 MVA
reference threshold values in order to avoid the possibility of the registry values being changed and thus affecting the BES Definition
prior to the resolution of the threshold values in Phase 2 of this project.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects
(i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being
responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012,
and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have prompted the SDT to
separate the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities.
Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2
of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing
Committees, to develop analyses which will properly assess the threshold values and provide compelling justification for modifications
to the existing values.
Inclusion I2 was clarified as follows:
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate nameplate
rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator terminals through the highside of the step-up transformer(s) connected at a voltage of 100 kV or above.

Organization

Yes or No

Question 3 Comment

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Yes or No

Question 3 Comment

Northeast Power Coordinating
Council

No

In deference to direction given to the Drafting Team, Inclusion I2 should remove the
reference to the Statement of Compliance Registry Criteria. The current language
induces circular arguments without a true governing document. The definition
should drive what appears in the registration criteria. I2 should be revised to read:
“Generating resources with a gross nameplate rating of 20MVA or greater, or
generating plant/facility connected at a common bus, with an aggregate nameplate
rating of 75MVA or greater and is directly connected to a BES Element.” This is
consistent with the proposed I2 and the current Compliance Registry Criteria.
Ultimately the definition should be the governing document and provide the details
of what generation should be included. It is understood that Phase 2 of this project
will address this.

Balancing Authority Northern
California

No

We recommend removing the reference of the ERO Statement of Compliance
Registry Criteria (Registry Criteria). The BES Definition should be the governing
document and independent of ERO registration requirements. The definition should
drive what appears in the Registry Criteria. Additionally, we support using the BES
Phase 2 technical analysis to identify and provide technical support for determining
the appropriate minimum MVA rating that a single unit, or the aggregation of
multiple units, must meet to be considered part of the BES.

Oregon Public Utility
Commission Staff

No

Reference to NERC Statement of Compliance Registry Criteria (SCRC) needs to be
eliminated from the BES Definition. This circularity must be eliminated. Proposed
revised language is:”I2 - Generating resource(s) with a gross individual nameplate
rating greater than 20 MVA or with a gross aggregate nameplate rating greater than
75 MVA including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above.”

American Electric Power

No

AEP is a proponent of cross-referencing related documents to avoid elements from
becoming out of sync, however, rather than having the BES Definition document
reference the ERO Statement of Compliance Registry Criteria, perhaps it should be
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Question 3 Comment
the other way around. This definition document undergoes a more thorough industry
development and review process. The ERO Statement of Compliance Registry Criteria
does not get specific in regards to device types. The BES Definition document is a
more appropriate place to designate inclusion criteria.

New York State Dept of Public
Service

No

In I2, there is a reference to the Statement of Compliance Registry Criteria. However,
the Statement references the BES definition. This circular logic results in a fatally
flawed definition. The statement reference should be replaced with the actual
intended words.

Rochester Gas and Electric
and New York State Electric
and Gas

No

Inclusion I2 should remove the reference to the Statement of Compliance Registry
Criteria. The definition should stand on its own. I2 should be revised to read:
“Generators with a gross nameplate rating of 20 MVA or greater, or a generating
plant/facility connected at a common bus, with a gross aggregate nameplate rating of
75 MVA or greater and is directly connected at a voltage of 100 kV or above. BES
includes the generator terminals through the high-side of the step-up transformer(s)
connected at a voltage of 100 kV or above.” This is consistent with the proposed I2
and the current Compliance Registry Criteria.

Sacramento Municipal Utility
District

No

We recommend removing the reference of the ERO Statement of Compliance
Registry Criteria (Registry Criteria). The BES Definition should be the governing
document and independent of ERO registration requirements. The definition should
drive what appears in the Registry Criteria. Additionally, we support using the BES
Phase 2 technical analysis to identify and provide technical support for determining
the appropriate minimum MVA rating that a single unit, or the aggregation of
multiple units, must meet to be considered part of the BES.

Central Maine Power
Company

No

Inclusion I2 should remove the reference to the Statement of Compliance Registry
Criteria. The definition should stand on its own. I2 should be revised to read:
“Generators with a gross nameplate rating of 20 MVA or greater, or a generating
plant/facility connected at a common bus, with a gross aggregate nameplate rating of
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75 MVA or greater; and is directly connected at a voltage of 100 kV or above. BES
includes the generator terminals through the high-side of the step-up transformer(s)
connected at a voltage of 100 kV or above.” This is consistent with the proposed I2
and the current Compliance Registry Criteria.

Farmington Electric Utility
System

No

FEUS is concerned I2 is dependent on the Statement of Compliance Registry Criteria
(SCRC). Modification of the SCRC is not required to go through the same process of
modification of a Standard but section 1400 of the NERC Rules of Procedure. Section
1400 does allow for industry comment and requires multiple tiers of approval.
However, it seems by changing the SCRC generating resources may be included or
excluded from the BES - without requiring modification to the definition of the BES
through the Standards Development Process. In addition, Page 4 Section I of the SCRC
is dependent on the NERC definition of the BES. Logically, the SCRC should be
dependent on the definition of the BES not the inverse.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2,
instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and
thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Electricity Consumers
Resource Council (ELCON)

No

Since an aggregate of 75 MVA is allowed at a single site, there is no basis for
maintaining the 20 MVA for a single generator. The proposed MOD-026 assigns
thresholds by region that are much higher than 20 MVA for modeling purposes.
Since modeling generally would require more granularity than what is necessary for
the reliable operation of the interconnected transmission system (BES), the SDT
might want to review the threshold basis for NERC Project 2007-09 (Generator
Verification). It is understood that the threshold will be reconsidered in Phase 2 of
the BES Definition Project; however, a modest change from 20 to 75 MVA seems
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appropriate on an interim basis justified by the current 75 MVA aggregate per site.
The following phrase should be added at the end “unless excluded under Exclusion
E2.”

Texas RE NERC Standards
Subcommittee

No

Since an aggregate of 75 MVA is allowed at a single site, there is no basis for
maintaining the 20 MVA for a single generator. The proposed MOD-026 assigns
thresholds by region that are much higher than 20 MVA for modeling purposes.
Since modeling generally would require more granularity than what is necessary for
the reliable operation of the interconnected transmission system (BES), the SDT
might want to review the threshold basis for NERC Project 2007-09 (Generator
Verification).

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values.
Coordination between the BES Definition and the MOD Standards will be addressed in Phase 2.
Tri-State GandT

No

1. The parenthetical phrase regarding the ERO SCRC is not clear. Is the intent that
the inclusion applies to any generating resource that is required to register as a
Generator or Generator Operator per the ERO SCRC? Or was a reference to the 75
MVA threshold inadvertently omitted? It also seems that it wouldn’t need to be in
parentheses, just make it a phrase in the sentence.
2. The wording of the sentence after the parenthetical phrase is also worded
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awkwardly. Suggest changing it to “including the generator terminals and all
electrical equipment up to and including the high side of generator step up
transformers, if they are connected at a voltage of 100 kV or higher.

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

No

1. The parenthetical phrase regarding the ERO SCRC is not clear. Is the intent that
the inclusion applies to any generating resource that is required to register as a
Generator or Generator Operator per the ERO SCRC? Or was a reference to the 75
MVA threshold inadvertently omitted? It also seems that it wouldn’t need to be in
parentheses, just make it a phrase in the sentence.
2. The wording of the sentence after the parenthetical phrase is also worded
awkwardly. Suggest changing it to “including the generator terminals and all
electrical equipment up to and including the high side of generator step up
transformers, if they are connected at a voltage of 100 kV or higher.

Pepco Holdings Inc and
Affiliates

No

The definition should not reference the ERO Statement of Compliance Registry
Criteria; rather the actual generation threshold criteria should be listed in the
definition itself. This way the definition can stand on it’s own without having to refer
to another document for applicability.
Also, the wording should be changed to read “including the generator terminals
through the high side of any dedicated generator step-up transformer(s), connected
at a voltage of 100kV or above.” Otherwise, the present wording could ensnare
distribution facilities (similar to the cranking path argument in I3) if a 21 MVA
generator was connected on a distribution line with no dedicated generator step-up
transformer. In that case the distribution line and substation feeder transformer
might be construed to be in scope.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion
I2, instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being
changed and thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
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nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
The I2 inclusion refers only to generation “ … through the high-side of the step-up transformer(s) connected at a voltage of 100
kV or above.” No change made.
ExxonMobil Research and
Engineering

No

The Inclusion I1 contains the phrase “unless excluded under Exclusion E1 or E3”.
While recognizing that this is a welcomed clarification on how I1 interacts with the
Exclusion section, it is inconsistent with Inclusions I2 through I5. The BES SDT team
should consider how to standardize the language around the interactions between
the Inclusions and Exclusions (perhaps add an “unless” qualifier for each Inclusion).

South Houston Green Power,
LLC

No

SHGP agrees with the proposed revisions to Inclusion I2, but requests the following
phrase added at the end “unless excluded under Exclusion E2”.

Nebraska Public Power District

No

Inclusion 2 does not take into consideration a later exclusion (Exclusion 3). At the end
of Inclusion 2 after the words “..100 kV or above.” Add the words “, unless excluded
under Exclusion 3”.

MRO NERC Standards Review
Forum (NSRF)

No

Unless excluded under E2.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer,
circuit breaker, bus section, or transmission line. An element may be comprised of one or more components. “
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Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application
of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific
criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The
exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied
in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element.
Harney Electric Cooperative,
Inc.

No

HEC would like to see the inclusion of specific thresholds that are technically justified.

City of St. George

No

The basis for the Compliance Registry Criteria generation levels for inclusion seems to
be arbitrary with little or no justification. As currently proposed, a small 20 MVA
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generator must comply with same requirements as large units of several hundred
MVA of generation capacity. Phase 2 of the BES project may help address the issue
but in the meantime many facilities must comply with numerous standards with little
or no benefit to the reliability of the actual BES. No timeline for Phase 2 is indicated.
Finding a bright line number for the generation levels on a per unit or overall plant
basis will be a difficult task, but the present MVA levels of the Registration Criteria
are very low for automatic inclusion. The compliance requirements of an entity
should match the impact to the system.

NV Energy

No

While we do not agree with making specific reference and linkage to the generator
thresholds of the SCRC, it is understood that a timely justification of any alternative
threshold was not possible. It is of paramount importance that the subject of
generation thresholds be addressed in subsequent development of this Definition.
We are of the opinion that generation ought to be considered as a “user” of the BES,
not necessarily a part of the BES, similar in concept to the way Load uses the BES.
Using this concept, the BES would be restricted to the “wires” type facilities.
Standards would nevertheless be applicable to generators that use the BES, so no gap
in reliability would exist.

Idaho Falls Power

No

Reliance upon the Registry Criteria falls back to the 20MVA threshold. We believe
this threshold is very low and unnecessarily draws in small entities for which there is
no impact to the BES. We understand the barriers and the volume of tenchnical
evidence required for any change and we therefore have no alternative language to
suggest.

PacifiCorp

No

Requiring owners of single generators (20 MVA - 75 MVA) to meet reliability
standards that owners of distributed power producing resources (See I4) do not have
to meet is discriminatory. The limit for a single unit should be set to 75 MVA until
such time as a technical review can determine the appropriate levels for all
generation resources. However, even with this concern, PacifiCorp supports the
entire BES definition in its current form based on the timeframe under which the SDT
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is operating and with an emphasis based on a phase II SAR to address PacifiCorp’s
objections regarding generation levels.

Holland Board of Public Works

No

It is essential that regional entities and NERC recognize that “facilities used in the
local distribution of electric energy” are not included in the definition of BES,
regardless of the gross individual or gross aggregate nameplate rating of generation
resources. While the addition of the second sentence in the core definition makes
this clarification, Holland BPW believes it is necessary that regional entities and NERC
recognize that neither this Inclusion nor any of the Inclusions may be used as a basis
to compel registration and compliance in such instances, regardless of the size of the
generators. The statutory exemption of facilities used in the local distribution of
electric energy is not limited by generator number or capability. NERC’s definitions
cannot impose limitations that are not set forth in the statute. For purposes of the
exclusion of facilities that might otherwise meet the definition of BES, the thresholds
for determining what generating resources constitute BES facilities should be
modified from the current levels (gross individual nameplate capacity of 20 MVA or
gross aggregate nameplate rating of 75 MVA). Holland BPW supports modification of
the thresholds to not less than 100 MVA (gross individual nameplate capacity) and
300 MVA (gross aggregate nameplate).

Hydro One Networks Inc.

No

We do not agree with the thresholds of 20 MVA for a single unit and 75 MVA
aggregate at a plant, carried forward from the compliance registry. We understand
the suggested phased approach and expect that the issue will be dealt with at that
future time. With the exception of units that are must runs for reliability reasons, we
suggest that the SDT should consider units smaller than 75 MVA or x MVA is
designated as BES support element and not BES element. These units should only be
required to comply with a handful of relevant NERC Standards. For example, o
Voltage and frequency ride through capability o Voltage control (AVR, etc.) o
Underfrequency trip setting o Protection relay setting coordination o Data
submission for modeling; verification of capability and model These smaller and
geographically dispersed generating resources should neither be designated as BES
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element nor be required to have its connection path be designated as BES. We
suggest removing the parentheses enclosing the text “with gross individual...” since
their inclusion may lead to an erroneous reading of provision to include generators
that do not meet ERO Statement of Compliance Registry Criteria.

Response: The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values. No change
made.
Ontario Power Generation Inc.

No

OPG does not agree that the question of the 20 MVA (single) versus 75 MVA
(aggregate) threshold should be deferred until a subsequent phase of the standard
development process ("Phase 2"). This question should be resolved now. In general,
key elements of the development process should not be parsed out into multiple
phases, in hopes that "Standard Development Fatigue" will eliminate critics of the
approach.
Further, selecting the generator terminals as the boundary for BES within the
generating station means that the Isolated Phase Bus (IPB), which connects the
generator terminals to the Low Voltage (LV) terminals of the generator step-up (GSU)
transformer, is now included as a BES element. The IPB is operated at low voltage, no
more than 22kV, so including it as a BES element is going beyond the FERC order 743
and 743a. OPG strongly recommends that the BES boundary be moved to the LV
terminals of the GSU transformer.
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Response: The SDT acknowledges and appreciates your perspective and frustration. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values. No change
made.
The I2 inclusion refers to generation“… including the generator terminals through the high-side of the step-up transformer(s)
connected at a voltage of 100 kV or above. Comments received regarding the threshold level for generators, the relationship
between the NERC Compliance Registry and the BES Definition and the need for contiguous BES elements will be considered in
the Phase 2 review.
Chevron U.S.A. Inc.

No

It is not logical to allow an aggregate of 75 MVA at a single site for multiple
generators while maintaining 20 MVA for a single generator.
Further, if a party exceeds export of 75 MVA to meet an emergency condition on the
grid, it should not be a triggering event for BES definition. Parties should be
concerned with keeping the grid operational rather than the adverse effect of
exceeding 75 MVA.

Response: The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
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System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values. No change
made.
Please see the detailed responses to Q9.
Massachusetts Department of
Public Utilities

No

Failing to establish a known MVA rating at this stage is problematic. The BES
definition cannot be considered in a vacuum, and adjusting or establishing thresholds
such as MVA ratings will create regulatory uncertainty and may result in additional
costs and unnecessary system upgrades.
Additionally, Inclusion I2 should remove the reference to the Statement of
Compliance Registry Criteria. The definition should be the governing document
regarding generation that is included in the BES.

NESCOE

No

Failing to establish a known MVA rating at this stage is problematic. The BES
definition cannot be considered in a vacuum, and adjusting or establishing thresholds
such as MVA ratings will create regulatory uncertainty and may result in additional
costs and unnecessary system upgrades.
Additionally, Inclusion I2 should remove the reference to the Statement of
Compliance Registry Criteria. The definition should be the governing document
regarding generation that is included in the BES.

Northern Wasco County PUD

No

Referencing the Criteria which in turn references the BES definition creates a circular
definition. Northern Wasco County PUD encourages the adoption of specific
thresholds that are technically justified. We also note that the Criteria and its
revisions do not go through the standards development process, so that thresholds
may change with little warning and without triggering an implementation plan for
facilities that may be swept into the BES as a result.

Central Lincoln

No

Referencing the Criteria which in turn references the BES definition creates a circular
definition. Central Lincoln encourages the adoption of specific thresholds that are
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technically justified. We also note that the Criteria and its revisions do not go through
the standards development process, so that thresholds may change with little
warning and without triggering an implementation plan for facilities that may be
swept into the BES as a result.

Tillamook PUD

No

Referencing the Criteria which in turn references the BES definition creates a circular
definition. Tillamook PUD encourages the adoption of specific thresholds that are
technically justified. We also note that the Criteria and its revisions do not go through
the standards development process, so that thresholds may change with little
warning and without triggering an implementation plan for facilities that may be
swept into the BES as a result.

Mission Valley Power

No

Mission Valley Power - Referencing the Criteria which in turn references the BES
definition creates a circular definition.
Mission Valley Power encourages the adoption of specific thresholds that are
technically justified. We also note that the Criteria and its revisions do not go through
the standards development process, so that thresholds may change with little
warning and without triggering an implementation plan for facilities that may be
swept into the BES as a result.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion
I2, instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being
changed and thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications
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that would warrant a change from the current values that exist through the application of the definition today. These and
similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will
allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the
threshold values and provide compelling justification for modifications to the existing values.
City of Austin dba Austin
Energy

No

We recommend removing the reference of the ERO Statement of Compliance
Registry Criteria (Registry Criteria). The BES Definition should be the governing
document and independent of ERO registration requirements. The definition should
drive what appears in the Registry Criteria.
Additionally, we support using the BES Phase 2 technical analysis to identify and
provide technical support for determining the appropriate minimum MVA rating that
a single unit, or the aggregation of multiple units, must meet to be part of the BES.

The Dow Chemical Company

No

Comments: Dow agrees with the proposed revisions to Inclusion I2, particularly the
proposal to expressly reference the ERO Statement of Compliance Registry Criteria,
but the following phrase should be added at the end “unless excluded under
Exclusion E2”.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2,
instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and
thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project due to numerous comments
received.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.

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Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer,
circuit breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application
of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific
criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The
exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied
in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
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include or exclude an Element.
LCRA Transmission Services
Corporation

No

Response: Without a specific comment the SDT is unable to respond.
Kansas City Power and Light
Company

No

Nameplate rating of the generator is not a reflection of what can be actually injected
into the transmission system with resulting electrical impacts on transmission loading
and behavior. Recommend the BES definition be based on a generators established
net accredited generating capacity instead of what it could do by nameplate rating.
In addition, many generators do not achieve their nameplate rating due to limitations
imposed by the limitations and capabilities of their turbine/boiler capabilities. Using
the nameplate rating will not allow the exclusion of some generators that should be
excluded. Recommend the following language: Generating resource(s) with a net
accredited capability per the ERO Statement of Compliance Registry Criteria and
including the generator terminals through the high-side of the step-up
transformer(s), connected at a voltage of 100 kV or above.

Response: For Phase 1, the SDT has used nameplate rating in order to maintain consistency with the ERO Statement of
Compliance Registry Criteria. No change made.
The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications
that would warrant a change from the current values that exist through the application of the definition today. These and similar
issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
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and provide compelling justification for modifications to the existing values.
Ameren

No

a) This definition becomes dependent on a document that can be changed without
direct correlation to the BES definition. Remove the reference to the ERO
Statement of Compliance Registry Criteria, and simply state the criteria as
currently used. There is no need to look up another definition in another
document to identify what is included in the BES definition.
b) All MOD Standards' requirements for generators should also follow this
definition.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2,
instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and
thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
b) Coordination between the BES Definition and the MOD Standards will be addressed in Phase 2.
Tacoma Power

Yes

Tacoma Power generally supports Inclusion I2 and deferring the appropriate
quantitative thresholds to those that will be determined in Phase 2. However, the
term “gross individual” and “gross aggregate” nameplate rating, although industry
used terms, are not industry defined or uniformly understood and applied.
Nameplate ratings are determined from discussions and negotiations between the
designer, supplier and the owner and it is the owner that makes the final
determination of the generating station equipment nameplate ratings. Nameplate
ratings for thermal or hydro plants may be based on such things as: fuel mix (best,
worst and average), fuel delivery capacity, reservoir level, best efficiency point,
normal operating point, ancillary equipment capacities, emissions and discharge
restrictions, continuous versus peak output and designed versus installed and tested
capacities. It would be more uniform to establish new or use existing criteria to
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define “gross individual” and “gross aggregate” nameplate ratings, such as that used
in the Code of Federal Regulations CFR 18, Part 11.1, “Authorized Installed Capacity”
for hydraulic units and CFR 18, Part 287.101, “Determination of Powerplant Design
Capacity” for steam electric, combustion turbine and combined cycle units.

Response: For Phase 1, the SDT has used nameplate rating in order to maintain consistency with the ERO Statement of
Compliance Registry Criteria. No change made.
The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications
that would warrant a change from the current values that exist through the application of the definition today. These and similar
issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
Hydro-Quebec TransEnergie

We believe that automatic inclusion of such generation and the path to connect them
to the BES would bring a great amount of facilities in the BES. Generation should be
considered on a different level such as "BES Support Elements" and provisions should
be made so that some specific reliability standards would apply to them.

Response: The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
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technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values. No change made.
Snohomish County PUD
Kootenai Electric Cooperative

Yes

SNPD supports the changes made in Inclusion 2 and believe that the definition in its
current form adds clarity. In particular, we support the SDT’s decision to collapse
Inclusions 2 and 3 from the previous draft definition into a single Inclusion that
addresses the treatment of generation for purposes of the BES definition. We also
support the SDT’s proposal for a Phase 2 of the BES Definition process to examine the
technical justification for these thresholds and to establish new thresholds based on a
careful technical analysis. It is our understanding that the generator threshold issue
will be vetted through the complete standards development process. We agree with
this approach because if the generator threshold is treated as merely an element of
NERC’s Rules of Procedure, it can be changed with considerably less due process and
industry input than the Standards Development Process. Compare NERC Rules of
Procedure § 1400 (providing for changes to Rules of Procedure upon approval of the
NERC board and FERC) with NERC Standards Process Manual (Sept. 3, 2010)
(providing for, e.g., posting of SDT proposals for comment, successive balloting, and
super-majority approval requirements). See also Order No. 743-A, 134 FERC ¶
61,210 at P 4 (2011) (“Order No. 743 directed the ERO to revise the definition of ‘bulk
electric system’ through the NERC Standards Development Process” (emph. added)).
Addressing all aspects of Phase 2 through the Standards Development Process will
improve the content of the definition by bringing to bear industry expertise on all
aspects of the definition and will ensure that, once firm guidelines are established,
they can be relied upon by both industry and regulators without threat that they will
be changed with little notice and little due process. SNPD also believes further
clarification of the proposed language would be appropriate. The SDT proposes
continued reliance upon the thresholds that are used in the NERC Statement of
Compliance Registry Criteria for registration of Generation Owners and Generation
Operators, which is currently 20 MVA for an individual generation unit and 75 MVA
for multiple units on a single site. Conceptually, we are concerned about this
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approach because, as we understand it, the purpose of the Compliance Registry is to
sweep in all generators that might be material to the reliable operation of the BES,
and not to definitively determine whether a given generator is, in fact, material to the
reliable operation of the BES. As the SCRC itself states, the SCRC is intended only to
identify “candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly,
we believe that the generator threshold determined in Phase 2 should be
incorporated directly into the BES Definition rather than being incorporated by
reference from the SCRC.We also believe that the specific language proposed by the
SDT could be further clarified. The SDT proposes to include generation in the BES if
the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder
for the results of the technical analysis that would occur in Phase 2 but we believe
simply stating that the threshold will be “per the ERO Statement of Compliance
Registry” is ambiguous. Further, for the reasons noted above, we believe the
threshold should be part of the BES Definition, and should not simply be a crossreference to the SCRC (and, given the different purposes of the BES Definition and
the SCRC, it is not clear that the same threshold should be used in both). We
therefore propose that Inclusion 2 be rewritten to state: “Qualifying Individual
Generation Resources or Qualifying Aggregate Resources connected at a voltage of
100 kV or above.” Two definitions would then be added to the note at the end of the
definition to read as follows:"For purposes of this BES Definition, Qualifying Individual
Generation Resources means an individual generating unit that meets the materiality
threshold to be included in this definition or, in the absence of such a materiality
threshold, that meets the gross nameplate capacity voltage threshold requiring
registration of the owner of such a resource as a Generation Owner under the ERO
Statement of Compliance Registry Criteria.""For purposes of this BES Definition,
Qualifying Aggregate Generation Resources means any facility consisting of one or
more generating units that are connected at a common bus that meets the
materiality threshold to be included in this definition, or, in the absence of such a
threshold, that meets the gross nameplate capacity voltage threshold requiring
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registration of the owner of multiple-unit generator as a Generation Owner under the
ERO Statement of Compliance Registry Criteria."The “materiality threshold” is
intended to refer to the generator threshold developed in Phase 2. We suggest using
definitions in this fashion for several reasons. First, we believe the language we
suggest more clearly states the intention of the SDT, which we understand is to
classify generation units as part of the BES if they are necessary for operation of the
BES, but to exclude smaller generating units because they are not material to the
operation of the interconnected transmission grid. Second, we believe use of the
defined terms better reflects the intention of the SDT to reserve the specific question
about generator thresholds to the technical analysis that will occur in Phase 2
without having to revise the BES Definition at the end of that process. That is, the
definitions are designed to allow the SDT to include revised thresholds in the
definition at the conclusion of the Phase 2 process based upon the technical analysis
planned for Phase 2, and the revised thresholds will be automatically incorporated
into the BES Definition if the language we suggest is used. The thresholds used in the
SCRC would only be a fall-back, to be used only until Phase 2 is completed.Third, the
definitions can be incorporated into other parts of the BES Definition, which will add
consistency and clarity. As noted in our answers to several of the questions below,
the specific 75 MVA threshold is retained in several of the Exclusions and Inclusions,
and we believe the industry would be better served if the revised thresholds arrived
at after technical analysis in Phase 2 are automatically incorporated into all relevant
provisions of the BES Definition. There is no reason for the SDT to continue to rely on
the 75 MVA threshold once the analysis planned for Phase 2 on the threshold issue is
completed. Fourth, the phrase “or that meets the materiality threshold to be
included in this definition” is intended to preserve the SDT’s flexibility to make a
determination that generators below a specific threshold are not “necessary to”
maintain the reliability of the interconnected transmission system, and to incorporate
that finding as part of the definition itself, even if a different threshold is used in the
SCRC to identify potential candidates for registration. Accordingly, our proposed
language makes clear that a specific threshold in the definition controls over any
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threshold that might be included in the SCRC. For the reasons stated above, we
believe is it highly desirable to include any material threshold in the BES Definition
itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Hence, we agree with the SDT’s
decision to examine the question of where the line between BES and non-BES
Elements should be drawn more closely in Phase 2 under the rubric of “contiguous vs.
non-contiguous BES,” and commend the work of the Project 2010-07 Standards
Drafting Team and the GO-TO Team as a good starting point for the SDT’s analysis on
this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities
interconnecting such generators to be part of the BES. As discussed more fully in our
answer to Question 9, based on extensive technical analysis that has already been
performed by the NERC Project 2010-07 Standards Drafting Team and its
predecessor, the NERC “GO-TO Team,” regulating as part of the BES a dedicated
interconnection facility connecting a BES generator to the interconnected bulk
transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no
improvement in bulk system reliability. We also believe the clauses at the end of
Inclusion 2 are somewhat confusing and that greater clarity would be achieved by
changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above” so that the Inclusion
covers transformers with terminals “connected at a voltage of 100 kV or above,
including the generator terminal(s) on the high side of the step-up transformer(s) if
operated at a voltage of 100 kV or above.”
Finally, as discussed further in our answer to Questions 5 and 6, SNPD believes more
clarity may be achieved by collapsing Inclusion 5, addressing Reactive Power
resources, and Inclusion 4, which addresses dispersed renewable resources, into a
single Inclusion that addresses “power producing resources” (the language used in
current Inclusion 4).

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Response: Thank you – the SDT acknowledges and appreciates your comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT
has responsibilities associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in
regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of
strong technical justifications that would warrant a change from the current values that exist through the application of the
definition today. These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT
to address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all
recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17
Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for modifications to the
existing values.
The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2, instead
specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and thus
affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Please see detailed responses to Q5 and Q6.
Independent Electricity
System Operator

Yes

While we agree with Inclusion I2, we suggest removing the parentheses enclosing the
text “with gross individual...” since their inclusion may lead to an erroneous reading
of provision to include generators that do not meet ERO Statement of Compliance
Registry Criteria.

Puget Sound Energy

Yes

The term "per" should be replaced by "greater than the levels specified for a
Generator Owner/Operator in". For a definition of this importance, the term "per" is
too vague.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2,
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instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed
and thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)
Central Electric Cooperatve
(CEC)
Clearwater Power Company
(CPC)
Consumer's Power Inc.
Douglas Electric Cooperative
(DEC)
Fall River Rural Electric
Cooperative (FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric

Yes

CLPD supports the changes made in Inclusion 2 and believe that the definition in its
current form adds clarity. In particular, we support the SDT’s decision to collapse
Inclusions 2 and 3 from the previous draft definition into a single Inclusion that
addresses the treatment of generation for purposes of the BES definition. We also
support that aspect of the SDT’s proposal for a Phase 2 of the BES Definition process
that would examine the technical justification for these thresholds and that would
establish new thresholds based on a careful technical analysis. It is our
understanding that the generator threshold issue will be vetted through the
complete standards development process. We agree with this approach becauseif
the generator threshold is treated as merely an element of NERC’s Rules of
Procedure, it can be changed with considerably less due process and industry input
than the Standards Development Process. Compare NERC Rules of Procedure §
1400 (providing for changes to Rules of Procedure upon approval of the NERC board
and FERC) with NERC Standards Process Manual (Sept. 3, 2010) (providing for, e.g.,
posting of SDT proposals for comment, successive balloting, and super-majority
approval requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011)
(“Order No. 743 directed the ERO to revise the definition of ‘bulk electric system’
through the NERC Standards Development Process” (emph. added)). Addressing all
aspects of Phase 2 through the Standards Development Process will improve the
content of the definition by bringing to bear industry expertise on all aspects of the
definition and will ensure that, once firm guidelines are established, they can be
relied upon by both industry and regulators without threat that they will be changed
with little notice and little due process.CLPD believes further clarification of the
proposed language would be appropriate. The SDT proposes continued reliance
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Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric Cooperative
(UEC)

Yes or No

Question 3 Comment
upon the thresholds that are used in the NERC Statement of Compliance Registry
Criteria for registration of Generation Owners and Generation Operators, which is
currently 20 MVA for an individual generation unit and 75 MVA for multiple units on
a single site. as we understand it, the purpose of the Compliance Registry is to sweep
in all generators that might be material to the reliable operation of the BES, and not
to definitively determine whether a given generator is, in fact, material to the reliable
operation of the BES. As the SCRC itself states, the SCRC is intended only to identify
“candidates for registration.” SCRC at p.3, § 1 (emph. added). Accordingly, we
believe that the generator threshold determined in Phase 2 should be incorporated
directly into the BES Definition rather than being incorporated by reference from the
SCRC.We also believe that the specific language proposed by the SDT could be further
clarified. The SDT proposes that generation be included in the BES if the “Generation
resource(s)” has a “nameplate rating per the ERO Statement of Compliance Registry.”
We understand this language is intended to be a placeholder for the results of the
technical analysis that would occur in Phase 2 but we believe simply stating that the
threshold will be “per the ERO Statement of Compliance Registry” is ambiguous.
Further, for the reasons noted above, we believe the threshold should be part of the
BES Definition, and should not simply be a cross-reference to the SCRC (and, given
the different purposes of the BES Definition and the SCRC, it is not clear that the
same threshold should be used in both). We therefore propose that Inclusion 2 be
rewritten to state: “Qualifying Individual Generation Resources or Qualifying
Aggregate Resources connected at a voltage of 100 kV or above.” Two definitions
would then be added to the note at the end of the definition to read as follows:For
purposes of this BES Definition, Qualifying Individual Generation Resources means an
individual generating unit that meets the materiality threshold to be included in this
definition or, in the absence of such a materiality threshold, that meets the gross
nameplate capacity voltage threshold requiring registration of the owner of such a
resource as a Generation Owner under the ERO Statement of Compliance Registry
Criteria.For purposes of this BES Definition, Qualifying Aggregate Generation
Resources means any facility consisting of one or more generating unitsthat are
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Question 3 Comment
connected at a common bus that meets the materiality threshold to be included in
this definition, or, in the absence of such a threshold, that meets the gross nameplate
capacity voltage threshold requiring registration of the owner of multiple-unit
generator as a Generation Owner under the ERO Statement of Compliance
RegistryCriteria..The “materiality threshold” is intended to refer to the generator
threshold developed in Phase 2. We suggest using definitions in this fashion for
several reasons. First, we believe the language we suggest more clearly states the
intention of the SDT, which we understand is to classify generation units as part of
the BES if they are necessary for operation of the BES, but to exclude smaller
generating units because they are not material to the operation of the
interconnected transmission grid. Second, we believe use of the defined terms
better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase 2 without
having to revise the BES Definition at the end of that process. That is, the definitions
are designed to allow the SDT to include revised thresholds in the definition at the
conclusion of the Phase 2 process based upon the technical analysis planned for
Phase 2, and the revised thresholds will be automatically incorporated into the BES
Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase 2 is completed.Third, the definitions
can be incorporated into other parts of the BES Definition, which will add consistency
and clarity. As noted in our answers to several of the questions below, the specific 75
MVA threshold is retained in several of the Exclusions and Inclusions, and we believe
the industry would be better served if the revised thresholds arrived at after
technical analysis in Phase 2 are automatically incorporated into all relevant
provisions of the BES Definition. There is no reason for the SDT to continue to rely on
the 75 MVA threshold once the analysis planned for Phase 2 on the threshold issue is
completed. Fourth, the phrase “or that meets the materiality threshold to be
included in this definition” is intended to preserve the SDT’s flexibility to make a
determination that generators below a specific threshold are not “necessary to”
maintain the reliability of the interconnected transmission system, and to incorporate
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Question 3 Comment
that finding as part of the definition itself, even if a different threshold is used in the
SCRC to identify potential candidates for registration. Accordingly, our proposed
language makes clear that a specific threshold in the definition controls over any
threshold that might be included in the SCRC. For the reasons stated above, we
believe is it highly desirable to include any material threshold in the BES Definition
itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard. Finally, we agree with the SDT’s
decision to examine the question of where the line between BES and non-BES
Elements should be drawn more closely in Phase 2 under the rubric of “contiguous vs.
non-contiguous BES,” and commend the work of the Project 2010-07 Standards
Drafting Team and the GO-TO Team as a good starting point for the SDT’s analysis on
this issue. We understand Inclusion 2 would classify generators exceeding specific
thresholds as part of the BES, but would not necessarily require facilities
interconnecting such generators to be part of the BES. As discussed more fully in our
answer to Question 9, based on extensive technical analysis that has already been
performed by the NERC Project 2010-07 Standards Drafting Team and its
predecessor, the NERC “GO-TO Team,” regulating as part of the BES a dedicated
interconnection facility connecting a BES generator to the interconnected bulk
transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no
improvement in bulk system reliability. We also believe the clauses at the end of
Inclusion 2 are somewhat confusing and that greater clarity would be achieved by
changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above” so that the Inclusion
covers transformers with terminals “connected at a voltage of 100 kV or above,
including the generator terminal(s) on the high side of the step-up transformer(s) if
operated at a voltage of 100 kV or above.”

Response: The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
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deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values.
The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2, instead
specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and thus
affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Southern Company
Generation

Yes

Yes, provided that the minimum gross individual nameplate rating threshold is the
same as the gross aggregate nameplate rating (currently > 75MVA).
The MVA ratings are specified in many places in the BES definition, where a reference
is made in I2 to using the Statement of Compliance Registry Criteria. We believe that
the BES definition should point to the Statement of Compliance Registry Criteria and
not include MVA values.
We also believe individual units < 75MVA should be excluded unless they have been
shown to be critical to BES reliability through a technical justification study
performed by the transmission planning authority.

Michigan Public Power Agency

Yes

MPPA supports the changes made in Inclusion 2 and believe that the definition in its
current form adds clarity. In particular, we support the SDT’s decision to collapse
Inclusions 2 and 3 from the previous draft definition into a single Inclusion that
addresses the treatment of generation for purposes of the BES definition. MPPA also
supports the SDT’s proposal for a Phase 2 of the BES Definition process that would
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Question 3 Comment
examine the technical justification for these thresholds and that would establish new
thresholds based on a careful technical analysis. It is our understanding that the
generator threshold issue will be vetted through the complete standards
development process. We agree with this approach because if the generator
threshold is treated as merely an element of NERC’s Rules of Procedure, it can be
changed with considerably less due process and industry input than the Standards
Development Process. Compare NERC Rules of Procedure § 1400 (providing for
changes to Rules of Procedure upon approval of the NERC board and FERC) with
NERC Standards Process Manual (Sept. 3, 2010) (providing for, e.g., posting of SDT
proposals for comment, successive balloting, and super-majority approval
requirements). See also Order No. 743-A, 134 FERC ¶ 61,210 at P 4 (2011) (“Order
No. 743 directed the ERO to revise the definition of ‘bulk electric system’ through the
NERC Standards Development Process” (emph. added)). Addressing all aspects of
Phase 2 through the Standards Development Process will improve the content of the
definition by bringing to bear industry expertise on all aspects of the definition and
will ensure that, once firm guidelines are established, they can be relied upon by both
industry and regulators without threat that they will be changed with little notice and
little due process. MPPA also believes further clarification of the proposed language
would be appropriate.
The SDT proposes continued reliance upon the thresholds that are used in the NERC
Statement of Compliance Registry Criteria for registration of Generation Owners and
Generation Operators, which is currently 20 MVA for an individual generation unit
and 75 MVA for multiple units on a single site. Conceptually, we are concerned about
this approach because, as we understand it, the purpose of the Compliance Registry
is to sweep in all generators that might be material to the reliable operation of the
BES, and not to definitively determine whether a given generator is, in fact, material
to the reliable operation of the BES. As the SCRC itself states, the SCRC is intended
only to identify “candidates for registration.” SCRC at p.3, § 1 (emph. added).
Accordingly, we believe that the generator threshold determined in Phase 2 should
be incorporated directly into the BES Definition rather than being incorporated by
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Yes or No

Question 3 Comment
reference from the SCRC. We also believe that the specific language proposed by the
SDT could be further clarified. The SDT proposes to include generation in the BES if
the “Generation resource(s)” has a “nameplate rating per the ERO Statement of
Compliance Registry.” We understand this language is intended to be a placeholder
for the results of the technical analysis that would occur in Phase 2 but we believe
simply stating that the threshold will be “per the ERO Statement of Compliance
Registry” is ambiguous. Further, for the reasons noted above, we believe the
threshold should be part of the BES Definition, and should not simply be a crossreference to the SCRC (and, given the different purposes of the BES Definition and
the SCRC, it is not clear that the same threshold should be used in both). We
therefore propose that Inclusion 2 be rewritten to state: “Qualifying Individual
Generation Resources or Qualifying Aggregate Resources connected at a voltage of
100 kV or above.”
Two definitions would then be added to the note at the end of the definition to read
as follows: For purposes of this BES Definition, Qualifying Individual Generation
Resources means an individual generating unit that meets the materiality threshold
to be included in this definition or, in the absence of such a materiality threshold,
that meets the gross nameplate capacity voltage threshold requiring registration of
the owner of such a resource as a Generation Owner under the ERO Statement of
Compliance Registry Criteria. For purposes of this BES Definition, Qualifying
Aggregate Generation Resources means any facility consisting of one or more
generating units that are connected at a common bus that meets the materiality
threshold to be included in this definition, or, in the absence of such a threshold, that
meets the gross nameplate capacity voltage threshold requiring registration of the
owner of multiple-unit generator as a Generation Owner under the ERO Statement of
Compliance Registry Criteria..The “materiality threshold” is intended to refer to the
generator threshold developed in Phase 2. We suggest using definitions in this
fashion for several reasons. First, we believe the language we suggest more clearly
states the intention of the SDT, which we understand is to classify generation units as
part of the BES if they are necessary for operation of the BES, but to exclude smaller
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Question 3 Comment
generating units because they are not material to the operation of the
interconnected transmission grid. Second, we believe use of the defined terms
better reflects the intention of the SDT to reserve the specific question about
generator thresholds to the technical analysis that will occur in Phase 2 without
having to revise the BES Definition at the end of that process. That is, the definitions
are designed to allow the SDT to include revised thresholds in the definition at the
conclusion of the Phase 2 process based upon the technical analysis planned for
Phase 2, and the revised thresholds will be automatically incorporated into the BES
Definition if the language we suggest is used. The thresholds used in the SCRC would
only be a fall-back, to be used only until Phase 2 is completed. Third, the definitions
can be incorporated into other parts of the BES Definition, which will add consistency
and clarity. As noted in our answers to several of the questions below, the specific 75
MVA threshold is retained in several of the Exclusions and Inclusions, and we believe
the industry would be better served if the revised thresholds arrived at after
technical analysis in Phase 2 are automatically incorporated into all relevant
provisions of the BES Definition. There is no reason for the SDT to continue to rely on
the 75 MVA threshold once the analysis planned for Phase 2 on the threshold issue is
completed. Fourth, the phrase “or that meets the materiality threshold to be
included in this definition” is intended to preserve the SDT’s flexibility to make a
determination that generators below a specific threshold are not “necessary to”
maintain the reliability of the interconnected transmission system, and to incorporate
that finding as part of the definition itself, even if a different threshold is used in the
SCRC to identify potential candidates for registration. Accordingly, our proposed
language makes clear that a specific threshold in the definition controls over any
threshold that might be included in the SCRC. For the reasons stated above, we
believe is it highly desirable to include any material threshold in the BES Definition
itself rather than relegating the threshold to the SCRC, which is merely a procedural
rule rather than a full-fledged Reliability Standard.
Finally, we agree with the SDT’s decision to examine the question of where the line
between BES and non-BES Elements should be drawn more closely in Phase 2 under
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Question 3 Comment
the rubric of “contiguous vs. non-contiguous BES,” and commend the work of the
Project 2010-07 Standards Drafting Team and the GO-TO Team as a good starting
point for the SDT’s analysis on this issue. We understand Inclusion 2 would classify
generators exceeding specific thresholds as part of the BES, but would not necessarily
require facilities interconnecting such generators to be part of the BES. As discussed
more fully in our answer to Question 9, based on extensive technical analysis that has
already been performed by the NERC Project 2010-07 Standards Drafting Team and
its predecessor, the NERC “GO-TO Team,” regulating as part of the BES a dedicated
interconnection facility connecting a BES generator to the interconnected bulk
transmission grid will result in an unnecessary regulatory burden that produces
considerable expense for the owner of the interconnection facility with little or no
improvement in bulk system reliability. We also believe the clauses at the end of
Inclusion 2 are somewhat confusing and that greater clarity would be achieved by
changing “. . . including the generator terminals through the high-side of the step-up
transformer(s) connected at a voltage of 100 kV or above” so that the Inclusion
covers transformers with terminals “connected at a voltage of 100 kV or above,
including the generator terminal(s) on the high side of the step-up transformer(s) if
operated at a voltage of 100 kV or above.”
MPPA and its members believe it is essential that regional entities and NERC
recognize that “facilities used in the local distribution of electric energy” are not
included in the definition of BES, regardless of the gross individual or gross aggregate
nameplate rating of generation resources. While the addition of the second sentence
in the core definition makes this clarification, MPPA and its members believes it is
necessary that regional entities and NERC recognize that neither this Inclusion nor
any of the Inclusions may be used as a basis to compel registration and compliance in
such instances, regardless of the size of the generators. The statutory exemption of
facilities used in the local distribution of electric energy is not limited by generator
number or capacity. NERC’s definitions cannot impose limitations that are not set
forth in the statute. For purposes of the exclusion of facilities that might otherwise
meet the definition of BES, the thresholds for determining what generating resources
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Question 3 Comment
constitute BES facilities should be modified from the current levels (gross individual
nameplate capacity of 20 MVA or gross aggregate nameplate rating of 75 MVA).
MPPA and its members would support modification of the thresholds to not less than
100 MVA (gross individual capacity) and 300 MVA (gross aggregate nameplate).

Response: The SDT acknowledges and appreciates your comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values.
The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2, instead
specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed and thus
affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Texas Industrial Energy
Consumers

Yes

The interplay between Inclusion I2, which references the Statement of Registry
Compliance, and Exclusions E1-E3 is unclear. Under the Registry criteria, “a
customer-owned or operated generator/generation that serves all or part of retail
load with electric energy on the customer’s side of the retail meter may be excluded
as a candidate for registration ... if (i) the net capacity provided to the bulk power
system does not exceed the criteria above.” It appears that the SDT intended to
invoke this provision by referencing the Statement of Registry Compliance, which
counts only the “net” capacity provided, by referencing the Statement of Compliance
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Question 3 Comment
Registry Criteria. However, Exclusions E1 and E3 exclude generation on the basis of
“gross nameplate ratings.” For customer-owned facilities, this treatment is
inconsistent with netting treatment provided in the Statement of Registry
Compliance. Exclusions E1-E3 should be revised to reference the Statement of
Compliance Registry Criteria as well so that customer-owned generation is included
or excluded based on its net capacity to the grid rather than its gross nameplate
capacity.
TIEC also supports revisiting and potentially raising the thresholds that trigger
registration as a Generation Owner or Operator. TIEC understands that the SDT has
decided to maintain the status quo as reflected in NERC’s Registry Criteria at this
time. TIEC looks forward to addressing potential modifications to the thresholds in
the appropriate context.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer,
circuit breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application
of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific
criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
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Question 3 Comment

Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The
exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied
in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude an
Element.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects
(i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being
responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012,
and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a
change from the current values that exist through the application of the definition today. These and similar issues have prompted the
SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory
authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for
inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC
Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide compelling
justification for modifications to the existing values.
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,

Yes

The word “identified” should be replaced with “designated”.

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Question 3 Comment

MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power
Cooperative
Response: The SDT believes this comment was intended for Q4 and directs you to the detailed response provided there.
Dominion

Yes

Dominion interprets the revised language to exclude generating resources connected
at less than 100 kV. If this interpretation is not accurate, then Dominion does not
support the revised language.

Response: The I2 inclusion refers only to generation “ … through the high-side of the step-up transformer(s) connected at a voltage
of 100 kV or above.”
Transmission Access Policy
Study Group

Yes

TAPS supports the intent of proposed Inclusion I2. For the sake of clarity, we suggest
revising “per the ERO Statement of Compliance Registry Criteria” to “as described in
the ERO Statement of Compliance Registry Criteria.”

ACES Power Marketing
Standards Collaborators

Yes

We’d prefer to see the language from the ERO Statement of Compliance Registry
Criteria repeated within the BES Definition itself instead of referencing an outside
document. As it stands right now, the Compliance Registry Criteria needs to stay
intact for Phase 1 of this project. That makes the Compliance Registry Criteria reliant
on the BES Definition and vice versa. We understand that the Statement of
Compliance Registry Criteria may be reviewed/revised at the same time Phase 2 of
this project is being developed, therefore we agree with Inclusion I2 of this draft.

Response: The SDT made a clarifying change removing the ERO Statement of Compliance Registry Criteria reference in Inclusion I2,
instead specifying the 20/75 MVA reference threshold values in order to avoid the possibility of the registry values being changed
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Question 3 Comment

and thus affecting the BES Definition prior to the resolution of the threshold values in Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Florida Municipal Power
Agency

Yes

Please see comments to Question 1

Response: Please see response to Q1.
Redding Electric Utility

Yes

Redding believes that the definition should drive what appears in the Registry
Criteria, therefore we only support this on a temporary basis based on the premise
that the BES Phase 2 technical analysis will identify and provide technical support for
determining the appropriate minimum MVA rating for a single unit or the aggregation
of multiple units.

City of Redding

Yes

Redding believes that the definition should drive what appears in the Registry
Criteria, therefore we only support this on a temporary basis based on the premise
that the BES Phase 2 technical analysis will identify and provide technical support for
determining the appropriate minimum MVA rating for a single unit or the aggregation
of multiple units.

MEAG Power

Yes

We agree in general with the revisions to I2 for generation; however, we maintain
that 200kV and above is the correct bright line for the Bulk Electric System.

Tennessee Valley Authority

Yes

TVA agrees in general with the revisions to I2 for generation; however, we maintain
that 200kV and above is the correct bright line for generation connected to the Bulk
Electric System, and requests that the Phase 2 for the project use 200kV and above or
develop a transmission voltage and/or an MVA threshold that is technically based.

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Question 3 Comment

SERC Planning Standards
Subcommittee

Yes

We are concerned that the generator MVA limits are too low and strongly support
addressing this issue in Phase 2 of this project.

NERC Staff Technical Review

Yes

The drafting team’s proposed approach for Inclusion I2 (generation), including the
reference to the ERO Statement of Compliance Registry Criteria, is generally
acceptable given the scope of this project and the breaking of the project into two
phases. Thresholds for generator MVA rating and interconnection voltage should be
considered in the second phase of this project.

SERC OC Standards Review
Group

Yes

We agree in general with the revisions to I2 for generation; however, we maintain
that 200kV and above is the correct bright line for the Bulk Electric System.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values. No change made.
ATC LLC

Yes

Westar Energy

Yes

Portland General Electric
Company

Yes

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Yes or No

Georgia System Operations
Corporation

Yes

Oncor Electric Delivery
Company LLC

Yes

National Grid

Yes

Cowlitz County PUD

Yes

Utility Services, Inc.

Yes

PSEG Services Corp

Yes

ISO New England Inc

Yes

Manitoba Hydro

Yes

Long Island Power Authority

Yes

Z Global Engineering and
Energy Solutions

Yes

Consumers Energy

Yes

Metropolitan Water District of
Southern California

Yes

Duke Energy

Yes

Question 3 Comment

Cowlitz also strongly supports Phase 2 to address the lack of technical justification of
the MVA bright line criteria.

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Yes or No

Central Hudson Gas and
Electric Corporation

Yes

City of Anaheim

Yes

ReliabilityFirst

Yes

Southern Company

Yes

FirstEnergy Corp.

Yes

Exelon

Yes

Western Area Power
Administration

Yes

IRC Standards Review
Committee

Yes

WECC Staff

Yes

Bonneville Power
Administration

Yes

Southwest Power Pool
Standards Review Team

Yes

BGE

Yes

Question 3 Comment

BPA agrees with the I2 changes and feels that they are excellent.

No comment.

Response: Thank you for your support. However, the SDT made a clarifying change removing the ERO Statement of Compliance
Registry Criteria reference in Inclusion I2, instead specifying the 20/75 MVA reference threshold values in order to avoid the
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Question 3 Comment

possibility of the registry values being changed and thus affecting the BES Definition prior to the resolution of the threshold values in
Phase 2 of this project.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator
terminals through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.

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4.

The SDT has revised the specific inclusions to the core definition in response to industry comments. Do you agree with Inclusion
I3 (blackstart)? If you do not support this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.

Summary Consideration: The directive by FERC to revise the definition of the BES has been interpreted by the SDT to include all
Facilities necessary for reliably operating the interconnected transmission system under both normal and emergency conditions. This
interpretation by the SDT includes situations related to Blackstart Resources and system restoration. Blackstart Resources have the
ability to be started without the support of the interconnected transmission system in order to meet a Transmission Operators
restoration plan requirements for Real and Reactive Power capability, frequency, and voltage control. The SDT maintains that Blackstart
Resources must be included in the definition however their associated Cranking Paths are not included in the BES definition as they can
fall within distribution class levels. Cranking Paths will be discussed further in Phase 2 of this project.
No changes were made to Inclusion I3 from the previous posting.
Organization

Yes or No

Question 4 Comment

SERC OC Standards Review
Group

No

We agree with the changes but believe clarity would be added by changing the word
“identified” to “designated”.

Tennessee Valley Authority

No

TVA agrees with the changes but believe clarity would be added by changing the word
“identified” to “designated”.

Southern Company

No

We agree with the changes but believe clarity would be added by changing the word
“identified” to “designated”.

MEAG Power

No

We agree with the changes but believe clarity would be added by changing the word
“identified” to “designated”.

Response: ‘Identified’ is consistent with the wording in EOP-005-2. The SDT does not feel that this change would add any
additional clarity. No change made.

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Question 4 Comment

Texas Reliability Entity

No

We feel that the Cranking Path should be included in the BES definition. Inclusion of
the Cranking Path is vital to a functional, sustainable and reliable system restoration
(and restoration plan) regardless of where the Cranking Path is located. CIP-002-4
Attachment 1 recognizes the critical nature of the Cranking Path.

NERC Staff Technical Review

No

The cranking path(s) identified in the Transmission Operator’s restoration plan should
be included in the BES definition.

Response: Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system
Elements. The Transmission Operator’s restoration plans identify a number of possible system restoration scenarios to address the
uncertainty of the actual requirements needed to address a particular restoration event including Cranking Paths. Therefore, the SDT
maintains that Cranking Paths are not required to be included in the BES definition as they are essentially a moving target and could
include distribution Elements. The Cranking Paths issue will be discussed anew in Phase 2 of this project. No change made.
NESCOE

No

While NESCOE appreciates that cranking paths were excluded in response to industry
comments, as we stated in comments to the prior posting of the BES definition,
blackstart units should be excluded from the BES. Such units are appropriately
covered under regional restoration procedures and applicable NERC standards (see for
example, Emergency Operating Procedure EOP-005-2). However, should blackstart
units be included in subsequent postings of the definition, we suggest that the
language be revised to state that only those units “material to” the BES are included.

Ontario Power Generation Inc.

No

To assure availability of the generation blackstart resources identified in the
Transmission Operator’s Power System Restoration Plan the generators are tested
according to the requirements of reliability standard EOP-009. Blackstart resources are
only required post LOBES (Loss of Bulk Electric System) and in many cases do not
contribute to the reliability of the BES under normal operating conditions. OPG
recommends that this inclusion be removed from the new definition of BES.

IRC Standards Review

No

We support the SDT’s decision to exclude the cranking paths from the BES definition
since testing and verification of the use of facilities in the cranking path is already
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Committee

Question 4 Comment
covered by the appropriate EOP standards.
This inclusion is extraneous given there is already a designation specific for system
restoration covered by an existing standard to recognize their reliability impacts and
to ensure their expected performance. NERC Standards EOP-005-2 stipulates the
requirements for testing blackstart resource and cranking paths. This testing
requirement suffices to ensure that the facilities critical to system restoration are
functional when needed, which meets the intent of identifying their criticality to
reliability. We therefore suggest removing Inclusion I3.

Hydro One Networks Inc.

No

We agree with the SDT in excluding the cranking paths from the BES definition, a point
we had raised in our comments to the previous posting.
We also disagree with the inclusion of blackstart resources and reiterate our view that
their inclusion is superfluous given there is already a designation specific for system
restoration covered by an existing standard, to recognize their reliability impacts and
to ensure their expected performance. NERC Standard EOP-005-2 stipulates the
requirements for testing blackstart resources and cranking paths. This testing
requirement suffices to ensure that the facilities critical to system restoration are
functional when needed, which meets the intent of identifying their criticality to
reliability. We therefore suggest completely removing Inclusion I3.We suggest the SDT
to drop I3 on the basis that: o The availability and performance expectations of
blackstart resources are ensured by existing related standards; and o Unless they
meet the BES definition under inclusion I2, there is no perceived reliability value in
everyday operation of the BES.

Northeast Power Coordinating
Council

No

Eliminating I3 should be considered based on the availability and performance
expectations of black start resources being ensured by existing standards, and unless
they meet the BES definition under the I2 inclusion they do not have any reliability
impact on BES operation. If I3 is retained, suggest rewording Inclusion I3 to read as
follows: Black start resources material to and designated as part of the Transmission

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Yes or No

Question 4 Comment
Operator’s restoration plan.

Independent Electricity
System Operator

No

We thank the SDT for excluding the cranking paths from the BES definition, a point we
had raised in our comments to the previous posting. However, we had also disagreed
with the inclusion of Blackstart Resources and reiterate our view that their inclusion is
superfluous given there is already a designation specific for system restoration
covered by an existing standard, to recognize their reliability impacts and to ensure
their expected performance. NERC Standards EOP-005-2 stipulates the requirements
for testing blackstart resource and cranking paths. This testing requirement suffices to
ensure that the facilities critical to system restoration are functional when needed,
which meets the intent of identifying their criticality to reliability. We therefore
suggest removing Inclusion I3 entirely.

FirstEnergy Corp.

Yes

We agree with the team's conclusion to remove cranking paths from the BES
definition since NERC (i.e. EOP standards) specifically address reliability matters
associated with cranking paths. Although we believe item I3 (blackstart unit) is
unnecessary as part of the BES Definition, we will not object to its inclusion. A
blackstart unit is a facility necessary for BES restoration, but not necessarily required
to be included within the BES Definition.

Response: The SDT disagrees that Blackstart Resources should not be included in the BES Definition. The Commission directed
NERC to revise its BES definition to ensure that the definition encompasses all facilities necessary for operating an
interconnected electric transmission network. The SDT interprets this to include operation under both normal and emergency
conditions, which includes situations related to black starts and system restoration. Blackstart Resources have the ability to be
started without support from the System or can be energized without connection to the remainder of the System, in order to
meet a Transmission Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage
control. The associated resources of the electric system that can be isolated and then energized to deliver electric power
during a restoration event are essential to enable the startup of one or more other generating units as defined in the
Transmission Operator’s restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in
the Transmission Operator’s restoration plan as BES elements. No change made.
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Organization
ACES Power Marketing
Standards Collaborators

Yes or No

Question 4 Comment

No

Blackstart Resources can actually be on the distribution system. There is still the
question of whether the distribution system would then be subjected to the
enforceable standards. If so, there would most likely be a significant cost increase
associated with tracking compliance for these distribution systems without a
commensurate increase in reliability since Blackstart Resources are rarely used. This
could very well cause entities to un-designate Blackstart Resources on distribution
systems to avoid these distribution systems from becoming part of the BES. The same
rationale that was used for eliminating cranking paths could also be applied to
Blackstart Resources.

Response: Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system
Elements. The Transmission Operator’s restoration plans identify a number of possible system restoration scenarios to address
the uncertainty of the actual requirements needed to address a particular restoration event including Cranking Paths.
Therefore, the SDT maintains that Cranking Paths are not required to be included in the BES definition as they are essentially a
moving target and could include distribution Elements. The Cranking Paths issue will be discussed anew in Phase 2 of this
project. The SDT feels that the situation described would fall within a minimal percentage of units and therefore would be
subject to the Exception Process as applicable. No change made.
ReliabilityFirst

No

Blackstart Resource is a defined NERC term, but as outlined in the definition, it could
be read to include the transmission assets that also make up the resource as part of
the TOP plan. Is that the intent?
ReliabilityFirst Staff also feels that without including the Cranking Paths, the reliable
operation of the system could be jeopardized if a restoration is required and the
Cranking Paths are unavailable due to non-compliance to Reliability Standards.

Response: The SDT does not agree that the definition of Blackstart Resource necessarily encompasses transmission assets. No
change made.
Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system Elements.
The Transmission Operator’s restoration plans identify a number of possible system restoration scenarios to address the
uncertainty of the actual requirements needed to address a particular restoration event including Cranking Paths. Therefore,
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Question 4 Comment

the SDT maintains that Cranking Paths are not required to be included in the BES definition as they are essentially a moving
target and could include distribution Elements. The Cranking Paths issue will be discussed anew in Phase 2 of this project. No
change made.
Central Maine Power
Company

No

Inclusion I3 should be changed to include the phrase, “material to,” currently in the
Statement of Compliance Registry Criteria (Section 3C3). Based on the definition
wording, the Generator Step-Up transformer (GSU) would not be BES if the generator
would not otherwise already be included as BES under another definition provision.

Rochester Gas and Electric
and New York State Electric
and Gas

No

Inclusion I3 should be changed to include the phrase, “material to,” currently in the
Statement of Compliance Registry Criteria (Section 3C3). Based on the definition
wording, the Generator Step-Up transformer (GSU) would not be BES if the generator
would not otherwise already be included as BES under another definition provision.

Orange and Rockland Utilities,
Inc.

Minimum Power system and material? NERC registry criteria for generation section
"3C3"

Massachusetts Department of
Public Utilities

No

The inclusion should be revised to specify that only those blackstart units that are
“material to” the BES are included in the definition.

Consolidated Edison Co. of NY,
Inc.

No

We suggest using wording from the Statement of Compliance Registry Criteria:Any
generator regardless of size which is material to ... [Ref: Statement of Compliance
Registry Criteria, III.c.3-Blackstart]Define “material to” as a generator listed as a
necessary part of the TOP-defined minimum system to restore the BES. This term
“material to” should exclude Blackstart-capable generators not necessary for BES
restoration or only used for local distribution system restoration. Wording
Recommendation: Following the words “identified in” add the words “and material
to” so that the new Inclusion reads:I3 - Blackstart Resources identified in and material
to the Transmission Operator’s restoration plan.

Response: The SDT believes that adding language such as “material to” does not provide clarity and remains immeasurable. No
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Question 4 Comment

change made.
Manitoba Hydro

No

Inclusion I3 should specifically state that only the Blackstart Resources specified
through EOP-005-2 R1.4 are included in the BES since “Transmission Operator
restoration plan’ is not a NERC defined term. Suggested wording:”I3 - Blackstart
Resources identified through EOP-005-2 R1.4”

Response: The SDT appreciates your concern but does not believe it is appropriate to reference a standard in the definition.
Any modification to the standard including an interpretation or a simple re-versioning for errata would change the standard
number and thus require that the definition be updated. No change made.
ISO New England Inc

No

The SDT has interpreted the FERC Directive to revise the BES definition in a manner
that goes beyond the mandate of ensuring that the definition encompasses all
facilities necessary for operating an interconnected electric transmission network. The
SDT states that operation is interpreted as being under both normal and emergency
conditions. However, loss of all electric power is the end state condition when all
normal and emergency remediating actions have failed to prevent a collapse of the
grid. System restoration involves the use of blackstart generators that are not
resources necessary for operating the electrical grid but rather a means to recover
following (not part of the emergency itself) an extreme emergency. The SDT should
simply refer to the current Compliance Registry, which, for now, appears to
adequately deal with the issue of how to treat Blackstart resources. I3 states
“Blackstart Resources identified in the Transmission Operator’s restoration plan”. This
is contrary to the preferred language that is part of the approved ERO Statement of
Compliance Registry, III.C.3 that states, “Any generator, regardless of size, that is a
blackstart unit material to (emphasis added) and designated as part of a transmission
operator entity’s restoration plan”. This language is necessary to distinguish between
those Blackstart Resources that are depended upon to restore the BES following an
emergency (“Key Facilities”) as compared to those Blackstart Resources that are used
to restore power to customer load.

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Yes or No

Question 4 Comment
Additionally, discussions with others during the preparation of comments have
revealed that some interpret this requirement to include the GSU. We do not
interpret this in this manner, but this should be clarified to avoid confusion.

Response: The SDT disagrees that Blackstart Resources should not be included in the BES Definition. The Commission directed
NERC to revise its BES definition to ensure that the definition encompasses all facilities necessary for operating an
interconnected electric transmission network. The SDT interprets this to include operation under both normal and emergency
conditions, which includes situations related to black starts and system restoration. Blackstart Resources have the ability to be
started without support from the System or can be energized without connection to the remainder of the System, in order to
meet a Transmission Operator’s restoration plan requirements for Real and Reactive Power capability, frequency, and voltage
control. The associated resources of the electric system that can be isolated and then energized to deliver electric power
during a restoration event are essential to enable the startup of one or more other generating units as defined in the
Transmission Operator’s restoration plan. For these reasons, the SDT continues to include Blackstart Resources indentified in
the Transmission Operator’s restoration plan as BES elements. No change made.
The SDT does not agree that the definition of Blackstart Resource necessarily encompasses transmission assets such as GSUs.
SRP

No

The Blackstart ‘Cranking Path’ has been deleted from Inclusion 3 of the BES definition.
However, NERC Standards EOP-005 and CIP-002, R1.2.4, require documenting the
Cranking Path. In addition, CIP-002—4 identifies the Cranking Path as a Critical Asset
in Attachment 1. Compliance to the NERC Standards needs to be an exact science
whenever possible. SRP does not argue the inclusion or exclusion of Cranking Path.
However, if it is excluded, guidance must be provided on whether or not a Cranking
Path is subject to the previously mentioned Standards.

Response: Cranking Paths are subject to any standard in which they are specifically spelled out.
Tacoma Power

Yes

Tacoma Power generally support Inclusion I3 as written. We continue to believe the
BES should only include the Blackstart Resources that support a regional recovery. We
propose changing Inclusion I3 to read,”Blackstart Resources identified in the
Transmission Operator’s restoration plan and included in a regional restoration plan.”
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Yes or No

Question 4 Comment

Response: The SDT does not agree that the definition should specify Blackstart Resources included in regional restoration plans as
those regional systems may not be included in the BES nor have any impact on the BES. No change made.
Ameren

Yes

a)The definition should include only those black start generators connected 100 kV
and above and included in the restoration plan.
b)We agree with the changes but believe clarity would be added by changing the word
“identified” to “designated”.

Response: Blackstart Resources are required to be registered regardless of connected voltage level. The SDT is remaining consistent
with its earlier position on that point. No change made.
‘Identified’ is consistent with the wording in EOP-005-2. The SDT does not feel that this change would add any additional clarity at
this time. No change made.
Utility Services, Inc.

Yes

Utility Services supports suggestions by others that request that the language of the
Inclusion use the exact language of the SCRC III.3.c. Leaving the language as is will
likely increase the number of black start facilities beyond those currently applicable.

Response: Adding language such as “material to” found in the ERO Statement of Compliance Registry Criteria does not provide
clarity and remains immeasurable. No change made.
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power

Yes

In general, we agree with this revision. However, the aggregate MVA threshold should
be 150 MVA or greater, and threshold voltage level should be 200kV or higher.

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Yes or No

Question 4 Comment

Cooperative
Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values. No change made.
City of Redding

Yes

Redding recommends the following rewording: “The Primary Blackstart resources
designated in the Transmission Operator’s restoration plan.” We believe it reduces
reliability if all Blackstart generation either primary or secondary are required to be
BES. Requiring all Blackstart capable units to be BES creates an incentive to leave
certain blacstart units out of restoration plans in order to avoid BES inclusion. By
making only the primary Blackstart unit a BES element then Transmission Operators
will be more willing to include ALL Blackstart units in their plan thus creating a
complete procedure for the Transmission Operator to restore the system.

Redding Electric Utility

Yes

Redding recommends the following rewording: “The Primary Blackstart resources
designated in the Transmission Operator’s restoration plan.” We believe it reduces
reliability if all Blackstart generation either primary or secondary are required to be
BES. Requiring all Blackstart capable units to be BES creates an incentive to leave
certain blacstart units out of restoration plans in order to avoid BES inclusion. By
making only the primary Blackstart unit a BES element then Transmission Operators
will be more willing to include ALL Blackstart units in their plan thus creating a
complete procedure for the Transmission Operator to restore the system.
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Yes or No

Question 4 Comment

City of Austin dba Austin
Energy

Yes

We recommend rewording Inclusion I3 as follows: “Only Primary Blackstart resources
designated as part of the Transmission Operator’s restoration plan.” We have
concerns that making all Blackstart generation either primary or secondary BES
elements creates an incentive to remove those secondary Blackstart capable units in
an effort to avoid BES inclusion. We believe that making the primary Blackstart unit
the only BES element will remove this incentive. In so doing, this will allow the
secondary Blackstart units to remain in the Transmission Operator’s plan and training
program as an alternate tool for the Transmission Operator to restore the system.

Sacramento Municipal Utility
District

Yes

We recommend rewording Inclusion I3 as follows: “Only Primary Blackstart resources
designated as part of the Transmission Operator’s restoration plan.” We have
concerns that making all Blackstart generation either primary or secondary BES
elements will create an incentive to remove those secondary Blackstart capable units
in order to avoid BES inclusion. Making the primary Blackstart unit the only BES
element will remove this incentive. In so doing, this will allow the secondary
Blackstart units to remain in the Transmission Operator’s plan and training program as
an alternate tool for the Transmission Operator to restore the system.

Balancing Authority Northern
California

Yes

We recommend rewording Inclusion I3 as follows: “Only Primary Blackstart resources
designated as part of the Transmission Operator’s restoration plan.” We have
concerns that making all Blackstart generation either primary or secondary BES
elements will create an incentive to remove those secondary Blackstart capable units
in order to avoid BES inclusion. Making the primary Blackstart unit the only BES
element will remove this incentive. In so doing, this will allow the secondary
Blackstart units to remain in the Transmission Operator’s plan and training program as
an alternate tool for the Transmission Operator to restore the system.

Response: The SDT discussed the recommended wording and determined that it did not provide further clarity to the definition.
Utilizing “primary” and “secondary” as a deterministic method for inclusion would create regional inconsistencies with application of
the definition which is contrary to the intent to create a consistent continent-wide definition. No change made.
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WECC Staff

Yes or No

Question 4 Comment

Yes

WECC agrees with the inclusion of the blackstart units, but does not agree with the
deletion of the cranking path from the I3. The cranking path should be included in the
definition since the NERC standards EOP-005 and CIP-002 R1.2.4 require documenting
the cranking path. The revised CIP-002-4 Standard identifies the cranking path as a
critical asset in Attachment 1 (1.5).

Response: Cranking Paths identified in a Transmission Operator’s restoration plans are often composed of distribution system
Elements. The Transmission Operator’s restoration plans identify a number of possible system restoration scenarios to address
the uncertainty of the actual requirements needed to address a particular restoration event including Cranking Paths.
Therefore, the SDT maintains that Cranking Paths are not required to be included in the BES definition as they are essentially a
moving target and could include distribution Elements. The Cranking Paths issue will be discussed anew in Phase 2 of this
project. No change made.
Florida Municipal Power
Agency

Yes

Please see comments to Question 1

Response: Please see response to Q1.
ExxonMobil Research and
Engineering

Yes

ATC LLC

Yes

Westar Energy

Yes

Northern Wasco County PUD

Yes

Farmington Electric Utility
System

Yes

We agree with the removal of the voltage language, since the inclusions and
exclusions apply only to equipment over 100 kV.

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Yes or No

Question 4 Comment

South Houston Green Power,
LLC

Yes

Portland General Electric
Company

Yes

Georgia System Operations
Corporation

Yes

Nebraska Public Power District

Yes

LCRA Transmission Services
Corporation

Yes

National Grid

Yes

Kansas City Power and Light
Company

Yes

Oncor Electric Delivery
Company LLC

Yes

Umatilla Electric Cooperative
(UEC)

Yes

UEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Central Lincoln

Yes

We agree with the removal of the voltage language, since the inclusions and
exclusions apply only to equipment over 100 kV.

Harney Electric Cooperative,

Yes

HEC agrees with the inclusions to the core definition.
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Yes or No

Question 4 Comment

Inc.
Cowlitz County PUD

Yes

PSEG Services Corp

Yes

Hydro-Quebec TransEnergie

Yes

Pacific Northwest Generating
Cooperative (PNGC)

Yes

PNGC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Raft River Rural Electric
Cooperative (RAFT)

Yes

RAFT supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

West Oregon Electric
Cooperative

Yes

WOEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Lincoln Electric Cooperative
(LEC)

Yes

LEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Northern Lights Inc. (NLI)

Yes

NLI supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
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Yes or No

Question 4 Comment
simply a specific type of such an interconnection facility.

Okanogan County Electric
Cooperative (OCEC)

Yes

OCEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Douglas Electric Cooperative
(DEC)

Yes

DEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Fall River Rural Electric
Cooperative (FALL)

Yes

FALL supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Lane Electric Cooperative
(LEC)

Yes

LEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Clearwater Power Company
(CPC)

Yes

CPC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Snohomish County PUD

Yes

SNPD supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.
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Yes or No

Question 4 Comment

Consumer's Power Inc.

Yes

CPI supports the removal of the Cranking Path language in I3. As noted in our response
to Question 9, there is no reason to classify as BES the facilities interconnecting a BES
generator to the bulk interstate system. A Cranking Path is simply a specific type of
such an interconnection facility.

Central Electric Cooperatve
(CEC)

Yes

CEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Coos-Curry Electric
Cooperative (CCEC)

Yes

CCEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Blachly-Lane Electric
Cooperative (BLEC)

Yes

BLEC supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

Long Island Power Authority

Yes

The Dow Chemical Company

Yes

City of St. George

Yes

American Electric Power

Yes

Tillamook PUD

Yes

Tillamook PUD agrees with the removal of the voltage language since the inclusions
and exclusions only apply to equipment over 100 kV.

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Yes or No

NV Energy

Yes

Z Global Engineering and
Energy Solutions

Yes

Consumers Energy

Yes

Mission Valley Power

Yes

Puget Sound Energy

Yes

Central Hudson Gas and
Electric Corporation

Yes

City of Anaheim

Yes

Chevron U.S.A. Inc.

Yes

Metropolitan Water District of
Southern California

Yes

Duke Energy

Yes

Clallam County PUD No.1

Yes

Exelon

Yes

Question 4 Comment

Mission Valley Power - We agree with the removal of the voltage language, since the
inclusions and exclusions apply only to equipment over 100 kV.

CLPD supports the removal of the Cranking Path language in I3. As noted in our
response to Question 9, there is no reason to classify as BES the facilities
interconnecting a BES generator to the bulk interstate system. A Cranking Path is
simply a specific type of such an interconnection facility.

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Yes or No

Michigan Public Power Agency

Yes

Idaho Falls Power

Yes

Tri-State GandT

Yes

Western Area Power
Administration

Yes

Texas Industrial Energy
Consumers

Yes

PacifiCorp

Yes

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

Yes

MRO NERC Standards Review
Forum (NSRF)

Yes

Electricity Consumers
Resource Council (ELCON)

Yes

Southern Company
Generation

Yes

Pepco Holdings Inc and
Affiliates

Yes

Question 4 Comment

We support the inclusion as drafted.

PacifiCorp supports the removal of reference to Cranking Paths in I3. There is no
reason to classify as BES the facilities interconnecting a BES generator to the
interconnected transmission system.

Agree with the SDT decision to delete the inclusion of Black Start Cranking Paths.

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Yes or No

Dominion

Yes

Bonneville Power
Administration

Yes

Texas RE NERC Standards
Subcommittee

Yes

SERC Planning Standards
Subcommittee

Yes

Southwest Power Pool
Standards Review Team

Yes

BGE

Yes

Question 4 Comment

No comment.

Response: Thank you for your support.

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5.

The SDT has revised the specific inclusions to the core definition in response to industry comments. Do you agree with Inclusion
I4 (dispersed power)? If you do not support this change or you agree in general but feel that alternative language would be
more appropriate, please provide specific suggestions in your comments.
Summary Consideration: Several comments sought clarification that Inclusion I4 was directed at including resources
such as wind and solar farms and sought a distinction between Inclusions I2 and I4. The SDT believes this is presently
clear in the definition. Inclusion I4 specifically addresses wind and solar farms being dispersed power producing
resources that “utilize[e] a system designed primarily for aggregating capacity.” The essential distinction between
Inclusion I2 and I4 is that Inclusion I2 may not include generating resources that use lower voltage collection systems
while Inclusion I4 is specifically designed to accomplish this purpose.
The SDT also clarifies that Inclusion I4 speaks towards the inclusion of the generation resources themselves, not the
transmission Element(s) of the collector systems operated below 100 kV or not included under Inclusion I2.
There were a number of comments seeking clarification on the location of the common point of connection. While the
SDT does not believe additional clarification of the term “common point” is needed in the BES definition, the following
guidance is provided. The common point of connection, which is the point from where generation is aggregated to
determine if the 75 MVA threshold is met, is the point where the individual transmission Element(s) of a collector system
ultimately meet the 100 kV transmission system.
Some stakeholders asked for clarity on the issue of units on the customer’s side of the retail meter. Generating units on
the customer’s side of the retail meter are not included under Inclusion I4 since customer-side retail generation typically
does not “utilize[e] a system designed primarily for aggregating capacity, connected at a common point at a voltage of
100 kV or above.”
Several comments sough clarification of the definitional difference between “dispersed power” and “distributed
generation” as used in the BES definition. While the SDT does not believe that further clarity of these terms is needed in
the BES definition, it clarifies that distributed generation is generally defined as: a generator that is located close to the
particular Load that it is intended to serve and is interconnected to the utility distribution system. The U.S Energy
Information Administration (EIA) and FERC generally use this as a basic definition. The language of Inclusion I4 stating
“Dispersed power producing resources . . . utilizing a system designed primarily for aggregating capacity, connected at a
common point at a voltage of 100 kV or above” was selected so as not to confuse what is traditionally considered
distributed generation with the types of systems to be included in Inclusion I4.

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The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has
responsibilities associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in
regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the
development of strong technical justifications that would warrant a change from the current values that exist through the
application of the definition today. These and similar issues have prompted the SDT to separate the project into phases
which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT
will consider all recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2 of
Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical
Standing Committees, to develop analyses which will properly assess the threshold values and provide compelling
justification for modifications to the existing values.
No changes were made to Inclusion I4 based on comments provided in response to this question.
Organization
Northeast Power
Coordinating Council

Yes or No

Question 5 Comment

No

Suggest the term “common point” needs clarification and/or definition
(is risk of single mode failure intended, i.e. where all the resources could
be lost for a single event?). Suggest the following wording: “connected
at a common point through a dedicated step-up transformer with a highside voltage of 100 KV or above.”
Dispersed power producing sources such as wind and solar should not be
included as BES elements because of the variable and intermittent nature
of these resources. If these dispersed power producing resources had
dedicated energy storage facilities only then that could make them BES
elements. Generally the collector systems for these resources (from the
bulk transmission system reliability perspective) do not differ from
distribution systems which are excluded from the BES.

Response: While the SDT does not believe that additional clarification of the term “common point” is needed in
the BES definition, the following guidance is provided. The common point of connection, which is the point
from where generation is aggregated to determine if the 75 MVA threshold is met, is the point where the
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Question 5 Comment

individual transmission Element(s) of a collector system ultimately meet the 100 kV transmission system. No
change made.
The SDT disagrees with excluding dispersed power producing sources such as wind and solar from the BES
definition. These resources comprise a significant share of the North American resource mix. No change made.
The SDT does not believe further clarification of Dispersed Power Resources is needed. Inclusion I4 is directed
at including resources such as wind and solar farms. This is denoted by the requirement that the dispersed
power producing resources “utilize[e] a system designed primarily for aggregating capacity.” Furthermore,
Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s) of the
collector systems operated below 100 kV or not included under Inclusion I2. No change made.
Southwest Power Pool
Standards Review Team

No

We believe that the removal of the wording “single site” in I2 would
remove the need to cover dispersed power producing resources in I4.
What is the reason for keeping I4 in this version?
Also we understand that 75MVA is held in I4 because of no direct link to
the registry criteria, but feel that this number could change in phase two
of the project which would create unnecessary work in the future.

Response: The essential distinction between Inclusions I2 and I4 is that Inclusion I2 may not include generating
resources that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this
purpose. Inclusion I4 is directed at including resources such as wind and solar farms. This is denoted by the
requirement that the dispersed power producing resources “utilize[e] a system designed primarily for
aggregating capacity.” No change made.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to
the technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT
has responsibilities associated with being responsive to the directives established in Orders No. 743 and 743-A,
particularly in regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with
sufficient time for the development of strong technical justifications that would warrant a change from the
current values that exist through the application of the definition today. These and similar issues have prompted
the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
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Yes or No

Question 5 Comment

stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications
to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk
Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for
modifications to the existing values. No change made.
Pepco Holdings Inc and
Affiliates

No

The SDT reworded Inclusion I4 to use the phrase “utilizing a system
designed primarily for aggregating capacity”. This was to address a
concern that the previous definition could ensnare distributed
generation or small generators in a distribution system. We agree with
the intent of this modification. I4 was intended solely to address wind
and solar farms that use a collector system to aggregate their capacity.
Therefore, to provide better clarity on the intent of this Inclusion,
perhaps it would be better to specifically mention these examples in the
wording: “Dispersed power producing resources (such as wind and solar
farms, etc.) which utilize a system designed primarily for aggregating
capacity, where the capacity is greater than 75MVA (gross aggregate
nameplate rating) and the facility is connected at a common point at a
voltage of 100kV or above.”

Response: Use of the term ‘etc.’ is not suitable for a definition as it is completely open ended. Inclusion of a list
is problematic as it may not be complete especially with regard to future technology enhancements which could
force a revision of the definition. The SDT does not believe the suggested change provides any additional
clarity. The SDT does not believe further clarification of Dispersed Power Resources is needed. Inclusion I4 is
directed at including resources such as wind and solar farms. This is denoted by the requirement that the
dispersed power producing resources “utilize[e] a system designed primarily for aggregating capacity.” No
change made.
Hydro One Networks Inc.

No

Although we agree with the I4 concept, we suggest that the SDT should
consider that this category primarily includes wind and solar farms and
their collector system. We believe these facilities should not be included
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Yes or No

Question 5 Comment
as BES elements but rather as supporting elements (see comments under
I2) for the following reasons: a) Any additional benefit of classifying
these resources as BES is insignificant for the reliability of supply
(capacity and energy), considering the intermittent and widely variable
nature of these resources. The planning and operational standards and
practices make sure that their unavailability or unexpected (sudden) loss,
which are significantly more likely due to the natural elements than
those due to mechanical or electrical causes, will not jeopardize the
reliability of the supply; and b) The reliability of the aspects of the
collector system of these resources (their impact on reliability of the bulk
transmission system) is not different from that of distribution systems
(load serving feeders) which are excluded from the BES.
We agree with the revised portion of Inclusion I4 which does indeed
clarify that there is no requirement for a contiguous BES path from the
dispersed generation resources to the point of interconnection to the
BES.

Response: The SDT disagrees with excluding dispersed power producing sources such as wind and solar from
the BES definition. These resources comprise a significant share of the North American resource base. No
change made.
Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s) of the
collector systems operated below 100 kV or not included under Inclusion I2. No change made.
Western Area Power
Administration

No

Need to clarify the systems associated with this inclusion. The phrase
“dispersed power producing resources” in inclusion (I4) is confusing and
does not clearly communicate the focus of this inclusion. Without
reviewing the reference information provided in the 1st draft comment
form, it’s not clear that dispersed power producing resources refer to
wind and solar resources. Recommendation: Include examples after
phrase “dispersed power producing resources” for clarification to this
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Question 5 Comment
inclusion. Change I4 to read - Dispersed power producing resources (i.e.
wind and solar resources) with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily
for aggregating capacity, connected at a common point at a voltage of
100 kV or above.

Response: The SDT does not believe that the suggestion provides any additional clarity. No change made.
PacifiCorp

No

Setting a dispersed power producing resource limit to 75 MVA at a
common point discriminates against single generator owners who own
generators between 20 MVA and 75 MVA (inclusion I1), typically
connected at a common point and requires such owners to be subject to
additional standards that dispersed power producing owners are not
required. However, even with this concern, PacifiCorp supports the
entire BES definition in its current form based on the timeframe under
which the SDT is operating and with an emphasis based on a phase II SAR
to address PacifiCorp’s objections regarding generation levels.
Under the attached scenario, please identify which elements would be
considered BES: This response included a drawing. This format will not
allow the submission of the drawing. The drawing will be sent separately
in an email. Reference "Proj 2010-17 PAC Drawing".

Response: The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition.
However, the SDT has responsibilities associated with being responsive to the directives established in Orders
No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded
the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. All recommendations for modifications to the technical
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aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System will be
considered. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop
analyses which will properly assess the threshold values and provide compelling justification for modifications
to the existing values. No change made.
The examples provided will be reviewed as part of Phase 2.
Massachusetts
Department of Public
Utilities

No

The aggregate 75 MVA of connected generation does not appear to be
adequately supported by technical analysis and appears, on its face, as
too low. Among our concerns is that such a low level will have a
potential adverse impact on the development of renewable generation
resources.
In addition, the inclusion needs to be clarified in order that entities have
clear guidance on what is meant by “common point of interconnection.”

NESCOE

No

NESCOE continues to disagree with this proposed inclusion. NESCOE is
concerned with the potential adverse impact this may have on the
development of renewable generation resources.
In addition, NESCOE suggests that the aggregate 75 MVA of connected
generation is too low and is not adequately supported by technical
analysis. The threshold value should be related to the largest
contingency the applicable control area is designed to operate to. A level
of 300 MVA would be appropriate.
Finally, the inclusion needs to be clarified in order that entities have clear
guidance on what is meant by “common point of interconnection.”

Response: The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition.
However, the SDT has responsibilities associated with being responsive to the directives established in Orders
No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded
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the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. The SDT will consider all recommendations for modifications
to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk
Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for
modifications to the existing values. No change made.
While the SDT does not believe that additional clarification of the term “common point” is needed in the BES
definition, the following guidance is provided. The SDT believes the common point of connection, which is the
point from where generation is aggregated to determine if the 75 MVA threshold is met, is the point where the
individual transmission Element(s) of a collector system ultimately meet the 100 kV transmission system. No
change made.
Idaho Falls Power

No

As drafted, it appears to draw in all generation resources that sum to 75
MVA or higher. We question then if there is value of categorizing every
wind turbine on a >75MVA wind farm as a BES asset and, what would be
the unintended consequences.
Perhaps language delineating the point of aggregation as the
demarcation point of a BES asset would better serve.

Response: Inclusion I4 denotes an aggregate threshold. This is clear from the requirement inclusion threshold
of “aggregate capacity greater than 75 MVA (gross aggregate nameplate rating).” Once this aggregate threshold
is met, all generation resources that comprise the facility would be included. No change made.
While the SDT does not believe that additional clarification of the term “common point” is needed in the BES
definition, the following guidance is provided. The SDT believes the common point of connection, which is the
point from where generation is aggregated to determine if the 75 MVA threshold is met, is the point where the
individual transmission Element(s) of a collector system ultimately meet the 100 kV transmission system. No
change made.
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ReliabilityFirst

No

Question 5 Comment
The term “Dispersed Power Producing Resource” is not a defined term
and needs further clarification.
However, I4 is not needed and is already included in I2. I4 does not add
any additional facilities that are not already included in I2. How are
“dispersed power producing resources” different from “generating
resources” described in I2? If the intent of I4 is to include wind
generators but exclude wind farm collector systems in the BES,
ReliabilityFirst Staff disagrees.
To maintain reliability, the BES cannot have pockets of generation that
are not connected to the BES via BES facilities. ReliabilityFirst Staff
believes that without including the paths from BES generators in the BES,
the reliable operation of the system could be jeopardized if the paths are
unavailable due to non-compliance to Reliability Standards. For example,
wind farm collector systems at voltages operated at less than 100 kV
should be included in the BES for the above reason. I4 could be deleted.

Response: The SDT does not believe further clarification of Dispersed Power Resources is needed. Inclusion I4 is
directed at including resources such as wind and solar farms. This is denoted by the requirement that the
dispersed power producing resources “utilize[e] a system designed primarily for aggregating capacity.” No
change made.
The essential distinction between Inclusions I2 and I4 is that Inclusion I2 may not include generating resources
that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this purpose.
Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s) of the
collector systems operated below 100 kV or not included under Inclusion I2. No change made.
The contiguous nature of the BES will be discussed as part of Phase 2 of the project. No change made.
Xcel Energy

No

Xcel Energy believes that this inclusion is still a little vague and could use
some clarification. For instance, if a wind farm has an aggregated
capacity greater than 75 MVA (and therefore meets Inclusion I4) exactly
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Question 5 Comment
what facilities are included as part of the BES, every turbine, all
distribution transformers and cables, etc. If all equipment is included,
what level of detail is required of this BES facility for modeling purposes,
and who is responsible for modeling this system. Or, is the intent to only
include the facilities at the common point of connection, whereby the
facility could be modeled as 1 large facility?

Response: Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission
Element(s) of the collector systems operated below 100 kV or not included under Inclusion I2. No change made.
Central Maine Power
Company

No

The term “common point” needs clarification and/or definition. (e.g., is it
intended to apply to the risk of single mode failure, where all the
resources could be lost for a single event?) Some northeast industry
expert colleagues interpret I2 to mean the collector system itself needs
to be 100 kV or above in order to be BES. I2 seems to not include the
collector system itself in BES. I4 should be restated as follows:
“Dispersed power producing resources with aggregate capacity greater
than 75 MVA (gross aggregate nameplate rating) utilizing a collector
system connected at a common point. BES includes the interconnecting
substation with the step-up transformer(s) connected at a voltage of 100
kV or above.”[alternatively, replace "interconnecting substation with"
with, “generator terminals through the high-side of” if the entire
collector system is intended to be BES]Also note that some wind
collector systems require supplemental dynamic reactive resources or
special control system to met reliability standards. As written, these
reactive resources or controls may not be considered to be BES.

New York State Dept of
Public Service

No

I4 reference to a “common point” lacks clarity that can lead to confusion
and required clarifications. Suggested wording change: ... connected at
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Question 5 Comment
side voltage of 100 kV or above.”

American Electric Power

No

We believe more clarity is needed as to where exactly the “common
point” is, for example in the case of a wind farm. This first common point
could be interpreted as the output voltage of the wind generator, would
be less than the 100kv threshold and thereby could (unintentionally?)
exclude the facility as a whole. If this was unintentional, we recommend
rewording I4 in a manner similar to I2.

Response: While the SDT does not believe that additional clarification of the term “common point” is needed in
the BES definition, the following guidance is provided. The SDT believes the common point of connection,
which is the point from where generation is aggregated to determine if the 75 MVA threshold is met, is the
point where the individual transmission Element(s) of a collector system ultimately meet the 100 kV
transmission system. No change made.
The Dow Chemical
Company

No

It is not clear how “Dispersed power producing resources” differ from
“Generating Resource (s)” in I2. Inclusion I4 should clarify this.
We suggest that the phrase “Variable Energy Resources” be used instead
of “Dispersed power producing resources”. Variable Energy Resources
should be defined as “Resources producing electricity using wind or solar
energy.”
The following phrase should be added at the end “unless excluded under
Exclusion E2”.

Response: The essential distinction between Inclusion I2 and I4 is that Inclusion I2 may not include generating
resources that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this
purpose. Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s)
of the collector systems operated below 100 kV or not included under Inclusion I2. No change made.
The SDT does not believe that the suggestion provides any additional clarity. No change made.
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The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately
applied will identify the vast majority of BES Elements in a consistent manner that can be applied on a
continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation
point between BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and
Reactive Power resources connected at 100 kV or higher as included in the BES. To fully appreciate the scope of
the ‘core’ definition an understanding of the term Element is needed. Element is defined in the NERC Glossary
of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator,
transformer, circuit breaker, bus section, or transmission line. An element may be comprised of one or more
components. “
An Element is basically any electrical device that is associated with the transmission or the generation
(generating resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included
through the application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power
and Reactive Power resources with specific criteria to provide for a consistent determination of whether an
Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES
Elements). The exclusion language is written to specifically identify Elements or groups of Elements for potential
exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific
criteria identified in the exclusion language. This does not include the exclusion of Real Power and Reactive
Power resources captured by Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of
the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner. Therefore, the
only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the
customer’s side) and supersedes inclusion I2.
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Question 5 Comment

Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and
supersedes Inclusion I5.
In the event that the BES definition does not provide a definitive determination on whether an Element is
classified as BES or non-BES, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element. No change made.
City of St. George

No

This language follows the 75 MVA plant requirements from the
Registration Criteria. See comments to question 3 (for I2) above.
Additional detail is needed to clarify exactly at what point in the
dispersed system the BES starts and what is not BES.

Response: Please see response to Q3.
While the SDT does not believe that additional clarification of the term “common point” is needed in the BES
definition, the following guidance is provided. The SDT believes the common point of connection, which is the
point from where generation is aggregated to determine if the 75 MVA threshold is met, is the point where the
individual transmission Element(s) of a collector system ultimately meet the 100 kV transmission system. No
change made.
ISO New England Inc

No

I4 is unclear as to whether or not the collector system (or system
designed primarily for aggregating capacity) itself is BES or just the
resource.”Utilizing a system designed primarily for aggregating capacity”
needs to be more clearly defined to account for multiple systems that
may exist out of one common point. A suggestion would be to modify the
end of the sentence to say “connected at any common point.”
I4 will allow for significant amounts of dispersed power producing
resources to be excluded from the BES. This includes wind resources
which are increasing in numbers and having a significant impact on
system operations. It does not seem appropriate that having ten 70 MVA
(total of 700 MVA) installations each with their own connection to a 115
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Question 5 Comment
kV bus should fall outside of the BES. As currently written, they would
fall outside of the inclusion if they do not utilize the same collector
system. It is unclear whether or not supplemental equipment associated
with the dispersed power producing resources is included in the BES. As
an example, many wind resources are being interconnected utilizing
supplemental dynamic and static reactive devices which are crucial to the
operation of these resources. The dynamic devices are often controlling
themselves and static reactive devices, which may or may not be
connected above 100 kV. Leaving these devices out of the BES definition
seems to be a potential gap.

Response: The essential distinction between Inclusion I2 and I4 is that Inclusion I2 may not include generating
resources that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this
purpose. Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s)
of the collector systems operated below 100 kV or not included under Inclusion I2. No change made.
The clustering of dispersed power producing resources and supplemental equipment will be discussed as part of
Phase 2 of the project. No change made.
Rochester Gas and Electric
and New York State
Electric and Gas

No

The term “common point” needs clarification and/or definition. (e.g., is it
intended to apply to the risk of single mode failure, where all the
resources could be lost for a single event?)
Some northeast industry expert colleagues interpret I2 to mean the
collector system itself needs to be 100 kV or above in order to be BES. I2
seems to not include the collector system itself in BES. I4 be restated as
follows:”Dispersed power producing resources with aggregate capacity
greater than 75 MVA (gross aggregate nameplate rating) utilizing a
collector system connected at a common point. BES includes the
interconnecting substation with the step-up transformer(s) connected at
a voltage of 100 kV or above.”[alternatively, replace the bold italics with,

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Question 5 Comment
“generator terminals through the high-side of”]
Also note that some wind collector systems require supplemental
dynamic reactive resources or special control system to met reliability
standards. As written, these reactive resources or controls may not be
considered to be BES.

Response: While the SDT does not believe that additional clarification of the term “common point” is needed in
the BES definition, the following guidance is provided. The SDT believes the common point of connection,
which is the point from where generation is aggregated to determine if the 75 MVA threshold is met, is the
point where the individual transmission Element(s) of a collector system ultimately meet the 100 kV
transmission system. No change made.
The essential distinction between Inclusion I2 and I4 is that Inclusion I2 may not include generating resources
that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this purpose.
Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s) of the
collector systems operated below 100 kV or not included under Inclusion I2. No change made.
The inclusion of supplemental equipment will be discussed as part of Phase 2 of the project. No change made.
LCRA Transmission Services
Corporation

No

LCRA TSC suggests consistency between this inclusion criteria and the
criteria used in I2 for “generation”.

Response: The essential distinction between Inclusion I2 and I4 is that Inclusion I2 may not include generating
resources that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this
purpose. Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s)
of the collector systems operated below 100 kV or not included under Inclusion I2. No change made.
Kansas City Power and
Light Company

No

It is not clear that it is the injection at the collection point that is the
defining point for the injection. Nameplate rating of the generator is not
a reflection of what can be actually injected into the transmission system
with resulting electrical impacts on transmission loading and behavior.
Recommend the BES definition be based on a generating resource(s)
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Question 5 Comment
established net accredited generating capacity at the common point
instead of what it could do by nameplate rating that may not be
achievable. Recommend the following language: Dispersed power
producing resources utilizing a system designed primarily for aggregating
capacity connected through a common point at a voltage of 100 kV or
above with aggregate net accredited capacity at the common point of
greater than 75 MVA.

Response: For Phase 1, the SDT has used nameplate rating in order to maintain consistency with the ERO
Statement of Compliance Registry Criteria. No change made.
This can be discussed in Phase 2 of the project. The SDT acknowledges and appreciates the comments and
recommendations associated with modifications to the technical aspects (i.e., the bright-line and component
thresholds) of the BES definition. However, the SDT has responsibilities associated with being responsive to the
directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25,
2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the
definition today. These and similar issues have prompted the SDT to separate the project into phases which will
enable the SDT to address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT
will consider all recommendations for modifications to the technical aspects of the definition for inclusion in
Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the
NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values and
provide compelling justification for modifications to the existing values. No change made.
Farmington Electric Utility
System

No

FEUS feels additional clarity should be added to I4. It appears I4 is not
intended to include each individual wind turbine generating unit in a
wind farm as a BES element, but rather to include the point at which the
aggregation becomes large enough to meet the aggregate capacity
threshold of 75MVA.

Response: inclusion I4 denotes an aggregate threshold. This is clear from the requirement inclusion threshold
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Question 5 Comment

of “aggregate capacity greater than 75 MVA (gross aggregate nameplate rating).” Once this aggregate threshold
is met, all generation resources that comprise the facility would be included. No change made.
South Houston Green
Power, LLC

No

Further clarification of “Dispersed power producing resources” is
needed. Multiple small resources should not be included.
The following phrase should be added at the end of Inclusion I4 “unless
excluded under Exclusion E2”.

Response: The SDT does not believe that additional clarification is needed. Inclusion I4 speaks towards the
inclusion of the resources themselves, not the transmission Element(s) of the collector systems operated below
100 kV or not included under Inclusion I2. No change made.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately
applied will identify the vast majority of BES Elements in a consistent manner that can be applied on a
continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation
point between BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and
Reactive Power resources connected at 100 kV or higher as included in the BES. To fully appreciate the scope of
the ‘core’ definition an understanding of the term Element is needed. Element is defined in the NERC Glossary
of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator,
transformer, circuit breaker, bus section, or transmission line. An element may be comprised of one or more
components. “
An Element is basically any electrical device that is associated with the transmission or the generation
(generating resources) of electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included
through the application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power
and Reactive Power resources with specific criteria to provide for a consistent determination of whether an
Element is classified as BES or non-BES.
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Question 5 Comment

Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES
Elements). The exclusion language is written to specifically identify Elements or groups of Elements for potential
exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific
criteria identified in the exclusion language. This does not include the exclusion of Real Power and Reactive
Power resources captured by Inclusions I2 – I5. The exclusion (E1) only speaks to the transmission component of
the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner. Therefore, the
only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the
customer’s side) and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and
supersedes Inclusion I5.
In the event that the BES definition does not provide a definitive determination on whether an Element is
classified as BES or non-BES, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element. No change made.
Westar Energy

No

We believe that the removal of the wording “single site” in I2 would
eliminate the need to include dispersed power producing resources in I4.
We feel that I4 should be removed to reduce redundancy in the
definition, unless there is some other reason to include it.
Also, we understand that 75 MVA is retained in I4 because there is no
direct link to the ERO Statement of Compliance Registry Criteria, but we
have concerns that this number could change in phase two of the
project, creating unnecessary work in the future.

Response: The essential distinction between Inclusion I2 and I4 is that I2 may not include generating resources
that use lower voltage collection systems while I4 is specifically designed to accomplish this purpose, therefore
I4 is needed. No change made.
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Question 5 Comment

The SDT acknowledges and appreciates the comments and recommendations associated with modifications to
the technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT
has responsibilities associated with being responsive to the directives established in Orders No. 743 and 743-A,
particularly in regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with
sufficient time for the development of strong technical justifications that would warrant a change from the
current values that exist through the application of the definition today. These and similar issues have prompted
the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. The SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop
analyses which will properly assess the threshold values and provide compelling justification for modifications
to the existing values. No change made.
Hydro-Quebec
TransEnergie

Same comment than Q. 3.
Also, since the path to connect the dispersed generation is often done at
distribution voltage, that lower voltage path should not be included in
BES.

Response: Please see response to Q3.
Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s) of the
collector systems operated below 100 kV or not included under Inclusion I2. No change made.
Tacoma Power

Yes

Tacoma Power generally supports the Inclusion I4 as currently written.
However, we support further refinement of the aggregate nameplate
rating definition and support deferring the appropriate quantitative
thresholds to those that will be determined in Phase 2.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition.
However, the SDT has responsibilities associated with being responsive to the directives established in Orders
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No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded
the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. The SDT will consider all recommendations for modifications
to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk
Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for
modifications to the existing values. No change made.
Ameren

Yes

a)For a consistent application, we suggest that the definition of the terms
"Dispersed power producing resources" is included. Consider including
some examples also.

Response: The SDT does not believe further clarification of Dispersed Power Resources is needed. Inclusion I4 is
directed at including resources such as wind and solar farms. This is denoted by the requirement that the
dispersed power producing resources “utilize[e] a system designed primarily for aggregating capacity.” No
change made.
Cowlitz County PUD

Yes

However, Cowlitz suggests Inclusion 4 be made parallel with Inclusion 2:
...(greater than the gross aggregate name plate rating per the ERO
Statement of Compliance Registry Criteria) utilizing...

Response: The SDT believes that Inclusions I2 and I4 do use consistent language and this point has been clarified
with the clarifying language changes to Inclusion I2. No change made.
Long Island Power
Authority

Yes

Need to define the term "common point"

Response: While the SDT does not believe that additional clarification of the term “common point” is needed in
the BES definition, the following guidance is provided. The SDT believes the common point of connection,
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which is the point from where generation is aggregated to determine if the 75 MVA threshold is met, is the
point where the individual transmission Element(s) of a collector system ultimately meet the 100 kV
transmission system.
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative ShoMe Power Electric Power
Cooperative

Yes

This inclusion should be limited to reactive devices 150 MVAR or greater
(gross aggregate nameplate rating) connected through a common point
at the 200 kV level or higher level.

Manitoba Hydro

Yes

Manitoba Hydro agrees with I4 but it does create a discrepancy between
the BES Definition and the Registration Criteria Document. The
Registration Criteria document should be updated and I2 and I4 should
be combined into a single Inclusion.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition.
However, the SDT has responsibilities associated with being responsive to the directives established in Orders
No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded
the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. The SDT will consider all recommendations for modifications
to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk
Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for
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Question 5 Comment

modifications to the existing values. Possible revisions to the ERO Statement of Compliance Registry Criteria will
be discussed as part of Phase 2 of the project. No change made.
Consumers Energy

Yes

We agree, but would like further clarification on what wind farm
equipment (e.g., collector systems or other equipment) would be
considered a part of the BES. Is the system designed for aggregating
capacity considered to be part of the dispersed plant or part of the BES.

Response: Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission
Element(s) of the collector systems operated below 100 kV or not included under Inclusion I2. No change made.
Michigan Public Power
Agency
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)
Central Electric Cooperatve
(CEC)
Clearwater Power
Company (CPC)

Yes

MPPA supports the revised language generally, but believes additional
changes would make the language clearer. Specifically, we believe
Inclusion 4 should not incorporate a hard 75 MVA generation threshold
(i.e, “resources with aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating)”). Instead, we urge the SDT to replace this
language with the defined term “Qualifying Aggregate Generation
Resources,” which is discussed in more detail in our response to
Question 3. This language, or some equivalent, will preserve the SDT’s
ability to revise the 75 MVA threshold in Phase 2, with the result of Phase
2 included in the BES Definition by operation rather than requiring
further revision of the Definition.

Douglas Electric
Cooperative (DEC)

More generally, we are not certain what is accomplished by Inclusion 4
that is not already accomplished by Inclusion 2, which also addresses
whether generation should be defined as BES. The SDT’s stated concern
is with variable generation units such as wind and solar plants. It is not
clear to us why this concern is not fully addressed in Inclusion 2, which
addresses multiple generation units connected at a common bus, the
configuration of most variable generation plants with multiple units.

Fall River Rural Electric

We are also concerned that the language, as proposed, could have

Snohomish County PUD
Consumer's Power Inc.

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Cooperative (FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric
Cooperative (LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest
Generating Cooperative
(PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric
Cooperative (UEC)
Kootenai Electric
Cooperative

Yes or No

Question 5 Comment
unintended consequences and improperly classify local distribution
systems as BES in certain circumstances. This is because multiple
distributed generation units could render a local distribution system a
“collector system” and the entire system the equivalent of an aggregated
generation unit, causing the local distribution system to be improperly
denied status as a LN. If many different distributed generation units are
connected to a local distribution system, it is very unlikely that more than
a few of those units would fail simultaneously, and it is therefore unlikely
that multiple generation units would produce a measureable impact on
the interconnected bulk transmission system, especially if the units
individually do not otherwise exceed the materiality threshold to be
established by the SDT in Phase 2.
Further, we are concerned that, if small distributed generation units
become the industry norm, Inclusion 4 could unintentionally sweep in
local distribution systems, especially where local policies favor the
growth of small solar or other renewable generation systems for public
policy reasons.
Finally, we suggest that the SDT add the phrase “. . . unless the dispersed
power producing resources operate within a Radial System meeting the
requirements of Exclusion E1 or a Local Network meeting the
requirements of Exclusion E2.” This language, which parallels the
language included at the end of Inclusion I1, would make clear that
dispersed small-scale generators scattered throughout a Radial System or
Local Network serving retail load would not convert the Radial System or
Local Network into a BES system, even if the aggregate capacity of those
small generators exceeds the relevant threshold.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition.
However, the SDT has responsibilities associated with being responsive to the directives established in Orders
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Yes or No

Question 5 Comment

No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded
the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. The SDT will consider all recommendations for modifications
to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk
Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for
modifications to the existing values. No change made.
The essential distinction between Inclusions I2 and I4 is that Inclusion I2 may not include generating resources
that use lower voltage collection systems while Inclusion I4 is specifically designed to accomplish this purpose.
No change made.
Inclusion I4 is directed at including resources such as wind and solar farms. This is denoted by the requirement that
the dispersed power producing resources “utilize[e] a system designed primarily for aggregating capacity.”
Furthermore, Inclusion I4 speaks towards the inclusion of the resources themselves, not the transmission Element(s)
of the collector systems operated below 100 kV or not included under Inclusion I2. Therefore distribution systems
would not be inadvertently included. No change made.
National Grid

Yes

We agree with Inclusion I4, however we feel that the inclusion could be
interpreted in some different ways. This inclusion could be interpreted
to exclude dispersed generation greater than 75 MVA if the first common
point is less than 100 kV. To eliminate any confusion in the
interpretation of this inclusion, we suggest this wording: Dispersed
power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) connected to a Transmission Element
at 100 kV or above, utilizing a system designed primarily for aggregating
capacity which includes all transformers between the generator(s) and
the Transmission Element.

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MRO NERC Standards
Review Forum (NSRF)

Yes or No

Question 5 Comment

Yes

I4 - Dispersed power producing resources with aggregate capacity
greater than 75 MVA (gross aggregate nameplate rating) utilizing a
system designed primarily for aggregating capacity, connected at a
common point at a voltage of 100 kV or above starting at the point of
aggregation to 75 MVA or more through to the point of interconnection
at 100 kV or above.”

Response: The SDT does not believe that the suggested change provides additional clarity. No change made.
Electricity Consumers
Resource Council (ELCON)

Yes

The term “dispersed power” and “dispersed generation” are often
synonymous with distributed generation, which includes behind-themeter generation (CHP). The Inclusion should be clarified by specifically
referencing wind and solar, or adopt the FERC term “Variable Energy
Resources.”
Also, to distinguish this Inclusion from Inclusion I2, the SDT might want to
clarify that the collection system (usually at voltage below 100 KV
anyway) is not part of the BES-just the resources and any transformers
included by I1, if this is indeed the intent of this Inclusion. The following
phrase should be added at the end “unless excluded under Exclusion E2.”

Response: The SDT believes that inclusion of a list is problematic as it may not be complete especially with
regard to future technology enhancements which could force a revision of the definition. Furthermore, the SDT
does not believe further clarification of Dispersed Power Resources is needed. Inclusion I4 is directed at
including resources such as wind and solar farms. This is denoted by the requirement that the dispersed power
producing resources “utilize[e] a system designed primarily for aggregating capacity.” No change made.
The SDT does not believe that additional clarification is needed. Inclusion I4 speaks towards the inclusion of the
resources themselves, not the transmission Element(s) of the collector systems operated below 100 kV or not
included under Inclusion I2. No change made.

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ACES Power Marketing
Standards Collaborators

Yes or No

Question 5 Comment

Yes

Further clarification on what “dispersed power” means would be helpful.
How does it compare to distributed generation?

Response: While the SDT believes that further clarity of the terms “dispersed power” and “distributed
generation” is not needed, it notes that distributed generation is generally defined as: a generator that is
located close to the particular load that it is intended to serve and is interconnected to the utility distribution
system. The U.S EIA and FERC generally use this as a basic definition. The language of Inclusion I4 stating
“Dispersed power producing resources . . . utilizing a system designed primarily for aggregating capacity,
connected at a common point at a voltage of 100 kV or above” was selected so as not to confuse what is
traditionally considered distributed generation with the types of systems to be included in Inclusion I4. No
change made.
Texas RE NERC Standards
Subcommittee

Yes

To distinguish this Inclusion from Inclusion I2, the SDT might want to
clarify that the collection system (usually at voltage below 100 KV
anyway) is not part of the BES-just the resources and any transformers
included by I1, if this is indeed the intent of this Inclusion.

Response: The SDT does not believe that additional clarification is needed. Inclusion I4 speaks towards the
inclusion of the resources themselves, not the transmission Element(s) of the collector systems operated below
100 kV or not included under Inclusion I2. No change made.
ExxonMobil Research and
Engineering

Yes

The BES SDT should clarify the difference between “dispersed power
producing resources” and “generation resources” in such a manner that
it is clear that an industrial plant containing providing the BES with power
from ten 7.5MVA machines connected at a common point at a voltage of
100 kV or higher meets the qualifications for generation resources and
does not meet the qualifications for a “dispersed power producing
resource”.

Portland General Electric

Yes

PGE requests additional clarity in the wording of Inclusion 4. Inclusion 4 is
not intended to include each individual wind turbine generating unit in a
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Yes or No

Company

Question 5 Comment
wind farm as a BES element, but rather to include the point at which the
aggregation becomes large enough to meet the aggregate capacity
threshold of 75 MVA. However, the response to comments from the last
comment posting and the current wording of Inclusion 4 does not
provide sufficient clarity to answer this question.

Bonneville Power
Administration

Yes

BPA suggests adding, “Including generating terminals of the high side” as
clarifying language to the end of the sentence. (Specifically where the
100kV is to be measured as clarified in I2). BPA believes that Inclusion 4
is not intended to include each individual wind turbine/generator unit in
a wind farm as a BES element, but rather to include the point at which
the aggregation becomes large enough to meet the aggregate capacity
threshold of 75 MVA.

WECC Staff

Yes

WECC seeks further clarification on Inclusion 4. Several comments were
submitted in the last round of comments whether each individual wind
turbine in a wind farm, will be included in the BES. WECC believes the
language change to I4 by the SDT did not address this issue. The current
language in I4 could be interpreted as each individual turbine (example
1MW) would be part of the BES. WECC believes that I4 is not intended to
include each individual wind turbine in a wind farm as a BES element but
rather to include the point at which the aggregation becomes large
enough to meet the aggregate capacity threshold of 75 MVA. WECC
recommends the SDT modify the language in I4 to clarify this issue.

Response: The SDT does not believe that additional clarification is needed. Inclusion I4 denotes an aggregate
threshold. This is clear from the requirement wording of “aggregate capacity greater than 75 MVA (gross
aggregate nameplate rating).” Once this aggregate threshold is met, all generation resources that comprise the
facility would be included. No change made.
Transmission Access Policy

Yes

We recommend clarifying that the dispersed power resources covered by
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Yes or No

Study Group

Florida Municipal Power
Agency

Question 5 Comment
this inclusion do not include generators on the retail side of the retail
meter. Specifically, we recommend that the Inclusion read: “Dispersed
power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily
for aggregating capacity, connected at a common point at a voltage of
100kV or above, but not including generation on the retail side of the
retail meter.”

Yes

We recommend clarifying that the dispersed power resources covered by
this inclusion do not include generators on the retail side of the retail
meter. Specifically, we recommend that the Inclusion read: “Dispersed
power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily
for aggregating capacity, connected at a common point at a voltage of
100kV or above, but not including generation on the retail side of the
retail meter.”

Response: The SDT does not believe that additional clarification is needed. The SDT further clarifies that
generating units on the customer’s side of the retail meter are not included under Inclusion I4 since customerside retail generation typically does not “utilize[e] a system designed primarily for aggregating capacity,
connected at a common point at a voltage of 100 kV or above.” No change made.
Redding Electric Utility

Yes

City of Redding

Yes

ATC LLC

Yes

City of Austin dba Austin
Energy

Yes

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Yes or No

Question 5 Comment

Georgia System Operations
Corporation

Yes

MEAG Power

Yes

Northern Wasco County
PUD

Yes

Northern Wasco County PUD agrees both with the inclusion and with the
revised language. The revised language removes the need to provide a
separate definition for “Collector System”.

Sacramento Municipal
Utility District

Yes

We support using the BES Phase 2 technical analysis to identify and
provide technical support for determining the appropriate minimum
MVA rating that the aggregation of multiple units must meet to be
considered part of the BES.
We also support using the Phase 2 studies to identify an appropriate
minimum MVA level that a single unit of the aggregation of multiple units
must be considered BES.

Oncor Electric Delivery
Company LLC

Yes

Utility Services, Inc.

Yes

Harney Electric
Cooperative, Inc.

Yes

HEC agrees with the inclusions and revised language to the definition

Central Lincoln

Yes

Central Lincoln agrees both with the inclusion and with the revised
language. The revised language removes the need to provide a separate
definition for “Collector System”.

Independent Electricity

Yes

The revised Inclusion I4 does indeed clarify that there is no requirement
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Yes or No

System Operator

Question 5 Comment
for a contiguous BES path from the dispersed generation resources to the
point of interconnection to the BES.

PSEG Services Corp

Yes

Mission Valley Power

Yes

Mission Valley Power agrees both with the inclusion and with the revised
language.
The revised language removes the need to provide a separate definition
for “Collector System”.

Puget Sound Energy

Yes

Tillamook PUD

Yes

Tillamook PUD agrees both with the inclusion and with the revised
language.
The revised language removes the need to provide a separate definition
for “Collector System”.

NV Energy

Yes

Z Global Engineering and
Energy Solutions

Yes

Metropolitan Water
District of Southern
California

Yes

Duke Energy

Yes

Ontario Power Generation
Inc.

Yes

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Yes or No

Central Hudson Gas and
Electric Corporation

Yes

City of Anaheim

Yes

Chevron U.S.A. Inc.

Yes

Southern Company

Yes

FirstEnergy Corp.

Yes

Texas Industrial Energy
Consumers

Yes

Tri-State GandT

Yes

Tennessee Valley Authority

Yes

IRC Standards Review
Committee

Yes

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

Yes

Southern Company
Generation

Yes

Dominion

Yes

Question 5 Comment

This is OK because the 75 MVA is connected at 100 kV or above.

The revised Inclusion I4 does clarify that there is no requirement for a
contiguous BES path from the dispersed generation resources to the
point of interconnection to the BES.

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Yes or No

Balancing Authority
Northern California

Yes

SERC Planning Standards
Subcommittee

Yes

SERC OC Standards Review
Group

Yes

NERC Staff Technical
Review

Yes

BGE

Yes

Question 5 Comment

No comment.

Response: Thank you for your support.

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6.

The SDT has added specific inclusions to the core definition in response to industry comments. Do you agree with Inclusion I5
(reactive resources)? If you do not support this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.

Summary Consideration: In response to comments, the SDT added further clarification to Inclusion I5 to exclude small generators that
would be improperly brought into the BES.
The SDT believes Inclusion I5 incorporates the necessary resources for the reliable operation of the BES, without unintentionally
including any distribution devices, or including any of the dedicated transformers which are not identified in the core definition or
Inclusion I1.
Additionally, Exclusion E4 will further exclude those non-generator Reactive Power resource devices that were identified through the
core definition or through Inclusion I5 which are on the load side of the customer meter solely for the customer’s own use.
Using a threshold for inclusion of non-generator Reactive Power resource devices in the BES will be considered in Phase 2 of this effort.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects
(i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being
responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012,
and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a change
from the current values that exist through the application of the definition today. These and similar issues have prompted the SDT to
separate the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities.
Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2
of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing
Committees, to develop analyses which will properly assess the threshold values and provide compelling justification for modifications
to the existing values.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are connected at 100 kV
or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated
in Inclusion I1.

Organization

Yes or No

Question 6 Comment
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Yes or No

Question 6 Comment

SERC OC Standards Review
Group

No

We feel that this inclusion should be limited to dynamic devices with an aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating) connected through a
common point.

Tennessee Valley Authority

No

TVA feels that this inclusion should be limited to dynamic devices with an aggregate
capacity greater than 75 MVAR (gross aggregate nameplate rating) connected through
a common point at a voltage of 200kV or above, and requests that the Phase 2 for the
project use 75 MVAR connected at 200kV or above or develop a transmission voltage
and/or an MVAR threshold that is technically based.

Tri-State GandT

No

There should be a limitation on what reactive components needs to be included. The
limits could be based on capacity of the units or on the voltage step that occurs upon
switching of the device.

Western Area Power
Administration

No

This inclusion should be worded to only include static or dynamic reactive devices
which are necessary to meet the NERC Planning Criteria in terms of normal and postdisturbance voltage profiles. We shouldn't have to include smaller shunt cap banks
and reactors which are used primarily for voltage support (not voltage collapse).
Recommendation: Change I5 to read - Static or dynamic devices dedicated to
supplying or absorbing Reactive Power which are necessary to meet the NERC
Planning Criteria in terms of normal and post-disturbance voltage profiles that are
connected at 100 kV or higher, or through a dedicated transformer with a high-side
voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1

Southern Company

No

We believe that the size of the reactive power resource should be considered as a key
factor to be part of BES. When considering generating resources, the size, e.g.,
greater than 75 MVA, was a key part of criteria to be included or excluded as BES. A
similar approach should be applied when considering reactive power resources. We
also suggest the removal of static reactive resources from this inclusion.

Response: Using a threshold for inclusion of non-generator Reactive Power resource devices in the BES will be considered in
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Yes or No

Question 6 Comment

Phase 2 of this effort. The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT
has responsibilities associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in
regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of
strong technical justifications that would warrant a change from the current values that exist through the application of the
definition today. These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT
to address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all
recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17
Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for modifications to the
existing values. No change made.
New York State Dept of Public
Service

No

I5 - which has been newly added and significantly expands the BES definition - should
be dropped due to lack of technical justification.

Northeast Power Coordinating
Council

No

Technical studies need to be conducted to confirm reactive resource impacts on the
reliability of the BES. The inclusion of reactive resources is a significant expansion of
the current BES definition and therefore requires technical justification for inclusion.
Inclusion I5 as written is confusing with a reference to Inclusion I1 in the definition.
Suggest removing references to reactive resources from Phase 1 until technical
justification can be demonstrated (as part of Phase 2).

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects of the definition. However, the SDT has responsibilities associated with being responsive to the directives
established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not
afforded the SDT with sufficient time for the development of strong technical justifications. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will provide compelling justification.

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Yes or No

Question 6 Comment

No change made.
Southwest Power Pool
Standards Review Team

No

We understand that this inclusion is used to capture those devices other than
generation resources, but the language leads us to believe that it could include all
generators used to supply or absorb reactive power. We would suggest that I5 be
changed to read “-Static or dynamic devices specifically used for supplying or
absorbing Reactive Power that are connected at 100 kV or higher, or through a
dedicated transformer with a high-side voltage of 100 kV or higher, or through a
transformer that is designated in Inclusion I1.

Consumers Energy

No

This inclusion appears to pull small generators that have an AVR that are connected to
138 kV into the BES. These generators are primarily intended to provide real power.

Response: The SDT added further clarifications to Inclusion I5 to specifically exclude generators.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are connected at
100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through a transformer that
is designated in Inclusion I1.
Dominion

No

The language in the last part of Inclusion I5 “....or through a transformer that is
designated in Inclusion I1” introduces ambiguity. Specifically, it is not clear how
implememtation of this language would result in the inclusion of any Static or dynamic
device that is not already included. Dominion suggests that the language in I5 be
revised to read “Static or dynamic devices dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or connected through a
dedicated transformer with at least one terminal voltage of 100 kV or higher.”
Dominion understands that the SDT intended for this Inclusion to not address
generators or power producing resources because they are covered elsewhere (I2 and
I4) and requests that the SDT confirm this understanding.

Response: The SDT believes these qualifications on non-generator Reactive Power resource devices in Inclusion I5 do include the
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Question 6 Comment

necessary resources for the reliable operation of the BES, without unintentionally including any distribution devices, or including
any of the dedicated transformers which are not identified in the core definition or Inclusion I1. No change made.
The SDT confirms that Dominion’s understanding of the intent of this inclusion is correct.
In response to comments, the SDT added further clarifications to Inclusion I5.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are
connected at 100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through
a transformer that is designated in Inclusion I1.
Pepco Holdings Inc and
Affiliates

No

Agree in principle. However, the last phrase “or through a transformer that is
designated in Inclusion I1” is unnecessary, since if the resource were connected
through a transformer meeting Inclusion I1 it would by nature be connected at 100kV
or higher.

Response: The SDT believes the Inclusion I1 wording is necessary to capture those devices dedicated to supplying or absorbing
Reactive Power. No change made.
MRO NERC Standards Review
Forum (NSRF)

No

NSRF recommends the following proposed language for I5 to address the concern:"I5 Static or dynamic devices which 1) are dedicated to supplying or absorbing Reactive
Power that are connected at 100 kV or higher, or through a dedicated transformer
with a high-side voltage of 100 kV or higher, or through a transformer that is
designated in Inclusion I1 and 2) are pertinent to meeting the NERC Planning Criteria
in terms of normal and post-disturbance voltage profiles."

Response: The SDT does not believe this change provides additional clarity as it diverts from the bright-line concept. No change
made.
PacifiCorp

No

PacifiCorp recommends the addition of the phrase “...unless excluded under E1 or E3.”
Otherwise, PacifiCorp believes that I5 is currently acceptable. However, phase II
should identify limits and technically justify the appropriate limit(s).

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Yes or No

Question 6 Comment

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element.
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Yes or No

Question 6 Comment

Using a threshold for inclusion of non-generator Reactive Power resource devices in the BES will be considered in Phase 2 of this
effort. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values.
Massachusetts Department of
Public Utilities

No

The inclusion of all devices that supply reactive power to the BES is unnecessary and
will result in unjustified costs to the ratepayer. Static devices (fixed capacitors) should
remain excluded from the BES as they are dispatched by operations personnel, and if
one fixed capacitor bank fails, the operator can replace its impact by switching in
another fixed bank. This represents routine operation of the system. On the other
hand, dynamic devices may be important to maintaining voltage stability of the
system. These installations typically are rated to supply or absorb 75 MVA or more to
or from the BES. Therefore, the MA DPU suggests that dynamic reactive power devices
rated at 75 MVA or more could be included in the BES.
Further, revised inclusion I5 is a new inclusion that lacks definition (and appears to be
redundant with the general BES definition). NERC should provide technical
justification for the additional language under Inclusion I5.

NESCOE

No

NESCOE believes that inclusion of all devices that supply reactive power to the BES is
unnecessary and will result in transferring unjustified costs to the ratepayer. Static
devices (fixed capacitors) should remain excluded from the BES as they are dispatched
by operations personnel, and if one fixed capacitor bank fails, the operator can replace
its impact by switching in another fixed bank. This represents routine operation of the
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Question 6 Comment
system. On the other hand, dynamic devices may be important to maintaining voltage
stability of the system. These installations typically are rated to supply or absorb 75
MVA or more to or from the BES. Therefore, NESCOE suggests that dynamic reactive
power devices rated at 75 MVA or more be included in the BES.
Further, revised inclusion I5 is a new inclusion that lacks definition (and appears to be
redundant with the general BES definition). NERC should provide additional technical
justification for the additional language under Inclusion I5.

Response: The SDT believes these qualifications on non-generator Reactive Power resource devices in Inclusion I5 do include the
necessary resources for the reliable operation of the BES, without unintentionally including any distribution devices, or including
any of the dedicated transformers which are not identified in the core definition or Inclusion I1. No change made.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects of the BES definition. However, the SDT has responsibilities associated with being responsive to the directives
established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not
afforded the SDT with sufficient time for the development of strong technical justifications. These and similar issues have
prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will provide compelling justifications.
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)

No

CLPD has several concerns about the new language in Inclusion 5. First, because
Reactive Power devices produce power, they are “power producing resources” and we
therefore believe Inclusion 5 is duplicative of Inclusion 4, which addresses “power
producing devices.”

Central Electric Cooperatve
(CEC)

Second, there is no capacity threshold specified in Inclusion 5 for Reactive Power
devices that would be considered part of the BES. This is inconsistent with the
approach taken in the balance of the definition, where thresholds are specified for
generators and other types of power producing devices.

Clearwater Power Company

Finally, CLPD believes the appropriate threshold for inclusion or exclusion of Reactive
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(CPC)
Snohomish County PUD

Yes or No

Question 6 Comment
Power devices from the BES should be subject to the same technical analysis that will
cover generators in the Phase 2 process.

Consumer's Power Inc
Douglas Electric Cooperative
(DEC)
Fall River Rural Electric
Cooperative (FALL)
Lane Electric Cooperative
(LEC)
Lincoln Electric Cooperative
(LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric Cooperative
(UEC)
Kootenai Electric Cooperative
Cowlitz County PUD
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Michigan Public Power Agency

Yes or No

Question 6 Comment

No

MPPA has several concerns about the new language in Inclusion 5. First, because
Reactive Power devices produce power, they are “power producing resources” and we
therefore believe Inclusion 5 is duplicative of Inclusion 4, which addresses “power
producing devices.”
Second, there is no capacity threshold specified in Inclusion 5 for Reactive Power
devices that would be considered part of the BES. This is inconsistent with the
approach taken in the balance of the definition, where thresholds are specified for
generators and other types of power producing devices.
Finally, MPPA believes the appropriate threshold for inclusion or exclusion of Reactive
Power devices from the BES should be subject to the same technical analysis that will
cover generators in the Phase 2 process. Without such analysis either: 1) no threshold
except for those connected at 100kV, or: 2) of .95 power factor of a 20 MVA
generator, or 6 MVAr and use the fact that most Facility Connection Requirements
require a power factor in the range of between 0.85 - 0.9 lagging to 0.9 - 0.95 leading
for a generator. Hence, a 20 MVA generator (the smallest to meet the registry
criteria) will need to absorb a minimum of 6 MVAr and use that as the technical
justification.

Response: The SDT added further clarifications to Inclusion I5 to address your concerns and those of others.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are
connected at 100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through
a transformer that is designated in Inclusion I1.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications
that would warrant a change from the current values that exist through the application of the definition today. These and similar
issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
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Question 6 Comment

aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values. No change made. .
Ontario Power Generation Inc.

No

OPG recommends that the wording of this inclusion be made clear that the BES
boundary extends to the Low Voltage terminals of the transformer, used in the
interface connection, and does not include the static or dynamic reactive power
source itself unless it is directly connected to the BES.

Response: The SDT refers the commenter to Inclusion I1 which addresses the situation presented here when used in
conjunction with Inclusion I5. No change made.
Metropolitan Water District of
Southern California

No

Inclusion 5 should be changed to be consistent with the core definition and to clarify
Reactive Power devices. Under I5, the additional phrase "or through a dedicated
transformer with a high side voltage of 100 kV or higher," appears to conflict with the
core definition's phrase "and Real Power and Reactive Power resources connected at
100 kV or higher". For example, if you have a device connected to a 69Kv system
which is used solely for an end-user's load, but the 69kv system is transformed up to a
115kV system, such device could be included as BES or you would have to define what
is meant by "dedicated. If Reactive Power is meant to agree with the definition under
NERC's Glossary of Terms, there should be consistency and less verbiage.
MWDSC also agrees with WECC's comment that there should be some minimum
threshold for Reactive Power devices similar to that identified for generating
resources in Inclusion 2.
MWDSC recommends that Inclusion 5 be changed as follows: I5 - "Reactive Power
devices dedicated to support the BES that are connected at 100kV or higher, or
through a transformer that is designated in Inclusion I1."

Response: The SDT does not believe that a contradiction exists. Proper application of the definition and inclusions (see
explanation of process immediately following) would seem to preclude the situation described by the commenter. No change
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made.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify
the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between
BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected
at 100 kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term
Element is needed. Element as defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions
I2 – I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local
networks) should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion
I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion
I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
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Question 6 Comment

the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications
that would warrant a change from the current values that exist through the application of the definition today. These and similar
issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values. No change made.
The SDT does not believe this change provides additional clarity. No change made.
LCRA Transmission Services
Corporation

No

This inclusion conflicts with exclusion E4. Which one takes priority?

Duke Energy

No

Need to add the exception for exclusions under E1 or E3, and also reword to exclude
devices connected to a transformer winding less than 100 kV unless that is the only
connection to that winding. Suggested rewording of I5 : “Unless excluded under
Exclusions E1 or E3, static or dynamic devices dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage or 100 kV or higher, or through a transformer
winding less than 100 kV that is designated in Inclusion I1 if the winding does not have
any circuits or load connected to it.” This would eliminate having to include a
capacitor connected to the 69 kV winding of a three winding BES transformer such as
230/138/69 kV if that winding had other connections such as 69 kV circuits. The
voltage threshold of 100 kV and above should capture devices connected to 100 kV or

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Question 6 Comment
higher windings of transformers designated in Inclusion I1.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
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Question 6 Comment

Tacoma Power

No

Tacoma Power generally supports the intent of Inclusion I5 as currently written.
However, we believe the definition of the MVAr threshold level must be included in
the Phase 2 evaluation and should be determined in a similar manner to the generator
threshold that will be determined for I2.

Farmington Electric Utility
System

No

I5 should be modified to identify a minimum Reactive Power threshold for static or
dynamic devices. As drafted a 1 MVA device supplying or absorbing Reactive Power
that is connected at 100 kV or higher would be included in the BES.

MEAG Power

No

We feel that this inclusion should be limited to dynamic devices with an aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating) connected through a
common point.

Harney Electric Cooperative,
Inc.

No

HEC believes this inclusion should include a technically justified capacity limit on
reactive resources to warrant inclusion.

City of St. George

No

A reasonable minimum value for inclusion should be added. As presently written all
static or dynamic devices would be included in the BES regardless of size.

Tillamook PUD

No

While we agree that reactive devices of sizable capacity connected at 100 kV or higher
are needed for BES reliability, Tillamook PUD fails to see why this inclusion is needed
as they are already captured by the 100 kV threshold. We would propose instead to
eliminate this inclusion and substitute an exclusion for smaller capacity devices.

include or exclude an Element.

If the SDT really believes an inclusion for reactive devices is needed, we suggest the
SDT provide a technically justified capacity limit within the inclusion. In addition we
suggest also including the phrase “...unless excluded under Exclusion E1, E2 or E4”
similar to that in I1.

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Mission Valley Power

Yes or No

Question 6 Comment

No

Mission Valley Power - While we agree that reactive devices of sizable capacity
connected at 100 kV or higher are needed for BES reliability, Mission Valley Power fails
to see why this inclusion is needed as they are already captured by the 100 kV
threshold. We would propose instead to eliminate this inclusion and substitute an
exclusion for smaller capacity devices. If the SDT really believes an inclusion for
reactive devices is needed, we suggest the SDT provide a technically justified capacity
limit within the inclusion. In addition we suggest also including the phrase “...unless
excluded under Exclusion E1, E2 or E4” similar to that in I1. Please see the answer to
Q1 above Q10 below.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values. No change
made.
Consolidated Edison Co. of NY,
Inc.

No

Normally, static and dynamic devices supply Reactive Power (VARs) to or absorb VARs
from the surrounding system. By their nature, VARs do not travel far, e.g., miles. So,
VARs by their nature only produce local impacts. Please explain the meaning of the
phrase “dedicated to supplying or absorbing Reactive Power,” with emphasis on
explaining why the term “dedicated” was employed?
How does an Entity determine if a particular static or dynamic device is “dedicated” to
the BES? What Guidance documents can the BES SDT provide describing “dedicated”

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Question 6 Comment
static and dynamic devices?

Response: The word 'dedicated' was used to identify those Elements whose sole purpose is supplying or absorbing Reactive Power.
The language limits those devices dedicated to voltages at 100 kV and higher (via the core definition or through Inclusion I5),
unless it can be excluded via Exclusion E4.
American Electric Power

No

I5 only specifies voltage limits, and makes no mention of reactive limits. We suggest
that the drafting team consider adding reactive capacity to these criteria as well.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values. No change
made.
South Houston Green Power,
LLC

No

The phrase should be added at the end “unless excluded under Exclusion E4”.

National Grid

No

We see some potential conflicts between this inclusion and the exclusions. Without
some additional wording, it seems like some devices that are in a Local Distribution
Network would be considered BES. In addition, reference to a transformer in Inclusion
I1 is not necessary since the definition includes “all Transmission Elements operated at
100 kV”, thus by definition and I5, those connected to 100 kV and higher are already
included. We suggest: Static or dynamic devices dedicated to supplying or absorbing
Reactive Power that are connected at 100kV or higher unless the device is in an area
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Question 6 Comment
excluded from BES by Exclusion E1 or E3, or through a dedicated transformer with a
high-side voltage of 100kV or higher, unless excluded by Exclusion E4.

Orange and Rockland Utilities,
Inc.

No

Should also mention "unless excluded under Exclusion E1 or E3".

The Dow Chemical Company

No

The phrase “or through a dedicated transformer with a high-side voltage of 100 kV or
higher” is inconsistent with I1 and would bring Reactive Power Equipment that is
lower than 100Kv into the BES definition. This phrase should be deleted.
The following phrase should be added at the end “unless excluded under Exclusion
E4”.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
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Yes or No

Question 6 Comment

exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element. No change made.
Hydro-Quebec TransEnergie

No

Response: Without specific comments the SDT is unable to respond.
Northern Wasco County PUD

No

While we agree that reactive devices of sizable capacity connected at 100 kV or higher
are needed for BES reliability, Northern Wasco County PUD fails to see why this
inclusion is needed as they are already captured by the 100 kV threshold. We would
propose instead to eliminate this inclusion and substitute an exclusion for smaller
capacity devices. If the SDT really believes an inclusion for reactive devices is needed,
we suggest the SDT provide a technically justified capacity limit within the inclusion. In
addition we suggest also including the phrase “...unless excluded under Exclusion E1,
E2 or E4” similar to that in I1.
Please see the answer to Q1 above Q10 below.

Central Lincoln

No

While we agree that reactive devices of sizable capacity connected at 100 kV or higher
are needed for BES reliability, Central Lincoln fails to see why this inclusion is needed
as they are already captured by the 100 kV threshold. We would propose instead to
eliminate this inclusion and substitute an exclusion for smaller capacity devices.If the
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Question 6 Comment
SDT really believes an inclusion for reactive devices is needed, we suggest the SDT
provide a technically justified capacity limit within the inclusion.
In addition we suggest also including the phrase “...unless excluded under Exclusion
E1, E2 or E4” similar to that in I1. Please see the answer to Q1 above Q10 below.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today.
These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the
concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric
System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will
properly assess the threshold values and provide compelling justification for modifications to the existing values. No change
made.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
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Yes or No

Question 6 Comment

specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element. No change made.
Please see detailed responses to Q1 and Q10.
Ameren

No

a)Only those Reactive Power devices applied for the purpose of BES support or BES
voltage control should be included. A Reactive Power device connected at >100kV but
used for the purpose of voltage support to local load and/or needed to support local
networks should be excluded.
b)We believe that this inclusion should be limited to dynamic devices with an
aggregate capacity greater than 75 MVA (gross aggregate nameplate rating)
connected through a common point.
c)See the response to question 2: The inclusion is unclear since it includes a certain
voltage transformers, but excludes those that have E1 or E3 Exclusion criteria. Each
exclusion criteria has multiple stipulations to its applicability, and then has a final
inclusive reference to I3. Please make the wording exact and not dependent on
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Question 6 Comment
clausal statements.

Response: a) The SDT believes that the proper application of the core definition with Inclusion i1 and I5 plus the application of
Exclusions E1, E3, and E4 will cover the situation described in most applications. In the event that the BES definition incorrectly
designates an Element as BES that is not necessary for the reliable operation of the interconnected transmission network or an
Element as non-BES that is necessary for the reliable operation of the interconnected transmission network, the Rules of
Procedure exception process may be utilized on a case-by-case basis to either include or exclude an Element. No change made.
b) The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical
aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated
with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of
January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical justifications
that would warrant a change from the current values that exist through the application of the definition today. These and similar
issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of industry
stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the technical
aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT,
in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold
values and provide compelling justification for modifications to the existing values.
c) The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the
vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
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Yes or No

Question 6 Comment

application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to
either include or exclude an Element. No change made.
ExxonMobil Research and
Engineering

No

The BES SDT should work on clarifying the differences between Inclusion I5 and
Exclusion E4.
The phrase “solely for its own use” in Exclusion E4 is vague and open to interpretation.
It is unclear whether equipment, such as power factor correction facilities, surge
capacitors located in motor terminal boxes and excitation capacitors installed for use
by a motor located on the low side of a 138 kV primary transformer would be
excluded from the BES. Is the intent of this requirement to capture “reactive
resources” that provide VARs to the BES in regions that exhibit voltage stability issues?

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
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Yes or No

Question 6 Comment

non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element. No change made.
The BES definition is predicated on operations at 100 kV or higher. In the example cited, the equipment in question appears to
be below that threshold and thus is not included in the BES. No change made.
ATC LLC

No

ATC agrees with the inclusion provided the last clause is removed, as noted below.
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Yes or No

Question 6 Comment
The BES definition is intended to establish a bright line BES definition. The clause
“dedicated transformer” is undefined and unclear. Inclusion I5 -Static or dynamic
devices dedicated to supplying or absorbing Reactive Power that are connected at 100
kV or higher (deletion of remainder of clause).

Response: The SDT considered the disposition of the word “dedicated” and determined that retention of this word is necessary
to show the SDT’s intent that the conditions described by the inclusion are for configurations where the intended device is only
going through one transformation. No change made.
Westar Energy

No

We understand that I5 is being used to capture those devices other than generation
resources, but the language used leads us to believe that it could include all
generators that supply or absorb reactive power.
We also believe the language should be changed to be consistent with I1. We suggest
that I5 be changed to read: “Static or dynamic devices specifically used for supplying
or absorbing Reactive Power that are connected at 100 kV or higher, or through a
dedicated transformer with a high-side terminal operated at 100 kV or higher, or
through a transformer that is designated in Inclusion I1.”

Response: The SDT has clarified the wording of Inclusion I5 to address your concern.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are
connected at 100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through
a transformer that is designated in Inclusion I1.
The SDT does not believe your suggested wording provides additional clarity. No change made.
Florida Municipal Power
Agency

To help clarify and to avoid inclusion of de minimis reactive resources, we propose a
size threshold of 6 MVAr consistent with the smallest size generator included in the
BES at a 0.95 power factor, which is a common leading power factor used in Facility
Connection Requirements for generators. In other words, 6 MVAr is consistent with
typically the least amount of MVAr required to be absorbed by the smallest generator
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Yes or No

Question 6 Comment
meeting the registry criteria.

Redding Electric Utility

Yes

Redding believes that an appropriate MVAr level should be established during Phase
2.

City of Redding

Yes

Redding believes that an appropriate MVAr level should be established in during
Phase 2.

City of Austin dba Austin
Energy

Yes

Appropriate MVAr level should be established. Reactive resources should be treated
similar to generation criteria and included in the technical studies associated with the
Phase 2 technical analysis in order to establish the appropriate MVAr level included as
BES.

Sacramento Municipal Utility
District

Yes

However, appropriate MVAr level should be established. Reactive resources should be
treated similar to generation criteria and included in the technical studies associated
with the Phase 2 technical analysis in order to establish the appropriate MVAr level
included as BES.

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

No

There should be a limitation on what reactive components needs to be included. The
limits could be based on capacity of the units or on the voltage step that occurs upon
switching of the device

AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power

Yes

This inclusion should be limited to reactive devices 150 MVAR or greater (gross
aggregate nameplate rating) connected through a common point at the 200 kV level
or higher level.

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Question 6 Comment

Memphis Light, Gas and
Water Division

Yes

We are in general agreement with this inclusion, except that there is no threshold for
reactive resources as there is for generators and transformers. We recommend that a
minimum level be established for this equipment, such as 100 MVAr, or that studies
be conducted to determine an appropriate threshold.

Southern Company
Generation

Yes

We believe that the size of the reactive power resource should be considered as a key
factor to be part of BES. When considering generating resources, the size, e.g.,
greater than 75 MVA, was a key part of criteria to be included or excluded as BES. A
similar approach should be applied when considering reactive power resources.
Moreover, the language at the end of I5, "or through a transformer that is designated
in Inclusion I1," appears to be redundant since the reactive power resources are
connected to 100 kV or higher already without this additional language. The following
language is suggested: I5 - Static or dynamic devices dedicated to supplying or
absorbing Reactive Power that are connected at 100 kV or higher, or through a
dedicated transformer with a high-side voltage of 100 kV or higher, and with an
aggregate continuous nameplate rating greater than 30 MVA.

ACES Power Marketing
Standards Collaborators

Yes

We understand the SDT’s logic behind not setting any threshold values for reactive
resources during Phase 1 of this project. Ample time and effort should be given to
developing the technical justification behind such values. However, we encourage the
SDT to consider adding threshold values in Phase 2 of the project to provide even
more clarity to this inclusion.

Balancing Authority Northern
California

Yes

However, appropriate MVAr level should be established. Reactive resources should be
treated similar to generation criteria and included in the technical studies associated
with the Phase 2 technical analysis in order to establish the appropriate MVAr level
included as BES.

WECC Staff

Yes

WECC believes I5 should be modified to identify a minimum Reactive Power threshold

Cooperative

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Question 6 Comment
for static or dynamic devices similar to the threshold identified for generating
resources in I2. As worded, any size device dedicated to supplying or absorbing
Reactive Power that is conected at 100 kV or higher, no matter how small, would be
included in the BES.

Response: Using a threshold for inclusion of non-generator Reactive Power resource devices in the BES will be considered in Phase 2
of this effort. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values. No change made.
Springfield Utility Board

Yes

SUB agrees in general, but does not agree that ALL reactive resources should be
automatically included in the BES Definition. For example, is a local network (100 kV
or above), which is otherwise excluded, but has a reactive device used for power
factor correction (100 kV or above), still excluded? There are a significant number of
reactive resources that are used to serve systems that provide service primarily to
load, with either no or a minimal amount of generation. If this section is included, the
Exclusion language needs to be modified to exclude those reactive resources from the
BES that are radial serving only load or local networks that serve load (with less than
75MVa of generation).
SUB does not agree with the language referring to only those “retail customer”
reactive power devices for Exclusion E.4. This is too narrow and does not accurately
reflect the use of reactive power devices installed by registered entities when retail
customers do not “fix” their reactive power issues on their own. SUB recommends
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Question 6 Comment
that the language in I5 and E4 be consistent, and that “retail customer” should include
Registered Entities as well as end users. This present language is overly broad and,
absent modifications to the BES definition, will generate a significant amount of
paperwork. SUB suggests the following language change:I5 -Static or dynamic devices
dedicated to supplying or absorbing Reactive Power that:a)are connected at 100 kV or
higher and are not part of a radial system or area network that are excluded from the
BES, or;b)are connected through a dedicated transformer with a high-side voltage of
100 kV or higher and are not part of a radial system or area network that are excluded
from the BES, or;c)are connected through a transformer that is designated in Inclusion
I1 and are not part of a radial system or area network that are excluded from the BES .

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
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Yes or No

Question 6 Comment

The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element. No change made.
The SDT team considered the disposition of the word “retail” in the context of Inclusion I5, and determined that retention of this word
is important and correct. This is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the load
side of a customer meter). No change made.
FirstEnergy Corp.

Yes

While we do not object to I5, we question its need based on item I2 and believe I2 also
covers this item

Response: The SDT added further clarifications to Inclusion I5 to address your concern.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are connected at
100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through a transformer that
is designated in Inclusion I1.
Central Maine Power
Company

Yes

There is no such thing as “supplying or absorbing Reactive Power” but the intended
meaning is sufficiently clear since it is industry ‘shorthand’. We suggest an alternative
wording of: “Static or dynamic Reactive Power resources that are connected at 100
kV or higher, or...”

Rochester Gas and Electric
and New York State Electric
and Gas

Yes

There is no such thing as “supplying or absorbing Reactive Power” but the intended
meaning is sufficiently clear since it is industry ‘shorthand’. Suggest alternative
wording:”Static or dynamic Reactive Power resources that are connected at 100 kV or
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Question 6 Comment
higher, or...”

Response: The SDT elected to also include the word 'dedicated' in front of the quotation listed to identify those Elements whose sole
purpose is supplying or absorbing Reactive Power. Re-arranging the words as suggested would not capture the same effect. No
change made.
Portland General Electric
Company

Yes

Georgia System Operations
Corporation

Yes

Kansas City Power and Light
Company

Yes

Oncor Electric Delivery
Company LLC

Yes

Utility Services, Inc.

Yes

Independent Electricity
System Operator

Yes

PSEG Services Corp

Yes

ISO New England Inc

Yes

Manitoba Hydro

Yes

Long Island Power Authority

Yes

The provisions of Inclusion I5 fully address the concerns we expressed in our previous
comments.

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Organization

Yes or No

Puget Sound Energy

Yes

NV Energy

Yes

Z Global Engineering and
Energy Solutions

Yes

Central Hudson Gas and
Electric Corporation

Yes

City of Anaheim

Yes

Chevron U.S.A. Inc.

Yes

Idaho Falls Power

Yes

ReliabilityFirst

Yes

Exelon

Yes

Texas Industrial Energy
Consumers

Yes

Hydro One Networks Inc.

Yes

IRC Standards Review
Committee

Yes

Transmission Access Policy
Study Group

Yes

Question 6 Comment

The SDT has appropriately captured the necessary inclusion of high voltage
transmission reactive resources.

We have no comments.

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Organization

Yes or No

Electricity Consumers
Resource Council (ELCON)

Yes

Bonneville Power
Administration

Yes

Texas RE NERC Standards
Subcommittee

Yes

SERC Planning Standards
Subcommittee

Yes

NERC Staff Technical Review

Yes

BGE

Yes

Question 6 Comment

No comment.

Response: Thank you for your support.

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7.

The SDT has revised the specific exclusions to the core definition in response to industry comments. Do you agree with
Exclusion E1 (radial system)? If you do not support this change or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: Exclusion E1 is an exclusion for the contiguous transmission Elements connected at or above 100 kV.
Generation resources connected within the radial system are qualifiers for this exclusion.
The “single point of connection of 100 kV or higher” is where the radial system will begin if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the radial
system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the transmission line
will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker and a half bus
configuration could also be the beginning of the radial system and the owner of the bus would need to insure the reliability of the
substation.
Furthermore, the SDT believes that radial systems cannot have multiple connections at 100 kV or higher. Networks that have multiple
connections at 100 kV or higher may qualify for exclusion under Exclusion E3. The owner always has the option to seek exclusion
through the exception process.
The SDT considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that retention of this word – in
lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be included in the term
“Element”.

The SDT has determined that it should be conservative with regard to allowing exclusion for radial systems that are depended upon for
blackstart functionality, as these will arguably be more important to the reliable operation of the transmission system than equivalent
radial systems without blackstart resources.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “non-retail
generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is important to retain
this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation to be unfairly biased against
obtaining this exclusion.

Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of connected
(non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the interconnected
transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be consistent with the existing

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threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of further review under Phase 2
development of the BES definition.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not prevent the
owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is operated in the
normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in the normal operating
environment.
No changes were made to Exclusion E1 due to received comments.
Organization
NERC Staff Technical Review

Yes or No

Question 7 Comment

No

While we appreciate the improvement in the text for Exclusion E1, but we continue to
believe that E1 should require (i) the normally open switch must not be used to make
a parallel connection if the normally switch is operated at 100 kV or higher and
(ii) an automatic interrupting device that is part of the BES must be provided at the
point of interconnection between the radial system and the BES.

American Electric Power

No

AEP supports the concept of the exclusion of radial systems, however further
clarification is needed regarding whether or not the source equipment is included as
part of the radial system (for example, ring bus or breaker and a half bus
configurations).
Regarding the following text: “Note - A normally open switching device between radial
systems, as depicted on prints or one-line diagrams for example, does not affect this
exclusion.” We interpret this as not including two radial lines which could be tied
together through a normally open switch, are we correct? Additional clarity may be
needed regarding this note.

Response: Radial systems should be assessed with the normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch
is used in the normal operating environment. No change made.
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Question 7 Comment

The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the
radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial and the owner of the bus would need to insure the
reliability of the substation. No change made.
Northeast Power Coordinating
Council

No

E1 can be simplified by not dividing in three subsets of a, b and c. The end result is
that a Radial system is excluded if it does not have more than 75 MVA aggregate nonretail generation.
There seems to be an error with reference to I3. Black start unit paths are not
designated as BES and were taken out in this version under I3 so E1 and E3 should not
reference I3. This contradicts the radial or LN exclusion from I3. Suggest deleting the
reference to I3 in E1 and E3 because this reference is in contradiction to I3. I3 does
not require a path to be BES, but it implied that a radial cannot be excluded if there is
a black start unit on the radial.
Further clarification is needed to the language in the Note referring to the “Normally
Open switch”. The E1 reference Note should be re-worded to state “Radial systems
shall be assessed with all normally open switching devices in their open positions.”
Explanatory figures should be included to illustrate the system configurations
addressed. Black start unit paths must be considered in the construction of E1.
In E1c, what is meant by “non-retail”?

Response: The SDT believes that the distinction between Load only, generation only, and Load with generation provides a
bright-line exclusion for radial systems that is needed to cover all of the possible scenarios. No change made.
The SDT appreciates the suggestion that there could be an appearance of an inconsistency between Inclusion I3 and Exclusions
E1 and E3. The SDT has determined that it should be conservative with regard to allowing exclusion for radial systems that are
depended upon for blackstart functionality, as these will arguably be more important to the reliable operation of the
transmission system than equivalent radial systems without Blackstart Resources. No change made.
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Organization

Yes or No

Question 7 Comment

The SDT agrees that the radial systems should be assessed with all normally open (NO) switches in the open position and these
NO switches will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to
indicate the switch is operated in the normally open position; however, it is the owner and operator’s responsibility to indicate
how a switch is used in the normal operating environment.
Non-retail generation is the generation on the system (supply) side of the meter.
Consumers Energy

No

In general we agree, but believe the word "transmission" should be removed from "A
group of contiguous transmission Elements..."

Southwest Power Pool
Standards Review Team

No

Why was the defined term for “T”ransmission dropped in this version of the
definition? This should be kept in this version of the definition as well.

Response: The SDT team considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that
retention of this word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would
otherwise be included in the term “Element”. No change made.

Bonneville Power
Administration

No

BPA believes that a system left connected in a network configuration, via use of a
normally open switch for temporary network connection, without the protections
afforded through the standards that apply to BES should be limited to less than 24
hours.
BPA believes that the term “non-retail generation” in E1(c) should be clearly defined.
In addition, BPA believes that there needs to be a means to isolate the radial system
from the BES during a fault on the radial system by means of a automatic fault
interrupting device. Automatic fault interrupting device should be a defined term.

Response: The exclusion for radial systems does not provide requirements in the operating environment. Any attempt to hard
code time duration into the exclusion language will create any number of one off situations when applied on a continent-wide
basis. It is the owner and operator’s responsibility to indicate how a switch is used in the normal operating environment. No
change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “non226

Organization

Yes or No

Question 7 Comment

retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation to
be unfairly biased against obtaining this exclusion. No change made.

The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the
radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. No change made.
Dominion

No

Dominion does not agree that exclusion of a radial should be based upon the
aggregate capacity of generation. A radial serving only generation should be excluded
just as it is for load (as proposed by the SDT in 1a). No reliability gaps exist since the
owner and/or operator of generation (with an individual with gross individual or gross
aggregate nameplate rating per the ERO Statement of Compliance Registry Criteria)
must comply with applicable reliability standards.
Dominion requests that the SDT provide technical justification for E1a and E1b as it did
for E3, and explain the intent of the footnote in E1.

Response: The SDT believes that a limit on the aggregate amount of connected (non-retail) generation within the radial system
is necessary to ensure that there is no reliability impact on the interconnected transmission system; however, the threshold of
the allowable generation – 75 MVA – was chosen to be consistent with the existing threshold in the NERC Statement of
Compliance Registry Criteria, and this threshold is a subject of further review under Phase 2 of the BES definition. No change
made.
Exclusion E1.a is a retained exclusion form the existing definition and as such requires no technical justification at this time.
As for Exclusion E1.b, the SDT acknowledges and appreciates the comments and recommendations associated with modifications to
the technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
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justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
The SDT believe that the radial systems should be assessed with all normally open (NO) switches in the open position and these
NO switches will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to
indicate the switch is operated in the normally open position; however, it is the owner and operator’s responsibility to indicate
how a switch is used in the normal operating environment.
Pepco Holdings Inc and
Affiliates

No

1) Additional clarification is needed on whether certain bus sections supplying radial
systems would be considered part of the BES. It is critical that the BES definition
address this issue, since it will define what transmission Protection Systems fall in
scope for PRC-004 and 005. One way to address this issue would be to add a qualifier
to Exclusion E1 that states, “if a radial system is supplied from a bus section in a
substation, then this bus section is considered part of the radial system and is not
considered part of the BES if the tripping of this bus section does not result in an
interruption to any BES facilities when the station is operating in its normal
configuration.”
2) Since the SDT deleted the inclusion of Black Start Cranking Paths in I3 then
reference to I3 in criteria E1b and E1c should also be removed. Limits on connected
generation should only be constrained by the 75MVA limit. In summary, delete the
phrase “not identified in Inclusion I3” from both Exclusions E1b and E1c.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial and the owner of the bus would need to insure
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the reliability of the substation. No change made.
The SDT appreciates the suggestion that there could be an appearance of an inconsistency between Inclusion I3 and Exclusions
E1 and E3. The SDT has determined that it should be conservative with regard to allowing exclusion for radial systems that are
depended upon for blackstart functionality, as these will arguably be more important to the reliable operation of the
transmission system than equivalent radial systems without Blackstart Resources. No change made.
Southern Company
Generation

No

Subpart (b) uses the term "generation resources" while subpart (c) uses the term
"non-retail generation", why are these different terms used?
Further, why is it important that the term "non-retail generation" is used in subpart
(c)? In addition, the SDT needs to clarify what the term "non-retail generation"
means. Is this what is commonly referred to as "customer owned" or "behind-themeter" generation?
The change in version 2 that removed the requirement that an excluded radial system
have an automatic interruption device at the single point of connection to the rest of
the BES creates a problem. Three-terminal circuits are common below 230 kV. The
"tapped portion" should not be left out of the BES since a fault on that portion takes
out the whole line. We propose this revised language in the first sentence on E1: “E1
- Radial systems: A group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher, where the connection has an automatic
interruption device,...”
Exclusion E1, subpart (c) uses the phrase "an aggregate capacity of ... less than or
equal to 75 MVA ...". Exclusion E3. subpart (a) provides that the local networks "do
not have an aggregate capacity of ... greater than 75 MVA ...". Why are these phrases
stated differently even though they appear to address the same resources?

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the
term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter.
It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation
to be unfairly biased against obtaining this exclusion.

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The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the
radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial and the owner of the bus would need to insure the
reliability of the substation. No change made.
The SDT believes that a limit on the aggregate amount of connected (non-retail) generation within the radial system is necessary
to ensure that there is no reliability impact on the interconnected transmission system; however, the threshold of the allowable
generation – 75 MVA – was chosen to be consistent with the existing threshold in the ERO Statement of Compliance Registry
Criteria, and this threshold is a subject of further review under Phase 2 of the BES definition. No change made.
IRC Standards Review
Committee

No

While we support the provisions of E1 in principle, we are seeking clarification to the
following issues. Does the connection voltage of generation referred to in E1.b affect
whether a radial system could be excluded under E1?
Please clarify the meaning of “non-retail” generation used in E1.c.

Response: Exclusion E1 is an exclusion for the contiguous transmission Elements connected at or above 100 kV. Generation
resources connected within the radial system are qualifiers for this exclusion. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term
“non-retail generation” in E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail
generation to be unfairly biased against obtaining this exclusion. No change made.
Hydro One Networks Inc.

No

Although we agree with the exclusion of radial systems, we believe that the reliability
of the interconnected transmission network should not be determined by the amount
of installed generation on the radial system. We believe that the generation limit is
restrictive and has little or no technical basis. It is not the size of a unit on the radial
system that should determine the reliability impact on the BES but more importantly
its location, configuration and system characteristics such as reliability must run unit.
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We believe that there is no reason to divide E1 in three subsets of a, b and c. The end
result is that a radial system is excluded if it does not have more than 75 MW of
aggregate non-retail generation. However, consistent with E2 we suggest replacing
"an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating)" with "a maximum net capacity of non-retail generation provided to
the BES of 75 MVA."
We suggest deleting the references to I3 in E1 and E3 because we believe that this
reference is in contradiction to I3 and probably an oversight and should be corrected.
I3 does not require path to be BES but it implies here that a radial system cannot be
excluded if there is a Blackstart unit on it.

Response: The SDT believes that the distinction between Load only, generation only, and Load with generation provides a
bright-line exclusion for radial systems that is needed to cover all of the possible scenarios. No change made.
Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
The SDT appreciates the suggestion that there could be an appearance of an inconsistency between Inclusion I3 and Exclusions
E1 and E3. The SDT has determined that it should be conservative with regard to allowing exclusion for radial systems that are
depended upon for blackstart functionality, as these will arguably be more important to the reliable operation of the
transmission system than equivalent radial systems without Blackstart Resources. No change made.
Southern Company

No

Subpart (b) uses the term "generation resources" while subpart (c) uses the term
"non-retail generation", why are these different terms used? Further, why is it
important that the term "non-retail generation" is used in subpart (c)? In addition, the
SDT needs to clarify what the term "non-retail generation" means. Is this what is
commonly referred to as "customer owned" or "behind-the-meter" generation?
The change in version 2 that removed the requirement that an excluded radial system
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Question 7 Comment
have an automatic interruption device at the single point of connection to the rest of
the BES creates a problem. Three-terminal circuits are common below 230 kV. The
"tapped portion" should not be left out of the BES since a fault on that portion takes
out the whole line. We propose this revised language in the first sentence on E1: “E1
- Radial systems: A group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher, where the connection has an automatic
interruption device,...”Exclusion E1, subpart (c) uses the phrase "an aggregate capacity
of ... less than or equal to 75 MVA ...".
Exclusion E3. subpart (a) provides that the local networks "do not have an aggregate
capacity of ... greater than 75 MVA ...". Why are these phrases stated differently even
though they appear to address the same resources?

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the
term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter.
It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation
to be unfairly biased against obtaining this exclusion. No change made.
The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the
radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. No change made.
The SDT believes that a limit on the aggregate amount of connected (non-retail) generation within the radial system is necessary
to ensure that there is no reliability impact on the interconnected transmission system; however, the threshold of the allowable
generation – 75 MVA – was chosen to be consistent with the existing threshold in the ERO Statement of Compliance Registry
Criteria, and this threshold is a subject of further review under Phase 2 of the BES definition. No change made.
ReliabilityFirst

No

The term radial must be specifically defined in this application. ReliabilityFirst Staff
believes this to mean a true radial in the sense that an adverse impact by the radial
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Question 7 Comment
facilities does NOT affect or impact BES facilities.
In the first sentence the word “Element” is capitalized but “transmission” is not, we
believe both terms should be capitalized.
The phrase “single point of connection” should have guidance so that everyone
reading this definition reads the single point of interconnection the same. Some have
read this phrase to be a single substation, while others have read this phrase to be one
and only one line or supply (i.e. interconnection point), which is it?
The “Note” we disagree with. In any and all cases if there is any operation or use of
the BES, the facilities should be included. By the wording of this exclusion, one cannot
determine if taps (sections of line from a BES transmission line to a single substation)
are intended to be included in the BES or not. More specifically, where does the radial
facility begin and the BES end? This determination was clearer in the previous version
of the definition with the use of the language “...originating with an automatic
interruption device...”.

Response: The SDT team considered the disposition of the word “transmission” in the context of Exclusion E1, and determined
that retention of this word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the
generation that would otherwise be included in the term “Element”. No change made.
The “single point of connection of 100 kV or higher” is where the radial will begin, if it meets the language of Exclusion E1
including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start of the
radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial and the owner of the bus would need to insure the
reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at 100 kV or
higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner always has the
option to seek exclusion through the exception process. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
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Question 7 Comment

in the normal operating environment. No change made.
Ontario Power Generation Inc.

No

Non-retail generation needs to be properly defined in the text of the exclusion.

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized
the term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the
retail meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local
networks with retail generation to be unfairly biased against obtaining this exclusion.
City of St. George

No

Radial systems should be excluded as generally outlined in E1, however the generation
levels (of 75 MVA) are too restrictive. The primary criteria should be, does power flow
into the radial system? If there is always flow into the radial system, generation levels
should not prevent exclusion from the BES.

City of Anaheim

No

The City of Anaheim recommends either changing the E1 (b) language back to that of
the previous BES definition draft, i.e. 75 MVA or above connected at 100 kV or above,
or limit the amount of generation allowed within a Radial Element or Local Network to
300 MVA or less, which is the amount of uncontrolled load loss that constitutes a
reportable "disturbance" pursuant to EOP-004 and DOE Form OE-417. If DOE and
NERC do not consider a 300 MW uncontrolled loss of load a reportable event, then
why would the potential loss of a 75 MVA of non-critical generator connected at 69 kV
make a Radial Element or Local Network critical to the reliability of the BES? The
current ERO Statement of Compliance Criteria does not require GO/GOP registration
for generation connected below 100 kV as long as it's not critical to the reliability of
the BES, i.e. black start, etc., even if the amount of generation is greater than 75 MVA.
There is good reason for this because the mere loss of 75 MVA generator would not
affect the reliability of a system as big as the Western Interconnection, at all, and a
fault at say 69 kV would have sufficient impedance not to affect the BES from an
electrical perspective.

Response: Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate
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amount of connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on
the interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the NERC Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
Xcel Energy

No

Xcel Energy believes that some more definition is required to clarify the intent of the
note under Exclusion E1 related to normal open switching device. A direct statement
would remove any ambiguity, such as “a normally open switch in a system that could
be interconnected or experience loop flows will be considered (BES/non BES)”.

Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch
is used in the normal operating environment. No change made.
Northern Wasco County PUD

No

Northern Wasco County PUD notes that a new term has been introduced, “non-retail
generation,” with no definition provided. The answer to the question on this during
the 9/28 webinar indicated that non-retail generation was behind the retail
customer’s meter. We can see no reason why the net-metered PV systems should
count toward the aggregate limit (exceeding the limit means no exclusion) while a
non-blackstart thermal plant doesn’t (the radial system is excluded if any amount of
load is present). We have also heard the SDT meant just the opposite of what was
stated in the webinar. We ask that a reasonable definition for non-retail be provided
within the BES definition document.
We strongly agree that radial systems should be excluded and that the presence of
normally open switching devices between radial systems should not cause them to be
considered non-radial. Such a result would cause the removal of these devices to the
detriment of the local level of service. We note that the singular “A normally open
switching device” is used and suggest that an allowance be made for the possibility of
multiple devices. “Normally open switching devices...”
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Question 7 Comment

LCRA Transmission Services
Corporation

No

The current wording is unclear with respect to the treatment of normally open
switching devices. LCRA TSC suggests the following language to replace the existing
language on the note to E1: “Two radial systems connected by a normally open,
manually operated switching device, as depicted on prints or one-line diagrams for
example, may be considered as radial systems under this exclusion.” The current
wording is unclear with respect to “non-retail generation”. The sudden loss of large,
radial-supplied load may result in reliability deficiencies. LCRA TSC suggests stating a
load level or a load capacity in the exclusion.

Tillamook PUD

No

Tillamook PUD notes that a new term has been introduced, “non-retail generation,”
with no definition provided. The answer to the question on this during the 9/28
webinar indicated that non-retail generation was behind the retail customer’s meter.
We can see no reason why the net-metered PV systems should count toward the
aggregate limit (exceeding the limit means no exclusion) while a non-blackstart
thermal plant doesn’t (the radial system is excluded if any amount of load is present).
We have also heard the SDT meant just the opposite of what was stated in the
webinar. We ask that a reasonable definition for non-retail be provided within the BES
definition document.We strongly agree that radial systems should be excluded and
that the presence of normally open switching devices between radial systems should
not cause them to be considered non-radial. Such a result would cause the removal of
these devices to the detriment of the local level of service. We note that the singular
“A normally open switching device” is used and suggest that an allowance be made for
the possibility of multiple devices. “Normally open switching devices...”

Mission Valley Power

No

Mission Valley Power notes that a new term has been introduced, “non-retail
generation,” with no definition provided. The answer to the question on this during
the 9/28 webinar indicated that non-retail generation was behind the retail
customer’s meter. We can see no reason why the net-metered PV systems should
count toward the aggregate limit (exceeding the limit means no exclusion) while a
non-blackstart thermal plant doesn’t (the radial system is excluded if any amount of
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Question 7 Comment
load is present). We have also heard the SDT meant just the opposite of what was
stated in the webinar. We ask that a reasonable definition for non-retail be provided
within the BES definition document.
We strongly agree that radial systems should be excluded and that the presence of
normally open switching devices between radial systems should not cause them to be
considered non-radial. Such a result would cause the removal of these devices to the
detriment of the local level of service. We note that the singular “A normally open
switching device” is used and suggest that an allowance be made for the possibility of
multiple devices. “Normally open switching devices...”

Central Lincoln

No

Central Lincoln notes that a new term has been introduced, “non-retail generation,”
with no definition provided. The answer to the question on this during the 9/28
webinar indicated that non-retail generation was behind the retail customer’s meter.
We can see no reason why the net-metered PV systems should count toward the
aggregate limit (exceeding the limit means no exclusion) while a non-blackstart
thermal plant doesn’t (the radial system is excluded if any amount of load is present).
We have also heard the SDT meant just the opposite of what was stated in the
webinar. We ask that a reasonable definition for non-retail be provided within the BES
definition document.
We strongly agree that radial systems should be excluded and that the presence of
normally open switching devices between radial systems should not cause them to be
considered non-radial. Such a result would cause the removal of these devices to the
detriment of the local level of service. We note that the singular “A normally open
switching device” is used and suggest that an allowance be made for the possibility of
multiple devices. “Normally open switching devices...”

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the
term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter.
It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation
to be unfairly biased against obtaining this exclusion. No change made.

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Question 7 Comment

Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used
in the normal operating environment. No change made.
BGE

No

During the previous comment period, BGE asked for clarification regarding the
exclusion of “radial facilities”. The particular example configuration in question
involved two 115 kV lines emanating from two different points of connection and
“tied” on the “low side” at 34.5 kV. The SDT responded that this was not a radial
facility but would be excluded under the E3-Local Network exclusion. BGE believes
that this particular configuration should be excluded under the E1-Radial Systems
exclusion. BGE does not beleive that two otherwise radial lines are made “non-radial”
because they are tied at a voltage lower than 100 kV.

Orange and Rockland Utilities,
Inc.

No

Please clarify on “single point of connection”. It seems like less confusion if “single
source” is used here instead of “single point of connection”.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
ISO New England Inc

No

The term “single point” is not clear. A better explanation is necessary. For example,
the same bus in a bus/branch model should suffice as a “single point”. There should
not be a requirement to be at the same node as found in a nodal model.
The term “a group of contiguous transmission elements” is ambiguous and needs to
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Question 7 Comment
be clarified.
The “Non-retail” qualifier in E1.c) should be deleted. It adds confusion to the
exclusion and is not defined.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
The SDT team considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that
retention of this word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation
that would otherwise be included in the term “Element”. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term
“non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail
meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks
with retail generation to be unfairly biased against obtaining this exclusion. No change made.
Kansas City Power and Light
Company

No

Nameplate rating of the generator is not a reflection of what can be actually injected
into the transmission system with resulting electrical impacts on transmission loading
and behavior. Recommend the BES definition be based on a generating resource(s)
established net accredited generating capacity instead of what it could do by
nameplate rating that may not be achievable. Recommend the following change to
the b) and c) parts of E1:b) Only includes generation resources not identified in
Inclusion I3 with an aggregate net accredited capacity less than or equal to 75 MVA.
Or, c) Where the radial system serves Load and includes generation resources not
identified in Inclusion I3 with an aggregate net accredited capacity of non-retail
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Question 7 Comment
generation less than or equal to 75 MVA.

Hydro-Quebec TransEnergie

No

Even with the modification proposed, it is too much restrictive to refuse exclusion of
radial system when they have generator or multiple generating units of aggregate
capacity greater than 75 MVA, especially when a system is able to function reliably
with the loss of generation much higher than this amount. To count on the exception
procedure to exclude radial system with greater generation is risky since no specific
criteria have been given to guide such exclusion. In most cases for radial or local
system including generation, the path that connects the generation should not be
included in the BES. Generators should be allowed to be considered "BES support
elements" and reliability standards should apply to them in specific.

Response: Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate
amount of connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on
the interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
Independent Electricity
System Operator

No

We support the provisions of E1 in principle but require clarification of some issues
and suggest alternative wording in some cases. It is unclear if the connection voltage
of generation referred to in E1.b affects whether a radial system could be excluded
under E1 although from the context it appears that it would. For clarity we suggest
appending “connected at 100 kV or higher.”
Please provide in the BES definition document an explanation of “non-retail” and
“retail” generation used in E1.c.
Additionally, despite the fact the revisions to Inclusion I3 (Blackstart Resources)
removed any reference to Cranking Paths, Exclusion 1 (b) and (c) both indicate that
the exclusion of a radial system would not be allowed if generation identified in I3
were connected to it. This implies that the Cranking Path for this Blackstart Resource
would have to be BES. This appears to be an inconsistency. We suggest removing the
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phrase “not identified in Inclusion I3” in both instances.
We disagree with notion that the capacity of generation connected to a radial system
ought to determine whether that radial system should be classified as BES. Firstly, it is
a given that the generation connected to the subject radial that meets the registry
criteria would already be captured within the core BES definition and Inclusion I2. The
function served by a radial that is of importance in the current context is that of
delivering surplus power to the rest of the bulk power system and so, the impact on
the BES of loss of the radial system or its connected generation needs to be
considered. In our view, the “BES-status” of the radial itself is immaterial and so too is
the aggregate capacity of generation resources connected to it. Detailed arguments
regarding impact on the BES can be made in support of an application for an exclusion
under the Exception Process, but it would be beneficial to avoid unnecessarily
including a radial merely because it has more than 75 MVA of qualifying generation
connected to it, without equal consideration of the connected load. To put a “bright
line” on the consideration of impact referred to above, we suggest: In E1 (b): Replace
"an aggregate capacity less than or equal to 75 MVA (gross nameplate rating)" with "a
net capacity provided to the BES of less than or equal to 75 MVA." In E1 (c): Replace
"an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating)" with "a net capacity of non-retail generation provided to the BES of
75 MVA."This wording would be consistent with E2 (i).
Finally the word “affect” stated in the note accompanying E1 lends itself to misinterpretation. We therefore suggest the following revision to achieve greater
clarity:”This exclusion applies to radial systems connected by a normally open switch.”

Response: Exclusion E1 is an exclusion for the contiguous transmission Elements connected at or above 100 kV. Generation
resources connected within the radial system are qualifiers for this exclusion. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “nonretail generation” in ExclusionE1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation to

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be unfairly biased against obtaining this exclusion. No change made.

The SDT appreciates the suggestion that there could be an appearance of an inconsistency between Inclusion I3 and Exclusions
E1 and E3. The SDT has determined that it should be conservative with regard to allowing exclusion for radial systems that are
depended upon for blackstart functionality, as these will arguably be more important to the reliable operation of the
transmission system than equivalent radial systems without Blackstart Resources. No change made.
Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
in the normal operating environment. No change made.
Central Maine Power
Company

No

E1 needs to be revised to make it less confusing. “Radial systems” leaves the
impression that E1 is not simply a “radial line exclusion”, because of the plural and the
word “systems.” Northeast industry expert colleagues are not clear what this sentence
specifies: “A group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher.” o Does E1 apply only to a single radial
transmission line (and its associated “group of Elements”)? o Alternatively, does E1
apply to multiple radial lines “emanating from” the same substation regardless of the
bus configuration - would a ring bus or a two-bus system that is connected with a tie
breaker be considered as “a single point of connection”? o If the radial line is simply
tapped off a BES line without any automatic interruption device, should not the radial
line be included as part of the BES since a permanent fault on this radial line will take
out the BES line it is tapping off of? If the radial line is defined as part of the BES, it
could be subject to certain requirements such as vegetation management for
overhead lines. o Should not the exclusion include some description of the
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operational requirements to help resolve the ambiguity? As it is, the exclusion is
scenarios-based. When a specific scenario is overlooked, the oversight becomes a
source of ambiguity.This definition is not clear. Clarity is imperative.E1(c) should
define or replace the term “non-retail”. Industry needs clarity on exactly what
generation this clause applies to, in order to properly apply this definition. The Note
referring to the “Normally Open switch” needs further clarification. As written, it
seems to conflict with FERC order 743, paragraph 55:”While commenters would like to
expand the scope of the term “radial” to exclude certain transmission facilities such as
tap lines and secondary feeds via a normally open line, we are not persuaded that
such categorical exemption is warranted.” E1 should be restated as follows: “Radial
systems: A single transmission line or transformer not otherwise identified in the
Inclusions above, with a single point of connection of 100 kV or higher and: a) Only
serves Load. Or, b) Only includes generation resources, not identified in the Inclusions
above. Or, c) Both serves Load and only includes generation resources not identified in
the Inclusions above."

Rochester Gas and Electric
and New York State Electric
and Gas

No

E1 needs to be revised to make it less confusing. “Radial systems” leaves the
impression that E1 is not simply a “radial line exclusion”, because of the plural and the
word “systems.” Northeast industry expert colleagues are not clear at all what this
sentence specifies: “A group of contiguous transmission Elements that emanates from
a single point of connection of 100 kV or higher.” o Does E1 apply only to a single
radial transmission line (and its associated “group of Elements”)? o Alternatively,
does E1 apply to multiple radial lines “emanating from” the same substation
regardless of the bus configuration - would a ring bus or a two-bus system that is
connected with a tie breaker be considered as “a single point of connection”? This
definition is not clear. Clarity is imperative.
E1(c) should define or replace the term “non-retail”. Industry needs clarity on exactly
what generation this applies to, in order to properly apply this definition.
The Note referring to the “Normally Open switch” needs further clarification. As
written, it seems to conflict with FERC order 743, paragraph 55:”While commenters
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would like to expand the scope of the term “radial” to exclude certain transmission
facilities such as tap lines and secondary feeds via a normally open line, we are not
persuaded that such categorical exemption is warranted.”
E1 should be restated as follows:”Radial systems: A single transmission line or
transformer not otherwise identified in the Inclusions above, with a single point of
connection of 100 kV or higher and: a) Only serves Load. Or, b) Only includes
generation resources, not identified in the Inclusions above. Or, c) Both serves Load
and only includes generation resources, not identified in the Inclusions above.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term
“non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail
meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks
with retail generation to be unfairly biased against obtaining this exclusion. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
in the normal operating environment. No change made.
The SDT does not believe that the suggested wording provides any additional clarity. No change made.
South Houston Green Power,
LLC

No

SHGP generally supports with the proposed revisions to Exclusion E1, but suggests
several additional clarifying revisions should be made. First, the phrase “a single point
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of connection” in the introductory sentence should be revised to read “a single point
of connection (including multiple connections to the same ring bus or substation
where the energy normally flows in the same direction)”. This revision is intended to
ensure that radial systems which involve multiple parallel lines and are designed to
operate as a single radial system, but that nevertheless connect to the grid through
more than line for reliability.
Second, for this same reason, an additional (i.e., second) note should be added to the
end of Exclusion E1 that reads as follows: “Note, a normally closed switching device
that enables multiple lines emanating from the same grid ring bus or different grid
buses to operate as a single radial system does not affect this exclusion.”
Third, the phrase “with an aggregate capacity of non-retail generation less than or
equal to 75 MVA should be eliminated.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
in the normal operating environment. No change made.
Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
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further review under Phase 2 of the BES definition. No change made.
Tacoma Power

Yes

Tacoma Power generally supports the Exclusion E1 as currently written. However, the
“note” at the end of E1 is confusing and can be interpreted inconsistently. We
recommend moving the language from the “note” to part of the exclusion as its own
section, as follows:(d) Normally-open switching devices between radial elements as
depicted and properly identified on system one-line diagrams should not be used to
deny this exclusion.
Additionally, we believe it is not appropriate for E1 to state an MVA threshold in
Section b) when determining such thresholds is the purpose for Phase 2. We urge the
SDT to defer the determination of a MVA threshold in E1 to Phase 2.

Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch
is used in the normal operating environment. No change made.
Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be consistent
with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of further review
under Phase 2 of the BES definition. No change made.
City of Austin dba Austin
Energy

Yes

For the E1 reference “Note,” we would benefit from additional clarification identifying
the treatment of a normally open switch and offer the following: “Radial systems shall
be assessed with all normally open switching devices in their open positions.”
The wording in Exclusion 1-c should more clearly reflect what is intended by using the
term “non-retail generation.”
Also, as with the technical justification for Inclusions I2 and I4, we recommend that
the generation threshold, i.e. gross nameplate values, be deferred to Phase 2.
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Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch
is used in the normal operating environment. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term
“non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail
meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks
with retail generation to be unfairly biased against obtaining this exclusion. No change made.
Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount
of connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
Ameren

Yes

a)We suggest the wording “non-retail generation’ should be clarified with an
explanation of why it is used in this exclusion.
b)This exclusion criterion has multiple stipulations to its applicability, and also has a
final inclusive reference to I3. Please make the wording exact and not dependent on
clausal statements.

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized
the term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the
retail meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local
networks with retail generation to be unfairly biased against obtaining this exclusion. No change made.
The SDT believes that the distinction between Load only, generation only, and Load with generation provides a bright-line
exclusion for radial systems that is needed to cover all of the possible scenarios. In addition, the SDT has determined that it
should be conservative with regard to allowing exclusion for radial systems that are depended upon for blackstart functionality,
as these will arguably be more important to the reliable operation of the transmission system than equivalent radial systems
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without blackstart resources. No change made.
Utility Services, Inc.

Yes

Utility Services is very concerned that the "single point of connection" lacks clarity and
applications need to be identified.
Utility Services suggests that the SDT publish illustrative one-line diagrams to aid the
industry in determining when the designations are best applied.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does necessarily include an automatic interrupting device (AID). For example, the start
of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of
the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or
breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
Publishing diagrams will be considered in Phase 2.
PSEG Services Corp

Yes

1. If a 50 MVA generator that is included per I2 is connected to an excluded radial
system, would the generator be excluded or included per E1b)? If yes, then the
language “unless excluded under Exclusion E1 and E3” in I1 needs to be added to I2,
I4, and I5.
2. Non-retail generation in E1c) was described behind-the-meter generation in the
Webinar. The term “non-retail generation” should be defined because one could infer
that generation defined by E2 is “retail generation.”
Also, is the 75 MVA limit intended apply to the generator (as stated) or its net capacity
as defined in E2? If it means the generator MVA, does that mean that generation
excluded in E2 cannot exceed 75 MVA when connected to an excluded radial
system?3. In general, the definition needs to better define the impact that “exclusion”
has on a different “inclusion” or “exclusion.”
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Response: Exclusion E1 is an exclusion for the contiguous transmission Elements connected at or above 100 kV. Generation
resources connected within the radial system are qualifiers for this exclusion. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “nonretail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail generation to
be unfairly biased against obtaining this exclusion. No change made.

Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be consistent
with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of further review
under Phase 2 of the BES definition. No change made.
Massachusetts Department of
Public Utilities

Yes

The aggregate 75 MVA of connected generation appears too low and would benefit
from additional technical justification.

Response: Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate
amount of connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on
the interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
The Dow Chemical Company

Yes

Dow generally agrees with the proposed revisions to Exclusion E1, but believes that
several additional clarifying revisions should be made. First, the phrase “a single point
of connection” in the introductory sentence should be revised to read “a single point
of connection (including multiple connections to the same ring bus or different buses
where the energy normally flows in the same direction)”. This revision is intended to
ensure that radial systems include arrangements involving multiple parallel lines that
are designed to operate as a single radial system, but that nevertheless connect at the
grid ring bus or different buses on the grid for reliability.
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Second, for this same reason, an additional (i.e., second) note should be added to the
end of Exclusion E1 that reads as follows: “Note, a normally closed switching device
that enables multiple lines emanating from the same grid ring bus or different grid
buses to operate as a single radial system does not affect this exclusion.”
Third, in “c),” the phrase “with an aggregate capacity of non-retail generation less
than or equal to 75 MVA (gross nameplate rating)” is confusing and potentially
inconsistent to the extent that “non-retail generation” may be different from “gross
nameplate rating.” The apparent intent of the clause is to exclude radial systems that
serve both load and generation, provided the generation capacity made available to
the transmission grid does not exceed 75 MVA. Dow would recommend that the
phrase be revised to read “where the net capacity provided to the transmission grid
does not exceed 75 MVA.” This revision would provide greater clarity and is
consistent with the language used in Exclusion E2.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
in the normal operating environment. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “nonretail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail
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generation to be unfairly biased against obtaining this exclusion. No change made.
ExxonMobil Research and
Engineering

Yes

The removal of the requirement for an automatic fault interrupting device from this
requirement is a welcomed change from the first posting. This Exclusion helps
preserve the current NERC Registry and explicitly excludes many facilities used in the
distribution of electric power.

Long Island Power Authority

Yes

Need to clarify what is a "single point of interconnection" e.g. is it a bus section or a
substation

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start
of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker
and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to insure the
reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at 100 kV or higher.
Networks that have multiple connections at 100kV or higher may qualify under Exclusion E3. The owner always has the option to seek
exclusion through the exception process. No change made.
Manitoba Hydro

Yes

Manitoba Hydro agrees with E1 but the wording of the note regarding ‘normally open
switching devices’ is unclear. In the Industry Webinar on September 28th, the Drafting
Team made it clear that the note means that if an element can be connected to the
BES from multiple points but under normal operating conditions it is only connected
to the BES at a single point by means of normally open switches, then the element is
still excluded from the BES provided it meets either the E1 a, b, or c criteria. The team
also noted that the discretion to operate the normally open switching devices in the
best interests of reliability rests with the operating entity. Suggested wording:”Note:
The ability to connect a group of contiguous transmission Elements from multiple
connection points of 100kV or higher through normally open switching devices does
not negate this Exclusion. “

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Question 7 Comment
As well, part c) of E1 should be changed to “c) Only serves Load and includes...”

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not prevent
the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is operated in
the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used in the normal
operating environment. No change made.
ATC LLC

Yes

Unless there is a specific reason to the contrary, ATC suggests that Exclusion E1b
include the qualification of “aggregate capacity of non-retail generation less than or
equal to 75 MVA” to be consistent with the wording in E1c.

Puget Sound Energy

Yes

The language addressing generation resources in sections b and c of E1 could be more
clear (an example of clearer language is section a of E3). At the least, the language in
these two sections should be revised to read "... includes generation resources that
are not identified in Inclusion I3 and that do not have an aggregate capacity exceeding
75 MVA ...".

Response: Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate
amount of connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on
the interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be
consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of
further review under Phase 2 of the BES definition. No change made.
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NV Energy

Yes or No

Question 7 Comment

Yes

There may be an opportunity to consolidate the sub-items of E1 into a single inclusion
statement in order to simplify this exclusion designation. We propose the following
replacement option: “E1 - Radial systems: A group of contiguous transmission
Elements that emanates from a single point of connection of 100 kV or higher and
serves any combination of load and/or generation, provided that the generation
resources are not identified in Inclusion I3 and do not have an aggregate capacity of
non-retail generation greater than 75 MVA (gross nameplate rating).”

Response: The SDT believes that the distinction between Load only, generation only, and Load with generation provides a
bright-line exclusion for radial systems that is needed to cover all of the possible scenarios. No change made.
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)
Central Electric Cooperatve
(CEC)
Clearwater Power Company
(CPC)
Snohomish County PUD
Consumer's Power Inc.
Douglas Electric Cooperative
(DEC)
Fall River Rural Electric
Cooperative (FALL)
Lane Electric Cooperative

Yes

CLPD continues to support the radial system exclusion, which is necessary as a legal
matter, because, for example, FERC in Orders No. 743 and 743-A has required that the
existing radial exemption in the NERC Statement of Compliance Registry Criteria be
maintained. As a practical matter, radial systems are used for service to retail loads,
usually in remote or rural areas, and not for the transmission of bulk power. Hence,
operation of the radials has little or nothing to do with the reliable operation of the
interconnected bulk transmission network. We also support the inclusion of the note
discussing normally open switches because this language provides needed clarity for a
common radial system configuration. We also agree with the substantive thrust of
this language, which is that a radial system should not be considered part of the BES if
it is interconnected at a single point, even if there is an alternative point of delivery
that is normally open. While we support the Exclusion for Radial Systems, we believe
several clarifications and refinements are necessary. (1) The term “transmission
Elements” in the initial paragraph should be changed to “Elements.” Radial systems
are not transmission systems and including the word “transmission” in the Radial
System exclusion is therefore unnecessary and confusing.
(2) Subparagraph (b) of Exclusion 1 refers to”generation resources . . . with aggregate
capacity greater than 75 MVA (gross aggregate nameplate rating)”). We urge the SDT
to replace this language with the defined term “Qualifying Aggregate Generation
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(LEC)
Lincoln Electric Cooperative
(LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric Cooperative
(UEC)
Kootenai Electric Cooperative

Yes or No

Question 7 Comment
Resources,” discussed in more detail in our response to Question 3. This language, or
some equivalent, will preserve the SDT’s ability to revise the 75 MVA threshhold in
Phase 2, with the result of Phase 2 included in the BES Definition by operation rather
than requiring further revision of the Definition.
(3) Subparagraph (b) also seems to assume that if a Radial System contains a
generator exceeding the 75 MVA threshhold, the Radial System itself must be included
in the BES because it links the generator to the interconnected bulk transmission
system. As discussed more fully in our response to Question 9, below, NERC’s Project
2010-17 Standards Drafting Team and GO-TO Task Force have both concluded that
this assumption is unwarranted.
(4) The “Note” as drafted by the SDT indicates that “a normally open switching device
between radial systems” will not serve to disqualify the Radial from exclusion under
Exclusion 1. As noted above, CLPD strongly supports the note conceptually. However,
we believe this language should be included in a separate subparagraph (d), rather
than a note, because treatment as a “note” suggests it is less important than other
portions of the Exclusion. We also suggest the language be changed to read: (d)
Normally-open switching devices between radial elements as depicted and properly
identified on system one-line diagrams does not affect this exclusion.This will make
clear that a radial with more than one normally-open switch connecting it to another
radial is still a radial. From the perspective of the BES Definition, the key question is
whether switches operating between Radials are normally open, not whether there is
more than one normally-open switch.

Response: 1) The SDT team considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that
retention of this word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that
would otherwise be included in the term “Element”. No change made.
2) Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be consistent
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with the existing threshold in the NERC Statement of Compliance Registry Criteria, and this threshold is a subject of further review
under Phase 2 of the BES definition. No change made.
3) See response to Q9.
4) Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is
operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used in the
normal operating environment. No change made.
Michigan Public Power Agency

Yes

MPPA and its members continue to support the radial system exclusion, which is
necessary as a legal matter, because, for example, FERC in Orders No. 743 and 743-A
has required that the existing radial exemption in the NERC Statement of Compliance
Registry Criteria be maintained. As a practical matter, radial systems are used for
service to retail loads, usually in remote or rural areas, and not for the transmission of
bulk power. Hence, operation of the radials has little or nothing to do with the
reliable operation of the interconnected bulk transmission network. But we believe
that further clarification is necessary. First, the deletion of “originating with an
automatic interruption device” is a step in the right direction. However, “emanates
from a single point of connection” could be too narrowly interpreted (i.e., multiple
buses within a single substation could be viewed as multiple points of connection).
MPPA and its members proposes the following modification: “emanates from a single
substation connected to the BES at 100 kV or higher ...”. Entities whose only
connection emanates from a single substation and otherwise meet the BES definition
should not be denied exclusion under E1 solely because they connect to multiple
buses within a single substation. Additionally, adoption of “E3- Local Networks”
renders specious any argument that clams that connecting to multiple buses within a
single suvstation makes a material difference for reliability purposes since local
networks would have multiple connections anyway.
Additionally, it is not clear why it is necessary to include the note at the end of the
revised definition. (“A normally open switching device between radial systems, as
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Question 7 Comment
depicted on prints or one-line diagrams for example, does not affect this exclusion.”)
This rasies questions as to what “normally open” means, and wheither the only
evidence demonstrating what “normally open” means will be prints or one-line
diagrams. Further, it is not entirely clear what is meant by the language “does not
affect this exclusion”. If the note remains, it should be modified to read something
like, “a normally open switching device between radial systems does not prevent
application of this exclusion.”
Finally, the generation threshold limit in E1(b) and E1(c) should be revised as discussed
in response to Q1. Specifically, the proposed threshold of 75 MVA for this exclusion
should be raised to not lessd than 300 MVA in both E1(b) and E1 (c).

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
always has the option to seek exclusion through the exception process. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
in the normal operating environment. No change made.
Exclusion E1.b refers to a radial system that contains only generation and the SDT believes that a limit on the aggregate amount of
connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability impact on the
interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen to be consistent
with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject of further review
under Phase 2 of the BES definition. No change made.

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NESCOE

Yes or No

Question 7 Comment

Yes

NESCOE suggests that the aggregate 75 MVA of connected generation is too low and
would benefit from additional technical justification. The threshold value should be
related to the largest contingency to which the applicable control area is designed to
operate. A level of 300 MVA would be appropriate. This 300 MVA limit represents
25% of the 1200 MVA loss of source that is typically assumed for operation of the
Northeast portion of the Eastern Interconnection. Depending on system conditions,
this number may be as high as 1500 MVA. Therefore, the suggested value of 300 MVA
has a technical basis and falls well within typical loss of source expectations for the
Northeast.

Response: The SDT believes that a limit on the aggregate amount of connected (non-retail) generation within the radial system
is necessary to ensure that there is no reliability impact on the interconnected transmission system; however, the threshold of
the allowable generation – 75 MVA – was chosen to be consistent with the existing threshold in the ERO Statement of
Compliance Registry Criteria, and this threshold is a subject of further review under Phase 2 of the BES definition. No change
made.
Z Global Engineering and
Energy Solutions

Yes

As stated in comment one. I recommend the Note is rewritten: "Note - A normally
open switching device between radial systems, as depicted on prints or oneline
diagrams, for example, does not classify the two or more radial lines as a loop line.
The exclusion will still apply."

Harney Electric Cooperative,
Inc.

Yes

HEC strongly agrees that radial systems should be excluded from the BES and that the
presence of a normally open switching device between radial systems should not
cause them to be considered non-radial

PacifiCorp

Yes

: The note in E1 as written is ambiguous and requires clarification. PacifiCorp assumes
the note means that two radial systems separated by a normally open switching
device allows for the exclusion of both radial systems. PacifiCorp recommends that
the SDT revise the note to serve as a paragraph clarifying E1 that, “Radial systems
separated by normally open switching device(s) as depicted on prints or one-line
diagrams for example, and operated in the normally open position, except during
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Question 7 Comment
abnormal operating conditions, qualifies both radial systems under this exclusion.”

Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch
is used in the normal operating environment. No change made.
Texas Industrial Energy
Consumers

Yes

As noted in response to Question 3, above, Exclusion E1 would only allow exclude
radial systems with “aggregate capacity of non-retail generation less than or equal to
75 MVA (gross nameplate rating).” The reference to “non-retail” generation in
subsection (c) indicates that the SDT may have intended to preserve the “netting”
approach set forth in the Statement of Registry Compliance, but this should be made
clearer. The description in subsection (c) should be revised to exclude “Where the
radial system serves Load and includes generation resources not identified in
Inclusions I2 or I3,” and the remainder of that sentence referencing a 75 MVA gross
nameplate rating should be removed. This will provide a reference back to the
Statement of Registry Compliance and clarify that only net capacity is considered for
customer-owned facilities.

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized
the term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the
retail meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local
networks with retail generation to be unfairly biased against obtaining this exclusion. The SDT believes that a limit on the
aggregate amount of connected (non-retail) generation within the radial system is necessary to ensure that there is no reliability
impact on the interconnected transmission system; however, the threshold of the allowable generation – 75 MVA – was chosen
to be consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria, and this threshold is a subject
of further review under Phase 2 of the BES definition. No change made.
Holland Board of Public Works

Yes

Holland BPW supports the exclusion of radial systems from the BES definition, but
believes that further clarification is necessary. First, the deletion of “originating
with an automatic interruption device” is a step in the right direction. However,
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Question 7 Comment
“emanates from a single point of connection” could be too narrowly interpreted (i.e.,
multiple buses within a single substation could be viewed as multiple points of
connection). Holland BPW proposes the following modification: “emanates from a
single substation connected to the BES at 100 kV or higher...” Entities whose only
connection emanates from a single substation and otherwise meet the BES definition
should not be denied exclusion under E1 solely because they connect to multiple
buses at that single substation. Additionally, adoption of “E3 - Local Networks”
renders specious any argument that claims that connecting to multiple buses within a
single substation makes a material difference for reliability purposes since local
networks would have multiple connections anyway.
Additionally, it is not clear why it is necessary to include the note at the end of the
revised definition. (“A normally open switching device between radial systems, as
depicted on prints or one-line diagrams for example, does not affect this exclusion.”)
This raises questions as to what “normally open” means, and whether the only
evidence demonstrating what “normally open” means will be prints or one-line
diagrams. Further, it is not entirely clear what is meant by the language “does not
affect this exclusion”. If the note remains, it should be modified to read something
like, “a normally open switching device between radial systems does not prevent
application of this exclusion.”
Finally, the generation threshold limit in E1(b) and E1(c) should be revised as discussed
in response to Q1. Specifically, the proposed threshold of 75 MVA for this exclusion
should be raised to not less than 300 MVA in both E1(b) and E1(c).

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the
start of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner
of the transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring
or breaker and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to
insure the reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at
100 kV or higher. Networks that have multiple connections at 100 kV or higher may qualify under Exclusion E3. The owner
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Question 7 Comment

always has the option to seek exclusion through the exception process. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not
prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch
is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch is used
in the normal operating environment. No change made.
The threshold of the allowable generation – 75 MVA – was chosen to be consistent with the existing threshold in the ERO Statement
of Compliance Registry Criteria, and this threshold is a subject of further review under Phase 2 of the BES definition. No change made.
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power
Cooperative

Yes

Remove “non-retail” because it is irrelevant to reliability.
In general, we agree with the remaining concepts. However transformer voltage
threshold should be 200 kV or higher, the power thresholds should be 150 MVA or
greater.

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the
term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail
meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with
retail generation to be unfairly biased against obtaining this exclusion. No change made.
The SDT believes that a limit on the aggregate amount of connected (non-retail) generation within the radial system is necessary to
ensure that there is no reliability impact on the interconnected transmission system; however, the threshold of the allowable
generation – 75 MVA – was chosen to be consistent with the existing threshold in the NERC Statement of Compliance Registry Criteria,
and this threshold is a subject of further review under Phase 2 of the BES definition. No change made.
Electricity Consumers

Yes

ELCON supports the changes made from the first posting for both E1 and E3 (which
complements E1), as this will help maintain the status quo referred to in the
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Yes or No

Resource Council (ELCON)

Question 7 Comment
introductory text. We seek one clarification: Some large industrial customers that
operate in remote, rural locations provide distribution services to third parties (usually
on a pro bono basis) where the local utility (LSE) is unable or unwilling to serve. These
transactions, which are akin to “border-line sales” in utility parlance, are typically de
minimis relative to the Load of the entity that delivers the power. While the
distribution is at low voltages (less than 100 kV), the power may have been received
by the entity at a higher voltage. We seek affirmation by the SDT that such situations
are not precluded by Exclusion E1.

Response: This is a bright-line definition for the BES and Exclusion E1 can be used to exclude radial systems for the contiguous
transmission Elements connected at or above 100 kV and lower voltage systems are already excluded from the BES. The
definition does not draw a distinction between ownership or connection arrangements. Without an exact configuration it is
impossible for the SDT to comment further but if this situation somehow slips through the cracks, there is always the option to
seek an exception. No change made.
ACES Power Marketing
Standards Collaborators

Yes

The term “non-retail generation” used in Exclusion E1 (item c) and again in E3 (item a)
should be clarified (see comments for question 8 below).
The Note after item c should also be clarified to indicate that closing a normally open
switch doesn’t affect this exclusion.

Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch
is used in the normal operating environment. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “nonretail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail
generation to be unfairly biased against obtaining this exclusion. No change made.
Sacramento Municipal Utility

Yes

For the E1 reference “Note,” we would benefit from additional clarification identifying
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District

Question 7 Comment
the treatment of a normally open switch and offer the following: “Radial systems shall
be assessed with all normally open switching devices in their open positions.”
The wording in Exclusion 1-c should more clearly reflect what is intended by using the
term “non-retail generation.”
Also, as with the technical justification for Inclusions I2 and I4, it is recommended that
the generation threshold, i.e. gross nameplate values, be deferred to Phase 2.

Balancing Authority Northern
California

Yes

For the E1 reference “Note,” we would benefit from additional clarification identifying
the treatment of a normally open switch and offer the following: “Radial systems shall
be assessed with all normally open switching devices in their open positions.”
The wording in Exclusion 1-c should more clearly reflect what is intended by using the
term “non-retail generation.”
Also, as with the technical justification for Inclusions I2 and I4, it is recommended that
the generation threshold, i.e. gross nameplate values, be deferred to Phase 2.

Response: Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches
will not prevent the owner or operator from using this exclusion. The note provides an example that can be used to indicate the
switch is operated in the normally open position; however, it is the owner and operators responsibility to indicate how a switch
is used in the normal operating environment. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term
“non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail
meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks
with retail generation to be unfairly biased against obtaining this exclusion. No change made.
The SDT believes that a limit on the aggregate amount of connected (non-retail) generation within the radial system is necessary to
ensure that there is no reliability impact on the interconnected transmission system; however, the threshold of the allowable
generation – 75 MVA – was chosen to be consistent with the existing threshold in the ERO Statement of Compliance Registry Criteria,
and this threshold is a subject of further review under Phase 2 of the BES definition. No change made.

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Florida Municipal Power
Agency
Transmission Access Policy
Study Group

Yes or No

Question 7 Comment

Yes

FMPA supports the exclusion of radial systems from the BES Definition. Such systems
are generally not “necessary for operating an interconnected electric transmission
network,” the standard in Orders 743 and 743-A. We have several suggestions to
clarify the proposed language for this Exclusion. Proposed Exclusion E1 refers to “[a]
group of contiguous transmission Elements that emanates from a single point of
connection of 100 kV or higher.” We appreciate the SDT’s clarification of the point of
connection requirement, but the term “a single point of connection” should be further
defined (more clearly than just by voltage), and should be generic enough to
encompass the various bus configurations. It is not the case, for example, that each
individual breaker position in a ring bus is a separate point of connection for this
purpose; in that situation, a bus at one voltage level at one substation should be
considered “a single point of connection.” Some examples of configurations that
should be considered a single point of connection for this purpose are at
https://www.frcc.com/Standards/StandardDocs/BES/BESAppendixA_V4_clean.pdf,
Examples 1-6.
Although the core definition (appropriately) refers to “Transmission Elements” (with a
capital “T”), proposed Exclusion E1 refers to “transmission Elements” (with a
lowercase “t”). To avoid confusion, either “Transmission” should be capitalized in
both locations, or the word “transmission” should simply be deleted from Exclusion
E1, leaving a “group of contiguous Elements.” We understand that the lack of
capitalization may have been a deliberate choice by the SDT in an attempt to avoid
confusion that SDT members believe exists in the Glossary definition. If the Glossary
definition of Transmission is unclear-which FMPA does not necessarily believe is the
case-the answer is not to simply abandon the Glossary definition in favor of an entirely
undefined term; it is to submit a SAR to improve the Glossary definition.
Exclusion E1(c) refers to “an aggregate capacity of non-retail generation less than or
equal to 75 MVA.” “Non-retail generation” is potentially ambiguous, because it could
be read as distinguishing between generation that will be sold at wholesale and
generation that is used by the retail provider to meet retail load. On the
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Question 7 Comment
understanding that the intent is in fact to describe generation behind the end-user
meter, sometimes referred to as “behind-the-second-meter generation,” we suggest
the following revision: “an aggregate generation capacity less than or equal to 75
MVA, not including generation on the retail customer’s side of the retail meter.”
Exclusion E1 concludes with a “Note”: “A normally open switching device between
radial systems, as depicted on prints or one-line diagrams for example, does not affect
this exclusion.” The Note should not specify the types of evidence required to prove a
normally open switch, and the phrase “as depicted on prints or one-line diagrams”
should be deleted. This phrase is equivalent to a “Measure” in a standard and should
not be embedded in the equivalent of a “Requirement.” Since the phrase only gives
an “example,” it does not in fact add anything to the Note, but may lead to confusion
over what sort of evidence is required.

Response: The “single point of connection of 100 kV or higher” is where the radial system will begin, if it meets the language of
Exclusion E1 including parts a, b, or c and does not necessarily include an automatic interrupting device (AID). For example, the start
of the radial system may be a hard tap of the transmission line where no automatic interruption device is used. The owner of the
transmission line will need to insure the reliability of the transmission line. Another example is the tap point within a ring or breaker
and a half bus configuration could also be the beginning of the radial system and the owner of the bus would need to insure the
reliability of the substation. Furthermore, the SDT believes that radial systems cannot have multiple connections at 100kV or higher.
Networks that have multiple connections at 100kV or higher may qualify under Exclusion E3. The owner always has the option to seek
exclusion through the exception process. No change made.
The SDT team considered the disposition of the word “transmission” in the context of Exclusion E1, and determined that retention of
this word – in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would
otherwise be included in the term “Element”. No change made.
Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the term “nonretail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail meter. It is
important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with retail
generation to be unfairly biased against obtaining this exclusion. No change made.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not prevent
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Question 7 Comment

the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is operated in
the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in the normal
operating environment. No change made.
MRO NERC Standards Review
Forum (NSRF)

Yes

Unless there is a specific reason to the contrary the NSRF suggests that E1b include
the qualification of “aggregate capacity of non-retail generation less thatn or equal to
75 MVA” be added to be consistent with the wording in E1c.

MEAG Power

Yes

We suggest the wording “non-retail generation’ should be clarified with an
explanation of why it is used in this exclusion.

SERC OC Standards Review
Group

Yes

We suggest the wording “non-retail generation’ should be clarified with an
explanation of why it is used in this exclusion.

Consolidated Edison Co. of NY,
Inc.

Yes

Please define the term “non-retail generation.”

Tennessee Valley Authority

Yes

TVA suggests the wording “non-retail generation’ should be clarified with an
explanation of why it is used in this exclusion.

SERC Planning Standards
Subcommittee

Yes

The SDT needs to clarify what is meant by "non-retail generation." Is this what is
commonly referred to as "customer owned" or "behind-the-meter" generation?

Response: Non-retail generation is the generation on the system (supply) side of the meter. The SDT has intentionally utilized the
term “non-retail generation” in Exclusion E1.c in order to specifically isolate that generation which is not situated behind the retail
meter. It is important to retain this concept, since removal of the clarifier “non-retail” would cause candidate local networks with
retail generation to be unfairly biased against obtaining this exclusion. No change made.
WECC Staff

Yes

The use of the word “affect” in the note may cause problems with interpretation by
users. WECC suggests replacing the term "affect" with “alter”.

Response: The SDT considered your comments and chose to leave the existing wording unchanged as it does not provide any
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Question 7 Comment

additional clarity.
Radial systems should be assessed with all normally open (NO) switches in the open position and these NO switches will not prevent
the owner or operator from using this exclusion. The note provides an example that can be used to indicate the switch is operated in
the normally open position; however, it is the owner and operator’s responsibility to indicate how a switch is used in the normal
operating environment. No change made.
Westar Energy

Yes

Redding Electric Utility

Yes

City of Redding

Yes

Portland General Electric
Company

Yes

Farmington Electric Utility
System

Yes

Georgia System Operations
Corporation

Yes

Oncor Electric Delivery
Company LLC

Yes

National Grid

Yes

Cowlitz County PUD

Yes

Memphis Light, Gas and
Water Division

Yes

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Yes or No

Springfield Utility Board

Yes

Oregon Public Utility
Commission Staff

Yes

Metropolitan Water District of
Southern California

Yes

Duke Energy

Yes

Chevron U.S.A. Inc.

Yes

Central Hudson Gas and
Electric Corporation

Yes

Idaho Falls Power

Yes

FirstEnergy Corp.

Yes

Exelon

Yes

Tri-State GandT

Yes

Western Area Power
Administration

Yes

Tri-State Generation and
Transmission Assn., Inc.

Yes

Question 7 Comment
SUB supports a radial system exclusion.

This is very important exclusion for an entity operating in remote areas of the country
that provides distribution service to third parties where utilities are unable or
unwilling to serve. While the distribution is at a low voltage, the power was initially
received by the operating entity at a high voltage.

We support the exclusion as drafted.

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Question 7 Comment

Energy Management
Texas RE NERC Standards
Subcommittee

Yes

This is a much needed change from the first posting, as this will maintain the status
quo referred to in the introduction text.

Response: Thank you for your support.

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8.

The SDT has revised the specific exclusions to the core definition in response to industry comments. Do you agree with
Exclusion E2 (behind-the-meter generation)? If you do not support this change or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: The majority of commenters are in agreement with Exclusion E2 but there were some requests for additional
clarification and the SDT responded by clarifying the language as shown below.
There were also questions raised about threshold levels in the exclusion. The SDT acknowledges and appreciates the comments and
recommendations associated with modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES
definition. However, the SDT has responsibilities associated with being responsive to the directives established in Orders No. 743 and
743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the
development of strong technical justifications that would warrant a change from the current values that exist through the application of
the definition today. These and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to
address the concerns of industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for
modifications to the technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System.
This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the
threshold values and provide compelling justification for modifications to the existing values.
Some commenters have questioned the reasoning behind Exclusion E2 (ii). Condition (ii) in Exclusion E2 is derived from FERC or
provincial regulations applicable to qualifying cogeneration and small power production facilities. For example, see 18 CFR §292.101 and
§292.305(b) for the requirements specific to the US. The SDT believes that condition (ii), which requires that the generation serving the
retail customer load self provide reserves, is essential for the integrity of the exclusion. This is not new ground and is simply clarifying
language that has been present in the ERO Statement of Compliance Registry Criteria for quite some time. The SDT believes that the
meaning of the definition will be understood in Balancing Authority Areas where it is applicable as it reflects existing practice.
Therefore, the SDT has declined to delete condition (ii).
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail customer
Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does not exceed 75 MVA,
and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple generating units or to the
retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator Operator, or
under terms approved by the applicable regulatory authority.

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Yes or No

Question 8 Comment

MEAG Power

No

Clarification needs to be provided for what is meant by E2 (ii), regarding generation on
the customer’s side of the retail meter; otherwise we have trouble developing a
position on this question.

SERC OC Standards Review
Group

No

Clarification needs to be provided for what is meant by E2 (ii), regarding generation on
the customer’s side of the retail meter; otherwise we have trouble developing a
position on this question.

Tennessee Valley Authority

No

Clarification needs to be provided for what is meant by E2 (ii), regarding generation on
the customer’s side of the retail meter; otherwise we have trouble developing a
position on this question.

ReliabilityFirst

No

It is not clear why “ii” is needed. If the net generation exceeds 75 MVA, then it is
included in the BES whether or not there are ancillary services provided for that
generation. Would customer owned generation less than a net of 75 MVA but greater
than 20 MVA be included in the BES if item ii was not met?

FirstEnergy Corp.

No

We suggest striking item "ii"

Dominion

No

Dominion supports exclusion for behind-the-meter generation, (if connected at >100
kV) if the load behind the meter (to which that generation is intended to support)
does not rely on generation outside that metered point for purposes of back-up
energy or any type of ancillary services at any time. The proposed language appears
to suggest that standby, back-up, and maintenance power services are always
required. There are alternative means to provide these services, such as reducing load
to match ‘reliability services’ provided by the available behind-the-meter generation.
Further, even if standby, back-up, and maintenance power services are always
required, the exclusion criteria obligation should be placed on the retail load, not the
generation outside the metered point

Response: Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying cogeneration and
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Yes or No

Question 8 Comment

small power production facilities. For example, see 18 CFR §292.101 and §292.305(b) for the requirements specific to the US. The
SDT believes that condition (ii), which requires that the generation serving the retail customer load self provide reserves, is
essential for the integrity of the exclusion. This is not new ground and is simply clarifying language that has been present in the
ERO Statement of Compliance Registry Criteria for quite some time. The SDT believes that the meaning of the definition will be
understood in Balancing Authority Areas where it is applicable. No change made.
Northeast Power Coordinating
Council

No

Why are references to Balancing Authority, Generator Owner, and Generator
Operator included in E2 which is part of the BES definition? The wording of Exclusion
E2 should be consistent with the Statement of Compliance Registry Criteria in Section
III.c.4.

Response: The roles of the Balancing Authority, Generator Owner, and Generator Operator are implied in the ERO Statement of
Compliance Registry Criteria and the terms were added as the result of industry requests for clarification. No change made.
Southern Company

No

We suggest that clarification is needed for what is meant by E2 (ii), regarding
generation on the customer’s side of the retail meter.
Also, we would like for a clarification of the difference between the terms "retail load"
and "retail customer load" as used in exclusions E2 and E3.

Response: Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying cogeneration and small
power production facilities. For example, see 18 CFR §292.101 and §292.305(b) for the requirements specific to the US. The SDT
believes that condition (ii), which requires that the generation serving the retail customer load self provide reserves, is essential for
the integrity of the exclusion. This is not new ground and is simply clarifying language that has been present in the ERO Statement of
Compliance Registry Criteria for quite some time. The SDT believes that the meaning of the definition will be understood in Balancing
Authority Areas where it is applicable. No change made.
The SDT accepts your recommendation regarding “retail Load” and has clarified Exclusion E2 to read:
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail
customer Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does not
exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple
generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator
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Yes or No

Question 8 Comment

Owner or Generator Operator, or under terms approved by the applicable regulatory authority.
Southwest Power Pool
Standards Review Team

No

This number could change in phase two of the project which would create
unnecessary work in the future.

Farmington Electric Utility
System

No

E2 should be modified to include a size and threshold for individual generating units,
similar to that identified in I2. As currently worded E2 places the same threshold (75
MVA) on a single generating unit as is placed on multiple generating units.

Westar Energy

No

As expressed in our comment to question 5, we have concerns that the 75 MVA
number could change in phase two of the project, creating unnecessary work in the
future.

American Electric Power

No

It appears an entity with less than 75 MVA would not have been included as part of
the earlier inclusions. Is it necessary to note this threshold once again in the exclusion
section? Might it be possible to add some of the “behind the meter load” to the
inclusion section to reduce the amount of both the inclusions and exclusions? Doing
so would likely provide more clarity to the standard.

City of Anaheim

No

Again, 75 MVA should be increased to 300 MVA in E2 for the reasons stated in
response to Question 7.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
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Yes or No

Question 8 Comment

and provide compelling justification for modifications to the existing values. No change made.
City of St. George

No

Same basic comments and concerns as question #7.

No

Exclusion E2 is confusing as written and seems counter intuitive. As an example, a 400
MW generator which is behind the meter with a 400 MW load could be excluded. This
generator could have a significant impact on the performance of the system and yet it
is excluded. As a simple example, loss of the 400 MW generator would require that
the 400 MW load be supplied from the system, possibly leading to low voltages and
thermal overloads. Additionally, a machine of this size could adversely impact the
dynamic response of the system, leading to damping concerns or unit instability.

Response: See response to Q7.
ISO New England Inc

If E2 is to be retained, it is not clear under what load conditions should the load at the
facility be measured. Load levels, and resulting net flows to the system, can be
significantly different between seasons, time of day, and the status of end user
equipment at large industrial/manufacturing sites.
The term “Retail Customer Load” needs to be defined.
The Balancing Authority should not be included as an entity providing this service. In
general the Statement of Compliance Registry has provided the preferred language to
use here (Page 9, [Exclusions: second paragraph).
Response: The SDT believes that Exclusion E2 should be dedicated to the situation faced by behind-the-meter (i.e., retail customer
owned) generation that are PURPA qualifying facilities (in the US) (e.g., see 18 CFR Part 292 for the regulations that are applicable in
the US), and similarly situated generators in Canada. Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations
applicable to qualifying facilities. The SDT believes that condition (ii), which requires that the generation serving the retail customer
load self provide reserves, is essential for the integrity of the exclusion. No change made.
The roles of the Balancing Authority, Generator Owner, and Generator Operator are implied in the ERO Statement of Compliance
Registry Criteria and the terms were added to Exclusion E2 as the result of industry requests for clarification.
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Yes or No

Question 8 Comment

The SDT has clarified Exclusion E2 to read:
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail
customer Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does not
exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple
generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator
Owner or Generator Operator, or under terms approved by the applicable regulatory authority.
Central Maine Power
Company

No

E2 should be consistent with the Statement of Compliance Registry Criteria.
References to Balancing Authority, Generator Owner, and Generator Operator should
not be included in the BES definition. “Net capacity” is unclear - must flow never
exceed 75 MVA on an instantaneous or integrated hourly energy basis per either
design or operating experience? There is a potential for hundreds of MW to be
interconnected at a customer facility, with the “net capacity” (= flow into the
transmission system? Instantaneous? Annual average? On an integrated hourly basis
at any hour?) being less than 75 MVA - are hundreds of MW of generation “not
material” to BES reliability? The conditions under which direction of flow (i.e., “net
capacity”) is assessed are critical, but E2(i) is silent on this.In E2(ii), the “and”, “or”,
and “or” are not clear - what are the necessary terms of the referenced “binding
obligation” and what is an “applicable regulatory authority”? Are “standby” and “backup” and “maintenance” power services independently defined and provided by a GOP,
GO, or BA? Northeast industry expert colleagues do not understand the relevance of
E2(ii) to BES reliability.E2 should be restated as follows:”A generating unit or multiple
generating units that serve all or part of retail customer Load with electric energy on
the customer’s side of the meter if the flow to or from the BES can never exceeds 75
MVA."

Rochester Gas and Electric
and New York State Electric
and Gas

No

E2 should be consistent with the Statement of Compliance Registry Criteria.
References to Balancing Authority, Generator Owner, and Generator Operator should
not be included in the BES definition.
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Yes or No

Question 8 Comment
“Net capacity” is unclear - must flow never exceed 75 MVA on an instantaneous or
integrated hourly energy basis per either design or operating experience? There is a
potential for hundreds of MW to be interconnected at a customer facility, with the
“net capacity” (= flow into the transmission system? Instantaneous? Annual average?
On an integrated hourly basis at any hour?) being less than 75 MVA - are hundreds of
MW of generation “not material” to BES reliability? The conditions under which
direction of flow (i.e., “net capacity”) is assessed are critical, but E2(i) is silent on this.
In E2(ii), the “and”, “or”, and “or” are not clear - what are the necessary terms of the
referenced “binding obligation” and what is an “applicable regulatory authority”?
Are “standby” and “back-up” and “maintenance” power services independently
defined and provided by a GOP, GO, or BA?
Northeast industry expert colleagues do not understand the relevance of E2(ii) to BES
reliability.E2 should be restated as follows:”A generating unit or multiple generating
units that serve all or part of retail customer Load with electric energy on the
customer’s side of the meter if the flow to or from the BES never exceeds 75 MVA”

Response: The wording of (ii) is essentially the same as the wording on this topic in the ERO Statement of Registry Criteria which
has been in existence for several years and is well understood in the industry. Qualifying for Exclusion E2 will be determined the
same as every other inclusion or exclusion; there is nothing special about Exclusion E2 that separates it from the rest of the
definition. The roles of the Balancing Authority, Generator Owner, and Generator Operator are implied in the ERO Statement of
Compliance Registry Criteria and the terms were added to Exclusion E2 as the result of industry requests for clarification.
The SDT believes that Exclusion E2 should be dedicated to the situation faced by behind-the-meter (i.e., retail customer owned)
generation that are PURPA qualifying facilities (in the US) (e.g., see 18 CFR Part 292 for the regulations that are applicable in the
US), and similarly situated generators in Canada. Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations
applicable to qualifying facilities. The primary purpose of retail customer owned generation in the context of Exclusion E2 is the
integrity of steam production that supports a manufacturing process. The electrical load of that process does not exist without
steam.
The SDT believes that condition (ii), which requires that the generation serving the retail customer load self provide reserves (i.e.,
standby, backup and maintenance power), is essential for the integrity of the exclusion. These reserves maintain steam generation
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Yes or No

Question 8 Comment

and the load to sustain the manufacturing process. In the US, the terms and conditions of standby, backup and maintenance
services are defined and administered by State PSCs (i.e., the “applicable regulatory authority” in the US) subject to FERC oversight.
These services are provided under contract or tariff with GOs, GOPs or BAs in regions that do not have ISOs or RTOs, and provided
by ISOs and RTOs where so-called “organized markets” operate.
The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was operated,
and the residual (“net”) amount exported to the BES that was deemed relevant to the exclusion and reliability, not the nameplate
rating. The export is subject to the 75 MVA threshold; the requirement for reserves under a “binding obligation” (standby, backup
and maintenance power) matches part or all of the on-site load and is not subject to the threshold.
No change made.
LCRA Transmission Services
Corporation

No

Response: Without any specific comment, the SDT is unable to respond.
Kansas City Power and Light
Company

No

Any facilities that are customer owned regardless of size or configuration are not
under the jurisdiction or responsibility of the Registered Entity and should not be
considered as included with a Registered Entity.

Response: Exclusion E2 was based on the ERO Statement of Compliance Registry Criteria. No change made.
Ameren

No

a)If retail generation fails to meet (i) or (ii) it appears that the retail generation would
be included. The wording of (ii) is complex. Who will police this with retail behindthe-meter generators?
b)Clarification needs to be provided for what is meant by E2 (ii), regarding generation
on the customer’s side of the retail meter; otherwise we have trouble developing a
position on this question.

Response: The wording of (ii) is essentially the same as the wording on this topic in the ERO Statement of Registry Criteria which has
been in existence for several years and is well understood in the industry. Qualifying for the E2 Exclusion will be determined the same
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Yes or No

Question 8 Comment

as every other inclusion or exclusion; there is nothing special about Exclusion E2 that separates it from the rest of the definition.
Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying facilities. The SDT believes that
condition (ii), which requires that the generation serving the retail customer load self provide reserves, is essential for the integrity of
the exclusion. The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was
operated that was deemed relevant to the exclusion, not the nameplate rating. No change made.
Nebraska Public Power District

Yes

However the exclusion needs to be noted in I2, so as to non conflict with I2. (See
comment on #2 above.)

Response: Any retail generation that meets the criteria in Exclusion E2 is not in the BES so there is no conflict. No change made.
National Grid

Yes

We agree with this exclusion, but the intention of point (i), the net capacity provided
to the BES does not exceed 75 MVA, is not clear. We suggest this wording:”the net
capacity provided to the BES for 90% of the hours of the year does not exceed 75
MVA”.

Response: The first condition (i) in Exclusion E2 had to reference the net generation (in MWs) since it was how the generation was
operated that was deemed relevant to the exclusion, not the nameplate rating. The threshold level for generators will be considered
in the Phase 2 review. No change made.
Utility Services, Inc.

Yes

Utility Services supports the comments offered by others suggesting that the language
be revised to be identical to the language in the SCRC.

Response: The SDT modified the language in response to industry requests for clarification. For example, the terms Balancing
Authority, Generator Owner, and Generator Operator are implied in the ERO Statement of Compliance Registry Criteria. No change
made.
South Houston Green Power,
LLC

Yes

SHGP generally agrees with the proposed revisions to Exclusion E2, but believes that a
clarifying revision should be made. Substitute “transmission grid” for “BES” in the
phrase “provided to the BES” to insure that the metering is to the grid.

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The Dow Chemical Company

Yes or No
Yes

Question 8 Comment
Dow generally agrees with the proposed revisions to Exclusion E2, but believes that a
clarifying revision should be made. Substitute “transmission grid” for “BES” in the
phrase “provided to the BES” to insure that the measurement is to the grid.

Response: The SDT believes that BES is the appropriate point of measurement because Exclusion E2 is defined in relation to the BES.
No change made.
Manitoba Hydro

Yes

Manitoba Hydro agrees with E2 but suggests that the phrase ‘A generating unit or
multiple generating units’ be replaced with ‘Generating resource(s)’ for clarity and
consistency.

Response: The SDT does not see where the suggested change will add any additional clarity. No change made.
Michigan Public Power Agency
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)
Central Electric Cooperatve
(CEC)
Clearwater Power Company
(CPC)
Snohomish County PUD
Consumer's Power Inc.
Douglas Electric Cooperative
(DEC)

Yes

MPPA and its members support the revised language. The language provides clarity
regarding the BES status of customer-owned cogeneration facilities. However, MPPA
and its members urge the SDT to remove the reference to the 75 MVA threshhold and
replace it with the defined term “Qualifying Aggregate Generation Resources” or some
equivalent language for the reasons stated in our responses to Questions 3, 5, and 7.
In addition, we are concerned that Exclusion 2 will place local distribution utilities in a
difficult position because, under Exclusion 1 or Exclusion 3 as drafted, they could lose
their status as a Radial System or a Local Network through the actions of a customer
constructing behind-the-meter generation, With respect to Radial Systems, the
appearance of behind-the-meter generators could cause the Radial System to exceed
the thresholds specified in subparagraphs (b) and (c) of Exclusion 1 through no fault of
the Radial System owner. Similar, a Local Network could lose its status because
behind-the-meter generation could be of sufficient size that power moves into the
interconnected grid in certain hours or under certain contingencies, rather than
moving purely onto the Local Network, as required in subparagraph (b) of Exclusion 3.
The Exclusions for Radial Systems and Local Networks should be made consistent with
the Exclusion for behind-the-meter generation. There is no technical reason to believe
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Organization
Fall River Rural Electric
Cooperative (FALL)
Lane Electric Cooperative
(LEC)

Yes or No

Question 8 Comment
the power flowing from a behind-the-meter customer-owned generator will have less
impact on the bulk system than an equivalent-sized generator owned by a utility
operating a Radial System or LN.

Lincoln Electric Cooperative
(LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric Cooperative
(UEC)
Cowlitz County PUD
Kootenai Electric Cooperative
Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
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Yes or No

Question 8 Comment

technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
The thresholds in Exclusions E1 and E3 apply only to non-retail generators (i.e., generation on the system (supply) side of the retail
meter) and are not affected by presence of retail generation. No change made.
Massachusetts Department of
Public Utilities

Yes

While the MA DPU generally supports Exclusion E2, no information has been provided
by NERC demonstrating that the 75 MVA rating is based on any sound technical
analysis.

NESCOE

Yes

While NESCOE generally supports Exclusion E2, no information has been provided by
NERC demonstrating that the 75 MVA rating is based on any sound technical analysis.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values. No change made.
Texas Industrial Energy
Consumers

Yes

Please see the response to Question 3, above. Unlike exclusions E1 and E3, this
exclusion refers specifically to the “net capacity” provided, which is consistent with
existing treatment for generation that is netted against internal load under the
Statement of Registry Compliance.

Response: See response to Q3.
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Organization
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power
Cooperative

Yes or No
Yes

Question 8 Comment
E2 “retail meter” should read “retail meter(s)”.
(i)
(ii)

Should be reworded as “the maximum net impact to the BES does not exceed
150 MVA, connected at 200 kV or higher.”
if we understand this clause correctly, we believe our proposed (i) wording will
handle the issue. Also, all load’s inclusion, within a BA, is dictated within the
BAL standards and so remove entirely or additional clarification is needed.

Response: It is accepted use in NERC Reliability Standards that singular words and terms apply to plural conditions as well. No change
made.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects
(i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being
responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012,
and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a
change from the current values that exist through the application of the definition today. These and similar issues have prompted the
SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory
authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for
inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC
Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide compelling
justification for modifications to the existing values.
Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying cogeneration and small power
production facilities. For example, see 18 CFR §292.101 and §292.305(b) for the requirements specific to the US. The SDT believes
that condition (ii), which requires that the generation serving the retail customer load self provide reserves, is essential for the
integrity of the exclusion. This is not new ground and is simply clarifying language that has been present in the ERO Statement of
Compliance Registry Criteria for quite some time. The SDT believes that the meaning of the definition will be understood in Balancing
Authority Areas where it is applicable. No change made.
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Southern Company
Generation

Yes or No

Question 8 Comment

Yes

Some editing is needed. The second part, (ii), of the and logic provided for the
exclusion criteria E2 is confusing. The initial criteria, (i), seems to be adequate
regarding impact to the BES. The criteria listed after "(ii)" does not seem to be
relevant to the impact on the BES. What does it mean to provide standby, back-up,
and maintenance power services to a generating unit or multiple generating units? It
is unclear who is providing the power service. If this is needed, the statement needs
to be simplified so it can be understood.
What is the difference between the terms "retail Load" and "retail customer Load" as
used in Exclusions E2 and E3?

Response: Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying cogeneration and small
power production facilities. For example, see 18 CFR §292.101 and §292.305(b) for the requirements specific to the US. The SDT
believes that condition (ii), which requires that the generation serving the retail customer load self provide reserves, is essential for
the integrity of the exclusion. This is not new ground and is simply clarifying language that has been present in the ERO Statement of
Compliance Registry Criteria for quite some time. The SDT believes that the meaning of the definition will be understood in Balancing
Authority Areas where it is applicable.
The SDT accepts your recommendation regarding “retail Load” and hasl clarified Exclusion E2 to read:
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail
customer Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does
not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple
generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator
Owner or Generator Operator, or under terms approved by the applicable regulatory authority.
ACES Power Marketing
Standards Collaborators

Yes

“A generating unit or multiple generating units that serve all or part of retail customer
Load with electric energy on the customer’s side of the retail meter” sounds a lot like
“non-retail generation” that is used in E1 and E3 which was described in the webinar
as generation that resides on the customer side of the retail meter and is used to
supply energy to that customer’s load and is owned by the customer. Is E2 assuming
that this generation is not owned by the customer?
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Yes or No

Question 8 Comment
Also, part ii) adds to the confusion. Conceptually we agree with this exclusion but
further clarification is preferred.

Response: Exclusion E2 does not apply to non-retail generation, which the SDT defines as generation on the system (supply) side of
the retail meter.
Condition (ii) in Exclusion E2 is derived from FERC or provincial regulations applicable to qualifying cogeneration and small power
production facilities. For example, see 18 CFR §292.101 and §292.305(b) for the requirements specific to the US. The SDT believes
that condition (ii), which requires that the generation serving the retail customer load self provide reserves, is essential for the
integrity of the exclusion. This is not new ground and is simply clarifying language that has been present in the ERO Statement of
Compliance Registry Criteria for quite some time. The SDT believes that the meaning of the definition will be understood in Balancing
Authority Areas where it is applicable. No change made.
Bonneville Power
Administration

Yes

BPA believes that if E2 is intended to exclude behind-the-meter generation, the phrase
“on the customer’s side of the retail meter” should immediately follow “generating
units” in the first line. Otherwise, the phrase could be seen as modifying “retail
customer Load.”

Response: The SDT has clarified Exclusion E2 as suggested.
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail
customer Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does
not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple
generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator
Owner or Generator Operator, or under terms approved by the applicable regulatory authority.
WECC Staff

Yes

E2 is inconsistent with Section III.c. of the NERC Statement of Compliance Registry
Criteria and is in conflict with I2. As written, E2 uses a net capacity threshold of
75MVA, which does not distinguish between a single generating unit and multiple
generating units. The threshold in the NERC Statement of Compliance Registry Criteria
for a single generating unit is 20MVA. As a result, E2 would appear to exclude
generators from 20MVA to 75MVA that serve any amount of retail load behind the
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Organization

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Question 8 Comment
meter. WECC recommends replacing “(i) the net capacity provided to the BES does
not exceed 75 MVA” with “(i) the net capacity provided to the BES does not exceed
the individual or gross nameplate ratings provided in the NERC Statement of
Compliance Registry Criteria.” WECC’s recommended change makes E2 consistent
with I2 and the SDT’s plan to address generator thresholds in Phase 2.

Response: Comments received on Inclusion I2 made it clear that industry did not want circular references in the definition so the SDT
has refrained from using the wording suggested here both in Inclusion I2 and Exclusion E2. The threshold levels of generators and the
relationship between the ERO Statement of Compliance Registry Criteria and the BES definition will be considered in the Phase 2
review. However, the SDT believes that a value was needed for Phase 1 and decided to proceed with the single 75 MVA threshold.
No change made.
ATC LLC

Yes

Portland General Electric
Company

Yes

City of Austin dba Austin
Energy

Yes

ExxonMobil Research and
Engineering

Yes

Northern Wasco County PUD

Yes

Georgia System Operations
Corporation

Yes

Oncor Electric Delivery
Company LLC

Yes

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Organization

Yes or No

Central Lincoln

Yes

Harney Electric Cooperative,
Inc.

Yes

PSEG Services Corp

Yes

Independent Electricity
System Operator

Yes

Long Island Power Authority

Yes

Mission Valley Power

Yes

Puget Sound Energy

Yes

Tillamook PUD

Yes

NV Energy

Yes

Oregon Public Utility
Commission Staff

Yes

Z Global Engineering and
Energy Solutions

Yes

Consumers Energy

Yes

Metropolitan Water District of
Southern California

Yes

Question 8 Comment

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Organization

Yes or No

Duke Energy

Yes

Chevron U.S.A. Inc.

Yes

Ontario Power Generation Inc.

Yes

Central Hudson Gas and
Electric Corporation

Yes

Idaho Falls Power

Yes

Exelon

Yes

PacifiCorp

Yes

Hydro One Networks Inc.

Yes

Tri-State GandT

Yes

Western Area Power
Administration

Yes

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

Yes

MRO NERC Standards Review
Forum (NSRF)

Yes

Question 8 Comment

This is a very important exclusion for Combined Heat and Power facilities that utilize
large amounts of steam and power, and secure and/or provide their own operating
reserves.

We support the exclusion as drafted.

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Organization

Yes or No

Question 8 Comment

IRC Standards Review
Committee

Yes

Pepco Holdings Inc and
Affiliates

Yes

Transmission Access Policy
Study Group

Yes

Electricity Consumers
Resource Council (ELCON)

Yes

Texas RE NERC Standards
Subcommittee

Yes

Florida Municipal Power
Agency

Yes

SERC Planning Standards
Subcommittee

Yes

Redding Electric Utility

Yes

City of Redding

Yes

Tacoma Power

Yes

Tacoma Power supports the Exclusion E2 as currently written.

BGE

Yes

No comment.

NERC Staff Technical Review

Yes

ELCON supports the proposed revisions to Exclusion E2.

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Question 8 Comment

Response: Thank you for your support. Due to other comments received, the SDT has made a slight clarifying change to Exclusion E2
as shown:
E2 - A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail
customer Load with electric energy on the customer’s side of the retail meter if: (i) the net capacity provided to the BES does
not exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple
generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator
Owner or Generator Operator, or under terms approved by the applicable regulatory authority.

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9.

The SDT has revised the specific exclusions to the core definition in response to industry comments. Do you agree with
Exclusion E3 (local network)? If you do not support this change or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: Commenters were generally supportive of the concept of the local network Exclusion E3 as proposed
in the second posting of the BES definition. The most prevalent comments, and the SDT’s response to those comments, were as
follows:
Several commenters suggested that the requirement under Exclusion E3.b should apply only during normal operating
conditions. In other words, commenters felt that some power flow should be allowed to flow from the candidate local network
back into the BES as long as it only occurred under abnormal conditions. To address this suggestion, the SDT considered the
addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, but determined that such a
qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. . However, the SDT
believes that, in circumstances where a local network is unable to utilize the local network exclusion solely because, under
abnormal system conditions power flows out of the network, the same network could be a suitable candidate for exclusion
under the Exception Process.
Numerous comments were received that either challenged the generator thresholds in Exclusion E3.a or suggested that the
Exclusion for local networks should be silent on generator thresholds until the question of appropriate generation thresholds is
addressed in Phase 2 of Project 2010-17. The SDT agrees that the threshold(s) for generation throughout the BES definition
should be addressed in Phase 2 of this effort. However, to satisfy to the Commission’s directives in Orders 743 and 743-A743-A
in a timely fashion, the SDT believes it is necessary to use a generation threshold that is consistent with the in-force ERO
Statement of Compliance Registry Criteria.
The SDT introduced the term “non-retail generation” in the E3 Exclusion, and a number of commenters questioned the SDT’s
understanding of the term. For the purpose of Exclusion E3 (and Exclusion E1), the SDT intends “non-retail generation” to mean
generation that is on the system (supply) side of the retail meter.
Numerous commenters suggested that the word “transmission” be removed from the phrase in the first paragraph of Exclusion
E3. The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word
– in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
included in the term “Element”.
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Several commenters expressed some confusion about Exclusion E3.b. Commenters felt that two separate and distinct ideas
were being addressed in Exclusion E3.b, and that the expression following the colon is expected to clarify the expression
preceding the colon. The SDT agrees that these two ideas are separate, but related. The SDT decided to revise Exclusion E3.b to
provide this clarity, as follows:
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;

This minor revision is clarifying only, and does not represent any material change to the Exclusion provision.
Organization

Yes or No

Question 9 Comment

SERC OC
Standards
Review Group

No

We would agree with the exclusion if the wording of the exclusion includes the following phrase (in
quotation marks) added at the end of E3 b): Power flows only into the LN: The LN does not transfer
energy originating outside the LN for delivery through the LN “under normal operating conditions”.

Tennessee
Valley
Authority

No

TVA would agree with the exclusion if the wording of the exclusion includes the following phrase (in
italics) added at the end of E3 b): “Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN under normal operating conditions; and”

MEAG Power

No

We would agree with the exclusion if the wording of the exclusion includes the following phrase (in
italics) added at the end of E3 b): Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN “under normal operating conditions”.

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition.
For those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power
to flow out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No
change made.
NERC Staff
Technical
Review

No

While we appreciate the improvement in the text of Exclusion E3, but we continue to believe that E3
should require automatic interrupting devices that are part of the BES must be provided at the points
of interconnection between the Local Network and the BES.

Response: The SDT considered the suggested requirement for separation of the LN via automatic fault interrupting devices during the
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Organization

Yes or No

Question 9 Comment

development of the language for the second posting, and determined that such a qualifier could not be enforced for facilities that are
not essential for the reliable operation of an interconnected transmission network. No change made.
Northeast
Power
Coordinating
Council

No

What is the technical justification for 300kv and higher?
Local Network is capitalized (network not capitalized at the beginning of E3) throughout E3, yet it is
not defined in the NERC Glossary.
The installed generation limit in a Local Network should be addressed in Phase 2.
Any studies supporting E3 should be made available.

Response: The threshold of 300 kV is used as a cap, not a minimum. Please refer to the companion document in the second posting
of the BES Definition under Project 2010-17 for a description of the technical justification for local network exclusion.
The term “local network” is not capitalized anywhere in the Exclusion E3 section of the definition except where it is placed as a section
title, and when abbreviated. The SDT understands that “local network” is not a NERC Glossary term.
The SDT agrees that the threshold(s) for generation throughout the BES definition should be addressed in Phase 2 of this effort;
however, to satisfy the Commission’s directives in Order 743 and 743-A in a timely fashion, it is necessary to use a generation
threshold that is consistent with the in-force Statement of Compliance Registry Criteria. No change made.
Please refer to the companion document in the second posting of the BES Definition under Project 2010-17 for a description of the
technical justification for local network exclusion.
Bonneville
Power
Administration

No

BPA has several concerns regarding Exclusion E3. First, BPA strongly believes that Exclusion E3 must
retain the requirement that the local network (LN) be separable from the BES by an automatic fault
interrupting device wherever the LN interconnects with the BES. BPA believes that this is necessary in
order to protect both the BES and the LN during faults, especially if there is any possibility that
backfeed could occur. BPA recommends retaining the original language: Separable by automatic fault
interrupting devices: Wherever connected to the BES, the LN must be connected through automatic
fault interrupting devices.
In addition, as stated in our comments in May, 2011, “automatic fault interrupting device” should be a
defined term.
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Question 9 Comment
BPA strongly believes that Exclusion E3 should not be allowed for any facilities above 200kV instead of
the 300kV limit in shown in the current proposal. Networks operated above 200kV have significant
fault duties, carry much more power, and have a greater potential for cascading if something does not
operate properly than networks operated below 200kV. Therefore, BPA believes that these networks
should be part of the BES.
BPA believes the term “non-retail generation” in E3(a) should also be defined.

Response: The SDT considered the suggested requirement for separation of the LN via automatic fault interrupting devices during the
development of the language of the second posting, and determined that such a qualifier could not be enforced for facilities that are
not essential for the reliable operation of an interconnected transmission network. No change made.
As the SDT does not propose the inclusion of the requirement for an automatic fault interrupting device, the definition of the term is
not necessary.
The threshold cap of 300 kV was a modification added for the second posting of the definition. The prior version of the definition had
no upper bound on operating voltage for the local network, and the SDT has now adopted a 300 kV upper limit pursuant to comments
received. Please refer to the technical justification document for local networks that accompanied the second posting under Project
2010-17 for details about the selection of 300kV as the cap for local networks. No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter. This is a well understood
interpretation which the SDT took from official literature and does not need to be officially defined.
ACES Power
Marketing
Standards
Collaborators

No

The term “non-retail generation” used in Exclusion E1 (item c) and again in E3 (item a) should be
clarified.
The following applies to E3 (item c): A flowgate should not be used to limit applicability of E3. First,
there is no definition for what constitutes a permanent flowgate. Second, flowgates are often created
for a myriad of reasons that have nothing to do with them being necessary to operate the BES. While
section c) in E3 attempts to limit the applicability to permanent flowgates, there is no definition for
what constitutes a permanent flowgate particularly since no flowgate is truly permanent. The NERC
Glossary of Terms definition of flowgate includes flowgates in the IDC. This is a problem because
flowgates are included in the IDC for many reasons not just because reliability issues are identified.
Flowgates could be included to simply study the impact of schedules on a particular interface as an
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Organization

Yes or No

Question 9 Comment
example. It does not mean the interface is critical. As an example, it could be used to generate
evidence that there are no transactional impacts to support exclusion from the BES. Furthermore, the
list of flowgates in the IDC is dynamic. The master list of IDC flowgates is updated monthly and IDC
users can add temporary flowgates at anytime. While the "permanent" adjective applied to flowgates
probably limits the applicability from the “temporary” flowgates, it is not clear which of the monthly
flowgates would be included from the IDC since they might be added one month and removed
another. Flowgates are created for many reasons that have nothing to do with them being necessary
to operate the BES. First, flowgates are created to manage congestion. The IDC is more of a
congestion management tool than a reliability tool. FERC recognized this in Order 693, when they
directed NERC to make clear in IRO-006 that the IDC should not be relied upon to relieve IROLs that
have been violated. Rather, other actions such as re-dispatch must be used in conjunction. Second,
flowgates are used as a convenient point to calculate flows to sell transmission service. The
characteristics of the flowgate make it a good proxy for estimating how much contractual use has
been sold not necessarily how much flow will actually occur. While some flowgates definitely are
created for reliability issues such as IROLs, many simply are not.

Response: Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT believes that the language in Exclusion E3.c prohibiting “Flowgates” from qualifying for definitional exclusion is appropriate
and necessary. As a definitional exclusion characteristic, Exclusion E3.c must follow the principle of being a bright-line and easily
identifiable, and as such, the SDT feels that the definition cannot allow some types of Flowgates and disallow others. Flowgates must
continue to be a prohibiting characteristic under Exclusion E3, since these facilities are more likely to be used in the transfer of bulk
power than not. An entity who wishes to make a case for exclusion of a unique type of Flowgate facility can do so through the
exception process. The SDT believes that the continued qualifier of “permanent” associated with the term “Flowgate” addresses the
majority of the concern in this comment. No change made.
Dominion

No

Dominion could support if E3a were eliminated.

Response: The SDT continues to believe that it is necessary to establish a limit on the allowable quantity of generation that may be
significant to the reliable operation of the surrounding interconnected transmission system. Please note that the issues surrounding
the appropriate generation threshold, among other topics, will be taken up in Phase 2 of this BES definition effort. No change made.
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Organization

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Question 9 Comment

Pepco
Holdings Inc
and Affiliates

No

1) In the Drafting Teams Consideration of Comments on the previous version, it was stated, “....It is
not the SDT’s intent to specifically exclude any facilities in major metropolitan areas; it expects that
the specific examples mentioned (NYC, Washington DC) would not qualify for exclusion under the
revised Exclusion E3.” The currently proposed E3 will result in specific exclusion of major local
networks in major metropolitan areas. These major LNs qualify for exclusion under proposed E3, and
its qualifiers, in that they distribute power to the local load rather than act as facilities to transfer bulk
power across the interconnected system. However, the LNs that supply large amounts of load in very
dense load areas should have some transmission reliability considerations. To capture the
appropriate LNs in question, consideration should be given to limiting the amount of load supplied by
a LN to some load level. For example if an LN has a peak load level of less than 1,000MVA it would
qualify for LN exclusion and if it exceeds 1,000MVA it would not qualify for exclusion. There are
certainly many LNs that supply relatively small amounts of load, just as radial facilities. They should be
excluded. It is important to develop a load level that would provide the proper balance between the
small LNs and the major LNs.
2) Since the SDT deleted the inclusion of Black Start Cranking Paths in I3 then reference to I3 in
criteria E3a should also be removed. Limits on connected generation should only be constrained by
the 75MVA limit. Therefore E3a should then read “Limits on connected generation: The LN and its
underlying Elements do not include generation resources with an aggregate capacity of non-retail
generation greater than 75 MVA (gross nameplate rating);”

Response: The SDT appreciates your concern about the possible exclusion of large metropolitan load centers through the exclusion
for local networks in Exclusion E3. However, the SDT feels that it has accurately captured the characteristics of facilities that are used
in the local distribution of electric energy within Exclusion E3 (and Exclusion E1), which the Commission’s Order specifically targeted
for exclusion. To the suggestion of a 1,000 MW demand cap on the exclusion for local networks, the SDT sees no technical basis upon
which to make such a change. Also, the SDT is unaware of any situations of a network of facilities serving a load of that size that
would not be precluded in some way under at least one of the three characteristics of Exclusion E3. Finally, an Exception Process will
exist in the event that an entity seeks an inclusion of such facilities. No change made.
The SDT appreciates the suggestion that the elimination of the inclusion for Cranking Paths, while maintaining the qualifier prohibiting
blackstart resources from existing in a qualifying local network could be viewed as an inconsistency. Given that the concept of
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Question 9 Comment

exclusion of ‘local networks’ is already an issue requiring careful technical justification, the SDT has determined that it should be
conservative with regard to allowing such an exclusion for facilities that are depended upon for blackstart functionality, as these will
arguably be more important to the reliable operation of the transmission system than equivalent networks without blackstart resources.
It is nevertheless possible to achieve exclusion through the Exception Process. No change made.

Tri-State
Generation
and
Transmission
Assn., Inc.
Energy
Management

No

Tri-State
GandT

No

1. b) should be reworded to “Normally there is power flow only into the LN: The LN is not normally
used to transfer power originating outside of the LN for delivery through the LN.” There could be
conditions inside the LN, such as large loads shut down for maintenance, which would allow the
parallel transmission Elements to allow power to flow through the LN. Those conditions would have
no negative or adverse effect on the BES.
2. Capitalize “Network” at the beginning of the Exclusion
1. b) should be reworded to “Normally there is power flow only into the LN: The LN is not normally
used to transfer power originating outside of the LN for delivery through the LN.” There could be
conditions inside the LN, such as large loads shut down for maintenance, which would allow the
parallel transmission Elements to allow power to flow through the LN. Those conditions would have
no negative or adverse effect on the BES.2. Capitalize “Network” at the beginning of the Exclusion.

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For
those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow
out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
The word “network” as used in “local network” is not intended as a defined term; therefore, it is not capitalized. When expressed in
abbreviation, “LN” is properly capitalized. No change made.
MRO NERC
Standards
Review Forum
(NSRF)

No

THE NSRF suggestion considering a different approach for the power flow criteria in [E]3b. [E]3b: No
[Firm] Power Transfers are scheduled out of, or [through], the LN in the operating horizon [for BES
designations applicable to the operating horizon] and [no] Firm Power Transfers are reserved to flow
out of, or through, the LN in the planning horizon [for BES designations applicable to the planning
horizon].
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Organization

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Question 9 Comment

Response: The SDT believes it is vital to ensure both that power flow is always in the direction from the BES toward the LN at all
points of connection, and that the LN facilities not be used for “wheeling” type transactions. The SDT believes the existing language
accomplishes this. The suggested language in this comment touches on an important aspect, the scheduled use of the facilities, but
the SDT believes that the existing language is more appropriate to express this point. No change made.
Hydro One
Networks Inc.

No

We agree with the exclusion concept of LN. However, the reliability of the interconnected
transmission network should not be determined by the amount of installed generation in the local
network. We believe that the generation limit is restrictive and has little or no technical basis. It is not
the size of a unit in the LN that will determine the reliability impact on the BES but more importantly
its location, configuration and system characteristics such as reliability must run unit. We suggest that
the SDT should address this in phase 2 to increase the installed generation limit in a LN.
We suggest deleting the references to I3 in E1 and E3 because we believe that this reference is in
contradiction to I3 and probably an oversight and should be corrected. I3 does not require a path to
be BES but it implies here that a radial system cannot be excluded if there is a Blackstart unit on it.

Response: The SDT agrees that the threshold(s) for generation throughout the BES definition should be addressed in Phase 2 of this
effort; however, to satisfy the Commission’s directives in Order 743 and 743-A in a timely fashion, it is necessary to use a generation
threshold that is consistent with the in-force Statement of Compliance Registry Criteria. No change made.
The SDT appreciates the suggestion that the elimination of the inclusion for Cranking Paths, while maintaining the qualifier prohibiting
blackstart resources from existing in a qualifying local network could be viewed as an inconsistency. Given that the concept of
exclusion of ‘local networks’ is already an issue requiring careful technical justification, the SDT has determined that it should be
conservative with regard to allowing such an exclusion for facilities that are depended upon for blackstart functionality, as these will
arguably be more important to the reliable operation of the transmission system than equivalent networks without blackstart
resources. It is nevertheless possible to achieve exclusion through the Exception Process. No change made.
Holland Board
of Public
Works

Yes

Holland BPW supports the exclusion of Local Networks (LN) from the definition of BES. Such systems
are generally not necessary for the reliable operation of the interconnected transmission network.
However, some revisions are necessary. Holland BPW believes that E3(a) and E3(b) can and should be
eliminated, provided E3(c) remains. E3(c) provides that an LN is BES if it is classified as a Flow Gate or
Transfer Path. The bases for removing E3(a) and E3(b) are as follows: (1) Provision E3(a) establishes a
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Question 9 Comment
75 MVA limit on connected generation. This is inconsistent with the concept of a LN and should be
removed. If not removed, it should be increased to not less than 300 MVA, consistent with the
discussion in response to Q1.
If an LN does not accommodate bulk power transfer across the interconnected system, the amount of
generation that exists and is distributed within that system is immaterial for purposes of the reliable
operation of the interconnected transmission system. During the NERC Webinar, NERC
representatives suggested that placing an upper limit on generation within a LN might be desirable
based upon an assumption that if that entity’s internal generation is lost, then replacement
generation would have to come from the BES, and could therefore affect reliability. This assumption
has not been substantiated. In most instances, generation resources are dispersed throughout the LN
- it is unlikely an event would result in the loss in the amount of the aggregate generation.
Additionally, LNs have local load shedding and system restoration plans for such contingencies.
(2) E3(b) is unnecessary and should be removed. The proposed language in E3(b) appears to be
concerned with flows originating from outside of the LN, coming into the LN, and then exiting the LN
to loads outside of the LN. As noted above, E3(c) appears to address this concern. If E3(b) is
maintained, then the introductory clause (“Power flows only into the LN:”) should be deleted, because
it is inconsistent with the second clause (“The LN does not transfer energy originating outside the LN
for delivery through then LN.”) If E3(b) is retained, Holland BPW supports the second clause (“The LN
does not transfer energy originating outside the LN for delivery through then LN”) because it appears
to be the portion of the provision that addresses the concern about flows into, through, and then out
of, the LN.
(3) E3(b) should also be removed or modified because it fails to recognize typical municipal system
operations. An LN may have internal generation that is less than its peak load but in excess of offpeak or holiday load levels. The language “Load flows only into the LN” does not recognize this
situation and prevents an LN from making the most economic use of surplus generation. There are
no reliability reasons to discourage such sales since with or without such transactions, this generation
is not necessary for the reliable operation of the interconnected transmission system.

Response: The SDT believes that a limit on the amount of connected (non-retail) generation within the LN is necessary to ensure that
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Question 9 Comment

there is no reliability impact on the interconnected transmission system; however, the threshold of the allowable generation – 75
MVA – was chosen to be consistent with the existing threshold in the NERC Statement of Compliance Registry Criteria, and this
threshold is a subject of further review under the Phase 2 development of the BES definition. The SDT believes that Exclusion E3.b
continues to be necessary to ensure that qualifying LN’s do not participate in “wheel-through” transactions, and that power always
flows in a direction from the BES toward the LN. The SDT has clarified Exclusion E3.b as follows due to your comments and those of
others.
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
Texas
Industrial
Energy
Consumers

Yes

As noted in response to Question 3, above, subsection (a) of Exclusion E3 would only exclude Local
Networks with “aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating).” The reference to “non-retail” generation in subsection (a) indicates that the SDT
may have intended to preserve the “netting” approach set forth in the Statement of Registry
Compliance, but this should be made clearer. The description in subsection (a) should be revised to
exclude “Where the radial system serves Load and includes generation resources not identified in
Inclusions I2 or I3,” and the remainder of that sentence referencing a 75 MVA gross nameplate rating
should be removed. This will provide a reference back to the Statement of Registry Compliance and
clarify that only net capacity is considered for customer-owned facilities.
TIEC also disagrees with the 300 kV upper limitation on transmission elements within a Local Network.
Consistent with TIEC’s comments to FERC, if these facilities are serving a distribution function, their
voltage level is irrelevant. The transmission versus distribution distinction should be based on
function, not voltage level. The remainder of this exclusion clarifies what constitutes a distribution
function, so the 300 kV limit is unnecessary and should be removed.

Response: The SDT evaluated this comment and has concluded that the exclusion must necessarily be based on the gross aggregate
nameplate of the generation connected within the candidate systems. The approach that is suggested in your comment could result
in significant amounts of generation existing within the excluded area. No change made.
The SDT does not agree with the removal of the 300 kV cap that limits the qualification of a group of facilities for local network
exclusion. The SDT feels that an upper bound is essential to prevent inappropriate exclusions of facilities that may be important to
the reliable operation of the interconnected transmission system. The Exception Process is available for specific circumstances where
a 300 kV cap is problematic. No change made.
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PacifiCorp

Yes or No
Yes

Question 9 Comment
PacifiCorp strongly supports the categorical exclusion of Local Networks (“LNs”) from the BES.
PacifiCorp believes the exclusion is necessary to ensure that the BES definition complies with FERC’s
statutory jurisdictional requirements. PacifiCorp recommends the following modifications: o Change
“contiguous transmission Elements” to “contiguous Elements”.
o Modify item b to state, “Power flows only into the LN during normal operating conditions: The LN
does not transfer energy originating outside the LN for delivery to loads located outside the LN...”
o Add an item (may be included in item b) to provide as follows: “The LN is not critical (or is not relied
upon) to maintain the reliability of the interconnected system during abnormal operating conditions.”

Response: The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word
– in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
included in the term “Element”. No change made.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
The SDT does not believe that the statement “The LN is not critical (or is not relied upon) to maintain the reliability of the
interconnected system during abnormal operating conditions” lends itself to determination by inspection; hence, it is not an
appropriate “bright-line” characteristic for ExclusionE3. No change made.
Southern
Company

No

We would agree with the exclusion if the wording of the exclusion includes the following phrase (in
italics) added at the end of E3 b): “Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN “under normal operating conditions”.
What does the term "non-retail generation" mean?
Can the term "non-retail generation in E3a be changed to simply "generation"?

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition.
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Question 9 Comment

For those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power
to flow out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No
change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT has intentionally utilized the term “non-retail generation” in Exclusion E3.a in order to specifically isolate that generation
which is not situated behind the retail meter. It is important to retain this concept, since removal of the clarifier “non-retail” would
cause candidate local networks with retail generation to be unfairly biased against obtaining this exclusion. No change made.
ReliabilityFirst

No

ReliabilityFirst Staff proposes to use the LN exclusion as part of the definition of what elements make
up the facilities used in the local “distribution” of electric energy and could be included in the
Exception Process as a criterion for exclusion.

Response: The SDT believes that Exclusion E3 has sufficient clarity and that its provisions can be readily demonstrated without the
need to be handled through the Exception Process. Therefore, it is more appropriately handled within the definition. No change
made.
Ontario Power
Generation
Inc.

No

Non-retail generation needs to be properly defined in the text of the exclusion.

Mission Valley
Power

No

Mission Valley Power - : We strongly agree that local networks should be excluded, since they act
much like the radial systems excluded in E1 while providing a higher level of service to customers.
These networks should not be discouraged in the name of reliability.
We again object to the introduction of the new confusing term “non-retail generation” with no
definition provided.

Tillamook PUD

No

We strongly agree that local networks should be excluded, since they act much like the radial systems
excluded in E1 while providing a higher level of service to customers. These networks should not be
discouraged in the name of reliability.

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Question 9 Comment
We again object to the introduction of the new confusing term “non-retail generation” with no
definition provided.

Central Lincoln

No

We strongly agree that local networks should be excluded, since they act much like the radial systems
excluded in E1 while providing a higher level of service to customers. These networks should not be
discouraged in the name of reliability.
We again object to the introduction of the new confusing term “non-retail generation” with no
definition provided.

Northern
Wasco County
PUD

No

We strongly agree that local networks should be excluded, since they act much like the radial systems
excluded in E1 while providing a higher level of service to customers. These networks should not be
discouraged in the name of reliability. We again object to the introduction of the new confusing term
“non-retail generation” with no definition provided.

Response: Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
Central
Hudson Gas
and Electric
Corporation

No

Under the proposed definition, clause E3.b. stipulates that ‘power only flows into the Local Network
(LN): The LN does not transfer energy originating outside the LN for delivery through the LN.’ Clearly,
this is a bright line. The Local Network Exclusion document, however, describes that ‘power flow
“shifts”‘ of ‘negligible fraction’ are acceptable. Further, the document acknowledges that parallel
flows through the LN, ‘as governed by the fundamentals of parallel circuits’ will occur. Finally, the
document goes on to exhibit that flows through the LN, however minimal, will result from both power
transfer distribution factor (PTDF) and line outage distribution factor (LODF) analysis. If this is the
case, what bright line criterion should be applied for this Exclusion Principal if no maximum PTDF
and/or LODF are specified?

Response: Exclusion E3.b does in fact prohibit power flow at the BES interface points of the LN from entering the BES. The
accompanying technical justification document merely addresses the insignificance of the power flow shifts that will occur in an
example system. Clearly, in the example system of the technical justification document, power flow is shown to always be in a
direction from the BES toward the LN, albeit with only a slight magnitude shift in the PTDF and LODF analyses. The technical
justification document does not attempt to set any threshold on the magnitude of this shift; it merely is a demonstration on a sample
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Yes or No

Question 9 Comment

system. The only bright-line criterion that is applicable to this question is that power flow shall always be from the BES toward the LN.
City of
Anaheim

No

Again, 75 MVA should be increased to 300 MVA in E2 for the reasons stated in response to Question
7.

Response: The SDT has determined that it must retain the 75 MVA threshold on generation allowed within a qualifying LN in order to
remain consistent with the existing ERO Statement of Compliance Registry Criteria. There has not been sufficient technical
justification to this point that would support a change from this threshold; however, such threshold will be considered in Phase 2 of
this Project 2010-17. No change made.
Consumers
Energy

No

In general we agree, but believe the word "transmission" should be removed from "A group of
contiguous transmission Elements..."

Response: The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word
– in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
included in the term “Element”. No change made.
Manitoba
Hydro

No

Manitoba Hydro agrees with the Local Network Exclusion but disagrees with the drafting team’s
removal of the requirement to have protective devices protecting the BES from the LN. We suggest
that the following requirement is re-inserted into E3 to meet the LN Exclusion:”a) Wherever
connected to the BES, the LN must be connected with a Protection System.”

Response: The SDT considered the suggested requirement for separation of the LN via automatic fault interrupting devices during the
development of the language of the second posting, and determined that, consistent with Order 743 and 743a, such a qualifier could
not be enforced for facilities that are not essential for the reliable operation of an interconnected transmission network. No change
made.
Long Island
Power
Authority

No

Main paragraph and items E3b and E3c adequately define a Local Network. It seems like the intent to
exclude non bulk distribution systems would still be included because of E3a.
E3a should be eliminated. If not eliminated, need to define the term "underlying Elements".

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Organization

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Question 9 Comment

Response: The SDT continues to believe that it is necessary to establish a limit on the allowable quantity of generation that may be
significant to the reliable operation of the surrounding interconnected transmission system. Please note that the issues surrounding
the appropriate generation threshold, among other topics, will be taken up in Phase 2 of this BES definition effort. No change made.
The SDT believes that the existing phrase in ExclusionE3.a “and its underlying Elements” has sufficient clarity and meets the intent of
the exclusion with brevity. No change made.
City of St.
George

No

The exclusion of Local Networks should be provided, however the generation level limits are too
restrictive. As long as the power flow is into the system the generation level of the local network
shouldn’t matter as long as it is being used to serve local load.
E3a should be deleted from the definition, or at least some higher level of allowed generation should
be included. Another possibility would be a ratio of local load to local generation. Areas with local
generation serving local load will have similar characteristics or affects to the BES system as were used
in the Local Network justification paper (Appendix 1) included with the documents. If some
reasonable level of local generation was added to the example system it is unlikely that the affects to
the BES flows would change from what was presented in the example.

Response: The SDT has determined that it must retain the 75 MVA threshold on generation allowed within a qualifying LN in order to
remain consistent with the existing ERO Statement of Compliance Registry Criteria. There has not been sufficient technical
justification to this point that would support a change from this threshold; however, such threshold will be considered in Phase 2 of
this Project 2010-17.
The SDT continues to believe that it is necessary to establish an upper limit on the allowable quantity of generation that may be
included in the local network since generation in a local network may be significant to the reliable operation of the surrounding
interconnected transmission system. Please note that the issues surrounding the appropriate generation threshold, among other
topics, will be taken up in Phase 2 of this BES definition effort.
Orange and
Rockland
Utilities, Inc.

No

We know that N-1 is assumed when power-flow study is performed, however, N-1 should be
mentioned here for clarification.

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Question 9 Comment

Response: The SDT understands this comment to be in reference to the technical justification document that accompanied the
definition in its second posting. This technical justification document was merely intended to be illustrative of the insignificance of
the interaction of a sample local network on its surrounding interconnected transmission system. The “LODF” values were for a single
element taken out of service. No change made.
ISO New
England Inc

No

E3 could result in many large load pockets being excluded from the BES definition and should be
deleted. Assuming that it is retained, we offer the following additional comments.
The term “a group of contiguous transmission elements” is ambiguous and needs to be clarified.
Please clarify in the exclusion if the flows into the LN as described in E3.b) are pre-contingency flows
only.
Please clarify the system conditions (time of year, peak or off-peak) that should be considered in
determining of flow is only into the LN.
The “Non-retail” qualifier in E3.a) should be deleted.

Response: The SDT appreciates your concern about the possible exclusion of large metropolitan load centers through the exclusion
for local networks in Exclusion E3. However, the SDT feels that it has accurately captured the characteristics of facilities that are used
in the local distribution of electric energy within Exclusion E3 (and Exclusion E1), which the Commission’s Order specifically targeted
for exclusion. No change made.
The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word – in lowercase – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be included in the
term “Element”. No change made.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
There are no specified conditions applicable to item Exclusion E3.b. In order to qualify for exclusion under this item, this characteristic
must be demonstrated under all conditions. This exclusion has been re-stated as follows for additional clarity:
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Question 9 Comment

E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
The SDT has intentionally utilized the term “non-retail generation” in Exclusion E3.a in order to specifically isolate that generation
which is not situated behind the retail meter. It is important to retain this concept, since removal of the clarifier “non-retail” would
cause candidate local networks with retail generation to be unfairly biased against obtaining this exclusion. No change made.
Texas
Reliability
Entity

No

There should be language that includes UFLS, UVLS, or load fully removable for Reserves even in a
local network to avoid a lapse in reliability in operation of the BES. Even if it is to be included in any
Phase 2 work, it should be mentioned here to avoid gaps.

Response: The SDT is uncertain whether this comment suggests that facilities used in UFLS, UVLS, or as interruptible load for reserve,
should be prohibited from exclusion from the BES under Exclusion E3. At any rate, even a facility that is excluded under Exclusion E3
may continue to have obligations under the reliability standards for UFLS, UVLS or other load shedding requirements.
Independent
Electricity
System
Operator

No

Consistent with our comments in response to Q7, we propose removing E3 (a) since, as explicitly
described in E3 (b), one of the characteristic of the LN is that power flows only into the LN. The level of
generation contained within the LN is therefore immaterial, particularly where the most onerous
contingency or system operating condition occurring within the LN, results in acceptable BES
performance as defined by the applicable criteria of the NERC transmission planning standards. The
generation connected within the LN that meets the registry criteria would already be captured within
the definition of the BES as provided for in Inclusion I2.

Response: The SDT continues to believe that it is necessary to establish a limit on the allowable quantity of generation that may be
significant to the reliable operation of the surrounding interconnected transmission system. Please note that the issues surrounding
the appropriate generation threshold, among other topics, will be taken up in Phase 2 of this BES definition effort. No change made.
Rochester Gas
and Electric
and New York
State Electric
and Gas

No

“Local Network” is capitalized (network not capitalized at the beginning of E3) throughout E3, yet it is
not defined in the NERC Glossary.
This exclusion is vague. This exclusion applies to a network with “multiple points of connection” with
the purpose “to improve the level of service to retail customer load” - this phrase is intent-based and
not reliability-based - most/all transmission “improves service” compared to it not being there. In
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Organization
Central Maine
Power
Company

Yes or No

Question 9 Comment
essence, this exclusion can be obtained if a portion of the network:1. Doesn’t have significant
generation (again, “non-retail” phrase is unclear)2. Power only flows “into” this portion of the
network, and not (ever? Even under any TPL design contingencies?) “out.” Is this considering only precontingency steady state conditions? During contingency conditions and for the period following a
contingency the LN could supply power to other parts of the network depending on the nature of the
contingency. The conditions under which direction of flow is assessed are critical, but E3(b) is silent on
this.3. This portion of the network is not part of a monitored transmission interfaceThis “Local
Network Exclusion” is supported by a technical analysis which relied on transfer distribution factors
(see
http://www.nerc.com/docs/standards/sar/bes_definition_technical_justification_local_network_201
10819.pdf on the NERC BES Definition standard page
http://www.nerc.com/filez/standards/Project2010-17_BES.html ). This transfer distribution factor
(TDF) method was rejected by FERC in Order 743. Paragraph 85 of the Order states: “Given the
questionable and inconsistent exclusions of facilities from the bulk electric system by the material
impact assessment and the variable results of the Transmission Distribution Factor test proposed in
NPCC’s compliance filing in Docket No. RC09-3, there are no grounds on which to reasonably assume
that the results of the material impact assessment are accurate, consistent, and comprehensive.93
Additionally, we have noted how the results of multiple material impact tests can vary depending on
how the test is implemented.”Unless E3 is made more specific and clear, it should be stricken.

Response: The term “local network” is not capitalized anywhere in the Exclusion E3 section of the definition except where it is placed
as a section title, and when abbreviated. The SDT understands that “local network” is not a NERC Glossary term. No change made.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
The SDT recognizes that the TDF methodology suggested by various entities as a threshold for determining inclusion in the BES was
not favored by the Commission. However, as used in the technical justification document, the transfer distribution factors for power
flow transfer as well as line outage factors are merely illustrative of the de minimis impact that a sample local network has on its
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Question 9 Comment

surrounding interconnected transmission system. The SDT does not propose the use of TDF as a threshold for determination of BES.
Kansas City
Power and
Light Company

No

Although the Technical Justification Local Network guidance document is helpful in explaining the
principles and concepts involved with determination of what constitutes a Local Network, criteria
needs to be established regarding the impacts of LODF and PTDF that will clearly define what
constitutes a Local Network to avoid debate and controversy.

Response: As used in the technical justification document, the transfer distribution factors for power flow transfer as well as line
outage factors are merely illustrative of the de minimis impact that a sample local network has on its surrounding interconnected
transmission system. The SDT does not propose the use of TDF as a threshold for determination of BES. No change made.
Nebraska
Public Power
District

No

In E3 (a): please define “non-retail generation” as usued in E3(a).
Also, what is the criterion that makes this genertion BES generation? The MVA rating only, or is there
other criteria? A generator may have a 75 MVA gross nameplate rating, but may be limited physically
or electrically to below the 75 MVA. Is this a basis for exclusion for this generator?

Response: Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
Consistent with the ERO Statement of Compliance Registry Criteria, the SDT has used language in describing generation thresholds in
Exclusion E3.a as being gross aggregate nameplate ratings.
Ameren

No

a) The exclusion should also be extended to reactive resources needed to support the local area
network (see response to Q10).
It is also suggested that “local network” be renamed to “local area network” to better describe or
distinguish itself from a wide-area network such as the BES.
b) We would agree with the exclusion if the wording of the exclusion includes the following phrase
(in italics) added at the end of E3 b): Power flows only into the LN: The LN does not transfer
energy originating outside the LN for delivery through the LN “under normal operating
conditions”.
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Organization

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Question 9 Comment

Response: If a candidate local network is granted exclusion under Exclusion E3, the exclusion would apply to the reactive resources
within that network as well. No change made.
The SDT believes that renaming the local network to “local area network” (LAN) will lead to industry confusion with the identical term
used to refer to communications infrastructure. No change made.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
Georgia
System
Operations
Corporation

No

Item (b) is unclear: Although the first sentence says “Power flows only into the LN,” which suggests
there will be no exports, the second sentence says “The LN does not transfer energy originating
outside the LN for delivery through the LN,” which suggests it could deliver power originating within
the LN. This would seem to be reasonable by comparison to E-2, so long as no more than 75 MVA is
exported (which is indeed the limitation on the quantity of “non-retail generation” in the LN).
On a related point, if the limit on connected generation is not intended to be a limit on possible
exports, and therefore any power from interconnected non-retail generation must be sold within the
LN, why does the limit need to be so low; why should the aggregate quantity of such internallyconsumed generation be an issue?
Also, is the “non-retail” designation intended to exclude customer-owned generation from the 75
MVA calculation?

Response: The SDT has re-stated item Exclusion E3.b for additional clarity.
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
The limit placed on the aggregate generation within the local network only applies to non-retail generation. To clarify, in order to
qualify under Exclusion E3, exports are not permissible from the local network.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.

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Organization
ATC LLC

Yes or No

Question 9 Comment

No

ATC agrees in general with the exclusions for E3 pending the following changes: Power flows only into
the LN: The LN does not transfer energy originating outside the LN for delivery through the LN under
normal operating conditions (n-0 contingency); and
ATC suggests considering a different approach for the power flow criteria in Exclusion E3b:Inclusion
E3b - No Firm Power Transfers are scheduled to flow out of, or through, the LN in the operating
horizon [for BES designations applicable to the operating horizon] and no Firm Power Transfers are
reserved to flow out of, or through, the LN in the planning horizon [for BES designations applicable to
the planning horizon).

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition.
For those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power
to flow out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No
change made.
The SDT believes it is vital to ensure both that power flow is always in the direction from the BES toward the LN at all points of
connection, and that the LN facilities not be used for “wheeling” type transactions. The SDT believes the existing language
accomplishes this. This suggested language in this comment touches on an important aspect, the scheduled use of the facilities, but
the SDT believes that the existing language is more appropriate to express this point. No change made.
Tacoma Power

No

Tacoma Power does not support the Exclusion E3 as currently written. We strongly believe that
Section c) of E3 must replace the term “transfer path” with “Major Transfer Path” to distinguish these
paths from any common ATC path. This revision is consistent with the existing language used in the
form, Detailed Information to Support an Exception Request.
Additionally, we believe it is not appropriate for E3 to state an MVA threshold in Section a) when
determining such thresholds is the purpose for Phase 2. We urge the SDT to defer the determination
of a MVA threshold in E3 to Phase 2.
Finally, the term “non-retail generation” is not a universally understood term in the industry. We
suggest that the SDT replace the phrase “non-retail generation” with “generation located on the retail
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Organization

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Question 9 Comment
customer’s side of the meter.”

Response: The existing language posted in the second draft of the BES definition does include the word “major” as a modifier of
transfer paths in the Western Interconnection. The definition cannot have this word “major” capitalized, as it is not part of the NERC
Glossary of Terms. Accordingly, the SDT believes that there is no need to make the suggested change to Exclusion E3.c.
The SDT agrees that the threshold(s) for generation throughout the BES definition should be addressed in Phase 2 of this effort;
however, to satisfy the Commission’s directives in Order 743 and 743-A in a timely fashion, it is necessary to use a generation
threshold that is consistent with the in-force Statement of Compliance Registry Criteria. No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter. The exclusion language of
Exclusion E3.a intends to consider only the non-retail (supply side) generation; whereas your comment suggests that the generation
to be counted is on the retail side of the meter. With the clarification of the use of the term “non-retail generation", the SDT believes
that Exclusion E3.c is appropriate. No change made.
MEAN

No

MEAN does not agree with the language of E3, b). This language is arbitrary and could be represented in
several ways, dependent on the entity making their case. As we all know, electricity doesn’t always take
the shortest path. MEAN would recommend eliminating E3, b) due to its subjective language and rely on
the current E3, c) to evaluate reliability and system impacts. If the language does not change, MEAN
would argue to any applicable RE that the language intent was to address facilities that have
documentation stating that the facilities are used for transferring energy across (e.g. joint ownership,
contribution in aid of construction, etc.) and have an E3 exception denied based on power flow models
or other transmission modeling.

Response: The SDT has reviewed the language of Exclusion E3.b, and does not find it to be subjective or arbitrary. However, the SDT
does propose a minor revision to re-state E3.b for additional clarity:
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
South Houston
Green Power,
LLC

SHGP would like to broaden the scope of Local Networks. If a Local Network does not allow transfer
of Bulk Power across the Interconnected System, then the Local Network should be excluded
regardless of the amount of generation behind the meter. Often, large industrial sites install large
combined Heat and Power cogeneration units due to a hefty steam load. Subjecting industrial
facilities to additional reporting and coordination efforts [other than those already required by the TO
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Organization

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Question 9 Comment
and RTO] may have little, if any, increase in grid reliability. The 75 MVA (gross nameplate rating) needs
to be eliminated. To date, none of the Regional Entities has suggested that SHGP or its affiliates
register as a Transmission Owner or Transmission Operator with respect to any SHGP or affiliated
delivery facilities.

Response: The SDT has determined that it must retain the 75 MVA threshold on generation allowed within a qualifying LN in order to
remain consistent with the existing ERO Statement of Compliance Registry Criteria. There has not been sufficient technical
justification to this point that would support a change from this threshold; however, such threshold will be considered in Phase 2 of
this Project 2010-17. No change made.
Hydro-Quebec
TransEnergie

Same comment than Q7.

Response: See response to Q7.
ExxonMobil
Research and
Engineering

Yes

Exclusion E1 and E3 aid in the delineation of distribution and transmission facilities. However, we
request that the BES SDT review paragraphs 108 and 109 of FERC Order 743. In order to meet
reliability target requirements to safely and economically operate manufacturing and production
facilities, many industrial facilities are fed by two or more utility transmission lines that originate at
independently fed utility substations. Due to the magnitude of an industrial site’s load, these
transmission lines are typically designed to operate at levels in excess of 100 kV at the request of the
utility company. These transmission lines typically terminate into an interconnection facility, owned
by the industrial facility, that spot networks the transmission lines via a ring buss or breaker and a half
substation within the industrial facility’s private use network in order to serve the load of the facility’s
private use network. These private use networks typically satisfy the requirements set forth in the
definition of a Local Network (power flows in, not a flowgate, etc.); however, the term “non-retail
generation” is not a term that is implicitly defined or consistent with this documents use of “net
capacity provided...” phrasing in similar exclusions.

Response: Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.

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Question 9 Comment

Sacramento
Municipal
Utility District

Yes

It is preferred to hold reference to gross nameplate rating/threshold values until generation technical
justification is completed as part of Phase 2; these studies should apply to any real or reactive power
threshold reference.
For Exclusion E3-b using the phrase “[p]ower flows only into the LN” is too restrictive. An allowable
MW threshold of LN power producing resources should be deferred to the Phase 2 BES technical
analysis. Where no generation is present in the LN, it is recommended that an allowance for residual
flow through the LN.

City of Austin
dba Austin
Energy

Yes

We prefer to hold reference to gross nameplate rating/threshold values until generation technical
justification is completed as part of Phase 2; these studies should apply to any real or reactive power
threshold reference.
For Exclusion E3-b using the phrase “[p]ower flows only into the Local Network” is too restrictive. An
allowable MW threshold of Local Network power producing resources should be deferred to the
Phase 2 BES technical analysis. Where no generation is present in the Local Network, it is
recommended that an allowance for residual flow through the Local Network.

Response: The SDT agrees that the threshold(s) for generation throughout the BES definition should be addressed in Phase 2 of this
effort; however, to satisfy the Commission’s directives in Order 743 and 743-A in a timely fashion, it is necessary to use a generation
threshold that is consistent with the in-force Statement of Compliance Registry Criteria. No change made.
The SDT feels strongly that in order for a network to qualify for exclusion under the Exclusion E3 section of the definition, there must
be strict bounds and limits placed on the characteristics of the candidate facilities. Allowances for minor “out-flow” from the local
network, or “minimal” flow, as suggested in this comment, will lead to an inconsistent application of the definition and therefore, a
lack of bright-line quality in the definition. Situations such as what is proposed in this comment can be referred to the Exception
Process for possible exclusion from the BES. No change made.
Portland
General
Electric
Company

Yes

PGE agrees with Exclusion E3, but believes additional clarification is necessary to facilitate a complete
understanding and application of the exclusion criteria. First, there is no specific definition of “nonretail” generation provided.
Additionally, E3 b) states “Power flows only into the LN: The LN does not transfer energy originating
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Organization

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Question 9 Comment
outside the LN for delivery through the LN.” PGE believes that a local network should still qualify for
the LN exclusion if power may flow out of the LN at a discrete point or certain discrete points during
abnormal operating conditions, but power still flows into the LN on an aggregate basis during all
operating conditions, and power flows only into the LN at all discrete points during normal operating
conditions.

Response: Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
Cowlitz
County PUD

Yes

Cowlitz strongly supports the categorical exclusion of Local Networks (“LNs”) from the BES. This
exclusion will allow conversion of radial systems to LNs without compliance impact, and should be
encouraged rather than discouraged as networked systems generally reduce losses, increase system
efficiency, and increase the level of service to retail customers. The decision of whether to network
radial systems should be made on the basis of costs and benefits to the retail customers served by
those radials, and not on the basis of disparate regulatory treatment. Consumers will ultimately
benefit from the path chosen by the SDT.
Cowlitz believes that the word “transmission” does not add clarity to the Exclusion; simply stating
“Elements” is sufficient. This will allow for a gradual acceptance that transmission is not defined by a
certain voltage, but more a medium in which electrical power is efficiently transported from power
resources to load centers where it is distributed. The old convention of transmission versus
distribution no longer fits in the current regulatory environment, and as such should be retired.
Cowlitz also believes that subparagraphs (a) and (b) are redundant; subparagraph (a) is duplicated by
the limit in subparagraph (b) requiring no flow out of the LN. However, Cowlitz also believes that
removing (a) will complicate FERC’s acceptance of this exclusion. Therefore this should be addressed
in Phase 2.
Cowlitz is confused by the use of the term “non-retail generation” in subparagraph (a). From context,
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we believe the SDT considers “non-retail generation” to mean generation that is not connected
through a dedicated step-up transformer to voltages at or above 100 kV, is consumed by the retail
customer’s load, or consumed within the LN rather than being physically exported and sold to markets
outside the LN.
Cowlitz suggests that the SDT rewrite subparagraph (a) to read “Limits on connected generation: The
LN and its underlying Elements do not include generation resources identified in Inclusion I3 and does
not have any generation net power flow greater than 75 MVA across any single retail revenue
metering point into an Element operated at or greater than 100 kV.”

Response: The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word
– in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
included in the term “Element”.
The SDT agrees that the threshold(s) for generation throughout the BES definition should be addressed in Phase 2 of this effort;
however, to satisfy the Commission’s directives in Order 743 and 743-A in a timely fashion, it is necessary to use a generation
threshold that is consistent with the in-force Statement of Compliance Registry Criteria. No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT appreciates the suggested language change for item Exclusion E3.a. The SDT considered this language, and has determined
that retention of the existing (non-retail) generation limit of 75 MVA is essential to meet the Commission’s order in the first phase of
Project 2010-17. No change made.
National Grid

Yes

We agree with Exclusion E3 on local networks, however we suggest this clarification to the first
sentence: A group of contiguous transmission Elements operated at or above 100kV but less than
300kV that distribute power to Load rather than transfer bulk power across the interconnected
system under normal (“all-lines-in”) configuration and conditions.
We also suggest the following clarification to part c, so that the IROLs don’t get overlooked: Not part
of Flowgate, transfer path, or an Interconnected Reliability Operating Limit (IROL). The LN does not
contain a monitored Facility of a permanent Flowgate in the Easter Interconnection, a major transfer
path within the Western Interconnection, or a comparable monitored Facility in the ERCOT or Quebec
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Question 9 Comment
Interconnection, and is not a monitored Facility included in an IROL.

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition.
For those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power
to flow out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No
change made.
The SDT believes it has adequately and concisely addressed the IROL characteristic with Exclusion E3.c. No change made.
Pacific
Northwest
Generating
Cooperative
(PNGC)
Raft River
Rural Electric
Cooperative
(RAFT)
West Oregon
Electric
Cooperative
Blachly-Lane
Electric
Cooperative
(BLEC)
Coos-Curry
Electric
Cooperative

Yes

PNGC strongly supports the exclusion of Local Networks (“LNs”) from the BES. The conversion of
radial systems to local networks should be encouraged because networked systems generally reduce
losses, increase system efficiency, and increase the level of service to retail customers. If the BES
definition were to provide an exclusion for radials without providing a similar exclusion for LNs,
however, it would discourage networking local distribution systems because of the significantly
increased regulatory burdens faced by the local distribution utility if it elected to network its radial
facilities. By placing radial systems and LNs on the same regulatory footing, the proposed definition
will ensure that decisions about whether to network radial systems are made on the basis of costs and
benefits to the retail customers served by those radials, and not on the basis of disparate regulatory
treatment. Consumers would ultimately benefit.PNGC also supports specific refinements made to the
LN exclusion by the SDT in the current draft of the BES definition. In particular, PNGC supports the
clarification of the purposes of a LN. The current draft states that LNs connect at multiple points to
“improve the level of service to retail customer Load and not to accommodate bulk power transfer
across the interconnected system.” PNGC supports this change in language because it reflects the
fundamental purposes of a LN and emphasizes one of the key distinctions between LNs and bulk
transmission facilities, namely, that LNs are designed primarily to serve local retail load while bulk
transmission facilities are designed primarily to move bulk power from a bulk source (generally either
the point of interconnection of a wholesale generator or a the point of interconnection with another
bulk transmission system) to one or more wholesale purchasers.
PNGC believes further improvement of the language could be achieved with additional modifications
and clarifications. With respect to the core language of Exclusion 3, we believe the language making
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Organization
(CCEC)
Central
Electric
Cooperatve
(CEC)
Clearwater
Power
Company
(CPC)
Consumer's
Power Inc.
Douglas
Electric
Cooperative
(DEC)
Fall River Rural
Electric
Cooperative
(FALL)
Lane Electric
Cooperative
(LEC)
Lincoln
Electric
Cooperative
(LEC)
Northern

Yes or No

Question 9 Comment
a “group of contiguous transmission Elements operated at or above 100kV” the starting point for
identifying a LN would be improved by deleting the term “transmission” from this phrase. This is so
because LNs are not used for transmission and the use of the term “transmission Elements” is
therefore both confusing and unnecessary. There would be no room for argument about what the
SDT intended by including the word “transmission” if the word is deleted and the Exclusion applies to
any “group of Elements operated at 100kV or above” that meets the remaining requirement of the
Exclusion. Further, any definitional value that is added by using the term “transmission Elements” is
accomplished by using that term in the core definition, and there is no reason to carry the term
through in the Exclusions.
PNGC also believes that subparagraphs (a) and (b) are redundant, because whatever protection is
offered by the generation limit in subparagraph (a) is duplicated by the limit in subparagraph (b)
requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a) of Exclusion 3 and
simply rely on subparagraph (b) because if power only flows into the LN even if it interconnects more
than 75 MVA of generation, the interconnected generation interconnected will have no significant
interaction with the interconnected bulk transmission system. It will only interact with the LN. And,
with the advent of distributed generation, it is easy to foresee a situation in which a large number of
very small distributed generators are interconnected into a LN, so that the aggregate capacity of these
generators exceeds 75 MVA. However, because the generators are small and dispersed and, under
the criterion in subparagraph (b), would be wholly absorbed within the LN rather than transmitting
power onto the interconnected grid, those generators would not have a material impact on the grid.
We also suggest that subparagraph (b) of Exclusion 3 could be more clearly drafted. Subparagraph
(b), as part of the requirement that power flow into a LN rather than out of it, includes this
description: “The LN does not transfer energy originating outside the LN for delivery through the LN.”
We understand this language is intended to distinguish a LN from a link in the transmission system power on a transmission link passes through the transmission link to a load located elsewhere, while
power in a LN enters the LN and is consumed by retail load within the LN. While we agree with the
concept proposed by the SDT, we believe the language would be clearer if it read: “The LN does not
transfer energy originating outside the LN for delivery through the LN to loads located outside the
LN.” We believe the italicized language is necessary to distinguish between a transmission system,
where power that originates outside a system is delivered through the system and passes through the
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Organization
Lights Inc.
(NLI)
Okanogan
County
Electric
Cooperative
(OCEC)
Umatilla
Electric
Cooperative
(UEC)

Yes or No

Question 9 Comment
system to a sink located somewhere outside the system, from a LN, in which power originating
outside the LN passes through the LN and is delivered to retail load within the LN. To put it another
way, the italicized language helps distinguish a transmission system from an LN, in which the LN
“transfers energy originating outside the LN for delivery through the LN to loads located within the
LN.”
We also believe the language of subparagraph (a) of Exclusion 3 could be improved. Subparagraph
(d) would make LNs part of the BES if they interconnect “non-retail generation greater than 75 MVA
(gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and 7, we urge
the SDT to replace the reference to a hard 75 MVA threshold with the defined term “Qualifying
Aggregate Generation Resources” or some equivalent.
We are also uncertain what is meant by the use of the term “non-retail generation” in subparagraph
(a). From context, we believe the SDT considers “non-retail generation” to be the equivalent of
generation that is located behind the retail meter, usually but not always owned by the customer and
used to serve the customer’s own load. We therefore suggest that the SDT replace the term “nonretail generation” with “generation located behind the retail customer’s meter.”
Similarly, we are unsure what is meant by the phrase “the LN and its underlying Elements.” We
believe the phrase “and its underlying Elements” could simply be deleted from the definition without
loss of meaning. In the alternative, the SDT might consider using the phrase “the LN, including all
Elements located on the distribution side of any Automatic Fault Interrupting Devices (or other points
of demarcation) separating the LN from the bulk interstate transmission system.” We believe this
phrase more accurately reflects the SDT’s intent, which appears to be that generation exceeding 75
MVA in aggregate capacity interconnected anywhere within the LN disqualifies that LN from being
excluded from the BES under Exclusion 3.
PNGC also believes that both subparagraphs (a) and (b) of Exclusion 3 could be safely eliminated as
long as subparagraph (c) is retained. Subparagraph (c) makes a LN part of the BES if it is classified as a
Flow Gate or Transfer Path. Flow Gates and Transfer Paths are, by definition, the key facilities that
allow reliable transmission of bulk electric power on the interconnected grid. If a LN has not been
identified as either a Flow Gate or a Transfer Path, it is unlikely the LN is necessary for the reliable
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transmission of electricity on the interconnected bulk system.
Apart from these specific improvements that we believe could be achieved by modifying the language
of Exclusion 3, we believe the SDT may need to re-examine certain assumptions that appear to
underlie the current draft. Specifically, subparagraph (a) suggests that if BES generation is embedded
within a LN, the LN itself must also be BES. But two NERC bodies have already addressed similar
questions and concluded there is no technical basis for such concerns. NERC’s Standards Drafting
Team for Project 2010-07 and its predecessor, the “GO-TO Task Force” were formed to address how
the dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. The GO-TO Team concluded that by complying with a
handful of reliability standards, primarily related to vegetation management, reliable operation of the
bulk interconnected system could be protected without unduly burdening the owners of such
interconnection systems. Therefore, there is no reason, according to the GO-TO Team, that dedicated
high-voltage interconnection facilities must be treated as “Transmission” and classified as part of the
BES in order to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for
Generator Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO
Task Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most
often not part of the integrated bulk power system, and as such should not be subject to the same
level of standards applicable to Transmission Owners and Transmission Operators who own and
operate transmission Facilities and Elements that are part of the integrated bulk power system.”
White Paper Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at
the Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to
comply with the same standards as BES Transmission Owners and Operators “would do little, if
anything, to improve the reliability of the Bulk Electric System,” especially “when compared to the
operation of the equipment that actually produces electricity - the generation equipment itself.” Id.
We believe that interconnection of BES generators within a LN is analogous and that, based on the
findings of the Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply
because a large generator is embedded in the LN will result in substantial overregulation and
unnecessary expense with little gain for bulk system reliability. If anything, generation interconnected
through a LN is less likely to produce material impacts on the interconnected bulk transmission system
than the equivalent generator interconnected through a single dedicated line because an LN is
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Question 9 Comment
interconnected to the bulk system at several points, so that if one interconnection goes down, power
can still flow from the BES generator to the bulk system on other interconnection points. Where a
dedicated interconnection facility is involved, by contrast, if the interconnection line fails, the
generator is unavailable to the interconnected bulk system. Similarly, we suggest that the SDT reexamine the assumptions underlying subparagraph (b), which seems to suggest that a local
distribution system cannot be classified as a Local Network if power flows out of that system at any
time, even if the amount is de minimis, the outward flow is only for a few hours, a year, or the
outward flow occurs only in an extreme contingency. Accordingly, we suggest that the initial clause of
subparagraph (b) be revised to read: “Except in unusual circumstances, power flows only into the LN.”
Finally, we note that the LN exclusion must not operate in any way as a substitution for the statutory
prohibition on including “facilities used in the local distribution of electric energy” in the BES.
Therefore, even with the LN exclusion, the SDT must retain this statutory language in the core
definition of the BES, as discussed in our answer to Question One. If a certain piece of equipment is a
“facility used in the local distribution of electric energy,” then it is not part of the BES in the first
instance, and so consideration of the LN Exclusion, or of any other Exclusion, any Inclusion, or any
Exception, would be both unnecessary and uncalled for.

Response: The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word
– in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
included in the term “Element”.
The SDT continues to believe that it is necessary to establish a limit on the allowable quantity of generation that may be significant to
the reliable operation of the surrounding interconnected transmission system. Please note that the issues surrounding the
appropriate generation threshold, among other topics, will be taken up in Phase 2 of this BES definition effort. No change made.
The intent of the SDT in structuring the language of Exclusion E3.b was to ensure two things: first that power flow is always in the
direction from the BES toward the LN, and second that the LN is not used for “wheel-through” transactions. The suggestion in your
comment places an unnecessary qualifier on the “wheel-through” whereby it would only apply if the transaction were serving “loads”.
The SDT believes this qualifier would inadvertently allow a wholesale transaction to be scheduled through the subject facilities, and
this is contrary to the intent of the exclusion provision of Exclusion E3.b. Given the high degree of certainty and assurances regarding
the high priority of the Phase 2 efforts on this Project 2010-17, for the purpose of completing the posting of the definition in the first
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phase of the Project, the SDT believes that it is preferable to continue to use the specific value of 75 MVA within item Exclusion E3.a.
No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT believes that the existing phrase in Exclusion E3.a “and its underlying Elements” has sufficient clarity and meets the intent of
the exclusion with brevity. No change made.
The SDT acknowledges the work of Project 2010-07 “GO-TO” task force in identification of various NERC Standard requirements that
would promote reliability of the generator-to-transmission interface. This Project 2010-17 SDT believes that the body of work in
Project 2010-07 is most pertinent to generator lead-line facilities, rather than the looped and parallel-operated facilities contemplated
in Exclusion E3, and therefore, the SDT finds it necessary to continue to require all of the characteristics of Exclusion E3 to be met in
order to qualify for exclusion from the BES. No change made.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
The SDT has retained the statutory language “facilities used in the local distribution of electric energy” in the core definition section.
Massachusetts
Department of
Public Utilities

Yes

The MA DPU generally supports this exclusion but believes it is too narrow. As noted in the response
to question 7, Exclusion E3 should likely allow a higher level of aggregate generation MVA on a Local
Network.
In addition, local networks should not necessarily be ineligible for Exclusion E3 simply because an
amount of power may transfer out of the network at times. NERC’s draft technical network exclusions
document should be amended such that local networks would be permitted to qualify for network
exclusions under E3 if power flowing out of the network is minimal and would not likely adversely
impact the BES.

Response: The SDT has determined that it must retain the 75 MVA threshold on generation allowed within a qualifying LN in order to
remain consistent with the existing ERO Statement of Compliance Registry Criteria. There has not been sufficient technical
justification to this point that would support a change from this threshold; however, such threshold will be considered in Phase 2 of
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this Project 2010-17. No change made.
The SDT feels strongly that in order for a network to qualify for exclusion under the Exclusion E3 section of the definition, there must
be strict bounds and limits placed on the characteristics of the candidate facilities. Allowances for minor “out-flow” from the local
network, or “minimal” flow, as suggested in this comment, will lead to an inconsistent application of the definition and therefore, a
lack of bright-line quality in the definition. Situations such as what is proposed in this comment can be referred to the Exception
Process for possible exclusion from the BES. No change made.
The Dow
Chemical
Company

Yes

Dow is uncertain whether end user-owned, behind-the-meter delivery facilities of the sort it has
described above would fall within the scope of the core BES definition proposed by NERC. To date,
none of the Regional Entities has suggested that Dow should register as a Transmission Owner or
Transmission Operator with respect to any of these Dow-owned delivery facilities. If a literal
application of the proposed BES Definition would, because of their voltage level or for any other
reason, include such facilities, then Dow has an interest in assuring that the E3 exclusion for "local
network" facilities is structured to embrace them. To that end, Dow would propose, first, the
elimination of the 300 Kv cap for these facilities. Dow has systems that operate above 300 Kv due
solely to the capacity of the lines to supply power over the distance required at our large
manufacturing sites.
Second, for the same reasons discussed above (in response to question #7), the phrase “do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating)” in “a)”
should be changed to “the net capacity provided to the transmission grid does not exceed 75 MVA.”
Third, the introductory phrase in “b)” -- “Power flows only into the LN” -- is inconsistent with the
recognition in “a)” (as amended pursuant to Dow’s above suggestion) that power may flow out of an
LN and into the transmission grid if there is generation connected to the LN and the 75 MVA limit is
observed. Dow recommends either deleting the introductory clause or correcting it to read “Power is
not transferred through the LN.”

Response: The SDT does not agree with the removal of the 300 kV cap that limits the qualification of a group of facilities for local
network exclusion. The SDT feels that an upper bound is essential to prevent inappropriate exclusions of facilities that may be
important to the reliable operation of the interconnected transmission system. The Exception Process is available for specific
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circumstances where a 300kV cap is problematic.
The SDT evaluated your comment in regard to Question 7 (Radial) as well as to the local network exclusion, and has concluded that
both exclusions must necessarily be based on the gross aggregate nameplate of the generation connected within the candidate
systems. The approach that is suggested in your comment could result in significant amounts of generation existing within the
excluded area.
It remains the intent of the SDT to uphold a 75 MVA limit on the connected (non-retail) generation within a qualifying LN and, at the
same time, reinforcing that power flow is always from the BES toward the LN at all points of connection. We believe these
characteristics are essential in order to ensure that qualifying LN facilities are not being relied upon for reliable operation of the
interconnected transmission system.
Springfield
Utility Board

Yes

SUB strongly supports the exclusion of Local Networks from the BES. SUB particularly agrees with the
addition of, “LN’s emanate from multiple points of connection at 100 kV or higher to improve the level
of service to customer Load and not to accommodate bulk power transfer across the interconnected
system.” language to the draft E3 Exclusion, as well as the LN characterization being more clearly
defined.SUB is concerned that the E3 Exclusion does not specify that these power flows would be
“under normal operating conditions” and specify if all power flow is considered.
SUB recommends that unscheduled power flow should not be considered, but that it is applicable only
to scheduled power flow.
While SUB supports the exclusion of LNs from the BES, we believe there is additional work that needs
to done regarding the Local Network Exclusion Technical Justification. Without specific parameters,
determining inclusions and exclusions will be left to the discretion of too many. This will create
ambiguity and inconsistency of application.

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition.
For those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power
to flow out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No
change made.
The suggestion that only the “scheduled” portion of flow be considered under Exclusion E3.b would ignore the physical impact that the
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candidate network has on the surrounding interconnected transmission system; therefore, the SDT must retain the provisions of
Exclusion E3.b. However, the SDT has made a clarifying change to the exclusion language to address various comments that were
received.
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
The SDT does not intend to perform additional work on the technical justification document at this time. It was not intended to have
any specific thresholds or parameters from which exclusions would be granted; it merely illustrates the negligible effects that a
sample local network has upon the flows in the surrounding transmission network. No change made.
Michigan
Public Power
Agency
Clallam
County PUD
No.1
Snohomish
County PUD
Kootenai
Electric
Cooperative

Yes

MPPA and its members strongly supports the categorical exclusion of Local Networks (“LNs”) from the
BES. We believe the exclusion is necessary to ensure that the BES definition complies with the
statutory requirement, discussed in our response to Question 1, to exclude all facilities used in the
local distribution of electric power. LNs are, of course, probably the most common form of local
distribution facility. Further, the conversion of radial systems to local distribution networks should be
encouraged because networked systems generally reduce losses, increase system efficiency, and
increase the level of service to retail customers. If the BES definition were to provide an exclusion for
radials without providing a similar exclusion for LNs, however, it would discourage networking local
distribution systems because of the significantly increased regulatory burdens faced by the local
distribution utility if it elected to network its radial facilities. By placing radial systems and LNs on the
same regulatory footing, the proposed definition will ensure that decisions about whether to network
radial systems are made on the basis of costs and benefits to the retail customers served by those
radials, and not on the basis of disparate regulatory treatment. Consumers will ultimately benefit
from the path chosen by the SDT.MPPA and its members also support specific refinements made to
the LN exclusion by the SDT in the current draft of the BES definition. In particular, MPPA supports
the clarification of the purposes of a LN. The current draft states that LNs connect at multiple points
to “improve the level of service to retail customer Load and not to accommodate bulk power transfer
across the interconnected system.” Snohomish supports this change in language because it reflects
the fundamental purposes of a LN and emphasizes one of the key distinctions between LNs and bulk
transmission facilities, namely, that LNs are designed primarily to serve local retail load while bulk
transmission facilities are designed primarily to move bulk power from a bulk source (generally either
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Question 9 Comment
the point of interconnection of a wholesale generator or a the point of interconnection with another
bulk transmission system) to one or more wholesale purchasers.
MPPA believes further improvement of the language could be achieved with additional modifications
and clarifications. With respect to the core language of Exclusion 3, we believe the language making
a “group of contiguous transmission Elements operated at or above 100 kV” the starting point for
identifying a LN would be improved by deleting the term “transmission” from this phrase. This is so
because LNs are not used for transmission and the use of the term “transmission Elements” is
therefore both confusing and unnecessary. There would be no room for argument about what the
SDT intended by including the word “transmission” if the word is deleted and the Exclusion applies to
any “group of Elements operated at 100 kV or above” that meets the remaining requirement of the
Exclusion. Further, any definitional value that is added by using the term “transmission Elements” is
accomplished by using that term in the core definition, and there is no reason to carry the term
through in the Exclusions.
MPPA also believes that subparagraphs (a) and (b) are redundant in the sense that whatever
protection is offered by the generation limit in subparagraph (a) is duplicated by the limit in
subparagraph (b) requiring no flow out of the LN. We believe the SDT can eliminate subparagraph (a)
of Exclusion 3 and simply rely on subparagraph (b) because if power only flows into the LN even if it
interconnects more than 75 MVA of generation, the interconnected generation interconnected will
have no significant interaction with the interconnected bulk transmission system. It will only interact
with the LN. And, with the advent of distributed generation, it is easy to foresee a situation in which a
large number of very small distributed generators are interconnected into a LDN, so that the
aggregate capacity of these generators exceeds 75 MVA. However, because the generators are small
and dispersed and, under the criterion in subparagraph (b), would be wholly absorbed within the LN
rather than transmitting power onto the interconnected grid, those generators would not have a
material impact on the grid. We also suggest that subparagraph (b) of Exclusion 3 could be more
clearly drafted. Subparagraph (b), as part of the requirement that power flow into a LN rather than
out of it, includes this description: “The LN does not transfer energy originating outside the LN for
delivery through the LN.” We understand this language is intended to distinguish a LN from a link in
the transmission system - power on a transmission link passes through the transmission link to a load
located elsewhere, while power in a LN enters the LN and is consumed by retail load within the LN.
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While we agree with the concept proposed by the SDT, we believe the language would be clearer if it
read: “The LN does not transfer energy originating outside the LN for delivery through the LN to loads
located outside the LN.” We believe the italicized language is necessary to distinguish between a
transmission system, where power that originates outside a system is delivered through the system
and passes through the system to a sink located somewhere outside the system, from a LN, in which
power originating outside the LN passes through the LN and is delivered to retail load within the LN.
To put it another way, the italicized language helps distinguish a transmission system from an LN, in
which the LN “transfers energy originating outside the LN for delivery through the LN to loads located
within the LN.”
We also believe the language of subparagraph (a) of Exclusion 3 could be improved. Subparagraph
(d) would make LNs part of the BES if they interconnect “non-retail generation greater than 75 MVA
(gross nameplate rating).” For the reasons stated in our responses to Questions 3, 5 and 7, we urge
the SDT to replace the reference to a hard 75 MVA threshold with the defined term “Qualifying
Aggregate Generation Resources” or some equivalent.
We are also uncertain what is meant by the use of the term “non-retail generation” in subparagraph
(a). From context, we believe the SDT considers “non-retail generation” to mean generation that is
used by retail customers located within a LN rather than being exported and sold on wholesale
markets outside the LN. We therefore suggest that the SDT replace the phrase “non-retail
generation” with the phrase “generation sold in wholesale markets and transmitted outside the LN.”
Similarly, we are unsure what is meant by the phrase “the LN and its underlying Elements.” We
believe the phrase “and its underlying Elements” could simply be deleted from the definition without
loss of meaning. In the alternative, the SDT might consider using the phrase “the LN, including all
Elements located on the distribution side of any Automatic Fault Interrupting Devices (or other points
of demarcation) separating the LN from the bulk interstate transmission system.” We believe this
phrase more accurately reflects the SDT’s intent, which appears to be that generation exceeding 75
MVA in aggregate capacity interconnected anywhere within the LN disqualifies that LN from being
excluded from the BES under Exclusion 3. Finally, MPPA believes that both subparagraphs (a) and (b)
of Exclusion 3 could be safely eliminated as long as subparagraph (c) is retained. Subparagraph (c)
makes a LN part of the BES if it is classified as a Flow Gate or Transfer Path. Flow Gates and Transfer
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Paths are, by definition, the key facilities that allow reliable transmission of bulk electric power on the
interconnected grid. If a LN has not been identified as either a Flow Gate or a Transfer Path, it is
unlikely the LN is necessary for the reliable transmission of electricity on the interconnected bulk
system.
Apart from these specific improvements that we believe could be achieved by modifying the language
of Exclusion 3, we believe the SDT may need to re-examine certain assumptions that appear to
underlie the current draft. Specifically, subparagraph (a) suggests that if BES generation is embedded
within a LN, the LN itself must also be BES. But two NERC bodies have already addressed similar
questions and concluded there is no technical basis for such concerns. NERC’s Standards Drafting
Team for Project 2010-07 and its predecessor, the “GO-TO Task Force” were formed to address how
the dedicated interconnection facilities linking a BES generator to high-voltage transmission facilities
should be treated under the NERC standards. The GO-TO Team concluded that by complying with a
handful of reliability standards, primarily related to vegetation management, reliable operation of the
bulk interconnected system could be protected without unduly burdening the owners of such
interconnection systems. Therefore, there is no reason, according to the GO-TO Team, that dedicated
high-voltage interconnection facilities must be treated as “Transmission” and classified as part of the
BES in order to make reliability standards effective. See Final Report from the NERC Ad Hoc Group for
Generator Requirements at the Transmission Interface (Nov. 16, 2009) (paper written by the GO-TO
Task Force). Similarly, the Project 2010-07 Team observed that interconnection facilities “are most
often not part of the integrated bulk power system, and as such should not be subject to the same
level of standards applicable to Transmission Owners and Transmission Operators who own and
operate transmission Facilities and Elements that are part of the integrated bulk power system.”
White Paper Proposal for Information Comment, NERC Project 2010-07: Generator Requirements at
the Transmission Interface, at 3 (March 2011). Requiring Generation Owners and Operators to
comply with the same standards as BES Transmission Owners and Operators “would do little, if
anything, to improve the reliability of the Bulk Electric System,” especially “when compared to the
operation of the equipment that actually produces electricity - the generation equipment itself.” Id.
We believe that interconnection of BES generators within a LN is analogous and that, based on the
findings of the Project 2010-07 and GO-TO Teams, automatically classifying a LN as “BES” simply
because a large generator is embedded in the LN will result in substantial overregulation and
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unnecessary expense with little gain for bulk system reliability. If anything, generation interconnected
through a LN is less likely to produce material impacts on the interconnected bulk transmission system
than the equivalent generator interconnected through a single dedicated line because an LN is
interconnected to the bulk system at several points, so that if one interconnection goes down, power
can still flow from the BES generator to the bulk system on other interconnection points. Where a
dedicated interconnection facility is involved, by contrast, if the interconnection line fails, the
generator is unavailable to the interconnected bulk system.
Similarly, we suggest that the SDT re-examine the assumptions underlying subparagraph (b), which
seems to suggest that a local distribution system cannot be classified as a Local Network if power
flows out of that system at any time, even if the amount is de minimis, the outward flow is only for a
few hours a year, or the outward flow occurs only in an extreme contingency. Accordingly, we suggest
that the initial clause of subparagraph (b) be revised to read: “Except in unusual circumstances, power
flows only into the LN.”

Response: The SDT considered the disposition of the word “transmission” in Exclusion E3, and determined that retention of this word
– in lower-case – is necessary to modify the word “Element”. This is meant to eliminate the generation that would otherwise be
included in the term “Element”.
The SDT continues to believe that it is necessary to establish a limit on the allowable quantity of generation that may be significant to
the reliable operation of the surrounding interconnected transmission system. Please note that the issues surrounding the
appropriate generation threshold, among other topics, will be taken up in Phase 2 of this BES definition effort. No change made.
The intent of the SDT in structuring the language of Exclusion E3.b was to ensure two things: first that power flow is always in the
direction from the BES toward the LN, and second that the LN is not used for “wheel-through” transactions. The suggestion in your
comment places an unnecessary qualifier on the “wheel-through” whereby it would only apply if the transaction were serving “loads”.
The SDT believes this qualifier would inadvertently allow a wholesale transaction to be scheduled through the subject facilities, and
this is contrary to the intent of Exclusion E3.b. Given the high degree of certainty and assurances regarding the high priority of the
Phase 2 efforts on Project 2010-17, for the purpose of completing the posting of the definition in the first phase of the Project, the
SDT believes that it is preferable to continue to use the specific value of 75 MVA within ExclusionE3.a. No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT believes that the existing phrase in ExclusionE3.a “and its underlying Elements” has sufficient clarity and meets the intent of
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the exclusion with brevity. No change made.
The SDT acknowledges the work of the Project 2010-07 “GO-TO” task force in identification of various NERC Reliability Standard
requirements that would promote reliability of the generator-to-transmission interface. The Project 2010-17 SDT believes that the
body of work in Project 2010-07 is most pertinent to generator lead-line facilities, rather than the looped and parallel-operated
facilities contemplated in the Exclusion E3, and therefore, the SDT finds it necessary to continue to require all of the characteristics of
Exclusion E3 to be met in order to qualify for exclusion from the BES. No change made.
The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and determined
that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition. For those
circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power to flow out
of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No change made.
NESCOE

Yes

NESCOE generally supports this exclusion but believes it is too narrow. As noted in the response to
question 7, Exclusion E3 should allow a higher level of aggregate generation MVA on a Local Network
(at least 300 MVA). In addition, NESCOE believes that local networks should not necessarily be
ineligible for Exclusion E3 simply because an amount of power may transfer out of the network at
times. NERC’s draft technical network exclusions document should be amended such that local
networks would be permitted to qualify for network exclusions under E3 if power flowing out of the
network is minimal and would not likely adversely impact the BES. For example, transfers of less than
or equal to 100 MVA should not have any adverse impact on the BES. The draft technical network
exclusions document should be amended to state that transfers of 100 MVA MVA into the BES from
the local distribution network are acceptable. The 100 MVA limit suggested here represents 25% of
the rated value of a typical 345/115 substation (typically on the order of 400 MVA). Rarely does more
than a fraction of the rated MVA flow from the low voltage side to the high voltage side. An allowance
of 100 MVA represents a flow level will have no significant impact to the interconnected bulk power
network.

Response: The SDT feels strongly that in order for a network to qualify for exclusion under the Exclusion E3 section of the definition,
there must be strict bounds and limits placed on the characteristics of the candidate facilities. Allowances for minor “out-flow” from
the local network, or “minimal” flow, as suggested in this comment, will lead to an inconsistent application of the definition and
therefore, a lack of bright-line quality in the definition. Situations such as what is proposed in this comment can be referred to the
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Exception Process for possible exclusion from the BES. No change made.
AECI and
member
GandTs,
Central
Electric Power
Cooperative,
KAMO Power,
MandA
Electric Power
Cooperative,
Northeast
Missouri
Electric Power
Cooperative,
NW Electric
Power
Cooperative
Sho-Me Power
Electric Power
Cooperative

Yes

We would agree in principle with the LN exclusion if the wording of the exclusion includes the
following phrase (in italics) added at the end of E3 b): Power flows only into the LN: The LN does not
transfer energy originating outside the LN for delivery through the LN “under normal operating
conditions”.
Also, the correct BES threshold level should be 200 kV rather than 100 kV.
Finally, the nomenclature of Flowgate (FG) components appears to be confused. AECI believes E3 c)
should be changed to read “contingent Facility” rather than “monitored Facility”. Although
unspecified within the NERC Glossary, we believe FG monitored Facilities are typically the impacted
facilities in danger of overload, while the contingent facilities are those which, if lost, would cause the
monitored Facility to become overloaded. As currently written, a formerly qualified LN could later
become disqualified due to an external entity’s ill-designing a parallel EHV line, thereby causing one or
more potential (N-1) overloaded Facility within that LN. Further, operational FG loading conditions
are often relieved by opening-up LN elements near the monitored Facility, with little impact upon BES
reliability, yet with lesser reliability to the underlying LN loads. This implies that the monitored
elements of Flowgates are typically non-essential to the BES reliability. AECI can support “contingent”
FG Facilities disqualifying a LN claim, but it cannot support “monitored” Facilities as disqualifying
factors for rejecting a LN claim.

Response: The SDT considered the addition of the phrase “under normal operating conditions”, as a qualifier to Exclusion E3.b, and
determined that such a qualifier is not consistent with the intent to develop a set of bright line characteristics in the BES definition.
For those circumstances where a network is unable to utilize the LN exclusion solely due to an abnormal situation that causes power
to flow out of the network, that network would be a suitable candidate to apply for exclusion under the Exception Process. No
change made.
The SDT appreciates the suggestion of an alternate BES threshold level of 200 kV rather than 100 kV; however, in the absence of a
strong technical justification, the SDT must retain the 100 kV threshold in the core definition. No change is being made at this time
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but all threshold values will be examined in Phase 2.
The SDT continues to believe that “monitored” is the most appropriate modifier of “Flowgate” in the text of Exclusion E3.c. Exclusion
E3.c is intended to identify the elements that are part of these Flowgates, not necessarily those whose contingency can affect the
Flowgate. The elements comprising Flowgates (and major transfer paths in the West) must continue to be prohibited from exclusion
via Exclusion E3.c, since these facilities are more likely to be used in the transfer of bulk power than not; therefore, they are more
characteristic of serving an interconnected transmission function than distribution. No change made.
Southern
Company
Generation

Yes

What does the term "non-retail generation" mean?
Can the term "non-retail generation" in E3a be changed to simply "generation."

Response: Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
The SDT has intentionally utilized the term “non-retail generation” in Exclusion E3.a in order to specifically isolate that generation
which is not situated behind the retail meter. It is important to retain this concept, since removal of the clarifier “non-retail” would
cause candidate local networks with retail generation to be unfairly biased against obtaining this exclusion. No change made.
Electricity
Consumers
Resource
Council
(ELCON)

Yes

This Exclusion and Exclusion E1 aid in the delineation of local distribution versus transmission. We
suggest three clarifying revisions. First, the phase “but less than 300 kV” should be deleted. Many
large industrial facilities have on-site distribution systems that operate above 300 kV due solely to the
capacity of the lines to supply power over the distance required at the manufacturing sites.
Second, for the same reasons discussed above (in response to question #7), the phrase “do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating)” in “a)”
should be changed to “the net capacity provided to the transmission grid does not exceed 75 MVA.”
Third, the introductory phrase in “b)” -- “Power flows only into the LN” -- is inconsistent with the
recognition in “a)” that power may flow out of an LN and into the transmission grid if there is
generation connected to the LN and the 75 MVA limit is observed. We recommend either deleting the
introductory clause or correcting it to read “Power is not transferred through the LN.”

Response: The SDT does not agree with the removal of the 300 kV cap that limits the qualification of a group of facilities for local
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network exclusion. The SDT feels that an upper bound is essential to prevent inappropriate exclusions of facilities that may be
important to the reliable operation of the interconnected transmission system. The Exception Process is available for specific
circumstances where a 300 kV cap is problematic. No change made.
The SDT evaluated your comment in regard to Question 7 as well as to the local network exclusion, and has concluded that both
exclusions must necessarily be based on the gross aggregate nameplate of the generation connected within the candidate systems.
The approach that is suggested in your comment could result in significant amounts of generation existing within the excluded area.
No change made.
It remains the intent of the SDT to uphold a 75 MVA limit on the connected (non-retail) generation within a qualifying LN and, at the
same time, reinforcing that power flow is always from the BES toward the LN at all points of connection. The SDT believes these
characteristics are essential in order to ensure that qualifying LN facilities are not being relied upon for reliable operation of the
interconnected transmission system. However, the SDT has clarified Exclusion E3.b in response to industry comments:
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
Transmission
Access Policy
Study Group

Yes

TAPS supports the exclusion of Local Networks from the BES. Such systems are generally not
“necessary for operating an interconnected electric transmission network,” the standard in Orders
743 and 743-A. We have several suggestions to clarify the proposed language for this Exclusion. TAPS’
comments in response to Question 7 above regarding “points of connection at 100kV or higher” and
“non-retail generation” are applicable to Exclusion E3 as well.
The term “bulk power,” which occurs twice in Exclusion E3, is vague and could be read incorrectly as a
reference to the statutorily-defined “bulk-power system,” which is not, we think, the SDT’s intent.
The word “bulk” should be deleted, so that the Exclusion simply refers to transferring “power” across
the interconnected system. TAPS raised this concern in response to the last posting of the BES
Definition. In response, the SDT removed some instances of “bulk power” but left the remaining two,
stating that “the SDT believes it provides conceptual value to the exclusion principle.” The SDT does
not state what conceptual value the term is intended to provide; on the assumption that it relates to a
distinction between transferring power from local generation to serve local load, and transferring
power over longer distances, TAPS suggests, as an alternative to simply deleting the word “bulk,” that
the Exclusion be revised to refer to “transfers of power from non-LN generation to non-LN
load.”Exclusion E3(c) states: “Power flows only into the LN: The LN does not transfer energy
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Question 9 Comment
originating outside the LN for delivery through the LN.” This statement is unclear because the two
parts mean different things. TAPS proposes rewriting this sentence to state: “Power flows only into
the LN, that is, at each individual connection at 100 kV or higher, the pre-contingency flow of power is
from outside the LN into the LN for all hours of the previous 2 years” to help clarify the intent. Two
years is suggested because it is the time period set out in the draft exception application form for
which an applicant should state whether power flows through an Element to the BES.

Response: See response to Q7.
The SDT prefers to continue the use of the word “bulk” in the core paragraph of Exclusion E3. The SDT believes this clarifies an
important conceptual idea to the industry, and the term “bulk” is not intended to be definitional in this context. This paragraph
merely provides an introduction to the concept of the local network, and retaining the term “bulk” conveys the concept effectively.
The lettered sub-items under the core paragraph are the prescriptive and precise characteristics that the industry will use to
determine qualification for exclusion under Exclusion E3. No change made.
The SDT prefers not to add demonstration criteria, such as the suggestion to provide a minimum of 2 years worth of data, within the
text of the BES definition. The SDT believes the language, particularly the word “always” adds sufficient clarity. No change made.
Florida
Municipal
Power Agency

Yes

: FMPA supports the exclusion of Local Networks from the BES. Such systems are generally not
“necessary for operating an interconnected electric transmission network,” the standard in Orders
743 and 743-A. However, we have several suggestions to clarify the proposed language for this
Exclusion. Exclusion E3(c) states: “Power flows only into the LN: The LN does not transfer energy
originating outside the LN for delivery through the LN.” This statement is unclear because the two
parts mean different things. FMPA proposes rewriting this sentence to state: “Power flows only into
the LN, that is, at each individual connection at 100 kV or higher, the pre-contingency flow of power is
from outside the LN into the LN for all hours of the previous 2 years” to help clarify the intent. Two
years is suggested because it is the time period set out in the draft exception application form for
which an applicant should state whether power flows through an Element to the BES.
FMPA’ comments in response to Question 7 above regarding “points of connection at 100kV or
higher” and “non-retail generation” are applicable to Exclusion E3 as well.
The term “bulk power,” which occurs twice in Exclusion E3, is vague and could be read incorrectly as a
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Question 9 Comment
reference to the statutorily-defined “bulk-power system,” which is not, we think, the SDT’s intent.
The word “bulk” should be deleted, so that the Exclusion simply refers to transferring “power” across
the interconnected system. FMPA raised this concern in response to the last posting of the BES
Definition. In response, the SDT removed some instances of “bulk power” but left the remaining two,
stating that “the SDT believes it provides conceptual value to the exclusion principle.” The SDT does
not state what conceptual value the term is intended to provide; on the assumption that it relates to a
distinction between transferring power from local generation to serve local load, and transferring
power over longer distances, FMPA suggests, as an alternative to simply deleting the word “bulk,” that
the Exclusion be revised to refer to “transfers of power from non-LN generation to non-LN load.”

Response: Exclusion E3.b was intended to be a combination of two similar properties when it was drafted for the second posting of the
BES definition. The SDT has received a number of comments indicating that these are two separate and distinct concepts, and has
revised Exclusion E3.b to provide more clarity.
E3.b: Power flows only into the LN: and Tthe LN does not transfer energy originating outside the LN for delivery through the LN;
The SDT prefers not to add demonstration criteria, such as the suggestion to provide a minimum of 2 years worth of data, within the
text of the BES definition. The SDT believes the language, particularly the word “always” adds sufficient clarity. No change made.
See response to Q7.
The SDT prefers to continue the use of the word “bulk” in the core paragraph of Exclusion E3. The SDT believes this clarifies an
important conceptual idea to the industry, and the term “bulk” is not intended to be definitional in this context. This paragraph
merely provides an introduction to the concept of the local network, and retaining the term “bulk” conveys the concept effectively.
The lettered sub-items under the core paragraph are the prescriptive and precise characteristics that the industry will use to
determine qualification for exclusion under Exclusion E3. No change made.
SERC Planning
Standards
Subcommittee

Yes

The term "non-retail generation" in E3a should be changed to simply "generation."

Response: The SDT has intentionally utilized the term “non-retail generation” in Exclusion E3.a in order to specifically isolate that
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Question 9 Comment

generation which is not situated behind the retail meter. It is important to retain this concept, since removal of the clarifier “nonretail” would cause candidate local networks with retail generation from obtaining this exclusion. No change made.
Balancing
Authority
Northern
California

Yes

It is preferred to hold reference to gross nameplate rating/threshold values until generation technical
justification is completed as part of Phase 2; these studies should apply to any real or reactive power
threshold reference.
For Exclusion E3-b using the phrase “[p]ower flows only into the LN” is too restrictive. An allowable
MW threshold of LN power producing resources should be deferred to the Phase 2 BES technical
analysis. Where no generation is present in the LN, it is recommended that an allowance for residual
flow through the LN.

Response: The SDT agrees that the threshold(s) for generation throughout the BES definition should be addressed in Phase 2 of this
effort; however, to satisfy the Commission’s directives in Order 743 and 743-A in a timely fashion, it is necessary to use a generation
threshold that is consistent with the in-force Statement of Compliance Registry Criteria. No change made.
The SDT feels strongly that in order for a local network to qualify for exclusion under the Exclusion E3 section of the definition, there
must be strict bounds and limits placed on the characteristics of the candidate facilities. Allowances for minor “out-flow” from the
local network, or “minimal” flow, as suggested in this comment, will lead to an inconsistent application of the definition and
therefore, a lack of bright-line quality in the definition. Situations such as what is proposed in this comment can be referred to the
Exception Process for possible exclusion from the BES. No change made.
Westar Energy

Yes

Redding
Electric Utility

Yes

City of
Redding

Yes

Farmington
Electric Utility

Yes

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Question 9 Comment

System
Oncor Electric
Delivery
Company LLC

Yes

Utility
Services, Inc.

Yes

LCRA
Transmission
Services
Corporation

Yes

Memphis
Light, Gas and
Water Division

Yes

Harney
Electric
Cooperative,
Inc.

Yes

PSEG Services
Corp

Yes

Puget Sound
Energy

Yes

American
Electric Power

Yes

HEC believes that local networks should be excluded from the BES and agrees with exclusions to the
definition.

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Organization

Yes or No

NV Energy

Yes

Oregon Public
Utility
Commission
Staff

Yes

Z Global
Engineering
and Energy
Solutions

Yes

Chevron
U.S.A. Inc.

Yes

Metropolitan
Water District
of Southern
California

Yes

Duke Energy

Yes

Idaho Falls
Power

Yes

FirstEnergy
Corp.

Yes

Exelon

Yes

Western Area

Yes

Question 9 Comment

This provision complements E1 in defining the difference between distribution and transmission

We support the exclusion as drafted.

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Question 9 Comment

Power
Administration
IRC Standards
Review
Committee

Yes

Texas RE NERC
Standards
Subcommittee

Yes

WECC Staff

Yes

Southwest
Power Pool
Standards
Review Team

Yes

BGE

Yes

This Exclusion and Exclusion E1 aid in the delineation of distribution versus transmission.

No comment.

Response: Thank you for your support.

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10.

The SDT has added specific exclusions to the core definition in response to industry comments. Do you agree with Exclusion E4
(reactive resources)? If you do not support this change or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments.

Summary Consideration: Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices. The
comments received identified overwhelming support of Exclusion E4 as written.
Some commenters questioned the use of the word ‘retail’ in Exclusion E4. The SDT determined that retention of this word is important
and correct. This is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the Load side of a
customer meter) and would otherwise be included via the core definition and/or Inclusion I5.
Other commenters proposed adding the same threshold qualification language contained in other exclusions. Using a threshold for
inclusion of non-generator Reactive Power resource devices in the BES will be considered in Phase 2 of this effort. The SDT
acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects (i.e., the
bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being responsive to
the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not
afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a change from the
current values that exist through the application of the definition today. These and similar issues have prompted the SDT to separate the
project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities. Therefore,
the SDT will consider all recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2 of Project
2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for modifications to the existing
values.
No changes were made to the definition as a result of these comments.
Organization
Westar Energy

Yes or No

Question 10 Comment

No

This particular Exclusion doesn’t address the qualifier as to the impact to the BES. We
believe the qualification language in E2, in regards to behind the meter generation,
should also be included in Exclusion E4 for clarification purposes.

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Organization
Southwest Power Pool
Standards Review Team

Yes or No

Question 10 Comment

No

This particular Exclusion doesn’t address the qualifier as to the impact to the BES. We
request that it emulate the language provided for E2 (behind the meter gen) and
classified for this specific exclusion.

Response: Using a threshold for inclusion of non-generator Reactive Power resource devices in the BES will be considered in Phase 2
of this effort. The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
ISO New England Inc

No

The term “retail customer” is unclear and will lead to confusion.
This exclusion should be removed as there are many instances where a generator may
be using the reactive power device to meet other interconnection requirements and
the reactive device should be held to the same BES requirements as the generator.

Response: The SDT team considered the disposition of the word “retail” in the context of E4, and determined that retention of this
word is important and correct. This is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the
load side of a customer meter). No change made.
Exclusion E4 is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the load side of a
customer meter) and would otherwise be included via the core definition and/or Inclusion I5. No change made.
Central Maine Power
Company

No

Consider using other wording to replace “retail”

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Organization

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Question 10 Comment

Response: The SDT team considered the disposition of the word “retail” in the context of E4, and determined that retention of this
word is important and correct. This is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the
load side of a customer meter). No change made.
Metropolitan Water District of
Southern California

No

Exclusion 4 appears to limit the devices just to retail customers. However, any enduser load, including wholesale or retail, should be included. NERC's Glossary of Terms
uses the phrase "end-use customer", not retail customers to describe loads. MWDSC
recommends that Exclusion 4 be changed as follows: E4 - Reactive Power devices
owned and operated by an end-use customer solely for its own use.

Response: The SDT team considered the disposition of the word “retail” in the context of E4, and determined that retention of this
word is important and correct. This is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the
load side of a customer meter). No change made.
The Dow Chemical Company

No

The term “solely” should be replaced by the term “primarily”. All devices to control
Reactive power behind-the-meter arguably provide some benefit to the transmission
grid.

Response: The SDT does not believe these changes provide additional clarity. No change made.
LCRA Transmission Services
Corporation

No

This exclusion conflicts with inclusion item I5. Which one takes priority?

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
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Yes or No

Question 10 Comment

breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
Ameren

No

a)Reactive Power devices connected 100 kV and above applied for the purpose of
voltage support to local load and/or local area network should also be excluded.

Response: Reactive Power devices connected at 100kV and above are included in the core definition. Exclusion E1 provides for the
exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the exclusion language. This does
not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The exclusion (E1) only speaks to
the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied in the same manner.

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Yes or No

Question 10 Comment

The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element as defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind-the-retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
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Yes or No

Question 10 Comment

An entity can always request an exception through the Exception Process. No change made.
Tillamook PUD

No

Any device that might be excluded under E4 has already been included per I5. Unless
I5 is removed, or rewritten as suggested above; this exclusion will exclude nothing.

Central Lincoln

No

Please see Central Lincoln’s answers to Q1 and Q6. Any device that might be excluded
under E4 has already been included per I5. Unless I5 is removed, or rewritten as
suggested above; this exclusion will exclude nothing.

Northern Wasco County PUD

No

Please see Northern Wasco County PUD’s answers to Q1 and Q6. Any device that
might be excluded under E4 has already been included per I5. Unless I5 is removed, or
rewritten as suggested above; this exclusion will exclude nothing.

Response: Please see responses to Q1 and Q6.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element as defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
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Yes or No

Question 10 Comment

language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind-the-retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices. No change made.
Northeast Power Coordinating
Council

No

Consider using other wording to replace “retail”. The statement “owned or operated
by the retail customer” is confusing and arguably inaccurate and should be revised.
Refer to comments related to reactive resources for Question 6 regarding Inclusion I5.
Retail and non-retail generation should be defined.

Response: The SDT team considered the disposition of the word “retail” in the context of E4, and determined that retention of this
word is important and correct. This is meant to eliminate non-generator Reactive Power devices that (are owned and operated on the
load side of a customer meter). No change made.
Non-retail generation is meant to be the generation on the system (supply) side of the retail meter.
American Electric Power

No

Does this refer to distribution level or reactive power resources? If so, it would appear
these are not included as part of I5. Or instead, does this refer to customer equipment
at BES voltages? If it is the latter, we recommend E4 be reworded to state “Reactive
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Question 10 Comment
Power devices that meet the Inclusion criteria of I5 that are owned and operated by
the retail customer solely for its own use...”

Response: Distribution devices are not included.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
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Yes or No

Question 10 Comment

interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power
Cooperative

Yes

Ownership is irrelevant, so “owned and operated by the retail customer solely for its
own use”, should be replaced by “owned and operated solely in conjunction with
specific industrial customer loads.”

Response: The SDT does not believe this change provides additional clarity. No change made.
NESCOE

Yes

While we are generally supportive of this exclusion, the term “retail” needs to be
clarified (i.e., are retail customers of all sizes intended to be excluded?).

Massachusetts Department of
Public Utilities

Yes

While we are generally supportive of this exclusion, the term “retail” needs to be
clarified (i.e., are retail customers of all sizes intended to be excluded?).

Response: The SDT reviewed your comment and believes that ‘retail’ is the correct terminology. This is meant to eliminate nongenerator Reactive Power devices that (are owned and operated on the load side of a customer meter. No change made.
Using a threshold for non-generator Reactive Power resource devices in the BES will be considered in Phase 2 of this effort.
Long Island Power Authority

Yes

Exclusion should identify a maximum value.

Response: Using a threshold for non-generator Reactive Power resource devices in the BES will be considered in Phase 2 of this
effort. No change made.
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ExxonMobil Research and
Engineering

Yes or No

Question 10 Comment

Yes

The BES SDT should work on clarifying the differences between Inclusion I5 and
Exclusion E4. The phrase “solely for its own use” in Exclusion E4 is vague and open to
interpretation. It is unclear whether equipment, such as power factor correction
facilities, surge capacitors located in motor terminal boxes and excitation capacitors
installed for use by a motor located on the low side of a 138 kV primary transformer
would be excluded from the BES.

Response: It is the intent of the SDT that distribution devises are not included in the BES.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify
the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between
BES and non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected
at 100 kV or higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term
Element is needed. Element as defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of
electric energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources
with specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The
exclusion language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in
the exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions
I2 – I5. The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local
networks) should be applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion
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Question 10 Comment

I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind-the-retail meter (on the customer’s side)
and supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion
I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of
the interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the
interconnected transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either
include or exclude an Element.
No change made.
Springfield Utility Board

Yes

Reactive power devices used to serve radial networks or Local Networks are often
owned and operated by the registered entity (not the “retail customer”) to address
Area Network - wide reactive power issues. This language should read:”E4. Reactive
power devices that are within a radial system excluded under E1 or within a local
network excluded under E3” If the current draft language is left as it is, there will likely
be a lot of unnecessary paperwork to exclude reactive power devices within radial
system or local networks from the BES through the exclusion process. SUB suggests
that the language in the E4 Exclusion be consistent with that in the I5 Inclusion.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
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Yes or No

Question 10 Comment

Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
SERC OC Standards Review
Group

Yes

NERC Staff Technical Review

Yes

SERC Planning Standards
Subcommittee

Yes

Florida Municipal Power

Yes
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Yes or No

Question 10 Comment

Agency
WECC Staff

Yes

Bonneville Power
Administration

Yes

Texas RE NERC Standards
Subcommittee

Yes

Balancing Authority Northern
California

Yes

ACES Power Marketing
Standards Collaborators

Yes

Dominion

Yes

Pepco Holdings Inc and
Affiliates

Yes

Transmission Access Policy
Study Group

Yes

Electricity Consumers
Resource Council (ELCON)

Yes

Southern Company
Generation

Yes

This is a needed exception to Inclusion I5 as these reactive power resources are used
by retail customers for power factor correction at their own facilities in order avoid
imposed power factor penalties.

This is a needed exception to Inclusion I5 as these reactive power resources are used
by retail customers for power factor correction at their own facilities in order avoid
imposed power factor penalties.

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Organization

Yes or No

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

Yes

MRO NERC Standards Review
Forum (NSRF)

Yes

IRC Standards Review
Committee

Yes

Tennessee Valley Authority

Yes

Hydro One Networks Inc.

Yes

Tri-State GandT

Yes

Western Area Power
Administration

Yes

Texas Industrial Energy
Consumers

Yes

PacifiCorp

Yes

Southern Company

Yes

FirstEnergy Corp.

Yes

Exelon

Yes

Michigan Public Power Agency

Yes

Question 10 Comment

Yes, MPPA and its members support the revised language because retail reactive
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Yes or No

Question 10 Comment
devices are used to address local customer or retail voltage issues, rather than voltage
issues on the interconnected bulk grid, and such local devices should therefore be
excluded from the BES definition.

Idaho Falls Power

Yes

ReliabilityFirst

Yes

Ontario Power Generation Inc.

Yes

Central Hudson Gas and
Electric Corporation

Yes

City of Anaheim

Yes

Chevron U.S.A. Inc.

Yes

Duke Energy

Yes

Clallam County PUD No.1

Yes

NV Energy

Yes

Z Global Engineering and
Energy Solutions

Yes

Consumers Energy

Yes

We have no comments.

Yes, CLPD supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

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Yes or No

Question 10 Comment

Puget Sound Energy

Yes

Manitoba Hydro

Yes

City of St. George

Yes

Orange and Rockland Utilities,
Inc.

Yes

Blachly-Lane Electric
Cooperative (BLEC)

Yes

BLEC supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Coos-Curry Electric
Cooperative (CCEC)

Yes

CCEC supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Central Electric Cooperatve
(CEC)

Yes

CEC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Clearwater Power Company
(CPC)

Yes

CPC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Snohomish County PUD

Yes

Yes, SNPD supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
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Yes or No

Question 10 Comment
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Consumer's Power Inc.

Yes

CPI supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Douglas Electric Cooperative
(DEC)

Yes

DEC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Fall River Rural Electric
Cooperative (FALL)

Yes

FALL supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Lane Electric Cooperative
(LEC)

Yes

LEC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Lincoln Electric Cooperative
(LEC)

Yes

LEC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Northern Lights Inc. (NLI)

Yes

NLI supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
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Yes or No

Question 10 Comment
the BES definition.

Okanogan County Electric
Cooperative (OCEC)

Yes

OCEC supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Pacific Northwest Generating
Cooperative (PNGC)

Yes

PNGC supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Raft River Rural Electric
Cooperative (RAFT)

Yes

RAFT supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

West Oregon Electric
Cooperative

Yes

WOEC supports the revised language because retail reactive devices are used to
address local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

PSEG Services Corp

Yes

Hydro-Quebec TransEnergie

Yes

Independent Electricity
System Operator

Yes

Umatilla Electric Cooperative
(UEC)

Yes

UEC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
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Yes or No

Question 10 Comment
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Memphis Light, Gas and
Water Division

Yes

Harney Electric Cooperative,
Inc.

Yes

Cowlitz County PUD

Yes

Utility Services, Inc.

Yes

National Grid

Yes

Kansas City Power and Light
Company

Yes

Oncor Electric Delivery
Company LLC

Yes

Sacramento Municipal Utility
District

Yes

Georgia System Operations
Corporation

Yes

MEAG Power

Yes

Farmington Electric Utility
System

Yes

HEC agrees with E4.

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Yes or No

Question 10 Comment

South Houston Green Power,
LLC

Yes

Portland General Electric
Company

Yes

City of Austin dba Austin
Energy

Yes

Kootenai Electric Cooperative

Yes

ATC LLC

Yes

Redding Electric Utility

Yes

City of Redding

Yes

Tacoma Power

Yes

Tacoma Power supports the Exclusion E4 as currently written.

BGE

Yes

No comment.

KEC supports the revised language because retail reactive devices are used to address
local customer or retail voltage issues, rather than voltage issues on the
interconnected bulk grid, and such local devices should therefore be excluded from
the BES definition.

Response: Thank you for your support.

357

11.

Are there any other concerns with this definition that haven’t been covered in previous questions and comments remembering
that the exception criteria are posted separately for comment?

Summary Consideration: Comments received for Question 11 were mostly re-statements of comments expressed in the previous
questions. No changes were made to the core definition or Inclusions or Exclusions based solely on question 11 comments. However,
changes were made to the Implementation Plan to clarify the compliance obligation date of the revised definition as shown below.
Some commenters have expressed frustration over the lack of high level guidance for the exception process. The SDT understands the
concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like nothing better than to be
able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion and an initial attempt at
doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If the SDT could have come up
with the simple answer, it would have been supplied within the bright-line. The SDT would also like to point out to the commenters that
it directly solicited assistance in this matter in the first posting of the criteria and received very little in the form of substantive
comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say that
the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this position.
The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a single
package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the Regional Entity
has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the submittal for
completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity plays no role in
actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the Regional Entity in a
position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In addition, the SDT believes
that the visibility of the process would belie such an action by the Regional Entity and also believes that one has to have faith in the
integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of Procedure, Sections 5.1.5, 5.3,
and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel assessment where a Regional Entity
decides to reject or disapprove an exception request. This panel’s findings become part of the exception request record submitted to
NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the option to remand the request to the
Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in rejecting or disapproving the exception
request. On the other side of this equation, one could make an argument that the Regional Entity has no basis for what constitutes an
acceptable submittal. Commenters point out that the explicit types of studies to be provided and how to interpret the information
aren’t shown in the request process. The SDT again points to the variations that will abound in the requests as negating any hard and
fast rules in this regard. However, one is not dealing with amateurs here. This is not something that hasn’t been handled before by
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either party and there is a great deal of professional experience involved on both the submitter’s and the Regional Entity’s side of this
equation. Having viewed the request details, the SDT believes that both sides can quickly arrive at a resolution as to what information
needs to be supplied for the submittal to travel upward to the ERO Panel for adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result ofa sudden disturbance, including a cyber security incident, or
unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a negative
response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section
3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or response to
a question will be solely dispositive in the determination of whether an Exception Request shall be approved or disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase 2 of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase 1 of this project, the
SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter to
consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.

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Some comments were received about the lack of a cost benefit analysis with regard to revision to the definition. The responsibilities
assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to improve clarity, to reduce
ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES Elements. The SDT’s efforts are
directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s concerns as expressed in the
directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has pursued a definition that remains as
consistent as possible with the existing definition, while not significantly expanding or contracting the current scope of the BES or
driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES definition has varying degrees of
Regional application and has resulted in different conclusions on what is currently considered to be part of the BES. This inconsistency in
the application and subsequent results were also identified by the Commission in Orders No. 743 and 743-A as a significant concern. The
SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in application of the current definition
there is a potential for varying degrees of impact on Regions. Without an approved BES definition any assumptions utilized in a cost
benefit analysis would be purely speculative and the results would have little meaning in regards to potential improvements in the
reliable operation of the interconnected transmission grid on a continent-wide basis. Therefore, the SDT believes that best opportunity
to address cost concerns will be through the development of Regional transition plans once the definition has been approved by the
Commission.
Several comments were received questioning how to apply the definition with the inclusions and exclusions. The application of the
draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast majority of BES
Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit breaker,
bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the application
of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with specific
criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.

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Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5. The
exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be applied
in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude an
Element.
Finally, there were comments on the lack of a technical basis for the threshold values employed in the definition. The SDT
acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects (i.e., the
bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being responsive to
the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012, and this has not
afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a change from the
current values that exist through the application of the definition today. These and similar issues have prompted the SDT to separate the
project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory authorities. Therefore,
the SDT will consider all recommendations for modifications to the technical aspects of the definition for inclusion in Phase 2 of Project
2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for modifications to the existing
values.
Implementation Plan - Compliance obligations for all newly identified Elements included by the definition shall begin 24 months after
the applicable effective date of the definition.

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SERC OC Standards Review
Group

Yes or No

Question 11 Comment

Yes

The definition of the BES is referenced in several existing standards and the Statement
of Compliance Registry Criteria. The SERC OC standards Review Group is concerned
how this revised definition will impact entity registration, i.e., how will the revised
definition be integrated into the Compliance Registry Criteria. The implementation
plan should include how the integration is going to occur.
The Rules of Procedure exception process should be further defined or referenced in
this definition.”The comments expressed herein represent a consensus of the views of
the above named members of the SERC OC Standards Review Group only and should
not be construed as the position of SERC Reliability Corporation, its board or its
officers.”

Southern Company

Yes

The definition of the BES is referenced in several existing standards and the Statement
of Compliance Registry Criteria. Southern Companies are concerned how this revised
definition will impact entity registration, i.e., how will the revised definition be
integrated into the Compliance Registry Criteria. The implementation plan should
include how the integration is going to occur.
The Rules of Procedure exception process should be further defined or referenced in
this definition.

Response: The revised definition of Bulk Electric System will be applied in the same manner as it is today. This is based on language
contained in FERC Order No. 693, which states: “…the Commission will rely on the NERC definition of bulk electric system and NERC’s
registration process to provide as much certainty as possible regarding the applicability to and the responsibility of specific entities to
comply with the Reliability Standards in the start-up phase of a mandatory Reliability Standard regime”. As the SDT progresses
through Phase 2 of the project, it is envisioned that the technical aspects contained in the definition and in the ERO Statement of
Compliance Registry will be merged and ultimately incorporated into the definition of the Bulk Electric System. At that time the ERO
Statement of Compliance Registry Criteria will be revised to point to the BES definition for the technical aspects in regards to BES
Elements. No change made.
The Rules of Procedure exception process is referenced in the current draft version of the BES definition in a note which states: “Note
- Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process”. No change made.
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Organization
Northeast Power Coordinating
Council

Yes or No
Yes

Question 11 Comment
Technical bases have not been provided for the proposed definition of the BES.
Additionally, the cost impacts have not been assessed and weighed against
thepotential benefits of this proposal.
There is confusion arising from the construction and interactions of the Inclusion, and
Exclusion sections.
System diagrams, put in a separate guidance document, would help in understanding.
The situation of using Exceptions to understand Exclusions must be avoided. Suggest
consider incorporating Inclusions directly, and leave the Exclusions as is format wise.
The Implementation period discusses a 24 month timeframe ( the Order suggests 18)
from when the standard becomes effective to begin Compliance obligations. If
construction is required to become compliant or meet performance requirements
with standards, or CIP Version 5 standards increase the amount of BES assets this will
be insufficient when considering budgeting, designing, siting requirements, and
permitting.
Concern exists over the paradigm that the definition should “mirror” the NERC
Compliance Registry Criteria regarding who is registered. Some RSC members believe
the definition should drive any changes to the registry criteria and not the criteria
perpetuating the thresholds in the definition. However, there is a need to confirm
that Phase 2 of this project will address this.
The Inclusions and Exclusions listed need clarifications and perhaps diagrams and
accompanying guidelines to clarify and explain the intent.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
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Question 11 Comment

and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s
concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has pursued a
definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting the
current scope of the BES or driving registration or de-registration. The technical aspects of the definition have remained identical to
the current definition and identical to the application of the ERO Statement of Compliance Registry Criteria and therefore do not
require a technical justification to support maintaining the status-quo.
The SDT acknowledges that the current BES definition has varying degrees of Regional application and has resulted in different
conclusions on what is currently considered to be part of the BES. This inconsistency in the application and subsequent results were
also identified by the Commission in Orders No. 743 and 743-A as a significant concern. The SDT acknowledges that by developing a
bright-line definition coupled with the inconsistency in application of the current definition there is a potential for varying degrees of
impact on Regions. Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative
and the results would have little meaning in regards to potential improvements in the reliable operation of the interconnected
transmission grid on a continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be
through the development of Regional transition plans once the definition has been approved by the Commission.
The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will identify the vast
majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
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Yes or No

Question 11 Comment

breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
The development of a guidance document which contains generic diagrams is a portion of the overall project that the SDT feels is
necessary to ensure the consistent application of the BES definition going forward. Therefore the SDT has determined that such a
document will be developed during Phase 2 of the project.
The SDT agrees that a potential reformatting of the definition (core, Inclusions and Exclusions) would improve the understanding of
the application of the definition. However, these types of changes would require a significant amount of revisions to the current draft
and could be seen as substantive in nature and prevent the SDT from moving forward with a recirculation ballot. This scenario would
require a successive ballot which would place the project schedule in jeopardy of achieving a successful filing by January 25, 2012. The
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Question 11 Comment

SDT will be exploring the reformatting of the definition (core, Inclusions and Exclusions) during Phase 2 of the project.
In proposing a 24 month period in the Implementation Plan before the definition is applied in assessing compliance obligations, the
SDT considered several activities that may require additional time to complete for an entity to become fully compliant. One of these
activities is the development of transition plans in cases where significant issues may have been identified as potentially preventing an
entity from meeting the compliance obligations within the 24 month period. These transition plans are to be developed by the
Regional Entity and the Registered Entity in a cooperative manner to best address the identified concerns and establish an agreed to
mitigation plan which results in full compliance by the Registered Entity.
Phase 1 of the project, as explained above, is addressing Commission directives established in Order No. 743 within a relatively short
time period. The SDT has decided to maintain the status quo with respect to applicability and the technical aspects contained in the
ERO Statement of Compliance Registry Criteria as the prudent path to take to ensure a successful conclusion to Phase 1 of the project.
The status quo was established in FERC Order No. 693, which states: “…the Commission will rely on the NERC definition of bulk
electric system and NERC’s registration process to provide as much certainty as possible regarding the applicability to and the
responsibility of specific entities to comply with the Reliability Standards in the start-up phase of a mandatory Reliability Standard
regime”. As the SDT progresses through Phase 2 of the project, it is envisioned that the technical aspects contained in the definition
and in the ERO Statement of Compliance Registry will be merged and ultimately incorporated into the definition of the Bulk Electric
System. At which time the ERO Statement of Compliance Registry Criteria will be revised to point to the BES definition for the
technical aspects in regards to BES Elements.
Westar Energy

Yes

We believe a reference should be made to the ROP changes which also provide a
mechanism whereby Elements may be excluded or included in the BES. Without that
reference, the proposed definition is not all inclusive of all means for exclusions or
inclusions. We would suggest the definition be expanded to say “Unless modified by
the lists shown below or as provided by Appendix 5C of the NERC Rules of Procedure,
all Transmission...” This comment was submitted in response to the original posting
and the response received was that it was inadvertently left out and that it would be
placed back in, but we don’t see the reference in this draft of the definition.

Southwest Power Pool
Standards Review Team

Yes

A reference needs to be made to the ROP changes which also provide a mechanism
whereby Elements may be excluded/included in the BES. Without that reference the
proposed definition does not completely include all means for exceptions/inclusions.
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Yes or No

Question 11 Comment
We would suggest the definition be expanded to say ‘...modified by the list shown
below or as provided by Appendix 5C of the NERC Rules of Procedure. We submitted
this in the original posting and the response received was that it was inadvertently left
out and that it would be placed back in. We don’t see the reference in this draft of the
definition.

Response: The Rules of Procedure exception process is referenced in the current draft version of the BES definition in a note which
states: “Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process”. No
change made.
WECC Staff

Yes

Following are additional comments not covered in previous questions: o Under the
section “Effective Dates”: There may be confusion with the statement “Compliance
Obligations for Elements included by definition shall begin 24 months after the
applicable effective data of the definition.” The phrase “included by definition” can be
interpreted broadly.
o WECC notes that a generation threshold of 75MVA is specified in Exclusions E1, E2,
and E3. WECC believes that generation thresholds for Exclusions should be addressed
in Phase 2 when generation thresholds for Inclusions are being considered.

Response: The complete statement from the Implementation Plan states: “Compliance obligations for all newly identified Elements
included by the definition shall begin 24 months after the applicable effective date of the definition.” The SDT’s intent with this
language is to identify newly identified BES Elements based on the revised definition. In other words, Elements that were not
considered to be BES Elements based on the exiting definition of BES in the NERC Glossary of Terms, but are now included as a result
of revising the exiting definition. The Implementation Plan has been clarified as shown:
Implementation Plan - Compliance obligations for all newly identified Elements included by the definition shall begin 24 months
after the applicable effective date of the definition.
The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the technical aspects
(i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities associated with being
responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing deadline of January 25, 2012,
and this has not afforded the SDT with sufficient time for the development of strong technical justifications that would warrant a
367

Organization

Yes or No

Question 11 Comment

change from the current values that exist through the application of the definition today. Phase 1 of the project is addressing
Commission directives established in Order No. 743 within a relatively short time period. Therefore the decision to maintain the status
quo as far as application of the definition and the technical aspects contained in the ERO Statement of Compliance Registry Criteria is
the prudent path to take to ensure a successful conclusion to Phase 1 of the project. The status quo was established in FERC Order No.
693, which states: “…the Commission will rely on the NERC definition of bulk electric system and NERC’s registration process to
provide as much certainty as possible regarding the applicability to and the responsibility of specific entities to comply with the
Reliability Standards in the start-up phase of a mandatory Reliability Standard regime”. These and similar issues have prompted the
SDT to separate the project into phases which will enable the SDT to address the concerns of industry stakeholders and regulatory
authorities. Therefore, the SDT will consider all recommendations for modifications to the technical aspects of the definition for
inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC
Technical Standing Committees, to develop analyses which will properly assess the threshold values and provide compelling
justification for modifications to the existing values. No change made.
ExxonMobil Research and
Engineering

Yes

It would be worthwhile to explain the relationship (timeline) between the BES
Definition implementation plan and the compliance implementation plan proposed in
the BES RoP team’s new Appendix 5C for the NERC Rules of Procedure.

Texas RE NERC Standards
Subcommittee

Yes

It might be worthwhile to explain the relationship (timeline) between the BES
Definition implementation plan and the compliance implementation plan proposed in
the BES RoP team’s new Appendix 5C for the NERC Rules of Procedure.

Response: For a newly identified Element(s) under the revised BES definition, the time period to be in full compliance with all
applicable Reliability Standards is 24 months from the effective date of the definition. If the entity wishes to file for an exception of a
newly identified Element(s) under the revised BES definition through the Rules of Procedure Exception Process, the entity will have 12
months from the effective date of the revised BES definition in which to file such a request. If the exception request is rejected or
disapproved and the classification of the Element(s) remains as a BES Element, the Regional Entity and the owner of such a BES
Element(s) shall agree to an Implementation Plan for full compliance obligations, which will establish an implementation date no
earlier than the date established by the definition Implementation Plan (24 months from the effective date of the definition).
Dominion

Yes

As a general policy, Dominion believes that attempting to precisely refine the
definition of the BES may not be the best way to insure BES reliability. Instead,
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Question 11 Comment
industry effort should be focused on developing specific reliability standard
requirements targeted toward solving problems that need to be addressed. Stated
differently, every Element that could have an impact on the BES does not need to be
included in the definition of the BES. NERC’s Functional Model addresses the broad
range of functions performed by the electric utility industry. When reliability concerns
are identified and can best be addressed via a standard, modifying the requirements
in that standard as applicable to that functional model should occur rather than
attempting to modify the BES definition. Effort spent on developing specific reliability
standard requirements mentioned above is superior to the industry engaging in
definitional debates that do not address to the underlying reliability drivers. It is not
essential that each reliability standard explicitly apply to each registered entity. The
existing reliability requirements, as applied to the various functional entities require
communication of information necessary to insure there are no reliability gaps, either
directly or indirectly among the various entities. The existing standards typically have a
hierarchy wherein: o Planners (PA, TP) receive information predominately from the
owners (GO, DP, TO) and those that represent end-use customers (LSE and PSE); o
Reliability entities (BA, RC and TOP) receive information predominately from operating
entities (GOP, TOP) and those that represent end-use customers (LSE and PSE); o
Planners provide reliability assessments to Reliability entities (BA, RC and TOP) and
receive feedback on these reliability assessments (including validity of assumptions
and result); and o Reliability entities (BA, RC and TOP) give instructions (including
when necessary directives) to operating entities (GOP, TOP) and those that represent
end-use customers (LSE and PSE). This is how the industry has historically operated,
how it operates today and why the standards in place today are structured as they
are. Reliability is best served when the standards themselves contain the appropriate
requirements and are applied to either an Element or Facility or to the appropriate
functional entity (DP, GO, GOP, LSE, TO, TOP, etc.). Definitional boundaries can create
the potential for false positives in reliability and, in fact, may be detrimental to
reliability in the longer term if they impose additional compliance burdens without
closing a reliability gap.
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Question 11 Comment

Response: The SDT acknowledges and appreciates the comments and recommendations associated with concepts for alternatives to
the revision of the exiting definition of BES. However, the SDT has responsibilities associated with being responsive to the directives
established in Orders No. 743 and 743-A, and is bound to answering those directives in a manner that achieves industry consensus
while remaining responsive to the language contained in the Orders. No change made.
Pepco Holdings Inc and
Affiliates

Yes

1) From the proposed BES definition and Exclusion E1 it is very clear that a 138-12kV
distribution transformer serving radial load would not be considered part of the BES.
However, suppose this transformer was connected to a position in a ring-bus or a
breaker-and-a-half arrangement. Would the physical bus between the transformer
high side terminals and the two breakers in the ring-bus, or breaker-and-a-half-bus, be
considered part of the BES? They would be contiguous transmission elements (bus)
operating at 138kV and supplying a radial distribution transformer. Also, tripping of
this “radial” bus section would not interrupt any BES facilities, due to the station bus
arrangement. As such, by definition and Exclusion E1 this 138kV bus section (element)
would not be part of the BES, and no special exclusion filing would be required. Is this
correct? However, take the same 138-12kV transformer but this time connected in a
typical line-bus arrangement. The transformer by definition is not a BES element. As
was the case above, the bus section between the transformer and the two breakers in
the line-bus would be contiguous elements (bus) operating at 138kV and supplying a
radial distribution transformer. Again, by definition and Exclusion E1 this bus section
(element) would not be part of the BES. However, in this case tripping of the “radial”
bus section would result in an interruption to the through path of the station, and
could therefore interrupt the through flow on BES facilities. Does this make either the
transformer, or its associated bus section, or both part of the BES? Based on the
above examples, if the type of bus connection could influence whether an element is
included in the BES or not, then additional language needs to be added to the
definition (either as an Inclusion or Exclusion) to make this point clear. The BES
definition needs to be specific enough to eliminate any confusion as to what is
included, and what is not included, and thereby greatly minimize, if not eliminate, the
need to request interpretations. A sample FAQ document, with examples, would be
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Question 11 Comment
extremely helpful, but should not be a substitute for a BES description which leaves
little room for interpretation.
2) As seen from the above attempt to describe issues that need clarification, without
a diagram to show specific situations, it is difficult to fully explain the concerns on
ensuring that the BES definition stands on its own. Since the commenting process
does not accommodate diagrams, PHI is sending separately a white paper with
diagrams in an attempt to clarify the definition and make it as unambiguous as
possible, leaving little room for interpretation. This paper may be helpful in developing
a FAQ document.
3) The definition should state that it applies to a system “normal” configuration. It
does not include maintenance or N-1 or any abnormal configurations.
4) There was no place on the comment forms to comment on the proposed
Implementation Plan for the BES definition. So comments are included here. The
proposed plan states “compliance obligations for Elements included by the definition
shall begin 24 months after the applicable effective date of the definition." This is
fine for most applications; however, there is an effect with PRC-005 compliance. PRC005 (Protection System Maintenance Standard) requires that evidence for the last two
maintenance intervals, in order to demonstrate that you are following the prescribed
intervals in your maintenance plan. If additional facilities are brought into scope by
the new BES definition, and the protection systems associated with these facilities
were not previously maintained on the same interval as other BES facilities, then it
may not be possible within the allotted 24 months to demonstrate the facilities were
maintained within the prescribed intervals for BES facilities. An implementation plan
at least as long as one full maintenance cycle would be required to assure compliance.
This issue needs to be addressed or coordinated with PRC-005.

Response: 1) Exclusion E1 identifies a Radial system as “a group of contiguous transmission Elements that emanates from a single
point of connection of 100 kV or higher” (with additional criteria identified in parts E1a, b and c). The SDT interprets the language
‘single point of connection’ as a tapped point where the radial system originates. Therefore in a ring-bus, a breaker-and-a-half or a
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typical line bus arrangement, the bus between the breakers and the breakers themselves are considered to be BES Elements. Under
these circumstances the bus position is the ‘single point of connection’, not a contiguous group of Elements as suggested in the
comment.
2) The development of a guidance document which contains generic diagrams is a portion of the overall project that the SDT feels is
necessary to ensure the consistent application of the BES definition going forward. Therefore the SDT has determined that such a
document will developed during Phase 2 of the project.
3) The SDT does not believe that system state affects the definition and therefore there is no need to declare that the definition only
applies to normal state. No change made.
4) The BES definition Implementation Plan addresses the implementation of the revised definition. The SDT is not in a position to
comment on compliance obligations associated with the Reliability Standards. However, in circumstances where data may not be
available due to the revised definition requirements, the SDT expects an entity to work with its Regional Entity to come up with a plan
to satisfy the obligation.
Southern Company
Generation

Yes

1) On page 1, the year of the anticipated date for the BOT adoption is correctly 2012.
2) We believe that the last two sentences of the first paragraph of the Background
Information section of the 2nd draft of the definition document is incorrect. The
statements read: " It should be noted that the revised definition does not address
functional entity registration or standards requirements applicability. Those are
separate issues." The definition of the BES that is approved will govern the scope of
the equipment that is relevant to many of the reliability standards. This issue cannot
be separated from the applicability of the requirements of the reliability standards.
What is the purpose of creating a continent wide definition of the BES if is is not to
provide instruction the enetties subject to the requirements of the standards? Refer
to these sample standard requirements to see that this definition already plays a
major part in the applicability of the requirements: EOP-005-2 R1, R4; EOP-006-2 R1;
EOP-008-1 R1; FAC-008-1 R1.2; and PRC-005-1a for example - there are many
others.

Response: 1) The SDT has made the revision to the BOT adoption date to correctly identify the year as 2012.
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2) The SDT acknowledges that the linkage between the BES definition and the Reliability Standards may have been understated in the
Background Information contained in the comment form. However, the goal of the SDT in addressing the Commission directives is to
develop modifications to the definition in response to the directives without significantly expanding or contracting the scope of the
BES and not drive registration changes in the industry. The SDT believes that they have met these goals, as evidenced by a detailed
review of the NERC Reliability Standards. The SDT determined that potentially the scope of applicability of certain requirements may
change due to the establishment of a bright-line definition. However, this potential change did not dictate a need for modification of
the language contained in the requirements.
AECI and member GandTs,
Central Electric Power
Cooperative, KAMO Power,
MandA Electric Power
Cooperative, Northeast
Missouri Electric Power
Cooperative, NW Electric
Power Cooperative Sho-Me
Power Electric Power
Cooperative

Yes

: AECI supports the bright-line concept, but believes the SDT should adopt a core
voltage threshold of “200 kV or higher”, and MVA capacity of “150 MVA or greater”. A
proper threshold is critical, because an inappropriately low threshold will divert
significant industry attention and resource away from what truly benefits the BES
reliability. (The number of facilities tend to rise more geometrically than linearly as
the voltage threshold drops.)We believe that an evaluation of the transmission-line
Surge Impedance Loading (SIL), at various kV levels, could provide technical insight as
to why many industry planning engineers believe sub-230kV Facilities, in general do
not belong within the BES. AECI suggests that the SDT consider a more consistent
bright-line facility threshold of 150 MVA capability for all equipment. This would
include transmission lines as well, where an Surge Impedance Loading analysis
demonstrates that lines below 230 kV, can support 150 MVA flow up to 280 miles
(applying 1.1 p.u. line-loadability of SIL, IEEE Transactions on Power Apparatus and
Systems, Vol.PAS-98, No.2 March/April 1979, p 609, Figure 7),without additional
reactive compensation. In comparison, single-conductor 138 kV lines, in same table,
can support 150 MVA transfers no more than 50 miles, while 345 kV lines are capable
of supporting 150 MVA transfers well over 600 miles.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
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and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values. No change made.
MRO NERC Standards Review
Forum (NSRF)

Yes

NSRF recommends that the following statement be added after I5. If an element is not
included based upon the core definition or I1 - I5, the elements is not consider to be a
part of the BES.

Response: The SDT is attempting through the BES definition to identify facilities that should be classified as BES Elements. Adding a
statement that emphasizes the opposite of what the definition is intending to accomplish would be redundant and would negate the
efforts of the SDT to improve clarity and remove the ambiguity that currently exists the definition today. No change made.
IRC Standards Review
Committee

Yes

(1) We support a phased approach proposed in the draft supplemental SAR.
Development of the revised BES definition is an important and complex undertaking.
The product of this work is fundamental to establishing the applicability of NERC
Reliability Standards. The issues identified for attention in Phase 2 of this project
warrant careful investigation and as such allowing additional time to properly research
and provide for stakeholders to vett them is justified. Specific to the assessment of
raising the generator rating threshold from 20 MVA to 75 MVA per unit, we would
point out that this needs to be looked at from a different perspective. Industry
debates so far have been on the apparent lack of reliability contribution and economic
benefits for keeping the threshold at 20 MVA. The former point implies that any
negative reliability impact that could be contributed by a generator higher than 20
MVA but lower than 75 MVA could be negligible. Some examples of the standards that
the 20-75 MVA units may need to comply with to ensure reliability are: o Voltage and
frequency ride through capability o Voltage control (AVR, etc.) o Underfrequency trip
setting o Protection relay setting coordination o Data submission for modeling;
verification of capability and model A Venn diagram developed by an industry group
shows that generators at 20 to 74.99 MVA account for about 13.8% of the total
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installed capacity in the US. Out of this, 3.0% are currently deemed non-BES whereas
the other 10.8% are BES. We do not know how the BES reliability may be affected if
these 10.8% generators are no longer deemed BES facilities (after an increase of
threshold to 75 MVA) and subject to compliance with NERC standards, including those
mentioned above. An assessment from both a positive contribution and a negative
impact viewpoints are thus required to aid the determination of the merit of raising
the rating threshold.
(2) The draft Implementation Plan for the BES definition states “Compliance
obligations for Elements included by the definition shall begin 24 months after the
applicable effective date of the definition.” We are concerned that the stated
implementation period may be insufficient time to complete transition plans for newly
identified BES Elements and Facilities, where those plans require procurement,
installation and commissioning of additional equipment. We believe a period of 24
months may be more appropriate.

Response: 1) The SDT agrees with the commenter that the best opportunity to address the industry concerns associated with the
technical aspects of the definition is through Phase 2 of the project. The SDT also agrees with the commenter in that any assessment
utilized to determine the correct threshold for generating resources should be accomplished without any preconceived threshold
value as a target for justification. The full scope of the assessments will be determined through a joint effort between the SDT and the
appropriate NERC Technical Committee.
2) In proposing a 24 month period in the Implementation Plan before the definition is applied in assessing compliance obligations, the
SDT considered several activities that may require additional time to complete for an entity to become fully compliant. One of these
activities is the development of transition plans in cases where significant issues may have been identified as potentially preventing an
entity from meeting the compliance obligations within the 24 month period. These transition plans are to be developed by the
Regional Entity and the Registered Entity in a cooperative manner to best address the identified concerns and establish an agreed to
mitigation plan which results in full compliance by the Registered Entity.
Tennessee Valley Authority

Yes

The definition of the BES is referenced in several existing standards and the Statement
of Compliance Registry Criteria. TVA is concerned with this revised definition’s impact
on entity registrations, i.e., how will the revised definition be integrated into the
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Compliance Registry Criteria.
The implementation plan should include how the integration is going to occur. The 24
month period for new facilities that are to become BES elements as a result of this
definition is very important to successful implementation of the definition. An period
shorter that 24 months would be very problematic for the industry.

Response: Phase 1 of the project, as explained above, is addressing Commission directives established in Order No. 743 within a
relatively short time period. The SDT has decided to maintain the status quo with respect to applicability and the technical aspects
contained in the ERO Statement of Compliance Registry Criteria as the prudent path to take to ensure a successful conclusion to Phase
1 of the project. The status quo was established in FERC Order No. 693, which states: “…the Commission will rely on the NERC
definition of bulk electric system and NERC’s registration process to provide as much certainty as possible regarding the applicability
to and the responsibility of specific entities to comply with the Reliability Standards in the start-up phase of a mandatory Reliability
Standard regime”. As the SDT progresses through Phase 2 of the project, it is envisioned that the technical aspects contained in the
definition and in the ERO Statement of Compliance Registry will be merged and ultimately incorporated into the definition of the Bulk
Electric System. At which time the ERO Statement of Compliance Registry Criteria will be revised to point to the BES definition for the
technical aspects in regards to BES Elements.
The SDT agrees with the commenter in regards to the implementation time period of 24 months. In proposing a 24 month period in
the Implementation Plan before the definition is applied in assessing compliance obligations, the SDT considered several activities that
may require additional time to complete for an entity to become fully compliant. One of these activities is the development of
transition plans in cases where significant issues may have been identified as potentially preventing an entity from meeting the
compliance obligations within the 24 month period. These transition plans are to be developed by the Regional Entity and the
Registered Entity in a cooperative manner to best address the identified concerns and establish an agreed to mitigation plan which
results in full compliance by the Registered Entity.
Hydro One Networks Inc.

Yes

o The definition of the Bulk Electric System (BES) is a foundational construct for the
North American Electric Reliability Corporation (NERC). FERC Orders 743 and 743-A do
not mandate a 100 kV approach. Instead, it states that a 100 kV bright line threshold
is one approach to defining the BES. It further states that only “some” 115/138 kV
facilities are necessary for the reliable operation of the bulk system. We believe that if
one subset issue (such as 20 MVA vs. 75 MVA) of the entire definition, requires more
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time and resources to arrive at the correct answer, the much larger and more
fundamental issue of how to define BES should not have been dismissed without the
appropriate analysis before another definition is proposed to be adopted by the ERO.
o The proposed definition, in combination with other new and/or modified Reliability
Standards such as newly modified and approved TPL Standards will require significant
system upgrades with high dollar investments. We are deeply concerned that a) no
such assessment has been undertaken by the SDT and/or the ERO and b) the proposed
definition of the BES is not based on a technical analysis that will enhance the
reliability of the interconnected transmission network.
o The NERC as the ERO should at least undertake a cost and incremental reliability
benefit analysis for its proposed definition of BES. Furthermore, cost impacts and
reliability benefit assessments of the BES definition coupled with other new and
modified reliability standards (such as the TPL Standards) must also be undertaken
and weighed against the potential benefits, if any, of this or any proposal. Not
providing such an assessment but using the 100 kV level as a starting point for the BES
definition, gives no assurances of benefits for any stakeholder including respective
governmental and regulatory authorities and rate payers in Canada or the USA.
o The proposed definition would significantly increase the population of BES elements.
Many of the standards requirements for these new elements will introduce
administrative burden and operating expenses. This would impose significant costs,
costs that ratepayers will have to bear, with little or no gain in reliability benefits for
the interconnected transmission system. We suggest that the resulting BES definition
must identify incremental reliability benefits by the ERO for the interconnected
transmission network based on sound technical analysis to justify the change to those
who will pay for any required system upgrades - the ratepayer.
o The draft Implementation Plan for the BES definition states “Compliance obligations
for Elements included by the definition shall begin 24 months after the applicable
effective date of the definition.” We are concerned that the stated implementation
period will give insufficient time to complete transition plans for newly identified BES
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Elements and Facilities, where those plans require approval, procurement, installation
and commissioning of additional equipment. We believe a period of 60 months at a
minimum is more appropriate.
Finally, we believe that the SDT proposed approach for exception criteria is reasonable
recognizing that one method/criteria can not be applicable to everyone and every
situation within the ERO footprint. However, we believe that there is a huge gap and
lack of any transparency on how the exception application will be evaluated and
processed. We strongly suggest that the SDT develop a reference or a guidance
document as part of the RoP that should provide guidance to Registered Entities,
Regional Entities and the ERO on how an exception application should be processed.
Else, (a) it will pose a challenge for each of the entities including ERO, and (b) may
introduce Regional discretion and be perceived as having no transparency for the
registered entities.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has responsibilities
associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to the filing
deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System including the 100
kV bright-line level. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which
will properly assess the threshold values and provide compelling justification for modifications to the existing values.
Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the results
would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission grid on a
continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the development of
Regional transition plans once the definition has been approved by the Commission.
The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
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improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s
concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has pursued a
definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting the
current scope of the BES or driving registration or de-registration. The technical aspects of the definition have remained identical to
the current definition and identical to the application of the ERO Statement of Compliance Registry Criteria and therefore do not
require a technical justification to support maintaining the status-quo.
In proposing a 24 month period in the Implementation Plan before the definition is applied in assessing compliance obligations, the
SDT considered several activities that may require additional time to complete for an entity to become fully compliant. One of these
activities is the development of transition plans in cases where significant issues may have been identified as potentially preventing an
entity from meeting the compliance obligations within the 24 month period. These transition plans are to be developed by the
Regional Entity and the Registered Entity in a cooperative manner to best address the identified concerns and establish an agreed to
mitigation plan which results in full compliance by the Registered Entity.
The SDT understands the concerns raised by the commenters in not receiving hard and fast guidance on this issue. The SDT would like
nothing better than to be able to provide a simple continent-wide resolution to this matter. However, after many hours of discussion
and an initial attempt at doing so, it has become obvious to the SDT that the simple answer that so many desire is not achievable. If
the SDT could have come up with the simple answer, it would have been supplied within the bright-line. The SDT would also like to
point out to the commenters that it directly solicited assistance in this matter in the first posting of the criteria and received very little
in the form of substantive comments.
There are so many individual variables that will apply to specific cases that there is no way to cover everything up front. There are
always going to be extenuating circumstances that will influence decisions on individual cases. One could take this statement to say
that the regional discretion hasn’t been removed from the process as dictated in the Order. However, the SDT disagrees with this
position. The exception request form has to be taken in concert with the changes to the ERO Rules of Procedure and looked at as a
single package. When one looks at the rules being formulated for the exception process, it becomes clear that the role of the
Regional Entity has been drastically reduced in the proposed revision. The role of the Regional Entity is now one of reviewing the
submittal for completion and making a recommendation to the ERO Panel, not to make the final determination. The Regional Entity
plays no role in actually approving or rejecting the submittal. It simply acts as an intermediary. One can counter that this places the
Regional Entity in a position to effectively block a submittal by being arbitrary as to what information needs to be supplied. In
addition, the SDT believes that the visibility of the process would belie such an action by the Regional Entity and also believes that one
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has to have faith in the integrity of the Regional Entity in such a process. Moreover, Appendix 5C of the proposed NERC Rules of
Procedure, Sections 5.1.5, 5.3, and 5.2.4, provide an added level of protection requiring an independent Technical Review Panel
assessment where a Regional Entity decides to reject or disapprove an exception request. This panel’s findings become part of the
exception request record submitted to NERC. Appendix 5C of the proposed NERC Rules of Procedure, Section 7.0, provides NERC the
option to remand the request to the Regional Entity with the mandate to process the exception if it finds the Regional Entity erred in
rejecting or disapproving the exception request. On the other side of this equation, one could make an argument that the Regional
Entity has no basis for what constitutes an acceptable submittal. Commenters point out that the explicit types of studies to be
provided and how to interpret the information aren’t shown in the request process. The SDT again points to the variations that will
abound in the requests as negating any hard and fast rules in this regard. However, one is not dealing with amateurs here. This is not
something that hasn’t been handled before by either party and there is a great deal of professional experience involved on both the
submitter’s and the Regional Entity’s side of this equation. Having viewed the request details, the SDT believes that both sides can
quickly arrive at a resolution as to what information needs to be supplied for the submittal to travel upward to the ERO Panel for
adjudication.
Now, the commenters could point to lack of direction being supplied to the ERO Panel as to specific guidelines for them to follow in
making their decision. The SDT re-iterates the problem with providing such hard and fast rules. There are just too many variables to
take into account. Providing concrete guidelines is going to tie the hands of the ERO Panel and inevitably result in bad decisions being
made. The SDT also refers the commenters to Appendix 5C of the proposed NERC Rules of Procedure, Section 3.1 where the basic
premise on evaluating an exception request must be based on whether the Elements are necessary for the reliable operation of the
interconnected transmission system. Further, reliable operation is defined in the Rules of Procedure as operating the elements of the
bulk power system within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result ofa sudden disturbance, including a cyber security incident,
or unanticipated failure of system elements. The SDT firmly believes that the technical prowess of the ERO Panel, the visibility of the
process, and the experience gained by having this same panel review multiple requests will result in an equitable, transparent, and
consistent approach to the problem. The SDT would also point out that there are options for a submitting entity to pursue that are
outlined in the proposed ERO Rules of Procedure changes if they feel that an improper decision has been made on their submittal.
Some commenters have asked whether a single ‘yes’ or ‘no’ response to an item on the exception request form will mandate a
negative response to the request. To that item, the SDT refers commenters to Appendix 5C of the proposed NERC Rules of Procedure,
Section 3.2 of the proposed Rules of Procedure that states “No single piece of evidence provided as part of an Exception Request or
response to a question will be solely dispositive in the determination of whether an Exception Request shall be approved or
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disapproved.”
The SDT would like to point out several changes made to the specific items in the form that were made in response to industry
comments. The SDT believes that these clarifications will make the process tighter and easier to follow and improve the quality of the
submittals.
Finally, the SDT would point to the draft SAR for Phase 2 of this project that calls for a review of the process after 12 months of
experience. The SDT believes that this time period will allow industry to see if the process is working correctly and to suggest changes
to the process based on actual real-world experience and not just on suppositions of what may occur in the future. Given the
complexity of the technical aspects of this problem and the filing deadline that the SDT is working under for Phase 1 of this project,
the SDT believes that it has developed a fair and equitable method of approaching this difficult problem. The SDT asks the commenter
to consider all of these facts in making your decision and casting your ballot and hopes that these changes will result in a favorable
outcome.
Western Area Power
Administration

Yes

Yes, the definition should also provide clarification on mobile equipment installed to
support maintenance or equipment failures. Adding mobile equipment is a common
practice for our industry and should be addressed in the definition to bring a general
awareness and common understanding of the practice regarding the NERC standards.
Recommendation: Add the following Exclusion to BES definition for mobile
equipment. Exclude all mobile equipment on stand-by that has not been placed into
service as well as all components of mobile equipment that does not meet the
inclusion criteria for the primary function of the device being installed (e.g. ,battery
bank on mobile transformer installed on radial feed would also be excluded)

Response: The SDT acknowledges the commenter’s concern and has determined that the need for an exclusion identifying mobile
equipment is not appropriate. The SDT believes that the BES definition is identifying Elements that support the reliable operation of
the interconnected transmission grid. This premise implies that the Element is electrically connected to the system and is performing
a reliability related service. The SDT believes that the time the mobile equipment is placed in service is when the equipment would be
classified as a BES Element and subject to compliance obligations. No change made.
NESCOE

Yes

NESCOE offers the following additional comments: 1) Phased Approach. While wellintentioned, separating the BES definition project into two separate phases is
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problematic from both a procedural and substantive perspective. While we recognize
that the filing due date is rapidly approaching, the BES definition cannot be considered
in a vacuum, divorced from the concerns raised by a number of parties in response to
past postings of the BES definition. The issues NERC has identified for consideration
during the proposed “Phase 2” are inseparable from the development of the BES
definition and should be squarely addressed before a definition is adopted. In
particular, the development of criteria for determining what facilities are “necessary
for the reliable operation” of the interconnected system cannot be put off for a
second phase. Contrary to FERC’s direction, NERC’s proposal will force ratepayers to
incur costs related to compliance with mandates that may or may not be revised
through the second phase of the project. The importance of considering and resolving
such concerns before adopting a definition is heightened by the proposed two-year
implementation requirement. This short implementation period almost guarantees
that entities will commit resources shortly after adoption of the definition to ensure
compliance within the mandated period. In other words, ratepayers will bear costs
related to compliance irrespective of any change resulting from the Phase 2 process or
the exception process. Expediency, while understandable given the filing deadline,
must be balanced against the risk that a multi-phased approach could lead to
significant consumer costs without attendant meaningful reliability benefits.
2) Cost-Benefit Analysis. A cost impact analysis should be performed as part of
developing any reliability standard. However, the development of the BES definition
has failed to consider the cost impacts of the definition (and its inclusions and
exclusions) and weigh these impacts against identified benefits that the definition
would achieve. NESCOE stated in its May 21, 2011 comments on the last posting of
the BES definition that “any new costs a revised definition imposes - which fall
ultimately on consumers - should provide meaningful reliability benefits.” A costbenefit analysis should be integral to the development of a BES definition and, indeed,
any reliability standard. This analysis should include a probabilistic risk assessment
examining the likelihood of an event and the costs and risks resulting from such event,
which should be weighed against the costs of complying with the proposed reliability
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measures.
3) Technical Justification. In addition to performing a cost-benefit analysis, a technical
basis must be provided to justify a proposed reliability standard. However, as we state
above, the proposed BES definition does not provide a technical justification for the
100 kV threshold. Nor does it provide a technical justification for the threshold for
generation resources or other elements of the definition. As stated above, while wellintentioned and understandable, deferring this technical justification to a later and
separate phase of the project is a flawed and potentially costly approach. Providing a
technical justification for a reliability standard is a core function of standards
development and should be addressed at the forefront of the process rather than
relegated to a separate phase largely undertaken after a standard is filed.

Response: 1) The SDT acknowledges the commenter’s concerns; however the SDT (and the ERO) has an obligation to respond to the
Commission directives established in Order No. 743 within the time frame allotted by the Order. The narrow scope of the directives
and the limited timeframe for project completion has prevented the SDT from fully vetting the concerns of the industry as expressed
through the development process. To best address the Commission directives and stakeholder concerns, the SDT has opted to
separate the project into phases. The revised project plan has been fully endorsed by the NERC Members Representative Committee
and the Board of Trustees. Additionally the NERC Standards Committee has committed to the continued development of a revised
definition by retaining the project as a high priority project and by dedicating the resources necessary to fully vet the issues raised by
stakeholders.
2) The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s
concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has pursued a
definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting the
current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. Without an approved BES definition
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any assumptions utilized in a cost benefit analysis would be purely speculative and the results would have little meaning in regards to
potential improvements in the reliable operation of the interconnected transmission grid on a continent-wide basis. Therefore, the
SDT believes that best opportunity to address cost concerns will be through the development of Regional transition plans once the
definition has been approved by the Commission.
3) The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s
concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has pursued a
definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting the
current scope of the BES or driving registration or de-registration. The technical aspects of the definition have remained identical to
the current definition and identical to the application of the ERO Statement of Compliance Registry Criteria and therefore do not
require a technical justification to support maintaining the status-quo.
ReliabilityFirst

Yes

This definition needs to be clear and easy enough for anyone to pickup, read,
understand, apply and arrive at the same conclusion on whether the facility or
element is included or excluded. This definition leaves room for continued debate and
interpretation. To help make this definition clearer, ReliabilityFirst Staff has provided
a redline version of the core definition under a separate cover (file titled “Bulk Electric
System definition by RFC Staff 10-4-2011”).

Response: The SDT believes that the revised definition of the BES has provided the necessary clarity to allow for consistent application
on a continent-wide basis. The issues identified in the commenter’s redline (provided following the responses to question 11) have
been fully vetted by the SDT and addressed in the responses to the comments for the applicable question related to the specific issue.
Ontario Power Generation Inc.

Yes

Further to comments submitted in Question #1, OPG disagrees in general with
proceeding to implement a 100 kV brightline definition in the absence of a properly
quantified cost/benefit analysis. Entities are being asked to incur a high cost for no
demonstrated benefit in wide-area reliability.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
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pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. Without an approved BES definition
any assumptions utilized in a cost benefit analysis would be purely speculative and the results would have little meaning in regards to
potential improvements in the reliable operation of the interconnected transmission grid on a continent-wide basis. Therefore, the
SDT believes that best opportunity to address cost concerns will be through the development of Regional transition plans once the
definition has been approved by the Commission.
Central Hudson Gas and
Electric Corporation

Yes

Due to the movement to a phased BES definition development process and assuming
the definition is approved as proposed, there is an urgent need for NERC to provide
clear guidance to Registered Entities regarding how to proceed with facilities and
address changes to the NERC Compliance Registry registration obligations brought
in/on by the application of the new definition. The problem stems from a likely
scenario whereby the affected Registered Entities may be faced with an
Implementation Plan and an Exception Request Procedure which must be completed
prior to the completion of the Phase 2 definition development process. If that is the
case, many Registered Entities will be confronted with either (1) spending large
amounts of human and financial resources, not yet acquired, to address
facilities/procedures necessary to address possible new compliance obligations only to
find their efforts rendered unnecessary by the results produced in Phase 2 or, (2)
waiting until the results of Phase 2 are provided and risking being found noncompliant and subject to substantial penalties in the future. Neither option can be
viewed as a desirable, or for that matter, an acceptable position to be placed in.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
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pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. Therefore, the SDT believes that
best opportunity to address cost and resources issues will be through the development of Regional transition plans once the definition
has been approved by the Commission. The SDT recommends that the commenter pursue achieving full compliance with the revised
definition in the appropriate time period (see Implementation Plan) while utilizing the Rules of Procedure exception process to
specific exceptions from the BES definition.
Springfield Utility Board

Yes

When submitting BES Definition comments, SUB would suggest a “not-applicable”,
“no-impact” or “abstain” option in addition to “yes” or “no”. In some cases, the draft
language has no impact on an entity’s system, yet that entity’s selection of “yes” or
“no” may imply agreement or disagreement rather than expressing lack of
applicability. This could skew the perception of agreement or disagreement, and
create a potential issue for those who are directly impacted by the changes.

Response: The SDT understands the commenter’s concern; however the formatting of the comment form (including the electronic
version) is governed by the ERO and beyond the control of the SDT. Your comment will be forwarded to the NERC Standards staff for
consideration.
Mission Valley Power

Yes

Mission Valley Power - In order to help meet the fast approaching target date, Mission
Valley Power will be voting affirmative in this ballot, with the hope these comments
will be addressed in Phase 2. If the ballot should fail, please address these comments
in this phase. Thanks to the team for their good work.

Response: The SDT acknowledges and appreciates the continued support of the project. The SDT will consider all recommendations
for modifications to the technical aspects of the definition for project inclusion at the appropriate time during Project 2010-17
Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for modifications to the existing
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Yes

Con Edison shares the concerns raised by the State of New York Department of Public
Service (NYPSC) in its September 12, 2011 letter to NERC Chairman Anderson. The
NYPSC expressed concern that the proposed BES Definition “would impose significant
costs, costs that New York ratepayers will be expected to bear, with little or no
increase in reliability benefits.” The BES definition is being revised without an
assessment of costs or benefits. The SDT is encouraged to work with NERC Staff to
perform such an assessment prior to providing the revised BES definition to the NERC
Board. Regional Entities share this concern with cost effectiveness. In NPCC, the Board
of Directors directed NPCC Staff to develop a methodology to assess the cost and
benefit of Standards. This NPCC Cost Effectiveness Analysis Procedure (CEAP)
establishes a process to address those concerns. The CEAP introduces two
assessments of the estimated industry-wide costs of requirements into that
Standard’s development process. The procedure adds supporting information and
background for the NPCC stakeholders, ballot body and the NPCC Board of Directors.
Moreover, during a 2010 FERC technical conference the Commission recognized that
“reliability does not come without cost.” As a result, significant interest was expressed
in development of a process to identify the costs for draft reliability Standards and the
ability of the proposed standards to achieve the reliability objective(s) sought in a cost
effective manner. We understand that it is a NERC priority to define adequate level of
reliability and use it as the basis for determining the cost effectiveness of a proposed
rule. While this has not yet been finalized, NERC could use this proposed standard as
a test case for determining the relationship between costs and benefits.

values.
Consolidated Edison Co. of NY,
Inc.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
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definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. Without an approved BES definition
any assumptions utilized in a cost benefit analysis would be purely speculative and the results would have little meaning in regards to
potential improvements in the reliable operation of the interconnected transmission grid on a continent-wide basis. Therefore, the
SDT believes that best opportunity to address cost concerns will be through the development of Regional transition plans once the
definition has been approved by the Commission.
Northern Wasco County PUD

Yes

In order to help meet the fast approaching target date, Northern Wasco County PUD
will be voting affirmative in this ballot, with the hope these comments will be
addressed in Phase 2. If the ballot should fail, please address these comments in this
phase. Thanks to the team for their good work.

Tillamook PUD

Yes

If Tillamook PUD had signed up to ballot in time, we would be voting yes with the
hope that these comments would be addressed in Phase 2. If the ballot fails, please
address these comments in this phase.

Response: The SDT acknowledges and appreciates the continued support of the project. The SDT will consider all recommendations
for modifications to the technical aspects of the definition for project inclusion at the appropriate time during Project 2010-17
Definition of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to
develop analyses which will properly assess the threshold values and provide compelling justification for modifications to the existing
values.
American Electric Power

Yes

There needs to be some clarification regarding the default status of an asset, as well as
the order and priority of the inclusion and exclusion classifications within the
definition. First, prior to any evaluation by virtue of the definition, is an asset by
default excluded from the BES, or rather, it is included? In addition, once the definition
is used to evaluate an asset which has both inclusion attributes and exclusion
attributes, which of the two classifications has greater weight? For example, if an asset
is first included by the BES definition inclusion criteria can it then be excluded by BES
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definition exclusion criteria? Or instead, if an asset is first excluded by BES definition
exclusion criteria can it then be included by the BES definition inclusion criteria? AEP’s
recommendation is that an asset, by default, not be considered part of the BES. Next,
the asset would be evaluated by the inclusion criteria as specified within the
definition. Next, any asset explicitly included by the inclusion criteria is then evaluated
using the exclusion criteria. Once the entity has made their determination based on
the definition, exception requests could then be made to include or exclude assets as
appropriate. We believe our interpretation is what is implied by the draft definition,
however, this needs to be explicitly communicated within the definition itself.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
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applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
City of St. George

Yes

The small utility exclusion issues discussed in the first draft of the documents are not
included (draft 1 proposed E4) nor addressed in the draft 2 documentation. Under the
present definition many small utilities with local generation to serve its own local load
will be required to register for additional functions, or at a minimum go through a
long, expensive, time consuming process to get an individual exclusion from the BES.
The topics that have been postponed to Phase 2 of the project are critical to and will
have a direct impact to many utilities. Phase 2 needs to have specific shorter than
normal timelines established, similar to what Phase 1 has had. The present definition
and standards in general makes little or no consideration for the actual impact of an
entity or facility on the bulk system. As such small utilities with a few miles of 115 kV
or 138 kV lines and some generation are required to meet the same requirements as
large utilities with 100’s or 1,000’s of miles of 345 kV or 500 kV lines and that operate
very large generation plants of several hundred MVA of capacity. All utilities support
reliability improvement, but the requirements and associated costs need to match
their actual impact to the overall system.

Response: The SDT acknowledges and appreciates the comments and recommendations associated with modifications to the
technical aspects (i.e., potential small utility exclusion) of the BES definition. However, it is important to emphasize the fact that the
SDT is developing a definition to identify the Elements that support the reliable operation of the interconnected transmission network
regardless of ownership or operational responsibility. Small utility issues are very similar to the issues raised through the GOTO
project and are best addressed through the applicability of the individual reliability standards, not through the definition of the BES.
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Yes

There are a number of possible scenarios where an element falls under both an
inclusion and exclusion. The definition is unclear as to whether or not this would have
the element be BES or not. During the webinar an example was given about a static
shunt device meeting the requirements of I5, but is part of a radial network. The
response during the webinar was that this would be excluded. If this is correct, it
means that an exclusion takes precedence over an inclusion. Is this always the case?
This needs to be clarified and stated somewhere in this document.

No change made.
ISO New England Inc

To be consistent with regard to the terms “Operated at 100 kV” and “Connected at
100 kV “, we suggest that reference to generators should state, “Connected at a
transmission element operated at 100 kV”. This will avoid confusion in cases where a
generator is connected to a transmission element rated at 100 kV but operated at a
lower voltage.
Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
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Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
The BES definition refers to operating voltage (as emphasized in FERC Order No. 743-A) and the SDT does not feel that the language
“connected at a voltage of 100kV or above” creates any confusion on the intent of the Inclusion. No change made.
NBPT

Yes

o When an exclusion and inclusion principles overlap which takes precedence? For
example I5 may be excluded if in a LN (E3)
o The Local Network Exclusion criterion does not appear to consider voltage support
and the effects of shifting of load or impacts due to a loss of load. The 75 MW
generation threshold has no technical basis. The LN exclusion should allow for studies
demonstrating no through flow benefit regardless if there is.
o 75 MW Generation has no technical justification.
o Black Start resources should not be included in all GO/GOP standards except for
those standards specific to black start units.

Response: The application of the draft ‘bright-line’ BES definition is a three (3) step process that when appropriately applied will
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identify the vast majority of BES Elements in a consistent manner that can be applied on a continent-wide basis.
Initially, the BES ‘core’ definition is used to establish the bright-line of 100 kV, which is the overall demarcation point between BES and
non-BES Elements. Additionally, the ‘core’ definition identifies the Real Power and Reactive Power resources connected at 100 kV or
higher as included in the BES. To fully appreciate the scope of the ‘core’ definition an understanding of the term Element is needed.
Element is defined in the NERC Glossary of Terms as:
“Any electrical device with terminals that may be connected to other electrical devices such as a generator, transformer, circuit
breaker, bus section, or transmission line. An element may be comprised of one or more components. “
Element is basically any electrical device that is associated with the transmission or the generation (generating resources) of electric
energy.
Step two (2) provides additional clarification for the purposes of identifying specific Elements that are included through the
application of the ‘core’ definition. The Inclusions address transmission Elements and Real Power and Reactive Power resources with
specific criteria to provide for a consistent determination of whether an Element is classified as BES or non-BES.
Step three (3) is to evaluate specific situations for potential exclusion from the BES (classification as non-BES Elements). The exclusion
language is written to specifically identify Elements or groups of Elements for potential exclusion from the BES.
Exclusion E1 provides for the exclusion of ‘transmission Elements’ from radial systems that meet the specific criteria identified in the
exclusion language. This does not include the exclusion of Real Power and Reactive Power resources captured by Inclusions I2 – I5.
The exclusion (E1) only speaks to the transmission component of the radial system. Similarly, Exclusion E3 (local networks) should be
applied in the same manner. Therefore, the only inclusion that Exclusions E1 and E3 supersede is Inclusion I1.
Exclusion E2 provides for the exclusion of the Real Power resources that reside behind the retail meter (on the customer’s side) and
supersedes inclusion I2.
Exclusion E4 provides for the exclusion of retail customer owned and operated Reactive Power devices and supersedes Inclusion I5.
In the event that the BES definition incorrectly designates an Element as BES that is not necessary for the reliable operation of the
interconnected transmission network or an Element as non-BES that is necessary for the reliable operation of the interconnected
transmission network, the Rules of Procedure exception process may be utilized on a case-by-case basis to either include or exclude
an Element.
The local network exclusion has established a bright-line with specific characteristics that must be met to be eligible for exclusion.
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Exclusion E3b states: “Power flows only into the LN and the LN does not transfer energy originating outside the LN for delivery
through the LN". This characteristic applies under all operating conditions including any variations in network load. It is not clear to
the SDT what the commenter is referring to in regards to voltage support. Exclusion E3 addresses transmission Elements and does not
exclude Real Power or Reactive Power resources from the BES.
The concept of the 75 MVA threshold is based on the generation inclusion criteria for plant/facility arrangements by carrying through
the concept of the reliability impact that the aggregated loss of 75 MVA or greater would have on the overall reliability of the
interconnected transmission grid. The SDT acknowledges and appreciates the comments and recommendations associated with
modifications to the technical aspects (i.e., the bright-line and component thresholds) of the BES definition. However, the SDT has
responsibilities associated with being responsive to the directives established in Orders No. 743 and 743-A, particularly in regards to
the filing deadline of January 25, 2012, and this has not afforded the SDT with sufficient time for the development of strong technical
justifications that would warrant a change from the current values that exist through the application of the definition today. These
and similar issues have prompted the SDT to separate the project into phases which will enable the SDT to address the concerns of
industry stakeholders and regulatory authorities. Therefore, the SDT will consider all recommendations for modifications to the
technical aspects of the definition for inclusion in Phase 2 of Project 2010-17 Definition of the Bulk Electric System. This will allow the
SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses which will properly assess the threshold values
and provide compelling justification for modifications to the existing values.
The SDT has determined that Blackstart Resources serve a reliability benefit to the interconnected transmission grid and therefore
have been included in the scope of the BES. This is consistent with current practice and specifically with the registration requirements
that identify the owner, operators, and users of Blackstart Resources be registered as Generator Owner/Generator Operator. Specific
concerns with the applicability of individual standards should be addressed through the Standard Development Process for the
individual Reliability Standards in question.
Texas Reliability Entity

Yes

(1) It is unclear exactly what is intended by “non-retail generation” in Exclusion E1(c).
We suggest that the term be explained or defined in the BES definition or in a
collateral document. This term does not have a commonly understood unambiguous
meaning in our Region.
(2) Phase 2 has to be completed or explicitly defined/scoped to fully capture all of the
components necessary for reliable operation of the BES.

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Response: (1) Non-retail generation is the generation on the system (supply) side of the retail meter.
(2) The supplemental SAR for Phase 2 of the project will be posted for industry comment at which time the SDT will be accepting
recommendations for specific issues to be addressed by the SDT during phase 2 of the project.
New York State Dept of Public
Service

Yes

o Per NERC’s obligations under the Energy Power Act of 2005 to provide FERC
technical advice, no technical justification has been provided for basing the BES
definition on the 100 kV and MVA thresholds.
o No cost analysis on either the reliability benefits of the overall definition or on the
implementation plan has been performed to determine whether the likely high cost of
the definition to ratepayers is justified.
o The definition of the BES should be the driver for the application of all other NERC
reliability standards and criteria. The definition uses the Statement of Compliance
Registry Criteria as a driver of the definition when the reverse should be taking place;
contents of the Statement should be driven by the BES definition.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the definition has not been altered in regards
to the bright-line or the generation thresholds and therefore does not require the development of technical justification to maintain
the status quo.
SDT acknowledges that the current BES definition has varying degrees of Regional application and has resulted in different conclusions
on what is currently considered to be part of the BES. This inconsistency in the application and subsequent results were also identified
by the Commission in Orders No. 743 and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line
definition coupled with the inconsistency in application of the current definition there is a potential for varying degrees of impact on
Regions. Without an approved BES definition any assumptions utilized in a cost benefit analysis would be purely speculative and the
results would have little meaning in regards to potential improvements in the reliable operation of the interconnected transmission
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grid on a continent-wide basis. Therefore, the SDT believes that best opportunity to address cost concerns will be through the
development of Regional transition plans once the definition has been approved by the Commission.
The SDT has revised the language in Inclusion I2 to eliminate the circular reference to the ERO Statement of Compliance Registry
Criteria. Inclusion I2 has been revised to read:
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
Hydro-Quebec TransEnergie

Yes

In the Implementation plan, it is given only 24 months for compliance after applicable
regulatory approval. Considering the possibility that a proposed transition plan may
involve commissioning of long term projects, a provision for such situation should be
made with longer delay.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. With that being said, the SDT
believes that an implementation time period of 24 months is sufficient time to address the development of regional transition plans,
address any necessary registration changes, file for exceptions through the Rules of Procedure exception process and address any
required training. The SDT also acknowledges that the potential exists for extenuating circumstances that will need to be addressed
through the regional transition plans.
Independent Electricity
System Operator

Yes

We wish to also express our support for phased approach proposed in the draft
supplemental SAR. Development of the revised BES definition is an important and
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complex undertaking. The product of this work is fundamental to establishing the
applicability of NERC Reliability Standards. The issues identified for attention in Phase
2 of this project warrant careful investigation and as such allowing additional time to
properly research and stakeholder them is justified. The draft Implementation Plan for
the BES definition sates “Compliance obligations for Elements included by the
definition shall begin 24 months after the applicable effective date of the definition.”
We are concerned that the stated implementation period may be insufficient time to
(1) prepare and file exception requests and have these assessed; and (2) in cases
where these exception requests are not approved, to develop and complete transition
plans for newly identified BES Elements and Facilities, particularly where those plans
require major investments for the procurement, installation and commissioning of
additional equipment. We therefore propose the following alternative wording for the
Implementation Plan: “Compliance obligations for elements included by the definition
shall be evaluated and an implementation schedule established within 24 months.”
Throughout the document various phrases are used to describe generating
units/resource, viz. “generation resources”, “generating resources”, “generating unit”
and “power producing resources”. Please review these to identify and address any
possible inconsistencies.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. With that being said, the SDT
believes that an implementation time period of 24 months is sufficient time to address the development of regional transition plans,
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Question 11 Comment

address any necessary registration changes, file for exceptions through the Rules of Procedure exception process and address any
required training. The SDT also acknowledges that the potential exists for extenuating circumstances that will need to be addressed
through the regional transition plans.
The SDT has reviewed the applicable documents for inconsistencies related to the terms generating units/resource, viz. “generation
resources”, “generating resources”, “generating unit” and “power producing resources”. The SDT has made the appropriate
modifications to address any issues resulting from the inconsistencies.
Central Lincoln

Yes

We note that the SAR for Phase 2, like that for Phase 1, does not include all entity
types. We see no reason to maintain dual definitions for the different entity types, and
the resulting confusion.
In order to help meet the fast approaching January target date, Central Lincoln will be
voting affirmative in this ballot, with the hope these comments will be addressed in
Phase 2. If the ballot should fail, please address these comments in this phase. Thanks
to the team for their good work.

Response: The draft SAR developed for Phase 2 of Project 2010-17 Definition of the Bulk Electric System, similar to the SAR for Phase
1 has purposefully omitted the Interchange Authority and the Purchase Selling Entity functional entities because these entities do not
own or operate BES Elements. This conclusion does not necessitate the need for dual definitions; the definition of the BES does not
impact the functional responsibilities of these entities.
The SDT acknowledges and appreciates the continued support of the project. The SDT will consider all recommendations for
modifications to the technical aspects of the definition for project inclusion at the appropriate time during Project 2010-17 Definition
of the Bulk Electric System. This will allow the SDT, in conjunction with the NERC Technical Standing Committees, to develop analyses
which will properly assess the threshold values and provide compelling justification for modifications to the existing values.
Utility Services, Inc.

Yes

Utility Services would like to raise the question of whether SCRC III.3.d (the so-called
"Generator Materiality" clause) is incorporated within the BES Inclusion Designations.
One theory suggests that given that I2 is designed to deal with III.3.a and III.3.b and I3
reflects the need to incorporate black start generation; then generators under the
materiality clause are not identified with the inclusion criteria. However, the second
theory suggests that resources identifed through I2 reflect the entire III.c.1-4 language
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Question 11 Comment
of the SCRC, then the generators in the material clause are captured under I2. But if
this is the case, then I3 is redundant to I2 and does not need to separately addressed.

Response: The SDT has revised the language in Inclusion I2 to clearly identify the applicability of generating resources. The revised
language is as follows:
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate
nameplate rating greater than 75 MVA per the ERO Statement of Compliance Registry Criteria) including the generator terminals
through the high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
FirstEnergy Corp.

Yes

FE supports the SDT's phased project approach which was well articulated in the NERC
BES Definition Fact Sheet

LCRA Transmission Services
Corporation

Yes

LCRA TSC supports the direction the standards drafting team taking with this project
on the BES Definition and encourages further clarification as noted in these comments
for proper application.

Response: The SDT acknowledges and appreciates the continued support of the project.
National Grid

Yes

The proposed implementation period in the draft definition is too short. The new BES
definition will likely result in increased operational costs during the implementation
period that will ultimately be borne by customers. Implicit in the Commission's
directive to change the BES definition is the Commission's determination that the
benefits of this change, including consistency among the regions, outweigh the
ratepayer impacts. However, National Grid remains concerned that the ratepayer
impacts have not been fully taken into account. The implementation period is a tool
that can allow NERC to meet the Commission's directive while softening any resulting
ratepayer impacts. Implementation can and should be staged in order to mitigate and
even out rate increases. National Grid suggests that the implementation period be
flexible to allow entities who anticipate that large and/or expensive upgrades to the
BES will be necessary to meet compliance can submit an alternate implementation
plan to spread compliance and the associated rate changes over a longer period; we
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Yes or No

Question 11 Comment
would suggest a minimum of 7 years. This time period was also recognized as a
reasonable implementation time period in the recent TPL-001-2 for those portions of
the standard that would also result in plans that would require siting, permitting and
construction activities. This BES definition is likely to have similar impacts for some
entities and allowing for an implementation timeline with the definition change
enables achievement of the goals while recognizing the realities of constructing
facilities in today's environment.

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. With this in mind, the SDT acknowledges that the current BES
definition has varying degrees of Regional application and has resulted in different conclusions on what is currently considered to be
part of the BES. This inconsistency in the application and subsequent results were also identified by the Commission in Orders No. 743
and 743-A as a significant concern. The SDT acknowledges that by developing a bright-line definition coupled with the inconsistency in
application of the current definition there is a potential for varying degrees of impact on Regions. With that being said, the SDT
believes that an implementation time period of 24 months is sufficient time to address the development of regional transition plans,
address any necessary registration changes, file for exceptions through the Rules of Procedure exception process and address any
required training. The SDT also acknowledges that the potential exists for extenuating circumstances that will need to be addressed
through the regional transition plans.
In proposing a 24 month period in the Implementation Plan before the definition is applied in assessing compliance obligations, the
SDT considered several activities that may require additional time to complete for an entity to become fully compliant. One of these
activities is the development of transition plans in cases where significant issues may have been identified as potentially preventing an
entity from meeting the compliance obligations within the 24 month period. These transition plans are to be developed by the
Regional Entity and the Registered Entity in a cooperative manner to best address the identified concerns and establish an agreed to
mitigation plan which results in full compliance by the Registered Entity.
Rochester Gas and Electric

Yes

If the definition and inclusions and exclusions are not sufficiently specific and clear,
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Yes or No

and New York State Electric
and Gas

Question 11 Comment
stakeholders will flood NERC and RROs with interpretation requests and/or apply the
definition and its inclusions or exclusions incorrectly. Explanatory figures with one-line
diagrams should be developed and shared to illustrate the system configurations
included and excluded in this BES Definition. This would be very helpful for definition
clarity. This should be done as part of an “Application Guide” for the BES Definition this has precedence in CIP-002 version 5. Attached is a sample set of one-line diagrams
with interpretations based upon the inclusions and exclusions developed by Northeast
Power Coordinating Council members for discussion purposes as an example, but note
that there is not a uniform agreement on these diagrams based on the BES Definition
as written, due to lack of clarity.

Response: The development of a guidance document which contains generic diagrams is a portion of the overall project that the SDT
feels is necessary to ensure the consistent application of the BES definition going forward. Therefore the SDT has determined that
such a document will be developed during Phase 2 of the project. The SDT thanks Rochester for the appended drawings but wishes to
point out that the SDT does not agree with some of the depictions shown on the drawings thus pointing out the need for an eventual
guidance document.
Central Maine Power
Company

Yes

If the definition and inclusions and exclusions are not sufficiently specific and clear,
stakeholders will flood NERC and RROs with interpretation requests and/or apply the
definition and its inclusions or exclusions incorrectly. Explanatory figures with one-line
diagrams should be developed and shared to illustrate the system configurations
included and excluded in a BES Definition. This would be very helpful for definition
clarity. This should be done as part of an “Application Guide” for the BES Definition there is precedence for an “Application Guide” with graphical support in CIP-002
version 5. A sample set of one-line diagrams with interpretations based upon the
inclusions and exclusions developed by Northeast Power Coordinating Council
members for discussion purposes is available as an example, but note that there is not
a uniform agreement on these diagrams based on the BES Definition as written, due to
lack of clarity.

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Nebraska Public Power District

Yes or No

Question 11 Comment

Yes

Regarding the Local Network: Can there be some additional technical documents or
examples provided for the most common configurations? The LN document is a good
document to provide guidance, however the supply of common configuration
examples would be very helpful in determining LN applicability. Examples where
technical document with examples would be helpful: 1. If a breaker and a half source
substation provides two parallel 115 kV lines feeding a load only substation from
separate breaker and a half legs at the source substation, would the two parallel lines
feeding the load be a LN distribution network feed since they are from the same
source substation? 2. if there is a radial feed from a ring bus or a breaker and a half
configuration to a radial load on a single line can the portion of the ring bus or breaker
and a half bus between the line breakers and the breakers themselves at the source
substation be excluded from the BES? 3. Can some legs of a 115kV breaker and a half
substation be disgnated BES and the other legs be non BES depending on how the BES
lines and loads tie in to the breaker and half legs? 4. In determining if elements are
BES is there any consideration to fault locations and if these faults would interrupt BES
flow on ring bus or breaker and a half configurations to help determine what is BES? If
so, how many contingencies would be considered to interrupt BES flow?

Response: The development of a guidance document which contains generic diagrams is a portion of the overall project that the SDT
feels is necessary to ensure the consistent application of the BES definition going forward. Therefore the SDT has determined that
such a document will be developed during Phase 2 of the project.
Ameren

Yes

a) We believe this revised definition is an improvement over the previous posting, a
step in the right direction.
b) The definition of the BES is referenced in several existing standards and the
Statement of Compliance Registry Criteria. Our concern is how this revised
definition will impact entity registration, i.e., how will the revised definition be
integrated into the Compliance Registry Criteria. The implementation plan should
include how the integration is going to occur. The Rules of Procedure exception
process should be further defined or referenced in this definition.
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Question 11 Comment
c) See Question 1 response: The general concept is sound, but the Inclusion and
Exclusion sections create so many circular references it is virtually impossible to
take a definitive stance on whether an asset is included or excluded to the BES
definition. Please revise the inclusion and exclusion criteria to give pinpointed
statements that are final and do not reference other criteria, that then again
reference other criteria

Response: a) The SDT acknowledges and appreciates the continued support of the project.
b) The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of Terms to
improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and non-BES
Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the Commission’s
concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has pursued a
definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting the
current scope of the BES or driving registration or de-registration. The BES definition will be utilized in conjunction with the ERO
Statement of Compliance Registry Criteria to determine how entities will be registered. As the SDT progresses through phase 2 of the
project, consideration will be given to establish a definition that will eventually be the definitive document to determine registration
requirements.
The Rules of Procedure exception process is referenced in the current draft version of the BES definition in a note which states: “Note
- Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process”.
c) The SDT has made several revisions that the address the clarity issues raised by commenter’s. For a detailed response concerning
the specific clarifications made by the SDT, see the individual responses for the appropriate question. The application of the brightline definition of the BES is explained in the detail in the Summary Consideration at the beginning of this question.
MEAG Power

Yes

The definition of the BES is referenced in several existing standards and the Statement
of Compliance Registry Criteria. We are concerned how this revised definition will
impact entity registration, i.e., how will the revised definition be integrated into the
Compliance Registry Criteria.
The implementation plan should include how the integration is going to occur.

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Question 11 Comment

Response: The responsibilities assigned to the SDT included the revision of the definition of BES contained in the NERC Glossary of
Terms to improve clarity, to reduce ambiguity, and to establish consistency across all Regions in distinguishing between BES and nonBES Elements. The SDT’s efforts are directed at fulfilling their responsibilities and developing a definition that addresses the
Commission’s concerns as expressed in the directives contained in Orders No. 743 and 743-A. To accomplish these goals, the SDT has
pursued a definition that remains as consistent as possible with the existing definition, while not significantly expanding or contracting
the current scope of the BES or driving registration or de-registration. The BES definition will be utilized in conjunction with the ERO
Statement of Compliance Registry Criteria to determine how entities will be registered. As the SDT progresses through phase 2 of the
project, consideration will be given to establish a definition that will eventually be the definitive document to determine registration
requirements.
The current Implementation Plan is determining the effective dates of the revised definition and the extended time period for
meeting compliance obligations. The revised definition and the current ERO Statement of Compliance Registry Criteria will continue to
be utilized in the same manner as today for registration determinations. In proposing a 24 month period in the Implementation Plan
before the definition is applied in assessing compliance obligations, the SDT considered several activities that may require additional
time to complete for an entity to become fully compliant. One of these activities is the development of transition plans in cases where
significant issues may have been identified as potentially preventing an entity from meeting the compliance obligations within the 24
month period. These transition plans are to be developed by the Regional Entity and the Registered Entity in a cooperative manner to
best address the identified concerns and establish an agreed to mitigation plan which results in full compliance by the Registered
Entity.
Redding Electric Utility

Yes

City of Redding

Yes

Redding is concerned that phase 2 will not produce significant rules or criteria that
further define the BES; the desire to dedicate adaquate resourses is currently high
since FERC has a looming deadline upon NERC, however without deadlines Redding
believes that NERC will find it difficult to find the expertise or desire to finish the
Project.

Response: The NERC Standards Committee (SC) has approved Phase 2 of Project 2010-17 Definition of the Bulk Electric System as a
‘high priority’ project. Additionally, the SC has retained the existing SDT and committed to providing the necessary resources through
the NERC Technical Committees in providing analysis of technical issues to be addressed in Phase 2 of the project. Furthermore, the
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Question 11 Comment

SDT will be developing a project schedule for Phase 2, subject to approval by the SC, which will identify the appropriate deadlines
throughout the project.
Indeck Energy Services

Yes

As acknowledged in the response to Question 12 comments on the previous BES
definition, the BES definition is expansive compared to the definition of the BPS in the
FPA Section 215. The inclusion of the limited Exclusions is an attempt to remedy the
situation. However, the Exclusions need to include a fifth one that if, based on studies
or other assessments, it can be shown that any tranmission or generator element
otherwise identified as part of the BES is not important to the reliability of the BPS,
then that element should be excluded from the mandatory standards program. There
has never been a study to show that elements, such as a 20 MW wind farm, 60 MW
merchant generator (which operates infrequently in the depressed market) in a large
BA (eg NYISO) or a radial transmission line connecting a small generator are important
to the reliability of the BPS. They are covered by the mandatory standards program
through the registration criteria. The BES Definition is the opportunity to permit an
entity to demonstrate that an element is unimportant to reliability of the BPS. The
SDT has identified a small subset of elements that it is willing to exclude. By their very
nature, these exclusions dim the bright line that is the stated goal of this project.
However, the SDT’s foresight seems limited in its selections. Analytical studies are
used to evaluate contingencies that could lead to the Big Three (cascading outages,
instability or voltage collapse). Such a study showing that a transmission or
generation element is bounded by the N-1 or N-2 contingency would exclude it from
the BES definition. For example, in a BA with a NERC definition Reportable
Disturbance of approximately 400 MW (eg NYISO), a 20 MW wind farm, 60 MW
merchant generator or numerous other smaller facilities would be bounded by larger
contingencies. It would take more than six 60 MW merchant generators with close
location and common mode failure to even be a Reportable Disturbance, much less
become the N-1 contingency for the Big Three. Exclusion E5 should be “E5 - Any
facility that can be demonstrated to the Regional Entity by analytical study or other
assessment to be unimportant to the reliability of the BPS (with periodic reports by
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Yes or No

Question 11 Comment
the Regional Entity to NERC of any such assessments).”

Response: The concerns of the commenter are addressed by the implementation of the Rules of Procedure exception process, which
establishes the exclusion methods described by the commenter. The commenter’s suggested language leaves Regional discretion in
the process, which is a cited concern requiring elimination by the Commission, in the Orders No. 743 and 743-A. The SDT has provided
a reference to the Rules of Procedure exception process in the definition with the following language: “Note - Elements may be
included or excluded on a case-by-case basis through the Rules of Procedure exception process.”
Kootenai Electric Cooperative
Michigan Public Power Agency
Clallam County PUD No.1
Blachly-Lane Electric
Cooperative (BLEC)
Coos-Curry Electric
Cooperative (CCEC)
Central Electric Cooperatve
(CEC)
Clearwater Power Company
(CPC)
Snohomish County PUD
Consumer's Power Inc.
Douglas Electric Cooperative
(DEC)
Fall River Rural Electric
Cooperative (FALL)
Lane Electric Cooperative

No

KEC extends its thanks to the SDT and to the many industry entities that have actively
participating in the Standards Development Process. KEC strongly supports the
current draft and believes, with certain refinements discussed in our comments, that
the definition will serve the industry and reliability regulators well for many years to
come. In addition, as noted earlier, KEC is encouraged that the 20/75 MVA generation
thresholds referred to in the NERC Statement of Compliance Registry Criteria, which
have been relied upon by the SDT largely as a matter of necessity, will be reviewed
and a technical assessment will be performed to identify the appropriate generation
unit and plant size threshold to ensure a reliable North America. Finally, we
understand that the Rules of Procedure Team will continue to move forward with
developing an Exceptions Process that will complement the BES Definition and ensure
that, to the extent the BES Definition is over-inclusive, facilities that should not be
classified as BES will be excluded from the BES. Because the Exceptions Process is
integral to a workable BES Definition, we support the current process for moving
forward with the Exceptions Process and the BES Definition on parallel paths. We note
that KEC specifically supports the changes made by the SDT in the “Effective Date”
provision of the BES Definition, which shortens the effective date of the new definition
to the beginning of the first calendar quarter after regulatory approval (as opposed to
the first calendar quarter twenty-four months after regulatory approval), with a 24month transition period. KEC supports this conclusion because it will allow entities
seeking deregistration under the terms of the new BES definition to obtain the
benefits of the new definition without an unreasonable wait, while allowing any
entities that may be newly-classified as BES owners or operators sufficient time to
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Organization

Yes or No

(LEC)

Question 11 Comment
come into compliance with newly-applicable Reliability Standards. KEC also supports
the 24-month transition period for the reasons laid out by the SDT.

Lincoln Electric Cooperative
(LEC)
Northern Lights Inc. (NLI)
Okanogan County Electric
Cooperative (OCEC)
Pacific Northwest Generating
Cooperative (PNGC)
Raft River Rural Electric
Cooperative (RAFT)
West Oregon Electric
Cooperative
Umatilla Electric Cooperative
(UEC)

Response: The SDT acknowledges and appreciates the continued support of the project.
PacifiCorp

No

It is absolutely imperative that phase II continue as proposed by the STD. If phase II
was not proposed PacifiCorp would vote no on this proposal.

Response: Phase 2 will start as soon as Phase 1 is completed and the SDT resources are freed up. .
Farmington Electric Utility
System

No

Portland General Electric
Company

No

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Organization

Yes or No

City of Austin dba Austin
Energy

No

Georgia System Operations
Corporation

No

Kansas City Power and Light
Company

No

Oncor Electric Delivery
Company LLC

No

Memphis Light, Gas and
Water Division

No

Harney Electric Cooperative,
Inc.

No

Cowlitz County PUD

No

PSEG Services Corp

No

Massachusetts Department of
Public Utilities

No

Manitoba Hydro

No

Long Island Power Authority

No

The Dow Chemical Company

No

Question 11 Comment

We appreciate the work the drafting team has done in preparing this document.

Cowlitz appreciates the opportunity to comment, and the hard work of the SDT.

408

Organization

Yes or No

Puget Sound Energy

No

NV Energy

No

Z Global Engineering and
Energy Solutions

No

Consumers Energy

No

City of Anaheim

No

Chevron U.S.A. Inc.

No

Metropolitan Water District of
Southern California

No

Duke Energy

No

Idaho Falls Power

No

Exelon

No

Texas Industrial Energy
Consumers

No

Tri-State GandT

No

ATC LLC

No

Tacoma Power

No

Question 11 Comment

Tacoma Power does not have any other concerns at this time. Thank you for
consideration of our comments.
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Organization

Yes or No

Arizona Public Service
Company

No

Tri-State Generation and
Transmission Assn., Inc.
Energy Management

No

Electricity Consumers
Resource Council (ELCON)

No

ACES Power Marketing
Standards Collaborators

No

Bonneville Power
Administration

No

SERC Planning Standards
Subcommittee

No

NERC Staff Technical Review

No

BGE

No

Question 11 Comment

The comments expressed herein represent a consensus of the views of the abovenamed members of the SERC EC Planning Standards Subcommittee only and should
not be construed as the position of SERC Reliability Corporation, its board, or its
officers”

No comment.

Response: Thank you for your support.

410

RFC Suggested changes to definition:
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission Elements operated at 100 kV or higher and
Real Power and Reactive Power resources connected at 100 kV or higher. This does not include facilities used in the local distribution
of electric energy. The BES includes:
Inclusions:

•
•
•
•

•

I1 - Transformers with primary and secondary terminals operated at 100 kV or higher. unless excluded under
Exclusion E1 or E3for local distribution or retail customers.
I2 - Generating resources as described in the ERO Statement of Compliance Registry Criteria including the
generator terminals through the high-side of the step-up transformer(s), connected at a voltage of 100 kV or above.
I3 - Blackstart Resources and associated designated blackstart Cranking Paths operated at 100 kV or higher,
identified in the Transmission Operator’s restoration plan. regardless of voltage level.
I4 - Dispersed power producing resources as described in the ERO Statement of Compliance Registry Criteria
utilizing a system designed primarily for aggregating capacity, connected at common point at a voltage of 100 kV
or above.
I45 –Static or dynamic devices dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or
higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through a transformer
that is designated in Inclusion I1.

This definition does not include facilities used in the local distribution of electric energy or retail customers, which are:.
Exclusions:

•

E1 - Radial systems: A group of contiguous transmission Elements that emanates from a single point of connection
of 100 kV or higher from a single Transmission source originating with a singlen automatic interruption device and:
a) Only serves Load. Or,
b) Only includes generation resources not identified in Inclusion I3, with an aggregate capacity less
than or equal to 75 MVA (gross nameplate rating). Or,
c) Where the radial system serves Load and includes generation resources, not identified in Inclusion
I3, with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross
nameplate rating).
Note - A normally open switching device between radial systems, as depicted on prints or one-line
diagrams for example, does not affect this exclusion.
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•

•

E2 - A generating unit or multiple generating units that serve all or part of retail customer Load with electric energy
on the customer’s side of the retail meter if:
o (i) the net capacity provided to the BES does not exceed 75 MVA, and
o (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple
generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation
with a Generator Owner or Generator Operator, or under terms approved by the applicable regulatory
authority.
E3 - Local Network (LN): A group of contiguous transmission Elements operated at or above 100 kV but less than
300 kV that distribute power to Load rather than transfer bulk power across the interconnected system. LN’s
emanate from multiple points of connection at 100 kV or higher to improve the level of service to retail customer
Load and not to accommodate bulk power transfer across the interconnected system. The LN is characterized by all
of the following:
a) Limits on connected generation: The LN and its underlying Elements do not include generation
resources identified in Inclusion I3 and do not have an aggregate capacity of non-retail generation
greater than 75 MVA (gross nameplate rating);
b) Power flows only into the LN: The LN does not transfer energy originating outside the LN for
delivery through the LN; and;

•

c) Not part of a Flowgate or transfer path: The LN does not contain a monitored Facility of a permanent
Flowgate in the Eastern Interconnection, a major transfer path within the Western Interconnection,
or a comparable monitored Facility in the ERCOT or Quebec Interconnections, and is not a
monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices owned and operated by the retail customer solely for its own use.

Note - Elements may be included or excluded on a case-by-case basis through the Rules of Procedure exception process.

412

Pacificorp additional comments:
5.

The SDT has revised the specific inclusions to the core definition in response to industry comments. Do you
agree with Inclusion I4 (dispersed power)? If you do not support this change or you agree in general but feel
that alternative language would be more appropriate, please provide specific suggestions in your comments.

Yes:
No: X
Comments: Setting a dispersed power producing resource limit to 75 MVA at a common point discriminates
against single generator owners who own generators between 20 MVA and 75 MVA (inclusion I1), typically
connected at a common point and requires such owners to be subject to additional standards that dispersed
power producing owners are not required.
However, even with this concern, PacifiCorp supports the entire BES definition in its current form based on the
timeframe under which the SDT is operating and with an emphasis based on a phase II SAR to address
PacifiCorp’s objections regarding generation levels.
Under the attached scenario, please identify which elements would be considered BES:

413

414

Rochester Diagrams: These diagrams were supplied by Rochester as examples and do not reflect the SDT’s opinion of what is
and isn’t a BES Element.

415

416

417

418

419

420

421

422

423

Project 2010-17 Definition of Bulk Electric System

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.

Development Steps Completed
1. SAR posted for comment 12/17/10 – 1/21/11
2. SC authorized moving the SAR forward to standard development 3/25/11
3. First posting of definition 4/28/11 – 5/27/11
4. First posting of criteria 5/11/11 – 6/10/11
5. Second posting of definition and criteria plus initial ballot 8/26/11 – 10/10/11

Description of Current Draft
This draft is the third posting and recirculation ballot of the revised definition of the Bulk
Electric System (BES). It is for a 10-day recirculation voting period.

Anticipated Actions

Anticipated Date

30-day Formal Comment Period

4/28/11

45-day Formal Comment Period with Parallel Initial Ballot

September 2011

Recirculation ballot

November 2011

BOT adoption

January 2012

Dra ft #2: Da te

Page 1 of 4

Project 2010-17 Definition of Bulk Electric System

Effective Dates
This definition shall become effective on the first day of the second calendar quarter after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
the definition will go into effect on the first day of the second calendar quarter after Board of
Trustees adoption. Compliance obligations for Elements included by the definition shall begin
24 months after the applicable effective date of the definition.

Version History

Version
1

Dra ft #2: Da te

Date
TBD

Action

Change
Tracking

Respond to FERC Order No. 743 to
N/A
clarify the definition of the Bulk Electric
System

Page 2 of 4

Project 2010-17 Definition of Bulk Electric System

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission
Elements operated at 100 kV or higher and Real Power and Reactive Power resources connected
at 100 kV or higher. This does not include facilities used in the local distribution of electric
energy.
Inclusions:
•
•

•
•

•

I1 - Transformers with the primary terminal and at least one secondary terminal operated
at 100 kV or higher unless excluded under Exclusion E1 or E3.
I2 - Generating resource(s) with gross individual nameplate rating greater than 20 MVA
or gross plant/facility aggregate nameplate rating greater than 75 MVA including the
generator terminals through the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily for aggregating
capacity, connected at a common point at a voltage of 100 kV or above.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is
designated in Inclusion I1.

Exclusions:
•

E1 - Radial systems: A group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusion I3, with an
aggregate capacity less than or equal to 75 MVA (gross nameplate rating).
Or,
c) Where the radial system serves Load and includes generation resources,
not identified in Inclusion I3, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted
on prints or one-line diagrams for example, does not affect this exclusion.

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Project 2010-17 Definition of Bulk Electric System
•

•

•

E2 - A generating unit or multiple generating units on the customer’s side of the retail
meter that serve all or part of the retail Load with electric energy if: (i) the net capacity
provided to the BES does not exceed 75 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating
units or to the retail Load by a Balancing Authority, or provided pursuant to a binding
obligation with a Generator Owner or Generator Operator, or under terms approved by
the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at or
above 100 kV but less than 300 kV that distribute power to Load rather than transfer bulk
power across the interconnected system. LN’s emanate from multiple points of
connection at 100 kV or higher to improve the level of service to retail customer Load
and not to accommodate bulk power transfer across the interconnected system. The LN is
characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do
not include generation resources identified in Inclusion I3 and do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating) ;
b) Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain a
monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection,
or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices owned and operated by the retail customer solely for its
own use.

Note - Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.

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Project 2010-17 Definition of Bulk Electric System

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.

Development Steps Completed
1. SAR posted for comment 12/17/10 – 1/21/11
2. SC authorized moving the SAR forward to standard development 3/25/11
3. First posting of definition 4/28/11 – 5/27/11
4. First posting of criteria 5/11/11 – 6/10/11
4.5.Second posting of definition and criteria plus initial ballot 8/26/11 – 10/10/11

Description of Current Draft
This draft is the secondthird posting and recirculation ballot of the revised definition of the Bulk
Electric System (BES). It is for a 45-day formal comment and parallel 10-day recirculation
voting period.

Anticipated Actions

Anticipated Date

30-day Formal Comment Period

4/28/11

45-day Formal Comment Period with Parallel Initial Ballot

September 2011

Recirculation ballot

DecemberNovember
2011

BOT adoption

January 20112

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Page 1 of 4

Project 2010-17 Definition of Bulk Electric System

Effective Dates
This definition shall become effective on the first day of the second calendar quarter after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
the definition will go into effect on the first day of the second calendar quarter after Board of
Trustees adoption. Compliance obligations for Elements included by the definition shall begin
24 months after the applicable effective date of the definition.

Version History

Version
1

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Date
TBD

Action

Change
Tracking

Respond to FERC Order No. 743 to
N/A
clarify the definition of the Bulk Electric
System

Page 2 of 4

Project 2010-17 Definition of Bulk Electric System

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission
Elements operated at 100 kV or higher and Real Power and Reactive Power resources connected
at 100 kV or higher. This does not include facilities used in the local distribution of electric
energy.
Inclusions:
•
•

•
•

•

I1 - Transformers with the primary terminal and at least one secondary terminals
operated at 100 kV or higher unless excluded under Exclusion E1 or E3.
I2 - Generating resource(s) (with gross individual nameplate rating greater than 20 MVA
or gross plant/facility aggregate nameplate rating greater than 75 MVA per the ERO
Statement of Compliance Registry Criteria) including the generator terminals through the
high-side of the step-up transformer(s) connected at a voltage of 100 kV or above.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily for aggregating
capacity, connected at a common point at a voltage of 100 kV or above.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is
designated in Inclusion I1.

Exclusions:
•

E1 - Radial systems: A group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusion I3, with an
aggregate capacity less than or equal to 75 MVA (gross nameplate rating).
Or,
c) Where the radial system serves Load and includes generation resources,
not identified in Inclusion I3, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted
on prints or one-line diagrams for example, does not affect this exclusion.

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Project 2010-17 Definition of Bulk Electric System
•

•

•

E2 - A generating unit or multiple generating units on the customer’s side of the retail
meter that serve all or part of the retail customer Load with electric energy on the
customer’s side of the retail meter if: (i) the net capacity provided to the BES does not
exceed 75 MVA, and (ii) standby, back-up, and maintenance power services are provided
to the generating unit or multiple generating units or to the retail Load by a Balancing
Authority, or provided pursuant to a binding obligation with a Generator Owner or
Generator Operator, or under terms approved by the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at or
above 100 kV but less than 300 kV that distribute power to Load rather than transfer bulk
power across the interconnected system. LN’s emanate from multiple points of
connection at 100 kV or higher to improve the level of service to retail customer Load
and not to accommodate bulk power transfer across the interconnected system. The LN is
characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do
not include generation resources identified in Inclusion I3 and do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating) ;
b) Power flows only into the LN: and Tthe LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain a
monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection,
or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices owned and operated by the retail customer solely for its
own use.

Note - Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.

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Implementation Plan for Project 2010-17:
Definition of BES
Prerequisite Approvals

There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this project can be implemented. However, this definition
relies heavily on the fact that an approved exception process exists in the NERC Rules of Procedure.
Effective Dates

This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required the definition shall
go into effect on the first day of the second calendar quarter after Board of Trustees adoption.
Compliance obligations for all newly identified Elements included by the definition shall begin 24
months after the applicable effective date of the definition.
The SDT realizes that Order 743 suggested a maximum of 18 months for implementation of a revised
definition of the BES. The 24 month period cited here is based on the various rehearing requests filed
by entities expected to be affected by the revised definition. Thus, the SDT believes that this is a more
realistic timeframe in which to effect any changes.
The SDT believes that the timeframe shown is needed to:
•

•

•

•

Effectively produce reasonable transition plans – As shown in Order 743, part of the overall process of
revising the definition of BES is for the ERO and Regional Entities to develop transition plans on a region
by region basis to accommodate any changes needed in those regions due to the revised definition. The
transition plans will include any actions necessary for entities to achieve compliance on any issues
brought about by the revised definition.
Submit any necessary registration changes – While Order 743 states that a revised definition should
provide clarity and not necessarily require major changes to registration; it is possible that the revised
definition may cause some registration changes. Entities will need time to submit their changes and for
those changes to work their way through the process.
File for exceptions – The revised definition does not exist in a vacuum. There is a corresponding process
for entities to request exceptions for specific equipment or configurations. This process will be defined
in the NERC Rules of Procedure and will involve individual entities or the Regional Entities having to
make a technical case to justify the exception. This process will take some time to complete and it
would be expected that there will be an initial backlog of cases to process.
Provide training – Entities will need to train their operators and personnel on changes to their
operations brought about by the revised definition.

The existing definition of BES shall be retired at midnight of the day immediately prior to the effective date of
the new definition of BES in the particular jurisdiction in which the new definition is becoming effective.

Implementation Plan for Project 2010-17:
Definition of BES
Prerequisite Approvals

There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this project can be implemented. However, this definition
relies heavily on the fact that an approved exception process exists in the NERC Rules of Procedure.
Effective Dates

This definition shall become effective on the first day of the second calendar quarter after applicable
regulatory approval. In those jurisdictions where no regulatory approval is required the definition shall
go into effect on the first day of the second calendar quarter after Board of Trustees adoption.
Compliance obligations for all newly identified Elements included by the definition shall begin 24
months after the applicable effective date of the definition.
The SDT realizes that Order 743 suggested a maximum of 18 months for implementation of a revised
definition of the BES. The 24 month period cited here is based on the various rehearing requests filed
by entities expected to be affected by the revised definition. Thus, the SDT believes that this is a more
realistic timeframe in which to effect any changes.
The SDT believes that the timeframe shown is needed to:
•

•

•

•

Effectively produce reasonable transition plans – As shown in Order 743, part of the overall process of
revising the definition of BES is for the ERO and Regional Entities to develop transition plans on a region
by region basis to accommodate any changes needed in those regions due to the revised definition. The
transition plans will include any actions necessary for entities to achieve compliance on any issues
brought about by the revised definition.
Submit any necessary registration changes – While Order 743 states that a revised definition should
provide clarity and not necessarily require major changes to registration; it is possible that the revised
definition may cause some registration changes. Entities will need time to submit their changes and for
those changes to work their way through the process.
File for exceptions – The revised definition does not exist in a vacuum. There is a corresponding process
for entities to request exceptions for specific equipment or configurations. This process will be defined
in the NERC Rules of Procedure and will involve individual entities or the Regional Entities having to
make a technical case to justify the exception. This process will take some time to complete and it
would be expected that there will be an initial backlog of cases to process.
Provide training – Entities will need to train their operators and personnel on changes to their
operations brought about by the revised definition.

The existing definition of BES shall be retired at midnight of the day immediately prior to the effective date of
the new definition of BES in the particular jurisdiction in which the new definition is becoming effective.

Detailed Information to Support an Exception Request

Entities that have Element(s) designated as excluded, under the BES definition and designations, do not
have to seek exception for those Elements under the Exception Procedure.
General Instructions:
A one-line breaker diagram identifying the Element(s) for which the exception is requested must be
supplied with every request. The diagram(s) supplied should also show the Protection Systems at the
interface points associated with the Elements for which the exception is being requested.
Entities are required to supply the data and studies needed to support their submittal. Studies should:
•
•
•

Be based on an Interconnection-wide base case that is suitably complete and detailed to reflect
the electrical characteristics and system topology
Clearly document all assumptions used
Address key performance measures of BES reliability through steady-state power flow, and
transient stability analysis as necessary to support the entity’s request, consistent with the
methodologies described in the Transmission Planning (TPL) standard and commensurate with
the scope of the request

Supporting statements for your position from other entities are encouraged.
List any attached supporting documents and any additional information that is included to support the
request:

1

Detailed Information to Support an Exception Request
For Transmission Elements:
1. Is there generation connected to the Element(s)?
Yes

No

If yes, what are the individual gross nameplate values of each unit?

Description/Comments:

2. How do/does the Element(s) impact permanent Flowgates in the Eastern Interconnection, major
transfer paths within the Western Interconnection, or a comparable monitored facility in the ERCOT
Interconnection or the Quebec Interconnection?
Please list the Flowgates or paths considered in your analysis along with any studies or assessments
that illustrate the degree of impact:

3. Is/Are the Element(s) included in an Interconnection Reliability Operating Limit (IROL) in the Eastern
Interconnection, ERCOT Interconnection, or Quebec Interconnection or a major transfer path rating in
the Western Interconnection?
Yes

No

Please provide the appropriate list for the operating area where the Element(s) is located:

4. How does an outage of the Element(s) impact the over-all reliability of the BES? Please provide study
results that demonstrate the most severe system impact of the outage of the Element(s) and the
rationale for your response:

2

Detailed Information to Support an Exception Request

5. Is/Are the Element(s) used for off-site power supply to a nuclear power plant as designated in a
mutually agreed upon Nuclear Plant Interface Requirement (NPIR)?
Yes

No

Description/Comments:

6. Is/Are the Element(s) part of a Cranking Path identified in a Transmission Operator’s restoration plan?
Yes

No

Description/Comments:

7. Does power flow through the Element(s) into the BES?
Yes

No

If yes, then using metered or SCADA data for the most recent consecutive two calendar year period,
what is the minimum and maximum magnitude of the power flow out of the Element(s)? Describe the
conditions and the time duration when this occurs?

3

Detailed Information to Support an Exception Request

For Generation Resources:
1. What is the MW value of the host Balancing Authority’s most severe single Contingency and what is
the generation resources percent of this value?
Please provide the values and a reference to supporting documents:

2. Is the generation resource used to provide reliability-related Ancillary Services?
Yes

No

If so, what reliability-related Ancillary Services are the generation resource supplying:

3. Is the generation resource designated as a must run unit for reliability?
Yes

No

Please provide the appropriate reference for your operating area:

4. How does an outage of the generation resource impact the over-all reliability of the BES? Please
provide study results that demonstrate the most severe system impact of the outage of the generator
and the rationale for your response:

5. Does the generation resource use the BES to deliver its actual or scheduled output, or a portion of its
actual or scheduled output, to Load?
Yes

No

Description/Comments:

4

Detailed Information to Support an Exception Request

Entities that have Element(s) designated as excluded, under the BES definition and designations, do not
have to seek exception for those Elements under the Exception Procedure.
General Instructions:
A one-line breaker diagram identifying the facility Element(s) for which the exception is requested must be
supplied with every applicationrequest. The diagram(s) supplied should also show the Protection Systems
at the interface points associated with the Elements for which the exception is being requested.
Entities are required to supply the data and studies needed to support their submittal. Studies should:
•
•
•

Be based on an Interconnection-wide base case that is suitably complete and detailed to reflect
the facility’s electrical characteristics and system topology
Clearly document all assumptions used
Address key performance measures of BES reliability through steady-state power flow, and
transient stability analysis as necessary to support the entity’s applicationrequest, consistent with
the methodologies described in the Transmission Planning (TPL) standard and commensurate
with the scope of the request

Supporting statements for your position from other entities are encouraged.
List any attached supporting documents and any additional information that is included to supports the
request:

1

Detailed Information to Support an Exception Request
For Transmission FacilitiesElements:
1. Is there generation connected to the facility Element(s)?
Yes

No

If yes, what are the individual gross nameplate values of each unit?

Description/Comments:

2. How do/does the facility Element(s) impact permanent Flowgates in the Eastern Interconnection,
major transfer paths within the Western Interconnection, or a comparable monitored facility in the
ERCOT Interconnection or the Quebec Interconnection?
Please list the Flowgates or paths considered in your analysis along with any studies or assessments
that illustrate the degree of impact:

3. Is/Are the facilityElement(s) included in an Interconnection Reliability Operating Limit (IROL) in the
Eastern Interconnection, ERCOT Interconnection, or Quebec Interconnection or a major transfer path
rating in the Western Interconnection?
Yes

No

Please provide the appropriate list for yourthe operating area where the Element(s) is located:

4. How does an outage of the facilityElement(s) impact the over-all reliability of the BES? Please provide
study results that demonstrate the most severe system impact of the outage of the facilityElement(s)
and the rationale for your response:

2

Detailed Information to Support an Exception Request

5. Is/Are the facilityElement(s) used for off-site power supply to a nuclear power plant as designated in a
mutually agreed upon Nuclear Plant Interface Requirement (NPIR)?
Yes

No

Description/Comments:

6. Is/Are the facility Element(s) part of a Cranking Path associated with a Blackstart Resource identified in
a Transmission Operator’s restoration plan?
Yes

No

Description/Comments:

7. Does power flow through this the facilityElement(s) into the BES?
Yes
If yes,

No
under 10% of the calendar year
25% - 50% of the calendar year

10% - 25% of the calendar year
More than 50% of the calendar year

If yes, then using metered or SCADA data for the most recent consecutive two calendar year period,
what is the minimum and maximum magnitude of the power flow out of the facility Element(s)? and
dDescribe the conditions and the time duration when this could occurs?

3

Detailed Information to Support an Exception Request

For Generation FacilitiesResources:
1. What is the MW value of the host Balancing Authority’s most severe single Contingency and what is
the generator’s, or generator facility’s generation resource’s, percent of this value?
Please provide the values and a reference to supporting documents:

2. Is the generator or generator facility generation resource used to provide reliability- related Ancillary
Services?
Yes

No

DescribeIf so, what reliability- related Ancillary Services are the generator or generator facility
generation resource is supplying:

3. Is the generator generation resource designated as a must run unit for reliability?
Yes

No

Please provide the appropriate reference for your operating area:

4. How does an outage of the generator generation resource impact the over-all reliability of the BES?
Please provide study results that demonstrate the most severe system impact of the outage of the
generator and the rationale for your response:

5. Does the generator generation resource use the BES to deliver its actual or scheduled output, or a
portion of its actual or scheduled output, to Load?
Yes

No

Description/Comments:

4

Standards Announcement

Project 2010-17 Definition of Bulk Electric System
Tw o Re circu la t io n Ba llo t Win d o w s Op e n : Th u r s d a y, No ve m b e r 1 0 – Mo n d a y,
No ve m b e r 2 1 , 2 0 1 1
Now Available

Two recirculation ballot windows are now open for Project 2010-17 Definition of Bulk Electric System
(BES). The first is for the definition of Bulk Electric System and the associated Implementation Plan,
and the second is for a draft application form titled Detailed Information to Support an Exception
Request referenced in the proposed Rules of Procedure BES Definition Exception Process. Both
recirculation ballots are open through 8 p.m. Eastern on Monday, November 21, 2011.
Since the initial ballot, the drafting team has considered all comments received during the formal
comment period and initial ballots of the definition and Detailed Information to Support an Exception
Request form, and made clarifying modifications to the Bulk Electric System Definition and
Implementation Plan in the following areas:
• Clarified the wording in Inclusion I1 to indicate that at least one secondary terminal
must be at 100 kV or higher to accommodate multiple terminal transformers.
•

Removed the reference to the ERO Statement of Compliance Registry Criteria in
Inclusion I2 so that there is no chance of the registry values being changed and
affecting the definition prior to resolution of threshold values in Phase 2 of this
project.

•

Clarified that generators were not part of Inclusion I5 to avoid improperly pulling in
small generators.

•

Clarified the issue of power flow into the local network in Exclusion E3.b.

•

Clarified the compliance obligation date of the revised definition in the
Implementation Plan.

The drafting team made the following clarifying modifications to the Detailed Information to Support
an Exception Request form referenced in the Rules of Procedure Exception Process:
• General – Clarified that it was the intent of the drafting team to allow an entity to
submit any data or information that it feels supports the exception request.
•

General – Clarified the use of facility versus Element(s).

•

Generation Questions:



Clarified several questions by consistently using ‘generation resource’s’
vs. ‘generator’s’ or ‘generator facility’s’.



Clarified several questions by clearly identifying reliability-related
purposes associated with the generation resources.

In response to industry concerns, the drafting team has provided a detailed explanation of the
hierarchy of the BES definition, including the proper application of the Inclusions and Exclusions for the
identification of BES Elements (See Consideration of Comments report posted on project page of the
NERC website). Additionally, the drafting team explained the rationale behind the creation of the
Detailed Information to Support an Exception Request form and the guidance it provides for evaluating
a request.
A presentation made in support of the NERC Standards and Compliance Workshop held in Atlanta, GA
on October 26 – 30, 2011 provides a detailed explanation of the ‘phased’ project approach to the
revision of the BES definition as well as addressing the modifications to the BES definition, the
Implementation Plan, and the application form titled Detailed Information to Support an Exception
Request. The presentation (audio and power-point) is available on the NERC website at the following
link: http://www.nerc.com/page.php?cid=2|247|326.
Documents associated with this project, including clean and redline copies of the definition, the
Implementation Plan, the Detailed Information to Support an Exception Request form referenced in the
Rules of Procedure Exception Process and the drafting team’s consideration of comments submitted
during the parallel formal comment period and initial ballot that ended on October 10, 2011, have
been posted on the project page.
Instructions for Balloting in the Recirculation Ballots

In a recirculation ballot, votes are counted by exception. Only members of the ballot pool may cast a
ballot; all ballot pool members may change their prior votes. A ballot pool member who failed to cast a
ballot during the last ballot window may cast a ballot in the recirculation ballot window. If a ballot pool
member does not participate in the recirculation ballot, that member’s last vote cast in the initial ballot
that ended on October 10, 2011 will be carried over and will be used to determine if there are
sufficient affirmative votes for approval.
Members of the two ballot pools associated with the definition and application form may log in and
submit their votes in the recirculation ballots from the following page:
https://standards.nerc.net/CurrentBallots.aspx.

Standards Announcement
Project 2010-17 Definition of Bulk Electric System

2

Next Steps

If the definition and application form achieve ballot pool approval, they will be presented to the Board
of Trustees for adoption and subsequently filed with regulators for approval along with the proposed
Rules of Procedure additions (Sections 509 and 1703). FERC Orders 743 and 743-A require that the
revised definition and an approach to determine exceptions be filed with FERC by January 25, 2012.
The Standards Committee and NERC Board of Trustees have recommended that the drafting team
address issues such as generation thresholds in a second phase of this project. This approach will
ensure that the drafting team has sufficient time to adequately consider and develop a sound technical
basis for an approach, and will allow the drafting team to meet the regulatory deadline in FERC Orders
743 and 743A (filing by January 25, 2012). The drafting team has posted a draft Supplemental
Standards Authorization Request (SAR) for information purposes only; the SAR will be posted for
comment at a future time.
Additional information about the project, including a Fact Sheet and additional informational
documents, has been posted on the project page.
Background

On November 18, 2010 FERC issued Order 743 (amended by Order 743A) and directed NERC to revise
the definition of Bulk Electric System so that the definition encompasses all Elements and Facilities
necessary for the reliable operation and planning of the interconnected bulk power system. Additional
specificity will reduce ambiguity and establish consistency across all Regions in distinguishing between
BES and non-BES Elements and Facilities.
In addition, NERC was directed to develop a process for identifying any Elements or Facilities that
should be excluded from the BES. NERC is working to address these directives with two activities – the
definition of Bulk Electric System is being revised through the standard development process and a BES
Definition Exception Process is being developed as proposed modifications to the Rules of Procedure.
The proposed modifications to the Rules of Procedure were posted for a comment period through
October 27, 2011.
The work of the BES Definition Exception Process (Rules of Procedure) team has been publicly posted
at: http://www.nerc.com/filez/standards/Rules_of_Procedure-RF.html.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. For more information or assistance,
please contact Monica Benson at monica.benson@nerc.net.

Standards Announcement
Project 2010-17 Definition of Bulk Electric System

3

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement
Project 2010-17 Definition of Bulk Electric System

4

Standards Announcement

Project 2010-07 Definition of Bulk Electric System
Re circu la t io n Ba llo t Re s u lt s
Now Available

Two recirculation ballots, for the definition of Bulk Electric System (BES) and for the application form
titled ‘Detailed Information to Support a Request for a BES Exception,’ closed on November 21, 2011.
Both recirculation ballots achieved stakeholder approval.
Voting statistics for each ballot are listed below, and the Ballot Results Web page provides a link to the
detailed results.

BES Definition

Detailed Information to Support a
Request for BES Exception

Quorum: 95.92%

Quorum: 93.02%

Approval: 81.32%

Approval: 81.48%

Next Steps
The definition of Bulk Electric System, its associated implementation plan and the supporting
application form titled ‘Detailed Information to Support a BES Exception Request’ will be presented to
the NERC Board of Trustees for adoption and subsequently filed with regulatory authorities. A set of
proposed changes to the Rules of Procedure to provide a process for determining exceptions to the
definition of BES is near completion and will be presented to the NERC Board of trustees for approval at
the same time as the BES definition. The regulatory deadline in FERC Orders 743 and 743A requires
that the revised definition of BES and process for handling exceptions be filed by January 25, 2012.
Additional information about the project, including a Fact Sheet and additional informational
documents, has been posted on the project page.
Background
On November 18, 2010 FERC issued Order 743 (amended by Order 743A) and directed NERC to revise
the definition of Bulk Electric System so that the definition encompasses all Elements and Facilities
necessary for the reliable operation and planning of the interconnected bulk power system. Additional
specificity will reduce ambiguity and establish consistency across all Regions in distinguishing between
BES and non-BES Elements and Facilities.

In addition, NERC was directed to develop a process for identifying any Elements or Facilities that
should be excluded from the BES. NERC addressed these directives with two activities – the definition
of Bulk Electric System was revised through the standard development process and a BES Definition
Exception Process has been developed as proposed modifications to the Rules of Procedure. The work
of the BES Definition Exception Process has been publicly posted at:
http://www.nerc.com/filez/standards/Rules_of_Procedure-RF.html.
Standards Development Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. For more information or assistance,
please contact Monica Benson at monica.benson@nerc.net.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement Project 2010-17
BES Definition and BES Exception

2

NERC Standards

Newsroom  •  Site Map  •  Contact NERC

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Ballot Results

Ballot Name: Project 2010-17 BES Definition_Initial Ballot_rc

Password

Ballot Period: 11/10/2011 - 11/21/2011
Ballot Type: recirculation

Log in

Total # Votes: 423

Register

Total Ballot Pool: 441
Quorum: 95.92 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
81.32 %
Vote:
Ballot Results: The Standard has Passed

 Home Page
Summary of Ballot Results

Affirmative
Segment

1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight

102
11
125
35
86
51
1
11
12
7
441

#
Votes

1
0.9
1
1
1
1
0.1
0.9
1
0.7
8.6

#
Votes

Fraction

81
6
107
30
64
43
1
7
5
6
350

Negative
Fraction

0.862
0.6
0.947
0.938
0.831
0.915
0.1
0.7
0.5
0.6
6.993

Abstain
No
# Votes Vote

13
3
6
2
13
4
0
2
5
1
49

0.138
0.3
0.053
0.063
0.169
0.085
0
0.2
0.5
0.1
1.608

7
2
4
2
4
4
0
1
0
0
24

1
0
8
1
5
0
0
1
2
0
18

Individual Ballot Pool Results

Segment

1
1
1
1
1
1
1
1

Organization

Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Balancing Authority of Northern California
Baltimore Gas & Electric Company

Member

Ballot

Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
James Armke
Kevin Smith
Gregory S Miller

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Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative

Comments

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NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Power Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lakeland Electric
Lee County Electric Cooperative
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
Memphis Light, Gas and Water Division
Metropolitan Water District of Southern
California
Mid-Continent Area Power Pool
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid
New Brunswick Power Transmission
Corporation
New York Power Authority
North Carolina Electric Membership Corp.
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company

Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
Dale Bodden
Michael B Bax
Kevin L Howes

Abstain
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Negative

Chang G Choi

Affirmative

Danny McDaniel
Paul Morland
Christopher L de Graffenried
Stuart Sloan
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

Bob Solomon

Affirmative

Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza

Negative
Negative
Affirmative
Affirmative

Michael Moltane

Affirmative

Walter Kenyon
Michael Gammon
Larry E Watt
John W Delucca
Robert Ganley
Ly M Le
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Allan Long

Affirmative
Affirmative
Affirmative
Affirmative
Negative

Ernest Hahn

View

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View

View

View
View

View

View

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Negative

View

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain

Randy MacDonald

Negative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=a7c0e234-6e24-45ab-9e57-841a78ceb175[11/22/2011 9:35:27 AM]

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Negative
Affirmative
Affirmative
Affirmative
Affirmative

Larry E. Brusseau
Terry Harbour
Richard Burt
Tim Reed
Mark Ramsey
Saurabh Saksena

Arnold J. Schuff
Gary Ofner
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson

View

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

View

View
View
View
View

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View

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NERC Standards
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1
1
1
1
1
1
1

1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2

PECO Energy
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
South Texas Electric Cooperative
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Transmission Agency of Northern California
Tri-State G & T Association, Inc.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
Alberta Electric System Operator

2

BC Hydro

2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
BC Hydro and Power Authority
Benton Rural Electric Association
Big Bend Electric Cooperative, Inc.
Blachly-Lane Electric Co-op
Blue Ridge Electric
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Electric Power Cooperative
Central Hudson Gas & Electric Corp.
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Cheney
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs

1

3
3
3
3
3
3
3
3
3
3
3

Ronald Schloendorn
John C. Collins
John T Walker
David Thorne
Brenda L Truhe
Brett A Koelsch
Laurie Williams
Kenneth D. Brown

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

View

Dale Dunckel

Affirmative

Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Richard McLeon
James Jones
Noman Lee Williams
Beth Young
Larry Akens
Bryan Griess
Tracy Sliman
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Michelle Denike
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Charles B Manning
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Pat G. Harrington
Clint Gerkensmeyer
Benjamin Friederichs
Bud Tracy
James L Layton
Rebecca Berdahl

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Abstain
Affirmative

Dave Markham

Affirmative

Ralph J Schulte
Thomas C Duffy
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Joe Noland
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

View

Affirmative
Abstain
Affirmative

View

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View
View
View
View
View
View
View
View
View

View

Abstain
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

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View

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NERC Standards
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3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

City of McMinnville
City of Redding
City of Ukiah
Clatskanie People's Utility District
Clay Electric Cooperative
Clearwater Power Co.
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Dominion Resources Services
Douglas Electric Cooperative
Duke Energy Carolina
East Kentucky Power Coop.
Fall River Rural Electric Cooperative
Fayetteville Public Works Commission
FirstEnergy Energy Delivery
Flathead Electric Cooperative
Florida Municipal Power Agency
Florida Power Corporation
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Idaho Falls Power
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Kootenai Electric Cooperative
La Plata Electric Association
Lakeview Light & Power
Lane Electric Cooperative, Inc.
Lincoln Electric Cooperative, Inc.
Lincoln Electric System
Lost River Electric Cooperative
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
Manitowoc Public Utilities
MidAmerican Energy Co.
Mission Valley Power
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Northern Lights Inc.
Northern Wasco County People's Utility
District (PUD)
NW Electric Power Cooperative, Inc.
Okanogan County Electric Cooperative, Inc.
Omaha Public Power District

John C Dietz
Bill Hughes
Colin Murphey
Brian Fawcett
Howard M. Mott Jr.
Dave Hagen
Michelle A Corley
Lisa Cleary
Bruce Krawczyk
Peter T Yost
CJ Ingersoll
Richard Blumenstock
Roman Gillen
Roger Meader
Russell A Noble
Jose Escamilla
Michael R. Mayer
Michael F. Gildea
Dave Sabala
Henry Ernst-Jr
Patrick Woods
Bryan Case
Allen R Wallace
Stephan Kern
John M Goroski
Joe McKinney
Lee Schuster
William N. Phinney
Wesley W Gray
Sam Kokkinen
Shane Sweet
William Bush
David Kiguel
Richard Malloy
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Dave Kahly
Ronald Meier
Robert Truesdell
Rick Crinklaw
Michael Henry
Jason Fortik
Richard Reynolds
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas E Reed
Thomas C. Mielnik
Kerry Wiedrich
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
Skyler Wiegmann
William SeDoris
Jon Shelby

Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative

Paul Titus

Affirmative

David McDowell
Ray Ellis
Blaine R. Dinwiddie

Affirmative
Affirmative
Negative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=a7c0e234-6e24-45ab-9e57-841a78ceb175[11/22/2011 9:35:27 AM]

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

View
View
View

View
View
View
View
View

View
View
View
View
View
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View

View
View

View
View
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Affirmative
Affirmative
Affirmative
Affirmative

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NERC Standards
3
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3
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3
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3
3
3
3
3
3
3
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3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4

Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Clallam County
Public Utility District No. 1 of Franklin County
Public Utility District No. 2 of Grant County
Raft River Rural Electric Cooperative
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salem Electric
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Southern California Edison Co.
Springfield Utility Board
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Umatilla Electric Cooperative
Vigilante Electric Cooperative
West Oregon Electric Cooperative, Inc.
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
American Public Power Association
Arkansas Electric Cooperative Corporation
Central Lincoln PUD
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
LaGen
Madison Gas and Electric Co.
Modesto Irrigation District
National Rural Electric Cooperative
Association
North Carolina Eastern Municipal Power
Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Pacific Northwest Generating Cooperative
Public Power Council
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County

David Burke
ned ratterman
Ballard K Mutters
Thomas T Lyons
John H Hagen
John Apperson
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
David Proebstel
Linda Esparza
Greg Lange
Heber Carpenter
Eddy Reece
Thomas M Haire
James Leigh-Kendall
Anthony Schacher
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
David Schiada
Jeff Nelson
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Steve Eldrige
Dave Alberi
Marc M Farmer
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Ronnie Frizzell
Shamus J Gamache
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Bob C. Thomas
Diana U Torres
Jack Alvey
Christopher Plante
Richard Comeaux
Joseph DePoorter
Spencer Tacke

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

View

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

View
View

Affirmative
Affirmative
Affirmative

View

Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative

Barry R. Lawson

Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Cecil Rhodes

Affirmative

Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Aleka K Scott
Nancy Baker
Henry E. LuBean

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

John D Martinsen

Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=a7c0e234-6e24-45ab-9e57-841a78ceb175[11/22/2011 9:35:27 AM]

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NERC Standards
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5

Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Transmission Access Policy Study Group
Western Montana Electric G&T
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
BC Hydro and Power Authority
Black Hills Corp
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Grand Island
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Cleco Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Covanta Energy
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
East Kentucky Power Coop.
Electric Power Supply Association
Entegra Power Group, LLC
Exelon Nuclear
ExxonMobil Research and Engineering
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Michigan Public Power Agency
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.

Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
William Gallagher
William Drummond
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Brad Haralson
Clement Ma
George Tatar

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative

View

View
View

Mike D Kukla
Francis J. Halpin
Chifong Thomas
Daniel Mason
Jeanie Doty
Jeff Mead
Paul Cummings

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative

Max Emrick

Affirmative

Brian Horton
Stephanie Huffman
Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Samuel Cabassa
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Stephen Ricker
John R Cashin
Kenneth B Parker
Michael Korchynsky
Martin Kaufman
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Alan Beckham
John J Babik
Mike Blough
James M Howard
Dennis Florom
Kenneth Silver
Tom Foreman
S N Fernando

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative

David Gordon
Steven Grego
Gary Carlson
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson

https://standards.nerc.net/BallotResults.aspx?BallotGUID=a7c0e234-6e24-45ab-9e57-841a78ceb175[11/22/2011 9:35:27 AM]

Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

View

View

View

View
View

View
View

View
View

View

Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative

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NERC Standards
5
5
5
5
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5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
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5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
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6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6

Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Westar Energy
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
MidAmerican Energy Co.
Muscatine Power & Water
New York Power Authority
North Carolina Municipal Power Agency #1
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project

Richard Kinas
Stacie Hebert
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Tim Hattaway
Annette M Bannon
Wayne Lewis
Mikhail Falkovich
Steven Grega
Tom Flynn
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Bo Jones
Linda Horn
Leonard Rentmeester
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daniel Prowse
Dennis Kimm
John Stolley
William Palazzo
Matthew Schull
Joseph O'Brien
Alan Johnson
David Ried
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Claire Warshaw
Steven J Hulet

https://standards.nerc.net/BallotResults.aspx?BallotGUID=a7c0e234-6e24-45ab-9e57-841a78ceb175[11/22/2011 9:35:27 AM]

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

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NERC Standards
6
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8
8
8
8
8
8
9
9
9
9
9
9
9
9
9
9
9
9
10
10
10
10
10
10
10

Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Tacoma Public Utilities
Tampa Electric Co.
Tenaska Power Services Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
Siemens Energy, Inc.

INTELLIBIND
JDRJC Associates
Montana Consumer Counsel
Pacific Northwest Generating Cooperative
Transmission Strategies, LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
Alabama Public Service Commission
California Energy Commission
Central Lincoln PUD
Commonwealth of Massachusetts Department
of Public Utilities
Michigan Public Service Commission
National Association of Regulatory Utility
Commissioners
New Hampshire Public Utilities Commission
New York State Department of Public Service
Oregon Public Utility Commission
Pennsylvania Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Michael C Hill
Benjamin F Smith II
John D Varnell
Marjorie S. Parsons

Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Abstain
Affirmative

Peter H Kinney

Affirmative

David F. Lemmons
Frank R. McElvain
Roger C Zaklukiewicz
Edward C Stein
Merle Ashton
James A Maenner
Kevin Conway
Jim Cyrulewski
Larry Nordell
Margaret Ryan
Bernie M Pasternack
Brian Evans-Mongeon
Terry Volkmann
John Free
William M Chamberlain
Bruce Lovelin

Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative

Donald Nelson

View
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View

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View

Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

View
View

Negative

View

Negative

View

Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative

View
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Donald J Mazuchowski
Diane J Barney
Michael Harrington
Thomas Dvorsky
Jerome Murray
darren gill
Philip Riley
Ric Campbell
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Stacy Dochoda
Donald G Jones
Steven L. Rueckert

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https://standards.nerc.net/BallotResults.aspx?BallotGUID=a7c0e234-6e24-45ab-9e57-841a78ceb175[11/22/2011 9:35:27 AM]

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NERC Standards

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Ballot Results

Ballot Name: Project 2010-17 Technical Information to Support BES Exception_rc

Password

Ballot Period: 11/10/2011 - 11/21/2011
Ballot Type: recirculation

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Total # Votes: 400

Register

Total Ballot Pool: 430
Quorum: 93.02 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
81.48 %
Vote:
Ballot Results: The Standard has Passed

 Home Page
Summary of Ballot Results

Affirmative
Segment

1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight

99
11
124
34
82
50
1
11
11
7
430

#
Votes

1
1
1
1
1
1
0
1
0.9
0.7
8.6

#
Votes

Fraction

75
6
98
28
54
41
0
8
6
6
322

Negative
Fraction

0.852
0.6
0.925
0.933
0.806
0.891
0
0.8
0.6
0.6
7.007

Abstain
No
# Votes Vote

13
4
8
2
13
5
0
2
3
1
51

0.148
0.4
0.075
0.067
0.194
0.109
0
0.2
0.3
0.1
1.593

8
1
4
2
6
4
0
0
2
0
27

3
0
14
2
9
0
1
1
0
0
30

Individual Ballot Pool Results

Segment

1
1
1
1
1
1
1
1

Organization

Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Balancing Authority of Northern California
Baltimore Gas & Electric Company

Member

Ballot

Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
James Armke
Kevin Smith
Gregory S Miller

https://standards.nerc.net/BallotResults.aspx?BallotGUID=6bda29ab-90aa-4f0d-b6bd-6bbb251c71aa[11/22/2011 9:36:10 AM]

Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Affirmative

Comments

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NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

BC Hydro and Power Authority
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Power Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Entergy Services, Inc.
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
Imperial Irrigation District
International Transmission Company Holdings
Corp
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Lakeland Electric
Lee County Electric Cooperative
Long Island Power Authority
Los Angeles Department of Water & Power
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
Memphis Light, Gas and Water Division
Metropolitan Water District of Southern
California
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
N.W. Electric Power Cooperative, Inc.
National Grid
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
PECO Energy
Platte River Power Authority

Patricia Robertson
Joseph S Stonecipher
Eric Egge
Donald S. Watkins
Tony Kroskey
Dale Bodden
Michael B Bax
Kevin L Howes

Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Negative

Chang G Choi

Affirmative

Danny McDaniel
Paul Morland
Christopher L de Graffenried
Stuart Sloan
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
Michael S Crowley
Douglas E. Hils
George S. Carruba
Edward J Davis
William J Smith
Dennis Minton
Mike O'Neil
Luther E. Fair
Harold Taylor
Gordon Pietsch

Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

Bob Solomon

Affirmative

Ajay Garg
Bernard Pelletier
Ronald D. Schellberg
Tino Zaragoza

Negative
Negative
Affirmative
Affirmative

Michael Moltane

Affirmative

Ted Hobson
Walter Kenyon
Michael Gammon
Larry E Watt
John W Delucca
Robert Ganley
Ly M Le
Martyn Turner
William Price
Joe D Petaski
Danny Dees
Allan Long

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

View

View
View
View

View

View

View

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View

Negative
Affirmative
Negative
Affirmative
Abstain

View

Negative

View

Terry Harbour
Richard Burt
Mark Ramsey
Saurabh Saksena

Affirmative
Affirmative
Affirmative

View

Randy MacDonald

Negative

Ernest Hahn

Arnold J. Schuff
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Brenda Pulis
Brad Chase
Daryl Hanson
Ronald Schloendorn
John C. Collins

https://standards.nerc.net/BallotResults.aspx?BallotGUID=6bda29ab-90aa-4f0d-b6bd-6bbb251c71aa[11/22/2011 9:36:10 AM]

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

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NERC Standards
1
1
1
1
1

1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2

Portland General Electric Co.
Potomac Electric Power Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South California Edison Company
South Texas Electric Cooperative
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Transmission Agency of Northern California
Tri-State G & T Association, Inc.
United Illuminating Co.
Vermont Electric Power Company, Inc.
Westar Energy
Western Area Power Administration
Wolverine Power Supply Coop., Inc.
Alberta Electric System Operator

2

BC Hydro

2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alameda Municipal Power
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
BC Hydro and Power Authority
Benton Rural Electric Association
Big Bend Electric Cooperative, Inc.
Blachly-Lane Electric Co-op
Blue Ridge Electric
Bonneville Power Administration
Central Electric Cooperative, Inc. (Redmond,
Oregon)
Central Electric Power Cooperative
Central Hudson Gas & Electric Corp.
Central Lincoln PUD
City of Austin dba Austin Energy
City of Bartow, Florida
City of Cheney
City of Clewiston
City of Farmington
City of Garland
City of Green Cove Springs
City of McMinnville
City of Redding
City of Ukiah

1

3
3
3
3
3
3
3
3
3
3
3
3
3
3

John T Walker
David Thorne
Brenda L Truhe
Laurie Williams
Kenneth D. Brown

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Dale Dunckel

Affirmative

Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Steven Mavis
Richard McLeon
James Jones
Noman Lee Williams
Beth Young
Larry Akens
Bryan Griess
Tracy Sliman
Jonathan Appelbaum
Kim Moulton
Allen Klassen
Brandy A Dunn
Michelle Denike
Mark B Thompson
Venkataramakrishnan
Vinnakota
Rich Vine
Charles B Manning
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
Tom Bowe
Charles Yeung
Michael E Deloach
Douglas Draeger
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Pat G. Harrington
Clint Gerkensmeyer
Benjamin Friederichs
Bud Tracy
James L Layton
Rebecca Berdahl

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Abstain
Affirmative

Affirmative

View

Dave Markham

Affirmative

View

Ralph J Schulte
Thomas C Duffy
Steve Alexanderson
Andrew Gallo
Matt Culverhouse
Joe Noland
Lynne Mila
Linda R Jacobson
Ronnie C Hoeinghaus
Gregg R Griffin
John C Dietz
Bill Hughes
Colin Murphey

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=6bda29ab-90aa-4f0d-b6bd-6bbb251c71aa[11/22/2011 9:36:10 AM]

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Abstain
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative

Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative

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NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

Clatskanie People's Utility District
Clay Electric Cooperative
Clearwater Power Co.
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Constellation Energy
Consumers Energy
Consumers Power Inc.
Coos-Curry Electric Cooperative, Inc
Cowlitz County PUD
CPS Energy
Delmarva Power & Light Co.
Dominion Resources Services
Douglas Electric Cooperative
Duke Energy Carolina
Fall River Rural Electric Cooperative
Fayetteville Public Works Commission
FirstEnergy Energy Delivery
Flathead Electric Cooperative
Florida Municipal Power Agency
Florida Power Corporation
Georgia Systems Operations Corporation
Grays Harbor PUD
Great River Energy
Harney Electric Cooperative, Inc.
Holland Board of Public Works
Hydro One Networks, Inc.
Idaho Falls Power
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Kootenai Electric Cooperative
La Plata Electric Association
Lakeview Light & Power
Lane Electric Cooperative, Inc.
Lincoln Electric Cooperative, Inc.
Lincoln Electric System
Lost River Electric Cooperative
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
Manitowoc Public Utilities
MidAmerican Energy Co.
Mission Valley Power
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
North Carolina Electric Membership Corp.
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
Northern Lights Inc.
Northern Wasco County People's Utility
District (PUD)
NW Electric Power Cooperative, Inc.
Okanogan County Electric Cooperative, Inc.
Omaha Public Power District
Orange and Rockland Utilities, Inc.
Oregon Trail Electric Cooperative
Orlando Utilities Commission

Brian Fawcett
Howard M. Mott Jr.
Dave Hagen
Michelle A Corley
Lisa Cleary
Bruce Krawczyk
Peter T Yost
CJ Ingersoll
Richard Blumenstock
Roman Gillen
Roger Meader
Russell A Noble
Jose Escamilla
Michael R. Mayer
Michael F. Gildea
Dave Sabala
Henry Ernst-Jr
Bryan Case
Allen R Wallace
Stephan Kern
John M Goroski
Joe McKinney
Lee Schuster
William N. Phinney
Wesley W Gray
Sam Kokkinen
Shane Sweet
William Bush
David Kiguel
Richard Malloy
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Dave Kahly
Ronald Meier
Robert Truesdell
Rick Crinklaw
Michael Henry
Jason Fortik
Richard Reynolds
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas E Reed
Thomas C. Mielnik
Kerry Wiedrich
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
Doug White
Skyler Wiegmann
William SeDoris
Jon Shelby

Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
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Affirmative
Affirmative
Affirmative
Negative
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Affirmative
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Paul Titus
David McDowell
Ray Ellis
Blaine R. Dinwiddie
David Burke
ned ratterman
Ballard K Mutters

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Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Clallam County
Public Utility District No. 1 of Franklin County
Public Utility District No. 2 of Grant County
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salem Electric
Salmon River Electric Cooperative
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
South Carolina Electric & Gas Co.
Southern California Edison Co.
Springfield Utility Board
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Umatilla Electric Cooperative
Vigilante Electric Cooperative
West Oregon Electric Cooperative, Inc.
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power
American Public Power Association
Arkansas Electric Cooperative Corporation
Central Lincoln PUD
City of Clewiston
City of Redding
City Utilities of Springfield, Missouri
Consumers Energy
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Illinois Municipal Electric Agency
Imperial Irrigation District
Indiana Municipal Power Agency
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
National Rural Electric Cooperative
Association
North Carolina Eastern Municipal Power
Agency
Ohio Edison Company
Oklahoma Municipal Power Authority
Old Dominion Electric Coop.
Pacific Northwest Generating Cooperative
Public Power Council
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Transmission Access Policy Study Group

Thomas T Lyons
John H Hagen
John Apperson
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
David Proebstel
Linda Esparza
Greg Lange
Eddy Reece
Thomas M Haire
James Leigh-Kendall
Anthony Schacher
Ken Dizes
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Hubert C Young
David Schiada
Jeff Nelson
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Steve Eldrige
Dave Alberi
Marc M Farmer
James R Keller
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Ronnie Frizzell
Shamus J Gamache
Kevin McCarthy
Nicholas Zettel
John Allen
David Frank Ronk
Russ Schneider
Frank Gaffney
Thomas Richards
Guy Andrews
Bob C. Thomas
Diana U Torres
Jack Alvey
Christopher Plante
Joseph DePoorter
Spencer Tacke

Affirmative
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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative

Barry R. Lawson

Affirmative

Cecil Rhodes

Affirmative

Douglas Hohlbaugh
Ashley Stringer
Mark Ringhausen
Aleka K Scott
Nancy Baker
Henry E. LuBean

Affirmative
Affirmative
Affirmative
Affirmative

John D Martinsen

Affirmative

Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
William Gallagher

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=6bda29ab-90aa-4f0d-b6bd-6bbb251c71aa[11/22/2011 9:36:10 AM]

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NERC Standards
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Western Montana Electric G&T
AEP Service Corp.
AES Corporation
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Grand Island
City of Redding
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
Cogentrix Energy, Inc.
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Power Source Generation, Inc.
Consumers Energy Company
Covanta Energy
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
Dynegy Inc.
East Kentucky Power Coop.
Electric Power Supply Association
Exelon Nuclear
ExxonMobil Research and Engineering
Florida Municipal Power Agency
Great River Energy
Green Country Energy
Imperial Irrigation District
Indeck Energy Services, Inc.
Invenergy LLC
JEA
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Michigan Public Power Agency
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
North Carolina Electric Membership Corp.
Northern Indiana Public Service Co.
Occidental Chemical
Oklahoma Gas and Electric Co.
Omaha Public Power District
Ontario Power Generation Inc.
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
Proven Compliance Solutions

William Drummond
Brock Ondayko
Leo Bernier
Sam Dwyer
Edward Cambridge
Brad Haralson
Clement Ma

Affirmative
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Mike D Kukla
Francis J. Halpin
Chifong Thomas
Daniel Mason
Jeanie Doty
Jeff Mead
Paul Cummings

Affirmative
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Abstain
Affirmative
Abstain
Affirmative

Max Emrick

Affirmative

Mike D Hirst
Jennifer Eckels
Wilket (Jack) Ng
Amir Y Hammad
David C Greyerbiehl
Samuel Cabassa
Robert Stevens
Christy Wicke
Mike Garton
Dale Q Goodwine
Dan Roethemeyer
Stephen Ricker
John R Cashin
Michael Korchynsky
Martin Kaufman
David Schumann
Preston L Walsh
Greg Froehling
Marcela Y Caballero
Rex A Roehl
Alan Beckham
John J Babik
Mike Blough
James M Howard
Dennis Florom
Kenneth Silver
Tom Foreman
S N Fernando

Abstain
Affirmative
Affirmative
Affirmative
Negative

David Gordon
Steven Grego
Gary Carlson
Christopher Schneider
Mike Avesing
Don Schmit
Gerald Mannarino
Jeffrey S Brame
William O. Thompson
Michelle R DAntuono
Kim Morphis
Mahmood Z. Safi
Colin Anderson
Richard Kinas
Stacie Hebert
Sandra L. Shaffer
Roland Thiel
Gary L Tingley
Tim Hattaway
Annette M Bannon
Wayne Lewis
Mitchell E Needham

https://standards.nerc.net/BallotResults.aspx?BallotGUID=6bda29ab-90aa-4f0d-b6bd-6bbb251c71aa[11/22/2011 9:36:10 AM]

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Negative
Abstain
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Negative
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Negative
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NERC Standards
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PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
North Carolina Municipal Power Agency #1
Northern Indiana Public Service Co.
NRG Energy, Inc.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South California Edison Company
Tacoma Public Utilities
Tampa Electric Co.
Tenaska Power Services Co.
Tennessee Valley Authority

Mikhail Falkovich
Steven Grega
Tom Flynn
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Denise Yaffe
William D Shultz
RJames Rocha
Scott M Helyer
David Thompson
Barry Ingold
Melissa Kurtz
Linda Horn
Leonard Rentmeester
Edward P. Cox
Jennifer Richardson
RANDY A YOUNG
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Lisa C Rosintoski
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daniel Prowse
Dennis Kimm
William Palazzo
Matthew Schull
Joseph O'Brien
Alan Johnson
David Ried
Claston Augustus Sunanon
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
Peter Dolan
Hugh A. Owen
Claire Warshaw
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
William T Moojen
Lujuanna Medina
Michael C Hill
Benjamin F Smith II
John D Varnell
Marjorie S. Parsons

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Negative
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Affirmative
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NERC Standards
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Xcel Energy, Inc.
Siemens Energy, Inc.

INTELLIBIND
JDRJC Associates
Montana Consumer Counsel
Pacific Northwest Generating Cooperative
Transmission Strategies, LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
Alabama Public Service Commission
California Energy Commission
Central Lincoln PUD
Commonwealth of Massachusetts Department
of Public Utilities
Michigan Public Service Commission
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Oregon Public Utility Commission
Pennsylvania Public Utility Commission
Public Service Commission of South Carolina
Utah Public Service Commission
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool RE
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

David F. Lemmons
Frank R. McElvain
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Merle Ashton
Kevin Conway
Jim Cyrulewski
Larry Nordell
Margaret Ryan
Bernie M Pasternack
Brian Evans-Mongeon
Terry Volkmann
John Free
William M Chamberlain
Bruce Lovelin

Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Donald Nelson

Affirmative

Diane J Barney

Negative

Thomas Dvorsky
Jerome Murray
darren gill
Philip Riley
Ric Campbell
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Stacy Dochoda
Donald G Jones
Steven L. Rueckert

https://standards.nerc.net/BallotResults.aspx?BallotGUID=6bda29ab-90aa-4f0d-b6bd-6bbb251c71aa[11/22/2011 9:36:10 AM]

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Negative
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Legal and Privacy  :  609.452.8060 voice  :  609.452.9550 fax  :  116-390 Village Boulevard  :  Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801

Copyright © 2010 by the North American Electric Reliability Corporation.  :  All rights reserved.
A New Jersey Nonprofit Corporation

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Donald J Mazuchowski

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Standards Authorization Request
Title of Proposed Standard
definition

NERC Glossary of Terms - Phase 2: Revision of the Bulk Electric System

Request Date

December 2, 2011

SAR Type

SAR Requester Information

(Check all that apply)

Name: Project 2010-17 Definition of Bulk Electric
System (BES) SDT
Primary Contact: Peter Heidrich (Manager of
Reliability Standards, FRCC) , Project 2010-17
Definition of Bulk Electric System (BES) SDT Chair
Telephone: (813) 207-7994
Fax: (813) 289-5646
E-mail: pheidrich@frcc.com

New Standard

X

Revision to existing Standard

Withdrawal of existing Standard
Urgent Action

SAR Information

Industry Need (What is the industry problem this request is trying to solve?)
This project supports the ERO’s obligation to identify the Elements necessary for the reliable operation
of the interconnected transmission network to ensure that the ERO, the Regional Entities, and the
industry have the ability to properly identify the applicable entities and Elements subject to the NERC
Reliability Standards.
Purpose or Goal (How does this request propose to address the problem described above?)
Research possible revisions to the definition of BES (Phase 2) to address the issues identified through
Project 2010-17 Definition of Bulk Electric System (BES) (Phase 1). The definition encompasses all
Elements necessary for the reliable operation of the interconnected transmission network. The
definition development may include other improvements to the definition as deemed appropriate by
the drafting team, with the consensus of stakeholders, consistent with establishing a high quality and

Standards Authorization Request

SAR Information

technically sound definition of the Bulk Electric System (BES).
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?)
Revise the BES definition to identify the appropriate electrical components necessary for the reliable
operation of the interconnected transmission network.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
Collect and analyze information needed to support revisions to the definition of Bulk Electric System
(BES) developed in Phase 1 of this project to provide a technically justifiable definition that identifies
the appropriate electrical components necessary for the reliable operation of the interconnected
transmission network. The definition development may include other improvements to the definition
as deemed appropriate by the drafting team, with the consensus of stakeholders, consistent with
establishing a high quality and technically sound definition of the BES.
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of
implementing or not implementing the standard action.)
Collect and analyze information needed to support revisions to the definition of BES developed in
Phase 1 of this project to provide a technically justifiable definition that identifies the appropriate
electrical components necessary for the reliable operation of the interconnected transmission
network. The definition development will include an analysis of the following issues which were
identified during the development of Phase 1 of Project 2010-17 Definition of the BES. Clarification of
these issues will appropriately define which Elements are necessary for the reliable operation of the
interconnected transmission network.
•
•
•
•
•

Develop a technical justification to set the appropriate threshold for Real and Reactive
Resources used in the operation of the Bulk Electric System (BES)
Determine if there is a technical justification to support the assumption that there is a
reliability benefit of a contiguous BES
Determine if there is technical justification for including the equipment which “supports” the
reliable operation of the BES
Determine if there is a technical justification to support an automatic interrupting device in
Exclusions E1 and E3
Determine if there is a technical justification to support the inclusion of Cranking Paths and

SAR- Phase 2: Revision of the Bulk Electric System definition

2

Standards Authorization Request

SAR Information

Blackstart Resources
•
•

Determine if there is a technical justification for selection of 100 kV as the bright-line voltage
level
Determine if there is a technical justification to support allowing power flow out of the local
network under certain conditions and if so, what the maximum allowable flow should be

Provide improved clarity to the following:
•
•
•

The relationship between the BES definition and the ERO Statement of Compliance Registry
Criteria established in FERC Order 693
The use of the term “non-retail generation”
The language for Inclusion I4 on dispersed power resources

•

The appropriate ‘points of demarcation’ between Transmission, Generation, and Distribution

Phase 2 of the definition development may include other improvements to the definition as deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent with establishing a
high quality and technically justifiable definition of the BES.
Based on the potential revisions to the definition of the BES and an analysis of the application of, and
the results from, the exception process, the drafting team will review and if necessary propose
revisions to the ‘Technical Principles’ associated with the Rules of Procedure Exception Process to
ensure consistency in the application of the definition and the exception process.
Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that
applies.)

This section is not applicable as the SAR is for a definition which is about Elements. Elements of the
BES may impact all functions, however Applicability to entities is covered in Section 4 of each
Reliability Standard.
Regional
Reliability
Organization

Conducts the regional activities related to planning and operations,
and coordinates activities of Responsible Entities to secure the
reliability of the Bulk Electric System within the region and adjacent
regions.

SAR- Phase 2: Revision of the Bulk Electric System definition

3

Standards Authorization Request

The Standard will Apply to the Following Functions (Check box for each one that
applies.)

Reliability
Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing
Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.

Interchange
Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.

Planning
Coordinator

Assesses the longer-term reliability of its Planning Coordinator Area.

Resource
Planner

Develops a >one year plan for the resource adequacy of its specific
loads within a Planning Coordinator area.

Transmission
Planner

Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within its portion of the Planning Coordinator
area.

Administers the transmission tariff and provides transmission
Transmission
services under applicable transmission service agreements (e.g., the
Service Provider
pro forma tariff).
Transmission
Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.

Distribution
Provider

Delivers electrical energy to the End-use customer.

Generator
Owner

Owns and maintains generation facilities.

Generator

Operates generation unit(s) to provide real and reactive power.

SAR- Phase 2: Revision of the Bulk Electric System definition

4

Standards Authorization Request

The Standard will Apply to the Following Functions (Check box for each one that
applies.)

Operator
PurchasingSelling Entity

Purchases or sells energy, capacity, and necessary reliability-related
services as required.

Market
Operator

Interface point for reliability functions with commercial functions.

Load-Serving
Entity

Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.

Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
X

1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.

X

2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.

X

3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and operating
the systems reliably.

X

4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.

X

5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.

X

6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.

SAR- Phase 2: Revision of the Bulk Electric System definition

5

Standards Authorization Request

Applicable Reliability Principles (Check box for all that apply.)
X

7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.

X

8. Bulk power systems shall be protected from malicious physical or cyber attacks.

Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)

1. A reliability standard shall not give any market participant an unfair competitive advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially nonsensitive information that is required for compliance with reliability standards. Yes
Related Standards
Standard No.

Explanation

Related SARs
SAR ID

Explanation

SAR- Phase 2: Revision of the Bulk Electric System definition

6

Standards Authorization Request

SAR ID

Explanation

Regional Variances
Region

Explanation

ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC

SAR- Phase 2: Revision of the Bulk Electric System definition

7

Project 2010-17 Definition of Bulk Electric System

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.

Development Steps Completed
1. SAR posted for comment 12/17/10 – 1/21/11
2. SC authorized moving the SAR forward to standard development 3/25/11
3. First posting of definition 4/28/11 – 5/27/11
4. First posting of criteria 5/11/11 – 6/10/11
5. Second posting of definition and criteria plus initial ballot 8/26/11 – 10/10/11

Description of Current Draft
This draft is the third posting and recirculation ballot of the revised definition of the Bulk
Electric System (BES). It is for a 10-day recirculation voting period.

Anticipated Actions

Anticipated Date

30-day Formal Comment Period

4/28/11

45-day Formal Comment Period with Parallel Initial Ballot

September 2011

Recirculation ballot

November 2011

BOT adoption

January 2012

Dra ft #2: Da te

Page 1 of 4

Project 2010-17 Definition of Bulk Electric System

Effective Dates
This definition shall become effective on the first day of the second calendar quarter after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
the definition will go into effect on the first day of the second calendar quarter after Board of
Trustees adoption. Compliance obligations for Elements included by the definition shall begin
24 months after the applicable effective date of the definition.

Version History

Version
1

Dra ft #2: Da te

Date
TBD

Action

Change
Tracking

Respond to FERC Order No. 743 to
N/A
clarify the definition of the Bulk Electric
System

Page 2 of 4

Project 2010-17 Definition of Bulk Electric System

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
Bulk Electric System (BES): Unless modified by the lists shown below, all Transmission
Elements operated at 100 kV or higher and Real Power and Reactive Power resources connected
at 100 kV or higher. This does not include facilities used in the local distribution of electric
energy.
Inclusions:
•
•

•
•

•

I1 - Transformers with the primary terminal and at least one secondary terminal operated
at 100 kV or higher unless excluded under Exclusion E1 or E3.
I2 - Generating resource(s) with gross individual nameplate rating greater than 20 MVA
or gross plant/facility aggregate nameplate rating greater than 75 MVA including the
generator terminals through the high-side of the step-up transformer(s) connected at a
voltage of 100 kV or above.
I3 - Blackstart Resources identified in the Transmission Operator’s restoration plan.
I4 - Dispersed power producing resources with aggregate capacity greater than 75 MVA
(gross aggregate nameplate rating) utilizing a system designed primarily for aggregating
capacity, connected at a common point at a voltage of 100 kV or above.
I5 –Static or dynamic devices (excluding generators) dedicated to supplying or absorbing
Reactive Power that are connected at 100 kV or higher, or through a dedicated
transformer with a high-side voltage of 100 kV or higher, or through a transformer that is
designated in Inclusion I1.

Exclusions:
•

E1 - Radial systems: A group of contiguous transmission Elements that emanates from a
single point of connection of 100 kV or higher and:
a) Only serves Load. Or,
b) Only includes generation resources, not identified in Inclusion I3, with an
aggregate capacity less than or equal to 75 MVA (gross nameplate rating).
Or,
c) Where the radial system serves Load and includes generation resources,
not identified in Inclusion I3, with an aggregate capacity of non-retail
generation less than or equal to 75 MVA (gross nameplate rating).
Note – A normally open switching device between radial systems, as depicted
on prints or one-line diagrams for example, does not affect this exclusion.

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Page 3 of 4

Project 2010-17 Definition of Bulk Electric System
•

•

•

E2 - A generating unit or multiple generating units on the customer’s side of the retail
meter that serve all or part of the retail Load with electric energy if: (i) the net capacity
provided to the BES does not exceed 75 MVA, and (ii) standby, back-up, and
maintenance power services are provided to the generating unit or multiple generating
units or to the retail Load by a Balancing Authority, or provided pursuant to a binding
obligation with a Generator Owner or Generator Operator, or under terms approved by
the applicable regulatory authority.
E3 - Local networks (LN): A group of contiguous transmission Elements operated at or
above 100 kV but less than 300 kV that distribute power to Load rather than transfer bulk
power across the interconnected system. LN’s emanate from multiple points of
connection at 100 kV or higher to improve the level of service to retail customer Load
and not to accommodate bulk power transfer across the interconnected system. The LN is
characterized by all of the following:
a) Limits on connected generation: The LN and its underlying Elements do
not include generation resources identified in Inclusion I3 and do not have
an aggregate capacity of non-retail generation greater than 75 MVA (gross
nameplate rating) ;
b) Power flows only into the LN and the LN does not transfer energy
originating outside the LN for delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain a
monitored Facility of a permanent Flowgate in the Eastern
Interconnection, a major transfer path within the Western Interconnection,
or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices owned and operated by the retail customer solely for its
own use.

Note - Elements may be included or excluded on a case-by-case basis through the Rules of
Procedure exception process.

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Project 2010-17 Phase 2 - Definition of BES
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the SAR. The electronic comment form must be completed by February 3, 2012.
If you have questions please contact Ed Dobrowolski at ed.dobrowolski@nerc.net or by telephone at
1.609.947.3673.
2010-17 Definition of BES project page
Background Information
This posting is for soliciting comment.
This SAR is a direct result of the industry comment periods for Project 2010-17 Definition of BES Phase
1 where the industry indicated a need for further detailed examination of the technical concepts
underlying the BES definition. Due to time constraints in Phase 1 brought about by the FERC Orders
driving the revised definition, any expansion of the scope of Phase 1 was deferred to Phase 2 where
time deadlines would be less of an issue. The language of the SAR is such that any and all aspects of
the Phase 1 definition are open to discussion and possible revision. However, the SDT outlined some
of the major points that were brought up in Phase 1 by bulleting them in the SAR description. The SDT
does not consider this list to be an all exclusive one – it is simply a brief listing of those issues that were
identified in Phase 1.
You do not have to answer all questions. Enter all comments in simple text format. Bullets, numbers,
and special formatting will not be retained.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
The scope of this project includes:
Collect and analyze information needed to support revisions to the definition of BES developed in
Phase 1 of this project to provide a technically justifiable definition that identifies the appropriate
electrical components necessary for the reliable operation of the interconnected transmission
network. The definition development will include an analysis of the following issues which were
identified during the development of Phase 1 of Project 2010-17 Definition of the BES. Clarification of
these issues will appropriately define which Elements are necessary for the reliable operation of the
interconnected transmission network.

Project YYYY-##.# - Project Name

•

•
•
•
•
•

•

Develop a technical justification to set the appropriate threshold for Real and Reactive
Resources used in the operation of the Bulk Electric System (BES)
Determine if there is a technical justification to support the assumption that there is a reliability
benefit of a contiguous BES
Determine if there is a technical justification for the equipment which “supports” the reliable
operation of the BES but is installed on the distribution system
Determine if there is a technical justification to support an automatic interrupting device in
Exclusions E1 and E3
Determine if there is a technical justification to support the inclusion of Cranking Paths and
Blackstart Resources
Determine if there is a technical justification for selection of 100 kV as the bright-line voltage
level
Determine if there is a technical justification to support allowing power flow out of the local
network under certain conditions and if so, what the maximum allowable flow should be

Provide improved clarity to the following:
•
•

•
•

The relationship between the BES definition and the ERO Statement of Compliance Registry
Criteria established in FERC Order 693
The use of the term “non-retail generation”
The language for Inclusion I4 on dispersed power resources
The appropriate ‘points of demarcation’ between Transmission, Generation, and Distribution

Phase 2 of the definition development may include other improvements to the definition as deemed
appropriate by the drafting team, with the consensus of stakeholders, consistent with establishing a
high quality and technically justifiable definition of the Bulk Electric System (BES).
Based on the potential revisions to the definition of the Bulk Electric System (BES) and an analysis of
the application of, and the results from, the exception process, the drafting team will review and if
necessary propose revisions to the ‘Technical Principles’ associated with the Rules of Procedure
Exception Process to ensure consistency in the application of the definition and the exception process.
1. Do you agree with this scope? If not, please explain.
Yes
No
Comments:
Unofficial Comment Form
Project 2010-17 Phase 2
Definition of BES

2

Project YYYY-##.# - Project Name

The SDT has identified several issues that are included in the scope of Phase 2 of the project that are
associated with the technical aspects of the definition and require technical justification to drive a
revision to the definition. Compelling technical justification is an essential component in moving any
revision forward that addresses the technical nature of the BES definition. The SDT is seeking to
identify existing technical justifications (i.e., completed studies, technical papers, etc.) and requests
your assistance to properly identify resources available to the SDT which will facilitate the SDT’s work
in prioritizing its efforts.
Note: The SDT does not intend to respond to all responses associated with an entity’s knowledge of
existing technical justification (i.e. analysis methodologies, completed studies, technical papers, etc.).
The SDT is collecting potential resources that could assist in the development of compelling technical
justification.
2. Do you agree that the SDT should pursue the development of technical justification to set
thresholds for Real and Reactive Power Resources used in the reliable operation of the BES
different from those presently existing in the BES definition?
Yes
No
Comments:
a. Are you aware of existing technical justification (i.e., analysis methodologies, completed
studies, technical papers, etc.) that would assist the SDT in the development of technical
justification for this issue? If so, please provide details in the ‘Comments’ field.
Yes
No
Comments:
3. Do you agree that the SDT should pursue technical justification that supports the assumption that
there is a reliability benefit of a contiguous BES?
Yes
No
Comments:

Unofficial Comment Form
Project 2010-17 Phase 2
Definition of BES

3

Project YYYY-##.# - Project Name

a. Are you aware of existing technical justification (i.e., analysis methodologies, completed
studies, technical papers, etc.) that would assist the SDT in the development of technical
justification for this issue? If so, please provide details in the ‘Comments’ field.
Yes
No
Comments:
4. Do you agree that the SDT should pursue technical justification for including in the BES definition
the equipment which “supports” the reliable operation of the BES?
Yes
No
Comments:
a. Are you aware of existing technical justification (i.e. analysis methodologies, completed
studies, technical papers, etc.) that would assist the SDT in the development of technical
justification for this issue? If so, please provide details in the ‘Comments’ field.
Yes
No
Comments:
5. Do you agree that the SDT should pursue technical justification to support including an automatic
interrupting device in Exclusions E1 and E3?
Yes
No
Comments:
a. Are you aware of existing technical justification (i.e., analysis methodologies, completed
studies, technical papers, etc.) that would assist the SDT in the development of technical
justification for this issue? If so, please provide details in the ‘Comments’ field.
Yes
No
Comments:

Unofficial Comment Form
Project 2010-17 Phase 2
Definition of BES

4

Project YYYY-##.# - Project Name

6. Do you agree that the SDT should pursue technical justification to support the inclusion of Cranking
Paths in the BES definition and to retain Blackstart Resources as part of the BES definition?
Yes
No
Comments:
a. Are you aware of existing technical justification (i.e., analysis methodologies, completed
studies, technical papers, etc.) that would assist the SDT in the development of technical
justification for this issue? If so, please provide details in the ‘Comments’ field.
Yes
No
Comments:
7. Do you agree that the SDT should pursue technical justification for selection of 100 kV as the
bright-line voltage level?
Yes
No
Comments:
a. Are you aware of existing technical justification (i.e. analysis methodologies, completed
studies, technical papers, etc.) that would assist the SDT in the development of technical
justification for this issue? If so, please provide details in the ‘Comments’ field.
Yes
No
Comments:
8. Do you agree that the SDT should pursue technical justification to support allowing power flow out
of the local network under certain conditions and if so, what the maximum allowable flow should
be?
Yes
No
Comments:

Unofficial Comment Form
Project 2010-17 Phase 2
Definition of BES

5

Project YYYY-##.# - Project Name

a. Are you aware of existing technical justification (i.e., analysis methodologies, completed
studies, technical papers, etc.) that would assist the SDT in the development of technical
justification for this issue? If so, please provide details in the ‘Comments’ field.
Yes
No
Comments:
9. Do you have any other issues that require technical justification that you feel need to be added to
the SAR? If so, please provide a detailed explanation of the issue and why it should be included.
Yes
No
Comments:
10. Do you have any other issues that are associated with improving the clarity of the definition
created in Phase 1 that will assist the Registered Entity in the identification of BES Elements
without altering the intent or scope of the definition? If so, please provide a detailed explanation
of the issue and why it should be included.
Yes
No
Comments:
11. Are you aware of any regional variances associated with approved NERC Reliability Standards that
will be needed as a result of this project? If yes, please identify the Regional Variance.
Yes
No
Comments:

Unofficial Comment Form
Project 2010-17 Phase 2
Definition of BES

6

Project YYYY-##.# - Project Name

12. Are you aware of any business practice that will be needed or that will need to be modified as a
result of this project? If yes, please identify the business practice:
Yes
No
Comments:
13. If you have any other comments on this SAR that you haven’t already mentioned above, please
provide them here:
Comments:

Unofficial Comment Form
Project 2010-17 Phase 2
Definition of BES

7

Standards Announcement

Project 2010-17 Definition of Bulk Electric System Phase 2
Comment Period Now Open: January 4 – February 3, 2012
Now Available
The Definition of Bulk Electric System Standard Drafting Team (DBES SDT) has posted a Standard
Authorization Request (SAR) for Phase 2 of Project 2010-17 Definition of Bulk Electric System for
comment through 8 p.m. Eastern on Friday, February 3, 2012.
During Phase 1 of this project, stakeholders identified a number of possible refinements to clarify
which Elements are necessary for the reliable operation of the interconnected transmission network,
but because of the regulatory deadline imposed by FERC Orders 743 and 743-A, the team was not able
to develop the technical justification required to support making such refinements. The Standards
Committee and NERC Board of Trustees supported initiation of Phase 2 of the project to provide an
opportunity to further evaluate and develop technical justification for refinements proposed by
stakeholders.
The team is seeking comments on the scope of the proposed Phase 2 project as well as specific
suggestions for existing sources of data or technical input to support revisions.
Instructions for Commenting

A comment period is open through 8 p.m. Eastern on Friday, February 3, 2012. Please use this
electronic form to submit comments. If you experience any difficulties in using the electronic form,
please contact Monica Benson at monica.benson@nerc.net. An off-line, unofficial copy of the comment
form is posted on the project page.
Next Steps

The drafting team will review the comments and determine whether to make changes to the SAR
before proceeding with Phase 2 of the project. The drafting team is not obligated to provide individual
responses to each comment on existing sources of data or technical input to support revisions but will
provide a summary Consideration of Comments on those items.
Background

On November 18, 2010 FERC issued Order 743 and directed NERC to revise the definition of Bulk
Electric System so that the definition encompasses all Elements and Facilities necessary for the reliable
operation and planning of the interconnected bulk power system. Phase 1 of Project 2010-17
Definition of Bulk Electric System achieved stakeholder approval of a revised definition of Bulk Electric

System and application form titled ‘Detailed Information to Support an Exception Request’ referenced
in the Rules of Procedure Exception Process, and the revised definition and exception process will be
filed with FERC by the required January 25, 2012 deadline.
Phase 2 of the project is being initiated to develop and analyze technical justification for refinements to
the definition that were suggested by stakeholders during Phase 1.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder participation.
We extend our thanks to all those who participate. For more information or assistance, please contact
Monica Benson at monica.benson@nerc.net.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at monica.benson@nerc.net or at 404-446-2560.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement: Project 2010-17
Definition of Bulk Electric System Phase 2

2

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF A REVISED DEFINITION OF “BULK ELECTRIC SYSTEM”
IN THE NERC GLOSSARY OF TERMS USED IN RELIABILITY STANDARDS

EXHIBIT F

DRAFTING TEAM ROSTER AND BIOGRAPHICAL INFORMATION
FOR NERC STANDARDS DEVELOPMENT
PROJECT 2010-17 DEFINITION OF BULK ELECTRIC SYSTEM

Project 2010-17 Definition of Bulk Electric System
Drafting Team Roster
Name and Title

Contact Info

Pete Heidrich
Mgr. of
Reliability
Standards and
SDT Chair

Company and
Address
Florida Reliability
Coordinating Council
1408 N. Westshore
Blvd.
Suite 1002
Tampa, FL 336074512

Barry Lawson
Associate
Director, Power
Delivery &
Reliability and
SDT Vice Chair

National Rural
Electric Cooperative
Association
4301 Wilson Blvd.
GR11-253
Arlington, VA 22203

1.703.907.5781
barry.lawson@nreca.c
oop

Jennifer Dering
Mgr. Operations
Planning –
Transmission

New York Power
Authority
123 Main St.
White Plains, NY
10601-3170

1.914.287.3179
Jennifer.dering@nypa
.gov

1.813.207.7994
pheidrich@frcc.com

Bio
Peter Heidrich is Manager of Reliability Standards at the Florida Reliability
Coordinating Council (FRCC). Peter joined FRCC in August, 2008 after 16
years at DTE Energy (Detroit Edison) and 8½ years of military service in the
United States Navy Nuclear Power Program. Peter is responsible for the
development of the FRCC Regional Reliability Standards and associated
reliability related policies and procedures (i.e., Regional Criteria, Regional
Interpretations, & FAQs, Regional Definitions, etc.) and oversight of the
FRCC Reliability Standards Development Process. Additionally, Peter
actively participates as the FRCC representative in NERC Reliability
Standards development and on various committees, subcommittees, and
working groups (i.e., NERC Standards Committee (SC), SC Process
Subcommittee, ERO Regional Standards Group (Vice-Chair), Functional
Model Working Group, and Results-Based Standard Initiative).
Barry Lawson is the Associate Director, Power Delivery & Reliability at the
National Rural Electric Cooperative Association (NRECA). Barry joined
NRECA in April 2001, after 18 years in positions with Dominion Virginia
Power, Edison Electric Institute, Columbia Gas Transmission, and KEMA
Consulting. At NRECA, Barry’s current focus is on NERC reliability
policy/governance issues, standards development and compliance process
developments, and critical infrastructure protection policy issues. In
addition, Barry actively participates in BOT, MRC, and SC activities and he
is currently the Chair of NERC’s Critical Infrastructure Protection
Committee (CIPC).
Jennifer Dering is Manager of Operations Planning at the New York Power
Authority. Jennifer joined the New York Power Authority 18 years ago
after beginning her career at IBM. Jennifer is responsible for the short
term operational planning of NYPA’s transmission assets that range from
69 kV to 765 kV and span the entire state of New York. Jennifer has held a
variety of positions at NYPA prior to her current role in Transmission
including roles within Nuclear Licensing, Energy Efficiency, Project
-1-

Brian EvansMongeon
Pres. & CEO

Utility Services
25 Crossroad
Suite 201
Waterbury, VT 05676

1.802.552.4022
brian.evansmongeon@utilitysvcs.
com

Phil Fedora
Asst. VP,
Reliability
Services

Northeast Power
Coordinating Council
1040 Avenue of the
Americas (6th Ave.)
10th Floor
New York, NY 100183703

1.212.840.4909
pfedora@npcc.org

Management, and Engineering. Jennifer is also a licensed Professional
Engineer in the state of New York and a Certified Energy Manager.
Brian Evans-Mongeon is the President and CEO of Utility Services, Inc., a
service firm formed in 2007, specializing in assisting registered entities in
the Electric Reliability Organization (ERO) program. As the
President and CEO of Utility Services, Brian is responsible for oversight of
ERO Compliance and Monitoring for client’s in regions across the U.S.; ISO
& NEPOOL markets; and Renewable Energy Trading and associated
activities. Utility Services is a member in five of the eight NERC regions
and its’ staff hold a number of committee positions within those regions.
Brian is a member of NPCC’s Compliance and Regional Standards
Committee, and is a participant in the NPCC task force for regional
standards on disturbance monitoring. At NERC, Brian is a participant in the
Standard Drafting Team for the Under Frequency Load Shedding program
(NERC Project 2007-01), is currently a member of the Definition of Bulk
Electric System (BES) team (NERC Project 2010-17), and is the current chair
of the Standard Drafting Team for Disturbance and Sabotage Reporting
(NERC Project 2009-01). Previously, Brian has over twenty years of
experience in the electrical utility business working for both Green
Mountain Power Corporation as a Power Operations & Administration
Manager and Vermont Public Power Supply Authority as a Marketing
Services Manager.
Philip Fedora is the Assistant Vice President of Reliability Services,
Northeast Power Coordinating Council (NPCC) where he oversees a wide
range of power system reliability activities associated with the
coordination of system planning, system studies and protection, the
assessment of adequacy, and multi-Area Regional planning. Phil is
responsible for NPCC’s Reliability Assessment and Performance Analysis
program area, including liaison with state, federal and provincial
governmental/regulatory officials. Phil joined NPCC in July, 1999 after 15
years at ISO-New England/New England Power Planning (NEPOOL), where
he was responsible for the management of the ISO-New England Power
Supply Reliability activities, and 8 years at Westinghouse Electric,
Advanced Systems Technology, providing consulting services for domestic
-2-

Ajay Garg
Mgr. Policy and
Approvals

Hydro One Networks
483 Bay St., TCT St-04
Toronto, Ontario,
Canada M5G 2P5

1.416.345.5420
ajay.garg@hydroone.c
om

John P. Hughes
VP, Technical
Affairs

Electricity Consumers
Research Council
1111 19th St. NW
Washington, DC
20036

1.202.682.1390
jhughes@elcon.org

and foreign utilities. Phil is NPCC’s representative on the NERC Planning
Committee, has authored several technical papers on power system
modeling and assessment, and is a member of the IEEE – Power
Engineering Society and
CIGRE. He is a licensed Professional Engineer in the Commonwealth of
Pennsylvania.
Ajay Garg is Manager, Policy & Approvals within Asset Management at
Hydro One Networks Inc (formerly Ontario Hydro). Ajay joined Hydro One
in 2000, after 15 years in positions with Nova Scotia Power and NPCC. At
Hydro One, Ajay’s current focus is on NERC reliability policy/governance
issues, standards development and compliance process, along with
addressing non-jurisdictional regulatory issues. Ajay has been actively
involved with the development of NERC and NPCC Standards/Criteria for
many years along with his participation on the 2003 NERC blackout
investigation team. Ajay also represents Hydro One and/or Canada on
various other committees of IEC, IEEE, NERC, NPCC, CEA, and CSA. Ajay is a
Canadian representative on IEC TC8 and ACEC along with convener of TC8
HV Transmission Group, and member of NERC-CCC and NPCC -CC. Ajay is a
licensed Professional Engineer in the Province of Ontario.
John Hughes is Vice President of Technical Affairs at the Electricity
Consumers Resource Council (ELCON), the national association of large
industrial consumers of electricity. John is responsible for managing
ELCON’s interventions before FERC, DOE, and related state regulatory
bodies. John is also author of ELCON policy papers and technical
documents on all facets of the electric industry. John joined ELCON in
1987 as technical director after serving as Director of Economic Research
at the Niagara Mohawk Power Corporation where he was previously
Associate Director of Corporate Planning. Prior to joining Niagara Mohawk
in 1982, John was Chief Economist at the Massachusetts Energy Facilities
Siting Council. John supervised the council’s technical staff regarding the
demand forecasts and supply plans of electric and natural gas utilities that
operated in the state. John was also directly involved with the council’s
adjudication of petitions to site transmission lines, natural gas pipelines
and gasification facilities, and nuclear power plants. John has been active
-3-

Joel Mickey
Director, Grid
Operations

ERCOT
2705 W. Lake Drive
Taylor, TX 76574

1.512.248.3925
jmickey@ercot.com

Jeffrey Mitchell
Director,
Engineering

Reliability First
320 Springside Dr.
Suite 300
Akron, OH 44333

1.330.247.3043
Jeff.mitchell@rfirst.or
g

with NERC since 1996, having been a member of the Commercial Practices
Working Group, the Market Interface Committee, and the Compliance and
Certification Committee (CCC).
Joel Mickey is Director of Grid Operations for the Electric Reliability Council
of Texas (ERCOT) Joel oversees the system operations control center,
operations engineering, operations analysis, and system operations
training. Joel joined ERCOT in 2000 as Manager of Market Operations with
management responsibilities for wholesale market design, market analysis,
demand-side resource support and testing, market clearing price
validation and correction, network modeling, and market reporting. Prior
to joining ERCOT, Joel worked with a computer software vendor
specializing in energy utility systems for restructured markets. Joel
started his career in the power industry in 1981 at Houston Lightning and
Power (now Centerpoint Energy) where he worked for 15 years in various
positions including underground network tester, system controller, and
staff consultant. Joel has served on various committees for the North
American Electric Reliability Council (NERC) including the Standards
Development team for Interchange, and the Electronic Scheduling
Committee. Joel currently serves as a member of the North American
Energy Standards Board (NAESB) Executive Committee and on NERC’s
Interchange Subcommittee and on the Standards Drafting Team Interchange. At ERCOT, he served as the co-chair of the Texas Nodal
Team’s market operations concept group and chaired the Nodal Transition
Plan Task Force.
Jeff Mitchell is the Director of Engineering at ReliabilityFirst Corp. (RFC)
where he oversees the reliability assessment and performance analysis
activities including resource and transmission assessment reports,
protection system mis-operation review, event analysis, model
development, operations, and the regional standards process. Jeff joined
the East Central Area Reliability Coordination Agreement (ECAR) staff in
1997 after 17 years with Ohio Edison (now FirstEnergy) and subsequently
the ReliabilityFirst staff since its inception. Jeff facilitated the
development of the ReliabilityFirst BES definition in 2007 and now handles
the interpretation requests. Jeff is currently the chair of the NERC
-4-

Jerome Murray
Senior Electrical
Engineer

Oregon Public Utility
Commission
550 Capitol St. NE
Suite 215
PO Box 2148
Salem, OR 973082148

1.503.378.6626
jerry.murray@state.or
.us

Rich Salgo
Director,
Electric System
Operations

Sierra Pacific Power
PO Box 10100
Reno, NV 89520

1.775.834.5874
rsalgo@nvenergy.com

Planning Committee and was the initial chair of the Eastern
Interconnection Reliability Assessment Group’s (ERAG) Management
Committee. He is also a licensed Professional Engineer in Ohio and
Pennsylvania.
Jerome Murray is a Senior Electrical Engineer with the Oregon Public
Utility Commission (OPUC). Jerome joined OPUC in 1983. Previously, he
was an electrical power engineering consultant. Jerome has also worked
for PacifiCorp, Pacific Gas and Electric, Southern California Edison, and the
Navy Civil Engineer Corps. Jerome is currently responsible for utility
regulation development, industry outreach, and compliance oversight
associated with OPUC’s electric reliability and service quality measure
programs. Additionally, Jerome actively participates as the State
Government representative on the NERC Operating Committee and the
WECC Operating Committee. Jerome also participates in the IEEE
Distribution Reliability Working Group and is a licensed professional
engineer in the states of Oregon and Washington.
Rich Salgo is the Director of Electric System Control Operations at NV
Energy, Inc., which includes the registered entities of Nevada Power
Company and Sierra Pacific Power Company. In this role, Rich is
responsible for the transmission, distribution, and balancing functions
conducted within the NV Energy control centers, including associated
operations engineering, training, and energy management system support
functions. Among the duties of his present position, Rich is responsible for
ensuring that policies, procedures, and processes are developed and
implemented pursuant to NERC and WECC Regional Standards, as well as
having responsibility for corporate initiatives in compliance with the CIP
Standards. Rich holds a Bachelor’s degree in Electrical Engineering, and he
joined the predecessor company, Sierra Pacific Resources, in 1984. In this
time, Rich has had experience in various facets of electric system design,
system protection, substation and line construction, and field operations.
Rich is a long-standing member of the WECC Operating Committee,
participates on an advisory committee for the WECC Reliability
-5-

Coordinator, and is a member of the WECC Unscheduled Flow
Administrative Subcommittee. Rich is a licensed Professional Engineer in
the state of California, and also holds a NERC Operator Certification at the
RC level.
Jason Snodgrass is the Regulatory Compliance Manager at Georgia
Transmission Corporation. Jason has been employed in this role since
2008, after 7½ years of experience as a planning engineer. Jason is
primarily responsible for developing, maintaining, and training of GTC’s
compliance program. Additional responsibilities include
policy/governance, compliance process developments, performing selfaudits of applicable mandatory standards, and performing selfassessments/consultation for new and revised NERC Standards prior to the
mandatory dates.

Jason Snodgrass
Regulatory
Compliance
Mgr.

Georgia Transmission

1.770.270.7294
jason.snodgrass@gatr
ans.com

Jennifer Sterling
Director,
Transmission
Strategy and
Compliance

Exelon
2 Lincoln Center
Oakbrook Terrace, IL
60181

1.630.437.2764
jennifer.sterling@exel
oncorp.com

Jennifer Sterling is the Director, Transmission Strategy and Compliance for
Exelon Corporation. Jennifer has been employed by Exelon and its
subsidiary, Commonwealth Edison for 21 years. She has also held
positions in ComEd’s System Planning, Bulk Power Operations,
Transmission Policy, and Regulatory & Strategic Services Departments.
Jennifer is responsible for managing the Exelon NERC Reliability Standards
Compliance Program across the corporation and for providing leadership
for strategic and reliability initiatives for the ComEd and PECO transmission
facilities. Additionally, Jennifer was a member of the NERC Violations
Severity Levels Drafting Team and actively participates on Edison Electric
Institute and North American Transmission Forum Committees.

Jonathan Sykes
Mgr., System
Protection

Pacific Gas & Electric
1919 Webster St.
Room #409
Oakland, CA 94612

1.510.874.2691
jfst@pge.com

Jonathan Sykes is Manager of System Protection at Pacific Gas and Electric
Company (PG&E) in California. Jonathan joined PG&E in June 2009 after 27
years at Salt River Project in Arizona where he worked as a principal
engineer in System Protection and Transmission Planning. Jonathan is
responsible for the oversight (application, design, and compliance) of the
40,000 protective relays at PG&E. Jonathan also serves as the Chairman
-6-

of the NERC System Protection and Control Subcommittee and has been
active in the committee for more than 5 years. Jonathan is also active on
the WECC Remedial Action Reliability Subcommittee and Relay Work
Group. He is also a Senior Member in IEEE and participates in the Power
System Relay Committee and chairs work groups. Jonathan has authored
and co-authored papers concerning reliability and advanced application.

-7-

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF A REVISED DEFINITION OF “BULK ELECTRIC SYSTEM”
IN THE NERC GLOSSARY OF TERMS USED IN RELIABILITY STANDARDS

EXHIBIT G

TECHNICAL JUSTIFICATION PAPER FOR THE
“LOCAL NETWORK EXCLUSION”
(EXCLUSION E3 OF THE BES DEFINITION)

Local Network Exclusion
Introduction

The purpose of this document is to provide the justification for the definitional exclusion of local
networks (LN) from the definition of the Bulk Electric System (BES) as proposed in NERC Standards
Development Project 2010-17. Presented herein are technical, logical, and practical considerations that
provide such justification for exclusion of these facilities from the Bulk Electric System.

Summary of Justification
The local network exclusion proposal is shown to be justified through the following facts:
1. In accordance with Commission Orders 743 and 743a on the matter of the revision of the
Definition of the Bulk Electric System, the facilities used in the local distribution of electric
energy are to be excluded;
2. The exclusion for local networks, as provided in the revised definition of the BES, ensures that a
candidate for local network exclusion must satisfy all of the exclusion principles thus
demonstrating that the candidate facilities are not performing a transmission function;
3. The limit on connected generation within the local network is consistent with the existing
threshold above which a generating plant in aggregate becomes subject to owner and operator
registration in the ERO Statement of Compliance Registry Criteria;
4. The voltage cap applied to the qualifications for a local network is established at 300 kV, which
is consistent with the distinction being made between Extra High Voltage and High Voltage in
the NERC Board of Trustees-approved Reliability Standard on transmission planning, TPL-001-2;
5. The power flow “shifts” that would occur on the elements of a local network are but a
negligible fraction of that which distributes upon the BES elements for a given power transfer
and is fully eclipsed by the Load in the local network; and
6. The interaction of the local network with the BES is similar in character to that of a radial facility.

Description of Local Network
Local networks are defined in the draft BES Definition as:
A group of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that
distribute power to Load rather than transfer bulk power across the interconnected system. LN’s
emanate from multiple points of connection at 100 kV or higher to improve the level of service to retail
customer Load and not to accommodate bulk power transfer across the interconnected system. The LN
is characterized by all of the following:

Page 1 of 16

a) Limits on connected generation: The LN and its underlying Elements do not include
generation resources identified in Inclusion I3 and do not have an aggregate capacity of
non-retail generation greater than 75 MVA (gross nameplate rating) ;
b) Power flows only into the LN: The LN does not transfer energy originating outside the LN for
delivery through the LN; and
c) Not part of a Flowgate or transfer path: The LN does not contain a monitored Facility of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within the
Western Interconnection, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability
Operating Limit (IROL).
Local networks are present to provide local electrical distribution service and are not planned, designed,
nor operated to benefit or support the balance of the interconnected electrical transmission network.
Their purpose is to provide local distribution service, not to provide transfer capacity for the
interconnected electric transmission network. Their design and operation is such that at the point of
connection with the interconnected electric transmission network, their effect on that network is similar
to that of a radial facility, particularly in that flow always moves in a direction that is from the BES into
the facility. Any distribution of parallel flows into the local network from the BES, as governed by the
fundamentals of parallel electric circuits, is negligible, and, more importantly, is overcome by the Load
served by the local network, thereby ensuring that the net actual power flow direction will always be
into the local network at all interface points. The presence of a local network is not for the operability of
the interconnected electric transmission network; neither will the local network’s separation or
retirement diminish the reliability of the interconnected electric transmission network.

Commission Determination on Exclusion of Local Distribution – Relation
to Local Network
In Order 743a, the Commission made it clear that facilities that are used in the local distribution of
electric energy will be excluded from the Bulk Electric System. Such clarification was provided in both
paragraphs 22 and 25 of the Order. The Commission agreed with certain commenters that facilities
used in the local distribution of energy should be excluded from the revised Bulk Electric System
definition.
In response to this facet of the Order, in developing the BES definition, the SDT has followed this
guidance. Exclusion E3 was specifically designed to capture for exclusion those high voltage non-radial
facilities being used for the local distribution of energy.
The exclusion characteristics in items a, b, and c above are further explained in the next section. These
exclusion principles serve to ensure that facilities excluded under the local network exclusion (E3) are
not necessary for the reliable operation of the interconnected electric transmission network and are
instead used in the local distribution of energy.

Page 2 of 16

Exclusion Principles
Of key importance is that Exclusion E3 in the draft BES definition requires the facilities of a candidate
network to meet all of the characteristics listed in the exclusion. The SDT adopted this approach to
ensure that none of the characteristics typical of interconnected electric transmission networks, or
necessary for the operation of the interconnected electric transmission system, would be permissible in
those facilities that are qualified for Exclusion E3. In the discussion below, it is shown that these
characteristics successfully prevent exclusion of facilities necessary for operating an interconnected
electric transmission network, and allow only facilities that are not necessary for such operation to be
excluded from the BES.
A. First Exclusion Principle: Limits on Connected Generation
Limits on connected generation: The LN and its underlying Elements do not include generation
resources identified in Inclusion I3, and do not have an aggregate capacity of non-retail
generation greater than 75 MVA (gross nameplate rating);
This characteristic places restrictions on the type and size of generation resources that can be connected
within the candidate facility. By placing this generation restriction on the local network, it is ensured
that that the candidate facility will not under any circumstance act as a host to generation that exceeds
the existing aggregate generation threshold in the ERO Statement of Compliance Registry Criteria (SCRC)
and that the candidate facility will not contain Blackstart Resources. The SDT submits that this
characteristic minimizes the contribution and influence the local network may have over the
neighboring Elements of the BES by limiting both the magnitude and the function of the connected
generation. The threshold of 75 MVA was chosen in a manner to provide consistency with the criteria
applied in the ERO’s SCRC regarding the registration for entities owning and operating generation plants
in aggregate.
B. Second Exclusion Principle: Power Flow and Function
Power flows only into the LN: The LN does not transfer energy originating outside the LN for
delivery through the LN;
This characteristic ensures that the real power flow direction at all connection points to the BES is into
the candidate local network, thereby ensuring that the candidate facilities behave in a manner that is
radial in character. Further, the local network is restricted as to its use; i.e., it cannot be used for
“wheel” transactions, or the transfer of energy originating outside the local network for delivery through
the local network. By restricting the flow direction to be exclusively into the network at its connection
points to the BES and precluding the network from providing transmission wheeling service, this
exclusion characteristic further ensures that the local network is providing only a distribution service,
and is not contributing to, nor is necessary for, the reliable operation of the interconnected electric
transmission network. Regarding the location of the connection points to the BES, Exclusion E3
specifies that local networks “emanate from multiple points of connection at 100 kV or higher…” These
points of emanation, where the local network begins and the BES ends, are established on a case-byPage 3 of 16

case basis, but will necessarily be the points, below 300 kV, at which all of the qualifying exclusion
principles are satisfied. As an example, see Appendix 1 to this document, which provides, among other
things, a single line diagram depicting a local network and its interface with the BES.
C. Third Exclusion Principle: Flowgates and Transfer Paths
Not part of a Flowgate or transfer path: The LN does not contain a monitored Facility of a
permanent Flowgate in the Eastern Interconnection, a major transfer path within the Western
Interconnection, or a comparable monitored Facility in the ERCOT or the Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability
Operating Limit (IROL).
This characteristic further ensures that the candidate local network facilities do not contain nor
comprise facilities of well-established flowgates and transfer paths throughout the Interconnections of
North America. These transfer paths are customarily used to provide bulk power transfers within the
Interconnections, and therefore, the function and purpose of any candidate facilities included in or
among such paths extends beyond the distribution function. A number of interchange coordination
Reliability Standards apply to these transfer paths and flowgates. The SDT feels that such facilities are
necessary for the reliable operation of an interconnected electric transmission network and would not
be excluded from the definition of the BES.

The Use of a 300 kV Cap is Appropriate for Local Network Exclusion
The selection of a 300 kV cap for the applicability of an exclusion for a local network was based upon
recent NERC Standards Development work in Project 2006-02 “Assess Transmission Future Needs and
Develop Transmission Plans.” As conveyed in its work product, TPL-001-2, the Project 2006-02 SDT sets
a voltage level of 300 kV to differentiate Extra High Voltage (EHV) facilities from High Voltage facilities
acting as a threshold to distinguish between expected system performance criteria. 1 The Project 201017 SDT seeks to establish consistency in the limitations placed on the exclusion applicability for local
network facilities, and has therefore adopted this 300 kV level to ensure that EHV facilities, which under
the TPL-001-2 Standard are held to a higher standard of performance, are not subject to this exclusion.

There is Minimal Effect to Flow in the Local Network due to BES Power
Transfer
Similar to the character of a radial facility, and in order to qualify for exclusion from the BES under
Exclusion E3.b,a local network must only have power flow into the network at all connection points to
the BES. As demonstrated below, while this flow at the connection points is always into the local
Per footnote #3 in TPL-001-2, “Bulk Electric System (BES) level references include extra-high voltage (EHV)
Facilities defined as greater than 300 kV and high voltage (HV) Facilities defined as the 300 kV and lower voltage
Systems. The designation of EHV and HV is used to distinguish between stated performance criteria allowances for
interruption of Firm Transmission Service and Non-Consequential Load Loss.”
1

Page 4 of 16

network, the magnitude of the flow at these connection points will exhibit very slight shifts as bulk
power transactions are implemented on neighboring BES facilities. This occurs because local network
facilities are electrically parallel to Elements comprising the BES, and hence, the local network will
experience a small effect due to changes in power angle across the parallel network as BES dispatch and
flow patterns change. However, such flow shift is shown to be minimal, and the resultant power flow at
all BES interface points is dominated by the superimposed load flow serving the distribution Load
connected within the local network. Again, Exclusion E3.b ensures that flow shall always be from the
BES into the local network in order to qualify for exclusion.
In order to provide a realistic example of the electrical interaction between a typical local network and
the BES, an electric system in the western United States was examined from a power transfer
distribution factor (PTDF) perspective. In a PTDF analysis, the branch elements of an electrical network
are examined on the basis of the percentage split of a given power flow as it propagates through the
network. In the simplest example of two identical lines operated at the same voltage, arranged in
parallel between a given sending bus and receiving bus, the total power transfer will divide equally
among the two parallel line elements, and hence, each element would be found to have a 50% PTDF. In
a more complicated network, the line elements will carry a portion of the total flow in a manner that is
inversely proportional to their impedance; i.e., the lower the impedance of the network branch, the
higher portion of the flow that will distribute along that branch.
The electric system in question is depicted in Appendix 1. The station name identifiers and the network
topology (but not electrical connectivity) have been changed to respect the confidentiality of the
information. In the represented system, a bulk power transfer was simulated, with a point of receipt
(injection) at BES bus T9 and a point of delivery at the other end of the system at BES bus T10. With this
simulated power transfer, power flow analysis tools were used to determine the distribution of this
simulated transfer as it propagates across the various parallel branches of the network. As depicted in
Appendix 1, the facilities that are presumed to be excluded via the local network exclusion (E3) are
shown to carry negligible flow, with the largest PTDF at a mere 0.23% of the total transfer. Note that a
PTDF analysis shows only the incremental shift in power flow and does not imply that this 0.23% actually
flows in and then back out of the network. The power flow results demonstrate that the flow measured
at the interface points of the BES continues to flow into the local network, and is essentially unchanged,
as it is only shifted in magnitude by a mere 0.23% of the modeled transaction amount.
In addition to the PTDF analysis, another analysis of Line Outage Distribution Factors (LODF), examines
the re-distribution of flow that occurs on parallel elements after a subject element is removed from
service. For example, if a BES element is carrying 500 MW, and is taken out of service, LODF describes
how that flow re-distributes among all parallel paths in a given network. LODF factors are measured in
percent of the pre-outage flow on the outaged element. Conducting this analysis on the example
network and modeling the worst case outage, which is the loss of the line element between BES buses
T9 and T10, shows that the net shift in flow for the local network is 4.0% of the pre-outage flow, and the
largest shift in flow on any of the individual local network elements is 2.7%. The flow direction at the
interface points between the local network and the BES continues to be into the local network.
Page 5 of 16

This degree of flow shift on the local network facilities is de minimus, and neither diminishes or
improves the reliability of the parallel BES facilities. From both a PTDF and an LODF analysis perspective,
the local network exhibits qualities equivalent to radial facilities in that the power flow emanates from
the point of BES connection in one direction – the only difference being that in the case of the local
network, in order to provide source reliability to the distribution Load, more than one connection is
provided to the BES.

Page 6 of 16

Appendix 1
Local Network Technical Justification
Power Transfer Distribution Factor Analysis
This appendix provides Power Transfer Distribution Factor (PTDF) and Line Outage Distribution Factor
(LODF) analyses and assessments using a relevant power flow case used in actual operating studies in
the Western Interconnection to assess reliable Operating Transfer Capability on a rated path in the
Western Electricity Coordinating Council ("WECC"). The electrical system representation is accurate;
however, the bus names and topology have been graphically rearranged to address any Critical Energy
Infrastructure Information (“CEII”) concerns.
Although linear analyses, such as these, are relatively independent of actual power transfer levels, the
modeled system conditions represented peak load demand and high power transfer conditions. The
PTDF analyzes the injection of power from BES electrical bus T9 and delivering it to BES bus T10, which is
consistent with the use of the BES transfer path. Based on the PTDF assessment, 92% of the power flow
is transferred over the 500 kV line that directly connects BES buses T9 and T10. The remaining flow
appears on the underlying 230 kV lines and adjacent 345 kV and 500 kV lines. The largest PTDF on any
local network is 0.23 percent.
The LODF analysis considers the “worst-case” outage of the strongest (lowest impedance) transmission
element, the line between BES buses T9 and T10. The LODF values that are computed represent the
percentage of the pre-outage T9-T10 flow that re-distributes on each of the remaining branches. The
analysis shows that the net shift in flow for the local network is 4.0% of the pre-outage flow, and the
largest shift in flow on any of the individual local network elements is 2.7%. The 2.7% shift occurs on the
local network branch between buses LN19 and LN28, and a 1.3% shift occurs on the branch between
LN27 and LN33. The flow direction at the interface points between the local network and the BES
continues to be into the local network.
Below are three single line diagrams, which depict the 1) powerflow, 2) percentage distribution of flows
for the PTDF analysis, and 3) the percent of flow distribution for the LODF analysis. In these diagrams,
the local network elements are indicated by a green line color, and the local network station buses are
indicated with an “LN” designation, for example, “LN23”.
Following the single line diagrams are two tables: Table 1 - a tabulation of the PTDF values for the
network, and Table 2 - depicting the LODF values for the T9-T10 line outage case.

Page 7 of 16

The Powerflow Single Line

T18

T16

T9
T6

T10

T5
T8

T11

T19
T36

T17

T35

T20
T23

T21

T22

T27

T25

T24

T29

T28

T31
LN2

LN10

Local Network

LN4

LN1

LN22

LN6

To generation
LN51

LN25

T26

Local Network
LN50

LN9
LN57
LN7

LN21

LN13

LN52
LN58
LN26

LN15
LN8

T33

LN23

LN12

LN5

LN6

T34

LN24

LN3
LN11

T32

T30

LN15

LN53

LN17

LN31

LN49
LN54

LN16

LN55

LN36
LN48

LN32
LN18

LN37

Red lines are 345 kV to 500 kV

LN20

Orange lines are 230 kV

LN56

LN27

LN33

LN38

Green lines are 115 kV
LN29

The size of the arrow is proportional to the magnitude of powerflow in
MWs
Arrows do not appear when the level of powerflow is very low

LN57

LN30

LN47
LN39

LN19

LN28

LN40
LN46

LN34
LN41
LN45
LN35

LN42
LN43
LN44

Page 8 of 16

The Power Transfer Distribution Factors (“PTDF”) Single Line

T18

T9
T6

PTDF
The transaction is from bus T9 to bus T10 where T9 is the seller and T10 is the buyer

T8

PTDF

T21

T11

T19
T35

2%

T22

PTDF

T27

T25

T24

T29

T28

T31
LN2

LN10

Local Network

LN11

LN1
LN6
LN6

To generation
LN51

LN25

T26

Local Network
LN50

LN9
LN57
LN7

LN21

LN13

LN52
LN58
LN26

LN15
LN8

T34

T33

LN23

LN12

LN5

T32

T30

LN24

LN22

LN3
LN4

T36

T17

2%
T23

T10

92%

T5

T20

T16

LN15

LN53

LN17

LN31

LN49
LN54

LN16

LN48

LN32
LN18

LN37

Red lines are 345 kV to 500 kV

LN20

LN56

LN27

Orange lines are 230 kV

LN33

0%

Green lines are 115 kV

LN38

PTDF

LN29

The size of the arrow is proportional to the magnitude of PTDF
Arrows do not appear when the level of PTDF is very low

LN55

LN36

0%

LN19

PTDF

LN57

LN30

LN47
LN39

LN28

LN40
LN46

LN34
LN41
LN45
LN35

LN42
LN43
LN44

Page 9 of 16

The Line Outage Distribution Factors ("LODF") Single Line identifying the revised PTDF values of the transmission line from T9 to T10 is opened

For the LODF assessment the transmission line from bus T9 to bus T10 is opened and the PTDF are
recalculated (See the LODF table for additional details)

T9
T6

T18

T16

T10

T5
T8

T11

T19
PTDF

T20
T23

T21

T35

22%

T22

PTDF

T27

T25

T24

T29

T28

T31
LN2

LN10

Local Network

LN22

LN11

LN4

LN6
LN6

To generation
LN51
T26

LN12

Local Network
LN50

LN9
LN57
LN7

LN21

LN13

LN52
LN58
LN26

LN15
LN8

T34

T33

LN23
LN25

LN5

T32

T30

LN24

LN3
LN1

T36

T17

22%

LN15

LN53

LN17

LN31

LN49
LN54

LN16

LN48

LN18

LN37

Red lines are 345 kV to 500 kV

LN20

LN56

LN27

Orange lines are 230 kV

LN33

1%

Green lines are 115 kV

LN38

PTDF

LN29

The size of the arrow is proportional to the magnitude of PTDF
Arrows do not appear when the level of PTDF is very low

LN55

LN36
LN32

3%

LN19

PTDF

LN57

LN30

LN47
LN39

LN28

LN40
LN46

LN34
LN41
LN45
LN35

LN42
LN43
LN44

Page 10 of 16

Table 1 - Power Flow Transfer Distribution Factor Results

From
Name
T10
T10
T5
T11
T36
T12
T19
T19
T22
T34
T34
T41
T40
T37
LN16
LN28
LN19
T30
LN50
LN32
LN31
LN20
LN12
LN11
LN3
T29
T29
LN30
LN9
LN5
T28
T32
LN50
LN53
LN55
LN41
T33
LN39
T42
LN47
LN1
LN41
LN25

Line PTDF Records
%
%
To
PTDF
PTDF
Name
From
To
T9
-91.61
91.61
T11
-5.4
5.4
T9
-4.77
4.77
T36
-4.13
4.13
T35
-3.08
3.08
T11
-2.4
2.4
T20
-1.84
1.84
T22
-1.81
1.81
T21
-1.74
1.74
T30
-1.3
1.3
T30
-1.29
1.29
T40
-0.57
0.57
T39
-0.55
0.55
T38
-0.49
0.49
LN8
-0.23
0.23
LN19
-0.23
0.23
LN18
-0.23
0.23
T33
-0.11
0.11
LN36
-0.11
0.11
LN33
-0.11
0.11
LN32
-0.11
0.11
LN17
-0.11
0.11
LN11
-0.11
0.11
LN10
-0.11
0.11
LN2
-0.1
0.1
T32
-0.09
0.09
T17
-0.09
0.09
LN29
-0.09
0.09
T23
-0.08
0.08
LN7
-0.08
0.08
T31
-0.07
0.07
T31
-0.07
0.07
LN49
-0.07
0.07
T33
-0.06
0.06
LN54
-0.06
0.06
LN43
-0.06
0.06
T32
-0.05
0.05
LN41
-0.05
0.05
T39
-0.04
0.04
T32
-0.04
0.04
T23
-0.04
0.04
LN42
-0.04
0.04
LN23
-0.04
0.04

Nom
kV
(Max)
500
500
500
230
230
500
230
230
230
230
230
230
230
230
115
115
115
115
115
115
115
115
115
115
115
115
230
115
115
115
115
115
115
115
115
115
115
115
230
115
115
115
115

From
Name
LN22
LN13
LN15
LN45
LN57
LN50
T1
LN51
T33
LN4
LN6
LN38
LN30
LN35
LN38
LN24
LN26
T25
LN26
LN14
LN22
LN17
LN23
T25
T24
T6
T19
T19
T19
LN47
LN46
LN25
LN22
LN13
LN53
LN45
LN44
LN41
LN9
LN37
T16
LN30
T20
LN3
T24

Line PTDF Records
%
%
To
PTDF
PTDF
Name
From
To
LN21
-0.04
0.04
LN15
-0.04
0.04
LN1
-0.04
0.04
LN57
-0.03
0.03
LN56
-0.03
0.03
LN48
-0.03
0.03
T2
0
0
LN52
0
0
LN52
0
0
LN5
0
0
LN5
0
0
LN37
0
0
LN35
0
0
LN34
0
0
LN34
0
0
LN27
0
0
LN25
0
0
LN23
0
0
LN20
0
0
LN15
0
0
LN11
0
0
LN10
0
0
LN10
0
0
T24
0.01
-0.01
T23
0.02
-0.02
T4
0.03
-0.03
T26
0.03
-0.03
T26
0.03
-0.03
T26
0.03
-0.03
LN46
0.04
-0.04
LN42
0.04
-0.04
LN24
0.04
-0.04
LN23
0.04
-0.04
LN21
0.04
-0.04
LN54
0.06
-0.06
LN44
0.06
-0.06
LN43
0.06
-0.06
LN40
0.06
-0.06
LN7
0.08
-0.08
T31
0.09
-0.09
T17
0.09
-0.09
LN37
0.09
-0.09
T23
0.1
-0.1
LN5
0.1
-0.1
LN2
0.1
-0.1

Nom
kV
(Max)
115
115
115
115
115
115
500
115
115
115
115
115
115
115
115
115
115
115
115
115
115
115
115
115
115
500
230
230
230
115
115
115
115
115
115
115
115
115
115
115
345
115
115
115
115

12

From
Name
LN50
T22
LN57
LN12
LN31
LN27
LN20
LN58
T25
LN50
T21
T19
LN5
LN28
LN16
T2
T2
T37
T13
T14
T38
T27
T28
T4
T19
T19
T19
T1
T4
T34
T34
T21
T6
T5
T5
T29
T15
T12
T9
T8

Line PTDF Records
%
%
To
PTDF
PTDF
Name
From
To
T31
0.11
-0.11
T25
0.11
-0.11
LN58
0.11
-0.11
LN57
0.11
-0.11
LN36
0.11
-0.11
LN33
0.11
-0.11
LN27
0.11
-0.11
LN17
0.11
-0.11
LN10
0.11
-0.11
T33
0.12
-0.12
T24
0.12
-0.12
T18
0.13
-0.13
LN8
0.23
-0.23
LN29
0.23
-0.23
LN18
0.23
-0.23
T7
0.3
-0.3
T7
0.34
-0.34
T34
0.49
-0.49
T12
0.59
-0.59
T11
0.71
-0.71
T39
0.78
-0.78
T28
0.94
-0.94
T29
1.1
-1.1
T3
1.15
-1.15
T29
1.21
-1.21
T27
1.22
-1.22
T38
1.26
-1.26
T7
1.28
-1.28
T1
1.28
-1.28
T35
1.54
-1.54
T35
1.54
-1.54
T20
1.77
-1.77
T2
2.34
-2.34
T6
2.37
-2.37
T4
2.4
-2.4
T30
2.48
-2.48
T11
2.97
-2.97
T10
3
-3
T8
3.62
-3.62
T21
3.62
-3.62

Nom
kV
(Max)
115
115
115
115
115
115
115
115
115
115
115
230
115
115
115
500
500
230
500
500
230
230
230
500
230
230
230
500
500
230
230
230
500
500
500
230
500
500
500
230

13

Table 2 - Line Outage Distribution Factor Results (Outage of T9-T10)

From
Name
T10
T9
T8
T12
T15

To
Name
T9
T8
T21
T10
T11

T29
T5
T5
T6
T21
T34
T34
T4
T1
T19
T19
T19
T4
T28
T27
T38
T14
T13
T37
T2
T2
LN5
LN16
LN28
T19
T22
T21
LN50
T25
LN12
LN57
LN58
LN20
LN27
LN31
LN50
T24
T20

T30
T4
T6
T2
T20
T35
T35
T1
T7
T38
T27
T29
T3
T29
T28
T39
T11
T12
T34
T7
T7
LN8
LN18
LN29
T18
T25
T24
T33
LN10
LN57
LN58
LN17
LN27
LN33
LN36
T31
LN2
T23

Line LODF Records
%
MW
MW
CTG MW
LODF
From
To
From
-100 -1482.1 1483.7
0
-43.2
217.9 -217.8
857.5
-43.2
217.8 -217.5
857.4
-35.7
-937.2
937.2
-408.3
-35.4
1632.1
2156.2
1596.9
-29.5
404.1 -404.1
841.8
-28.6
-835.5
835.5
-411.4
-28.2
-873.5
873.5
-455.2
-27.8
-911.5
912.6
-499
-21
69
-69
380.8
-18.3
29.2
-29.1
300.9
-18.3
29.2
-29.1
300.9
-15.3 -1783.5 1802.5
-1557.4
-15.3 -1802.5 1802.5
-1576.4
-15
107.3
-107
330.4
-14.5
-53.1
53.2
162.3
-14.4
-50.9
51
162.8
-13.8
986
-985
1189.8
-13.1
155.8 -155.8
349.4
-11.2
-154.7
154.7
11.3
-9.2
326.8 -319.7
463.7
-8.4 -1656.8 1684.2
-1532.1
-7.1 -1308.7 1329.4
-1204.2
-5.8
-219.8
220.1
-133.7
-4.1
-826.9
833.1
-766.2
-3.5
-714.3
719.6
-661.9
-2.7
21.8
-21.8
62.3
-2.7
21.1
-21.1
61.6
-2.7
-8.4
8.5
32.1
-1.5
203.2 -202.5
225.6
-1.4
83.1
-83
103.2
-1.4
78.4
-78.3
99.1
-1.4
-38.6
38.7
-18.2
-1.3
35.7
-35.7
54.4
-1.3
22.3
-22.3
41
-1.3
12.4
-12.4
31.1
-1.3
0.1
-0.1
18.8
-1.3
0.1
-0.1
18.8
-1.3
0.1
-0.1
18.8
-1.3
-20.3
20.3
-1.6
-1.3
-36.7
36.7
-16.7
-1.2
80.3
-80.2
98.3
-1.2
77.4
-77.2
95.8

14

CTG MW
To
1.6
-857.4
-857.1
408.3
-2120.9
-841.8
411.4
455.2
500.1
-380.8
-300.9
-300.9
1576.4
1576.4
-330
-162.2
-162.7
-1188.9
-349.4
-11.3
-456.6
1559.6
1224.8
133.9
772.4
667.2
-62.3
-61.6
-32.1
-224.8
-103.1
-99
18.3
-54.4
-41
-31.1
-18.8
-18.8
-18.8
1.6
16.8
-98.2
-95.7

LN3
T16

LN5
T17

From
Name
LN9
LN30
LN37
LN45
LN44
LN53
LN41
LN46
LN47
LN13
LN22
LN25
T6
T24
T19
T19
T19
T25
LN51
LN30
LN17
LN23
LN22
LN26
T25
LN24
LN35
LN38
T1
LN38
LN26
LN14
T33
LN4
LN6
LN50
LN57
LN45
LN25
T42
LN22
LN41
LN13
LN15

To
Name
LN7
LN37
T31
LN44
LN43
LN54
LN40
LN42
LN46
LN21
LN23
LN24
T4
T23
T26
T26
T26
T24
LN52
LN35
LN10
LN10
LN11
LN20
LN23
LN27
LN34
LN34
T2
LN37
LN25
LN15
LN52
LN5
LN5
LN48
LN56
LN57
LN23
T39
LN21
LN42
LN15
LN1

-1.2
53.6
-53.5
71.6
-1
449.4 -436.5
464.6
Line LODF Records
%
MW
MW
CTG MW
LODF
From
To
From
-1
48.7
-48.6
63.3
-1
-39.1
39.1
-24
-1
-48.3
48.4
-33.2
-0.7
70.8
-70.8
81.3
-0.7
67.7
-67.6
78.2
-0.7
59.5
-59.5
69.6
-0.7
53.2
-53.1
63.1
-0.5
55.6
-55.6
63.5
-0.5
55.8
-55.6
63.7
-0.5
47.9
-47.9
55.7
-0.5
24.6
-24.6
32.5
-0.5
14.4
-14.4
22.2
-0.4
38
-38
43.8
-0.3
45.3
-45.3
49.4
-0.3
-152.9
157.7
-148.1
-0.3
-152.9
157.7
-148.1
-0.3
-152.9
157.7
-148.1
-0.1
47.3
-47.3
48.7
0
30.6
-30.5
30.6
0
24.4
-24.4
24.4
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
-9.1
9.1
-9.1
0
-10.2
10.2
-10.2
0
-12.4
12.4
-12.4
0
-22
22.1
-22.1
0
-22.4
22.4
-22.4
0
-33.9
33.9
-33.9
0.3
29.9
-29.9
25.4
0.3
-17.2
17.3
-21.7
0.3
-37.6
37.6
-42
0.5
-24.6
24.6
-32.4
0.5
-28.5
30.5
-35.9
0.5
-38.1
38.1
-45.9
0.5
-48.9
48.9
-56.8
0.5
-51.6
51.6
-59.4
0.5
-64
64
-71.8

15

-71.5
-451.7
CTG MW
To
-63.3
24
33.3
-81.3
-78.1
-69.5
-63
-63.5
-63.5
-55.7
-32.5
-22.2
-43.8
-49.4
153
153
153
-48.7
-30.5
-24.4
0
0
0
0
0
0
0
0
0
9.1
10.2
12.4
22.1
22.4
33.9
-25.3
21.7
42
32.5
37.9
46
56.8
59.4
71.9

LN1
LN47
T33
LN39

T23
T32
T32
LN41

From
Name
LN55
LN41
LN53
T32
T28
LN50
T29
LN30
LN5
LN9
T29
LN3
T30
LN50
LN31
LN20
LN32
LN11
LN12
LN28
LN19
LN16
T37
T40
T41
T34
T34
T22
T19
T19
T12
T36
T11
T5

To
Name
LN54
LN43
T33
T31
T31
LN49
T32
LN29
LN7
T23
T17
LN2
T33
LN36
LN32
LN17
LN33
LN10
LN11
LN19
LN18
LN8
T38
T39
T40
T30
T30
T21
T22
T20
T11
T35
T36
T9

T10

T11

0.5
-64
64
-71.9
0.5
-66.5
66.6
-74.4
0.6
45.7
-45.7
36.4
0.6
-46.7
46.8
-55.3
Line LODF Records
%
MW
MW
CTG MW
LODF
From
To
From
0.7
-50.6
50.7
-60.7
0.7
-58.7
58.8
-69.2
0.7
-62.8
63
-72.9
0.8
65.9
-65.9
54.4
0.9
125.9 -125.5
112.9
0.9
61.9
-61.8
49.1
1
136.8 -136.4
121.6
1
-4.5
4.5
-19.7
1
-38.7
38.7
-53.4
1
-58.4
58.5
-73
1
-436.1
436.5
-451.3
1.2
-61.9
62
-79.9
1.3
125.6 -125.3
105.9
1.3
29.7
-29.7
11
1.3
11.2
-11.2
-7.5
1.3
-0.1
0.1
-18.8
1.3
-0.1
0.1
-18.8
1.3
-35.7
35.7
-54.4
1.3
-35.6
35.7
-54.3
2.7
-2.1
2.1
-42.6
2.7
-12.6
12.6
-53.1
2.7
-21.7
21.8
-62.3
5.8
219.8 -219.8
133.7
6.6
-221.1
222.8
-318.7
6.8
-308.2
309.9
-408.2
15.4
-138.7
138.7
-366.6
15.5
-139.7
139.7
-369.2
20.7
-70.2
70.2
-377.3
21.5
-90.4
90.7
-409.8
21.9
-91.6
91.9
-416.3
28.6
-392.2
392.2
-816.5
36.7
-58.2
58.2
-601.7
49.2
65.3
-64.8
-663.5
56.8
1709
866.6
1701.6
64.3
544.9 -544.9
-408.3

16

71.9
74.5
-36.4
55.4
CTG MW
To
60.7
69.3
73
-54.4
-112.5
-49
-121.1
19.7
53.4
73.2
451.7
80
-105.7
-11
7.5
18.8
18.8
54.4
54.4
42.6
53.1
62.3
-133.7
320.4
409.9
366.7
369.2
377.3
410
416.6
816.5
601.7
664
-859.1
408.3